Thunder Energy Trust
TSX : THY.UN

Thunder Energy Trust

March 06, 2007 08:25 ET

Thunder Announces Pursuit of Strategic Alternatives, Year-End Financials and Revised Production Guidance

CALGARY, ALBERTA--(CCNMatthews - March 6, 2007) - Thunder Energy Trust (TSX:THY.UN) is announcing its financial and operational results for the quarter and full year ended December 31, 2006, revised production guidance for 2007 based on operational plans focused on production enhancement, and the determination of the Board of Directors of Thunder Energy Inc. to examine strategic alternatives to maximize unitholder value.

Strategic Alternatives

Given the current market circumstances affecting the Trust, the Board of Directors of Thunder Energy Inc., the administrator of the Trust, has determined that it would be in the best interest of the Trust and its stakeholders to commence a formal process to examine the strategic alternatives available to maximize unitholder value. The Board of Directors, in conjunction with the management of the Trust and the Trust's financial advisors, BMO Capital Markets and Canaccord Adams, will consider a full range of possible transactions or restructuring steps available to the Trust. These may include a merger with another issuer, the acquisition by the Trust of another issuer, the disposition of the Trust to another issuer, the acquisition or disposition of select assets, the reversion of the Trust to a corporate structure, the spin-out of one or more new issuers, or the continuance of the current strategic direction of the Trust. No decision on any particular alternative has been reached at this time and there can be no assurance that the Board of Directors will determine to pursue any transaction or restructuring step. The Trust will promptly announce any decision to pursue a particular strategic alternative.

Fourth quarter highlights

Fourth quarter production averaged 9,279 boe/d, the third quarter of stable production (9,307 boe/d in Q2; 9,229 boe/d in Q3).

Funds from operations totaled $18.5 million ($0.37 per unit basic; $0.35 per unit diluted), down from $39.6 million in fourth quarter 2005 ($0.86 per unit basic; $0.85 per unit diluted). The decline resulted from lower commodity prices and lower production than in fourth quarter 2005.

The Trust recorded a quarterly net loss of $130.2 million (loss of $2.61 per unit basic and diluted), compared with a net loss of $25.4 million in 2005 (loss of $0.55 per unit basic and diluted).

Distributions declared for the quarter were $0.36 per unit ($0.12 per unit per month), versus $0.45 per unit in 2005 ($0.15 per unit per month).

Full-year 2006 highlights

Full-year production averaged 9,452 boe/d, 99% of the revised 2006 production guidance (35.1 mmcf/d of natural gas and 3,605 bbls/d of oil and NGL).

Funds from operations for 2006 were $79.0 million ($1.65 per unit basic; $1.51 per unit diluted), compared with $110.4 million in 2005 ($2.47 per unit basic; $2.46 per unit diluted). The decline resulted from lower commodity prices.

For the year, the Trust recorded a loss of $99.5 million (loss of $2.07 per unit basic and diluted), versus a loss of $9.9 million in 2005 (loss of $0.22 per unit basic and diluted). At December 31, 2006, a downward revision in the Trust's reserves resulted in a write-down of $102.0 million on its property and plant assets (2005 write-down - $56.2 million). In addition, the year-end reserve revisions resulted in an additional write-down of $58.6 million in goodwill related to the formation of the Trust in July 2005.

Distributions declared for 2006 totaled $1.56 per unit, compared with $0.90 per unit in 2005 from the Trust's inception in July.

Revised Production Guidance

Thunder's further evaluation of a range of its properties, drilling activity and reserves has resulted in it revising 2007 production guidance to 8,600 to 9,000 boe/d. While this is lower than the 9,452 boe/d averaged in 2006, it reflects temporary shut-in volumes and is supported by an operational program focused on enhancing production. Thunder is planning to spend $62 million in 2007, which includes the drilling of 57 wells (31.0 net), along with lower risk exploitation activities.

In the short-term approximately 350 boe/d have been shut-in. Much of this is a result of various operational issues ranging from capacity restrictions through to construction delays of new facilities. Plans are to have this production back in Q2 and Q3 along with current behind pipe volumes of approximately 480 boe/d from new wells.

2006 Drilling

Total 2006 drilling resulted in 16 oil wells (7.3 net), 40 gas wells (25.8 net), and 13 drilled and abandoned ("D&A") (7.7 net) for an annualized success rate of 81%. At year-end 2006, the undeveloped land inventory was 165,248 net acres.

The Trust maintains approximately four years of drilling inventory, which does not include full resource development potential of the Belly River sands at Fenn-Big Valley. Approximately 65% of all conventional locations are covered by 3-D seismic.

Q-4 2006 Drilling Activity

A total of seven wells (1.7 net) were drilled and rig released in Q-4 2006, which resulted in two oil wells (0.1 net), five gas wells (1.6 net) and zero D&A's for an overall success rate of 100%.

Central Alberta

Manola: Two gas wells (1.0 net) were drilled in the fourth quarter at Manola. The first gas well was placed on production at the end of December 2006 and is currently producing at approximately 120 boe/d (60 net). The second well is awaiting final completion.

West Alberta

Three non-operated wells were drilled in West Alberta consisting of one gas well (0.1 net) at Lodgepole and two oil wells (0.1 net) in Pembina.

Alberta North

Two non-operated gas wells (0.5 net) were drilled in Alberta north and are currently awaiting tie-in.

Q-1 2007 Drilling Activity (Year to date)

In the first two months of 2007, drilling has resulted in an overall success rate of 72%. The Trust has drilled a total of 14 wells (6.1 net), which resulted in eight oil wells (4.3 net), three gas wells (0.1 net) and three D&A (1.7 net).

Central & Southern Alberta

Matziwin

Two wells (2.0 net) were drilled at Matziwin, which resulted in one oil well (1.0 net) and one D&A (1.0 net). The successful well has encountered three potential hydrocarbon zones and is currently awaiting completion. 3-D seismic was shot in January 2007 and is currently being processed.

Rosalind

Two wells (2.0 net) were drilled at Rosalind, which are both awaiting multi-zone completions. A 3-D seismic shoot at Rosalind will be completed by mid-March 2007.

Skiff (Southern Alberta)

Development of the Skiff-Sawtooth oil reservoir continues with four successful oil wells (2.7 net), two of which have further confirmed extension of the existing reservoir to the south side of the Etzicom River. The Trust plans to fully exploit this pool through infill drilling and initiating a full-scale waterflood.

Greater Sylvan Lake

Three wells (1.2 net) were drilled which resulted in one oil well (0.5 net) and two D&A (0.7 net). The oil well was drilled as a new pool discovery into the Leduc reef complex and was successfully tested at 900 boe/d over a 48-hour flow test from net pay of 16 metres. Production is scheduled for Q2 2007 and will coincide with completion of the Sylvan Lake battery expansion. At a recent land sale, the Trust was successful in acquiring an adjacent section of land and has identified two additional Leduc locations on this acreage where it holds a 50% working interest. All new discoveries in the Sylvan Lake Area are subject to a Maximum Rate Limitation ("MRL") as determined by the Alberta Energy and Utilities Board upon commencement of production.

Manola

The Trust's 3-D seismic program at Manola is scheduled for completion mid-March 2007.

Alberta North/Minor

Three minor interest wells were drilled by the end of February 2007, which resulted in one oil well (0.1 net) and two gas wells (0.1 net). In addition, one (0.03 net) minor interest gas well was drilled in the Clive area.

Forward-looking Statements

This press release contains forward-looking statements. More particularly, this press release contains statements concerning the Trust's projected annual average production of oil and natural gas, the volumes of oil and natural gas that are currently shut-in and planned exploration and development activities.

The forward-looking statements are based on certain key expectations and assumptions made by the Trust, including expectations and assumptions concerning prevailing commodity prices and exchange rates, availability and cost of labour and services, the timing of receipt of regulatory approvals, the performance of existing wells, the success obtained in drilling new wells and the performance of new wells and the sufficiency of budgeted capital expenditures in carrying out the Trust's planned activities.

Although the Trust believes that the expectations and assumptions on which the forward-looking statements are based are reasonable, undue reliance should not be placed on the forward-looking statements because the Trust can give no assurance that they will prove to be correct. Since forward-looking statements address future events and conditions, by their very nature they involve inherent risks and uncertainties. Actual results could differ materially from those currently anticipated due to a number of factors and risks. These include, but are not limited to, the risks associated with the oil and gas industry in general (e.g., operational risks in development, exploration and production; delays or changes in plans with respect to exploration or development projects or capital expenditures; the uncertainty of reserve estimates; the uncertainty of estimates and projections relating to production, costs and expenses, and health, safety and environmental risks), commodity price and exchange rate fluctuations and uncertainties resulting from potential delays or changes in plans with respect to exploration or development projects or capital expenditures. These risks are set out in more detail in the Trust's annual information form for the year ended December 31, 2005, which can be accessed at www.sedar.com.

The forward-looking statements contained in this press release are made as of the date hereof and the Trust undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise, unless so required by applicable securities laws.



Financial
($000s, except per unit data) 2006 2005
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Petroleum and natural gas sales 169,977 195,778
Funds from operations(1) 79,014 110,391
per unit(2) - basic ($) 1.65 2.47
- diluted ($) 1.51 2.46
Net income (loss) (99,466) (9,851)
per unit(2) - basic ($) (2.07) (0.22)
- diluted ($) (2.07) (0.22)

Capital expenditures 86,944 88,394
Distributions declared 74,091 38,746
Distributions declared per unit ($) 1.56 0.90
Payout ratio(3) before DRIP 94% 35%
Payout ratio(3) after DRIP 50% 31%
Total debt including working capital deficiency 204,225 154,643
Weighted average units outstanding (basic) 48,018 44,733
Weighted average units outstanding (diluted) 48,018 44,938
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Operations
2006 2005
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Daily production
Natural gas (mcf/d) 35,081 40,349
Crude oil and NGL (bbls/d) 3,605 2,706
Barrels of oil equivalent (boe/d) 9,452 9,431
Average sale price(4)
Natural gas ($/mcf) 6.43 8.66
Crude oil and NGL ($/bbl) 62.29 62.56
Wells drilled - gross (net)
Gas 40 (25.8) 56 (42.9)
Oil 16 (7.3) 17 (10.2)
Dry 13 (7.7) 24 (14.0)
Total 69 (40.8) 97 (67.1)
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Barrels of oil equivalent are reported with a 6:1 conversion with six mcf =
one barrel
(1) Non-GAAP financial measure defined as cash provided by operating
activities before changes in non-cash working capital relating to operating
activities and the settlement of asset retirement obligations.
(2) The term "units" has been used to identify both the trust units and
exchangeable shares of the Trust issued on or after July 7, 2005 as well as
the common shares of Thunder Energy Inc. issued prior to conversion on
July 7, 2005.
(3) The payout ratio is calculated using distributions declared divided by
funds from operations.
(4) Average sale price at the wellhead before commodity contracts gain or
loss.


MANAGEMENT'S DISCUSSION AND ANALYSIS

The following discussion is management's analysis of Thunder Energy Trust's ("Thunder" or the "Trust") operating and financial data for 2006 and prior years, as well as estimates of future operating and financial performance based on information currently available. It should be read in conjunction with the audited consolidated financial statements of the Trust for the years ended December 31, 2006, and 2005. These financial statements and additional information about the Trust are available on SEDAR at www.sedar.com. The Management's Discussion and Analysis ("MD&A") and consolidated financial statements of the Trust have been prepared on a continuity of interest basis which recognizes the Trust as the successor to Thunder Energy. Accordingly, the MD&A and consolidated financial statements for periods prior to July 7, 2005 reflect the financial position, results of operations and cash flows as if the Trust had always carried on the business formerly carried on by Thunder Energy. As a result, certain prior period information may not be directly comparable. The MD&A was prepared as of March 2, 2007.

Basis of Presentation

The financial data presented below has been prepared in accordance with Canadian generally accepted accounting principles ("GAAP"). The reporting and the measurement currency is the Canadian dollar.

Non-GAAP Measurements

The following are descriptions of non-GAAP measures used in this MD&A:

This MD&A contains the term funds from operations to evaluate operating performance and leverage. Funds from operations and funds from operations per unit as presented and as used in the MD&A do not have any standardized prescribed meaning under GAAP and therefore may not be comparable with the calculation of similar measures of other entities. Funds from operations does not represent operating profit for the year nor should it be viewed as an alternative to operating profit, net income (loss) or other measures of financial performance calculated in accordance with Canadian GAAP. All references to funds from operations throughout the MD&A are based on cash provided by operating activities before changes in non-cash working capital relating to operating activities and the settlement of asset retirement obligations.

Payout ratio as used in the MD&A does not have any standardized meaning under GAAP and therefore it may not be comparable with the calculation of similar measures of other entities. The payout ratio is calculated using distributions declared divided by funds from operations. Payout ratio is a useful measure used by management to analyze the Trust's efficiency and sustainability.

Distributable cash from operations is not a measure under GAAP and there is no standard measure of distributable cash from operations. Distributable cash from operations is calculated as funds from operations less capital expenditures funded by operations.

Operating netbacks per boe equal total petroleum and natural gas revenue net of transportation expenses and realized gains on commodity contracts per boe less royalties per boe and operating expenses per boe. Cash flow netbacks from operations equal operating netbacks less all other cash expenses per boe. Operating netbacks and cash flow netbacks as used in the MD&A does not have any standardized meaning under GAAP and therefore may not be comparable with the calculation of similar measures of other entities. Operating netbacks and cash flow netbacks are a useful measure to compare the Trust's operations with those of its peers.

BOE Presentation

The term barrels of oil equivalent (boe) may be misleading, particularly if used in isolation. The boe conversion ratio used by the Trust of 6 mcf to 1 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 by converting gas to oil in the ratio of six thousand cubic feet of gas to one barrel of oil.

The term "units" has been used to identify both trust units issued on or after July 7, 2005 as well as common shares of Thunder Energy outstanding prior to the conversion on July 7, 2005.

Forward-Looking Statements

Statements throughout this MD&A that are not historical facts may be considered "forward-looking statements". These forward-looking statements sometimes include words to the effect that management believes or expects a stated condition or result. Forward-looking statements included in the MD&A concern anticipated production and capital expenditures.

Forward-looking statements and information are based on the Trust's current beliefs as well as assumptions made by and information currently available to the Trust concerning anticipated financial performance, business prospects, strategies and regulatory developments. Although management considers these assumptions to be reasonable based on information currently available to it, they may prove to be incorrect.

By their very nature forward-looking statements involve inherent risks and uncertainties, both general and specific, and risks that predictions, forecasts, projections and other forward-looking statements will not be achieved. We caution readers not to place undue reliance on these statements as a number of important factors could cause the actual results to differ materially from the beliefs, plans, objectives, expectations and anticipations, estimates and intentions expressed in such forward-looking statements. These factors include, but are not limited to: the volatility of oil and gas prices; production and development costs and capital expenditures; the imprecision of reserve estimates and estimates of recoverable quantities of oil and gas reserves; environmental claims and liabilities; incorrect assessments of value when making acquisitions; increases in debt service charges; the loss of key personnel; the marketability of production; defaults by third-party operators; fluctuations in foreign currency and exchange rates; inadequate insurance coverage; compliance with environmental laws and regulations; changes in tax laws; the failure to qualify as a mutual fund trust; and the Trust's ability to access external sources of debt and equity capital. Further information regarding these factors may be found in this MD&A under the headings "Critical Accounting Estimates" and "Risks and Uncertainties".

The Trust cautions that the foregoing list of factors that may affect future results is not exhaustive. When relying on the Trust's forward-looking statements to make decisions with respect to the Trust, investors and others should carefully consider the foregoing factors and other uncertainties and potential events. The forward-looking statements and information contained in this MD&A are as of the date hereof and the Trust undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise, unless so required by applicable securities laws.

Corporate Reorganization

Effective July 7, 2005, Thunder Energy, Mustang Resources Inc. ("Mustang") and Forte Resources Inc. ("Forte") entered into a business combination resulting in the conversion into an energy trust through a Plan of Arrangement. The reorganization resulted in the shareholders of Thunder Energy receiving trust units in the new oil and natural gas energy trust, Thunder Energy Trust, and common shares in two new publicly-listed companies: Ember Resources Inc. ("Ember"), a coalbed methane company, and Alberta Clipper Energy Inc. ("Clipper") an exploration and production company. An additional exploration and production company was created, Valiant Energy Inc. ("Valiant"), which owns certain Forte exploration assets and undeveloped lands.

Shareholders of Thunder Energy received common shares of Ember and Clipper and at their election, either units of the Trust or exchangeable shares which may be exchanged into units of the Trust. Specifically, shareholders of the respective companies, after the consolidation of shares, received:

For each Thunder Energy common share owned:

(a) 0.5 trust units or exchangeable shares

(b) 0.3333 common shares of Clipper

(c) 0.3333 common shares of Ember

For each Mustang common share owned:

(a) 0.55 trust units or exchangeable shares

(b) 0.3666 common shares of Clipper

(c) 0.0833 common shares of Ember

For each Forte common share owned:

(a) 0.175 trust units or exchangeable shares

(b) 0.3333 common shares of Valiant




Financial Results
($000s, except per unit amounts) 2006 2005
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Petroleum and natural gas sales 169,977 195,778
Funds from operations (1) 79,014 110,391
Per unit - basic 1.65 2.47
Per unit - diluted 1.51 2.46
Net income (loss) (99,466) (9,851)
Per unit - basic (2.07) (0.22)
Per unit - diluted (2.07) (0.22)
Capital expenditures 86,944 88,394
Net debt including working capital deficiency 204,225 154,643
Total assets 654,370 817,390
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(1) Funds from operations is calculated as cash from operating activities
before the settlement of asset retirement obligations and changes in
non-cash working capital related to operating activities.


RESULTS OF OPERATIONS

Petroleum and Natural Gas Revenues

Oil and gas revenues decreased 13% to $170.0 million for the year ended December 31, 2006 compared with 2005. The 35% decline in natural gas sales to $85.4 million is due to a 26% decline in the price of natural gas at the wellhead and a 13% decline in natural gas production compared to the prior year. Crude oil and NGL sales increased 32% to $84.6 million due to a 33% increase in crude oil and NGL production. The average crude oil and NGL price remained flat with 2005. Production is targeted at 8,600 to 9,000 boe per day in 2007, 62% to be natural gas.



The table below calculates revenues and segregates transportation costs.

Petroleum and Natural Gas Revenues ($000s) 2006 2005
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Natural gas sales 85,371 131,742
Crude oil and NGL sales 84,606 64,036
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Gross revenues 169,977 195,778
Transportation expenses (5,615) (6,383)
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Net revenues 164,362 189,395
Realized net gain on commodity contracts 724 -
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Net revenues after realized gain on commodity
contracts 165,086 189,395
Unrealized net gain on commodity contracts 4,558 -
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Net revenues after realized and unrealized gains on
commodity contracts 169,644 189,395
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Sales Variance Analysis
($000s, net of transportation expenses and
realized commodity contract gain/loss) 2006 2005
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Natural gas sales
Effect of change in sales volumes (16,651) 3,210
Effect of change in product prices (28,551) 31,767
Effect of realized gain on commodity contracts 2,600 -
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Net natural gas sales change (42,602) 34,977
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Crude oil and NGL sales
Effect of change in sales volumes 20,521 20,789
Effect of change in product prices (352) 21,445
Effect of realized loss on commodity contracts (1,876) -
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Net crude oil and NGL sales change 18,293 42,234
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Combined sales change (24,309) 77,211
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Production 2006 2005
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Natural gas (mcf/d) 35,081 40,349
Crude oil and NGL (bbls/d) 3,605 2,706
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Total (boe/d) 9,452 9,431
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Percentage gas (%) 62 71
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Marketing

The Trust markets its natural gas in the Alberta spot market and through aggregators, which sell to major markets in Canada and the United States. Aggregator prices are based on a combination of term and spot markets. Crude oil and NGL are sold on a spot basis at various delivery points in Alberta. Prices received for crude oil and NGL are determined by the quality of the crude compared to a benchmark price for light sweet oil. The Trust's current composite crude oil is a medium blend averaging approximately 35 degrees API (2005 - 33 degrees API); whereas, the Edmonton light price is 40 degrees API.

The Trust continually monitors commodity markets to determine the appropriate marketing of its products including hedging production. In 2006, approximately 83% (2005 - 83%) of natural gas sales were to the higher value Alberta spot market and the remaining 17% was hedged at a monthly average price. The Trust received an average natural gas price at the wellhead of $6.43 per mcf, $0.11 per mcf lower than AECO, but before a $0.20 per mcf commodity contract gain. The Trust's average price for crude oil and NGL was discounted to the Edmonton light posted price by $10.48 per bbl before a commodity contract loss of $1.43 per bbl (2005 - $6.16 per bbl).

Commodity prices received by the Trust are based on the respective reference prices for both crude oil and natural gas adjusted for transportation and quality differentials, as applicable, and foreign exchange. For the year, the Trust's average crude oil and NGL price at the wellhead remained steady with the 2005 average price; whereas, the average natural gas price decreased 26%.



Average Commodity Prices 2006 2005
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Natural gas ($/mcf)
NYMEX ($US/mmbtu) 7.27 8.58
AECO Daily ($/mmbtu) 6.54 8.77
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Thunder price before commodity contracts and
transportation 6.66 8.94
Transportation (0.23) (0.28)
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Thunder price at the wellhead 6.43 8.66
Realized gain on commodity contracts 0.20 -
Thunder price after commodity contracts 6.63 8.66
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Crude oil ($/bbl)
WTI ($US/bbl) 66.22 56.56
Edmonton posted 72.77 68.72
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Thunder price before commodity contracts and
transportation 64.29 64.82
Transportation (2.00) (2.26)
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Thunder price at the wellhead 62.29 62.56
Realized loss on commodity contracts (1.43) -
Thunder price after commodity contracts 60.86 62.56
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Cdn/US $ average exchange rate 1.134 1.208
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Transportation expenses relate to the cost of transporting natural gas on the main natural gas pipelines and for crude oil trucking charges. In 2006, transportation expenses decreased 12% to $5.6 million due to the decline in natural gas production. Natural gas transportation increased in the second half of 2005 to $0.28 per mcf due to the amalgamation with Mustang and Forte and an increased presence in northeast British Columbia and northern Alberta. For crude oil and NGL, transportation costs were down as much of the Trust's oil production is pipeline connected.

Financial instruments are used by the Trust to mitigate its exposure to future fluctuations in commodity prices. The Trust has entered into the following financial transactions:



Gas Volume Pricing Strike
Contracts GJ/d Point Price per GJ Term
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Costless
Collar 10,000 AECO Cdn$8.00 to Cdn$9.40 Nov 1/06 to March 31/07
Costless
Collar 10,000 AECO Cdn$8.00 to Cdn$10.00 Nov 1/06 to March 31/07
Costless
Collar 10,000 AECO Cdn$6.50 to Cdn$8.10 April 1/07 to Oct 31/07
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Oil Volume Pricing Strike
Contracts bbls/d Point Price per bbl Term
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Costless
Collar 800 WTI NYMEX US$61.00 to US$73.05 Jan 1/07 to Mar 31/07
Costless
Collar 800 WTI NYMEX US$65.00 to US$80.00 Jan 1/07 to Mar 31/07
Costless
Collar 800 WTI NYMEX US$60.00 to US$70.50 April 1/07 to June 30/07
Costless
Collar 800 WTI NYMEX US$60.00 to US$72.50 July 1/07 to Sept 30/07
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The net effect of these contracts and others, which have already expired, was a realized gain of $0.7 million and an unrealized gain of $4.6 million for the year ended December 31, 2006 (2005 - nil).

Subsequent to December 31, 2006, the Trust entered into the following financial transaction to mitigate its exposure to future fluctuations in commodity prices.



Gas Volume Pricing Strike
Contract GJ/d Point Price per GJ Term
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Costless
Collar 8,000 AECO Cdn$6.50 to Cdn$8.00 April 1/07 to Oct 31/07
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Royalties for the year were down 11% to $30.3 million from $33.9 million in 2005. Royalties as a percentage of revenue net of transportation were up to 18.4% compared to 17.9% in 2005. The increase was due to higher freehold and other royalties due to the amalgamation with Mustang and Forte offset by lower Crown royalties due to decreased natural gas prices in 2006. On September 21, 2006, the Alberta government announced it would discontinue its Alberta Royalty Tax Credit ("ARTC") program effective January 1, 2007.



Royalties ($000s) 2006 2005
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Crown 21,897 26,278
Freehold and other 8,857 8,118
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Total gross royalties 30,754 34,396
ARTC (500) (491)
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Net royalties 30,254 33,905
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Royalty Rates (as a % of revenue,
net of transportation expenses) 2006 2005
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Crown 13.3 13.9
Freehold and other 5.4 4.3
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Total gross royalties 18.7 18.2
ARTC (0.3) (0.3)
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Net royalties 18.4 17.9
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Operating costs for the year increased 26% from 2005 to $37.5 million or $10.87 per boe. The increase was due to a full year of operations as a Trust, as well as a reflection of high costs across the industry and the Trust's increased presence in northeast British Columbia and northern Alberta which tend to have higher operating costs. The Trust incurred higher operating costs in the second half of 2006 related to increased power and plant turnaround costs.



Operating Costs 2006 2005
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Operating costs ($000s) 37,498 29,704
Per boe ($) 10.87 8.63
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Gross general and administrative expenses (G&A) increased 8% from 2005 to $14.3 million due to increased salaries and benefits and office space as a result of the transition into a Trust as well as increased compensation necessary to continue to attract and retain qualified personnel in a highly competitive market. Net G&A was $2.44 per boe, down 1% from 2005. The Trust incurred several budgeted, one-time costs in 2006 such as audit and tax services, annual filing costs and consulting services due to its transition into a Trust, as well as unbudgeted costs related to the federal government's October 31, 2006 announcement to apply a tax on distributions from publicly-traded income trusts. These budgeted and non-budgeted costs totaled $0.3 million or $0.10 per boe for the year (2005 - $3.3 million or $0.96 per boe). Also included in G&A are costs relating to documenting internal controls to meet regulatory requirements, which totaled $0.2 million or $0.06 per boe for the year.



G&A Expenses ($000s) 2006 2005
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Gross G&A expenses 14,252 13,226
Capitalized G&A (3,903) (1,619)
Recoveries from joint operations
Capital (867) (1,627)
Operating (1,083) (1,463)
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Net G&A expenses 8,399 8,517
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Per boe ($)
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Gross G&A expenses 4.13 3.84
Capitalized G&A (1.13) (0.47)
Recoveries from joint operations
Capital (0.25) (0.47)
Operating (0.31) (0.43)
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Net G&A expenses 2.44 2.47
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Capitalized G&A per boe increased in 2006 to $1.13 per boe from $0.47 per boe in 2005 due to increased salaries due to a full year of operations as a Trust.

Unit-based compensation expense decreased 81% to $1.7 million from $8.6 million in 2005. In the third quarter of 2005, the Trust recognized $5.4 million of stock-based compensation related to the exercise of options resulting from the Plan of Arrangement.

Financial charges are comprised of bank debt interest, convertible debenture interest, amortization of deferred financing costs, and accretion of convertible debenture liability. Financial charges were up 95% from 2005 due to increased interest rates and higher levels of debt due to lower commodity prices and production. A reconciliation of these charges follows:



Financial charges ($000s) 2006 2005
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Bank debt interest 5,640 5,357
Convertible debenture interest 4,037 -
Amortization of deferred financing costs 539 -
Accretion of convertible debenture liability 209 -
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Total financial charges 10,425 5,357
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Bank debt interest for the year increased 5% from 2005 due to a higher effective interest rate, offset by a decrease in the average bank debt outstanding. The decrease in average bank debt was due to the issuance of convertible debentures during the second quarter of 2006.



Bank Debt 2006 2005
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Average bank debt outstanding ($000s) 106,739 121,047
Effective annualized interest rate for the
period (%) 5.3 4.4
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Convertible debenture interest was $4.0 million for the year. The Trust issued convertible debentures of $75.0 million during the second quarter of 2006. The net proceeds of $71.6 million were used to repay bank debt.

Depletion, depreciation and accretion (DD&A) expenses increased $4.75 per boe to $26.55 per boe in 2006. The increase to $91.6 million from $75.1 million in 2005 was due to a full year of operations as a Trust. In addition, the DD&A rate increased due to a reduction in proved reserves at December 31, 2006. Accretion and DD&A expense on the asset retirement obligation increased due to the transition into a Trust and a revision to the Trust's liability estimate. Prior period DD&A has been restated to reflect the Trust's change in accounting policy for capitalized G&A expenses.



DD&A Expense
($000s, except where noted) 2006 2005
---------------------------------------------------------------------------
DD&A Expense 91,606 75,058
DD&A Rate ($/boe) 26.55 21.80
---------------------------------------------------------------------------
---------------------------------------------------------------------------


Write-down of Oil and Gas Assets

The carrying value of the Trust's petroleum and natural gas property and equipment is limited to the amount calculated under the ceiling test at the balance sheet date. At December 31, 2006, the calculation indicated the carrying value of the Trust's petroleum and natural gas property and equipment was in excess of the amount calculated under the ceiling test. Accordingly, a write-down in the amount of $102.0 million (2005 - $56.2 million) was recorded. This write-down is primarily the result of downward revisions in the Trust's petroleum and natural gas reserves, as estimated by independent engineers as of December 31, 2006. The ceiling test calculation was based on benchmark reference prices adjusted for the Trust's quality and price differentials, discounted at an interest rate of 6.4% (2005 - 6.8%) over the estimated reserve life.

Tax Legislation Announcement

On October 31, 2006, the Federal Minister of Finance announced proposals (the "October 31, 2006 Proposals") to amend the Tax Act to apply a tax on distributions from publicly-traded income trusts. Under the October 31, 2006 Proposals, existing income and royalty trusts will be subject to the new measures commencing in their 2011 taxation year, following a four-year grace period. The Federal Minister of Finance has issued a Notice of Ways and Means Motion to Amend the Tax Act, but it is not known at this time if or when the proposal will be enacted by Parliament.

In simplified terms, under the proposed tax plan, distributions to unitholders, which are currently not subject to taxes or withholdings at the income trust level, will be subject to a new tax. Distributions to individual unitholders will be treated as dividends from a Canadian corporation, and will be eligible for the dividend tax credit. Income distributions to corporations resident in Canada will be eligible for full deduction as tax-free intercorporate dividends. Tax-deferred accounts (Registered Retirement Savings Plans, Registered Retirement Income Funds and Canadian Pension Funds) will continue to pay no tax on distributions received until funds are withdrawn. Non-resident unitholders will be taxed on distributions at the non-resident withholding tax rate for dividends. With tax to be applied at the Trust level, distributions will be reduced; however, the net impact on Canadian taxable investors is expected to be minimal as they will be able to take advantage of the dividend tax credit. By contrast, the impact on tax-deferred accounts and distributions to non-residents will be lower after-tax distributions as no tax credit will be available.

The government has also proposed to limit the growth of existing trusts by limiting new equity issues to 40% of that trust's October 31, 2006 market capitalization ("benchmark") for 2007, and an additional 20% of the benchmark for each of 2008, 2009, and 2010. The government also announced its intention to allow trusts to convert to a corporation on a tax-deferred basis, with no immediate tax impact for unitholders.

As none of the proposed rules has been substantively enacted into law, there has been no adjustment to future income taxes in regards to this announcement.

Given the grace period before existing trusts will be taxed, the Trust has an opportunity to examine its strategy, and, if warranted, modify it to provide the best possible return for unitholders. At the same time, unitholders have an opportunity to arrange their investments to minimize the impact of the proposed tax changes on their portfolios. The effect of the proposed tax changes on the Trust is yet to be determined. In particular, the Trust is evaluating the impact of the proposed measures on net income and cash flows, and the potential valuation of long-lived assets such as goodwill, all of which could be material.

Provision for Income Taxes

The Trust is a taxable entity under the Tax Act, but is taxable only on income that is not distributed or distributable to the unitholders. To the extent that cash distributions represent taxable distributions to unitholders, the distributions will reduce the Trust's future income tax expense. The Trust had a future income tax recovery of $71.6 million for the year primarily due to the estimated taxability of distributions and the write-down of oil and gas assets, as well as future tax rate reductions enacted by the federal and provincial governments during the second quarter of 2006.

In 2006, the federal budget eliminated the large corporations tax effective for the 2006 taxation year. The Trust is still required to pay Saskatchewan capital tax.

The following table summarizes the Trust's tax pools at December 31, 2006:



Tax Pools ($000s) 2006
---------------------------------------------------------------------------
Canadian oil and gas property expenses (COGPE) 21,213
Canadian development expenses (CDE) 98,643
Canadian exploration expense (CEE) 58,263
Undepreciated capital costs (UCC) 79,781
Non-capital tax loss carry forwards 75,842
Unit issue costs 3,674
---------------------------------------------------------------------------
Total 337,416
---------------------------------------------------------------------------
---------------------------------------------------------------------------


Trust Unit Information

For the years ending December 31, 2006 and 2005 the Trust had the following trust units and trust unit equivalents outstanding:



Trust units (000s) 2006 2005
---------------------------------------------------------------------------
Weighted average trust units 47,279 41,373
Exchangeable shares at exchange ratio 739 3,360
---------------------------------------------------------------------------
Trust units (basic) 48,018 44,733
Convertible debentures 6,731 -
Restricted and performance trust units 350 205
---------------------------------------------------------------------------
Trust units (diluted) 55,099 44,938
---------------------------------------------------------------------------
---------------------------------------------------------------------------


When calculating the diluted net loss per unit for the year ended December 31, 2006, the effect of the convertible debentures and the restricted and performance trust units are anti-dilutive and thus trust units (basic) have been used to calculate both basic and diluted net loss per unit amounts.

The funds from operations per unit calculations include the dilutive impact of both the convertible debentures and the restricted and performance trust units.

Distribution Reinvestment and Optional Trust Unit Purchase Plan ("DRIP")

The Trust has a Distribution Reinvestment and Optional Trust Unit Purchase Plan ("DRIP") for eligible unitholders of the trust. On distribution payment dates, eligible DRIP unitholders may reinvest their cash distributions in additional trust units at a price that is 95% of the average market price for the corresponding pricing period. Eligible DRIP unitholders may also make optional cash payments on this date to purchase additional trust units at a price that is equal to the 10-day weighted average trading price of trust units. During the year, the Trust issued 4.2 million (2005 - 175,000) trust units from treasury for the DRIP which resulted in an increase to unitholders' capital of $34.1 million (2005 - $2.1 million).

Net Income (Loss) and Funds from Operations

Net loss increased to $99.5 million from $9.9 million in the prior year due to the write-down of the full cost pool under the ceiling test and the write-down of goodwill. The write-downs were offset by future tax recoveries due to the taxability of distributions and future tax rate reductions.



Net Income (Loss) 2006 2005
Net income (loss) ($000s) (99,466) (9,851)
Per unit - basic ($) (2.07) (0.22)
Per unit - diluted ($) (2.07) (0.22)
---------------------------------------------------------------------------
---------------------------------------------------------------------------


Funds from operations decreased 28% year over year reflecting lower natural gas prices and higher operating and G&A expenses compared to 2005.



Funds from Operations 2006 2005
---------------------------------------------------------------------------
Funds from operations(1) ($000s) 79,014 110,391
Per unit - basic ($) 1.65 2.47
Per unit - diluted ($) 1.51 2.46
Funds from operations per boe ($) 22.90 32.07
Funds from operations as a percentage of gross
sales (%) 46.5 56.4
---------------------------------------------------------------------------
---------------------------------------------------------------------------
(1) Funds from operations is calculated as cash from operating activities
before the settlement of asset retirement obligations and changes in
non-cash working capital related to operating activities.


Netback Analysis Natural Gas ($/mcf) Crude Oil and NGL
($/bbl)
---------------------------------------------------------------------------
2006 2005 2006 2005
---------------------------------------------------------------------------
Selling price (net of transportation) 6.43 8.66 62.29 62.57
Realized gain on commodity contracts (0.20) - 1.43 -
Royalties (net of ARTC) 1.14 1.55 11.83 12.99
Operating costs 1.28 1.48 15.99 7.97
---------------------------------------------------------------------------
Operating netback 4.21 5.63 33.04 41.61
---------------------------------------------------------------------------
---------------------------------------------------------------------------

Netback Analysis Barrels of Oil Equivalent ($/boe)
---------------------------------------------------------------------------
2006 2005
---------------------------------------------------------------------------
Selling price (net of transportation) 47.64 55.02
Realized gain on commodity contracts (0.21) -
Royalties (net of ARTC) 8.77 9.85
Operating costs 10.87 8.63
---------------------------------------------------------------------------
Operating netback 28.21 36.54
G&A expenses 2.44 2.47
Bank debt interest 1.63 1.56
Convertible debenture interest 1.17 -
Current tax expense 0.07 0.44
---------------------------------------------------------------------------
Cash flow netback from operations 22.90 32.07
---------------------------------------------------------------------------
---------------------------------------------------------------------------


The total gas operating netback decreased 25% due to lower gas production and natural gas prices, which more than offset the declines in royalties and operating costs.

The total crude oil and NGL netback decreased 21% due a significant rise in operating costs due to increased crude oil production in northern Alberta. Lower royalties offset the higher operating costs.

Capital expenditures for the year aggregated $86.9 million. Drilling, completion, equipping and tie-in costs totaled $60.6 million for the drilling of 40 gas wells (25.8 net), 16 oil wells (7.3 net) and 13 dry holes (7.7 net). The Trust had an overall net drilling success ratio of 81%. In the fourth quarter of 2006, the Trust acquired three wells for $10.0 million. In 2007 the Trust has budgeted $62 million for capital expenditures to complete its drilling program.

At December 31, 2006, costs of $24.8 million (2005 - $16.3 million) related to unproven properties were excluded from the full cost pool.



Capital Expenditures Summary ($000s) 2006 2005
---------------------------------------------------------------------------
Land and retention 5,956 3,682
Seismic 3,214 4,876
Drilling and completions 41,285 51,750
Well equipping and tie-in 19,309 19,264
Facilities and gas gathering 2,450 6,503
Property acquisitions, net of dispositions 10,382 741
Other, including capitalized G&A 4,348 1,578
---------------------------------------------------------------------------
Total capital expenditures 86,944 88,394
---------------------------------------------------------------------------
Wells drilled gross (net) 69(40.8) 97(67.1)
---------------------------------------------------------------------------
---------------------------------------------------------------------------

Liquidity and Capital Resources

Total Capitalization ($000s) 2006 2005
---------------------------------------------------------------------------
Working capital deficiency 5,793 18,284
Bank debt 124,925 136,359
Convertible debenture 73,507 -
Unit-based compensation 1,049 528
Future income taxes (long-term) 73,920 146,876
Asset retirement obligation 28,771 24,774
Market value of trust units at year end 287,275 553,865
---------------------------------------------------------------------------
Total 595,240 880,686
---------------------------------------------------------------------------
---------------------------------------------------------------------------


Goodwill

Under GAAP goodwill is assessed for impairment at least annually. The assessment is a two-step test under which the carrying value of goodwill is compared to its fair value. If the carrying value is greater than the fair value goodwill then the second step of the test is performed to determine the amount of impairment. Under the second step, the amount of the impairment is determined by deducting the fair value of the reporting unit's tangible assets and liabilities from the fair value of the reporting unit to determine the implied fair value of goodwill and comparing that amount to the book value of goodwill. Any excess of the book value of goodwill over the implied fair value is the impairment amount and is charged to income in the period of the impairment. The Trust has assessed goodwill for impairment at December 31, 2006 and has recorded a write-down of $58.6 million (2005 - nil). The decrease in the value of goodwill is attributable to the write-down of the Trust's full cost pool. The following table reconciles the goodwill balance:



($000s)
---------------------------------------------------------------------------
Balance December 31, 2004 45,448
Goodwill on Plan of Arrangement (Note 2) 62,844
---------------------------------------------------------------------------
Balance December 31, 2005 108,292
Write-down of goodwill (58,590)
---------------------------------------------------------------------------
Balance December 31, 2006 $ 49,702
---------------------------------------------------------------------------
---------------------------------------------------------------------------


Asset Retirement Obligations

The Trust accrues asset retirement obligations which result from net ownership interests in petroleum and natural gas assets including well sites, gathering systems and processing facilities. The Trust periodically reviews the assumptions used in its asset retirement obligation calculation. In the current year, revisions were made to the liability to reflect changes in the inflation rate and the credit-adjusted risk-free rate. A reconciliation of the asset retirement obligations is provided below:



Asset Retirement Obligations ($000s) 2006 2005
---------------------------------------------------------------------------
Balance, beginning of year $ 24,774 13,417
Liabilities incurred in the year 800 1,758
Liabilities assumed due to business combination
- Forte - 7,596
Liabilities assumed due to business combination
- Mustang - 5,019
Revisions 3,571 (135)
Liabilities released due to dispositions - (3,328)
Liabilities settled in the period (2,952) (1,306)
Accretion expense 2,578 1,753
---------------------------------------------------------------------------
Balance, end of year $ 28,771 24,774
---------------------------------------------------------------------------
---------------------------------------------------------------------------


Liquidity

For the year ended December 31, 2006, capital expenditures of $86.9 million, the settlement of asset retirement obligations of $3.0 million, a combined decrease to long-term debt, bank indebtedness, unit issue costs and working capital of $20.1 million and cash distributions, net of the distribution reinvestment plan ("DRIP"), of $40.6 million were funded by funds from operations of $79.0 million and net proceeds from convertible debentures of $71.6 million.

The Trust has a $160.0 million credit facility with a syndicate of chartered banks consisting of a $145.0 million revolving term credit facility and a $15.0 million operating credit facility. The credit facilities are available on a revolving basis for a period of at least 364 days until April 30, 2007, and such initial term out date may be extended for further 364 day periods at the request of the Trust, subject to approval by the banks. Following the term-out date, the facilities will be available on a non-revolving basis for a two-year term, payable in quarterly payments in the second year. The credit facilities are collateralized by the Trust's assets and are subject to semi-annual review at which time the lenders may re-determine the borrowing base. The next scheduled semi-annual review is scheduled for April 30, 2007.

Management anticipates that Thunder will continue to have adequate liquidity to fund future working capital and forecasted capital expenditures during 2007 through a combination of cash flow, debt and equity. Cash flow used to finance these commitments may reduce the amount of cash distributions paid to unitholders.

Convertible Debentures

On April 5, 2006, the Trust issued $75.0 million principal amount of 7.25% Convertible Unsecured Subordinated Debentures (the "Debentures") for net proceeds of $71.6 million. The Debentures have a conversion price of $11.70 per trust unit and a maturity date of April 30, 2011. The Debentures pay interest semi-annually in arrears on April 30 and October 31 each year, commencing October 31, 2006. The Debentures will not be redeemable by the Trust prior to April 30, 2009. The Debentures are redeemable by the Trust, on not more than 60 days and not less than 30 days prior notice, at a price of $1,050 per Debenture after April 30, 2009 and on or before April 30, 2010, and at a price of $1,025 per Debenture after April 30, 2010 and before the maturity date, in each case, plus accrued and unpaid interest thereon, if any. On redemption or maturity the Trust may elect to satisfy its obligations to repay the principal and may satisfy its interest obligations by issuing trust units. The Debentures are traded on the Toronto Stock Exchange under the trading symbol THY.DB.

The Debentures have been classified as debt net of the fair value of the conversion feature at the date of issue, which has been classified as part of unitholders' equity. The debt portion will accrete up to the principal balance at maturity. Issue costs have been classified under deferred financing costs and are being amortized over the term of the Debentures. If the Debentures are converted into units, a portion of the value of the conversion feature under unitholders' equity will be reclassified to trust units along with the conversion price paid. The following table sets forth a reconciliation of the Debenture activity:



As at December 31,
Convertible Debentures ($000s) 2006
---------------------------------------------------------------------------
Debt portion on April 5, 2006 $ 73,298
Accretion of non-cash interest 209
---------------------------------------------------------------------------
Debt portion, end of period 73,507
Equity portion 1,702
---------------------------------------------------------------------------
Total Debentures, end of period $ 75,209
---------------------------------------------------------------------------
---------------------------------------------------------------------------


Distributable Cash from Operations and Distributions

Management and the Board of Directors monitor the Trust's distribution payout policy with respect to forecasted net cash flow, debt levels and capital expenditures. Distributions are made at the discretion of the Trust's management and Board of Directors. For 2006 the payout ratio was 94% of funds from operations were distributed before DRIP, 50% after DRIP. Exchangeable shares are convertible into trust units based on the Exchange Ratio, which is adjusted monthly to reflect that distributions are not paid on the exchangeable shares and cash flow related to the exchangeable shares is retained by the Trust for additional capital expenditures or debt repayment.

The amount of distributable cash from operations is calculated in accordance with the Trust's indenture. Distributable cash from operations is not a measure under GAAP and there is no standard measure of distributable cash from operations. Distributable cash from operations, as presented, may not be comparable to similar measures presented by other trusts.

Distributable cash from operations is calculated as funds from operations less discretionary amounts withheld for capital expenditures.



Distributions ($000s) 2006 2005
---------------------------------------------------------------------------
Cash provided by operating activities 75,505 81,466
Settlement of asset retirement obligations 2,952 1,306
Changes in non-cash working capital relating to
operating activities 557 27,619
---------------------------------------------------------------------------
Funds from operations 79,014 110,391
Cash used to fund capital expenditures (32,388) (73,717)
---------------------------------------------------------------------------
Distributable cash from operations (1) 46,626 36,674
---------------------------------------------------------------------------
---------------------------------------------------------------------------

Cash distributions declared and payable, including
DRIP at December 31, 2006 6,035 6,595
Cash distributions paid in the period 40,591 30,079
---------------------------------------------------------------------------
Accumulated cash distributions paid and payable 46,626 36,674
---------------------------------------------------------------------------
---------------------------------------------------------------------------
(1) Distributable cash from operations will differ from cash distributions
to unitholders on the Consolidated Statement of Cash Flows due to the
timing of distribution announcements versus the cash payment of
distributions.


Sustainability of Distributions and the Asset Base

As an oil and gas trust, the Trust has a declining asset base and therefore relies on acquisitions and ongoing development activities to replace production and add additional reserves. Future oil and natural gas reserves are highly dependent on the successful exploitation of the asset base or the acquisition of new reserves. To the extent that the Trust is unsuccessful in these activities, cash available for distributions could be reduced.

Acquisitions and development activities may be funded internally by withholding a portion of cash flow or though external sources of capital such as debt or the issuance of equity. To the extent the Trust is required to withhold cash flow to finance these activities, the amount of cash available for distribution will be reduced. Should external sources of capital become limited or unavailable, the ability to make the necessary acquisitions and development expenditures to maintain or expand the Trust's asset base may be impaired and the amount of cash available for distribution will be reduced.

Distribution Policy

The amount of cash available for distribution is proposed by management and approved by the Board of Directors. Distribution levels are continually assessed with respect to forecasted funds from operations, debt levels and capital spending plans. The level of cash withheld can vary and is dependent upon numerous factors, the most significant of which are: the prevailing commodity price environment, current levels of production, debt obligations, the Trust's access to equity markets and the funding requirements for its development capital program. Although the Trust intends to continue to make cash distributions to unitholders, these distributions are not guaranteed.

On October 31, 2006, the Government of Canada announced proposed legislation that, if enacted, will impose a tax on the Trust of 31.5% on cash distributions paid to unitholders. Income trusts that are publicly traded prior to November 2006 will not be impacted by this proposed legislation until 2011. If this proposed legislation is implemented, it will have an impact on distributable cash and the payout ratio.



Distributions Declared ($000s)

Distributions per unit
2006 2005
---------------------------------------------------------------------------
Cash distributions declared and payable per unit $ 0.12 $ 0.15
Cash distributions declared and paid per unit $ 1.44 $ 0.75
---------------------------------------------------------------------------
Accumulated cash distributions per unit $ 1.56 $ 0.90
---------------------------------------------------------------------------
---------------------------------------------------------------------------


Accumulated
distributions (000s) Cash distributions DRIP Total
---------------------------------------------------------------------------
July distribution 6,301 - 6,301
August distribution 6,394 - 6,394
September distribution 6,419 - 6,419
October distribution 6,515 - 6,515
November distribution 4,450 2,072 6,522
December distribution 4,283 2,312 6,595
---------------------------------------------------------------------------
Balance December 31, 2005 34,362 4,384 38,746
---------------------------------------------------------------------------
January distribution 4,501 2,248 6,749
February distribution 4,127 2,705 6,832
March distribution 3,554 3,350 6,904
April distribution 3,543 3,428 6,971
May distribution 2,907 2,722 5,629
June distribution 2,987 2,716 5,703
July distribution 3,029 2,731 5,760
August distribution 3,004 2,795 5,799
September distribution 3,075 2,765 5,840
October distribution 2,784 3,120 5,904
November distribution 2,797 3,168 5,965
December distribution 2,992 3,043 6,035
---------------------------------------------------------------------------
2006 distributions 39,300 34,791 74,091
---------------------------------------------------------------------------
Balance December 31, 2006 73,662 39,175 112,837
---------------------------------------------------------------------------
---------------------------------------------------------------------------


Tax Treatment of Distributions

The Trust has provided to unitholders general comments regarding the taxability of distributions but does not intend to provide legal or tax advice. Trust unitholders, exchangeable shareholders, or potential investors should seek their own legal or tax advice in this regard.

Related Party Transactions

During the year, the Trust incurred expenditures of $0.5 million (2005 - $1.0 million) for general corporate legal fees to a legal firm of which a director is a partner. These legal fees were included in general and administrative expenses, convertible debenture issue costs, property and equipment and unit issue costs. At December 31, 2006, $1,750 (2005 - $10,000) remained outstanding. The related party transactions were provided in the normal course of business under the same terms and conditions as transactions with unrelated companies.

Contractual Obligations, Commitments and Guarantees

The Trust has assumed various contractual obligations and commitments in the normal course of operations and financing activities. These obligations and commitments have been considered when assessing cash requirements and in the analysis of future liquidity.



Payments
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Greater
Less than than
($000s) Total 1 year 1-3 years 4-5 years 5 years
---------------------------------------------------------------------------
Firm transportation $ 1,243 $ 500 $ 743 $ - $ -
Power contract 1,221 1,051 170 - -
Office and vehicle leases 12,205 2,022 6,326 3,857 -
---------------------------------------------------------------------------
Total $ 14,669 $ 3,573 $ 7,239 $ 3,857 $ -
---------------------------------------------------------------------------
---------------------------------------------------------------------------


Corporate Restructuring

On July 7, 2005, and in accordance with the Plan of Arrangement announced on May 3, 2005, Thunder Energy amalgamated with Mustang and Forte to form the Trust, two exploration companies, Clipper and Valiant, and a coalbed methane company, Ember.

The consideration for the Mustang acquisition was 1.1 trust units for each Mustang share resulting in 9.6 million trust units and 1.0 million exchangeable shares being issued. The value assigned to each trust unit was $7.60 based on the Thunder Energy share price at the time the Arrangement was announced. The value of the transaction was $161.2 million before the $24.5 million reduction for the conveyance of certain Mustang assets and liabilities to Clipper.

The consideration for the Forte acquisition was 0.35 trust units for each Forte share resulting in 6.5 million trust units and 1.0 million exchangeable shares being issued. The value assigned to each trust unit was $7.60 based on the Thunder Energy share price at the time the Arrangement was announced. The value of the transaction was $113.5 million, net of the $35.1 million reduction for the conveyance of certain Forte assets and liabilities to Valiant prior to the amalgamation.

In conjunction with the Plan of Arrangement, Thunder Energy transferred certain assets and undeveloped land to Ember and Clipper. At the time of the transaction the companies were related, and consequently, the assets were transferred to Ember and Clipper at the Thunder Energy carrying values which, for the assets acquired by Thunder Energy from Forte and Mustang, were fair market value. As part of the Arrangement, both Ember and Clipper paid $5.0 million to the Trust, which is accounted for as a reduction in capital in each entity.

Financial Reporting Update

For fiscal years beginning on or after October 1, 2006, the new Canadian Institute of Chartered Accountants ("CICA") Handbook section 3855 "Financial Instruments - Recognition and Measurement", section 1530 "Comprehensive Income" and section 3865 "Hedges" that deal with the recognition and measurement of financial instruments at fair value and comprehensive income will come into effect. The new standards are intended to harmonize Canadian standards with United States and international accounting standards. Management has assessed the impact of these pronouncements on the Trust's operating results and concluded they are not material.



Fourth Quarter Overview
-----------------------

Three Months Ended
Financial December 31 %
($000s, except per share data) 2006 2005 Change
---------------------------------------------------------------------------

Petroleum and natural gas sales 40,879 67,833 (40)
Funds from operations(1) 18,530 39,587 (53)
per unit - basic ($) 0.37 0.86 (57)
- diluted ($) 0.35 0.85 (59)
Net loss (130,195) (25,433) (412)
per unit - basic ($) (2.61) (0.55) (375)
- diluted ($) (2.61) (0.55) (375)

Capital expenditures 26,502 24,456 (8)
Distributions declared 17,904 19,632 (9)
Distributions declared per unit ($) 0.36 0.45 (20)
Payout ratio(2) before DRIP 97% 50% 94
Payout ratio(2) after DRIP 46% 39% 18

Total debt including working capital
deficiency 204,225 154,643 32
Weighted average units outstanding (basic) 49,863 45,990 8
Weighted average units outstanding (diluted) 49,863 46,332 8
---------------------------------------------------------------------------

Three Months Ended
Operations December 31 %
2006 2005 Change
---------------------------------------------------------------------------

Daily production
Natural gas (mcf/d) 35,594 40,489 (12)
Crude oil and NGL (bbls/d) 3,346 4,312 (22)
Barrels of oil equivalent (boe/d) 9,279 11,060 (16)
Average sale price(3)
Natural gas ($/mcf) 6.65 11.11 (40)
Crude oil and NGL ($/bbl) 56.10 62.64 (10)
Wells drilled - gross (net)
Gas 5 (1.6) 23 (19.3)
Oil 2 (0.1) 7 (2.2)
Dry - (-) 18 (10.3)
Total 7 (1.7) 48 (31.8)
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Barrels of oil equivalent are reported with a 6:1 conversion with six mcf
equals one barrel
(1) Non-GAAP financial measure defined as cash provided by operating
activities before changes in non-cash working capital relating to operating
activities and the settlement of asset retirement obligations
(2) The payout ratio is calculated using distributions declared divided by
funds from operations.
(3) Average sale price at the wellhead before commodity contracts gain or
loss.


Results of Operations

Gross oil and gas revenues decreased 40% to $40.9 million in fourth quarter 2006 compared to 2005. The decrease is due to lower commodity prices (a 40% decrease in natural gas prices and a 10% decrease in crude oil and NGL prices) compared to the same period in 2005, as well as a 16% decline in overall production.

Commodity prices received by the Trust are based on the respective reference prices for both crude oil and natural gas adjusted for transportation and quality differentials, as applicable, and foreign exchange. The average price for crude oil and NGL in the quarter decreased 10% from fourth quarter 2005. The benchmark Edmonton posted oil price averaged $64.49 per bbl in the fourth quarter of 2006, a 9% decrease from fourth quarter 2005. The Trust's average natural gas price for the fourth quarter decreased 40% from the same period in 2005. The benchmark AECO gas price averaged $6.74 per mmbtu in the fourth quarter of 2006, a 41% decrease from fourth quarter 2005.

Transportation expenses for the fourth quarter increased 15% from 2005 to $1.8 million due to additional clean oil hauling charges in northern Alberta and Saskatchewan due to temporary pipeline closures and quotas.

Royalties as a percentage of revenue were 18.2% a 2% decrease from the fourth quarter of 2005 due to strong commodity pricing in 2005.

Operating costs increased 2% to $10.0 million or $11.76 per boe in fourth quarter 2006 from the same period in 2005. The Trust's operating costs are a reflection of high costs across the industry and the Trust's increased presence in northeast British Columbia and Northern Alberta which have higher operating costs. The Trust performed plant turnarounds which contributed to higher operating costs per boe as well as experiencing higher power costs.

Gross general and administrative expenses (G&A) were $4.2 million or $4.88 per boe in the fourth quarter of 2006. This is a 30% increase over 2005 due to increased compensation necessary to continue to attract and retain qualified personnel in a highly competitive market as well as unbudgeted costs related to the Federal government's October 31, 2006 announcement to apply a tax on distributions from publicly-traded income trusts. Also included in G&A are costs relating to documenting internal controls to meet regulatory requirements. For the fourth quarter of 2006 these costs totaled $0.1 million or $0.14 per boe.

Financial charges increased 83% over fourth quarter 2005 to $3.4 million from $1.9 million in 2005 due to higher debt comprised of bank debt and convertible debentures as well as higher interest rates.

Interest expense on bank debt decreased 5% over fourth quarter 2005 to $1.8 million due to lower bank debt in the quarter offset by higher interest rates.

Convertible debenture interest was $1.4 million for the fourth quarter 2006. Thunder issued convertible debentures of $75.0 million during the second quarter of 2006. The net proceeds of $71.6 million were used to repay bank debt.




Three months Three months
ended ended
December 31, December 31,
Financial charges ($000s) 2006 2005
---------------------------------------------------------------------------
Bank debt interest 1,757 1,856
Convertible debenture interest 1,383 -
Amortization of deferred financing costs 191 -
Accretion of convertible debenture liability 72 -
---------------------------------------------------------------------------
Total financial charges 3,403 1,856
---------------------------------------------------------------------------
---------------------------------------------------------------------------


Depletion, depreciation and accretion (DD&A) expenses increased to $21.8 million or $25.56 per boe up $3.88 per boe from the fourth quarter of 2005. The DD&A rate increased due to a reduction in proved reserves at December 31, 2006. Accretion and DD&A expense on asset retirement obligations increased due to revisions made to the Trust's liability estimate for changes to the inflation rate and the credit-adjusted risk-free rate.

Write-down of Oil and Gas Assets

The carrying value of the Trust's petroleum and natural gas property and equipment is limited to the amount calculated under the ceiling test at the balance sheet date. At December 31, 2006, the calculation indicated the carrying value of the Trust's petroleum and natural gas property and equipment was in excess of the amount calculated under the ceiling test, accordingly, a write-down in the amount of $102.0 million (2005 - $56.2 million) has been recorded. This write-down is primarily the result of downward revisions in the Trust's petroleum and natural gas reserves, as estimated by independent engineers as of December 31, 2006. The ceiling test calculation was based on benchmark reference prices adjusted for the Trust's quality and transportation differentials discounted at an interest rate of 6.4% (2005 - 6.8%) over the estimated reserve life.

Goodwill

The Trust has assessed goodwill for impairment at December 31, 2006 and has recorded a write-down of $58.6 million (2005 - nil) during the fourth quarter.

Unit-based compensation expense decreased 47% to $0.4 million in the fourth quarter 2006 from the same period in 2005. The compensation liability was based on the December 31, 2006 unit closing price of $5.67, distributions of $0.12 per unit per month for the quarter, and management's estimate of the number of RTUs and PTUs to be issued on maturity.

Funds from operations decreased 53% to $18.5 million in the fourth quarter 2006 over the same periods in 2005 reflecting lower commodity prices and production as well as increased operating and G&A expenses.

Net loss

The Trust experienced a loss of $130.2 million in the fourth quarter 2006 due to a write-down of $102.0 million of the full cost pool due to a decline in the Trust's reserves as well as a $58.6 million write-down of goodwill, offset by a future tax recovery of $71.6 million related to the tax effect of the write-downs as well as the taxability of distributions and future tax rate reductions.



Quarterly Information

Quarterly Information 2005
($000s, except per unit data) Q1 Q2 Q3 Q4
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Petroleum and natural gas sales 29,350 32,729 65,866 67,833
Funds from operations(2) 16,599 19,168 35,037 39,587
Per unit ($)
Basic 0.64 0.74 0.79 0.86
Diluted 0.63 0.73 0.79 0.85
Net income 3,243 4,621 7,718 (25,433)
Per unit ($)
Basic 0.13 0.18 0.18 (0.55)
Diluted 0.12 0.18 0.17 (0.55)
Daily production
Natural gas (mcf/d) 38,174 37,978 44,680 40,489
Oil and NGL (bbls/d) 1,145 1,190 4,128 4,312
Barrels of oil equivalent (boe/d) 7,508 7,520 11,574 11,060
Average sale price(1)
Natural gas ($/mcf) 6.74 7.41 9.13 11.11
Oil and NGL ($/bbl) 48.67 49.81 69.90 62.64
Capital expenditures 32,579 10,131 21,228 24,456

2006
Q1 Q2 Q3 Q4
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Petroleum and natural gas sales 46,242 41,504 41,352 40,879
Funds from operations(2) 22,813 18,894 18,777 18,530
Per unit ($)
Basic 0.50 0.40 0.39 0.37
Diluted 0.49 0.36 0.36 0.35
Net income 3,725 18,744 8,260 (130,195)
Per unit ($)
Basic 0.08 0.39 0.17 (2.61)
Diluted 0.08 0.36 0.17 (2.61)
Daily production
Natural gas (mcf/d) 36,572 34,001 34,178 35,594
Oil and NGL (bbls/d) 3,910 3,640 3,532 3,346
Barrels of oil equivalent (boe/d) 10,005 9,307 9,229 9,279
Average sale price(1)
Natural gas ($/mcf) 7.40 5.83 5.79 6.65
Oil and NGL ($/bbl) 57.34 67.21 68.51 56.10
Capital expenditures 18,183 21,530 20,729 26,502
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(1) Average sale price at the wellhead before commodity contracts gain or
loss.
(2) Funds from operations is calculated as cash from operating activities
before the settlement of asset retirement obligations and changes in
non-cash working capital relating to operating activities.


Disclosure Controls and Procedures

Disclosure controls and procedures have been designed to ensure that information required to be disclosed by the Trust is accumulated and communicated to the Trust's management as appropriate to allow timely decisions regarding required disclosure. The Trust's Chief Executive Officer and Chief Financial Officer have concluded, based on their evaluation, the Trust's disclosure controls and procedures for the years ended December 31, 2006 and 2005, are effective to provide reasonable assurance that material information related to the Trust, including its consolidated subsidiaries, is made known to them by others within those entities. It should be noted that while the Trust's Chief Executive Officer and Chief Financial Officer believe that the Trust's disclosure controls and procedures provide a reasonable level of assurance that they are effective, they do not expect that the disclosure controls and procedures will prevent all errors and fraud. A control system, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met.

Management's Conclusion on the Design of Internal Controls over Financial Reporting

Internal controls have been designed to provide reasonable assurance regarding the reliability of the Trust's financial reporting and the preparation of financial statements together with other financial information for external purposes in accordance with Canadian GAAP. The Trust's Chief Executive Officer and Chief Financial Officer have designed, or caused to be designed under their supervision, internal controls over financial reporting related to the Trust, including its consolidated subsidiaries.

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.

Critical Accounting Estimates

The significant accounting policies used by the Trust are disclosed in Note 1 of the consolidated financial statements for the periods ended December 31, 2006 and 2005. Certain accounting policies require that management make appropriate decisions with respect to the formulation of estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. Management reviews its estimates on a regular basis. The emergence of new information and changed circumstances may result in actual results or changes to the estimated amounts that differ materially from current estimates. The following discussion helps to assess the critical accounting policies and practices of the Trust and the likelihood of materially different results being reported.

Oil and Gas Accounting - Reserves Determination

Under the National Instrument 51-101 ("NI 51-101") "proved" reserves are defined as those reserves that can be estimated with a high degree of certainty to be recoverable. The level of certainty should result in at least 90% probability that the quantities actually recovered will equal or exceed the estimated proved reserves.

"Proved plus probable" reserves are the most likely case and are based on a 50% certainty that they will equal or exceed the reserves estimated. The new standard provides for a more conservative evaluation of proved and probable reserves, particularly on new wells where production history has not yet been established.

The Trust follows the full cost method of accounting for its oil and gas activities, as described in Note 1 to the consolidated financial statements. Full cost accounting depends on the estimated proved reserves that the Trust believes are recoverable from its oil and gas properties. The process of estimating reserves is complex. It requires significant judgments and decisions based on available geological, geophysical, engineering, and economic data. These estimates may change substantially as additional data from ongoing development activities and production performance becomes available and as economic conditions impacting oil and gas prices and costs change. Reserve estimates are based on current production forecasts, prices and economic conditions. The Trust's reserves are evaluated by an independent engineering firm (GLJ Petroleum Consultants).

Reserve estimates are critical to many of the Trust's accounting estimates, including:

- Calculating unit-of-production depletion rates and asset retirement obligations. Proved reserve estimates are used to determine rates that are applied to each unit-of-production in calculating depletion expense.

- Assessing the Trust's oil and gas assets for possible impairment. Estimated future undiscounted cash flows are determined using proved reserves. The criteria used to assess impairment, including the impact of changes in reserve estimates, are discussed below.

As circumstances change and additional data becomes available, reserve estimates also change, possibly materially impacting net income. Estimates made are reviewed and revised, either upward or downward, as warranted by the new information. Revisions are often required due to changes in well performance, prices, economic conditions and governmental restrictions.

Although every reasonable effort is made to ensure the reserve estimates are accurate, reserve estimation is an inferential science. As a result, subjective decisions, new geological or production information and a changing environment may impact these estimates. Revisions to the Trust's reserve estimates can arise from changes in year-end oil and gas prices, and reservoir performance. Such revisions can be either positive or negative.

Ceiling Test

Under full cost accounting, a ceiling test is performed to ensure that unamortized capitalized costs in each cost centre do not exceed their fair value. Impairment is recognized when the carrying amount is greater than the undiscounted future net revenues, at which time assets are written down to the fair value of proved and probable reserves plus the cost of unproven properties, net of impairment allowances. Fair value is determined by discounting expected future product prices and costs.

Depletion and Depreciation

The Trust uses the full cost method of accounting for exploration and development activities whereby all costs associated with these activities are capitalized, whether successful or not. The aggregate of capitalized costs, net of certain costs related to unproven properties, and estimated future development costs is amortized using the unit-of-production method based on estimated proved reserves. Changes in estimated proved reserves or future development costs have a direct impact on depletion and depreciation expense. Certain costs related to unproven properties and major development projects may be excluded from costs subject to depletion until proved reserves have been determined or their value impaired. These properties are reviewed quarterly to determine if proved reserves should be assigned, at which point they would be included in the depletion calculation, or for impairment, for which any write-down would be charged to depletion and depreciation or, if significant, disclosed separately on the consolidated statement of loss.

Goodwill

Goodwill represents the excess of the purchase price on corporate acquisitions over the fair value of net assets acquired. Goodwill is assessed for impairment at least annually. If it is determined that the fair value of the assets and liabilities is less than the book value at the time of assessment, an impairment amount is determined by deducting the fair value from the book value and applying it against the book value of goodwill. Any excess of the book value of goodwill over the implied fair value is the impairment amount and will be charged to income in the period of the impairment.

Asset Retirement Obligations

The Trust records the fair value of an asset retirement obligations as a liability in the period in which it incurs a legal obligation associated with the retirement of tangible long-lived assets that result from the acquisition, construction, development, and/or normal use of the assets. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset and depleted and depreciated using a unit-of-production method over estimated proved reserves. Subsequent to the initial measurement of the asset retirement obligations, the obligations are adjusted at the end of each period to reflect the passage of time (accretion) and changes in the estimated future cash flows underlying the obligation.

Trust Unit Incentive Plans

The Trust approved a restricted unit plan and a performance unit incentive plan (the "Plans"). Under the terms of the Plans, both restricted and performance units ("RTUs" and "PTUs") may be granted to directors, officers, employees, consultants and service providers (the "Plan Participants") to the Trust and any of its subsidiaries.

Compensation expense associated with the Plans is granted in the form of RTUs and PTUs and is determined based on the intrinsic value of the trust units at each period end. The intrinsic value method is used as Plan Participants may be paid, at management's discretion, in cash or new units issued from treasury. This valuation incorporates the period end trust unit price, the number of RTUs and PTUs outstanding at each period end, and certain management estimates. As a result, large fluctuations, even recoveries, in compensation expense may occur due to changes in the underlying trust unit incentive price. In addition, compensation expense is amortized over the vesting period of the incentive plan with a corresponding increase or decrease in liabilities. Classification between current and long-term unit-based compensation liability is dependent upon expected payout dates.

Income Taxes

The determination of the Trust's income and other tax liabilities requires interpretation of complex laws and regulations often involving multiple jurisdictions. All tax filings are subject to audit and potential reassessment after lapse of considerable time. Accordingly, the actual income tax liability may differ significantly from the liability estimated or recorded.

Other Estimates

The accrual method of accounting requires management to incorporate certain estimates including estimates of revenues, royalties and production costs as at a specific reporting date but for which actual revenues and costs have not yet been received, and estimates on capital projects which are in progress or recently completed where actual costs have not been received at a specific reporting date.

The Trust ensures that the individuals with the most knowledge of the activity are responsible for the estimate. These estimates are then reviewed for reasonableness and past estimates are compared to actual results in order to make informed decisions on future estimates.

Risks and Uncertainties

Exploration, Development and Production Risks

Oil and natural gas exploration involves a high degree of risk, which even a combination of experience, knowledge and careful evaluation may not be able to overcome. There is no assurance that expenditures made on future exploration by the Trust will result in new discoveries of oil or natural gas in commercial quantities. It is difficult to project the costs of implementing an exploratory drilling program due to the inherent uncertainties of drilling in unknown formations, the cost associated with encountering various drilling conditions such as over-pressured zones and tools lost in the hole, and changes in drilling plans and locations as a result of prior exploratory wells or additional seismic data and interpretations thereof.

The long-term commercial success of the Trust depends on its ability to find, acquire, develop and commercially produce oil and natural gas reserves. No assurance can be given that the Trust will be able to continue to locate satisfactory properties for acquisition or participation. Moreover, if such acquisitions or participations are identified, the Trust may determine that current markets, terms of acquisition and participation or pricing conditions make such acquisitions or participations uneconomic.

Future oil and gas exploration may involve unprofitable efforts, not only from dry wells, but from wells that are productive but do not produce sufficient net revenues to return a profit after drilling, operating and other costs. Completion of a well does not assure a profit on the investment or recovery of drilling, completion and operating costs. In addition, drilling hazards or environmental damage could greatly increase the cost of operations, and various field operating conditions may adversely affect the production from successful wells. These conditions include delays in obtaining governmental approvals or consents, shut-ins of connected wells resulting from extreme weather conditions, insufficient storage or transportation capacity or other geological and mechanical conditions. While diligent well supervision and effective maintenance operations can contribute to maximizing production rates over time, production delays and declines from normal field operating conditions cannot be eliminated and can be expected to adversely affect revenue and cash flow levels to varying degrees.

In addition, oil and gas operations are subject to the risks of exploration, development and production of oil and natural gas properties, including encountering unexpected formations or pressures, premature declines of reservoirs, blow-outs, cratering, sour gas releases, fires and spills. Losses resulting from the occurrence of any of these risks could have a materially adverse effect on future results of operations, liquidity and financial condition.

Prices, Markets and Marketing of Crude Oil and Natural Gas

Oil and natural gas are commodities whose prices are determined based on world demand, supply and other factors, all of which are beyond the control of the Trust. World prices for crude oil and natural gas have fluctuated widely in recent years. Any material decline in prices could result in a reduction of net production revenue. Certain wells or other projects may become uneconomic as a result of a decline in world crude oil and natural gas prices, leading to a reduction in the volume of the Trust's oil and gas reserves. The Trust might also elect not to produce from certain wells at lower prices. All of these factors could result in a material decrease in the Trust's future net production revenue, causing a reduction in its oil and gas acquisition and development activities. In addition, bank borrowings available to the Trust are in part determined by the borrowing base of the Trust. A sustained material decline in prices from historical average prices could limit the Trust's borrowing base; therefore, reducing the bank credit available to the Trust, and could require that a portion of any of the Trust's existing bank debt be repaid.

In addition to establishing markets for its crude oil and natural gas, the Trust must also successfully market its crude oil and natural gas to prospective buyers. The marketability and price of crude oil and natural gas, which may be acquired or discovered by the Trust, will be affected by numerous factors beyond its control. The Trust will be affected by the differential between the price paid by refiners for light quality oil and the grades of oil produced by the Trust. The ability of the Trust to market its natural gas may depend upon its ability to acquire space on pipelines which deliver natural gas to commercial markets. The Trust will also likely be affected by deliverability uncertainties related to the proximity of its reserves to pipelines and processing facilities and related to operational problems with such pipelines and facilities and extensive government regulation relating to price, taxes, royalties, land tenure, allowable production, the export of crude oil and natural gas, and many other aspects of the crude oil and natural gas business. The Trust has limited direct experience in the marketing of crude oil and natural gas.

The Trust is also exposed to currency exchange risk arising from the fact that prices for crude oil and, to a lesser degree, natural gas, are determined in international markets, usually in US dollars. As a result, the amount received by the Trust may depend on the strength of the Canadian dollar versus the US dollar. The Trust has the ability to hedge its currency exposure to manage currency fluctuations but currently has no hedges of this type in place.

Substantial Capital Requirements; Liquidity

The Trust anticipates that it will make substantial capital expenditures for the acquisition, exploration, development and production of crude oil and natural gas reserves in the future. If the Trust's revenues or reserves decline, the Trust may have limited ability to expend the capital necessary to undertake or complete future drilling 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. Moreover, future activities may require the Trust to alter its capitalization significantly. The inability of the Trust to access sufficient capital for its operations could have a materially adverse effect on the Trust's financial condition, results of operations or prospects.

The Trust's lenders have been provided with security over substantially all of the assets of the Trust. If the Trust becomes unable to pay its debt service charges or otherwise commits an event of default, such as bankruptcy, these lenders may foreclose or sell the Trust's properties. The proceeds of any such sale would be applied to satisfy amounts owed to the Trust's lenders and other creditors and only the remainder, if any, would be available to the Trust.

An increase in interest rates would result in an increase in the amount the Trust pays to service debt, which could result in a decrease in distributions to unitholders, as well as impact the market price of trust units.

Competition

The Trust actively competes for reserve acquisitions, exploration leases, licenses and concessions and skilled industry personnel with a substantial number of other oil and gas companies, many of which have significantly greater financial and personnel resources than the Trust. The Trust's competitors include major integrated oil and natural gas companies and numerous other independent oil and natural gas companies and individual producers and operators.

Certain of the Trust's customers and potential customers are themselves exploring for oil and natural gas, and the results of such exploration efforts could affect the Trust's ability to sell or supply oil or gas to these customers in the future. The Trust's ability to successfully bid on and acquire additional property rights, to discover reserves, to participate in drilling opportunities and to identify and enter into commercial arrangements with customers will be dependent upon developing and maintaining close working relationships with its future industry partners and joint operators, and its ability to select and evaluate suitable properties and to consummate transactions in a highly competitive environment.

Environmental Risks

All phases of the oil and natural gas business present environmental risks and hazards and are subject to environmental regulation pursuant to a variety of international conventions and provincial, state and municipal laws and regulations. Environmental legislation provides for, among other things, restrictions and prohibitions on spills, releases, or emissions of various substances produced in association with oil and gas operations. The legislation also requires that wells and facility sites be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. Compliance with such legislation can require significant expenditures and a breach may result in the imposition of fines and penalties, some of which may be material. Environmental legislation is evolving in a manner expected to result in stricter standards and enforcement, larger fines and liabilities, and potentially increased capital expenditures and operating costs. No assurance can be given that environmental laws will not result in a curtailment of production or a material increase in the costs of production, development or exploration activities or otherwise adversely affect the Trust's financial condition, results of operations or prospects.

Insurance

The Trust's involvement in the exploration for and development of oil and gas properties may result in the Trust becoming subject to liability for pollution, blow-outs, property damage, personal injury or other hazards. Although the Trust has obtained insurance in accordance with industry standards to address such risks, such insurance has limitations on liability that may not be sufficient to cover the full extent of such liabilities. In addition, such risks may not, in all circumstances be insurable or, in certain circumstances, the Trust may elect not to obtain insurance to deal with specific risks due to the high premiums associated with such insurance or other reasons. The payment of such uninsured liabilities would reduce the funds available to the Trust. The occurrence of a significant event that the Trust is not fully insured against, or the insolvency of the insurer of such event, could have a materially adverse effect on the Trust's financial position, results of operations or prospects.

Kyoto Protocol

Canada is a signatory to the United Nations Framework Convention on Climate Change. Canada has ratified the Kyoto Protocol established thereunder. Annex B parties to the Kyoto Protocol, which includes Canada, are required to establish legally binding targets to reduce nation-wide emissions of carbon dioxide, methane, nitrous oxide, and other so-called "greenhouse gases". The Trust's exploration and production facilities and other operations and activities emit a small amount of greenhouse gases which may subject the Trust to legislation in Canada regulating emissions of greenhouse gases. The Government of Canada has put forward a Climate Change Plan for Canada which suggests further legislation to set greenhouse gases emission reduction requirements for various industrial activities, including oil and gas exploration and production. Future Canadian federal legislation, together with provincial emission reduction requirements, such as those proposed in the Climate Change and Emissions Management Act (Alberta), may require the reduction of emissions or emissions intensity from the Trust's operations and facilities. The direct and indirect costs of complying with these emissions regulations may adversely affect the business of the Trust.

Reserve Replacement

The Trust's future crude oil and natural gas reserves and production, and cash flows to be derived therefrom, are highly dependent on the Trust successfully acquiring or discovering new reserves. Without the continual addition of new reserves, any existing reserves the Trust may have at any particular time and the production therefrom will decline over time as such existing reserves are exploited. A future increase in the Trust's reserves will depend not only on the Trust's ability to develop any properties it may have from time to time, but also on its ability to develop any producing properties or prospects. There can be no assurance that the Trust's future exploration and development efforts will result in the discovery of additional commercial accumulations of crude oil and natural gas.

Reliance on Operators and Key Employees

To the extent the Trust is not the operator of its oil and gas properties, the Trust will be dependent on such operators for the timing of activities related to such properties and will largely be unable to direct or control the activities of the operators. In addition, the success of the Trust will be largely dependent upon the performance of its management and key employees. The Trust does not have any key man insurance policies; therefore, there is a risk that the death or departure of any member of management or any key employee could have a materially adverse effect on the Trust.

Permits and Licenses

The operations of the Trust may require licenses and permits from various governmental authorities. There can also be no assurance that the issuer will be able to obtain all necessary licenses and permits that may be required to carry out exploration and development at its projects.

Additional Funding Requirements

The Trust's cash flow from its reserves may not be sufficient to fund its ongoing activities at all times. From time to time, the Trust may require additional financing in order to carry out its oil and gas acquisition, exploration and development activities. Failure to obtain such financing on a timely basis could cause the Trust to forfeit interest in certain properties, miss certain acquisition opportunities and reduce or terminate its operations. If the Trust's revenue from its reserves decreases as a result of low crude oil and natural gas prices or otherwise, it will affect the Trust's ability to expend the necessary capital to replace its reserves or to maintain its production. If the Trust's cash flow from operations is not sufficient to satisfy its capital expenditure requirements, there can be no assurance that additional debt or equity financing will be available to meet these requirements or available on terms acceptable to the Trust.

From time to time, the Trust may enter into transactions to acquire assets or the shares of other corporations. These transactions may be financed partially or wholly with debt, which may increase the Trust's debt levels above industry standards. Neither the Trust's articles nor its by-laws limit the amount of indebtedness that the Trust may incur. The level of the Trust's indebtedness from time to time could impair the Trust's ability to obtain additional financing in the future on a timely basis to take advantage of business opportunities that may arise.

Title to Properties

Although title reviews are done according to industry standards prior to the purchase of most crude oil and natural gas producing properties or the commencement of drilling wells, such reviews do not guarantee or certify that an unforeseen defect in the chain of title will not arise to defeat the Trust's claim which could result in a reduction of the revenue received by the Trust.

Aboriginal Claims

Aboriginal people have claimed aboriginal title and rights to portions of western Canada. The Trust is not aware that any claims have been made in respect of its property and assets; however, if a claim arose and was successful this could have an adverse effect on the Trust and its operations.

Delays in Business Operations

In addition to the usual delays in payments by purchasers of crude oil and natural gas to the Trust or to the operators, and the delays by operators in remitting payment to the Trust, payments between these parties may be delayed due to restrictions imposed by lenders, accounting delays, delays in the sale or delivery of products, delays in the connection of wells to a gathering system, adjustments for prior periods, or recovery by the operator of expenses incurred in the operation of the properties. Any of these delays could reduce the amount of cash flow available for the business of the Trust in a given period and expose the Trust to additional third party credit risks.

Changes in Legislation

The return on an investment in securities of the Trust is subject to changes in Canadian federal and provincial tax laws and government incentive programs and there can be no assurance that such laws or programs will not be changed in a manner that adversely affects the Trust or the holding and disposing of the securities of the Trust.

Seasonality

The level of activity in the Canadian oil and gas industry is influenced by seasonal weather patterns. Wet weather and spring thaw may make the ground unstable. Consequently, municipalities and provincial transportation departments enforce road bans that restrict the movement of rigs and other heavy equipment; thereby, reducing activity levels. Also, certain oil and gas producing areas are located in areas that are inaccessible other than during the winter months because the ground surrounding the sites in these areas consists of swampy terrain. Seasonal factors and unexpected weather patterns may lead to declines in exploration and production activity and corresponding declines in the demand for the goods and services of the Trust.

Return of Capital

Trust units will have no value when Thunder's oil and gas properties can no longer be economically produced and, as a result, cash distributions do not represent a "yield" in the traditional sense and are not comparable to bonds or other fixed yield securities, where investors are entitled to a full return of the principal amount of debt on maturity in addition to a return on investment through interest payments. Distributions represent a combination of return of unitholders' initial investment and return on unitholders' initial investment.

Unitholders have a limited right to require the Trust to repurchase their trust units, which is referred to as a redemption right. It is anticipated that the redemption right will not be the primary mechanism for unitholders to liquidate their investment. The right to receive cash in connection with a redemption is subject to limitations.

Nature of Trust Units

Trust units do not represent a traditional investment in the oil and natural gas sector and should not be viewed as shares in Thunder Energy Inc. or its subsidiaries. Trust units represent a fractional interest in the Trust. As holders of trust units, unitholders will not have the statutory rights normally associated with ownership of shares of a corporation including, for example, the right to bring "oppression" or "derivative" actions. The Trust's sole assets are investments and notes receivable from Thunder Energy Inc. The price per trust unit is a function of anticipated distributable cash from operations, underlying assets and management's ability to effect long-term growth in value. The market price of the trust units will be sensitive to a variety of market conditions including, but not limited to, interest rates and the Trust's ability to acquire suitable oil and natural gas properties. Changes in market conditions may adversely affect the trading price of the trust units.

The trust units are not "deposits" within the meaning of the Canada Deposit Insurance Corporation Act (Canada) and are not insured under the provisions of that Act or any other legislation. Furthermore, the Trust is not a trust company and, accordingly, is not registered under any trust and loan company legislation as it does not carry on nor intend to carry on the business of a trust company.

Exchangeable Shares

An investment in exchangeable shares should be considered speculative due to the fact that adjustments to the exchange ratio are made assuming reinvestment of distributions or dividends, as applicable, at the prevailing market price of a trust unit at the time at which any such distributions are made on the trust units or any such dividends are paid on the exchangeable shares. As a result, the cumulative return on an investment in exchangeable shares may be higher or lower than that on an investment in trust units over a comparable period.

Unitholder Limited Liability

The Trust Indenture provides that no unitholder will be subject to any liability in connection with the Trust or its obligations and affairs and, in the event that a court determines unitholders are subject to any such liabilities, the liabilities will be enforceable only against, and will be satisfied only out of the Trust's assets. Pursuant to the Trust Indenture, the Trust will indemnify and hold harmless each unitholder from any costs, damages, liabilities, expenses, charges and losses suffered by a unitholder resulting from or arising out of such unitholder not having such limited liability.

The Trust Indenture provides that all written instruments signed by or on behalf of the Trust must contain a provision to the effect that such obligation will not be binding upon unitholders personally. Personal liability may also arise in respect of claims against the Trust that do not arise under contracts, including claims in tort, claims for taxes and possibly certain other statutory liabilities. The possibility of any personal liability of this nature arising is considered unlikely.

The Trust's operations will be conducted, upon the advice of counsel, in such a way and in such jurisdictions as to avoid as far as possible any material risk of liability on the unitholders for claims.

In addition the Income Trust Liability Act (Alberta) was proclaimed in force in Alberta on June 30, 2004. The Income Trust Liability Act (Alberta) provides that the beneficiary of a trust that is (a) created by a trust instrument governed by the laws of Alberta, and (b) a reporting issuer as defined in the Securities Act (Alberta), is not liable as a beneficiary for any act, default, obligation or liability of the trustee.

Mutual Fund Trust Status

It is intended that the Trust qualify at all times as a mutual fund trust for the purposes of the Tax Act. The Trust may not, however, always be able to satisfy any future requirement for the maintenance of mutual fund trust status. Should the status of the Trust as a mutual fund trust be lost or successfully challenged by a relevant tax authority, certain adverse consequences may arise for the Trust and its unitholders. Some of the significant consequences of losing mutual fund trust status are as follows:

- where at the end of any month a registered retirement savings plan ("RRSP"), registered retirement income fund ("RRIF"), registered education savings plan ("RESP") or deferred profit sharing plan (collectively, "Exempt Plans") holds units that are not qualified investments, the Exempt Plan must, in respect of that month, pay a tax under Part XI.1 of the Tax Act equal to one percent of the fair market value of the units at the time such units were acquired by the Exempt Plan. An RRSP or RRIF holding units that are not qualified investments would become taxable on income attributable to the units while they are not qualified investments (including the entire amount of any capital gain arising on a disposition of the non-qualified investment). RESP's which hold units that are not qualified investments may have their registration revoked by the CRA.

- the Trust would be required to pay a tax under Part XII.2 of the Tax Act. The payment of Part XII.2 tax by the Trust may have adverse income tax consequences for certain unitholders, including non-resident persons and residents of Canada who are exempt from Part I tax.

- the Fund would cease to be eligible for the capital gains refund mechanism available under Canadian tax laws; and

- units would become taxable Canadian property. As a result, non-resident unitholders would be subject to Canadian income tax on any gains realized on a disposition of units held by them, subject to relief under an applicable tax convention. In addition, the Trust may take certain measures in the future to the extent that it believes such measures are necessary to ensure it maintains its status as a mutual fund trust. These measures could be adverse to certain holders of units.

Non-resident Ownership of Units

In order for the Trust to maintain its status as a mutual fund trust under the Tax Act, the Trust must not be established or maintained primarily for the benefit of non-residents of Canada ("non-residents") within the meaning of the Tax Act. Proposed amendments to the Tax Act originally published by the Minister of Finance (Canada) on March 22, 2004, were to provide that after December 31, 2004, the Trust must continuously ensure that not more than 50% of its issued units are held by non-residents of Canada or partnerships (other than "Canadian partnerships" as defined in the Tax Act). In December 2004 the Minister of Finance announced that these Proposed Amendments were not being included in draft legislation and that further discussions would be pursued with the private sector concerning the appropriate Canadian tax treatment of non-residents investing in resource property through mutual fund trusts. The Trust Indenture provides that at no time may non-residents be the beneficial owners of more than 49% of the trust units. If at any time the Trust or its administrator, Thunder Energy Inc., become aware that the activities of the Trust and/or ownership of units by non-residents may threaten the status of the Trust under the Tax Act as a "mutual fund trust", the Trust, by or through Thunder Energy Inc. on the Trust's behalf, is authorized to take such action as may be necessary in the opinion of Thunder Energy Inc. to maintain the status of the Trust as a "mutual fund trust".

Income Tax Matters

Generally, income trusts, including the Trust, involve significant amounts of intercompany debt, royalties or similar instruments, generating substantial interest expense or other deductions which serve to reduce taxable income and income tax payable. Although the Trust is of the view that all expenses claimed by the Trust and its subsidiaries will be reasonable and deductible and that the cost amount and capital cost allowance claims of such entities' depreciable properties will have been correctly determined, there can be no assurance that the taxation authorities will not seek to challenge the amount of interest expense and other deductions. If such a challenge were to succeed, it could materially adversely affect the amount of distributions available to the Trust. The Trust believes that the interest expense inherent in the structure of the Trust is supportable and reasonable.

Maintenance of Distributions

The Trust adds to its crude oil and natural gas reserves primarily through development and acquisitions with only a small percentage of the capital directed to exploration. As a result, future crude oil and natural gas reserves are highly dependent on the Trust's operating entities' success in exploiting existing properties and acquiring additional reserves. The Trust distributes a portion of its net cash flow to unitholders rather than reinvesting it in reserve additions. Accordingly, if external sources of capital, including the issuance of additional trust units, become limited or unavailable on commercially reasonable terms, the Trust's operating entities' ability to make the necessary capital investments to maintain or expand crude oil and natural gas reserves will be impaired. To the extent that the Trust's operating entitles are required to use cash flow to finance capital expenditures or property acquisitions, the level of cash flow available for distribution to unitholders will be reduced. Additionally, the Trust cannot guarantee that it will be successful in developing additional reserves or acquiring additional reserves on terms that meet its investment objectives. Without these reserve additions, the Trust's reserves will deplete and as a consequence, either production from, or the average reserve life of, the Trust's properties will decline. Either decline may result in a reduction in the value of trust units and in a reduction in cash available for distributions to unitholders.

Assessments of Value of Acquisitions

Acquisitions of oil and gas issuers and oil and gas assets are typically based on engineering and economic assessments made by independent engineers and the Trust's own assessments. Both these assessments will include a series of assumptions regarding such factors as recoverability and marketability of oil and gas, future prices of oil and gas and operating costs, future capital expenditures and royalties and other government levies which will be imposed over the producing life of the reserves. Many of these factors are subject to change and are beyond the Trust's control. In particular, the prices of and markets for crude oil and natural gas products may change from those anticipated at the time of making such assessment. In addition, all such assessments involve a measure of geologic and engineering uncertainty which could result in lower production and reserves than anticipated. Initial assessments of acquisitions may be based on reports by a firm of independent engineers that are not the same as the firm that the Trust uses for its year-end reserve evaluations.

Accounting Write-Downs as a Result of GAAP

Canadian GAAP requires that management apply certain accounting policies and make certain estimates and assumptions which affect reported amounts in the consolidated financial statements of the Trust. The accounting policies may result in non-cash charges to net income and write-downs of net assets in the financial statements. Such non-cash charges and write-downs may be viewed unfavorably by the market and result in an inability to borrow funds and/or may result in a decline in the trading price of the Trust's units.

Under GAAP, the net amounts at which petroleum and natural gas costs on a property or project basis are carried are subject to a cost-recovery test which is based in part upon estimated future net cash flow from reserves. If net capitalized costs exceed the estimated recoverable amounts, the Trust would have to charge the amounts of the excess to earnings. A decline in the net value of oil and natural gas properties could cause capitalized costs to exceed the cost ceiling, resulting in a charge against earnings.

Third Party Credit Risk

The Trust is or 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 failure could have a materially adverse effect on the Trust and its cash flow.



THUNDER ENERGY TRUST
CONSOLIDATED BALANCE SHEETS

As at December 31
($000s) 2006 2005
---------------------------------------------------------------------------

Assets (Note 5)

Current
Accounts receivable (Note 14) $ 35,470 $ 49,810
Commodity contracts (Note 12) 4,558 -
Prepaid expenses 3,381 1,219
---------------------------------------------------------------------------
43,409 51,029
Deferred financing costs (Note 7) 2,887 -
Property and equipment (Note 3) 558,372 658,069
Goodwill (Note 4) 49,702 108,292
---------------------------------------------------------------------------
$ 654,370 $ 817,390
---------------------------------------------------------------------------
---------------------------------------------------------------------------

Liabilities and Unitholders' Equity

Current
Bank indebtedness $ 2,931 $ 4,409
Distributions payable 6,035 6,595
Accounts payable and accrued liabilities (Note 14) 38,237 57,542
Future income taxes (Note 11) 1,395 -
Unit-based compensation (Note 9) 604 767
---------------------------------------------------------------------------
49,202 69,313

Bank debt (Note 5) 124,925 136,359
Convertible debentures (Note 6) 73,507 -
Unit-based compensation (Note 9) 1,049 528
Asset retirement obligations (Note 8) 28,771 24,774
Future income taxes (Note 11) 73,920 146,876
---------------------------------------------------------------------------
351,374 377,850
---------------------------------------------------------------------------
Commitments and contingencies (Note 16)

Unitholders' equity
Unitholders' capital (Note 9) 446,652 411,341
Equity component of convertible debentures (Note 6) 1,702 -
Contributed surplus (Note 9) 3,025 3,025
Accumulated earnings (deficit) (148,383) 25,174
---------------------------------------------------------------------------
302,996 439,540
---------------------------------------------------------------------------
$ 654,370 $ 817,390
---------------------------------------------------------------------------
See accompanying notes


On behalf of the Board:

"Signed" "Signed"
Douglas A. Dafoe John Clark
Director Director


THUNDER ENERGY TRUST
CONSOLIDATED STATEMENTS OF LOSS AND ACCUMULATED EARNINGS (DEFICIT)

Years ended December 31
($000s, except per unit data) 2006 2005
---------------------------------------------------------------------------

Revenues

Petroleum and natural gas sales $ 169,977 $ 195,778
Royalties, net of ARTC (30,254) (33,905)
Transportation expenses (5,615) (6,383)
---------------------------------------------------------------------------
Petroleum and natural gas sales, after royalties
and transportation 134,108 155,490
Realized net gain on commodity contracts (Note 12) 724 -
Unrealized net gain on commodity contracts (Note 12) 4,558 -
---------------------------------------------------------------------------
Petroleum and natural gas sales, net 139,390 155,490
---------------------------------------------------------------------------

Expenses
Operating 37,498 29,704
General and administrative (Note 15) 8,399 8,517
Unit-based compensation (Note 9) 1,659 8,582
Financial charges (Note 7) 10,425 5,357
Write-down of property and equipment (Note 3) 101,984 56,243
Write-down of goodwill (Note 4) 58,590 -
Depletion, depreciation and accretion 91,606 75,058
---------------------------------------------------------------------------
310,161 183,461
---------------------------------------------------------------------------

Loss before income taxes (170,771) (27,971)
Income tax recovery (Note 11) (71,305) (18,120)
---------------------------------------------------------------------------
Net loss for the year (99,466) (9,851)
Accumulated distributions (Note 10) (74,091) (38,746)
Accumulated earnings (deficit)
Beginning of year 25,174 73,771
---------------------------------------------------------------------------
End of year $(148,383) $ 25,174
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Net loss per unit (Note 9)
Basic & Diluted $ (2.07) $ (0.22)
---------------------------------------------------------------------------
---------------------------------------------------------------------------

See accompanying notes


THUNDER ENERGY TRUST
CONSOLIDATED STATEMENTS OF CASH FLOWS

Years ended December 31
($000s) 2006 2005
---------------------------------------------------------------------------
Operating Activities
Net loss for the year $ (99,466) $ (9,851)
Add items not requiring cash:
Amortization of deferred financing costs (Note 7) 539 -
Accretion on convertible debenture liability
(Note 7) 209 -
Unit-based compensation 1,659 8,582
Unrealized net gain on commodity contracts (4,558) -
Depletion, depreciation and accretion 91,606 75,058
Write-down of property and equipment (Note 3) 101,984 56,243
Write-down of goodwill (Note 4) 58,590 -
Future income taxes (Note 11) (71,549) (19,641)
Settlement of asset retirement obligations (2,952) (1,306)
Changes in non-cash working capital relating to
operating activities (Note 13) (557) (27,619)
---------------------------------------------------------------------------
Cash provided by operating activities 75,505 81,466
---------------------------------------------------------------------------

Financing Activities
Issue of units for cash, net of costs (62) 11,398
Convertible debenture issue costs (Note 7) (3,426) -
Proceeds on convertible debentures (Note 6) 75,000 -
Increase (decrease) in bank indebtedness (1,478) 2,841
Increase (decrease) in bank debt (11,434) 53,463
Cash distributions (Note 10) (40,591) (30,079)
Cash received on Plan of Arrangement (Note 2) - 10,000
---------------------------------------------------------------------------
Cash provided by financing activities 18,009 47,623
---------------------------------------------------------------------------

Investing Activities
Expenditures on property and equipment (86,944) (88,394)
Assumption of bank indebtedness (Note 2) - (49,728)
Changes in non-cash working capital related to
investing activities (Note 13) (6,570) 9,012
---------------------------------------------------------------------------
Cash used in investing activities (93,514) (129,110)
---------------------------------------------------------------------------
Net change in cash position - (21)
Cash - beginning of year - 21
---------------------------------------------------------------------------
- end of year $ - $ -
---------------------------------------------------------------------------
---------------------------------------------------------------------------

See accompanying notes


THUNDER ENERGY TRUST

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2006 and 2005

Thunder Energy Trust (the "Trust") is an open-ended, unincorporated investment trust governed by the laws of the province of Alberta. The principal undertaking of the Trust is to indirectly explore for, develop and hold interest in petroleum and natural gas properties through investments in securities of subsidiaries. Thunder Energy Inc. and its subsidiaries carry on the business of the Trust and directly own the petroleum and natural gas properties and assets related thereto. The Trust owns, directly and indirectly, 100% of the common shares (excluding the outstanding exchangeable shares) of Thunder Energy Inc.

The Trust was established as part of a Plan of Arrangement (the "Arrangement"), which became effective on July 7, 2005. The Arrangement gave effect to the transaction completed with Thunder Energy Inc. ("Thunder Energy"), Mustang Resources Inc. ("Mustang") and Forte Resources Inc. ("Forte") to combine the entities to create a new oil and gas trust, two exploration-focused production companies: Alberta Clipper Energy Inc. ("Clipper") and Valiant Energy Inc. ("Valiant"); and a resource-based coal bed methane company, Ember Resources Inc. ("Ember"). As a result of the combination, shareholders of Thunder Energy received 0.5 trust units or exchangeable shares of the Trust, 0.3333 common shares of Clipper and 0.3333 common shares of Ember.

The conversion of Thunder Energy to a trust has been accounted for on a continuity of interest basis. Accordingly, the consolidated financial statements for 2005 reflect the financial position, results of operations and cash flows as if the Trust had always carried on the business formerly carried on by Thunder Energy. The consolidated financial statements for the year ended December 31, 2005 reflect the results of operations and cash flows of Thunder Energy and its subsidiaries for the period January 1 to July 6, 2005 and the results of operations and cash flows of the Trust and its subsidiaries for the period July 7 to December 31, 2005. Due to the conversion into a trust, certain information included in the consolidated financial statements for prior periods may not be directly comparable.

1. Significant Accounting Policies

Basis of Business and Basis of Presentation

The Trust is involved in the exploration, development and production of petroleum and natural gas in British Columbia, Alberta and Saskatchewan. The consolidated financial statements of the Trust have been prepared in accordance with Canadian generally accepted accounting principles ("GAAP"). The preparation of financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements, and revenues and expenses during the reporting period. Actual results could differ from those estimated. Specifically, the amounts recorded for depletion, depreciation and accretion of oil and natural gas properties and equipment and asset retirement obligations are based on estimates. The ceiling test is based on estimates of proved reserves, production rates, oil and gas prices, future costs and other relevant assumptions. By their nature, these estimates are subject to measurement uncertainty and the effect on the financial statements of changes in such estimates in future periods could be significant.

Principles of Consolidation

The consolidated financial statements include the accounts of the Trust and its wholly owned subsidiaries. All intercompany transactions and balances have been eliminated.

Petroleum and Natural Gas Properties and Gas Plants and Related Facilities

The Trust follows the full cost method of accounting whereby all costs associated with the acquisition of and the exploration for and development of petroleum and natural gas reserves, whether productive or unproductive, are capitalized in one Canadian cost centre and charged to income as set out below. Such costs include lease acquisition, drilling, equipping, geological and geophysical costs and overhead expenses directly related to exploration and development activities. Certain salaries, benefits and general and administrative expenses related to acquisition, exploration and development activities are also included in the full cost pool.

Gains or losses are not recognized upon disposition of petroleum and natural gas properties unless crediting the proceeds against accumulated costs would result in a change in the rate of depletion of 20% or more.

Depletion and Depreciation

Depletion of petroleum and natural gas properties is provided on accumulated costs and future development costs associated with proved undeveloped reserves using the unit-of-production method based on estimated gross proved petroleum and natural gas reserves, as determined by independent engineers. For purposes of the depletion calculation, proved petroleum and natural gas reserves are converted to a common unit of measure on the basis of one barrel of oil or liquids being equal to six mcf of natural gas. Costs of acquiring and evaluating unproven properties are excluded from depletion calculations until it is determined whether or not proved reserves are attributable to the properties or impairment occurs.

Depreciation of gas plants and related facilities is calculated on a straight-line basis over their estimated useful lives of 15 years.

The Trust records other assets at cost and provides depreciation on the declining balance method at rates varying from 20% to 100% per annum which is designed to amortize the cost of the assets over their estimated useful lives.

Impairment

The Trust evaluates its petroleum and natural gas assets in each reporting period to determine that the costs are recoverable and do not exceed the fair value of the properties. If the sum of the undiscounted cash flows expected from the production of proved reserves plus the cost (less any impairment) of unproven properties exceeds the carrying value of the petroleum and natural gas assets plus future development costs associated with proved undeveloped reserves, the costs are considered recoverable. Cash flows are calculated based on third-party quoted forward prices, adjusted for the Trust's contract prices and quality differentials. If the carrying value of the petroleum and natural gas assets is not considered to be recoverable, an impairment loss is recognized to the extent that the carrying value plus future development costs associated with proved undeveloped reserves exceeds the sum of the discounted cash flows expected from the production of proved and probable reserves. The cash flows are estimated using future product prices and costs and then discounted.

The costs of unproven properties are excluded from the ceiling test calculation and subject to a separate impairment test.

Asset Retirement Obligations

The Trust records the fair value of an asset retirement obligation as a liability in the period in which it incurs a legal obligation associated with the retirement of tangible long-lived assets that result from the acquisition, construction, development, and/or normal use of the assets. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset and depleted and depreciated using a unit-of-production method over estimated gross proved reserves. Subsequent to the initial measurement of the asset retirement obligations, the obligations are adjusted at the end of each period to reflect the passage of time (accretion) and changes in the estimated future cash flows underlying the obligation.

Goodwill

Goodwill, at the time of acquisition, represents the excess of the purchase price of a business over the fair value of net assets acquired; thereafter, goodwill is assessed for impairment at least annually. If the fair value of the reporting unit is less than the carrying amount, a second test is performed to determine the amount of the impairment. The amount of the impairment is determined by deducting the fair value of the reporting unit's tangible assets and liabilities from the fair value of the reporting unit to determine the implied fair value of goodwill and comparing that amount to the book value of goodwill. Any excess of the book value of goodwill over the implied fair value is the impairment amount and will be charged to income in the period of the impairment. Due to the nature of the Trust's operations, the Trust has only one reporting unit.

Joint Interest Operations

A portion of the Trust's petroleum and natural gas activities are conducted jointly with others. These consolidated financial statements reflect only the Trust's proportionate interest in such activities.

Revenue Recognition

Revenue from the sale of petroleum and natural gas is recognized during the month when title passes.

Trust Unit Incentive Plans

The Trust has established incentive plans for employees, officers, directors, consultants and other service providers. Compensation expense associated with the unit incentive plans is granted in the form of Restricted Trust Units ("RTUs") and Performance Trust Units ("PTUs") and is determined based on the intrinsic value of the trust units at each period end. The intrinsic value method is used as Plan Participants may be paid, at management's discretion, in cash or new units issued from treasury. This valuation incorporates the period end trust unit price, the number of RTUs and PTUs outstanding at each period end, and certain management estimates. As a result, large fluctuations, even recoveries, in compensation expense may occur due to changes in the underlying trust unit incentive price. In addition, compensation expense is amortized over the vesting period of the incentive plans with a corresponding increase or decrease in liabilities. Classification between current and long-term unit-based compensation liability is dependent upon the expected payout date. The Trust has not incorporated an estimated forfeiture rate for RTUs and PTUs that will not vest; rather, the Trust accounts for actual forfeitures as they occur.

Per Unit Amounts

Per unit amounts are calculated using the weighted average number of trust units outstanding during the period. Diluted per unit amounts are calculated using the treasury stock method to determine the dilutive effect of unit-based compensation. The Trust follows the treasury stock method, which assumes that the proceeds received from "in-the-money" trust unit rights and unrecognized future unit-based compensation expense are used to repurchase units at the average market rate during the period. Diluted per unit amounts also include exchangeable shares and convertible debentures using the "if-converted" method, whereby it is assumed the conversion of the exchangeable securities and convertible debentures occurs at the beginning of the reporting period (or at the time of issuance if later).

Income Taxes

The Trust is a mutual fund trust for purposes of the Tax Act (Canada), and is subject only to statutory income taxes on taxable income not distributed to unitholders. There is no recognition of future income tax assets or liabilities on temporary differences within the Trust; however, the asset and liability method of accounting for income taxes is followed within the subsidiaries of the Trust. Under this method, future tax assets and liabilities are determined based on differences between the financial reporting and tax bases of assets and liabilities, and measured using the substantively enacted tax rates and laws that will be in effect when the differences are expected to reverse. The effect on future tax assets and liabilities of a change in tax rates is recognized in income in the period in which the change becomes substantively enacted.

Hedging

The Trust is exposed to market risks resulting from fluctuations in commodity prices in the normal course of its business. The Trust may use a variety of instruments to manage these exposures. The Trust does not enter into financial instruments for trading or speculative purposes. For transactions where hedge accounting is not applied, the Trust accounts for such instruments using the fair value method by initially recording an asset or liability, and recognizing changes in the fair value of the instruments in income as an unrealized gain or loss on commodity contracts. Fair values of financial instruments are determined from third party quotes or valuations provided by independent third parties. Any realized gains or losses on commodity contracts are recognized in income in the period they occur. The Trust may elect to use hedge accounting when there is a high degree of correlation between the price movements in the financial instruments and the items designated as being hedged and it has documented the relationship between the instruments and the hedged item, its risk management objective and strategy, the method of assessing effectiveness and the method of accounting for the hedging relationship. The effectiveness of the hedging derivative is assessed on an ongoing basis to ensure that the derivative is highly effective in offsetting changes in fair value of the hedged items. Gains or losses from all hedging contracts, other than forward sales settled by physical delivery, are recognized as hedging gains or losses when the sale of hedged production occurs. In the event that a designated hedged item ceases to exist, any realized or unrealized gain or loss on such derivative commodity instrument is recognized in income immediately. If the hedge relationship is terminated, either via ineffectiveness or via termination of the designation, gains or losses previously deferred continue to be deferred and recognized when they are realized.

Comparative Amounts

Certain comparative amounts have been reclassified to conform to the presentation adopted for the current year.

2. Plan of Arrangement

On July 7, 2005, and in accordance with the Plan of Arrangement announced on May 3, 2005, Thunder Energy amalgamated with Mustang and Forte to form the Trust, two exploration companies, Clipper and Valiant, and a coalbed methane company, Ember. The amalgamation was accounted for as a business combination with Thunder Energy being deemed the acquirer of Mustang and Forte, net of the Valiant assets. Consequently the Trust has accounted for Mustang and Forte as acquisitions under the purchase method of accounting. Certain Mustang assets acquired by Thunder Energy were transferred to Clipper. As the former Thunder Energy shareholders had the majority of the voting control of Clipper, Ember and the Trust (including its subsidiaries), the transfer of assets and liabilities from Thunder Energy to Clipper and Ember was accounted for at Thunder Energy's net book value; the transfer of the Mustang assets to Clipper was at fair value, being Thunder Energy's acquisition cost.

The consideration for the Mustang acquisition was 1.1 trust units for each Mustang share resulting in 9.6 million trust units and 1.0 million exchangeable shares being issued. The value assigned to each trust unit was $7.60 based on the Thunder Energy share price at the time the Arrangement was announced. The value of the transaction was $161.2 million before the $24.5 million reduction for the conveyance of certain Mustang assets and liabilities to Clipper. The results of Mustang have been included in the consolidated financial statements commencing from the acquisition date. The final allocation of the purchase price was as follows:



Mustang net assets acquired ($000s)
---------------------------------------------------------------------------
Current assets $ 10,523
Property and equipment 200,683
Goodwill 38,500
Current liabilities (12,040)
Bank indebtedness (26,188)
Asset retirement obligations (5,019)
Future income tax liability (45,259)
---------------------------------------------------------------------------
$ 161,200
---------------------------------------------------------------------------
---------------------------------------------------------------------------

Value of units and exchangeable shares of the Trust issued $ 161,200
---------------------------------------------------------------------------
---------------------------------------------------------------------------


The consideration for the Forte acquisition was 0.35 trust units for each Forte share resulting in 6.5 million trust units and 1.0 million exchangeable shares being issued. The value assigned to each trust unit was $7.60 based on the Thunder Energy share price at the time the Arrangement was announced. The value of the transaction was $113.5 million, net of the $35.1 million reduction for the conveyance of certain Forte assets and liabilities to Valiant prior to the amalgamation. The results of Forte have been included in the consolidated financial statements commencing from the acquisition date. The final allocation of the purchase price was as follows:



Forte net assets acquired ($000s)
---------------------------------------------------------------------------
Current assets $ 13,577
Property and equipment 155,588
Goodwill 24,344
Current liabilities (14,280)
Bank indebtedness (23,540)
Asset retirement obligations (7,596)
Future income tax liability (34,590)
---------------------------------------------------------------------------
$ 113,503
---------------------------------------------------------------------------
---------------------------------------------------------------------------

Value of units and exchangeable shares of the Trust issued $ 113,503
---------------------------------------------------------------------------
---------------------------------------------------------------------------


In conjunction with the Plan of Arrangement, certain one-time external costs related to the reorganization of $8.7 million have been included as a capital cost and internal costs including $3.3 million in retention and severance have been charged to results of operations of the Trust. The costs related to the reorganization incurred by Mustang and Forte were reflected in the financial statements of those companies prior to the transaction date.

Under the Plan of Arrangement, Thunder Energy transferred certain assets and undeveloped land to Ember and Clipper. At the time of the transaction the companies were related, and consequently, the assets were transferred to Ember and Clipper at the Thunder Energy carrying values which, for the assets acquired by Thunder Energy from Forte and Mustang, were equal to fair market value. As part of the Arrangement, both Ember and Clipper paid $5.0 million to the Trust, which was accounted for as a reduction in capital for each entity.



The values transferred to Ember were as follows:

Ember net assets transferred ($000s)
---------------------------------------------------------------------------
Property and equipment $ 16,431
Future income tax asset 9,949
Asset retirement obligations (1,487)
---------------------------------------------------------------------------
Total assets transferred 24,893
Cash paid 5,000
---------------------------------------------------------------------------
Net assets transferred and reduction in capital $ 19,893
---------------------------------------------------------------------------
---------------------------------------------------------------------------

The values transferred to Clipper were as follows:

Clipper net assets transferred ($000s)
---------------------------------------------------------------------------
Property and equipment $ 53,388
Future income tax asset 7,041
Accounts payable (1,000)
Asset retirement obligations (1,841)
---------------------------------------------------------------------------
Total assets transferred 57,588
Cash paid 5,000
---------------------------------------------------------------------------
Net assets transferred and reduction in capital $ 52,588
---------------------------------------------------------------------------
---------------------------------------------------------------------------


In conjunction with the Plan of Arrangement, all outstanding stock options of Thunder Energy vested and option holders had the right to exercise their options until August 5, 2005 after which time the options expired. As a result, a stock-based compensation expense of $5.4 million was charged to the earnings of the Trust. Stock-based compensation of $0.6 million was apportioned to Ember ($0.2 million) and Clipper ($0.4 million) based on the relative reserve values of the proved and probable oil and natural gas reserves (discounted at 10%) as determined by independent reserve engineers.



3. Property and Equipment

2006

Accumulated
depletion and Net book
($000s) Cost depreciation value
---------------------------------------------------------------------------
Petroleum and natural gas properties $ 674,128 $ 215,928 $ 458,200
Gas plants and related facilities 137,588 38,620 98,968
Office equipment 1,812 608 1,204
---------------------------------------------------------------------------
$ 813,528 $ 255,156 $ 558,372
---------------------------------------------------------------------------
---------------------------------------------------------------------------


2005

Accumulated
depletion and Net book
($000s) Cost depreciation value
---------------------------------------------------------------------------
Petroleum and natural gas properties $ 709,222 $ 135,589 $ 573,633
Gas plants and related facilities 113,607 30,101 83,506
Office equipment 1,367 437 930
---------------------------------------------------------------------------
$ 824,196 $ 166,127 $ 658,069
---------------------------------------------------------------------------
---------------------------------------------------------------------------


At December 31, 2006 costs of $24.8 million (2005 - $16.3 million) related to unproven properties were excluded from the full cost pool.

In 2006, the Trust capitalized $3.9 million (2005 - $1.6 million) of overhead directly related to acquisition, exploration and development activities.

The carrying value of the Trust's petroleum and natural gas properties and gas plant and related facilities is limited to the amount calculated under the ceiling test at the balance sheet date. At December 31, 2006, the calculation indicated the carrying value of the Trust's petroleum and natural gas properties and equipment was in excess of the amount calculated under the ceiling test. Accordingly, a write-down in the amount of $102.0 million (2005 - $56.2 million) was recorded. This write-down is primarily the result of downward revisions in the Trust's petroleum and natural gas reserves, as estimated by independent engineers as at December 31, 2006. The ceiling test calculation was based on benchmark reference prices adjusted for the Trust's quality and price differentials discounted at an interest rate of 6.4% (2005 - 6.8%) over the estimated reserve life.



The following table summarizes the benchmark reference prices used in the
ceiling test calculation:

Edmonton Light AECO
Crude Oil NYMEX Natural Gas
WTI Oil 40 degree API Gas Price Price
Year ($US/bbl) ($Cdn/bbl) ($US/mmbtu) ($Cdn/mmbtu)
---------------------------------------------------------------------------

2007 62.00 70.25 7.25 7.20

2008 60.00 68.00 7.50 7.45

2009 58.00 65.75 7.50 7.75

2010 57.00 64.50 7.50 7.80

2011 57.00 64.50 7.50 7.85

Escalate
thereafter 2.0% per year 2.0% per year 2.0% per year 2.0% per year
---------------------------------------------------------------------------
---------------------------------------------------------------------------


4. Goodwill

The Trust assessed goodwill for impairment at December 31, 2006 and determined that the fair value of the reporting unit had declined due to the write-down of oil and gas assets, as described in Note 3, and thus recorded a write-down of $58.6 million (2005 - nil). The following table reconciles the goodwill balance:



($000s)
---------------------------------------------------------------------------
Balance December 31, 2004 45,448
Goodwill on Plan of Arrangement (Note 2) 62,844
---------------------------------------------------------------------------
Balance December 31, 2005 108,292
Write-down of goodwill (58,590)
---------------------------------------------------------------------------
Balance December 31, 2006 $ 49,702
---------------------------------------------------------------------------
---------------------------------------------------------------------------


5. Bank Debt

The Trust has a $160.0 million credit facility with a syndicate of chartered banks consisting of a $145.0 million extendible revolving term credit facility and a $15.0 million operating credit facility. The credit facilities are available on a revolving basis for a period of at least 364 days until April 30, 2007, and such initial term-out date may be extended for further 364 day periods at the request of the Trust, subject to approval by the banks. Following the term-out date, the facilities will be available on a non-revolving basis for a two-year term, payable in quarterly payments in the second year. The credit facilities bear interest at the lenders' prime rate, or bankers' acceptance rates plus an applicable margin, based on the debt to cash flow ratio. The credit facilities are collateralized by a $500.0 million demand debenture providing for a fixed and floating charge over the petroleum and natural gas properties and all other assets of the Trust and are subject to semi-annual review, at which time the lenders may re-determine the borrowing base. The effective annualized interest rate was 5.3% (2005 - 4.4%). Cash interest paid in the year was $5.7 million (2005 - $4.7 million).

6. Convertible Debentures

On April 5, 2006, the Trust issued $75.0 million principal amount of 7.25% Convertible Unsecured Subordinated Debentures (the "Debentures") for net proceeds of $71.6 million. The Debentures have a conversion price of $11.70 per trust unit and a maturity date of April 30, 2011. The Debentures pay interest semi-annually in arrears on April 30 and October 31 each year, commencing October 31, 2006. The Debentures will not be redeemable by the Trust prior to April 30, 2009. The Debentures are redeemable by the Trust, on not more than 60 days and not less than 30 days prior notice, at a price of $1,050 per Debenture after April 30, 2009 and on or before April 30, 2010, and at a price of $1,025 per Debenture after April 30, 2010 and before the maturity date, in each case, plus accrued and unpaid interest thereon, if any. On redemption or maturity the Trust may elect to satisfy its obligations to repay the principal and may satisfy its interest obligations by issuing trust units. The Debentures are traded on the Toronto Stock Exchange under the trading symbol THY.DB.

The Debentures have been classified as debt net of the fair value of the conversion feature at the date of issue, which has been classified as part of unitholders' equity. The debt portion will accrete up to the principal balance at maturity. Issue costs have been classified under deferred financing costs, which are being amortized over the term of the Debentures, or as part of the equity component. A reconciliation of deferred financing costs is included in Note 7. If the Debentures are converted into units, a portion of the value of the conversion feature under unitholders' equity will be reclassified to trust units along with the conversion price paid. The following table sets forth a reconciliation of the Debenture activity:



As at
Convertible debentures ($000s) December 31, 2006
---------------------------------------------------------------------------
Debt component on April 5, 2006 $ 73,298
Accretion of non-cash interest in the period 209
---------------------------------------------------------------------------
Debt portion, end of period 73,507
Equity component 1,702
---------------------------------------------------------------------------
Total Debentures, end of period $ 75,209
---------------------------------------------------------------------------
---------------------------------------------------------------------------

Cash interest paid in the year was $3.1 million (2005 - nil).


7. Financial Charges

During the years ended December 31, 2006 and 2005, the Trust incurred interest charges on bank debt and convertible debentures as well as the amortization of deferred financing costs and accretion of convertible debenture liability as follows:



Financial charges ($000s) 2006 2005
---------------------------------------------------------------------------
Bank debt interest $ 5,640 $ 5,357
Convertible debenture interest 4,037 -
Amortization of deferred financing costs 539 -
Accretion of convertible debenture liability 209 -
---------------------------------------------------------------------------
Total financial charges $ 10,425 $ 5,357
---------------------------------------------------------------------------
---------------------------------------------------------------------------

A reconciliation of deferred financing costs is provided as follows:

As at
Deferred financing costs ($000s) December 31, 2006
---------------------------------------------------------------------------
Balance, beginning of period -
Deferred financing costs 3,426
Amortization of deferred financing costs (539)
---------------------------------------------------------------------------
Balance, end of period 2,887
---------------------------------------------------------------------------
---------------------------------------------------------------------------


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 to be approximately $54.9 million which will be incurred up to 2034. The majority of the costs are expected to be incurred between 2010 and 2034. A credit-adjusted risk-free rate of 8.0% (2005 - 9%) and an inflation rate of 2.0% (2005 - 1.5%) were used to calculate the fair value of the asset retirement obligations. The Trust periodically reviews the assumptions used in its asset retirement obligations calculation. During the year, revisions were made to reflect changes in the inflation rate and the credit-adjusted risk-free rate.



A reconciliation of the asset retirement obligations is provided below:

Asset retirement obligations ($000s) 2006 2005
---------------------------------------------------------------------------
Balance, beginning of year $ 24,774 $ 13,417
Liabilities incurred in the year 800 1,758
Forte acquisition - 7,596
Mustang acquisition - 5,019
Revisions 3,571 (135)
Liabilities released to Ember and Clipper - (3,328)
Liabilities settled in the year (2,952) (1,306)
Accretion expense 2,578 1,753
---------------------------------------------------------------------------
Balance, end of year $ 28,771 $ 24,774
---------------------------------------------------------------------------
---------------------------------------------------------------------------


9. Unitholders' Capital

Trust units of Thunder Energy Trust (including Number of
the conversion of exchangeable shares) units (000s) ($000s)
---------------------------------------------------------------------------
Trust units outstanding (see (a) below) 50,295 $ 442,948
Trust units issuable on conversion of exchangeable
shares (see (b) below) 370 3,704
---------------------------------------------------------------------------
Balance December 31, 2006 50,665 $ 446,652
---------------------------------------------------------------------------
---------------------------------------------------------------------------


(a) Trust Units of Thunder Energy Trust

The Trust Indenture provides that an unlimited number of trust units may be authorized and issued. Each trust unit is transferable, carries the right to one vote and represents an equal undivided beneficial interest in any distributions from the Trust and in the assets of the Trust in the event of termination or winding-up of the Trust. All trust units are of the same class with equal rights and privileges.



Number of
Trust units units (000s) ($000s)
---------------------------------------------------------------------------
Balance December 31, 2004 - $ -
Issued for common shares of Thunder Energy 24,246 174,050
Issued on Forte acquisition (Note 2) 6,475 99,288
Issued on Mustang acquisition (Note 2) 9,607 123,810
Reduction of capital, Ember conveyance (Note 2) - (19,893)
Reduction of capital, Clipper conveyance (Note 2) - (28,047)
Issued for cash on exercise of stock options 1,921 19,332
Stock-based compensation on options - 7,080
Exchangeable shares converted 1,543 14,713
Unit issue costs, net of tax of $2,353 - (6,445)
Distribution reinvestment program 175 2,072
---------------------------------------------------------------------------
Balance December 31, 2005 43,967 $ 385,960
Exchangeable shares converted 2,000 21,677
Unit issue costs, net of tax of $12 - (50)
Distribution reinvestment program 4,224 34,060
Issued on exercise of Restricted Trust Units 104 1,301
---------------------------------------------------------------------------
Balance December 31, 2006 50,295 $ 442,948
---------------------------------------------------------------------------
---------------------------------------------------------------------------


Premium Distribution Reinvestment and Optional Trust Unit Purchase Plan ("Premium DRIP™")

The Trust has a Premium Distribution Reinvestment and Optional Trust Unit Purchase Plan ("Premium DRIP™") for eligible unitholders of the Trust. On distribution payment dates eligible Premium DRIP™ unitholders may receive in lieu of the cash distribution that unitholders are otherwise entitled to receive in respect of their units, a cash payment equal to 102% of such amount. Unitholders may also reinvest their cash distribution in additional Trust units at a price that is 95% of the Average Market Price for the Pricing Period. The Pricing Period refers to the period beginning on the later of the 21st business day preceding the distribution payment date and the second business day following the record date applicable to that distribution payment date, and ending on the second business day preceding the distribution payment date. The Average Market Price in respect of a particular Distribution payment date refers to the arithmetic average of the daily volume weighted average trading price of units traded during the corresponding Pricing Period. Eligible Premium DRIP™ unitholders may also make optional cash payments on this date to purchase additional trust units at a price that is equal to the average market price for the Pricing Period.

Distribution Reinvestment and Optional Trust Unit Purchase Plan ("DRIP")

The Trust has a Distribution Reinvestment and Optional Trust Unit Purchase Plan ("DRIP") for eligible unitholders of the Trust. On distribution payment dates eligible DRIP unitholders may reinvest their cash distributions in additional Trust units at a price that is 95% of the Average Market Price for the corresponding Pricing Period. Eligible DRIP unitholders may also make optional cash payments on this date to purchase additional trust units at a price that is equal to the 10-day weighted average trading price of trust units.

During the year, the Trust issued 4.2 million (2005 - 175,000) trust units from treasury for the DRIP which resulted in an increase to unitholders' capital of $34.1 million (2005 - $2.1 million).

Redemption Right

Unitholders may redeem their trust units for cash at any time, up to a maximum of $50,000 in any calendar month, by delivering their unit certificates to the Trustee, together with a properly completed notice of redemption. The redemption amount per trust unit will be the lesser of 90% of the market price of the trust units on the principal market on which they are quoted for trading during the 10-day trading period immediately prior to the date on which the trust units have been validly tendered for the redemption and the closing market price of the trust units on the principal market on which they are traded on the date on which they were validly tendered for redemption, or if there was no trade of the trust units on that date, the average of the highest and lowest prices of the trust units of the date.



(b) Exchangeable Shares of Thunder Energy Trust

Authorized: unlimited number of exchangeable shares

Number of
Exchangeable shares units (000s) ($000s)
---------------------------------------------------------------------------
Balance December 31, 2004 - $ -
Issued for common shares of Thunder Energy 1,759 13,030
Issued on Forte acquisition 927 14,215
Issued on Mustang acquisition 997 12,849
Exchanged for trust units (1,495) (14,713)
---------------------------------------------------------------------------
Balance December 31, 2005 2,188 $ 25,381
Exchanged for trust units (1,818) (21,677)
---------------------------------------------------------------------------
Balance December 31, 2006 370 $ 3,704
---------------------------------------------------------------------------
---------------------------------------------------------------------------


Exchangeable shares accrue notional distributions in-kind and are convertible into trust units at the shareholder's option. Exchangeable shares are non-transferable and are ultimately required to be exchanged for units of the Trust.

The exchangeable shares are not entitled to cash distributions. The Exchange Ratio increases on a monthly basis. The increase in Exchange Ratio is calculated by multiplying the Thunder Energy Trust distribution per unit by the Exchange Ratio immediately prior to Record Date and dividing by the weighted average trading price per unit of THY.UN on the TSX for the five trading days preceding the Record Date. A holder of Thunder Energy Inc. exchangeable shares can exchange all or a portion of their holdings into trust units, at any time by giving notice to their investment advisor or the Trust Agent. The Exchange Ratio to convert each exchangeable share to a trust unit was 1.00000 at the time of issuance. Effective December 15, 2006, the Exchange Ratio was 1.26071. If the 0.4 million exchangeable shares outstanding at December 31, 2006 were exchanged at that time, 0.5 million trust units would have been issued.



(c) Contributed Surplus

The following table reconciles the Trust's contributed surplus:

($000s)
---------------------------------------------------------------------------
Balance December 31, 2004 2,836
Stock-based compensation 7,287
Options exercised for trust units (7,098)
---------------------------------------------------------------------------
Balance December 31, 2006 and 2005 $ 3,025
---------------------------------------------------------------------------
---------------------------------------------------------------------------


(d) Trust Unit Incentive Plans

The Trust approved a restricted unit incentive plan and a performance unit incentive plan (the "Plans"). Under the terms of the Plans, both restricted and performance units ("RTUs" and "PTUs") may be granted to directors, officers, employees, consultants and service providers (the "Plan Participants") to the Trust and any of its subsidiaries.

Subject to the Board of Directors of the Trust's administrator, Thunder Energy, determining otherwise, (i) RTUs of the Trust vest evenly over three years, commencing on the first anniversary date of grant, with the number of trust units issued adjusted for the value of the distributions from the time of the granting to the time when the trust units are issued, and (ii) PTUs vest on the third anniversary date of the grant, adjusted for the value of the distributions, plus a further upward or downward adjustment based on the Trust's performance relative to the performance of a group of comparable publicly-traded oil and gas royalty trusts. Upon vesting and at management's option, the Plan Participant is entitled to receive either the units granted plus accumulated distributions or the cash payment based on the fair value of the underlying trust units plus notional accrued distributions. As such, the fair value associated with the RTUs and PTUs is expensed in the statement of loss over the vesting period. As the value of the RTUs and PTUs is dependent upon the trust unit price, the expense recorded in the consolidated statement of loss may vary from period to period.

The Trust recorded a compensation expense of $1.7 million for the year (2005 - $8.6 million) resulting in a current liability of $0.6 million and a long-term liability of $1.0 million. The decrease from prior year relates to the vesting of stock options on the formation of the Trust as described in Note 2. The compensation expense was based on the December 31, 2006 unit closing price of $5.67 per unit, distributions of $0.15 per unit from January to April and $0.12 per unit from May to December as well as management's estimate of the number of RTUs and PTUs to be issued on maturity. No estimate has been made for forfeitures as the Trust accounts for actual forfeitures as they occur. The following table summarizes the RTU and PTU movement for the year ended December 31, 2006.



RTUs PTUs
---------------------------------------------------------------------------
Balance December 31, 2004 - -
Granted 283 59
Exercisable - -
---------------------------------------------------------------------------
Balance December 31, 2005 283 59
Granted 242 107
Cancelled (43) (13)
Redeemed (104) -
---------------------------------------------------------------------------
Balance December 31, 2006 378 153
---------------------------------------------------------------------------
---------------------------------------------------------------------------

(e) Per Unit Amounts

The following table summarizes the weighted average basic and diluted trust
units and exchangeable shares used in calculating net loss per trust unit:

Trust units (000s) 2006 2005
---------------------------------------------------------------------------
Weighted average trust units 47,279 41,373
Exchangeable shares at exchange ratio 739 3,360
---------------------------------------------------------------------------
Trust units (basic) 48,018 44,733
Convertible debentures - -
Restricted and performance trust units - 205
---------------------------------------------------------------------------
Trust units (diluted) 48,018 44,938
---------------------------------------------------------------------------
---------------------------------------------------------------------------

The units issuable under the trust unit incentive plan and the convertible
debentures have been excluded since they would be anti-dilutive and thus
have not been included in the diluted per unit calculations for the year
ended December 31, 2006.

10. Accumulated Distributions

The table below shows the cumulative distributions for the Trust:

Accumulated distributions (000s) Cash distributions DRIP Total
---------------------------------------------------------------------------
July distribution $ 6,301 $ - $ 6,301
August distribution 6,394 - 6,394
September distribution 6,419 - 6,419
October distribution 6,515 - 6,515
November distribution 4,450 2,072 6,522
December distribution 4,283 2,312 6,595
---------------------------------------------------------------------------
Balance, December 31, 2005 34,362 4,384 38,746
---------------------------------------------------------------------------
January distribution 4,501 2,248 6,749
February distribution 4,127 2,705 6,832
March distribution 3,554 3,350 6,904
April distribution 3,543 3,428 6,971
May distribution 2,907 2,722 5,629
June distribution 2,987 2,716 5,703
July distribution 3,029 2,731 5,760
August distribution 3,004 2,795 5,799
September distribution 3,075 2,765 5,840
October distribution 2,784 3,120 5,904
November distribution 2,797 3,168 5,965
December distribution 2,992 3,043 6,035
---------------------------------------------------------------------------
2006 distributions 39,300 34,791 74,091
---------------------------------------------------------------------------
Balance, December 31, 2006 $ 73,662 $ 39,175 $ 112,837
---------------------------------------------------------------------------
---------------------------------------------------------------------------


11. Income Taxes

The Trust is a taxable entity under the Tax Act and is taxable only on income that is not distributed or distributable to unitholders. To the extent that cash distributions represent taxable distributions to the unitholders, the distributions will reduce the Trust's future income tax expense. Income taxes recorded in the consolidated statements of loss and accumulated earnings (deficit) differ from the tax calculated by applying the combined Canadian corporate federal and provincial income tax rate to income before taxes as follows:



Income taxes ($000s, except where noted) 2006 2005
---------------------------------------------------------------------------
Statutory income tax rate for year 35.03% 37.75%
Computed income tax recovery $(59,821) $(10,559)
Add (deduct) income tax effect of:
Non-deductible Crown charges, net of ARTC (175) 4,447
Resource allowance - (5,217)
Unit-based compensation 581 3,240
Taxable distributions (23,073) (11,823)
Write-down of goodwill (Note 4) 20,524 -
Tax rate adjustments (9,612) 258
Other 27 13
---------------------------------------------------------------------------
Future income tax (71,549) (19,641)
Current taxes 244 1,521
---------------------------------------------------------------------------
Provision for income taxes (recovery) $(71,305) $(18,120)
---------------------------------------------------------------------------
---------------------------------------------------------------------------


Cash taxes paid were for Saskatchewan capital tax in the year ended December 31, 2006 and Federal large corporations tax and Saskatchewan capital tax for the year ended December 31, 2005.

The primary components of the future income tax liability relate to the following:



Future income tax liability ($000s) 2006 2005
---------------------------------------------------------------------------
Property and equipment $ 91,974 $143,652
Deferral of partnership income 19,913 32,608
Commodity contracts 1,395 -
Tax loss carry forwards recognized (23,215) (17,779)
Attributed Canadian royalty income (4,850) (1,567)
Asset retirement obligations (8,807) (8,329)
Unit issue costs (1,125) (1,709)
Deferred financing costs 30 -
---------------------------------------------------------------------------
Future income tax liability 75,315 146,876
Less current future income tax liability 1,395 -
---------------------------------------------------------------------------
Long-term future income tax liability $ 73,920 $146,876
---------------------------------------------------------------------------
---------------------------------------------------------------------------


The Trust's tax pools totaled $337 million at December 31, 2006 (2005 - $288 million).

On October 31, 2006, the Federal Minister of Finance announced proposals (the "October 31, 2006 Proposals") to amend the Tax Act to apply a tax on distributions from publicly-traded income trusts. Under the October 31, 2006 Proposals, existing income trusts will be subject to the new measures commencing in their 2011 taxation year, or sooner under certain circumstances following a four-year grace period. The Federal Minister of Finance has issued a Notice of Ways and Means Motion to Amend the Tax Act, but it is not known at this time if or when the proposal will be enacted by Parliament. The Trust is currently assessing the proposals and the potential implications to the Trust.



12. Financial Instruments

The Trust entered into the following financial transactions to mitigate its
exposure to future fluctuations in commodity prices.


Gas Volume Pricing Strike
Contracts GJ/d Point Price per GJ Term
---------------------------------------------------------------------------
Costless
Collar 10,000 AECO Cdn$8.00 to Cdn$9.40 Nov 1/06 to March 31/07
Costless
Collar 10,000 AECO Cdn$8.00 to Cdn$10.00 Nov 1/06 to March 31/07
Costless
Collar 10,000 AECO Cdn$6.50 to Cdn$8.10 April 1/07 to Oct 31/07
---------------------------------------------------------------------------
---------------------------------------------------------------------------


Oil Volume Pricing Strike
Contracts bbls/d Point Price per bbl Term
---------------------------------------------------------------------------
Costless
Collar 800 WTI NYMEX US$61.00 to US$73.05 Jan 1/07 to Mar 31/07
Costless
Collar 800 WTI NYMEX US$65.00 to US$80.00 Jan 1/07 to Mar 31/07
Costless
Collar 800 WTI NYMEX US$60.00 to US$70.50 April 1/07 to June 30/07
Costless
Collar 800 WTI NYMEX US$60.00 to US$72.50 July 1/07 to Sept 30/07
---------------------------------------------------------------------------
---------------------------------------------------------------------------


The net effect of these contracts was a realized net gain of $0.7 million and an unrealized net gain of $4.6 million for the year ended December 31, 2006 (2005 - nil).

Subsequent to December 31, 2006, the Trust entered into the following financial transaction to mitigate its exposure to future fluctuations in commodity prices.




Gas Volume Pricing Strike
Contract GJ/d Point Price per GJ Term
---------------------------------------------------------------------------
Costless
Collar 8,000 AECO Cdn$6.50 to Cdn$8.00 April 1/07 to Oct 31/07
---------------------------------------------------------------------------
---------------------------------------------------------------------------


13. Supplemental Cash Flow Information

Supplemental cash flow information ($000s) 2006 2005
---------------------------------------------------------------------------
Changes in non-cash working capital:
Accounts receivable $ 14,340 $ (26,082)
Prepaid expenses (2,162) (266)
Accounts payable and accrued liabilities (19,305) 9,961
Assumption of working capital on acquisitions
(Note 2) - (2,220)
---------------------------------------------------------------------------
$ (7,127) $ (18,607)
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Changes in non-cash working capital
Operating activities $ (557) $ (27,619)
Investing activities (6,570) 9,012
---------------------------------------------------------------------------
$ (7,127) $ (18,607)
---------------------------------------------------------------------------
---------------------------------------------------------------------------


14. Risk Management

a) Credit risk

A substantial portion of the Trust's accounts receivable are with oil and gas marketing entities. The Trust generally extends unsecured credit to these companies; therefore, the collection of accounts receivable may be affected by changes in economic or other conditions and may accordingly impact the Trust's overall credit risk. Management believes the risk is mitigated by the size, reputation and diversified nature of the companies to which it extends credit.

The Trust is exposed to losses in the event of non-performance by counterparties to financial risk management contracts. The Trust minimizes credit risk associated with possible non-performance of these financial instruments by entering into contracts with only investment grade counterparties, limits on exposures to any one counterparty, and monitoring procedures. The Trust believes these risks are minimal.

The Trust has not previously experienced any material credit losses on the collection of receivables.

b) Fair value of financial instruments

Financial instruments of the Trust consist of accounts receivable, commodity contracts, bank indebtedness, accounts payable, distributions payable, unit-based compensation, bank debt, convertible debentures and asset retirement obligations. The carrying amounts of financial instruments included in the balance sheet approximate their fair value.

c) Interest rate risk management

Borrowings under bank credit facilities are market-rate-based (variable interest rates); thus exposing the Trust to interest rate risk.

d) Foreign currency risk management

The Trust is exposed to fluctuations in the exchange rate between the Canadian dollar and the US dollar. Crude oil, and to a large extent natural gas prices, are based upon reference prices denominated in US dollars, while the majority of the Trust's expenses are denominated in Canadian dollars.

15. Related Party Transactions

During the year, the Trust incurred expenditures of $0.5 million (2005 - $1.0 million) for general corporate legal fees charged by a legal firm of which a director is a partner. These legal fees were included in general and administrative expenses, convertible debenture issue costs, property and equipment and unit issue costs. At December 31, 2006, $1,750 (2005 - $10,000) remained outstanding. The related party transactions were provided in the normal course of business under the same terms and conditions as transactions with unrelated companies.

16. Contractual Obligations, Commitments and Guarantees

The Trust has assumed various contractual obligations and commitments in the normal course of operations and financing activities. These obligations and commitments have been considered when assessing cash requirements in the analysis of future liquidity.



Payments
---------------------------------------------------------------------------
less greater
than 1 1-3 4-5 than 5
($000s) Total year years years years
---------------------------------------------------------------------------
Firm transportation
$ 1,243 $ 500 $ 743 $ - $ -
Power contract 1,221 1,051 170 - -
Office and vehicle
leases 12,205 2,022 6,326 3,857 -
---------------------------------------------------------------------------
Total $ 14,669 $ 3,573 $ 7,239 $ 3,857 $ -
---------------------------------------------------------------------------
---------------------------------------------------------------------------


The Trust indemnifies its directors and officers against any and all claims or losses reasonably incurred in the performance of their service to the Trust to the extent permitted by law. The Trust has acquired and maintains liability insurance for its directors and officers.

Contact Information

  • Thunder Energy Trust and Thunder Energy Inc
    Stuart Keck
    President & C.E.O.
    (403) 294-1635
    (403) 232-1317 (FAX)
    or
    Thunder Energy Trust and Thunder Energy Inc
    Brent Kirkby
    Vice President, Finance and C.F.O.
    (403) 294-1635
    (403) 232-1317 (FAX)
    Email: thunder@thunderenergy.com
    Website: www.thunderenergy.com