Thunder Energy Trust
TSX : THY.UN

Thunder Energy Trust

November 09, 2006 08:50 ET

Thunder Announces 12-Cent Distribution, Third Quarter 2006 Results and 2006 Operational Update

CALGARY, ALBERTA--(CCNMatthews - Nov. 9, 2006) - Thunder Energy Trust (TSX:THY.UN) today released financial and operational results for the three months and nine months ended September 30, 2006. As the Trust was formed on July 7, 2005, substantially all of the comparative 2005 third quarter results are for the Trust's operations. However, for the nine-month period, in accordance with Canadian generally accepted accounting principles ("GAAP"), comparative year to date 2005 results are for the Trust and its predecessor, Thunder Energy Inc., and therefore are not directly comparable with the 2006 results for the Trust.

Distributions

Thunder Energy Trust has declared a distribution of 12 cents per trust unit to be paid on December 15, 2006, in respect of November production, for unitholders of record on November 22, 2006. The ex distribution date is November 20, 2006.

Declared monthly distributions for the third quarter totalled $0.36 per unit, down from $0.45 per unit for third quarter 2005 with the decline due to lower commodity prices. For the nine months of 2006, distributions totalled $1.20 per unit. Declared distributions totalled $17.4 million for the third quarter, representing a payout ratio of 93% before the Trust's Distribution Reinvestment Program (DRIP) and 49% after taking into account the DRIP. Year to date, declared distributions totalled $56.2 million with a payout ratio of 93% before the DRIP, 51% after the DRIP. Cumulative distributions since the Trust's inception to September 30, 2006 were $2.10 per unit.

Financial

Quarterly funds from operations totalled $18.8 million ($0.39 per unit basic, $0.36 per unit diluted) compared with $35.0 million in third quarter 2005 ($0.79 per unit basic and diluted). The quarter over quarter decline reflects a 37% decrease in natural gas prices at the wellhead to an average $5.79/mcf, a 2% reduction in average oil and NGL prices at the wellhead to $68.51/bbl and a 20% decline in average production.

For the nine months, funds from operations totalled $60.5 million ($1.28 per unit basic; $1.16 per unit diluted). The decline in the average natural gas price was less severe for the nine months at 19% with the Trust averaging $6.36/mcf, offset by a 7% increase in average production to 9,511 boe/d and 3% growth in the average oil and NGL price at the wellhead to $64.18/bbl.

The Trust recorded net income of $8.3 million for the quarter ($0.17 per unit basic and diluted) versus $7.7 million in third quarter 2005 ($0.18 per unit basic and $0.17 per unit diluted). For the nine months, net income totalled $30.7 million ($0.65 per unit basic and $0.60 per unit diluted), a substantial increase from the $15.6 million recorded for the nine months of 2005. The increase is attributable to, among other factors, future tax recoveries due to the federal and provincial governments enacting significant future tax deductions in second quarter 2006.

Production

Production for the third quarter 2006 averaged 9,229 boe/d, 62% of which was natural gas. Production was within 1.0% of second quarter volumes of 9,307 boe/d. Gas volumes averaged 34.2 mmcf/d versus 34.0 mmcf/d in Q2 2006; average oil and NGL volumes of 3,532 bbls/d were down 3% from 3,640 bbls/d in second quarter 2006. Approximately 60% of the behind pipe volumes of 1,930 boe/d reported at the end of June, were brought on stream in late August and September. At September end, behind pipe volumes were estimated at 740 boe/d.

Hedging

Thunder's hedging policy is designed to mitigate downside commodity price risk. In third quarter 2006, hedging activity resulted in a realized loss of $0.7 million and an unrealized gain of $8.2 million. For the nine months, hedging resulted in a realized loss of $1.9 million and an unrealized gain of $6.0 million.

A complete hedging summary is included in the attached Management Discussion and Analysis (MD&A).

Q3 2006 Activity

Thunder Trust drilled 24 wells (18.5 net) in the third quarter comprising 14 gas wells (13.5 net), four oil wells (1.4 net) and six (3.6 net) dry and abandoned wells (D&A). Drilling and completion results for Q3 2006 yielded an 80.5% success rate as detailed below. Capital expenditures for the third quarter totalled $20.7 million.



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Oil Gas D&A Total
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Gross Net Gross Net Gross Net Gross Net
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Central Alberta
Fenn-Big Valley 0 0.0 12 12.0 6 3.6 18 15.6
Rosalind 0 0.0 1 1.0 0 0.0 1 1.0
Matziwin 1 1.0 0 0.0 0 0.0 1 1.0
Manola 0 0.0 1 0.5 0 0.0 1 0.5
West Alberta
Sylvan Lake 1 0.3 0 0.0 0.0 1 0.3
Northern Alberta 2 0.1 0 0.0 0 0.0 2 0.1
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Totals 4 1.4 14 13.5 6 3.6 24 18.5
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Success 80.5%


Operational Update

Central Alberta

Fenn-Big Valley: The majority of Thunder's Q3 2006 drilling activity was in the Fenn-Big Valley area, with 18 wells (15.6 net) drilled at a success rate of 77%. This brings the year to date total to 24 wells (20.0 net). All but 3 (3.0 net) wells from the 2005 and 2006 program are now on production and will undergo a rigorous post-investment appraisal in light of lower commodity process. Of the wells drilled in 2006, 58% were economic successes, however, based on the cost sharing agreement detailed below, success rises to 70% on a capital adjusted basis.

Under the agreement with Ember Resources Inc. (Ember), joint drilling is targeting Thunder's 100%-owned conventional Belly River sand potential and Ember's 100%-owned coalbed methane (CBM) resource potential in a single well bore. This cost sharing enhances the economics of the Belly River development program in the Fenn-Big Valley area. Drilling costs to the base of the Belly River sands are shared 60% by Thunder and 40% by Ember. Thunder pays approximately 40% of major facility costs and 100% of Belly River completion costs; Ember pays 100% of the CBM completion costs. Projected capital cost savings pursuant to this strategic alliance are approximately 30%. This alliance provides the opportunity to fully exploit the Belly River sand potential on a higher drilling density basis.

Approximately half of the area's behind pipe volumes of 640 boe/d at the end of June 2006 were brought on stream in the third quarter. At September 30, 2006, an estimated 300 boe/d remained behind pipe at Fenn. Thunder participated in the expansion of a non-operated compression facility and, although construction was delayed, start up was initiated in early October 2006.

Rosalind: One well (1.0 net) was drilled at Rosalind in Q3 2006, based on interpretation of Thunder's proprietary 3-D seismic. Two separate Mannville zones were encountered which tested a total of 4.3 mmcf/d (4.3 net). Current production from this well is 1.2 mmcf/d (1.2 net) and flows through Thunder 100% owned and operated facilities. Year to date drilling at Rosalind totalled seven wells (6.0 net) with an associated success rate of 83%.

Matziwin: One oil well (1.0 net) was drilled in Matziwin, which tested at 240 boe/d (240 net) from the Lower Mannville zone. The well is tied in and currently producing to Thunder-owned facilities.

Manola: One gas well (0.5 net) was drilled at Manola in Q3 2006, which tested at approximately 0.8 mmcf/d (0.40 net) from an Upper Manville sandstone. The well is currently awaiting tie in. Two additional wells (1.0 net) are scheduled for drilling in the fourth quarter based on new 3-D seismic shot in Q1 2006.

West Alberta

Greater Sylvan Lake: One well (0.25 net) at Sylvan Lake was drilled at 12-36-38-4W5 in the third quarter with the Trust's strategic partner, Alberta Clipper Resources Inc. The well encountered 112 feet of net oil pay in the Leduc Formation averaging 9% porosity. During a five-day testing period, the well flowed at restricted rates averaging 1,775 boe/d (444 net) from three perforation intervals in the Leduc formation. At the end of the quarter, behind pipe volumes for this well were 220 boe/d net to Thunder. This well is now tied in to Thunder-operated facilities, and is currently flowing at a restricted rate pending facility optimization.

Thunder is currently drilling one (0.5 net) additional well in the Sylvan Lake area, and another two wells (0.7 net) are scheduled prior to year end. In addition to the fourth quarter drills, the Trust carries an inventory of 11 (4.6 net) potential locations targeting Leduc reefs.

Foothills-Whiskey Creek

To optimize flowing conditions for the Whiskey Creek area, additional compression is required at Imperial Oil's Quirk Creek gas plant. Although originally scheduled for installation in the fourth quarter 2006, the operator has now delayed the on-stream date for this compressor to second quarter 2007.

Land

Year to date, the Trust acquired 5,899 net acres for a total of $3.1 million, resulting in an average cost of $520 per acre ($1,285 per hectare). Primary focus areas for mineral land purchases have been Sylvan Lake, Rosalind and Manola. Sylvan Lake accounted for 3,760 net acres (approximately 64%), which were acquired in the third quarter for $2.3 million. All lands purchased at Sylvan Lake and Rosalind, and the majority of lands purchased in the Manola area, are covered by the Trust's extensive 3-D seismic database.

The Trust's net undeveloped mineral lands at September 30, 2006 totalled 154,000 net acres.

2006 Outlook

Full year 2006 production is now expected to average approximately 9,500 boe/d, reduced from previous guidance of 9,900 to 10,100 boe/d. The reduction is primarily driven from delays in facility on-stream dates at Thunder's Fenn Big Valley and Whiskey Creek areas, plus delays in facility optimization required in the Greater Sylvan Lake area to handle additional volumes and NGL production.

Capital spending for the full year of 2006 is expected to be approximately $75.0 million, up from the previous guidance of $65.0 million, largely due to land purchases, facility upgrades, and incremental drilling costs in the Sylvan Lake area.

"Our location inventory continues to be one of well defined and well balanced development, and low risk exploration, especially in the Sylvan Lake and Central areas of Alberta. Our geological assessment is working extremely well with our 3-D seismic models and has been tangibly confirmed by the last 12 drills, 10 of which are currently producing. The Trust's four-year drilling inventory continues to expand and gravitate to much higher quality targets," said Stuart Keck, President & CEO.

At the end of the third quarter, Thunder's opportunity base included:

- Almost four years of defined drilling inventory;

- Over 21 townships (756 square miles) of 3-D seismic yielding significant drilling success;

- Strategic Partnerships in which tangible benefits are now being realized;

- Undeveloped land holdings of approximately 154,000 net acres at September 30, 2006.

- Estimated tax pools at September 30, 2006 of $300 million.

Subsequent Event

On October 31, 2006, the federal government announced its intention to change the way energy trusts and certain income funds are taxed, which would take effect January 1, 2011. A detailed draft of the proposed legislation has not been provided to the Trust at this time and therefore it is uncertain what impact the legislative changes will have on the Trust and its unitholders. If the proposed changes are enacted, a tax will be applied at the trust level on distributions at rates of tax comparable to the combined federal and provincial corporate tax, estimated at 31.5%. Under this tax regime, distributions would be treated as dividends to unitholders.

Forward-looking Statements

This press release contains forward-looking statements. More particularly, this press release contains statements concerning the Trust's volumes of oil and natural gas that are currently behind pipe and planned exploration and development activities, planned capital expenditures and anticipated average daily production for 2006.

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 labor 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.

Note: Boe means barrel of oil equivalent on the basis of 1 boe to 6,000 cubic feet of natural gas. Boe's may be misleading, particularly if used in isolation. A boe conversion ratio of 1 boe for 6,000 cubic feet of natural gas is based on an energy equivalency conversion method primarily applicable at the burner.



HIGHLIGHTS

Financial Three Months Ended Nine Months Ended
($000s, except September 30 % September 30 %
per share data) 2006 2005 Change 2006 2005 Change
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Petroleum and natural
gas sales 41,352 65,866 (37) 129,098 127,945 1
Funds from operations(1) 18,777 35,037 (46) 60,484 70,804 (15)
per unit(2) - basic ($) 0.39 0.79 (51) 1.28 1.65 (22)
- diluted ($) 0.36 0.79 (54) 1.16 1.59 (27)
Net income 8,260 7,718 7 30,729 15,582 97
per unit(2) - basic ($) 0.17 0.18 (6) 0.65 0.36 81
- diluted ($) 0.17 0.17 - 0.60 0.35 71

Capital expenditures 20,729 21,228 (2) 60,442 63,938 (5)
Distributions declared 17,399 19,114 (9) 56,187 19,114 194
Distributions declared
per unit ($) 0.36 0.45 (20) 1.20 0.45 167
Payout ratio(3)
before DRIP 93% 55% 69 93% 27% 244
Payout ratio(3)
after DRIP 49% - 100 51% - 100
Total debt including
working capital
deficiency 185,036 148,432 25 185,036 148,432 25
Weighted average units
outstanding
- basic 48,643 44,083 10 47,395 43,033 10
Weighted average units
outstanding
- diluted 55,847 44,392 26 54,469 44,519 22
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Three Months Ended Nine Months Ended
Operations September 30 % September 30 %
2006 2005 Change 2006 2005 Change
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Daily production
Natural gas (mcf/d) 34,178 44,680 (24) 34,908 40,301 (13)
Oil and NGL (bbls/d) 3,532 4,128 (14) 3,693 2,165 71
Barrels of oil equivalent 9,229 11,574 (20) 9,511 8,882 7
(boe/d)
Average sale price(4)
Natural gas ($/mcf) 5.79 9.13 (37) 6.36 7.84 (19)
Oil and NGL ($/bbl) 68.51 69.90 (2) 64.18 62.51 3
Wells drilled - gross (net)
Gas 14(13.5) 16(10.8) 37(25.1) 33(23.6)
Oil 4(1.4) 2(1.0) 11(6.2) 10(8.0)
Dry 6(3.6) 5(2.7) 12(7.2) 6(3.7)
Total 24(18.5) 23(14.5) 60(38.5) 49(35.3)
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Barrels of oil equivalent are reported with a 6:1 conversion with six
mcf = one barrel
(1) Non-GAAP financial measures are identified and defined in the
Management's Discussion and Analysis.
(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 hedging 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 the quarter ended September 30, 2006, as well as their estimate of future operating and financial performance based on information currently available. It should be read in conjunction with the unaudited interim consolidated financial statements of the Trust for the three and nine months ended September 30, 2006 and the audited consolidated financial statements and notes for the year ended December 31, 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 Inc. ("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 November 6, 2006.

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 - Management uses funds from operations (cash provided by operating activities before changes in non-cash working capital and settlement of asset retirement obligations) to analyze operating performance and leverage. The term distributable cash is used to present the amount of cash that the Trust distributes to unitholders. The payout ratio is used to present the amount of cash as a percentage of the Trust's funds from operations which are distributed before and after the distribution reinvestment program ("DRIP"). Distributable cash, funds from operations and payout ratio presented have no standardized meaning prescribed by GAAP; therefore, they may not be comparable with the calculation of similar measures for other entities. Distributable cash, funds from operations and the payout ratio as presented are not intended as alternates to, or to be more meaningful than, GAAP performance measures such as net income. The reconciliation between net income and funds from operations can be found in the consolidated statements of cash flows in the consolidated financial statements. The Trust also presents funds from operations per unit whereby per unit amounts are calculated using weighted average units outstanding consistent with the calculation of earnings per unit. Distributable cash is calculated using funds from operations less funds withheld for capital expenditures. Payout ratio is calculated as funds from operations divided by declared distributions before and after DRIP. The Trust considers funds from operations to be a key measure as it demonstrates the Trust's ability to generate the cash necessary to pay distributions, repay debt, and to fund future capital investments. Distributable cash, funds from operations and payout ratio are used by research analysts to value and compare oil and gas trusts and are frequently included in published third-party research when providing investment recommendations.

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: 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.

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 cash flow to fund distributions 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 the Trust's annual report for the year ended December 31, 2005 under the headings "Critical Accounting Estimates" and "Risks and Uncertainties" in the MD&A.

The Trust cautions that the foregoing list of factors that may affect future results is not exhaustive. When relying on our 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


Results of Operations

Gross oil and gas revenues decreased 37% to $41.4 million for the three months ended September 30, 2006 compared with the same period in 2005 and increased 1% to $129.1 million for the nine months ended September 30, 2006. The decline in third quarter revenues was mainly due to lower natural gas prices and lower production volumes. Year-to-date revenues remained steady as declining natural gas prices during the year were offset by higher production for the nine months.

In the third quarter of 2006, natural gas revenues decreased 50% from the same period in 2005 due to a 37% decrease in Thunder's average price at the wellhead and a 24% decline in gas production offset by a realized hedging gain of $0.4 million. Oil and NGL revenues were down 20% in the third quarter from 2005 due to a 2% decrease in the average price at the wellhead and a 14% decline in production offset by a $1.0 million realized hedging loss.

For the first nine months natural gas revenues decreased 29% from 2005 due to a 19% decline in Thunder's average natural gas price at the wellhead and a 13% production decrease, offset by a realized hedging gain of $0.7 million. Oil and NGL revenues increased 68% due to a 3% rise in Thunder's average price at the wellhead and a 71% increase in oil and NGL production offset by a realized hedging loss of $2.6 million.

In 2006 the Trust entered into financial contracts to mitigate the effect of commodity price fluctuations. The above noted hedging gains and losses relate to contracts to hedge 15,000 GJ/d of natural gas and 2,400 bbls/d of crude oil. The net effect of these contracts was a realized loss of $0.7 million and an unrealized gain of $8.2 million for the third quarter and a realized loss of $1.9 million and an unrealized gain of $6.0 million for the year to date.



Oil and Gas Revenues ($000s)
Three months ended Nine months ended
September 30 September 30
2006 2005 2006 2005
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Gross revenues 41,352 65,866 129,098 127,945
Transportation expenses (885) (1,982) (3,796) (4,800)
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Net revenues 40,467 63,884 125,302 123,145
Realized net loss on commodity
contracts (660) - (1,886) -
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Net revenues after realized hedging
loss 39,807 63,884 123,416 123,145
Unrealized net gain on commodity
contracts 8,244 - 5,985 -
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Net revenues after realized and
unrealized hedging gain/loss 48,051 63,884 129,401 123,145
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Oil and Gas Revenues
($000s, net of transportation expenses and realized hedging gain/loss)

Crude Oil
Natural Gas and NGL Total
---------------------------------------------------------------------------
Three months ended September 30, 2005 37,338 26,546 63,884
Effect of change in product prices (10,313) (451) (10,764)
Effect of change in sales volumes (8,821) (3,832) (12,653)
Effect of realized gain (loss) on commodity
contracts 390 (1,050) (660)
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Three months ended September 30, 2006 18,594 21,213 39,807
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Nine months ended September 30, 2005 86,189 36,956 123,145
Effect of change in product prices (14,047) 1,687 (12,360)
Effect of change in sales volumes (11,542) 26,059 14,517
Effect of realized gain (loss) on commodity
contracts 705 (2,591) (1,886)
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Nine months ended September 30, 2006 61,305 62,111 123,416
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Production

Three months ended Nine months ended
September 30 September 30
2006 2005 2006 2005
---------------------------------------------------------------------------
Crude oil (bbls/d) 3,146 3,833 3,278 1,960
NGL (bbls/d) 386 295 415 205
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Total crude oil and NGL (bbls/d) 3,532 4,128 3,693 2,165
Natural gas (mcf/d) 34,178 44,680 34,908 40,301
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Total (boe/d) 9,229 11,574 9,511 8,882
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Percentage gas (%) 62 64 61 76
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Average Commodity Prices

Three months ended Nine months ended
September 30 September 30
2006 2005 2006 2005
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Natural gas ($/mcf)
NYMEX ($US/mmbtu) 6.53 8.17 7.48 7.15
AECO Daily ($/mmbtu) 5.65 9.37 6.40 7.88
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Thunder price before hedging and
transportation 5.98 9.50 6.60 8.17
Transportation (0.19) (0.37) (0.24) (0.33)
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Thunder price at the wellhead 5.79 9.13 6.36 7.84
Realized gain on commodity
contracts 0.12 - 0.07 -
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Thunder price after hedging 5.91 9.13 6.43 7.84
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Crude oil ($/bbl)
WTI ($US/bbl) 70.48 63.19 68.22 55.40
Edmonton posted 79.08 76.51 75.53 67.91
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Thunder price before hedging and
transportation 69.36 71.13 65.68 64.56
Transportation (0.85) (1.23) (1.50) (2.05)
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Thunder price at the wellhead 68.51 69.90 64.18 62.51
Realized loss on commodity
contracts (3.23) - (2.57) -
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Thunder price after hedging 65.28 69.90 61.61 62.51
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Cdn/US $ average exchange rate 1.121 1.202 1.133 1.220
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Transportation expenses were down 55% to $0.9 million compared with third quarter 2005 and 21% to $3.8 million for the first nine months of 2006. The Trust's transportation expenses per barrel for crude oil have not increased proportionately with the rise in production as the majority of crude oil production acquired from Mustang and Forte in 2005 is pipeline connected.

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
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April 1/06 to
Costless Collar 15,000 AECO Cdn$6.00 to Cdn$6.50 Oct 31/06
Nov 1/06 to
Costless Collar 10,000 AECO Cdn$8.00 to Cdn$9.40 March 31/07
Nov 1/06 to
Costless Collar 10,000 AECO Cdn$8.00 to Cdn$10.00 March 31/07
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Oil Volume Pricing Strike
Contracts bbls/d Point Price per bbl Term
---------------------------------------------------------------------------
Oct 1/06 to
Costless Collar 800 WTI NYMEX US$61.00 to US$72.70 Dec 31/06
Oct 1/06 to
Costless Collar 800 WTI NYMEX US$65.00 to US$80.70 Dec 31/06
Jan 1/07 to
Costless Collar 800 WTI NYMEX US$61.00 to US$73.05 Mar 31/07
Jan 1/07 to
Costless Collar 800 WTI NYMEX US$65.00 to US$80.00 Mar 31/07
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The net effect of these contracts was a realized loss of $0.7 million and an unrealized gain of $8.2 million during the three months ended September 30, 2006 and a realized loss of $1.9 million and unrealized gain of $6.0 million during the nine month period.

Subsequent to September 30, 2006, the Trust entered into the following financial transactions to mitigate its exposure to future fluctuations in commodity prices.



Gas Volume Pricing Strike
Contracts bbls/d Point Price per GJ Term
---------------------------------------------------------------------------
April 1/07 to
Costless Collar 10,000 AECO Cdn$6.50 to Cdn$8.10 Oct 31/07
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Oil Volume Pricing Strike
Contracts bbls/d Point Price per bbl Term
---------------------------------------------------------------------------
April 1/07 to
Costless Collar 800 WTI NYMEX US$60.00 to US$70.50 June 30/07
July 1/07 to
Costless Collar 800 WTI NYMEX US$60.00 to US$72.50 Sept 30/07
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---------------------------------------------------------------------------


Royalties decreased to $7.6 million in the third quarter of 2006 and to $23.1 million for the first nine months of the year, decreases of 41% and 7%, respectively over the corresponding prior periods in 2005. Royalties as a percentage of net revenue decreased to 18.8% from 20.2% in the third quarter 2005, and increased to 18.4% from 17.5% for the nine-month period. The third quarter decline in royalties from 2005 was due to lower revenue compared to 2005. The increase in royalties during the first nine months of 2006 was due to higher revenue in 2006 and a gas cost allowance refund in the second quarter of 2005.



Royalties ($000s)
Three months ended Nine months ended
September 30 September 30
2006 2005 2006 2005
---------------------------------------------------------------------------
Crown 5,423 10,539 16,942 17,275
Freehold and other 2,293 2,483 6,546 4,697
---------------------------------------------------------------------------
Gross royalties 7,716 13,022 23,488 21,972
ARTC (125) (125) (375) (366)
---------------------------------------------------------------------------
Net royalties 7,591 12,897 23,113 21,606
---------------------------------------------------------------------------
---------------------------------------------------------------------------


Royalty Rates (as a % of net revenues)

Three months ended Nine months ended
September 30 September 30
2006 2005 2006 2005
---------------------------------------------------------------------------
Crown 13.4 16.5 13.5 14.0
Freehold and other 5.7 3.9 5.2 3.8
---------------------------------------------------------------------------
Gross royalties 19.1 20.4 18.7 17.8
ARTC (0.3) (0.2) (0.3) (0.3)
---------------------------------------------------------------------------
Net royalties 18.8 20.2 18.4 17.5
---------------------------------------------------------------------------
---------------------------------------------------------------------------


Operating costs increased 4% from the third quarter 2005 to $9.4 million and 39% to $27.5 million in the first nine months of 2006. In addition to the general rise in costs for services and supplies in the oil industry and high fuel and power costs, the increase was due to the acquisitions of Mustang and Forte and the transition into a Trust. The acquisition of Forte increased the Trust's operations in northeast B.C. and northern Alberta where operating costs are generally higher compared with central Alberta. In the current commodity price environment, low-rate, high cost wells that would otherwise be unprofitable continue to contribute to the overall production base.



Operating Costs
Three months ended Nine months ended
September 30 September 30
2006 2005 2006 2005
---------------------------------------------------------------------------
Operating costs ($000s) 9,426 9,059 27,462 19,827
Per boe ($) 11.10 8.51 10.58 8.18
---------------------------------------------------------------------------
---------------------------------------------------------------------------


Gross general and administrative expenses (G&A) increased 30% to $3.5 million for the third quarter of 2006 and 50% to $10.1 million for the nine months ended September 30, 2006 compared to the same periods in 2005 due to increased salaries and benefits and office space as a result of the transition into a Trust. Net G&A was $2.27 per boe and $2.18 per boe for the three and nine months ended September 30, 2006 respectively. The increases over the corresponding prior periods were due to the increased size of the Trust as well as several budgeted, one-time costs such as audit and tax services, annual filing costs and consulting services. Also included in G&A are costs relating to documenting internal controls to meet regulatory requirements. For the third quarter these costs totaled $0.1 million or $0.11/boe.



G&A Expenses

Three months ended Nine months ended
September 30 September 30
G&A Expenses ($000s) 2006 2005 2006 2005
---------------------------------------------------------------------------
Gross G&A expenses 3,538 2,719 10,083 6,710
Capitalized G&A (1,227) (405) (2,885) (1,214)
Overhead recoveries
Capital (144) (158) (699) (1,083)
Operating (238) (565) (837) (1,094)
---------------------------------------------------------------------------
Net G&A expenses 1,929 1,591 5,662 3,319
Non-recurring retention & severance - 3,300 - 3,300
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Net G&A & non-recurring expense 1,929 4,891 5,662 6,619
---------------------------------------------------------------------------
---------------------------------------------------------------------------

G&A Expenses ($/boe)
---------------------------------------------------------------------------
Gross G&A expenses 4.17 2.55 3.88 2.77
Capitalized G&A (1.45) (0.38) (1.11) (0.50)
Overhead recoveries
Capital (0.17) (0.15) (0.27) (0.45)
Operating (0.28) (0.53) (0.32) (0.45)
---------------------------------------------------------------------------
Net G&A expenses 2.27 1.49 2.18 1.37
Non-recurring retention & severance - 3.10 - 1.36
---------------------------------------------------------------------------
Net G&A & non-recurring expense 2.27 4.59 2.18 2.73
---------------------------------------------------------------------------
---------------------------------------------------------------------------


Financial charges are comprised of bank debt interest, convertible debenture interest, amortization of deferred financing costs and accretion of convertible debenture liability. Financial charges have increased by 78% to $2.9 million for the quarter and 101% to $7.0 million for the nine months ended September 30, 2006 compared to the same periods in 2005. Financial charges have increased due to increased interest rates and higher levels of debt due to lower commodity prices and production. A reconciliation of these charges is as follows:


Three months ended Nine months ended
September 30 September 30
Financial charges ($000s) 2006 2005 2006 2005
---------------------------------------------------------------------------
Bank debt interest 1,276 1,625 3,883 3,501
Convertible debenture interest 1,360 - 2,654 -
Amortization of deferred financing
costs 180 - 348 -
Accretion of convertible debenture
liability 70 - 137 -
---------------------------------------------------------------------------
Total financial charges 2,886 1,625 7,022 3,501
---------------------------------------------------------------------------
---------------------------------------------------------------------------


Bank debt interest for the quarter decreased 21% from 2005 due to a decrease in the average bank debt outstanding offset by a higher effective interest rate. The decrease in the average bank debt was due to the issuance of convertible debentures during the second quarter of 2006. For the first nine months of 2006 interest expense increased 11% from 2005 due to a higher effective interest rate offset by a lower average bank debt outstanding.



Bank Debt
Three months ended Nine months ended
September 30 September 30
2006 2005 2006 2005
---------------------------------------------------------------------------
Average bank debt
outstanding ($000s) 96,651 144,397 106,140 117,500
Effective annualized interest
rate for the period (%) 5.2 4.5 4.9 4.0
---------------------------------------------------------------------------
---------------------------------------------------------------------------


Convertible debenture interest was $1.4 million for the third quarter of 2006 and $2.7 million year to date. 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.

Depletion, depreciation and accretion expense (DD&A) increased to $22.9 million in the third quarter and $69.8 million in the first nine months of 2006. The increases reflect the rise in general industry costs and the reduction in proved reserves at year-end 2005. A ceiling test was performed at September 30, 2006 and it was determined that there was no impairment to the carrying value of the Trust's unamortized capitalized costs.



DD&A Expense
Three months ended Nine months ended
September 30 September 30
2006 2005 2006 2005
---------------------------------------------------------------------------
DD&A expense ($000s) 22,911 22,650 69,788 45,104
Per boe ($) 26.98 21.27 26.88 18.60
---------------------------------------------------------------------------
---------------------------------------------------------------------------


Unit-based compensation expense was $0.5 million in the third quarter of 2006 and $1.3 million for the first nine months of 2006, down from $6.1 million and $7.9 million in the corresponding periods of 2005 due to the corporate reorganization in the prior year. The Trust's unit-based compensation is determined based on the intrinsic value of the Trust units at each period end.

Provision for Income Taxes

The Trust is a taxable entity under the Tax Act (Canada), 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 $4.9 million for the third quarter and $35.8 million for the nine months ended September 30, 2006 primarily due to the estimated taxability of distributions as well as future tax rate reductions enacted by the federal and provincial governments during the second quarter.

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.

Funds from operations for the third quarter decreased 46% from the same period in 2005 to $18.8 million due to decreased production, lower natural gas prices and higher operating costs and G&A expenses. For the nine months of 2006 funds from operations decreased 15% from 2005 to $60.5 million due to lower natural gas prices and a decline in natural gas production from the prior year along with higher operating and G&A expenses.



Funds from Operations

Three months ended Nine months ended
September 30 September 30
2006 2005 2006 2005
---------------------------------------------------------------------------
Funds from operations ($000s) 18,777 35,037 60,484 70,804
Per unit - basic ($) 0.39 0.79 1.28 1.65
- diluted ($) 0.36 0.79 1.16 1.59
---------------------------------------------------------------------------
---------------------------------------------------------------------------


Net income increased 7% in the third quarter 2006 to $8.3 million and 97% to $30.7 million for the months ended September 30 compared with the same periods in 2005. The increases are attributable to, amongst other things, future income tax recoveries offset by higher DD&A expenses.



Net Income

Three months ended Nine months ended
September 30 September 30
2006 2005 2006 2005
---------------------------------------------------------------------------
Net income ($000s) 8,260 7,718 30,729 15,582
Per unit - basic ($) 0.17 0.18 0.65 0.36
- diluted ($) 0.17 0.17 0.60 0.35
---------------------------------------------------------------------------
---------------------------------------------------------------------------


Asset retirement obligations are accrued by the Trust resulting 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 period, a revision was made to the liability to reflect an increase in the inflation rate from 1.5% to 2.0% . A reconciliation of the asset retirement obligations is provided below:



Asset Retirement Obligations ($000s)
Nine Months Year
Ended ended
September 30 December 31
2006 2005
---------------------------------------------------------------------------
Balance, beginning of period $ 24,774 $ 13,417
Liabilities incurred in the period 703 1,758
Liabilities assumed due to business combination
- Forte - 7,596
Liabilities assumed due to business combination
- Mustang - 5,019
Revision 1,513 (135)
Liabilities released due to dispositions - (3,328)
Liabilities settled in the period (1,652) (1,306)
Accretion expense 1,904 1,753
---------------------------------------------------------------------------
Balance, end of period $ 27,242 $ 24,774
---------------------------------------------------------------------------
---------------------------------------------------------------------------


Capital and Liquidity

Capital expenditures for the third quarter totaled $20.7 million and $60.4 million for the year to date Drilling, completion, equipping and tie-in costs totalled $45.6 million for the nine month period for the drilling of 37 gas wells (25.1 net), 11 oil wells (6.2 net), and 12 dry holes (7.2 net). The Trust's drilling success ratio was 81%. The following table breaks out the capital expenditures by category:



Capital Expenditures Summary ($000s)

Three months ended Nine months ended
September 30 September 30
2006 2005 2006 2005
---------------------------------------------------------------------------
Land and rentals 3,137 357 5,062 2,659
Seismic 999 206 2,880 4,243
Drilling and completions 9,597 10,613 35,011 34,855
Well equipping and tie-in 5,169 5,507 10,553 16,021
Facilities and gas gathering 660 4,068 1,354 4,890
Other, including capitalized G&A 1,167 477 5,582 1,270
---------------------------------------------------------------------------
Total capital expenditures 20,729 21,228 60,442 63,938
---------------------------------------------------------------------------
---------------------------------------------------------------------------


Liquidity

For the nine months ended September 30, 2006, capital expenditures of $60.4 million, the settlement of asset retirement obligations of $1.7 million, a combined decrease to long-term debt, unit issue costs and working capital of $38.0 million and cash distributions, net of the distribution reinvestment plan ("DRIP"), of $31.9 million were funded by funds from operations of $60.5 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 2006 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 Thunder Energy 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:



Convertible Debentures ($000s) As at September 30, 2006
---------------------------------------------------------------------------
Debt portion on April 5, 2006 $ 73,298
Accretion of non-cash interest 137
---------------------------------------------------------------------------
Debt portion, end of period 73,435
Equity portion 1,702
---------------------------------------------------------------------------
Total Debentures, end of period $ 75,137
---------------------------------------------------------------------------
---------------------------------------------------------------------------


Distributable Cash 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. During the third quarter of 2006, 93% of funds from operations before DRIP were distributed, 49% after DRIP. For the nine months ended September 30, 2006, 93% of funds from operations before DRIP were distributed, 51% 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. Commodity prices and production volumes are critical variables in determining cash flow and changes in these two items have a material impact on cash flow and distributions.

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



Distributions ($000s)
Three months Nine months
ended ended
September 30, September 30,
2006 2006
---------------------------------------------------------------------------
Cash provided by operating activities 28,033 59,824
Settlement of asset retirement obligations 1,262 1,652
Changes in non-cash working capital related to
operating activities (10,518) (992)
---------------------------------------------------------------------------
Funds from operations 18,777 60,484
Cash used to fund capital expenditures (9,757) (28,549)
---------------------------------------------------------------------------
Distributable cash 9,020 31,935
---------------------------------------------------------------------------
---------------------------------------------------------------------------

Cash distributions declared and payable, including
DRIP at September 30, 2006 5,840 5,840
Cash distributions paid in the period 9,020 31,935
---------------------------------------------------------------------------
Accumulated cash distributions paid and payable 14,860 37,775
---------------------------------------------------------------------------
---------------------------------------------------------------------------


Distributions Declared ($000s)
Cash distributions DRIP Total
---------------------------------------------------------------------------
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
---------------------------------------------------------------------------
Balance March 31, 2006 46,544 12,687 59,231
April distribution 3,543 3,428 6,971
May distribution 2,907 2,722 5,629
June distribution 2,987 2,716 5,703
---------------------------------------------------------------------------
Balance June 30, 2006 55,981 21,553 77,534
July distribution 3,029 2,731 5,760
August distribution 3,004 2,795 5,799
September distribution 3,075 2,765 5,840
---------------------------------------------------------------------------
Balance September 30, 2006 65,089 29,844 94,933
---------------------------------------------------------------------------
---------------------------------------------------------------------------


Distributions per unit
Three months Nine months
ended ended
September 30, September 30,
2006 2006
---------------------------------------------------------------------------
Cash distributions declared and payable per unit $0.12 $0.12
Cash distributions declared and paid per unit $0.24 $1.08
---------------------------------------------------------------------------
Accumulated cash distributions per unit $0.36 $1.20
---------------------------------------------------------------------------
---------------------------------------------------------------------------


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 three and nine months ended September 30, 2006, the Trust incurred expenditures of $0.2 million and $0.5 million, respectively 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 September 30, 2006, $14,000 was included in accounts payable. The related party transactions were recorded at the exchange amount as services were provided in the normal course of business under the same terms and conditions as transactions with unrelated companies.

Subsequent Event

On October 31, 2006 the Government of Canada proposed changes to the tax treatment of income trusts that would take effect in 2011. The Trust has not completed its assessment of the potential implications that these proposed changes might have.

Quarterly Information

The following table is a summary of quarterly results for the last eight quarters relating to the years 2006, 2005 and 2004. Because the consolidated financial statements of the Trust have been prepared on a continuity of interest basis which recognized the Trust as the successor to Thunder Energy, results prior to July 7, 2005 may not be directly comparable to those of the Trust.

Revenue is directly related to fluctuations in commodity prices and production. Declines in natural gas prices in the first nine months of 2006 resulted in lower revenues and distributable cash from the fourth quarter of 2005. Natural gas, oil and NGL production have steadied through the second and third quarters of 2006.

The Trust recorded a write-down of the carrying value of its petroleum and natural gas property and equipment in the fourth quarter of 2005 resulting in a net loss of $25.4 million. The Trust recognized a future tax recovery of $25.0 million in the second quarter of 2006 related to a reduction in future federal and provincial income tax rates as well as the taxability of distributions. This resulted in net income of $18.7 million for the second quarter.




Quarterly Information 2004 2005
($000s, except per unit data) Q4 Q1 Q2 Q3
---------------------------------------------------------------------------
---------------------------------------------------------------------------

Petroleum and natural gas sales 29,049 29,350 32,729 65,866
Funds from operations 15,525 16,599 19,168 35,037
Per unit ($)
Basic 0.61 0.64 0.74 0.79
Diluted 0.60 0.63 0.73 0.79
Net income 1,407 3,243 4,621 7,718
Per unit ($)
Basic 0.06 0.13 0.18 0.18
Diluted 0.05 0.12 0.18 0.17
Daily production
Natural gas (mcf/d) 38,827 38,174 37,978 44,680
Oil and NGL (bbls/d) 1,307 1,145 1,190 4,128
Barrels of oil equivalent (boe/d) 7,778 7,508 7,520 11,574
Average sale price(1)
Natural gas ($/mcf) 6.57 6.74 7.41 9.13
Oil and NGL ($/bbl) 43.24 48.67 49.81 69.90


2005 2006
Q4 Q1 Q2 Q3
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Petroleum and natural gas sales 67,833 46,242 41,504 41,352
Funds from operations 39,587 22,813 18,894 18,777
Per unit ($)
Basic 0.86 0.50 0.40 0.39
Diluted 0.85 0.49 0.36 0.36
Net income (25,433) 3,725 18,744 8,260
Per unit ($)
Basic (0.55) 0.08 0.39 0.17
Diluted (0.55) 0.08 0.36 0.17
Daily production
Natural gas (mcf/d) 40,489 36,572 34,001 34,178
Oil and NGL (bbls/d) 4,312 3,910 3,640 3,532
Barrels of oil equivalent (boe/d) 11,060 10,005 9,307 9,229
Average sale price(1)
Natural gas ($/mcf) 11.11 7.40 5.83 5.79
Oil and NGL ($/bbl) 62.64 57.34 67.21 68.51
---------------------------------------------------------------------------
---------------------------------------------------------------------------

(1) Average sale price at the wellhead before hedging gain or loss.


CONSOLIDATED BALANCE SHEETS
(unaudited)
September 30, December 31,
($000s ) 2006 2005
------------------------------

Assets (Note 4)

Current
Accounts receivable $ 40,446 $ 49,810
Commodity contracts (Note 9) 5,985 -
Prepaid expenses 2,141 1,219
------------------------------
48,572 51,029
Deferred financing costs (Note 6) 3,078 -
Property and equipment (Note 3) 652,843 658,069
Goodwill 108,292 108,292
------------------------------
$ 812,785 $ 817,390
------------------------------
------------------------------

Liabilities and Unitholders' Equity
Current
Bank indebtedness $ 6,404 $ 4,409
Accounts payable and accrued liabilities 40,430 57,542
Distributions payable 5,840 6,595
Future income taxes (Note 10) 1,827 -
Unit-based compensation (Note 8) 613 767
------------------------------
55,114 69,313

Bank debt (Note 4) 105,059 136,359
Convertible debentures (Note 5) 73,435 -
Unit-based compensation (Note 8) 682 528
Asset retirement obligations (Note 7) 27,242 24,774
Future income taxes (Note 10) 109,203 146,876
------------------------------
370,735 377,850

Unitholders' equity
Unitholders' capital (Note 8) 437,607 411,341
Equity component of convertible
debentures (Note 5) 1,702 -
Contributed surplus 3,025 3,025
Retained earnings (deficit) (284) 25,174
------------------------------
442,050 439,540
------------------------------
$ 812,785 $ 817,390
------------------------------
------------------------------
See accompanying notes


CONSOLIDATED STATEMENTS OF INCOME AND RETAINED EARNINGS (DEFICIT)
(unaudited)
Three Months Ended Nine Months Ended
September 30 September 30
($000s, except per share data) 2006 2005 2006 2005
-----------------------------------------
Revenue

Petroleum and natural gas sales $ 41,352 $ 65,866 $ 129,098 $ 127,945
Royalties, net of ARTC (7,591) (12,897) (23,113) (21,606)
Transportation expenses (885) (1,982) (3,796) (4,800)
-----------------------------------------
Petroleum and natural gas sales,
after royalties and
transportation 32,876 50,987 102,189 101,539
Realized net loss on commodity
contracts (Note 9) (660) - (1,886) -
Unrealized net gain on commodity
contracts (Note 9) 8,244 - 5,985 -
-----------------------------------------
Petroleum and natural gas sales,
net 40,460 50,987 106,288 101,539
-----------------------------------------

Expenses
Operating 9,426 9,059 27,462 19,827
General and administrative 1,929 4,891 5,662 6,619
Financial charges (Note 6) 2,886 1,625 7,022 3,501
Unit-based compensation (Note 8) 549 6,111 1,301 7,901
Depletion, depreciation and
accretion 22,911 22,650 69,788 45,104
-----------------------------------------
37,701 44,336 111,235 82,952
-----------------------------------------

Income (loss) before income taxes 2,759 6,651 (4,947) 18,587
Provision for income taxes
(recovery) (Note 10) (5,501) (1,067) (35,676) 3,005
-----------------------------------------
Net income for the period 8,260 7,718 30,729 15,582
Accumulated distributions (17,399) (19,114) (94,933) (19,114)
Retained earnings (deficit)
Beginning of period 8,855 81,635 63,920 73,771
-----------------------------------------
End of period $ (284) $ 70,239 $ (284) $ 70,239
-----------------------------------------
-----------------------------------------

Units and exchangeable shares
outstanding (weighted average)
(Note 8)
Basic 48,643 44,083 47,395 43,033
Diluted 55,847 44,392 54,469 44,519
Net income per unit (Note 8)
Basic $ 0.17 $ 0.18 $ 0.65 $ 0.36
Diluted $ 0.17 $ 0.17 $ 0.60 $ 0.35
-----------------------------------------
-----------------------------------------

See accompanying notes


CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited)

Three Months Ended Nine Months Ended
September 30 September 30
($000s) 2006 2005 2006 2005
-----------------------------------------
Operating Activities
Net income for the period $ 8,260 $ 7,718 $ 30,729 $ 15,582
Add items not requiring cash:
Amortization of deferred
financing costs (Note 6) 180 - 348 -
Accretion on convertible
debenture liability (Note 6) 70 - 137 -
Unit-based compensation 549 6,111 1,301 7,901
Unrealized net gain on
commodity contracts (8,244) - (5,985) -
Depletion, depreciation and
accretion 22,911 22,650 69,788 45,104
Future income taxes (Note 10) (4,949) (1,442) (35,834) 2,217
Settlement of asset retirement
obligations (1,262) (432) (1,652) (801)
Changes in non-cash working
capital relating to operating
activities (Note 11) 10,518 7,254 992 (19,488)
-----------------------------------------
Cash provided by operating
activities 28,033 41,859 59,824 50,515
-----------------------------------------

Financing Activities
Issue of units for cash, net of
costs (66) 10,672 (54) 11,506
Convertible debenture issue
costs (20) - (3,426) -
Proceeds on convertible
debentures - - 75,000 -
Increase in bank indebtedness 1,177 1,846 1,995 3,234
Increase (decrease) in bank debt 17,265 28,562 (31,300) 53,624
Cash distributions (9,020) (12,695) (31,935) (12,695)
Cash received on Plan of
Arrangement - 10,000 - 10,000
-----------------------------------------
Cash provided by financing
activities 9,336 38,385 10,280 65,669
-----------------------------------------

Investing Activities
Expenditures on property and
equipment (20,729) (21,228) (60,442) (63,938)
Assumption of working capital
deficit on business acquisition - (49,546) - (49,546)
Deferred transaction costs - 2,312 - -
Changes in non-cash working
capital related to investing
activities (Note 11) (16,640) (11,782) (9,662) (2,721)
-----------------------------------------
Cash used in investing
activities (37,369) (80,244) (70,104) (116,205)
-----------------------------------------
Net change in cash position - - - (21)
-----------------------------------------
Cash position
- beginning of period - - - 21
-----------------------------------------
- end of period $ - $ - $ - $ -
-----------------------------------------
-----------------------------------------

See accompanying notes

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)


1. Basis of Presentation

The interim consolidated financial statements of Thunder Energy Trust (the "Trust") have been prepared by management in accordance with Canadian generally accepted accounting principles. The interim consolidated financial statements have been prepared following the same accounting policies and methods of computation as the audited consolidated financial statements for the fiscal year ended December 31, 2005, except that certain disclosures required in annual financial statements have been condensed or omitted. The disclosures below are incremental to those included in the annual consolidated financial statements. Accordingly, the interim consolidated financial statements should be read in conjunction with the Trust's consolidated financial statements and notes as at and for the year ended December 31, 2005. The results of operations for the three and nine months ended September 30, 2006 may not be indicative of the results for the 2006 fiscal year.

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 coalbed 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 Trust 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 conversion of Thunder Energy to a trust was accounted for on a continuity of interest basis. Due to the conversion into a trust, certain information included in the consolidated financial statements for prior periods may not be directly comparable.

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 outstanding prior to the conversion on July 7, 2005.

2. Accounting Policies

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. 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 as well as its risk management objective and strategy.



3. Property and equipment
As at As at
Property and equipment ($000s) September 30, 2006 December 31, 2005
---------------------------------------------------------------------------
Cost $ 886,854 $ 824,196
Accumulated depletion and
depreciation (234,011) (166,127)
---------------------------------------------------------------------------
Net book value $ 652,843 $ 658,069
---------------------------------------------------------------------------
---------------------------------------------------------------------------


During the nine months ended September 30, 2006, the Trust capitalized $2.9 million (2005 - $1.6 million) of general and administrative expenses related to acquisition, exploration and development activities.

At September 30, 2006, costs of $23.1 million (2005 - $16.3 million) related to unproved properties were excluded from the full cost pool.

An impairment test calculation was performed on the Trust's oil and natural gas property interests at September 30, 2006. The estimated undiscounted future net cash flows from proved reserves, using forecast prices, exceeded the carrying amount of the Trust's oil and natural gas property interests and the cost of its unproved properties.

4. 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 rates for the three and nine months ended September 30, 2006 were 5.2% and 4.9%, respectively (2005 - 4.5% and 4.0%) .

5. 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 Thunder Energy 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. A reconciliation of deferred financing costs is included in Note 6. 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) September 30, 2006
---------------------------------------------------------------------------
Debt component on April 5, 2006 $ 73,298
Accretion of non-cash interest in the period 137
---------------------------------------------------------------------------
Debt portion, end of period 73,435
Equity component 1,702
---------------------------------------------------------------------------
Total Debentures, end of period $ 75,137
---------------------------------------------------------------------------
---------------------------------------------------------------------------


6. Financial Charges

During the nine months ended September 30, 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:


Three months ended Nine months ended
September 30 September 30
Financial charges ($000s) 2006 2005 2006 2005
---------------------------------------------------------------------------
Bank debt interest 1,276 1,625 3,883 3,501
Convertible debenture interest 1,360 - 2,654 -
Amortization of deferred financing
costs 180 - 348 -
Accretion of convertible debenture
liability 70 - 137 -
---------------------------------------------------------------------------
Total financial charges 2,886 1,625 7,022 3,501
---------------------------------------------------------------------------
---------------------------------------------------------------------------

A reconciliation of deferred financing costs is provided as follows:

As at
Deferred financing costs ($000s) September 30, 2006
---------------------------------------------------------------------------
Balance, beginning of period -
Deferred financing costs 3,426
Amortization (348)
---------------------------------------------------------------------------
Balance, end of period 3,078
---------------------------------------------------------------------------
---------------------------------------------------------------------------


7. 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 $55.0 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 9.0% and an inflation rate of 2.0% were used to calculate the fair value of the asset retirement obligations. The Trust periodically reviews the assumptions used in its asset retirement obligation calculation. In the current period, a revision was made to the liability to reflect an increase in the inflation rate.

A reconciliation of the asset retirement obligations is provided below:



Nine Months Ended Year ended
September 30 December 31
Asset retirement obligations ($000s) 2006 2005
---------------------------------------------------------------------------
Balance, beginning of period $ 24,774 $ 13,417
Liabilities incurred in the period 703 1,758
Liabilities assumed due to business
combination - Forte - 7,596
Liabilities assumed due to business
combination - Mustang - 5,019
Revision 1,513 (135)
Liabilities released due to
dispositions - (3,328)
Liabilities settled in the period (1,652) (1,306)
Accretion expense 1,904 1,753
---------------------------------------------------------------------------
Balance, end of period $ 27,242 $ 24,774
---------------------------------------------------------------------------
---------------------------------------------------------------------------


8. Unitholders' Capital

(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 of Thunder Energy Trust units (000s) ($000s)
---------------------------------------------------------------------------
Balance December 31, 2004 - $ -
Issued for common shares of Thunder Energy 24,246 174,050
Issued on Forte acquisition (Note 1) 6,475 99,288
Issued on Mustang acquisition (Note 1) 9,607 123,810
Reduction of capital, Ember conveyance (Note 1) - (19,893)
Reduction of capital, Clipper conveyance (Note 1) - (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
Unit issue costs, net of tax of $4 - 8
Distribution reinvestment program 697 7,265
Exchangeable shares converted 1,364 14,676
---------------------------------------------------------------------------
Balance March 31, 2006 46,028 $ 407,909
Distribution reinvestment program 1,031 9,500
Issued on exercise of Restricted Trust Units 104 1,301
Exchangeable shares converted 491 5,023
---------------------------------------------------------------------------
Balance June 30, 2006 47,654 $ 423,733
Distribution reinvestment program 1,005 8,242
Exchangeable shares converted 3 32
Unit issue costs related, net of tax of $16 - (50)
---------------------------------------------------------------------------
Balance September 30, 2006 48,662 $ 431,957
---------------------------------------------------------------------------
---------------------------------------------------------------------------


The Trust has a distribution reinvestment program ("DRIP") whereby unitholders can elect to reinvest their distributions back into the Trust and receive additional units rather than receive the cash payment. This accounted for a $25.0 million increase in unitholders' capital for the nine months ended September 30, 2006.



(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 (Note 1) 1,759 13,030
Issued on Forte acquisition (Note 1) 927 14,215
Issued on Mustang acquisition (Note 1) 997 12,849
Exchanged for Trust units (1,495) (14,713)
---------------------------------------------------------------------------
Balance December 31, 2005 2,188 $ 25,381
Exchanged for Trust units (1,265) (14,676)
---------------------------------------------------------------------------
Balance March 31, 2006 923 $ 10,705
Exchanged for Trust units (433) (5,023)
---------------------------------------------------------------------------
Balance June 30, 2006 490 $ 5,682
Exchanged for Trust units (3) (32)
---------------------------------------------------------------------------
Balance September 30, 2006 487 $ 5,650
---------------------------------------------------------------------------
---------------------------------------------------------------------------


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 the Exchange Ratio is calculated by multiplying the Thunder Energy Trust distribution per unit by the Exchange Ratio immediately prior to the 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 Thunder Energy 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 September 30, 2006, the Exchange Ratio was 1.19727. If the 0.5 million exchangeable shares outstanding at September 30, 2006 were exchanged at that time, 0.6 million Trust units would have been issued.

(c) Unit-based Compensation

For the three and nine months ended September 30, 2006, the Trust recorded a compensation expense relating to its Trust Unit Incentive Plan of $0.5 million and $1.3 million, respectively (2005 - $6.1 million and $7.9 million). The compensation expense was based on the September 29, 2006 unit closing price of $6.93, distributions of $0.15 per unit from January to April and $0.12 distributions per unit from May to September as well as management's estimate of the number of Restricted Trust Units ("RTUs") and Performance Trust Units ("PTUs") to be issued on maturity. No estimate has been made for forfeitures. The following table summarizes the RTU and PTU movement for the three and nine months ended September 30, 2006.



Restricted and Performance Trust units (000s) RTUs PTUs
---------------------------------------------------------------------------
Balance December 31, 2004 - -
Granted 283 59
---------------------------------------------------------------------------
Balance December 31, 2005 283 59
Granted 6 1
Cancelled (3) (1)
---------------------------------------------------------------------------
Balance March 31, 2006 286 59
Granted 224 104
Cancelled (3) -
Redeemed (104) -
---------------------------------------------------------------------------
Balance June 30, 2006 403 163
Granted 5 1
Cancelled (30) (11)
---------------------------------------------------------------------------
Balance September 30, 2006 378 153
---------------------------------------------------------------------------
---------------------------------------------------------------------------

---------------------------------------------------------------------------
Unit-based compensation ($000s)
---------------------------------------------------------------------------
Balance December 31, 2004 $ -
Unit-based compensation 1,295
---------------------------------------------------------------------------
Balance December 31, 2005 $ 1,295
Unit-based compensation 548
---------------------------------------------------------------------------
Balance March 31, 2006 $ 1,843
Unit-based compensation 204
Vested Restricted Trust Units (1,301)
---------------------------------------------------------------------------
Balance June 30, 2006 $ 746
Unit-based compensation 549
---------------------------------------------------------------------------
Balance September 30, 2006 $ 1,295
---------------------------------------------------------------------------
---------------------------------------------------------------------------


(d) Per Unit Amounts

The following table summarizes the weighted average Trust units, exchangeable shares and convertible debentures used in calculating net income per Trust unit:



Three months ended Nine months ended
September 30 September 30
Trust units (000s) 2006 2005 2006 2005
---------------------------------------------------------------------------
Weighted average Trust units 48,154 40,755 46,541 39,567
Exchangeable shares at exchange
ratio 489 3,328 854 3,466
---------------------------------------------------------------------------
Trust units (basic) 48,643 44,083 47,395 43,033
Convertible debentures 6,731 - 6,731 -
Restricted and Performance Trust
Units 473 309 343 1,486
---------------------------------------------------------------------------
Trust units (diluted) 55,847 44,392 54,469 44,519
---------------------------------------------------------------------------
---------------------------------------------------------------------------


Diluted Trust units include the dilutive impact of units issuable under the Trust Unit Incentive Plan. Diluted net income per unit adds back the effect of the convertible debentures which included an adjustment to net income of $1.0 million and $2.0 million, respectively for the three and nine months ended September 30, 2006.

9. 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
---------------------------------------------------------------------------
April 1/06 to
Costless Collar 15,000 AECO Cdn$6.00 to Cdn$6.50 Oct 31/06
Nov 1/06 to
Costless Collar 10,000 AECO Cdn$8.00 to Cdn$9.40 March 31/07
Nov 1/06 to
Costless Collar 10,000 AECO Cdn$8.00 to Cdn$10.00 March 31/07
---------------------------------------------------------------------------
---------------------------------------------------------------------------

Oil Volume Pricing Strike
Contracts bbls/d Point Price per bbl Term
---------------------------------------------------------------------------
Oct 1/06 to
Costless Collar 800 WTI NYMEX US$61.00 to US$72.70 Dec 31/06
Oct 1/06 to
Costless Collar 800 WTI NYMEX US$65.00 to US$80.70 Dec 31/06
Jan 1/07 to
Costless Collar 800 WTI NYMEX US$61.00 to US$73.05 Mar 31/07
Jan 1/07 to
Costless Collar 800 WTI NYMEX US$65.00 to US$80.00 Mar 31/07
---------------------------------------------------------------------------
---------------------------------------------------------------------------


The net effect of these contracts was a realized loss of $0.7 million and an unrealized gain of $8.2 million during the three months ended September 30, 2006 and a realized loss of $1.9 million and unrealized gain of $6.0 million during the nine months ended September 30, 2006.

Subsequent to September 30, 2006, 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
---------------------------------------------------------------------------
April 1/07 to
Costless Collar 10,000 AECO Cdn$6.50 to Cdn$8.10 Oct 31/07
---------------------------------------------------------------------------
---------------------------------------------------------------------------


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


10. Income Taxes

The Trust is a taxable entity under the Income Tax Act (Canada) 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 income and retained earnings differ from the tax calculated by applying the combined Canadian corporate federal and provincial income tax rate to income before taxes as follows:



Three months ended Nine months ended
September 30 September 30
Income taxes ($000s) 2006 2005 2006 2005
---------------------------------------------------------------------------
Statutory income tax rate for the
period 35.03% 37.75% 35.03% 37.75%
Computed income tax expense
(recovery) $ 966 $ 2,511 $ (1,733) $ 7,017
Add (deduct) income tax effect of:
Non-deductible Crown charges, net
of ARTC (43) 1,798 (131) 2,939
Resource allowance - (1,784) - (3,421)
Estimated taxable distribution (5,411) (6,342) (17,408) (6,342)
Tax rate adjustments (675) (53) (17,060) (979)
Unit-based compensation 193 2,307 456 2,983
Other 21 121 42 20
---------------------------------------------------------------------------
Future income tax (4,949) (1,442) (35,834) 2,217
Income tax (552) 375 158 788
---------------------------------------------------------------------------
Provision for income taxes
(recovery) $ (5,501) $ (1,067) $ (35,676) $ 3,005
---------------------------------------------------------------------------
---------------------------------------------------------------------------

11. Supplemental Cash Flow Information

Three months ended Nine months ended
Supplemental Cash Flow Information September 30 September 30
($000s ) 2006 2005 2006 2005
---------------------------------------------------------------------------
Changes in non-cash working
capital:
Accounts receivable $ 4,699 $ (22,441) $ 9,364 $ (12,902)
Prepaid expenses (949) (2,561) (922) (2,180)
Accounts payable and accrued
liabilities (9,872) 20,474 (17,112) (7,127)
---------------------------------------------------------------------------
$ (6,122) $ (4,528) $ (8,670) $ (22,209)
---------------------------------------------------------------------------

Changes in non-cash working
capital:
Operating activities 10,518 7,254 $ 992 $ (19,488)
Investing activities (16,640) (11,782) (9,662) (2,721)
---------------------------------------------------------------------------
$ (6,122) $ (4,528) $ (8,670) $ (22,209)
---------------------------------------------------------------------------

---------------------------------------------------------------------------
Cash payments made for interest $ 1,042 $ 1,411 $ 3,949 $ 3,507
---------------------------------------------------------------------------
Cash payments made for taxes $ 101 $ 5 $ 1,686 $ 66
---------------------------------------------------------------------------
---------------------------------------------------------------------------


12. Related Party Transactions

During the three and nine months ended September 30, 2006, the Trust incurred expenditures of $0.2 million and $0.5 million, respectively 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 September 30, 2006, $14,000 was included in accounts payable. The related party transactions were recorded at the exchange amount as services were provided in the normal course of business under the same terms and conditions as transactions with unrelated companies.


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