Petrofund Energy Trust (PTF) F-10 Registration of securities (Canada)

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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.

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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.

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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.

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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.

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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 - 7^th 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

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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

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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