CNE China Everbright Environment Group Limited

We pay royalties to the owners of the mineral rights with whom we hold leases, including provincial governments. Overriding royalties are also paid to other parties according to contracts. In Alberta, where we produce the majority of our natural gas, a Crown royalty is invoiced on the Crown's share of production based on a monthly established Alberta Reference Price. The Alberta Reference Price is a monthly weighted average price of gas consumed in Alberta and natural gas exported from Alberta reduced for transportation and marketing allowances. For 2006, the Alberta Reference Price averaged $6.22/Gj or about $6.56/mcf. There is a maximum rate of 30 percent for new gas and 35 percent on old gas. The vast majority of our gas production is from new natural gas. In the 2006 gas price environment, we were subject to the maximum rates. Natural gas cost allowance, low productivity and other incentive schemes serve to reduce our effective royalty rate. The majority of our oil production is in Alberta and Saskatchewan. Royalty rates in both Alberta and Saskatchewan vary depending on the rate of production, oil prices and applicable incentives. For the year ended December 31, 2006, royalties totalled $258.3 million as compared to $175.7 million during the same period a year earlier. As a percentage of sales, royalties averaged 18.3 percent during 2006 as compared to 22 percent in the same period in 2005. For 2006, royalties averaged $9.51/boe or approximately 18.3 percent of Canetic's total petroleum and natural gas sales price (before hedging) of $51.83/boe. This compares to $11.90/boe or 22.0 percent of average sales price reported for the same period in 2005 (2004 - $8.50/boe). The reduced effective royalty rate results from the acquisition of properties that carry a lower royalty burden. For the three months ended December 31, 2006, royalties totalled $63.6 million as compared to $52.3 million during the same period a year earlier due to higher production volumes. During the fourth quarter, royalties as a percentage of sales averaged approximately 18.3 percent as compared to 16.9 percent in the third quarter. OPERATING COSTS Operating Costs ($000s) 2006 2005 2004 ------------------------------------------------------------------------- Operating costs before unit-based compensation 249,623 125,448 98,001 Unit-based compensation: Cash expense 412 124 251 Accrued compensation 2,107 4,074 1,102 ------------------------------------------------------------------------- Total operating costs and unit-based compensation 252,142 129,646 99,354 ------------------------------------------------------------------------- ------------------------------------------------------------------------- $/boe before unit-based compensation $ 9.19 $ 8.49 $ 8.01 $/boe after unit-based compensation $ 9.28 $ 8.78 $ 8.12 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Producing petroleum and natural gas involves many field activities including lifting the oil and natural gas to surface, as well as treating, processing, gathering and storing the commodities. Other costs involved in the production function include those incurred to operate and maintain the wells along with the leases and well equipment. Assets most suitable for the trust environment are generally more mature with more predictable production profiles. Operating costs associated with these types of assets will generally be higher on a unit-of-production basis reflecting the amount of manpower, repairs and maintenance required to keep the wells on production and the recovery techniques utilized to extract the reserves. Our operating costs net of processing fees and unit-based compensation, increased to $249.6 million compared to $125.4 million during the same period a year earlier (2004 - $98.0 million). On a unit-of-production basis, operating costs averaged $9.19/boe compared to $8.49/boe for the prior year (2004 - $8.01/boe). A general theme throughout the industry in 2005 and 2006 has been higher field service costs including higher energy and fuel costs, labour, trucking and other related mechanical services. These increases, combined with the operating cost structures inherited from acquisitions made, caused operating costs year-over-year to increase on a unit-of-production basis. In addition, certain assets within our portfolio, primarily in east central Alberta, are significantly more costly to operate. Although these assets increase our operating costs in total and on a per unit basis, they provide positive cash flow during a high commodity price cycle. Production Expense Variance Analysis ($000s) % Change ------------------------------------------------------------------------- Reported operating costs - 2005 125,448 ------------------------------------------------------------------------- Increase due to production volumes 105,260 85 Increase due to increased costs 18,915 15 ------------------------------------------------------------------------- Total increase 124,175 100 ------------------------------------------------------------------------- Reported operating costs - 2006 249,623 ------------------------------------------------------------------------- ------------------------------------------------------------------------- During the fourth quarter, operating costs before unit-based compensation totalled $71.4 million or $9.67 per boe as compared to $32.9 million or $9.05 per boe in 2005. Our estimate of $8.50 - $9.50/boe operating costs for the fourth quarter was impacted by a plant turnaround at Acheson in October and cold weather and associated repairs and maintenance in November required to restore production. The increase also reflects cost pressures due to industry activity. Canetic was also active in 2006 in completing operational activities associated with the EUB's guidelines for the suspension of existing wells, resulting in incremental costs incurred throughout the year. Although operating costs year-over-year increased on a unit-of-production basis, we are committed to managing operational efficiencies and maximizing field netbacks in all areas where we do business. As we continue to experience higher field costs throughout our asset base, considerable effort and focus is being given to operational efficiencies which will control operating costs on a unit-of-production basis. To date, Canetic has been successful in maintaining control of our operational costs in a high priced operating environment and will continue to focus on doing so in 2007. PETROLEUM AND NATURAL GAS TRANSPORTATION Transportation ($000s) 2006 2005 2004 ------------------------------------------------------------------------- Transportation expense 18,968 9,897 8,807 $/boe $ 0.70 $ 0.67 $ 0.72 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Transportation costs are defined by the point of legal custody transfer of the commodity and are dependent upon the type of product being sold, location of the producing asset, availability of pipeline capacity and sales point of the product. For crude oil, Canetic sells all of its production at the lease. The purchaser picks up the production at the lease and pays Canetic a price for the applicable crude type based upon a price posted at the appropriate market hub, less the transportation costs between that market hub and the lease. For natural gas, Canetic transports its natural gas from the plant gate to certain established market hubs such as AECO C in Alberta, at which point title transfers to the purchaser. In both cases, transportation costs associated with getting natural gas and clean marketable oil to the point of title transfer are shown separately as a transportation expense. NETBACKS Operating netbacks represent the profit margin associated with the production and sale of petroleum and natural gas. For 2006, our netbacks were influenced by our product mix, commodity prices, financial derivative losses, royalty rates, the appreciation in the Canadian dollar and higher operating costs. ------------------------------------------------------------------------- Cash Netbacks Per Unit Natural Of Production Oil Gas NGL's Total ------------------------------------------------------------------------- Conven- tional Heavy ($/bbl) ($/bbl) ($/mcf) ($/bbl) ($/boe) ------------------------------------------------------------------------- Sales Price 63.39 43.57 7.01 47.84 51.83 Less: Royalties 10.58 6.54 1.42 11.77 9.51 Operating costs 10.80 12.97 1.44 - 9.19 Transportation 0.24 0.23 0.22 0.25 0.70 ------------------------------------------------------------------------- Cash Netbacks Per Unit Of Production 41.77 23.83 3.93 35.82 32.43 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Components of our netbacks are as follows: Netbacks ($/boe) 2006 2005 2004 ------------------------------------------------------------------------- Petroleum and natural gas revenue 51.83 54.19 42.63 Less: Royalties 9.51 11.90 8.50 Operating costs 9.19 8.49 8.01 Transportation 0.70 0.67 0.72 ------------------------------------------------------------------------- Cash net operating income 32.43 33.13 25.40 General and administrative 1.46 1.46 1.39 Interest on long term debt 1.98 0.93 0.98 Interest on convertible debentures 0.32 0.30 0.37 Realized loss on financial derivatives 0.31 5.43 3.21 Capital tax 0.64 0.54 0.21 ------------------------------------------------------------------------- Cash netback from operations 27.72 24.47 19.24 Non-cash unit-based compensation 0.62 1.90 0.74 Depletion, depreciation and amortization 23.76 15.82 14.68 Accretion 0.42 0.31 0.25 Unrealized (gain) loss on financial derivatives (3.51) 1.40 0.91 Future income taxes (recovery) (1.78) 0.58 0.10 ------------------------------------------------------------------------- Net earnings 8.21 4.46 2.56 ------------------------------------------------------------------------- ------------------------------------------------------------------------- GENERAL AND ADMINISTRATIVE EXPENSES General and Administrative Expenses ($000s) 2006 2005 2004 ------------------------------------------------------------------------- G&A expenses 60,631 31,885 21,356 Overhead recoveries (20,925) (10,299) (4,343) ------------------------------------------------------------------------- Cash G&A expenses before unit-based compensation 39,706 21,586 17,013 Unit-based compensation: Cash expense 2,336 695 1,421 Accrued compensation 11,941 23,091 6,242 ------------------------------------------------------------------------- Total G&A and unit-based compensation 53,983 45,372 24,676 ------------------------------------------------------------------------- ------------------------------------------------------------------------- $/boe before unit-based compensation $ 1.46 $ 1.46 $ 1.39 $/boe after unit-based compensation $ 1.99 $ 3.07 $ 2.02 ------------------------------------------------------------------------- ------------------------------------------------------------------------- General and administrative expenses net of overhead recoveries and unit-based compensation totalled $39.7 million in 2006, as compared to $21.6 million in 2005 (2004 - $17.0 million). On a unit-of-production basis, general and administrative expenses averaged $1.46/boe as compared to $1.46/boe for the same period in 2005 (2004 - $1.39/boe). During 2006, we increased our head office staff in order to properly manage our business. The level of activity in the trust sector increased the cost of hiring qualified candidates and retaining existing employees and consultants. In 2006, approximately 66 percent of our total general and administrative expenses were labour related, including salary, benefits and consulting fees. For the three months ended December 31, 2006, general and administrative expenses increased slightly to $1.62 per boe (net of unit-based compensation), reflecting costs associated with hiring additional permanent staff, leasing additional office space and integrating the assets acquired during the third quarter. Unit-based Compensation On December 19, 2005, the unitholders of Canetic approved a unit award incentive plan. The plan authorizes the Board of Directors to grant rights to acquire up to five percent of the trust units outstanding to directors, officers, employees and consultants of the Trust and its affiliates. These rights consist of Restricted Trust Units ("RTU's") and Performance Trust Units ("PTU's"). The number of PTU's granted is dependent on the performance of the Trust relative to a peer comparison group of petroleum and natural gas trusts and other companies or other criteria the Board of Directors may determine. A holder of an RTU or PTU may elect, subject to consent of the Trust, to receive cash upon vesting in lieu of the number of units to be issued. The plan provides for adjustments to the number of units issued based on the cumulative distributions of the Trust during the period that the RTU or PTU is outstanding. The compensation issued upon vesting of the PTU's is dependant upon the performance of the Trust compared to its peers. The performance multiplier is based on our percentile rank of total unitholder return compared to a select group of peers approved by the Board of Directors. Total return is calculated as the sum of the change in market price plus distributions in the period divided by the opening market price. The performance multiplier ranges from zero, where our total return is less than the 35th percentile, to two, if our performance exceeds the 75th percentile. For the year ended December 31, 2006, the Trust recorded a compensation expense of $16.8 million (2005 - $28.0 million) and capitalized unit-based compensation of $3.4 million (2005 - $11.0 million). Upon vesting, the obligation may be settled in units or cash, therefore, the amounts due in the next year of $7.3 million (2005 - $40.8 million) has been classified as a current liability. The compensation liability is remeasured each period at the current market price. The December 31, 2006 compensation liability was based on the period-end closing price of $16.44 and the number of RTU's and PTU's outstanding at that time and the number of PTU's expected to vest using a PTU multiplier of 0.6. As of December 31, 2006, there were 915,916 RTU's and 1,386,377 PTU's outstanding. INTEREST EXPENSE ON LONG-TERM DEBT Interest Expense ($000s) 2006 2005 2004 ------------------------------------------------------------------------- Interest expense 53,809 13,752 12,054 Bank loans, December 31 1,289,678 309,146 283,845 Debt to funds flow 1.7 0.9 1.2 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Interest expense, representing interest on bank debt increased to $53.8 million or $1.98 per boe from $13.8 million or $0.93 per boe a year earlier (2004 - $12.1 million or $0.98/boe). In addition to slightly higher interest rates due to increases in the Bank of Canada lending rate in 2006, average debt levels have increased as a result of the corporate and property acquisitions made during the year. At December 31, 2006, $1.29 billion was drawn under our facility. Although interest rates continue to be favourable and are not expected to increase substantially in the short-term, interest expense in future periods will reflect our higher debt levels. Average interest rates incurred by Canetic during 2006 averaged approximately 5.1 percent. INTEREST EXPENSE ON CONVERTIBLE DEBENTURES Interest expense on convertible debentures totalled $8.6 million for the year ended December 31, 2006 as compared to $4.4 million for the same period in 2005. During the year, debentures totaling $230.0 million were issued in conjunction with the Samson acquisition. At December 31, 2006, debentures totaling $263.2 million remain outstanding. For the three months ended December 31, 2006, interest expense increased to $19.6 million reflecting the increased debt levels incurred to finance the Samson acquisition. INTEREST RATE RISK MANAGEMENT Canetic has assumed through the StarPoint arrangement, fixed interest rate swaps between January 6, 2006 and September 30, 2007 covering $40.0 million of principal, with interest rates varying between 3.58 percent and 3.65 percent, plus a stamping fee. The fair value of the fixed interest swaps at December 31, 2006 was a gain of approximately $0.3 million. DEPLETION, DEPRECIATION AND AMORTIZATION The current year provision for depletion, depreciation and amortization totalled $645.2 million as compared to $233.7 million in 2005 (2004 - $179.6 million). On a unit-of-production basis, depletion, depreciation and amortization costs averaged $23.76 per boe as compared to $15.82 per boe in 2005 (2004 - $14.68/boe). The increase in the 2006 depletion rate results from the assets acquired in 2006. UNREALIZED LOSS ON FINANCIAL DERIVATIVES Accounting standards require that we determine the fair value of our financial contracts and record a liability or asset at the end of each accounting period. Any changes in the fair value of the financial contracts are included in net earnings for the period. At December 31, 2006, we recorded a current financial derivative liability of $1.1 million and a long-term financial derivative asset of $6.2 million. The estimated fair value is based on a mark-to-market calculation as at December 31, 2006 to settle the financial contracts. The actual gain or loss realized upon settlement could vary significantly due to fluctuations in commodity prices. At December 31, 2006, Canetic recorded an unrealized financial derivative gain of $95.4 million (2005-loss of $20.6 million) which represents the change in the mark-to-market calculations from December 31, 2005. Gain (Loss) On Financial Derivatives ($000s) 2006 2005 ------------------------------------------------------------------------- Realized cash loss on financial derivatives (8,465) (80,157) Unrealized gain (loss) on financial derivatives 95,371 (20,635) ------------------------------------------------------------------------- Gain (loss) on financial derivatives 86,906 (100,792) ------------------------------------------------------------------------- ------------------------------------------------------------------------- ASSET RETIREMENT OBLIGATIONS The total future asset retirement obligation was estimated by management based on the Trust's net ownership interest in all wells and facilities, estimated costs to reclaim and abandon the facilities and the estimated timing of the costs to be incurred in future periods. The costs are expected to be incurred over an average of 15 years. The estimated cash flow has been calculated using a credit adjusted risk free discount rate of 8 percent and an inflation rate of 2 percent. As of December 31, 2006, the amount to be recorded as the fair value of the liability was estimated to be $191.9 million (December 31, 2005 - $68.2 million). During this year, Canetic incurred $16.9 million (2005 - $6.3 million) of actual abandonment and reclamation costs and recorded accretion of $11.4 million (2005 - $4.6 million). INCOME TAXES Future Income Taxes Future income taxes arise from differences between the accounting and tax bases of assets and liabilities of certain operating subsidiaries of the Trust. The future taxes recorded on the balance sheet are expected to be recovered over time through interest and/or royalty payments to the Trust from its operating subsidiaries. The Trust is a taxable entity under Canadian tax law and is subject to cash taxes only to the extent that income is not distributed or distributable to its unitholders. As the Trust is required to distribute all of its taxable income to unitholders, the Trust is not expected to be subject to current or future income taxes. For the period ended December 31, 2006, a future tax recovery of $48.3 million was included in income compared to a future tax expense of $8.6 million in 2005. The change year-over-year was mainly due to a significant increase in temporary differences arising from the acquisition of StarPoint Energy Trust, increased depletion on recognition of purchase price increments. Also, reductions to future corporate tax rates were enacted during the year by Federal, Alberta and Saskatchewan governments resulting in a future tax recovery of $32 million. These were offset by a future tax expense of $33.6 million related to unrealized hedging gains. On October 31, 2006, the Federal Government announced a proposal to introduce a new tax on publicly traded income trusts beginning in 2011. On December 21, 2006, draft legislation to implement these proposals was released for comment. If the legislation becomes enacted as currently proposed, the Trust will effectively become subject to tax on earnings in excess of available tax pools, in a similar manner as a corporation. It is anticipated that future taxes would be then be adjusted to include temporary differences between accounting and tax bases of assets and liabilities at the Trust level. Current Income Taxes In general, both current and future income taxes are transferred to the unitholder level through various interest and/or royalty payments. There are some corporate entities in the underlying structure which hold minority interests in some of the Trust's operating partnerships which subject them to a small amount of current income tax. The Trust has provided $2 million in this respect for the current year and $4 million in respect of prior periods. Capital Taxes Federal Large Corporations Tax was eliminated effective January 1, 2006 and thus no amount is provided for federal capital taxes in respect of 2006. The Trust has recorded $12 million of capital tax for the year, of this amount, $11 million relates to the Saskatchewan Resource Surcharge and is higher compared to the previous year due to an increase in oil and gas revenue earned in the Province of Saskatchewan, a result of the significant number of Saskatchewan properties added through the StarPoint acquisition. Estimated Income Tax Pools ($000s) December 31, 2006 ------------------------------------------------------------------------- Undepreciated capital costs 505,232 Canadian oil and gas property expenses 611,509 Canadian exploration expenses 2,966 Canadian development expenses 285,662 Non-capital losses 276,270 Financing charges 48 ------------------------------------------------------------------------- Total estimated income tax pools 1,681,687 ------------------------------------------------------------------------- ------------------------------------------------------------------------- CAPITAL EXPENDITURES Petroleum and natural gas reserves are a non-renewable resource. As they are produced, our objective is to replace those reserves through a combination of property acquisitions and internal drilling opportunities. In 2005 and 2006, we have continued to increase our focus on upgrading the quality of our asset base through acquisition, exploiting our reserve base, drilling new wells and optimizing existing production. Capital Expenditures ($000s) 2006 2005 2004 ------------------------------------------------------------------------- Land 14,868 13,361 3,792 Geological and geophysical 2,783 3,139 1,067 Drilling and completion 215,593 100,182 56,493 Production equipment and facilities 118,044 55,539 30,418 ------------------------------------------------------------------------- Net development expenditures 351,288 172,221 91,770 Major acquisitions StarPoint 2,511,746 - - Samson 924,635 - - Producing properties 23,869 - 477,168 Minor property acquisitions 32,416 13,554 10,447 Minor property dispositions (17,167) (4,610) (9,280) ------------------------------------------------------------------------- Net capital expenditures 3,826,787 181,165 570,105 Office 8,134 4,667 3,609 Asset retirement obligation - change in estimate 56,537 11,319 13,043 Asset retirement obligation - Samson 18,228 - - Capitalized non-cash compensation 3,365 11,016 - Other non-cash 11,000 - - ------------------------------------------------------------------------- Total capital expenditures 3,924,051 208,167 586,757 ------------------------------------------------------------------------- ------------------------------------------------------------------------- During 2006, expenditures for exploration and development activities totalled $351.3 million as compared to $172.2 million in 2005 (2004 - $91.8 million). A total of 378 gross (174.4 net) wells were drilled during the year, including 115 gross (48.8 net) wells in the fourth quarter, compared to 82 gross (52.4 net) wells during the fourth quarter 2005 resulting in 161 gross (81.9 net) oil wells and 205 gross (85.4 net) natural gas wells. The increase reflects the larger opportunity associated with our assets as a result of the acquisitions made in 2006. Of the total wells drilled in 2006, 102 gross (90.6 net) were operated by Canetic resulting in 64 gross (58.0 net) oil wells and 32 gross (26.9 net) natural gas wells. The Trust also completed two major acquisitions in 2006 totalling $3.5 billion. The StarPoint transaction was completed by way of a Plan of Arrangement whereby unitholders of Acclaim received 0.8333 units of Canetic for each unit held and unitholders of StarPoint received one Canetic unit for each unit held. Costs associated with the transaction were financed through our bank facility. The merger was strategic in that it provided unitholders with a high quality asset base; a reserve base in excess of 230 million boe on a proved plus probable basis; a reserve life index in excess of 9 years; a diversified production base weighted 60 percent towards primarily light oil and a high quality low risk development drilling program. On August 31, 2006, we closed the Samson acquisition which included properties in British Columbia and central Alberta. We acquired approximately 13,500 boe/d of production, 40.1 million boe of proved plus probable reserves and 230,000 net acres of undeveloped land. The acquisition was financed by the issuance of 20.8 million trust units for net proceeds of $437 million, as well as $230.0 million principal ($220.8 million net) of 6.5% convertible, extendible, unsecured, subordinated debentures. The balance of the transaction was financed with bank debt. In addition, we also acquired approximately $87 million of working capital including $77 million of cash which was financed with long-term debt. Sources Of Funding Net Capital Expenditures Acquisitions Net -------------------------------- Development StarPoint Samson Other Total ------------------------------------------------------------------------- ($million) Net Capital Expenditures $ 351.3 $ 2,511.7 $ 924.6 $ 39.2 $ 3,826.8 ------------------------------------------------------------------------- Percentage funded by: Cashflow 47% - - - 5% DRIP 14% - - - 1% Issuance of equity - 99% 47% - 77% Issuance of debentures - - 24% - 6% Bank debt 39% 1% 29% 100% 11% ------------------------------------------------------------------------- 100% 100% 100% 100% 100% ------------------------------------------------------------------------- ------------------------------------------------------------------------- GOODWILL The Trust recognizes goodwill on corporate acquisitions when the total purchase price exceeds the fair value of the net identifiable assets and liabilities of the acquired entity. Goodwill is tested annually at year-end for impairment or as events occur that could result in impairment. Impairment is recognized and charged to income in the period in which the impairment occurs when the fair value of the Trust is less than the book value of the Trust. A write down of goodwill was not required at December 31, 2006 or 2005. The goodwill balance of $943.8 million arose primarily as a result of the StarPoint acquisition in 2006. The balance was determined based on the excess of total consideration plus the future income tax liability less the fair value of the assets acquired for accounting purposes. LIQUIDITY AND CAPITAL RESOURCES As an oil and gas trust we have a declining asset base and therefore rely on acquisitions and ongoing development activities to mitigate production and reserve declines. Future production volumes and reserves are highly dependent on our success in exploiting our asset base and acquiring addition reserves. The increase in capital expenditures in 2006 reflects both the costs associated with maintaining the larger producing asset base we now have, as well as the execution of growth programs that continue to be developed as we increase our operational knowledge of the properties acquired over the past three years. We finance our operations and capital activities primarily with funds generated from operating activities, but also through the issuance of trust units, debentures and borrowings from our credit facility. The amount of equity we raise through the issuance of trust units depends on many factors including projected cash needs, availability of funding through other sources, our unit price and the state of the capital markets. We believe our sources of cash, including bank debt, will be sufficient to fund our operations and anticipated capital expenditure program in 2007 as well as make monthly distribution payments. Our ability to fund will also depend on performance and is subject to commodity prices and other economic conditions which are beyond our control. In August 2006, in connection with the Samson acquisition, Canetic completed a $690 million bought deal equity and debenture issue. The net proceeds of $657.8 million in addition to bank borrowings under our credit facility were utilized to fund the acquisition. In addition, Canetic purchased working capital at May 31, 2006, of $89.1 million by drawing upon its bank facility. Working capital included approximately $77 million of cash. Under the terms of the agreement Canetic will be kept whole in the event of uncollectability or valuation of working capital. Canetic's capital structure at December 31, 2006 is reconciled as follows: 2006 2005 ($000s except per unit amounts) Amount % $/unit Amount % $/unit ------------------------------------------------------------------------- Debt Bank debt 1,289,678 25 5.71 309,146 27 3.38 Working capital deficiency 29,794 1 0.13 74,466 6 0.81 ------------------------------------------------------------------------- Net debt 1,319,472 26 5.84 383,612 33 4.19 Convertible debentures 258,959 5 1.15 16,289 1 0.18 Unitholders' equity 3,506,915 69 15.53 764,583 66 8.35 ------------------------------------------------------------------------- Total capitalization 5,085,346 100 22.52 1,164,484 100 12.72 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Bank Debt Canetic has an unsecured covenant based credit facility with a syndicate of financial institutions in the amount of $1.6 billion including a $50.0 million operating facility. The facility carries floating interest rates which range between 65.0 and 115.0 basis points over Banker's Acceptance rates. This facility was increased in the third quarter from $1.1 billion upon closing of the Samson acquisition. The loan has a maturity date of May 31, 2009 and is reviewed annually and may be extended at the option of the lender for an additional 1 year period. The loan has therefore been classified as long-term on the balance sheet. At December 31, 2006, $1.29 billion was drawn under the facility. Working capital liquidity is maintained by drawing from and repaying the unutilized credit facility as needed. At December 31, 2006, Canetic had a working capital deficiency of $29.8 million including a financial derivative liability of $1.1 million. The increase in bank debt year over year includes $293.5 million drawn on the facility related to the acquisition of Samson which closed on August 31, 2006. As part of this acquisition, Canetic acquired $89.1 million of working capital including $77 million of cash at May 31, 2006. Our net debt at December 31, 2006 and 2005 is reconciled as follows: December 31, 2006 December 31, 2005 ------------------------------------------------------------------------- Star- ($000s) Acclaim Point(1) Total ------------------------------------------------------------------------- Bank debt 1,289,678 309,146 434,123 743,269 Working capital deficiency 29,794 45,630 101,477 147,107 ------------------------------------------------------------------------- Net debt 1,319,472 354,776 535,600 890,376 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) As at closing, January 5, 2006 Convertible Debentures As at December 31, 2006, we had convertible debentures outstanding of $260.7 million. The debentures consist of the StarPoint 9.4% convertible, unsecured, subordinated debentures; StarPoint 6.5% convertible, extendible, unsecured, subordinated debentures; Acclaim 8% convertible, extendible, unsecured, subordinated debentures; Acclaim 11% convertible, extendible, unsecured, subordinated debentures and Canetic 6.5% convertible, extendible, unsecured, subordinated debentures. The StarPoint debentures are described further below. The debentures are convertible into Canetic trust units at the following conversion prices: - StarPoint 9.4% Debentures (CNE.DB.A) - $16.02. Each $1,000 principal amount of 9.4% Debentures is convertible into approximately 62.42 Canetic trust units; - StarPoint 6.5% Debentures (CNE.DB.B) - $18.96. Each $1,000 principal amount of StarPoint 6.5% Debentures is convertible into approximately 52.74 Canetic trust units; - Acclaim 8% Debentures (CNE.DB.C) - $15.56. Each $1,000 principal amount of 8% Debentures is convertible into approximately 64.27 Canetic trust units; - Acclaim 11% Debentures (CNE.DB.D) - $11.24. Each $1,000 principal amount of 11% Debentures is convertible into approximately 88.97 Canetic trust units; and - Canetic 6.5% Debentures (CNE.DB.E) - $26.55. Each $1,000 principal amount of Canetic 6.5% Debentures is convertible into approximately 37.66 Canetic trust units. The following table is a summary of the dollar value of issuances and conversions of the convertible debentures: ------------------------------------------------------------------------- ($000s) 9.4% 6.5% 8% ------------------------------------------------------------------------- (CNE.DB.A) (CNE.DB.B) (CNE.DB.C) Balance, December 31, 2004 $ - $ - $ 72,901 Converted to units - (59,330) ------------------------------------------------------------------------- Balance, December 31, 2005 - - 13,571 Acquisition of StarPoint 9,255 43,944 - Samson acquisition - - - Converted to units (3,633) (26,123) (5,525) ------------------------------------------------------------------------- Balance, December 31, 2006 $ 5,622 $ 17,821 $ 8,046 ------------------------------------------------------------------------- ------------------------------------------------------------------------- ($000s) 11% 6.5% ------------------------------------------------------------------------- (CNE.DB.D) (CNE.DB.E) Total Balance, December 31, 2004 $ 6,562 $ - $ 79,463 Converted to units (3,844) (63,174) ------------------------------------------------------------------------- Balance, December 31, 2005 2,718 - 16,289 Acquisition of StarPoint - - 53,199 Samson acquisition - 227,470 227,470 Converted to units (1,021) - (36,302) ------------------------------------------------------------------------- Balance, December 31, 2006 $ 1,697 $ 227,470 $ 260,656 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (000s) 9.4% 6.5% 8% ------------------------------------------------------------------------- Units Issuable Upon Conversion (CNE.DB.A) (CNE.DB.B) (CNE.DB.C) Balance, December 31, 2004 - - 5,401 Converted to units - - (4,395) ------------------------------------------------------------------------- Balance, December 31, 2005 - - 1,006 Adjustment to conversion ratio - - (135) Acquisition of StarPoint 576 2,313 - Samson acquisition - - - Converted to units (225) (1,373) (354) ------------------------------------------------------------------------- Balance, December 31, 2006 351 940 517 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (000s) 11% 6.5% ------------------------------------------------------------------------- Units Issuable Upon Conversion (CNE.DB.D) (CNE.DB.E) Total Balance, December 31, 2004 672 - 6,073 Converted to units (394) - (4,789) ------------------------------------------------------------------------- Balance, December 31, 2005 278 - 1,284 Adjustment to conversion ratio (36) - (171) Acquisition of StarPoint - - 2,889 Samson acquisition - 8,663 8,663 Converted to units (90) - (2,042) ------------------------------------------------------------------------- Balance, December 31, 2006 152 8,663 10,623 ------------------------------------------------------------------------- On August 24, 2006, Canetic issued $230.0 million principal amount of 6.5% convertible, extendible, unsecured, subordinated debentures to partially fund the Samson acquisition. The conversion feature was valued at $2.5 million which has been allocated to equity. The debentures have a face value of $1,000 per debenture, a coupon of 6.5%, a maturity date of December 31, 2011 and are convertible at any time, at the option of the holder, into the trust units of Canetic at a conversion price of $26.55 per trust unit. The Trust may redeem the debentures in whole or in part at a redemption price of $1,050 per debenture after December 31, 2009 and at a redemption price of $1,025 per debenture after December 31, 2010 and before the maturity date. On June 15, 2004, Acclaim issued $75.0 million principal amount of 8% convertible, extendible, unsecured, subordinated debentures. The debentures have a face value of $1,000 per debenture, a coupon of 8.0%, a maturity date of August 31, 2009 and are convertible at any time, at the option of the holder, into trust units of Canetic at a price of $15.56 per trust unit. The Trust may redeem the debentures in whole or in part at a redemption price of $1,050 per debenture after August 31, 2007 and at a redemption price of $1,025 per debenture after August 31, 2008 and before the maturity date. In December 2002, Acclaim issued $45.0 million principal amount of 11% convertible, extendible, unsecured, subordinated debentures. The debentures have a face value of $1,000 per debenture, a coupon of 11%, a maturity date of December 31, 2007 and are convertible at any time, at the option of the holder, into trust units of Canetic at a price of $11.24 per trust unit. The Trust may redeem the debentures in whole or in part at a redemption price of $1,025 per debenture before the maturity date. Convertible Debentures Assumed on Acquisition of StarPoint StarPoint issued $60.0 million of 6.5% convertible, extendible, unsecured, subordinated debentures (the "StarPoint 6.5% Debentures") on May 26, 2005. The StarPoint 6.5% Debentures mature on July 31, 2010 and are convertible at any time, at the option of the holder, into the trust units of Canetic at a conversion price of $18.96 per trust unit. The StarPoint 6.5% Debentures are not redeemable at the option of the Trust on or before July 31, 2008. After July 31, 2008, and prior to the maturity date, the StarPoint 6.5% Debentures may be redeemed in whole or in part, at a price of $1,050 per debenture after July 31, 2008 and after July 31, 2009 at a price of $1,025 per debenture. In connection with the StarPoint/APF Energy Trust Combination, and pursuant to a debenture agreement dated June 27, 2005, the 9.4% Debentures were assumed by StarPoint. The 9.4% unsecured, subordinated, convertible debentures are convertible at the holder's option into fully paid and non-assessable trust units of Canetic at any time prior to July 31, 2008 at a conversion price of $16.02 per trust unit. The 9.4% Debentures are redeemable at $1,050 per 9.4% Debenture, in whole or in part, after July 31, 2006 and redeemable at $1,025 per debenture after July 31, 2007 and before maturity. Trust Unit Capital As at December 31, 2006, we had issued capital of 225.8 million units and as at March 7, 2007, we had issued capital of 226.6 million units. If all the outstanding convertible debentures were converted into units, a total of 236.4 million units would have been outstanding as at December 31, 2006 and 237.2 million units as at March 7, 2007. The merger of Acclaim and StarPoint on January 5, 2006, occurred pursuant to a Plan of Arrangement in which Canadian unitholders could elect to exchange their units on a tax-deferred basis. Each Acclaim unitholder received 0.8333 of a Canetic trust unit for each unit held and each StarPoint unitholder received 1.0000 Canetic trust unit for each unit they held. A total of 106.2 million units were issued pursuant to the arrangement. Also pursuant to the Arrangement, all exchangeable shares were exchanged for trust units. a) Trust Units 2006 2005 ------------------------------------------------------------------------- Units Units (000s) Amount (000s) Amount ------------------------------------------------------------------------- Balance, beginning of year 91,583 $ 1,087,459 86,313 $ 1,003,294 Issued for cash: Acquisition of Samson, net of costs 20,769 437,001 - - Pursuant to equity offering, net of costs - - - (350) Employee Unit Savings Plan 274 6,184 89 1,646 Distribution reinvestment plan 2,470 44,825 456 8,492 Issued pursuant to Arrangement 106,242 2,562,563 - - Properties contributed to TriStar - (5,000) - - Conversion of debentures 2,042 36,302 3,990 63,174 Conversion of debentures - equity portion - 4,636 - - Conversion of exchangeable shares 358 3,804 357 4,033 Unit award incentive plan 2,058 46,696 378 7,170 ------------------------------------------------------------------------- Balance, end of year 225,796 $ 4,224,470 91,583 $ 1,087,459 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Units Amount (000s) ($000s) (Restated b) Exchangeable Shares - Note 1) ------------------------------------------------------------------------- Balance, December 31, 2004 673 7,837 Shares exchanged (357) (4,033) Adjustment to exchange ratio for distributions 42 - ------------------------------------------------------------------------- Balance, December 31, 2005 358 3,804 Shares exchanged (358) (3,804) ------------------------------------------------------------------------- Balance, December 31, 2006 - - ------------------------------------------------------------------------- ------------------------------------------------------------------------- Funds Flow from Operations Funds flow from operations as presented is not intended to represent operating cash flow or operating profits for the period nor should it be viewed as an alternative to cash flow from operating activities, net earnings or other measures of financial performance calculated in accordance with GAAP. Funds flow from operations is reconciled as follows: Funds Flow ($000s) 2006 2005 2004 ------------------------------------------------------------------------- Net Earnings 223,101 65,848 31,263 ------------------------------------------------------------------------- Adjustments for: Unit-based compensation expense 14,049 27,166 7,344 Depletion, depreciation and amortization 645,203 233,693 179,557 Accretion 11,410 4,560 3,045 Unrealized gain on financial derivatives (95,371) 20,635 11,093 Future income taxes (48,246) 8,573 1,171 ------------------------------------------------------------------------- Funds flow from operations 750,146 360,475 233,473 ------------------------------------------------------------------------- Unitholder's equity 3,506,915 764,583 780,980 ------------------------------------------------------------------------- For the year ended December 31, 2006, funds flow from operations totalled $750.1 million or $3.57 per diluted unit, representing a 108 percent increase from the $360.5 million, or $3.98 per diluted unit during the same period in 2005 (2004 - $233.5 million or $3.09 per diluted unit). The increase is due to higher production levels associated with the StarPoint and Samson acquisitions. Our 2006 funds flow included a realized loss on financial derivative contracts of $8.5 million ($0.04 per diluted unit) as compared to a loss of $80.2 million ($0.88 per diluted unit) in 2005. Funds flow for the fourth quarter was $170.1 million or $0.75 per diluted unit as compared to $106.5 million or $1.15 per diluted unit during the same quarter in 2005 (2004 - $73.8 million or $0.84 per diluted unit). The increase is attributable to an increase in production due to the StarPoint and Samson acquisitions. We believe that funds generated from our operations, together with borrowings under our credit facility and proceeds from property dispositions, will be sufficient to finance our operations and planned capital expenditure program. During 2006, funds flow in excess of distributions funded 47 percent of our capital expenditure program. Our dividend reinvestment program plus additional bank borrowings funded the remaining 53 percent or $186.2 million. We anticipate that our annual capital expenditures over the next few years will be similar to our capital expenditures in fiscal 2006. We establish our capital expenditure program based on an annual budget review process, including budgeted cash flow from operations, and we closely monitor changes throughout the year. Cash Distributions Canetic declared cash distributions of $583.5 million ($2.76/unit), representing 78 percent of 2006 funds flow from operations compared to cash distributions of $208.5 million ($2.34/unit), representing 58 percent of funds flow from operations in 2005. The remaining 22 percent of funds flow in 2006 was utilized to fund 47 percent of Canetic's 2006 capital program. Effective with the merger with StarPoint, Canetic set its monthly distribution at $0.23 per unit per month beginning with distributions payable on February 15, 2006. This represented an 18 percent increase to former Acclaim unitholders and a five percent increase to former StarPoint unitholders. ($000s, except where indicated) 2006 2005 2004 ------------------------------------------------------------------------- Funds flow from operations 750,146 360,475 233,473 Total distributions 583,528 208,477 176,741 Distributions per unit ($) 2.76 2.34 2.34 Payout ratio (%) 78% 58% 74% ------------------------------------------------------------------------- ------------------------------------------------------------------------- In aggregate our distributions and net capital expenditure program totalled approximately $4.4 billion or approximately 586% of our 2006 cash flow of $750.1 million. We fund our distributions and capital expenditure programs with cash flow, but also supplement growth and fund acquisitions with long-term debt and equity. We distribute a portion of the funds flow from operations to our Trust unitholders on a monthly basis with a portion withheld to initially repay bank debt and ultimately fund capital expenditures. Although the level of funds retained for capital expenditures and/or debt repayment typically varies, we monitor our distribution policy with respect to forecasted funds flows from operations, debt levels, spending plans and taxability. Our 2006 distributions are summarized as follows: Value of Units Number Total Distri- Issued of DRIP ($000, except Distri- butions under Units Unit where indicated) butions Paid DRIP Issued Price ------------------------------------------------------------------------- Distributions declared: December 2006 51,933 47,793 4,140 284,172 $ 14.57 November 2006 51,848 46,743 5,104 330,490 $ 15.44 October 2006 51,739 45,419 6,321 424,474 $ 14.90 September 2006 51,642 45,289 6,353 374,054 $ 16.98 August 2006 51,577 47,029 4,548 225,495 $ 20.18 July 2006 46,699 41,236 5,463 252,973 $ 21.61 June 2006 46,583 42,538 4,045 189,023 $ 21.40 May 2006 46,516 42,570 3,946 184,238 $ 21.48 April 2006 46,439 43,175 3,264 145,356 $ 22.46 March 2006 46,272 43,230 3,042 130,570 $ 23.29 February 2006 46,208 43,629 2,579 119,674 $ 21.55 January 2006 46,072 46,000 72 3,175 $ 22.70 -------------------------------------------------------------- Total 583,528 534,651 48,877 2,663,694 -------------------------------------------------------------- -------------------------------------------------------------- In light of the weaker short-term outlook for commodity prices, Canetic announced on January 15, 2007 that it would reduce the monthly distribution in order to increase the level of cash flow available to fund drilling and development opportunities, bring Canetic's payout ratio in line with the Trust's long-term target of 60 to 70 percent of funds flow from operations, and prudently manage the level of Canetic's long-term debt. The regular monthly distribution was fixed at $0.19 per trust unit, commencing with the January 31, 2007 distribution paid on February 15, 2007. For the year ended December 31, 2006, we declared distributions of $583.5 million ($2.76 per unit) which represented 78 percent of funds flow from operations as compared to cash distributions of $208.5 million ($2.34 per unit) representing a 58 percent payout ratio in 2005. For the three months ended December 31, 2006, our payout ratio increased to 91 percent as we generated $170.1 million of funds flow from operations and distributed $155.5 million. CONTRACTUAL OBLIGATIONS In addition to financial derivative commitments, the Trust has the following contractual obligations as at December 31, 2006: ------------------------------------------------------------------------- ($000s) Total 2007 2008 2009 2010 2011 Thereafter ------------------------------------------------------------------------- Credit facility 1,289,678 - - - - - 1,289,678 Convertible debentures 260,656 1,697 5,622 8,046 17,821 227,740 - Office lease 24,659 6,415 6,295 6,295 3,231 2,423 - Pipeline contract 6,116 636 802 814 877 823 2,164 ------------------------------------------------------------------------- Total 1,581,109 8,748 12,719 15,155 21,929 230,986 1,291,842 ------------------------------------------------------------------------- ------------------------------------------------------------------------- TAXATION OF CASH DISTRIBUTIONS The following sets out a general discussion of the Canadian and U.S. tax consequences of holding Canetic units as capital property. The summary is not exhaustive in nature and is not intended to provide legal or tax advice. Unitholders or potential unitholders should consult their own legal or tax advisors as to their particular tax consequences. CANADIAN TAXPAYERS The Trust qualifies as a mutual fund trust under the Income Tax Act (Canada) and, accordingly, trust units are qualified investments for RRSP's, RRIF's, RESP's and DPSP's. Each year, the Trust is required to file an income tax return and any taxable income of the Trust is allocated to unitholders. Unitholders are required to include in computing income their pro-rata share of any taxable income earned by the Trust in that year. An investor's adjusted cost base ("ACB") in a trust unit equals the purchase price of the unit less any non-taxable cash distributions received from the date of acquisition. To the extent the unitholders' ACB is reduced below zero, such amount will be deemed to be a capital gain to the unitholder and the unitholders' ACB will be brought to nil. Canetic paid $2.76 per trust unit in cash distributions to unitholders during the period February 2006 to January 2007. For Canadian tax purposes, 100 percent of these distributions are taxable as other income. During the same period in 2005, the Trust paid $1.95 per trust unit in cash distributions, of which 31.28 percent was a tax-deferred return of capital and 68.72 percent taxable. The taxability of our distributions increased during 2006, a direct result of increased cash flows due to strong commodity prices and limited tax pools associated with the acquired assets. U.S. TAXPAYERS Prior to 2005, U.S. unitholders who received cash distributions were subject to a 15 percent withholding tax, applied only on the taxable portion of the distribution as computed under Canadian tax law. Legislative changes which took effect on January 1, 2005, imposed an additional 15 percent withholding tax on the non-taxable portion of the distribution. U.S. taxpayers should be eligible for a foreign tax credit with respect to 100 percent of Canadian withholding taxes paid. The taxable portion of the cash distributions is determined by the Trust in relation to its current and accumulated earnings and profit using U.S. tax principles. The taxable portion so determined, is considered to be a dividend for U.S. tax purposes. For most taxpayers, these dividends should be considered "Qualifying Dividends" and eligible for a reduced rate of tax. The non-taxable portion of the cash distributions is a return of the cost (or other basis). The cost (or other basis) is reduced by this amount for computing any gain or loss from disposition. However, if the full amount of the cost (or other basis) has been recovered, any further non-taxable distributions should be reported as a gain. Canetic paid US$2.23 per trust unit to US residents during the calendar year 2006. The portion considered to be a qualified dividend will be announced immediately upon completion of the Trust's calculation of current earnings and accumulated deficit for the year. RISK MANAGEMENT Investors who purchase our units are participating in the net funds flow from a portfolio of western Canadian crude oil and natural gas producing properties. As such, the funds flow paid to investors and the value of the units are subject to numerous risks inherent in the industry. Our expected funds flow from operations depends largely on the volume of petroleum and natural gas production and the price received for such production, along with the associated operating costs and taxability of distributions. The price we receive for our oil depends on a number of factors, including West Texas Intermediate oil prices, Canadian/U.S. currency exchange rates, quality differentials and Edmonton par oil prices. The price we receive for our natural gas production is primarily dependent on current Alberta market prices. Canetic has an ongoing commodity price risk management policy that provides for downside protection on a portion of its future production while allowing access to the upside price movements. Acquisition of oil and natural gas assets depends on our assessment of value at the time of acquisition. Incorrect assessments of value can adversely affect distributions to unitholders and the value of the units. We employ experienced staff on the business development team and perform stringent levels of due diligence on our analysis of acquisition targets, including a detailed examination of reserve reports; re-engineering of reserves for a large portion of the properties to ensure the results are consistent; site examinations of facilities for environmental liabilities; detailed examination of balance sheet accounts; review of contracts; review of prior year tax returns and modeling of the acquisition to ensure accretive results to the unitholders. The Board of Directors approves all acquisitions greater than $5 million. Inherent in development of the existing oil and gas reserves are the risks, among others, of drilling dry holes, encountering production or drilling difficulties or experiencing high decline rates in producing wells. To minimize these risks, we employ experienced staff to evaluate and operate wells and utilize appropriate technology in our operations. In addition, we use prudent work practices and procedures, safety programs and risk management principles, including insurance coverage against potential losses. We are subject to credit risk associated with the purchase of the commodities produced. In order to mitigate the risk of non-payment, we minimize the total sales value with any particular purchaser. The value of our trust units is based on the underlying value of the oil and natural gas reserves. Geological and operational risks can affect the quantity and quality of reserves and the cost of ultimately recovering those reserves. Lower oil and gas prices increase the risk of write-downs on our oil and gas property investments. In order to mitigate this risk, our proven and probable oil and gas reserves are evaluated each year by a firm of independent reservoir engineers. A special committee of the Board of Directors reviews and approves the reserve report. Our access to commodity markets may be restricted at times by pipeline or processing capacity. We minimize these risks by controlling as much of our processing and transportation activities as possible and ensuring transportation and processing contracts are in place with reliable cost efficient counterparties. The petroleum and natural gas industry is subject to extensive controls, regulatory policies and income and resource taxes imposed by various levels of government. These regulations, controls and taxation policies are amended from time to time. We have no control over the level of government intervention or taxation in the petroleum and natural gas industry. However, we operate in such a manner to ensure that we are in compliance with all applicable regulations and are able to respond to changes as they occur. The petroleum and natural gas industry is subject to both environmental regulations and an increased environmental awareness. We have reviewed our environmental risks and are in compliance with the appropriate environmental legislation and have determined that there is no current material impact on our operations. We are subject to financial market risk. In order to achieve substantial rates of growth, we must continue reinvesting in, acquiring or drilling for petroleum and natural gas. As we distribute the majority of our net cash flow to unitholders, we must finance a large portion of our acquisitions and development activity through continued access to equity and debt capital markets. One source of funding for our acquisition/expenditure program is through the issuance of equity. If we are not able to access the equity markets due to unfavorable market conditions for an extended period of time, this may adversely impact our growth rate. We minimize the financial market risk by maintaining a conservative financing structure. On October 31, 2006, the Canadian federal government announced proposals to introduce a new tax on distributions from existing publicly-traded income trusts. If enacted as currently proposed, Canetic would be subject to these new taxes beginning in 2011, provided it does not experience "undue expansion" in the intervening period as that term is defined in the recently released federal guidelines on "normal growth". The intent of these rules is to impose tax on income trusts in a similar manner and at similar rates as public corporations and the distributions be treated as dividends at the investor level. Income at the Trust level in excess of available tax shelter would be subject to the new tax at a statutory rate of 31.5 percent which would directly reduce cash available for distribution. These rules have not been enacted and are discussed in more detail in an earlier section of the MD&A. CRITICAL ACCOUNTING POLICIES AND ESTIMATES The Trust's significant accounting policies are summarized in Note 1 to the Trust's audited consolidated financial statements for the years ended December 31, 2006 and 2005. Certain of these policies are recognized as critical because in applying these policies, management is required to make judgments, assumptions and estimates that have a significant impact on the financial results of the Trust. OIL AND GAS RESERVES Reserves estimates and revisions to those reserves, although not reported as part of the Trust's financial statements, can have a significant impact on net earnings as a result of their impact on depletion, depletion rates, asset retirement obligations, asset impairments and purchase price allocations. In adherence with National Instrument 51-101, 100 percent of the Trust's proved plus probable oil and gas reserves were evaluated and reported on by independent petroleum engineers GLJ Petroleum Consultants Ltd. and Sproule Associates Limited. However, the process of estimating oil and gas reserves is complex and is subject to uncertainties and interpretations. Estimating reserves requires significant judgments based on available geological and reservoir data, past production and operating performance and forecasted economic and operating conditions. These estimates may change substantially as additional data from ongoing development, testing and production becomes available, and due to unforeseen changes in economic conditions which impact oil and gas prices and costs. FULL COST ACCOUNTING The Trust follows the full cost method of accounting for oil and natural gas activities. Using the full cost method of accounting, all costs of acquiring, exploring and developing oil and natural gas properties are capitalized, including unsuccessful drilling costs and administrative costs associated with acquisitions and development. In accordance with full cost accounting, a ceiling test is performed, on a quarterly basis, to test for asset impairment. An impairment loss is recorded if the sum of the undiscounted cash flows expected from the production of the proved reserves and the lower of cost and market of unproved properties does not exceed the carrying values of the oil and gas assets. An impairment loss is recognized to the extent that the carrying value exceeds the sum of the discounted cash flow expected from the production of proved and probable reserves and the lower of cost and market of unproved properties. The cash flow used in testing for impairment is based on the estimates of remaining proved and probable reserves, future commodity prices and future operating costs. Capitalized costs are depleted using the unit-of-production method based on estimated proved reserves of petroleum and natural gas before royalties as determined by independent petroleum engineers. Costs relating to unproved properties are excluded from costs subject to depletion and depreciation until it is determined whether or not proved reserves exist or if impairment occurs. Proved natural gas reserves and production are converted to equivalent volumes of crude petroleum based on the approximate relative energy content ratio of six thousand cubic feet of natural gas to one barrel of crude oil. ASSET RETIREMENT OBLIGATIONS Management calculates the asset retirement obligation based on estimated costs to abandon and reclaim its net ownership interest in all wells and facilities and the estimated timing of the costs to be incurred in future periods. The fair value estimate is capitalized to property, plant and equipment as part of the cost of the related asset and amortized over its useful life. BUSINESS COMBINATIONS Management makes various assumptions in determining the fair values of any acquired company's assets and liabilities in a business combination. The most significant assumptions and judgments made relate to the estimation of the fair value of the oil and natural gas properties. To determine the fair value of these properties we estimated oil and gas reserves and future prices of oil and natural gas. INCOME TAXES The Trust is not liable for income tax as it allocates substantially all of its taxable income to its unitholders. Future income taxes are calculated for the corporate subsidiaries using the liability method whereby tax liabilities and assets are recognized for the estimated tax consequences attributable to differences between amounts reported in the financial statements and their respective tax base using substantively enacted income tax rates. The effect of a change in income tax rates in future tax liabilities and assets are recognized in income in the period in which the change occurs. The determination of income and other tax liabilities requires interpretation of complex laws and regulations. All tax filings are subject to audit and assessment by taxing authorities after the lapse of considerable time. As a result, the actual income tax liability may differ from that recorded. RECENT ACCOUNTING PRONOUNCEMENTS FINANCIAL INSTRUMENTS Effective January 1, 2007, the Trust will apply the following new CICA Handbook sections: Section 1530-Comprehensive Income; Section 3251-Equity; Section 3855-Financial Instruments - Recognition and Measurement; and Section 3865-Hedges. The new accounting pronouncements are effective for the first quarter of 2007, and address the recognition and measurement of financial assets, financial liabilities and non-financial derivatives. The Trust has assessed the requirements under these sections, and has noted no current impact on the financial statements. Financial assets, financial liabilities and non-financial derivatives acquired in future periods will be evaluated under the framework set forth in the new pronouncements. BUSINESS RISKS The operations of Canetic are subject to underlying risks associated with the business of the Trust. For a detailed discussion of business risks, please refer to "Risk Factors" in the Trust's most recently filed Annual Information Form. Canetic Resources Trust Consolidated Balance Sheet (unaudited) As at December 31 ($000s) 2006 2005 ------------------------------------------------------------------------- ASSETS Current Assets Accounts receivable $ 261,498 $ 140,907 Prepaid expenses and deposits 34,647 11,630 ------------------------------------------------------------------------- 296,145 152,537 Property, plant and equipment, net (Note 4) 4,597,654 1,317,917 Goodwill (Note 2) 922,024 87,954 Deferred financing charges, net of amortization 8,996 689 Deferred costs - 12,000 Financial derivative asset (Note 12) 6,157 - ------------------------------------------------------------------------- Total assets $ 5,830,976 $ 1,571,097 ------------------------------------------------------------------------- ------------------------------------------------------------------------- LIABILITIES AND UNITHOLDERS' EQUITY Current Liabilities Accounts payable and accrued liabilities $ 260,206 $ 157,368 Income taxes payable (Note 3) 10,979 - Distributions payable 51,933 17,834 Convertible debentures (Note 6) 1,697 - Financial derivative liability (Note 12) 1,124 22,965 ------------------------------------------------------------------------- 325,939 198,167 ------------------------------------------------------------------------- Bank debt (Note 5) 1,289,678 309,146 Convertible debentures (Note 6) 258,959 16,289 Other long-term liabilities (Note 9) 7,272 - Financial derivative liability (Note 12) - 8,763 Future income taxes (Note 11) 250,339 202,110 Asset retirement obligations (Note 7) 191,874 68,235 ------------------------------------------------------------------------- 2,324,061 802,710 Non-controlling interest (Note 8) - 3,804 Commitments and guarantees (Note 14) UNITHOLDERS' EQUITY Capital (Note 8) 4,224,470 1,087,459 Convertible debentures (Note 6) 6,584 - Contributed surplus (Note 9) - 40,836 Deficit (Note 10) (724,139) (363,712) ------------------------------------------------------------------------- 3,506,915 764,583 ------------------------------------------------------------------------- Total liabilities and unitholders' equity $ 5,830,976 $ 1,571,097 ------------------------------------------------------------------------- ------------------------------------------------------------------------- See accompanying notes to consolidated financial statements. Approved on Behalf of the Board of Directors Jack C. Lee J. Paul Charron Chairman of the Board President and Chief Executive Officer Canetic Resources Trust Consolidated Statements of Earnings and Deficit (unaudited) Years ended December 31 Three months ended Year ended ($000s except per December 31 December 31 unit amounts) 2006 2005 2006 2005 ------------------------------------------------------------------------- REVENUE Petroleum and natural gas sales $ 347,701 $ 234,098 $ 1,407,754 $ 800,249 Royalty expense (63,609) (52,303) (258,260) (175,723) ------------------------------------------------------------------------- 284,092 181,795 1,149,494 624,526 ------------------------------------------------------------------------- EXPENSES Operating 70,981 34,671 252,142 129,646 Transportation 5,252 3,316 18,968 9,897 General and administrative 9,193 15,565 53,983 45,372 Interest on bank debt 19,612 3,922 53,809 13,752 Interest on convertible debentures 4,603 453 8,627 4,357 Depletion, depreciation and amortization 176,074 55,233 645,203 233,693 Accretion of asset retirement obligations 3,651 1,041 11,410 4,560 (Gain) loss on financial derivatives (Note 12) (19,978) (21,622) (86,906) 100,792 ------------------------------------------------------------------------- Earnings before taxes 14,704 89,217 192,258 82,457 Capital taxes 2,662 3,143 11,836 8,036 Current income tax 3,306 - 5,567 - Future income tax (recovery) expense (Note 11) 30,368 37,412 (48,246) 8,573 ------------------------------------------------------------------------- NET (LOSS) EARNINGS (21,632) 48,662 223,101 65,848 Deficit, beginning of period (546,987) (358,995) (363,712) (221,083) Distributions declared (155,520) (53,379) (583,528) (208,477) ------------------------------------------------------------------------- Deficit, end of year $ (724,139) $ (363,712) $ (724,139) $ (363,712) ------------------------------------------------------------------------- ------------------------------------------------------------------------- Net (loss) earnings per unit (Note 13) Basic $ (0.10) $ 0.53 $ 1.08 $ 0.74 Diluted $ (0.10) $ 0.52 $ 1.06 $ 0.73 Weighted average units outstanding (Note 13) Basic 225,192 91,489 206,081 89,331 Diluted 227,740 92,947 210,397 90,591 ------------------------------------------------------------------------- ------------------------------------------------------------------------- See accompanying notes to consolidated financial statements. Canetic Resources Trust Consolidated Statements of Cash Flows (unaudited) Years ended December 31 Three months ended Year ended ($000s except per December 31 December 31 unit amounts) 2006 2005 2006 2005 ----------------------------------------------- ------------------------- OPERATING ACTIVITIES Net earnings $ (21,632) $ 48,662 $ 223,101 $ 65,848 Adjustments for: Unit-based compensation (2,766) 11,448 14,049 27,166 Depletion, depreciation and amortization 176,074 55,233 645,203 233,693 Accretion 3,651 1,041 11,410 4,560 Unrealized (gain) loss on financial derivatives (15,612) (47,319) (95,371) 20,635 Future income tax (recovery) expense 30,368 37,412 (48,246) 8,573 Asset retirement costs incurred (6,314) (2,220) (16,877) (6,293) Changes in non-cash operating working capital 32,898 42,946 (50,778) (7,812) ------------------------------------------------------------------------- 196,667 147,203 682,491 346,370 ------------------------------------------------------------------------- FINANCING ACTIVITIES ------------------------------------------------------------------------- Proceeds from bank debt 66,662 (27,783) 546,409 25,301 Proceeds from issuance of units, net of issue costs - 2,357 437,001 9,788 Proceeds from issuance of convertible debentures - - 220,800 - Distributions to unitholders (154,094) (53,258) (538,703) (207,474) Changes in non-cash financing working capital - 902 - 1,231 ------------------------------------------------------------------------- (87,432) (77,782) 665,507 (171,154) ------------------------------------------------------------------------- 109,235 69,421 1,347,998 175,216 ------------------------------------------------------------------------- INVESTING ACTIVITIES Acquisition of petroleum and natural gas properties - (3,607) (56,285) (13,554) Disposition of petroleum and natural gas properties 2,132 - 17,168 4,610 Corporate acquisitions, net of cash - - (933,458) - Capital expenditures (111,367) (74,608) (375,423) (176,888) Changes in non-cash investing working capital - 8,794 (12,753) 10,616 ------------------------------------------------------------------------- (109,235) (69,421) (1,347,998) (175,216) ------------------------------------------------------------------------- Cash beginning and end of period $ - $ - $ - $ - ------------------------------------------------------------------------- The Trust paid the following cash amounts: Interest paid $ 18,994 $ 8,566 $ 60,875 $ 19,994 Capital taxes paid $ 19,606 $ 463 $ 34,494 $ 4,033 ------------------------------------------------------------------------- ------------------------------------------------------------------------- See accompanying notes to consolidated financial statements. NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited) Years Ended December 31, 2006 and 2005 (tabular amounts in $000s except for unit amounts) 1. SIGNIFICANT ACCOUNTING POLICIES BASIS OF PRESENTATION These consolidated financial statements include the accounts of Canetic Resources Trust and its direct and indirect wholly owned subsidiaries and partnerships (collectively, "Canetic" or the "Trust"). The consolidated financial statements have been prepared by management in accordance with Canadian Generally Accepted Accounting Principles. A reconciliation between Canadian Generally Accounting Principles and the United States of America Generally Accepted Accounting Principles is disclosed in Note 15. The preparation of consolidated financial statements in conformity with Canadian Generally Accepted Accounting Principles requires management of the Trust to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimated. The consolidated financial statements have, in management's opinion, been properly prepared using careful judgment and within the framework of the following significant accounting principles. In particular the amounts recorded for depletion and depreciation of property, plant and equipment, the impairment test and asset retirement obligations are based on estimates of proven reserves, production rates, future crude oil and natural gas prices, future costs and other relevant assumptions. By their nature, these estimates are subject to measurement uncertainty and changes in such estimates may impact the financial statements in future periods. PETROLEUM AND NATURAL GAS PROPERTIES The Trust follows the full-cost method of accounting for petroleum and natural gas operations, whereby all costs related to the exploration and development of petroleum and natural gas reserves are capitalized. Such costs include land acquisition costs, costs of drilling both productive and non-productive wells, well equipment, flowline and plant costs, geological and geophysical expenses and overhead expenses directly related to exploration and development activities. Gains or losses on sales of properties are recognized only when crediting the proceeds to the recorded costs would result in a change of 20 percent or more in the depletion and depreciation rate. Capitalized costs are depleted using the unit-of-production method based on estimated proved reserves of petroleum and natural gas before royalties as determined by independent petroleum engineers. Costs relating to unproved properties are excluded from costs subject to depletion and depreciation until it is determined whether or not proved reserves exist or if impairment occurs. Proved natural gas reserves and production are converted to equivalent volumes of crude petroleum based on the approximate relative energy content ratio of six thousand cubic feet of natural gas to one barrel of crude oil. The Trust places a limit on the aggregate carrying value of the Trust's petroleum and natural gas properties. An impairment loss exists when the carrying amount of the Trust's petroleum and natural gas properties exceeds the estimated undiscounted future net cash flows associated with the Trust's proved reserves. If an impairment loss is determined to exist, the costs carried on the balance sheet in excess of the discounted future net cash flows associated with the Trust's proved and probable reserves are charged to earnings. Reserves are determined pursuant to National Instrument 51-101. GOODWILL The Trust recognizes goodwill on corporate acquisitions when the total purchase price exceeds the fair value of net identifiable assets and liabilities of the acquired entity. Goodwill is tested annually at year-end for impairment or as events occur that could result in impairment. Impairment is recognized based on the fair value of the Trust compared to the book value of the Trust. If the fair value of the Trust is less that the book value, impairment is measured by allocating the fair value to the identifiable assets and liabilities as if the Trust had been acquired in a business combination for its fair value. The excess of the fair value over the amounts assigned to the identifiable assets and liabilities is the fair value of the goodwill. Any excess of the book value over this implied fair value of goodwill is the impairment amount. Impairment is charged to earnings in the period in which it occurs. Goodwill is stated at cost less impairment and is not amortized. HEDGING RELATIONSHIPS The Trust follows Accounting Guideline 13 - Hedging Relationships, which deals with the identification, designation, documentation and effectiveness of hedging relationships for the purpose of applying hedge accounting. Where hedge accounting does not apply, any changes in the fair value of the financial derivative contracts relating to a financial period can either reduce or increase net earnings and net earnings per trust unit for that period. The Trust enters into numerous financial instruments to manage commodity price and foreign exchange risk that do not qualify as hedges under Accounting Guideline 13. Therefore, the Trust has elected to not apply hedge accounting and to follow the fair value accounting method for all financial instruments. ASSET RETIREMENT OBLIGATIONS The Trust recognizes as a liability the estimated fair value of the future retirement obligations associated with PP&E. The fair value is capitalized and amortized over the same period as the underlying asset. The Trust estimates the liability based on the estimated costs to abandon and reclaim its net ownership interest in all wells and facilities and the estimated timing of the costs to be incurred in future periods. This estimate is evaluated on a periodic basis and any adjustment to the estimate is prospectively applied. As time passes, the change in net present value of the future retirement obligation is expensed through accretion. Retirement obligations settled during the period reduce the future retirement liability. No gains or losses on retirement activities were realized, due to settlements approximating the estimates. JOINT VENTURES A portion of the Trust's development and production activities are conducted jointly with others. These financial statements reflect only the Trust's proportionate interest in such activities. REVENUE RECOGNITION Revenue associated with sales of crude oil, natural gas and NGLs is recognized when title passes to the purchaser, normally at the pipeline delivery point for natural gas and at the wellhead for crude oil. DEPRECIATION Office furniture and equipment is depreciated on a declining-balance method at annual rates of 10 percent to 33 percent. UNIT AWARD INCENTIVE PLAN The Trust has a Unit Award Incentive Plan for directors, officers, employees and consultants of the Trust. Under the terms of the plan, a holder may elect, subject to consent of the Trust, to receive cash upon vesting in lieu of the number of rights held. Compensation expense associated with rights granted under the plan is measured at the date of exercise or at the date of the financial statements for unexercised rights. Compensation expense on unexercised rights is determined on the rights as the excess of the market price over the exercise price of the rights at the end of each reporting period and is deferred and recognized in income over the vesting period of the rights. See Note 9 for a description of the plan. INCOME TAXES The Trust is a taxable entity under the Canadian Income Tax Act ("Act") and is taxable only on income that is not distributed or distributable to the unitholders. As the Trust distributes all of its taxable income (if any) to the unitholders and meets the requirements of the Act applicable to the Trust, no provision for income tax has been made in the Trust. The Trust follows the liability method of accounting for income taxes. Under this method, income tax liabilities and assets are recognized for the estimated tax consequences attributable to differences between the amounts reported in the financial statements of the Trust's corporate subsidiaries and their respective tax bases, using substantially enacted income tax rates. The effect of a change in income tax rates on future income tax liabilities and assets is recognized in earnings in the period that the change occurs. CASH The Trust considers all highly liquid investments with a maturity of three months or less at the time of purchase to be cash equivalents. These cash equivalents primarily consist of funds on deposit under various terms or Banker's Acceptances utilized to fix the interest rate on bank debt. Cash and cash equivalents are stated at cost which approximates fair value. PER UNIT INFORMATION Basic earnings per unit are calculated using the weighted average number of units outstanding during the year adjusted for the impact of units to be issued on the conversion of exchangeable shares. Diluted earnings per unit are calculated using the treasury stock method to determine the dilutive effects of unit options and the "if converted" method is used to determine the dilution impact of the convertible debentures. The treasury method assumes that proceeds from the exercise of "in-the-money" unit options and exercise of the convertible debentures are used to re-purchase units at the prevailing market rate. 2. STARPOINT ARRANGEMENT Acclaim and StarPoint merged on January 5, 2006 pursuant to a Plan of Arrangement ("Arrangement"), which resulted in the creation of Canetic. Each Acclaim unitholder received 0.8333 of a Canetic trust unit for each trust unit they owned and each StarPoint unitholder received one Canetic trust unit for each trust unit they owned. Unitholders in both Acclaim and StarPoint also received common shares and warrants in a new publicly-listed junior exploration company, TriStar Oil & Gas Ltd. ("TriStar"), which was formed with assets from both Acclaim and StarPoint. Each Acclaim unitholder received 0.0833 of a TriStar common share for each trust unit they owned and each StarPoint unitholder received 0.1000 of a TriStar common share for each trust unit they owned. In addition, each Acclaim unitholder received 0.0175 of a TriStar warrant for each trust unit they owned and each StarPoint unitholder received 0.0210 of a TriStar warrant for each trust unit they owned. The merger was accounted for as an acquisition of StarPoint by Acclaim using the purchase method of accounting. ($000s) ------------------------------------------------------------------------- Current assets 124,803 Property, plant and equipment 2,511,746 Goodwill 834,070 Accounts payable and accrued liabilities (144,777) Distributions payable (22,662) Long-term debt (434,123) Financial derivative liability (57,785) Convertible debentures - liability (53,199) Convertible debentures - equity (8,691) Future income taxes (96,476) Asset retirement obligations (54,343) ------------------------------------------------------------------------- 2,598,563 ------------------------------------------------------------------------- Consideration was comprised of: Issuance of 106,242,000 units of Canetic 2,562,563 Transaction costs 36,000 ------------------------------------------------------------------------- 2,598,563 ------------------------------------------------------------------------- ------------------------------------------------------------------------- 3. SAMSON ACQUISITION On August 31, 2006, Canetic completed the share acquisition of a private oil and gas company ("Samson") for total consideration of $955.1 million. The transaction was effective June 1, 2006. The transaction was financed with bank debt and a $690.0 million bought deal financing which was completed on August 24, 2006. Under the bought deal financing, Canetic issued 20,769,000 units at a price of $22.15 per unit and $230.0 million principal amount of convertible extendible unsecured subordinated debentures. This acquisition was accounted for using the purchase method of accounting as follows: ($000s) ------------------------------------------------------------------------- Cash 57,635 Current assets 76,803 Property, plant and equipment 942,864 Accounts payable and accrued liabilities (60,035) Income taxes payable (43,946) Asset retirement obligations (18,228) ------------------------------------------------------------------------- 955,093 ------------------------------------------------------------------------- Consideration was comprised of: Cash 951,314 Transaction costs 3,779 ------------------------------------------------------------------------- 955,093 ------------------------------------------------------------------------- ------------------------------------------------------------------------- DATASOURCE: Canetic Resources Trust CONTACT: PRNewswire - - 03/08/2007

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