EXHIBIT 3
Audited Consolidated Financial Statements
dated December 31, 2003 and 2002
and for the years ended
December 31, 2003, 2002 and 2001
MANAGEMENT'S REPORT
These financial statements are the responsibility of the management of Petrofund
Corp. ("Management"). They have been prepared in accordance with Canadian
generally accepted accounting principles using Management's best estimates and
judgments, where appropriate.
Management is responsible for the reliability and integrity of the consolidated
financial statements, notes to the consolidated financial statements and other
financial information contained in this report. Estimates are sometimes
necessary in the preparation of these statements because a precise determination
of some assets and liabilities depends on future events. Management has based
these estimates on careful judgments and believes they are properly reflected in
the accompanying financial statements. Management is also responsible for
maintaining a system of internal controls designed to provide reasonable
assurance that assets are safeguarded and that accounting systems provide
timely, accurate and reliable financial information.
The Board of Directors of Petrofund is responsible for ensuring that Management
fulfils its responsibilities for financial reporting and internal controls. The
Board meets with Management to ensure that Management's responsibilities are
fulfilled, to review financial statements and to recommend approval of the
financial statements. An independent auditor appointed by the unitholders,
Deloitte & Touche LLP, has audited the financial statements of Petrofund in
accordance with Canadian generally accepted auditing standards and has provided
an independent professional opinion.
Jeffery E. Errico Vince Moyer
President Senior Vice-President, Finance
& Chief Executive Officer & Chief Financial Officer
Calgary, Alberta
February 6, 2004
AUDITORS' REPORT
To the Unitholders of Petrofund Energy Trust:
We have audited the consolidated balance sheet of Petrofund Energy Trust (an
Ontario open-ended investment trust) as at December 31, 2003 and 2002 and the
consolidated statements of operations, unitholder's equity, and cash flows for
the years then ended. These financial statements are the responsibility of the
management of Petrofund Corp. 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 Petrofund Energy 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.
The consolidated financial statements of Petrofund Energy Trust for the year
ended December 31, 2001, were audited by other auditors who have ceased
operations. Those auditors expressed an opinion without reservation on those
financial statements in their report dated February 14, 2002.
Deloitte & Touche LLP
Chartered Accountants
Calgary, Alberta, Canada
February 6, 2004
2
THIS AUDITOR'S REPORT IS A COPY OF THE REPORT PREVIOUSLY ISSUED BY ARTHUR
ANDERSEN LLP AND HAS NOT BEEN REISSUED
AUDITORS' REPORT
To the Unitholders of NCE Petrofund:
We have audited the consolidated balance sheet of NCE Petrofund (an Ontario
open-ended investment trust) as at December 31, 2001 and 2002 and the
consolidated statements of operations, unitholders' equity, cash flows and
distributions accruing to unitholders for each of the years in the three-year
period ended December 31, 2001. These financial statements are the
responsibility of the management of NCE Petrofund Management Corp. 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 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 evaluation the overall financial statement presentation.
In our opinion, these consolidated financial statements present fairly, in all
material respects, the financial position of NCE Petrofund as at December 31,
2001 and 2000 and the results of its operations and its cash flows for each of
the years in the three-year period ended December 31, 2001 in accordance with
Canadian generally accepted accounting principles.
Calgary, Alberta Arthur Anderson LLP
February 15, 2002 Chartered Accountants
3
Consolidated Balance Sheet
(thousands of dollars)
As at December 31, 2003 2002
- --------------------------------------------------------------------------- ----------------------------
Assets
Current assets
Cash $ 2,182 $ -
Accounts receivable 48,268 41,953
Due from affiliates - 164
Prepaid expenses 10,036 10,090
- --------------------------------------------------------------------------- ----------------------------
Total current assets 60,486 52,207
Reclamation and abandonment reserve (Note 7) 3,779 3,001
Oil and gas royalty and property interests,
at cost less accumulated depletion and depreciation
of $468,208 (2002 - $354,309) (Notes 2 and 3) 879,633 835,366
- --------------------------------------------------------------------------- ----------------------------
$ 943,898 $ 890,574
- --------------------------------------------------------------------------- ----------------------------
Liabilities and unitholders' equity
Current liabilities
Bank overdraft $ - $ 1,572
Accounts payable and accrued liabilities 36,684 22,007
Payable to affiliates (Note 4) - 2,168
Current portion of capital lease obligations (Note 6) 356 3,304
Distributions payable to Unitholders 53,452 30,065
- --------------------------------------------------------------------------- ----------------------------
Total current liabilities 90,492 59,116
Long-term debt (Note 5) 109,707 212,253
Capital lease obligations (Note 6) 608 6,965
Future income taxes (Notes 2 and 15) 77,005 116,845
Accrued reclamation and abandonment costs 16,846 15,298
- --------------------------------------------------------------------------- ----------------------------
Total liabilities 294,658 410,477
Unitholders' equity (Notes 8 and 9) 649,240 480,097
- --------------------------------------------------------------------------- ----------------------------
$ 943,898 $ 890,574
- --------------------------------------------------------------------------- ----------------------------
Signed on behalf of Petrofund Energy Trust by Petrofund Corp.:
Jeffery E. Errico, Director James E. Allard, Director
The accompanying notes to consolidated financial statements are an integral part
of this consolidated balance sheet.
4
Consolidated Statement of Operations
(thousands of dollars except per unit amounts)
For the years ended December 31, 2003 2002 2001
- ------------------------------------------------------------------------ -------------------- -------------------
Revenues
Oil and gas sales $ 393,109 $ 270,669 $ 244,512
Royalties, net of incentives (84,804) (50,427) (54,746)
- ------------------------------------------------------------------------ -------------------- -------------------
308,305 220,242 189,766
- ------------------------------------------------------------------------ -------------------- -------------------
Expenses
Lease operating 91,251 74,774 48,237
Management fee (Note 4) - 4,728 5,307
Interest on long-term debt (Note 5) 8,748 8,291 7,806
General and administrative (Note 4) 13,047 15,514 14,436
Capital taxes 2,454 2,137 1,719
Depletion and depreciation 113,899 98,777 68,453
Provision for reclamation and abandonment 6,199 5,856 3,680
Internalization of management contract (Note 9) 30,850 - -
- ------------------------------------------------------------------------ -------------------- -------------------
266,448 210,077 149,638
- ------------------------------------------------------------------------ -------------------- -------------------
Income before provision for income taxes 41,857 10,165 40,128
- ------------------------------------------------------------------------ -------------------- -------------------
Provision for (recovery of) income taxes (Note 15)
Current 569 38 1,701
Future (44,516) (14,252) (15,561)
- ------------------------------------------------------------------------ -------------------- -------------------
(43,947) (14,214) (13,860)
- ------------------------------------------------------------------------ -------------------- -------------------
Net income $ 85,804 $ 24,379 $ 53,988
- ------------------------------------------------------------------------ -------------------- -------------------
Net income per trust unit (Notes 2 and 16)
Basic $ 1.41 $ 0.49 $ 1.71
Diluted $ 1.40 $ 0.49 $ 1.71
The accompanying notes to consolidated financial statements are an integral part
of these consolidated statements.
5
Consolidated Statement Of Unitholders' Equity
(thousands of dollars)
For the years ended December 31, 2003 2002 2001
- ---------------------------------------------------------------------------- ------------------ ----------------- --------------
Balance, beginning of year $ 480,097 $ 398,702 $ 136,812
Units issued, net of issue costs (Note 8) 226,325 154,460 318,548
Exchangeable shares issued/ converted to Trust units (Note 10) 10,518 - -
Redemption of exchangeable shares (Note 10) (2,792) - -
Net income 85,804 24,379 53,988
Distributions accruing to Unitholders (Note 12) (150,712) (97,444) (110,646)
- ---------------------------------------------------------------------------- ------------------ ----------------- ------------
Balance, end of year $ 649,240 $ 480,097 $ 398,702
- ---------------------------------------------------------------------------- ------------------ ----------------- -------------
The accompanying notes to consolidated financial statements are an integral part
of these consolidated statements.
6
Consolidated Statement of Cash Flows
(thousands of dollars except per unit amounts)
For the years ended December 31, 2003 2002 2001
- -------------------------------------------------------------------------- ------------------ ----------------------
Cash provided by (used in):
Operating activities
Net income $ 85,804 $ 24,379 $ 53,988
Add items not affecting cash:
Depletion and depreciation 113,899 98,777 68,453
Provision for reclamation and abandonment 6,199 5,856 3,680
Future income taxes (44,516) (14,252) (15,561)
Actual abandonment costs incurred (Note 7) (4,651) (2,190) (384)
Internalization of management contract (Note 9) 30,850 - -
- -------------------------------------------------------------------------- ------------------ ----------------------
Cash flow 187,585 112,570 110,176
Net change in non-cash operating working capital balances 6,410 (30,938) 18,334
- -------------------------------------------------------------------------- ------------------ ----------------------
Cash provided by operating activities 193,995 81,632 128,510
- -------------------------------------------------------------------------- ------------------ ----------------------
Financing activities
Bank loan (102,546) 83,470 14,216
Distributions paid (127,325) (85,218) (126,883)
Redemption of exchangeable shares (2,792) - -
Capital lease repayments (9,305) (11,366) (2,629)
Issuance of trust units (Note 8) 214,002 55,821 161,409
Advances to affiliates (Note 4) - 948 -
- -------------------------------------------------------------------------- ------------------ ----------------------
Cash provided by (used in) financing activities (27,966) 43,655 46,113
- -------------------------------------------------------------------------- ------------------ ----------------------
Investing activities
Reclamation and abandonment reserve (Note 7) (776) (706) (447)
Acquisition of property interests (186,956) (158,516) (177,729)
Proceeds on disposition of properties 33,466 30,019 3,736
Cash acquired on acquisition (Note 3b) - 427 -
Internalization of management contract (Note 9) (8,009) - -
- -------------------------------------------------------------------------- ------------------ ----------------------
Cash used in investing activities (162,275) (128,776) (174,440)
- -------------------------------------------------------------------------- ------------------ ----------------------
Net change in cash 3,754 (3,489) 183
Cash (bank overdraft), beginning of year (1,572) 1,917 1,734
- -------------------------------------------------------------------------- ------------------ ----------------------
Cash (bank overdraft), end of year $ 2,182 $ (1,572) $ 1,917
- -------------------------------------------------------------------------- ------------------ ----------------------
Interest paid during the year $ 8,885 $ 8,016 $ 7,806
- -------------------------------------------------------------------------- ------------------ ----------------------
Income taxes paid during the year $ 842 $ 1,281 $ 1,065
- -------------------------------------------------------------------------- ------------------ ----------------------
The accompanying notes to consolidated financial statements are an integral part
of these consolidated statements.
7
Notes to consolidated financial statements
December 31, 2003, 2002 and 2001
1. ORGANIZATION
Petrofund Energy Trust ("Petrofund" or the "Trust") is an open-ended investment
trust created under the laws of the Province of Ontario pursuant to a trust
indenture, as amended from time to time (the "Trust Indenture"), between
Petrofund Corp. ("PC") and Computershare Trust Company of Canada (the
"Trustee"). Active operations commenced March 3, 1989. The beneficiaries of the
Trust are the holders of the trust units ("Unitholders").
PC, a wholly-owned subsidiary of the Trust, acquires oil and gas properties for
its own account and sells a royalty interest (the "Royalty") to the Trust. The
Royalty acquired from PC effectively transfers substantially all of the economic
interest in the oil and gas properties to the Trust. The Trust is entitled to
99% of the production revenue from properties purchased by PC, less operating
costs, general and administrative expenses, management fees (prior to 2003),
debt service charges (including principal and interest) and taxes payable by PC.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The consolidated financial statements have been prepared by the management of PC
following Canadian generally accepted accounting principles. The preparation of
financial statements requires management to make estimates and assumptions that
affect the reported amounts of assets and liabilities and disclosures of
contingencies at the date of the financial statements and the reported amounts
of revenues and expenses during the reporting period. Actual results could
differ from those estimated. The following significant accounting policies are
presented to assist the reader in evaluating these consolidated financial
statements.
(a) Basis of consolidation
The consolidated financial statements include the accounts of the Trust and its
wholly-owned subsidiaries, PC, 1518274 Ontario Ltd., NCE Management Services
Inc. ("NMSI"), which employed all of the personnel who provided services to the
Trust, and NCE Petrofund Management Corp. ("NCEP Management", the "Previous
Manager") collectively, the "Subsidiaries". NMSI and NCEP Management were
acquired to effect the internalization of management and the shares of 1518274
Ontario Limited are exchangeable into trust units (see Notes 9 and 10).
(b) Oil and gas royalty and property interests
Oil and gas royalty and property interests are accounted for using the full cost
method of accounting whereby all costs of acquiring and developing oil and gas
royalty and property interests and equipment are capitalized. General and
administrative costs and interest are not capitalized.
The provision for depletion and depreciation and the provision for site
reclamation and abandonment costs are computed using the unit-of-production
method based on the estimated gross proven oil and gas reserves. Proceeds on
sale or disposition of oil and gas royalty and property interests are credited
to oil and gas royalty and property interests, unless this results in a change
in the depletion and depreciation rate by 20% or more, in which case a gain or
loss is recognized in the consolidated statement of operations. The provision
for reclamation and abandonment costs is accumulated as a long-term liability,
which is reduced as actual expenditures are made.
The carrying value of the oil and gas royalty and property interests, net of
accumulated depletion and depreciation, accrued reclamation and abandonment
costs and future income taxes is limited to an amount equal to the estimated
future net revenue, net of production-related general and administrative costs,
reclamation and abandonment costs, and income taxes. Future net revenue was
calculated using year end oil and gas prices and costs.
Effective January 1, 2004, the carrying value of the oil and gas royalty and
property interests is limited to their fair value determined by the expected
discounted future net revenue from the properties.
(c) Distributions payable to Unitholders
Distributions payable to Unitholders are equal to amounts received or receivable
by the Trust on the cash distribution date. Income earned, but not received, is
distributed on the cash distribution date following receipt.
(d) Future 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 Subsidiaries and their respective tax bases, 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 acquisitions result in future
income tax assets or liabilities.
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 the Unitholders. As
the Trust distributes all of its taxable income to the Unitholders and meets the
requirements of the Income Tax Act (Canada) applicable to the Trust, no
provision for future income taxes in the Trust has been made.
(e) Net income per Trust unit
Basic net income per Trust unit is computed by dividing net income by the
weighted average number of Trust units outstanding for the period. Diluted per
unit amounts reflect the potential dilution that would occur if options to issue
Trust units were exercised and Trust units were issued. The treasury stock
method is used to determine the effect of dilutive instruments.
(f) Hedging activity
The Trust uses derivative instruments to reduce its exposure to commodity price
fluctuations. Gains and losses on contracts, all of which constitute effective
hedges, are deferred and recognized as a component of the price of the related
transaction.
(g) Trust unit incentive plan
A Trust Unit Incentive Plan (the "Unit Incentive Plan") was established
authorizing the issuance of options to acquire Trust units to directors, senior
officers, employees and consultants of NCEP, Management, NCE Petrofund Advisory
Corp., NMSI and certain other related parties, all of whom are deemed to be
employees of the Trust. No options have been issued since 2002.
The Trust has elected to prospectively adopt amendments to the recommendations
of the CICA on accounting for stock based compensation in accordance with the
transitional provisions contained therein. Under the amended recommendations,
the Trust must account for compensation expense based on the fair value of the
options at the grant date. As the Trust has not granted any options since
December 31, 2002, this change in accounting policy has no impact on the
consolidated financial statements.
For options granted in 2002, the Trust has elected to continue accounting for
compensation expense based on the intrinsic value of the options at the grant
date and disclose pro forma net income and pro forma net income per Trust unit
as if the fair value method had been adopted retroactively. The exercise price
of options granted under the Unit Incentive Plan may be reduced in future
periods in accordance with the terms of the Unit Incentive Plan. The amount of
the reduction cannot be reasonably determined as it is dependent upon a number
of factors including, but not limited to, future prices received on the sale of
oil and natural gas, future production of oil and natural gas, and the
determination of the amount to be withheld from future distributions to fund
capital expenditures. Therefore, it is not possible to determine a fair value
for the options granted under the Unit Incentive Plan and compensation expense
has been determined based on the excess of the unit price over the reduced
exercise price at the date of the financial statements and recognized in income
over the vesting period of the options with a corresponding increase or decrease
in contributed surplus. 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. The compensation
expense under this method in 2003 for the options issued in 2002 is $2.0
million. Net income would have been reduced by this amount and net income per
Trust unit would have decreased by $0.03. For 2002, net income would have been
reduced by $60,000 with a negligible impact on net income per Trust unit.
Consideration paid upon the exercise of the options together with any amount
previously recognized in contributed surplus is recorded as an increase in
unitholders' capital.
3. ACQUISITIONS
(a) Solaris Oil & Gas Inc.
On February 7, 2003, PC acquired 100% of the outstanding common shares of
Solaris Oil & Gas Inc. for $7.4 million in cash and assumed $1.2 million of debt
including negative working capital and the outstanding bank loan.
The acquisition was accounted for using the purchase method. A summary of the
net assets acquired is a follows:
$000's
-------------------------------------------
Working capital $ (813)
Oil and gas properties 13,219
Bank loan (370)
Future income taxes (4,676)
-------------------------------------------
$ 7,360
-------------------------------------------
(b) NCE Energy Trust
On May 30, 2002, Petrofund Energy Trust acquired NCE Energy Trust for 0.2325 of
a Trust unit for each Trust unit on a tax-free rollover basis. The value
assigned to the Trust units of $13.024 per unit issued on the acquisition was
based on the average market value of the Trust units five days before and after
the acquisition was announced.
The acquisition was accounted for using the purchase method. A summary of the
net assets acquired is as follows:
$000's
---------------------------------------
Working capital $ (39,518)
Oil and gas properties 165,254
Future income taxes (27,097)
---------------------------------------
$ 98,639
---------------------------------------
Prior to the acquisition, Petrofund advanced $37.3 million to NCE Energy Trust
to pay down the bank debt of NCE Energy Trust.
(c) Magin Energy Inc. ("Magin")
On June 25, 2001, PC acquired 93.6% of the outstanding common shares of Magin
and on July 3, 2001 acquired the remaining shares. Magin was amalgamated into PC
on July 3, 2001.
In total, PC acquired 38,338,535 Magin common shares for $58.6 million in cash,
8.5 million Trust units with a deemed value of $18.56 per unit and the
assumption of $43.7 million of debt including negative working capital, the
outstanding bank loan and capital leases. In addition, other transaction costs
of $11.8 million were incurred.
The acquisition was accounted for using the purchase method. A summary of the
net assets acquired is as follows:
$000's
----------------------------------------------
Working capital $ (4,749)
Oil and gas properties 381,043
Bank loan (21,569)
Capital leases (17,359)
Future income taxes (109,790)
----------------------------------------------
$ 227,576
----------------------------------------------
4. RELATED PARTY TRANSACTIONS
(a) Management, advisory and administration agreement
PC, NCEP Management, the Previous Manager, and the Trust had entered into
an agreement which was amended from time to time, whereby the Previous
Manager was to provide management, advisory and administrative services to
PC and the Trust. During 2002 the Previous Manager was paid a management
fee equal to 3.25% of net operating income plus Alberta Royalty Credit
(2001-3.75%). In addition the Previous Manager received an investment fee
of 1.5% (1.75% prior to January 1, 2002) of the purchase cost of all
properties purchased by PC other than replacement properties, and a
disposition fee equal to 1.25% (1.5% prior to January 1, 2002) of the sale
price of properties sold. During 2002, the Previous Manager received a
management fee from PC of $4.7 million (2001 - $5.3 million). In addition,
the Previous Manager received investment fees of $1.3 million (2001 - $5.2
million), which were capitalized as part of the acquisitions, and
disposition fees of $116,000 (2001 - $3,000), which reduced the proceeds of
disposition. No management fees have been charged directly to the Trust.
Due to the internalization of management, no fees were payable in 2003.
(See Note 9)
Under the terms of the agreement, the Previous Manager was entitled to be
reimbursed by PC for general and administrative expenses. In any year, PC
was to reimburse the Previous Manager no less than $240,000 and no more
than 5% of gross production revenue for general and administrative
expenses. To the extent that general and administrative expenses exceed 5%
of gross production revenue, PC was entitled to set off and deduct the
excess from its liability to pay management fees to the Previous Manager.
(b) Management agreement
The Previous Manager had entered into an agreement with NMSI to provide oil
and gas investment, consulting, administrative and management services to
PC. An officer and director of the Previous Manager is the sole beneficial
shareholder of NMSI. During 2002 PC paid NMSI $11.7 million (2001 - $9.3
million) for accounting and administrative services, which is included in
general and administrative expenses and $838,000 (2001 -
$1.4 million) for project sourcing and evaluation services, which have been
capitalized to oil and gas properties. In addition, PC reimbursed NMSI
$300,000 (2001 - $600,000) for marketing and other related equity issue
costs. No amounts for these services have been charged directly to the
Trust. The amounts for general and administrative expenses paid to NMSI are
subject to the same limitations noted for the Previous Manager in (a)
above. Due to the internalization of management no amounts were paid to
NMSI in 2003.
5. LONG-TERM DEBT
Under the loan agreements, PC has a revolving working capital operating facility
of $25 million and a syndicated facility of $240 million. Interest on the
working capital loan is at prime and interest on the syndicated facility varies
with PC's debt to cash flow ratio from prime to prime plus 75 basis points or,
at the Trust's option, banker's acceptances rates plus stamping fees. As at
December 31, 2003, there was no amount outstanding under the working capital
facility and $110 million outstanding under the syndicated facility.
The revolving period on the syndicated facility ends on May 28, 2004, 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, Petrofund 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 in the amount of $350 million
pursuant to which a Canadian chartered bank (the "Lender"), as principal and as
agent for the other lender, 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 Bankers' Acceptances,
resulting in a reduction in the stated bank loan interest rates.
6. CAPITAL LEASE OBLIGATIONS
The future minimum lease payments under the capital leases are as follows:
$000's
- ----------------------------------------------------------------------------
2004 $ 423
2005 621
- ----------------------------------------------------------------------------
Total minimum lease payments 1,044
Less imputed interest at rates ranging from 7.37% to 8.425% (80)
- ----------------------------------------------------------------------------
Obligation under capital leases 964
Current portion (356)
- ----------------------------------------------------------------------------
Long-term portion $ 608
- ----------------------------------------------------------------------------
7. RECLAMATION AND ABANDONMENT RESERVE
PC maintains a cash reserve to finance large and unusual oil and gas property
reclamation and abandonment costs by withholding distributions accruing to
Unitholders. At December 31, 2003, the cash reserve was $3.8 million (2002 -
$3.0 million, 2001 - $2.1 million). In 2003, PC increased the cash reserve by
withholding $776,000 (2002 - $706,000, 2001 - $447,000) from distributions
accruing to Unitholders.
In addition, routine ongoing reclamation and abandonment costs of $4.7 million
in 2003 (2002 - $2.2 million, 2001 - $384,000) were incurred and deducted from
distributions accruing to Unitholders. 8.
TRUST UNITS
Number
Authorized: unlimited number of trust units of Units $000's
- ----------------------------------------------------------------------------
Issued
December 31, 2000 21,914,079 $ 321,344
Issued for cash 11,183,334 167,350
Issued for Magin acquisition (Note 3(c)) 8,464,399 157,139
Commissions and issue costs - (11,781)
Options exercised 341,305 5,620
Unit purchase plan 13,279 220
- ----------------------------------------------------------------------------
December 31, 2001 41,916,396 639,892
Issued for cash 4,600,000 59,800
Issued for NCE Energy acquisition (Note 3(b)) 7,573,874 98,639
Commissions and issue costs - (4,190)
Options exercised 7,966 85
Unit purchase plan 10,184 126
- ----------------------------------------------------------------------------
December 31, 2002 54,108,420 794,352
Issued for cash 15,800,000 204,440
Issued for internalization of management
contract (Note 9) 100,244 1,123
Exchangeable shares converted 1,000,000 11,200
Commissions and issue costs - (11,001)
Options exercised 1,673,404 20,474
Unit purchase plan 6,509 89
- ----------------------------------------------------------------------------
December 31, 2003 72,688,577 $1,020,677
============================================================================
The Trust has a Distribution Reinvestment and Unit Purchase Plan (the "Plan")
for Canadian residents. Under the terms of the Plan, Unitholders can elect,
firstly, to reinvest their cash distributions and obtain either newly issued
units of the Trust directly from the Trust or previously issued units of the
Trust purchased in the open market and, secondly, to purchase for cash newly
issued units directly from the Trust.
For the years ended December 31, 2003 2002 2001
- ----------------------------------------------------------------------------------------------------------
Distributions reinvested to acquire
previously issued units (000's) $ 4,095 $ 3,387 $ 6,979
Price per unit $ 13.20 $ 12.15 $ 16.61
Number of units acquired 310,276 278,797 420,100
Distributions reinvested
to acquire newly issued units (000's) $ 89 $ 126 $ 220
Price per unit $ 13.65 $ 12.36 $ 16.59
Number of units acquired 6,509 10,184 13,279
The weighted average Trust units/exchangeable shares outstanding are as follows:
For the years ended December 31, 2003 2002 2001
- ----------------------------------------------------------------------------------------------------------
Basic 61,010,105 49,921,523 31,593,378
Diluted 61,153,027 49,967,648 31,635,976
===========================================================================================================
Trust units/exchangeable shares:
For the years ended December 31, 2003 2002 2001
- ----------------------------------------------------------------------------------------------------------
Trust units outstanding 72,688,577 54,108,420 41,916,396
Trust units issuable on exchangeable
shares (Note 10) 939,147 - -
- ----------------------------------------------------------------------------------------------------------
73,627,724 54,108,420 41,916,396
===========================================================================================================
9. INTERNALIZATION OF MANAGEMENT
On April 29, 2003, PC purchased 100% of the outstanding shares of NCEP
Management (the Previous Manager) and NMSI. As a result of these transactions,
all management acquisition and disposition fees payable to the Previous Manager
were eliminated retroactive to January 1, 2003.
The total consideration paid was $30.9 million as detailed below.
Total Consideration $000's
-----------------------------------------------------------------------------------------
Issuance of 1,939,147 exchangeable shares to the shareholder of the
Previous Manager $ 21,718
Cash repayment of indebtedness owing by the Previous Manager 3,400
Issuance of 100,244 units to executive management 1,123
Cash payment to executive management 780
Cash payment for distributions on exchangeable shares and trust units
from January 1 to April 30, 2003, 1,326
Transaction costs 2,503
-----------------------------------------------------------------------------------------
Total Purchase Price $ 30,850
=========================================================================================
To ensure an orderly transition of the services that were provided by the
Previous Manager through its offices in Toronto, PC entered into an agreement
with Sentry Select Capital Corp. ("Sentry") to provide certain services to the
Trust and PC until December 31, 2003, for a maximum cost of $2 million. The
amount incurred decreased from $1 million in the first quarter of 2003 to
$500,000 in the second quarter and to $250,000 in each of the third and fourth
quarters. As of December 31, 2003, Sentry no longer provides any services to
Petrofund or to any of its subsidiaries. Sentry is a company in which John
Driscoll, the Chairman of the Board of Directors of PC, owns a controlling
interest.
Prior to the acquisition, the Previous Manager was paid a management fee equal
to 3.25% of net operating income plus Alberta Royalty Credit, an investment fee
equal to 1.50% of the purchase
price of all properties purchased by PC and a disposition fee of 1.25% of
properties sold, except replacement properties.
10. EXCHANGEABLE SHARES
The number of Exchangeable Shares to be issued in connection with the
internalization of the management contract was determined based on a negotiated
value of $12.17 per share as set out in the Information Circular dated March 10,
2003. For accounting purposes, the 1,939,147 Exchangeable Shares were deemed to
be issued at a value of $11.20 per share, being the average trading value of the
Trust units for the last ten days prior to the closing date. Initially, each
Exchangeable Share was exchangeable into one Trust Unit. The exchange ratio is
adjusted from time to time to reflect the per unit distributions paid to
unitholders after the closing date. Under the terms of the Exchangeable Share
Agreement, the holder of the Exchangeable Shares is entitled to redeem for cash
the number of shares equal to the cash distributions that would have been
received had the Exchangeable Shares been converted to Trust units. As a result
of the redemption feature, the number of Trust units issuable upon conversion is
expected to remain constant over time. As the substance of this feature is to
allow the holder of the Exchangeable Shares to receive cash distributions, the
redemption has been accounted for as a distribution of earnings rather than a
return of capital. In 2003, 181,041 Exchangeable Shares were redeemed for $2.8
million in cash.
On December 17, 2003, 906,635 Exchangeable Shares were converted to 1,000,000
Trust units at a rate of 1.10298. At December 31, 2003, 851,471 Exchangeable
Shares were outstanding, at an exchange ratio of 1.10298 per Trust Unit.
Issued and Outstanding Number of Shares $000's
Issued for internalization of Management Contract 1,939,147 $ 21,718
Redemption of Shares (181,041) -
Exchanged for Trust Units (906,635) (11,200)
-----------------------------------------------------------------------------------------------
Balance, December 31, 2003 851,471 10,518
Exchange ratio, end of period 1.10298 -
-----------------------------------------------------------------------------------------------
Trust Units issuable upon conversion 939,147 $ 10,518
===============================================================================================
11. UNIT INCENTIVE PLAN
A total of 5,200,000 units have been reserved for issuance under the Unit
Incentive Plan of which 2,254,100 have been issued as at December 31, 2003.
A summary of the status of the Unit Incentive Plan as of December 31, 2003, 2002
and 2001, and changes during the years then ended is presented below:
For the years ended December 31, 2003 2002 2001
- -------------------------------------------------------------------------------------------------------------------
Weighted Weighted Weighted
Average Average Average
Exercise Exercise Exercise
Units Price Units Price Units Price
----- ----- ----- ----- ----- -----
Options outstanding,
beginning of year 3,028,280 $ 13.21 1,840,190 $ 15.92 941,278 $ 16.71
Issued - - 1,468,100 10.65 1,477,800 17.65
Forfeited (555,754) 16.82 (272,044) 16.66 (237,583) 18.38
Exercised (1,673,404) 12.88 (7,966) 10.65 (341,305) 16.47
- -------------------------------------------------------------------------------------------------------------------
Options outstanding before
reduction of exercise price 799,122 $ 14.74 3,028,280 $ 13.31 1,840,190 $ 17.29
Reduction of exercise price - (1.81) - (0.10) - (1.37)
- ---------------------------------------------------------------------------------------------------------------------
Options outstanding,
end of year 799,122 $ 12.93 3,028,280 $ 13.21 1,840,190 $ 15.92
- -------------------------------------------------------------------------------------------------------------------
Options exercisable,
end of year 440,656 $ 15.36 1,593,681 $ 14.10 745,565 $ 16.08
- -------------------------------------------------------------------------------------------------------------------
The options granted in 2002 and 2001 are exercisable at the original option
prices, which were the market prices of the units on the date of the grants, or
if so elected by the participant, at reduced prices as described below. The
option prices are reduced for each calendar quarter ending after the date of the
grant by the positive amount, if any, equal to the amount by which the aggregate
distributions made by the Trust in any calendar quarter ending after the date of
the grant exceed 2.5% of the oil and gas royalty and property interests on the
Trust's consolidated balance sheet at the beginning of the applicable calendar
quarter divided by the issued and outstanding units at the beginning of the
applicable quarter.
The following table summarizes the options outstanding at December 31, 2003:
Number Exercise Reduced Exercise
of Units Price Price Expiry Date
4,689 $ 15.00 N/A May 8, 2005
280,666 $ 19.35 $ 16.23 January 30, 2006
109,067 $ 17.25 $ 14.78 April 4, 2006
21,800 $ 14.71 $ 13.31 July 20, 2006
382,900 $ 10.65 $ 9.93 July 25, 2007
12. DISTRIBUTIONS ACCRUING TO UNITHOLDERS
Under the terms of the Trust Indenture, the Trust makes monthly
distributions within a specified period following the end of each month ("Cash
Distribution Date"). Distributions are equal to amounts received by the Trust on
the Cash Distribution Date less
permitted expenses. Distributions to Unitholders coincide with cash receipts of
royalty income from PC. An overall analysis is as follows:
For the period ended Cash Distribution Date 2003 2002 2001
- ----------------------------------------------------------------------------------------------------------
November 30 January 31 $ 0.15 $ 0.15 $ 0.42
December 31 February 28 0.16 0.15 0.42
January 31 March 31 0.17 0.13 0.42
February 28 April 30 0.17 0.13 0.42
March 31 May 31 0.18 0.14 0.45
April 30 June 30 0.18 0.14 0.45
May 31 July 31 0.18 0.14 0.36
June 30 August 31 0.18 0.14 0.32
July 31 September 30 0.18 0.14 0.25
August 31 October 31 0.18 0.15 0.25
September 30 November 30 0.18 0.15 0.25
October 31 December 31 0.18 0.15 0.23
- ----------------------------------------------------------------------------------------------------------
Cash Distributions per Trust unit $ 2.09 $ 1.71 $ 4.24
- ----------------------------------------------------------------------------------------------------------
Reconciliation of Distributions Accruing to Unitholders
(thousands of dollars except per unit amounts)
For the years ended December 31, 2003 2002 2001
- ----------------------------------------------------------------------------------------------------------
Distributions payable, beginning of year $ 30,065 $ 12,188 $ 28,425
- ----------------------------------------------------------------------------------------------------------
Distributions accruing during the year
Cash flow from operating activities 187,585 112,570 110,176
Redemption of exchangeable shares (2,792) - -
Proceeds on disposition of property interests - 946 3,546
Reclamation and abandonment reserve (776) (706) (447)
Less capital lease repayment (2) (3) (3,305) (5,366) (2,629)
Capital expenditures (30,000) (10,000) -
- ----------------------------------------------------------------------------------------------------------
Total distributions accruing during the year 150,712 97,444 110,646
NCE Energy Trust cash flow (1) - 5,651 -
- ----------------------------------------------------------------------------------------------------------
Total distributable income for the year 150,712 103,095 110,646
- ----------------------------------------------------------------------------------------------------------
Distributions paid (127,325) (85,218) (126,883)
- -----------------------------------------------------------------------------------------------------------
Distributions payable, end of year (4) $ 53,452 $ 30,065 $ 12,188
- ----------------------------------------------------------------------------------------------------------
Distributions accruing to Unitholders per Trust unit
Basic $ 2.47 $ 2.07 $ 3.50
Diluted $ 2.46 $ 2.06 $ 3.49
(1) Remaining undistributed cash flow of NCE Energy Trust on May 30, 2002 (see
Note 3b).
(2) Net of $6 million refinanced by increased bank loan in 2002
(3) Net of $6 million refinanced by increased bank loan in 2003.
(4) It is expected that a portion of this amount will be used to fund capital
expenditures.
13. FINANCIAL INSTRUMENTS
The Trust's financial instruments consist of cash, accounts receivable and
payable, long-term debt, capital lease obligations and derivative instruments.
As at December 31, 2003, the carrying value of the cash and accounts receivable
and payable approximated their fair value due to their short-term nature. The
carrying value of the long-term debt approximated its fair value due to the
floating rate of interest charged under the facilities. The carrying value of
the capital lease obligations is not significantly different from their fair
values.
The derivative instruments have no carrying value (see Note 14). The derivative
instruments at December 31, 2003, had a negative fair value of $6.8 million
based on quotes provided by brokers. This fair value represents an approximation
of amounts that would be paid to counterparties to settle these instruments at
the balance sheet date. The Trust plans to hold all derivative instruments
outstanding at December 31, 2003, to maturity.
14. DERIVATIVE FINANCIAL INSTRUMENTS AND PHYSICAL CONTRACTS
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, all of which constitute
effective hedges, and the related unrealized gains or losses, and physical
contracts as at December 31, 2003, are summarized separately below:
Unrealized
Volume Price Delivery Gain (Loss)
Natural Gas Term mcf/d $/mcf Point $000's
Collar November 1, 2003 to 9,475 $6.23-$8.34 AECO $ 118
March 31, 2004
Collar November 1, 2003 to 9,475 $5.80-$10.98 AECO 164
March 31, 2004
Fixed January 1, 2004 to 4,737 $6.07 AECO (316)
March 31, 2004
Fixed January 1, 2004 to 4,737 $6.23 AECO (246)
March 31, 2004
Fixed January 1, 2004 to 4,737 $6.81 AECO 18
March 31, 2004
Fixed January 1, 2004 to 4,737 $7.39 AECO 255
March 31, 2004
Collar April 1, 2004 to 9,475 $5.17-$7.28 AECO 268
October 31, 2004
Collar April 1, 2004 to 9,475 $5.07-$6.81 AECO (66)
October 31, 2004
Collar April 1, 2004 to 1,895 $5.28-$7.39 AECO 56
October 31, 2004
Fixed April 1, 2004 to 4,737 $5.33 AECO (550)
October 31, 2004
Collar November 1, 2004 to 9,475 *(1) AECO 54
March 31, 2005
- --------------------------------------------------------------------------------------------------
Total $ (245)
==================================================================================================
*(1) At Prices above $8.97/mcf Petrofund receives $8.97/mcf.
At Prices between $5.80/mcf and $8.97/mcf receives the market price.
At Prices below $4.74/mcf Petrofund receives a premium of $1.06/mcf.
Unrealized
Volume Price Delivery Gain (Loss)
Oil Term bbl/d $/bbl Point $000's
Fixed Price January 1, 2004 to 1,995 $38.59 Edmonton $ (897)
June 30, 2004
Fixed Price July 1, 2004 to 668 $36.41 Edmonton (186)
December 31, 2004
Collar January 1, 2004 to 2,000 $31.12-$35.98 Edmonton (999)
March 31, 2004
Three Way Collar January 1, 2004 to 2,000 *(1) Edmonton (1,478)
June 30, 2004
Collar April 1, 2004 to 2,000 $31.12-$36.56 Edmonton (768)
June 30, 2004
Three Way Collar July 1, 2004 to 2,000 *(2) Edmonton (892)
December 31, 2004
Collar July 1, 2004 to 2,000 $31.12-$36.30 Edmonton (591)
September 30, 2004
Collar October 1, 2004 to 2,000 $31.12-$36.30 Edmonton (505)
December 31, 2004
Three Way Collar January 1, 2005 to 1,000 *(3) Edmonton (516)
December 31, 2005
- --------------------------------------------------------------------------------------------------------------------
Total $ (6,832)
====================================================================================================================
*(1) At Prices above $37.27 Petrofund receives $37.27/bbl.
At Prices between $31.12 and $37.27/bbl Petrofund receives the
market price.
At Prices below $27.55 Petrofund receives a premium of $3.89/bbl.
*(2) At Prices above $37.60 Petrofund receives $37.60/bbl.
At Prices between $31.45 and $37.60/bbl Petrofund receives the
market price.
At Prices below $27.87 Petrofund receives a premium of $3.89/bbl.
*(3) At Prices above $37.60 Petrofund receives $37.60/bbl.
At Prices between $31.12 and $37.60/bbl Petrofund receives the
market price.
At Prices below $25.93 Petrofund receives a premium of $5.19/bbl.
All the oil hedges are at U.S. WTI prices and have been converted to Canadian
dollars at the year end exchange rate of $1.2965 C$:U.S.$.
Unrealized
Volume Price Delivery Gain (Loss)
Electricity Term MW/h $/MWh Point $000's
- --------------------------------------------------------------------------------------------------------------------
Fixed Price January 1, 2004 to 3.0 $ 44.50 Alberta Power $ 303
December 31, 2005 Pool
- --------------------------------------------------------------------------------------------------------------------
The gains or losses are recognized on a monthly basis over the terms of the
contracts and adjust the prices received.
Derivative financial instruments and physical hedge contracts involve a degree
of credit risk, which the Trust controls through the use of financially sound
counterparties. Market risk relating to changes in value or settlement cost of
the Trust's derivative financial instruments is essentially offset by gains or
losses on the underlying physical sales.
15. INCOME TAXES
The future income tax liability (asset) includes the following temporary
differences (thousands of dollars):
As at December 31, 2003 2002 2001
--------------------------------------------------------------------------
Oil and gas properties $ 77,005 $ 119,825 $ 106,961
Resource allowance - (2,980) (2,961)
---------------------------------------------------------------------------
$ 77,005 $ 116,845 $ 104,000
--------------------------------------------------------------------------
The provision for current and future income taxes differs from the result which
would be obtained by applying the combined federal and provincial statutory tax
rates to income before income taxes. This difference results from the following:
For the years ended December 31, 2003 2002 2001
- ----------------------------------------------------------------------------------------------------------
Income before income tax provision $ 41,857 $ 10,165 $ 40,128
- ----------------------------------------------------------------------------------------------------------
Income tax provision computed at statutory rates $ 17,052 $ 4,294 $ 17,304
Effect on income tax of:
Income attributed to the Trust (41,468) (24,435) (32,665)
Internalization of management contract 12,568 - -
Non-deductible crown charges,
net of Alberta Royalty Credit 24,190 17,055 19,276
Resource allowance (20,730) (15,045) (16,661)
Capital taxes 1,000 831 1,130
Income tax rate reductions on opening balances (36,688) - (329)
Temporary differences in resource allowance - (19) (2,427)
Other 129 3,105 512
- ----------------------------------------------------------------------------------------------------------
Provision for (recovery of) income taxes $ (43,947) $ (14,214) $ (13,860)
===========================================================================================================
The petroleum and natural gas properties and facilities owned by the
Subsidiaries have a tax basis of $232.7 million ($212 million - 2002, $153.3
million - 2001) available for future use as deductions from taxable income.
Included in this tax basis are non-capital loss carry forwards of $43.6 million
($34.0 million - 2002, $33.6 million - 2001), which could expire in various
years through 2010.
16. NET INCOME PER TRUST UNIT
Basic per unit calculations are based on the weighted average number of Trust
units and exchangeable shares outstanding. Diluted calculations include
additional Trust units for the dilutive impact of options. There were no
adjustments to net income in calculating diluted per Trust unit amounts.
The weighted average units/exchangeable shares outstanding are as follows:
For the years ended December 31, 2003 2002 2001
- --------------------------------------------------------------------------------
Basic 61,010,105 49,921,523 31,593,378
Diluted 61,153,027 49,967,648 31,635,976
17. LONG-TERM COMMITMENTS
PC has the following long-term commitments for the years indicated:
(thousands of dollars) 2004 2005 2006 2007 2008
- ----------------------------------------------------------------------------------------------------------------
Capital leases (Note 6) $ 0.4 $ 0.6 $ - $ - $ -
Office lease 1.1 0.8 - - -
Processing & transportation agreement 1.8 1.8 2.0 2.1 2.2
CO2 purchases 3.9 4.7 4.1 3.5 3.3
- ----------------------------------------------------------------------------------------------------------------
$ 7.2 $ 7.9 $ 6.1 $ 5.6 $ 5.5
- ----------------------------------------------------------------------------------------------------------------
18. 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%. In addition, the SEC does not require the
inclusion of any general and administrative or interest expenses in
the calculation.
(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) Effective January 1, 2001, for U.S. reporting purposes, the Trust
adopted Statement of Financial Accounting Standards ("SFAS") No. 133,
"Accounting for Derivative Instruments and Hedging Activities." SFAS
133 establishes accounting and reporting standards requiring 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. Upon adoption, the Trust formally documented and designated
all hedging relationships and verified that its hedging instruments
are effective in offsetting changes in actual prices received by the
Trust. Such effectiveness is monitored at least quarterly and any
ineffectiveness is reported in other revenues (losses) in the
consolidated statement of operations. In 2003, 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, 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. Effective January 1, 2003, the Trust accounts for compensation
expense for options granted on or after January 1, 2003, based on the
fair value method of accounting as described in Note 2g.
For U.S. GAAP purposes, the Unit Incentive Plan is 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.
At December 31, 2001, the exercise price of the options granted under
the Unit Incentive Plan exceeded the market price of the Trust units.
Therefore, no compensation expense was recorded in 2001. No options
have been granted subsequent to December 31, 2002.
(e) In June 2001, the U.S. Financial Accounting Standards Board issued
Statement No. 143, "Accounting for Asset Retirement Obligations" (FAS
143). FAS 143 requires recognition of a liability for the future
retirement obligations associated with property, plant and equipment.
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 FAS 143 effective January 1, 2003,
for U.S. reporting purposes and the cumulative effect adjustment from
initial application has been charged to net income in the current
year. Under current Canadian GAAP and U.S. GAAP prior to asset
retirement obligations are accrued using the unit-of-production method
based on the undiscounted value of the liability. Effective January 1,
2004, the
Trust must adopt new Canadian accounting standards for accounting for
asset retirement obligations which are expected to eliminate this
difference in future years.
(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:
o FAS 150 "Accounting for Certain Instruments with Characteristics
of Both Liabilities and Equity".
o 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 U.S. GAAP would have the following effects on net income as
reported:
For the years ended December 31, ($000's) 2003 2002 2001
- ----------------------------------------------------------------------------------------------------------------
Net income as reported in consolidated
statement of operations $ 85,804 $ 24,379 $ 53,988
Adjustments:
Unrealized loss on derivatives (6,774) (563) -
Compensation expense (3,144) (59) -
Depletion and depreciation 21,098 24,552 1,550
Asset retirement obligation 3,955 - -
Ceiling test write down - - (221,886)
Deferred income taxes (3,823) (8,228) 66,392
- ----------------------------------------------------------------------------------------------------------------
Net income, as adjusted, before cumulative
effect of a change in accounting principle 97,116 40,081 (99,956)
Cumulative effect of a change in accounting
principle, net of income taxes (2,419) - -
- ----------------------------------------------------------------------------------------------------------------
Net income, as adjusted, after cumulative effect 94,697 40,081 (99,956)
Unrealized gain (loss) on derivatives, net of income tax
expense (recovery) of $330 (2002 -$(1,113), 2001 - $783) 451 (1,483) 1,032
- ----------------------------------------------------------------------------------------------------------------
Comprehensive income $ 95,148 $ 38,598 $ (98,924)
- -----------------------------------------------------------------------------------------------------------------
Net income (loss) per unit, as adjusted
before cumulative effect
Basic $ 1.59 $ 0.77 $ (3.16)
Diluted $ 1.59 $ 0.77 $ (3.16)
Net income (loss) per unit, as adjusted
after cumulative effect
Basic $ 1.55 $ 0.77 $ (3.16)
Diluted $ 1.55 $ 0.77 $ (3.16)
Accumulated other comprehensive income:
For the years ended December 31, ($000's) 2003 2002 2001
- -----------------------------------------------------------------------------------------------------------------
Opening balance at January 1 $ (451) $ 1,032 $ -
Unrealized gain (loss) on derivatives, net of income tax
expense (recovery) of $330 (2002 - $(1,113), 2001 - $783) 451 (1,483) 1,032
- -----------------------------------------------------------------------------------------------------------------
Closing balance at December 31 $ - $ (451) $ 1,032
- -----------------------------------------------------------------------------------------------------------------
The application of US GAAP would have the following effects on the consolidated
balance sheet as reported:
Increase
As at ($000's) As reported (Decrease) US GAAP
- ----------------------------------------------------------------------------------------------------------
December 31, 2003
Oil and gas derivative instruments $ - $ (6,774) $ (6,774)
Oil and gas royalty and property interests, net 879,633 (157,172) 722,461
Future income taxes 77,005 (52,450) 24,555
Accrued reclamation and abandonment costs 16,846 17,517 34,643
Unitholders' equity 649,240 (129,013) 520,227
December 31, 2002
Oil and gas derivative instruments $ - $ (1,194) $ (1,194)
Oil and gas royalty and property interests, net 835,366 (198,651) 632,715
Future income taxes 116,845 (58,344) 58,501
Unitholders' equity 480,097 (141,501) 338,596