Bonavista Energy Trust
TSX : BNP.UN

Bonavista Energy Trust

August 06, 2009 18:13 ET

Bonavista Energy Trust Announces Second Quarter Results

CALGARY, ALBERTA--(Marketwire - Aug. 6, 2009) - 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, 2009.



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Highlights
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Three months Six months
ended June 30, ended June 30,
2009 2008 2009 2008
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Financial
($ thousands, except per unit)
Production revenues 166,430 361,555 345,576 657,942
Funds from operations(1) 101,655 183,912 207,340 339,044
Per unit(1)(2) 0.85 1.62 1.74 3.06
Distributions declared 47,430 84,282 102,504 161,857
Per unit 0.48 0.90 1.04 1.80
Percentage of funds from
operations(1) 47% 46% 49% 48%
Net income 661 29,282 33,620 101,580
Per unit(2) 0.01 0.26 0.28 0.92
Adjusted net income(3) 35,227 107,247 80,688 193,567
Per unit (2) 0.29 0.94 0.68 1.75
Total assets 2,496,168 2,512,365
Long-term debt, including
working capital deficiency(4) 668,637 752,792
Long-term debt, net of
adjusted working capital(3)(4) 680,848 631,871
Unitholders' equity 1,351,059 1,232,554
Capital expenditures:
Exploitation and development 41,350 62,166 98,498 155,431
Acquisitions 128 4,771 22,225 174,145
Weighted average outstanding
equivalent trust units:
(thousands)(2)
Basic 119,726 113,713 119,238 110,795
Diluted 121,851 116,292 121,174 113,228
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Operating
(boe conversion - 6:1 basis)
Production:
Natural gas (mmcf/day) 176 172 174 175
Oil and liquids (bbls/day) 22,378 22,974 22,567 23,834
Total oil equivalent
(boe/day) 51,768 51,598 51,559 52,998
Product prices:(5)
Natural gas ($/mcf) 4.19 9.62 5.26 8.73
Oil and liquids ($/bbl) 58.61 81.94 54.97 75.05
Operating expenses ($/boe) 10.25 9.37 10.37 9.16
General and administrative
expenses ($/boe) 0.89 0.74 0.86 0.72
Cash costs ($/boe)(6) 11.68 11.86 11.90 11.94
Operating netback ($/boe)(7) 23.01 41.66 23.75 37.92
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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) Amounts have been adjusted to exclude unrealized gains or losses on
financial instruments and its related tax impact.

(4) Amounts exclude convertible debentures.

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

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

(7) Operating netback equals production revenues including realized gains
or losses on financial instruments, less royalties, transportation and
operating expenses, calculated on a boe basis.

Three months ended
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June 30, March 31, December 31, September 30,
Trust Unit Trading Statistics 2009 2009 2008 2008
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($ per unit, except volume)
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High 19.95 18.93 26.39 37.65
Low 14.84 11.74 14.25 25.01
Close 18.04 15.30 17.00 26.29
Average Daily Volume - Units 231,577 306,298 425,042 273,074
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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, 2009. The execution of Bonavista's long term, proven strategies in the second quarter of 2009 continues to validate the effectiveness of an operationally and technically focused energy trust. During the quarter, weaker commodity prices persisted compared to the same period last year and as a result Bonavista continued to adjust to the current economic environment by curtailing its disciplined capital program. We continued to focus on the key aspects of our business to ensure production and revenues are optimized and all costs minimized. This discipline has resulted in excellent operational and relatively strong financial results for the quarter despite weak oil and natural gas prices.

Although the North American economy has been slow to recover and industry fundamentals remain relatively weak, there are signs of stabilization, and this, coupled with our determination to position Bonavista for long term growth and profitability provided us the confidence to act on a significant acquisition opportunity. In this regard, on July 16, 2009 Bonavista announced that it had agreed to acquire certain long-life, liquids rich natural gas weighted properties located in its Central Alberta core area (the "Acquired Properties"). The acquisition has an effective date of April 1, 2009 and is expected to close on or about August 21, 2009 for a cash purchase price, at closing, of approximately $694 million. The completion of the transaction is subject to customary regulatory approvals and other conditions. In conjunction with this acquisition, Bonavista announced equity and bank financings and agreed to a property disposition. Details of all of these activities are as follows:

a) Acquisition Highlights - The acquisition is consistent with Bonavista's strategy of acquiring high quality, long-life oil and natural gas assets with significant low-risk development potential. The Acquired Properties are characterized by high working interests and operatorship with extensive gathering and processing infrastructure that enable low operating costs and efficiently accommodate production additions. The Acquired Properties complement Bonavista's emerging initiatives involving the use of leading technologies to access under developed reservoirs, located in close proximity to Bonavista's existing lands in our Central Alberta core area. The area is characterized as one of the most prolific multi-zone regions in western Canada with over twelve different producing horizons and the Acquired Properties provide significant exposure to the Glauconite, Rock Creek, Cardium, Viking and Notikewin formations. Utilizing leading technology, Bonavista believes that both production and recoverable reserves can be increased by over 50% from these large and scalable under developed reservoirs. While there is extensive exploration and development potential in many zones within the area, the primary development program will initially consist of drilling horizontal wells within the Glauconite and Rock Creek formations utilizing multistage fracture techniques paralleling Bonavista's success in the area over the past year. Bonavista has initially identified 165 horizontal drilling locations on the Acquired Properties in a development program anticipated to generate attractive future development efficiencies with finding and development costs of approximately $10 per boe and on-stream costs of approximately $10,000 per boe per day.

b) Financing - The cash to close the acquisition of approximately $694 million will be funded through a combination of bank debt and an issuance of subscription receipts ("Subscription Receipts"). In conjunction with the acquisition, Bonavista entered into an agreement to sell, on a bought deal basis, 23 million Subscription Receipts at a price of $16.85 each for gross proceeds of approximately $388 million. In addition, Bonavista has granted the underwriters an over-allotment option to purchase an additional two million Subscription Receipts at the same price. On August 5, 2009, the underwriters advised that they would elect to exercise on their option to purchase an additional two million Subscription Receipts for gross proceeds of approximately $34 million, to be completed on the closing of the equity financing.

In addition, Bonavista is currently arranging to increase its bank facilities by up to $400 million with the current members of its banking syndicate with the same maturity and financial covenants of its existing bank credit facility. This will provide Bonavista with up to $1.4 billion of total bank credit facilities to fund its ongoing capital programs. In connection with the contemplated increase, Bonavista has obtained $150 million of commitments from two of its lenders.

c) Property Disposition - On July 23, 2009, Bonavista agreed to sell its Southeast Saskatchewan assets effective June 1, 2009 to Glamis Resources Ltd. ("Glamis") for total consideration of $91.3 million in cash and approximately four million common shares of Glamis. The rationale for this disposition is as follows:

- The assets comprise less than 2% of overall operations;

- The area has become extremely competitive to expand operations significantly;

- Bonavista received an attractive purchase price with equity upside in a high growth company;

- The assets are better suited to a junior oil and natural gas company with plans to aggressively accelerate capital investment to achieve significant growth objectives; and

- Creates an opportunity for Bonavista to focus both human and capital resources in areas of greater presence and higher impact, generating superior returns over the long term.

Other significant accomplishments for Bonavista in the first half of 2009 include:

- Operationally, production volumes averaged 51,768 boe per day during the second quarter of 2009, versus 51,598 boe per day in 2008. Production volumes averaged 51,559 boe per day for the first half of 2009 versus 52,998 boe per day in 2008. Bonavista's proforma production rate is approximately 62,000 boe per day after accounting for the Acquired Properties and the Southeast Saskatchewan disposition;

- Maintained a disciplined capital program during both the second quarter and first half of 2009. In the second quarter of 2009 Bonavista invested $41.4 million in exploitation and development activities compared to $62.2 million in the same period of 2008 by drilling 20 wells with an overall 100% success rate. For the first six months of 2009, Bonavista invested $98.5 million in exploitation and development activities, drilling 56 wells with an overall 98% success rate and completed six transactions for $22.2 million;

- Drilled 27 successful horizontal wells, year to date, on seven different play types within our existing core regions. Six of these wells were drilled on a highly prospective Glauconite trend at Willesden Green in Central Alberta. The first three horizontal Glauconite wells began production at six times the initial rate of the offsetting verticals with all three averaging in excess of 400 boe per day per well for the first three months of production. In addition, Bonavista has drilled three Elkton horizontal wells in the Garrington area which are currently producing at seven mmcf per day in aggregate. Finally, three heavy oil wells drilled in the second quarter have added 400 bbls per day of incremental heavy oil production;

- Continued to participate at Crown land sales and freehold purchases, investing $7.7 million in land activity, further enhancing our future drilling prospect inventory for several years. Bonavista's undeveloped land position was improved to 1.3 million net acres;

- Generated funds from operations of $101.7 million ($0.85 per unit) in the second quarter of 2009 and $207.3 million ($1.74 per unit) in the first half of 2009. Of the total funds from operations generated in the respective periods, Bonavista distributed 47% of these funds in the second quarter and 49% of these funds for the first half of 2009 to Unitholders with the remaining funds reinvested in the business to continue growing our production base;

- Continued to record attractive levels of profitability in the first half of 2009 with a return on equity of 12% adjusting net income to negate the impact of unrealized gains or losses on financial instruments and its related tax impact, and an adjusted net income to funds from operations ratio of 39%; and

- Since inception as a Trust, Bonavista has delivered cumulative distributions of $1.6 billion or $20.15 per unit. These cumulative distributions are in excess of our closing price of $16.00 per unit on the first trading day after we became an energy trust on July 2, 2003.

Strengths of Bonavista Energy Trust

Upon restructuring from an exploration and production corporation into an energy trust in July 2003, Bonavista brought forward the same attributes that resulted in the tremendous success of the company between 1997 and 2003. We have maintained a high level of investment activity on our asset base, increasing production more than 50% since 2003. This activity stems from the operational and technical focus of our Trust, the attention to detail, and the ability to continuously generate economic prospects on our asset base within the Western Canadian Sedimentary Basin. Our experienced technical teams have a solid understanding of our assets and possess the necessary discipline and commitment to deliver profitable results to our Unitholders over 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, an increase in the quality and quantity of our drilling inventory and a growing production base. Our production base, including the recently announced property transactions is balanced 61% in favour of natural gas and 39% towards oil and liquids and is geographically focused within select medium depth, multi-zone regions in Alberta, British Columbia and Saskatchewan. This asset base has a low operating cost structure resulting in attractive operating netbacks. In addition, the high working interest asset base is predominantly operated by Bonavista, ensuring that operating and capital cost efficiencies are maintained and that Bonavista controls the pace of its operations.

Our team brings a successful track record of executing low to medium risk development programs, including both asset and corporate acquisitions, along with a solid track record of sound financial management. With our recently announced acquisition, Bonavista is confident that the acquired properties can be integrated quickly and seamlessly into our current base of operations due to the concentrated nature of the assets and our existing presence in the area. Our management team and Board of Directors possess extensive experience in the oil and natural gas business, navigating successfully through many different economic cycles utilizing a proven strategy consisting of strict cost controls and prudent financial management. Directors, management and employees also own approximately 15% of the Trust after giving effect to the recent financing, resulting in a close 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, 2008. The following MD&A of the financial condition and results of operations was prepared at, and is dated August 6, 2009. Our audited consolidated financial statements, Annual Report, and other disclosure documents for 2008 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 and prospects; (iii) anticipated production rates; (iv) expected royalty rate; (v) annualized debt to funds from operations; (vi) funds from operations, (vii) anticipated operating costs; (viii) expected service agreement fees; (ix) expected finding and development costs; (x) expected on-stream costs; (xi) closing of the acquisition of the Acquired Properties and the expected timing of such closing, 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 there from. 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 2009 led to the drilling of 56 wells in our four core regions with an overall success rate of 98%. This program resulted in 32 natural gas wells and 23 oil wells. Bonavista continues to pursue deeper and higher impact drilling opportunities focusing on unconventional development through the use of horizontal drilling and multi-stage fracture stimulation technology particularly in our Southern Alberta core area, where we have experienced excellent success and attractive finding and development costs over the past few years. These activities have also continued to enhance the predictability in our overall production base in addition to lengthening our reserve life index.

Production - For the second quarter of 2009, production increased slightly to 51,768 boe per day when compared to 51,598 boe per day for the same period a year ago and compared to the first quarter level of 51,347 boe per day. Specifically, average natural gas production increased 2% to 176 mmcf per day in the second quarter of 2009 from 172 mmcf per day for the same period a year ago, while total oil and liquids production decreased 3% to 22,378 bbls per day in the second quarter of 2009 (comprised of 16,531 bbls per day of light and medium oil and 5,847 bbls per day of heavy oil) from 22,974 bbls per day (comprised of 16,659 bbls per day of light and medium oil and 6,315 bbls per day of heavy oil) for the same period in 2008. For the six months ended June 30, 2009, production decreased 3% to 51,559 boe per day when compared to 52,998 boe per day for the same period a year ago. Natural gas production decreased slightly to 174 mmcf per day in the first six months of 2009 from 175 mmcf per day for the same period a year ago, while total oil and liquids production decreased 5% to 22,567 bbls per day in the first six months of 2009 (comprised of 16,874 bbls per day of light and medium oil and 5,693 bbls per day of heavy oil) from 23,834 bbls per day (comprised of 17,199 bbls per day of light and medium oil and 6,635 bbls per day of heavy oil) for the same period in 2008. Bonavista's balanced commodity investment approach minimizes our dependence on any one product and helped us report consistent results in the quarter. Upon closing the Central Alberta acquisition and the Southeast Saskatchewan disposition, our production is estimated to be 62,000 boe per day consisting of 61% natural gas, 30% light and medium oil and 9% heavy oil. We now anticipate production volumes in 2009 to average between 55,500 and 56,000 boe per day with the completion of the property transactions.

Production revenues - Production revenues for the second quarter of 2009 decreased 54% to $166.4 million when compared to $361.6 million for the same period a year ago, primarily due to lower average commodity prices. In the second quarter of 2009, natural gas prices decreased 56% to $4.19 per mcf, when compared to $9.62 per mcf realized in the same period in 2008. The average oil and liquids price also decreased 28% to $58.61 per bbl (comprised of $59.23 per bbl for light and medium oil and $56.83 per bbl for heavy oil) for the second quarter of 2009 from $81.94 per bbl (comprised of $84.26 per bbl for light and medium oil and $75.83 per bbl for heavy oil) for the same period in 2008. For the six months ended June 30, 2009, production revenues decreased 47% to $345.6 million when compared to $657.9 million for the same period a year ago, primarily due to lower average commodity prices and lower oil and liquids production. In the first half of 2009, natural gas prices decreased 40% to $5.26 per mcf, when compared to $8.73 per mcf realized in the same period in 2008. The average oil and liquids price also decreased 27% to $54.97 per bbl (comprised of $56.79 per bbl for light and medium oil and $49.56 per bbl for heavy oil) in the first half of 2009 from $75.05 per bbl (comprised of $76.86 per bbl for light and medium oil and $70.34 per bbl for heavy oil) for the same period in 2008.

The following table highlights Bonavista's realized commodity pricing for the three and six months ended June 30:



Three months Six months
ended June 30, ended June 30,
2009 2008 2009 2008
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Natural gas ($/mcf):
Production revenues $3.82 $9.70 $4.92 $8.76
Realized gains (losses) on
financial instruments 0.37 (0.08) 0.34 (0.03)
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4.19 9.62 5.26 8.73
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Light and medium oil ($/bbl):
Production revenues 50.35 102.53 46.83 89.78
Realized gains (losses) on
financial instruments 8.88 (18.27) 9.96 (12.92)
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59.23 84.26 56.79 76.86
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Heavy oil ($/bbl):
Production revenues 55.23 95.06 46.34 81.04
Realized gains (losses) on
financial instruments 1.60 (19.23) 3.22 (10.70)
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$56.83 $75.83 $49.56 $70.34
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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 volatile 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 primarily 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 2009, our risk management program on financial instruments resulted in a net loss of $27.8 million, consisting of a realized gain of $20.2 million and an unrealized loss of $48.0 million. The realized gain of $20.2 million consisted of a $6.0 million gain on natural gas commodity derivative contracts and a $14.2 million gain on crude oil commodity derivative contracts. For the same period in 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, 2009, our risk management program on financial instruments resulted in a net loss of $20.8 million, consisting of a realized gain of $44.5 million and an unrealized loss of $65.3 million. The realized gain of $44.5 million consisted of a $10.8 million gain on natural gas commodity derivative contracts and a $33.7 million gain on crude oil commodity derivative contracts. For the same period in 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 of $54.2 million consisted of a $887,000 loss on natural gas commodity derivative contracts and a $53.3 million loss on crude oil commodity derivative contracts.

Royalties - For the three months ended June 30, 2009, royalties decreased 71% to $21.0 million from $73.0 million for the same period a year ago, largely attributed to a decrease in commodity prices. In addition, royalties as a percentage of revenues (including realized gains and losses on financial instruments) for the second quarter of 2009 decreased to 11.2% compared to 22.7% in 2008 for similar reasons discussed above and the impact of realized gains on financial instruments in the second quarter of 2009 compared to realized losses on financial instruments in the comparable period of 2008. For the three months ended June 30, 2009, royalties by product as a percentage of revenues (including realized gains and losses on financial instruments) were 10.8% for natural gas, 11.0% for light and medium oil and 12.8% for heavy oil. In the second quarter of 2008, royalties by product, as a percentage of revenue (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. For the six months ended June 30, 2009, royalties also decreased by 59% to $53.9 million from $130.5 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 decreased from 21.6% in 2008 to 13.8% in 2009, for the same reasons as discussed above. For the six months ended June 30, 2009, royalties by product as a percentage of revenues (including realized gains and losses on financial instruments) were 14.9% for natural gas, 13.0% for light and medium oil and 13.0% for heavy oil. 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.

On October 25, 2007, the Alberta Government announced the New Royalty Framework ("NRF") which was subsequently revised on April 10, 2008 to provide further clarification on the NRF as well as to introduce two new royalty programs related to the development of deep oil and natural gas reserves. The NRF was legislated in November 2008 and took effect on January 1, 2009. Subsequent to legislation of the NRF, the Government of Alberta introduced the Transitional Royalty Plan ("TRP") in response to the decrease in development activity in Alberta resulting from declining commodity prices and the global economic downturn. The TRP offers reduced royalty rates for new wells drilled on or after November 19, 2008 that meet certain depth requirements. An election must be filed on an individual well basis in order to qualify for the TRP. The TRP is in place for a maximum of 5 years to December 31, 2013. All wells drilled between 2009 and 2013 that adopt the transitional rates will be required to shift to the NRF on January 1, 2014. On March 3, 2009, the Alberta Government announced a further royalty incentive program consisting of a three-point incentive program to stimulate new and continued economic activity in Alberta which includes a drilling royalty credit for new conventional oil and natural gas wells and a new royalty incentive program. The net effect of these programs will add approximately $8 to $9 million of funds from operations and credits in 2009.

Operating expenses - Operating expenses for the second quarter of 2009 increased 10% to $48.3 million compared to $44.0 million for the same period a year ago. Due to reduced industry activities during the second quarter, Bonavista has experienced a slight reduction in its operating expenses on a per boe basis compared to the first quarter. Bonavista remains optimistic that operating costs will continue to decrease over the remainder of 2009. Average per unit operating expenses increased by 9% to $10.25 per boe for the three months ended June 30, 2009, from $9.37 per boe in the comparable period of 2008. For the second quarter of 2009, operating expenses by product were $1.48 per mcf for natural gas, $10.87 per bbl for light and medium oil and $15.47 per bbl for heavy oil compared to $1.36 per mcf for natural gas, $9.93 per bbl for light and medium oil and $13.35 per bbl for heavy oil for the same period in 2008. Operating expenses for the first half of 2009 increased 9% to $96.7 million compared to $88.4 million for the same period a year ago. An increase in operating costs coupled with a 3% decrease in production volumes led to a 13% increase in average per unit operating expenses for the six months ended June 30, 2009 to $10.37 per boe, from $9.16 per boe in the comparable period of 2008. Operating expenses by product for the first half of 2009 were $1.52 per mcf for natural gas, $10.93 per bbl for light and medium oil and $15.20 per bbl for heavy oil compared to $1.30 per mcf for natural gas, $9.84 per bbl for light and medium oil and $13.37 per bbl for heavy oil for the same period in 2008.

Transportation expenses - For the three months ended June 30, 2009, transportation expenses remained steady at $9.0 million ($1.91 per boe) when compared to $9.0 million ($1.91 per boe) for 2008. For the six months ended June 30, 2009, transportation expenses decreased 7% to $17.8 million ($1.90 per boe) when compared to $19.0 million ($1.97 per boe) for 2008. Transportation expenses by product for the second quarter of 2009 were $0.34 per mcf for natural gas, $0.93 per bbl for light and medium oil and $4.05 per bbl for heavy oil compared to $0.37 per mcf for natural gas, $0.86 per bbl for light and medium oil and $3.31 per bbl for heavy oil for the same period in 2008. For the first half of 2009 transportation expenses by product were $0.35 per mcf for natural gas, $0.91 per bbl for light and medium oil and $3.93 per bbl for heavy oil compared to $0.39 per mcf for natural gas, $0.85 per bbl for light and medium oil and $3.32 per bbl for heavy oil for the same period in 2008.

General and administrative expenses - General and administrative expenses, after overhead recoveries, increased 21% to $4.2 million for the three months ended June 30, 2009 from $3.5 million in the same period in 2008 and increased 15% to $8.0 million for the six months ended June 30, 2009 from $7.0 million in the same period in 2008. On a per boe basis, general and administrative expenses increased 20% for the three months ended June 30, 2009 to $0.89 per boe from $0.74 per boe in the same period in 2008 and increased 19% for the six months ended June 30, 2009 to $0.86 per boe from $0.72 per boe in the same period in 2008. These increases are largely due to the termination of general and administrative cost recoveries under the services agreement with NuVista Energy Ltd., higher costs of personnel required to manage our operations and increasing cost pressures currently experienced throughout our industry.

In connection with its Trust Unit Incentive Rights and Restricted Trust Unit Plans, Bonavista recorded a unit-based compensation charge of $2.8 million and $5.6 million for the three and six months ended June 30, 2009 respectively, compared to $2.5 million and $4.8 million for the same periods in 2008.

Financing expenses - Financing expenses, which include interest expense on long-term debt and convertible debentures, decreased 69% to $2.5 million for the three months ended June 30, 2009, from $8.2 million for the same period in 2008 and on a boe basis, decreased 69% to $0.54 per boe for the three months ended June 30, 2009 from $1.75 per boe for the same period in 2008. For the six months ended June 30, 2009 financing expenses decreased 68% to $6.3 million, from $19.8 million for the same period in 2008 and on a boe basis, decreased 67% to $0.67 per boe for the first half of 2009 from $2.05 per boe for the same period in 2008. This decrease is due to lower average debt levels used to fund Bonavista's capital program, proceeds received in April 2008 from a $214.0 million equity financing and a declining interest rate environment. During the second quarter of 2009, Bonavista paid cash interest of $3.3 million compared to $9.2 million in 2008. For the six months ended June 30, 2009, Bonavista paid cash interest of $6.8 million compared to $20.1 million for the same period in 2008. Bonavista's effective interest rate as at June 30, 2009 was approximately 1.0% (2008 - 3.7%).

Depreciation, depletion and accretion expenses - Depreciation, depletion and accretion expenses increased 4% to $66.7 million for the three months ended June 30, 2009 from $64.0 million for the same period of 2008. For the six months ended June 30, 2009, depreciation, depletion and accretion expenses increased by 2% to $132.3 million from $129.3 million for the same period in 2008. These increases are due to higher costs of finding, developing and acquiring reserves and a larger asset base in 2009 offset by a 3% decline in overall production year over year. For the three months ended June 30, 2009, the average cost increased to $14.17 per boe from $13.62 per boe for the same period in 2008 and for the six months ended June 30, 2009, the average cost increased to $14.18 per boe from $13.41 per boe for the same period a year ago. Over the past few years our industry has seen cost escalation in all areas of our activities.

Income taxes - For the three months ended June 30, 2009, the provision for income tax was a recovery of $16.5 million compared to a recovery of $20.0 million for the same period in 2008. For the six months ended June 30, 2009, the provision for income tax was a recovery of $29.4 million compared to a recovery of $24.3 million for the same period in 2008. Bonavista made no cash payments relating to installments for the three months ended June 30, 2009, or for the comparative period in 2008.

Funds from operations, net income and comprehensive income - For the three months ended June 30, 2009, Bonavista experienced a 45% decrease in funds from operations to $101.7 million ($0.85 per unit, basic) from $183.9 million ($1.62 per unit, basic) for the same period in 2008. For the six months ended June 30, 2009, Bonavista experienced a 39% decrease in funds from operations to $207.3 million ($1.74 per unit, basic) from $339.0 million ($3.06 per unit, basic) for the same period in 2008. Funds from operations decreased for the three and six months ended June 30, 2009 primarily due to both lower commodity prices and production volumes partially offset by the impact of realized gains on financial instruments. Net income and comprehensive income for the three months ended June 30, 2009, decreased 98% to $661,000 ($0.01 per unit, basic) from $29.3 million ($0.26 per unit, basic) for the same period in 2008. For the six months ended June 30, 2009, net income and comprehensive income decreased 67% to $33.6 million ($0.28 per unit, basic) from $101.6 million ($0.92 per unit, basic) for the same period in 2008. The following table is a reconciliation of a non-GAAP measure, funds from operations, to its nearest measure prescribed by GAAP:



--------------------------------------------------------------------------
Three months Six months
Calculation of Funds From ended June 30, ended June 30,
Operations: 2009 2008 2009 2008
--------------------------------------------------------------------------
(thousands)
Cash flow from operating
activities $101,122 $180,694 $181,683 $345,343
Asset retirement expenditures 3,018 4,204 5,258 7,122
Changes in non-cash working
capital (2,485) (986) 20,399 (13,421)
--------------------------------------------------------------------------
Funds from operations $101,655 $183,912 $207,340 $339,044
--------------------------------------------------------------------------
--------------------------------------------------------------------------


Capital expenditures - Capital expenditures for the three month period ended June 30, 2009 were $41.5 million, primarily consisting of exploitation and development spending. For the same period in 2008 capital expenditures were $66.9 million, consisting of $62.2 million on exploitation and development spending and $4.7 million on property acquisitions. Capital expenditures for the six month period ended June 30, 2009 were $120.7 million, consisting of $98.5 million on exploitation and development spending and $22.2 million on property acquisitions. For the same period in 2008 capital expenditures were $329.6 million, consisting of $155.4 million on exploitation and development spending and $174.2 million on property acquisitions. We continued to see some downward movement in service costs in the second quarter, and we anticipate this trend to continue for the remainder of the year such that our exploitation and development program will continue to generate an attractive return on investment. The substantial reduction in exploitation and development capital expenditures compared to last year, is a testament to our commitment to maintaining our financial flexibility and strong balance sheet.

Liquidity and capital resources - As at June 30, 2009, long-term debt including working capital (excluding unrealized gains on financial instruments, its related tax impact and convertible debentures) was $680.8 million with a debt to 2009 annualized funds from operations ratio of 1.7:1. Bonavista has significant flexibility to finance future expansions of its capital programs, through the use of its current funds generated from operations and our bank loan facility of $1.0 billion, of which $319.2 million is unused borrowing capability. Bonavista's bank loan facility is provided by a syndicate of 12 domestic and international banks. The bank loan facility is a three year revolving facility and may at the request of the Trust and with the consent of the lenders be extended on an annual basis. On August 25, 2008, Bonavista and its lenders agreed to extend its bank loan facility to August 10, 2011 with no principal repayments required until then.

Under the terms of the credit facility, the Trust has provided the covenant that its: (i) consolidated senior debt borrowing will not exceed three times net income before unrealized gains and losses on financial instruments, interest, taxes and depreciation, depletion and accretion; (ii) consolidated total debt will not exceed three and one half times consolidated net income before unrealized gains and losses on financial instruments, interest, taxes and depreciation, depletion and accretion; and (iii) consolidated senior debt borrowing will not exceed one-half of consolidated total debt plus consolidated unitholders' equity of the Trust, in all cases calculated based on a rolling prior four quarters.

In 2009, Bonavista plans to invest between $225 and $250 million on its capital programs, excluding the recently announced major acquisition, to expand its core regions. From this point forward, the Trust intends on financing its remaining 2009 capital program with a combination of funds from operations and to the extent required, its existing credit facility. The Trust remains committed to the fundamental principle of maintaining financial flexibility and the prudent use of debt going forward.

Unitholders' equity - As at June 30, 2009, Bonavista had 119.8 million equivalent trust units outstanding. This includes 9.9 million exchangeable shares, which are exchangeable into 20.8 million trust units. The exchange ratio in effect at June 30, 2009 for exchangeable shares was 2.10695:1. As at August 6, 2009, Bonavista had 120.2 million equivalent trust units outstanding. This includes 9.9 million exchangeable shares, which are exchangeable into 21.0 million trust units. The exchange ratio in effect at August 6, 2009 for exchangeable shares was 2.12539:1. In addition, Bonavista has 4.2 million trust unit incentive rights outstanding at August 6, 2009, with an average exercise price of $21.71 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, 2009 the Trust declared distributions of $47.4 million ($0.48 per unit) compared to $84.3 million ($0.90 per unit) in the same period in 2008. For the six months ended June 30, 2009 the Trust declared distributions of $102.5 million ($1.04 per unit) compared to $161.9 million ($1.80 per unit) in the same period in 2008. We 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, such as depreciation, depletion and accretion, unrealized gains and losses on financial instruments, fluctuations in future income taxes due to changes in tax rates and tax rules, these non-cash charges do not represent the actual cost of maintaining our production capacity given the natural declines associated with oil and natural gas assets. For the three months ended June 30, 2009, the non-cash charges amounted to $101.0 million compared to $154.6 million for the same period in 2008. For the six months ended June 30, 2009, the non-cash charges amounted to $173.7 million compared to $237.5 million for the same period in 2008. In 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 Six months
ended June 30, ended June 30,
Distribution Analysis 2009 2008 2009 2008
----------------------------------------------------------------------------
(thousands)

Cash flow provided from
operating activities $101,122 $180,694 $181,683 $345,343
Net income 661 29,282 33,620 101,580
Distributions declared 47,430 84,282 102,504 161,857
Excess of cash flow provided
from operating activities
over distributions declared 53,692 96,412 79,179 183,486
Excess (shortfall) of net
income over distributions
declared (46,769) (55,000) (68,884) (60,277)
----------------------------------------------------------------------------


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 $0.16 per unit, down from $0.30 per unit at the same time last year. Our objective is to distribute up to 50% of our funds from operations, which allows us to withhold sufficient funds to finance capital expenditures required to maintain or modestly grow our production base over a longer period of time. Our distribution rate of $0.16 per unit per month will place us slightly below this range for 2009, assuming current strip prices are realized.

Subsequent Events - On July 16, 2009, Bonavista agreed to acquire certain natural gas weighted properties in its Central Alberta core region for a cash purchase price, at closing, of approximately $694 million. The acquisition is effective April 1, 2009 and expected to close on or about August 21, 2009. Completion of the acquisition is subject to customary regulatory approval and other conditions.

In connection with the acquisition, Bonavista agreed to sell, to a syndicate of underwriters, 23 million Subscription Receipts at a price of $16.85 per subscription receipt for gross proceeds of approximately $388 million. Bonavista has granted the underwriters an over-allotment option to purchase an additional two million Subscription Receipts at the same price. On August 5, 2009, the underwriters advised that they would elect to exercise on their option to purchase an additional two million Subscription Receipts for gross proceeds of approximately $34 million, to be completed on the closing of the equity financing.

In addition, Bonavista is currently arranging to increase its bank facilities by up to $400 million with the current members of its banking syndicate with the same maturity and financial covenants of its existing bank credit facility. This will provide Bonavista with up to $1.4 billion of total bank credit facilities to fund its ongoing capital programs. In connection with the contemplated increase, Bonavista has obtained $150 million of commitments from two of its lenders.

On July 23, 2009, Bonavista agreed to dispose of all of its Southeast Saskatchewan property interests for approximately $91.3 million in cash and approximately four million common shares of the purchaser. The transaction is effective June 1, 2009 and is expected to close on or about August 31, 2009. The transaction is subject to customary regulatory approvals and other conditions.

Quarterly financial information - The following table highlights Bonavista's performance for the eight quarterly periods ending on September 30, 2007 to June 30, 2009:



----------------------------------------------------------------------------
2009 2008
-----------------------------------------------------------
June 30 March 31 December 31 September 30 June 30
-----------------------------------------------------------
($ thousands,
except per unit
amounts)
Production
revenues 166,430 179,146 221,782 354,667 361,555
Net income 661 32,959 129,192 207,594 29,282
Net income
per unit:
Basic 0.01 0.28 1.09 1.77 0.26
Diluted 0.01 0.28 1.09 1.75 0.26
----------------------------------------------------------------------------
----------------------------------------------------------------------------


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


Production revenues over the past eight quarters has fluctuated between a low of $166.4 million in the second quarter of 2009 to a high of $361.6 million in the second quarter of 2008, largely due to the volatility of commodity prices as our volumes have remained relatively constant throughout the last two years. Net income in the past eight quarters has fluctuated from a low of $661,000 in the second quarter of 2009 to a high of $207.6 million in the third quarter of 2008. These fluctuations are primarily influenced by commodity prices, realized and unrealized gains and losses on financial instruments and future income tax recoveries associated with the reduction in corporate income tax rates. Net income decreased 98% in the second quarter of 2009 as compared to the second quarter of 2008. The decrease in net income in the second quarter of 2009 is largely attributed to lower overall commodity prices over the comparable period in 2008.

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. There were no material changes made to the internal controls over financial reporting for the period ended June 30, 2009.

Update on regulatory and financial reporting matters - On March 3, 2009, the Government of Alberta announced a three-point incentive program to stimulate new and continued economic activity in Alberta which included a drilling royalty credit program for new conventional oil and natural gas wells and a new well royalty incentive program. Under the drilling royalty credit program a $200 per metre royalty credit will be available on new conventional oil and natural gas wells drilled between April 1, 2009 and March 31, 2010, subject to certain maximum amounts. The maximum credits available will be determined by the company's production level in 2008 and its drilling activity between April 1, 2009 and March 31, 2010. The new well incentive program will apply to wells beginning production of conventional oil and natural gas between April 1, 2009 and March 31, 2010 and provides for a maximum 5% royalty rate for the first 12 months of production, up to a maximum of 50,000 bbls of oil or 500 mmcf of natural gas. On June 25, 2009, the Alberta Government announced the extension of these drilling incentives by one year to March 31, 2011.

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"). Canadian generally accepted accounting principles as we currently know them, will cease to exist for all publicly reporting entities. In July 2009 an amendment to IFRS 1 First Time Adoption of International Reporting Standards was issued that applies to oil and natural gas assets. The amendment allows an entity that used full cost accounting under its previous GAAP to elect, at its time of adoption, to measure exploration and evaluation assets at the amount determined under the entity's previous GAAP and to measure oil and natural gas assets in the development or production phases by allocating the amount determined under the entity's previous GAAP for those assets to the underlying assets pro rata using reserve volumes or reserve values as of that date. The Canadian Securities Administrators continue to examine changes to securities rules as a result of this initiative. Bonavista has completed a preliminary analysis of the accounting differences and has plans in place to perform a detailed assessment of the impact of IFRS on our results of operations, financial position and disclosures in 2009.

Effective January 1, 2009, Bonavista adopted Canadian Institute of Chartered Accountants ("CICA") Section 3064, "Goodwill and Intangible Assets", which defines the criteria for the recognition of intangible assets. The adoption of this standard did not impact the Trust's consolidated financial statements.

Environmental matters - On February 19, 2008 the Government of British Columbia introduced a consumer-based carbon tax that became effective on July 1, 2008. The Trust is required to pay carbon tax on all fuel used in the province of British Columbia through its normal course of operations. For the period ending June 30, 2009 Bonavista has paid approximately $123,000 (2008 - nil) with respect to the carbon tax. The British Columbia consumer-based carbon tax rate will increase 50% effective July 1, 2009.

OUTLOOK

As we progress into our twelfth year since restructuring the Company in 1997, and our sixth year since converting to an energy trust, we continue to benefit from the same qualities that drove the success of Bonavista as a public corporation and an energy trust. We continue to apply a proven strategy and execute this strategy in a disciplined and cost-effective manner much the same way we did in 1997 when we started on our mission of creating value for our investors. 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 several years, the quality and quantity of our inventory of opportunities continues to improve as we progress through 2009. Our consistent strategy also involves a component of strategic and timely acquisitions where we can add value utilizing our own technical expertise. In the third quarter of this year we expect to close on the most significant acquisition in our history. This acquisition grows our prospect inventory by 25% to approximately 850 locations adding high quality, low cost drilling prospects to our healthy inventory of opportunities. This transaction will not only enhance our presence in the Central Alberta area with operatorship of an extensive gathering and processing infrastructure but it will also provide low cost growth opportunities for many years to come. 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 and productivity remains among the strongest levels in our eleven year history.

In the short term we remain concerned about weak natural gas prices due to current storage levels and depressed industrial demand. This price weakness will continue to pressure funds from operations generated from natural gas production. For the remainder of 2009, given the current instability of commodity prices and the reduced funds from operations, Bonavista will continue to focus on its reduced capital budget of approximately $225 to $250 million (excluding the recently announced transactions), which is a reduction of over 30% from the 2008 exploitation and development budget. We expect production levels to average between 55,500 and 56,000 boe per day for the year upon closing of our property transactions and given our level of capital spending. Our development program will result in the drilling of 110 to 120 wells, of which, 50 to 60 will be high impact horizontal wells focusing on multi-stage fracture stimulation with thick, tight sandstone like the Glauconite formation in our Central Alberta core area. In addition, Bonavista believes that new micro-seismic, drilling and completion technologies will have a significant impact on our vast land holdings in all of our core regions. This will inevitably lead to further development of several under developed resources and the economic extraction of incremental reserves from proven reservoirs over the next several years. We will closely monitor our capital programs and will remain flexible to reallocate or expand our capital program on additional assets, land acquisitions or drilling opportunities as success and economic conditions dictate. In the meantime, our prudent approach to capital spending, balance sheet management and distributions will preserve our financial strength and should serve our Unitholders well in the current environment.

We are extremely proud of our achievements over the past eleven years and despite some short term commodity weakness, we remain enthusiastic and excited about the future and the growing opportunities that exist for Bonavista. We would like to thank our employees for their significant effort and their continued enthusiasm and perseverance as we pursue these opportunities in the current economic environment. Despite the setbacks we have endured over the past couple of years, including the passage of federal legislation on the taxation of distributions from certain publicly traded Canadian trusts, the introduction of the New Royalty Framework by the Government of Alberta, and the volatile capital and commodity markets, Bonavista's commitment and value creation process has not changed and we remain comfortable that our operating philosophy works well in this challenging environment. Throughout many business cycles and changes in the business environment, Bonavista has converted adversity into opportunity, pursued counter-cyclical strategies and has emerged an even stronger entity as a result of this approach. Our success is based on the consistent application of our core philosophy and operating strategies. Although our legal structure may ultimately change come 2011, our steadfast commitment to creating Unitholder value will not, regardless of our environment. Our team remains committed to this vision over the long term.



BONAVISTA ENERGY TRUST
Consolidated Balance Sheets

----------------------------------------------------------------------------
----------------------------------------------------------------------------
June 30, December 31,
(thousands) 2009 2008
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(unaudited)
Assets:
Current assets:
Accounts receivable $ 109,467 $ 106,116
Unrealized gains on financial
instruments 27,328 76,203
----------------------------------------------------------------------------

136,795 182,319
Oil and natural gas properties and equipment 2,318,052 2,319,600
Goodwill 41,321 41,321
----------------------------------------------------------------------------

$ 2,496,168 $ 2,543,240
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Liabilities and Unitholders' Equity:
Current liabilities:
Accounts payable and accrued liabilities $ 115,486 $ 143,093
Distributions payable 15,835 28,731
Unrealized losses on financial
instruments 10,090 -
Convertible debentures 37,474 -
Future income taxes 5,027 22,221
----------------------------------------------------------------------------

183,912 194,045
Unrealized losses on financial instruments 6,325 -
Long-term debt 658,994 588,792
Convertible debentures - 43,711
Asset retirement obligations 130,862 127,467
Future income taxes 165,016 177,253
Unitholders' equity:
Unitholders' capital and debenture
conversion component 1,116,082 1,100,768
Exchangeable shares 60,332 69,488
Contributed surplus 12,500 10,687
Accumulated earnings 162,145 231,029
----------------------------------------------------------------------------

1,351,059 1,411,972
----------------------------------------------------------------------------

$ 2,496,168 $ 2,543,240
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes to the consolidated financial statements.


BONAVISTA ENERGY TRUST
Consolidated Statements of Operations, Comprehensive Income and Accumulated
Earnings

(thousands, except per unit amounts) Three months Six months
ended June 30, ended June 30,
2009 2008 2009 2008
----------------------------------------------------------------------------

(unaudited)
Revenues:
Production $166,430 $361,555 $345,576 $657,942
Royalties (20,974) (72,999) (53,889) (130,450)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
145,456 288,556 291,687 527,492
----------------------------------------------------------------------------

Realized gains (losses) on
financial instruments 20,193 (39,967) 44,477 (54,250)
Unrealized losses on
financial instruments (47,949) (108,224) (65,291) (127,688)
----------------------------------------------------------------------------

(27,756) (148,191) (20,814) (181,938)
----------------------------------------------------------------------------

117,700 140,365 270,873 345,554
----------------------------------------------------------------------------
Expenses:
Operating 48,272 44,005 96,749 88,400
Transportation 8,994 8,977 17,767 19,043
General and administrative 4,193 3,455 8,043 6,974
Financing 2,535 8,240 6,265 19,781
Unit-based compensation 2,823 2,460 5,577 4,773
Depreciation, depletion and
accretion 66,749 63,965 132,283 129,331
----------------------------------------------------------------------------

133,566 131,102 266,684 268,302
----------------------------------------------------------------------------

Income before taxes (15,866) 9,263 4,189 77,252
Income tax reductions (16,527) (20,019) (29,431) (24,328)
----------------------------------------------------------------------------
Net income and comprehensive
income 661 29,282 33,620 101,580

Accumulated earnings, beginning
of period 208,914 119,926 231,029 125,203
Distributions declared (47,430) (84,282) (102,504) (161,857)
----------------------------------------------------------------------------

Accumulated earnings, end of
period $162,145 $ 64,926 $162,145 $ 64,926
----------------------------------------------------------------------------
Net income per unit - basic $ 0.01 $ 0.26 $ 0.28 $ 0.92
----------------------------------------------------------------------------
Net income per unit - diluted $ 0.01 $ 0.26 $ 0.28 $ 0.92
----------------------------------------------------------------------------

See accompanying notes to the consolidated financial statements.


BONAVISTA ENERGY TRUST
Consolidated Statements of Cash Flows

----------------------------------------------------------------------------
(thousands, except per unit amounts) Three months Six months
ended June 30, ended June 30,
2009 2008 2009 2008
----------------------------------------------------------------------------
(unaudited)
Cash provided by (used in):
Operating Activities:
Net income $ 661 $ 29,282 $ 33,620 $ 101,580
Items not requiring cash
from operations:
Depreciation, depletion
and accretion 66,749 63,965 132,283 129,331
Unit-based compensation 2,823 2,460 5,577 4,773
Unrealized losses on financial
instruments 47,949 108,224 65,291 127,688
Future income tax reductions (16,527) (20,019) (29,431) (24,328)
Asset retirement expenditures (3,018) (4,204) (5,258) (7,122)
Changes in non-cash working
capital items 2,485 986 (20,399) 13,421
----------------------------------------------------------------------------
101,122 180,694 181,683 345,343
----------------------------------------------------------------------------
Financing Activities:
Issuance of equity, net
of issue costs 932 214,401 1,384 219,103
Distributions (47,375) (81,915) (115,400) (159,343)
Changes in long-term debt (1,405) (248,772) 70,202 (105,522)
Repayment of convertible
debentures (6,586) - (6,586) -
Changes in non-cash working
capital items (765) (989) (486) (326)
----------------------------------------------------------------------------
(55,199) (117,275) (50,886) (46,088)
----------------------------------------------------------------------------
Investing Activities:
Exploitation and development (41,350) (62,166) (98,498) (155,431)
Property acquisitions (128) (4,771) (22,225) (174,145)
Changes in non-cash working
capital items (4,445) 3,518 (10,074) 30,321
----------------------------------------------------------------------------
(45,923) (63,419) (130,797) (299,255)
----------------------------------------------------------------------------
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, 2009 (unaudited)

Structure of the Trust and Basis of Presentation:

Bonavista Energy Trust ("Bonavista" or the "Trust") is an open-ended unincorporated investment trust governed by the laws of the Province of Alberta. The Trust was established on July 2, 2003 under a Plan of Arrangement entered into by the Trust, Bonavista Petroleum Ltd. ("BPL") and its subsidiaries and partnerships and NuVista Energy Ltd. ("NuVista"). Under the Plan of Arrangement, a wholly-owned subsidiary of the Trust amalgamated with BPL and became the successor company. The Trust has two significant subsidiaries in which it owns 100% of the common shares of BPL (excluding the exchangeable shares - see note 6) and 100% of the units of Bonavista Trust (2003) ("BT"). The activities of these entities are financed through interest bearing notes from the Trust and third party debt as described in the notes to the consolidated financial statements. The business of the Trust is carried on through the entities owned by the subsidiaries of the Trust, Bonavista Petroleum, a general partnership ("BP") and Bonavista Energy Limited Partnership ("BELP"). The net income of the Trust is generated from interest on notes advanced to its subsidiaries, royalty payments on oil and natural gas assets owned by BP, as well as any dividends or distributions paid by its subsidiaries. The Trustee must declare payable to the Trust Unitholders all of the taxable income of the Trust.

1. Changes in accounting policies:

a) Goodwill:

On January 1, 2009, the Trust adopted CICA Handbook Section 3064 "Goodwill and Intangible Assets", which defines the criteria for the recognition of intangible assets. The adoption of this standard did not impact the Trust's consolidated financial statements.

b) 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. Bonavista has completed a preliminary analysis of the accounting differences and has plans in place to perform a detailed assessment of the impact of IFRS on our results of operations, financial position and disclosures.

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. This new services agreement was terminated on November 1, 2008.

For the three months ended June 30, 2009, Bonavista charged NuVista nil (2008 - $373,000) 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 (2008 - $337,500). For the six months ended June 30, 2009, Bonavista charged NuVista nil (2008 - $786,000) 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 (2008 - $675,000). As at June 30, 2009, the amount payable to NuVista was $215,000.

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 $601.4 million (2008 - $556.7 million) which will be incurred over the next 51 years. The majority of the costs will be incurred between 2010 and 2038. A credit-adjusted risk-free rate of 7.5% (2008 - 7.5%) and an inflation rate of 2% (2008 - 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,
2009 2008
----------------------------------------------------------------------------
(thousands)
Balance, beginning of period $ 127,467 $ 116,893
Accretion expense 4,525 4,190
Liabilities incurred 1,579 4,682
Liabilities acquired 2,128 2,487
Liabilities settled (5,258) (7,122)
Change in assumptions 421 -
----------------------------------------------------------------------------
Balance, end of period $ 130,862 $ 121,130
----------------------------------------------------------------------------


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. On August 25, 2008 the facility was extended to August 10, 2011 with no principal payments required until then. This facility also includes an accordion feature providing that at anytime during the term, on participation of any existing or additional lenders, we can increase the facility by $250 million.

Under the terms of the credit facility, the Trust has provided the covenant that its: (i) consolidated senior debt borrowing will not exceed three times net income before unrealized gains and losses on financial instruments, interest, taxes and depreciation, depletion and accretion; (ii) consolidated total debt will not exceed three and one half times consolidated net income before unrealized gains and losses on financial instruments, interest, taxes and depreciation, depletion and accretion; and (iii) consolidated senior debt borrowing will not exceed one-half of consolidated total debt plus consolidated unitholders' equity of the Trust, in all cases calculated based on a rolling prior four quarters.

Financing expenses for the six months ended June 30, 2009 include interest on bank loans of $4.7 million (2008 - $18.1 million) and convertible debentures of $1.5 million (2008 - $1.7 million). For the six months ended June 30, 2009, Bonavista paid cash interest of $6.8 million (2008 - $20.1 million). Our effective interest rate for the period ending June 30, 2009 was approximately 1.1% (2008 - 3.9%).

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. The debt portion is accreted over the term of the obligation to the principal value on maturity with a corresponding charge to net income. On June 30, 2009 the 7.5% convertible debentures matured and were cash settled. The following table sets out the convertible debenture activities to June 30, 2009:



Debt Equity
Component Component
----------------------------------------------------------------------------
(thousands)
Balance, December 31, 2008 $ 43,711 $ 933
Accretion 22 -
Issue expenses related to conversion trust units 2 -
Amortization of issue expenses 336 -
Conversion to trust units (11) (2)
Repayment of convertible debenture on maturity (6,586) (123)
----------------------------------------------------------------------------
Balance, June 30, 2009 $ 37,474 $ 808
----------------------------------------------------------------------------


6. Unitholders' equity:

a) Authorized:

Unlimited number of voting trust units.

b) Issued and outstanding:

(i) Trust units:



Number of
Units Amount
----------------------------------------------------------------------------
(thousands)
Balance, December 31, 2008 95,770 $ 1,099,835
Issued on conversion of convertible debentures 1 11
Issued on conversion of exchangeable shares 3,016 9,156
Issued upon exercise of trust unit incentive
rights 118 1,384
Conversion of restricted trust units 65 -
Issue costs, related to debenture conversion - (2)
Adjustment to equity component of debenture
on conversion - 2
Adjustment to equity component of debenture on
repayment - 123
Unit-based compensation - 4,765
----------------------------------------------------------------------------
Balance, June 30, 2009 98,970 $ 1,115,274
----------------------------------------------------------------------------


(ii) Contributed surplus:
----------------------------------------------------------------------------
Amount
----------------------------------------------------------------------------
(thousands)
Balance, December 31, 2008 $ 10,687
Unit-based compensation expense 5,577
Unit-based compensation capitalized 1,001
Exercise of trust unit incentive rights and conversion
of restricted trust units (4,765)
----------------------------------------------------------------------------
Balance, June 30, 2009 $ 12,500
----------------------------------------------------------------------------
----------------------------------------------------------------------------


(iii) Exchangeable shares:
----------------------------------------------------------------------------
Number Amount
----------------------------------------------------------------------------
(thousands)
Balance, December 31, 2008 11,375 $ 69,488
Exchanged for trust units (1,499) (9,156)
----------------------------------------------------------------------------
Balance, June 30, 2009 9,876 60,332
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Exchange ratio, June 30, 2009 2.10695 -
----------------------------------------------------------------------------
Trust units issuable on exchange 20,809 $ 60,332
----------------------------------------------------------------------------
----------------------------------------------------------------------------


As a result of minimal conversions of exchangeable shares into trust units over the last few years, Bonavista elected to redeem 10% of its exchangeable shares outstanding on January 16, 2009. This redemption allows Bonavista to manage the dilution created by the compounding effect of the exchangeable shares, maintain an optimal capital and tax efficient trust structure for the Trust and its unitholders. On January 16, 2009, 1.1 million exchangeable shares were redeemed for 2.3 million trust units.

c) Long term incentive plans:

For the three months ended June 30, 2009 there were 6,895 restricted trust units granted and 49,900 trust unit incentive rights issued with an average exercise price of $16.00 per trust unit and an estimated fair value of $8.87 per trust unit. As at June 30, 2009 there were 238,810 restricted trust units outstanding and 4.2 million trust unit rights outstanding with an average exercise price of $22.16 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 rate was 3.5%; volatility of 66%; 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, 2009
----------------------------------------------------------------------------
(thousands)
Trust units 98,727
Exchangeable shares converted at the exchange ratio 20,999
----------------------------------------------------------------------------
Basic equivalent trust units 119,726
Convertible debentures 1,614
Trust unit incentive rights 272
Restricted trust units 239
----------------------------------------------------------------------------
Diluted equivalent trust units 121,851
----------------------------------------------------------------------------
----------------------------------------------------------------------------


For the purposes of calculating net income per trust unit on a diluted basis, net income has been increased by $1.0 million (2008 - $1.0 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.

a) Credit risk:

The carrying amount of accounts receivable represents the maximum credit exposure. As at June 30, 2009 the Trust's receivables consisted of $59.9 million of receivables from crude oil and natural gas marketers which has substantially been collected, $30.0 million from joint venture partners of which $2.2 million has been subsequently collected, and $19.6 million of Crown deposits and prepaid expenses. As at June 30, 2009 the Trust has $7.6 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, 2009 and did not provide for any doubtful accounts nor was it required to write-off any receivables during the period ended June 30, 2009.

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 a series of convertible debentures outstanding. The 6.75% debentures have a conversion price of $29.00 per trust unit, maturing on June 30, 2010. The Trust may elect to satisfy the principal obligation of this debenture by issuing trust units to the holders of the debentures. 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) 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 instruments 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 net after royalty, forecasted production volumes.

i) Financial instruments:

As at June 30, 2009, the Trust has hedged by way of costless collars to sell natural gas and crude oil as follows:



Volume Average Price Term
---------------------------------------------------------------------------
July 1, 2009 -
20,000 gjs/d CDN$ 6.75- CDN$ 8.53 - AECO October 31, 2009
November 1, 2009 -
5,000 gjs/d CDN$ 5.00 - CDN$ 6.50 - AECO March 31, 2010
April 1, 2010 -
5,000 gjs/d CDN$ 5.00 - CDN$ 7.00 - AECO October 31, 2010
July 1, 2009 -
1,000 bbls/d CDN$ 70.00- CDN$ 78.00 - Bow River December 31, 2009
July 1, 2009 -
8,000 bbls/d CDN$ 78.44 - CDN$ 117.48 - WTI December 31, 2009
July 1, 2009 -
1,000 bbls/d US$ 85.00 - US$ 105.60 - WTI December 31, 2009
January 1, 2010 -
4,500 bbls/d CDN$ 60.56 - CDN$ 92.72 - WTI December 31, 2010
---------------------------------------------------------------------------


Financial instruments are recorded on the consolidated 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 statements of operations, comprehensive income and accumulated earnings. These financial instruments had the following gains and losses reflected in the consolidated statements of operations, comprehensive income and accumulated earnings:



Three months
ended June 30,
2009 2008
----------------------------------------------------------------------------
Realized gains (losses) on financial instruments $ 20,193 $ (39,967)
Unrealized losses on financial instruments (47,949) (108,224)
----------------------------------------------------------------------------
$ (27,756) $ (148,191)
----------------------------------------------------------------------------


Bonavista mitigates its risk associated with fluctuations in commodity prices by utilizing financial instruments. A $0.10 increase or decrease to the price per thousand cubic feet of natural gas - AECO would have an impact of approximately $270,000 on net income for those financial instruments that were in place as at June 30, 2009. A $1.00 increase or decrease to the price per barrel of oil - WTI would have an impact of approximately $1.8 million on net income for those financial instruments that were in place as at June 30, 2009.

ii) Physical purchase contracts:

As at June 30, 2009, the Trust has entered into direct sale costless collars to sell natural gas as follows:



Volume Average Price (CDN$ - AECO) Term
----------------------------------------------------------------------------
20,000 gjs/d $ 6.03 - $ 7.79 July 1, 2009 - October 31, 2009
10,000 gjs/d $ 5.25 - $ 6.53 November 1, 2009 - March 31, 2010
5,000 gjs/d $ 5.25 - $ 7.00 April 1, 2010 - October 31, 2010
----------------------------------------------------------------------------


Physical purchase contracts are being accounted for as they are settled.

Fair value of financial instruments

The fair value of financial instruments is determined by the financial intermediary to extinguish all rights or obligations of the financial instruments. As at June 30, 2009, the fair market value of these financial instruments was an asset of approximately $10.9 million (2008 - $172.7 million liability).

Fair market value of the convertible debentures as at June 30, 2009 is $38.8 million (2008 - $61.6 million), as determined by its most recent closing trading price.

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

8. Subsequent events:

a) Property acquisition and financing:

On July 16, 2009, Bonavista agreed to acquire certain natural gas weighted properties in its Central Alberta core region for a cash purchase price, at closing, of approximately $694 million. The acquisition is effective April 1, 2009 and expected to close on or about August 21, 2009. Completion of the acquisition is subject to customary regulatory approval and other conditions.

In connection with the acquisition, Bonavista agreed to sell, to a syndicate of underwriters, 23 million Subscription Receipts at a price of $16.85 per Subscription Receipt for gross proceeds of approximately $388 million. Bonavista has granted the underwriters an over-allotment option to purchase an additional two million Subscription Receipts at the same price. On August 5, 2009, the underwriters advised that they would elect to exercise on their option to purchase an additional two million Subscription Receipts for gross proceeds of approximately $34 million, to be completed on the closing of the equity financing.

In addition, Bonavista is currently arranging to increase its bank facilities by up to $400 million with the current members of its banking syndicate with the same maturity and financial covenants of its existing bank credit facility. In connection with the contemplated increase, Bonavista has obtained $150 million of commitments from two of its lenders.

b) Property disposition:

On July 23, 2009, Bonavista agreed to dispose of all of its Southeast Saskatchewan property interests for approximately $91.3 million in cash and approximately four million common shares of the purchaser. The transaction is effective June 1, 2009 and is expected to close on or about August 31, 2009. The transaction is subject to customary regulatory approvals and other conditions.

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