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EXHIBIT 4.7  
  

ULTIMA ENERGY TRUST

CONSOLIDATED FINANCIAL STATEMENTS

As at and for the Years Ended December 31, 2003 and 2002  

C-98

 
  
 

    REPORT OF INDEPENDENT REGISTERED CHARTERED ACCOUNTANTS    
    

To
the Directors of Ultima Ventures Corp. and Ultima Acquisitions Corp.: 

        We
have audited the consolidated balance sheet of Ultima Energy Trust as at December 31, 2003 and 2002 and the consolidated statements of income and deficit and cash flows for the
years then ended. These financial statements are the responsibility of the Trust's management. Our responsibility is to express an opinion on these financial statements based on our audits. 

        We
conducted our audits in accordance with Canadian generally accepted auditing standards. Those standards require that we plan and perform an audit to obtain reasonable assurance
whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. 

        In
our opinion, these consolidated financial statements present fairly, in all material respects, the financial position of the Trust as at December 31, 2003 and 2002 and the
results of its operations and its cash flows for the years then ended in accordance with Canadian generally accepted accounting principles. 

	Calgary, Alberta

February 24, 2004 (except as to Notes 14 and 15

which are as of April 30, 2004)	 	(signed) Deloitte & Touche LLP

Independent Registered Chartered Accountants

	 

ULTIMA ENERGY TRUST  

COMMENTS BY INDEPENDENT REGISTERED CHARTERED ACCOUNTANTS ON CANADA — U.S. REPORTING DIFFERENCES  

        The standards of the Public Company Accounting Oversight Board (United States) require the addition of an explanatory paragraph (following the opinion
paragraph) outlining changes in accounting principles that have been implemented in the financial statements. As discussed in Note 2 to the consolidated financial statements of Ultima
Energy Trust, the Trust changed its method of accounting for capital assets from the successful efforts method to full cost method. Also, as discussed in Note 2, the Trust changed its method of
accounting for unit based compensation. 

	Calgary, Alberta

April 30, 2004	 	(signed) Deloitte & Touche LLP

Independent Registered Chartered Accountants

C-99

 
 
 

ULTIMA ENERGY TRUST    
    
    CONSOLIDATED BALANCE SHEET    
    
    (thousands of dollars)    
    

	 
	 	December 31
	 
	 
	 	2003
	 	2002
	 
	ASSETS	 	 	 	 	 	 	 
	Current assets	 	 	 	 	 	 	 
	 	Accounts receivable	 	$	12,442	 	$	8,969	 
	 	Prepaid expenses	 	 	1,803	 	 	528	 
	 	 	
	 	
	 
	 	 	 	14,245	 	 	9,497	 
	Reclamation fund (note 7)	 	 	1,077	 	 	748	 
	Goodwill (note 5)	 	 	16,682	 	 	—	 
	Capital assets, net (note 4)	 	 	294,535	 	 	207,930	 
	 	 	
	 	
	 
	Total Assets	 	$	326,539	 	$	218,175	 
	 	 	
	 	
	 
	LIABILITIES and UNITHOLDERS' EQUITY	 	 	 	 	 	 	 
	LIABILITIES	 	 	 	 	 	 	 
	Current liabilities	 	 	 	 	 	 	 
	 	Bank indebtedness	 	$	977	 	$	19	 
	 	Accounts payable	 	 	16,613	 	 	9,204	 
	 	Cash distributions payable	 	 	4,898	 	 	2,710	 
	 	 	
	 	
	 
	 	 	 	22,488	 	 	11,933	 
	Accumulated site restoration	 	 	8,076	 	 	5,066	 
	Deferred capital obligation (note 6)	 	 	28,126	 	 	20,444	 
	Future Income Taxes (notes 5 and 13)	 	 	14,398	 	 	—	 
	Long-term bank debt (note 8)	 	 	45,007	 	 	55,358	 
	Contingencies and Commitments (note 12)	 	 	 	 	 	 	 
	 	 	
	 	
	 
	 	 	 	118,095	 	 	92,801	 
	 	 	
	 	
	 
	UNITHOLDERS' EQUITY	 	 	 	 	 	 	 
	Unitholders' capital (note 9)	 	 	324,821	 	 	206,154	 
	Contributed surplus (note 9)	 	 	260	 	 	—	 
	Deficit	 	 	(4,944	)	 	(17,222	)
	Accumulated cash distributions (note 3)	 	 	(111,693	)	 	(63,558	)
	 	 	
	 	
	 
	 	 	 	208,444	 	 	125,374	 
	 	 	
	 	
	 
	Total Liabilities and Unitholders' Equity	 	$	326,539	 	$	218,175	 
	 	 	
	 	
	 

The accompanying notes are an intergral part of these consolidated financial statements  

C-100

 
  
 

    ULTIMA ENERGY TRUST    
    
    CONSOLIDATED STATEMENT OF INCOME AND DEFICIT    
    
    (thousands of dollars except for per unit amounts)    
    

	 
	 	Year Ended December 31
	 
	 
	 	2003
	 	2002
	 
	Revenue:	 	 	 	 	 	 	 
	 	Oil and natural gas	 	$	111,107	 	$	44,472	 
	 	Royalties	 	 	(21,810	)	 	(6,219	)
	 	Income from Weyburn Limited Partnership (note 6)	 	 	—	 	 	4,198	 
	 	 	
	 	
	 
	 	 	 	89,297	 	 	42,451	 
	 	 	
	 	
	 
	Expenses:	 	 	 	 	 	 	 
	 	Oil and natural gas operating	 	 	25,485	 	 	13,603	 
	 	General and administrative (note 10)	 	 	9,914	 	 	3,159	 
	 	Management fee (note 10)	 	 	487	 	 	856	 
	 	Interest on long-term debt (note 8)	 	 	3,171	 	 	817	 
	 	Unit based compensation (note 9)	 	 	260	 	 	—	 
	 	Capital taxes	 	 	76	 	 	—	 
	 	Depletion and amortization (note 4)	 	 	38,526	 	 	14,792	 
	 	 	
	 	
	 
	 	 	 	77,919	 	 	33,227	 
	 	 	
	 	
	 
	Net income before income taxes	 	 	11,378	 	 	9,224	 
	Future income tax recovery (note 13)	 	$	900	 	$	—	 
	 	 	
	 	
	 
	Net income	 	 	12,278	 	 	9,224	 
	Deficit, beginning of year (note 2(l))	 	 	(17,222	)	 	(26,446	)
	 	 	
	 	
	 
	Deficit, end of year	 	$	(4,944	)	$	(17,222	)
	 	 	
	 	
	 
	Net income per unit, basic (note 2(k))	 	$	0.29	 	$	0.42	 
	Net income per unit, diluted (note 2(k))	 	$	0.28	 	$	0.41	 

The accompanying notes are an intergral part of theses consolidated financial statements  

C-101

 
  
 

    ULTIMA ENERGY TRUST    
    
    CONSOLIDATED STATEMENT OF CASH FLOWS    
    
    (thousands of dollars)    
    

	 
	 	Year Ended December 31
	 
	 
	 	2003
	 	2002
	 
	Operating Activities:	 	 	 	 	 	 	 
	 	Net income	 	$	12,278	 	$	9,224	 
	 	Add/(less) items not involving cash:	 	 	 	 	 	 	 
	 	Future income tax recovery	 	 	(900	)	 	—	 
	 	Unit based compensation	 	 	260	 	 	—	 
	 	Internalization of management contract (note 10)	 	 	4,716	 	 	—	 
	 	Depletion and amortization	 	 	38,526	 	 	14,792	 
	 	 	
	 	
	 
	 	 	 	54,880	 	 	24,016	 
	 	Changes in non-cash operating working capital	 	 	(572	)	 	(816	)
	 	 	
	 	
	 
	 	 	 	54,308	 	 	23,200	 
	 	 	
	 	
	 
	Financing Activities:	 	 	 	 	 	 	 
	 	Issuance of Trust units, net	 	 	117,617	 	 	71,840	 
	 	Bank loan	 	 	(10,351	)	 	26,068	 
	 	Cash distributions paid to unitholders	 	 	(45,947	)	 	(19,371	)
	 	 	
	 	
	 
	 	 	 	61,319	 	 	78,537	 
	 	 	
	 	
	 
	Investing Activities:	 	 	 	 	 	 	 
	 	Capital asset additions	 	 	(23,884	)	 	(5,690	)
	 	Investment in Weyburn Limited Partnership	 	 	—	 	 	1,042	 
	 	Acquisitions of properties, net of divestments	 	 	(88,410	)	 	(96,504	)
	 	Internalization of management contract	 	 	(3,666	)	 	—	 
	 	Reclamation fund contributions	 	 	(625	)	 	(325	)
	 	 	
	 	
	 
	 	 	 	(116,585	)	 	(101,477	)
	 	 	
	 	
	 
	Increase/(Decrease) in bank indebtedness	 	 	(958	)	 	260	 
	Bank indebtedness, beginning of year	 	 	(19	)	 	(279	)
	 	 	
	 	
	 
	Bank indebtedness, end of year	 	$	(977	)	$	(19	)
	 	 	
	 	
	 
	Supplemental Information	 	 	 	 	 	 	 
	Cash income taxes paid	 	$	—	 	$	—	 
	Cash interest paid	 	$	3,171	 	$	817	 

The accompanying notes are an intergral part of these consolidated financial statements  

C-102

  

 
 

ULTIMA ENERGY TRUST    
    
    NOTES TO CONSOLIDATED FINANCIAL STATEMENTS    
    
    Years ended December 31, 2003 and 2002
  (Tabular amounts in thousands of dollars except for per unit amounts)

    

1.     Basis of Presentation  

	a.
	Structure

Ultima
Ventures Corp. (the "Corporation"), Ultima Ventures Trust ("Ventures Trust") Ultima Energy Inc. ("Energy Inc."), Ultima Management Inc. ("the Manager") and Ultima Acquisitions Corp.
("Acquisitions Corp.") operate under common management. The financial statements include the accounts of Ultima Energy Trust ("the Trust"), and the accounts of its subsidiaries, the Corporation,
Ventures Trust, Energy Inc., the Manager and Acquisitions Corp., on a consolidated basis. Inter-entity transactions and balances have been eliminated. These consolidated financial statements are
prepared following accounting principles generally accepted in Canada. 

The
Trust is an open-ended, unincorporated investment trust formed under the laws of the Province of Alberta. The beneficiaries of the Trust and its subsidiaries are the unitholders. Ventures Trust
and Energy Inc. hold oil and natural gas properties. The Trust acquires an interest in the cash flow generated by these properties in the form of a royalty with each of Ventures Trust and Energy Inc.
The Trust was set up to acquire and hold the royalty(s) and to issue trust units. Each
royalty consists of 99% of the net cash flow generated by the underlying properties, less certain expenditures, including capital expenditures funded by cashflow and any debt repayments. 

2.     Significant Accounting Policies  

	a.
	Joint
Interests 

Certain
oil and natural gas activities are conducted jointly with others and, these consolidated financial statements reflect the Trust's proportionate interest in such activities. 

	b.
	Oil
and Natural Gas Properties 

The
Trust follows the Full Cost Method of accounting whereby all costs relating to the acquisition and development of oil and natural gas reserves are capitalized. The Trust does not capitalize
general and administration expenses. Interest relating to the Weyburn Unit NRI deferred capital obligation is capitalized pursuant to the terms of the agreement. 

No
gains or losses are recognized in income during the year in which oil and natural gas properties are sold unless the depletion and amortization rate changes by more than 20% as a result of the
sale. 

	c.
	Depletion
and Amortization 

Capital
costs of oil and natural gas properties, net of estimated salvage values, are depleted using the unit of production method. These capital costs are depleted based on estimated gross proved oil
and natural gas reserves as determined by independent engineers. For purposes of these calculations production of crude oil, natural gas, natural gas liquids and proved reserves are converted to a
common unit of measure on the basis of 6 thousand cubic feet of natural gas to 1 barrel of oil equivalent. 

C-103

 

	d.
	Future
Site Restoration 

Estimated
future costs of site restoration are provided for over the life of the proved reserves on a unit of production basis. Costs are estimated each period by management using current costs and in
accordance with existing legislation and underlying practice. The provision is included with depletion and amortization expense and actual site restoration expenditures are charged against the
accumulated provision. 

	e.
	Ceiling
Test 

The
Trust places a limit on the aggregate carrying amount of capital assets, which may be depleted against revenues of future periods (the "ceiling test"). Capitalized costs plus the estimated future
capital associated with proved undeveloped reserves, less accumulated depletion and amortization are limited to an amount equal to the discounted future net revenues of the estimated proved and risked
probable reserves. 

	f.
	Goodwill 

The
Trust recorded goodwill relating to a corporate acquisition. The goodwill was determined as the excess of the purchase price over the fair value of the acquired assets less liabilities, including
future income taxes, of the acquired company. The goodwill balance is assessed for impairment at each balance sheet reporting date. Impairment would be charged to earnings in the period it was
incurred. Goodwill is reported at cost less any impairment and is not subject to amortization. 

	g.
	Investment
in Weyburn Limited Partnership ("WLP") 

Effective
November 1, 2002, the Trust increased its ownership in the WLP and immediately redeemed its entire interest (see Note 6) in the WLP. Prior to this time, the Trust's interest in the
WLP was accounted for using the cost method. Pursuant to this method, no income with respect to the WLP was recorded in the accounts of the Trust except for cash distributions received or receivable.
Cash distributions received or receivable were recorded as a reduction of the investment to the extent that such distributions represented a return of capital. 

	h.
	Hedging
Contracts 

From
time to time the Trust enters into various arrangements to hedge against possible fluctuations in commodity prices, interest rates and exchange rates. Gains or losses from these arrangements,
which constitute effective economic hedges, are reported as adjustments to the related revenue or expense accounts as they are settled. 

	i.
	Unit-Based
Compensation Plan 

The
Trust has a Trust Unit Rights Incentive Plan ("the Plan"), which is described in Note 9. The exercise price of the rights awarded pursuant to the plan may be reduced in future periods in
accordance with the terms of the Plan. The reduction is primarily a function of distributions to unitholders and the net book value of the Trust's capital assets. The reduction is calculated as the
excess, if any, of quarterly distributions greater than 2.5% of the net book value of capital assets. It is not possible to determine a fair value for the rights awarded pursuant to the Plan at
inception using an option-pricing model because the exercise reduction feature of the Plan is dependent upon a number of factors, including, but not limited to, future prices realized on the sale of
oil and natural gas, future production levels of oil and natural gas, amounts withheld from future distributions and the purchase and sale of capital assets. Compensation expense has been determined
based upon the intrinsic value of the rights at the date of exercise or at the date of the financial statements for unexercised rights. 

The
compensation expense associated with rights awarded under the Plan is deferred and recorded in earnings over the average vesting period of the rights awarded along with an equal increase or
decrease in contributed surplus. Changes in the intrinsic value of the unexercised rights after the vesting period will be recognized in the corresponding period of the change, along with an
accompanying increase or decrease to contributed surplus. 

C-104

 

On
the actual exercise of the rights by the holder the consideration paid and the amount of contributed surplus attributable to the exercised right will be recorded as an increase to Unitholders'
capital. 

	j.
	Income
Taxes 

The
Trust follows the liability method of accounting for income taxes. Under this method, income tax liabilities and assets are recognized for the estimated tax consequences attributable to
differences between the amounts reported in the financial statements of the Trust's corporate subsidiaries and their respective tax base, using enacted income tax rates. The effect of a change in
income tax rates on future tax liabilities and assets is recognized in income in the period in which the change occurs. Temporary differences arising on corporate acquisitions could result in future
income tax assets and liabilities. It is anticipated that any future assets or liabilities would be for the account of the unitholders. 

The
Trust is a taxable entity under the Income Tax Act (Canada) and is taxable only on income that is not distributed or distributable to unitholders. As the Trust expects to distribute its taxable
income to the unitholders and meets the requirements of the Income Tax Act (Canada) applicable to the Trust, no current provision for income taxes has been made. 

	k.
	Weighted
Average Number of Units Outstanding 

The
Trust uses the treasury stock method to determine the dilutive effect of "in the money" options, rights and other dilutive instruments issued. The basic and diluted calculations presented in these
financial statements are based on the following weighted average units outstanding: 

	 
	 	2003
	 	2002

	Basic	 	42,732,252	 	22,099,613
	Diluted	 	43,285,647	 	22,334,714

All
outstanding rights have been included in the calculation of diluted weighted average units outstanding. 

	l.
	Change
in Accounting Policies

	1.
	Capital
Assets 

In
late 2003 Ultima retroactively adopted the Full Cost Method of accounting for its capital assets pursuant to the Canadian Institute of Chartered Accountants ("CICA") Accounting Guideline ("AcG") 16
"Oil and Gas Accounting — Full Cost". Previously the Trust used the Successful Efforts Method of accounting for its capital assets. The effect of the change in
accounting policy on the financial statements of the Trust as previously presented is as follows: 

	As at December 31 
	 	2003(1)
	 	2002
	 
	Capital Assets, net	 	 	 	 	 	 	 
	As reported	 	$	301,904	 	$	212,092	 
	Adjustment	 	 	(7,369	)	 	(4,162	)
	 	 	
	 	
	 
	As restated	 	$	294,535	 	$	207,930	 
	 	 	
	 	
	 
	Net Income	 	 	 	 	 	 	 
	As reported	 	$	14,644	 	$	9,191	 
	Adjustment	 	 	(2,366	)	 	33	 
	 	 	
	 	
	 
	 	 	 	 	 	 	 	 

C-105

 

	As restated	 	$	12,278	 	$	9,224	 
	 	 	
	 	
	 
	Deficit	 	 	 	 	 	 	 
	Beginning of year	 	$	(13,060	)	$	(22,251	)
	Adjustment	 	 	(4,162	)	 	(4,195	)
	 	 	
	 	
	 
	As restated	 	 	(17,222	)	 	(26,446	)
	Net Income as restated	 	 	12,278	 	 	9,224	 
	 	 	
	 	
	 
	End of year	 	$	(4,944	)	$	(17,222	)
	 	 	
	 	
	 

	

	(1)	 	For 2003, the amounts noted as "As reported" reflect the Successful Efforts Method of accounting for capital assets as if it had been applied for the full year.

There
is no effect on cashflow in either period presented due to the adoption of the Full Cost Method. 

	2.
	Unit
Based Compensation Plan 

The
Trust elected to prospectively adopt amendments to the CICA Handbook Section 3870, "Stock-Based Compensation and Other Stock-Based Payments". Pursuant to this accounting standard the Trust
must account for compensation expense based upon the fair value of the rights awarded under the Plan. As the Trust is unable to determine the fair value of the rights upon issuance compensation
expense has been determined based upon the intrinsic value of the rights at the exercise date or at the date of the financial statements for unexercised rights. Previously the Trust accounted for
compensation expense based upon the intrinsic value of the rights at the award date. Because the rights were awarded at fair market value, no compensation expense was charged to net income at the time
of the award under the previous method of accounting. 

The
intrinsic value is determined as the excess of the trading price of the Trust's trust units over the exercise price of the unexercised rights. For exercised rights the intrinsic value is
determined as the excess of the trading price of the Trust's trust units over the exercise price of the rights at the time the rights were exercised. 

For
rights granted prior to 2003 the Trust elected to continue accounting for the compensation expense based upon the intrinsic value at the award date. For rights awarded in 2002 the Trust has
disclosed the pro-forma results for 2002 and 2003. However, the net income for 2002 has not been restated. The pro-forma results are presented in Note 10. 

For
2003 the Trust has recorded $260,000 as compensation expense, noted as a separate line in the income statement. Included in Unitholders' Equity is contributed surplus of the same amount. No
amounts would have been recorded under the prior method of accounting. 

There
was no material effect on net income per unit as a result of adopting this method of accounting for unit based compensation. 

	3.
	Disclosure
of Guarantees 

The
Trust has adopted AcG-14 "Disclosure of Guarantees". This guideline requires the Trust to disclose all guarantees to third parties, of which there are none. There is no effect on net income or
cashflow as a result of adopting this guideline. 

C-106

 

3.     Cash Distributions to Unitholders  

	 
	 	2003
	 	2002
	 
	Net income	 	$	12,278	 	$	9,224	 
	Future income tax recovery (note 13)	 	 	(900	)	 	—	 
	Unit based compensation	 	 	260	 	 	—	 
	Internalization of Management (note 10)	 	 	4,716	 	 	—	 
	Depletion and amortization	 	 	38,526	 	 	14,792	 
	 	 	
	 	
	 
	Cash available for distributions	 	 	54,880	 	 	24,016	 
	Reclamation fund contributions (note 7)	 	 	(625	)	 	(325	)
	Cash applied to financing and investing activities	 	 	(6,120	)	 	(2,717	)
	 	 	
	 	
	 
	Cash distributions declared	 	 	48,135	 	 	20,974	 
	Accumulated cash distributions, beginning of year	 	 	63,558	 	 	42,584	 
	Accumulated cash distributions, end of year	 	$	111,693	 	$	63,558	 
	 	 	
	 	
	 
	Cash distributions declared per unit	 	$	1.09	 	$	0.90	 

4.     Capital Assets  

	Oil and natural gas properties 
	 	Cost
	 	Accumulated

Depletion and

Amortization
	 	Net Book Value

	2003	 	$	443,550	 	$	149,015	 	$	294,535
	2002	 	 	321,659	 	 	113,729	 	 	207,930

The
balances shown above have been restated due to the change in accounting policy whereby the Trust adopted the Full Cost Method of accounting for its capital assets. See note 2 (l). 

Estimated
future capital costs included in the 2003 depletion and amortization calculation were $83,642,000 (2002 — $3,211,000), primarily attributable to the
Weyburn Unit Net Royalty Interest ("Weyburn Unit NRI") acquired on the redemption of the Trust's interest in the WLP. Excluded from the calculation of depletion and amortization for 2003 is unproved
property attributable to the Weyburn Unit NRI in the amount of $11,300,000 (2002 — $nil). 

Included
in the 2003 provision for depletion and amortization is a provision for future site restoration of $3,239,000 (2002 — $1,200,000). 

5.     Trioco Acquisition  

On
June 26, 2003, the Trust acquired all the issued and outstanding shares of Trioco Resources Inc. ("Trioco") a private company engaged in the exploration and development of oil and natural
gas in Alberta. The transaction has been accounted for using the purchase method of accounting (results of operations have been included as at June 26, 2003) and the allocation of the purchase
price is as follows: 

C-107

 

	Net assets acquired	 	 	 	 
	 	Current assets	 	$	2,546	 
	 	Capital assets	 	 	71,000	 
	 	Goodwill	 	 	16,682	 
	 	Current liabilities	 	 	(3,863	)
	 	Future income taxes	 	 	(15,298	)
	 	Future site restoration	 	 	(67	)
	 	 	
	 
	 	 	$	71,000	 
	 	 	
	 
	Paid by	 	 	 	 
	 	Cash	 	$	61,000	 
	 	Bank debt assumed	 	 	10,000	 
	 	 	
	 
	 	 	$	71,000	 
	 	 	
	 

6.     Weyburn Limited Partnership and Deferred Capital Obligation  

Effective
November 1, 2000, the Trust acquired a 92% interest in the WLP in a transaction involving the sale to the WLP of the Trust's Plato property for $3.3 million and the investment of the
proceeds of sale in the WLP. The capital assets of the WLP were comprised of the Plato property, the Ferrybank property acquired from another partner and an 11.7% net royalty interest ("Weyburn Unit
NRI") in the Weyburn Unit. The Weyburn Unit NRI was acquired by the WLP from EnCana Resources, the managing partner of the WLP, in consideration for a note payable for $77.8 million ($66.9 million as
at November 1, 2002). The note payable is a non-recourse instrument with respect to the Trust's assets held outside of the WLP. 

Effective
November 1, 2002, the Trust contributed additional capital of approximately $66.9 million in cash, before adjustments, to the WLP to allow repayment in full of the outstanding note
payable to EnCana Resources. The Trust subsequently redeemed its entire limited partnership interest. As consideration for the redemption, the Trust received 100% of the WLP's interest in the Weyburn
Unit NRI, the interest in the Plato property, cash and working capital. The Trust funded the additional capital contribution from the net proceeds of an equity offering of $46,550,000 along with
approximately $20,383,000 of borrowings drawn from the bank credit facility of Ventures Trust. 

The
redemption price and consideration paid was as follows: 

	Net assets acquired on redemption:	 	 	 
	 	Cash and working capital	 	$	1,042
	 	Capital Assets	 	 	84,731
	 	 	

	Total net assets	 	$	85,773
	 	 	

	Financed by:	 	 	 
	 	Bank borrowings	 	$	20,383
	 	Trust Units issued	 	 	46,550
	 	Deferred capital obligation assumed	 	 	18,840
	 	 	

	Total purchase price	 	$	85,773
	 	 	

C-108

 

The
deferred capital obligation arose pursuant to the Weyburn Unit NRI agreement whereby payment for capital costs incurred in connection with the Weyburn Unit's operations prior to January 1,
2003 was deferred until the earlier of the date when the costs deferred totalled $18,778,000 or December 31, 2002. Interest was accrued on the amount deferred at a base rate of 8.5% per annum.
Pursuant to an agreement with EnCana Resources in connection with the redemption, payment of up to an additional $15 million of capital expenditures applicable to the Weyburn Unit NRI will be deferred
for the years 2003, 2004 and 2005. The Trust has the right to select the amount of the payment to be deferred each year to a maximum of $8 million of deferred expenditures for any given year. Also
beginning January 1, 2003, interest will accrue on the deferred capital obligation at a base rate of 7% per annum. Repayment will commence on the earlier of January 1, 2006, or the date
on which the deferred capital payments total $33,778,000. The deferred capital obligation will be amortized over a 15 year period. Interest will continue to accrue over the amortization period at a
base rate of 7%, however, the deferred capital obligation repayment terms include an after-tax equalization component. This component provides for an effective interest rate over the amortization
period of approximately 10%. The income tax equalization component will primarily affect the payments made in the latter half of the amortization period. 

At
December 31, 2003, the capital costs that have been deferred in accordance with the agreement were $24,437,000. This amount plus interest of $3,689,000, for a total of $28,126,000, has been
recorded as a long-term obligation. Pursuant to the Weyburn Unit NRI agreement, the Trust has the right at any time to pre-pay all or any part of the obligation along with an additional 7% of the
amount being prepaid. Unless the deferred capital obligation is prepaid, the deferred capital obligation is only payable out of future income from the Weyburn Unit NRI, and as such the other assets of
the Trust do not secure the deferred capital obligation. 

7.     Reclamation Fund  

Funds
have been deducted from cash distributions to unitholders to provide for the future cost of abandonments and reclamation work on wells, plants and facilities. The amount of the contribution for
2003 and 2002 was $0.20 per boe of production. 

	 
	 	2003
	 	2002
	 
	Reclamation fund, beginning of year	 	$	748	 	$	472	 
	Contributions	 	 	625	 	 	325	 
	Reclamation expenditures	 	 	(296	)	 	(49	)
	 	 	
	 	
	 
	Reclamation fund, end of year	 	$	1,077	 	$	748	 
	 	 	
	 	
	 

8.     Long-Term Bank Debt  

	 
	 	2003
	 	2002

	Bankers' acceptance notes	 	$	42,007	 	$	30,000
	Revolving line of credit	 	 	3,000	 	 	25,358
	 	 	
	 	

	 	 	$	45,007	 	$	55,358
	 	 	
	 	

Pursuant
to a loan agreement dated June 26, 2003 between Ventures Trust and a syndicate comprised of the Alberta Treasury Branches and the National Bank of Canada ("the Syndicate"), Ventures
Trust has a revolving term production loan facility ("the facility") with a maximum limit of $95,000,000, including a $10,000,000 operating line of credit. 

The
facility has a 364-day extendable revolving period and a two year term. Borrowings under the facility bear interest from bank prime plus 0.125% to bank prime plus 1.875%, dependent upon the level
of trailing net debt to operating cashflow. The borrowings are secured by a $150,000,000 floating charge debenture over all the assets and undertakings of Ventures Trust, Energy Inc., the Manager, the
Corporation and Acquisitions Corp. The credit facilities are subject to a semi annual review on May 31 and November 1 each year and upon review the Syndicate determines if it will extend the
revolving period for another six months. In the event that the Syndicate does not extend the facility for another six months, there is a two year payment period with no payments being required for the
first year. 

C-109

 

Pursuant
to a subordination agreement entered into on June 26, 2003, the Syndicate has been provided with security over all of the assets of Ventures Trust, Energy Inc., the Manager, the
Corporation and Acquisitions Corp. in priority to the royalty payable to the Trust by each of Ventures Trust and Energy Inc. The facility is the legal obligation of Ventures Trust. Principal and
interest payments are deducted in the calculation of cash available for distribution to unitholders. In the event that the oil and natural gas properties of Ventures Trust and Energy Inc. do not
generate sufficient income to discharge the obligation, the unitholders of the Trust will have no direct liability. 

9.     Unitholders' Capital  

	a.
	Authorized 

Unlimited
number of trust units 

	b.
	Issued

	 
	 	2003
	 	2002

	 
	 	Number of Trust Units
	 	Amount
	 	Number of Trust Units
	 	Amount

	Balance, beginning of year	 	33,873,808	 	$	206,154	 	18,447,142	 	$	134,314
	Issued for cash, net of costs	 	23,000,000	 	 	115,197	 	15,350,000	 	 	71,564
	Issued on exercise of rights	 	512,998	 	 	3,301	 	16,666	 	 	73
	Issued for internalization (note 10)	 	188,169	 	 	—	 	—	 	 	—
	Issued on exercise of options	 	50,000	 	 	169	 	60,000	 	 	203
	 	 	
	 	
	 	
	 	

	Balance, end of year	 	57,624,975	 	$	324,821	 	33,873,808	 	$	206,154
	 	 	
	 	
	 	
	 	

In
2003, the Trust issued 23.0 million Trust units for net proceeds of $115.8 million, before legal and other costs in three separate equity offerings. These offerings are summarized below: 

	Date
 
	 	Number of

Trust Units
	 	Net Proceeds

	May 2003	 	5,000,000	 	$	23,988
	July 2003	 	12,000,000	 	 	59,280
	December 2003	 	6,000,000	 	 	32,490
	 	 	
	 	

	 	 	23,000,000	 	$	115,758
	 	 	
	 	

Trust
units are retractable at any time on demand by the holders thereof at a price based on an established formula. The aggregate cash retraction price payable by the Trust during any calendar month
shall not exceed $100,000 provided that such limitation may be waived at the discretion of the Boards of Directors of the Corporation (the trustee for Ventures Trust) and Acquisitions Corp. If a
unitholder is not entitled to receive cash upon the retraction of trust units as a result of the foregoing limitations, then the retraction price for such trust units shall be the fair market value
thereof as determined by the Boards of Directors of the Corporation and Acquisitions Corp. and shall, subject to any applicable regulatory approvals, be paid and satisfied by way of a distribution in
specie of the Trust's interests in Ventures Trust and Acquisitions Corp., a corporation as yet inactive, incorporated for the purpose of holding future acquired corporate shares and facilities, if
any. 

C-110

 

	c.
	Trust
Unit Options 

	 
	 	2003
	 	2002

	 
	 	Number of Options
	 	Exercise price per unit
	 	Number of Options
	 	Exercise price per unit

	Beginning Balance	 	50,000	 	$	3.38	 	110,000	 	$	3.38
	Issued during the year	 	—	 	 	—	 	—	 	 	—
	Less: exercised during the year	 	50,000	 	$	3.38	 	60,000	 	$	3.38
	 	 	
	 	
	 	
	 	

	Ending Balance	 	—	 	 	—	 	50,000	 	$	3.38
	 	 	
	 	
	 	
	 	

No
further options have been issued pursuant to this plan. 

	d.
	Trust
Unit Rights Incentive Plan 

A
Trust Units Rights Incentive Plan (the "Plan") was established in 2001. The Trust is authorized to award up to an additional 881,597 rights to the employees of the Manager, and directors of the
Trust to purchase trust units, as a form of long-term performance incentive. The rights awarded pursuant to the Plan may not be granted at a price that is less than the prevailing market price of the
trust units at the time of the date of the award, and the maximum term of each right may not exceed ten years. 

The
exercise price of each right may be adjusted downwards at the option of the rights holder from time to time by the amount, if any, that distributions in any calendar quarter exceed 2.5% of the
Trust's net book value of capital assets. 

During
the year, the Trust granted 1,044,000 rights to employees of the Manager and directors of the Corporation and Acquisitions Corp. to purchase trust units at an average price of $5.27 per unit.
Rights awarded pursuant to the Plan have terms ranging from five to 10 years and vest equally over three years, commencing on the first anniversary date of the grant. 

A
summary of the rights issued, exercised, cancelled and outstanding pursuant to the Plan is as follows: 

	 
	 	2003
	 	2002
	 
	 
	 	Number of

Rights
	 	Weighted

Average

Exercise

Price
	 	Number of

Rights
	 	Weighted

Average

Exercise

Price
	 
	Balance beginning of year	 	1,476,667	 	$	4.30	 	1,310,000	 	$	4.34	 
	Granted	 	1,044,000	 	 	5.27	 	240,000	 	 	5.23	 
	Exercised	 	512,998	 	 	4.40	 	16,666	 	 	4.40	 
	Cancelled	 	—	 	 	—	 	56,667	 	 	4.34	 
	 	 	
	 	
	 	
	 	
	 
	Balance before reduction in exercise price	 	2,007,669	 	 	4.78	 	1,476,667	 	 	4.49	 
	Reduction of exercise price	 	—	 	 	(0.38	)	—	 	 	(0.19	)
	 	 	
	 	
	 	
	 	
	 
	Balance, end of year	 	2,007,669	 	$	4.40	 	1,476,667	 	$	4.30	 
	 	 	
	 	
	 	
	 	
	 

A
summary of the Plan as at December 31, 2003 is as follows: 

	Exercise

Price at

Grant Date
 
	 	Adjusted

Exercise Price
	 	Number of

Rights

Outstanding
	 	Remaining

Contractual Life

of Rights (years)
	 	Number of

Rights

Exercisable

	$4.40	 	$	3.70	 	738,335	 	8	 	331,669
	$5.23	 	$	4.69	 	225,334	 	9	 	65,334
	$5.27	 	$	4.85	 	1,044,000	 	5 to 10	 	—
	 	 	 	 	 	
	 	 	 	

	 	 	 	 	 	2,007,669	 	 	 	397,003
	 	 	 	 	 	
	 	 	 	

C-111

 

The
Trust has recorded compensation expense and contributed surplus of $260,000 based upon the year-end trust unit trading price of $6.24 per trust unit in respect of the rights awarded in 2003. 

For
rights awarded in 2002 compensation cost for pro forma disclosure purposes has been determined based on the excess of the unit price over the exercise price at the date of the financial
statements. 

Provided
below is the pro forma net earnings and net earnings per trust unit for the year ended December 31, 2003 and 2002. 

	(Thousands of dollars)
	 	2003
	 	2002

	Net earnings:	 	 	 	 
	 	As reported	 	12,278	 	9,224
	 	Pro forma	 	12,014	 	9,199
	Net earnings per share	 	 	 	 
	 	Basic	 	 	 	 
	 	 	As reported	 	0.29	 	0.42
	 	 	Pro forma	 	0.28	 	0.42
	 	Diluted	 	 	 	 
	 	 	As reported	 	0.28	 	0.41
	 	 	Pro forma	 	0.28	 	0.41

10.     Related Party Transactions  

On
March 26, 2003 the Trust, through its subsidiary 1032213 Alberta Ltd, purchased from WhitePass Capital Inc. all of the issued and outstanding common shares of the Manager for total
consideration of $3,000,000 in cash and the issuance of 143,365 trust units (valued at $800,000). The Manager provided the management and administrative services to the Trust. For 2003 up to the time
of the purchase by the Trust, the Manager was paid $487,000 in management fees. For 2002, it was paid $1.3 million of management fees and administration fees by the Trust and the WLP respectively,
plus acquisition fees of $1.4 million. The purchase price of $3,800,000 was recorded as a charge to general and administrative expense in the quarter, except for furniture and fixtures in the amount
of $137,000, which was capitalized as part of capital assets. 

On
July 31, 2003, 1032213 Alberta Ltd. was amalgamated with the Manager and the resulting entity was named Ultima Management Inc. 

In
conjunction with the purchase of the Manager and internalization of the Management Agreement, retention payments of $500,000 in cash and 44,803 trust units with a market value of $250,000 was paid
to the officers and management of the Manager. The three officers will earn an additional $750,000 to be paid by the issuance of trust units over the next three anniversary dates of the closing of the
transaction should the Manager still employ them. 

The
retention paid at the close of the transaction was charged to general and administrative expense. The remaining retention will be charged to general and administrative expense when it is incurred. 

C-112

 

11.     Financial Instruments  

Financial
instruments of the Trust include accounts receivable, cash distributions payable, accounts payable, bank indebtedness, the bank loan and the deferred capital obligation. There are no
significant differences between the carrying value of these amounts and their estimated fair value. 

Substantially
all of the Trust's accounts receivable are due from customers in the oil and gas industry, and are subject to normal industry credit risks. The carrying value of the accounts receivable
reflects management's assessment of the associated credit risks. 

The
Trust is exposed to risks arising from fluctuations in commodity prices, foreign exchange rates and interest rates. The Trust utilizes a variety of derivative instruments to reduce its exposure to
changes in commodity prices. The fair values of these derivative instruments are based on an estimate of the amounts that would have been received from or paid to counterparties to settle these
instruments at year end. 

The
Trust is exposed to losses in the event of default by the counterparties to these derivative instruments. The Trust manages this risk by dealing only with financially sound counterparties and by
utilizing more than one counterparty to build its derivative position. 

During
2003, the Trust entered into or assumed as part of a corporate acquisition, six separate crude oil commodity price hedge arrangements which are summarized below: 

(US$/bbl
except as indicated) 

	Daily Quantity
 
	 	Fixed

Price
	 	Sold

Call
	 	Purchased

Put
	 	Sold

Put
	 	Term

	500 bbls	 	23.40	 	—	 	—	 	—	 	Calendar 2003
	500 bbls	 	24.30	 	—	 	—	 	—	 	Calendar 2003
	1,000 bbls	 	25.98	 	 	 	—	 	—	 	Jan.1 to June 30, 2003
	1,500 bbls	 	—	 	30.00	 	25.00	 	20.50	 	Feb.1 to Dec.31 2003
	1,000 bbls	 	28.05	 	—	 	—	 	—	 	July 1 to Dec. 31, 2003
	100 bbls	 	—	 	27.60	 	25.00	 	—	 	Calendar 2003

During
2003, the Trust entered into three separate natural gas commodity price hedge arrangements, which are summarized below: 

	Daily Quantity
 
	 	Fixed Price

$Cdn/GJ
	 	Term

	4,000 GJ	 	6.15	 	Aug.1, 2003 to March 31, 2004
	1,000 GJ	 	5.69	 	Jan. 1 to Oct. 31, 2003
	1,000 GJ	 	7.00	 	April 1, 2003 to March 31, 2004

A
realized hedging loss of $6.6 million was recorded in oil and natural gas revenue 2003 (2002 — realized hedging loss of $5.3 million). 

The
Trust has entered into a variety of crude oil and natural gas commodity price hedge arrangements for 2004 as summarized below: 

Crude Oil Hedges (all amounts are in US$/bbl except as indicated) 

	Daily Quantity
 
	 	Fixed Price
	 	Sold call
	 	Sold put
	 	Purchased put
	 	Term

	1,000 bbls(1)	 	Cdn$35.00	 	—	 	—	 	—	 	Calendar 2004
	1,000 bbls(1)	 	27.00	 	—	 	—	 	—	 	Jan. 1 to June 30, 2004
	800 bbls(1)	 	—	 	27.50	 	24.00	 	20.00	 	Calendar 2004
	700 bbls(1)&(2)	 	—	 	30.00	 	25.00	 	21.00	 	Calendar 2004

C-113

 

Natural Gas Hedges

	Daily Quantity
 
	 	Fixed Price

$/GJ
	 	Term

	4,000 GJ(1)	 	6.15	 	Aug.1, 2003 to March 31, 2004
	1,000 GJ(1)	 	7.00	 	April 1, 2003 to March 31, 2004

	

	(1)	 	Hedges outstanding as at December 31, 2003. The fair value of these commodity price hedge arrangements was a loss of $3.6 million, based on quoted market prices and if not available, on estimates from third-party
brokers or dealers or amounts derived from valuation models.
	
 (2)	
 	

For clarity:

	If WTI Price is

(US$/bbl)
 
	 	Ultima receives

(US$/bbl)

	Greater than $30	 	$30 per bbl
	Between $25 per bbl and $30 per bbl	 	Actual price
	Less than $21 per bbl	 	Actual price plus $4.00 per bbl

12.     Contingencies and Commitments  

The
Trust is involved in litigation and claims associated with normal operations and is of the opinion that any resulting settlements would not materially affect its financial position or reported
results of operations. 

The
Trust has entered into an office lease agreement for the Calgary head office for the period June 1, 2003 to May 31, 2009. The minimum annual lease payments, before occupancy costs, over the
next six years range from $247,000 at the beginning of the term to $291,000 at the end of the term. 

The
Trust has entered into a fixed price purchase contract with its electricity supplier in central Alberta for 2004 for the purchase of one megawatt hour per hour ("mwh") at a price of $51.00 per
mwh. The total purchase commitment is $447,000. 

Pursuant
to the Weyburn Unit NRI agreement the Trust has future development capital costs associated with carbon dioxide purchases of $59.5 million, to be incurred over the next 15 years. This amount
was determined by the Trust's independent engineers and is attributable to the total proved case for the oil and natural gas reserves. The Weyburn Unit NRI agreement has a provision that, for any
given month, cashflow attributable to the NRI cannot be negative. Accordingly, the Trust's share of the Weyburn Unit carbon dioxide purchases is only recourse to the Weyburn Unit NRI, and is
non-recourse in nature to the balance of the Trust's assets. 

13.     Income Taxes  

The
provision for current and future income taxes is different than what would have been calculated by applying the combined federal and provincial statutory rates to net income before income taxes. 

	 
	 	2003
	 
	Net income before income taxes	 	$	11,378	 
	 	Income tax provision calculated at statutory rates	 	 	(4,508	)
	 	Income attributable to the Trust	 	 	5,436	 
	 	Internalization of management	 	 	(1,550	)
	 	Non-deductible crown charges	 	 	(9,524	)
	 	Resource allowance	 	 	10,219	 
	 	Income tax rate reductions on opening balances	 	 	827	 
	 	 	
	 
	Recovery of future taxes	 	$	900	 
	 	 	
	 

C-114

 

The
future income tax liability includes the following temporary differences: 

	 
	 	2003

	Oil and natural gas properties	 	$	14,398
	 	 	

There
is no 2002 comparative balances presented as the future income tax is only attributable to a corporate acquisition which closed in 2003. 

The
crude oil and natural gas properties and related facilities owned by the corporate subsidiary have a tax basis of $26.7 million (2002 — $nil) available for
future use as deductions in the determination of taxable income for the subsidiary. There are no loss carry forwards included in this amount. 

14.     Differences Between Canadian and United States Generally Accepted Accounting Principles ("GAAP")  

The
Trust's consolidated financial statements have been prepared in accordance with Canadian generally accepted accounting principles ("Canadian GAAP"). These principles, as they pertain to the
Trust's consolidated financial statements, differ from United States generally accepted accounting principles ("U.S. GAAP") as follows: 

	a.
	The
Canadian GAAP ceiling test is comparable to the Securities and Exchange Commission ("SEC") method using constant prices, costs and tax legislation except that the SEC requires the
resulting amounts to be discounted at 10%.

	b.
	U.S.
GAAP utilizes the concept of comprehensive income, which includes items not included in net income. At the current time, there is no similar concept under Canadian GAAP. The
Trust's net income under U.S. GAAP is the same as its comprehensive income.

	c.
	U.S.
GAAP accounting and reporting standards require that all derivative instruments (including derivative instruments embedded in other contracts), as defined, be recorded in the
balance sheet as either an asset or a liability measured at fair value and requires that changes in fair value be recognized currently in income unless specific hedge accounting criteria are met.
There are no similar standards under Canadian GAAP at this time. 

Hedge
accounting treatment allows unrealized gains and losses to be deferred in other comprehensive income (for the effective portion of the hedge) until such time as the forecasted transaction occurs
and requires that an entity formally document, designate and assess effectiveness of derivative instruments that receive hedge accounting treatment. The Trust has elected to use fair value accounting
for its derivative instruments for U.S. GAAP and the change in fair value of these contracts has been reported in income. 

	d.
	Prior
to January l, 2003, for Canadian GAAP purposes, compensation expense for options granted under the Trust Unit Rights Incentive Plan ("the Plan") was measured based on the
intrinsic value of the award at the grant date. For the years ended December 31, 2003 and 2002, pro forma disclosures are included in the notes to the financial statements of the impact on net
income and net income per Trust unit had the Trust accounted for compensation expense based on the fair value of rights awarded during 2002. Effective January l, 2003, the Trust accounts for
compensation expense for rights awarded on or after January 1 , 2003, based on the fair value method of accounting as described in Note 2. 

For
U.S. GAAP purposes, the Plan is a variable compensation plan as the exercise price of the rights is subject to downward revisions from time to time. Accordingly, compensation expense is determined
as the excess of the market price of the Trust units over the adjusted exercise price of the rights at each financial reporting date and is deferred and recognized in income over the vesting period of
the rights. After the rights have vested, compensation expense is recognized in income in the period in which a change in the market price of the Trust units or the exercise price of the rights
occurs. 

C-115

 

	e.
	U.S.
GAAP accounting and reporting standards requires recognition of a liability for the retirement obligations associated with capital assets. These obligations are initially measured
at fair value, which is the discounted future value of the liability. The liability is accreted each period for the change in present value and the accretion expense is charged to income. The fair
value of the liability is capitalized as part of the cost of the related asset and amortized to expense over its useful life. The Trust adopted these U.S. standards effective January 1, 2003
and the cumulative effect adjustment has been charged to net income in the current year. Under current Canadian GAAP and U.S. GAAP prior to January 1, 2003, asset retirement obligations are
accrued using the unit-of-production method based on the undiscounted value of the liability.

	f.
	In
November 2002, the FASB issued Interpretation No.45, "Guarantors' Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of
Others" (FIN 45). FIN 45 elaborates on the disclosures that must be made regarding obligations under certain guarantees issued by the Trust. It also requires that the Trust recognize, at the inception
of a guarantee, a liability for the fair value of the obligations undertaken in issuing the guarantee. The initial recognition and initial measurement provisions are to be applied to guarantees issued
or modified after December 31, 2002. There are no guarantees outstanding at December 31, 2003.

	g.
	The
Trust presents cash flow before changes in non-cash operating working capital as a subtotal in the Consolidated Statement of Cash Flows. This line item would not be presented in a
cash flow statement prepared in accordance with U.S. GAAP. This difference does not result in an adjustment to the financial results as reported under the Canadian GAAP.

	h.
	The
following standards issued by the FASB do not have an impact on the Trust, at the current time:

	•
	FAS
150 "Accounting for Certain Instruments with Characteristics of Both Liabilities and Equity".

	•
	FIN
46 and FIN 46-R "Consolidation of Variable Interest Entities". 

The
Trust will continue to assess the applicability of these standards in the future. 

The
application of US GAAP would have the following effects on net income as reported: 

	 
	 	2003
	 	2002
	 
	Net Income as reported	 	$	12,278	 	$	9,224	 
	Adjustments:	 	 	 	 	 	 	 
	 	Unrealized loss on derivatives	 	 	(3,600	)	 	(4,987	)
	 	Compensation expense	 	 	(1,993	)	 	(550	)
	 	Depletion and depreciation	 	 	(1,065	)	 	—	 
	 	Asset retirement obligation	 	 	2,362	 	 	—	 
	 	 	
	 	
	 
	Net income as adjusted, before cumulative effect of change in accounting principle	 	 	7,982	 	 	3,687	 
	Culmulative effect of change in accounting principle	 	 	(1,484	)	 	—	 
	 	 	
	 	
	 
	Net income as adjusted, after cumulative effect	 	$	6,498	 	$	3,687	 
	 	 	
	 	
	 
	Net income per unit, as adjusted, before cumulative effect	 	 	 	 	 	 	 
	 	Basic	 	$	0.19	 	$	0.17	 
	 	Diluted	 	$	0.18	 	$	0.17	 
	Net income per unit, as adjusted, after cumulative effect	 	 	 	 	 	 	 
	 	Basic	 	$	0.15	 	$	0.17	 
	 	Diluted	 	$	0.15	 	$	0.17	 
	 	 	
	 	
	 

C-116

 

The
application of US GAAP would have the following effects on the consolidated balance sheets as reported: 

	 
	 	As reported
	 	Increase

(Decrease)
	 	U.S. GAAP

	December 31, 2003	 	 	 	 	 	 	 	 	 
	 	Oil and gas derivative instruments	 	$	—	 	$	3,600	 	$	3,600
	 	Capital assets, net	 	 	294,535	 	 	7,757	 	 	302,292
	 	Future Income Taxes	 	 	14,398	 	 	—	 	 	14,398
	 	Accumulated site restoration	 	 	8,076	 	 	7,944	 	 	16,020
	 	Unitholders' Equity	 	$	208,444	 	$	(3,787	)	$	204,657
	December 31, 2002	 	 	 	 	 	 	 	 	 
	 	Oil and gas derivative instruments	 	$	—	 	$	4,987	 	$	4,987
	 	Capital assets, net	 	 	207,930	 	 	—	 	 	207,930
	 	Unitholders' Equity	 	$	125,374	 	$	(4,987	)	$	120,387

15.     Subsequent Event  

On
March 29, 2004, Ultima and Petrofund Energy Trust ("Petrofund") announced that that they had entered into an agreement providing for the combination of Petrofund and Ultima. Under the terms
of the agreement, each Ultima unit will be exchanged for 0.442 of a Petrofund unit on a tax-deferred rollover basis. Ultima unitholders will also receive an aggregate $10 million in the form of a
one-time special distribution, payable prior to closing the transaction. Subject to regulatory approval and the approval of Ultima unitholders by a majority of at least two thirds voting at a meeting
to be held on or about June 4, 2004, the transaction is expected to close on or about June 16, 2004. 

C-117

QuickLinks

EXHIBIT 4.7

REPORT OF INDEPENDENT REGISTERED CHARTERED ACCOUNTANTS

ULTIMA ENERGY TRUST CONSOLIDATED BALANCE SHEET (thousands of dollars)

ULTIMA ENERGY TRUST CONSOLIDATED STATEMENT OF INCOME AND DEFICIT (thousands of dollars except for per unit amounts)

ULTIMA ENERGY TRUST CONSOLIDATED STATEMENT OF CASH FLOWS (thousands of dollars)

ULTIMA ENERGY TRUST NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Years ended December 31, 2003 and 2002 (Tabular amounts in thousands of dollars except for per unit amounts)QuickLinks
 -- Click here to rapidly navigate through this document
  

 
 

EXHIBIT 4.8    
    

         

  

 
 

First Quarter Report Ending March 31, 2004    
    

Highlights  

	(Thousands of dollars except per unit amounts) 
	 	 
	 	 

	Three months ended March 31 
	 	2004
	 	2003

	Production(1)	 	 	 	 	 	 
	 	Oil and liquids (barrels per day)	 	 	7,757	 	 	6,047
	 	Natural gas (mcf per day)	 	 	12,885	 	 	4,967
	 	Oil equivalent (boe per day @ 6:1)	 	 	9,905	 	 	6,877
	 	 	
	 	

	Commodity Prices, before non-hedging derivatives	 	 	 	 	 	 
	 	Oil ($ per barrel)	 	 	41.53	 	 	45.87
	 	Natural gas liquids ($ per barrel)	 	 	36.99	 	 	34.36
	 	Natural gas ($ per mcf)	 	 	7.03	 	 	7.65
	 	Oil equivalent ($/boe)	 	 	41.45	 	 	45.53
	 	 	
	 	

	Financial	 	 	 	 	 	 
	 	Revenue, net(2)	 	$	23,882	 	$	19,850
	 	Cash flow from operations(3)(4)	 	 	18,988	 	 	12,336
	 	Cash flow from operations — per unit basic(3)(4)	 	 	0.33	 	 	0.36
	 	Net income	 	 	1,918	 	 	86
	 	Net income — per unit basic	 	 	0.03	 	 	—
	 	Working capital deficit	 	 	14,489	 	 	8,243
	 	Long-term debt	 	 	75,838	 	 	73,133
	 	Distributions declared	 	 	14,729	 	 	9,192
	 	Distributions declared — per unit	 	$	0.255	 	$	0.270
	 	 	
	 	

	Supplemental (thousands)	 	 	 	 	 	 
	 	Trust units outstanding, end of period	 	 	57,807	 	 	34,189
	 	Weighted average Trust units	 	 	57,721	 	 	33,968
	 	Payout Ratio %(5)	 	 	78	 	 	75
	 	 	
	 	

	(1)
	Includes
working interest and the Weyburn Unit net royalty interest volumes.

	(2)
	Net
of royalties and non-hedging derivative losses.

	(3)
	Before
internalization costs in 2003 ($4.7 million).

	(4)
	These
are non-GAAP measures, which are provided for informative purposes only. See discussion in "Management Discussion and Analysis" on page 2.

	(5)
	Payout
ratio is calculated as the distributions declared divided by the cash flow from operations. 

President's Message and Outlook  

        On March 29, 2004 Ultima and Petrofund Energy Trust ("Petrofund") announced that they had entered into an agreement providing for the combination of
Petrofund and Ultima. 

        Under
the terms of the agreement, each Ultima unit will be exchanged for 0.442 of a Petrofund unit on a tax-deferred rollover basis. Ultima unitholders will also
receive an aggregate $10 million in the form of a one-time special distribution, payable prior to closing the transaction. Subject to regulatory approval and the approval of Ultima
unitholders by a majority of at least two thirds voting at a meeting to be held on or about June 4, 2004, the transaction is expected to close on or about June 16, 2004. 

/s/
S. BRIAN GIENI 

S.
Brian Gieni

President & Chief Executive Officer

May 7, 2004 

1

 

Management's Discussion and Analysis ("MD&A")  

        The following discussion is management's analysis of Ultima's operating and financial results for the quarter and year to date ended March 31, 2004
compared with the comparative period of 2003. This discussion also contains information and opinions concerning the Trust's future outlook based on currently available information at May 7,
2004. This discussion should be read in conjunction with the Trust's audited consolidated financial statements for the years ended December 31, 2003 and 2002 and the annual MD&A as contained in
the Trust's 2003 Annual Report. 

        Management
uses cash flow (before changes in non-cash working capital) to analyze financial performance. Cash flow is calculated as net income for the period plus charges to
income not requiring an outlay of funds less credits to net income not involving a source of funds. Cash flow as presented does not have any standardized meaning prescribed by Canadian Generally
Accepted Accounting Principles ("GAAP") and therefore it may not be comparable with the calculation of similar measures by other entities. Cash flow as presented is not intended to represent operating
cash flows or operating profits for the period nor should it be viewed as an alternative to cash flow from operating activities, net income or other measures of financial performance calculated in
accordance with GAAP. All references to cash flow throughout this report are based on cash flow before changes in non-cash working capital. 

Forward-Looking Information  

        Because forward-looking information relates to future events and conditions, it involves risks and uncertainties that could cause actual results to differ
materially from those contemplated. These risks and uncertainties include commodity price levels; currency-exchange rates; the recoverability of reserves; transportation availability and costs;
operating and other costs; interest rates; and changes in environmental and other legislation and regulations. Please refer to the Trust's Annual Report and Annual Information Form for more details as
to these risks and uncertainties. Management does not intend to update the forward-looking information as events and conditions change. 

Change in Accounting Policies  

        Effective January 1, 2004, the Trust adopted the CICA Handbook Section 3110 "Asset Retirement Obligations" accounting policy in respect of asset
retirement and reclamation obligations associated with the Trust's oil and natural gas properties. This change in accounting policy has been applied retroactively with restatement of prior periods
presented for comparative purposes. 

        Previously
the Trust recognized a provision for future site abandonment and reclamation costs calculated on the unit-of-production method over the life of the oil
and natural gas properties based on total proved reserves and the estimated future liability. 

        As
a result of this change, there was no material effect on net income for the quarter ended March 31, 2004. As at January 1, 2004, capital assets, net of accumulated
depletion and depreciation increased by $7.7 million, the asset retirement obligation increased by $7.95 million. Opening 2004 retained earnings decreased by $187,000 to reflect the
cumulative effect of accretion and depletion expense, net of the cumulative site restoration provision on the asset retirement obligation recorded retroactively to the Trust's inception in 1996. There
was no effect on cash flow as a result of the adoption of the new accounting policy. 

2

 

        Effective
January 1, 2004, the Trust adopted Accounting Guideline ("AcG") 13 "Hedging Relationships". This guideline requires that in order for an economic hedge to be considered
"effective" for accounting purposes and qualify for hedge accounting treatment, specific and detailed criteria must first be met. Should an economic hedge not qualify for hedge accounting treatment
the fair value of the contract at the balance sheet date is recorded as an asset or liability on the balance sheet under Emerging Issues Committee Abstract 128 ("EIC 128"), which became effective upon
implementation of AcG 13. All the Trust's hedges are deemed by management to be effective economic hedges. However, not all the Trust's hedges are deemed to be effective hedges pursuant to AcG 13's
criterion. Specifically the Trust's "three-way" crude oil hedges are not deemed to be effective hedges for accounting purposes as they do not provide by design a direct correlation between
the change in the price of WTI crude oil and the hedged price received. Management has deemed that none of its existing hedges qualify as effective hedges for accounting purposes pursuant to AcG 13,
and has provided $3.9 million as a charge to net income in the period and reported a corresponding obligation on the balance sheet. Changes in the fair value of these non-hedging
derivative instruments will be accounted for in the income statement in future periods. 

Highlights  

        Net income for Q1 2004 was $1.9 million ($0.03 per unit), compared to $0.1 million ($0.00 per unit) in Q1 2003. Net income in 2004 includes a charge
to income of $3.9 million in respect of unrealized non-hedging derivative losses and amortization of the January 1, 2004 net non-hedging derivative liability. 

        Q1
2004 production volumes increased by 44% from the previous quarter which, coupled with strong commodity prices, resulted in cash flow of $19.0 million ($0.33 per unit) in Q1
2004, compared to $12.3 million ($0.36 per unit) in Q1 2003. The 2004 cash flow does not include charges to income from unrealized non-hedging derivative gains and losses, neither
of which affect cash flow from operations. 

        Ultima
declared distributions of $14.7 million ($0.255 per unit) in Q1 2004 with the balance of cash flow from operations being used primarily to fund capital expenditures and
contribute to the reclamation fund. 

Production Volumes, by product  

	First Quarter 
	 	2004
	 	2003

	Crude oil (barrels per day)	 	7,288	 	5,848
	Natural gas liquids (barrels per day)	 	469	 	199
	Natural gas (mcf per day)	 	12,885	 	4,976
	Oil equivalent (boe per day @ 6:1)	 	9,905	 	6,877

Production Volumes, by area  

	Area: boe per day 
	 	 
	 	 

	First Quarter 
	 	2004
	 	2003

	Central Alberta & the Peace River Arch	 	5,708	 	2,904
	Weyburn Unit net royalty interest	 	2,739	 	2,465
	Kindersley	 	1,216	 	1,326
	Other Properties	 	242	 	182
	 	 	
	 	

	 	 	9,905	 	6,877
	 	 	
	 	

3

 

        Production
volumes increased in 2004 over 2003 due to a number of transactions during the period and significant development on the Trust's properties. Production volumes in Q1 2004 were
in line with production volumes for Q4 2003 of 10,214 boe per day. The slight decrease in production volumes from Q4 2003 to Q1 2004 was primarily due to downtime associated with facility
modifications at Spirit River. 

Prices and Risk Management  

	First Quarter 
	 	2004
	 	2003

	Crude oil, before non-hedging derivative losses ($ per bbl)	 	41.53	 	45.87
	Crude oil, net of non-hedging derivative losses ($ per bbl)	 	37.44	 	40.20
	Natural gas liquids ($ per bbl)	 	36.99	 	34.36
	Natural gas, before of non-hedging derivative losses ($ per mcf)	 	7.03	 	7.65
	Natural gas, net of non-hedging derivative losses ($ per mcf)	 	6.87	 	6.77
	Price per boe, before non-hedging derivative losses ($ per boe)	 	41.45	 	45.53
	Price per boe, net of non-hedging derivative losses ($ per boe)	 	38.23	 	40.07

        For
Q1 2004 realized cash non-hedging derivative losses were $3.22 per boe, compared to $5.46 per boe in 2003. Not included in the 2004 amounts shown above are unrealized
non-hedging derivative losses and amortization of the opening liability totaling $3.9 million, as this amount does not affect cash flow. 

        Oil
prices received by Ultima were lower in Q1 2004 than in Q1 2003 primarily due to the appreciation of the Canadian dollar over the US dollar from Q1 2003 to Q1 2004 of approximately
16%. 

        The
crude oil non-hedging derivative instruments in place for 2004 are provided below. Ultima has no outstanding natural gas non-hedging derivative instruments as
at April 1, 2004. 

Crude Oil Non-hedge Derivative Instruments ($US/bbl except as indicated)  

	Daily Quantity 
	 	Fixed Price
	 	Sold Call
	 	Purchased Put
	 	Sold Put
	 	Term

	1,000 bbls ($CDN/bbl)	 	$	35.00	 	 	 	 	 	 	 	 	 	 	Calendar 2004
	800 bbls	 	 	 	 	$	27.50	 	$	24.00	 	$	20.00	 	Calendar 2004
	700 bbls(1)	 	 	 	 	$	30.00	 	$	25.00	 	$	21.00	 	Calendar 2004
	1,000 bbls	 	$	27.00	 	 	 	 	 	 	 	 	 	 	Jan. 1 to June 30, 2004

	(1)
	For
clarity and illustration: 

	If WTI Price is ($US/bbl) 
	 	Ultima receives ($US/bbl)

	Greater than $30	 	$30 per bbl
	Between $25 per bbl and $30 per bbl	 	Actual price
	Between $21 per bbl and $25 per bbl	 	$25 per bbl
	Less than $21 per bbl	 	Actual price plus $4.50 per bbl

Revenue  

	($ thousands) 
	 	 
	 	 
	 
	First Quarter 
	 	2004
	 	2003
	 
	Gross revenue(1)	 	30,577	 	24,802	 
	Royalties	 	(6,695	)	(4,952	)
	 	 	
	 	
	 
	Revenue, net of royalties	 	23,882	 	19,850	 
	 	 	
	 	
	 

	(1)
	Net
of realized and unrealized non-hedging derivative losses 

4

 

Oil and Natural Gas Gross Revenue Variance Analysis  

	($ thousands) 
	 	 
	 	 

	First Quarter 
	 	2004
	 	2003

	Prior period ending March 31	 	24,802	 	8,722
	Volume variance	 	10,860	 	9,489
	Price variance	 	(5,085	)	6,591
	Current period ending March 31	 	30,577	 	24,802

        Higher
volumes in Q1 2004 more than offset lower realized prices resulting in higher gross revenues in Q1 2004 compared to Q1 2003. 

Royalties  

	($ thousands) 
	 	 
	 	 

	First Quarter 
	 	2004
	 	2003

	Royalty expense	 	6,695	 	4,952
	Royalties as % of gross revenue	 	 	 	 
	 	 — excluding non-hedging derivatives losses	 	17.9	 	17.6

        Royalties
as a percentage of revenue have remained largely unchanged since Q1 2003. 

Oil and Natural Gas Operating Expense  

	($ thousands) 
	 	 
	 	 

	First Quarter 
	 	2004
	 	2003

	Operating costs	 	6,623	 	5,500
	$'s per boe	 	7.35	 	8.89

        On
a per boe basis operating expenses have decreased by 17% in Q1 2004 from Q1 2003. Operating costs per boe have decreased because the properties acquired and developed by the Trust
have had lower operating cost structures. 

General and Administrative Expense  

        General and administrative ("G&A") expense for Q1 2004 was $1.8 million ($1.97 per boe), compared to $879,000 ($1.44 per boe) in Q1 2003. G&A was higher in
2004 due to incremental costs associated with the proposed merger and the higher staff levels in 2004. The Trust did not capitalize any G&A in Q1 2004. 

Management Fee  

	($ thousands) 
	 	 
	 	 

	First Quarter 
	 	2004
	 	2003

	Management fee	 	—	 	487
	On a per unit basis	 	—	 	0.01

        Due
to the internalization of the management contract on March 26, 2003, management fees were eliminated. 

Interest Expense  

        Interest expense for Q1 2004 totaled $0.5 million versus $0.6 million in the corresponding period in 2003. The decrease in interest expense is a
result of the decreased bank debt level in Q1 2004 compared to Q1 2003. Interest attributable to the deferred capital charge is capitalized pursuant to the terms of the Weyburn Unit NRI agreement. 

5

 

Unit Based Compensation Expense  

        The Trust recorded $765,000 as a charge to income for Q1 2004, and a corresponding increase to Contributed Surplus. The charge is based on the rights issued to
employees since January 1, 2003. The Trust has also provided pro-forma disclosure in respect of the unit based compensation expense that would have been incurred on rights issued in
2002. 

        There
were approximately 1.96 million rights issued and outstanding at March 31, 2004 pursuant to the trust unit rights incentive plan. These rights had an average adjusted
exercise price of $4.31 per unit after reflecting the available right exercise price reduction. 

Operating Netback  

	($ per boe) 
	 	 
	 	 
	 
	First Quarter 
	 	2004
	 	2003
	 
	Oil and natural gas revenues, net of non-hedging derivatives	 	$	37.11	 	$	40.07	 
	Royalties	 	 	(7.42	)	 	(8.00	)
	Oil and natural gas operating expense	 	 	(7.35	)	 	(8.89	)
	 	 	
	 	
	 
	Operating netback	 	$	22.34	 	$	23.18	 
	 	 	
	 	
	 

        The
operating netback in Q1 2004 decreased from Q1 2003 due to the lower realized commodity prices more than offsetting lower operating costs and royalties on a per boe basis. 

Income Tax  

        Ultima Trust units are acceptable investments for purposes of Canadian Income Tax exempt plans such as RRSPs, DPSPs, and RRIFs. 

        As
at March 31, 2004 a future income tax liability of $14.2 million was recorded, relating to one of the Trust's corporate subsidiaries. The future tax liability decreased
from year-end 2003 by $198,000 due to a recovery of future income taxes being recorded. In management's opinion, the future income tax liability will not be required to be paid by the
Trust because royalties paid by the corporate subsidiary to the Trust and future distributions paid to Unitholders will eliminate the liability. 

        Current
taxes are comprised of capital taxes and a recovery of future income taxes. Capital taxes were $8,000 in Q1 2004 compared to nil in 2003. Capital taxes relates to a corporate
subsidiary, which resulted from the acquisition of Trioco Resources Inc. in June 2003. 

        For
2004, it is anticipated that distributions paid to Unitholders will have a taxable component and a return of capital component. The taxability of distributions is sensitive to a
number of factors, including commodity price volatility; the higher the commodity prices, the more likely the taxable component will be higher. 

Capital Costs  

        Capital costs in Q1 2004 totaled $9.9 million, compared to $5.8 million in Q1 2003. The Q1 2004 capital investment of the Trust is summarized below: 

	 
	 	($ thousands)

	Acquisitions, net of dispositions	 	$	137
	Asset retirement obligation liabilities incurred	 	 	127
	Development drilling and facilities	 	 	4,706
	Weyburn Unit miscible flood expansion and other	 	 	4,945
	 	 	

	Total	 	$	9,915
	 	 	

6

 

        For
the balance of 2004 prior to the proposed merger with Petrofund, the Trust plans to drill and tie-in four wells at Spirit River. Capital investment at Weyburn will also
be ongoing as the planned 2004 expansion of the carbon dioxide miscible flood is continued. The Trust plans to fund these capital costs utilizing cash flow, the deferred capital obligation and a
portion of the available bank credit facility. 

Reclamation Fund  

        Upon inception, Ultima established a reclamation fund into which cash is contributed at a rate of $0.20 per boe of production. For Q1 2004, a total of $180,000
was contributed to the fund, and at quarter end the balance was $1.3 million. 

Depletion, Depreciation and Asset Retirement Obligation  

        The 2004 depletion, depreciation and accretion ("DD&A") rate was $13.81 per boe in Q1 2004 compared to $12.17 per boe in Q1 2003. Included in DD&A is accretion
expense associated with the Asset Retirement Obligation ("ARO") of $260,000 for Q1 2004 (Q1 2003 — $203,000). The higher DD&A rate in 2004 is due to
increased capital costs and production levels. The retroactive application of the new accounting policy for asset retirement obligations and the change to the Full Cost method of accounting for
capital assets at year-end 2003 required restatement of the comparative period, which resulted in an increase in the Q1 2003 DD&A rate to $12.17 per boe from the previously reported rate
of $9.75 per boe. 

        Capital
assets of $11.3 million associated with the Weyburn Unit NRI were excluded from the DD&A calculation as this amount relates to unproven property. Included in the DD&A
calculation are future capital costs of $95.4 million, which are primarily associated with development of the Weyburn Unit miscible flood. 

Cash Distributions  

        Ultima declared cash distributions to the Unitholders in Q1 2004 in the amount of $14.7 million ($0.255 per unit) compared to $9.2 million ($0.27
per unit) in Q1 2003. The decrease in distributions per unit reflects the lower average commodity prices received by the Trust in Q1 2004. 

Balance Sheet  

Assets  

        As at March 31, 2004, total assets were $336.8 million consisting of net capital assets of $300 million, current assets of
$18.8 million, goodwill of $16.7 million and a reclamation fund of $1.3 million. Net capital assets have increased from year-end 2003 primarily due to the adoption of
the ARO accounting policy and capital expenditures in Q1 2004 offsetting DD&A. 

Liabilities and Unitholders' Equity  

        Liabilities totaled $139.8 million as at March 31, 2004, consisting of a $45.5 million long-term bank debt, $33.3 million
in current liabilities (including an unrealized non-hedging derivative liability of $6.6 million), a deferred capital obligation of $30.3 million, a future income tax
liability of $14.2 million and an asset retirement obligation of $16.4 million. 

        The
authorized capital of the Trust consists of an unlimited number of trust units. Unitholders' equity was $197 million at March 31, 2004, compared to
$208.3 million at December 31, 2003. 

7

 

        Provided
below is a schedule of the change in trust units outstanding for Q1 2004. 

	 
	 	Number of Trust Units
	 	($ thousands)

	Balance, as at January 1, 2004	 	57,624,975	 	$	324,821
	Issued on exercise of rights	 	147,996	 	 	928
	Issued on retention obligation	 	34,386	 	 	—
	 	 	
	 	

	Balance, as at March 31, 2004	 	57,807,357	 	$	325,749
	 	 	
	 	

Cash flow From Operations  

        Cash flow on a per unit basis for Q1 2004 was $0.33 per unit, compared to $0.36 per unit in Q1 2003. Higher production volumes offset by lower realized average
commodity prices and lower financial leverage were the primary drivers of the decrease in cash flow per unit. 

Liquidity and Capital Resources  

	($ thousands) 
	 	March 31, 2004
	 	December 31, 2003

	As at 

	Long term bank debt	 	45,507	 	45,007
	Working capital deficit	 	14,489	 	8,243
	 	 	
	 	

	Net bank debt	 	59,996	 	53,250
	Deferred capital obligation	 	30,331	 	28,126
	Market value of Trust Units(1)(2)	 	440,492	 	359,420
	 	 	
	 	

	Total capitalization	 	530,819	 	440,796
	 	 	
	 	

	Net bank debt as a % of total capitalization	 	11%	 	12%
	Total debt as a % of total capitalization	 	17%	 	19%
	 	 	
	 	

	(1)
	The
number of trust units issued at March 31, 2004 was 57.8 million and the closing price was $7.62 per unit.

	(2)
	Total
capitalization as represented in this table includes the market value of the Trust's equity, and does not represent the historical cost of the Unitholders' equity of the Trust.
Therefore total capitalization may not be comparable with the calculation of similar measures by other entities. A GAAP measure would be using the book value of Unitholders' Equity, which at
March 31, 2004 was $197 million, and total capitalization would therefore be $287.4 million. Management has presented debt as a function of total capitalization because management
uses this measure to benchmark the financial position of the Trust. 

8

  

 
 

CONSOLIDATED BALANCE SHEET    
    
    (unaudited)    
    
    (Thousands of dollars)    
    

	As at 
	 	March 31, 2004
	 	December 31, 2003
	 
	 
	 	 
	 	(restated — see Note 2)
 
	 
	Assets	 	 	 	 	 	 	 
	Current assets	 	 	 	 	 	 	 
	 	Accounts receivable	 	$	14,741	 	$	12,442	 
	 	Deferred non-hedging derivative loss (note 4)	 	 	2,542	 	 	—	 
	 	Prepaid expenses	 	 	1,533	 	 	1,803	 
	 	 	
	 	
	 
	 	 	 	18,816	 	 	14,245	 
	Reclamation fund	 	 	1,257	 	 	1,077	 
	Goodwill	 	 	16,682	 	 	16,682	 
	Capital assets, net	 	 	300,023	 	 	302,292	 
	 	 	
	 	
	 
	Total Assets	 	$	336,778	 	$	334,296	 
	 	 	
	 	
	 
	
Liabilities and Unitholders' Equity	
 	
 	

 	
 	
 	

 	
 
	
Liabilities	
 	
 	

 	
 	
 	

 	
 
	Current Liabilities	 	 	 	 	 	 	 
	 	 	Bank indebtedness	 	$	4,565	 	$	977	 
	 	 	Cash distribution payable	 	 	4,914	 	 	4,898	 
	 	 	Oil and gas derivative instruments (note 4)	 	 	6,602	 	 	—	 
	 	 	Accounts payable	 	 	17,224	 	 	16,613	 
	 	 	
	 	
	 
	 	 	 	33,305	 	 	22,488	 
	Asset retirement obligation (note 5)	 	 	16,408	 	 	16,020	 
	Future income taxes	 	 	14,200	 	 	14,398	 
	Long-term bank debt (note 6)	 	 	45,507	 	 	45,007	 
	Deferred capital obligation	 	 	30,331	 	 	28,126	 
	 	 	
	 	
	 
	 	 	 	139,751	 	 	126,039	 
	 	 	
	 	
	 
	
Unitholders' Equity	
 	
 	

 	
 	
 	

 	
 
	Unitholders' capital (note 7)	 	 	325,749	 	 	324,821	 
	Contributed surplus (note 8)	 	 	912	 	 	260	 
	Deficit	 	 	(3,213	)	 	(5,131	)
	Accumulated cash distributions	 	 	(126,421	)	 	(111,693	)
	 	 	
	 	
	 
	 	 	 	197,027	 	 	208,257	 
	 	 	
	 	
	 
	Total Liabilities and Unitholders' Equity	 	$	336,778	 	$	334,296	 
	 	 	
	 	
	 

9

 
 
 

CONSOLIDATED STATEMENTS OF INCOME AND DEFICIT    
    
    (unaudited)    
    
    (Thousands of dollars except per unit amounts)    
    

	Three months ended March 31 
	 	2004
	 	2003
	 
	 
	 	 
	 	(restated — see Note 2)
 
	 
	Revenue	 	 	 	 	 	 	 
	Oil and natural gas	 	$	36,176	 	$	24,802	 
	Royalties	 	 	(6,695	)	 	(4,952	)
	Realized and unrealized non-hedging derivative loss	 	 	(5,599	)	 	—	 
	 	 	
	 	
	 
	 	 	 	23,882	 	 	19,850	 
	 	 	
	 	
	 
	
Expenses	
 	
 	

 	
 	
 	

 	
 
	Oil and natural gas operating	 	 	6,623	 	 	5,500	 
	General and administrative	 	 	1,778	 	 	879	 
	Unit based compensation	 	 	765	 	 	—	 
	Management fee	 	 	—	 	 	487	 
	Internalization of management	 	 	—	 	 	4,716	 
	Interest on bank loan	 	 	545	 	 	648	 
	Depletion, depreciation and accretion	 	 	12,443	 	 	7,534	 
	 	 	
	 	
	 
	 	 	 	22,154	 	 	19,764	 
	 	 	
	 	
	 
	Net income before income taxes	 	 	1,728	 	 	86	 
	Future income tax recovery	 	 	(198	)	 	—	 
	Capital taxes	 	 	8	 	 	—	 
	 	 	
	 	
	 
	Net income	 	 	1,918	 	 	86	 
	Deficit, beginning of period (see Note 2a)	 	 	(5,131	)	 	(18,706	)
	 	 	
	 	
	 
	Deficit, end of period	 	$	(3,213	)	$	(18,620	)
	 	 	
	 	
	 
	Net income per unit	 	 	 	 	 	 	 
	 	Basic	 	$	0.03	 	$	0.00	 
	 	Diluted	 	$	0.03	 	$	0.00	 

        The
basic and diluted per unit information is calculated by using the following weighted average units outstanding. 

	Three months ended March 31 
	 	2004
	 	2003

	Basic	 	57,720,973	 	33,967,784
	Diluted	 	58,541,361	 	34,294,118

10

 
 
 

CONSOLIDATED STATEMENT OF CASH FLOWS    
    
    (unaudited)    
    
    (Thousands of dollars)    
    

	Three months ended March 31 
	 	2004
	 	2003
	 
	 
	 	 
	 	(restated — see Note 2)
 
	 
	Operating Activities	 	 	 	 	 	 	 
	Net Income	 	$	1,918	 	$	86	 
	Internalization of Management	 	 	—	 	 	4,716	 
	Unrealized non-hedging derivative loss	 	 	2,875	 	 	—	 
	Unit based compensation	 	 	765	 	 	—	 
	Amortization of initial hedge liability	 	 	1,185	 	 	—	 
	Future income tax recovery	 	 	(198	)	 	—	 
	Depletion, depreciation and accretion	 	 	12,443	 	 	7,534	 
	 	 	
	 	
	 
	Funds from operations	 	 	18,988	 	 	12,336	 
	Changes in non-cash working capital	 	 	(4,114	)	 	(1,000	)
	 	 	
	 	
	 
	 	 	 	14,874	 	 	11,336	 
	 	 	
	 	
	 
	
Financing Activities	
 	
 	

 	
 	
 	

 	
 
	Issuance of Trust units	 	 	928	 	 	605	 
	Draw of bank loan	 	 	500	 	 	1,942	 
	Cash distributions paid to Unitholders	 	 	(14,713	)	 	(8,825	)
	 	 	
	 	
	 
	 	 	 	(13,285	)	 	(6,278	)
	 	 	
	 	
	 
	
Investing Activities	
 	
 	

 	
 	
 	

 	
 
	Capital asset additions	 	 	(4,997	)	 	(2,070	)
	Internalization of Management	 	 	—	 	 	(3,666	)
	Property acquisitions, net	 	 	—	 	 	(487	)
	Reclamation fund contributions	 	 	(180	)	 	(124	)
	 	 	
	 	
	 
	 	 	 	(5,177	)	 	(6,347	)
	 	 	
	 	
	 
	Increase in bank indebtedness	 	 	(3,588	)	 	(1,289	)
	Bank indebtedness, beginning of period	 	 	(977	)	 	(19	)
	 	 	
	 	
	 
	Bank indebtedness, end of period	 	$	(4,565	)	$	(1,308	)
	 	 	
	 	
	 
	
Supplemental Information	
 	
 	

 	
 	
 	

 	
 
	 	Income taxes paid	 	$	—	 	$	—	 
	 	Interest paid	 	$	545	 	$	648	 

11

  

 
 

ULTIMA ENERGY TRUST    
    
    NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS    
    

1.     Accounting Policies  

The
accompanying unaudited interim consolidated financial statements of Ultima Energy Trust, and its subsidiaries (collectively, "Ultima" or the "Trust") have been prepared in accordance with Canadian
generally accepted accounting principles, following the same accounting policies and methods of computation as the consolidated financial statements of the Trust as at December 31, 2003, except
as described in Note 2. The note disclosure in the annual financial statements provides disclosure additional to that required for interim financial statements. Accordingly, these interim
financial statements should be read in conjunction with the financial statements included in the Trust's 2003 annual report. 

2.     Change in Accounting Policies  

        a.     Asset Retirement Obligations  

The
Trust retroactively adopted the Canadian Institute of Chartered Accountants ("CICA") Handbook Section 3110 "Asset Retirement Obligations". This section replaces the previous standard for
the provision for site restoration and abandonment and is effective for fiscal years beginning on or after January 1, 2004. The Trust recognizes the fair value of an Asset Retirement Obligation
("ARO") in the period in which it is incurred when a reasonable estimate of fair value can be made. The fair value of the estimated ARO is recorded as a long-term liability with a
corresponding increase in capital assets. The capitalized amount is depleted over the life of the asset using the unit-of-production method. The liability is increased each
reporting period due to accretion being charged to net income each period. Any future revisions to the estimated timing of obligations or in the undiscounted cost would also affect the ARO. Actual
asset retirement costs incurred are charged to the ARO to the extent of the liability recorded. Any difference between the actual asset retirement cost and the recorded ARO liability is recognized as
a gain or loss in net income at that time. 

The
retroactive application of the new accounting policy has resulted in the restatement of prior periods. The effect of this change in accounting policy on net income for the three months ended
March 31, 2003 and 2004 was immaterial. The effect of this change in accounting policy on the December 31, 2003 balance sheet amounts as previously presented is as follows: 

	($ thousands) 
	 	As reported
	 	Adjustment
	 	As restated
	 
	Capital Assets, net	 	294,535	 	7,757	 	302,292	 
	Asset Retirement Obligation	 	8,076	 	7,944	 	16,020	 
	Deficit as at December 31, 2003	 	(4,944	)	(187	)	(5,131	)
	Deficit as at January 1, 2003	 	(17,222	)	(1,484	)	(18,706	)

There
was no effect on cash flow as a result of adopting this policy (see Note 5). 

        b.     Non-Hedging Derivative Instruments  

The
Trust adopted CICA Accounting Guideline ("AcG") 13 "Hedging Relationships". This guideline requires that in order for an economic hedge to be considered "effective" for accounting purposes and
qualify for hedge accounting treatment, specific and detailed criteria must first be met. Should a hedge not qualify for hedge accounting treatment the fair value of the hedge at the balance sheet
date is recorded as an asset or liability on the balance sheet, and a corresponding charge to net income. From time to time the Trust enters into various arrangements to hedge against possible
fluctuations in commodity prices, interest rates and exchange rates. Gains or losses from these arrangements, which in management's view constitute effective economic hedges, are reported as
adjustments to the related revenue or expense accounts as they are settled. Management has elected to not follow hedge accounting and to account for unrealized gains and losses at a reporting date in
accordance with Emerging Issues Committee ("EIC") 128, "Accounting for Trading, Speculative or Non-Hedging Derivative Financial Instruments." These non-hedging derivative
instruments will be recorded on the balance sheet at fair value and changes in fair value will be recognized in income in the period in which the change occurs. 

The
new accounting policy has been applied prospectively. Effective January 1, 2004, Ultima recorded the fair value of the non-hedging derivative loss pursuant to crude oil
contracts as a liability of $3.7 million, and a deferred loss of $3.7 million. Ultima also recorded the fair value of the non-hedging derivative gain pursuant to natural gas
contracts as an asset of $175,000, and a deferred gain of $175,000. Deferred gains and losses are recognized in net income over the life of the derivative contracts. 

12

 

3.     Proposed Merger  

On
March 29, 2004, Ultima and Petrofund Energy Trust ("Petrofund") announced that they had entered into an agreement providing for the combination of Petrofund and Ultima. Under the terms of
the agreement, each Ultima unit will be exchanged for 0.442 of a Petrofund unit. Ultima unitholders will also receive an aggregate $10 million in the form of a one-time
special distribution, payable prior to closing the transaction. Subject to regulatory approval and the approval of Ultima unitholders by a majority of at least two thirds voting at a meeting to be
held on or about June 4, 2004, the transaction is expected to close on or about June 16, 2004. 

4.     Oil and Gas Derivative Liability  

	 
	 	($ thousands)

	Oil and Gas Derivative Liability, January 1, 2004	 	3,727
	Change in value of mark-to-market fair value	 	2,875
	 	 	

	Oil and Gas Derivative Liability, March 31, 2004	 	6,602
	 	 	

	 

	Deferred Non-Hedging Derivative Loss 
	 	($ thousands)
	 
	Deferred Non-Hedging Derivative Loss, January 1, 2004	 	3,727	 
	Amortization of opening loss	 	(1,185	)
	 	 	
	 
	Deferred Non-Hedging Derivative Loss, March 31, 2004	 	2,542	 
	 	 	
	 

Ultima
also recorded a deferred non-hedging derivative gain of $175,000 as at January 1, 2004 in respect of Ultima's natural gas derivative contracts. This gain was amortized and
reflected in net income during the quarter as Ultima's natural gas hedging contracts expired on March 31, 2004. 

5.     Asset Retirement Obligation  

Management
has estimated the total future asset retirement obligation based on the Trust's net ownership interest in all wells and facilities. This includes costs to abandon, reclaim and remove the
wells and facilities and the estimated time period over which these costs will be incurred in the future. 

The
following table is a summary of the asset retirement obligation. 

	Asset Retirement Obligation 
	 	($ thousands)

	Asset Retirement Obligation, January 1, 2004	 	16,020
	Liabilities incurred	 	128
	Liabilities settled	 	—
	Accretion expense	 	260
	 	 	

	Asset Retirement Obligation, March 31, 2004	 	16,408
	 	 	

6.     Bank loan  

Pursuant
to a loan agreement dated June 26, 2003 between Ventures Trust and a syndicate comprised of the Alberta Treasury Branches and the National Bank of Canada ("the Syndicate"), Ventures
Trust has a revolving term production loan facility ("the facility") with a maximum limit of $95,000,000, including a $10,000,000 operating line of credit. 

13

 

The
facility has a 364-day extendable revolving period and a two year term. Borrowings under the facility bear interest from bank prime plus 0.125% to bank prime plus 1.875%, dependent
upon the level of trailing net debt to operating cash flow. The borrowings are secured by a $150,000,000 floating charge debenture over all the assets and undertakings of Ventures Trust,
Energy Inc., the Manager, the Corporation and Acquisitions Corp. The credit facilities are subject to a semi annual review on May 31 and November 1 each year and upon review the
Syndicate determines if it will extend the revolving period for another six months. In the event that the Syndicate does not extend the facility for another six months, there is a two year payment
period with no payments being required for the first year. Due to the merger contemplated in Note 3, the Syndicate has agreed to review the facility at or prior to July 19, 2004, at
which time, should the proposed transaction not have closed, the Syndicate will determine if it will extend the revolving period for another six months. 

Pursuant
to a subordination agreement entered into on June 26, 2003, the Syndicate has been provided with security over all of the assets of Ventures Trust, Energy Inc., the Manager, the
Corporation and Acquisitions Corp. in priority to the royalty payable to the Trust by each of Ventures Trust and Energy Inc. The facility is the legal obligation of Ventures Trust. Principal
and interest payments are deducted in the calculation of cash available for distribution to unitholders. In the event that the oil and natural gas properties of Ventures Trust and Energy Inc.
do not generate sufficient income to discharge the obligation, the unitholders of the Trust will have no direct liability. 

7.     Unitholders' Capital  

The
authorized capital of the Trust consists of an unlimited number of Trust units, with the balance at March 31, 2004 summarized below. 

	Trust Units 
	 	# of Units
	 	($ thousands)

	Balance at December 31, 2003	 	57,624,975	 	324,821
	Issued pursuant to trust unit rights plan	 	147,996	 	928
	Issued pursuant to retention obligation	 	34,386	 	—
	 	 	
	 	

	Balance at March 31, 2004	 	57,807,357	 	325,749
	 	 	
	 	

8.     Unit Based Compensation Plan  

A
summary of the rights issued, exercised, cancelled and outstanding pursuant to the trust unit rights plan ("the Plan") for the three months ending March 31, 2004 is provided below: 

	 
	 	Number of Rights
	 	Weighted Average

Exercise Price
	 
	Balance beginning of year	 	2,007,669	 	$	4.40	 
	Granted	 	100,000	 	$	6.25	 
	Exercised	 	147,996	 	$	5.07	 
	Cancelled	 	—	 	 	—	 
	 	 	
	 	
	 
	Balance before reduction in exercise price	 	1,959,673	 	$	4.44	 
	Reduction in exercise price	 	—	 	$	(0.13	)
	 	 	
	 	
	 
	Balance as at March 31, 2004	 	1,959,673	 	$	4.31	 
	 	 	
	 	
	 

The
exercise price of rights granted under the Plan may be reduced in future periods in accordance with the terms of the Plan. The amount of the reduction cannot be reasonably determined as it is
dependent upon a number of factors including, but not limited to, future prices received on the sale of oil and natural gas, future production of oil and natural gas, and determination of the amounts
to be withheld from future distributions to fund capital expenditures. Therefore, it is not possible to determine the fair value of the rights granted under the plan. 

14

 

The
Trust has recorded compensation expense and a corresponding increase in contributed surplus of $765,000 based on the March 31, 2004 trust unit trading price of $7.62 per unit in respect of
rights awarded since January 1, 2003. 

The
Trust has elected to continue to measure compensation cost associated with new rights issued on or after January 1, 2002 but prior to January 1, 2003 based on the intrinsic value of
the award at the date of the grant and recognize that cost over the vesting period. As the exercise price of the rights granted approximates the market price of the trust units at the time of the
grant date, no compensation cost has been provided in the statement of income. 

As
it is not possible to determine the fair value of rights granted under the Plan, compensation cost for pro forma disclosure purposes has been determined based on the excess of the unit price
over the exercise price at the date of the financial statements. Provided below is the pro forma net earnings and net earnings per trust unit for the three months ended March 31, 2003
and 2002. 

	(Thousands of dollars)

Three months ended March 31 
	 	2004
	 	2003

	Net earnings:	 	 	 	 
	 	As reported	 	1,918	 	86
	 	Pro forma	 	1,549	 	51
	Net earnings per share	 	 	 	 
	 	Basic	 	 	 	 
	 	 	As reported	 	0.03	 	0.00
	 	 	Pro forma	 	0.03	 	0.00
	 	Diluted	 	 	 	 
	 	 	As reported	 	0.03	 	0.00
	 	 	Pro forma	 	0.03	 	0.00

Directors  

Marshall M. Williams  

Chairman of the Board  

Mr. Williams
is a former Chairman of Alberta Treasury Branches. Previously Mr. Williams has also served as Chairman of the Board of TransAlta Corporation, and as a Director of
Stelco Inc. and Sun Life Assurance Company. 

Arthur E. Dumont  

Director, Chairman of the Governance Committee  

Mr. Dumont
is Chairman, President and C.E.O. of Technicoil Corporation. Previously, he worked in senior roles at CenAlta Energy Services, Western Rock Bit Company, Precision Drilling, Kenting
Energy Services and Trimac Limited. 

S. Brian Gieni  

Director  

President
and Chief Executive Officer of Ultima Management Inc., Ultima Acquisitions Corp., Ultima Venture Trust and Ultima Venture Corp. Mr. Gieni is a finance and accounting
professional with 30 years of experience in senior management capacities with major energy and service companies in the oil and gas industry. 

15

 

John M. Gunn  

Director, Chairman of the Reserves Committee  

Mr. Gunn
is a professional engineer who is currently President and C.E.O. of Tango Resources Inc. Mr. Gunn co-founded and was President, CEO, and Director of Ballistic
Energy Corporation and also co-founded and was a Chairman and Director of Renata Resources Inc. 

Henry R. Lawrie  

Director  

Chairman of the Audit Committee  

Mr. Lawrie
is an advisor to the Ross Smith Energy Group and a Director of a number of public companies. He previously served as Chief Accountant of the Alberta Securities Commission and was for
many years a senior partner with Price Waterhouse in Calgary, Toronto and Dallas. 

Gary Lee  

Director, Chairman of the Compensation Committee  

Mr. Lee
is a lawyer with over 20 years of experience in oil and gas related matters and is a partner with Northwest Capital Inc. 

David A. Tuer  

Director  

Mr. Tuer
is President and CEO of Hawker Resources Inc. He also currently acts as Chairman of the Board for the Calgary Health Region as well as serves on the Board for Canadian Natural
Resources Limited and as Chairman of AltaLink Management Ltd. He was previously President and CEO of PanCanadian Petroleum Limited and Assistant Deputy Minister of Energy (Alberta). 

Officers  

S. Brian Gieni  

President and Chief Executive Officer  

Ken G. Pinsky  

Chief Financial Officer  

Mr. Pinsky
is responsible for all financial and accounting matters of the Trust. He is a Chartered Accountant and a Chartered Financial Analyst with more than 16 years experience in oil
and gas acquisitions and divestitures, business planning, restructuring, financial accounting and reporting. 

Michael P. Wihak  

Chief Operating Officer  

Mr. Wihak
is responsible for all engineering and operations matters of the Trust. He is a professional engineer with a Masters Degree in business administration and 17 years of
experience in managing and exploiting producing properties, oil and gas acquisitions and divestitures, and corporate planning. 

Head Office  

1000,
350 - 7th Avenue S.W.

Calgary, Alberta Canada T2P 3N9

Telephone: (403) 264-5709

Toll Free: 1-888-840-1133

Fax: (403) 264-6103

E-mail: ultima@ultimatrust.com

Web: www.ultimatrust.com 

Investor Relations  

Toll
Free: 1-877-2ULTIMA (1-877-285-8462)

Fax: (403) 266-6027

Email: investor@ultimatrust.com 

16

 

Related Entities  

Ultima
Acquisitions Corp.

Ultima Ventures Trust

Ultima Ventures Corp.

Ultima Management Inc.

Ultima Energy Inc. 

Auditors  

Deloitte &
Touche LLP

Chartered Accountants

Calgary, Alberta 

Legal Counsel  

Bennett
Jones LLP

Calgary, Alberta 

Independent Engineering Consultants  

McDaniel &
Associates Consultants Ltd.

Calgary, Alberta 

Gilbert
Laustsen Jung Associates Ltd.

Calgary, Alberta 

Trustee / Transfer Agent  

Computershare
Trust Company of Canada

Calgary, Alberta 

Bankers  

The
Alberta Treasury Branches

Calgary, Alberta 

National
Bank of Canada

Calgary, Alberta 

Stock Exchange Listing  

The
Toronto Stock Exchange

Trust Units: UET.UN 

17

QuickLinks

EXHIBIT 4.8

First Quarter Report Ending March 31, 2004

CONSOLIDATED BALANCE SHEET (unaudited) (Thousands of dollars)

CONSOLIDATED STATEMENTS OF INCOME AND DEFICIT (unaudited) (Thousands of dollars except per unit amounts)

CONSOLIDATED STATEMENT OF CASH FLOWS (unaudited) (Thousands of dollars)

ULTIMA ENERGY TRUST NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Source: [{"source": "alea-institute/alea-institute/kl3m-data-edgar-agreements/train-00085-of-00352.parquet"}, [{"source": "alea-institute/alea-institute/kl3m-data-edgar-agreements/train-00085-of-00352.parquet"}]]