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Press release from Marketwire

Bonavista Energy Trust Announces Third Quarter Results

Thursday, November 04, 2010

Bonavista Energy Trust Announces Third Quarter Results16:42 EDT Thursday, November 04, 2010CALGARY, ALBERTA--(Marketwire - Nov. 4, 2010) - 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, 2010.----------------------------------------------------------------------------Highlights---------------------------------------------------------------------------- Three months ended Nine months ended September 30, % September 30, % 2010 2009 Change 2010 2009 Change----------------------------------------------------------------------------Financial($ thousands, except per unit)Production revenues 222,656 180,977 23% 704,020 526,553 34%Funds from operations (1) 123,562 104,869 18% 399,729 312,209 28% Per unit (1) (2) 0.79 0.80 (1%) 2.63 2.58 2%Distributions declared 64,106 55,678 15% 188,056 158,182 19% Per unit 0.48 0.48 - 1.44 1.52 (5%) Percentage of funds from operations(1) 52% 53% (1%) 47% 51% (4%)Net income 36,614 33,339 10% 161,797 66,959 142% Per unit(2) 0.24 0.25 (4%) 1.06 0.55 93%Adjusted net income(3) 34,762 31,506 10% 143,538 112,195 28% Per unit(2) 0.22 0.24 (8%) 0.94 0.93 1%Total assets 3,368,079 3,094,547 9%Long-term debt, net of working capital (4) 1,034,832 862,706 20%Long-term debt, net of adjusted working capital(3)(4) 1,040,185 872,237 19%Unitholders' equity 1,892,078 1,738,958 9%Capital expenditures: Exploration and development 84,657 43,303 95% 255,087 141,801 80% Acquisitions, net 15,168 594,602 (97%) 260,315 616,827 (58%)Weighted average outstanding equivalent trust units: (thousands)(2) Basic 155,604 131,845 18% 151,987 121,053 26% Diluted 156,602 133,684 17% 153,875 122,976 25%----------------------------------------------------------------------------Operating(boe conversion - 6:1 basis)Production: Natural gas (mmcf/day) 248 193 28% 237 180 32% Oil and liquids (bbls/day) 26,613 23,924 11% 26,010 23,024 13% Total oil equivalent (boe/day) 68,029 56,125 21% 65,569 53,097 23%Product prices:(5) Natural gas ($/mcf) 4.12 3.85 7% 4.65 4.75 (2%) Oil and liquids ($/bbl) 54.84 59.36 (8%) 58.25 56.50 3%Operating expenses ($/boe) 7.75 9.61 (19%) 8.12 10.10 (20%)General and administrative expenses ($/boe) 0.84 0.90 (7%) 0.86 0.87 (1%)Cash costs ($/boe)(6) 9.77 11.15 (12%) 9.95 11.63 (14%)Operating netback ($/boe)(7) 21.76 21.85 - 24.16 23.07 5%--------------------------------------------------------------------------------------------------------------------------------------------------------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 and losses on financial instrument contracts, their related tax impact and associated assets or liabilities.(4) Amounts exclude convertible debentures.(5) Product prices include realized gains and losses on financial instrument contracts.(6) Cash costs equal the total of operating, general and administrative, and financing expenses, calculated on a boe basis.(7) Operating netback equals production revenues including realized gains and losses on financial instrument contracts, less royalties, transportation and operating expenses, calculated on a boe basis. Three months ended ------------------------------------------------Trust Unit Trading September 30, June 30, March 31, December 31, Statistics 2010 2010 2010 2009----------------------------------------------------------------------------($ per unit, except volume)----------------------------------------------------------------------------High 24.91 25.60 25.70 24.00Low 22.34 22.03 22.40 19.86Close 23.89 22.81 23.35 22.30Average Daily Volume - Units 309,312 423,688 341,312 314,701--------------------------------------------------------------------------------------------------------------------------------------------------------MESSAGE TO UNITHOLDERSBonavista Energy Trust ("Bonavista" or the "Trust") is pleased to report to unitholders (the "Unitholders") its consolidated financial and operating results for the three and nine months ended September 30, 2010. Bonavista has continued its pattern of generating profitable results since commencing operations as an energy trust in July 2003. Despite continued volatility in both commodity and capital markets throughout 2010, we remain focused on the consistent execution of Bonavista's proven business strategies which has resulted in excellent operational and financial results. Corporate ConversionOn October 14, 2010 we announced our intent to convert to a dividend paying corporation effective December 31, 2010. The details of the conversion, which is subject to securityholder, regulatory and court approvals, will be included in an information circular anticipated to be mailed to securityholders in mid-November in preparation for a special meeting scheduled on December 14, 2010. Bonavista has been preparing diligently for this conversion over the past four years and today we are well positioned to provide our investors a combination of sustainable growth and a meaningful dividend in the new corporate structure. While the proven underlying operating strategies of the company will remain intact, our business model has been designed to deliver long term total shareholder returns of between 10 and 15% per annum.Corporate Dividend and Targeted Growth RateUpon conversion, Bonavista will strike a healthy balance between growth and income and we anticipate delivering both of these components over an extended period within the thresholds of projected cash flow. In this regard, the Board of Directors has decided to set the initial dividend rate at $0.12 per share per month commencing January 2011. This new dividend level will be approximately equivalent to the current $0.16 per trust unit distribution on an after tax basis to a taxable Canadian shareholder and will represent a dividend yield of approximately 6% based on the current trading range of Bonavista's trust units.The incremental cash flow available for reinvestment as a result of the lower payout ratio will be allocated to our high-impact resource development programs. Even in today's compressed natural gas price environment, these resource development programs offer attractive rates of return that far exceed Bonavista's cost of capital thereby enhancing overall returns to shareholder's equity. Furthermore, these programs exhibit attractive capital efficiencies and will provide for sustainable annual production growth of 5 to 7% under the new corporate structure.We are excited about the upcoming corporate conversion and the continued delivery of growth in shareholder value within this balanced business model. Over the past few years, we have strategically assembled a robust inventory of both conventional and unconventional growth opportunities that will support this business model for many years to come. Q3 2010 accomplishmentsThe third quarter of 2010 was characterized by an active and successful exploration and development drilling program resulting in significant increases in production and reserves at attractive reinvestment efficiencies.Specific accomplishments for Bonavista in the third quarter of 2010 include:- Increased production volumes to a record level of 68,029 boe per day. This represents a 3% increase over production levels in the second quarter of 2010 and a 21% increase over production levels in the third quarter of 2009. We are currently producing 69,500 boe per day representing another record production achievement. Despite some weather related challenges encountered in the latter part of the third quarter, production additions over the first nine months of 2010 resulting from our exploration and development program have met expectations, reinforcing our confidence in our 2010 production targets and the efficiency of our organic growth opportunities as we approach 2011; - Executed an effective capital program during the quarter investing $84.7 million in exploration and development activities drilling 40 wells with an overall 98% success rate. Drilled 21 successful horizontal wells which include unconventional resource development in the Glauconite, Cardium, Montney, Viking, Bluesky and Belly River horizons. The key highlights of our horizontal drilling program are as follows:a) Drilled seven horizontal wells and participated in four non-operated horizontal wells on the highly prospective Hoadley Glauconite trend in our Western Core Region. Our Hoadley Glauconite liquids rich natural gas development program remains one of the cornerstones of growth for our company and continues to impress with its consistency and ability to deliver meaningful economics even in today's low natural gas price environment. Bonavista has now drilled 55 horizontal Glauconite wells successfully testing the resource across 60 miles of the Hoadley trend. The production profile of the producing wells to date continues to meet or exceed our expectations with initial one month production rates of 500 to 600 boe per day which includes a highly valuable liquids stream of 150 to 180 bbls per day of natural gas liquids. Since closing our strategic Hoadley acquisition in August 2009, we've increased our exposure to this play by approximately 50% through successful step out development and land consolidation activities. Our remaining inventory of 275 horizontal drilling prospects on the Hoadley Glauconite trend will result in an attractive multi-year development program with on-stream capital efficiencies of approximately $6,000 per boe per day. Bonavista believes that our Glauconite horizontal development program is one of the most profitable liquids rich natural gas resource developments in North America with economics that outperform many oil projects being developed today. Single well economics are exceptionally attractive and provide abundant capital spending flexibility with half-cycle breakeven economics of approximately $2.00 per mcf.b) Drilled three horizontal wells and participated in two additional non-operated horizontal wells on the emerging unconventional Cardium light oil play in our Western Core Region. With 22 horizontal Cardium wells drilled to date, our confidence in the repeatability and the profitability of this resource play is steadily increasing. With the majority of our 300 section land base currently being held by production, we have been able to prudently advance our 2010 development program by focusing on higher impact areas within this attractive, yet variable, light oil resource play. We continue to see an improvement in initial production results as we focus our development program and refine our completion techniques. Our recent wells have delivered average one month initial production rates of 150 to 200 boe per day and our latest well, drilled at Willesden Green, is expected to deliver an average of 500 boe per day in its first month of production. c) Drilled our first Bluesky horizontal well on lands we acquired through the $230 million Deep Basin acquisition which closed in May 2010. Initial test results are positive and we anticipate continued allocation of capital to the Bluesky and other liquids rich natural gas resource plays in the area including the Rock Creek, Wilrich, Cardium, Montney and Notikewin formations. Since closing of this strategic acquisition we have increased our inventory of liquids rich natural gas drilling opportunities by 60% to 80 locations and have held production steady at approximately 3,500 boe per day, with modest capital reinvestment. d) Assembled a contiguous land position of 55 net sections in the Blueberry area of North East British Columbia which is prospective for unconventional resource development in both the upper and lower Montney horizons. Our initial delineation program has delivered encouraging results with one vertical well and one horizontal well drilled to date in the upper Montney. Initial tests have produced a high heat content natural gas stream suggesting the presence of significant natural gas liquids. Our first horizontal well has been on production for 10 days at a restricted rate of 650 boe per day of which 75% is liquids production. We are very excited with the initial results of this discovery and are currently drilling one additional horizontal well in 2010 and plan to continue the delineation of our land base with an additional four horizontal wells in 2011.- Participated at Crown land sales in the third quarter of 2010 purchasing approximately 20,000 net acres of undeveloped land spending $18.3 million. In the first nine months of 2010, Bonavista has purchased a record 101,000 net acres at Crown land sales, spending $60.7 million, enhancing our ability to sustainably generate profitable drilling opportunities for many years to come;- Achieved significant improvements in our cost structure with operating costs on a per boe basis decreasing 19% for the three months ended September 30, 2010 to $7.75 per boe from $9.61 per boe in the comparable period of 2009. These improvements stem from continued cost discipline in all operating areas led by reduced energy costs, coupled with lower per unit operating costs from acquisitions and continued development drilling in areas where we own and operate infrastructure with ample processing capacity and attractive processing costs;- Generated funds from operations of $123.6 million ($0.79 per unit) for the three months ended September 30, 2010. Bonavista distributed 52% of these funds to Unitholders with the remaining funds reinvested in the business to continue growing our production base;- Completed the renewal of Bonavista's $1.4 billion bank loan facility for an additional three year term to September 10, 2013. Additionally on November 2, 2010, Bonavista completed the issue of approximately $350 million of senior unsecured notes by way of a private placement. The notes have a blended rate of 4.1% and a weighted average term of approximately 8.8 years;- Continued to record attractive levels of profitability in the third quarter of 2010 with a return on equity of 8% and an adjusted net income to funds from operations ratio of 28%. The above ratios reflect net income adjusted to negate the after tax impact of the unrealized gains and losses on financial instrument contracts; and- Since inception as a Trust, Bonavista has delivered cumulative distributions of $1.9 billion or $22.71 per trust unit. These cumulative distributions are in excess of our closing price of $16.00 per trust unit on the first trading day after we became an energy trust on July 2, 2003. Strengths of Bonavista Energy TrustUpon restructuring from an exploration and production corporation into an energy trust in July 2003 and as we approach our conversion back to the corporate model at the end of 2010, Bonavista remains committed to the same strategies that resulted in our tremendous success from inception to date. We have maintained a high level of investment activity on our asset base, increasing current production by approximately 89% since 2003. This activity stems from the operational and technical focus of our people, their attention to detail, and their entrepreneurial approach to generating 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 long-term profitable results to our Unitholders. We actively participate in undeveloped land acquisitions through Crown land sales, property purchases and 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 is weighted 62% toward natural gas 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 most operating environments. In addition, our asset base is predominantly operated by Bonavista, providing control over the pace of operations and ensuring that operating and capital cost efficiencies are consistently optimized. 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. Our Board of Directors and management team possess extensive experience in the oil and natural gas business. They have successfully guided our organization through many different economic cycles utilizing a proven strategy consisting of disciplined cost controls and prudent financial management. Directors, management and employees also own approximately 15% of the Trust, resulting in the alignment of interests with all Unitholders.MANAGEMENT'S DISCUSSION AND ANALYSISManagement'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, 2009. The following MD&A of the financial condition and results of operations was prepared at, and is dated November 4, 2010. Our audited consolidated financial statements, Annual Report, and other disclosure documents for 2009 are available through our filings on SEDAR at www.sedar.com or can be obtained from Bonavista's website at www.bonavistaenergy.com. Basis of Presentation - The financial data presented below has been prepared in accordance with Canadian Generally Accepted Accounting Principles ("GAAP"). The reporting and the measurement currency is the Canadian dollar. For the purpose of calculating unit costs, natural gas is converted to a barrel of oil equivalent ("boe") using six thousand cubic feet of natural gas equal to one barrel of oil unless otherwise stated. A boe may be misleading, particularly if used in isolation. A boe conversion of 6 mcf to one barrel is based on an energy equivalent conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Forward-Looking Statements - Certain information set forth in this document, including management's assessment of Bonavista's future plans and operations, contains forward-looking statements including: (i) forecasted capital expenditures; (ii) exploration, drilling and development plans; (iii) prospects and inventory; (iv) anticipated production rates; (v) expected royalty rate; (vi) anticipated operating and service costs; (vii) our financial strength; (viii) incremental development opportunities; (ix) expected conversion to a corporation, the timing thereof and our business model of combined growth and income; (x) anticipated natural gas supply and demand; (xi) reserve life index; (xii) utilization of technology; and (xiii) rate of return and dividend yield, 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 and losses on financial instrument contracts, 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 2010 led to the drilling of 101 wells within our core regions with an overall success rate of 98%. This program resulted in 53 natural gas wells and 46 oil wells. Profitability continues to guide our exploration and development program which remains flexible to changes in commodity price, development risk and deliverability upside. Once again, our operations in the third quarter 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 continue to enhance the predictability in our overall production base in addition to lengthening our reserve life index ("RLI") to approximately 12 years on a proved plus probable basis. Production - For the third quarter of 2010, production increased 21% to a record level of 68,029 boe per day when compared to 56,125 boe per day for the same period a year ago. Natural gas production increased 28% to 248 mmcf per day in the third quarter of 2010 from 193 mmcf per day for the same period a year ago, while total oil and liquids production increased 11% to 26,613 bbls per day in the third quarter of 2010 from 23,924 bbls per day for the same period in 2009. For the nine months ended September 30, 2010, production increased 23% to 65,569 boe per day when compared to 53,097 boe per day for the same period a year ago. Natural gas production increased 32% to 237 mmcf per day in the first nine months of 2010 from 180 mmcf per day for the same period a year ago, while total oil and liquids production increased 13% to 26,010 bbls per day in the first nine months of 2010 from 23,024 bbls per day for the same period in 2009. The following table highlights Bonavista's production by product for the three and nine months ended September 30: ---------------------------------------------------------------------------- Three months ended Nine months ended September 30, September 30, 2010 2009 2010 2009----------------------------------------------------------------------------Natural gas (mmcf/day) 248 193 237 180Oil and liquids (bbls/day): Light and medium oil 21,688 18,499 21,076 17,422 Heavy oil 4,925 5,425 4,934 5,602 ---------------------------------------Total oil and liquids (bbls/day) 26,613 23,924 26,010 23,024----------------------------------------------------------------------------Total oil equivalent (boe/day) 68,029 56,125 65,569 53,097--------------------------------------------------------------------------------------------------------------------------------------------------------Our current production is approximately 69,500 boe per day, consisting of 62% natural gas, 31% light and medium oil and 7% heavy oil. Production revenues - Production revenues for the third quarter of 2010 increased 23% to $222.7 million when compared to $181.0 million for the same period a year ago, due mainly to increased production volumes. For the three months ended September 30, 2010, natural gas prices increased 7% to $4.12 per mcf, when compared to $3.85 per mcf realized in the same period in 2009. The average oil and liquids price decreased 8% to $54.84 per bbl for the three months ended September 30, 2010 from $59.36 per bbl for the same period in 2009. For the nine months ended September 30, 2010, production revenues increased 34% to $704.0 million when compared to $526.6 million for the same period a year ago, largely due to increased production volumes. For the nine month period ended September 30, 2010, natural gas prices decreased 2% to $4.65 per mcf, when compared to $4.75 per mcf realized in the same period in 2009. The average oil and liquids price increased 3% to $58.25 per bbl for the nine month period ended September 30, 2010 from $56.50 per bbl for the same period in 2009.The following table highlights Bonavista's realized commodity pricing for the three and nine months ended September 30:---------------------------------------------------------------------------- Three months ended Nine months ended September 30, September 30, 2010 2009 2010 2009----------------------------------------------------------------------------Natural gas ($/mcf): Production revenues $ 3.88 $ 3.45 $ 4.49 $ 4.39 Realized gain on financial instrument contracts 0.24 0.40 0.16 0.36 --------------------------------------- 4.12 3.85 4.65 4.75 --------------------------------------- ---------------------------------------Light and medium oil ($/bbl): Production revenues 54.01 53.17 57.65 49.10 Realized gain on financial instrument contracts 0.05 6.09 0.09 8.57 --------------------------------------- 54.06 59.26 57.74 57.67 --------------------------------------- ---------------------------------------Heavy oil ($/bbl): Production revenues 58.24 58.53 60.39 50.32 Realized gain on financial instrument contracts - 1.16 0.04 2.55 --------------------------------------- 58.24 59.69 60.43 52.87 --------------------------------------- ---------------------------------------Total ($/boe): Production revenues 35.58 35.05 39.33 36.32 Realized gain on financial instrument contracts 0.91 3.50 0.62 4.32 --------------------------------------- $ 36.49 $ 38.55 $ 39.95 $ 40.64--------------------------------------------------------------------------------------------------------------------------------------------------------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, costs and protect acquisition economics. Bonavista's Board of Directors has approved a commodity price risk management limit of 60% of forecast production, net of royalties, primarily using costless collars. Our strategy of using costless collars limits Bonavista's exposure to downturns in commodity prices, while allowing for participation in commodity price increases. For the third quarter of 2010, our risk management program on financial instrument contracts resulted in a net gain of $3.2 million, consisting of a realized gain of $5.7 million and an unrealized loss of $2.5 million. The realized gain of $5.7 million consisted of a $5.6 million gain on natural gas commodity derivative contracts and a $108,000 gain on crude oil commodity derivative contracts. For the same period in 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 nine months ended September 30, 2010, our risk management program on financial instrument contracts resulted in a net gain of $35.9 million, consisting of a realized gain of $11.2 million and an unrealized gain of $24.8 million. The realized gain of $11.2 million consisted of a $10.6 million gain on natural gas commodity derivative contracts and a $600,000 gain on crude oil commodity derivative contracts. For the same period in 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. Royalties - For the three months ended September 30, 2010, royalties increased by 23% to $33.1 million from $27.0 million for the same period a year ago, largely attributed to a significant increase in production volumes. In addition, royalties as a percentage of revenues (including realized gains and losses on financial instrument contracts) for the third quarter of 2010 increased to 14.5% as compared to 13.6% in 2009. The increase in royalty rates is due largely from the impact of lower realized gains on financial instrument contracts and a higher percentage of natural gas liquids production volumes that attract higher royalty rates. For the nine months ended September 30, 2010, royalties increased by 34% to $108.4 million from $80.9 million for the same period a year ago, for similar reasons as stated above. In addition, royalties as a percentage of revenues (including realized gains and losses on financial instrument contracts) for the first nine months of 2010 increased to 15.2% compared to 13.7% in 2009. The increase in royalty rates is again largely due to similar reasons as discussed above.The following table highlights Bonavista's royalties by product for the three and nine months ended September 30:---------------------------------------------------------------------------- Three months ended Nine months ended September 30, September 30, 2010 2009 2010 2009----------------------------------------------------------------------------Natural gas ($/mcf): Royalties 0.40 0.33 0.46 0.62 % of revenues (1) 9.8% 8.5% 10.0% 13.0%----------------------------------------------------------------------------Light and medium oil ($/bbl): Royalties 9.71 9.28 11.08 8.07 % of revenues (1) 18.0% 15.7% 19.2% 14.0%----------------------------------------------------------------------------Heavy oil ($/bbl): Royalties 9.97 10.81 10.90 7.85 % of revenues (1) 17.1% 18.1% 18.0% 14.9%----------------------------------------------------------------------------(1) % of revenues include realized gains and losses on financial instrument contractsOn January 1, 2009 the Alberta Government's New Royalty Framework ("NRF") took effect. Subsequent to this legislation the Government of Alberta has introduced a number of programs to stimulate new and continued economic activity in Alberta. The Transitional Royalty Plan ("TRP"), which expires December 31, 2013, offers reduced royalty rates for new wells drilled that meet certain depth requirements. In addition to the TRP, a second royalty incentive program was announced by the Government of Alberta. The Three Point Incentive Plan includes a drilling royalty credit for new conventional oil and natural gas wells and a new royalty incentive program, this program is set to expire on March 31, 2011 and will add approximately $28 million in royalty and drilling credits to Bonavista for 2010. On March 11, 2010 the Alberta Competitiveness Review board made a number of recommendations for further improvements to Alberta's current royalty structure. These recommendations become effective on a permanent basis for the January 2011 production month and are outlined as follows:- The current incentive program rate of 5% on new natural gas and conventional oil wells will become a permanent feature of the royalty system, with the current time and volume limits;- The maximum royalty rate for conventional oil will be reduced at higher price levels from 50% to 40% to provide better risk-reward balance to investors;- Recognizing the fundamental changes to the North American supply/demand balance and increased competition from other jurisdictions, the maximum royalty rate for conventional and unconventional natural gas will be reduced at higher price levels from 50% to 36%; and- The NRF legislated in November 2008 will continue until its original announced expiration on December 31, 2013. Effective January 1, 2011, no new wells will be allowed to select the transitional royalty rates. Wells that have already selected the transitional royalty rates will have the option to stay with those rates or switch to the new rates effective January 1, 2011.On May 27, 2010 the Government of Alberta revealed its proposed changes to the base royalty curves for both conventional oil and natural gas, which are to take effect on January 1, 2011. The Government also unveiled further initiatives, as a result of the competiveness review, intended to energize investment and encourage development of Alberta's unconventional and deep resource pools. The most significant of these initiatives are modifications to the natural gas deep drilling program and the implementation of the emerging resources and technologies initiative. The change in the qualifying depth of the deep drilling program from 2,500 to 2,000 meters true vertical depth has increased the number of horizontal wells applicable for this credit by approximately 130 wells in our Hoadley Glauconite development program. This depth change will result in a significant royalty credit of approximately $1.0 million per Glauconite horizontal well.Operating expenses - Operating expenses for the three months ended September 30, 2010 decreased 2% to $48.5 million compared to $49.6 million for the same period a year ago. For the three months ended September 30, 2010 operating costs on a per boe basis decreased 19% to $7.75 per boe compared to $9.61 per boe in the comparable period of 2009. This significant decrease on a per boe basis is attributed to efficiency gains derived from production additions through our recent drilling, lower per unit operating costs from acquisitions, lower electricity costs and our ongoing operating cost reduction initiatives. Operating expenses for the nine months ended September 30, 2010 decreased 1% to $145.3 million compared to $146.4 million for the same period a year ago. For the nine months ended September 30, 2010 operating costs on a per boe basis decreased 20% to $8.12 per boe, from $10.10 per boe in the comparable period of 2009 for similar reasons as stated above. Bonavista anticipates that operating costs on a per boe basis will decrease in 2010 to approximately $8.00 per boe as compared to $9.80 per boe in 2009.The following table highlights Bonavista's operating expenses by product for the three and nine months ended September 30:---------------------------------------------------------------------------- Three months ended Nine months ended September 30, September 30, 2010 2009 2010 2009----------------------------------------------------------------------------Natural gas ($/mcf) $ 1.08 $ 1.34 $ 1.14 $ 1.45Light and medium oil ($/bbl) 8.65 10.83 9.06 10.89Heavy oil ($/bbl) 14.47 14.85 14.44 15.09----------------------------------------------------------------------------Total ($/boe) $ 7.75 $ 9.61 $ 8.12 $ 10.10--------------------------------------------------------------------------------------------------------------------------------------------------------Transportation expenses - For the three months ended September 30, 2010, transportation expenses increased 9% to $10.5 million ($1.68 per boe) compared to $9.6 million ($1.87 per boe) for the same period in 2009. For the nine months ended September 30, 2010, transportation expenses increased 6% to $29.0 million ($1.62 per boe) compared to $27.4 million ($1.89 per boe) for the same period in 2009. Per unit transportation costs have decreased 10% and 14% over the three and nine months ended September 30, 2010 as a result of our significant increase in production volumes in areas with lower associated transportation costs. The following table highlights Bonavista's transportation expenses by product for the three and nine months ended September 30:---------------------------------------------------------------------------- Three months ended Nine months ended September 30, September 30, 2010 2009 2010 2009----------------------------------------------------------------------------Natural gas ($/mcf) $ 0.32 $ 0.34 $ 0.31 $ 0.35Light and medium oil ($/bbl) 0.81 0.94 0.83 0.92Heavy oil ($/bbl) 3.30 3.89 3.28 3.92----------------------------------------------------------------------------Total ($/boe) $ 1.68 $ 1.87 $ 1.62 $ 1.89--------------------------------------------------------------------------------------------------------------------------------------------------------General and administrative expenses - General and administrative expenses, after overhead recoveries, increased 14% to $5.3 million for the three months ended September 30, 2010 from $4.6 million in the same period in 2009 and increased 22% to $15.5 million for the nine months ended September 30, 2010 from $12.7 million in the same period in 2009. These increases are largely due to higher costs of personnel required to manage our growing operations. On a per boe basis, general and administrative expenses decreased 7% for the three months ended September 30, 2010 to $0.84 per boe from $0.90 per boe in the same period in 2009 and decreased 1% to $0.86 per boe for the nine months ended September 30, 2010 from $0.87 per boe in the same period in 2009. Our current rate of general and administrative expenses on a boe basis 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 $3.1 million and $8.5 million for the three and nine months ended September 30, 2010 respectively, compared to $2.9 million and $8.4 million for the same periods in 2009.Financing expenses - Financing expenses increased 122% to $7.4 million for the three months ended September 30, 2010, from $3.3 million for the same period in 2009 and on a per boe basis, increased 84% to $1.18 per boe for the three months ended September 30, 2010 from $0.64 per boe for the same period in 2009. For the nine months ended September 30, 2010, financing expenses increased 81% to $17.3 million from $9.6 million for the same period in 2009 and on a per boe basis, increased 45% to $0.96 per boe for the nine months ended September 30, 2010 from $0.66 per boe for the same period in 2009. The increase in financing expenses for the three and nine months ended September 30, 2010 compared to the same period in 2009 is largely the result of an increase in borrowing costs on our bank loan facilities, an increase in our average debt levels and an increase in interest rates. With the recently renewed bank loan facility and the issuance of the senior unsecured notes, we expect an increase in our average borrowing costs. During the third quarter of 2010, Bonavista paid cash interest of $7.7 million compared to $2.5 million for the same period in 2009. For the nine months ended September 30, 2010, Bonavista paid cash interest of $16.0 million compared to $9.2 million for the same period in 2009. Bonavista's effective interest rate as at September 30, 2010 was approximately 3.3% (2009 - 1.4%). Depreciation, depletion and accretion expenses - Depreciation, depletion and accretion expenses increased 18% to $91.7 million for the three months ended September 30, 2010 from $77.8 million for the same period of 2009. For the nine months ended September 30, 2010, depreciation, depletion and accretion expenses increased 25% to $263.0 million from $210.1 million for the same period of 2009. These increases are largely due to an increase in our overall production base compared to the same periods in 2009. For the three months ended September 30, 2010, the average cost decreased 3% to $14.65 per boe from $15.07 per boe for the same period in 2009 and for the nine months ended September 30, 2010, the average cost increased slightly to $14.70 per boe from $14.49 per boe for the same period a year ago. Income taxes - For the three months ended September 30, 2010, the income tax recovery was $8.8 million compared to an income tax recovery of $7.4 million for the same period in 2009. For the nine months ended September 30, 2010, the income tax recovery was $5.9 million compared to an income tax recovery of $36.8 million for the same period in 2009. The income tax recovery for the nine months ended September 30, 2010 is mainly attributable to the unrealized gain on financial instrument contracts. Bonavista made no cash payments on tax installments for the three and nine months ended September 30, 2010 or for the comparative periods in 2009.Funds from operations, net income and comprehensive income - For the three months ended September 30, 2010, Bonavista experienced a 18% increase in funds from operations to $123.6 million ($0.79 per unit, basic) from $104.9 million ($0.80 per unit, basic) for the same period in 2009. For the nine months ended September 30, 2010, Bonavista experienced a 28% increase in funds from operations to $399.7 million ($2.63 per unit, basic) from $312.2 million ($2.58 per unit, basic) for the same period in 2009. Funds from operations increased for the three months ended September 30, 2010 largely due to increased production volumes. Net income and comprehensive income for the three months ended September 30, 2010, increased 10% to $36.6 million ($0.24 per unit, basic) from $33.3 million ($0.25 per unit, basic) for the same period in 2009. For the nine months ended September 30, 2010, net income and comprehensive income increased 142% to $161.8 million ($1.06 per unit, basic) from $67.0 million ($0.55 per unit, basic) for the same period in 2009. The following table is a reconciliation of a non-GAAP measure, funds from operations, to its nearest measure prescribed by GAAP:---------------------------------------------------------------------------- Three months ended Nine months ended September 30, September 30,Calculation of Funds From Operations: 2010 2009 2010 2009----------------------------------------------------------------------------(thousands)Cash flow from operating activities $ 134,290 $ 87,492 $ 398,423 $269,175Asset retirement expenditures 4,256 3,338 8,819 8,596Changes in non-cash working capital (14,984) 14,039 (7,513) 34,438----------------------------------------------------------------------------Funds from operations $ 123,562 $104,869 $ 399,729 $312,209--------------------------------------------------------------------------------------------------------------------------------------------------------Capital expenditures - Capital expenditures for the three months ended September 30, 2010 were $99.8 million, consisting of $84.7 million spent on exploration and development activities and net property acquisitions of $15.1 million. For the same period in 2009, capital expenditures were $637.9 million, consisting of $43.3 million spent on exploration and development and $594.6 million spent on net property acquisitions. Capital expenditures for the nine months ended September 30, 2010 were $515.4 million, consisting of $255.1 million spent on exploration and development activities and net property acquisitions of $260.3 million. For the same period in 2009 capital expenditures were $758.6 million, consisting of $141.8 million on exploration and development spending and $616.8 million on net property acquisitions. Our service costs supporting our exploration and development activities have remained relatively stable across the first three quarters of 2010, however, the recent increase in industry activity may inherently drive an increase in the cost of services into 2011. Bonavista will continue to focus on maintaining similar long-term relationships with service providers in specific operating areas where we have remained active in the past.Liquidity and capital resources - As at September 30, 2010, long-term debt including working capital (excluding associated assets and liabilities from financial instrument contracts and their related tax impact) was $1.0 billion with a debt to third quarter 2010 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 facility of $1.4 billion, of which $477.4 million is unused borrowing capability as at September 30, 2010. Proforma the issuance of the senior unsecured notes subsequent to September 30, 2010 there would be approximately $827 million of unused borrowing capability.On September 10, 2010 Bonavista combined and renewed its bank loan facilities into a single facility of $1.4 billion provided by a syndicate of 12 domestic and international banks. This 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. The facility has a maturity date of September 10, 2013. Under the terms of the credit facility, the Trust has provided the covenant that its: (i) consolidated senior debt borrowing will not exceed three times net income before unrealized gains and losses on financial instrument contracts and marketable securities, 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 instrument contracts and marketable securities, 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 the second quarter of 2010, the Trust entered into an uncommitted master shelf agreement that allows for an aggregate draw of up to US$125 million in notes at a rate equal to the related US treasury corresponding to the term of the notes plus an appropriate credit risk adjustment at the time of issuance. On June 4, 2010 the Trust drew down US$50 million on the master shelf agreement with a coupon rate of 4.86% with US$25.0 million maturing on June 4, 2016 and the remaining US$25.0 million maturing on June 4, 2017. Under the terms of the master shelf agreement, the Trust has provided the same significant covenants that exist under the bank credit facility.Subsequent to September 30, 2010, Bonavista issued via a private placement US$300 million and CDN$50 million of long-term notes with a weighted average coupon rate of 4.12% and a weighted average term of 8.8 years. Proceeds from the issuance were used to repay existing long-term debt under the bank loan facility.In 2010, Bonavista plans to invest approximately $600 million on its capital programs within its core regions. This capital budget includes the acquisition of certain long-life natural gas weighted properties located adjacent to its Whitecourt property in west central Alberta for a purchase price of $230.4 million. The Trust intends on financing its 2010 capital program with a combination of funds from operations, proceeds received from a $177.0 million bought deal financing, property dispositions 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, 2010, Bonavista had 155.7 million equivalent trust units outstanding. This includes 9.4 million exchangeable shares, which are exchangeable into 22.1 million trust units. The exchange ratio in effect at September 30, 2010 for exchangeable shares was 2.35147:1. As at November 4, 2010, Bonavista had 155.8 million equivalent trust units outstanding. This includes 9.4 million exchangeable shares, which are exchangeable into 22.2 million trust units. The exchange ratio in effect at November 4, 2010 for exchangeable shares was 2.36741:1. In addition, Bonavista has 4.3 million trust unit incentive rights outstanding at November 4, 2010, with an average exercise price of $20.60 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 main objectives of the Trust has been to maintain sustainability, which is defined as maintaining both production and reserves over an extended period of time with a minimum amount of capital. 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, 2010, the Trust declared distributions of $64.1 million ($0.48 per unit) compared to $55.7 million ($0.48 per unit) in the same period in 2009. For the nine months ended September 30, 2010 the Trust declared distributions of $188.1 million ($1.44 per unit) compared to $158.2 million ($1.52 per unit) in the same period in 2009. 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 instrument contracts, fluctuations in future income taxes due to changes in tax rates and tax rules, unit-based compensation and foreign exchange gains or losses. 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, 2010, the non-cash charges amounted to $86.9 million compared to $70.7 million for the same period in 2009. For the nine months ended September 30, 2010, the non-cash charges amounted to $239.8 million compared to $244.5 million for the same period in 2009. 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 ended Nine months ended September 30, September 30,Distribution Analysis 2010 2009 2010 2009----------------------------------------------------------------------------(thousands)Cash flow provided from operating activities $ 134,290 $ 87,492 $ 398,423 $ 269,175Net income 36,614 33,339 161,797 66,959Distributions declared 64,106 55,678 188,056 158,182Excess of cash flow provided from operating activities over distributions declared 70,184 31,814 210,367 110,993Excess (shortfall) of net income over distributions declared (27,492) (22,339) (26,259) (91,223)--------------------------------------------------------------------------------------------------------------------------------------------------------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. For 2010, 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. Our current distribution rate of $0.16 per unit per month will place us slightly below this targeted level for the year assuming current strip prices are realized. On October 14, 2010, Bonavista announced its intention to convert to a corporation on December 31, 2010. Bonavista expects to deliver a 5 to 7% production growth rate and expects to pay a monthly dividend of $0.12 per share for the production month beginning January 2011.Quarterly financial information - The following table highlights Bonavista's performance for the eight quarterly periods ending on December 31, 2008 to September 30, 2010: ---------------------------------------------------------------------------- 2010 -------------------------------- September 30 June 30 March 31 --------------------------------($ thousands, except per unit amounts)Production revenues 222,656 227,732 253,632Net income 36,614 45,449 79,734Net income per unit: Basic 0.24 0.30 0.54 Diluted 0.23 0.30 0.53------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------ 2009 2008 ------------------------------------------- ------------ December 31 September 30 June 30 March 31 December 31 ------------------------------------------- ------------($ thousands, except per unit amounts)Production revenues 232,870 180,977 166,430 179,146 221,782Net income 39,647 33,339 661 32,959 129,192Net income per unit: Basic 0.27 0.25 0.01 0.28 1.09 Diluted 0.27 0.25 0.01 0.28 1.09--------------------------------------------------------------------------------------------------------------------------------------------------------Production revenues over the past eight quarters have fluctuated largely due to the volatility of commodity prices and increasing production volumes. 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 $129.2 million in the fourth quarter of 2008. These fluctuations are primarily influenced by production volumes, commodity prices, realized and unrealized gains and losses on financial instrument contracts and future income tax recoveries associated with the reduction in corporate income tax rates. Net income increased 10% in the third quarter of 2010 as compared to the third quarter of 2009. The increase in net income in the third quarter of 2010 is largely attributed to higher production volumes and revenues as compared to the same period in 2009. Disclosure controls and procedures - Disclosure controls and procedures have been designed to ensure that information to be disclosed by Bonavista is accumulated and communicated to management, as appropriate, to allow timely decisions regarding required 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 appropriately designed and operating effectively to provide reasonable assurance that material information relating to the issuer is made known to them by others within the Trust. Internal control over financial reporting - Internal control over financial reporting is a process designed to provide reasonable assurance that all assets are safeguarded, transactions are appropriately authorized and to facilitate the preparation of relevant, reliable and timely information. 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. Management has assessed the effectiveness of Bonavista's internal control over financial reporting as defined by National Instrument 52-109, Certification of Disclosure in Issuers' Annual and Interim Filings. Management has concluded that their internal control over financial reporting was effective as of September 30, 2010. There were no material changes to the internal controls over financial reporting during the three months ended September 30, 2010.Update on SIFT tax and corporate conversion - On October 14, 2010 Bonavista announced its intent to convert to a dividend paying corporation. We anticipate securityholder, regulatory and court approvals in the fourth quarter of 2010 to allow Bonavista to begin operating within the new legal structure in 2011. Bonavista has been preparing diligently for this conversion over the past few years and feel we are well positioned to provide our investors a combination of sustainable growth and meaningful income within a dividend paying corporate structure. While the proven underlying operating strategies of the company will remain intact, our new business model has been designed to deliver long term total shareholder returns of between 10 and 15% per annum. International financial reporting standards - On January 1, 2011 International Financial Reporting Standards ("IFRS") will become the generally accepted accounting principles in Canada. The adoption date of January 1, 2011 will require restatement, for comparative purposes, of amounts reported by Bonavista for the year ended December 31, 2010, including the opening balance sheet as at January 1, 2010. An internal project team assisted by external consultants has been set up to manage the conversion from Canadian GAAP to IFRS. The members of this project team have attended IFRS industry specific seminars and continue to guide the Trust's transition to IFRS. The Trust's auditors have and continue to be involved throughout the process to ensure that the Trust's accounting policies are in accordance with the standards set out by IFRS.In July 2009, the International Accounting Standards Board ("IASB") issued amendments to IFRS 1, "First Time Adoption of IFRS" allowing an entity that used full cost accounting under its previous GAAP, 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 Trust currently plans to adopt this exemption under IFRS 1. IFRS 1 also provides a number of other optional and mandatory exemptions in certain areas to the general requirement for full retrospective application of IFRS. Management is analyzing the various exemptions available under IFRS 1 and will implement those determined to be the most appropriate for the Trust which at this time are summarized as follows:- Property, Plant and Equipment ("PP&E") - IFRS 1 provides the option to value the PP&E assets at their deemed cost being the Canadian GAAP net book value assigned to these assets as at the date of transition, January 1, 2010. This amendment is for entities that follow the full cost accounting guidelines under Canadian GAAP that accumulate all oil and natural gas assets into one cost centre. Under IFRS, the Trust's PP&E assets are allocated to cash generating units ("CGU"); the net book value of these assets on the date of transition will be allocated to the CGU's on the basis of either reserve value or reserve volumes at January 1, 2010. Bonavista has completed its review and will be allocating its net book value to its CGU's based upon its reserve values.- Business Combinations - IFRS 1 would allow the Trust to use the IFRS rules from business combinations on a prospective basis rather than restating all business combinations. Bonavista will not be recording any adjustments to retrospectively restate any of its business combinations that have occurred prior to January 1, 2010.The transition from present Canadian GAAP to IFRS on January 1, 2011 is significant and may materially affect our reported financial position and results of operations. At this time, Bonavista has identified the following key differences that will impact its financial statements:- Exploration and Evaluation ("E&E") expenditures - Upon transition to IFRS, Bonavista will reclassify all E&E expenditures that are currently included in the PP&E balance on the Consolidated Balance Sheet. This will consist of the book value for Bonavista's undeveloped land that relates to exploration properties. E&E assets will not be depleted and must be assessed for impairment when indicators of impairment exist. We are currently reviewing the non-depletable pool for impairment.- Depletion Expense - Upon transition to IFRS, Bonavista will calculate depletion based upon using proved and probable reserves. - Impairment of PP&E assets - Under IFRS, an impairment test of PP&E must be performed on specific portions of PP&E as opposed to the entire PP&E balance, which is currently required under Canadian GAAP through the full cost ceiling test. The Trust is required to recognize an impairment loss if the carrying amount of any property, plant and equipment exceeds its estimated future discounted cash flows. Under Canadian GAAP, estimated future cashflows used to assess impairments are not discounted. The Trust does not anticipate any impairment of property, plant and equipment as at January 1, 2010 as a result of adopting IFRS. - Provisions for Asset Retirement costs - Under IFRS, Bonavista is required to revalue its liability for asset retirement costs at each balance sheet date using a current liability specific discount rate. Under present Canadian GAAP, once recorded, asset retirement obligations are not adjusted for future changes in discount rates. The Trust has made a preliminary decision to discount the estimated fair value of its asset retirement obligations and the related property, plant and equipment assets using a risk-free interest rate. IFRS also requires that asset retirement obligations be re-measured each reporting period for changes in the discount rate with a corresponding adjustment to the cost of property, plant and equipment, whereas under Canadian GAAP, changes in discount rates do not result in a re-measurement.- Future Income Taxes - IFRS requires the Trust to measure future income taxes using the tax rate applicable to earnings not distributed to Unitholders whereas, under Canadian GAAP, future income taxes are measured using the tax rate applicable to distributed earnings.- Exchangeable Shares - Under IFRS, exchangeable shares are considered to be a puttable financial instrument and will be classified as a current financial liability. They will be recorded on the statement of financial position at their fair value with any changes being recorded in the statement of comprehensive income. Upon conversion to a corporation, exchangeable shares under IFRS will be classified as equity.- Unit-based payments - Under IFRS, Bonavista's trust unit incentive rights awards are considered to be cash-settled awards and will be classified as a liability. The liability is measured at fair value with subsequent changes in the fair value recognized in the statement of comprehensive income. Under Canadian GAAP, the Trust uses the fair value based method for the determination of the unit-based compensation costs. Upon conversion to a corporation, share based awards under IFRS will be classified as equity.Other post-conversion accounting policy choices and difference between IFRS and Canadian GAAP differences are not expected to materially impact the financial position or financial results of the Trust. Although the Trust has yet to determine the impact that componentization of property, plant and equipment under IFRS will have on the determination of its calculation of depreciation and depletion, it is not expected that there will be material changes to the carrying value if its property, plant and equipment nor to its depreciation and depletion expense on adoption of IFRS.The preliminary decisions with respect to the exemptions under IFRS 1, accounting policy choices and the assessment of the differences between IFRS and Canadian GAAP have not been finalized. Users should note that these decisions will not be finalized until 2011 and the estimated impacts with respect to these preliminary decisions on adopting IFRS may change. In addition, other differences may arise between amounts reported by the Trust under Canadian GAAP as compared to IFRS, as well, new or revised accounting standard under IFRS are being developed by the IASB that may impact the adoption of IFRS by the Trust in 2011 and thereafter. Bonavista will continue to monitor these and other accounting standard developments within IFRS which might impact its conversion.In addition to accounting policy differences, Bonavista's transition to IFRS is expected to impact internal controls over financial reporting, disclosure controls and procedures, certain business activities and information systems.- Internal controls over financial reporting ("ICFR") - in conjunction with assessing our accounting policy choices, we will also determine whether any changes will be required for ICFR. This will be an ongoing process throughout 2010 to ensure that all changes in accounting policy include the appropriate controls and procedures for IFRS reporting requirements.- Disclosure controls and procedures - during this transition period Bonavista will assess its stakeholders' information requirements to ensure that adequate and timely information is provided to meet these needs.- Business activities - Upon transition to IFRS, management has been cognizant of ensuring that any existing agreements that contain references to Canadian GAAP are modified to allow for IFRS statements. - Information Systems - Bonavista has tested the accounting system updates required in order to handle IFRS reporting. The updates while not significant are critical to allow for reporting of both Canadian GAAP and IFRS statements in 2010. Certain modifications have also been made to track PP&E and E&E expenditures required for IFRS reporting. Additional modifications may be required as we finalize our accounting policy choices.OUTLOOKAs we approach our conversion to a dividend paying corporation at the end of 2010, we continue to apply the same proven strategies as we have throughout our entire history of creating value for our investors. The foundation of this strategy is to consistently exercise cost discipline as we actively pursue low to medium-risk drilling opportunities on our extensive land base within geographically concentrated areas of operations. This strategy also involves a consistent component of strategic and complementary acquisitions where we aim to capture incremental value through the application of our operational and technical expertise. Despite our execution of a very active exploration and development program over the past year, both the quality and quantity of our drilling inventory continues to flourish. We have currently identified approximately 1,150 drilling prospects on our land base which represents a 100% increase over our inventory at the time of the announcement signaling the end of the trust sector. Importantly, the quality of our drilling inventory has increased such that more than 75% of our future opportunities involve the application of horizontal drilling and multi-stage fracture technology within scalable resource plays. Our timely and prudent approach to capital investment has been very effective in the past and our attention to detail together with our steadfast commitment to adding shareholder value will continue to provide the foundation for the future success of our organization. Today our efficiency, productivity, and confidence are among the highest level in our twelve year history.We continue to closely monitor natural gas fundamentals and believe current prices are at levels where industry full cycle profitability is being compromised. As a result, we remain optimistic that natural gas focused activity will abate and the current over-supply situation will correct itself in due course. We intend to maintain our capital spending program for 2010 at approximately $600 million. Excluding approximately $250 million in budgeted acquisitions and divestment activities, our 2010 exploration and development program of $350 million consists of drilling approximately 140 wells. Despite some unusually wet weather in the second and third quarters of 2010 which has deferred a portion of scheduled operations into the fourth quarter, we remain confident we can achieve our existing 2010 annual production guidance of 66,500 to 67,500 boe per day. In consideration of current natural gas prices and our conversion to a dividend paying corporation, we have established a preliminary 2011 capital spending program of between $360 and $390 million where we expect to drill between 140 and 150 wells. This activity will lead to average 2011 production levels of 70,000 to 72,000 boe per day representing 5 to 7% growth year over year. As always, we will continue to closely monitor the economic climate together with our drilling results and remain flexible to adjust our level of capital spending depending on the circumstances. Despite the dynamic property acquisition activity year to date, there remains an abundance of acquisition opportunities in the market. As a result, we continue to exercise additional diligence when selecting incremental investment opportunities investing only in those projects that will maximize value both in the short and long-term.We are proud of our accomplishments in the third quarter of 2010 and despite continued instability in commodity prices, we remain enthusiastic and confident about our future. We would like to thank our employees for their significant effort and their continued perseverance as we position ourselves for the future. We remain confident that our operating philosophy works well in any environment and we will continue to create long-term value for our unitholders. 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. With our imminent reorganization back to a corporation at year end, our primary focus of executing a proven strategy that has worked so well for us for thirteen years will remain unchanged. Our team is very committed to this vision.BONAVISTA ENERGY TRUST Consolidated Balance Sheets-------------------------------------------------------------------------------------------------------------------------------------------------------- September 30, December 31,(thousands) 2010 2009--------------------------------------------------------------------------------------------------------------------------------------------------------(unaudited)Assets: Current assets: Accounts receivable and prepaids $ 128,557 $ 128,363 Marketable securities - 6,322 Financial instrument contracts 7,355 5,626 Future income tax asset - 4,424---------------------------------------------------------------------------- 135,912 144,735 Financial instrument contracts 10,774 - Oil and natural gas properties and equipment 3,180,072 2,906,073 Goodwill 41,321 41,321---------------------------------------------------------------------------- $ 3,368,079 $ 3,092,129--------------------------------------------------------------------------------------------------------------------------------------------------------Liabilities and Unitholders' Equity: Current liabilities: Accounts payable and accrued liabilities $ 173,282 $ 157,019 Distributions payable 21,379 19,937 Financial instrument contracts - 15,169 Convertible debentures - 38,093 Future income tax 2,002 1,641---------------------------------------------------------------------------- 196,663 231,859 Financial instrument contracts 2,884 - Long-term debt 974,081 832,138 Asset retirement obligations 171,143 160,314 Future income tax 131,230 144,235 Unitholders' equity: Unitholders' capital and debenture conversion component 1,726,732 1,531,299 Exchangeable shares 57,309 59,295 Contributed surplus 14,626 13,319 Accumulated earnings 93,411 119,670---------------------------------------------------------------------------- 1,892,078 1,723,583---------------------------------------------------------------------------- $ 3,368,079 $ 3,092,129--------------------------------------------------------------------------------------------------------------------------------------------------------See accompanying notes to the consolidated financial statements.BONAVISTA ENERGY TRUSTConsolidated Statements of Operations, Comprehensive Income and Accumulated Earnings--------------------------------------------------------------------------------------------------------------------------------------------------------(thousands, except per unit Three months ended Nine months ended amounts) September 30, September 30, 2010 2009 2010 2009----------------------------------------------------------------------------(unaudited)Revenues: Production $ 222,656 $ 180,977 $ 704,020 $ 526,553 Royalties (33,112) (26,981) (108,436) (80,870)---------------------------------------------------------------------------- 189,544 153,996 595,584 445,683---------------------------------------------------------------------------- Realized gains on financial instrument contracts 5,700 18,087 11,153 62,564 Unrealized gains (losses) on financial instrument contracts (2,516) 2,543 24,788 (62,748)---------------------------------------------------------------------------- 3,184 20,630 35,941 (184)---------------------------------------------------------------------------- 192,728 174,626 631,525 445,499----------------------------------------------------------------------------Expenses: Operating 48,523 49,639 145,261 146,388 Transportation 10,526 9,631 28,975 27,398 General and administrative 5,262 4,630 15,456 12,673 Financing 7,371 3,314 17,316 9,579 Loss (Gain) on marketable securities - 790 (1,871) 790 Foreign exchange (gain) loss (1,540) - (1,135) - Unit-based compensation 3,062 2,870 8,539 8,447 Depreciation, depletion and accretion 91,664 77,784 263,041 210,067---------------------------------------------------------------------------- 164,868 148,658 475,582 415,342----------------------------------------------------------------------------Income before taxes 27,860 25,968 155,943 30,157 Income taxes (reductions) (8,754) (7,371) (5,854) (36,802)----------------------------------------------------------------------------Net income and comprehensive income 36,614 33,339 161,797 66,959Accumulated earnings, beginning of period 120,903 162,145 119,670 231,029 Distributions declared (64,106) (55,678) (188,056) (158,182)----------------------------------------------------------------------------Accumulated earnings, end of period $ 93,411 $ 139,806 $ 93,411 $ 139,806--------------------------------------------------------------------------------------------------------------------------------------------------------Net income per unit - basic $ 0.24 $ 0.25 $ 1.06 $ 0.55--------------------------------------------------------------------------------------------------------------------------------------------------------Net income per unit - diluted $ 0.23 $ 0.25 $ 1.06 $ 0.54--------------------------------------------------------------------------------------------------------------------------------------------------------See accompanying notes to the consolidated financial statements.BONAVISTA ENERGY TRUSTConsolidated Statements of Cash Flows----------------------------------------------------------------------------(thousands, except per unit Three months ended Nine months ended amounts) September 30, September 30, 2010 2009 2010 2009----------------------------------------------------------------------------(unaudited)Cash provided by (used in):Operating Activities: Net income $ 36,614 $ 33,339 $ 161,797 $ 66,959 Items not requiring cash from operations: Depreciation, depletion and accretion 91,664 77,784 263,041 210,067 Unit-based compensation 3,062 2,870 8,539 8,447 Unrealized (gains) losses on financial instrument contracts 2,516 (2,543) (24,788) 62,748 Loss (Gain) on marketable securities - 790 (1,871) 790 Foreign exchange (gain) loss (1,540) - (1,135) - Future income tax (reductions) (8,754) (7,371) (5,854) (36,802) Asset retirement expenditures (4,256) (3,338) (8,819) (8,596) Changes in non-cash working capital items 14,984 (14,039) 7,513 (34,438)---------------------------------------------------------------------------- 134,290 87,492 398,423 269,175----------------------------------------------------------------------------Financing Activities: Issuance of equity, net of issue costs 2,770 401,452 181,658 402,836 Issuance of senior notes - - 52,625 - Distributions (64,070) (51,595) (186,614) (166,995) Changes in long-term debt 29,894 198,001 90,453 268,203 Repayment of convertible debentures - - (38,567) (6,586) Changes in non-cash working capital items (299) 823 (114) 337---------------------------------------------------------------------------- (31,705) 548,681 99,441 497,795----------------------------------------------------------------------------Investing Activities: Exploration and development (84,657) (43,303) (255,087) (141,801) Property acquisitions (34,300) (700,818) (285,028) (723,043) Property dispositions 19,132 106,216 25,388 106,216 Proceeds on sale of marketable securities - - 8,193 - Changes in non-cash working capital items (2,760) 1,732 8,670 (8,342)---------------------------------------------------------------------------- (102,585) (636,173) (497,864) (766,970)--------------------------------------------------------------------------------------------------------------------------------------------------------Change in cash - - - -Cash, beginning of period - - - -----------------------------------------------------------------------------Cash, end of period $ - $ - $ - $ ---------------------------------------------------------------------------------------------------------------------------------------------------------See accompanying notes to the consolidated financial statements.BONAVISTA ENERGY TRUSTNotes to Consolidated Financial StatementsFor the three and nine months ended September 30, 2010 (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. Significant accounting policies:The interim consolidated statements of the Trust have been prepared by management in accordance with generally accepted accounting policies in Canada. The unaudited interim consolidated financial statements have been prepared following the same accounting policies and methods of computation as the consolidated financial statements for the fiscal year ended December 31, 2009. The interim consolidated financial statement note disclosures do not include all of those required by Canadian generally accepted accounting principles ("GAAP") applicable for annual financial statements. Accordingly, the interim consolidated financial statements should be read in conjunction with the consolidated financial statements and notes hereto as at and for the year ended December 31, 2009.2. 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 another director of NuVista is also an officer of Bonavista.For the three months ended September 30, 2010, no management fees, other than standard industry overhead recoveries, were charged by NuVista for our jointly owned partnership (2009 - $337,500). For the nine months ended September 30, 2010, no management fees, other than standard industry overhead recoveries, were charged by NuVista for our jointly owned partnership (2009 - $1.0 million). As at September 30, 2010, the amount payable to NuVista was $384,000 (2009 - $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 $790.0 million (2009 - $698.4 million) which will be incurred over the next 51 years. The majority of the costs will be incurred between 2011 and 2038. A credit-adjusted risk-free rate of 7.5% (2009 - 7.5%) and an inflation rate of 2% (2009 - 2%) were used to calculate the fair value of the asset retirement obligations.A reconciliation of the asset retirement obligations for the nine months ended September 30, 2010 is provided below:---------------------------------------------------------------------------- Amount----------------------------------------------------------------------------(thousands)Balance, December 31, 2009 $ 160,314 Accretion expense 8,779 Liabilities incurred 2,796 Liabilities acquired 8,073 Liabilities settled (8,819)----------------------------------------------------------------------------Balance, September 30, 2010 $ 171,143--------------------------------------------------------------------------------------------------------------------------------------------------------4. Property acquisition:On May 31, 2010 the Trust acquired certain long-life natural gas weighted properties located in west central Alberta for a cash purchase price of approximately $230.4 million.5. Long-term debt:---------------------------------------------------------------------------- September 30, December 31,Long-Term Debt 2010 2009----------------------------------------------------------------------------(thousands) Bank credit facility $ 922,591 $ 832,138 Senior unsecured notes 51,490 -----------------------------------------------------------------------------Balance, end of period $ 974,081 $ 832,138--------------------------------------------------------------------------------------------------------------------------------------------------------a) Bank credit facility:On September 10, 2010, Bonavista combined and renewed its bank loan facilities into a single facility of $1.4 billion provided by a syndicate of 12 domestic and international banks with a maturity date of September 10, 2013. This facility is an unsecured, covenant-based, extendible revolving facility and includes a $50 million working capital facility. This 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. This 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. There is an accordion feature providing that at anytime during the term, on participation of any existing or additional lenders, the Trust can increase the facility by $250 million.Under the terms of the bank credit facility, the Trust has provided the covenant that its: (i) consolidated senior debt borrowing will not exceed three times net income before unrealized gains and losses on financial instrument contracts and marketable securities, 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 instrument contracts and marketable securities, 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 three months ended September 30, 2010 include interest on long-term debt of $7.4 million (2009 - $2.7 million) and convertible debentures of nil (2009 - $656,000). For the three months ended September 30, 2010 Bonavista paid cash interest of $7.7 million (2009 - $2.5 million).Financing expenses for the nine months ended September 30, 2010 include interest on long-term debt of $16.0 million (2009 - $7.4 million) and convertible debentures of $1.3 million (2009 - $2.2 million). For the nine months ended September 30, 2010, Bonavista paid cash interest of $16.0 million (2009 - $9.2 million). Our effective interest rate for period ending September 30, 2010 was approximately 3.0% (2009 - 1.3%).b) Senior unsecured notes issued under a master shelf agreement:In the second quarter of 2010, the Trust entered into an uncommitted master shelf agreement that allows for an aggregate draw of up to US$125 million in notes at a rate equal to the related US treasuries corresponding to the term of the notes plus an appropriate credit risk adjustment at the time of issuance. On June 4, 2010 the Trust drew down US$50 million on the master shelf agreement with a coupon rate of 4.86% with US$25.0 million maturing on June 4, 2016 and the remaining US$25.0 million maturing on June 4, 2017. Under the terms of the master shelf agreement, the Trust has provided similar significant covenants that exist under the bank credit facility.c) Senior unsecured notes not subject to the master shelf agreement:On November 2, 2010, Bonavista issued the following senior unsecured notes via a private placement. The significant covenants of the senior unsecured notes are the same as those under the bank credit facility.The terms and coupon rates of the notes are summarized below:----------------------------------------------------------------------------Issued Date Principal Coupon Rate Maturity Date----------------------------------------------------------------------------November 2, 2010 CDN $50.0 million 3.79% November 2, 2015November 2, 2010 US $90.0 million 3.66% November 2, 2017November 2, 2010 US $160.0 million 4.37% November 2, 2020November 2, 2010 US $50.0 million 4.47% November 2, 2022----------------------------------------------------------------------------6. Convertible debentures:On June 30, 2010 the 6.75% convertible debentures with a conversion price of $29.00 per trust unit matured and were cash settled. 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 $2.8 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. The following table sets out the convertible debenture activities to September 30, 2010:---------------------------------------------------------------------------- Debt Equity Component Component----------------------------------------------------------------------------(thousands)Balance, December 31, 2009 $ 38,093 $ 808 Accretion 285 - Amortization of issue expenses 189 - Repayment of convertible debenture on maturity (38,567) (808)----------------------------------------------------------------------------Balance, September 30, 2010 $ - $ ---------------------------------------------------------------------------------------------------------------------------------------------------------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, 2009 124,604 $ 1,530,491 Issued for cash 7,500 177,000 Issued on property acquisition 28 675 Issued on conversion of exchangeable shares 732 1,986 Issued upon exercise of trust unit incentive rights 692 14,010 Conversion of restricted trust units 62 - Issue costs, net of future tax benefit - (6,986) Unit-based compensation - 9,556----------------------------------------------------------------------------Balance, September 30, 2010 133,618 $ 1,726,732--------------------------------------------------------------------------------------------------------------------------------------------------------(ii) Contributed surplus:---------------------------------------------------------------------------- Amount----------------------------------------------------------------------------(thousands)Balance, December 31, 2009 $ 13,319 Unit-based compensation expense 8,539 Unit-based compensation capitalized 1,516 Exercise of trust unit incentive rights and conversion of restricted trust units (9,556) Adjustment to equity component of debenture on repayment 808----------------------------------------------------------------------------Balance, September 30, 2010 $ 14,626--------------------------------------------------------------------------------------------------------------------------------------------------------(iii) Exchangeable shares:---------------------------------------------------------------------------- Number Amount----------------------------------------------------------------------------(thousands)Balance, December 31, 2009 9,707 $ 59,295 Exchanged for trust units (325) (1,986)----------------------------------------------------------------------------Balance, September 30, 2010 9,382 57,309--------------------------------------------------------------------------------------------------------------------------------------------------------Exchange ratio, September 30, 2010 2.35147 -----------------------------------------------------------------------------Trust units issuable on exchange 22,061 $ 57,309--------------------------------------------------------------------------------------------------------------------------------------------------------c) Long-term incentive plans:For the three months ended September 30, 2010 there were 77,650 restricted trust units granted and 737,890 trust unit incentive rights issued with an average exercise price of $23.49 per trust unit and an estimated fair value of $6.36 per trust unit. As at September 30, 2010 there were 255,667 restricted trust units outstanding and 4.3 million trust unit rights outstanding with an average exercise price of $20.59 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 27%; a forfeiture rate of 10% and an expected life of 4.5 years.d) Per unit amounts:The following table summarizes the weighted average trust units, exchangeable shares and convertible debentures used in calculating net income per trust unit:---------------------------------------------------------------------------- Three months ended September 30, 2010----------------------------------------------------------------------------(thousands)Trust units 133,530Exchangeable shares converted at the exchange ratio 22,074----------------------------------------------------------------------------Basic equivalent trust units 155,604Convertible debentures -Trust unit incentive rights 742Restricted trust units 256----------------------------------------------------------------------------Diluted equivalent trust units 156,602--------------------------------------------------------------------------------------------------------------------------------------------------------8. Financial instruments:The Trust has exposure to credit 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, 2010 the Trust's receivables consisted of $71.3 million of receivables from crude oil and natural gas marketers which has substantially been collected, subsequent to September 30, 2010, $33.0 million from joint venture partners of which $4.0 million has been subsequently collected, and $24.3 million of Crown deposits, inventories and prepaid expenses. As at September 30, 2010 the Trust has $9.3 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, 2010 and did not provide for any doubtful accounts nor was it required to write-off any receivables during the three months ended September 30, 2010.b) 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 instrument contracts 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 instrument contracts:As at September 30, 2010, the Trust has hedged by way of costless collars to sell natural gas and crude oil as follows:----------------------------------------------------------------------------Volume Average Price Term---------------------------------------------------------------------------- October 1, 2010 -35,000 gjs/d CDN$4.46 - CDN$6.05 - AECO October 31, 2010 October 1, 2010 -20,000 gjs/d CDN$4.56 - CDN$6.12 - AECO December 31, 2010 October 1, 2010 -5,000 gjs/d CDN$4.50 - CDN$7.24 - AECO October 31, 2011 November 1, 2010 -10,000 gjs/d CDN$5.13 - CDN$7.75 - AECO March 31, 2011 January 1, 2011 -10,000 gjs/d CDN$5.25 - CDN$7.20 - AECO December 31, 2011 April 1, 2011 -5,000 gjs/d CDN$5.00 - CDN$6.50 - AECO October 31, 2011 October 1, 2010 -9,000 bbls/d CDN$68.06 - CDN$92.83 - WTI December 31, 2010 October 1, 2010 -1,500 bbls/d CDN$75.00 - CDN$93.58 - WTI December 31, 2010 January 1, 2011 -7,000 bbls/d CDN$79.43 - CDN$96.50 - WTI December 31, 2011 January 1, 2012 -1,500 bbls/d CDN$80.00 - CDN$100.02 - WTI December 31, 2012----------------------------------------------------------------------------Subsequent to September 30, 2010 the Trust entered into the followingcostless collar to sell crude oil as follows:----------------------------------------------------------------------------Volume Average Price Term---------------------------------------------------------------------------- January 1, 2011 -1,000 bbls/d CDN$80.00 - CDN$95.99 - WTI December 31, 2011----------------------------------------------------------------------------As at September 30, 2010, the Trust has entered into the following options contracts listed below to manage its overall commodity exposure. The Trust has also hedged its exposure to electricity pricing by entering into a swap which determines a fixed price paid throughout the term of the contract. These financial instrument contracts are outlined below:----------------------------------------------------------------------------Volume Price Contract Term---------------------------------------------------------------------------- October 1, 2010 -5,000 gjs/d CDN $ 4.50 Purchased Put - AECO October 31, 2010 April 1, 2011 -10,000 gjs/d CDN $ 6.45 Sold Call - AECO October 31, 2011 January 1, 2011 -500 bbls/d CDN $100.00 Sold Call - WTI December 31, 2011 October 1, 2010 -1 mw/h CDN $55.00 Swap - AESO December 31, 2010----------------------------------------------------------------------------Subsequent to September 30, 2010 the Trust entered into the followingoptions contracts:----------------------------------------------------------------------------Volume Average Price Term---------------------------------------------------------------------------- April 1, 2011 -15,500 gjs/d CDN $4.14 Swap - AECO October 31, 2011 January 1, 2011 -500 bbls/d CDN $100.00 Sold Call - WTI December 31, 2011 January 1, 2012 -1,000 bbls/d CDN $105.00 Sold Call - WTI December 31, 2012 January 1, 2011 -1 mw/h CDN $45.00 Swap - AESO December 31, 2011----------------------------------------------------------------------------Financial instrument contracts 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. As at September 30, 2010 the fair market value recorded on the consolidated balance sheet for these financial instrument contracts was a net asset of $15.2 million, compared to a net liability of $9.5 million as at December 31, 2009. These financial instrument contracts had the following gains and losses reflected in the consolidated statements of operations, comprehensive income and accumulated earnings:---------------------------------------------------------------------------- Three months Nine months ended September 30, ended September 30, 2010 2009 2010 2009----------------------------------------------------------------------------Realized gains on financial instrument contracts $ 5,700 $ 18,087 $ 11,153 $ 62,564Unrealized gains (losses) on financial instrument contracts (2,516) 2,543 24,788 (62,748)---------------------------------------------------------------------------- $ 3,184 $ 20,630 $ 35,941 $ (184)--------------------------------------------------------------------------------------------------------------------------------------------------------Bonavista mitigates its risk associated with fluctuations in commodity prices by utilizing financial instrument contracts. A $0.10 increase or decrease in the price per thousand cubic feet of natural gas - AECO would have a negative impact of approximately $2.4 million and $662,000 respectively on net income for those financial instrument contracts that were in place as at September 30, 2010. A $1.00 change in the price per barrel of oil - WTI would have an impact of approximately $1.5 million on net income for those financial instrument contracts that were in place as at September 30, 2010.ii) Physical purchase and sale contracts:As at September 30, 2010, the Trust has entered into physical contracts to sell natural gas as follows:----------------------------------------------------------------------------Volume Average Price Term---------------------------------------------------------------------------- October 1, 2010 û15,000 gjs/d CDN$4.58 - CDN$6.41 - AECO October 31, 2010 October 1, 2010 û5,000 gjs/d CDN$5.00 - CDN$6.60 - AECO December 31, 2010 November 1, 2010 -10,000 gjs/d CDN$5.00 - CDN$7.34 - AECO March 31, 2011 January 1, 2011 -10,000 gjs/d CDN$5.13 - CDN$6.99 - AECO December 31, 2011 October 1, 2010 -5,000 gjs/d CDN$5.06 - AECO December 31, 2010 April 1, 2011 -7,500 gjs/d CDN$4.00 - AECO October 31, 2011----------------------------------------------------------------------------As at September 30, 2010, the Trust has entered into contracts to purchase electricity as follows:----------------------------------------------------------------------------Volume Average Price Term----------------------------------------------------------------------------4 mw/h CDN$50.54 - AESO October 1, 2010 - December 31, 20105 mw/h CDN$51.44 - AESO January 1, 2011 - December 31, 20111 mw/h CDN$51.00 - AESO January 1, 2011 - December 31, 2012----------------------------------------------------------------------------Subsequent to September 30, 2010, the Trust has entered into physical contracts to sell natural gas as follows:----------------------------------------------------------------------------Volume Average Price Term----------------------------------------------------------------------------7,000 gjs/d CDN$4.15 - AECO April 1, 2011 - October 31, 2011----------------------------------------------------------------------------Physical purchase and sale contracts are being accounted for as they are settled.c) Fair value of financial instruments:The fair value of financial instrument contracts is determined by the financial intermediary to extinguish all rights or obligations of the financial instrument contracts. As at September 30, 2010, the fair market value of these financial instrument contracts was a net asset of approximately $15.2 million (2009 - $13.5 million net asset).Fair market value of the note payable as at September 30, 2010 is approximately $51.5 million (2009 - $nil), as determined by converting the US$50 million denominated debt to Canadian dollars using the Bank of Canada noon day rate at September 30, 2010.Bank debt bears interest at a floating market rate and accordingly the fair market value approximates the carrying value.9. Subsequent event:On October 14, 2010, Bonavista announced its intention to convert to a corporation, subject to unitholder approval, on December 31, 2010.INVESTOR INFORMATIONBonavista 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.For more information, please contact Keith A. MacPhailChairman & CEO(403) 213-4300orJason E. SkeharPresident & COO(403) 213-4300orRonald J. PoelzerExecutive Vice President(403) 213-4300orGlenn A. HamiltonSenior Vice President & CFO(403) 213-4300orBonavista Energy Trust700, 311 - 6th Avenue SWCalgary, AB T2P 3H2www.bonavistaenergy.com