Bonavista Energy Trust
TSX : BNP.UN

Bonavista Energy Trust

August 07, 2008 15:45 ET

Bonavista Energy Trust Announces Second Quarter Results

CALGARY, ALBERTA--(Marketwire - Aug. 7, 2008) - Bonavista Energy Trust (TSX:BNP.UN) is pleased to report to unitholders its interim consolidated financial and operating results for the three and six months ended June 30, 2008.



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Highlights
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Three Months Six Months
ended June 30, ended June 30,
2008 2007 2008 2007
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Financial
($ thousands, except per
unit)
Production revenues 361,555 223,878 657,942 449,100
Funds from operations (1) 183,912 126,111 339,044 254,623
Per unit (1) (2) 1.62 1.20 3.06 2.43
Distributions declared 84,282 76,757 161,857 153,293
Per unit 0.90 0.90 1.80 1.80
Percentage of funds from
operations (1) 46% 61% 48% 60%
Net income 29,282 33,936 101,580 95,566
Per unit (2) 0.26 0.32 0.92 0.91
Total assets 2,512,365 2,115,759
Long-term debt, including
working capital deficiency 752,792 577,409
Long-term debt, net of
adjusted working capital (3) 631,871 572,937
Unitholders' equity 1,232,554 1,087,869
Capital expenditures:
Exploitation and development 62,166 67,715 155,431 158,331
Acquisitions, net 4,771 (155) 174,145 810
Weighted average outstanding
equivalent trust units:
(thousands) (2)
Basic 113,713 105,087 110,795 104,699
Diluted 116,292 107,701 113,228 107,385
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Operating
(boe conversion - 6:1 basis)
Production:
Natural gas (mmcf/day) 172 171 175 172
Oil and liquids (bbls/day) 22,974 22,964 23,834 23,198
Total oil equivalent (boe/day) 51,598 51,533 52,998 51,792

Product prices: (4)
Natural gas ($/mcf) 9.62 7.35 8.73 7.61
Oil and liquids ($/bbl) 81.94 52.66 75.05 51.34
Operating expenses ($/boe) 9.37 8.46 9.16 8.40
General and administrative expenses
($/boe) 0.74 0.68 0.72 0.67
Cash costs ($/boe) (5) 11.86 10.68 11.94 10.64
Operating netback ($/boe) (6) 41.66 29.11 37.92 29.40
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NOTES:
(1) 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.
(2) Basic per unit calculations include exchangeable shares which are
convertible into trust units on certain terms and conditions.
(3) Long-term debt, net of adjusted working capital excludes unrealized
losses on financial instruments and its related tax impact.
(4) Product prices include realized gains or losses on financial
instruments.
(5) Cash costs equal the total of operating, general and
administrative, and financing expenses.
(6) Operating netback equals production revenues including realized gains
or losses on financial instruments, less royalties, transportation and
operating expenses, calculated on a boe basis.


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Three Months ended
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June 30, March 31, December 31, September 30,
Trust Unit Trading Statistics 2008 2008 2007 2007
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($ per unit, except volume)
High 37.64 31.35 31.85 31.38
Low 28.96 24.24 24.14 27.25
Close 37.45 29.85 28.50 29.02
Average Daily Volume 329,638 231,949 275,892 177,752
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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 and six months ended June 30, 2008. The results for the second quarter of 2008 represents twenty consecutive quarters of profitability for Bonavista since commencing operations as an energy trust in July 2003. The continued execution of Bonavista's proven strategies in the first half of 2008 are a testament to the validity and effectiveness of an operationally and technically focused energy trust. The first half results for 2008 are also highlighted by an active and successful drilling and acquisitions program, which has led to increased production and attractive reserve addition costs. In 2008, Bonavista plans to spend approximately $475 million on its conventional drilling and acquisition programs, drilling 220 to 230 wells, and forecasted production of approximately 54,300 boe per day. In addition, for the remainder of the year Bonavista plans to invest up to $20 million in resource land purchases and applying new technology towards resource play development. The current dynamic environment continues to benefit Bonavista, given our significant financial flexibility and opportunity rich land base within the Western Canadian Sedimentary Basin.

Other significant accomplishments for Bonavista in the first half of 2008 include:

- Operationally, production volumes averaged 51,598 boe per day during the second quarter of 2008, despite experiencing significant downtime from plant turnarounds which impacted production volumes by approximately 2,800 boe per day. Production volumes averaged 52,998 boe per day for the first half of 2008;

- Maintained an active capital program during both the second quarter of 2008 and first half of 2008. In the second quarter of 2008 Bonavista invested $62.2 million in exploitation and development activities by drilling 28 wells with an overall 96% success rate. In addition, Bonavista spent $4.8 million on synergistic acquisitions within our core regions. For the first six months of 2008, Bonavista invested $155.4 million in exploitation and development activities, drilling 97 wells with an overall 94% success rate and completed seven acquisitions for $174.1 million;

- Drilled 12 successful horizontal wells, year to date, on the highly prospective, light oil Bakken trend in our Southeast Saskatchewan area with very favourable results. In addition to our Bakken resource initiatives, we have identified several additional resource plays to pursue in the coming months using horizontal drilling and multi-stage fracture stimulation technology;

- On January 14, 2008 Bonavista completed a $171 million acquisition of producing and undeveloped oil and natural gas properties (61% natural gas weighted) in the greater Willesden Green area. This acquisition further complements the property acquisition that we completed in the third quarter of 2007 and our pre-existing assets in this area. We now have a concentrated position in this area with current production over 5,500 boe per day. There is also significant exploitation and optimization opportunities remaining to be developed on these lands;

- Continued to actively participate at crown land sales and freehold purchases, investing $11.7 million in land activity during the first half of 2008, further enhancing our future drilling prospect inventory to more than three years;

- Generated record funds from operations of $183.9 million ($1.62 per unit) in the second quarter of 2008 and $339.0 million ($3.06 per unit) in the first half of 2008. Of the total funds from operations generated in the respective periods, Bonavista distributed 46% of these funds in the second quarter and 48% of these funds for the first half of 2008 to Unitholders with the remaining funds reinvested in the business to continue growing our production base;

- Continued to record strong profitability in both the second quarter and first half of 2008 with a strong average return on equity of 35% and 32% respectively, and a strong net income to funds from operations ratio of 57% and 56% respectively. The above ratios reflect net income adjusted to negate the after tax impact of the unrealized gains and losses on financial instruments;

- Within the energy trust industry, Bonavista delivered attractive total returns of 38% to our Unitholders in the first half of 2008 and currently has a cash-on-cash yield of 11%. In addition, Bonavista has delivered cumulative distributions of $1.3 billion or $17.31 per trust unit since the inception of our Trust. These cumulative distributions are in excess of our initial closing trading price of $15.85 on the day we became an energy trust on July 2, 2003; and

- On April 29, 2008 Bonavista completed a $214.0 million equity financing which improves financial flexibility to pursue future growth opportunities through expansions in our drilling and acquisitions programs.

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 generate economic prospects on our asset base within the Western Canadian Sedimentary Basin. Our experienced and consistent technical teams have a solid understanding of our assets 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. Combined, all of these attributes 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 a record of 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, together with a strong Board of Directors, possess 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 August 7, 2008. Our audited consolidated financial statements, Annual Report, and other disclosure documents for 2007 are available 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 including; (i) forecasted capital expenditures; (ii) exploration, drilling and development plans; (iii) anticipated production rates; (iv) expected royalty rate; (v) annualized debt to funds from operations; (vi) funds from operations, (vii) anticipated operating costs; and (viii) interest expense per boe, which are provided to allow investors to better understand our business. 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 an 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 first six months of 2008 led to the drilling of 97 wells in our four core regions with an overall success rate of 94%. This program resulted in 34 natural gas wells, 57 oil wells and six dry holes. Bonavista continues to emphasize higher impact drilling opportunities particularly in the Bakken play in our Southeast Saskatchewan area and our South Central core region in Alberta, where we have experienced excellent success and attractive finding and development costs over the past couple of years. These activities have also continued to lengthen our reserve life index and the predictability in our overall production base. In addition to the exploitation and development program, Bonavista executed seven complementary acquisitions in its core regions during the first half of 2008.
Production - For the second quarter of 2008, production increased to 51,598 boe per day when compared to 51,533 boe per day for the same period in 2007. Production in the second quarter exceeded initial expectations but was curtailed by approximately 2,800 boe per day primarily due to two significant planned turnarounds at third party gas facilities and normal spring breakup conditions. Natural gas production increased to 172 mmcf per day in the second quarter of 2008 from 171 mmcf per day for the same period a year ago, while total oil and liquids production increased to 22,974 bbls per day in the second quarter of 2008 (comprised of 16,659 bbls per day of light and medium oil and 6,315 bbls per day of heavy oil) from 22,964 bbls per day (comprised of 15,868 bbls per day of light and medium oil and 7,096 bbls per day of heavy oil) for the same period in 2007. Our current production is approximately 54,000 boe per day consisting of 54% natural gas, 33% light and medium oil and 13% heavy oil. Production for the six months ended June 30, 2008, increased 2% to 52,998 boe per day when compared to 51,792 boe per day for the same period in 2007. Natural gas production increased 2% to 175 mmcf per day in the first six months of 2008 from 172 mmcf per day for the same period a year ago, while total oil and liquids production increased 3% to 23,834 bbls per day in the first six months of 2008 (comprised of 17,199 bbls per day of light and medium oil and 6,635 bbls per day of heavy oil) from 23,198 bbls per day (comprised of 16,070 bbls per day of light and medium oil and 7,128 bbls per day of heavy oil) for the same period in 2007. Bonavista's diversified commodity investment approach minimizes our dependence on any one product. We anticipate production volumes in 2008 to average approximately 54,300 boe per day.

Revenues - Revenues, excluding gains and losses on financial instruments, for the second quarter of 2008 increased by 62% to $361.6 million when compared to $223.9 million in the second quarter of 2007 primarily due to higher average commodity prices. In the second quarter of 2008, natural gas prices increased 31% to $9.62 per mcf, when compared to $7.35 per mcf realized in the same period in 2007. The average oil and liquids price increased 56% to $81.94 per bbl (comprised of $84.26 per bbl for light and medium oil and $75.83 per bbl for heavy oil) in the second quarter of 2008 from $52.66 per bbl (comprised of $57.38 per bbl for light and medium oil and $42.09 per bbl for heavy oil) for the same period in 2007. Revenues, excluding gains and losses on financial instruments, for the six months ended June 30, 2008 increased by 47% to $657.9 million when compared to $449.1 million for the same period a year ago due to higher average commodity prices and increased production volumes. In the first half of 2008, natural gas prices increased 15% to $8.73 per mcf, compared to $7.61 per mcf realized in the same period in 2007. The average oil and liquids price increased 46% to $75.05 per bbl (comprised of $76.86 per bbl for light and medium oil and $70.34 per bbl for heavy oil) in the first half of 2008 from $51.34 per bbl (comprised of $55.74 per bbl for light and medium oil and $41.44 per bbl for heavy oil) for the same period in 2007.

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.

In the second quarter of 2008, our risk management program on financial instruments resulted in a net loss of $148.2 million, consisting of a realized loss of $40.0 million and an unrealized loss of $108.2 million. The realized loss of $40.0 million consisted of a $1.2 million loss on natural gas commodity derivative contracts and a $38.8 million loss on crude oil commodity derivative contracts. For the six months ended June 30, 2008, our risk management program on financial instruments resulted in a net loss of $181.9 million consisting of a realized loss of $54.2 million and an unrealized loss of $127.7 million. The realized loss consisted of a $887,000 loss on natural gas commodity derivative contracts and a $53.3 million loss on crude oil commodity derivative contracts. A summary of commodity price risk management contracts in place as at June 30, 2008 and subsequent to June 30 2008, is included in note 7 of the consolidated financial statements.

Royalties - For the three months ended June 30, 2008, royalties increased 91% to $73.0 million from $38.2 million for the same period a year ago, largely attributed to an increase in commodity prices and 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 second quarter of 2008 increased to 22.7% compared to 17.0% in 2007 for similar reasons discussed above and the result of realized losses on financial instruments. For the three months ended June 30, 2008, royalties by product as a percentage of revenues (including realized gains and losses on financial instruments) were 23.4% for natural gas, 21.6% for light and medium oil and 23.6% for heavy oil. In the second quarter of 2007, royalties by product, as a percentage of revenue (including realized gains and losses on financial instruments) were 17.8% for natural gas, 16.5% for light and medium oil and 15.4% for heavy oil. For the six months ended June 30, 2008, royalties also increased significantly by 69% to $130.5 million from $77.2 million for the same period a year ago, for similar reasons discussed above. In addition, royalties as a percentage of revenue (including realized gains and losses on financial instruments) for the six month period also increased from 17.1% in 2007 to 21.6% in 2008, for the same reasons as discussed above. For the six months ended June 30, 2008, royalties by product as a percentage of revenue (including realized gains and losses on financial instruments) were 22.2% for natural gas, 20.9% for light and medium oil and 21.6% for heavy oil. For the six months ended June 30, 2007, royalties by product, as a percentage of revenues including realized gains and losses on financial instruments were 18.2% for natural gas, 16.4% for light and medium oil and 14.4% for heavy oil.

On October 25, 2007, the Alberta Government announced the New Royalty Framework ("NRF") which is proposed to take effect on January 1, 2009. The proposed NRF includes new royalty formulas for conventional oil and natural gas that will operate on sliding scales that are determined by commodity prices and well productivity. The Government of Alberta, on April 10, 2008, provided some further clarification on the NRF and introduced two new royalty programs related to the development of deep oil and natural gas reserves. The Trust has reviewed the information that is currently available and has determined that the impact of these changes may increase our existing average corporate royalty rate by approximately 3% to 4%. Bonavista will continue to assess the impact that the NRF will have on existing operations when legislation is finalized or as more information becomes available.

Operating expenses - Operating expenses for the second quarter of 2008 increased 11% to $44.0 million compared to $39.7 million for the same period a year ago. Operating costs increased primarily due to spring breakup conditions, two significant planned turnarounds at third party gas facilities and the continuation of industry wide operating cost increases, primarily driven by higher fuel, power, chemical and labour costs. These factors resulted in average per unit operating costs increasing by 11% for the three months ended June 30, 2008, to $9.37 per boe from $8.46 per boe in the comparable period of 2007. Operating costs by product for the second quarter of 2008 were $1.36 per mcf for natural gas, $9.93 per bbl for light and medium oil and $13.35 per bbl for heavy oil compared to $1.21 per mcf for natural gas, $9.14 per bbl for light and medium oil and $12.28 per bbl for heavy oil for the same period in 2007. Operating expenses for the first half of 2008 increased 12% to $88.4 million compared to $78.7 million for the same period a year ago. The increase in operating costs are for similar reasons noted above. Average per unit operating costs increased 9% for the six months ended June 30, 2008, to $9.16 per boe from $8.40 per boe in the comparable period of 2007. Operating costs by product for the first half of 2008 were $1.30 per mcf for natural gas, $9.84 per bbl for light and medium oil and $13.37 per bbl for heavy oil compared to $1.18 per mcf for natural gas, $9.06 per bbl for light and medium oil and $12.14 per bbl for heavy oil for the same period in 2007. As a result of the increasing cost pressures noted in the first half of 2008, we anticipate our operating costs will average approximately $9.20 per boe in 2008. Notwithstanding these cost increases, Bonavista continues to experience one of the lowest operating costs of any producer in the energy trust sector and continues to look for innovative ways to reduce costs in the future.

Transportation expenses - For the three months ended June 30, 2008, transportation expenses decreased 13% to $9.0 million ($1.91 per boe) when compared to $10.3 million ($2.19 per boe) for the same period last year. The 13% decrease in transportation expenses on a per boe basis was primarily due to a decrease in natural gas transportation costs because of the expiry of certain firm export service obligations. For similar reasons, transportation costs for the six months ended June 30, 2008 decreased 7% to $19.0 million ($1.97 per boe) compared to $20.4 million ($2.18 per boe) for the same period a year ago. Transportation expenses by product for the second quarter of 2008 were $0.37 per mcf for natural gas, $0.86 per bbl for light and medium oil and $3.31 per bbl for heavy oil compared to $0.44 per mcf for natural gas, $0.99 per bbl for light and medium oil and $3.16 per bbl for heavy oil for the second quarter of 2007. For the first half of 2008 transportation expenses by product were $0.39 per mcf for natural gas, $0.85 per bbl for light and medium oil and $3.32 per bbl for heavy oil compared to $0.43 per mcf for natural gas, $0.97 per bbl for light and medium oil and $3.19 per bbl for heavy oil for the same period a year ago.

General and administrative expenses - General and administrative expenses, after overhead recoveries, increased 9% to $3.5 million for the three months ended June 30, 2008 from $3.2 million in the same period in 2007 and increased 12% to $7.0 million for the six months ended June 30, 2008 from $6.2 million in the same period in 2007. On a per boe basis, general and administrative expenses increased 9% for the three months ended June 30, 2008 to $0.74 per boe from $0.68 per boe in the same period in 2007 and increased 7% for the six months ended June 30, 2008 to $0.72 per boe from $0.67 per boe in the same period in 2007. These increases are largely due to the higher staffing levels required to manage our operations and increasing cost pressures currently experienced throughout our industry. In addition, through the services agreement with NuVista Energy Ltd., Bonavista provides certain administrative activities. The fee charged under this agreement was $373,000 for the three months ended June 30, 2008 as compared to $370,000 in the same period in 2007 and $786,000 for the six months ended June 30, 2008 as compared to $712,000 for the same period in 2007. In connection with its Trust Unit Incentive Rights Plan, Bonavista also recorded a unit-based compensation charge of $2.5 million and $4.8 million for the three and six months ended June 30, 2008 respectively, compared to $1.4 million and $2.8 million for the same periods in 2007.

Financing expenses - Financing expenses, which include interest expense on long-term debt and convertible debentures, increased 14% to $8.2 million for the three months ended June 30, 2008, from $7.2 million for the same period in 2007 and, on a boe basis, increased 14% to $1.75 per boe for the three months ended June 30, 2008 from $1.54 per boe for the same period in 2007. For the six months ended June 30, 2008, financing expenses increased 34% to $19.8 million from $14.8 million for the same period in 2007 and on a boe basis increased to $2.05 per boe for the first half of 2008 from $1.58 per boe in the same period in 2007. These increases are due to increased debt levels used to fund Bonavista's capital program. With the impact of Bonavista's recently completed equity financing, we expect the interest expense to decrease on a per boe basis during the last half of 2008. During the second quarter of 2008, Bonavista paid cash interest of $9.2 million compared to $7.8 million in 2007. For the six months ended June 30, 2008, Bonavista paid cash interest of $20.1 million compared to $15.0 million for the same period in 2007.

Depreciation, depletion and accretion expenses - Depreciation, depletion and accretion expenses increased 13% to $64.0 million for the three months ended June 30, 2008 from $56.6 million in the same period of 2007. For the six months ended June 30, 2008 depreciation, depletion and accretion expenses also increased 15% to $129.3 million from $112.0 million. Both increases were due to higher costs of finding and developing reserves and a larger asset base in 2008. For the three months ended June 30, 2008, the average cost increased to $13.62 per boe from $12.06 per boe for the same period in 2007 and for the six months ended June 30, 2008 the average cost increased to $13.41 per boe from $11.95 for the same period a year ago. The increase in depreciation, depletion and accretion expenses are due to increased costs associated with adding new reserves. Over the past few years our industry has seen cost escalation in all areas of activities.

Income taxes - For the three months ended June 30, 2008, the provision for income tax was a recovery of $20.0 million compared to a $38.0 million provision for the same period in 2007. For the six months ended June 30, 2008, the provision for income tax was a recovery of $24.3 million compared to $35.1 million for the same period in 2007. Bonavista made no cash payments relating to installments for either of the three or six months ended June 30, 2008, or for the comparative periods in 2007.

On February 26, 2008, the Federal government announced that the provincial component of the SIFT tax is to be determined based on the general corporate provincial tax rate in each province that the Trust has a permanent establishment. On June 18, 2008, the legislation to re-define the provincial component of the tax rate was passed. However, the specific rules governing how the provincial component is to be calculated was released in draft on July 14, 2008 and is therefore not considered to be substantively enacted as at June 30, 2008. As a result, any changes in the tax rate for the Trust's future income tax has not been reflected in these financial statements.

Funds from operations, net income and comprehensive income - For the three months ended June 30, 2008, Bonavista experienced a 46% increase in funds from operations to $183.9 million ($1.62 per unit, basic) from $126.1 million ($1.20 per unit, basic) for the same period in 2007. For the six month period ended June 30, 2008, Bonavista experienced a 33% increase in funds from operations to $339.0 million ($3.06 per unit, basic) from $254.6 million ($2.43 per unit, basic) for the same period in 2007. Funds from operations increased for the three and six months ended June 30, 2008 primarily due to higher commodity prices. Net income for the three months ended June 30, 2008, decreased 14% to $29.3 million ($0.26 per unit, basic) from $33.9 million ($0.32 per unit, basic) for the same period in 2007. For the six months ended June 30, 3008, net income increased 6% to $101.6 million ($0.92 per unit, basic) from $95.6 million ($0.91 per unit, basic) in the first half of 2007. Other comprehensive income for the three months ended June 30, 2008 included a charge of nil (2007 - $1.3 million) relating to the amortization of the amount recognized in accumulated other comprehensive income January 1, 2007 for the fair value of financial instruments on adoption of the new accounting standards for financial instruments. This resulted in a total comprehensive income for the three months ended June 30, 2008 of $29.3 million (2007 - $32.7 million). Other comprehensive income for the six months ended June 30, 2008 included a charge of nil (2007 - $2.7 million) 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 in the first half of 2008 of $101.6 million (2007 - $92.9 million).

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



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Three Months
ended June 30,
Calculation of Funds From Operations: 2008 2007
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(thousands)
Cash flow from operating activities $ 183,912 $ 126,111
Asset retirement expenditures (4,204) (1,093)
Changes in non-cash working capital 986 (8,008)
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Funds from operations $ 180,694 $ 117,010
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Capital expenditures - Capital expenditures for the three month period ended June 30, 2008 were $66.9 million, consisting of $62.2 million on exploitation and development spending and $4.7 million on net property acquisitions. For the same period in 2007 capital expenditures were $67.6 million, consisting of $67.7 million on exploitation and development spending and $155,000 of net property dispositions. Capital expenditures for the six month period ended June 30, 2008 were $329.6 million, consisting of $155.4 million on exploitation and development spending and $174.2 million on property acquisitions. For the same period in 2007 capital expenditures were $159.1 million, consisting of $158.3 million on exploitation and development spending and $810,000 on net acquisitions. With the industry experiencing cost reductions in many of its services due to lower industry activity levels in the first half of 2008, Bonavista too benefited with its active drilling program which is generating production addition costs at attractive levels of less than $35,000 boe/d. In 2008 we continue to generate favourable economic returns from our capital expenditure program as a direct result of relatively stable service costs coupled with strong commodity prices.

Liquidity and capital resources - As at June 30, 2008, long-term debt including working capital (excluding unrealized losses on financial instruments and related tax impact), was $631.9 million with a debt to 2008 annualized funds from operations ratio of 0.9:1. Bonavista has significant flexibility to finance future expansions of its capital programs or acquisition opportunities as they arise, through the use of its bank credit facility of $1.0 billion of which $368.1 million is unused borrowing capability and the use of its funds from operations, or through a combination of both bank debt and funds from operations.

In 2008, Bonavista plans to invest approximately $475 million on its conventional capital programs to expand its core regions, which will be financed through a combination of funds from operations, recent equity issuance 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.

Unitholders' equity - As at June 30, 2008, Bonavista had 116.3 million equivalent trust units outstanding. This includes 12.2 million exchangeable shares, which are exchangeable into 22.3 million trust units. The exchange ratio in effect at June 30, 2008 for exchangeable shares was 1.82966:1. As at August 7, 2008, Bonavista had 116.6 million equivalent trust units outstanding. This includes 12.2 million exchangeable shares, which are exchangeable into 22.4 million trust units. The exchange ratio in effect at August 7, 2008 for exchangeable shares was 1.84491:1. In addition, Bonavista has 3.2 million trust unit incentive rights outstanding at August 7, 2008, with an average exercise price of $27.10 per trust unit.

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 three months ended June 30, 2008 the Trust declared distributions of $84.3 million ($0.90 per trust unit) compared to $76.8 million ($0.90 per trust unit) in the same period in 2007. For the six months ended June 30, 2008 the Trust declared distributions of $161.9 million ($1.80 per trust unit) compared to $153.3 million ($1.80 per trust unit) in the same period in 2007. Due to recent price volatility, coupled with a slight expansion to our capital program targeting unconventional resource potential, we have elected to maintain our current monthly distribution. We will continuously monitor all the factors influencing our distribution rate and the necessity to adjust the monthly distribution in the future.

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 three months ended June 30, 2008, the non-cash charges amounted to $154.6 million compared to $92.2 million for the same period in 2007. For the six months ended June 30, 2008, the non-cash charges amounted to $237.5 million compared to $159.1 million for the same period in 2007. 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 natural 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
ended June 30,
Distribution Analysis 2008 2007
----------------------------------------------------------------------------
(thousands)

Cash flow provided from operating activities $ 183,912 $ 126,111
Net income 29,282 33,936
Distributions declared 84,282 76,757
Excess of cash flow provided from operating
activities over distributions declared 99,630 49,354
Excess (shortfall) of net income over
distributions declared (55,000) (42,821)
----------------------------------------------------------------------------


Bonavista announces its distribution policy on a quarterly basis. Distributions are determined by the Board of Directors and are dependent upon the commodity price environment, production levels, and the amount of capital expenditures to be financed from funds from operations. Bonavista's current monthly distribution rate is $0.30 per unit. This monthly distribution is comprised of the base distribution of $0.28 per unit plus a supplementary distribution of $0.02 per unit, due to the average realized commodity prices in excess of budget prices. The 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 unit per month places us slightly below 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 September 30, 2006 to June 30, 2008:



----------------------------------------------------------------------------
2008 2007
-------------------------------------------------
June 30 March 31 December 31 September 30
-------------------------------------------------
($ thousands, except
per unit amounts)
Production revenues 361,555 296,387 242,361 219,885
Net income 29,282 72,298 63,631 58,990
Net income per unit:
Basic 0.26 0.67 0.60 0.56
Diluted 0.26 0.67 0.59 0.55
----------------------------------------------------------------------------
----------------------------------------------------------------------------

----------------------------------------------------------------------------
2007 2006
-------------------------------------------------
June 30 March 31 December 31 September 30
-------------------------------------------------
($ thousands, except
per unit amounts)
Production revenues 223,878 225,222 220,484 227,270
Net income 33,936 61,630 67,635 70,800
Net income per unit:
Basic 0.32 0.59 0.65 0.69
Diluted 0.32 0.59 0.65 0.68
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Production revenue, excluding gains and losses on financial instruments was 62% higher in the second quarter of 2008 versus the second quarter of 2007, primarily due to higher average product prices. Net income decreased 14% in the second quarter of 2008 as compared to the second quarter of 2007. The decrease in net income in the second quarter of 2008 is attributed to a $148.2 million loss on financial instruments consisting of a $40.0 million realized loss and an unrealized loss of $108.2 million as compared to a $4.7 million gain consisting of a $834,000 realized gain and an unrealized gain of $3.9 million in the same period in 2007. The large decrease in net income in the second quarter of 2007 is primarily attributable to the non-cash future income tax charge to net income of $41.0 million to reflect changes to income tax legislation, substantially enacted in the second quarter of 2007.

Disclosure and internal controls - Disclosure controls and procedures have been designed to ensure that information required to be disclosed by Bonavista is accumulated and communicated to management, as appropriate, to allow timely decisions regarding required disclosures. The Chief Executive Officer and Chief Financial Officer have concluded, as of the end of the period covered by the interim filings, that Bonavista's disclosure controls and procedures are effectively designed to provide reasonable assurance that material information related to the issuer is made known to them by others within the Trust. It should be noted that while the Trust's Chief Executive Officer and Chief Financial Officer believe that the disclosure controls and procedures provide a reasonable level of assurance that they are effective, they do not expect that the disclosure controls and procedures or internal control over financial reporting will prevent all errors and fraud. A control system, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objective of the control system is met.

Update on regulatory and financial reporting matters - On April 18, 2008, the Canadian Securities Administrators published the notice and request for comments for the proposed repeal and replacement of Multilateral Instrument 52-109 Certification of Disclosure in Issuers' Annual and Interim filings. The proposed changes would include the requirement to provide certification of internal controls over financial reporting for years ending after December 15, 2008.

Effective January 1, 2008, Bonavista adopted Canadian Institute of Chartered Accountants ("CICA") Section 3862, "Financial Instruments - Disclosures", Section 3863, "Financial Instruments - Presentation" and Section 1535, "Capital Disclosure". The first two sections establish standards for the presentation and disclosure of information that enables users to evaluate the significance of financial instruments to the entity's financial position, and the nature and extent of risks arising from financial instruments and how the entity manages the risks. The last section establishes standards for disclosing information about an entity's capital and how it is managed. The Trust will also be required to adopt Section 3064 "Goodwill and Intangible Assets" on January 1, 2009, which defines the criteria for the recognition of intangible assets.

On February 13, 2008, 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 and is implementing plans for transition.

OUTLOOK

As we enter into our eleventh year since restructuring the Company in 1997, and our sixth year since converting to an energy trust, we continue to benefit from all of the same qualities that drove the success of Bonavista as a public company and an energy trust. We apply a similar proven strategy and execute this strategy in a disciplined and cost-effective manner much the same as in 1997 when we started on our mission of creating value for our stakeholders. The foundation of this strategy is to actively pursue low to medium risk drilling opportunities on our extensive undeveloped land base within geographically concentrated areas of operations. Despite a very active exploitation and development program over the past few years, the quality and quantity of our drilling opportunities continues to increase as we progress through 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 and have been successful in strategic acquisition opportunities where we can add value utilizing our own technical expertise. Over the last winter, we witnessed acquisition prices decreasing to a level that compared favourably with our cost of adding reserves organically and we acted on this by completing a significant, natural gas-weighted, property acquisition in January 2008. Since that time, natural gas prices have improved substantially. Our timely and prudent approach to capital investments 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 and a half year history.

For 2008, Bonavista is planning to invest $475 million into its conventional capital programs. The focus of this capital program will be directed to Bonavista's exploration, exploitation and development programs which include drilling approximately 220 to 230 wells, along with strategic property acquisitions, the majority of which have already been completed. In addition, Bonavista plans to invest up to $20 million in undeveloped land with future resource potential and applying new technology towards resource play development. Bonavista has currently identified approximately 700 drilling prospects on its current land base and remains flexible to consider accelerating the drilling of some of these prospects in the latter part of 2008 should commodity prices stabilize at attractive levels. It is anticipated that this capital program should result in Bonavista's 2008 production volumes averaging approximately 54,300 boe per day. This level of production factors in significant downtime experienced in the second and third quarters, primarily due to major third party plant turnarounds and normal spring break-up curtailments. Assuming commodity prices of CDN$8.30 per GJ of natural gas (AECO), US$120.00 per bbl of crude oil (WTI) and CDN$/US$ exchange rate of $0.987, Bonavista now anticipates 2008 funds from operations to increase to approximately $730 to $740 million. Bonavista will continue to conduct its operations prudently and remain opportunistic to further expand its capital programs on additional property or land acquisitions and/or drilling opportunities as they present themselves.

We are extremely proud of our achievements over the past ten and a half years and remain enthusiastic 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 legal structure may ultimately change by 2011 when the new tax laws become effective, but our proven strategy will not change under this new tax regime nor the provincial government's new royalty regime. Our team remains dedicated to add Unitholder value in the oil and natural gas business, regardless of the changing landscape.



----------------------------------------------------------------------------
Consolidated Balance Sheets June 30, December 31,
(thousands) 2008 2007
----------------------------------------------------------------------------
(unaudited)
Assets:
Current assets:
Accounts receivable $ 131,633 $ 125,390
Future income tax asset 51,824 13,517
----------------------------------------------------------------------------
183,457 138,907
Oil and natural gas properties and equipment 2,287,587 2,074,993
Goodwill 41,321 41,321
----------------------------------------------------------------------------

$ 2,512,365 $ 2,255,221
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Liabilities and Unitholders' Equity:
Current liabilities:
Accounts payable and accrued liabilities $ 128,129 $ 78,469
Distributions payable 28,243 25,729
Unrealized losses on financial instruments 172,745 45,058
----------------------------------------------------------------------------
329,117 149,256
Long-term debt 607,132 712,654
Convertible debentures 44,469 48,830
Asset retirement obligations 121,130 116,893
Future income taxes 177,963 166,621
Unitholders' equity:
Unitholders' capital and debenture conversion
component 1,085,535 851,685
Exchangeable shares 74,381 74,710
Contributed surplus 7,712 9,369
Accumulated earnings 64,926 125,203
----------------------------------------------------------------------------
1,232,554 1,060,967
----------------------------------------------------------------------------
$ 2,512,365 $ 2,255,221
----------------------------------------------------------------------------
----------------------------------------------------------------------------

See accompanying notes to the consolidated financial statements.


----------------------------------------------------------------------------
Consolidated Statements of Operations, Comprehensive Income and Accumulated
Earnings
(thousands, except per unit amounts) Three Months Six Months
ended June 30, ended June 30,
2008 2007 2008 2007
----------------------------------------------------------------------------
(unaudited)
Revenues:
Production $ 361,555 $223,878 $ 657,942 $ 449,100
Royalties (72,999) (38,227) (130,450) (77,242)
----------------------------------------------------------------------------

288,556 185,651 527,492 371,858
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Realized gains (losses) on
financial instruments (39,967) 834 (54,250) 2,905
Unrealized gains (losses) on
financial instruments (108,224) 3,830 (127,688) (9,175)
----------------------------------------------------------------------------

(148,191) 4,664 (181,938) (6,270)
----------------------------------------------------------------------------
140,365 190,315 345,554 365,588
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Expenses:
Operating 44,005 39,683 88,400 78,726
Transportation 8,977 10,289 19,043 20,409
General and administrative 3,455 3,181 6,974 6,236
Financing 8,240 7,221 19,781 14,769
Unit-based compensation 2,460 1,421 4,773 2,833
Depreciation, depletion and
accretion 63,965 56,568 129,331 111,993
----------------------------------------------------------------------------
131,102 118,363 268,302 234,966
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Income before taxes 9,263 71,952 77,252 130,622
Income taxes (reductions) (20,019) 38,016 (24,328) 35,056
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Net income 29,282 33,936 101,580 95,566
Changes in comprehensive income,
net of taxes - (1,251) - (2,701)
----------------------------------------------------------------------------

Comprehensive income 29,282 32,685 101,580 92,865
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Accumulated earnings, beginning of
period 119,926 199,511 125,203 214,417
Distributions declared (84,282) (76,757) (161,857) (153,293)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Accumulated earnings, end of
period $ 64,926 $156,690 $ 64,926 $ 156,690
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net income per unit - basic $ 0.26 $ 0.32 $ 0.92 $ 0.91
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net income per unit - diluted $ 0.26 $ 0.32 $ 0.92 $ 0.91
----------------------------------------------------------------------------
----------------------------------------------------------------------------

See accompanying notes to the consolidated financial statements.


----------------------------------------------------------------------------
----------------------------------------------------------------------------
Consolidated Statements of Cash Flows
(thousands) Three Months Six Months
ended June 30, ended June 30,
2008 2007 2008 2007
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(unaudited)
Cash provided by (used in):
Operating Activities:
Net income $ 29,282 $ 33,936 $ 101,580 $ 95,566
Items not requiring
cash from operations:
Depreciation, depletion
and accretion 63,965 56,568 129,331 111,993
Unit-based compensation 2,460 1,421 4,773 2,833
Unrealized (gains) losses
on financial instruments 108,224 (3,830) 127,688 9,175
Future income taxes
(reductions) (20,019) 38,016 (24,328) 35,056
Asset retirement
expenditures (4,204) (1,093) (7,122) (1,473)
Changes in non-cash
working capital items 986 (8,008) 13,421 (4,273)
----------------------------------------------------------------------------
180,694 117,010 345,343 248,877
----------------------------------------------------------------------------
Financing Activities:
Issuance of equity, net
of issue costs 214,401 3,361 219,103 6,371
Distributions (81,915) (76,662) (159,343) (153,106)
Changes in long-term debt (248,772) 29,810 (105,522) 60,252
Changes in non-cash
working capital items (989) (534) (326) (271)
----------------------------------------------------------------------------
(117,275) (44,025) (46,088) (86,754)
----------------------------------------------------------------------------
Investing Activities:
Exploitation and
development (62,166) (67,715) (155,431) (158,331)
Property acquisitions (5,454) 55 (174,828) (910)
Property dispositions 683 100 683 100
Changes in non-cash working
capital items 3,518 (5,425) 30,321 (2,982)
----------------------------------------------------------------------------
(63,419) (72,985) (299,255) (162,123)
----------------------------------------------------------------------------

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 three and six months ended June 30, 2008 (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.

The unaudited consolidated financial statements include the accounts of the Trust and its wholly-owned subsidiaries and partnerships, and have been prepared by management in accordance with Canadian Generally Accepted Accounting Principles. The interim consolidated financial statements and notes should be read in conjunction with the consolidated financial statements for the year ended December 31, 2007. Certain amounts have been reclassified to conform to the current period's presentation.

1. Changes in accounting policy:

a) Financial instruments

On January 1, 2008, the Trust adopted CICA Handbook Section 3862, "Financial Instruments - Disclosures", and Section 3863, "Financial Instruments - Presentation". Section 3862 and 3863 establish standards for the presentation and disclosure of information that enable users to evaluate the significance of financial instruments to the entity's financial position, and the nature and extent of risks arising from financial instruments and how the entity manages these risks. The implementation of these standards did not impact the Trust's financial results, however it did result in additional disclosure presented in note 7 of the Trust's notes to the consolidated financial statements.

b) Capital disclosures

On January 1, 2008, the Trust adopted CICA Handbook Section 1535 "Capital Disclosures". Section 1535 establishes standards for disclosing information about an entity's capital and how it is managed. This section specifies disclosure about objectives, policies and processes for managing capital, quantitative data about what an entity regards as capital, whether an entity has complied with all capital requirements, and if it has not complied, the consequences of such non-compliances. The implementation of this standard did not impact the Trust's financial results, however it did result in additional disclosure presented in note 8 of the Trust's notes to the consolidated financial statements.

c) Goodwill

As of January 1, 2009, the Trust will be required to adopt CICA Handbook Section 3064 "Goodwill and Intangible Assets", which defines the criteria for the recognition of intangible assets. This new standard is not expected to have a material impact on the Trust's consolidated financial statements.

d) International Financial Reporting Standards

On February 13, 2008, Canada's Accounting Standards Board confirmed January 1, 2011 as the effective date for the convergence of Canadian GAAP to International Financial Reporting Standards ("IFRS"). The Canadian Securities Administrators are in the process of examining the changes to securities rules as a result of this initiative. The Trust continues 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 three months ended June 30, 2008 Bonavista charged NuVista $373,000 (2007 - $370,000) in fees relating to general and administrative services provided to NuVista, in addition NuVista charged Bonavista management fees for a jointly owned partnership totaling $337,500 (2007 - nil). For the six months ended June 30, 2008 Bonavista charged NuVista $786,000 (2007 - $712,000) in fees relating to general and administrative services provided to NuVista, in addition NuVista charged Bonavista management fees for a jointly owned partnership totaling $675,000 (2007 - nil). Bonavista also charged NuVista $71,800 (2007 - $604,000) for costs that are outside the TSA during the first six months of 2008 relating to NuVista's share of direct charges from third parties. As at June 30, 2008, the amount payable to NuVista was $2.2 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. The Trust estimates the total undiscounted amount of expenditures required to settle its asset retirement obligations is approximately $556.7 million (2007 - $487.4 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% (2007 - 7.5%) and an inflation rate of 2% (2007 - 2%) were used to calculate the fair value of the asset retirement obligations.

A reconciliation of the asset retirement obligations is provided below:



----------------------------------------------------------------------------
Six Months
ended June 30,
2008 2007
----------------------------------------------------------------------------
(thousands)
Balance, beginning of period $ 116,893 $ 96,324

Accretion expense 4,190 3,429
Liabilities incurred 4,682 492
Liabilities acquired 2,487 -
Liabilities settled (7,122) (1,473)
----------------------------------------------------------------------------

Balance, end of period $ 121,130 $ 98,772
----------------------------------------------------------------------------
----------------------------------------------------------------------------


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 six months ended June 30, 2008 include interest on bank loans of $18.1 million (2007 - $12.9 million) and convertible debentures of $1.7 million (2007 - $1.8 million). For the six months ended June 30, 2008, Bonavista paid cash interest of $20.1 million (2007 - $15.0 million). For the six months ending June 30, 2008 our effective interest rate was 4.4% (2007 - 5.0%).

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 June 30, 2008:



----------------------------------------------------------------------------
Debt Equity
Component Component
----------------------------------------------------------------------------
(thousands)
Balance, December 31, 2007 $ 48,830 $ 1,054
Accretion 33 -
Issue expenses related to conversions to trust
units 37 -
Amortization of issue expenses 346 -
Conversion to trust units (4,777) (98)
----------------------------------------------------------------------------

Balance, June 30, 2008 $ 44,469 $ 956
----------------------------------------------------------------------------
----------------------------------------------------------------------------


6. Unitholders' equity:

a) Authorized:

Unlimited number of voting trust units.

b) Issued and outstanding:

(i) Trust units:



----------------------------------------------------------------------------
Number Amount
----------------------------------------------------------------------------
(thousands)
Balance, December 31, 2007 85,757 $ 850,631
Issued for cash 7,000 214,200
Issued on conversion of convertible debentures 171 4,777
Issued on conversion of exchangeable shares 98 329
Issued upon exercise of trust unit incentive rights 904 15,967
Conversion of restricted trust units 53 -
Issue costs, related to debenture conversions - (37)
Issue costs, net of future tax benefit - (8,426)
Adjustment to equity component of debenture on
conversion - 98
Unit-based compensation - 7,040
----------------------------------------------------------------------------
Balance, June 30, 2008 93,983 $ 1,084,579
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(ii) Contributed surplus:

----------------------------------------------------------------------------
Amount
----------------------------------------------------------------------------
(thousands)
Balance, December 31, 2007 $ 9,369
Unit-based compensation expense 4,773
Unit-based compensation capitalized 610
Exercise of trust unit incentive rights and conversion of
restricted trust units (7,040)
----------------------------------------------------------------------------
Balance, June 30, 2008 $ 7,712
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(iii) Exchangeable shares:

----------------------------------------------------------------------------
Number Amount
----------------------------------------------------------------------------
(thousands)
Balance, December 31, 2007 12,230 $ 74,710
Exchanged for trust units (53) (329)
----------------------------------------------------------------------------
Balance, June 30, 2008 12,177 $ 74,381
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Exchange ratio, June 30, 2008 1.82966 -
----------------------------------------------------------------------------
Trust units issuable on exchange 22,279 $ 74,381
----------------------------------------------------------------------------
----------------------------------------------------------------------------


c) Long term incentive plans:

For the three months ended June 30, 2008 there were 10,540 restricted trust units granted and 106,800 trust unit incentive rights issued with an average exercise price of $29.70 per trust unit and an estimated fair value of $7.36 per trust unit. As at June 30, 2008 there were 114,566 restricted trust units outstanding and 2,750,225 trust unit rights outstanding with an average exercise price of $25.04 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 27%; a forfeiture rate of 10% and an expected life of 4.5 years.

d) 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 June 30, 2008
----------------------------------------------------------------------------
(thousands)
Trust units 91,356
Exchangeable shares converted at the exchange ratio 22,357
----------------------------------------------------------------------------
Basic equivalent trust units 113,713
Convertible debentures 1,775
Trust unit incentive rights 689
Restricted trust units 115
----------------------------------------------------------------------------
Diluted equivalent trust units 116,292
----------------------------------------------------------------------------
----------------------------------------------------------------------------


For the purposes of calculating net income per trust unit on a diluted basis, the net income has been increased by $1.0 million (2007 - $1.1 million) with respect to the accretion, amortization and interest expense on the convertible debentures.

7. Financial instruments:

The Trust has exposure to credit, liquidity and market risks from its use of financial instruments. This note provides information about the Trust's exposure to each of these risks, the Trust's objectives, policies and processes for measuring and managing risk. Further quantitative disclosures are included throughout these financial statements.

The Board of Directors has overall responsibility for the establishment and oversight of the Trust's risk management framework. The Board has implemented and monitors compliance with risk management policies. The Trust's risk management policies are established to identify and analyze the risks faced by the Trust, to set appropriate risk limits and controls, and to monitor risks and adherence to market conditions and the Trust's activities.

(a) Credit risk:

Credit risk is the risk of financial loss to the Trust if a customer or counterparty to a financial instrument fails to meet its contractual obligations, and arises principally from the Trust's receivables from crude oil and natural gas marketers and joint venture partners.

Substantially all of the Trust's crude oil and natural gas production is marketed under standard industry terms. Receivables from crude oil and natural gas marketers are normally collected on the 25th day of the month following production. The Trust's policy to mitigate credit risk associated with these balances is to establish marketing relationships with large credit worthy purchasers and to sell through multiple purchasers. The Trust historically has not experienced any collection issues with its crude oil and natural gas marketers. Joint venture receivables are typically collected within three months of the joint venture bill being issued to the partner. The Trust attempts to mitigate the risk from joint venture receivables by obtaining partner approval of significant capital expenditures prior to the expenditure. However, the receivables are from participants in the crude oil and natural gas sector, and collection of the outstanding balances can be impacted by industry factors such as commodity price fluctuations, limited capital availability and unsuccessful drilling programs. The Trust does not typically obtain collateral from crude oil and natural gas marketers or joint venture partners; however the Trust does have the ability in most cases to withhold production from joint venture partners in the event of non-payment.

The carrying amount of accounts receivable represents the maximum credit exposure. As at June 30, 2008 the Trust's receivables consisted of $95.9 million of receivables from crude oil and natural gas marketers which has substantially been collected, $19.2 million from joint venture partners of which $2.1 million has been subsequently collected, and $16.5 million of Crown deposits, prepaids and inventory. As at June 30, 2008 the Trust has $10.2 million in accounts receivable that is considered to be past due. Although these amounts have been outstanding for greater than 90 days, they are still deemed to be collectible. The Trust does not have an allowance for doubtful accounts as at June 30, 2008 and did not provide for any doubtful accounts nor was it required to write-off any receivables during the period ended June 30, 2008.

(b) Liquidity risk:

Liquidity risk is the risk that the Trust will encounter difficulty in meeting obligations associated with the financial liabilities. The Trust's financial liabilities consist of accounts payable and accrued liabilities, financial instruments, bank debt and convertible debentures. Accounts payable consists of invoices payable to trade suppliers for office, field operating activities, capital expenditures, and distributions payable. The Trust processes invoices within a normal payment period. Accounts payable and financial instruments have contractual maturities of less than one year. The Trust maintains a three year revolving credit facility, as outlined in note 4, which may, at the request of the Trust with the consent of the lenders, be extended on an annual basis. The Trust also has two series of convertible debentures outstanding with conversion prices of $23.00 and $29.00, we expect that both of these convertible debenture series will convert to trust units prior to maturity as the current trust unit trading price exceeds the conversion price. The Trust also maintains and monitors a certain level of cash flow which is used to partially finance all operating, investing and capital expenditures.

(c) Market risk:

Market risk is the risk that changes in market conditions, such as commodity prices, interest rates, and foreign exchange rates, will affect the Trust's net income or the value of financial instruments. The objective of market risk management is to manage and control market risk exposures within acceptable limits, while maximizing the Trust's returns.

The Trust utilizes both financial derivatives and physical delivery sales contracts to manage market risks. All such transactions are conducted in accordance with the Trust's risk management policy that has been approved by the Board of Directors.

i) Commodity price risk

Commodity price risk is the risk that the fair value of future cash flows will fluctuate as a result of changes in commodity prices. Commodity prices for crude oil and natural gas are impacted not only by global economic events that dictate the levels of supply and demand but also by the relationship between the Canadian and United States dollar. The Trust has attempted to mitigate a portion of the commodity price risk through the use of various financial derivative and physical delivery sales contracts. The Trust's policy is to enter into commodity price contracts when considered appropriate to a maximum of 60% of forecasted production volumes.

As at June 30, 2008, 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
----------------------------------------------------------------------------
July 1, 2008 -
35,000 gjs/d CDN$ 7.43 - CDN$ 8.77 - AECO October 31, 2008
November 1, 2008 -
10,000 gjs/d CDN$ 9.25 - CDN$ 13.50 - AECO March 31, 2009
April 1, 2009 -
5,000 gjs/d CDN$ 9.00 - CDN$ 12.00 - AECO October 31, 2009
July 1, 2008 -
7,000 bbls/d US$ 65.43 - US$ 78.58 - WTI December 31, 2008
July 1, 2008 -
4,000 bbls/d CDN$ 61.75 - CDN$ 70.88 - Bow River December 31, 2008
January 1, 2009 -
1,000 bbls/d CDN$ 70.00 - CDN$ 78.00 - Bow River December 31, 2009
January 1, 2009 -
1,000 bbls/d CDN$ 85.00 - CDN$125.25 - WTI December 31, 2009
April 1, 2009 -
2,000 bbls/d CDN$ 100.00 - CDN$ 169.00 - WTI December 31, 2009
January 1, 2009 -
2,000 bbls/d US$ 65.00 - US$ 80.50 - WTI March 31, 2009
April 1, 2009 -
1,000 bbls/d US$ 85.00 - US$ 105.60 - WTI December 31, 2009
----------------------------------------------------------------------------


Derivatives are recorded on the balance sheet at fair value at each reporting period with the change in fair value being recognized as an unrealized gain or loss on the consolidated statement of operations, comprehensive income and retained earnings. These contracts had the following reflected in the consolidated statement of operations, comprehensive income and retained earnings:



----------------------------------------------------------------------------
Three Months
ended June 30,
2008 2007
----------------------------------------------------------------------------
Realized gains (losses) on financial
instruments $ (39,967) $ 834
Unrealized gains (losses) on financial
instruments (108,224) 3,830
----------------------------------------------------------------------------
$ (148,191) $ 4,664
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Bonavista mitigates its risk associated with fluctuations in commodity prices by entering into commodity price contracts. A $0.10 change to the price per thousand cubic feet of natural gas - AECO and a $1.00 change to the price per barrel of oil - WTI would have an impact of approximately $407,000 and $2.6 million, respectively, on net income for those commodity price contracts that were in place as at June 30, 2008.

ii) Physical purchase contracts:

As at June 30, 2008, the Trust has entered into direct sale costless collars to sell natural gas as follows:



ii) Physical purchase contracts:

As at June 30, 2008, 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 July 1, 2008 - October 31, 2008
40,000 gjs/d $ 8.16 - $ 10.69 November 1, 2008 - March 31, 2009
10,000 gjs/d $ 8.00 - $ 10.84 April 1, 2009 - October 31, 2009
----------------------------------------------------------------------------

Subsequent to June 30, 2008, the Trust has entered into direct sale costless
collars to sell natural gas as follows:

----------------------------------------------------------------------------
Volume Average Price (CDN$ - AECO) Term
----------------------------------------------------------------------------
5,000 gjs/d $ 8.00 - $ 10.13 April 1, 2009 - October 31, 2009
----------------------------------------------------------------------------


iii) Foreign currency exchange rate risk

Foreign currency exchange rate risk is the risk that the fair value of future cash flows will fluctuate as a result of changes in foreign exchange rates. The Trust sells crude oil and natural gas that is denominated in both US and Canadian dollars. Canadian commodity prices are influenced by fluctuations in the Canadian to U.S. dollar exchange rate. The Trust had no forward exchange rate contracts in place as at or during the period ended June 30, 2008.

iv) Interest rate risk

Interest rate is the risk that future cash flows will fluctuate as a result of changes in market interest rates. The Trust is exposed to interest rate fluctuations on its bank debt which bears a floating rate of interest. If the interest rates applicable to Bonavista's bank debt were to change by 100 basis points and assuming that the changes in bank debt are consistent with what actually occurred in the period, we would estimate that net income for the three and six months ended June 30, 2008 would have a $1.3 million and $2.9 million impact respectively. For the similar periods in 2007 net income would be impacted by approximately $844,000 and $1.9 million respectively. The sensitivity impact is higher for the periods ending in 2008 because of an increase in the weighted average outstanding bank debt. The Trust had no interest rate swap or financial contracts in place as at or during the period ended June 30, 2008.

Fair value of financial instruments

The Trust's financial instruments as at June 30, 2008 and December 31, 2007 include accounts receivable, derivative contracts, accounts payable and accrued liabilities, convertible debentures and bank debt. The fair value of accounts receivable, accounts payable and accrued liabilities approximate their carrying amounts due to their short-terms to maturity. The Trust does not hold any financial assets or liabilities that are held for trading, nor does it have held to maturity investments or available for sale financial assets.

The fair value of derivative contracts is determined by the financial intermediary to extinguish all rights or obligations of the financial instruments. As at June 30, 2008, the market deficit of these derivative financial instruments was approximately $172.7 million.

The fair market value of the convertible debentures as at June 30, 2008 is $61.6 million, which has been determined by its June 30, 2008 closing trading price.

Bank debt bears interest at a floating market rate and accordingly the fair market value approximates the carrying value.

8. Capital management:

The Trust's objective when managing capital is to maintain a flexible capital structure which allows it to execute its growth strategy through strategic acquisitions and expenditures on exploration and development activities while maintaining a strong financial position that provides our unitholders with stable distributions and rates of return.

The Trust considers its capital structure to include working capital (excluding unrealized gains and losses on financial instruments), convertible debentures, bank debt, and unitholders' equity. The Trust monitors capital based on the ratio of net debt to annualized funds from operations. The ratio represents the time period it would take to pay off the debt if no further capital expenditures were incurred and if funds from operations remained constant. This ratio is calculated as net debt, defined as outstanding bank debt plus or minus net working capital, divided by funds from operations for the most recent calendar quarter, annualized (multiplied by four). The Trust's strategy is to maintain a ratio of no more than 2.0 to 1. This strategy is more restrictive than the existing financial covenants on the Trust's credit facility. This ratio may increase at certain times as a result of acquisitions or low commodity prices. As at June 30, 2008, the Trust's ratio of net debt to annualized funds from operations was 0.9 to 1 (2007 - 1.1 to 1), which is within the acceptable range established by the Trust.

In order to facilitate the management of this ratio, the Trust prepares annual funds from operations and capital expenditure budgets, which are updated as necessary, and are reviewed and periodically approved by the Trust's Board of Directors. The Trust manages its capital structure and makes adjustments by continually monitoring its business conditions, including; the current economic conditions; the risk characteristics of the Trust's crude oil and natural gas assets; the depth of its investment opportunities; current and forecasted net debt levels; current and forecasted commodity prices; and other facts that influence commodity prices and funds from operations, such as quality and basis differential, royalties, operating costs and transportation costs.

In order to maintain or adjust the capital structure, the Trust will consider; its forecasted ratio of net debt to forecasted funds from operations while attempting to finance an acceptable capital expenditure program including acquisition opportunities; the current level of bank credit available from the Trust's lenders; the level of bank credit that may be attainable from its lenders as a result of crude oil and natural gas reserves; the availability of other sources of debt with different characteristics than the existing bank debt; the sale of assets; limiting the size of the capital expenditure program; issuance of new equity if available on favourable terms; and its level of distributions payable to its unitholders. The Trust's unitholder's capital is not subject to external restrictions, however the Trust's credit facility does contain financial covenants that are outlined in note 4 of the consolidated financial statements.

There has been no change in the Trust's approach to capital management during the period ended June 30, 2008.

INVESTOR INFORMATION

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

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

Contact Information

  • Bonavista Energy Trust
    Keith A. MacPhail
    President & CEO
    (403) 213-4300
    or
    Ronald J. Poelzer
    Executive Vice President
    (403) 213-4300
    or
    Glenn A. Hamilton
    Senior Vice President& CFO
    (403) 213-4300
    or
    700, 311 - 6th Avenue SW
    Calgary, AB T2P 3H2
    (403) 213-4300
    Website: www.bonavistaenergy.com