Vault Energy Trust
TSX : VNG.UN

Vault Energy Trust

March 15, 2007 06:00 ET

Vault Energy Trust Announces Fourth Quarter and Full Year 2006 Financial and Operating Results

CALGARY, ALBERTA--(CCNMatthews - March 15, 2007) - Vault Energy Trust (Vault) (TSX:VNG.UN) today announces the release of its fourth quarter and year ended December 31, 2006 financial and operating results.

Vault is pleased to report 2006 averaged production of 7,603 boe/d, a 33% increase over average production volumes of 5,716 boe/d in 2005. The increase in 2006 is attributable to recognition of full year production results from the June 2005 acquisition and the December 2005 acquisitions.

Production reported for the fourth quarter was higher than expected at 7,718 boe/d, and includes approximately 400 boe/d from prior quarters. Vault exited year end 2006 at approximately 7,000 boe/d with a number of production shut-ins which are expected to be back on stream prior to the end of the first quarter.

The Reserve report as stated in the February 22, 2007 news release, reaffirmed confidence in Vault's reserve base. Vault recorded 2006 year end Proved plus Probable reserves of 27.46 million BOE, which are within 3% of 2005 year end reserves. Vault added 1.86 million BOE Proved reserves and 1.92 million BOE Proved plus Probable reserves excluding acquisitions and disposition. This represents a 70% replacement of Proved plus Probable reserves and a 68% replacement of Proved reserves.

Finding and Development costs were $22.96 per boe on a proved basis and $22.97 per boe on a proved plus probable basis. Vault's F&D costs are in line with the trust sector average.

Vault will be filing a normal course issuer bid as one element of the ongoing business strategy. Vault believes today, on a per barrel basis, one of the best reserve acquisitions it can make is acquiring Vault units at their current value. By doing so, it allows Vault to effectively purchase reserves at approximately 50% of its peer group's 2006 finding and development costs. In 2007, Vault will focus on improving corporate netbacks per barrel of oil equivalent to further enhance unitholder value. Vault continues with its ongoing hedging program for production, and entered into two separate physical natural gas hedges for the winter of 2006/2007. Vault entered into another gas hedge for April through October 2007.

Overview

- Funds flow for 2006 was $50.8 million (2005- $52.5 million), primarily due to lower natural gas prices and higher production costs offset by higher production volumes.

- Vault records 2006 year end Proved plus Probable reserves of 27.46 million BOE, which are within 3% of 2005 year end reserves and reaffirms confidence in the Company's base reserves.

- Vault added 1.86 million BOE Proved and 1.92 million BOE Proved plus Probable excluding acquisitions and disposition. This represents a 70% replacement of Proved plus Probable reserves and a 68% replacement of Proved reserves.

- Production for 2006 averaged 7,603 boe/d, a 33% increase over average production volumes of 5,716 boe/d in 2005.

- Finding and Development costs (including the change in future development costs) were $22.96 per boe on a proved basis and $22.97 per boe on a proved plus probable basis.

- Vault drilled 12 (7.5 net) wells, with a 100% success rate resulting in 7 (3.4 net) gas and 5 (4.1 net) oil wells.

- Distributions payable in the year were $1.32 per Trust unit based on monthly payments of $.115 per Trust unit to unitholders of record from January to October and $.085 per Trust unit to unitholders of record in November and December.

- Vault raised $50 million in convertible debentures in May for repayment of revolving facility credit loan and to fund the 2006 capital expenditures program.

- 2006 year end tax pools totaled $472.8 million which is available for deduction against future taxable income.

Financial and Operating Highlights

Vault Energy Trust ("Vault" or the "Trust") announces its consolidated financial and operating results for the year ended December 31, 2006. Vault was created and commenced operations on June 22, 2005, subsequent to the reorganization of Chamaelo Energy Inc. ("Chamaelo") pursuant to a Plan of Arrangement.



Three months ended Year ended
December 31, December 31,
($ thousands, except per volume
and per Trust unit) 2006 2005 2006 2005
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FINANCIAL (1)

Petroleum and natural
gas revenue (2) 34,155 47,791 138,798 121,120

Funds flow from operations 10,661 26,761 50,841 52,475
per Trust unit - basic 0.30 0.82 1.47 2.21
per Trust unit - diluted 0.27 0.73 1.26 2.16

Net income (loss) (3,300) 4,573 (15,814) 10,482
per Trust unit - basic (0.09) 0.14 (0.46) 0.44
per Trust unit - diluted (0.09) 0.14 (0.46) 0.43

Distributions 10,236 11,309 45,714 29,708
Payout ratio 96% 42% 90% 57%
Capital expenditures 10,041 14,731 42,591 35,003
Bank debt 56,000 81,500 56,000 81,500
Working capital deficit 16,482 17,293 16,482 17,293

Trust units outstanding
(thousands) (3)
weighted average - basic 35,828 32,740 34,542 23,742
- diluted 37,088 28,094
end of period - basic 36,106 32,785 36,106 32,785

OPERATIONS (units as noted)

Average daily production
Natural gas (mcf) 27,184 29,363 28,366 20,630
Crude oil (bbls) 2,692 2,582 2,435 1,939
Natural gas liquids (bbls) 496 443 440 339
------ ------ ------ -------
Total (BOE) 7,718 7,919 7,603 5,716

Average sales price (4)
Natural gas ($ per mcf) 6.83 11.26 6.48 9.43
Crude oil ($ per bbl) 58.08 66.26 67.37 65.89
Natural gas liquids ($ per bbl) 48.96 73.64 60.80 59.16

Netback per BOE ($ per BOE)
Petroleum and natural gas revenue 48.10 65.60 50.01 58.06
Royalties 6.86 11.77 8.44 10.96
Production expense 17.45 10.76 16.17 11.20
------ ------ ------ -------
Operating netback 23.79 43.07 25.40 35.90

Wells drilled (gross/net) 2 (.7) 31 (19.9) 12(7.5) 44 (31.3)
Undeveloped land (net acres) 133,000 161,900 133,000 161,900
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(1) For 2005, the results reflect the operations of Chamaelo from January
1, 2005 to June 21, 2005 plus the operations of Vault for the 193-day
period from June 22, 2005 to December 31, 2005.
(2) Petroleum and natural gas revenue are shown net of transportation costs.
(3) Prior period per Trust unit amounts based on 2 Chamaelo shares for 1
Trust unit.
(4) Net of oil and gas transportation costs.


Management's Discussion and Analysis

Management's Discussion and Analysis ("MD&A") should be read in conjunction with the consolidated financial statements of Vault Energy Trust ("Vault" or the "Trust") for the years ended December 31, 2006 and 2005, together with accompanying notes. Barrel of oil equivalent ("BOE") amounts have been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of crude oil ("6:1") unless otherwise stated. The financial statements and financial data contained in the MD&A have been prepared in accordance with Canadian generally accepted accounting principles ("Canadian GAAP") in Canadian currency (except where noted as being in another currency).

Additional information related to the Trust, including the Trust Indenture, may be found on the SEDAR website at www.sedar.com.

This MD&A may contain forward-looking information that involves a number of risks and uncertainties that could cause actual results to differ materially from those anticipated. For this purpose, any statements herein that are not statements of historical fact may be deemed to be forward-looking statements. Such risks and uncertainties include, but are not limited to: risks associated with the oil and gas industry (e.g. - operational risks in exploration, development and production; changes and/or delays in the development of capital assets; uncertainty of reserve estimates; uncertainty of estimates and projections relating to production and costs; commodity price fluctuations; environmental risks; and industry competition).

Management uses financial measures such as funds flow, funds flow per unit, distributable cash, distributable cash per unit, payout ratio and operating netback as a factors in evaluating performance. These financial measures do not have any standardized meaning prescribed by Canadian GAAP and therefore may not be comparable to similar measures used by other companies. Vault uses these measures as it believes they facilitate the understanding of the operating results and the Trust's financial position. Vault calculated funds from operations prior to the change in non-cash working capital relating to operating activities, with the per unit amount calculated using a weighted average units outstanding for the period.

Plan of Arrangement

The reorganization of Chamaelo Energy Inc. into Vault Energy Trust and a newly created exploration focused junior oil and gas producer was completed on June 22, 2005 pursuant to a Plan of Arrangement ("Plan of Arrangement") involving Chamaelo Energy Inc. ("Chamaelo"), Vault Energy Inc. ("Vault Energy"), Vault Energy Trust ("Vault" or "the Trust") and a new exploration focused entity ("Chamaelo Exploration"). Concurrent with the Plan of Arrangement, Vault Energy acquired certain petroleum and natural gas properties in West Central Alberta and North Eastern British Columbia (the "June 2005 Acquisition") for approximately $365.6 million, including transaction costs, net of estimated closing adjustments. The operating results from the June 2005 Acquisition have been included in the Trust's operational results for 193 days from the closing date on June 22, 2005 to the end of the period. In addition, pursuant to the Plan of Arrangement, Vault Energy disposed of certain oil and natural gas assets to Chamaelo Exploration ("Chamaelo Exploration Disposition"), on June 22, 2005. The results of operations from the Chamaelo Exploration Disposition assets have been included in results from operations of the Trust only up to the date of the disposition. The comparative figures used in the MD&A and consolidated financial statements are those of Chamaelo as the Trust is following the continuity of interests accounting method.



Summary of Financial Results (1) 2006 2005
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($ thousands, except per Trust unit amounts)
Petroleum and natural gas revenue(2) 138,798 121,120

Funds flow from operations 50,841 52,475
per Trust unit - basic 1.47 2.21
per Trust unit - diluted 1.26 2.16

Net income (loss) (15,814) 10,482
per Trust unit - basic (0.46) 0.44
per Trust unit - diluted (0.46) 0.43

Total assets 519,659 543,176

Bank debt 56,000 81,500

Working capital deficit 16,482 17,293

Total long-term liabilities 140,143 91,779
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(1) For 2005, the results reflect the operations of Chamaelo from January
1, 2005 to June 21, 2005 plus the operations of Vault for the 193-day
period from June 22, 2005 to December 31, 2005.
(2) Petroleum and natural gas revenue are shown net of transportation
costs.


Production

Daily production averaged 7,603 BOE per day, a 33% increase over average production volumes of 5,716 BOE per day in 2005. The increase in 2006 is attributable to recognition of full year production results from the June 2005 Acquisition and the December 2005 acquisitions. Production reported for the 4th quarter was higher than expected at 7,718 BOE per day and includes approximately 400 BOE per day from prior quarters. Vault exited yearend 2006 at approximately 7,000 BOE per day. Production guidance for 2007 remains unchanged at 7,000 to 7,200 BOE per day.

Average daily production for the fourth quarter and years ended December 31, 2006 and 2005 are outlined below:



Three months ended Year ended
December 31, December 31,
Average Daily % %
Production (1) 2006 2005 Change 2006 2005 Change
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Natural gas (mcf per day) 27,184 29,363 (7) 28,366 20,630 37
Crude oil (bbls per day) 2,692 2,582 4 2,435 1,939 26
Natural gas liquids (bbls
per day) 496 443 12 440 339 30
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Total (BOE per day) 7,718 7,919 (3) 7,603 5,716 33
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(1) For 2005, the results reflect the operations of Chamaelo from January 1,
2005 to June 21, 2005 plus the operations of Vault for the 193-day
period from June 22, 2005 to December 31, 2005.


Pricing

The Trust's earnings, funds flow and financial condition are dependent on the prices received for our petroleum and natural gas production. Petroleum and natural gas prices have fluctuated widely during recent years.



Three months ended Year ended
December 31, December 31,
% %
Average Sales Price(1) 2006 2005 Change 2006 2005 Change
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Before effect of physical hedges:
Natural gas ($ per mcf) 6.83 11.26 (39) 6.48 9.43 (31)
Crude oil ($ per bbl) 58.08 66.26 (12) 67.37 65.89 2
Natural gas liquids ($ per bbl) 48.96 73.64 (34) 60.80 59.16 3
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Average sales price ($ per BOE) 46.28 67.47 (31) 49.25 59.90 (18)
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Effect of physical hedges:
Natural gas ($ per mcf) 0.55 (0.35) - 0.42 (0.37) -
Crude oil ($ per bbl) (0.31) (1.73) - (2.51) (1.51) -
Natural gas liquids ($ per bbl) - - - - - -
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Average sales price ($ per BOE) 1.82 (1.87) - 0.76 (1.84) -
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Net sales price:
Natural gas ($ per mcf) 7.38 10.91 (32) 6.90 9.06 (24)
Crude oil ($ per bbl) 57.77 64.53 (10) 64.86 64.38 1
Natural gas liquids ($ per bbl) 48.96 73.64 (34) 60.80 59.16 3
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Average sales price ($ per BOE) 48.10 65.60 (27) 50.01 58.06 (14)
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(1) Net of oil and gas transportation costs

% %
Average Benchmark Pricing 2006 2005 Change 2006 2005 Change
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Natural Gas
AECO Daily Index (Cdn$ per mcf) 6.90 11.39 (39) 6.51 8.73 (25)
AECO Monthly Index (Cdn$ per mcf) 6.48 11.89 (46) 7.16 8.58 (17)
Crude Oil
West Texas Intermediate (US$ per
bbl) 60.06 60.07 - 66.09 56.45 17
West Texas Intermediate (Cdn$ per
bbl) 68.41 70.48 (3) 74.96 68.35 10
Edmonton Par (Cdn$ per bbl) 65.15 71.66 (9) 73.31 69.28 6
Exchange Rates
US$/CDN$ Dollar Period-end 1.17 1.17 - 1.17 1.17 -
US$/CDN$ Dollar Average 1.14 1.17 (3) 1.13 1.21 (7)
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Commodity Price Risk Management

Currently, the Trust does not have any financial derivative instruments to hedge against future commodity price fluctuations. Subsequent to December 31, 2006, the Trust entered into a physical sales contract for delivery of 2,500 GJs per day of natural gas during the November 2007 to March 2008 period at a floor price of $7.85 per GJ with 50% participation on prices in excess of $7.85 per GJ.

The Trust will continue to monitor commodity prices and will implement price risk management programs as necessary to assist with the sustainability of distributions and growth of the organization given the risk inherent in the sale of oil and natural gas commodities.

The Trust has physical sales contracts in place representing approximately 35% of its 2007 estimated production. A summary of the physical instruments is as follows:



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Floor Upside
Product Volume price Participation Term
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Natural gas 4,000 GJ/day $7.50/GJ 61.75% above $7.50/GJ Nov 1, 2006
- Mar 31, 2007
Natural gas 7,000 GJ/day $7.50/GJ 61% above $7.50/GJ Jan 1, 2007
- Mar 31, 2007
Natural gas 2,500 GJ/day $7.00/GJ Max price $9.00/GJ Apr 1, 2007
- Oct 31, 2007
Natural gas 7,500 GJ/day $7.60/GJ N/A Apr 1, 2007
- Oct 31, 2007
Natural gas 2,500 GJ/day $7.85/GJ 50% above $7.85/GJ Nov 1, 2007
- Mar 31, 2008
Crude Oil 1,000 bbls/day $68.00/bbl 50% above $68.00/bbl Jan 1, 2007
- Dec 31, 2007
Electricity 5 MWH $60.75/MW N/A Apr 1, 2006
- Dec 31, 2008
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Petroleum and natural gas revenue

Petroleum and natural gas revenue, net of transportation was $138.8 million (2005 - $121.1 million) in 2006. The increase in revenue of $17.7 million or 15% is primarily due to the impact of including full year production results from the June 2005 asset acquisition. Transportation expense for the year was $4.8 million (2005 - $3.6 million), up 34% with the increased production.

Natural gas prices averaged 31% lower in the year, while crude oil prices averaged marginally higher by 2% compared to the previous year. The price of natural gas is based primarily on the supply and demand fundamentals in the North American markets. Natural gas prices began to weaken in early 2006 as North America experienced one of its mildest winters on record. This weakness continued through most of 2006 with relatively uneventful weather resulting in a build of historic natural gas inventories. These high inventory levels can decrease rapidly from a weather change and we continue to be bullish on the long-term pricing fundamentals. Crude oil prices have remained at high levels due to the continued global demand, significant geopolitical and weather related issues, and concerns regarding lack of North American refining capacity. These key issues persist and will continue to impact overall crude oil commodity prices.



Analysis of Sales Revenue(1)
($ thousands) Natural Gas Crude Oil NGLs Total
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2005 Sales Revenue 68,241 45,556 7,323 121,120
Price Variance (16,288) 1,051 164 (15,073)
Volume Variance 19,423 11,043 2,285 32,751
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2006 Sales Revenue 71,376 57,650 9,772 138,798
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(1) Net of oil and gas transportation costs and including the effect of
physical hedges reflecting the operations of Chamaelo from January 1,
2005 to June 21, 2005 plus the operations of Vault for the 193-day
period from June 22, 2005 to December 31, 2005.


The physical natural gas and crude oil hedges increased revenues by $2.1 million, compared to a decrease of $3.8 million in 2005.



Revenue(1) ($ thousands) 2006 2005
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Petroleum and natural gas revenue, before hedging 136,706 124,959

Hedging receipts (payments) 2,092 (3,839)
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Total revenue 138,798 121,120
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(1) Net of oil and gas transportation costs. For 2005, results reflect the
operations of Chamaelo from January 1, 2005 to June 21, 2005 plus the
operations of Vault for the 193-day period from June 22, 2005 to
December 31, 2005.


Royalties

Royalties are paid to various government entities and other land and mineral rights owners. Royalties are shown net of Alberta Royalty Tax Credit which is a royalty rebate provided by the Alberta government to certain producers and will be eliminated effective January 1, 2007. In 2006 royalties increased marginally to $23.4 million or 16% of petroleum and natural gas revenue compared to $22.9 million or 18% in 2005. The increase is consistent with our increased production due to the 2005 acquisitions offset partly by lower natural gas prices. The percentage decrease is due to a combination of higher gas cost allowance claims and lower average gas prices in the year.

Production Expense

Production expenses for the year ended December 31, 2006 were $44.9 million or $16.17 per BOE compared to $23.4 million or $11.20 per BOE in 2005. This represents a 44% increase on a per BOE basis. 2006 presented a challenging year for production expenses. During the course of the year, Vault completed significant scheduled facility maintenance programs at its Wimborne and Keho gas facilities and at a majority of its Pembina and Bigoray oil facilities. Facility maintenance costs for the year totaled $5.5 million representing $1.97 per BOE prior to any adjustment for production downtime. Facility maintenance costs for 2007 are estimated at approximately $500,000. Well maintenance costs, most notably the run time for electrical submersible pumps in the Wimborne area continue to present operational challenges. During 2006 approximately $3.4 million was spent in the Wimborne area on well maintenance. Future production expenses will continue to be influenced by the number of workovers, well suspensions and also the availability of services in 2007. Management of production expenses will be a challenge as Vault is committed to focusing efforts on opportunities that will improve operational efficiencies and reduce per BOE production expenses to enhance operating netbacks.



Operating Netback

Three months ended Year ended
December 31, December 31,
% %
Operating Netback(1) 2006 2005 Change 2006 2005 Change
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Natural gas ($ per mcf)
Revenue 7.38 10.91 (32) 6.90 9.06 (24)
Royalties 1.12 2.38 (53) 1.36 2.05 (34)
Production expense 2.58 1.79 44 2.25 1.69 33
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Operating Netback 3.68 6.74 (45) 3.29 5.32 (38)
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Crude oil and NGL ($ per bbl)
Revenue 53.54 65.87 (19) 64.24 63.61 1
Royalties 7.04 7.72 (9) 8.86 8.93 (1)
Production expense 20.28 10.77 88 20.52 12.80 60
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Operating Netback 26.22 47.38 (45) 34.86 41.88 (17)
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Combined ($ per BOE)
Revenue 48.10 65.60 (27) 50.01 58.06 (14)
Royalties 6.86 11.77 (42) 8.44 10.96 (23)
Production expense 17.45 10.76 62 16.17 11.20 44
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Operating Netback 23.79 43.07 (45) 25.40 35.90 (29)
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(1) Revenue is shown net of oil and gas transportation costs and including
the effect of physical hedges. Results reflect the operations of
Chamaelo from January 1, 2005 to June 21, 2005 plus the operations of
Vault for the 193-day period from June 22, 2005 to December 31, 2005.


The operating netback is a key indicator of the Trust's ability to generate funds flow for distribution and reinvestment. During 2006, Vault generated an operating netback of $ 25.40 per BOE (2005 - $35.90) per BOE. The 29% decrease is attributable primarily to lower natural gas prices and higher production expenses in the year.



A reconciliation of the 2006 operating netback by components compared to
2005 is as follows:

Operating netback reconciliation (1) ($ thousands) 2006
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Production increase 33,964
Price decrease, net of hedging (15,073)
Transportation increase (1,213)
Royalty increase (577)
Production expense increase (21,492)
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Decrease in net operating income (4,391)
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General and Administrative Expenses ("G&A")

G&A costs, net of overhead recoveries on operated properties, amounted to $8.1 million or $2.91 per BOE as compared to $6.3 million or $3.03 per BOE in 2005. Gross G&A costs have increased in 2006 primarily due to a combination of the addition of technical and administrative staff to manage the increased asset and production base and higher costs due to escalating labour markets. G&A costs on a per BOE basis have decreased due to the production increases resulting from the 2005 property acquisitions.

Unit-based Compensation

During 2006, $4.4 million was charged to income in respect of unit-based payments as compared to $4.3 million in 2005. The Trust uses the fair value method of allocating value to Trust unit rights. The unit-based compensation recognized represents the amortization of this fair value to income over the vesting period with an offset to contributed surplus. In the second quarter an amount of $285,000 was recovered that was previously charged to unit based compensation. This recovery is the result of Chamaelo Energy Inc. retention payments being lower then originally estimated.

Interest Expense

The Trust incurred $10.0 million or $ 3.59 per BOE (2005 - $5.3 million or $2.56 per BOE) in interest expense for the year ended December 31, 2006. The inclusion of a full year interest on the 8% debenture issued last year and drawing on available lines of credit to fund capital expenditure programs has increased overall interest expense. On May 2, 2006, a $50 million convertible 7.2% debenture was issued and the proceeds were used to paydown bank debt. The Trust's average interest rate on credit facilities for the year was 5.8 % (2005 - 4.5%).

Depletion, Depreciation and Accretion ("DD&A")

During 2006, DD&A expense was $68.8 million or $24.80 per BOE as compared to $40.0 million or $19.16 per BOE in 2005. The DD&A rate partially reflects the higher cost of the corporate and property acquisitions made in 2005 together with the inclusion of asset retirement obligations in the Trust's depletion base. During the year ended December 31, 2006, the provision for DD&A includes $2.1 million or $0.76 per BOE as compared to $1.4 million or $0.67 per BOE in 2005, for accretion of asset retirement obligations.



2006 2005
Depletion and depreciation and accretion $'000 $/BOE $'000 $/BOE
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Depletion and depreciation expense 65,156 23.47 38,027 18.23
Accretion of asset retirement obligations 2,095 0.76 1,398 0.67
Other 1,573 0.57 543 0.26
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Total 68,824 24.80 39,968 19.16
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Under Canadian GAPP, a ceiling test is applied to the carrying value of the property, plant and equipment and other assets. The carrying value is assessed to be recoverable when the sum of the undiscounted cash flow expected from the production of proved reserves; the lower of cost and market of unproved properties; and the cost of major development projects exceeds the carrying value. When the carrying value is not assessed to be recoverable, an impairment loss is recognized to the extent that the carrying value of assets exceeds the sum of discounted cash flows expected from the production of proved and probable reserves; the lower of cost and market of unproved properties; and the cost of major development projects. The cash flows are estimated using future product prices and costs are discounted using a risk free interest rate. At December 31, 2006, the undiscounted cash flows were in excess of the carrying value.

Goodwill Impairment

Goodwill was recorded on the Capstone acquisition in 2004 when the purchase price was in excess of the fair values assigned to the assets acquired and liabilities assumed. To assess impairment, the fair value of the goodwill was determined and compared to the carrying value. As the carrying amount of the goodwill exceeds its fair value, a goodwill impairment of $4.2 million was recognized and charged to income in the period.

Taxes

Current income taxes for the year ended December 31, 2006 were $92,000 as compared to $546,000 in 2005. The decrease in the period is due to the elimination of the federal Large Corporation Tax effective January 1, 2006.

Future income taxes arise from differences between the accounting and tax bases of the operating company's assets and liabilities. Payments are made between the operating company and the Trust in our current structure, which ultimately transfers both income and future tax liability to our unitholders. Therefore, it is Vault's opinion that no cash income taxes are expected to be paid by the operating entities in the near future. As a result, the future income tax liability recorded on the balance sheet should be recovered through earnings over time.

For the year ended December 31, 2006, a future tax recovery of $7.7 million was recorded as compared to a recovery of $1.5 million recorded in 2005. This 2006 tax recovery includes $0.8 million due to enacted changes to statutory tax rates.

On October 31, 2006, the Minister of Finance announced proposed tax legislation which if enacted would modify the taxation of certain flow-through entities including mutual fund trusts and their unitholders. The proposed legislation will apply to specified investment flow-through trusts and will apply a tax at the trust level on distributions of certain income from such specified investment flow-through trusts at a rate of tax comparable to the combined federal and provincial corporate tax rate. These distributions will be treated as dividends to the trust unitholders. Currently, the Trust does not pay tax on distributions as tax is paid by the unitholders. If enacted, the proposals would apply to the Trust subject to certain grandfathering rules in place effective January 1, 2011, however the legislation has not been enacted at this time. The Trust is currently assessing the proposals and the potential implications.

Funds Flow and Net Loss

Funds flow from operations for the year ended December 31, 2006 was $50.8 million ($ 1.26 per diluted Trust unit) as compared to $52.5 million ($2.16 per diluted Trust unit) in 2005.

The Trust had a net loss of $15.8 million (-$0.46 per diluted Trust unit) for the year ended December 31, 2006 compared to net income of $10.5 million ($0.43 per diluted Trust unit) in 2005.



Capital Expenditures

Capital Expenditures(1)
($ thousands) 2006 2005
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Land 1,721 1,612
Drilling, completions and workovers 27,020 25,596
Equipment 11,367 3,593
Geological and Geophysical 1,378 1,842
Office 1,105 2,360
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Capital expenditures 42,591 35,003
Property acquisitions, net of dispositions (3,284) 365,592
Corporate acquisitions - 23,598
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Total capital expenditures and property acquisitions 39,307 424,193
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(1) For 2005, results reflect the operations of Chamaelo from January 1,
2005 to June 21, 2005 plus the operations of Vault for the 193-day
period from June 22, 2005 to December 31, 2005.


During the year ended December 31, 2006, Vault drilled 12 (7.5 net) wells versus 44 (31.3 net) wells in 2005. In addition, Vault completed numerous well workovers and recompletions primarily at Wimborne to sustain production. Capital expenditures for drilling, completions and workovers totaled $27.0 million is allocated as follows: drilling $ 12.3 million (2005 - $12.0 million), completions $ 6.5 million (2005 - $5.5 million), and workovers $8.2 million (2005 - $8.1 million). Approximately 65 % of the expenditures were incurred at our core properties, namely Bigoray, Pembina, and Wimborne. Capital expenditures totaled $ 42.6 million (2005 - $35.0 million) for the year ended December 31, 2006. Proceeds received from the disposition of non-core properties and equipment were $4.0 million.

Distributable Cash

Distributions are paid monthly on or about the 15th day of each month with the record date being the last business day of the preceding calendar month or such other date as may be determined. A portion of cash flow is retained to fund acquisitions and development activity.

The Trust will monitor the payout level with respect to cash flow, debt levels and spending plans. We will continue to distribute a significant portion of our cash flow with the distribution level set by the Board of Directors dependent on the level of commodity prices and the success of the Trust's drilling and development program. However we are prepared to adjust the payout ratio in an effort to align the investors' desire for cash distributions with the Trust's requirement to maintain a prudent capital structure.

During the year ended December 31, 2006, Vault distributed $45.7 million (2005 - $29.7 million) or $1.32 (2005 - $0.92) per Trust unit to unitholders. As a result of lower natural gas commodity prices and higher production expenses prevailing in the year, the Trust lowered its monthly distribution from $0.115 to $.085 per Trust unit effective for the December 15, 2006 distribution payment.




Reconciliation of Cash Available Year ended 193 days ended(1)
for Distribution ($ thousands) December 31, 2006 December 31, 2005
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Cash flow from operating activities 45,609 58,209
Change in non-cash working capital 5,232 (5,734)
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Funds flow from operations 50,841 52,475
Cash withheld for acquisitions, capital
expenditures and debt repayment(2) (5,127) (22,767)
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Distributions 45,714 29,708
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Distributions per Trust unit $ 1.32 $ 0.92
Payout ratio 90% 57%
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(1) Represents the period from the inception of the Trust on June 22, 2005
to December 31, 2005 and includes a special distribution on June 30,
2005.
(2) Cash withheld for acquisition, capital expenditures and debt repayment
is a discretionary amount and represents the difference between funds
flow from operations and distributions.


Liquidity and Capital Resources

Bank debt was $56.0 million (2005 - $81.5 million) and the working capital deficit, which includes bank overdraft of $7.4 million, was $16.5 million (2005 - $17.3 million) at December 31, 2006.

The Trust has, through its subsidiary, a credit agreement with a syndicate of Canadian banks to provide the Trust with $125,000,000 of total credit facilities. This is comprised of an extendible revolving term credit facility of $115,000,000 and a $10,000,000 operating facility each bearing interest at prime plus a premium ranging between 0% and 1.75% based on the Trust's debt to cash flow ratio. The credit facilities are secured by a $200,000,000 demand debenture on the assets of Vault Energy and have been renewed to June 29, 2007.



Quarterly Financial Information

Summary of Quarterly Results

($ thousands) Q1/05 Q2/05 Q3/05 Q4/05
----------------------------------------------------------------------------

Production:
Natural gas (mcf per day) 10,323 11,611 30,899 29,363
Crude oil and NGL (bbls per day) 1,383 1,475 3,200 3,025
----------------------------------------------------------------------------
Total BOE (Natural Gas 6:1) 3,104 3,410 8,350 7,919
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Petroleum and natural gas revenue (1) 13,489 15,993 43,847 47,791

Funds flow from operations 6,902 (2,377) 21,188 26,761
per Trust unit - basic 0.50 (0.15) 0.66 0.82
per Trust unit - diluted 0.46 (0.15) 0.57 0.73

Net income (loss) 1,479 (6,241) 10,671 4,573
per Trust unit - basic 0.10 (0.39) 0.33 0.14
per Trust unit - diluted 0.10 (0.39) 0.29 0.14
----------------------------------------------------------------------------


($ thousands) Q1/06 Q2/06 Q3/06 Q4/06
----------------------------------------------------------------------------

Production:
Natural gas (mcf per day) 29,428 29,502 27,388 27,184
Crude oil and NGL (bbls per day) 2,912 3,041 2,364 3,188
----------------------------------------------------------------------------
Total BOE (Natural Gas 6:1) 7,817 7,958 6,929 7,718
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Petroleum and natural gas revenue (1) 36,175 36,310 32,158 34,155

Funds flow from operations 15,578 15,499 9,102 10,661
per Trust unit - basic 0.47 0.45 0.26 0.30
per Trust unit - diluted 0.42 0.38 0.23 0.27

Net income (loss) (1,280) 2,607 (13,841) (3,300)
per Trust unit - basic (0.04) 0.08 (0.40) (0.09)
per Trust unit - diluted (0.04) 0.07 (0.40) (0.09)
----------------------------------------------------------------------------

(1) Petroleum and natural gas revenue are shown net of transportation costs.


Summary Fourth Quarter Information

In comparing the fourth quarter of 2006 with the same period in 2005:

- Production reported for the 4th quarter was higher than expected at 7,718 BOE per day and includes approximately 400 BOE per day from prior quarters. Vault exited yearend 2006 at approximately 7,000 BOE per day.

- Funds flow from operations decreased 60% to $10.7 million (2005 - $26.8 million) as a result of lower oil and gas wellhead prices and higher production costs in the period.

- The average sales price of $46.28 per BOE decreased 31% as impacted from lower natural gas and crude oil prices by 39% and 12% respectively in the quarter.

- Production expense increased by $4.5 million to $17.45 per BOE (2005- $10.76 per BOE) due to significantly higher field supplies and service costs, and additional well workover maintenance expenses.

- G&A expenses in the quarter were relatively unchanged at $2.3 million from last year. Higher staffing costs in 2006 with the increased asset base was offset by higher field and overhead recoveries.

- Net loss for the period was $3.3 million, compared to net income of $4.6 million last year.

Trust Unit Information

The Trust is authorized to issue an unlimited number of Trust units. The Trust units are traded on the Toronto Stock Exchange under the symbol "VNG.UN". At December 31, 2006, the Trust had 36,105,737 (2005 - 32,785,833) Trust units and 2,126,063 (2005 - 3,560,586) exchangeable shares outstanding.

The increase in Trust units during the year is a result of 1,615,358 issued for exchangeable shares, 81,364 issued for warrants exercised, and 1,623,182 units issued pursuant to the Distribution Reinvestment and Optional Purchase Plan ("DRIP").

Commitments

The Trust is committed to payments under an operating lease for office space and capital leases for leased vehicles as at December 31, 2006:



----------------------------------------------------------------------------
Total
Committed
Minimum Commitments Each Year After
($ thousands) 2007 2008 2009 2010 2011 2011 Total
----------------------------------------------------------------------------
Capital lease
obligations 212 248 12 13 - 485
Operating lease
obligation 1,619 1,698 1,742 1,746 1,746 3,637 12,188
----------------------------------------------------------------------------
1,831 1,946 1,754 1,759 1,746 3,637 12,673
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Debt commitments are outlined in the Notes to the Consolidated Financial
Statements.


As at December 31, 2006, the Trust in its normal course of business has issued bank letter of credits in the amount of $671,000 to various governmental agencies to cover capital and operating performance requirements.

Critical Estimates

Management is required to make judgments, assumptions, and estimates in the application of generally accepted accounting principles that have a significant impact on the financial results of the Trust. These estimates and assumptions are developed based on the best available information and are believed by management to be reasonable under the existing circumstances. New events or additional information may result in the revision of these estimates over time. The following summarizes the accounting policies that are critical to determining the company's financial results.

Petroleum and Natural Gas Reserves - The Trust's petroleum and natural gas reserves are evaluated and reported on by independent petroleum engineers. The estimates of reserves is a very subjective process as forecasts are based on engineering data, projected future rates of production, estimated future commodity prices and the timing of future expenditures, which are all subject to uncertainty and interpretation. Reserve estimates can have a significant impact on earnings, as they are a key component in the calculation of depletion. A downward revision to the reserve estimate could result in higher depletion and thus lower net earnings. In addition, estimated reserves are also used in the calculation of the impairment (ceiling) test.

Critical Accounting Policies

Full Cost Accounting - The Trust follows the full cost method of accounting whereby all costs related to the acquisition of, exploring for and developing petroleum and natural gas reserves are capitalized and charged against earnings. These costs, together with the estimated future costs to be incurred in developing proved reserves, are depleted or depreciated using the unit-of-production method based on the proved reserves before royalties as estimated by independent petroleum engineers. The costs of undeveloped properties are excluded from the costs subject to depletion and depreciation until it is determined whether proved reserves are attributable to the properties or impairment occurs. Petroleum and natural gas properties are evaluated each reporting period through an impairment test to determine the recoverability of capitalized costs. The carrying amount is assessed as recoverable when the sum of the undiscounted cash flows expected from proved reserves plus the cost of unproved interests, net of impairments, exceeds the carrying amount. When the carrying amount is assessed not to be recoverable, an impairment loss is recognized to the extent that the carrying amount exceeds the sum of the discounted cash flows from proved and probable reserves plus the cost of unproved interests, net of impairments.

The cash flows are estimated using expected future prices and costs and are discounted using a credit adjusted risk-free interest rate. Proceeds from the sale of petroleum and natural gas properties are applied against capitalized costs, with no gain or loss recognized, unless such a sale would result in a change in the depletion rate of 20% or more.

Goodwill - Goodwill, which represents the excess of purchase price over the fair value of net assets received in an acquisition, is tested for impairment on an annual basis in the fourth quarter. A goodwill impairment loss would be recognized when the carrying amount of goodwill exceeds its fair value. Should the test result in an impairment, it will be charged to income in the period of the impairment.

Asset Retirement Obligation - The Trust is required to provide for future abandonment and site restoration costs. These costs are estimated based on existing laws, contracts or other policies and are presented as asset retirement obligation. The obligation is initially measured at fair value and subsequently adjusted for the accretion of discount and any changes to the underlying cash flows. The asset retirement cost is capitalized to petroleum and natural gas properties and equipment and amortized into earnings on a basis consistent with depletion and depreciation. The estimate of the asset retirement obligation involves estimates relating to the timing of abandonment, the economic life of the underlying asset and the costs associated with abandonment and site restoration which are all subject to uncertainty and interpretation.

Exchangeable shares and Non-controlling Interests - Exchangeable shares in Vault Energy were issued pursuant to the Plan of Arrangement. The exchangeable shares are transferable and are retractable for Trust units. As such, they have been classified outside of equity as a non-controlling interest. Net income (loss) as reported is net of net income (loss) attributable to non-controlling interest.

Convertible debentures - Convertible debentures are initially recorded at the fair value of the obligation without the conversion feature. The difference between the principal amount and the fair value without the conversion feature is recorded in unitholders' equity as equity component of convertible debentures. The obligation is accreted through earnings using the effective interest rate method and the equity component of convertible debentures is increased as the debentures are converted for Trust units.

Recent Canadian Accounting and Related Pronouncements

Financial Instruments - Recognition and Measurement, Hedges, and Comprehensive Income

In an effort to harmonize Canadian standards with United States and International accounting standards, the Canadian Accounting Standards Board has recently issued the following new Handbook sections which are effective for annual and interim periods in fiscal years beginning on or after October 1, 2006:

- 1530 ; Comprehensive Income

- 3855 ; Financial Instruments - Recognition and Measurement

- 3861 ; Financial Instruments - Disclosure and Presentation; and

- 3865 ; Hedges

Under these new standards, all financial assets should be measured at fair value with the exception of loans, receivables, and investments that are intended to be held to maturity and certain equity investments, which should be measured at cost. Similarly, all financial liabilities should be measures at fair value when they are either derivatives or held for trading. Gains and losses on financial instruments measured at fair value will be recognized in net income in the periods they arise with the exception of gains and losses arising from:

- Financial assets held for sale, for which unrealized gains and losses are deferred in other comprehensive income until sold or impaired; and

- Certain financial instruments that qualify for hedge accounting

Section 3855 and 3865 make use of the term "other comprehensive income". Unrealized gains and losses on qualifying hedging instruments, unrealized foreign exchange gains and losses, and unrealized gains and losses on financial instruments held for sale will be included in other comprehensive income and reclassified to net income when realized. Comprehensive income and its components will be a required disclosure under the new standard. Section 3861 addresses the presentation of financial instruments and non-financial derivatives, and identifies disclosure of information.

The Trust will be adopting these new measures effective January 1, 2007 and does not anticipate that this section will have a material impact on our results of operations or financial position.

Risk Assessment

The acquisition, exploration and development of petroleum and natural gas assets involves many risks common to all participants in the petroleum and natural gas industry. Vault's exploration and development activities are subject to various business risks such as unstable commodity prices, interest rate and foreign exchange fluctuations, the uncertainty of replacing production and reserves on an economic basis, government regulations, taxes and safety and environmental concerns. As such, the funds flow paid to unitholders as well as the value of Vault's trust units are subject to such risks. While the management of Vault realizes these risks cannot be eliminated, they are committed to monitoring and mitigating these risks.

Reserves and Reserve Replacement

The recovery and reserve estimates on Vault's properties are estimates only and the actual reserves may be materially different from that estimated. The estimates of reserve values are based on a number of variables including price forecasts, projected production volumes and future production and capital costs. All of these factors may cause estimates to vary from actual results.

Vault's future petroleum and natural gas reserves, production, and fund flows to be derived there from are highly dependent on Vault successfully acquiring new reserves and developing existing reserves.

To mitigate this risk, Vault has assembled a team of experienced technical professionals who have expertise operating and exploring in areas which Vault has identified as the most prospective for increasing Vault's reserves on an economic basis.

To further mitigate reserve replacement risk, Vault has targeted a majority of its prospects in areas which have multi-zone potential, year-round access and lower drilling costs. Also, Vault employs advanced geological and geophysical techniques to increase the likelihood of finding additional reserves.

Reserves that Vault may have at any particular time and the production there from will decline over time as such existing reserves are exploited. A future increase in Vault's reserves will depend on its abilities to acquire suitable prospects or properties and discover new reserves. Acquisitions of oil and gas assets depend upon the assessment of value that Vault makes at the time of acquisition, which are subject to the risk of incorrect assessments. Vault mitigates acquisition risk by performing due diligence, review and obtaining approval from the Board of Directors for potential acquisitions. Where required, evaluations from independent reserve engineers are also obtained.

Operational Risks

Vault's operations are subject to the risks normally incidental to the operation and development of oil and natural gas properties and the drilling of oil and natural gas wells. Continuing production from a property, and to some extent the marketing of production there from, are largely dependent upon the ability of the operator of the property.

Commodity Price Risk

The Company's oil and natural gas production is marketed and sold on the spot market to area aggregators based on daily spot prices that are adjusted for product quality and transportation costs. Operating results and financial condition of the Trust are impacted by prices it receives for its production.

Interest Rate Risk

Vault has exposure to movements in interest rates, particularly those charged on the revolving credit facility entered into at the time of the Plan of Arrangement.

Foreign Currency Risk

The Trust is exposed to foreign currency fluctuations as crude oil prices received are referenced to U.S. dollar denominated prices. Currently, Vault sells natural gas in Canadian currency; however, if that were to change then Vault would be subject to foreign exchange risk on selling this product in U.S. dollar denominated indices.

Safety and Environmental Risks

The petroleum and natural gas business is subject to extensive regulation pursuant to various municipal, provincial, national, and international conventions and regulations. Environmental legislation provides for, among other things, restrictions and prohibitions on spills, releases or emissions of various substances produced in association with oil and natural gas operations. Vault is committed to meeting and exceeding its environmental and safety responsibilities. Vault has implemented an environmental and safety policy that is designed, at a minimum to comply with current governmental regulations set for the oil and natural gas industry. Changes to governmental regulations are monitored to ensure compliance. Environmental reviews are completed as part of the due diligence process when evaluating acquisitions. Environmental and safety updates are presented and discussed at each Board of Directors' meeting. Vault maintains adequate insurance commensurate with industry standards to cover reasonable risks and potential liabilities associated with its activities as well as insurance coverage for officers and directors executing their corporate duties.

Regulatory Risk

On October 31, 2006, the Minister of Finance announced proposed legislation that trusts will be taxed. If this legislation passes, all existing trusts will be taxable commencing 2011 at a tax rate of 31.5%. Distributions and undistributed income will be taxable. Trust unitholders will be required to treat distributions as dividend income. This announcement resulted in a market value adjustment for the trust industry and on going change is possible until further information is available.

Credit Risk

Vault is exposed to credit risk from sales of petroleum and natural gas as well as from joint venture participants. These customers are in the oil and natural gas industry, which makes Vault subject to normal industry credit risk. In order to limit this risk, the Trust selects financially sound counterparties to transact with and reviews its exposure to individual customers on a frequent basis.

Unitholder Liability

Previously, there has been some concern that trust unitholders may be held personally liable for the indebtedness of the Trust. In June 2004, the Province of Alberta enacted legislation that provides statutory protection for unitholders which is similar to protection to shareholder of a corporation. Therefore, since Vault is registered in Alberta, the risk of Unitholder Liability is removed.



VAULT ENERGY TRUST
Consolidated Balance Sheets

As at December 31, ($thousands) 2006 2005
----------------------------------------------------------------------------
Assets
Current assets:
Cash $ - $ 5,769
Accounts receivable 16,025 17,564
Prepaid expenses and deposits 2,413 2,074
----------------------------------------------------------------------------
----------------------------------------------------------------------------
18,438 25,407

Property, plant and equipment (Note 2) 497,316 511,069
Deferred charges (Note 5) 3,905 2,521
Goodwill - 4,179
----------------------------------------------------------------------------
$ 519,659 $ 543,176
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Liabilities and Unitholders' Equity
Current liabilities:
Bank indebtedness $ 7,433 $ -
Accounts payable and accrued liabilities 24,418 38,930
Distributions payable to unitholders 3,069 3,770
----------------------------------------------------------------------------
----------------------------------------------------------------------------
34,920 42,700

Capital lease obligation 258 166
Deferred credits (Note 15) 2,310 1,598
Revolving credit facility (Note 4) 56,000 81,500
Convertible debentures (Note 5) 94,928 46,616
Asset retirement obligation (Note 6) 34,508 29,560
Future income taxes (Note 10) 8,139 13,839
----------------------------------------------------------------------------
----------------------------------------------------------------------------
196,143 173,279

Non-controlling interest (Note 7) 13,861 24,856

Unitholders' equity:
Trust units/common shares (Note 8) 344,363 317,193
Contributed surplus (Note 9) 6,081 1,729
Equity component of convertible debentures (Note 5) 4,701 2,301
Accumulated deficit (80,410) (18,882)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
274,735 302,341
----------------------------------------------------------------------------
----------------------------------------------------------------------------
$ 519,659 $ 543,176
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes to the consolidated financial statements

Approved by the Board of Directors:

Robert Jepson Sean Monaghan
President, Chairman of the Board of Directors
Chief Executive Officer and Director



Consolidated Statements of Income

For the year ended December 31, ($ thousands) 2006 2005
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Revenue:
Petroleum and natural gas $ 143,563 $ 124,672
Transportation expense (4,765) (3,552)
Royalties (23,435) (22,858)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
115,363 98,262

Expenses:
Production 44,861 23,369
General and administrative 8,080 6,327
Unit-based compensation (Note 9) 4,352 4,321
Interest 9,956 5,333
Depletion, depreciation and accretion 68,824 39,968
Goodwill impairment (Note 3) 4,179 -
Foreign exchange (12) 13
Plan of arrangement - 8,176
----------------------------------------------------------------------------
----------------------------------------------------------------------------
140,240 87,507

Income (loss) before taxes (24,877) 10,755
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Taxes:
Current taxes 92 546
Future income tax recovery (Note 10) (7,674) (1,462)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(7,582) (916)

Net income (loss) before non-controlling interest (17,295) 11,671
Non-controlling interest (Note 7) 1,481 (1,189)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net income (loss) $ (15,814) $ 10,482
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Net income (loss) per Trust unit (Note 11)
Basic (0.46) 0.44
Diluted (0.46) 0.43


Consolidated Statements of Accumulated (Deficit) Income

For the year ended December 31, ($ thousands) 2006 2005
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Accumulated income (deficit), beginning of year $ (18,882) $ 344
Net income (loss) (15,814) 10,482
Accumulated cash distributions (45,714) (29,708)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Accumulated deficit, end of year $ (80,410) $ (18,882)
----------------------------------------------------------------------------
----------------------------------------------------------------------------



Consolidated Statements of Cash Flows

For the year ended December 31, ($ thousands) 2006 2005
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Cash provided by (used in):

Operating:
Net income (loss) $ (15,814) $ 10,482
Items not affecting cash:
Depletion, depreciation and accretion 68,824 39,968
Goodwill impairment 4,179 -
Amortization of natural gas sales contract (961) (1,248)
Unit-based compensation 4,352 3,554
Future income taxes (7,674) (1,462)
Non-controlling interest (1,481) 1,189
Gas over bitumen royalty adjustment 1,423 -
Asset retirement expenditures (2,007) (8)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Funds flow from operations 50,841 52,475
Net change in non-cash operating working capital (5,232) 5,734
----------------------------------------------------------------------------
----------------------------------------------------------------------------
45,609 58,209
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Financing:
Increase (decrease) in revolving credit facility (18,067) 68,535
Convertible debenture issue, net of costs 47,756 52,199
Increase (decrease) in capital lease obligation 92 136
Trust units issued, net of costs 11,893 261,258
Warrants exercised 472 1,940
Options exercised, net of settled - 811
Distributions to unitholders (45,714) (29,708)
Change in non-cash financing working capital (702) 3,770
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(4,270) 358,941
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Investments:
Property acquisitions, net of dispositions 3,284 (365,592)
Capital expenditures (42,591) (35,003)
Corporate acquisitions - (23,598)
Change in non-cash investing working capital (7,801) 12,812
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(47,108) (411,381)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Change in cash (5,769) 5,769
Cash, beginning of year 5,769 -
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Cash, end of year $ - $ 5,769
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Vault Energy Trust
Notes to the Consolidated Financial Statements
Year ended December 31, 2006
(Tabular amounts in thousands of Canadian dollars, except per unit amounts)


Vault Energy Trust ("Vault" or the "Trust") is an open-ended, unincorporated investment trust governed by the laws of the province of Alberta pursuant to a Trust Indenture. Valiant Trust Company has been appointed trustee under the Trust Indenture. The beneficiaries of the Trust are the holders of the Trust units ("unitholders").

The Trust was formed on April 25, 2005, completed a private placement on April 27, 2005 and began active oil and gas operations through its subsidiary, Vault Energy Inc. ("Vault Energy") as part of a plan of arrangement ("Plan of Arrangement") on June 22, 2005 involving Chamaelo Energy Inc. ("Chamaelo"), a new exploration focused entity ("Chamaelo Exploration"), Vault Energy and the Trust.

While the Trust was created on June 22, 2005, the audited consolidated financial statements follow the continuity of interests basis of accounting as if the Trust was a continuation of Chamaelo. Accordingly, the results of operations include Chamaelo's results for the period up to and including June 21, 2005, and the Trust's results of operations from June 22, 2005 to December 31, 2005.

Structure of the Trust

Vault Energy Trust (the "Trust") is an open-ended, unincorporated investment trust governed by the laws of the Province of Alberta. The Trust was established as part of a Plan of Arrangement (the "Arrangement" that became effective on June 22, 2005. The purpose of the Trust is to indirectly explore for, develop and hold interests in petroleum and natural gas properties, through investments in securities of subsidiaries and royalty interests in oil and natural gas properties. The business of the Trust is carried on by Vault Energy Inc. The Trust owns, directly and indirectly, 100% of the common shares, (excluding the exchangeable shares -- see note 8) of Vault Energy Inc. The activities of Vault Energy Inc. are financed through interest bearing notes from the Trust and third party debt as described in the notes to the financial statements. The convertible debentures are direct obligations of the Trust.

Pursuant to the terms of an agreement (the "NPI Agreement"), the Trust is entitled to a payment from Vault Energy Inc. each month equal to the amount by which 99% of the gross proceeds from the sale of production exceed 99% of certain deductible expenditures (as defined). Under the terms of the NPI Agreement, deductible expenditures may include amounts, determined on a discretionary basis, to fund capital expenditures, to repay third party debt and to provide for working capital required to carry out the operations of Vault Energy Inc.

The Trustee may declare payable to the Trust Unitholders all or any part of the net income of the Trust earned from interest income on the notes and from the income generated under the NPI Agreement, and from any dividends paid on the common shares of Vault Energy Inc., less any expenses of the Trust including interest on the convertible debentures.

1. SIGNIFICANT ACCOUNTING POLICIES

a) Basis of presentation

These consolidated financial statements include the accounts of the Trust and its wholly-owned subsidiaries. These financial statements have been prepared by management in accordance with accounting principles generally accepted in Canada.

b) Property, plant and equipment

The Trust follows the full cost method of accounting whereby all costs related to the acquisition of, exploring for and developing petroleum and natural gas reserves are capitalized and charged against earnings as set out below. Such costs include land acquisition costs, geological and geophysical expenses, production equipment, carrying charges of non-producing properties, costs of drilling both productive and non-productive wells and overhead charges directly related to acquisition, exploration and development activities.

These costs, together with the estimated future costs to be incurred in developing proved reserves, are depleted or depreciated using the unit-of-production method based on the proved reserves before royalties as estimated by independent petroleum engineers. Petroleum and natural gas reserves and production are converted into equivalent units based upon estimated relative energy content of six thousand cubic feet of natural gas to one barrel of crude oil. The costs of undeveloped properties are excluded from the costs subject to depletion and depreciation until it is determined whether proved reserves are attributable to the properties or impairment occurs.

Petroleum and natural gas properties are evaluated each reporting period through an impairment test to determine the recoverability of capitalized costs. The carrying amount is assessed as recoverable when the sum of the undiscounted cash flows expected from proved reserves plus the cost of unproved interests, net of impairments, exceeds the carrying amount. When the carrying amount is assessed not to be recoverable, an impairment loss is recognized to the extent that the carrying amount exceeds the sum of the discounted cash flows from proved and probable reserves plus the cost of unproved interests, net of impairments. The cash flows are estimated using expected future prices and costs and are discounted using a credit adjusted risk-free interest rate.

Proceeds from the sale of petroleum and natural gas properties are applied against capitalized costs, with no gain or loss recognized, unless such a sale would result in a change in the depletion rate of 20% or more.

Portions of the Trust's petroleum and natural gas activities are conducted jointly with others and accordingly these financial statements reflect only the Trust's proportionate interest in such activities.

c) Office and other equipment

Office and other equipment are depreciated using the straight-line method over the estimated useful life of three years.

d) Goodwill

Goodwill, which represents the excess of purchase price over the fair value of net assets received in an acquisition, is tested for impairment on an annual basis. A goodwill impairment loss would be recognized when the carrying amount of goodwill exceeds its fair value. Should the test result in impairment, it will be charged to income in the period of the impairment.

e) Asset retirement obligations ("ARO")

The Trust recognizes the liability associated with future site reclamation costs in the financial statements at the time when the liability is incurred. ARO obligations are initially measured at fair value and subsequently adjusted for the accretion of discount and any changes to the underlying cash flows. The asset retirement cost is capitalized to oil and natural gas properties and equipment and amortized into earnings on a basis consistent with depletion and depreciation.

f) Use of estimates

The amounts recorded for depletion and depreciation, asset retirement obligations and the amounts used in impairment test calculations are based on estimates of proved reserves, production rates, crude oil and natural gas prices, future costs and other relevant assumptions. By their nature, these estimates are subject to measurement uncertainty and the effect on the financial statements of changes in such estimates in future periods could be significant.

g) Revenue recognition

Petroleum and natural gas revenues are recognized when title and risks pass to the purchaser.

h) Financial Instruments

The Trust does not enter into any derivative financial instruments for trading or speculative purposes. This includes the formal documentation of the hedge, linking the derivatives to specific assets and liabilities on the balance sheet or specific firm commitments or forecasted transactions and performing assessment of hedge effectiveness. The change in fair value of the derivative contracts are not recognized on the balance sheet. Realized gains and losses on these contracts are recognized in petroleum and natural gas revenue and cash flows in the same period in which the revenues associated with the hedged transaction are recognized.

i) Unit-based compensation

The Trust has a unit rights incentive plan ("TURIP"), which is described in note 9. The Trust applies the fair value method for valuing unit rights granted to officers, directors, employees and consultants. Under this method, compensation cost attributable to unit rights granted to officers, directors, employees and consultants is measured at fair value at the grant date and expensed over the vesting period with a corresponding increase to contributed surplus. Upon the exercise of the stock options, consideration paid together with the amount previously recognized in contributed surplus is recorded as an increase to unitholders' capital.

j) 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 the Trust's unitholders. As the Trust distributes all of its taxable income to the unitholders and meets the requirements of the Income Tax Act (Canada) applicable to the Trust, no provision for income tax has been made by the Trust, except for its subsidiaries as noted below.

The Trust follows the liability method of accounting for future income taxes, whereby temporary differences arising from the difference between the tax basis of an asset or liability and its carrying amount on the balance sheet are used to calculate future income tax liabilities or assets. Future income tax liabilities or assets are calculated using tax rates anticipated to apply in the periods that the temporary differences are expected to reverse.

On October 31, 2006, the Minister of Finance announced proposed legislation to Canada's tax system that includes altering the tax treatment of income trusts. The government proposed a two-tier tax structure, similar to that of corporations, whereby distributions paid by the trusts will be subject to tax at the trust level in addition to personal tax as if they were dividends from a taxable Canadian corporation. The changes are proposed to take effect for 2011 for existing publicly-traded trusts, but the proposal has not been enacted at this time. The Trust is currently still assessing the proposals and the potential implications.

k) Per unit information

Per unit information is computed using the weighted average number of trust units outstanding during the period. Diluted per unit information is calculated including the impact of exchangeable shares, using the treasury stock method, which assumes that any proceeds from the exercise of stock options, trust unit rights and warrants would be used to purchase trust units at the average market price during the period. No adjustment to diluted earnings per trust unit is made if the result of these calculations is anti-dilutive.

l) Exchangeable shares - non-controlling interest

Exchangeable shares in Vault Energy were issued pursuant to the Plan of Arrangement. The exchangeable shares are transferable and are retractable for Trust units. As such, they have been classified outside of equity as a non-controlling interest. Net income (loss) as reported is net of net income (loss) attributable to non-controlling interest. Retractions of exchangeable shares are accounted for using step acquisition accounting. As a result, any excess between the fair market value of the trust units issued upon retraction and the book value of the corresponding exchangeable shares is recorded as an increase to property, plant and equipment. In addition, future taxes are recorded as a result of differences between fair market values and tax bases.

m) Convertible debentures

Convertible debentures are initially recorded at the fair value of the obligation without the conversion feature. The difference between the principal amount and the fair value without the conversion feature is recorded in unitholders' equity as equity component of convertible debentures. The obligation is accreted through earnings using the effective interest rate method and the equity component of convertible debentures is increased as the debentures are converted for Trust units.



2. PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment ($ thousands) 2006 2005
----------------------------------------------------------------------------
Petroleum and natural gas properties 599,606 549,336
Office and other equipment 3,744 2,639
----------------------------------------------------------------------------
603,350 551,975
----------------------------------------------------------------------------
Accumulated depletion, depreciation and accretion (106,034) (40,906)
----------------------------------------------------------------------------
Property, plant and equipment 497,316 511,069
----------------------------------------------------------------------------


As at December 31, 2006, the cost of petroleum and natural gas properties includes $15,069,000 (2005 - $18,953,000) relating to properties from which there is no proved reserves and which have been excluded from costs subject to depletion and depreciation. The provision for depletion, depreciation and accretion also includes $2,095,000 (2005 - $1,398,000) for accretion of asset retirement costs. During the period, the Trust capitalized $524,000 (2005 - $999,000) of geological and geophysical administrative costs associated with exploration and development activities. Future development costs of $26,895,000 (2005 - $28,277,000) have been included in the calculation of depletion, depreciation and accretion.

The Trust performed an impairment (ceiling) test at December 31, 2006 to assess the recoverable value of the petroleum and natural gas properties. The crude oil and natural gas future prices are based on January 1, 2007 commodity price forecasts of the Trust's independent reserve evaluators. These prices have been adjusted for commodity price differentials specific to the Trust. The following table summarizes the benchmark prices used in the ceiling test calculation. Based on these assumptions, there was no impairment at December 31, 2006.



----------------------------------------------------------------------------
Foreign Edmonton Light
WTI Oil Exchange Crude Oil AECO Gas
Year ($US/bbl) Rate ($Cdn/bbl) ($Cdn/mmbtu)
----------------------------------------------------------------------------
2007 65.73 0.870 74.10 7.72
2008 68.82 0.870 77.62 8.59
2009 62.42 0.870 70.25 7.74
2010 58.37 0.870 65.56 7.55
2011 55.20 0.870 61.90 7.72
2012 56.31 0.870 63.15 7.85
2013 57.43 0.870 64.42 7.99
2014 58.58 0.870 65.72 8.12
2015 59.75 0.870 67.04 8.26
2016 60.95 0.870 68.39 8.40
2017 62.17 0.870 69.76 8.54
Escalate 2.0% 2.0% 2.0%
Thereafter per year per year per year
----------------------------------------------------------------------------
----------------------------------------------------------------------------


3. GOODWILL IMPAIRMENT

Goodwill was recorded on the Capstone acquisition in 2004 when the purchase price was in excess of the fair values assigned to the assets acquired and liabilities assumed. To assess impairment, the fair value of goodwill was determined and compared to the carrying value. As the carrying amount of the goodwill exceeds its fair value, a goodwill impairment of $4.2 million was recognized and charged to income in the third quarter of 2006.

4. REVOLVING CREDIT FACILITY

Concurrent with the Plan of Arrangement, Vault Energy entered into a credit agreement with a syndicate of Canadian banks to provide the Trust with $125,000,000 of total credit facilities. This is comprised of an extendible revolving term credit facility of $115,000,000 and a $10,000,000 operating facility each bearing interest at prime plus a premium ranging between 0% and 1.75% based on the Trust's debt to cash flow ratio. The credit facilities are secured by a $200,000,000 demand debenture on the assets of Vault Energy and have been renewed to June 29, 2007. Should the facilities not be renewed they convert to 366-day non-revolving term facilities on the renewal date. Payment will not be required under the facilities for more than 365 days from the conversion date and, as such, the revolving credit facility has been classified as non-current. The effective interest rate as at December 31, 2006 was 5.5%.

5. CONVERTIBLE DEBENTURES

On April 27, 2005, Chamaelo completed a bought deal private placement financing issuing 55,000 Series D subscription receipts at a price of $1,000 per Series D subscription receipt for aggregate gross proceeds of $55,000,000. Issue costs of $2,801,000 have been classified as deferred financing charges and will be amortized over the life of the debentures. For the period ended December 31, 2006, amortization of $560,000 (2005 - $280,000) has been expensed.

Pursuant to the Plan of Arrangement, each Series D subscription receipt was converted into one convertible debenture of the Trust. The convertible debentures have a face value of $1,000 per debenture and a maturity date of June 30, 2010. The convertible debentures pay interest semi-annually on June 30 and December 31 of each year at 8% per annum and are convertible into Trust units at a conversion price of $11.50 per Trust unit. Holders of convertible debentures have the option of redeeming them at a price of $1,050 per debenture after June 30, 2008 and on or before June 30, 2009 and thereafter until the maturity date at a price of $1,025 per debenture. The Trust may repay the convertible debentures in cash or through the issue of additional Trust units at 95% of the market price.

The debentures were initially recorded at the fair value of the obligation without the conversion feature. This fair value to make future payments of principal and interest was determined to be $52,400,000. The difference between the principal amount of $55,000,000 and the fair value of the obligation is $2,600,000 and has been recorded in unitholders' equity as the fair value of the conversion feature of the debentures. The following table shows the convertible debenture activities for the year ended December 31, 2006:



Equity
Number of Debt Component component
Convertible Debentures - 8% Debentures ($ thousands) ($ thousands)
----------------------------------------------------------------------------
Issued April 27, 2005 55,000 52,400 2,600
Accretion - 263 -
Conversion to Trust Units (6,329) (6,047) (299)
----------------------------------------------------------------------------
Balance at December 31, 2005 48,671 46,616 2,301
Accretion - 387 -
----------------------------------------------------------------------------
Balance at December 31, 2006 48,671 47,003 2,301
----------------------------------------------------------------------------
----------------------------------------------------------------------------


On May 2, 2006, Vault closed a bought deal offering of $50,000,000 principle amount of convertible unsecured subordinated debentures. The convertible debentures have a face value of $1,000 per debenture, a maturity date of May 31, 2011 and a conversion price of $10.50 per Trust unit. These pay interest semi-annually at 7.2% per annum on May 31 and November 30 each year commencing on November 30, 2006. Holders of convertible debentures have the option of redeeming them at a price of $1,050 per debenture after May 31, 2009 and on or before May 31, 2010 and thereafter until the maturity date at a price of $1,025 per debenture. The Trust may repay the convertible debentures in cash or through the issue of additional Trust units at 95% of the market price. Issue costs of $2,200,000 have been classified as deferred financing charges and will be amortized over the life of the debentures. For the period ended December 31, 2006, amortization of $300,000 has been expensed.

The debentures were initially recorded at the fair value of the obligation without the conversion feature. This fair value to make future payments of principal and interest was determined to be $47,600,000. The difference between the principal amount of $50,000,000 and the fair value of the obligation is $2,400,000 and has been recorded in unitholders' equity as the fair value of the conversion feature of the debentures. The following table shows the convertible debenture activities for the year ended December 31, 2006:



Equity
Number of Debt Component component
Convertible Debentures - 7.2% Debentures ($ thousands) ($ thousands)
----------------------------------------------------------------------------
Balance at January 1, 2006
Issued on May 2, 2006 50,000 47,600 2,400
Accretion 325 -
----------------------------------------------------------------------------
Balance at December 31, 2006 50,000 47,925 2,400
----------------------------------------------------------------------------


6. ASSET RETIREMENT OBLIGATION

The Trust's asset retirement obligation result from net ownership interests in petroleum and natural gas properties including well sites, gathering systems and processing facilities. The Trust estimates the total undiscounted amount of cash flows (adjusted for inflation using a rate of 2%) required to settle its asset retirement obligation is approximately $132,500,000 (2005 - $112,000,000) which will be incurred during years ranging from 2007 to 2036. A credit-adjusted risk-free rate of 7% was used to calculate the fair value of the asset retirement obligation.



A reconciliation of the asset retirement obligations is provided below:

----------------------------------------------------------------------------
Asset retirement obligation ($ thousands) 2006 2005
----------------------------------------------------------------------------
Balance, beginning of year 29,560 15,563
Liabilities acquired, net - 9,316
Liabilities incurred in period - 897
Liabilities resulting from changes in estimates 4,860 2,394
Accretion expense 2,095 1,398
Liabilities settled in period (2,007) (8)
----------------------------------------------------------------------------
Balance, end of year 34,508 29,560
----------------------------------------------------------------------------


7. NON-CONTROLLING INTEREST

Vault Energy Inc. is authorized to issue an unlimited number of exchangeable shares. Exchangeable shares are convertible into Trust units based on the exchange ratio, which is adjusted monthly to reflect the distributions paid on the Trust units. Cash distributions are not paid on exchangeable shares, however the exchangeable shareholders do have the right to vote at the meetings of unitholders. The exchangeable shares must be exchanged for Trust units by June 22, 2008.

Pursuant to the Plan of Arrangement, former shareholders of Chamaelo had the option to receive 0.5 exchangeable shares of Vault Energy Inc. for each Chamaelo share held to a maximum of 5,000,000 exchangeable shares. As a result, 3,889,462 exchangeable shares were issued in exchange for 7,778,924 common shares of Chamaelo.



The following summarizes the exchangeable shares outstanding and the
non-controlling interest ("NCI") as at December 31, 2006:

2006 2005
----------------------------------------------------------------------------
Exchangeable Non-controlling Exchangeable Non-controlling
Shares Interest ('000s) Shares Interest ('000s)
----------------------------------------------------------------------------
Balance,
beginning of
period 3,560,586 24,856 - -
Plan of
Arrangement - - 3,889,462 25,881
Retracted for
Trust units (1,434,523) (9,514) (328,876) (2,214)
Net (loss)
income
attributable
to NCI (1,481) 1,189
----------------------------------------------------------------------------
Balance, end
of period 2,126,063 13,861 3,560,586 24,856
Exchange
ratio, end of
period 1.26889 1.07185
----------------------------------------------------------------------------
Trust units
issuable upon
conversion,
end of period 2,697,740 3,816,414
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Exchangeable share retractions are accounted for using the step acquisition
method of accounting. A summary of these acquisitions as at December 31,
2006 follows:


2006 2005
----------------------------------------------------------------------------
Acquisition of non-controlling interest ($ thousands) ($ thousands)
----------------------------------------------------------------------------
Retraction of exchangeable shares
reflected in property, plant and equipment 7,208 2,706
Future taxes on acquisition of exchangeable
shares (1,974) (923)
----------------------------------------------------------------------------
Excess of fair market value over book value 5,234 1,783
----------------------------------------------------------------------------
----------------------------------------------------------------------------


8. UNITHOLDERS' EQUITY

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.



a) Trust units:
2006 2005

Number of Amount Number of Amount
Shares ('000s) Shares ('000s)
----------------------------------------------------------------------------
Balance, beginning of the period 32,785,833 315,612 28,079,786 107,745
Exercise of warrants - - 421,020 2,226
Exercise of options - - 680,200 5,280
Shares exchanged for exchangeable
shares - - (7,778,924) (25,881)
Shares cancelled on conversion to
Trust units - - (21,402,082)
Trust units issued on cancellation
of common shares - - 10,701,051
Trust units issued in private
placement - - 21,156,000 275,028
Trust units issued on conversion
of debentures - - 550,347 6,346
Trust units issued on retraction
of exchangeable shares 1,615,358 14,747 340,532 3,996
Trust units issued through
Distribution Re-investment
and Optional Purchase Plan 1,623,182 11,848 35,411 411
Trust units issued on exercise of
warrants 81,364 625 2,492 23
Plan of Arrangement & other 24 (59,562)
----------------------------------------------------------------------------
Balance, end of the period 36,105,737 342,856 32,785,833 315,612
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Warrants (note 8(b)) - 1,507 - 1,581
----------------------------------------------------------------------------
Total Unitholders' equity 36,105,737 344,363 32,785,833 317,193
----------------------------------------------------------------------------
----------------------------------------------------------------------------


On April 27, 2005, Chamaelo completed a bought deal private placement issuing 42,312,000 Series E subscription receipts in the capital of the Trust at a price of $6.50 per Series E subscription receipt for aggregate gross proceeds of $275,028,000.

Pursuant to the Plan of Arrangement, each Series E subscription receipt was converted into 0.5 Trust Units and 0.2 Chamaelo Exploration shares.

Distribution Re-investment and Optional Purchase Plan ("DRIP")

The Trust has initiated a distribution reinvestment plan (the "Regular DRIP") and a premium distribution reinvestment plan (the "Premium DRIP"). The Regular DRIP permits eligible unitholders to direct their distributions to the purchase of additional units at 95 percent of the weighted average market price of Trust units for the 10-day trading period prior to a distribution payment date. The Premium DRIP permits eligible unitholders to elect to receive 102 percent of the cash the unitholder would otherwise have received on the distribution date. The cash distributed to the Premium DRIP unitholders is funded through the issuance of additional trust units in the open market. Participation in the Regular and Premium DRIP is subject to proration by the Trust. Unitholders who participate in either the Regular DRIP or the Premium DRIP are also eligible to participate in the Optional Unit Purchase Plan as defined in the plan. The Premium DRIP has been temporarily suspended effective December 15, 2006.

Redemption Right

Unitholders may redeem their Trust units for cash at any time, up to a maximum of $250,000 in any calendar month, by delivering their unit certificates to the Trust, together with a properly completed notice of redemption. The redemption amount per Trust unit will be the lesser of 90 percent of the market price of the Trust units on the principal market on which they are traded during the 10 day trading period after the Trust units have been validly tendered for redemption and the closing market price on the principal market on which they are traded on the date which they were validly tendered for redemption, or if there was no trade of the Trust units on that date, the average of the last bid and ask prices of the Trust units on that date.

b) Warrants

As a result of the Plan of Arrangement, unexercised warrants of Chamaelo were converted into 0.5 warrants of the Trust and 0.2 warrants of Chamaelo Exploration. Warrants of the trust allow the holder to purchase units of the Trust at the specified warrant exercise price. The exercise price of each warrant is reduced as of the date of conversion by the cumulative cash distributions attributable to one Trust unit. As at December 31, 2006, the remaining warrants outstanding have been reduced in exercise price by $2.24 per warrant.




The following summarizes the warrants outstanding and exercisable as at
December 31, 2006:

Number of Average Amount
Warrants Warrants Price ($) ($ thousands)
----------------------------------------------------------------------------
Initially issued and balance beginning
of 2005 3,917,626 4.34 2,020
Exercised for shares (421,020) 4.56 (305)
----------------------------------------------------------------------------
Balance at June 22, 2005 3,496,606 4.31 1,715
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Trust warrants granted on cancellation
of share purchase warrants 1,749,061 7.65 1,715
Plan of arrangement (132)
----------------------------------------------------------------------------
1,749,061 7.65 1,583
Exercised for Trust units (2,492) 8.13 (2)
----------------------------------------------------------------------------
Balance, at December 31, 2005 1,746,569 6.96 1,581
----------------------------------------------------------------------------
Exercised for Trust units (81,364) 6.78 (74)
----------------------------------------------------------------------------
Balance, at December 31, 2006 1,665,205 6.27 1,507
----------------------------------------------------------------------------
----------------------------------------------------------------------------


c) Trust Unit Rights Incentive Plan

On July 1, 2005, the Trust introduced its Trust Unit Rights Incentive Plan. The rights vest over three years, expire five years from the date of grant and have an exercise price that declines by the amount of distributions paid per Trust unit.



The following table summarizes the rights outstanding at December 31, 2006:

Weighted Weighted
Average Average Weighted
Number of Original Reduced Average
Rights Price ($) Price ($) Years to Expiry
----------------------------------------------------------------------------
Balance, beginning of year 1,603,950 10.94 9.14 4.59
Rights granted 889,705 8.26 7.60 4.47
Rights cancelled (323,725) 10.52 9.07 3.85
----------------------------------------------------------------------------
Balance, end of year 2,169,930 9.96 8.58 3.94
----------------------------------------------------------------------------
----------------------------------------------------------------------------

The following table summarizes information with respect to outstanding
rights as at December 31, 2006:


Weighted Weighted Weighted
Number of Rights Average Average Average Number of Rights
Outstanding at Exercise Reduced Years to Exercisable at
December 31, 2006 Price ($) Price ($) Expiry December 31, 2006
----------------------------------------------------------------------------
1,190,020 10.56 8.72 3.56 394,340
33,075 12.43 10.65 3.65 11,025
113,275 13.27 11.60 3.69 37,758
47,355 10.67 9.26 3.89 15,785
4,800 9.82 8.73 4.15 -
781,405 8.21 7.51 4.61 -
----------------------------------------------------------------------------
2,169,930 9.96 8.58 3.94 458,908
----------------------------------------------------------------------------
----------------------------------------------------------------------------


9. UNIT- BASED COMPENSATION

During the year ended December 31, 2006, $4,352,000 (2005 - $4,321,000) was charged to income in respect of unit-based compensation cost. These charges comprise amortization of the fair value Trust unit rights as well as a one time adjustment relating to the payment of Chamaelo Energy Inc. stock option plan payouts which were lower than accrued at the time of the transaction.

On July 1, 2005, the Trust introduced its Trust Unit Rights Incentive Plan (the "Plan"). The Trust has granted 2,169,930 (Note 8(c)) rights to employees which are outstanding as of December 31, 2006. The rights vest over three years, expire five years from the date of grant and have an exercise price that declines by the amount of distributions paid per Trust unit. Under the terms of the Plan employees are not entitled to cash payments.



Unit-based compensation ($ thousands)
----------------------------------------------------------------------------
Amortization of fair value 4,637
One time adjustment (1) (285)
----------------------------------------------------------------------------
Unit-based compensation expense 4,352
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Contributed surplus
----------------------------------------------------------------------------
Balance, beginning of year 1,729
Unit-based compensation 4,352
----------------------------------------------------------------------------
Balance, end of year 6,081
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) Difference between what was accrued for payouts under the Chamaelo
Energy Inc. stock option plan and what was actually paid in May 2006.


The fair value of each right granted was estimated on the date of the grant
using the Black-Scholes option pricing model with the following weighted
average assumptions:

2006 2005
----------------------------------------------------------------------------
Fair value per right $ 4.66 $ 4.72
Risk-free rate 4.2% 3.8%
Expected life 5 years 5 years
Expected forfeitures 10.0% 10.0%
Expected volatility 27.2% 19.3%
Dividend yield $ 1.37 $ 1.38
----------------------------------------------------------------------------
----------------------------------------------------------------------------


10. TAXES

a) Vault Energy Trust

The Trust is an inter-vivos trust for income tax purposes. As such, the Trust's income that is not allocated to the Trust's unitholders is taxable.

For 2006, the Trust had taxable income, before distributions, of $ 25.8 million (2005 -$20.6 million). Taxable income of the Trust comprises net profit interests of corporate subsidiaries, interest income, less deductions for Canadian oil and gas property expense ("COGPE") and issue costs. The Trust did not have to use any COGPE deductions in the year.



b) Corporate Subsidiaries

The future tax liability on the balance sheet arises as a result of the
following temporary differences:

($ thousands) 2006 2005
----------------------------------------------------------------------------

Future income tax liabilities:
Capital assets 19,036 25,475
Future income tax assets:
Asset retirement obligations (10,083) (9,976)
Share issue costs and other (814) (1,660)
----------------------------------------------------------------------------
Net future income tax liability 8,139 13,839
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The provision for income taxes varies from the amount that would be computed
by applying the combined Canadian federal and provincial tax rates as
follows:


Income tax rate 34.77% 37.62%

($ thousands) 2006 2005
----------------------------------------------------------------------------
Expected income tax expense (recovery) (8,649) 4,046
Increase (decrease) in income taxes resulting from:
Effect of change in tax rate (792) 47
Net income attributed to the Trust 47 (6,853)
Non-deductible crown charges 1,232 2,483
Resource allowance (1,440) (2,778)
Alberta royalty tax credit - (68)
Non-deductible expenses 2,966 1,337
Other (1,038) 324
----------------------------------------------------------------------------
Future income tax recovery (7,674) (1,462)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The tax returns for all prior years are still open and may be subject to tax audit review in the future.

On October 31, 2006, the Minister of Finance announced proposed legislation that trusts will be taxed. Currently, the Trust does not pay tax on distributions as tax is paid by the unitholders. If enacted, the proposals would apply to the Trust subject to certain grandfathering rules in place effective January 1, 2011, however the legislation has not been enacted at this time. The Trust is currently still assessing the proposals and the potential implications.

11. PER TRUST UNIT INFORMATION

The weighted average number of Trust units outstanding for the determination of basic and diluted per Trust unit amounts are as follows:




2006 2005
----------------------------------------------------------------------------
Basic 34,542,045 23,741,790
Dilution on account of:
Exchangeable shares 3,317,190 3,758,623
Warrants 162,386 593,701
----------------------------------------------------------------------------
Diluted 38,021,621 28,094,114
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Trust unit rights and convertible debentures are anti-dilutive for the year ended December 31, 2006, and as a result, they have not been included in the table above. The if-converted method used to calculate dilution of certain dilutive instruments may cause differences in the diluted trust unit figures used to determine earnings per trust unit and funds flow per trust unit.

The weighted average and diluted calculations, as well as all per unit amounts presented, assume that the outstanding shares and dilutive instruments of Chamaelo have been consolidated to equivalent Trust units and dilutive instruments of Trust units as of the first period presented.



12. SUPPLEMENTAL CASH FLOW INFORMATION

($ thousands) 2006 2005
----------------------------------------------------------------------------
Cash interest paid 9,627 5,315

Cash taxes paid 92 246
----------------------------------------------------------------------------
----------------------------------------------------------------------------


13. PHYSICAL SALES CONTRACTS

Vault has entered into physical purchase and sales contracts as follows:

----------------------------------------------------------------------------
Upside
Product Volume Floor price Participation Term
----------------------------------------------------------------------------
Nov 1, 2006-
Natural gas 4,000 GJ/day $ 7.50/GJ 61.75% above $7.50/GJ Mar 31, 2007
Jan 1, 2007-
Natural gas 7,000 GJ/day $ 7.50/GJ 61% above $7.50/GJ Mar 31, 2007
Apr 1, 2007-
Natural gas 2,500 GJ/day $ 7.00/GJ Max price $9.00/GJ Oct 31, 2007
Apr 1, 2007-
Natural gas 7,500 GJ/day $ 7.60/GJ N/A Oct 31, 2007
Nov 1, 2007-
Natural gas 2,500 GJ/day $ 7.85/GJ 50% above $7.85/GJ Mar 31, 2008
Jan 1, 2007-
Crude Oil 1,000 bbls/day $ 68.00/bbl 50% above $68.00/bbl Dec 31, 2007
Apr 1, 2006-
Electricity 5 MWH $ 60.75/MW N/A Dec 31, 2008


14. FINANCIAL INSTRUMENTS

The Trust's financial instruments presented on the balance sheet consist of current assets, current liabilities, capital lease obligations, revolving credit facility and convertible debentures.

a) Fair values

The carrying value of current assets and current liabilities approximate their fair value due to the near term maturity of these instruments. Due to the revolving credit facility's floating interest rate, carrying value approximates fair value. Convertible debentures on the balance sheet are allocated between convertible debentures and equity component of convertible debentures. See note 5. The fair value of the outstanding convertible debentures as at December 31, 2006 is $49,158,000 for the June 2005 issue and $47,500,000 for the May 2006 issue.

The estimated fair values have been determined based on available market information and appropriate valuation methods. The actual amounts realized may differ from these estimates.

b) Credit risk

A substantial portion of the Trust's accounts receivable are with major customers and joint venture partners in the oil and gas industry and are subject to normal industry credit risks. The Trust manages this credit risk by entering into sales contracts with only highly rated entities and reviewing its exposure to individual entities on a regular basis.

c) Interest Rate Risk

The Trust is exposed to movements in interest rates. The revolving credit facility is a variable rate facility. The Trust is monitoring this risk by examining the interest rate forward market for opportunities to fix the rate on a portion of its variable rate debt. As at December 31, 2006, The Trust has fixed the rate on a short term basis on a portion of the revolving credit facility.

d) Commodity price risk

Natural gas sales contract - This contract was acquired in conjunction with the purchase of certain petroleum and natural gas properties on November 30, 2004. At the date of the acquisition, the fair value of the contract was a liability of $2,962,000. This value was recorded as a deferred credit which is $637,000 at December 31, 2006 (2005 - $1,598,000) and is being amortized over the life of the contract, which expires in October 2007.

Other than the natural gas sales contract and the physical sales contracts outlined in Note 13, the Trust's oil and natural gas production was marketed and sold on the spot market to area aggregators based on daily spot prices that are adjusted for product quality and transportation costs.

e) Currency Risk

The Trust is exposed to foreign currency fluctuations as crude oil prices received are referenced to U.S. dollar denominated prices. As at December 31, 2006, The Trust has not entered into any foreign currency derivatives with respect to oil and natural gas sales.

15. DEFERRED CREDITS

In October 2004, the Alberta Government passed amendments to the royalty regulations. The Government may reduce the royalty calculated if production has been constrained by the AEUB's objective to conserve bitumen. The royalty adjustments received have been recorded on the balance sheet rather than income as the Trust cannot determine if, when or to what extent the royalty adjustments may be repayable through incremental royalties if and when gas production recommences. However, all royalty adjustments are recorded as a component of cash flow and are considered distributable income. Included in deferred credits, the Trust recorded gas over bitumen royalty adjustments of $ 1,423,000 as at December 31, 2006.



16. COMMITMENTS AND CONTINGENCIES

The Trust is committed to payments under an operating lease for office space
and capital leases for leased vehicles as at December 31, 2006:

----------------------------------------------------------------------------
----------------------------------------------------------------------------
Minimum Commitments Each Year Total
----------------------------- Committed
($ thousands) 2007 2008 2009 2010 2011 After 2011 Total
----------------------------------------------------------------------------
Capital lease obligations 212 248 12 13 - 485
Operating lease obligation 1,619 1,698 1,742 1,746 1,746 3,637 12,188
----------------------------------------------------------------------------
1,831 1,946 1,754 1,759 1,746 3,637 12,673
----------------------------------------------------------------------------
----------------------------------------------------------------------------


As at December 31, 2006, the Trust in its normal course of business has issued bank letter of credits in the amount of $671,000 to various governmental agencies to cover capital and operating performance requirements.

Vault Energy Trust is a conventional oil and gas income trust. Vault units are traded on the Toronto Stock Exchange (TSX) under the symbol "VNG.UN". Convertible debentures of Vault trade on the TSX under the symbols "VNG.DB", and "VNG.DB.A".

Contact Information

  • Vault Energy Trust
    Robert Jepson
    President and Chief Executive Officer
    (403) 444-9662
    or
    Vault Energy Trust
    Greg Fisher
    VP, Finance and Chief Financial Officer
    (403) 444-9651
    or
    Vault Energy Trust
    Nicole Collard
    Investor Relations
    (403) 444-9657
    Email: info@vaultenergy.com
    Website: www.vaultenergy.com