TSX: TUI.UN CALGARY, Aug. 6 /CNW/ - (TSX: TUI.UN) True Energy Trust ("True," "Company" or the "Trust") announces its financial and operating results for the three and six months ended June 30, 2009.HIGHLIGHTS ------------------------------------------------------------------------- Three months ended Six months ended June 30, June 30, 2009 2008 2009 2008 ------------------------------------------------------------------------- FINANCIAL (unaudited) (CDN$000s except unit and per unit amounts) Revenue (before royalties and hedging(1)) 29,805 82,074 61,150 152,107 Funds flow from operations(2) 10,765 26,304 17,254 50,537 Per basic trust unit $ 0.14 $ 0.33 $ 0.22 $ 0.64 Per diluted trust unit(7) $ 0.14 $ 0.33 $ 0.22 $ 0.64 Net loss (99,715) (21,374) (108,771) (39,995) Per basic trust unit $ (1.27) $ (0.27) $ (1.39) $ (0.50) Per diluted trust unit(7) $ (1.27) $ (0.27) $ (1.39) $ (0.50) Distributions declared - 9,505 1,570 19,012 Per unit - $ 0.12 $ 0.02 $ 0.24 ------------------------------------------------------------------------- Exploration and development 1,028 3,475 3,556 11,759 Corporate and property acquisitions 123 605 351 971 ------------------------------------------------------------------------- Capital expenditures - cash 1,151 4,080 3,907 12,730 Property dispositions - cash (8,289) (38,530) (8,281) (44,318) Other - non-cash (1,107) (2,521) (1,221) (2,714) ------------------------------------------------------------------------- Total capital expenditures - net (8,245) (36,971) (5,595) (34,302) ------------------------------------------------------------------------- Long-term debt 120,205 125,458 120,205 125,458 Convertible debentures(3) 82,075 80,253 82,075 80,253 Working capital excess (5,563) (16,357) (5,563) (16,357) ------------------------------------------------------------------------- Total net debt(3) 196,717 189,354 196,717 189,354 ------------------------------------------------------------------------- Pro-forma total net debt after Divestiture(4) 111,717 N/A 111,717 N/A ------------------------------------------------------------------------- Total assets 562,854 793,883 562,854 793,883 Unitholders' equity 296,443 404,062 296,443 404,062 ------------------------------------------------------------------------- OPERATING Daily sales volumes Crude oil, condensate and NGLs (bbls/d) 3,816 4,170 3,821 4,506 Natural gas (mcf/d) 35,703 46,515 36,312 49,383 Total oil equivalent (boe/d) 9,767 11,922 9,873 12,737 Average prices Crude oil, condensate and NGLs ($/bbl) 53.55 103.14 45.16 86.19 Crude oil, condensate and NGLs (including hedging(1)) ($/bbl) 53.55 82.56 45.16 71.50 Natural gas ($/mcf) 3.40 9.94 4.42 8.90 Natural gas (including hedging(1)) ($/mcf) 5.18 8.80 5.70 8.37 Total oil equivalent ($/boe) 33.34 74.85 33.72 64.99 Total oil equivalent (including hedging(1)) ($/boe) 39.85 63.22 38.43 57.76 Statistics Operating netback(5) ($/boe) 12.52 42.66 11.16 35.54 Operating netback(5) (including hedging(1)) ($/boe) 19.03 31.01 15.87 28.30 Transportation ($/boe) 1.42 2.28 1.58 1.43 Production expenses ($/boe) 13.41 14.90 14.47 14.31 General & administrative ($/boe) 2.90 4.14 3.03 3.56 Royalties as a % of sales after Transportation 19% 21% 20% 22% ------------------------------------------------------------------------- TRUST UNITS Trust units outstanding 78,496,581 79,095,460 78,496,581 79,095,460 Trust unit incentive rights outstanding 4,234,632 5,006,079 4,234,632 5,006,079 Units issuable for exchangeable shares 312,467 347,254 312,467 347,254 Units issuable for convertible debentures(6) 5,390,625 5,390,625 5,390,625 5,390,625 ------------------------------------------------------------------------- Diluted trust units outstanding 88,434,305 89,839,418 88,434,305 89,839,418 Diluted weighted average trust units(7) 78,496,581 79,203,976 78,496,581 79,213,532 ------------------------------------------------------------------------- TRUST UNIT TRADING STATISTICS (CDN$, except volumes) based on intra-day trading High 1.08 4.69 1.56 4.69 Low 0.66 3.54 0.48 2.94 Close 0.77 4.40 0.77 4.40 Average daily volume 123,853 266,304 147,289 261,833 ------------------------------------------------------------------------- (1) The Trust has entered into various commodity risk management contracts which are considered to be economic hedges. Per unit metrics after hedging includes only the realized portion of gains or losses on commodity contracts. The Trust does not apply hedge accounting to these contracts. As such, these contracts are revalued to fair value at the end of each reporting date. This results in recognition of unrealized gains or losses over the term of these contracts which is reflected each reporting period until these contracts are settled, at which time realized gains or losses are recorded. These unrealized gains or losses on commodity contracts are not included for purposes of per unit metrics calculations disclosed. (2) The highlights section contains the term "funds flow from operations" (or as commonly referred to as "cash flow from operations"), which should not be considered an alternative to, or more meaningful than cash flow from operating activities as determined in accordance with Canadian generally accepted accounting principles ("GAAP") as an indicator of the Trust's performance. Therefore reference to diluted funds flow from operations or funds flow from operations per trust unit may not be comparable with the calculation of similar measures for other entities. Management uses funds flow from operations to analyze operating performance and leverage and considers funds flow from operations to be a key measure as it demonstrates the Trust's ability to generate the cash necessary to fund future capital investments and to repay debt. The reconciliation between cash flow from operating activities and funds flow from operations can be found in the Management Discussion and Analysis ("MD&A"). Funds flow from operations per trust unit is calculated using the weighted average number of trust units for the period. (3) Net debt includes the net working capital deficiency (excess) before short-term commodity contract assets and liabilities, current portion of long-term debt and short-term future income tax assets and liabilities. Total net debt also includes the liability component of convertible debentures and excludes asset retirement obligations and the future income tax liability. (4) Pro-forma total net debt after Divestiture is calculated as total net debt as of June 30, 2009, reduced by $85 million of net proceeds, after purchase adjustments and estimated closing costs, received from the divestiture of properties in Saskatchewan and others as disclosed further herein. (5) Operating netbacks are calculated by subtracting royalties, transportation, and operating costs from revenues. (6) Units issuable for convertible debentures are calculated as the $86.25 million principal amount of the convertible debentures divided by the conversion price of $16.00 per unit available to debenture holders. (7) In computing weighted average diluted earnings per trust unit and weighted average diluted funds flow from operations for both the three and six month periods ended June 30, 2009 a total of 4,234,632 (2008: 5,006,079) trust incentive units, 312,467 (2008: 347,254) exchangeable shares and 5,390,625 (2008: 5,390,625) trust units issuable pursuant to the conversion of convertible debentures were excluded from the calculation of diluted earnings per trust unit and weighted average diluted funds flow from operations as they were not dilutive. REPORT TO UNITHOLDERSTrue is pleased to announce that significant progress had been accomplished in the restructuring of the Trust through the first half of 2009. The Trust now has a proven team of top tier professional management in all key operational areas of the organization. The new team has over 175 years of combined successful experience providing organic growth through full cycle exploration, exploitation and development. The cost control strategy implemented at the start of Q1 2009 is on target through the second quarter with both operating expenses and G&A expenses meeting budgets, which represent cuts in excess of 30% from 2008 levels. Production levels have been maintained by diligent field optimization programs designed to arrest decline. Sales volumes averaged 9,767 boe/d in the second quarter in spite of plant turnarounds in late May and June and a one time negative accounting adjustment of 261 boe/d. For the first half of 2009 sales volumes averaged 9,873 boe/d. As of June 30, 2009, year to date capital expenditures totalled $3.9 million. True will maintain its $15 million capital budget for 2009 with the drilling program to be initiated in August. Capital constraints will remain in place until improved commodity pricing is demonstrated. The highly leveraged balance sheet has been addressed through a series of asset transactions designed to reduce bank indebtedness, thereby providing True with the ability to move forward with substantially improved financial flexibility. These efforts include:- On July 8, 2009, True announced the divestiture of a majority of its oil and natural gas assets in Saskatchewan for gross proceeds of $93 million effective May 1, 2009 (the "Divestiture"). On July 30, 2009 True closed the Divestiture for net proceeds, after purchase adjustments, of approximately $86 million. The purchase adjustments of approximately $7 million include net operating income, prepaid and other items for the interim period from May 1, 2009 to July 30, 2009. The Divestiture excludes the Saskatchewan properties of Cypress and Mantario. True's interest to the base Belly River in three sections in the Ferrier area of West Central Alberta were also disposed of in the transaction. The assets sold include production estimated to average 3,000 boe/d in Q3 and Q4 in 2009, including 5.3 mmcf/d of natural, 128 km(2) of 3D proprietary seismic with 389.7 km of 2D proprietary seismic, subject to a royalty free license on the seismic in favor of True, and 63,333 net acres of undeveloped mineral leases. - In a separate transaction, on June 30, 2009, True sold 145 boe/d, including 0.63 mmcf/d of natural gas, in the Penhold Area of Central Alberta for $4.7 million, after purchase adjustments and estimated closing costs. In addition, in June 2009, True closed on the disposition of certain royalty interests for approximately $3.7 million, after purchase adjustments and estimated closing costs to undisclosed buyers. The proceeds from these two dispositions were also used to reduce True's bank indebtedness. - True's total net debt as of July 31, 2009 after completion of the dispositions, excluding an unrealized commodity contract asset of $13.8 million, future income taxes and asset retirement obligations is approximately $110 million, being approximately $28 million in net debt outstanding on the credit facility including working capital adjustments and $82 million in convertible debentures (liability component). - After completion of the divestitures, True's production is forecast to be approximately 6,500 boe/d, comprised of 31.7 mmcf/d of natural gas and 1,230 bbls/d of light/medium oil. True is forecasting a 2009 average production rate of 8,100 boe/d and a 2009 production exit rate of 7,000 boe/d based on normal decline rates and risked production adds from True's capital program. - Upon completion of the divestitures, 65% of True's natural gas production for Q3 - Q4 2009 is forward sold for an average of $7.26 CAD/mcf and 21.5% of Q1 - Q2 2010 natural gas production hedged at an average of $7.96 CAD/mcf. In addition, 500 bbl/d of oil for Q3 - Q4 is hedged by way of a costless collar of $52.30 CAD x $80.70 CAD. As a result of these hedges, on a go forward basis True has approximately 61% of total 2009 production protected through the remainder of 2009. - On July 30, 2009, in conjunction with completion of the Divestiture, True negotiated a new banking syndicate commitment to replace the existing facility, subject to finalization and execution of a mutually acceptable credit agreement, that will provide True with a credit facility of $85 million. The facility will consist of a $10 million demand operating facility provided by one Canadian bank and a $75 million extendible revolving term credit facility syndicated by one Canadian chartered bank and one Canadian financial institution. As of July 31, 2009 there was approximately $28 million drawn on True's existing facility. The second quarter of 2009 featured continued erosion of natural gas pricing primarily as a result of the supply demand imbalance associated with the persistent global economic recession. Second quarter financial results include: - Funds flow from operations for the second quarter of 2009 was $10.8 million on gross sales of $29.8 million compared to funds flow from operations for the first quarter of 2009 of $6.5 million on gross sales of $31.3 million. - The net loss for the second quarter of 2009 was $99.7 million compared to a net loss of $21.4 million for the same period in 2008 and a net loss of $9.1 million in the first quarter of 2009. The net loss for Q2 2009 was primarily the result of a non-cash accounting loss on petroleum and natural gas properties held for sale of $114.2 million. This amount was calculated as the excess of the historical net book value allocated to Saskatchewan oil and gas property assets sold as compared to the expected total net proceeds received on closing subsequent to quarter-end. - True's total net debt including the liability component of its convertible debentures, excluding unrealized commodity contract assets and liabilities, future income taxes and asset retirement obligations, as at June 30, 2009 was $196.7 million, as compared to $213.9 million as at March 31, 2009. After completion of the Saskatchewan asset divestiture on July 30, 2009, True's total net debt has reduced to approximately $110.0 million. - 2009 second quarter sales volumes averaged 9,767 boe/d compared to 9,981 boe/d in the first quarter of 2009. True initiated a production optimization and maintenance program at the beginning of the year. This program has not only arrested True's production decline through the first and second quarters, but also increased overall deliverability without drilling or recompleting wells. - True's natural gas price for the second quarter of 2009, after including hedging, was $5.18/mcf compared to $8.80/mcf for the same period in 2008. - Capital expenditures for the second quarter of 2009 were $1.2 million which were funded by available cash flow. - Following the receipt of net proceeds from the Divestiture closing on July 30, 2009, the Trust and operating subsidiaries of the Trust are anticipated to have approximately $391 million in tax pools for deduction against future income.True's latest forecast for 2009, as updated for June 30, 2009 year to date results, recent disposition activity and further assumptions including production volumes of 6,500 boe/d for August to December 2009, a CAD$/US$ exchange rate of $0.90, and a WTI oil price of US$70.00 and AECO natural gas price of CAD$4.50/mcf for the third and fourth quarters of 2009, generates estimated cash flow from operations for fiscal 2009 of $38 million. True's drilling program for the third and fourth quarters has commenced with plans to participate in up to 20 wells operated by True to take advantage of the Alberta Government Royalty incentive program. True's drilling program is targeting oil in Mantario, Saskatchewan and natural gas in Alberta including up to three Notikewan horizontal well tests in West Central Alberta. True's total capital expenditure program for the 3rd and 4th quarters is anticipated to be approximately $11.1 million. Upon closing of the recent dispositions, True continues to have approximately 274,000 net acres of undeveloped land with 320 exploitation drilling opportunities identified representing over 5 years of drilling inventory. With the Trust's improved financial flexibility, True plans to move forward with an organic growth model coupled with an M&A mandate to seek opportunities to consolidate assets that complement its focused asset base either through geographic fit, technical expertise or future development potential.Raymond G. Smith, P. Eng. President and CEO August 6, 2009 MANAGEMENT'S DISCUSSION AND ANALYSISAugust 6, 2009 - The following Management's Discussion and Analysis of financial results as provided by the management of True Energy Trust ("True" or the "Trust") should be read in conjunction with the unaudited interim consolidated financial statements and selected notes for the three and six months ended June 30, 2009 and the audited consolidated financial statements of the Trust for the years ended December 31, 2008 and 2007 and the related Management's Discussion and Analysis of financial results. This commentary is based on information available to, and is dated as of, August 6, 2009. The financial data presented is in accordance with Canadian generally accepted accounting principles ("GAAP") in Canadian dollars, except where indicated otherwise. CONVERSION: The term barrels of oil equivalent ("boe") may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet of natural gas to one barrel of oil equivalent (6 mcf/bbl) is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. All boe conversions in this report are derived from converting gas to oil in the ratio of six thousand cubic feet of gas to one barrel of oil. NON-GAAP MEASURES: This Management's Discussion and Analysis contains the term "funds flow from operations" (or also commonly referred to as "cash flow from operations"), which should not be considered an alternative to, or more meaningful than "cash flow from operating activities" as determined in accordance with Canadian GAAP as an indicator of the Trust's performance. Therefore reference to funds flow from operations or funds flow from operations per unit may not be comparable with the calculation of similar measures for other entities. Management uses funds flow from operations to analyze operating performance and leverage and considers funds flow from operations to be a key measure as it demonstrates the Trust's ability to generate the cash necessary to fund future capital investments and to repay debt. The reconciliation between cash flow from operating activities and funds flow from operations can be found in the Management's Discussion and Analysis. Funds flow from operations per unit is calculated using the weighted average number of units for the period. This Management's Discussion and Analysis also contains other terms such as total net debt and operating netbacks, which are not recognized measures under Canadian GAAP. Total net debt is calculated as long-term debt plus the liability component of the convertible debentures and the net working capital deficiency (excess) before short-term commodity contract assets and liabilities, current portion of long-term debt and short-term future income tax assets and liabilities. Operating netbacks are calculated by subtracting royalties, transportation, and operating expenses from revenues. Management believes these measures are useful supplemental measures of firstly, the total amount of current and long-term debt and secondly, the amount of revenues received after transportation, royalties and operating expenses. Readers are cautioned, however, that these measures should not be construed as an alternative to other terms such as current and long-term debt or net income determined in accordance with GAAP as measures of performance. True's method of calculating these measures may differ from other entities, and accordingly, may not be comparable to measures used by other trusts or companies. Additional information relating to the Trust, including the Trust's Annual Information Form, is available on SEDAR at www.sedar.com. FORWARD LOOKING STATEMENTS: Certain information contained herein may contain forward looking statements including management's assessment of future plans and operations, drilling and tie-in plans and the timing thereof, plans regarding wells to be drilled, expected or anticipated average and exit production rates, hedging strategies, anticipated liquidity of the Trust and various matters that may impact such liquidity, planned reductions in operating expenses in 2009 and expected operating expenses, expected production and transportation expenses and general and administrative expenses, expected levels of revenues and operating expenses and operating netbacks in 2009 compared to 2008, the expected effect of dispositions on debt to funds flow ratios, the effect of the SIFT tax on cash flow levels, the use of forecast funds flow from operations, the proportion of distributions anticipated to be taxable, maintenance of productive capacity and capital expenditures and the nature of capital expenditures and the timing and method of financing thereof, may constitute forward-looking statements under applicable securities laws and necessarily involve risks including, without limitation, risks associated with oil and gas exploration, development, exploitation, production, marketing and transportation, loss of markets, volatility of commodity prices, currency fluctuations, imprecision of reserve estimates, environmental risks, competition from other producers, inability to retain drilling rigs and other services, incorrect assessment of the value of acquisitions, failure to realize the anticipated benefits of acquisitions, delays resulting from or inability to obtain required regulatory approvals and ability to access sufficient capital from internal and external sources. The recovery and reserve estimates of True's reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Events or circumstances may cause actual results to differ materially from those predicted, as a result of the risk factors set out and other known and unknown risks, uncertainties, and other factors, many of which are beyond the control of True. In addition, forward-looking statements or information are based on a number of factors and assumptions which have been used to develop such statements and information but which may prove to be incorrect. Included herein is an estimate of True's cash flow from operations in 2009 and the percentage that 2009 assumed distributions and its planned capital budget will be of such estimated funds flow from operations. Such recent financial outlook was approved by management of the Trust on July 8, 2009 and such financial outlook is included herein to provide an assessment of the ability of the Trust to generate the cash necessary to fund future capital investments after assumed distributions and to repay debt. Although the Trust believes that the expectations reflected in such forward-looking statements or information are reasonable, undue reliance should not be placed on forward-looking statements because the Trust can give no assurance that such expectations will prove to be correct. In addition to other factors and assumptions which may be identified herein, assumptions have been made regarding, among other things: the impact of increasing competition; the general stability of the economic and political environment in which the Trust operates; the timely receipt of any required regulatory approvals; the ability of the Trust to obtain qualified staff, equipment and services in a timely and cost efficient manner; drilling results; the ability of the operator of the projects which the Trust has an interest in to operate the field in a safe, efficient and effective manner; the ability of the Trust to obtain financing on acceptable terms; field production rates and decline rates; the ability to replace and expand oil and natural gas reserves through acquisition, development of exploration; the timing and costs of pipeline, storage and facility construction and expansion and the ability of the Trust to secure adequate product transportation; future commodity gas prices; currency, exchange and interest rates; the regulatory framework regarding royalties, taxes and environmental matters in the jurisdictions in which the Trust operates; and the ability of the Trust to successfully market its oil and natural gas products. Readers are cautioned that the foregoing list is not exhaustive of all factors and assumptions which have been used. As a consequence, actual results may differ materially from those anticipated in the forward-looking statements. Additional information on these and other factors that could effect True's operations and financial results are included in reports on file with Canadian securities regulatory authorities and may be accessed through the SEDAR website (www.sedar.com), at True's website (www.trueenergytrust.com). Furthermore, the forward-looking statements contained herein are made as at the date hereof and True does not undertake any obligation to update publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required by applicable securities laws. The reader is further cautioned that the preparation of financial statements in accordance with GAAP requires management to make certain judgments and estimates that affect the reported amounts of assets, liabilities, revenues and expenses. Estimating reserves is also critical to several accounting estimates and requires judgments and decisions based upon available geological, geophysical, engineering and economic data. These estimates may change, having either a negative or positive effect on net earnings as further information becomes available, and as the economic environment changes. Overview and Description of the Business True Energy Trust is a Canadian trust, formed in 2005 via the reverse takeover of TKE Energy Trust. The Trust is involved in the exploration, development and production of petroleum and natural gas in western Canada. The Trust has a significant multi-year drilling inventory of locations in Alberta, Saskatchewan and British Columbia. True's Trust units and convertible debentures are listed on the Toronto Stock Exchange under the symbols TUI.UN and TUI.DB, respectively. Second Quarter 2009 Financial and Operational Results Dispositions The Trust's focus in 2009 has been on the restructuring and strengthening of its balance sheet. The Trust had two minor dispositions in the quarter and has successfully completed the divestiture of the majority of its petroleum and natural gas properties in Saskatchewan subsequent to quarter end. Net proceeds from the dispositions were used to reduce the Trust's bank indebtedness; these strategic accomplishments will allow the Trust to progress forward with substantially improved financial flexibility. On June 30, 2009, True sold 145 boe/d, including 0.63 mmcf/d of natural gas, in the Penhold Area of Central Alberta for $4.7 million, after purchase adjustments and closing costs. In addition, in June 2009, True completed a disposition of certain royalty interests for approximately $3.7 million, after purchase adjustments and closing costs. The proceeds from these two dispositions were used to reduce True's bank indebtedness. On July 8, 2009, True announced the divestiture of a majority of its petroleum and natural gas properties in Saskatchewan (the "Saskatchewan Divestiture") for gross proceeds of $93 million effective May 1, 2009. The Saskatchewan Divestiture excludes the Saskatchewan properties of Mantario and Cypress. True's interest to the base Belly River in three sections in the Ferrier area of West Central Alberta were also included in the divestiture package. The transaction was successfully closed on July 30, 2009. The assets subject to the Saskatchewan Divestiture have been classified as held for sale under CICA handbook section 3475 - "Disposal of Long-lived Assets and Discontinued Operations" as at June 30, 2009 and accounted for under the guidance of Accounting Guideline 16 - "Oil and Gas Accounting - Full Cost". Under full cost accounting, if crediting the proceeds from disposition to costs results in a change of 20 percent or more to the DD&A rate then a gain or loss should be recognized. When a gain or loss is to be recognized the total net book value of capitalized costs should be allocated between the properties sold and the properties retained. The assets held for sale as of June 30, 2009 are an allocation of the Trust's historical full cost pool based on a pro-rata ratio of future cash flows of proved reserves associated with the assets held for sale, discounted at 10%, as compared to all oil and gas assets. The Trust has recorded a $114.2 million non-cash loss on the assets held for sale for the excess of the allocated net book value to these assets, compared to the total estimated net proceeds, after purchase adjustments and estimated closing costs, of $85 million. The purchase adjustments of approximately $7 million include net operating income, prepaid and other items for the interim period from May 1, 2009 to July 30, 2009. Sales Volumes Sales volumes for the three months ended June 30, 2009 averaged 9,767 boe/d compared to 11,922 boe/d for the same period in 2008, representing a 18% decrease. In comparison, sales volumes for the first quarter of 2009 averaged 9,981 boe/d. Sales volumes for the six months ended June 30, 2009 averaged 9,873 boe/d as compared to 12,737 boe/d for the same period in 2008, representing a 22% decrease. The decrease in average sales volumes from second quarter 2008 to 2009 is a result of natural production decline, minimal 2009 capital spending, dispositions in the second quarter totaling approximately 145 boe/d and dispositions totaling approximately 1,000 boe/d that were closed during the second quarter of 2008, partially offset by tuck-in acquisitions completed in the fourth quarter of 2008 that added approximately 250 boe/d. During the first quarter of 2009, True implemented a full scale field optimization and maintenance program throughout True's operated properties. The field optimization programs were designed to arrest production declines and increase overall deliverability without drilling or recompleting wells; which is evidenced by the second quarter average production volumes of 9,767 boe/d in spite of plant turnarounds in late May and June.Sales Volumes ------------------------------------------------------------------------- Three months ended Six months ended June 30, June 30, 2009 2008 2009 2008 ------------------------------------------------------------------------- Natural gas (mcf/d) 35,703 46,515 36,312 49,383 ------------------------------------------------------------------------- Heavy oil (bbls/d) 2,771 2,721 2,646 2,773 Light oil and condensate (bbls/d) 680 1,116 818 1,253 NGLs (bbls/d) 365 333 357 480 ------------------------------------------------------------------------- Total crude oil and NGLs (bbls/d) 3,816 4,170 3,821 4,506 ------------------------------------------------------------------------- Total boe/d (6:1) 9,767 11,922 9,873 12,737 ------------------------------------------------------------------------- -------------------------------------------------------------------------During the second quarter of 2009, True did not participate in any drilling. For the three months ended June 30, 2009, the weighting towards natural gas sales averaged 61% compared to 65% in the same period in 2008. Similarly, for the six month period ended June 30, 2009, the weighting towards natural gas sales averaged 61% compared to 65% for the same period in 2008. Heavy oil sales made up 28% of total production for the 2009 second quarter compared to 23% in the 2008 second quarter. In comparison, heavy oil sales made up 25% of total production for the 2009 first quarter. Sales of natural gas averaged 35.7 Mmcf/d for the second quarter of 2009, compared to 46.5 Mmcf/d in the same 2008 period, a decrease of 23%. Crude oil and NGL sales for the 2009 second quarter decreased 8% averaging 3,816 bbls/d compared to 2008 average sales of 4,170 bbls/d. For August to December 2009, following completion of the Saskatchewan Divestiture, production volumes are anticipated to average approximately 6,500 boe/d and a 2009 production exit rate of 7,000 boe/d. The forecast of 2009 production volumes has been updated from the 10,000 boe/d forecast previously reported to include the recent disposition activity. The forecast is based on a number of assumptions, including normal production declines and expenditures under the current planned capital budget of $15 million.Commodity Prices Average Commodity Prices ------------------------------------------------------------------------- Three months ended Six months ended June 30, June 30, % % 2009 2008 Change 2009 2008 Change ------------------------------------------------------------------------- Exchange rate (US$/Cdn$) 0.8570 1.0000 (14) 0.8291 0.9989 (17) Natural gas: NYMEX (US$/mmbtu) 3.81 11.47 (67) 4.13 9.99 (59) AECO daily index (CDN$/Mcf) 3.45 10.20 (66) 4.18 9.09 (54) AECO monthly index (CDN$/Mcf) 3.47 9.35 (63) 4.64 8.24 (44) True's average price ($/mcf) 3.40 9.94 (66) 4.42 8.90 (50) True's average price (including hedging(1)) ($/mcf) 5.18 8.80 (41) 5.70 8.37 (32) Crude oil: WTI (US$/bbl) 43.31 123.80 (65) 43.31 109.92 (61) Edmonton par - light oil ($/bbl) 66.16 126.37 (48) 58.16 112.30 (48) Bow River - medium/heavy oil ($/bbl) 61.69 103.98 (41) 52.73 90.74 (42) Hardisty Heavy - heavy oil ($/bbl) 58.07 96.34 (40) 48.72 83.20 (41) True's average prices ($/bbl) Light crude oil, condensate, and NGLs 47.83 110.23 (57) 44.88 95.92 (53) Heavy crude oil 55.71 99.37 (44) 45.29 80.11 (44) Total crude oil and NGLs 53.55 103.14 (48) 45.16 86.19 (48) Total crude oil and NGLs (including hedging(1)) 53.55 82.56 (35) 45.16 71.50 (37) ------------------------------------------------------------------------- (1) Per unit metrics including hedging include realized gains or losses on commodity contracts and exclude unrealized gains or losses on commodity contracts.True's natural gas sales are priced with reference to the daily or monthly AECO indices. During the 2009 second quarter, the AECO daily and monthly reference price decreased by 66% and 63%, respectively, compared to the same period in 2008. Similarly, True's average sales price before hedging for the 2009 second quarter decreased by 66% compared to the same period in 2008. True's natural gas price after including hedging for the second quarter of 2009 was $5.18/mcf compared to $8.80/mcf for the same period in 2008. The Trust has entered into a natural gas physical delivery sales contract to sell 5,275 GJ/day at a fixed price of $7.29/GJ and $7.90/GJ for the third and fourth quarter of 2009, respectively. For heavy crude oil, True received an average price before transportation of $55.71/bbl in the 2009 second quarter, a decrease of 44% over prices in the same period in 2008. The Bow River reference price and the Hardisty Heavy reference price both decreased approximately 40% from the 2008 second quarter to the 2009 second quarter. The majority of True's heavy crude oil density ranges between 11 and 16 degrees API consistent with the Hardisty Heavy reference price, although all of True's heavy oil production is sold at Saskatchewan delivery points. For light oil, condensate and NGLs, True recorded an average $47.83/bbl before hedging in the 2009 second quarter, 57% lower than the average price of $110.23/bbl received in the same period in 2008. In comparison, the Edmonton par price decreased by 48% over the same period. The average WTI crude oil US dollar based price decreased 65% from the second quarter of 2008 to that in 2009. The average US$/Cdn$ foreign exchange rate was 0.86 for the 2009 second quarter compared to 1.0 during the same period in 2008. The negative correlation between the Canadian dollar and U.S. dollar denominated WTI oil prices has softened the impact on the Trust. WTI crude oil prices varied greatly throughout 2008, increasing significantly to a high of US$147/bbl in July and dramatically falling during the fourth quarter of 2008 with December 2008 prices of under US$40/bbl and averaging over US$40/bbl for the first and second quarters of 2009. The pricing outlook in 2009 for crude oil and natural gas remains uncertain given the current global economic environment. Revenue Revenue before other income and hedging for the three month period ended June 30, 2009 was $29.6 million, 64% lower than the $81.2 million in the same period in 2008. The decrease in revenue for the 2009 period was the result of lower sales volumes in conjunction with significantly lower commodity prices.------------------------------------------------------------------------- Three months ended Six months ended June 30, June 30, ($000s) 2009 2008 2009 2008 ------------------------------------------------------------------------- Light crude oil, condensate and NGLs 4,550 14,528 9,548 30,262 Heavy oil 14,046 24,608 21,689 40,426 ------------------------------------------------------------------------- Crude oil and NGLs 18,596 39,136 31,237 70,688 Natural gas 11,033 42,067 29,026 79,961 ------------------------------------------------------------------------- Total revenue before other 29,629 81,203 60,263 150,649 Other(1) 176 871 887 1,458 ------------------------------------------------------------------------- Total revenue before royalties and hedging 29,805 82,074 61,150 152,107 ------------------------------------------------------------------------- (1) Other revenue primarily consists of processing and other third party income.Revenues for the remainder of 2009 are currently expected to be lower than 2008 due to lower commodity prices and average estimated 2009 year production of approximately 8,100 boe/d, after adjusting for divestitures closed during the year. Commodity Price Risk Management The Trust has a formal risk management policy which permits management to use specified price risk management strategies as determined by the board of directors including fixed price contracts, collars and the purchase of floor price options and other derivative financial instruments and physical delivery sales contracts to reduce the impact of price volatility and ensure minimum prices for a maximum of eighteen months beyond the current date. The program is designed to provide price protection on a portion of the Trust's future production in the event of adverse commodity price movement, while retaining significant exposure to upside price movements. By doing this, the Trust seeks to provide a measure of stability to funds flow from operations, as well as, to ensure True realizes positive economic returns from its capital developments and acquisition activities. The Trust will continue its hedging strategies focusing on maintaining sufficient cash flow to fund True's operations. Any remaining unhedged production is realized at market prices. A summary of the financial hedge volumes and average prices by quarter currently outstanding as of August 6, 2009 is shown in the following tables:Natural gas Average Volumes (GJ/d) ------------------------------------------------------------------------- Q3 2009 Q4 2009 ------------------------------------------------------------------------- Fixed 19,500 15,000 ------------------------------------------------------------------------- ------------------------------------------------------------------------- ------------------------------------------------------------------------- Q1 2010 Q2 2010 Q3 2010 Q4 2010 ------------------------------------------------------------------------- Fixed 10,000 5,000 - - Call option (ceiling price) 5,000 5,000 5,000 5,000 ------------------------------------------------------------------------- Total GJ/d 15,000 10,000 5,000 5,000 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Average Price ($/GJ AECO C) ------------------------------------------------------------------------- Q3 2009 Q4 2009 ------------------------------------------------------------------------- Fixed 5.97 6.75 ------------------------------------------------------------------------- ------------------------------------------------------------------------- ------------------------------------------------------------------------- Q1 2010 Q2 2010 Q3 2010 Q4 2010 ------------------------------------------------------------------------- Fixed 7.58 6.59 - - Call option (ceiling price) 8.05 8.05 8.05 8.05 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Crude oil and liquids Average Volumes (bbls/d) ------------------------------------------------------------------------- Q3 2009 Q4 2009 ------------------------------------------------------------------------- Costless collars 500 500 ------------------------------------------------------------------------- Total bbls/d 500 500 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Average Price (CDN$/bbl WTI) ------------------------------------------------------------------------- Q3 2009 Q4 2009 ------------------------------------------------------------------------- Collar ceiling price 80.70 80.70 Collar floor price 52.30 52.30 ------------------------------------------------------------------------- -------------------------------------------------------------------------Included in the above natural gas table is a fixed price contract of $5.90/GJ at 5,000 GJ/d from the second quarter 2009 to fourth quarter 2009 periods which was funded by selling a call option of 5,000 GJ/d at $8.05 for the 2010 year. As of June 30, 2009, the fair value of True's outstanding commodity contracts is a net unrealized asset of $8.9 million as reflected in the financial statements. The fair value or mark-to-market value of these contracts is based on the estimated amount that would have been received or paid to settle the contracts as at June 30, 2009 and may be different from what will eventually be realized. Changes in the fair value of the commodity contracts are recognized in the Consolidated Statements of Loss within the financial statements. The following is a summary of the gain (loss) on commodity contracts for the three and six months ended June 30, 2009 and 2008 as reflected in the Consolidated Statements of Loss in the financial statements:Commodity contracts ------------------------------------------------------------------------- Crude Oil Natural Q2 2009 Q2 2008 ($000s) & Liquids Gas Total Total ------------------------------------------------------------------------- Realized cash gain (loss) on contracts - 5,789 5,789 (12,619) Unrealized gain (loss) on contracts(1) (433) (2,271) (2,704) (25,550) ------------------------------------------------------------------------- Total gain (loss) on commodity contracts (433) 3,518 3,085 (38,169) ------------------------------------------------------------------------- ------------------------------------------------------------------------- ------------------------------------------------------------------------- Crude Oil Natural YTD 2009 YTD 2008 ($000s) & Liquids Gas Total Total ------------------------------------------------------------------------- Realized cash gain (loss) on contracts - 8,420 8,420 (16,761) Unrealized gain (loss) on contracts(1) (705) 5,845 5,140 (43,237) ------------------------------------------------------------------------- Total gain (loss) on commodity contracts (705) 14,265 13,560 (59,998) ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Unrealized gain (loss) commodity contracts represent non-cash adjustments for changes in the fair value of these contracts during the period.Royalties For the three months ended June 30, 2009, total royalties were $5.3 million, compared to $16.3 million incurred in the same period in 2008. Overall royalties as a percentage of revenue (after transportation costs) in the second quarter of 2009 were 19%, compared with 21% over the same period in 2008. Royalties for the six months ended June 30, 2009 were $11.6 million compared to $31.8 million for the same period in 2008.------------------------------------------------------------------------- Royalties by Commodity Type Three months ended Six months ended ($000s, except June 30, June 30, where noted) 2009 2008 2009 2008 ------------------------------------------------------------------------- Light crude oil, condensate and NGLs 1,222 2,897 2,583 6,663 $/bbl 12.84 21.98 12.14 21.12 Average light crude oil, condensate and NGLs royalty rate (%) 24 20 24 23 Heavy Oil 2,645 5,341 4,494 7,632 $/bbl 10.49 21.57 9.38 15.12 Average heavy oil royalty rate (%) 20 23 22 20 Natural Gas 1,457 8,051 4,555 17,494 $/mcf 0.45 1.90 0.69 1.95 Average natural gas royalty rate (%) 14 20 16 22 ------------------------------------------------------------------------- Total 5,324 16,289 11,632 31,789 ------------------------------------------------------------------------- $/boe 5.99 15.01 6.51 13.71 ------------------------------------------------------------------------- Average total royalty rate (%) 19 21 20 22 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Royalties, by Type ------------------------------------------------------------------------- Three months ended Six months ended June 30, June 30, ($000s) 2009 2008 2009 2008 ------------------------------------------------------------------------- Crown royalties 3,018 9,587 6,091 18,543 Freehold & GORR 1,230 4,848 3,078 9,711 Indian Oil and Gas Canada royalties 784 1,854 1,973 3,535 Saskatchewan resource surcharge 292 - 490 - ------------------------------------------------------------------------- Total 5,324 16,289 11,632 31,789 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Expenses ------------------------------------------------------------------------- Three months ended Six months ended June 30, June 30, ($000s) 2009 2008 2009 2008 ------------------------------------------------------------------------- Production 11,916 16,170 25,862 33,166 Transportation 1,267 2,478 2,830 3,321 General and administrative 2,581 4,492 5,423 8,262 Interest and financing charges 4,218 3,487 7,520 8,003 Unit-based compensation 243 160 (360) 429 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Expenses per boe ------------------------------------------------------------------------- Three months ended Six months ended June 30, June 30, ($ per boe) 2009 2008 2009 2008 ------------------------------------------------------------------------- Production 13.41 14.90 14.47 14.31 Transportation 1.42 2.28 1.58 1.43 General and administrative 2.90 4.14 3.03 3.56 Interest and financing charges 4.75 3.21 4.21 3.45 Unit-based compensation 0.27 0.15 (0.20) 0.19 -------------------------------------------------------------------------Production Expenses For the three months ended June 30, 2009, production expenses totaled $11.9 million ($13.41/boe), compared to $16.2 million ($14.90/boe) recorded in the same 2008 period. In comparison, production expenses were $13.9 million ($15.53/boe) in the first quarter of 2009 and $66.6 million ($15.33/boe) for the 2008 annual period. For the six month period ended June 30, 2009, production expenses totaled $25.9 million ($14.47/boe) compared to $33.2 million ($14.31/boe) for the same period in 2008. True is targeting operating costs of approximately $39.6 million ($12.74/boe) in 2009 which based on assumptions of estimated 2009 annualized production of approximately 8,100 boe/d, after considering completed divestitures, planned cost reductions, and cost reductions due to disposition of high operating cost properties. Forecasted cost reductions are on track through to the second quarter of 2009.Production Expenses, by Commodity Type ------------------------------------------------------------------------- Three months ended Six months ended ($000s, except June 30, June 30, where noted) 2009 2008 2009 2008 ------------------------------------------------------------------------- Light crude oil, condensate and NGLs 2,350 2,193 4,627 5,274 $/bbl 24.70 16.64 21.75 16.71 Heavy oil 3,412 5,808 8,148 10,843 $/bbl 13.53 23.45 17.01 21.49 Natural gas 6,154 8,169 13,087 17,049 $/mcf 1.89 1.93 1.99 1.90 ------------------------------------------------------------------------- Total 11,916 16,170 25,862 33,166 ------------------------------------------------------------------------- $/boe 13.41 14.90 14.47 14.31 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Total 11,916 16,170 25,862 33,166 ------------------------------------------------------------------------- Processing and other third party income(1) (176) (871) (887) (1,458) ------------------------------------------------------------------------- Total after deducting processing and other third party income 11,740 15,299 24,975 31,708 ------------------------------------------------------------------------- $/boe 13.21 14.10 13.98 13.68 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Processing and other third party income is included within petroleum and natural gas sales on the statement of income.Transportation Transportation expenses for the three month period ended June 30, 2009 were $1.3 million ($1.42/boe) compared to $2.5 million ($2.28/boe) in the same 2008 period. In comparison, transportation was $1.74/boe in the first quarter of 2009 and $1.62/boe 2008 annual periods, respectively. Operating Netback For the second quarter of 2009, corporate field operating netback (before hedging) was $12.52/boe compared to $42.66/boe in the same period in 2008. This was the result of decreased overall commodity prices, offset somewhat by lower transportation, royalties and operating expenses. By comparison, corporate field operating netback (before hedging) for the first quarter of 2009 was $9.81/boe. After including hedging activities, the corporate field operating netback for the second quarter of 2009 was $19.03/boe compared to $31.01/boe in the same 2008 period.Field Operating Netback - Corporate (before hedging) ------------------------------------------------------------------------- Three months ended Six months ended June 30, June 30, ($/boe) 2009 2008 2009 2008 ------------------------------------------------------------------------- Sales 33.34 74.85 33.72 64.99 Transportation (1.42) (2.28) (1.58) (1.43) Royalties (5.99) (15.01) (6.51) (13.71) Production expense (13.41) (14.90) (14.47) (14.31) ------------------------------------------------------------------------- Field operating netback 12.52 42.66 11.16 35.54 ------------------------------------------------------------------------- -------------------------------------------------------------------------Overall, corporate operating netbacks for 2009 are currently expected to be lower than 2008 due to anticipated lower commodity prices. Field operating netback for natural gas in the second quarter of 2009 decreased 85% to $0.85/mcf, compared to $5.77/mcf in the same 2008 period, primarily reflecting weakening natural gas prices experienced. After including hedging activities, field operating netback for natural gas in the three months ended June 30, 2009 was $2.63/mcf compared to $4.62/mcf in the same period in 2008.Field Operating Netback - Natural Gas (before hedging) ------------------------------------------------------------------------- Three months ended Six months ended June 30, June 30, ($/mcf) 2009 2008 2009 2008 ------------------------------------------------------------------------- Sales 3.40 9.94 4.42 8.90 Transportation (0.21) (0.34) (0.20) (0.11) Royalties (0.45) (1.90) (0.69) (1.95) Production expense (1.89) (1.93) (1.99) (1.90) ------------------------------------------------------------------------- Field operating netback 0.85 5.77 1.54 4.94 ------------------------------------------------------------------------- -------------------------------------------------------------------------Field operating netback for crude oil, condensate and NGLs averaged $24.11/bbl in the second quarter of 2009, representing a 58% decrease from the second quarter 2008 operating netback of $57.65/bbl. This compares to a 48% decrease in the crude oil, condensate and NGLs sales price. After including hedging activities, field operating netback for crude oil and NGLs in the 2009 second quarter was $24.11/boe compared to $37.08/boe in the same period in 2008.Field Operating Netback - Crude Oil, Condensate and NGLs (before hedging) ------------------------------------------------------------------------- Three months ended Six months ended June 30, June 30, ($/bbl) 2009 2008 2009 2008 ------------------------------------------------------------------------- Sales 53.55 103.14 45.16 86.19 Transportation (1.72) (2.69) (2.15) (2.83) Royalties (11.13) (21.71) (10.23) (17.43) Production expense (16.59) (21.09) (18.47) (19.65) ------------------------------------------------------------------------- Field operating netback 24.11 57.65 14.31 46.28 ------------------------------------------------------------------------- -------------------------------------------------------------------------General and Administrative Net general and administrative ("G&A") expenses for the three and six months ended June 30, 2009 were $2.6 million and $5.4 million, respectively, compared to $4.5 million and $8.3 million, respectively for the same period in 2008. The decrease in the G&A expense for the 2009 periods compared to the 2008 periods is primarily due to targeted G&A reductions completed in January 2009. True streamlined its operations and reduced head office staffing levels by one third in January 2009. The reduction in amounts of capitalized G&A for the 2009 first and second quarter is consistent with a lower capital program. On a per boe basis, G&A expenses for the three and six months ended June 30, 2009 were $2.90/boe and $3.03/boe, respectively, compared to $4.14/boe and $3.56/boe, respectively, for the same period in 2008. In comparison, G&A expenses were $2.8 million or $3.16/boe for the first quarter of 2009.General and Administrative Expenses ------------------------------------------------------------------------- Three months ended Six months ended ($000s, except June 30, June 30, where noted) 2009 2008 2009 2008 ------------------------------------------------------------------------- Gross expenses 3,178 5,508 6,564 10,387 Capitalized (106) (692) (212) (1,199) Recoveries (491) (324) (929) (926) ------------------------------------------------------------------------- Net G&A expenses 2,581 4,492 5,423 8,262 ------------------------------------------------------------------------- Net G&A expenses, per unit ($/boe) 2.90 4.14 3.03 3.56 ------------------------------------------------------------------------- -------------------------------------------------------------------------Interest and Financing Charges True recorded $4.2 million of interest and financing charges for the three months ended June 30, 2009 compared to $3.5 million in the same period in 2008. For the six months ended June 30, 2009, interest and financing charges totaled $7.5 million compared to $8.0 million for the same period in 2008. True's total net debt at June 30, 2009 of $196.7 million includes the $82.1 million liability portion of convertible debentures, $120.2 million of bank debt and the net balance of a working capital surplus. The convertible debentures have a maturity date of June 30, 2011.Interest and Financing Charges ------------------------------------------------------------------------- Three months ended Six months ended ($000s, except June 30, June 30, where noted) 2009 2008 2009 2008 ------------------------------------------------------------------------- Interest and financing charges 4,218 3,487 7,520 8,003 Interest and financing charges ($/boe) 4.75 3.21 4.21 3.45 Debt to funds flow from operations ratio (annualized)(2) Total net debt(1) at quarter end 196,717 189,354 196,717 189,354 Total net debt to periods funds flow from operations ratio (annualized) 4.6x 1.8x 5.7x 1.9x Net debt(1) (excluding convertible debentures) at quarter end 114,642 109,101 114,642 109,101 Net debt to periods funds flow from operations ratio (annualized)(2) 2.7x 1.1x 3.3x 1.1x Debt to funds flow from operations ratio (trailing)(3) Total net debt to periods funds flow from operations ratio (trailing) 3.2x 2.2x 3.2x 2.2x Net debt to periods funds flow from operations ratio (trailing) 1.8x 2.0x 1.8x 2.0x ------------------------------------------------------------------------- (1) Net debt includes the net working capital deficiency (excess) before short-term commodity contract assets and liabilities, current portion of long-term debt and short-term future tax assets and liabilities. Total net debt also includes the liability component of convertible debentures and excludes asset retirement obligations and the future income tax liability. (2) Total net debt and net debt to periods funds flow from operations ratio (annualized) is calculated based upon annualizing funds flow from operations for the three and six month periods ended June 30, 2009, respectively. (3) Trailing periods funds flow from operations is based on the trailing twelve month period ended June 30, 2009 and 2008.These ratios for the remainder of 2009 are expected to be lower following reduction to bank indebtedness associated with the Saskatchewan Divestiture closing on July 30, 2009. Unit-Based Compensation Non-cash unit-based compensation expense for the six month period ended June 30, 2009 was a recovery of $0.4 million compared to expense of $0.4 million in 2008. The decrease in the expense for the six month period ended June 30, 2009 reflects a reduction in the estimated weighted average fair value of incentive rights granted for more recent options, and a reduction to the 2009 expense of $0.7 million for a reversal of prior year unit-based compensation expense for 2009 forfeitures of unvested incentive rights. Depletion, Depreciation and Accretion Depletion, depreciation and accretion expense for the three months ended June 30, 2009 was $27.4 million ($30.80/boe), compared to the $33.2 million ($30.61/boe) in the same period in 2008, which reflects lower production volumes combined with reduced carrying costs in the 2009 period as compared to 2008. For the three months ended June 30, 2009, True has included $62.5 million for future development costs in the depletion calculation and excluded from the depletion calculation $26.6 million for undeveloped land and $37.9 million for estimated salvage.Depletion, Depreciation and Accretion Costs ------------------------------------------------------------------------- Three months ended Six months ended ($000s, except June 30, June 30, where noted) 2009 2008 2009 2008 ------------------------------------------------------------------------- Depletion and Depreciation 26,714 32,696 53,307 68,444 Accretion 660 513 1,322 1,068 ------------------------------------------------------------------------- Total 27,374 33,209 54,629 69,512 ------------------------------------------------------------------------- Per unit ($/boe) 30.80 30.61 30.57 29.99 ------------------------------------------------------------------------- -------------------------------------------------------------------------Income Taxes For the six months ended June 30, 2009, the Trust has recorded no capital tax expense compared to $1.1 million expensed in the same period in 2008. Prior to January 1, 2009, capital taxes were based on a combination of debt and equity levels of the Trust at the end of the year in addition to a resource surcharge component of Saskatchewan provincial taxes calculated as a percentage of revenues. Effective for True's 2009 taxation year, this Saskatchewan tax has been changed such that it is calculated solely as a percentage of revenues. Accordingly, this Saskatchewan tax is grouped with royalties on a prospective basis. Future income taxes arise from differences between the accounting and tax bases of the Trust's assets and liabilities. For the six months ended June 30, 2009, the Trust recognized a future income tax recovery of $38.3 million compared to a recovery of $23.3 million in the same period in 2008. Under our current structure, the operating entities may make interest and royalty payments to the Trust, which transfers taxable income to the Trust to eliminate income subject to corporate and other income taxes in the operating entities. Alternatively, the Trust's operating company may claim discretionary tax deductions to reduce taxable income. Under the SIFT tax (as defined and referred to below), amounts transferred to the Trust could be taxable beginning in 2011 as distributions will no longer be deductible for income tax purposes. At that time, True could claim discretionary tax deductions in its operating companies, reduce the income transferred to the Trust, and pay all or a portion of distributions as a return of capital. Until 2011, under the terms of its trust indenture, the Trust is required to distribute amounts at least equal to its taxable income. In the event that the Trust has undistributed taxable income in a taxation year (prior to 2011), an additional special taxable distribution, subject to certain withholding taxes for non-resident holders, would be required under the trust indenture. The SIFT tax is not expected to directly affect our cash flow levels and distribution policies until 2011 at the earliest. Enactment of the Tax on Income Trusts On June 22, 2007, the legislation implementing a new tax (the "SIFT tax") on publicly traded income trusts and limited partnerships, referred to as "specified investment flow-through" ("SIFTs") entities (Bill C-52) received Royal Assent. As a result, the SIFT tax was considered to be enacted for accounting purposes in June 2007, which resulted in a $1.2 million future income tax recovery amount being recorded in 2007 to reflect current temporary differences between the book and tax basis of assets and liabilities expected to be remaining in the Trust in 2011. The SIFT tax announcement and the related future income tax recovery did not affect cash flow or distributions and is not expected to affect distribution policies until 2011 at the earliest. SIFTs are certain publicly traded income and royalty trusts and limited partnerships including True. For SIFTs in existence on October 31, 2006 the SIFT tax will be effective in 2011, unless certain rules related to "undue expansion" are not adhered to. Under the guidance provided, True can increase its equity by approximately $737 million between 2006 and 2011 without prematurely triggering the SIFT tax. In June 2008, Bill C-50, which contained legislation to adjust the deemed provincial component of the SIFT tax on distributions from SIFTs expected to apply to the Trust commencing in 2011, received Royal Assent. Under regulations now enacted, instead of basing the provincial component of the SIFT tax on a flat rate of 13%, the provincial component will instead be based on the general provincial corporate income tax rate in each province in which the SIFT has a permanent establishment. For purposes of calculating this component of the tax, the general corporate taxable income allocation formula will be used. Specifically, the Trust's taxable distributions will be allocated to provinces by taking the pro rata of:- that proportion of the Trust's taxable distributions for the year that the Trust's wages and salaries in the province are of its total wages and salaries in Canada; and - that proportion of the Trust's taxable distributions for the year that the Trust's gross revenues in the province are of its total gross revenues in Canada.Under the regulations, the Trust would be considered to have a permanent establishment only in Alberta, where the provincial tax rate in 2011 is expected to be 10%. As of March 4, 2009, the regulations are substantively enacted. On July 14, 2008, the Department of Finance released proposed amendments (the "Conversion Rules") to the Income Tax Act (Canada) to facilitate the conversion of existing SIFTs into corporations. In general, the proposed amendments will permit a conversion to be tax deferred for both the unitholders and the SIFT if completed before 2013. These rules were subsequently revised and introduced as part of Bill C-10 as part of the Budget Implementation Act, 2009 on February 6, 2009 and received Royal Assent on March 12, 2009. The True Board of Directors and Management continue to review the impact of this tax on business strategy as well as the Conversion Rules in considering alternatives available. At the present time, True believes some or all of the following actions will or could result due to the enactment of the SIFT tax:- If structural or other similar changes are not made if and to the extent that the Trust makes distributions to unitholders, the distribution yield net of the SIFT tax in 2011 and beyond to taxable Canadian investors will remain approximately the same; however, the distribution yield to tax-deferred Canadian investors (RRSPs, RRIFs, pension plans, etc.) would fall by an estimated 26.5 percent in 2011 and 25.0 percent in 2012 and beyond. For U.S. investors, the distribution yield net of the SIFT and withholding taxes would fall by an estimated 25.3 percent in 2011 and 25.1 percent in 2012 and beyond; - If and to the extent that the Trust makes distributions to unitholders, a portion of True's cash flow could be allocated to the payment of the SIFT tax, or other forms of tax, and would not be available for distribution or re-investment; - True could convert to a corporate structure to facilitate investing a higher proportion or all of its cash flow in exploration and development projects. Such a conversion and change to capital programs could result in a significant continued elimination of distributions and/or dividends; - True might determine that it is more economic to remain in the trust structure, at least for a period of time, and shelter its taxable income using discretionary tax deductions and, if and to the extent that it reinstates the payments of distributions, pay all or a portion of its distributions (if any) on a return of capital basis, likely at a lower payout ratio.The Trust is reviewing all organizational structures and alternatives to minimize the impact of the SIFT tax on our unitholders. While there can be no assurance that the negative effect of the tax can be minimized or eliminated, True and its advisors will continue to review these issues. As at June 30, 2009, the operating subsidiaries and the Trust itself have a total net future income tax liability balance of $5.7 million. Canadian GAAP requires that a future income tax liability be recorded when the book value of assets exceeds the balance of tax pools. At June 30, 2009, the Trust and operating subsidiaries of the Trust had approximately $476 million in tax pools available for deduction against future income as follows:------------------------------------------------------------------------- Operating ($000s) Trust subsidiaries Total ------------------------------------------------------------------------- Intangible resource pools 15,000 306,000 321,000 Undepreciated capital cost - 123,000 123,000 Loss carryforwards (expire through 2027) - 30,000 30,000 Unit issue costs 2,000 - 2,000 ------------------------------------------------------------------------- 17,000 459,000 476,000 -------------------------------------------------------------------------Following the receipt of net proceeds from the Divestiture closing on July 30, 2009, the Trust and operating subsidiaries of the Trust are anticipated to have approximately $391 million in tax pools for deduction against future income. Net Loss and Funds Flow from Operations True generated funds flow from operations of $10.8 million ($0.14 per diluted unit) for the three month period ended June 30, 2009, down 59% from $26.3 million ($0.33 per diluted unit) for the second quarter of 2008. The decrease in funds flow for the 2009 period compared to the same period in 2008 was primarily the result of a significant decrease in commodity prices, in combination with lower sales volumes. Funds flow from operations for the second quarter of 2009 increased 66% from first quarter 2009 funds flow from operations of $6.5 million. Funds flow from operations for the six month period ended June 30, 2009 was $17.3 million ($0.22 per diluted unit), down from the $50.5 million ($0.64 per diluted unit) for the same period in 2008. True maintains a commodity price risk management program to provide a measure of stability to funds flow from operations. Unrealized mark-to-market gains or losses are non-cash adjustments to the current fair market value of the contract over its entire term and are included in the calculation of net loss. True generated a net loss of $99.7 million ($1.27 per diluted unit) in the second quarter of 2009 compared to a net loss of $21.4 million ($0.27 per diluted unit) in 2008. The increase in the net loss is primarily a result of the $114.2 million non-cash accounting loss recorded on the assets held for sale.Funds Flow From Operations and Net Loss ------------------------------------------------------------------------- Three months ended Six months ended ($000s, except per June 30, June 30, unit amounts) 2009 2008 2009 2008 ------------------------------------------------------------------------- Funds flow from operations 10,765 26,304 17,254 50,537 Basic ($/unit) 0.14 0.33 0.22 0.64 Diluted ($/unit) 0.14 0.33 0.22 0.64 Net loss (99,715) (21,374) (108,771) (39,995) Basic ($/unit) (1.27) (0.27) (1.39) (0.50) Diluted ($/unit) (1.27) (0.27) (1.39) (0.50) ------------------------------------------------------------------------- Reconciliation of Cash Flow from Operating Activities and Funds Flow from Operations ------------------------------------------------------------------------- Three months ended Six months ended ($000s, except per June 30, June 30, unit amounts) 2009 2008 2009 2008 ------------------------------------------------------------------------- Cash flow from operating activities 6,467 19,892 15,778 37,735 Asset retirement costs incurred 313 123 1,051 712 Change in non-cash working capital 3,985 6,289 425 12,090 ------------------------------------------------------------------------- Funds flow from operations 10,765 26,304 17,254 50,537 ------------------------------------------------------------------------- Capital Expenditures True planned for a very modest capital program for the first half of 2009. Second quarter 2009 capital spending was $1.2 million, as compared to $4.1 million for the same period in 2008. Capital Expenditures ------------------------------------------------------------------------- Three months ended Six months ended June 30, June 30, ($000s) 2009 2008 2009 2008 ------------------------------------------------------------------------- Lease acquisitions and retention 225 415 308 965 Geological and geophysical 40 (55) 51 12 Drilling and completion costs 141 2,382 1,447 9,157 Facilities and equipment 622 734 1,750 1,626 ------------------------------------------------------------------------- Exploration and development(1) 1,028 3,475 3,556 11,759 Corporate and property acquisitions 123 605 351 971 ------------------------------------------------------------------------- Total capital expenditures - cash 1,151 4,080 3,907 12,730 Property dispositions - cash (8,289) (38,530) (8,281) (44,318) ------------------------------------------------------------------------- Total net capital expenditures - cash (7,138) (34,450) (4,374) (31,588) ------------------------------------------------------------------------- Other - non-cash(2) (1,107) (2,521) (1,221) (2,714) ------------------------------------------------------------------------- Total net capital expenditures(1) (8,245) (36,971) (5,595) (34,302) ------------------------------------------------------------------------- (1) Excludes capitalized costs related to asset retirement obligation expenditures incurred during the year. (2) Other includes non-cash adjustments for current period's asset retirement obligations and unit based compensation capitalized.The $1.2 million capital program for the three months ended June 30, 2009, was financed entirely with funds flow from operations. Based on the current economic conditions and True's operating forecast for the remainder of 2009, the Trust has budgeted a 2009 capital program of $15 million and is anticipating capital expenditures of approximately $11.1 million for the remainder of 2009. True's drilling program for the third and fourth quarters has commenced with plans to participate in up to 20 wells operated by True to take advantage of the Alberta Government Royalty incentive program. True's drilling program is targeting oil in Mantario, Saskatchewan and natural gas in Alberta including up to three Notikewan horizontal well tests in West Central Alberta. Land True's net mineral leases in Alberta, British Columbia and Saskatchewan as of June 30, 2009 decreased to approximately 338,000 net acres from 358,000 net acres established on March 31,2009. Upon closing of the recent dispositions, True continues to have approximately 274,000 net acres of undeveloped land with 320 exploitation drilling opportunities identified representing over 5 years of drilling inventory. Ceiling Test The Trust calculates a ceiling test quarterly and annually to place a limit on the aggregate carrying value of its capitalized costs, which may be amortized against revenues of future periods. The ceiling test is performed in accordance with the requirements of the Canadian Institute of Chartered Accountants ("CICA") AcG-16 "Oil and Gas Accounting - Full Cost", a two step process. The Trust performed a ceiling test calculation at June 30, 2009 resulting in undiscounted cash flows from proved reserves and the undeveloped properties not exceeding the carrying value of oil and gas assets. Consequently, True performed stage two of the ceiling test assessing whether discounted future cash flows from production of proved plus probable reserves plus the carrying cost of undeveloped properties, net of any impairment allowance, exceeds the carrying value of its petroleum and natural gas properties. No impairment in oil and gas assets was identified as at June 30, 2009. The ceiling test calculation will be updated in 2009 on a quarterly and annual basis based upon the latest available data, including but not limited to an updated annual external reserve engineering report which incorporates a full evaluation of reserves or internal reserve updates at quarterly periods, and the latest commodity pricing deck. Estimating reserves is very complex, requiring many judgments based on available geological, geophysical, engineering and economic data. Changes in these judgments could have a material impact on the estimated reserves. These estimates may change, having either a negative or positive effect on net earnings as further information becomes available and as the economic environment changes. Asset Retirement Obligations As at June 30, 2009, the Trust has recorded an Asset Retirement Obligation ("ARO") of $33.7 million, compared to $26.3 million at June 30, 2008 for future abandonment and reclamation of the Trust's properties. For the six months ended June 30, 2009, the overall ARO balance remained approximately the same as a result of accretion expense of $1.3 million, $1.0 million net changes in estimates and liabilities incurred on development activities, offset by $1.3 million of liabilities released on dispositions and $1.0 million of liabilities settled. The asset retirement obligation associated with the Saskatchewan Divestiture of $9.6 million has been classified as a current liability. Distributions For the six months ended June 30, 2009 Trust declared distributions as follows:------------------------------------------------------------------------- ($000s, except per unit amount) Distribution Six months ended June 30, 2009 Per Unit Total ------------------------------------------------------------------------- Distributions declared $ 0.02 $ 1,570 ------------------------------------------------------------------------- Distribution Paid History(1) Distributions comprise a taxable portion and a return of capital portion (tax deferred). The return of capital component reduces the cost basis of the trust units held, as described below. For additional information, please see our website at www.trueenergytrust.com. ------------------------------------------------------------------------- Distributions Taxable Return of Calendar Year per unit Portion Capital ------------------------------------------------------------------------- 2005 (two months)(2) $ 0.480 $ 0.456 $ 0.024 2006 $ 2.640 $ 2.033 $ 0.607 ------------------------------------------------------------------------- Cumulative to Dec. 31, 2006 $ 3.120 $ 2.489 $ 0.631 ------------------------------------------------------------------------- 2007 year $ 0.960 $ 0.960 - ------------------------------------------------------------------------- Cumulative to Dec. 31, 2007 $ 4.080 $ 3.449 $ 0.631 ------------------------------------------------------------------------- 2008 year $ 0.460 $ 0.460 - ------------------------------------------------------------------------- Cumulative to December 31, 2008 $ 4.540 $ 3.909 $ 0.631 ------------------------------------------------------------------------- 2009 year to date (one month)(3) $ 0.020 ----------------------------------------------- Cumulative to June 30, 2009 $ 4.560 ----------------------------------------------- (1) Applies to unitholders who are residents of Canada and hold their trust units as capital property. (2) Based upon the distributions paid in the 2005 calendar year, after the November 2, 2005 Arrangement with TKE Energy Trust. (3) It is currently estimated that the approximate taxable portion of the January 2009 distribution to Canadian unitholders will be 100%. In consultation with its U.S. tax advisors, True believes that its Trust units should be "qualified dividends" for U.S. federal purposes. As such, the portion of distributions made during 2009 that are considered dividends for U.S. federal purposes should qualify for the reduced rate of tax applicable to long-term capital gains. Unitholders or potential unitholders should consult their own legal or tax advisors as to their particular income tax consequences of holding True units. Please review our February 19, 2009 press release addressing this. Monthly Distributions Actual distributions paid and declared per Trust unit along with relevant payment dates for 2009 to date are as follows: ------------------------------------------------------------------------- Distribution Ex-distribution Date Record Date Payment Date per unit ------------------------------------------------------------------------- December 29, 2008 December 31, 2008 January 15, 2009 0.02 January 28, 2009 January 30, 2009 February 17, 2009 0.02 -------------------------------------------------------------------------During the first six months of 2009, funding requirements for distributions declared was 9% of funds flow from operations. As announced on March 17, 2009, due to the continued deterioration in economic conditions, including the significant decline in crude oil and natural gas prices, a weakening outlook for natural gas demand and heightened risk in the credit markets, True has deemed it prudent to suspend distributions, until further notice, to maintain corporate liquidity during the current financial turmoil and prevailing commodity price environment. Distributions remain suspended until such time as the Board of Directors determines otherwise. Pursuant to True's credit facility, distributions to unitholders (other than by way of the issuance of Trust units) require the approval of True's lenders if the funds to pay such distributions are received from True Energy Inc. ("True Energy"). Foreign Ownership Update Based on information from Trust records and information provided by intermediaries holding Trust units for others, the Trust estimates that, as of July 20, 2009 approximately 25 percent of unitholders are non-Canadian residents with the remaining 75 percent being Canadian residents. In order that the Trust maintains its status as a "mutual fund trust" under the Income Tax Act (Canada), certain provisions of the Income Tax Act (Canada) require that the trust not be established or maintained primarily for the benefit of non-residents of Canada ("non-residents"). The trust indenture for the Trust provides that if the Trust or its administrator becomes aware that the activities of the Trust and ownership of Trust units by non-residents may threaten the status of the Trust under the Income Tax Act (Canada) as a "unit trust" or "mutual fund trust", the Trust is authorized to take action as may be necessary to maintain the status of the Trust as a unit trust and a mutual fund trust, including the imposition or restrictions on the issuance by the Trust, or the transfer by any unitholder, of Trust units to a non-resident. Liquidity and Capital Resources As an oil and gas business, the Trust has a declining asset base and therefore relies on ongoing development and acquisitions to replace production and add additional reserves. Future oil and natural gas production and reserves are highly dependent on the success of exploiting the Trust's existing asset base and in acquiring additional reserves. To the extent the Trust is successful or unsuccessful in these activities; funds flow could be increased or reduced. Global financial markets continued to remain fragile during the first and second quarters of 2009. The economic crisis continues to put a strain on credit and equity markets as characterized by a decline in liquidity and higher borrowing costs. Access to capital markets has become constrained and significantly more expensive for the Trust along with other oil and gas entities. The current global economic environment has continued to create volatility in commodity prices, tempered somewhat by the growing US to Canadian dollar exchange rate. Given the continuing uncertain economic conditions, the Trust has maintained a 2009 capital budget of $15 million and has suspended distributions until further notice. The Trust continues to monitor forecasted debt levels to manage its operations within forecasted cash flow. In addition, the Trust will continue to monitor developments within the global economic environment to consider the impacts on current or future lending arrangements. Liquidity risk is the risk that the Trust will not be able to meet its financial obligations as they fall due. The Trust actively manages its liquidity through daily and longer-term cash, debt and equity management strategies. Such strategies encompass, among other factors: having adequate sources of financing available through its bank credit facilities, estimating future cash generated from operations based on reasonable production and pricing assumptions, analysis of economic hedging opportunities, and maintaining sufficient cash flows for compliance with debt covenants. The Trust is fully compliant with all of its debt covenants. The Trust generally relies on operating cash flows and its credit facilities to fund capital requirements and provide liquidity. Future liquidity depends primarily on cash flow generated from operations, existing credit facilities and the ability to access debt and equity markets. From time to time, the Trust accesses capital markets to meet its additional financing needs and to maintain flexibility in funding its capital programs. There can be no assurance that debt or equity financing, or cash generated by operations will be available or sufficient to meet these requirements or for other corporate purposes or, if debt or equity financing is available, that it will be on terms acceptable to the Trust. The inability of the Trust to access sufficient capital for its operations could have a material adverse effect on the Trust's business financial condition, results of operations and prospects. Credit risk is the risk of financial loss to the Trust if a customer or counterparty to a financial instrument fails to meet its contractual obligations, and arises principally from the Trust's trade receivables from joint venture partners, petroleum and natural gas marketers, and financial derivative counterparties. A substantial portion of the Trust's accounts receivable are with customers and joint interest partners in the petroleum and natural gas industry and are subject to normal industry credit risks. The Trust sells substantially all of its production to eight primary purchasers under standard industry sale and payment terms. Purchasers of the Trust's natural gas, crude oil and natural gas liquids are subject to a periodic internal credit review to minimize the risk of non-payment. The Trust has continued to closely monitor and reassess the creditworthiness of its counterparties, including financial institutions. This has resulted in the Trust reducing or mitigating its exposures to certain counterparties where it is deemed warranted and permitted under contractual terms. The Trust may be exposed to third party credit risk through its contractual arrangements with its current or future joint venture partners, marketers of its petroleum and natural gas production and other parties. In the event such entities fail to meet their contractual obligations to the Trust, such failures may have a material adverse effect on the Trust's business, financial condition, results of operations and prospects. In addition, poor credit conditions in the industry and of joint venture partners may impact a joint venture partner's willingness to participate in the Trust's ongoing capital program, potentially delaying the program and the results of such program until the Trust finds a suitable alternative partner. During 2009, the Trust has been executing several strategies for dealing with these uncertain times. True's corporate thrust in 2009 is to continue to improve the Trust's balance sheet by reducing total outstanding debt and streamlining its operating cost structure. In 2009, True has limited its capital program to $15 million in an effort to maintain production and increase financial flexibility to fund operations. This compares to the $43 million capital program employed in 2008. As a consequence of a reduced capital program and strategic divestitures completed in 2008 and 2009, total net debt levels decreased by $42.7 million from $239.4 million at March 31, 2008 to $196.7 million at June 30, 2009. Total net debt excludes unrealized commodity contract assets and liabilities, future income taxes and asset retirement obligations. On July 30, 2009, the Trust successfully completed the divestiture of the majority of its Saskatchewan assets for net proceeds, after purchase adjustments of $86 million. These proceeds have been used to reduce the Trust's bank indebtedness. On July 30, 2009, in conjunction with completion of the Saskatchewan Divestiture, True negotiated a new banking syndicate commitment to replace the existing bank facility, subject to finalization and execution of a mutually acceptable credit agreement, that will provide True with a credit facility of $85 million. The facility will consist of a $10 million demand operating facility provided by one Canadian bank and a $75 million extendible revolving term credit facility syndicated by one Canadian chartered bank and one Canadian financial institution. The revolving period on the revolving term credit facility will end on June 30, 2010, unless extended for a further 364 day period. Should the facilities not be renewed they will convert to 366 day non-revolving term facilities on the renewal date. The borrowing base will be subject to renewal on March 31, 2010. The strategic dispositions accomplished in the year allow the Trust to progress forward with substantially improved financial flexibility. Combined funding requirements for the January distribution declared and True's capital expenditures represented 11% and 32% of funds flow from operations in the three and six months ended June 30, 2009, respectively. As a result of the continued deterioration in economic conditions, including the significant decline in crude oil prices seen earlier in 2009, a weakening outlook for natural gas demand and a heightened risk in the credit markets, True has deemed it prudent to suspend distributions to maintain corporate liquidity during the current financial turmoil and prevailing commodity price environment. Distributions remain suspended until such time as the Board of Directors determines otherwise. Pursuant to True's credit facility, distributions to unitholders (other than by way of the issuance of Trust units) generally require the approval of True's lenders if the funds to pay such distributions are received from True Energy. True continues to tighten its cost structure in the current economically challenging climate with forecasted cuts from 2008 levels of 30% to total operating expenses which includes G&A and lease operating costs in 2009. The results through the first half of 2009 are on track. True's operating forecast for 2009 which assumes a CAD$/US$ exchange rate of $0.90, a WTI oil price of US$70.00/bbl, AECO natural gas price of CAD$4.50/GJ ($4.95/mcf) and production volumes of 6,500 boe/d for August to December 2009, generates cash flow from operations of $38 million. Based on the foregoing assumptions and assuming 2009 distributions of $1.6 million coupled with the planned capital budget of $15 million the Trust would utilize approximately 44% of the Trust's forecasted funds flow from operations. As an added layer of protection of its cash flow forecast, upon completion of the divestitures, True's hedging represents approximately 65% of its estimated natural gas production for the third and fourth quarter of 2009 at an average price of $6.60 CAD per GJ ($7.26/mcf) and 21.5% of the first quarter of 2010 through to the second quarter of 2010 at an average of $7.25 CAD per GJ ($7.96/mcf). In addition, 500 bbl/d of oil for the third and fourth quarter of 2009 are hedged by way of a costless collar of $52.30 CAD x $80.70 CAD. True maintains an active commodity price risk management program focused on maintaining sufficient cash flow to fund its operations. Pursuant to True's existing credit facility, distributions from True Energy to the Trust during the remaining term of the facilities is restricted other than: (i) distributions by True Energy to the Trust to permit the regular semi-annual interest payments by the Trust on June 30, 2009, December 31, 2009 and June 30, 2010 in respect of the convertible debentures issued by the Trust on or before April 1, 2009; and (ii) distributions from True Energy to the Trust to permit cash distributions in respect of Trust unit redemptions, if and only if and to the extent that the total cash amount payable in respect of all unit redemptions in a month does not exceed $250,000; provided in each case that the foregoing distributions shall not be permitted if a borrowing base shortfall has occurred and is continuing, a demand for payment has been made and remains outstanding, a default or an event of default is then in existence or could reasonably be expected to result from such distribution, or the distribution could impair the ability of True Energy to satisfy its covenants and obligations to the lenders under the credit facility. There are currently no commitments, other than those associated with the Trust's credit facilities outlined above, its 2009 capital program of $11.1 million for the remaining second half of 2009, and the off-balance sheet arrangements outlined below. The Trust continually monitors its capital spending program in light of the recent volatility with respect to commodity prices and Canadian dollar exchange rates with the aim of ensuring the Trust will be able to meet future anticipated obligations incurred from normal ongoing operations with funds flow from operations and draws on the Trust's syndicated facility, as necessary. As announced on March 17, 2009, Trust unit distributions have been suspended until further notice. On June 15, 2006 the Trust completed a bought deal public offering of 86,250 7.5% convertible unsecured subordinated debentures at a price of $1,000 per debenture for aggregate gross proceeds of $86,250,000. The debentures have a face value of $1,000 per debenture and a maturity date of June 30, 2011. The debentures bear interest at an annual rate of 7.50% payable semi-annually on June 30 and December 31 in each year commencing December 31, 2006. The debentures are convertible at anytime at the option of the holders into Trust units of the Trust at a conversion price of $16.00 per trust unit. The Trust will have the right to redeem all or a portion of the debentures at a price of $1,050 per debenture after June 30, 2009 and on or before June 30, 2010 and at a price of $1,025 per debenture after June 30, 2010 and before the maturity date. Upon maturity or redemption of the debentures, the Trust may, subject to notice and regulatory approval, pay the outstanding principal and premium (if any) on the debentures in cash or through the issue of additional Trust units at 95% of the weighted average trading price of the Trust units. As at July 22, 2009, the Trust had outstanding a total of 4,377,132 incentive units exercisable at an average exercise price of $2.36 per unit, 294,026 exchangeable shares (convertible, as at July 22, 2009 into an aggregate of 312,467 Trust units, subject to further adjustments based on distributions made on Trust units), $86.25 million principal amount of debentures convertible into trust units (at a conversion price of $16.00 per Trust unit) and 78,496,581 Trust units.Commitments Off-Balance Sheet ArrangementsThe Trust has certain lease agreements, including primarily office space leases, which were entered into in the normal course of operations. All leases have been treated as operating leases whereby the lease payments are included in operating expenses or G&A expenses depending on the nature of the lease. No asset or liability value has been assigned to these leases in the balance sheet as of June 30, 2009. Business Prospects and 2009 Year Outlook The Trust continues to develop its core assets and conduct some exploration programs utilizing its large inventory of geological prospects. In addition, the Trust will continue to explore potential acquisition opportunities. Currently, the Trust's producing properties are located in Saskatchewan, Alberta and British Columbia. Upon closing of the recent dispositions, True continues to have approximately 274,000 net acres of undeveloped land with 320 exploitation drilling opportunities identified representing over 5 years of drilling inventory. True continues to monitor its cost structure in the current economically challenging climate and as a result, completed G&A reductions in January 2009. True streamlined its operations and reduced head office staffing levels by one third compared to 2008 levels. True's capital program for 2009 remains at $15 million. Production volumes are estimated to average 6,500 boe/d through August to December 2009 as a result of recent dispositions, with an expected 2009 average production rate of 7,000 boe/d. As an added layer of protection of its cash flow forecast, upon completion of divestitures, True's hedging represents approximately 65% of its estimated natural gas production for the third and fourth quarter of 2009 at a combined fixed price of $6.60 CAD per GJ ($7.26/mcf ) and 21.5% of the first quarter of 2010 through to the second quarter of 2010 at an average of $7.25 CAD per GJ ($7.96/mcf). In addition, 500 bbl/d of oil for the third and fourth quarter of 2009 are hedged by way of a costless collar of $52.30 CAD x $80.70 CAD. True's operating forecast for 2009 which assumes a CAD$/US$ exchange rate of $0.90, a WTI oil price of US$70.00/bbl, AECO natural gas price of CAD$4.50/GJ ($4.95/mcf) and production volumes of 6,500 boe/d for August to December 2009, generates cash flow from operations of $38 million. Based on the foregoing assumptions and assuming 2009 distributions of $1.6 million coupled with the planned capital budget of $15 million the Trust would utilize approximately 44% of the Trust's forecasted funds flow from operations. True's 2009 capital program is not expected to exceed $15 million and will limit the second half 2009 capital program to $11.1 million. Given the nature of True's lands and their inherent advantage of year round access, True currently plans to spread its 2009 capital program evenly through the full year of 2009 to take advantage of reduced service costs during non-peak times. True will continue to focus on opportunities to increase its farm-out activity in non-core areas. If the 2009 outlook for commodity prices improves, True would plan to increase its capital spending later in 2009 dependant upon cash flow. On July 30, 2009 True announced that it has negotiated a new banking syndicate commitment to replace its existing bank facility, subject to finalization and execution of a mutually acceptable credit agreement, with a revolving period of June 30, 2010 and a maturity date of June 2011. The next borrowing base review under the new facility will be scheduled for March 31, 2010.Financial Reporting Update Goodwill and intangible assetsIn February 2008, the CICA issued a new accounting standard, Section 3064 - Goodwill and Intangible Assets, which replaces Section 3062 - Goodwill and Other Intangible Assets, and Section 3450 - Research and Development costs. The new section establishes standards for the recognition, measurement and disclosure of goodwill and intangible assets. The section was effective for the Trust beginning January 1, 2009. Application of the new section does not currently have any impact on the Trust's financial statements. International Financial Reporting Standards ("IFRS") On February 13, 2008 the CICA Accounting Standards Board announced that Canadian public reporting issuers will be required to report under International Financial Reporting Standards ("IFRS"), which will replace Canadian generally accepted accounting principles ("GAAP") for years beginning on or after January 1, 2011. The transition date of January 1, 2011 will require restatement for comparative purposes, of amounts reported by the Trust for its year ended December 31, 2010, and of the opening balance sheet as at January 1, 2010. An internal project team has been set up to manage this transition and to ensure successful implementation within the required time frame. Current economic conditions may require re-allocation of resources available for the IFRS conversion project. The Trust has completed a high level analysis to determine the areas impacted by the conversion and is assessing the financial reporting impacts on the adoption of IFRS and, at this time, the impact on future financial position and results of operations has not yet been determined. On July 23, 2009 the IASB published amendments to IFRS 1 - "First-time Adoption of International Financial Reporting Standards" which will allow an election to measure oil and gas assets at the date of transition to IFRS at the amount determined under Canadian GAAP. The Trust anticipates a significant increase in disclosures resulting from the adoption of IFRS and is continuing to assess the level of this disclosure required and any necessary systems changes to gather and process the information. We will continue to monitor any changes in the adoption of IFRS and will update plans as necessary. Business Risks and Uncertainties The reader is advised that True continues to be subject to various types of business risks and uncertainties as described in the Management, Discussion and Analysis for the year ended December 31, 2008 and the Trust's Annual Information Form for the year ended December 31, 2008. Critical Accounting Estimates The reader is advised that the critical accounting estimates, policies, and practices as described in the Trust's Management's Discussion and Analysis for the year ended December 31, 2008 continue to be critical in determining True's unaudited financial results as at June 30, 2009. There were no changes in accounting policies for the six month period ended June 30, 2009, except for the adoption of a new accounting standard, Section 3064 - Goodwill and Intangible Assets, which does not have any impact on the Trust's financial statements. Legal, Environmental Remediation and Other Contingent Matters The Trust reviews legal, environmental remediation and other contingent matters to both determine whether a loss is probable based on judgment and interpretation of laws and regulations and determine that the loss can reasonably be estimated. When the loss is determined, it is charged to earnings. The Trust's management monitor known and potential contingent matters and make appropriate provisions by charges to earnings when warranted by the circumstances.Controls and Procedures Disclosure Controls and ProceduresThe Trust's Chief Executive Officer and Chief Financial Officer have designed, or caused to be designed under their supervision, disclosure controls and procedures to provide reasonable assurance that: (i) material information relating to the Trust is made known to the Trust's Chief Executive Officer and Chief Financial Officer by others, particularly during the period in which the annual and interim filings are being prepared; and (ii) information required to be disclosed by the Trust in its annual filings, interim filings or other reports filed or submitted by it under securities legislation is recorded, processed, summarized and reported within the time period specified in securities legislation. Internal Control over Financial Reporting The Trust's Chief Executive Officer and Chief Financial Officer have designed, or caused to be designed under their supervision, internal control over financial reporting to provide reasonable assurance regarding the reliability of the Trust's financial reporting and the preparation of financial statements for external purposes in accordance with the Canadian GAAP. The Trust is required to disclose herein any change in the Trust's internal control over financial reporting that occurred during the period beginning on April 1, 2009 and ended on June 30, 2009 that has materially affected, or is reasonably likely to materially affect, the Trust's internal control over financial reporting. No material changes in the Trust's internal control over financial reporting were identified during such period, that has materially affected, or are reasonably likely to materially affect, the Trust's internal control over financial reporting. It should be noted that a control system, including the Trust's disclosure and internal controls and procedures, no matter how well conceived, can provide only reasonable, but not absolute, assurance that the objectives of the control system will be met and it should not be expected that the disclosure and internal controls and procedures will prevent all errors or fraud. Standardized Distributable Cash The Canadian Securities Administrators revised and re-issued in July 2007 National Policy 41-201 "Income Trusts and Other Indirect Offerings", which includes disclosures regarding distributable cash for Income Trusts. Further, the Canadian Institute of Chartered Accountants ("CICA") issued the Interpretive Release "Standardized Distributable Cash in Income Trusts and Other Flow-Through Entities: Guidance on Preparation and Disclosure" (the "Release"). In this guidance, sustainability concepts are discussed and standardized distributable cash is defined as cash flow from operating activities less adjustments for productive capacity maintenance, long-term unfunded contractual obligations and the effect of any foreseeable financing matters, related to debt covenants, which could impair True's ability to pay distributions or maintain productive capacity. This Management Discussion and Analysis is in all material respects in accordance with the recommendations provided in CICA's Release and NP 41-201.------------------------------------------------------------------------- Three months ended Six months ended ($000s, except per unit June 30, June 30, amounts and ratios) 2009 2008 2009 2008 ------------------------------------------------------------------------- Net loss (99,715) (21,374) (108,771) (39,995) ------------------------------------------------------------------------- Cash flow from operating activities 6,467 19,892 15,778 37,735 Productive capacity maintenance(1) (1,028) (3,654) (3,556) (12,107) ------------------------------------------------------------------------- Standardized distributable cash 5,439 16,238 12,222 25,628 Proceeds on sale of property, plant and equipment 8,289 38,530 8,281 44,318 Corporate and property acquisition and other capital expenditures (123) (426) (351) (623) Repurchase of trust units under normal course issuer bid - (596) - (596) Bank borrowings (debt repayment) and working capital changes and other (13,605) (44,241) (18,582) (49,715) ------------------------------------------------------------------------- Cash Distributions declared - 9,505 1,570 19,012 Accumulated distributions, beginning of period 253,071 224,674 251,501 215,167 ------------------------------------------------------------------------- Accumulated distributions, end of period 253,071 234,179 253,071 234,179 ------------------------------------------------------------------------- Standardized distributable cash per unit - basic $0.09 $0.21 $0.16 $0.32 Standardized distributable cash per unit - diluted $0.09 $0.21 $0.16 $0.32 ------------------------------------------------------------------------- Standardized distributable cash payout ratio(2) N/A 0.59 0.13 0.74 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Distributions declared per unit for outstanding units in the period - $0.12 $0.02 $0.24 Accumulated distributions per unit, beginning of period 4.56 4.20 4.54 4.08 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Accumulated distributions per unit, end of period $4.56 $4.32 $4.56 $4.32 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Excess (shortfall) of net income over cash distributions declared (99,715) (30,879) (110,341) (59,007) ------------------------------------------------------------------------- ------------------------------------------------------------------------- Excess of cash flow from operating activities over cash distributions declared 6,467 10,387 14,208 18,723 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Please refer to the discussion of productive capacity maintenance below (2) Represents cash distributions declared divided by standardized distributable cashTrue strives to fund both distributions (if any) and maintenance capital primarily from funds flow from operations. Productive capacity is the amount of capital funds required in a period for an enterprise to maintain its ability to generate future cash flow from operating activities at a constant level. As commodity prices can be volatile and short-term variations in production levels are often experienced in the oil and gas industry, True defines production capacity as production on a barrel of oil equivalent basis. A quantifiable measure for these short-term variations is not objectively determinable or verifiable due to various factors including the inability to distinguish natural production declines from the effect of production additions resulting from capital and optimization programs, and the effect of temporary production interruptions. As a result, the adjustment for productive capacity maintenance in True's calculation of standardized distributable cash is True's capital expenditures excluding the cost of any asset acquisition, corporate asset acquisitions or proceeds of any asset disposition. True believes that its capital programs based on 40% to 60% of forecasted funds flow including its current view of True's assets and opportunities and True's outlook for commodity prices and industry conditions in the medium term, should be sufficient to maintain True's productive capacity in the medium term. True sets its hurdle rates for evaluating potential development and optimization projects according to these parameters. Due to the risks inherent in the oil and natural gas industry, particularly True's exploration and development activities and inherent variations in commodity prices, there can be no assurance that capital programs, whether limited to excess of cash flow over distributions or not, will be sufficient to maintain or increase True's production levels or cash flow from operating activities. True's capital expenditures and production can be impacted by the timing of the capital program and spring break up associated with certain operating areas of its properties. As True strives to maintain sufficient credit facilities and appropriate levels of bank debt, this seasonality is not expected to influence True's distribution policies. True's calculation of standardized distributable cash has no adjustment for long-term unfunded contractual obligations. True's only material long-term unfunded contractual obligation at this time is for asset retirement obligations. True's abandonment obligations are being funded on an annual basis with cash flow from operating activities. Cash flow from operating activities, used in our standardized distributable cash calculation, includes a deduction for abandonment expenditures incurred in the year. True regularly monitors its current forecast debt levels to ensure debt covenants are not exceeded. Distributions, if paid, typically exceed net income as a result of non-cash items such as unit-based compensation, depletion, depreciation and accretion, unrealized loss (gain) on commodity contracts, and future income tax expense (recovery). These non-cash items generally result in a reduction to net income, with no impact to cash flow from operating activities. Therefore, distributions, if paid, will exceed net income in most periods. In the event distributions exceed cash flow from operating activities and the requirements of True's capital program, the shortfall would typically be funded by a combination of available bank facilities, equity or debt issues, or the sale proceeds from non-core assets. The Board of Directors and management regularly review the level of distributions. The board considers a number of factors, including expectations of future current commodity prices, hedge positions, production volumes, capital expenditure requirements, market conditions, the availability of debt and equity capital and other factors. As announced on March 17, 2009, as a result of the continued deterioration in economic conditions, including the significant decline in crude oil and natural gas prices and heightened risk in the credit markets, the Trust has suspended its distributions until further notice. Pursuant to True's existing credit facility, distributions to unitholders (other than by way of the issuance of Trust units) generally require the approval of True's lenders if the funds to pay such distributions are received from True Energy. It is expected that these restrictions will continue to exist under the new credit facility.------------------------------------------------------------------------- ($000s, except ratios) To June 30, 2009 ------------------------------------------------------------------------- Cumulative distributable cash from operations(1) 78,655 Proceeds on sale of property, plant and equipment 108,943 Corporate and property acquisitions and other capital expenditures (26,537) Net proceeds from issue of trust units 54,375 Proceeds from issue of convertible debentures, net of issue costs 82,261 Repurchase of trust units under normal course issuer bid (4,194) Funding from DRIP 42,909 Bank borrowings (debt repayment) and working capital changes and other (83,341) ------------------------------------------------------------------------- Cumulative cash distributions declared(1) 253,071 ------------------------------------------------------------------------- Standardized distributable cash payout ratio(2) 3.22 ------------------------------------------------------------------------- (1) Subsequent to the November 2, 2005 reverse takeover of TKE Energy Trust (2) Represents cumulative distributions declared divided by cumulative standardized distributable cashSensitivity Analysis The table below shows sensitivities to funds flow as a result of product price and operational changes. This is based on actual average prices received for the second quarter of 2009 and average production volumes of 9,767 boe/d during that period, as well as the same level of debt outstanding at June 30, 2009. Diluted weighted average Trust units is based upon the second quarter of 2009. These sensitivities are approximations only, and not necessarily valid under other significantly different production levels or product mixes. Hedging activities can significantly affect these sensitivities. Changes in any of these parameters will affect funds flow as shown in the table below:------------------------------------------------------------------------- Funds Funds Flow from Flow from Operations Operations Per Diluted (annualized) Unit ------------------------------------------------------------------------- Sensitivity Analysis ($000s) ($) ------------------------------------------------------------------------- Change of US $1/bbl WTI 1,300 0.02 Change of $0.10/mcf 1,100 0.01 Change of US $0.01 Cdn/US exchange rate 700 0.01 Change in prime of 1% 1,200 0.02 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Selected Quarterly Consolidated Information The following table sets forth selected consolidated financial information of the Trust for the most recently completed quarters ending at June 30, 2009. ------------------------------------------------------------------------- 2009 - Quarter ended (unaudited) ($000s, except per unit amounts) March 31 June 30 ------------------------------------------------------------------------- Revenues before royalties and hedging 31,345 29,805 Funds flow from operations(1) 6,489 10,765 Funds flow from operations per unit(1) Basic $0.08 $0.14 Diluted $0.08 $0.14 Net income (loss) (9,056) (99,715) Net income (loss) per unit Basic $(0.12) $(1.27) Diluted $(0.12) $(1.27) Net capital expenditures (cash) 2,764 (7,138) Distributions declared 1,570 - Distributions per unit $0.02 - ------------------------------------------------------------------------- ------------------------------------------------------------------------- ------------------------------------------------------------------------- 2008 - Quarter ended (unaudited) ($000s, except per unit amounts) March 31 June 30 Sept. 30 Dec. 31 ------------------------------------------------------------------------- Revenues before royalties and hedging 70,033 82,074 72,225 41,053 Funds flow from operations(1) 24,233 26,304 21,491 5,865 Funds flow from operations per unit(1) Basic $0.31 $0.33 $0.27 $0.07 Diluted $0.30 $0.33 $0.27 $0.07 Net income (loss) (18,621) (21,374) 29,939 (9,534) Net income (loss) per unit Basic $(0.24) $(0.27) $0.38 $(0.12) Diluted $(0.24) $(0.27) $0.38 $(0.12) Net capital expenditures (cash) 2,862 (34,450) 13,779 16,471 Distributions declared 9,507 9,505 9,474 7,848 Distributions per unit $0.12 $0.12 $0.12 $0.10 ------------------------------------------------------------------------- ------------------------------------------------------------------------- ------------------------------------------------------------------------- 2007 - Quarter ended (unaudited) ($000s, except per unit amounts) March 31 June 30 Sept. 30 Dec. 31 ------------------------------------------------------------------------- Revenues before royalties and hedging 71,196 74,991 50,547 61,756 Funds flow from operations(1) 29,988 34,192 17,478 19,514 Funds flow from operations per unit(1) Basic $0.43 $0.47 $0.22 $0.25 Diluted $0.42 $0.45 $0.22 $0.25 Net income (loss) (8,571) 1,741 (17,003) (434) Net income (loss) per unit Basic $(0.12) $0.02 $(0.21) $(0.01) Diluted $(0.12) $0.02 $(0.21) $(0.01) Net capital expenditures (cash) 27,915 6,739 7,562 14,828 Distributions declared 16,866 18,376 19,132 19,077 Distributions per unit $0.24 $0.24 $0.24 $0.24 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Refer to "Non-GAAP Measures" in respect of the term "funds flow from operations" and "funds flow from operations per unit". TRUE ENERGY TRUST CONSOLIDATED BALANCE SHEETS As at June 30 and December 31 (unaudited) ------------------------------------------------------------------------- ($000s) 2009 2008 ------------------------------------------------------------------------- ASSETS Current assets Accounts receivable $ 22,787 $ 28,119 Marketable securities (note 4) - 120 Deposits and prepaid expenses 4,345 5,969 Commodity contract asset (note 15) 9,571 3,726 Petroleum and natural gas properties held for sale (note 5) 94,578 - -------------------------- 131,281 37,934 Property, plant and equipment (note 5) 431,573 698,183 -------------------------- Total assets $ 562,854 $ 736,117 -------------------------- -------------------------- LIABILITIES Current liabilities Accounts payable and accrued liabilities $ 21,569 $ 34,128 Distribution payable to unitholders - 1,570 Commodity contract liability (note 15) 705 - Future income taxes (note 13) 2,610 1,100 Bank debt (note 6) 120,205 - Asset retirement obligations related to petroleum and natural gas properties held for sale (note 5) 9,578 - -------------------------- 154,667 36,798 Long-term debt (note 6) - 132,388 Convertible debentures (note 7) 82,075 81,124 Asset retirement obligations (note 8) 24,141 33,682 Future income taxes (note 13) 3,076 42,777 -------------------------- Total liabilities 263,959 326,769 -------------------------- NON-CONTROLLING INTEREST Exchangeable shares of subsidiary (note 9) 2,452 2,887 UNITHOLDERS' EQUITY Unitholders' capital (note 10) 917,012 917,012 Equity component of convertible debentures 5,119 5,119 Contributed surplus (note 11) 27,943 28,240 Accumulated other comprehensive income - (620) Deficit (653,631) (543,290) -------------------------- (653,631) (543,910) -------------------------- -------------------------- Total unitholders' equity 296,443 406,461 -------------------------- Total liabilities and unitholders' equity $ 562,854 $ 736,117 ------------------------------------------------------------------------- ------------------------------------------------------------------------- See accompanying selected notes to the consolidated financial statements. TRUE ENERGY TRUST CONSOLIDATED STATEMENTS OF LOSS AND COMPREHENSIVE LOSS For the three and six months ended June 30 (unaudited) Three months ended June 30, Six months ended June 30, ($000s) 2009 2008 2009 2008 ------------------------------------------------------------------------- REVENUES Petroleum and natural gas sales $ 29,805 $ 82,074 $ 61,150 $ 152,107 Royalties (5,324) (16,289) (11,632) (31,789) Gain (loss) on commodity contracts (note 15) 3,085 (38,169) 13,560 (59,998) ---------------------------------------------------- 27,566 27,616 63,078 60,320 EXPENSES Production 11,916 16,170 25,862 33,166 Transportation 1,267 2,478 2,830 3,321 General and administrative 2,581 4,492 5,423 8,262 Interest and financing charges 4,218 3,487 7,520 8,003 Unit-based compensation (recovery) (notes 10 and 11) 243 160 (360) 429 Depletion, depreciation and accretion 27,374 33,209 54,629 69,512 Loss on sale of marketable securities (note 4) 501 - 501 - Loss on petroleum and natural gas properties held for sale (note 5) 114,182 - 114,182 - ---------------------------------------------------- 162,282 59,996 210,587 122,693 LOSS BEFORE TAXES (134,716) (32,380) (147,509) (62,373) TAXES Capital taxes - 651 - 1,114 Future income tax recovery (note 13) (34,602) (11,562) (38,303) (23,316) ---------------------------------------------------- (34,602) (10,911) (38,303) (22,202) NET LOSS BEFORE NON-CONTROLLING INTEREST (100,114) (21,469) (109,206) (40,171) Non-controlling interest (399) (95) (435) (176) ---------------------------------------------------- NET LOSS (99,715) (21,374) (108,771) (39,995) Realized loss on available for sale marketable securities 509 - 620 - ---------------------------------------------------- COMPREHENSIVE LOSS $ (99,206) $ (21,374) $ (108,151) $ (39,995) ---------------------------------------------------- Net loss per trust unit Basic $ (1.27) $ (0.27) $ (1.39) $ (0.50) Diluted $ (1.27) $ (0.27) $ (1.39) $ (0.50) ------------------------------------------------------------------------- ------------------------------------------------------------------------- See accompanying selected notes to the consolidated financial statements. TRUE ENERGY TRUST CONSOLIDATED STATEMENTS OF UNITHOLDERS' EQUITY For the three and six months ended June 30 (unaudited) Three months ended Six months ended June 30, June 30, ($000s) 2009 2008 2009 2008 ------------------------------------------------------------------------- UNITHOLDERS' CAPITAL Balance, beginning of period $ 917,012 $ 925,735 $ 917,012 $ 925,573 Repurchased under normal course issuer bid - (1,577) - (1,577) Exchangeable shares converted - - - 162 ---------------------------------------------------- Balance, end of period 917,012 924,158 917,012 924,158 ---------------------------------------------------- EQUITY COMPONENT OF CONVERTIBLE DEBENTURES ---------------------------------------------------- Balance, beginning and end of period 5,119 5,119 5,119 5,119 ---------------------------------------------------- CONTRIBUTED SURPLUS Balance, beginning of period 27,670 19,872 28,240 19,454 Unit-based compensation expense (note 10 and 11) 175 562 390 1,165 Adjustment of prior period unit-based compensation expense for forfeitures of unvested incentive units 98 (257) (687) (442) Adjustment for repurchase of units under normal course Issuer bid - 981 - 981 ---------------------------------------------------- Balance, end of period 27,943 21,158 27,943 21,158 ---------------------------------------------------- DEFICIT Balance, beginning of period (553,916) (515,494) (543,290) (487,366) Net loss (99,715) (21,374) (108,771) (39,995) Distributions declared - (9,505) (1,570) (19,012) ---------------------------------------------------- Balance, end of period (653,631) (546,373) (653,631) (546,373) ---------------------------------------------------- ACCUMULATED OTHER COMPREHENSIVE INCOME Balance, beginning of period (509) - (620) - Realized loss on sale of marketable securities (note 4) 509 - 620 - ---------------------------------------------------- Balance, end of period - - - - ---------------------------------------------------- ------------------------------------------------------------------------- TOTAL UNITHOLDERS' EQUITY $ 296,443 $ 404,062 $ 296,443 $ 404,062 ------------------------------------------------------------------------- See accompanying selected notes to the consolidated financial statements. TRUE ENERGY TRUST CONSOLIDATED STATEMENTS OF CASH FLOWS For the three and six months ended June 30 (unaudited) Three months ended Six months ended June 30, June 30, ($000s) 2009 2008 2009 2008 ------------------------------------------------------------------------- Cash provided by (used in): CASH FLOW FROM OPERATING ACTIVITIES Net loss $ (99,715) $ (21,374) $ (108,771) $ (39,995) Items not involving cash: Non-controlling interest (note 9) (399) (95) (435) (176) Depletion, depreciation and accretion 27,374 33,209 54,629 69,512 Unit-based compensation (recovery) (notes 10 and 11) 243 160 (360) 429 Unrealized loss (gain) on commodity contracts (note 15) 2,704 25,550 (5,140) 43,237 Accretion on convertible debentures 477 416 951 846 Future income tax recovery (note 13) (34,602) (11,562) (38,303) (23,316) Loss on sale of marketable securities (note 4) 501 - 501 - Loss on petroleum and natural gas properties held for sale (note 5) 114,182 - 114,182 - Asset retirement costs incurred (note 8) (313) (123) (1,051) (712) Change in non-cash working capital (note 12) (3,985) (6,289) (425) (12,090) ---------------------------------------------------- 6,467 19,892 15,778 37,735 CASH FLOW FROM (USED IN) FINANCING ACTIVITIES Decrease in bank debt (11,417) (46,392) (12,183) (43,017) Repurchase of trust units under normal course issuer bid - (596) - (596) Distributions declared - (9,505) (1,570) (19,012) ---------------------------------------------------- (11,417) (56,493) (13,753) (62,625) Change in non-cash working capital (note 12) 709 50 (809) (3,110) ---------------------------------------------------- (10,708) (56,443) (14,562) (65,735) CASH FLOW FROM (USED IN) INVESTING ACTIVITIES Additions to property, plant and equipment (1,151) (4,080) (3,907) (12,730) Proceeds on sale of property, plant and equipment 8,289 38,530 8,281 44,318 Proceeds on sale of marketable securities 349 - 349 - ---------------------------------------------------- 7,487 34,450 4,723 31,588 Change in non-cash working capital (note 12) (3,246) 2,101 (5,939) (3,588) ---------------------------------------------------- 4,241 36,551 (1,216) 28,000 Change in cash - - - - Cash, beginning of period - - - - ------------------------------------------------------------------------- Cash, end of period $ - $ - $ - $ - ------------------------------------------------------------------------- ------------------------------------------------------------------------- See accompanying selected notes to the consolidated financial statements. NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited) ------------------------------------------------------------------------- 1. STRUCTURE OF THE TRUST True Energy Trust ("True" or the "Trust") is an open-ended, unincorporated investment trust governed by the laws of the Province of Alberta. The purpose of the Trust is to indirectly explore for, develop and hold interests in petroleum and natural gas properties, through investments in securities of subsidiaries and net profits interests in oil and natural gas properties. The business of the Trust is carried on by True Energy Inc. and its indirect wholly owned subsidiary True Energy Peru S.A.C. The Trust owns, directly and indirectly, 100% of the common shares, (excluding the exchangeable shares - see note 9) of True Energy Inc. and True Energy Peru S.A.C. The activities of True Energy Inc. are financed through interest bearing notes from the Trust and third party debt. 2. SIGNIFICANT ACCOUNTING POLICIES The interim consolidated financial 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, 2008, except as described in note 3. 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 the notes thereto as at and for the year ended December 31, 2008. 3. RECENT ACCOUNTING PRONOUNCEMENTS Effective January 1, 2009, the Trust adopted the following new accounting standard: Goodwill and intangible assets The CICA issued a new accounting standard, Section 3064 - Goodwill and Intangible Assets, which replaces Section 3062 - Goodwill and Other Intangible Assets, and Section 3450 - Research and Development costs. The new section establishes standards for the recognition, measurement and disclosure of goodwill and intangible assets. Application of the new section does not have any impact on the Trust's financial statements. International Financial Reporting Standards ("IFRS") On February 13, 2008 the CICA Accounting Standards Board announced that Canadian public reporting issuers will be required to report under International Financial Reporting Standards ("IFRS"), which will replace Canadian generally accepted accounting principles for years beginning on or after January 1, 2011. Currently, we are assessing the effects of adoption and developing a plan accordingly. We will continue to monitor any changes in the adoption of IFRS and will update plans as necessary. 4. MARKETABLE SECURITIES The Trust's investment in Veraz Petroleum Ltd. was sold in May 2009 for proceeds of $0.3 million and a realized loss on sale of $0.5 million was recognized in the second quarter. 5. PROPERTY, PLANT AND EQUIPMENT ($000s) --------------------------------------------------------------------- Accumulated depletion and Net book June 30, 2009 Cost depreciation value --------------------------------------------------------------------- Petroleum and natural gas properties $ 1,370,748 $ 846,482 $ 524,266 Less: Petroleum and natural gas properties held for sale (434,933) (340,355) (94,578) --------------------------------------------------------------------- 935,815 506,127 429,688 Office furniture and equipment 3,994 2,109 1,885 --------------------------------------------------------------------- $ 939,809 $ 508,236 $ 431,573 --------------------------------------------------------------------- December 31, 2008 --------------------------------------------------------------------- Petroleum and natural gas properties $ 1,375,331 $ 679,196 $ 696,135 Office furniture and equipment 3,955 1,907 2,048 --------------------------------------------------------------------- $ 1,379,286 $ 681,103 $ 698,183 --------------------------------------------------------------------- --------------------------------------------------------------------- The Trust has included $62.5 million (December 31, 2008: $62.8 million) for future development costs and excluded $26.6 million (December 31, 2008: $31.3 million) for undeveloped land and $37.9 million (December 31, 2008: $42.5 million) for estimated salvage from the depletion calculation during the six month period ended June 30, 2009. For the six month period ended June 30, 2009, the Trust capitalized $0.2 million of general and administrative expenses and $0.06 million of unit-based compensation expense directly related to exploration activities. Petroleum and Natural Gas Properties Held for Sale The Trust entered into an agreement for the divestiture of the majority of its petroleum and natural gas properties in Saskatchewan (the "Saskatchewan Divestiture") for gross proceeds of $93 million, subject to closing adjustments, effective May 1, 2009. This disposition closed on July 30, 2009. The disposition meets the criteria under CICA handbook section 3475 - "Disposal of Long-lived Assets and Discontinued Operations" and Accounting Guideline 16 - "Oil and Gas Accounting - Full Cost", and as a result, the Trust has classified the group of assets as assets held for sale. Under full cost accounting, if crediting the proceeds from disposition to costs results in a change of 20 percent or more to the DD&A rate then a gain or loss should be recognized. When a gain or loss is to be recognized the total net book value of capitalized costs should be allocated between the properties sold and the properties retained. The assets held for sale as of June 30, 2009 are an allocation of the Trust's historical full cost pool based on a pro-rata ratio of future cash flows of proved reserves associated with the assets held for sale, discounted at 10%, as compared to all oil and gas assets. The Trust has recorded a $114.2 million loss on the assets held for sale for the excess of the allocated net book value to the these assets, compared to the total estimated net proceeds, after purchase adjustments and closing costs, of $85 million. The associated asset retirement obligation for these properties of $9.6 million has been classified as a current liability. 6. Bank Debt --------------------------------------------------------------------- June 30, December 31, 2009 2008 --------------------------------------------------------------------- ($000s) --------------------------------------------------------------------- Operating facility $ 3,696 $ 7,388 Revolving term facility 116,509 125,000 --------------------------------------------------------------------- Balance, end of period $ 120,205 $ 132,388 Pro-forma bank debt after Saskatchewan Divestiture as of June 30, 2009, was reduced by approximately $86 million of net proceeds, after purchase adjustments. The bank facility outstanding at June 30, 2009 had a borrowing base of $134 million and matures on June 30, 2010. Pursuant to True's existing credit facility, distributions to unitholders (other than by way of the issuance of Trust units) generally require the approval of True's lenders if the funds to pay such distributions are received from True Energy Inc. In conjunction with completion of the Saskatchewan Divestiture on July 30, 2009, True has negotiated a new banking syndicate commitment to replace the existing bank facility, subject to finalization and execution of a mutually acceptable credit agreement, that will provide True with a credit facility of $85 million. The facility will consist of a $10 million demand operating facility provided by one Canadian bank and a $75 million extendible revolving term credit facility syndicated by one Canadian chartered bank and one Canadian financial institution. The revolving period on the new revolving term credit facility will end on June 30, 2010, unless extended for a further 364 day period. Should the facilities not be renewed they will convert to 366 day non-revolving term facilities on the renewal date. The borrowing base will be subject to renewal on March 31, 2010. 7. CONVERTIBLE DEBENTURES The following table shows the convertible debenture activities for the six month period ended June 30, 2009 and the year ended December 31, 2008: --------------------------------------------------------------------- Debt Equity Number of Component Component Debentures ($000s) ($000s) --------------------------------------------------------------------- Balance, December 31, 2007 86,250 $ 79,407 $ 5,119 Accretion - 1,717 - --------------------------------------------------------------------- Balance, December 31, 2008 86,250 $ 81,124 $ 5,119 --------------------------------------------------------------------- Accretion - 951 - --------------------------------------------------------------------- Balance, June 30, 2009 86,250 $ 82,075 $ 5,119 --------------------------------------------------------------------- In November 2008, the Trust received Toronto Stock Exchange approval for its normal course issuer bid program ("NCIB") to repurchase up to 10% of the issued and outstanding 7.50% convertible unsecured subordinated debentures of the Trust from December 1, 2008 to November 30, 2009. As of June 30, 2009 there have been no repurchases of convertible debentures under the NCIB. Commencing April 1, 2009, repurchase of convertible debentures requires the consent of the lenders of the long-term debt. 8. ASSET RETIREMENT OBLIGATIONS The Trust's asset retirement obligations result from net ownership interests in petroleum and natural gas assets including well sites, gathering systems and processing facilities. The Trust estimates the total undiscounted amount of cash flows required to settle its asset retirement obligations is approximately $75.6 million which will be incurred between 2009 and 2053. Approximately $13.4 million of undiscounted cash flows required for the settlement of asset retirement obligations will be disposed of as part of the Saskatchewan Divestiture. A credit-adjusted risk-free rate of 8 percent and an inflation rate of 2.4 percent were used to calculate the fair value of the asset retirement obligation. --------------------------------------------------------------------- June 30, December 31, ($000s) 2009 2008 --------------------------------------------------------------------- Balance, beginning of period $ 33,682 $ 28,373 Liabilities incurred on development activities 30 784 Changes in prior period estimates 995 8,302 Liabilities released on dispositions (1,259) (3,333) Liabilities settled during the period (1,051) (2,603) Accretion expense 1,322 2,159 --------------------------------------------------------------------- Sub-total 33,719 33,682 --------------------------------------------------------------------- Obligations related to petroleum and natural gas assets held for sale (note 5) (9,578) - --------------------------------------------------------------------- Balance, end of period $ 24,141 $ 33,682 --------------------------------------------------------------------- --------------------------------------------------------------------- 9. EXCHANGEABLE SHARES OF SUBSIDIARY/NON-CONTROLLING INTEREST --------------------------------------------------------------------- June 30, 2009 December 31, 2008 Number Amount Number Amount ($000s) ($000s) --------------------------------------------------------------------- Balance, beginning of period 294,026 $ 2,887 390,276 $ 3,922 Non-controlling interest recovery - (435) - (83) Exchanged for trust units - - (96,250) (952) --------------------------------------------------------------------- Balance, end of period 294,026 $ 2,452 294,026 $ 2,887 --------------------------------------------------------------------- --------------------------------------------------------------------- The exchange ratio is calculated monthly based on the five day weighted average trust unit trading price preceding the monthly effective date. The exchangeable shares are not eligible for cash distributions; however cash distributions will increase the exchange ratio. As at June 30, 2009, the exchange ratio was 1.0627 (2008: 1.0218). 10. UNITHOLDERS' CAPITAL a. Trust Units --------------------------------------------------------------------- June 30, 2009 December 31, 2008 Number Amount Number Amount ($000s) ($000s) --------------------------------------------------------------------- Balance, beginning of period 78,496,581 $ 917,012 79,216,046 $ 925,573 Repurchased under normal course issuer bid - - (814,300) (9,513) Exchangeable shares converted - - 94,835 952 --------------------------------------------------------------------- Balance, end of period 78,496,581 $ 917,012 78,496,581 $ 917,012 --------------------------------------------------------------------- In August 2008, the Trust announced approval of the renewal of its normal course issuer bid ("NCIB") program to repurchase up to 7.8 million of its outstanding trust units during the period August 28, 2008 through August 27, 2009, subject to certain restrictions. As of June 30, 2009, the Trust has purchased 615,100 trust units at a weighted average price of $2.74 per trust unit under the NCIB renewed on August 28, 2008. No repurchases have taken place in the six month period ended June 30, 2009. Commencing April 1, 2009, repurchase of trust units requires the consent of the lenders of the long-term debt. b. Trust Unit Incentive Plan The following tables summarize information regarding trust unit incentive rights for the six month period ended June 30, 2009: Unit Rights Continuity --------------------------------------------------------------------- Weighted Average Exercise Price(a) Number --------------------------------------------------------------------- Balance, December 31, 2008 $ 3.97 2,700,500 Granted $ 1.48 2,546,800 Forfeited $ 4.34 (1,012,668) --------------------------------------------------------------------- Balance, June 30, 2009 $ 2.38 4,234,632 --------------------------------------------------------------------- (a) Exercise prices reflect grant prices less reduction in exercise prices. Unit Rights Outstanding, June 30, 2009 ------------------------------------------------------------------------- Outstanding Exercisable Weighted Average Weighted Exercise Average Exercise Exercise Price Remaining Price Price At Net of Contrac- At Net of Net of June 30, Price tual June 30, Price Reductions 2009 Reductions Life 2009 Reductions ------------------------------------------------------------------------- $ 0.65 1,327,881 $ 1.10 4.7 - - - $ 1.50 $ 1.64 2,002,585 $ 2.05 4.3 181,986 $ 2.47 - $ 2.47 $ 2.58 227,000 $ 3.60 3.9 49,832 $ 3.66 - $ 4.29 $ 4.23 652,166 $ 5.03 2.9 424,484 $ 5.05 - $ 5.57 $16.95 25,000 $16.95 1.4 25,000 $16.95 - $16.95 ------------------------------------------------------------------------- ------------------------------------------------------------------------- $ 0.65 4,234,632 $ 2.38 4.2 681,302 $ 4.69 - $16.95 ------------------------------------------------------------------------- ------------------------------------------------------------------------- c. Employee Trust Unit Savings Plan Effective October 1, 2006, the Trust introduced an employee trust unit savings plan for the benefit of all employees. Under the savings plan, employees may elect to contribute up to 10 percent of their salary and contributions are used to fund the acquisition of trust units. The Trust matches employee contributions at a rate of $1.00 for each $1.00 contributed. Trust units are purchased in the open market by the plan administrator, an investment firm, on behalf of the participants in the plan. For the six month period ended June 30, 2009, the Trust matched $0.1 million (2008 - $0.2 million) under the plan. Effective for March 2009, the Trust suspended matching contributions under the plan until further notice. 11. CONTRIBUTED SURPLUS --------------------------------------------------------------------- June 30, December 31, ($000s) 2009 2008 --------------------------------------------------------------------- Balance, beginning of period $ 28,240 $ 19,454 Unit-based compensation expense 390 1,869 Incentive units voluntarily surrendered - 466 Adjustment of prior period unit-based compensation expense for forfeitures of unvested incentive units (687) (526) Adjustment for repurchase of units under NCIB - 6,977 --------------------------------------------------------------------- Balance, end of period $ 27,943 $ 28,240 --------------------------------------------------------------------- --------------------------------------------------------------------- Unit-based Compensation Expense During the six months ended June 30, 2009, the Trust granted 2,546,800 unit incentive rights to employees, directors and officers. Of the 2,546,800 unit incentive rights granted during the period, 2,054,520 unit incentive rights have an exercise price that is higher than the Trust's unit market price on the grant date. The unit incentive rights for which the exercise price is higher than the Trust's unit market price on the grant date have a weighted average fair value of $0.25 per unit and an average exercise price of $1.69. The remaining unit incentive rights have a weighted average fair value of $0.39 per unit. During the six month period ended June 30, 2009, the Trust recorded unit-based compensation of $0.4 million, of which $0.1 million was capitalized to property, plant and equipment. The fair values of all incentive rights granted are estimated on the date of grant using the Black-Scholes option-pricing model. The weighted average fair market value of incentive rights granted during the six month period ended June 30, 2009 and the assumptions used in their determination are as noted below: --------------------------------------------------------------------- 2009 --------------------------------------------------------------------- Assumptions: Risk free interest rate (%) 2 Expected life (years) 5 Expected volatility (%) 69-71 --------------------------------------------------------------------- Results: Weighted average fair value of each incentive right granted $ 0.27 --------------------------------------------------------------------- --------------------------------------------------------------------- 12. SUPPLEMENTAL CASH FLOW INFORMATION Cash Interest and Taxes Paid --------------------------------------------------------------------- Three months ended June 30, Six months ended June 30, ($000s) 2009 2008 2009 2008 --------------------------------------------------------------------- Cash paid: Interest $ 4,280 $ 5,580 $ 5,174 $ 8,085 Taxes (net of refunds) 1 $ 246 $ (273) $ 531 --------------------------------------------------------------------- Change in Non-cash Working Capital --------------------------------------------------------------------- Three months ended June 30, Six months ended June 30, ($000s) 2009 2008 2009 2008 --------------------------------------------------------------------- Changes in non-cash working capital items: Accounts receivable $ 2,787 $ 4,352 $ 5,332 $ (4,822) Deposits and prepaid expenses 1,722 1,446 1,624 1,065 Accounts payable and accrued liabilities (11,031) (9,935) (12,559) (11,862) Distribution payable to unitholders - (1) (1,570) (3,169) --------------------------------------------------------------------- $ (6,522) $ (4,138) $ (7,173) $ (18,788) --------------------------------------------------------------------- Changes related to: Operating activities $ (3,985) $ (6,289) $ (425) $ (12,090) Financing activities 709 50 (809) (3,110) Investing activities (3,246) 2,101 (5,939) (3,588) --------------------------------------------------------------------- --------------------------------------------------------------------- $ (6,522) $ (4,138) $ (7,173) $ (18,788) --------------------------------------------------------------------- --------------------------------------------------------------------- 13. INCOME TAXES The Trust is a mutual fund trust as defined under the Income Tax Act (Canada). All taxable income earned by the Trust has been allocated to unitholders and such allocations are deducted for income tax purposes. In June 2007, the government legislation implementing the new tax (the "SIFT tax") on publicly traded income trust and limited partnerships (Bill C-52) received third reading in the House of Commons and Royal Assent. For existing income trusts and limited partnerships, the SIFT tax will be effective in 2011 unless certain rules related to "undue expansion" are not adhered to. As such, the Trust would not be subject to the new measures until the 2011 taxation year provided the Trust continues to meet certain requirements. As at June 30, 2009, the total "temporary difference" (tax basis exceeds accounting basis) in the Trust is $8.7 million. As at June 30, 2009, the Trust's subsidiaries have a tax basis of approximately $459 million that is available to shelter future taxable income. Included in this tax basis are estimated non-capital loss carry forwards of approximately $30 million that expire in years through 2027. In addition, the Trust itself has approximately $17 million of tax basis. 14. PER TRUST UNIT AMOUNTS --------------------------------------------------------------------- Three months ended June 30, Six months ended June 30, 2009 2008 2009 2008 --------------------------------------------------------------------- Basic trust units outstanding 78,496,581 79,095,460 78,496,581 79,095,460 Dilutive effect of: Trust unit incentive rights outstanding 4,234,632 5,006,079 4,234,632 5,006,079 Units issuable for exchangeable shares 312,467 347,254 312,467 347,254 Units issuable for convertible debentures 5,390,625 5,390,625 5,390,625 5,390,625 --------------------------------------------------------------------- Diluted trust units outstanding 88,434,305 89,839,418 88,434,305 89,839,418 --------------------------------------------------------------------- Weighted average trust units outstanding 78,496,581 79,203,976 78,496,581 79,213,532 Dilutive effect of exchangeable shares, trust unit incentive plan and convertible debentures(1) - - - - --------------------------------------------------------------------- Diluted weighted average trust units outstanding 78,496,581 79,203,976 78,496,581 79,213,532 --------------------------------------------------------------------- (1) A total of 4,234,632 (2008: 5,006,079) trust incentive units, 312,467 (2008: 347,254) exchangeable shares and 5,390,625 (2008: 5,390,625) trust units issuable pursuant to the conversion of convertible debentures were excluded from the calculation for the three and six month period ended June 30, 2009 as they were not dilutive. 15. FINANCIAL RISK MANAGEMENT a. Credit risk As at June 30, 2009, accounts receivable was comprised of the following: --------------------------------------------------------------------- ($000s) --------------------------------------------------------------------- Trade accounts receivable 5,014 Accrued and other accounts receivable 17,773 --------------------------------------------------------------------- 22,787 --------------------------------------------------------------------- The carrying amount of accounts receivable and derivative assets represents the maximum credit exposure. The Trust has an allowance for doubtful accounts as at June 30, 2009 of $0.6 million. As at June 30, 2009 the Trust estimates its trade accounts receivables to be aged as follows: --------------------------------------------------------------------- Aging ($000s) --------------------------------------------------------------------- Not past due (less than 90 days) 1,896 Past due (90 or more days) 3,118 --------------------------------------------------------------------- Total 5,014 --------------------------------------------------------------------- --------------------------------------------------------------------- After considering June 30, 2009 trade accounts payable from the same companies and cash receipts received subsequent to June 30, 2009, the Trust's trade receivables aged 90 or more days of approximately $3.1 million are reduced to a net balance of approximately $1.7 million. Included in accrued and other accounts receivable are approximately $4.7 million of amounts aged 90 or more days. b. Liquidity risk The following are the contractual maturities of financial liabilities as at June 30, 2009: --------------------------------------------------------------------- Financial (less than) liability ($000s) 1 Year 1-2 Years 2-5 Years Thereafter --------------------------------------------------------------------- Accounts payable and accrued liabilities 21,569 - - - Distribution payable to unitholders - - - - Bank debt - principal(1) 120,205 - - - Convertible debentures - principal - - 86,250 - --------------------------------------------------------------------- Total 141,774 - 86,250 - --------------------------------------------------------------------- (1) The current facility is due on June 30, 2010. Refer to note 6 for further details. The Trust's convertible debentures outstanding at June 30, 2009 bear interest at a coupon rate of 7.5%, which currently requires total annual interest payments of $6.5 million. Interest due on the bank credit facility is calculated based upon floating rates. c. Commodity price risk Commodity price risk is the risk that the fair value or future cash flows will fluctuate as a result of changes in commodity prices. Commodity prices for petroleum and natural gas are impacted by not only the relationship between the Canadian and United States dollar, as outlined above, but also world economic events that dictate the levels of supply and demand. The Trust utilizes both financial derivatives and physical delivery sales contracts to manage commodity price risks. All such transactions are conducted in accordance with the risk management policy that has been approved by the Board of Directors. The Trust's formal risk management policy permits management to use specified price risk management strategies including fixed price contracts, costless collars and the purchase of floor price options, other derivative financial instruments, and physical delivery sales contracts to reduce the impact of price volatility and ensure minimum prices for a maximum of eighteen months beyond the current date. The program is designed to provide price protection on a portion of the Trust's future production in the event of adverse commodity price movement, while retaining significant exposure to upside price movements. By doing this, the Trust seeks to provide a measure of stability to funds flows from operations, as well as, to ensure True realizes positive economic returns from its capital developments and acquisition activities. As at June 30, 2009, the Trust had entered into commodity price risk management arrangements as follows: ------------------------------------------------------------------------- Price Price Type Period Volume Floor Ceiling Index ------------------------------------------------------------------------- Natural Gas March 1, 2009 to 4,500 GJ/day $ 5.00 CDN $ 5.00 CDN AECO fixed Sept. 30, 2009 Natural Gas March 1, 2009 to 5,000 GJ/day $ 5.90 CDN $ 5.90 CDN AECO fixed Dec. 31, 2009 Natural Gas July 1, 2009 to 5,000 GJ/day $ 5.41 CDN $ 5.41 CDN AECO fixed Sept. 30, 2009 Natural Gas July 1, 2009 to 5,000 GJ/day $ 7.49 CDN $ 7.49 CDN AECO fixed Sept. 30, 2009 Natural Gas Oct. 1, 2009 to 5,000 GJ/day $ 8.09 CDN $ 8.09 CDN AECO fixed Dec. 31, 2009 Natural Gas Oct. 1, 2009 to 5,000 GJ/day $ 6.26 CDN $ 6.26 CDN AECO fixed Dec. 31, 2009 Natural Gas Jan. 1, 2010 to 5,000 GJ/day $ 7.16 CDN $ 7.16 CDN AECO fixed March 31, 2010 Natural Gas Jan. 1, 2010 to 5,000 GJ/day $ 8.00 CDN $ 8.00 CDN AECO fixed March 31, 2010 Natural Gas Jan. 1, 2010 to 5,000 GJ/day - $ 8.05 CDN AECO call option Dec. 31, 2010 Natural Gas April 1, 2010 to 5,000 GJ/day $ 6.59 CDN $ 6.59 CDN AECO fixed June 30, 2010 Oil collar March 1, 2009 to 500 bbl/d $52.30 CDN $80.70 CDN WTI Dec. 31, 2009 ------------------------------------------------------------------------- For the three and six months ended June 30, 2009 and 2008, the gain (loss) on commodity contracts was comprised of the following: --------------------------------------------------------------------- Three months ended June 30, Six months ended June 30, ($000s) 2009 2008 2009 2008 --------------------------------------------------------------------- Gain (loss) on commodity contracts Realized(1) $ 5,789 $ (12,619) $ 8,420 $ (16,761) Unrealized(2) (2,704) (25,550) 5,140 (43,237) --------------------------------------------------------------------- $ 3,085 $ (38,169) $ 13,560 $ (59,998) --------------------------------------------------------------------- (1) Realized gains and losses on commodity contracts represent actual cash settlements and other amounts paid under these contracts. (2) Unrealized gains and losses on commodity contracts represent non- cash adjustments for changes in the fair value of these contracts during the period. The Trust has entered into a natural gas physical delivery sales contract to sell 5,275 GJ/day at a fixed price of $7.29/GJ and $7.90/GJ for the third and fourth quarter of 2009, respectively. d. Interest rate risk The Trust had no interest rate swap or financial contracts in place during the three and six months period ended June 30, 2009. e. Capital management The Trust's policy is to maintain a strong capital base so as to maintain investor, creditor and market confidence and to sustain the future development of the business. The Trust manages its capital structure and makes adjustments to it in the light of changes in economic conditions and the risk characteristics of the underlying petroleum and natural gas assets. The Trust considers its capital structure to include unitholders' equity, bank debt, convertible debentures and working capital. In order to maintain or adjust the capital structure, the Trust may from time to time issue trust units, adjust its capital spending, and/or dispose of certain assets to manage current and projected debt levels. The Trust monitors capital based on the ratio of total net debt to annualized funds flow (the "ratio"). This ratio is calculated as total net debt, defined as outstanding bank debt, plus the liability component of convertible debentures, plus or minus working capital (excluding commodity contract assets and liabilities, current portion of long-term debt and future income tax assets or liabilities), divided by funds flow from operations (cash flow from operating activities before changes in non-cash working capital and deductions for asset retirement costs) for the most recent calendar quarter, annualized (multiplied by four). The total net debt to annualized funds flow ratio may increase at certain times as a result of acquisitions, fluctuations in commodity prices, timing of capital expenditures and other factors. In order to facilitate the management of this ratio, the Trust prepares annual capital expenditure budgets and sets unitholder distributions on a monthly basis. Capital expenditure budgets and levels of monthly unitholder distributions are reviewed and updated as necessary depending on varying factors including current and forecast prices, successful capital deployment and general industry conditions. The annual and updated budgets and monthly unitholder distributions are approved by the Board of Directors. Given the continuing uncertain economic conditions, the Trust has suspended unit distributions in order to maintain financial flexibility. The Trust plans to continue to monitor forecasted debt levels to manage its operations within forecasted funds flow. The Trust expects the total net debt to annualized funds flow ratio to reflect the economic burdens experienced as a result of the recent downturn in the global economic environment. The Trust will continue to monitor developments within the global economic environment to consider the impacts on the current or future lending arrangements. The Trust's long-term strategy, under a more stable economic environment, is to target a total net debt to annualized funds flow ratio of 2.0 times. As at June 30, 2009, the Trust's ratio of total net debt to annualized funds flow based on second quarter results was 4.6 times. The total net debt to annualized funds flow ratio as at June 30, 2009 decreased from that at December 31, 2008 of 9.2 times due to higher funds flow from operations in the second quarter in addition to lower total net debt. The Trust expects this ratio to decrease in the third quarter of 2009 as total net debt levels are reduced by the estimated net proceeds of $85 million from the closing of the Saskatchewan Divestiture on July 30, 2009; True continues to take a balanced approach to the priority use of funds flows. The Debentures have a maturity date of June 30, 2011. Upon maturity, the Trust may settle the principal in cash or issuance of additional Trust units. Excluding Debentures, net debt to annualized funds flow based on second quarter results was 2.7 times. The calculation of total net debt and total net debt to cash flow is as follows: --------------------------------------------------------------------- Three months ended Six months ended ($000s, except June 30, June 30, where noted) 2009 2008 2009 2008 --------------------------------------------------------------------- Long-term debt 120,205 125,458 120,205 125,458 Convertible debentures (liability component) 82,075 80,253 82,075 80,253 Working capital excess (5,563) (16,357) (5,563) (16,357) --------------------------------------------------------------------- Total net debt(1) at year end 196,717 189,354 196,717 189,354 Debt to funds flow from operations ratio (annualized)(2) Funds flow from operations (annualized) 43,060 105,216 34,508 105,216 Total net debt(1) to periods funds flow from operations ratio (annualized) 4.6x 1.8x 5.7x 1.8x Net debt(1) excluding convertible debentures) at quarter end 114,642 109,101 114,642 109,101 Net debt to periods funds flow from operations ratio (annualized) 2.7x 1.1x 3.3x 1.1x Debt to funds flow from operations ratio (trailing)(3) Total net debt to periods funds flow from operations ratio (trailing) 3.2x 2.2x 3.2x 2.2x Net debt to periods funds flow from operations ratio (trailing) 1.8x 2.0x 1.8x 2.0x --------------------------------------------------------------------- (1) Net debt includes the net working capital deficiency (excess) before short-term commodity contract assets and liabilities, current portion of long-term debt and short-term future income tax assets and liabilities. Total net debt also includes the liability component of convertible debentures and excludes asset retirement obligations and the future income tax liability. (2) Debt to funds flow from operations ratio (annualized) is calculated based upon second quarter funds flow from operations annualized. (3) Trailing periods funds flow from operations is based on the trailing twelve-months period ended June 30, 2009 and 2008. The Trust's credit facility is based on petroleum and natural gas reserves (see note 6). The credit facility outlines limitations on percentages of forecasted production, from external reserve engineer data, which may be hedged through financial commodity risk management contracts and limitations on property dispositions without prior consent of the lenders. The Trust also has outstanding normal course issuer bids for its convertible debentures and trust units, as detailed in note 7 and 10, respectively. f. Fair value of financial instruments The Trust's financial instruments as at June 30, 2009 include accounts receivable, deposits, marketable securities, commodity contract liability, accounts payable and accrued liabilities, distributions payable, long-term debt and convertible debentures. The fair value of accounts receivable, accounts payable and accrued liabilities and distributions payable approximate their carrying amounts due to their short-terms to maturity. The fair value of commodity contracts is determined by discounting the difference between the contracted price and published forward price curves as at the balance sheet date, using the remaining contracted petroleum and natural gas volumes. Long-term bank debt bears interest at a floating market rate and accordingly the fair market value approximates the carrying value. The fair value of the convertible debentures of $65.1 million is based on exchange traded values.True Energy Trust is a Calgary-based oil and natural gas trust. True is an open-ended, incorporated investment trust governed by the laws of the Province of Alberta. The purpose of the Trust is to indirectly explore for, develop and hold interests in petroleum and natural gas properties, through investments in securities of subsidiaries and net profits interests. The trust structure allows individual unitholders to participate in the cash flow of the business. Cash flow is realized from the Trust's subsidiaries' ownership of natural gas and petroleum properties and related facilities. Trust units and convertible debentures of True trade on the Toronto Stock Exchange ("TSX") under the symbols TUI.UN and TUI.DB, respectively.