Vault Energy Trust
TSX : VNG.UN
TSX : VNG.DB
TSX : VNG.DB.A

Vault Energy Trust

August 14, 2007 06:00 ET

Vault Energy Announces Second Quarter Financial and Operating Results

CALGARY, ALBERTA--(Marketwire - Aug. 14, 2007) - Vault Energy Trust (TSX:VNG.UN) (TSX:VNG.DB) (TSX:VNG.DB.A) ("Vault" or the "Trust") announces its consolidated financial and operating results for the three months ended June 30, 2007.

MESSAGE TO UNITHOLDERS

Vault Energy announces results for the quarter ended June 30, 2007. Daily production volumes for the quarter are on track with our 2007 guidance for the year with Q2 production volumes averaging 7,314 boe/d. Year to date production volumes averaged 7,233 boe/d and we continue to expect that we will meet our production guidance of 7,000 to 7,200 boe/d. Cash flow from operations was $9.8 million or $0.27 per basic trust unit, $1.0 million lower than anticipated due to nonrecurring third party operated facility equalization adjustments invoiced and received during the quarter relating to the 2005-2006 period and a one time retroactive crown royalty adjustment.

Vault's 2007 capital program of $25 million is front end loaded and as such the Company invested approximately $8.4 million in the quarter and $19.0 million for the year to date on our Alberta and BC properties. The Company has had an excellent drilling program this year with 6 gross (3.7 net) wells resulting in 5 (2.7 net) gas wells and 1 net oil well. As part of our long term strategy, $2.7 million was invested during Q2 in the Wimborne D2B Enhanced Oil Recovery Project. Water injection has commenced and we anticipate increased production results late this year or early in 2008. Vault is continuing to push ahead with various Enhanced Oil Recovery Projects to promote unbooked resources to reserves.

Natural gas price averaged $6.43 per mcf in the quarter, lower by 8% from the first quarter. Natural gas prices have followed their historic pattern and weakened through the shoulder season due to low weather related demand and higher natural gas storage levels. Crude oil prices averaged $66.27 per bbl in the quarter, up 5% compared to the last quarter. Oil prices have continued to strengthen in the quarter due to strong global demand and tight downstream conditions.

In addition to commodity price fluctuations, the Canadian dollar significantly appreciated against the U.S. dollar, reaching a 30 year high of USD/CDN exchange rate of $0.94 at the end of the second quarter. The average USD/CDN exchange rate for the second quarter of 2007 was $0.91, a seven per cent increase from $0.85 in the first quarter of 2007. The Trust has seen a negative impact to revenue, and therefore Cash Flow, during the quarter because commodity prices are derived from U.S. dollar posted prices for both oil and natural gas. Future revenues may be negatively impacted due to the continued strengthening of the Canadian dollar, however Vault's production hedges are fixed in Canadian dollars. Vault currently has approximately 35% of its net production volumes hedged for 2007 and will continue to look for opportunities to take advantage of strength in the forward commodity markets.

Operating costs for the second quarter averaged $15.13 per boe, and includes approximately $0.72 per boe for third party facilities equalization adjustments from prior periods. This equates to a normalized operating cost of $14.41 per boe which is 2% lower than the same quarter of last year. Vault continues to focus on operating cost initiatives to enhance operating netbacks. Specifically, we have recently converted two Wimborne electrical submersible pumps (ESP) to gas lift and are reviewing the other eight ESP's for alternate pumping equipment.

During the quarter, the $125 million total credit facility agreement was renewed with a syndicate of Canadian banks giving Vault a reasonable level of financial flexibility.

Distributions to our unitholders for the quarter remained at $0.085 per Trust unit per month resulting in a payout ratio for the quarter of 95%, which when adjusted for out of period costs would have been 86%. Vault's payout ratio for the year to date is 85%. The August distribution payable in September to unitholders of record as of August 31, 2007 will remain at $0.085 per Trust Unit. Vault continues to monitor natural gas prices in conjunction with long term sustainability and payout ratio and will look at longer term trends in commodity prices.

In April 2007, the Federal Government included the proposed Trust Taxation in the Federal Budget ("Bill C-52"). Bill C-52 received a third reading on June 12, 2007 and then Royal Assent on June 22, 2007, thus fully enacting the tax measures. The future income tax recovery adjustment of $15.0 million represents the taxable temporary differences of the Trust tax effected at 31.5%, which is the rate that will be applicable in 2011 under the current legislation. Due to the uncertainty as to when the Trust will substantially be able to utilize the income tax pools, the Trust has taken a valuation allowance of $15.0 million on this adjustment. The Trust is currently evaluating the new legislation and the Trust's organizational alternatives to maximize shareholder value.

Our activities will continue to be focused on the successful execution of our capital development program and managing our conventional operations. Our balanced portfolio of development prospects in Western Canada continues to benefit us by providing flexibility in the allocation of our funds to maximize the economic returns of our various projects. Our hedging strategy combined with the diversification of our production mix by commodity will also provide additional stability in our cash flows as crude oil prices have remained strong while natural gas prices have declined in the near term.

Sincerely,

Robert T. Jepson, President & CEO



Three months ended Six months ended
June 30, June 30,
Summary of Financial Results 2007 2006 2007 2006
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($ thousands, except per
Trust unit amounts)
Petroleum and natural gas revenue (1) 32,057 36,310 64,151 72,485

Funds flow from operations 9,787 15,499 21,849 31,078
per Trust unit - basic 0.27 0.45 0.60 0.92
per Trust unit - diluted 0.24 0.38 0.53 0.80

Net income (loss) (4,865) 2,607 (7,293) 1,327
per Trust unit - basic (0.13) 0.08 (0.20) 0.04
per Trust unit - diluted (0.13) 0.07 (0.20) 0.03

Total assets 505,799 530,377 505,799 530,377

Bank debt 75,000 49,280 75,000 49,280
Working capital deficit 12,690 14,025 12,690 14,025

Total long-term liabilities 133,078 136,188 133,078 136,188
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(1) Petroleum and natural gas revenue are shown net of transportation costs.


FINANCIAL AND OPERATIONAL
HIGHLIGHTS Three months ended Six months ended
($ thousands, except per June 30, June 30,
volume and per Trust unit) 2007 2006 2007 2006
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FINANCIAL

Petroleum and natural gas revenue(1) 32,057 36,310 64,151 72,475

Funds flow from operations 9,787 15,499 21,849 31,078
per Trust unit - basic 0.27 0.45 0.60 0.92
per Trust unit - diluted 0.24 0.38 0.53 0.80

Net income (loss) (4,865) 2,607 (7,293) 1,327
per Trust unit - basic (0.13) 0.08 (0.20) 0.04
per Trust unit - diluted (0.13) 0.07 (0.20) 0.03

Distributions 9,316 11,805 18,563 23,372
Payout ratio 95% 76% 85% 75%
Capital expenditures 8,552 8,049 19,179 26,117
Bank debt 75,000 49,280 75,000 49,280
Working capital deficit 12,690 14,025 12,690 14,025

Trust units outstanding (thousands)
weighted average - basic 36,490 34,306 36,353 33,693
- diluted 38,992 37,387 38,895 37,550
end of period - basic 36,581 34,457 36,581 34,457
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OPERATIONAL (units as noted)

Average daily production
Natural gas (mcf) 28,497 29,502 27,467 29,465
Crude oil (bbls) 2,175 2,616 2,247 2,535
Natural gas liquids (bbls) 390 425 408 442
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Total (BOE) 7,314 7,958 7,233 7,888

Average sales price (2)
Natural gas ($ per mcf) 6.43 5.81 6.69 6.59
Crude oil ($ per bbl) 66.27 71.84 64.56 68.80
Natural gas liquids ($ per bbl) 49.06 75.87 48.15 69.37

Netback per BOE ($ per BOE)
Petroleum and natural gas revenue 48.12 50.13 48.97 50.76
Royalties 9.85 7.27 9.33 9.04
Production expense 15.13 14.73 15.25 13.33
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Operating netback 23.14 28.13 24.39 28.39

Wells drilled (gross/net) 2 (1.2) 4 (3.2) 6 (3.7) 9 (5.9)
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(1) Petroleum and natural gas revenue are shown net of transportation costs.
(2) Net of oil and gas transportation costs.


Management's Discussion and Analysis

August 13, 2007

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") as at and for the six months ended June 30, 2007 and the audited consolidated financial statements for the year ended December 31, 2006 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.

Production

Daily oil and natural gas production, for the three and six months ended June 30, 2007, averaged 7,314 BOE per day (2006 - 7,958 BOE per day) and 7,233 BOE per day (2006 - 7,888 BOE per day) respectively. Production levels to date have exceeded the 2007 stated production guidance of 7,000 to 7,200 BOE per day. Production in the second quarter improved approximately 163 BOE per day or 2% compared to the first quarter, primarily as a result of shut in gas being brought back on stream at Chinchaga in late March. Production targets exceeded expectations in the quarter in spite of very wet weather conditions and a prolonged spring break up which hampered access to our well sites.

Natural gas production for the quarter averaged 28.5 mmcf/d (2006 - 29.5 mmcf/d) and for the period to date averaged 27.5 mmcf/d (2006 - 29.5 mmcf/d). Quarter over quarter gas production increased by approximately 2,071 mmcf/d or 8% with the resumption of gas production at Chinchaga.

Oil production averaged 2,175 bbls per day (2006 - 2,616 bbls per day) and 2,247 bbls per day (2006 - 2,535 bbls per day) for the three and six months ended respectively. Quarter over quarter oil production was lower by 145 bbls per day due primarily to spring break up access problems to maintain the oil wells. The majority of these maintenance workover issues have subsequently been rectified.

Average daily production for the period ended June 30th is outlined below:



Three months Six months
Average ended June 30, % ended June 30, %
Daily Production 2007 2006 Change 2007 2006 Change
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Natural gas (mcf per day) 28,497 29,502 (3) 27,467 29,465 (7)
Crude oil (bbls per day) 2,175 2,616 (17) 2,247 2,535 (11)
Natural gas liquids
(bbls per day) 390 425 (8) 408 442 (8)
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Total (BOE per day) 7,314 7,958 (8) 7,233 7,888 (8)
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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 Six months
Average ended June 30, % ended June 30, %
Sales Price(1) 2007 2006 Change 2007 2006 Change
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Before effect of
physical hedges:
Natural gas ($ per mcf) 6.43 5.81 11 6.69 6.59 2
Crude oil ($ per bbl) 66.27 71.84 (8) 64.56 68.80 (6)
Natural gas liquids
($ per bbl) 49.06 75.87 (35) 48.15 69.37 (31)
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Average sales price
($ per BOE) 47.33 49.22 (4) 48.12 50.62 (5)
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Effect of Physical Hedges:
Natural gas ($ per mcf) 0.26 0.52 - 0.24 0.28 -
Crude oil ($ per bbl) (0.96) (3.10) - (0.32) (2.77) -
Natural gas liquids
($ per bbl) - - - - - -
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Average sales price
($ per BOE) 0.79 0.91 - 0.85 0.14 -
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Net Sales Price:
Natural gas ($ per mcf) 6.69 6.33 6 6.93 6.87 1
Crude oil ($ per bbl) 65.31 68.74 (5) 64.24 66.03 (3)
Natural gas liquids
($ per bbl) 49.06 75.87 (35) 48.15 69.37 (31)
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Average sales price
($ per BOE) 48.12 50.13 (4) 48.97 50.76 (4)
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(1) Net of oil and gas transportation costs


% %
Average Benchmark Pricing 2007 2006 Change 2007 2006 Change
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Natural Gas
AECO Daily Index
(Cdn$ per mcf) 7.06 6.01 17 7.23 6.77 7
AECO Monthly Index
(Cdn$ per mcf) 7.46 6.36 17 7.44 8.02 (7)

Crude Oil
West Texas Intermediate
(US$ per bbl) 64.93 70.70 (8) 61.40 67.09 (8)
West Texas Intermediate
(Cdn$ per bbl) 71.30 79.44 (10) 69.68 76.24 (9)
Edmonton Par
(Cdn$ per bbl) 72.65 78.85 (8) 70.18 74.13 (5)

Exchange Rates
US$/CDN$ Dollar Period-end 1.07 1.12 (4) 1.07 1.12 (4)
US$/CDN$ Dollar Average 1.10 1.12 (2) 1.13 1.14 (1)
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Commodity Price Risk Management

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



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Floor Upside
Product Volume price Participation Term
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Natural
gas 2,500 GJs/d $ 7.00/GJ Max price $9.00/GJ Apr 1, 2007-Oct 31, 2007

Natural
gas 7,500 GJs/d $ 7.60/GJ N/A Apr 1, 2007-Oct 31, 2007

Natural
gas 2,500 GJs/d $ 7.85/GJ 50% above $7.85/GJ Nov 1, 2007-Mar 31, 2008

Crude
Oil 1,000 bbls/d $68.00/bbl 50% above $68.00/bbl Jan 1, 2007-Dec 31, 2007

Crude
Oil
- WTI
Swap 500 bbls/d $ 76.43 N/A Jan 1, 2008-Dec 31, 2008
Crude
Oil 500 bbls/d $ 71.15 50% above $71.15/bbl Jan 1, 2008-Dec 31, 2008

Crude
Oil
- WTI
Swap 250 bbls/d $ 76.15 N/A Jan 1, 2009-Dec 31, 2009
Crude
Oil 250 bbls/d $ 69.20 50% above $69.20/bbl Jan 1, 2009-Dec 31, 2009

Natural
Gas -
AECO
Swap 2,500 GJs/d $ 8.61 N/A Nov 1, 2007-Mar 31, 2008

Electricity 5 MWH $ 60.75/MW N/A Apr 1, 2006-Dec 31, 2008
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On January 1, 2007, the Trust adopted the new accounting standards regarding the accounting for financial instruments. The Trust determined that the physical instruments in respect of the commodity purchase and sales contracts qualify for the normal purchase or sale exemption. Accordingly, the change in fair value of these financial instruments 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 financial transactions are recognized. At June 30, 2007, the fair value of these physical contracts was estimated to be $4.0 million.

During the quarter, the Trust recognized a current liability of $389,000 for the fair value of its oil and gas swap derivative contracts.

Petroleum and natural gas revenue

Petroleum and natural gas revenue, net of transportation was $32.0 million (2006 - $36.3 million) and $64.1 million (2006 - $72.5 million) for the three and six months ended June 30, 2007. Sales revenue for the second quarter of $32.0 million remained virtually unchanged from the first quarter of this year.

Natural gas prices averaged $6.43 per mcf for the quarter and $6.69 per mcf for the period to date. Average gas prices received for the second quarter were down approximately 8% compared to the first quarter in 2007. The price of natural gas is based primarily on the supply and demand fundamentals in the North American markets. In Western Canada, a pullback in exploration and development drilling activity has decreased gas production, and together with growth demand for gas by oil sands producers, will result in lower volumes available for U.S. export. Natural gas prices have weakened in the near term as a result of surplus natural gas storage, and liquefied natural gas imports to the United States have continued to grow in the absence of demand in Europe. We believe the outlook for natural gas prices remains positive over the medium to long term.

Crude oil prices averaged $66.27 per bbl for the quarter and $64.56 per bbl for the six months ended. Average crude oil prices received for the quarter were higher by 5% compared to the first quarter in the year. Crude oil prices have remained at relatively high levels due to the continued global demand, significant geopolitical and weather related issues, and concerns regarding lack of North American refining capacity.



For the Three Months Ended June 30, 2007
Analysis of Sales Revenue(1)
($ thousands) Natural Gas Crude Oil NGLs Total
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2006 Sales Revenue 17,002 16,377 2,931 36,310
Price Variance 990 (821) (1,032) (863)
Volume Variance (613) (2,621) (156) (3,390)
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2007 Sales Revenue 17,379 12,935 1,743 32,057
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For the Six Months Ended June 30, 2007
Analysis of Sales Revenue(1)
($ thousands) Natural Gas Crude Oil NGLs Total
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2006 Sales Revenue 36,636 30,304 5,545 72,485
Price Variance 326 (821) (1,693) (2,188)
Volume Variance (2,507) (3,347) (292) (6,146)
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2007 Sales Revenue 34,455 26,136 3,560 64,151
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(1) Revenue is shown net of oil and gas transportation costs and including
the effect of physical hedges.


The physical natural gas and crude oil hedges increased revenues by $497,000 (2006 - $659,000) and $1.1 million (2006 - $205,000) for the three and six months ended respectively.

Royalties

Royalties are paid to various government entities and other land and mineral rights owners. Effective for 2007, the Alberta government eliminated the Alberta royalty tax credit program. The impact to the Trust was an increase to royalty expense of approximately $0.1 million in the period to date.

For the three months ended, royalty expenses were $6.6 million or 20% of petroleum and natural gas revenue compared to $5.3 million or 14% in 2006. This includes a 2005-2007 one-time retroactive crown oil royalty adjustment of $474,000 which was received in the quarter. The second quarter 2006 results included an annual gas cost allowance adjustment of $1.3 million. For the six months ended, royalty expenses were $12.2 million or 18% of petroleum and natural gas revenue compared to $12.9 million or 17% in 2006.

The Alberta government is currently conducting a review of the oil and gas royalty regime which may impact royalties in the future.

Production Expense

Production expenses for the three and six months ended June 30, 2007 were $10.1 million or $ 15.13 per BOE (2006 - $10.7 million or $14.73 per BOE) and $20.0 million or $15.25 per BOE (2006 - $19.0 million or $13.33 per BOE) respectively.

Operating costs for the second quarter decreased by approximately 2% or $0.23 per BOE compared to the first quarter. Included in the second quarter operating costs are non-operated facility equalization costs from 2005 and 2006 totaling $480,000 ($0.72/BOE) which was received and recorded in the period. Progress has continued to be made to mitigate the well maintenance costs for the electrical submersible pump failures through modifying existing pump design and replacement at various Wimborne wells.

Future production expenses will continue to be influenced by the number of workovers, and well suspensions. Management is committed and focused on identifying opportunities to improve operational efficiencies to reduce operating costs.



Operating Netback

Three months Six months
ended June 30, % ended June 30, %
Operating Netback(1) 2007 2006 Change 2007 2006 Change
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Natural gas ($ per mcf)
Revenue 6.69 6.33 6 6.93 6.87 1
Royalties 1.59 1.24 28 1.52 1.52 -
Production expense 2.02 2.05 (1) 2.09 1.86 12
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Operating Netback 3.08 3.04 1 3.32 3.49 (5)
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Crude oil and NGL
($ per bbl)
Revenue 62.84 69.74 (10) 61.76 66.52 (7)
Royalties 10.37 7.02 48 9.68 8.93 8
Production expense 20.71 18.64 11 19.93 16.96 18
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Operating Netback 31.76 44.08 (28) 32.15 40.63 (21)
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Combined ($ per BOE)
Revenue 48.12 50.13 (4) 48.97 50.76 (4)
Royalties 9.85 7.27 35 9.33 9.04 3
Production expense 15.13 14.73 3 15.25 13.33 14
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Operating Netback 23.14 28.13 (18) 24.39 28.39 (14)
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(1) Revenue is shown net of oil and gas transportation costs and including
the effect of physical hedges.


The operating netback is a key indicator of the Trust's ability to generate funds flow for distribution and reinvestment. During the three and six months ended, Vault generated an operating netback of $ 23.14 per BOE (2006 - $28.13 per BOE) and $ 24.39 per BOE (2006 - $28.39 per BOE). The 14% decrease for the period to date as compared to last year is attributable primarily to higher production expenses.

A reconciliation of the year to date 2007 operating netback by components compared to 2006 is as follows:



Operating netback reconciliation ($ thousands) 2007
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Production decrease (6,145)
Price decrease, net of hedging (2,476)
Transportation decrease 287
Royalty decrease 688
Production expense increase (926)
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Decrease in net operating income (8,572)
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General and Administrative Expenses ("G&A")

G&A costs, net of overhead recoveries on operated properties, were $2.6 million or $3.84 per BOE (2006 -$2.1 million or $2.88 per BOE) for the three months ended and $4.2 million or $3.21 per BOE (2006 - $ 3.9 million or $2.73 per BOE) for the six months ended June 30, 2007. The increase is attributable to higher employee compensation and office lease costs in the period.

Unit-based Compensation

In June 2007, the Board of Directors approved a new compensation plan that would better suit the employee base of the Trust and be more comparable with the standard industry compensation framework for a trust of this size. As part of the change to the compensation arrangements, the new Long Term Incentive Plan (LTIP) will provide for employees to be granted deemed units based on individual and corporate performance, which vest over a three year performance period. At the time of vesting, the deemed units are settled in cash and include the accumulated distributions over the three year period which are reinvested to purchase additional units. The LTIP has two components, namely: (1) Restricted Trust Units (RTUs) - 163,720 deemed units granted; and (2) Performance Trust

Units (PTUs) - 271,528 deemed units granted. The deemed RTUs granted vest one third annually over the three year period. The deemed PTUs will vest at the end of the three year period dependent upon certain performance levels being achieved, as vesting can range from 0-200% of the units granted. The Board reserves the right to change the LTIP from a deemed unit grant with a cash settlement program to a grant of units from Treasury, which is subject to unitholder approval. The LTIP does not replace the existing unit based compensation plan.

For the three and six months ended June 30, 2007, $869,000 (2006 - $658,000) and $1.7 million (2006 - $1.5 million) respectively were charged to income in respect of non-cash unit-based payments, which includes $21,000 compensation costs under the new LTIP arrangement. 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.

Interest Expense

The Trust incurred $3.0 million or $4.41 per BOE (2006 - $2.5 million or $3.45 per BOE) and $5.8 million or $4.52 per BOE (2006 - $4.5 million or $3.12 per BOE) in interest expense for the three and six months ended respectively. The inclusion of interest on the 7.2% debenture issuance in May of last year and drawing on available lines of credit to fund capital expenditure programs have increased overall interest expense. The Trust's average interest rates on bank credit facilities for the three and six months ended June 30, 2007 were 5.7% (2006 - 6.4%) and 5.6% (2006 -5.5%) respectively.

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

DD&A expense was $17.3 million or $25.92 per BOE (2006 -$17.6 million or $24.34 per BOE) and $33.8 million or $25.78 per BOE (2006 - $34.9 million or $24.47 per BOE) for the three and six months ended June 30, 2007. The provision for the quarter and year to date includes $469,000 or $ 0.70 per BOE (2006 - $417,000 or $0.58 per BOE) and $930,000 or $0.71 per BOE (2006 - $648,000 or $0.46 per BOE) respectively, for amortization and accretion on the convertible debentures.



Three months Six months
Depletion, depreciation ended June 30, % ended June 30, %
and accretion 2007 2006 Change 2007 2006 Change
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Depletion and
depreciation expense 16,236 16,695 (3) 31,743 33,261 (5)
Accretion of asset
retirement obligations 551 515 7 1,078 1,031 5
Other 469 417 12 930 648 44
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Total 17,256 17,627 (2) 33,751 34,940 (3)
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Taxes

In June 2007, the Government of Canada enacted new legislation as Bill C-52 received Royal Assent that will tax publicly traded income trusts. The new 31.5% tax which will be applied to income distributions, is not expected to apply to the Trust until January 1, 2011. The future income tax recovery adjustment of $15.0 million represents the taxable temporary differences of the Trust tax effected at 31.5%, which is the rate that will be applicable in 2011 under the current legislation. The taxable temporary differences relate principally to the excess of the Trust's income tax pools over the net book value of its oil and gas properties. Previously, the future income liability on the consolidated balance sheet represented only the future income tax liability of the Trust's subsidiary. Due to the uncertainty as to when the Trust will substantially be able to utilize the income tax pools, the Trust has taken a valuation allowance of $15.0 million on this adjustment. The Trust is currently evaluating the new legislation and the Trust's organizational alternatives to maximize shareholder value.

For the period to date, the provision for future income taxes was a recovery of $5.7 million, unchanged from 2006.

The current income taxes for the six months ended June 30, 2007 was a recovery of $271,000 relating to prior year's taxes, as compared to a provision of $8,000 in 2006.

Funds Flow and Net Loss

Funds flow from operations for the three months ended was $9.8 million ($0.24 per diluted Trust unit) as compared to $15.5 million ($0.38 per diluted Trust unit) in the same period for 2006. For the six months ended June 30, 2007, funds flow from operations was $21.8 million ($0.53 per diluted Trust unit) versus $31.1 million ($0.80 per diluted Trust unit) for the same period last year.

The Trust had a net loss of $4.9 million ($0.13 loss per diluted Trust unit) for the three month ended, compared to a net income of $2.6 million ($0.07 per diluted Trust unit) in the same period last year. For the six months ended June 30, 2007, the net loss was $7.3 million ($0.20 loss per diluted Trust unit) compared to a net income of $1.3 million ($0.03 per diluted Trust unit) for the same period in 2006.



Capital Expenditures
Three months ended Six months ended
Capital Expenditures ended June 30, ended June 30,
($ thousands) 2007 2006 2007 2006
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Land 399 368 889 708
Drilling, completions and workovers 4,836 4,608 11,519 15,382
Equipment 2,807 3,243 6,012 8,465
Geological and Geophysical 468 (182) 636 624
Office 42 12 123 938
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Capital expenditures 8,552 8,049 19,179 26,117
Property acquisitions - 412 - 412
Dispositions (140) (2,052) (140) (2,052)
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Net capital expenditures 8,412 6,409 19,039 24,477
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For the three and six months ended June 30, 2007, Vault drilled 2 (1.2 net) and 6 (3.7 net) wells respectively. During the quarter, capital expenditures incurred totaled $8.6 million which included costs to fund various recompletions, workovers, and pipeline construction projects to enhance and add new production. In the quarter, the Wimborne Nisku D2B project was completed and water injection commenced. Capital costs of $2.7 million were spent recompleting five wells and converting or installing necessary pipelines. Vault anticipates additional production volumes will start to be produced later this year. This project is expected to add incremental production volumes of approximately 200 BOE per day and 240,000 bbls of additional reserves. Total net capital expenditures incurred for the year to date were $19.0 million (2006 - $24.5 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 three and six months ended June 30, 2007, Vault declared cash distributions of $9.3 million or $0.26 per Trust unit and $18.6 million or $0.51 per Trust unit respectively to unitholders.



Reconciliation of Cash Three months ended Six months ended
Available for Distribution June 30, June 30,
($ thousands) 2007 2006 2007 2006
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Cash flow from operating
activities 10,583 (1,378) 18,839 12,634
Change in non-cash working
capital (796) 16,877 3,010 18,444
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Funds flow from operations 9,787 15,499 21,849 31,078
Cash withheld for acquisitions,
capital expenditures and debt
repayment(1) (471) (3,694) (3,286) (7,706)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Distributions 9,316 11,805 18,563 23,372
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Distributions per Trust unit $ 0.26 $ 0.35 $ 0.51 $ 0.69
Payout ratio 95% 76% 85% 75%
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) 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 $75.0 million and the working capital deficit, which includes bank overdraft of $7.1 million, was $12.7 million at June 30, 2007.

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 28, 2008.



Quarterly Financial Information

Summary of Quarterly Results

($ thousands) Q3/05 Q4/05 Q1/06 Q2/06 Q3/06 Q4/06 Q1/07 Q2/07
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Production:
Natural gas
(mcf per day) 30,899 29,363 29,428 29,502 27,388 27,184 26,426 28,497
Crude oil
and NGL
(bbls per day) 3,200 3,025 2,912 3,041 2,364 3,188 2,747 2,565
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total BOE
(Natural Gas
6:1) 8,350 7,919 7,817 7,958 6,929 7,718 7,151 7,314
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Petroleum and
natural gas
revenue (1) 43,847 47,791 36,175 36,310 32,158 34,155 32,095 32,057

Funds flow
from
operations 21,188 26,761 15,578 15,499 9,102 10,661 12,062 9,787
per Trust
unit -
basic 0.66 0.82 0.47 0.45 0.26 0.30 0.33 0.27
per Trust
unit -
diluted 0.57 0.73 0.42 0.38 0.23 0.27 0.29 0.24

Net income
(loss) 10,671 4,573 (1,280) 2,607 (13,841) (3,300) (2,428) (4,865)
per Trust
unit - basic 0.33 0.14 (0.04) 0.08 (0.40) (0.09) (0.07) (0.13)
per Trust
unit -
diluted 0.29 0.14 (0.04) 0.07 (0.40) (0.09) (0.07) (0.13)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

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


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 Trust units and 2,126,063 exchangeable shares outstanding.

At June 30, 2007, the Trust had 36,580,796 Trust units and 1,940,793 exchangeable shares outstanding. The increase in Trust units during the period is a result of 251,589 issued for exchangeable shares and 223,470 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 June 30, 2007:



----------------------------------------------------------------------------
----------------------------------------------------------------------------
Minimum Commitments Each Year Total
---------------------------------- Committed
($ thousands) 2007 2008 2009 2010 2011 After 2011 Total
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Capital lease
obligations 188 219 8 12 - - 427
Operating lease
obligation 876 1,752 1,819 1,825 1,825 3,802 11,899
----------------------------------------------------------------------------
1,064 1,971 1,827 1,837 1,825 3,802 12,326
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Debt commitments are outlined in the Notes to the Consolidated Financial
Statements.


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.

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.

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

A portion of 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

In June 2007, the Government of Canada enacted new legislation that will tax publicly traded income trusts, effective January 1, 2011. Prior to June 2007, the Trust estimated the future income tax on certain temporary differences between amounts recorded on its balance sheet for book and tax purposes at a nil effective tax rate. The new 31.5% tax which will be applied to income distributions, is not expected to apply to Vault until 2011. As the legislation is new, future technical interpretations of the legislation could occur and could materially affect management's estimate of the future income tax liability.

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.

Evaluation of Disclosure Controls and Procedures

Vault has implemented a system of internal controls that it believes adequately protects the asset of the Trust and is appropriate for the nature of its business and the size of its operation. These internal controls include disclosure controls and procedures designed to ensure that information required to be disclosed by the Trust is accumulated and communicated to management as appropriate to allow timely decisions regarding financial disclosure.

Management of Vault, including the Chief Executive Officer and Chief Financial Officer, have evaluated the effectiveness of the design of the disclosure controls and procedures. Management has concluded that the design of the disclosure controls and procedures provide reasonable assurance that material information is made known to them by others within Vault. It should be noted that while the Chief Executive Officer and Chief Financial Officer believe that the Trust's design of the disclosure controls and procedures provide a reasonable level of assurance that they are effective, they do not expect these disclosure controls and procedures or internal control over financial reporting will necessarily prevent all errors and fraud.

There were no material changes to the Trust's internal control over financial reporting since December 31, 2006 that have materially affected, or are reasonably likely to materially affect, the Trust's internal control over financial reporting.

Additional information related to Vault, including the Annual Information Form (AIF), may be found on the SEDAR website at www.sedar.com.



VAULT ENERGY TRUST
Consolidated Balance Sheets

June 30, December 31,
($ thousands) 2007 2006
----------------------------------------------------------------------------
(unaudited)

Assets
Current assets:
Accounts receivable $ 17,868 $ 16,025
Prepaid expenses and deposits 2,249 2,413
----------------------------------------------------------------------------
20,117 18,438

Property, plant and equipment (Note 3) 485,682 497,316
Deferred charges (Note 5) - 3,905
----------------------------------------------------------------------------
$ 505,799 $ 519,659
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Liabilities and Unitholders' Equity
Current liabilities:
Bank indebtedness $ 7,116 $ 7,433
Accounts payable and accrued liabilities 22,193 24,418
Derivative contracts (Note 14) 389 -
Distributions payable to unitholders 3,109 3,069
----------------------------------------------------------------------------
32,807 34,920

Capital lease obligation 138 258
Deferred credits (Note 15) 2,370 2,310
Revolving credit facility (Note 4) 75,000 56,000
Convertible debentures (Note 5) 91,953 94,928
Asset retirement obligation (Note 6) 35,608 34,508
Future income taxes (Note 10) 3,009 8,139
----------------------------------------------------------------------------
208,078 196,143

Non-controlling interest (Note 7) 12,036 13,861

Unitholders' equity:
Trust units/common shares (Note 8) 346,688 344,363
Contributed surplus (Note 9) 7,755 6,081
Equity component of convertible debentures
(Note 5) 4,701 4,701
Deficit (106,266) (80,410)
----------------------------------------------------------------------------
252,878 274,735
----------------------------------------------------------------------------
$ 505,799 $ 519,659
----------------------------------------------------------------------------
----------------------------------------------------------------------------

See accompanying notes to the consolidated financial statements

Approved by the Board of Directors:

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


VAULT ENERGY TRUST
Consolidated Statements of Income (Loss) and Deficit
(unaudited)
Three Three Six Six
Months Months Months Months
Ended Ended Ended Ended
June 30, June 30, June 30, June 30,
($ thousands) 2007 2006 2007 2006
----------------------------------------------------------------------------
Revenue:
Petroleum and natural
gas $ 33,071 $ 37,495 $ 66,479 $ 75,100
Transportation expense (1,014) (1,185) (2,328) (2,615)
Royalties (6,559) (5,267) (12,225) (12,913)
Unrealized loss on
derivative contracts (389) - (389) -
----------------------------------------------------------------------------
25,109 31,043 51,537 59,572

Expenses:
Production 10,071 10,670 19,960 19,034
General and
administrative 2,561 2,086 4,205 3,899
Unit-based compensation
(Note 9) 869 658 1,694 1,465
Interest 3,009 2,497 5,786 4,461
Depletion, depreciation
and accretion 17,256 17,627 33,751 34,940
----------------------------------------------------------------------------
33,766 33,538 65,396 63,799

----------------------------------------------------------------------------
Net loss before
taxes (8,657) (2,495) (13,859) (4,227)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Taxes:
Current tax provision
(recovery) (1) (179) (271) 8
Future income tax recovery
(Note 10) (3,398) (5,206) (5,702) (5,698)
----------------------------------------------------------------------------
(3,399) (5,385) (5,973) (5,690)

Net income (loss) before
non-controlling interest (5,258) 2,890 (7,886) 1,463
Non-controlling
interest (Note 7) 393 (283) 593 (136)
----------------------------------------------------------------------------
Net income (loss) $ (4,865) $ 2,607 $ (7,293) $ 1,327
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Deficit, beginning
of period $ (92,085) $ (31,729) $ (80,410) $ (18,882)
Net income (loss) (4,865) 2,607 (7,293) 1,327
Distributions (9,316) (11,805) (18,563) (23,372)
----------------------------------------------------------------------------
Deficit, end of period $ (106,266) $ (40,927) $ (106,266) $ (40,927)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Net income (loss) per
Trust unit (Note 11)
Basic (0.13) 0.08 (0.20) 0.04
Diluted (0.13) 0.07 (0.20) 0.03


VAULT ENERGY TRUST
Consolidated Statements of Cash Flows
(unaudited)
Three Three Six Six
Months Months Months Months
Ended Ended Ended Ended
June 30, June 30, June 30, June 30,
($ thousands) 2007 2006 2007 2006
----------------------------------------------------------------------------


Cash provided by (used in):

Operating:
Net income (loss) $ (4,865) $ 2,607 $ (7,293) $ 1,327
Items not affecting cash:
Unrealized loss on
derivative contracts 389 - 389 -
Depletion, depreciation
and accretion 17,256 17,627 33,751 34,940
Amortization of natural
gas sales contract (193) (248) (396) (506)
Unit-based compensation 848 658 1,674 1,465
Future income tax
recovery (3,398) (5,206) (5,702) (5,698)
Non-controlling
interest (393) 283 (593) 136
Gas over bitumen royalty
adjustment 226 - 430 -
Asset retirement
expenditures (83) (222) (411) (586)
----------------------------------------------------------------------------
Funds flow from
operations 9,787 15,499 21,849 31,078
Net change in non-cash
operating working
capital 796 (16,877) (3,010) (18,444)
----------------------------------------------------------------------------
10,583 (1,378) 18,839 12,634
----------------------------------------------------------------------------

Financing:
Increase in revolving
credit facility 8,896 (42,395) 18,683 (32,219)
Convertible debenture
issue, net of costs - 47,787 - 47,787
Increase (decrease) in
capital lease obligation (93) (36) (119) 73
Trust units issued,
net of costs 241 3,626 1,054 3,828
Warrants exercised - 24 - 262
Distributions to
unitholders (9,316) (11,805) (18,563) (23,372)
Change in non-cash
financing working
capital 16 74 40 192
----------------------------------------------------------------------------
(256) (2,725) 1,095 (3,449)
----------------------------------------------------------------------------

Investments:
Capital expenditures (8,552) (8,049) (19,179) (26,117)
Property acquisitions - (412) - (412)
Property dispositions 140 2,052 140 2,052
Change in non-cash
investing working
capital (1,915) 8,672 (895) 9,523
----------------------------------------------------------------------------
(10,327) 2,263 (19,934) (14,954)
----------------------------------------------------------------------------

Change in cash - (1,840) - (5,769)
Cash, beginning of
period - 1,840 - 5,769
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Cash, end of period $ - $ - $ - $ -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes to the consolidated financial statements


Vault Energy Trust
Notes to the Consolidated Financial Statements
Six months ended June 30, 2007
(Tabular amounts in thousands of Canadian dollars, except per unit amounts)


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 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 7) 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. SUMMARY OF ACCOUNTING POLICIES

The interim consolidated financial statements of Vault have been prepared by management in accordance with accounting principles generally accepted in Canada. The interim consolidated financial statements have been prepared following the same accounting policies and methods of computation as the audited consolidated financial statements of Vault for the period ended December 31, 2006. The disclosures provided below are incremental to those included with the audited annual consolidated financial statements. The interim consolidated financial statements should be read in conjunction with the audited consolidated financial statements and the notes thereto in Vault Energy Trust's annual report for the period ended December 31, 2006.

2. CHANGE IN ACCOUNTING POLICY

a) Financial Instruments

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 measured 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

Currently, the Trust does not enter into any financial instruments for trading or speculative purposes. Effective January 1, 2007, the Trust determined that the financial instruments in respect of the commodity purchase and sales contracts qualify for the normal purchase or sale exemption. Accordingly, the change in fair value of these financial instruments 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 financial transactions are recognized.

The fair value of the commodity derivative contacts are recognized at each reporting date with the change in the fair value being classified as an unrealized gain or loss in the statement of income.

b) Deferred Charges

Under the requirements of the new financial instrument standards, the Trust has included the debenture issue costs as part of the carrying value of the debt component effective January 1, 2007. Refer to note 5 for more details.



3. PROPERTY, PLANT AND EQUIPMENT

June 30, December 31,
Property, plant and equipment ($ thousands) 2007 2006
----------------------------------------------------------------------------
Petroleum and natural gas properties 619,599 599,606
Office and other equipment 3,833 3,744
----------------------------------------------------------------------------
623,432 603,350
----------------------------------------------------------------------------
Accumulated depletion, depreciation and accretion (137,750) (106,034)
----------------------------------------------------------------------------
Property, plant and equipment 485,682 497,316
----------------------------------------------------------------------------
----------------------------------------------------------------------------


As at June 30, 2007, the cost of petroleum and natural gas properties includes $14,497,000 (2006 - $15,554,000) 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 $1,079,000 (2006 - $1,031,000) for accretion of asset retirement costs. During the period, the Trust capitalized $232,000 (2006 - $136,000) of geological and geophysical administrative costs associated with exploration and development activities. Future development costs of $24,060,000 (2006 - $14,263,000) have been included in the calculation of depletion, depreciation and accretion.

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 28, 2008. 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 June 30, 2007 was 5.9% (2006 - 6.3%).

5. CONVERTIBLE DEBENTURES

On April 27, 2005, Chamaelo Energy Inc. ("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. Effective January 1, 2007, issue costs of $1,960,000 have been classified with the debt component and will be amortized over the life of the debentures. For the six months ended June 30, 2007, amortization of $279,000 (2006 - $280,000) 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 $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 period ended June 30, 2007:



Number of Debt Component Equity component
Convertible Debentures - 8% Debentures ($ thousands) ($ thousands)
----------------------------------------------------------------------------
Balance at December 31, 2006 48,671 47,003 2,301
Deferred charges (1,960)
----------------------------------------------------------------------------
Balance at January 1, 2007 45,043
Accretion & Amortization 496
----------------------------------------------------------------------------
Balance at June 30, 2007 48,671 45,539 2,301
----------------------------------------------------------------------------
----------------------------------------------------------------------------


On May 2, 2006, Vault closed a bought deal offering of $50,000,000 principle amount of convertible unsecured subordinated debentures. Effective January 1, 2007, issue costs of $1,945,000 have been classified with the debt component and will be amortized over the life of the debentures. For the six months ended June 30, 2007, amortization of $225,000 (2006 - $75,000) 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 period ended June 30, 2007:



Number of Debt Component Equity component
Convertible Debentures - 7.2% Debentures ($ thousands) ($ thousands)
----------------------------------------------------------------------------
Balance at December 31, 2006 50,000 47,925 2,400
Deferred charges (1,945)
----------------------------------------------------------------------------
Balance at January 1, 2007 45,980
Accretion & Amortization 434
----------------------------------------------------------------------------
Balance at June 30, 2007 50,000 46,414 2,400
----------------------------------------------------------------------------
----------------------------------------------------------------------------


6. ASSET RETIREMENT OBLIGATION

The Trust's asset retirement obligation results 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 $133,600,000 (2006 - $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 obligation is provided below:

June 30, December 31,
Asset retirement obligation ($ thousands) 2007 2006
----------------------------------------------------------------------------
Balance, beginning of period 34,508 29,560
Liabilities incurred in period 164 395
Liabilities resulting from changes in estimates 269 4,465
Accretion expense 1,078 2,095
Liabilities settled in period (411) (2,007)
----------------------------------------------------------------------------
Balance, end of period 35,608 34,508
----------------------------------------------------------------------------
----------------------------------------------------------------------------


7. NON-CONTROLLING INTEREST

Pursuant to the Plan of Arrangement on June 22, 2005, 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 exchangeable shares must be exchanged for Trust units by June 22, 2008.



The following summarizes the exchangeable shares outstanding and the non-
controlling interest ("NCI") as at June 30, 2007:

June 30, 2007 December 31, 2006
----------------------------------------------------------------------------
Exchangeable Non-controlling Exchangeable Non-controlling
Shares Interest ('000s) Shares Interest ('000s)
----------------------------------------------------------------------------
Balance,
beginning of
period 2,126,063 13,861 3,560,586 24,856
Retracted for
Trust units (185,270) (1,232) (1,434,523) (9,514)
Net loss
attributable
to NCI (593) (1,481)
----------------------------------------------------------------------------
Balance, end
of period 1,940,793 12,036 2,126,063 13,861
Exchange
ratio,
end of period 1.4041 1.26889
----------------------------------------------------------------------------
Trust units
issuable upon
conversion,
end of period 2,725,067 2,697,740
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Exchangeable share retractions are accounted for using the step acquisition method of accounting. A summary of these acquisitions to date as at June 30, 2007 is as follows:



June 30, December 31,
2007 2006
----------------------------------------------------------------------------
Acquisition of non-controlling interest ($ thousands) ($ thousands)
----------------------------------------------------------------------------
Retraction of exchangeable shares
reflected in property, plant and equipment 10,538 9,913
Future taxes on acquisition of exchangeable
shares (3,483) (2,897)
----------------------------------------------------------------------------
Excess of fair market value over book value 7,055 7,016
----------------------------------------------------------------------------
----------------------------------------------------------------------------


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:

June 30, 2007 December 31, 2006
Number of Amount Number of Amount
Units ('000s) Units ('000s)
----------------------------------------------------------------------------
Balance, beginning of the period 36,105,737 342,856 32,785,833 315,612
Trust units issued on retraction of
exhangeable shares 251,589 1,271 1,615,358 14,747
Trust units issued through
Distribution
Re-investment & Optional Purchase
Plan 223,470 1,054 1,623,182 11,848
Trust units issued on exercise of
warrants - - 81,364 625
Plan of Arrangement & other - - - 24
----------------------------------------------------------------------------
Balance, end of the period 36,580,796 345,181 36,105,737 342,856
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Warrants (note 8(b)) - 1,507 - 1,507
----------------------------------------------------------------------------
Total Unitholders' Equity 36,580,796 346,688 36,105,737 344,363
----------------------------------------------------------------------------
----------------------------------------------------------------------------


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 was suspended effective December 15, 2006 while the Regular DRIP was suspended effective the May 15, 2007 distribution 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. No warrants were exercised for Trust units during the period. As at June 30, 2007, the remaining warrants outstanding of 1,664,455 have been reduced in exercise price by $2.75 per warrant.

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 June 30, 2007:

Weighted
Average Average Average
Number of Original Reduced Years to
Rights Price ($) Price ($) Expiry
----------------------------------------------------------------------------
Balance, January 1, 2007 2,169,930 9.96 8.58 3.94
Rights granted 68,730 5.34 5.13 4.86
Rights cancelled (237,678) 10.11 8.22 3.42
----------------------------------------------------------------------------
Balance, June 30, 2007 2,000,982 9.66 7.82 3.38
----------------------------------------------------------------------------
----------------------------------------------------------------------------

The following table summarizes information with respect to outstanding
rights as at June 30, 2007:

Number of
Weighted Weighted Weighted Rights
Number of Rights Average Average Average Exercisable
Outstanding at Exercise Reduced Years to at June 30,
June 30, 2007 Price ($) Price ($) Expiry 2007
----------------------------------------------------------------------------
1,076,670 10.56 8.21 3.07 358,890
33,075 12.43 10.14 3.15 11,025
78,775 13.27 11.09 3.19 26,258
37,125 10.67 8.75 3.40 12,375
4,800 9.82 8.22 3.59 1,600
770,537 8.00 6.78 4.17 -
----------------------------------------------------------------------------
2,000,982 9.66 7.82 3.38 410,148
----------------------------------------------------------------------------
----------------------------------------------------------------------------


9. UNIT-BASED COMPENSATION

During the six months ended June 30, 2007, $1,694,000 (2006 - 1,465,000) was charged to income in respect of unit-based compensation cost. These charges comprise amortization of the fair value of Trust unit rights and also include $21,000 relating to compensation costs under the new Long Term Incentive Plan (LTIP).

In June 2007, the Board of Directors approved a new compensation plan that would better suit the employee base of the Trust and be more comparable with the standard industry compensation framework for a trust of this size. As part of the change to the compensation arrangements, the new LTIP will provide for employees to be granted deemed units based on individual and corporate performance, which vest over a three year performance period. At the time of vesting, the deemed units are settled in cash and include the accumulated distributions over the three year period which are reinvested to purchase additional units. The LTIP has two components namely: (1) Restricted Trust Units (RTUs) - 163,720 deemed units granted; and (2) Performance Trust Units (PTUs) - 271,528 deemed units granted. The deemed RTUs granted vest one third annually over the three year period. The deemed PTUs will vest at the end of the three year period dependent upon certain performance levels being achieved, as vesting can range from 0-200% of the units granted. The Board reserves the right to change the LTIP from a deemed unit grant with a cash settlement program to a grant of units from Treasury, which is subject to unitholder approval. The LTIP does not replace the existing unit based compensation plan.

On July 1, 2005, the Trust introduced its Trust Unit Rights Incentive Plan (the "Plan"). The Trust has granted 2,000,892 (Note 8(c)) rights to employees which are outstanding as of June 30, 2007. 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.



Six months ended
Unit-based compensation ($ thousands) June 30, 2007
----------------------------------------------------------------------------
Amortization of fair value 1,674

Contributed surplus
----------------------------------------------------------------------------
Balance, beginning of period 6,081
Amortization of fair value 1,674
----------------------------------------------------------------------------
Balance, end of period 7,755
----------------------------------------------------------------------------
----------------------------------------------------------------------------

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 for the period to date:

2007 2006
----------------------------------------------------------------------------
Fair value per right $4.71 $4.70
Risk-free rate 4.4% 3.9%
Expected life 5 years 5 years
Expected forfeitures 13.5% 10.0%
Expected volatility 52.0% 22.0%
Dividend yield $1.02 $1.38
----------------------------------------------------------------------------


10. TAXES

In June 2007, the Government of Canada enacted new legislation as Bill C-52 received Royal Assent that will tax publicly traded income trusts. The new 31.5% tax which will be applied to income distributions, is not expected to apply to the Trust until January 1, 2011. The future income tax recovery adjustment of $15.0 million represents the taxable temporary differences of the Trust tax effected at 31.5%, which is the rate that will be applicable in 2011 under the current legislation. The taxable temporary differences relate principally to the excess of the Trust's income tax pools over the net book value of its oil and gas properties. Previously, the future income liability on the consolidated balance sheet represented only the future income tax liability of the Trust's subsidiary. Due to the uncertainty as to when the Trust will substantially be able to utilize the income tax pools, the Trust has taken a valuation allowance of $15.0 million on this adjustment.

The future income tax provision for the six months ended June 30, 2007 was a recovery of $5,702,000, compared to a recovery of $5,698,000 in 2006.



11. PER TRUST UNIT INFORMATION

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

2007 2006
----------------------------------------------------------------------------
Basic 36,353,443 33,692,958
Dilution on account of:
Exchangeable shares 2,541,165 3,386,663
Warrants - 470,777
----------------------------------------------------------------------------
Diluted 38,894,608 37,550,398
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Trust unit rights and convertible debentures are anti-dilutive for the six months ended June 30, 2007, 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.



12. SUPPLEMENTAL CASH FLOW INFORMATION

Three months ended Six months ended
June 30, June 30,
($ thousands) 2007 2006 2007 2006
----------------------------------------------------------------------------
Cash interest paid 4,826 2,529 5,710 3,544

Cash taxes paid - 8 - 195
----------------------------------------------------------------------------
----------------------------------------------------------------------------

13. PHYSICAL SALES CONTRACTS

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

----------------------------------------------------------------------------
Upside
Product Volume Floor price Participation Term
----------------------------------------------------------------------------
Natural gas 2,500 GJs/d $7.00/GJ Max price $9.00/GJ Apr 1, 2007
-Oct 31, 2007
Natural gas 7,500 GJs/d $7.60/GJ N/A Apr 1, 2007
-Oct 31, 2007
Natural gas 2,500 GJs/d $7.85/GJ 50% above $7.85/GJ Nov 1, 2007
-Mar 31, 2008
Crude Oil 1,000 bbls/d $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
----------------------------------------------------------------------------


Effective January 1, 2007, the Trust determined that the physical financial instruments in respect of the commodity purchase and sales contracts qualify for the normal purchase or sale exemption. Accordingly, the change in fair value of these financial instruments 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 financial transactions are recognized. At June 30, 2007, the fair value of these physical contracts is estimated to be $3,963,000.

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 June 30, 2007 is $52,073,000 for the 8% convertible debentures and $48,625,000 for the 7.2% convertible debentures.

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.



The following financial derivative contracts were outstanding at June 30,
2007:

----------------------------------------------------------------------------
Upside
Product Volume Floor price Participation Term
----------------------------------------------------------------------------

Crude Oil 500 bbls/d $76.43 N/A Jan 1, 2008
- WTI Swap -Dec 31, 2008
Crude Oil 500 bbls/d $71.15 50% above $71.15/bbl Jan 1, 2008
-Dec 31, 2008

Crude Oil 250 bbls/d $76.15 N/A Jan 1, 2009
- WTI Swap -Dec 31, 2009
Crude Oil 250 bbls/d $69.20 50% above $69.20/bbl Jan 1, 2009
-Dec 31, 2009

Natural Gas 2,500 GJs/d $8.61 N/A Nov 1, 2007
- AECO Swap -Mar 31, 2008

----------------------------------------------------------------------------


New CICA Handbook Standards, Section 1530 "Comprehensive Income", Section 3855 "Financial Instruments - Recognition and Measurement", Section 3861 "Financial Instruments - Disclosure and Presentation" and Section 3865 "Hedges" are applicable for the Trust beginning in 2007.

All derivative contracts commencing in 2007 are recorded at fair value on the balance sheet. Derivatives are adjusted to fair value each period with the change recognized in the determination of income. At June 30, 2007, the Trust recognized a current liability of $389,000 for the fair value of its oil and gas derivative contracts.

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 June 30, 2007, 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 $242,000 at June 30, 2007 (2006 - $1,091,000) 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 June 30, 2007, the Trust has not entered into any foreign currency derivatives with respect to oil and natural gas sales. The financial derivatives have been transacted in Canadian dollars and as such have a foreign currency derivative embedded.

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 $1,853,000 as at June 30, 2007.



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 June 30, 2007:

----------------------------------------------------------------------------
Total
Minimum Commitments Each Year Committed
($ thousands) 2007 2008 2009 2010 2011 After 2011 Total
----------------------------------------------------------------------------
Capital lease obligations 188 219 8 12 - - 427
Operating lease obligation 876 1,752 1,819 1,825 1,825 3,802 11,899
----------------------------------------------------------------------------
1,064 1,971 1,827 1,837 1,825 3,802 12,326
----------------------------------------------------------------------------
----------------------------------------------------------------------------

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