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EXHIBIT 4.4    
    

 
 

PETROFUND ENERGY TRUST    
    
    CONSOLIDATED BALANCE SHEET    
    
    (thousands of dollars) (unaudited)    
    

	As at September 30, 2005 and December 31, 2004 
	 	2005
	 	2004
	 
	Assets	 	 	 	 	 	 	 
	
Current assets	
 	
 	

 	
 	
 	

 	
 
	 	Cash	 	$	7,993	 	$	—	 
	 	Accounts receivable	 	 	47,671	 	 	37,713	 
	 	Deferred loss on commodity contracts	 	 	129	 	 	517	 
	 	Commodity contracts (Note 9)	 	 	745	 	 	3,281	 
	 	Prepaid expenses	 	 	16,591	 	 	10,847	 
	 	 	
	 	
	 
	Total current assets	 	 	73,129	 	 	52,358	 
	Asset retirement reserve fund (Note 7(b))	 	 	8,538	 	 	7,053	 
	Goodwill (Note 2)	 	 	190,247	 	 	180,307	 
	Oil and natural gas royalty and property interests, at cost less accumulated depletion and depreciation of $772,403 (2004 — $632,668)	 	 	1,297,522	 	 	1,246,694	 
	 	 	
	 	
	 
	 	 	$	1,569,436	 	$	1,486,412	 
	 	 	
	 	
	 
	
Liabilities and Unitholders' Equity	
 	
 	

 	
 	
 	

 	
 
	
Current liabilities	
 	
 	

 	
 	
 	

 	
 
	 	Bank overdraft	 	$	—	 	$	733	 
	 	Accounts payable and accrued liabilities	 	 	42,052	 	 	60,961	 
	 	Current portion of capital lease obligations	 	 	—	 	 	608	 
	 	Deferred gain on commodity contracts	 	 	38	 	 	184	 
	 	Commodity contracts (Note 9)	 	 	37,051	 	 	14,599	 
	 	Distributions payable to Unitholders (Note 8)	 	 	18,126	 	 	35,568	 
	 	 	
	 	
	 
	Total current liabilities	 	 	97,267	 	 	112,653	 
	Long-term debt (Note 6)	 	 	244,499	 	 	214,414	 
	Future income taxes	 	 	87,658	 	 	81,411	 
	Asset retirement obligations (Note 7(a))	 	 	55,266	 	 	51,408	 
	 	 	
	 	
	 
	Total liabilities	 	 	484,690	 	 	459,886	 
	
Unitholders' equity	
 	
 	

 	
 	
 	

 	
 
	 	Unitholders' capital (Note 3)	 	 	1,560,317	 	 	1,477,963	 
	 	Exchangeable shares (Note 4)	 	 	6,038	 	 	10,518	 
	 	Accumulated earnings	 	 	383,257	 	 	272,612	 
	 	Accumulated cash distributions (Note 8)	 	 	(864,866	)	 	(734,567	)
	 	 	
	 	
	 
	Total unitholders' equity	 	 	1,084,746	 	 	1,026,526	 
	 	 	
	 	
	 
	 	 	$	1,569,436	 	$	1,486,412	 
	 	 	
	 	
	 

The
accompanying notes to the Interim Consolidated Financial Statements are an integral part of this consolidated balance sheet. 

1

 

 
 

CONSOLIDATED STATEMENT OF OPERATIONS AND ACCUMULATED EARNINGS    
    
    (thousands of dollars, except per unit amounts) (unaudited)    
    

	 
	 	3 months ended

September 30,
	 	9 months ended

September 30,
	 
	 
	 	2005
	 	2004
	 	2005
	 	2004
	 
	Revenues	 	 	 	 	 	 	 	 	 	 	 	 	 
	 	Oil and natural gas sales	 	$	212,404	 	$	147,489	 	$	540,003	 	$	360,158	 
	 	Royalties	 	 	(42,095	)	 	(27,578	)	 	(105,048	)	 	(69,173	)
	 	Loss on commodity contracts	 	 	(23,971	)	 	(29,903	)	 	(54,254	)	 	(60,934	)
	 	 	
	 	
	 	
	 	
	 
	 	 	 	146,338	 	 	90,008	 	 	380,701	 	 	230,051	 
	 	 	
	 	
	 	
	 	
	 
	Expenses	 	 	 	 	 	 	 	 	 	 	 	 	 
	 	Lease operating	 	 	35,558	 	 	30,920	 	 	103,245	 	 	74,388	 
	 	Transportation costs	 	 	2,291	 	 	1,753	 	 	6,222	 	 	4,264	 
	 	Financing costs	 	 	2,123	 	 	1,703	 	 	6,858	 	 	3,792	 
	 	General and administrative	 	 	4,816	 	 	3,764	 	 	12,357	 	 	10,218	 
	 	Capital taxes	 	 	1,023	 	 	788	 	 	3,167	 	 	2,444	 
	 	Depletion, depreciation and accretion	 	 	51,027	 	 	41,982	 	 	141,960	 	 	104,619	 
	 	 	
	 	
	 	
	 	
	 
	 	 	 	96,838	 	 	80,910	 	 	273,809	 	 	199,725	 
	 	 	
	 	
	 	
	 	
	 
	Income before provision for income taxes	 	 	49,500	 	 	9,098	 	 	106,892	 	 	30,326	 
	 	 	
	 	
	 	
	 	
	 
	Provision for (recovery of) income taxes	 	 	 	 	 	 	 	 	 	 	 	 	 
	 	Current	 	 	202	 	 	100	 	 	418	 	 	368	 
	 	Future	 	 	(1,911	)	 	(6,149	)	 	(4,171	)	 	6,365	 
	 	 	
	 	
	 	
	 	
	 
	 	 	 	(1,709	)	 	(6,049	)	 	(3,753	)	 	6,733	 
	 	 	
	 	
	 	
	 	
	 
	Net income	 	 	51,209	 	 	15,147	 	 	110,645	 	 	23,593	 
	 	 	
	 	
	 	
	 	
	 
	Accumulated earnings, beginning of period	 	 	332,048	 	 	206,699	 	 	272,612	 	 	198,253	 
	Accumulated earnings, end of period	 	$	383,257	 	$	221,846	 	$	383,257	 	$	221,846	 
	 	 	
	 	
	 	
	 	
	 
	
Net income per Trust unit (Note 3)	
 	
 	

 	
 	
 	

 	
 	
 	

 	
 	
 	

 	
 
	 	Basic	 	$	0.49	 	$	0.15	 	$	1.08	 	$	0.28	 
	 	Diluted	 	$	0.49	 	$	0.15	 	$	1.08	 	$	0.28	 
	 	 	
	 	
	 	
	 	
	 

The
accompanying notes to the Interim Consolidated Financial Statements are an integral part of these consolidated statements. 

2

 

 
 

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

	 
	 	3 months ended

September 30,
	 	9 months ended

September 30,
	 
	 
	 	2005
	 	2004
	 	2005
	 	2004
	 
	Cash provided by (used in):	 	 	 	 	 	 	 	 	 	 	 	 	 
	
Operating activities	
 	
 	

 	
 	
 	

 	
 	
 	

 	
 	
 	

 	
 
	 	Net income	 	$	51,209	 	$	15,147	 	$	110,645	 	$	23,593	 
	 	Add items not affecting cash:	 	 	 	 	 	 	 	 	 	 	 	 	 
	 	 	Depletion, depreciation and accretion	 	 	51,027	 	 	41,982	 	 	141,960	 	 	104,619	 
	 	 	Commodity contracts unrealized loss	 	 	11,136	 	 	15,344	 	 	25,230	 	 	32,587	 
	 	 	Future income taxes (recovery)	 	 	(1,911	)	 	(6,149	)	 	(4,171	)	 	6,365	 
	 	Actual abandonment costs incurred (Note 7(b))	 	 	(339	)	 	(1,249	)	 	(1,772	)	 	(3,222	)
	 	 	
	 	
	 	
	 	
	 
	 	 	 	111,122	 	 	65,075	 	 	271,892	 	 	163,942	 
	Net change in non-cash operating working capital balances	 	 	(21,083	)	 	(2,395	)	 	(39,516	)	 	24,797	 
	 	 	
	 	
	 	
	 	
	 
	Cash provided by operating activities	 	 	90,039	 	 	62,680	 	 	232,376	 	 	188,739	 
	 	 	
	 	
	 	
	 	
	 
	Financing activities	 	 	 	 	 	 	 	 	 	 	 	 	 
	 	Long-term debt	 	 	(9,846	)	 	(12,989	)	 	30,085	 	 	(20,640	)
	 	Distributions paid (Note 8)	 	 	(50,150	)	 	(47,684	)	 	(146,837	)	 	(121,759	)
	 	Redemption of exchangeable shares (Note 4)	 	 	(258	)	 	(450	)	 	(904	)	 	(1,352	)
	 	Capital lease repayments	 	 	(74	)	 	(90	)	 	(608	)	 	(264	)
	 	Issuance of Trust units (Note 3)	 	 	452	 	 	1,642	 	 	77,874	 	 	3,351	 
	 	 	
	 	
	 	
	 	
	 
	Cash used in financing activities	 	 	(59,876	)	 	(59,571	)	 	(40,390	)	 	(140,664	)
	 	 	
	 	
	 	
	 	
	 
	Investing activities	 	 	 	 	 	 	 	 	 	 	 	 	 
	 	Asset retirement reserve (Note 7(b))	 	 	(518	)	 	(482	)	 	(1,485	)	 	(1,228	)
	 	Corporate acquisitions (Note 2 (a)(b))	 	 	42	 	 	5,636	 	 	(56,058	)	 	(1,800	)
	 	Property acquisitions	 	 	(11,287	)	 	598	 	 	(17,768	)	 	(1,544	)
	 	Property dispositions	 	 	871	 	 	—	 	 	871	 	 	—	 
	 	Development expenditures	 	 	(29,895	)	 	(20,486	)	 	(108,908	)	 	(47,931	)
	 	Cash acquired on acquisitions (Note 2 (b))	 	 	—	 	 	—	 	 	88	 	 	9,711	 
	 	 	
	 	
	 	
	 	
	 
	Cash used in investing activities	 	 	(40,787	)	 	(14,734	)	 	(183,260	)	 	(42,792	)
	 	 	
	 	
	 	
	 	
	 
	Net change in cash	 	 	(10,624	)	 	(11,625	)	 	8,726	 	 	5,283	 
	Cash (bank overdraft), beginning of period	 	 	18,617	 	 	19,090	 	 	(733	)	 	2,182	 
	 	 	
	 	
	 	
	 	
	 
	Cash, end of period	 	$	7,993	 	$	7,465	 	$	7,993	 	$	7,465	 
	 	 	
	 	
	 	
	 	
	 
	Interest paid during the period	 	$	2,087	 	$	2,504	 	$	6,521	 	$	3,671	 
	 	 	
	 	
	 	
	 	
	 
	Income taxes paid during the period	 	$	144	 	$	141	 	$	77	 	$	247	 
	 	 	
	 	
	 	
	 	
	 

The
accompanying notes to the Interim Consolidated Financial Statements are an integral part of these consolidated statements. 

3

  

 
 

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS    
    
    September 30, 2005 and 2004    
    
    (unaudited)    
    
    (tabular amounts in thousands of dollars,
except unit and per unit amounts)    

1.     INTERIM FINANCIAL STATEMENTS  

These
unaudited interim consolidated financial statements follow the same accounting policies and methods of their application as the most recent annual financial statements. The note disclosure
requirements for annual financial statements are prepared in accordance with Canadian generally accepted accounting principles and provide additional disclosures to that required for interim financial
statements. Accordingly, these interim financial statements should be read in conjunction with the audited consolidated financial statements of Petrofund Energy Trust ("Petrofund" or the "Trust") as
at December 31, 2004 and 2003 and for each of the years in the three-year period ended December 31, 2004. 

2.     ACQUISITIONS  

	(a)
	Acquisition of Northern Crown Petroleums Ltd.  

On
May 10, 2005 Petrofund acquired 100% of the outstanding shares of Northern Crown Petroleums Ltd. and its wholly owned subsidiary Spiral Resources Ltd. for $32.7 million
in cash and assumed debt and negative working capital of $4.8 million. Of the total acquisition costs of $45.7 million, $38.5 million was allocated to oil and gas royalty and
property interest and $7.1 million to goodwill, which is not deductible for tax purposes. 

A
summary of the estimated net assets acquired is as follows: 

	 
	 	(000's)
	 
	Current assets	 	$	1,733	 
	Goodwill	 	 	7,120	 
	Oil and gas royalties and property interests	 	 	38,556	 
	Current liabilities	 	 	(6,550	)
	Asset retirement obligations	 	 	(756	)
	Future income taxes	 	 	(7,398	)
	 	 	
	 
	 	 	$	32,705	 
	 	 	
	 

	(b)
	Acquisition of Tahiti Gas Ltd.  

On
May 31, 2005 Petrofund acquired 100% of the outstanding shares of Tahiti Gas Ltd. ("Tahiti") for $23.4 million in cash and assumed debt and working capital of $23,000. Of the
total acquisition costs of $26.8 million, $24.0 million was allocated to oil and gas royalty and property interest and $2.8 million to goodwill, which is not deductible for tax
purposes. 

A
summary of the estimated net assets acquired is as follows: 

	 
	 	(000's)
	 
	Current assets	 	$	184	 
	Goodwill	 	 	2,820	 
	Oil and gas royalties and property interests	 	 	23,974	 
	Current liabilities	 	 	(161	)
	Asset retirement obligations	 	 	(420	)
	Future income taxes	 	 	(3,020	)
	 	 	
	 
	 	 	$	23,377	 
	 	 	
	 

4

 

3.     TRUST UNITS  

	Authorized: unlimited number of Trust units 
	 	Number of Units
	 	$000's
	 
	Issued	 	 	 	 	 	 
	Balance, December 31, 2004	 	99,511,576	 	$	1,477,963	 
	Issued for cash	 	4,150,000	 	 	75,738	 
	Exchangeable shares exchanged (Note 4)	 	400,000	 	 	4,480	 
	Commissions and issue costs	 	—	 	 	(4,296	)
	Options exercised	 	405,424	 	 	5,751	 
	Unit purchase plan	 	4,118	 	 	79	 
	Unit incentive plan	 	36,002	 	 	602	 
	 	 	
	 	
	 
	Balance, September 30, 2005	 	104,507,120	 	$	1,560,317	 
	 	 	
	 	
	 

The weighted average Trust units/exchangeable shares outstanding are as follows:

	 
	 	3 months ended

September 30,
	 	9 months ended

September 30,

	 
	 	2005
	 	2004
	 	2005
	 	2004

	Basic	 	105,017,651	 	100,266,733	 	102,412,474	 	84,064,168
	Diluted	 	105,039,185	 	100,353,257	 	102,441,345	 	84,210,974

The
diluted amounts include all dilutive instruments. 

Trust units/exchangeable shares outstanding:

	As at September 30, 
	 	2005
	 	2004

	Trust units outstanding	 	104,507,120	 	99,405,256
	Trust units issuable for exchangeable shares (Note 4)	 	539,147	 	939,147
	 	 	
	 	

	 	 	105,046,267	 	100,344,403
	 	 	
	 	

4.     EXCHANGEABLE SHARES  

	Issued and Outstanding 
	 	Number of Shares
	 	$000's
	 
	Balance, December 31, 2004	 	756,648	 	$	10,518	 
	Redemption of shares	 	(37,779	)	 	—	 
	Exchanged for Trust Units(1)	 	(316,251	)	 	(4,480	)
	 	 	
	 	
	 
	Balance, September 30, 2005	 	402,618	 	 	6,038	 
	Exchangeable ratio, end of period	 	1.3391	 	 	—	 
	 	 	
	 	
	 
	Exchangeable for Trust units	 	539,147	 	$	6,038	 
	 	 	
	 	
	 

	(1)
	On
March 7, 2005, 316,251 Exchangeable Shares were exchanged for 400,000 Trust units at an exchange rate of 1.26482. 

5.     RESTRICTED UNIT PLAN ("RUP") AND LONG-TERM INCENTIVE PLAN ("LTIP")  

On
February 17, 2004, the Board of Directors approved the adoption of the RUP and LTIP which authorizes the Trust to issue units to directors, officers, employees, or consultants of the Trust
or any of its subsidiaries. The units, plus accrued distributions, vest over time and upon vesting may be redeemed by the holder for cash or units under the RUP and for units only under the LTIP. The
units are issued, or the cash paid out, on the vesting dates based upon the weighted average trading prices of the units for the last 20 trading days prior to the vesting dates. The estimated
value of the units to be issued, or the cash to be paid out, is charged to expense over the vesting periods of the grants. The number of units outstanding, excluding accrued distributions, is as
follows: 

5

 

	 
	 	RUP
	 	LTIP
	 
	Balance, December 31, 2004	 	54,326	 	31,156	 
	Granted	 	110,067	 	61,245	 
	Units issued	 	(20,315	)	(51,571	)
	Forfeitures	 	(20,905	)	—	 
	 	 	
	 	
	 
	Balance, September 30, 2005	 	123,173	 	40,830	 
	 	 	
	 	
	 

The
Trust recorded compensation expenses of $2.6 million in the nine months ended September 30, 2005 (2004 — $1.2 million). The compensation
expense was based on the September 30, 2005 unit price of $22.82, distributions of $1.44 per unit during the period and management's estimate of the number of RUP and LTIP units to be issued on
maturity. 

6.     LONG-TERM DEBT  

Under
the loan agreements, as at September 30, 2005, Petrofund Corp. ("PC"), a wholly-owned subsidiary of the Trust had a revolving working capital operating facility of $25 million and
a syndicated facility of $390 million. On April 29, 2005, PC increased its syndicated facility to $390 million, bringing PC's borrowing base to $415 million
(December 31, 2004 — $325 million). Interest on the working capital loan is at prime and interest on the syndicated facility varies with PC's debt
to cash ratio from prime or, at the Trust's option, Banker's Acceptances rates plus 80 to 125 basis points plus stamping fees. The prime rate at September 30, 2005 was 4.50%. As
at September 30, 2005, there was no amount outstanding under the working capital facility and $244.5 million outstanding under the syndicated facility. 

The
revolving period on the syndicated facility ends on April 28, 2006, unless extended for a further 364 day period. In the event that the revolving bank line is not extended at the end
of the 364 day revolving period, no payments are required to be made to non-extending lenders during the first year of the term period. However, PC will be required to maintain
certain minimum balances on deposit with the syndicate agent. 

The
limit of the syndicated facility is subject to adjustment from time to time to reflect changes in PC's asset base. 

The
credit facility is secured by a debenture of $600 million pursuant to which a Canadian chartered bank, as principal and as agent for the other lenders, received a first ranking security
interest on all of PC's assets. 

The
loan is the legal obligation of PC. While principal and interest payments are allowable deductions in the calculation of royalty income, the Unitholders have no direct liability to the bank or to
PC should the assets securing the loan generate insufficient cash flow to repay the obligation. 

Substantially
all of the credit facility is financed with Banker's Acceptances, resulting in a reduction in the stated bank loan interest rates. 

7.     ASSET RETIREMENT OBLIGATIONS AND RESERVE FUND  

	(a)
	Asset Retirement Obligations ("ARO")  

The
total future asset retirement obligation was estimated by management based on the Trust's net ownership interest in wells and facilities and the estimated timing of the costs to be incurred in
future periods. 

The
following reconciles the Trust's outstanding ARO for the periods indicated: 

	 
	 	3 months ended

September 30,
	 	9 months ended

September 30,
	 
	($000's) 
	 	2005
	 	2004
	 	2005
	 	2004
	 
	Balance, at beginning of period	 	$	54,126	 	$	50,506	 	$	51,408	 	$	34,363	 
	Increase in liabilities during the period	 	 	490	 	 	204	 	 	2,229	 	 	540	 
	Accretion expense during period	 	 	989	 	 	824	 	 	2,225	 	 	1,932	 
	Actual costs incurred during the period	 	 	(339	)	 	(1,249	)	 	(1,772	)	 	(3,222	)
	Acquisitions additions during the period (Note 2)	 	 	—	 	 	—	 	 	1,176	 	 	16,672	 
	 	 	
	 	
	 	
	 	
	 
	Balance, at end of period	 	$	55,266	 	$	50,285	 	$	55,266	 	$	50,285	 
	 	 	
	 	
	 	
	 	
	 

6

 

	(b)
	Asset Retirement Reserve Fund  

PC
maintains a cash reserve to finance large and unusual oil and natural gas property reclamation and abandonment costs by withholding amounts, which would otherwise represent distributions accruing
to Unitholders. At September 30, 2005, the cash reserve was $8.5 million (December 31, 2004 — $7.1 million). In the third quarter of
2005, PC increased the cash reserve by withholding $518,000 (2004 — $482,000) from distributions accruing to Unitholders. In addition, routine ongoing reclamation
and abandonment costs of $339,000 in the third quarter of 2005 (2004 — $1.2 million) were incurred and deducted from distributions accruing to Unitholders.
Ongoing reclamation and abandonment cost of $1.8 million for nine months ended September 30, 2005 (2004 — $3.2 million) were incurred and
deducted from distributions accruing the unitholders. 

8.     RECONCILIATION OF CASH FLOW AND DISTRIBUTIONS  

Cash
distributions are calculated in accordance with the Trust Indenture. To arrive at cash distributions, funds from operations, before changes in non-cash working capital, is reduced by
reclamation fund contributions including interest earned on the fund, a portion of capital expenditures, debt repayments, Trust expenses, unit retraction or repurchases, if any, and all amounts paid
into the reserve account. The portion of cash flow withheld to fund capital expenditures and to made debt repayments is at the discretion of the Board of Directors. 

Reconciliation of Distributions Accruing to Unitholders

(thousands of dollars) 

	 
	 	3 months ended

September 30,
	 	9 months ended

September 30,
	 
	 
	 	2005
	 	2004
	 	2005
	 	2004
	 
	Distributions payable, beginning of period	 	$	67,504	 	$	26,029	 	$	35,568	 	$	53,452	 
	 	 	
	 	
	 	
	 	
	 
	Distributions accruing during the period	 	 	 	 	 	 	 	 	 	 	 	 	 
	 	Cash provided by operating activities	 	 	90,039	 	 	62,680	 	 	232,376	 	 	188,739	 
	 	Net change in non-cash operating working capital balance	 	 	21,083	 	 	2,395	 	 	39,516	 	 	(24,797	)
	 	Amortization of the cost of commodity contracts	 	 	—	 	 	(238	)	 	—	 	 	(701	)
	 	Redemption of exchangeable shares	 	 	(258	)	 	(450	)	 	(904	)	 	(1,352	)
	 	Asset retirement reserve contributions	 	 	(518	)	 	(482	)	 	(1,485	)	 	(1,228	)
	 	Capital lease repayment	 	 	(74	)	 	(90	)	 	(608	)	 	(264	)
	 	 	
	 	
	 	
	 	
	 
	Cash flow before capital reinvestment	 	 	110,272	 	 	63,815	 	 	268,895	 	 	160,397	 
	 	Weyburn deferred capital obligation	 	 	—	 	 	(1	)	 	—	 	 	(34,931	)
	 	Capital expenditures funded from cash flow	 	 	(109,500	)	 	(15,000	)	 	(139,500	)	 	(30,000	)
	 	 	
	 	
	 	
	 	
	 
	Total distributions accruing during the period	 	 	772	 	 	48,814	 	 	129,395	 	 	95,466	 
	Distributions paid	 	 	(50,150	)	 	(47,684	)	 	(146,837	)	 	(121,759	)
	 	 	
	 	
	 	
	 	
	 
	Distributions payable, end of period	 	$	18,126	 	$	27,159	 	$	18,126	 	$	27,159	 
	 	 	
	 	
	 	
	 	
	 

Accumulated Cash Distributions

(thousands of dollars) 

	 
	 	3 months ended

September 30,
	 	9 months ended

September 30,

	 
	 	2005
	 	2004
	 	2005
	 	2004

	Accumulated cash distributions, beginning of period	 	$	863,836	 	$	628,709	 	$	734,567	 	$	581,155
	Distributions accruing during the period	 	 	772	 	 	48,814	 	 	129,395	 	 	95,466
	Redemption of exchangeable shares	 	 	258	 	 	450	 	 	904	 	 	1,352
	 	 	
	 	
	 	
	 	

	Accumulated cash distributions, end of period	 	$	864,866	 	$	677,973	 	$	864,866	 	$	677,973
	 	 	
	 	
	 	
	 	

7

 

9.     DERIVATIVE FINANCIAL INSTRUMENTS  

The
Trust enters into various pricing mechanisms to reduce price volatility and establish minimum prices for a portion of its oil and gas production. These include fixed-price contracts and the use of
derivative financial instruments. 

The
outstanding derivative financial instruments and related contracts as at September 30, 2005 and the related unrealized gains or losses are summarized separately below: 

	Natural Gas 
	 	Term
	 	Volume

mcf/d
	 	Price

$/mcf
	 	Delivery

Point
	 	Unrealized Gain (Loss)

$000's
	 
	Collar	 	April 1, 2005 to

October 31, 2005	 	4,737	 	$6.33-$8.44	 	AECO	 	$	(491	)
	Collar	 	April 1, 2005 to

October 31, 2005	 	4,737	 	$6.33-$9.60	 	AECO	 	 	(288	)
	Collar	 	April 1, 2005 to

October 31, 2005	 	4,737	 	$6.33-$8.44	 	AECO	 	 	(491	)
	Collar	 	April 1, 2005 to

October 31, 2005	 	4,737	 	$6.33-$8.44	 	AECO	 	 	(455	)
	Three way collar	 	April 1, 2005 to

October 31, 2005	 	4,737	 	$4.75-$5.80-$7.92	 	AECO	 	 	(535	)
	Three way collar	 	November 1, 2005 to March 31, 2006	 	4,737	 	$5.65-$6.70-$10.55	 	AECO	 	 	(2,809	)
	Three way collar	 	November 1, 2005 to March 31, 2006	 	4,737	 	$5.28-$6.33-$12.98	 	AECO	 	 	(1,583	)
	Collar	 	November 1, 2005 to March 31, 2006	 	4,737	 	$7.39-$13.72	 	AECO	 	 	(1,351	)
	Collar	 	November 1, 2005 to March 31, 2006	 	4,737	 	$7.39-$16.15	 	AECO	 	 	(815	)
	Floor	 	November 1, 2005 to March 31, 2006	 	4,737	 	$8.44	 	AECO	 	 	43	 
	Floor	 	November 1, 2005 to March 31, 2006	 	4,737	 	$8.44	 	AECO	 	 	53	 
	Three way collar	 	April 1, 2006 to October 31, 2006	 	4,737	 	$6.07-$7.39-$8.99	 	AECO	 	 	(2,237	)
	Collar	 	April 1, 2006 to October 31, 2006	 	4,737	 	$7.39-$10.55	 	AECO	 	 	(1,318	)
	Collar	 	April 1, 2006 to October 31, 2006	 	4,737	 	$8.44-$11.35	 	AECO	 	 	(794	)
	Collar	 	April 1, 2006 to October 31, 2006	 	4,737	 	$8.44-$14.51	 	AECO	 	 	38	 
	 	 	 	 	 	 	 	 	 	 	
	 
	Total	 	 	 	 	 	 	 	 	 	$	(13,033	)
	 	 	 	 	 	 	 	 	 	 	
	 

8

 

	Oil 
	 	Term
	 	Volume

bbl/d
	 	Price

$/bbl
	 	Delivery Point
	 	Unrealized Gain (Loss)

$000's
	 
	Three way collar	 	January 1, 2005 to December 31, 2005	 	1,000	 	$23.25-$27.90-$33.72	 	Edmonton	 	$	(5,244	)
	Three way collar	 	January 1, 2005 to December 31, 2005	 	1,000	 	$27.90-$31.39-$39.53	 	Edmonton	 	 	(4,539	)
	Three way collar	 	January 1, 2005 to December 31, 2005	 	1,000	 	$26.74-$31.39-$38.37	 	Edmonton	 	 	(4,680	)
	Three way collar	 	July 1, 2005 to December 31, 2005	 	1,000	 	$40.69-$46.51-$69.76	 	Edmonton	 	 	(978	)
	Collar	 	October 1, 2005 to December 31, 2005	 	1,000	 	$48.83-$69.76	 	Edmonton	 	 	(794	)
	Three way collar	 	January 1, 2006 to March 31, 2006	 	1,000	 	$40.69-$46.51-$61.62	 	Edmonton	 	 	(1,571	)
	Collar	 	January 1, 2006 to March 31, 2006	 	1,000	 	$48.83-$69.76	 	Edmonton	 	 	(964	)
	Collar	 	January 1, 2006 to March 31, 2006	 	1,000	 	$52.32-$81.39	 	Edmonton	 	 	(425	)
	Collar	 	January 1, 2006 to March 31, 2006	 	1,000	 	$58.14-$93.02	 	Edmonton	 	 	(117	)
	Collar	 	January 1, 2006 to March 31, 2006	 	1,000	 	$58.14-$79.94	 	Edmonton	 	 	(462	)
	Collar	 	January 1, 2006 to

June 30, 2006	 	1,000	 	$63.95-$103.48	 	Edmonton	 	 	194	 
	Three way collar	 	April 1, 2006 to

June 30, 2006	 	1,000	 	$43.02-$48.83-$68.89	 	Edmonton	 	 	(1,179	)
	Collar	 	April 1, 2006 to

June 30, 2006	 	1,000	 	$55.23-$81.39	 	Edmonton	 	 	(487	)
	Collar	 	April 1, 2006 to

June 30, 2006	 	1,000	 	$58.14-$75.58	 	Edmonton	 	 	(638	)
	Collar	 	April 1, 2006 to

June 30, 2006	 	1,000	 	$58.14-$88.37	 	Edmonton	 	 	(241	)
	Collar	 	April 1, 2006 to

June 30, 2006	 	1,000	 	$58.14-$94.18	 	Edmonton	 	 	(124	)
	Collar	 	July 1, 2006 to

September 30, 2006	 	1,000	 	$58.14-$75.58	 	Edmonton	 	 	(648	)
	Collar	 	July 1, 2006 to

September 30, 2006	 	1,000	 	$58.14-$87.78	 	Edmonton	 	 	(268	)
	Collar	 	July 1, 2006 to

September 30, 2006	 	1,000	 	$58.14-$93.89	 	Edmonton	 	 	(138	)
	Collar	 	July 1, 2006 to

September 30, 2006	 	1,000	 	$63.95-$96.74	 	Edmonton	 	 	(24	)
	Collar	 	October 1, 2006 to

December 31, 2006	 	1,000	 	$58.14-$75.58	 	Edmonton	 	 	(653	)
	 	 	 	 	 	 	 	 	 	 	
	 
	Total	 	 	 	 	 	 	 	 	 	$	(23,980	)
	 	 	 	 	 	 	 	 	 	 	
	 

9

 

	Electricity 
	 	Term
	 	Volume

MW/h
	 	Price

$/MWh
	 	Delivery Point
	 	Unrealized Gain

$000's

	Fixed Price	 	February 1, 2004 to December 31, 2005	 	2.0	 	$44.50	 	Alberta Power Pool	 	$	155
	Fixed Price	 	January 1, 2006 to December 31, 2008	 	2.0	 	$57.00	 	Alberta Power Pool	 	 	552
	 	 	 	 	 	 	 	 	 	 	

	Total	 	 	 	 	 	 	 	 	 	$	707
	 	 	 	 	 	 	 	 	 	 	

Derivative
financial instruments and related hedge contracts involve a degree of credit risk, which the Trust controls through the use of financially sound counterparties. The gains or losses incurred
are recognized on a monthly basis over the terms of the hedge contracts. All foreign exchange calculations incorporate the Bank of Canada U.S. dollar rate at the close on September 30,
2005 of CDN $1.1627: U.S. $1. 

10.   DIFFERENCES BETWEEN CANADIAN AND UNITED STATES GENERALLY ACCEPTED

        ACCOUNTING PRINCIPLES ("GAAP")  

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

	(a)
	Under
U.S. GAAP, the carrying value of oil and gas royalty and property interests, net of future income taxes, is limited to the present value of after tax future net revenue
from proven reserves excluding future assets retirement costs, discounted at 10% (based on prices and costs at the balance sheet date), plus the lower of cost and fair value of unproven properties.
Where the amount of an impairment test write-down under Canadian GAAP differs from the amount of the write-down under U.S. GAAP, the charge for depletion, depreciation
and accretion will differ in subsequent years.

	(b)
	U.S. GAAP
utilizes the concept of comprehensive income, which includes items not included in net income. At the current time, there is no similar concept under Canadian GAAP.

	(c)
	Prior
to the Trust adopting AcG-13 for Canadian GAAP purposes, a difference existed in that U.S. GAAP accounting and reporting standards required that all
derivative instruments (including derivative instruments embedded in other contracts), as defined, be recorded in the balance sheet as either an asset or a liability measured at fair value and
requires that changes in fair value be recognized currently in income unless specific hedge accounting criteria are met. In 2005 and 2004, for Canadian GAAP purposes, Petrofund applied the fair value
method of accounting for all derivative transactions. 

U.S. GAAP
hedge accounting treatment allows unrealized gains and losses to be deferred in other comprehensive income (for the effective portion of the hedge) until such time as the
forecasted transaction occurs and requires that an entity formally document, designate and assess effectiveness of derivative instruments that receive hedge accounting treatment. For 2005 and 2004 the
Trust has elected to use fair value accounting for its derivative instruments for U.S. GAAP and the change in fair value of these contracts has been reported in income. 

	(d)
	Prior
to January 1, 2003, for Canadian GAAP purposes, compensation expense for options granted under the Unit Incentive Plan was measured based on the intrinsic value of the
award at the grant date. For the years ended December 31, 2004, 2003 and 2002 pro forma disclosures are included in the notes to the financial statements of the impact on net income and
net income per Trust unit had the Trust accounted for compensation expense based on the fair value of options granted during 2002. No options have been granted since 2002. Effective January 1,
2003, the Trust accounts for compensation expense for options awarded on or after January 1, 2003, based on the fair value method of accounting. 

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

	(e)
	On
January 1, 2003 Petrofund adopted the U.S. reporting requirements for ARO through a cumulative effect adjustment in the Consolidated Statement of Operations.
Petrofund adopted the equivalent Canadian standard for ARO on January 1, 2004. These standards are consistent except for the method of implementation and the adoption date. 

10

 

	(f)
	The
Trust presents oil and natural gas sales and royalty amounts gross in the Consolidated Statement of Operations. These line items would be combined and presented net in a statement
of operations prepared in accordance with U.S. GAAP. This difference does not result in an adjustment to the financial results as reported under Canadian GAAP.

	(g)
	An
income statement prepared in accordance with U.S. GAAP segregates operating and non-operating expenses in the statement of operations. Management fees, financing
costs and internalization of management contracts would be presented in the non-operating section of the statement of operations. This difference does not result in an adjustment to the
financial results as reported under Canadian GAAP.

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

Under
U.S. GAAP, the Trust's bank overdraft would be presented as a financial activity rather than as a component of cash. Therefore, cash used in financing activities under U.S. GAAP
would be $39,657 for the nine months ended September 30, 2005. 

The
net change in non-cash operating working capital balances for the nine months ended is comprised of the following: 

	 
	 	Nine Months Ended

September 30,
	 
	(000's)
 
	 
	 	2005
	 	2004
	 
	Accounts receivable	 	$	(8,313	)	$	(3,980	)
	Prepaids and deposits	 	 	(5,744	)	 	(1,299	)
	Accounts payable and accrued liabilities	 	 	(25,459	)	 	30,076	 
	 	 	
	 	
	 
	 	 	$	(39,516	)	$	24,797	 
	 	 	
	 	
	 

	(i)
	In
2004 and 2005, the FASB issued new and revised standards, all of which were assessed by Management to be not applicable to the Trust with the exception that tin
December 2004, the FASB issued SFAS No. 123R, "Share Based Payments", which addresses the issue of measuring compensation cost associated with Share Based Payment plans. This
statement requires that all such plans be measured at fair value using an option pricing model whereas previously certain plans could be measured using either a fair value method or an intrinsic value
method. The revision is intended to increase the consistency and comparability of financial results by only allowing one method of application. This revised standard is effective for the Trust's 2006
fiscal year. Management is in the process of evaluating the impact of this standard.

	(j)
	Under
U.S. GAAP, the number of authorized and issued Trust units and Exchangeable Shares would be disclosed on the face of the balance sheet.

	(k)
	Under
U.S. GAAP, redeemable equity instruments which are not mandatorily redeemable at a specific or determinable date must be presented as temporary equity and carried on the
balance sheet at redemption value. Changes in redemption value between periods are charged or credited to retained earnings. The Trust has concluded that the restrictions on redemption are not
substantive and the trust units must be presented as temporary equity and carried on the balance sheet at their redemption value.

	(l)
	Additional
accounts payable and accrued liability disclosure include: 

Accounts Payable and Accrued Liabilities

	(000's)
 
	 	September 30,

2005
	 	December 31,

2004

	Capital accrual	 	$	12,117	 	$	16,850
	Joint venture and trade payables	 	 	5,565	 	 	22,165
	Other	 	 	24,370	 	 	21,946
	 	 	
	 	

	Total	 	$	42,052	 	$	60,961
	 	 	
	 	

11

 

The
application of U.S. GAAP would have the following effects on net income as reported: 

	 
	 	Nine Months Ended

September 30,
	 
	($ Cdn (000's) other than per unit amounts)
 
	 
	 	2005
	 	2004
	 
	Net income as reported in consolidated statement of operations	 	$	110,645	 	$	23,593	 
	Adjustments:	 	 	 	 	 	 	 
	 	Realized/(unrealized) loss on derivatives	 	 	—	 	 	6,774	 
	 	Compensation expense	 	 	(633	)	 	1,493	 
	 	Depletion and depreciation	 	 	12,167	 	 	10,938	 
	 	Future income taxes	 	 	(4,258	)	 	(6,233	)
	 	 	
	 	
	 
	Net income, U.S. GAAP	 	$	117,921	 	$	36,565	 
	 	 	
	 	
	 
	Net income per unit, U.S. GAAP	 	 	 	 	 	 	 
	 	Basic	 	$	1.15	 	$	0.43	 
	 	Diluted	 	$	1.15	 	$	0.43	 

The
application of U.S. GAAP would have the following effects on Petrofund's consolidated balance sheet as at September 30, 2005: 

	(000's)
 
	 	As

reported
	 	Decrease
	 	U.S.

GAAP
	 
	As at September 30, 2005	 	 	 	 	 	 	 	 	 	 
	Oil and gas royalty and property interests, net	 	$	1,297,522	 	$	(149,051	)	$	1,148,471	 
	Future income taxes	 	 	87,658	 	 	(42,734	)	 	44,924	 
	Temporary equity	 	 	—	 	 	2,397,156	 	 	2,397,156	 
	Unitholders' equity	 	 	1,084,746	 	 	(2,503,473	)	 	(1,418,727	)

The
following presents the consolidated statement of unitholders' equity and temporary equity for the year ended December 31, 2004 and the nine months ended September 30, 2005, under
U.S. GAAP. 

	(000's)
 
	 	Accumulated Distributions
	 	Retained Earnings

(Deficit)
	 	Total Unitholders' Equity

(Deficiency)
	 	Temporary Equity
	 
	December 31, 2003	 	$	(581,155	)	$	(282,083	)	$	(863,238	)	$	1,383,465	 
	Units issued	 	 	—	 	 	—	 	 	—	 	 	452,807	 
	Redemption of exchangeable shares	 	 	(1,803	)	 	—	 	 	(1,803	)	 	—	 
	Commission & issue costs	 	 	—	 	 	—	 	 	—	 	 	—	 
	Options excercised	 	 	—	 	 	—	 	 	—	 	 	3,771	 
	Unit purchase plan	 	 	—	 	 	—	 	 	—	 	 	70	 
	Unit incentive plan	 	 	—	 	 	—	 	 	—	 	 	638	 
	Net income	 	 	—	 	 	90,190	 	 	90,190	 	 	—	 
	Stock based compensation expense	 	 	—	 	 	—	 	 	—	 	 	(1,991	)
	Distribution accruing to unitholders	 	 	(151,609	)	 	—	 	 	(151,609	)	 	—	 
	Change in redemption value	 	 	—	 	 	270,724	 	 	270,724	 	 	(270,724	)
	 	 	
	 	
	 	
	 	
	 
	December 31, 2004	 	 	(734,567	)	 	78,831	 	 	(655,736	)	 	1,568,036	 
	 	 	
	 	
	 	
	 	
	 
	Units issued	 	 	—	 	 	—	 	 	—	 	 	75,738	 
	Redemption of exchangeable shares	 	 	(904	)	 	—	 	 	(904	)	 	—	 
	Commission & issue costs	 	 	—	 	 	—	 	 	—	 	 	(4,296	)
	Options exercised	 	 	—	 	 	—	 	 	—	 	 	5,751	 
	Unit purchase plan	 	 	—	 	 	—	 	 	—	 	 	79	 
	Unit incentive plan	 	 	—	 	 	—	 	 	—	 	 	602	 
	Net income	 	 	—	 	 	117,921	 	 	117,921	 	 	—	 
	Stock based compensation expense	 	 	—	 	 	—	 	 	—	 	 	633	 
	Distribution accruing to unitholders	 	 	(129,395	)	 	—	 	 	(129,395	)	 	—	 
	Change in redemption value	 	 	—	 	 	(750,613	)	 	(750,613	)	 	750,613	 
	 	 	
	 	
	 	
	 	
	 
	September 30, 2005	 	$	(864,866	)	$	(553,861	)	$	(1,418,727	)	$	2,397,156	 
	 	 	
	 	
	 	
	 	
	 

12

QuickLinks

EXHIBIT 4.4

PETROFUND ENERGY TRUST CONSOLIDATED BALANCE SHEET (thousands of dollars) (unaudited)

CONSOLIDATED STATEMENT OF OPERATIONS AND ACCUMULATED EARNINGS (thousands of dollars, except per unit amounts) (unaudited)

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

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS September 30, 2005 and 2004 (unaudited) (tabular amounts in thousands of dollars, except unit and per unit amounts)QuickLinks
 -- Click here to rapidly navigate through this document
  

 
 

EXHIBIT 4.7  
  

ULTIMA ENERGY TRUST

CONSOLIDATED FINANCIAL STATEMENTS

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

C-98

 
  
 

    REPORT OF INDEPENDENT REGISTERED CHARTERED ACCOUNTANTS    
    

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

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

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

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

	Calgary, Alberta

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

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

Independent Registered Chartered Accountants

	 

ULTIMA ENERGY TRUST  

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

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

	Calgary, Alberta

April 30, 2004	 	(signed) Deloitte & Touche LLP

Independent Registered Chartered Accountants

C-99

 
 
 

ULTIMA ENERGY TRUST    
    
    CONSOLIDATED BALANCE SHEET    
    
    (thousands of dollars)    
    

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

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

C-100

 
  
 

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

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

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

C-101

 
  
 

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

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

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

C-102

  

 
 

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

    

1.     Basis of Presentation  

	a.
	Structure

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

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

2.     Significant Accounting Policies  

	a.
	Joint
Interests 

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

	b.
	Oil
and Natural Gas Properties 

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

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

	c.
	Depletion
and Amortization 

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

C-103

 

	d.
	Future
Site Restoration 

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

	e.
	Ceiling
Test 

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

	f.
	Goodwill 

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

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

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

	h.
	Hedging
Contracts 

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

	i.
	Unit-Based
Compensation Plan 

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

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

C-104

 

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

	j.
	Income
Taxes 

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

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

	k.
	Weighted
Average Number of Units Outstanding 

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

	 
	 	2003
	 	2002

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

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

	l.
	Change
in Accounting Policies

	1.
	Capital
Assets 

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

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

C-105

 

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

	

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

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

	2.
	Unit
Based Compensation Plan 

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

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

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

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

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

	3.
	Disclosure
of Guarantees 

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

C-106

 

3.     Cash Distributions to Unitholders  

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

4.     Capital Assets  

	Oil and natural gas properties 
	 	Cost
	 	Accumulated

Depletion and

Amortization
	 	Net Book Value

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

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

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

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

5.     Trioco Acquisition  

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

C-107

 

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

6.     Weyburn Limited Partnership and Deferred Capital Obligation  

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

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

The
redemption price and consideration paid was as follows: 

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

	Total net assets	 	$	85,773
	 	 	

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

	Total purchase price	 	$	85,773
	 	 	

C-108

 

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

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

7.     Reclamation Fund  

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

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

8.     Long-Term Bank Debt  

	 
	 	2003
	 	2002

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

	 	 	$	45,007	 	$	55,358
	 	 	
	 	

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

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

C-109

 

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

9.     Unitholders' Capital  

	a.
	Authorized 

Unlimited
number of trust units 

	b.
	Issued

	 
	 	2003
	 	2002

	 
	 	Number of Trust Units
	 	Amount
	 	Number of Trust Units
	 	Amount

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

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

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

	Date
 
	 	Number of

Trust Units
	 	Net Proceeds

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

	 	 	23,000,000	 	$	115,758
	 	 	
	 	

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

C-110

 

	c.
	Trust
Unit Options 

	 
	 	2003
	 	2002

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

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

	Ending Balance	 	—	 	 	—	 	50,000	 	$	3.38
	 	 	
	 	
	 	
	 	

No
further options have been issued pursuant to this plan. 

	d.
	Trust
Unit Rights Incentive Plan 

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

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

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

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

	 
	 	2003
	 	2002
	 
	 
	 	Number of

Rights
	 	Weighted

Average

Exercise

Price
	 	Number of

Rights
	 	Weighted

Average

Exercise

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

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

	Exercise

Price at

Grant Date
 
	 	Adjusted

Exercise Price
	 	Number of

Rights

Outstanding
	 	Remaining

Contractual Life

of Rights (years)
	 	Number of

Rights

Exercisable

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

	 	 	 	 	 	2,007,669	 	 	 	397,003
	 	 	 	 	 	
	 	 	 	

C-111

 

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

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

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

	(Thousands of dollars)
	 	2003
	 	2002

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

10.     Related Party Transactions  

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

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

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

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

C-112

 

11.     Financial Instruments  

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

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

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

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

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

(US$/bbl
except as indicated) 

	Daily Quantity
 
	 	Fixed

Price
	 	Sold

Call
	 	Purchased

Put
	 	Sold

Put
	 	Term

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

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

	Daily Quantity
 
	 	Fixed Price

$Cdn/GJ
	 	Term

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

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

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

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

	Daily Quantity
 
	 	Fixed Price
	 	Sold call
	 	Sold put
	 	Purchased put
	 	Term

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

C-113

 

Natural Gas Hedges

	Daily Quantity
 
	 	Fixed Price

$/GJ
	 	Term

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

	

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

For clarity:

	If WTI Price is

(US$/bbl)
 
	 	Ultima receives

(US$/bbl)

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

12.     Contingencies and Commitments  

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

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

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

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

13.     Income Taxes  

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

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

C-114

 

The
future income tax liability includes the following temporary differences: 

	 
	 	2003

	Oil and natural gas properties	 	$	14,398
	 	 	

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

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

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

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

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

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

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

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

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

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

C-115

 

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

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

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

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

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

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

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

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

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

C-116

 

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

	 
	 	As reported
	 	Increase

(Decrease)
	 	U.S. GAAP

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

15.     Subsequent Event  

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

C-117

QuickLinks

EXHIBIT 4.7

REPORT OF INDEPENDENT REGISTERED CHARTERED ACCOUNTANTS

ULTIMA ENERGY TRUST CONSOLIDATED BALANCE SHEET (thousands of dollars)

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

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

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

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