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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 STATEMENTSQuickLinks
 -- Click here to rapidly navigate through this document

 
 

EXHIBIT 4.9    
    

 
 

MATERIAL CHANGE REPORT    
    

Item 1.    Reporting Issuer:  

Petrofund
Energy Trust (the "Trust" or "Petrofund")

600, 444 - 7th Avenue SW

Calgary, Alberta

T2P 0X8 

Item 2.    Date of Material Change:  

November 16,
2005 

Item 3.    News Release:  

A
Press Release reporting the material change was issued by the Trust on November 16, 2005, through CCN Matthews. 

Item 4.    Summary of Material Change:  

Petrofund
announced that it had entered into an agreement to acquire all of the outstanding shares of Kaiser Energy Ltd. ("Kaiser"), a private company (the "Acquisition"), for
consideration of Cdn. $485 million before adjustments. Petrofund intends to fund the Acquisition with proceeds from a bought deal equity financing in the amount of Cdn. $225 million
(which was increased to Cdn. $250 million on November 24, 2005 as a result of an option granted to the underwriters of the equity financing) and debt drawn from the Trust's credit
facilities which are to be expanded in conjunction with the Acquisition. The Acquisition is expected to close on or about December 15, 2005, with an adjustment date of December 1, 2005. 

Item 5.    Full Description of Material Change:  

Petrofund
announced that it had entered into an agreement (the "Purchase Agreement") to acquire all of the outstanding shares of Kaiser, a private company, from Kaiser-Francis Oil Company of
Canada (the "Vendor") for consideration of Cdn. $485 million before adjustments. Petrofund intends to fund the Acquisition with proceeds from a bought deal equity financing in the amount
of Cdn. $225 million (which was increased to Cdn. $250 million on November 24, 2005 as a result of an option granted to the underwriters of the equity financing) and debt
drawn from the Trust's credit facilities which are to be expanded in conjunction with the Acquisition. The Acquisition is expected to close on or about December 15, 2005, with an adjustment
date of December 1, 2005. 

Properties  

With
the Acquisition, Petrofund is acquiring approximately 5,400 boe/d of almost 100% natural gas weighted conventional production. The producing properties to be acquired pursuant to the
Acquisition are high netback properties with an average operating cost of $6.00 per boe and are approximately 80% operated. The assets to be acquired pursuant to the Acquisition also include
55,000 net acres of highly prospective undeveloped land on which Petrofund has already identified 166 (net) low to medium risk development drilling opportunities. Pursuit of these projects is
expected to positively impact production in 2006 and thereafter. 

Included
in the above lands are 12,600 net undeveloped acres along the Horseshoe Canyon coalbed methane fairway. Petrofund has also identified a further 143 (net) potential coalbed methane
wells on these properties. 

 

Scotia
Capital Inc. (together with its affiliate, Scotia Waterous Inc.) was retained as financial advisor to Petrofund regarding the Acquisition. 

The
conventional gas and liquids reserves to be acquired pursuant to the Acquisition were evaluated by GLJ Petroleum Consultants ("GLJ"). GLJ estimates the following gross working interest reserves
(based on forecast price and cost assumptions) as of July 1, 2005: 

	Proved Producing Reserves (mboe)	 	11,207
	Total Proved Reserves (mboe)	 	14,993
	Total Proved + Probable ("P+P") Reserves (mboe)	 	20,835

These
volumes do not include the development upside or coalbed methane potential identified by Petrofund. 

Adjusting
the above reserves using Petrofund's estimates of production between July 1, 2005 and December 1, 2005, results in the following estimates of gross working interest reserves
(based on forecast price and cost assumptions) as of the effective date: 

	Proved Producing Reserves (mboe)	 	10,362
	Total Proved Reserves (mboe)	 	14,148
	Total P+P Reserves (mboe)	 	19,990

After
deducting Cdn. $25 million of value which Petrofund has assigned to the coalbed methane potential and Cdn. $11.4 million of value attributed to the net undeveloped
lands but before applying any value for the upside development identified by Petrofund, the Acquisition has the following metrics as of the effective date: 

	P+P Reserves Price ($/boe)	 	$	22.44
	Production Price* ($/boe/d)	 	$	83,000
	Cash Flow Multiple (Q3 Annualized)	 	 	5.6x
	Reserve Life Index	 	 	10.1 years
	*Based on current production of 5,400 Boe/d	 	 	 

The
acquisition of the Kaiser assets is expected to provide the following benefits to Petrofund: 

	•
	14%
increase in current production to approximately 42,500 boe/d

	•
	14%
increase in reserves to approximately 160 million boe

	•
	A
more balanced oil and gas weighting, at approximately 50% oil / 50% natural gas on a production basis and to 58% oil / 42% natural gas on a
reserves basis post completion of the Acquisition

	•
	Continued
strong reserve life index approximating 11 years

	•
	Increased
portfolio of development opportunities as the Acquisition is expected to provide Petrofund with a significant number of additional opportunities to add value
through organic growth

	•
	Reduction
in per boe operating costs and general and administrative costs

	•
	Operating
synergies due to overlapping field locations (particularly in the Strachan area, one of the three core properties being acquired) 

The
Kaiser assets provide an excellent fit with Petrofund's long term strategy. Over its seventeen-year history, Petrofund has assembled an asset base comprising long life high quality oil
and gas properties. This portfolio approach to acquisitions and asset development has secured the Trust a diverse property 

2

 

base
extending throughout the western Canadian sedimentary basin. Petrofund's focus on long life high quality assets, as well as its strategies of commodity balance, geographic and geologic diversity,
coupled with a conservative management style have helped mitigate business risks and have contributed to the Trust's strong long term performance. The Kaiser assets are an ideal fit with Petrofund's
existing asset portfolio as they contain a combination of a high gas weighting, a long reserve life index and significant upside potential. The almost 100% gas weighting further strengthens Petrofund
by realigning its commodity balance to a 50% oil / 50% natural gas production ratio. This commodity balance will help the Trust take further advantage of expected strong future gas fundamentals. 

By
financing the Acquisition in the fashion proposed, Petrofund's debt to cash flow ratio will increase, but will still remain at a conservative level of less than 1.0 times. Petrofund expects
the Acquisition to be accretive to cash flow, net asset value, production and reserves per unit over the long term. 

The
Kaiser assets are located entirely in the province of Alberta. Over 50% of the value is contained in the following three core properties — Berland River,
Herronton and Strachan. The Berland River property is located approximately 130 kilometers south of Grande Prairie. This is a multi zone area with production predominantly from the Bluesky,
Gething, Cadomin, Falher, Viking, and Dunvegan formations. 

Herronton
is located approximately 50 kilometers southeast of Calgary. Kaiser currently operates 93 percent of their Herronton area production which is mainly from the Belly River zone.
Significant production in this area comes from the Kaiser operated Arrowwood Gas Unit #1 as well as the Herronton Turner Valley Unit. The Herronton property contains the majority of the
previously mentioned coalbed methane potential. 

The
Strachan area is located in south central Alberta approximately 20 kilometers from Rocky Mountain House. Strachan is an existing core area for Petrofund and, as such, there are major
synergies associated with the operations in this area. Strachan represents a multi zone area with productive formations ranging from the sweet and shallow Cretaceous Cardium formation down to the
deep, sour Devonian Leduc formation. 

Financing of Acquisition  

Concurrent
with the Acquisition, Petrofund has entered into an agreement to sell, to a syndicate of Canadian underwriters, 11,250,000 Subscription Receipts at Cdn. $20.00 each to raise
gross proceeds of Cdn. $225,000,000 on a bought deal basis. The Subscription Receipts will be exchangeable into Petrofund trust units on a one-for-one basis upon the
closing of the Acquisition. The underwriting syndicate is led by CIBC World Markets Inc. and includes National Bank Financial Inc., Scotia Capital Inc., RBC Capital Markets,
TD Securities Inc., BMO Nesbitt Burns Inc., Canaccord Capital Corporation, FirstEnergy Capital Corp., GMP Securities Ltd., Raymond James Ltd., Blackmont
Capital Inc., Sprott Securities Inc. and Tristone Capital Inc. Petrofund has granted the underwriters an option (the "Underwriters Option"), exercisable in whole or in part
prior to closing, to purchase up to an additional 1,250,000 Subscription Receipts at the same offering price. On November 24, 2005 the Underwriters' Option was fully exercised, and as a
result the total gross proceeds of the financing will be Cdn. $250,000,000. 

The
gross proceeds from the sale of the Subscription Receipts will be held in escrow. If the Acquisition closes on or before January 31, 2006, the proceeds will be released to Petrofund to
finance a portion of the purchase price of the Acquisition. If the offering closes before the Acquisition closes, purchasers of Subscription Receipts will receive payments equivalent to the amount of
any cash distributions paid or declared payable to unitholders of the Trust for those record dates that occur between the closing of the equity offering and the date immediately preceding the closing
of the Acquisition. However, if the 

3

 

Acquisition
fails to close by January 31, 2006, or the agreement governing the terms of the Acquisition is terminated at an earlier time, the escrow agent will return to the holders of
Subscription Receipts the issue price and their pro-rata entitlement to interest earned thereon, but no distribution equivalent payments will be made. 

The
offering of Subscription Receipts is being made only in Canada by means of a short-form prospectus. Closing of the offering is expected to occur on December 6, 2005, and is
subject to normal regulatory approvals. The underwriters have agreed not to offer, sell or deliver the Subscription Receipts, as part of the distribution of such Subscription Receipts at any time,
within the United States or to, or for the benefit or account of, U.S. persons. The Trust intends to file a registration statement to register under the United States
Securities Act of 1933 the offered Subscription Receipts and the Trust Units issuable pursuant to the offered Subscription Receipts. 

Petrofund
intends to finance the portion of the purchase price of the Acquisition which is not financed with the offering of Subscription Receipts with debt drawn from the Trust's credit facilities
which are expected to be expanded in conjunction with the Acquisition. 

Purchase Agreement  

Pursuant
to the Purchase Agreement, Petrofund paid a deposit of $48.5 million to the Vendor, which amount will be credited to the purchase price in the event that the Acquisition is completed
and will be retained by the Vendor if the Acquisition is not completed under certain circumstances, including breach by Petrofund of its representations and warranties contained in the Purchase
Agreement and failure by Petrofund to perform its covenants contained in the Purchase Agreement. 

Conditions
to closing of the Acquisition include standard conditions for transactions of this nature including the following: the continued accuracy of representations and warranties in the Purchase
Agreement (provided that breaches of representations and warranties of the Vendor must exceed $5 million in aggregate for Petrofund not to close for reason of such breaches); the performance of
covenants contained in the Purchase Agreement; the delivery of closing documents; title due diligence satisfactory to Petrofund; and receipt of regulatory approvals. If Petrofund fails to complete the
Acquisition as a result of the breach by the Vendor of its representations and warranties contained in the Purchase Agreement, Petrofund is entitled to recover from the Vendor its costs and expenses
resulting from such breach up to a maximum of $10 million. 

In
connection with the Acquisition, the Vendor has agreed to indemnify Petrofund in respect of its tax liabilities that relate to the period prior to the date that the Acquisition is completed
(provided that such liabilities exceed $5 million) and liabilities relating to breaches of representations and warranties of Vendor contained in the Purchase Agreement (provided that individual
breaches exceed $200,000 and provided that all of such breaches exceed $5 million). Petrofund has also agreed to indemnify the Vendor in respect of all past, present and future environmental
liabilities relating to the New Properties. 

Other Information  

All
oil and natural gas information contained in this material change report has been prepared and presented in accordance with National Instrument 51-101. In this material change
report, all estimates of oil and natural gas reserves and production are presented on a "working interest" basis. As the Trust is not currently the owner of the Properties, all operational information
relating to the Properties contained in this material change report is based on information provided to the Trust by third parties. 

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The
Trust has adopted the standard of 6 mcf:1 boe when converting natural gas to boes. Boes may be misleading, particularly if used in isolation. A BOE conversion ratio of
6 mcf:1 boe is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. 

Item 6.    Reliance on Subsection 7.1(2) or (3) of National Instrument 51-102.  

Not
applicable. 

Item 7.    Omitted Information:  

Not
applicable. 

Item 8.    Senior Officer:  

The
name and business numbers of the executive officer of Petrofund who is knowledgeable of the material change and this report is: 

Jeffrey
Newcommon

Executive Vice-President

Telephone: (403) 218-8625

Facsimile: (403) 539-4300 

Item 9.    Statement of Senior Officer  

The
foregoing accurately discloses the material change referred to herein. 

                Dated as of November 25, 2005, Calgary, Alberta. 

	 	 	PETROFUND ENERGY TRUST

by Petrofund Corp.
	
 	
 	

By:	

/s/  JEFFREY NEWCOMMON      

	 	 	 	Jeffrey Newcommon

Executive Vice-President

cc:
Toronto Stock Exchange 

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QuickLinks

EXHIBIT 4.9

MATERIAL CHANGE REPORT

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