Petrofund Energy Trust F10 Registration of securities | PTF 30 Nov 05

QuickLinks -- Click here to rapidly navigate through this document

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.

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.

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.

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

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:

	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

(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

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	)

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	)

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.

(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)	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

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)		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

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)

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