Bonavista Energy Trust
TSX : BNP.UN

Bonavista Energy Trust

November 05, 2009 16:34 ET

Bonavista Energy Trust Announces Third Quarter Results

CALGARY, ALBERTA--(Marketwire - Nov. 5, 2009) - Bonavista Energy Trust (TSX:BNP.UN) is pleased to report to unitholders its interim consolidated financial and operating results for the three and nine months ended September 30, 2009.



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Highlights
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Three months Nine months
ended September 30, ended September 30,
2009 2008 2009 2008
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Financial
($ thousands, except per unit)
Production revenues 180,977 354,667 526,553 1,012,609
Funds from operations (1) 104,869 173,091 312,209 512,135
Per unit (1) (2) 0.80 1.48 2.58 4.54
Distributions declared 55,678 84,859 158,182 246,716
Per unit 0.48 0.90 1.52 2.70
Percentage of funds from
operations (1) 53% 49% 51% 48%
Net income 33,339 207,594 66,959 309,174
Per unit (2) 0.25 1.77 0.55 2.74
Adjusted net income (3) 31,506 96,306 112,195 289,873
Per unit (2) 0.24 0.82 0.93 2.57
Total assets 3,094,547 2,488,447
Long-term debt, including working
capital deficiency(4) 862,706 648,572
Long-term debt, net of adjusted
working capital (3)(4) 872,237 635,785
Unitholders' equity 1,738,958 1,361,847
Capital expenditures:
Exploration and development 43,303 89,847 141,801 245,278
Acquisitions, net 594,602 2,743 616,827 176,888
Weighted average outstanding
equivalent trust units:
(thousands) (2)
Basic 131,845 117,032 121,053 112,889
Diluted 133,684 119,439 122,976 115,313
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Operating
(boe conversion - 6:1 basis)
Production:
Natural gas (mmcf/day) 193 177 180 176
Oil and liquids (bbls/day) 23,924 23,912 23,024 23,860
Total oil equivalent (boe/day) 56,125 53,473 53,097 53,157
Product prices: (5)
Natural gas ($/mcf) 3.85 8.21 4.75 8.56
Oil and liquids ($/bbl) 59.36 80.31 56.50 76.82
Operating expenses ($/boe) 9.61 9.56 10.10 9.30
General and administrative
expenses ($/boe) 0.90 0.73 0.87 0.73
Cash costs ($/boe) (6) 11.15 11.72 11.63 11.86
Operating netback ($/boe) (7) 21.85 37.34 23.07 37.73
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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.


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Three months ended
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September 30, June 30, March 31, December 31,
Trust Unit Trading Statistics 2009 2009 2009 2008
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($ per unit, except volume)
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High 21.89 19.95 18.93 26.39
Low 16.64 14.84 11.74 14.25
Close 20.42 18.04 15.30 17.00
Average Daily Volume - Units 566,846 231,577 306,298 425,042
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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 nine months ended September 30, 2009. During the quarter, weaker commodity prices continued to persist when compared to the same period last year. As a result Bonavista continued to adjust to this environment by curtailing its drilling program. We remain very focused on the key aspects of our business to ensure that production and revenues are optimized and all costs are minimized. This discipline has resulted in excellent operational and relatively strong financial results for the quarter despite weaker oil and natural gas prices compared to the same period last year.

During the quarter, there were many signs that indicate the North American economy is recovering, and in recent weeks, commodity prices have responded favourably. These factors, coupled with our determination to position Bonavista for long term growth and profitability, provided us with the confidence to act on a significant acquisition opportunity during the third quarter of 2009. 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 closed on August 20, 2009 for a cash purchase price of $698 million. In conjunction with this acquisition, Bonavista completed equity and bank financings and agreed to a property disposition of our entire southeast Saskatchewan assets. 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 at an opportune time in the cycle. 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 a minimum of twelve different producing horizons. The Acquired Properties provide significant exposure to formations such as the Glauconite, Rock Creek, Cardium, Viking and Notikewin. 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 Cardium formations utilizing multi-stage fracture techniques paralleling Bonavista's success in the area over the past year. Bonavista has identified 200 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 initial on-stream costs of approximately $10,000 per boe per day. This acquisition brings our total drilling inventory to 320 primarily Glauconite and Cardium locations in the area of which 315 are expected to be drilled horizontally.

b) Financing - The cash to close the acquisition was funded through a combination of bank debt and an issuance of units. In conjunction with the acquisition, Bonavista issued 23 million units at a price of $16.85 per unit for gross proceeds of approximately $387.6 million. Furthermore, Bonavista granted the underwriters an over-allotment option to purchase an additional two million units 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 units for incremental gross proceeds of $33.7 million.

In addition, Bonavista arranged to increase its bank facilities by $400 million with the current members of its banking syndicate with the same maturity and financial covenants of its existing bank credit facility. This provides Bonavista with $1.4 billion of total bank credit facilities to fund its ongoing capital programs.

c) Property Disposition - On August 31, 2009, Bonavista closed the disposition of its southeast Saskatchewan assets to Glamis Resources Ltd. ("Glamis") for cash consideration of $98.7 million and approximately four million common shares of Glamis. The rationale for this disposition is as follows:

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

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

- 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; and

- 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.

Other significant accomplishments for Bonavista year to date include:

- Operationally, production volumes reached a record level of 56,125 boe per day during the third quarter of 2009, versus 53,473 boe per day in 2008. Production volumes averaged 53,097 boe per day for the nine months ended September 30, 2009. Bonavista's current production rate is approximately 61,500 boe per day after accounting for the Acquired Properties and the southeast Saskatchewan disposition;

- Maintained a conservative exploration and development program during the third quarter investing $43.3 million compared to $89.8 million in the same period of 2008 by drilling 22 wells with an overall 100% success rate. For the nine months ended September 30, 2009, Bonavista invested $141.8 million in exploration and development activities, drilling 78 wells with an overall 99% success rate and completed 18 transactions for net proceeds of $616.8 million;

- Drilled 38 successful horizontal wells, year to date, on 10 different play types within our existing core regions. Nine of these wells were drilled on a highly prospective Hoadley Glauconite trend in Central Alberta. Since inception, we have drilled 14 horizontal Glauconite wells of which 12 have been brought on production. These 12 wells have averaged initial rates in their first month of production of 550 boe per day per well and were brought on at an average all in cost of $3.0 million per well. Six of these wells have been on production for greater than six months and their average rate after six months of production is 325 boe per day per well. Of note, the last three horizontal wells were placed on production at an average cost of $2.7 million per well and have averaged 630 boe per day per well in their first month of production. Bonavista believes that our Glauconite horizontal development program continues to compete with the top tier resource developments in North America.

- Continued to participate at Crown land sales and freehold purchases, investing $14.0 million in land activity, further enhancing our future drilling prospect inventory for several years. Bonavista's undeveloped land position amounts to 1.3 million net acres at the present time;

- Generated funds from operations of $104.9 million ($0.80 per unit) in the third quarter of 2009 and $312.2 million ($2.58 per unit) in the nine months ended September 30, 2009. Of the total funds from operations generated in the respective periods, Bonavista distributed 53% of these funds in the third quarter and 51% of these funds for the nine months ended September 30, 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 third quarter and the nine months ended September 30, 2009 with a return on equity of 10% after adjusting net income to negate the impact of unrealized gains or losses on financial instruments and its related tax impact, and recorded an adjusted net income to funds from operations ratio of 36%;

- Since inception as a Trust, Bonavista has delivered cumulative distributions of $1.7 billion or $20.63 per unit. These cumulative distributions are in excess of our closing price of $16.00 per unit on the first trading day after becoming an energy trust on July 2, 2003 and exceeds our initial market capitalization of $1.6 billion.

Strengths of Bonavista Energy Trust

Upon restructuring from an exploration and production corporation into an energy trust in July 2003, Bonavista employed the same strategy 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 75% 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 they continue to exercise the discipline and commitment required 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 enhanced the quality and quantity of our extensive low-risk drilling inventory. These activities have led to low cost reserve additions, lengthening of our reserve life index, a significant increase in our drilling inventory and a growing production base. Our production base, including the recently closed property transactions, is weighted 60% in favour of natural gas and 40% towards oil and liquids and is geographically focused within select, multi-zone regions primarily in Alberta and British Columbia. The low cost structure of our asset base maintains attractive operating netbacks in any operating environment. 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. Despite its size, the recently announced acquisition has been integrated quickly and efficiently into our 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 November 5, 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 exploration and development program for the first nine months of 2009 led to the drilling of 78 wells within our core regions with an overall success rate of 99%. This program resulted in 43 natural gas wells and 34 oil wells. Bonavista continues to pursue low risk, higher impact drilling opportunities focusing on unconventional development through the use of horizontal drilling and multi-stage fracture stimulation technology. Specifically, our operations in Central Alberta have resulted in superior capital efficiencies driven off of strong production performance, healthy reserve additions and a disciplined approach to spending with every well drilled. These activities, along with our significant third quarter acquisition in our Central Alberta area, continue to enhance the predictability in our overall production base in addition to lengthening our reserve life index to over 10 years.

Production - For the third quarter of 2009, production increased 5% to a record 56,125 boe per day when compared to 53,473 boe per day for the same period a year ago. Natural gas production increased 9% to 193 mmcf per day in the third quarter of 2009 from 177 mmcf per day for the same period a year ago, while total oil and liquids production increased slightly to 23,924 bbls per day in the third quarter of 2009 from 23,912 bbls per day for the same period in 2008. For the nine months ended September 30, 2009, production decreased slightly to 53,097 boe per day when compared to 53,157 boe per day for the same period a year ago. Natural gas production increased 2% to 180 mmcf per day in the first nine months of 2009 from 176 mmcf per day for the same period a year ago, while total oil and liquids production decreased 4% to 23,024 bbls per day in the first nine months of 2009 from 23,860 bbls per day for the same period in 2008.



The following table highlights Bonavista's production by product for the
three and nine months ended September 30:

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Three months Nine months
ended September 30, ended September 30,
2009 2008 2009 2008
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Natural gas (mmcf/day) 193 177 180 176
Oil and liquids (bbls/day):
Light and medium oil 18,499 17,237 17,422 17,212
Heavy oil 5,425 6,675 5,602 6,648
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Total oil and liquids 23,924 23,912 23,024 23,860
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Total oil equivalent (boe/day) 56,125 53,473 53,097 53,157
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Bonavista's balanced commodity investment approach minimizes our dependence on any one product and has generated consistent results in the quarter. Having recently closed the Central Alberta acquisition and the Southeast Saskatchewan disposition, our production is currently 61,500 boe per day consisting of 60% natural gas, 31% light and medium oil and 9% heavy oil. After considering these transactions, we anticipate production volumes will average approximately 55,500 boe per day in 2009.

Production revenues - Production revenues for the third quarter of 2009 decreased 49% to $181.0 million when compared to $354.7 million for the same period a year ago, primarily due to lower commodity prices. In the third quarter of 2009, natural gas prices decreased 53% to $3.85 per mcf, when compared to $8.21 per mcf realized in the same period in 2008. The average oil and liquids price also decreased 26% to $59.36 per bbl (comprised of $59.26 per bbl for light and medium oil and $59.69 per bbl for heavy oil) for the third quarter of 2009 from $80.31 per bbl (comprised of $81.27 per bbl for light and medium oil and $77.85 per bbl for heavy oil) for the same period in 2008. For the nine months ended September 30, 2009, production revenues decreased 48% to $526.6 million when compared to $1,012.6 million for the same period a year ago, primarily due to lower average commodity prices and slightly lower oil and liquids production. For the nine month period ended September 30, 2009, natural gas prices decreased 45% to $4.75 per mcf, when compared to $8.56 per mcf realized in the same period in 2008. The average oil and liquids price also decreased 26% to $56.50 per bbl (comprised of $57.67 per bbl for light and medium oil and $52.87 per bbl for heavy oil) for the nine month period ended September 30, 2009 from $76.82 per bbl (comprised of $78.34 per bbl for light and medium oil and $72.87 per bbl for heavy oil) for the same period in 2008.



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

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Three months Nine months
ended September 30, ended September 30,
2009 2008 2009 2008
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Natural gas ($/mcf):
Production revenues $ 3.45 $ 8.33 $ 4.39 $ 8.62
Realized gains (losses) on
financial instruments 0.40 (0.12) 0.36 (0.06)
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3.85 8.21 4.75 8.56
Light and medium oil ($/bbl):
Production revenues 53.17 99.92 49.10 93.19
Realized gains (losses) on
financial instruments 6.09 (18.65) 8.57 (14.85)
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59.26 81.27 57.67 78.34
Heavy oil ($/bbl):
Production revenues 58.53 98.35 50.32 86.87
Realized gains (losses) on
financial instruments 1.16 (20.50) 2.55 (14.00)
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$ 59.69 $ 77.85 $ 52.87 $ 72.87
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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 third quarter of 2009, our risk management program on financial instruments resulted in a gain of $20.6 million, consisting of a realized gain of $18.1 million and an unrealized gain of $2.5 million. The realized gain of $18.1 million consisted of a $7.1 million gain on natural gas commodity derivative contracts and an $11.0 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 gain of $110.4 million, consisting of a realized loss of $44.1 million and an unrealized gain of $154.5 million. The realized loss of $44.1 million consisted of a $1.9 million loss on natural gas commodity derivative contracts and a $42.2 million loss on crude oil commodity derivative contracts. For the nine months ended September 30, 2009, our risk management program on financial instruments resulted in a net loss of $184,000, consisting of a realized gain of $62.6 million and an unrealized loss of $62.8 million. The realized gain of $62.6 million consisted of a $17.9 million gain on natural gas commodity derivative contracts and a $44.7 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 $71.6 million consisting of a realized loss of $98.4 million and an unrealized gain of $26.8 million. The realized loss of $98.4 million consisted of a $2.8 million loss on natural gas commodity derivative contracts and a $95.6 million loss on crude oil commodity derivative contracts.

Royalties - For the three months ended September 30, 2009, royalties decreased 61% to $27.0 million from $69.7 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 third quarter of 2009 decreased to 13.6% compared to 22.4% in 2008 for similar reasons discussed above and the impact of realized gains on financial instruments in the third quarter of 2009 compared to realized losses on financial instruments in the comparable period of 2008. For the nine months ended September 30, 2009, royalties also decreased by 60% to $80.9 million from $200.2 million for the same period a year ago, for similar reasons discussed above. In addition, royalties as a percentage of revenue (including realized gains and losses on financial instruments) for the nine month period also decreased from 21.9% in 2008 to 13.7% in 2009, for the same reasons as discussed above.



The following table highlights Bonavista's royalties by product for the
three and nine months ended September 30:

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Three months Nine months
ended September 30, ended September 30,
2009 2008 2009 2008
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Natural gas ($/mcf):
Royalties 0.33 1.89 0.62 1.93
% of revenues (1) 8.5% 23.1% 13.0% 22.5%
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Light and medium oil ($/bbl):
Royalties 9.28 16.86 8.07 16.33
% of revenues (1) 15.7% 20.7% 14.0% 20.8%
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Heavy oil ($/bbl):
Royalties 10.81 19.69 7.85 16.71
% of revenues (1) 18.1% 25.3% 14.9% 22.9%
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(1) % of revenues include realized gains and losses on financial instruments


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 $10 to $12 million of royalty and drilling credits in 2009.

Operating expenses - Operating expenses for the third quarter of 2009 increased 6% to $49.6 million compared to $47.1 million for the same period a year ago. Bonavista has experienced cost reductions associated with power and fuel consumption, general oilfield maintenance, well servicing and trucking services in the third quarter. This has resulted in a reduction of per unit operating costs of 8% and 6% over the first and second quarters of 2009 respectively. Average per unit operating expenses increased slightly to $9.61 per boe for the three months ended September 30, 2009, from $9.56 per boe in the comparable period of 2008. For the third quarter of 2009, operating expenses by product were $1.34 per mcf for natural gas, $10.83 per bbl for light and medium oil and $14.85 per bbl for heavy oil compared to $1.37 per mcf for natural gas, $10.18 per bbl for light and medium oil and $13.93 per bbl for heavy oil for the same period in 2008. Operating expenses for the nine months ended September 30, 2009 increased 8% to $146.4 million compared to $135.5 million for the same period a year ago. Operating expenses per unit of production increased 9% for the nine months ended September 30, 2009 to $10.10 per boe, from $9.30 per boe in the comparable period of 2008. Operating expenses by product for the nine months ended September 30, 2009 were $1.45 per mcf for natural gas, $10.89 per bbl for light and medium oil and $15.09 per bbl for heavy oil compared to $1.32 per mcf for natural gas, $9.95 per bbl for light and medium oil and $13.56 per bbl for heavy oil for the same period in 2008. Bonavista remains optimistic that operating costs will continue to trend lower for the remainder of 2009 and into 2010.

Transportation expenses - For the three months ended September 30, 2009, transportation expenses decreased 5% to $9.6 million ($1.87 per boe) when compared to $10.1 million ($2.06 per boe) for 2008. For the nine months ended September 30, 2009, transportation expenses decreased 6% to $27.4 million ($1.89 per boe) when compared to $29.2 million ($2.00 per boe) for the same period in 2008. Transportation expenses by product for the third quarter of 2009 were $0.34 per mcf for natural gas, $0.94 per bbl for light and medium oil and $3.89 per bbl for heavy oil compared to $0.39 per mcf for natural gas, $0.85 per bbl for light and medium oil and $3.86 per bbl for heavy oil for the same period in 2008. For the nine months ended September 30, 2009 transportation expenses by product were $0.35 per mcf for natural gas, $0.92 per bbl for light and medium oil and $3.92 per bbl for heavy oil compared to $0.39 per mcf for natural gas, $0.85 per bbl for light and medium oil and $3.50 per bbl for heavy oil for the same period in 2008.

General and administrative expenses - General and administrative expenses, after overhead recoveries, increased 28% to $4.6 million for the three months ended September 30, 2009 from $3.6 million in the same period in 2008 and increased 20% to $12.7 million for the nine months ended September 30, 2009 from $10.6 million in the same period in 2008. On a per boe basis, general and administrative expenses increased 23% for the three months ended September 30, 2009 to $0.90 per boe from $0.73 per boe in the same period in 2008 and increased 19% for the nine months ended September 30, 2009 to $0.87 per boe from $0.73 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, however, our current level of general and administrative expenses remains among the lowest in our sector.

In connection with its Trust Unit Incentive Rights and Restricted Trust Unit Plans, Bonavista recorded a unit-based compensation charge of $2.9 million and $8.4 million for the three and nine months ended September 30, 2009 respectively, compared to $1.6 million and $6.4 million for the same periods in 2008.

Financing expenses - Financing expenses, which include interest expense on long-term debt and convertible debentures, decreased 53% to $3.3 million for the three months ended September 30, 2009, from $7.0 million for the same period in 2008 and on a boe basis, decreased 55% to $0.64 per boe for the three months ended September 30, 2009 from $1.42 per boe for the same period in 2008. For the nine months ended September 30, 2009 financing expenses also decreased 64% to $9.6 million, from $26.8 million for the same period in 2008 and on a boe basis, decreased 64% to $0.66 per boe for the nine months ended September 30, 2009 from $1.84 per boe for the same period in 2008. This decrease is due largely to a declining interest rate environment. During the third quarter of 2009, Bonavista paid cash interest of $2.5 million compared to $6.4 million in 2008. For the nine months ended September 30, 2009, Bonavista paid cash interest of $9.2 million compared to $26.5 million for the same period in 2008. Bonavista's effective interest rate as at September 30, 2009 was approximately 1.4% (2008 - 3.9%).

Depreciation, depletion and accretion expenses - Depreciation, depletion and accretion expenses increased 14% to $77.8 million for the three months ended September 30, 2009 from $67.9 million for the same period of 2008. For the nine months ended September 30, 2009, depreciation, depletion and accretion expenses increased by 6% to $210.1 million from $197.3 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. For the three months ended September 30, 2009, the average cost increased to $15.07 per boe from $13.80 per boe for the same period in 2008 and for the nine months ended September 30, 2009, the average cost increased to $14.49 per boe from $13.55 per boe for the same period a year ago.

Income taxes - For the three months ended September 30, 2009, the provision for income tax was a recovery of $7.4 million compared to a provision of $50.5 million for the same period in 2008. For the nine months ended September 30, 2009, the provision for income tax was a recovery of $36.8 million compared to a provision of $26.1 million for the same period in 2008. Bonavista made no cash payments on tax installments for the three months ended September 30, 2009, or for the comparative period in 2008.

Funds from operations, net income and comprehensive income - For the three months ended September 30, 2009, Bonavista experienced a 39% decrease in funds from operations to $104.9 million ($0.80 per unit, basic) from $173.1 million ($1.48 per unit, basic) for the same period in 2008. For the nine months ended September 30, 2009, Bonavista experienced a 39% decrease in funds from operations to $312.2 million ($2.58 per unit, basic) from $512.1 million ($4.54 per unit, basic) for the same period in 2008. Funds from operations decreased for the three and nine months ended September 30, 2009 primarily due to lower commodity prices partially offset by the impact of realized gains on financial instruments. Net income and comprehensive income for the three months ended September 30, 2009, decreased 84% to $33.3 million ($0.25 per unit, basic) from $207.6 million ($1.77 per unit, basic) for the same period in 2008. For the nine months ended September 30, 2009, net income and comprehensive income decreased 78% to $67.0 million ($0.55 per unit, basic) from $309.2 million ($2.74 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 Nine months
Calculation of Funds From ended September 30, ended September 30,
Operations: 2009 2008 2009 2008
----------------------------------------------------------------------------
(thousands)
Cash flow from operating activities $ 87,492 $ 191,437 $269,175 $ 536,780
Asset retirement expenditures 3,338 3,046 8,596 10,168
Changes in non-cash working capital 14,039 (21,392) 34,438 (34,813)
----------------------------------------------------------------------------
Funds from operations $104,869 $ 173,091 $312,209 $ 512,135
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Capital expenditures - Capital expenditures for the three months ended September 30, 2009 were $637.9 million, consisting of $43.3 million spent on exploration and development and $594.6 million spent on net property acquisitions. For the same period in 2008, capital expenditures were $92.6 million, consisting of $89.8 million on exploration and development spending and $2.8 million on net property acquisitions. Capital expenditures for the nine month period ended September 30, 2009 were $758.6 million, consisting of $141.8 million on exploration and development spending and $616.8 million on net property acquisitions. For the same period in 2008 capital expenditures were $422.2 million, consisting of $245.3 million on exploration and development spending and $176.9 million on net property acquisitions. We continued to see considerable downward movement in service costs in the third quarter, and we anticipate this trend to continue for the remainder of the year such that our exploration and development program will continue to generate attractive returns despite relatively weak commodity prices. Although the quarter saw us spend a record amount due to the completion of the large acquisition, we remained very disciplined on the exploration and development front spending 53% less than the same period in 2008.

Liquidity and capital resources - As at September 30, 2009, long-term debt including working capital (excluding unrealized gains on financial instruments, its related tax impact and convertible debentures) was $872.2 million with a debt to 2009 annualized funds from operations ratio of 2.1:1. 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 facilities of $1.4 billion, of which $527.8 million is unused borrowing capability.

Bonavista's bank loan facilities are provided by a syndicate of 12 domestic and international banks. The one billion dollar 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 20, 2009 an additional $400 million bank loan facility became effective with the same maturity and financial covenants as the existing one billion dollar bank loan facility.

Under the terms of both credit facilities, 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 approximately $250 million on its capital programs, excluding the recently announced major acquisition and disposition, to expand its core regions. 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. Going forward, the Trust remains committed to the fundamental principle of maintaining financial flexibility and the prudent use of debt.

Unitholders' equity - As at September 30, 2009, Bonavista had 145.5 million equivalent trust units outstanding. This includes 9.7 million exchangeable shares, which are exchangeable into 21.0 million trust units. The exchange ratio in effect at September 30, 2009 for exchangeable shares was 2.16408:1. As at November 5, 2009, Bonavista had 145.8 million equivalent trust units outstanding. This includes 9.7 million exchangeable shares, which are exchangeable into 21.2 million trust units. The exchange ratio in effect at November 5, 2009 for exchangeable shares was 2.18087:1. In addition, Bonavista has 3.9 million trust unit incentive rights outstanding at November 5, 2009, with an average exercise price of $21.26 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 September 30, 2009 the Trust declared distributions of $55.7 million ($0.48 per unit) compared to $84.9 million ($0.90 per unit) in the same period in 2008. For the nine months ended September 30, 2009 the Trust declared distributions of $158.2 million ($1.52 per unit) compared to $246.7 million ($2.70 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, unrealized gains and losses on marketable securities, 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 September 30, 2009, the non-cash charges amounted to $71.5 million compared to a non-cash add back of $34.5 million for the same period in 2008. For the nine months ended September 30, 2009, the non-cash charges amounted to $245.3 million compared to $203.0 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 Nine months
ended September 30, ended September 30,
Distribution Analysis 2009 2008 2009 2008
----------------------------------------------------------------------------
(thousands)
Cash flow provided from operating
activities $ 87,492 $191,437 $269,175 $536,780
Net income 33,339 207,594 66,959 309,174
Distributions declared 55,678 84,859 158,182 246,716
Excess of cash flow provided from
operating activities over
distributions declared 31,814 106,578 110,993 290,064
Excess (shortfall) of net income
over distributions declared (22,339) 122,735 (91,223) 62,458
----------------------------------------------------------------------------
----------------------------------------------------------------------------


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 within this range for 2009, assuming current strip prices are realized.

Quarterly financial information - The following table highlights Bonavista's performance for the eight quarterly periods ending on December 31, 2007 to September 30, 2009:



----------------------------------------------------------------------------
2009 2008
--------------------------------------------------------
September 30 June 30 March 31 December 31 September 30
--------------------------------------------------------
($ thousands, except
per unit amounts)
Production revenues 180,977 166,430 179,146 221,782 354,667
Net income 33,339 661 32,959 129,192 207,594
Net income per unit:
Basic 0.25 0.01 0.28 1.09 1.77
Diluted 0.25 0.01 0.28 1.09 1.75
----------------------------------------------------------------------------
----------------------------------------------------------------------------


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


Production revenues over the past eight quarters have 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 84% in the third quarter of 2009 as compared to the third quarter of 2008. The decrease in net income in the third quarter of 2009 is largely attributed to lower overall commodity prices and the impact of the unrealized gains on financial instruments 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 September 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 is in the process of performing 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 three months ending September 30, 2009 Bonavista has paid approximately $163,000 (2008 - nil) with respect to the carbon tax. The British Columbia consumer-based carbon tax rate increased 50% effective July 1, 2009.

OUTLOOK

As we navigate through 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 both as a 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 exploration and development program over the past several years, the quality and quantity of our inventory of opportunities continues to improve each and every year. 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 closed the most significant acquisition in our history. This acquisition grew our prospect inventory by 25% to approximately 860 locations adding high quality, low cost drilling prospects to our previous healthy inventory of opportunities. This is truly a transformational transaction for our company and will lead to several years of drilling and tuck-in acquisition opportunities in an area where we have established a dominant presence of operations. Our timely and prudent approach to capital investments has been very effective in the past, and our attention to detail together with our steadfast commitment to adding Unitholder value, will continue to provide the foundation for the future success of our organization. Today our activity, efficiency and productivity remains among the strongest levels in our eleven year history.

In the near term we are monitoring natural gas economics very closely and remain optimistic that the current North American oversupply situation will reverse itself. The lack of current capital being directed towards natural gas targets within North America is resulting in a rapid decline in supply which, when coupled with stabilizing or modestly increasing industrial demand, should result in rising natural gas prices into 2010. For the remainder of 2009, Bonavista will continue to focus on profitability and cost control. Capital expenditures will continue to flow towards development within our Central Alberta core area while pursuing additional tuck-in acquisition opportunities. We expect production levels to average approximately 55,500 boe per day for the year given our level of capital spending of approximately $250 million (excluding the Central Alberta acquisition and southeast Saskatchewan disposition). Our 2009 development program will result in the drilling of approximately 125 wells, of which approximately 50% will be high impact horizontal wells focusing on multi-stage stimulation within large tight reservoirs like the Glauconite and Cardium formations in our Central Alberta core area. In addition, Bonavista believes that new micro-seismic techniques, and new drilling and completion technologies will have a very positive impact on our vast land holdings in all of our core regions. This will inevitably lead to the incremental development of several under-developed resources, amongst our asset portfolio, 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. 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.

With the economic picture improving as we head into 2010, we have established a preliminary capital spending program of between $300 and $330 million, which at this time will be entirely directed toward our exploration and development program. Approximately one-half of the expenditures will be devoted to our Central Alberta development initiatives. In total for 2010, we expect to drill between 120 and 130 wells, of which 60% to 70% will be horizontal wells. This activity should lead to production levels averaging between 62,000 and 63,000 boe per day in 2010. As always, we will continue to closely monitor the economic recovery together with our drilling results and remain flexible to adjust the level of spending depending on the circumstances.

We are extremely proud of our achievements over the past eleven years and despite some short term commodity weakness, we are more enthusiastic and excited about the future and the growing opportunities that exist for Bonavista than ever before. 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 confident that our operating philosophy works well in any 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 philosophies 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

----------------------------------------------------------------------------
----------------------------------------------------------------------------
September 30, December 31,
(thousands) 2009 2008
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(unaudited)
Assets:
Current assets:
Accounts receivable $ 123,383 $ 106,116
Marketable securities 6,868 -
Unrealized gains on financial instruments 20,542 76,203
----------------------------------------------------------------------------
150,793 182,319
Oil and natural gas properties and equipment 2,902,433 2,319,600
Goodwill 41,321 41,321
----------------------------------------------------------------------------
$ 3,094,547 $ 2,543,240
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Liabilities and Unitholders' Equity:
Current liabilities:
Accounts payable and accrued liabilities $ 125,575 $ 143,093
Distributions payable 19,918 28,731
Unrealized losses on financial instruments 7,087 -
Convertible debentures 37,853 -
Future income taxes 3,924 22,221
----------------------------------------------------------------------------
194,357 194,045
Long-term debt 856,995 588,792
Convertible debentures - 43,711
Asset retirement obligations 150,884 127,467
Future income taxes 153,353 177,253
Unitholders' equity:
Unitholders' capital and debenture conversion
component 1,528,952 1,100,768
Exchangeable shares 59,320 69,488
Contributed surplus 10,880 10,687
Accumulated earnings 139,806 231,029
----------------------------------------------------------------------------
1,738,958 1,411,972
----------------------------------------------------------------------------
$ 3,094,547 $ 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 Three months Nine months
amounts) ended September 30, ended September 30,
2009 2008 2009 2008
----------------------------------------------------------------------------
(unaudited)
Revenues:
Production $180,977 $354,667 $ 526,553 $1,012,609
Royalties (26,981) (69,716) (80,870) (200,166)
----------------------------------------------------------------------------
153,996 284,951 445,683 812,443
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Realized gains (losses) on
financial instruments 18,087 (44,094) 62,564 (98,344)
Unrealized gains (losses) on
financial instruments 2,543 154,480 (62,748) 26,792
----------------------------------------------------------------------------
20,630 110,386 (184) (71,552)
----------------------------------------------------------------------------
174,626 395,337 445,499 740,891
----------------------------------------------------------------------------
Expenses:
Operating 49,639 47,050 146,388 135,450
Transportation 9,631 10,112 27,398 29,155
General and administrative 4,630 3,611 12,673 10,585
Financing 3,314 6,993 9,579 26,774
Unrealized loss on marketable
securities 790 - 790 -
Unit-based compensation 2,870 1,582 8,447 6,355
Depreciation, depletion and
accretion 77,784 67,940 210,067 197,271
----------------------------------------------------------------------------
148,658 137,288 415,342 405,590
----------------------------------------------------------------------------
Income before taxes 25,968 258,049 30,157 335,301
Income tax (reductions) (7,371) 50,455 (36,802) 26,127
----------------------------------------------------------------------------
Net income and comprehensive
income 33,339 207,594 66,959 309,174

Accumulated earnings, beginning
of period 162,145 64,926 231,029 125,203
Distributions declared (55,678) (84,859) (158,182) (246,716)
----------------------------------------------------------------------------
Accumulated earnings, end of
period $139,806 $187,661 $ 139,806 $ 187,661
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net income per unit - basic $ 0.25 $ 1.77 $ 0.55 $ 2.74
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net income per unit - diluted $ 0.25 $ 1.75 $ 0.54 $ 2.71
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes to the consolidated financial statements.


BONAVISTA ENERGY TRUST
Consolidated Statements of Cash Flows

----------------------------------------------------------------------------
----------------------------------------------------------------------------
(thousands, except per unit Three months Nine months
amounts) ended September 30, ended September 30,
2009 2008 2009 2008
----------------------------------------------------------------------------
(unaudited)
Cash provided by (used in):
Operating Activities:
Net income $ 33,339 $ 207,594 $ 66,959 $ 309,174
Items not requiring cash from
operations:
Depreciation, depletion and
accretion 77,784 67,940 210,067 197,271
Unit-based compensation 2,870 1,582 8,447 6,355
Unrealized gains (losses) on
financial instruments (2,543) (154,480) 62,748 (26,792)
Unrealized loss on marketable
securities 790 - 790 -
Future income tax reductions (7,371) 50,455 (36,802) 26,127
Asset retirement expenditures (3,338) (3,046) (8,596) (10,168)
Changes in non-cash working
capital items (14,039) 21,392 (34,438) 34,813
----------------------------------------------------------------------------
87,492 191,437 269,175 536,780
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Financing Activities:
Issuance of equity, net of
issue costs 401,452 3,489 402,836 222,592
Distributions (51,595) (84,768) (166,995) (244,111)
Changes in long-term debt 198,001 (41,927) 268,203 (147,449)
Repayment of convertible
debentures - - (6,586) -
Changes in non-cash working
capital items 823 589 337 263
----------------------------------------------------------------------------
548,681 (122,617) 497,795 (168,705)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Investing Activities:
Exploration and development (43,303) (89,847) (141,801) (245,278)
Property acquisitions (700,818) (8,948) (723,043) (183,776)
Property dispositions 106,216 6,205 106,216 6,888
Changes in non-cash working
capital items 1,732 23,770 (8,342) 54,091
----------------------------------------------------------------------------
(636,173) (68,820) (766,970) (368,075)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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 nine months ended September 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 7) 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 is in the process of performing 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 is also an officer of Bonavista.

For the three months ended September 30, 2009, Bonavista charged NuVista no fees (2008 - $330,000) 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 nine months ended September 30, 2009, Bonavista charged NuVista no fees (2008 - $1.1 million) relating to general and administrative services provided to NuVista, in addition, NuVista charged Bonavista management fees for a jointly owned partnership totaling $1.0 million (2008 - $1.0 million). As at September 30, 2009, the amount payable to NuVista was $377,000.

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 $698.4 million (2008 - $559.2 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:

----------------------------------------------------------------------------
Nine months
ended September 30,
2009 2008
----------------------------------------------------------------------------
(thousands)
Balance, beginning of period $ 127,467 $ 116,893
Accretion expense 7,192 6,330
Liabilities incurred 2,786 6,106
Liabilities acquired 21,614 2,487
Liabilities settled (8,596) (10,168)
Change in assumptions 421 -
----------------------------------------------------------------------------
Balance, end of period $ 150,884 $ 121,648
----------------------------------------------------------------------------
----------------------------------------------------------------------------


4. Property acquisition:

On August 20, 2009 Bonavista acquired certain long-life natural gas weighted properties located in its Central Alberta core area for a cash purchase price of approximately $698 million.

5. Long-term debt:

The Trust has a one billion loan 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.

On August 20, 2009 an additional bank loan facility of $400 million became effective and has the same maturity and financial covenants as its existing one billion dollar bank loan facility.

Under the terms of the credit facilities, 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 nine months ended September 30, 2009 include interest on bank loans of $7.4 million (2008 - $24.3 million) and convertible debentures of $2.2 million (2008 - $2.5 million). For the nine months ended September 30, 2009, Bonavista paid cash interest of $9.2 million (2008 - $26.5 million). Our effective interest rate for the three month period ending September 30, 2009 was approximately 1.3% (2008 - 3.7%).

6. 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 September 30, 2009:



----------------------------------------------------------------------------
Debt Equity
Component Component
----------------------------------------------------------------------------
(thousands)
Balance, December 31, 2008 $ 43,711 $ 933
Accretion 307 -
Issue expenses related to conversion trust units 2 -
Amortization of issue expenses 430 -
Conversion to trust units (11) (2)
Repayment of convertible debenture on maturity (6,586) (123)
----------------------------------------------------------------------------
Balance, September 30, 2009 $ 37,853 $ 808
----------------------------------------------------------------------------
----------------------------------------------------------------------------


7. 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 for cash 25,000 421,250
Issued on conversion of convertible debentures 1 11
Issued on conversion of exchangeable shares 3,371 10,168
Issued upon exercise of trust unit incentive
rights 235 3,149
Conversion of restricted trust units 113 -
Issue costs, related to debenture conversion - (2)
Issue costs, net of future tax benefit (16,168)
Adjustment to equity component of debenture on
conversion - 2
Adjustment to equity component of debenture on
repayment - 123
Unit-based compensation - 9,776
----------------------------------------------------------------------------
Balance, September 30, 2009 124,490 $ 1,528,144
----------------------------------------------------------------------------
----------------------------------------------------------------------------


(ii) Contributed surplus:

----------------------------------------------------------------------------
Amount
----------------------------------------------------------------------------
(thousands)
Balance, December 31, 2008 $ 10,687
Unit-based compensation expense 8,447
Unit-based compensation capitalized 1,522
Exercise of trust unit incentive rights and conversion of
restricted trust units (9,776)
----------------------------------------------------------------------------
Balance, September 30, 2009 $ 10,880
----------------------------------------------------------------------------
----------------------------------------------------------------------------


(iii) Exchangeable shares:

----------------------------------------------------------------------------
Number Amount
----------------------------------------------------------------------------
(thousands)
Balance, December 31, 2008 11,375 $ 69,488
Exchanged for trust units (1,664) (10,168)
----------------------------------------------------------------------------
Balance, September 30, 2009 9,711 59,320
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Exchange ratio, September 30, 2009 2.16408 -
----------------------------------------------------------------------------
Trust units issuable on exchange 21,015 $ 59,320
----------------------------------------------------------------------------
----------------------------------------------------------------------------


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 September 30, 2009 there were 9,795 restricted trust units granted and 113,900 trust unit incentive rights issued with an average exercise price of $18.28 per trust unit and an estimated fair value of $10.46 per trust unit. As at September 30, 2009 there were 197,315 restricted trust units outstanding and 3.9 million trust unit rights outstanding with an average exercise price of $21.58 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 69%; 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 September 30, 2009
----------------------------------------------------------------------------
(thousands)
Trust units 110,647
Exchangeable shares converted at the exchange ratio 21,198
----------------------------------------------------------------------------
Basic equivalent trust units 131,845
Convertible debentures 1,330
Trust unit incentive rights 312
Restricted trust units 197
----------------------------------------------------------------------------
Diluted equivalent trust units 133,684
----------------------------------------------------------------------------
----------------------------------------------------------------------------


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.

8. 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 September 30, 2009 the Trust's receivables consisted of $68.6 million of receivables from crude oil and natural gas marketers which has substantially been collected, $31.1 million from joint venture partners of which $1.7 million has been subsequently collected, and $23.7 million of Crown deposits and prepaid expenses. As at September 30, 2009 the Trust has $12.8 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 September 30, 2009 and did not provide for any doubtful accounts nor was it required to write-off any receivables during the period ended September 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 5, 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 September 30, 2009, the Trust has hedged by way of costless collars to sell natural gas and crude oil as follows:



----------------------------------------------------------------------------
Volume Average Price Term
----------------------------------------------------------------------------
20,000 gjs/d CDN$ 6.75 - CDN$ 8.53 - AECO October 1, 2009 -
October 31, 2009
5,000 gjs/d CDN$ 5.00 - CDN$ 6.50 - AECO November 1, 2009 -
March 31, 2010
5,000 gjs/d CDN$ 5.00 - CDN$ 7.00 - AECO April 1, 2010 -
October 31, 2010
5,000 gjs/d CDN$ 5.00 - CDN$ 6.25 - AECO January 1, 2010 -
December 31, 2010
5,000 gjs/d CDN$ 5.50 - CDN$ 7.28 - AECO January 1, 2011 -
December 31, 2011
1,000 bbls/d CDN$ 70.00 - CDN$ 78.00 - Bow River October 1, 2009 -
December 31, 2009
1,000 bbls/d US$ 85.00 - US$ 105.60 - WTI October 1, 2009 -
December 31, 2009
8,000 bbls/d CDN$ 78.75 - CDN$ 117.66 - WTI October 1, 2009 -
December 31, 2009
7,000 bbls/d CDN$ 65.36 - CDN$ 93.39 - WTI January 1, 2010 -
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 September 30,
2009 2008
----------------------------------------------------------------------------
Realized gains (losses) on financial instruments $ 18,087 $ (44,094)
Unrealized gains on financial instruments 2,543 154,480
----------------------------------------------------------------------------
$ 20,630 $ 110,386
----------------------------------------------------------------------------
----------------------------------------------------------------------------


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 $385,000 on net income for those financial instruments that were in place as at September 30, 2009. A $1.00 increase or decrease to the price per barrel of oil - WTI would have an impact of approximately $1.6 million on net income for those financial instruments that were in place as at September 30, 2009.

Subsequent to September 30, 2009, the Trust has hedged by way of costless collars to sell crude oil as follows:



----------------------------------------------------------------------------
Volume Average Price Term
----------------------------------------------------------------------------
1,000 bbls/d CDN$ 75.00 - CDN$ 91.70 - WTI January 1, 2010 -
December 31, 2010
1,000 bbls/d CDN$ 80.00 - CDN$ 95.25 - WTI January 1, 2011 -
December 31, 2011
----------------------------------------------------------------------------


ii) Physical purchase contracts:

As at September 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 $ 5.31 - $ 7.06 October 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
5,000 gjs/d $ 5.00 - $ 6.60 January 1, 2010 -
December 31, 2011
----------------------------------------------------------------------------


As at September 30, 2009, the Trust entered into physical swap contracts to
sell natural gas as follows:

----------------------------------------------------------------------------
Volume Price (CDN$ - AECO) Term
----------------------------------------------------------------------------
5,000 gjs/d $ 5.06 January 1, 2010 -
December 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 September 30, 2009, the fair market value of these financial instruments was an asset of approximately $13.5 million (2008 - $18.3 million liability).

Fair market value of the convertible debentures as at September 30, 2009 is $39.4 million (2008 - $47.1 million), as determined by its most recent closing trading price.

Fair market value of marketable securities as at September 30, 2009 is $6.9 million (2008 - nil), as determined by the closing price of common shares of Glamis Resources Ltd.

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

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

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