EXHIBIT 20.2
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COMPTON PETROLEUM CORPORATION
CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2004
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INDEPENDENT AUDITORS' REPORT
To the Shareholders of
Compton Petroleum Corporation
We have audited the consolidated balance sheets of Compton Petroleum Corporation
as at December 31, 2004 and 2003 and the consolidated statements of earnings,
retained earnings and cash flow for each of the years in the three year period
ended December 31, 2004. These consolidated financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted
in Canada and the standards of the Public Company Accounting Oversight Board
(United States). These 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. We believe that our audit provides a reasonable basis for our
opinion.
In our opinion, these consolidated financial statements present fairly, in all
material respects, the financial position of the Company as at December 31, 2004
and 2003 and the results of its operations and cash flow for each of the years
in the three year period ended December 31, 2004 in accordance with accounting
principles generally accepted in Canada.
Calgary, Alberta (SIGNED) "GRANT THORNTON LLP"
Canada
March 15, 2005 Chartered Accountants
COMMENTS BY AUDITOR FOR U.S. READERS ON CANADA-U.S. REPORTING DIFFERENCES
The standards of the Public Company Accounting Oversight Board (United States)
require the addition of an explanatory paragraph (following the opinion
paragraph) when there is a change in accounting principles that has a material
effect on the comparability of the Company's financial statements, such as the
change described in Note 2 to the consolidated financial statements. Also, in
the United States of America, reporting standards for auditors require the
addition of an explanatory paragraph (following the opinion paragraph) when
there is a restatement of the Company's historical financial statements, such as
correction of an error in application of accounting principle described in Note
18(f) to the consolidated financial statements. Our report to the shareholders
dated March 15, 2005 is expressed in accordance with Canadian reporting
standards which do not require a reference to such a change in accounting
principles and correction of an error in the Auditors' Report when the change is
properly accounted for and adequately disclosed in the consolidated financial
statements.
Calgary, Alberta (SIGNED) "GRANT THORNTON LLP"
Canada
March 15, 2005 Chartered Accountants
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COMPTON PETROLEUM CORPORATION
CONSOLIDATED BALANCE SHEETS
As at December 31,
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(thousands of dollars)
2004 2003
----------- -----------
ASSETS
Current
Cash $ 10,068 $ 15,548
Accounts receivable and other 115,113 94,937
Unrealized hedge gain (Note 15a) i)) 1,985 --
----------- -----------
127,166 110,485
Property and equipment (Note 5) 1,178,550 942,303
Goodwill (Note 3) 7,914 --
Deferred financing charges and other 9,729 11,532
Deferred risk management loss (Note 15a) ii)) 7,252 --
----------- -----------
$ 1,330,611 $ 1,064,320
=========== ===========
LIABILITIES
Current
Bank debt (Note 6) $ 220,000 $ 164,500
Accounts payable 125,483 85,885
Income taxes payable 301 2,757
----------- -----------
345,784 253,142
Senior term notes (Note 7) 198,594 213,246
Asset retirement obligations (Note 9) 18,006 17,329
Unrealized hedge liability (Note 15a)iii)) 11,416 --
Future income taxes (Note 14b) 261,196 223,807
Non-controlling interest (Note 4) 71,537 (110)
----------- -----------
906,533 707,414
----------- -----------
SHAREHOLDERS' EQUITY
Capital stock (Note 10b) 135,526 131,577
Contributed surplus (Note 11c) 3,840 760
Retained earnings 284,712 224,569
----------- -----------
424,078 356,906
----------- -----------
$ 1,330,611 $ 1,064,320
=========== ===========
Commitments and contingent liabilities (Note 17)
On behalf of the Board
/s/ M.F. Belich /s/ J.A. Thomson
- --------------------------- ---------------------------
M.F. Belich J.A. Thomson
Director Director
See accompanying notes to the consolidated financial statements.
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COMPTON PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF EARNINGS
Years ended December 31,
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(thousands of dollars, except per share data)
2004 2003 2002
--------- --------- ---------
REVENUE
Oil and natural gas revenues $ 391,659 $ 346,565 $ 226,597
Royalties (93,416) (82,566) (47,497)
--------- --------- ---------
298,243 263,999 179,100
--------- --------- ---------
EXPENSES
Operating 55,655 49,916 45,546
Transportation 8,595 8,447 8,167
General and administrative 15,215 12,206 9,845
Interest and finance charges (Note 8) 33,733 30,595 23,197
Depletion and depreciation 82,554 61,749 55,473
Foreign exchange (gain) loss (Note 7) (14,631) (47,368) 1,583
Accretion of asset retirement obligations (Note 9) 1,670 1,436 1,241
Stock-based compensation (Note 11c) and d)) 3,410 793 190
Risk management loss (gain) (Note 15a)iv)) 8,808 4,132 (4,424)
--------- --------- ---------
195,009 121,906 140,818
--------- --------- ---------
EARNINGS BEFORE TAXES AND NON-CONTROLLING INTEREST 103,234 142,093 38,282
--------- --------- ---------
INCOME TAXES (Note 14a)
Current 2,751 3,282 1,428
Future 33,432 20,041 18,542
--------- --------- ---------
36,183 23,323 19,970
--------- --------- ---------
EARNINGS BEFORE NON-CONTROLLING INTEREST 67,051 118,770 18,312
Non-controlling interest (Note 4) 3,418 (110) --
--------- --------- ---------
NET EARNINGS $ 63,633 $ 118,880 $ 18,312
========= ========= =========
NET EARNINGS PER SHARE (Note 12)
Basic $ 0.54 $ 1.02 $ 0.16
========= ========= =========
Diluted $ 0.51 $ 0.97 $ 0.16
========= ========= =========
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CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
Years ended December 31,
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(thousands of dollars)
2004 2003 2002
--------- --------- ---------
RETAINED EARNINGS, beginning of year $ 224,569 $ 112,039 $ 96,093
Net earnings 63,633 118,880 18,312
Premium on redemption of shares (Note 10b) (3,490) (6,350) (2,366)
--------- --------- ---------
RETAINED EARNINGS, end of year $ 284,712 $ 224,569 $ 112,039
========= ========= =========
See accompanying notes to the consolidated financial statements.
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COMPTON PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOW
Years ended December 31,
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(thousands of dollars)
2004 2003 2002
--------- --------- ---------
OPERATING ACTIVITIES
Net earnings $ 63,633 $ 118,880 $ 18,312
Amortization of deferred charges and other 2,101 2,208 1,367
Depletion and depreciation 82,554 61,749 55,473
Accretion of asset retirement obligations 1,670 1,436 1,241
Unrealized foreign exchange (gain) loss (14,652) (47,388) 1,583
Future income taxes 33,432 20,041 18,542
Unrealized risk management loss (Note 15a)iv)) 2,179 -- --
Stock-based compensation 3,410 760 --
Asset retirement expenditures (614) (2,683) (446)
Non-controlling interest 3,418 (110) --
--------- --------- ---------
Cash flow from operations 177,131 154,893 96,072
Change in non-cash working capital (Note 16) (12,594) 1,318 (5,166)
--------- --------- ---------
164,537 156,211 90,906
--------- --------- ---------
FINANCING ACTIVITIES
Issuance (repayment) of bank debt 43,373 124,500 (190,000)
Issuance of senior notes -- -- 259,050
Deferred financing charges -- (128) (14,810)
Proceeds from share issuances, net 3,258 6,400 18,177
Proceeds from partnership unit issuance 74,343 -- --
Distributions to partner (6,114) -- --
Redemption of common shares (4,005) (7,942) (3,026)
Change in non-cash working capital (Note 16) 324 (1,387) 3,514
--------- --------- ---------
111,179 121,443 72,905
--------- --------- ---------
INVESTING ACTIVITIES
Property and equipment additions (296,676) (222,055) (127,993)
Corporate acquisitions (Note 3) (12,132) -- --
Property acquisitions (20,830) (65,622) (44,857)
Property dispositions 19,276 2,194 17,700
Change in non-cash working capital (Note 16) 29,166 8,652 1,012
--------- --------- ---------
(281,196) (276,831) (154,138)
--------- --------- ---------
CHANGE IN CASH (5,480) 823 9,673
CASH, beginning of year 15,548 14,725 5,052
--------- --------- ---------
CASH, end of year $ 10,068 $ 15,548 $ 14,725
========= ========= =========
See accompanying notes to the consolidated financial statements.
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COMPTON PETROLEUM CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Tabular amounts in thousands of dollars, unless otherwise stated)
December 31, 2004
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1. SIGNIFICANT ACCOUNTING POLICIES
Compton Petroleum Corporation (the "Company" or "Compton") is in the
business of the exploration for and production of petroleum and natural
gas reserves in the Western Canadian Sedimentary Basin.
a) BASIS OF PRESENTATION
The consolidated financial statements of the Company have been prepared in
accordance with accounting principles generally accepted in Canada within
the framework of the accounting policies summarized below. Information
prepared in accordance with accounting principles generally accepted in
the United States is included in Note 18.
The consolidated financial statements include the accounts of the Company
and its wholly owned subsidiaries from their respective dates of
acquisition. The consolidated financial statements also include the
accounts of Mazeppa Processing Partnership in accordance with Accounting
Guideline 15 ("AcG-15") "Consolidation of Variable Interest Entities", as
outlined in Note 4.
All amounts are presented in Canadian dollars unless otherwise stated.
b) MEASUREMENT UNCERTAINTY
The timely preparation of financial statements requires that Management
make estimates and assumptions and use judgment regarding assets,
liabilities, revenues and expenses. Such estimates relate primarily to
transactions and events that have not settled as of the date of the
financial statements. Accordingly, actual results may differ from
estimated amounts as future confirming events occur.
Amounts recorded for depletion and depreciation, asset retirement
obligations and amounts used in impairment test calculations are based
upon estimates of petroleum and natural gas reserves and future costs to
develop those reserves. By their nature, these estimates of reserves,
costs and related future cash flows are subject to uncertainty, and the
impact on the consolidated financial statements of future periods could be
material.
c) PROPERTY AND EQUIPMENT
i) Capitalized costs
The Company follows the full cost method of accounting for its
petroleum and natural gas operations as determined by the Canadian
Institute of Chartered Accounts ("CICA"), Accounting Guideline 16
("AcG-16"). Under this method all costs related to the exploration
for and development of petroleum and natural gas reserves are
capitalized. Costs include lease acquisition costs, geological and
geophysical expenses, costs of drilling both producing and
non-producing wells, production facilities, asset retirement costs
and certain general and administrative expenses directly related to
exploration and development activities.
Proceeds from the sale of properties are applied against
capitalized costs, without any gain or loss being realized, unless
such sale would significantly alter the rate of depletion and
depreciation.
Expenditures related to renewals or betterments that improve the
productive capacity or extend the life of an asset are capitalized.
Maintenance and repairs are expensed as incurred.
ii) Depletion and depreciation
Depletion and depreciation of property and equipment is provided
using the unit-of-production method based upon estimated proved
petroleum and natural gas reserves. The costs of significant
undeveloped properties are excluded from costs subject to depletion
until it is determined whether or not proved reserves are
attributable to the properties or impairment has occurred.
Estimated future costs to be incurred in developing proved reserves
are included in costs subject to depletion. For depletion and
depreciation purposes, relative volumes of natural gas production
and reserves are converted at the energy equivalent conversion rate
of six thousand cubic feet of natural gas to one barrel of crude
oil.
Depreciation of certain midstream facilities is provided for on a
straight line basis over 30 years and depreciation of office
equipment is provided for on a declining balance basis at 20% per
annum.
iii) Impairment test
At each reporting period the Company performs an impairment test to
determine the recoverability of capitalized costs associated with
reserves. An impairment loss is recognized when the carrying amount
of a cost centre exceeds its fair value. The carrying amount of the
cost centre is not recoverable if the carrying amount exceeds the
sum of the undiscounted cash flows from proved reserves plus the
costs of unproved properties. If the sum of the cash flows is less
than the carrying amount, the impairment loss is limited to the
amount by which the carrying amount exceeds the sum of the fair
value of proved and probable reserves and the costs of unproved
properties that have been subject to a separate impairment test and
contain no probable reserves.
iv) Asset retirement obligations
The Company recognizes the fair value of estimated asset retirement
obligations on the consolidated balance sheet when a reasonable
estimate of fair value can be made. Asset retirement obligations
include those legal obligations where the Company will be required
to retire tangible long-lived assets such as well sites, pipelines
and facilities. The asset retirement cost, equal to the initially
estimated fair value of the asset retirement obligation, is
capitalized as part of the cost of the related long-lived asset.
Changes in the estimated obligation resulting from revisions to
estimated timing or amount of undiscounted cash flows are
recognized as a change in the asset retirement obligation and the
related asset retirement cost.
Asset retirement costs are amortized using the unit-of-production
method and are included in depletion and depreciation in the
consolidated statement of earnings. Increases in the asset
retirement obligations resulting from the passage of time are
recorded as accretion of asset retirement obligations in the
consolidated statement of earnings.
v) Inventories
Physical inventory held for exploration, development and operating
activities is included in property and equipment and is valued at
cost.
d) GOODWILL
Goodwill is recorded on a corporate acquisition when the purchase price is
in excess of the fair values assigned to assets acquired and liabilities
assumed. Goodwill is not amortized and an impairment test is performed at
least annually to evaluate the carrying value. To assess impairment the
fair value of the reporting unit is determined and compared to the
carrying value. If fair value is less than the carrying value then a
second test is performed to determine the amount of the impairment. Any
loss recognized is equal to the difference between the implied fair value
and the carrying value of the goodwill.
e) FINANCIAL INSTRUMENTS
Financial instruments consist mainly of accounts receivable and other,
accounts payable and long-term debt. There are no significant differences
between the carrying value of these financial instruments and their
estimated fair value except as disclosed in Note 15b)ii).
The Company uses financial instruments for non-trading purposes to manage
fluctuations in commodity prices, foreign currency exchange rates and
interest rates, as described in Note 15. The Company has elected not to
designate any of its current risk management activities as accounting
hedges and accounts for all derivative financial instruments using the
mark-to-market accounting method.
f) JOINT OPERATIONS
Certain petroleum and natural gas activities are conducted jointly with
others. These consolidated financial statements reflect only the Company's
proportionate interest in such activities.
g) FLOW-THROUGH SHARES
Resource expenditure deductions for income tax purposes related to
exploration and development activities funded by flow-through share
arrangements are renounced to investors in accordance with income tax
legislation. The liability for future income taxes is increased and
capital stock is reduced by the estimated tax benefits transferred to
shareholders at the time the resource expenditure deductions are
renounced.
h) EARNINGS PER SHARE AMOUNTS
The Company uses the treasury stock method to determine the dilutive
effect of stock options. This method assumes that proceeds received from
the exercise of in-the-money stock options are used to repurchase common
shares at the average market price for the period. Basic net earnings per
common share are determined by dividing net earnings by the weighted
average number of common shares outstanding during the period. Diluted
earnings per share are computed by giving effect to the potential dilution
that would occur if stock options were exercised.
i) INCOME TAXES
Income taxes are recorded using the liability method of accounting. Future
income taxes are calculated based on the difference between the accounting
and income tax basis of an asset or liability, using the substantively
enacted income tax rates. Changes in income tax rates that are
substantively enacted are reflected in the accumulated future income tax
balances in the period the change occurs.
j) REVENUE RECOGNITION
Revenue associated with the production and sale of crude oil, natural gas
and natural gas liquids owned by the Company is recognized when the
purchaser takes possession of the commodity product. Other revenue is
recognized in the period that the service is provided to the customer.
k) STOCK-BASED COMPENSATION PLAN
The Company has stock-based compensation plans which include stock options
and an employee stock savings plan.
The Company records compensation expense in the consolidated statements of
earnings for stock options granted to Directors, Officers and employees
using the fair-value method. Compensation costs are recognized over the
vesting period. Fair values are determined using the Black-Scholes option
pricing model.
The Company matches employee contributions to the stock savings plan and
these cash payments are recorded as compensation expense as incurred.
l) DEFERRED FINANCING CHARGES
Financing costs related to the issuance of the senior term notes have been
deferred and are amortized over the term of the notes on a straight-line
basis.
m) FOREIGN CURRENCY TRANSLATION
Long-term debt payable in U.S. dollars is translated into Canadian dollars
at the period-end exchange rate, with any resulting adjustment recorded in
the consolidated statement of earnings.
n) DIVIDEND POLICY
The Company has neither declared nor paid any dividends on its common
shares. The Company intends to retain its earnings to finance growth and
expand its operations and does not anticipate paying any dividends on its
common shares in the foreseeable future.
o) DEFINED BENEFIT PENSION PLAN
The Company accrues for obligations under a defined benefit pension plan
and the related costs, net of plan assets. The cost of the pension is
actuarially determined using the projected benefit method based on length
of service and reflects Management's best estimate of expected plan
investment performance, salary escalation and retirement age of employees.
p) RECLASSIFICATION
Certain information provided for prior years has been reclassified to
conform with the current period presentation.
2. CHANGES IN ACCOUNTING POLICY
HEDGING RELATIONSHIPS
On January 1, 2004, the Company adopted the amendments made to the CICA modified
Accounting Guideline 13 ("AcG-13") "Hedging Relationships" and Emerging Issues
Committee Abstract 128 ("EIC 128"), "Accounting for Trading, Speculative or Non
Trading Derivative Financial Instruments". Derivative instruments that do not
qualify for hedge accounting or are not designated as hedges, are recorded on
the balance sheet as either an asset or liability with changes in fair value
recognized in earnings.
The Company has elected not to designate any of its risk management activities
in place at December 31, 2003 as accounting hedges under AcG-13 and accordingly,
accounts for all derivative financial instruments using the mark-to-market
accounting method. The impact on the Company's consolidated financial statements
at January 1, 2004 was the recognition of an unrealized hedge liability of $10.9
million and a deferred risk management loss of $10.9 million, before tax. The
deferred risk management loss is charged to earnings as the contracts are
settled and the liability is re-valued at each balance sheet date with any gain
or loss recognized in earnings.
3. BUSINESS COMBINATIONS
On April 12, 2004 and November 15, 2004, respectively, the Company acquired 100%
of the issued and outstanding shares of Redwood Energy, Ltd. and Mayfair Energy
Ltd. for total cash consideration of $12.1 million plus the assumption of $12.1
million of debt. Both were independent exploration and production companies with
operations in the Company's core areas.
The business combinations have been accounted for using the purchase method with
results of operations included in the consolidated financial statements from the
date of acquisition. Goodwill recognized on these transactions amounted to $7.9
million.
During the year, both companies were wound up into Compton Petroleum Corporation
and dissolved.
4. NON-CONTROLLING INTEREST
Mazeppa Processing Partnership ("MPP" or "the Partnership") is a limited
partnership organized under the laws of the province of Alberta and owns certain
midstream facilities, including gas plants and pipelines in Southern Alberta.
The Company processes a significant portion of its production from the area
through these facilities pursuant to a processing agreement with MPP. The
Company does not have an ownership position in MPP, however, the Company,
through a management agreement, manages the activities of MPP and is considered
to be the primary beneficiary of MPP's operations. Pursuant to AcG-15, these
consolidated financial statements include the assets, liabilities and operations
of the Partnership. Equity in the Partnership, attributable to the partners of
MPP, is recorded on consolidation as a non-controlling interest and is comprised
of the following:
As at December 31, 2004 2003
- ----------------------------------------------------------------------------------------------
Non-controlling interest, beginning of year $ (110) $ --
Proceeds from issue of partnership units, net 74,343 --
Earnings (loss) attributable to non-controlling interest 3,418 (110)
Distributions to limited partner (6,114) --
---------- ----------
Non-controlling interest, end of year $ 71,537 $ (110)
========== ==========
Commencing May 1, 2004, pursuant to the terms of a processing agreement between
Compton and MPP, Compton pays a monthly fee to MPP for the transportation and
processing of natural gas through the MPP owned facilities. The fee is comprised
of a fixed base fee of $764 thousand per month plus MPP operating costs, net of
third party revenues. These amounts are eliminated from revenues and expenses on
consolidation.
The processing agreement has a five year term ending April 1, 2009, at which
time Compton may renew the agreement under terms determined at that time or
purchase the Partnership units for the predetermined amount of $55 million,
deemed to be fair value. In the event that the Company does not renew the
processing agreement nor exercise the purchase option, the Limited Partner may
dispose of the Partnership units to an independent third party.
MPP has guaranteed payment of certain obligations of its limited partner under a
credit agreement between the limited partner and a syndicate of lenders. The
maximum liability of the Partnership under the guarantee is limited to amounts
due and payable to MPP by the Company pursuant to the processing agreement. The
maximum liability at December 31, 2004 is $39.7 million payable over the
remaining term of the processing agreement. The Company has determined that its
exposure to loss under these arrangements is minimal, if any.
5. PROPERTY AND EQUIPMENT
As at December 31, 2004 2003
- ------------------------------------------------------------------------------------------------------------------------------
ACCUMULATED Accumulated
DEPLETION AND depletion and
COST DEPRECIATION NET Cost depreciation Net
------------ --------------- ----------- ----------- -------------- -------------
Exploration and
development costs $ 1,161,396 $ (281,614) $ 879,782 $ 931,970 $ (212,223) $ 719,747
Production equipment
and processing
facilities 317,477 (34,150) 283,327 231,918 (21,411) 210,507
Inventory 6,187 -- 6,187 2,246 -- 2,246
Future asset
retirement costs 9,576 (3,111) 6,465 10,557 (3,422) 7,135
Office equipment 6,005 (3,216) 2,789 5,143 (2,475) 2,668
----------- ----------- ----------- ----------- ----------- -----------
$ 1,500,641 $ (322,091) $ 1,178,550 $ 1,181,834 $ (239,531) $ 942,303
=========== =========== =========== =========== =========== ===========
Employee salaries and insurance costs of $4.6 million (2003 - $4.0 million)
directly related to exploration and development activities are capitalized. No
other general and administrative costs are capitalized.
Future capital expenditures of $89.1 million (2003 - $62.4 million; 2002 - $37.5
million), as estimated by independent engineers, relating to the development of
proved reserves have been included in costs subject to depletion. Undeveloped
properties with a cost at December 31, 2004 of $187.8 million (2003 - $161.9
million; 2002 - $155.0 million) included in exploration and development costs,
have not been subject to depletion.
The prices used in the impairment test evaluation of the Company's natural gas,
crude oil and natural gas liquids reserves were:
As at December 31, 2004 NATURAL GAS OIL NGL
-------------- ------------ -----------
$ per mcf $ per bbl $ per bbl
2005 $ 7.03 $ 46.13 $ 42.67
2006 $ 6.77 $ 43.75 $ 40.28
2007 $ 6.57 $ 40.60 $ 36.64
2008 $ 6.24 $ 38.05 $ 34.14
2009 $ 6.04 $ 36.33 $ 32.52
Approximate % increase thereafter 1.5 1.5 1.5
6. CREDIT FACILITIES
As at December 31, 2004 2003
- --------------------------------------------------------------------------------
Authorized $240,000 $185,000
======== ========
Prime rate 3,000 21,000
Bankers' Acceptance 217,000 143,500
-------- --------
Utilized $220,000 $164,500
======== ========
As of December 31, 2004, the Company had arranged authorized senior credit
facilities with a syndicate of Canadian banks in the amount of $240 million.
Advances under the facilities can be drawn and currently bear interest as
follows:
Prime rate plus 0.45%
Bankers' Acceptance rate plus 1.45%
LIBOR rate plus 1.45%
Margins are determined based on the ratio of total consolidated debt to
consolidated cash flow. These facilities mature on July 7, 2005.
The senior credit facilities are secured by a first fixed and floating charge
debenture in the amount of $325.0 million covering all the Company's assets and
undertakings.
7. SENIOR TERM NOTES
As at December 31, 2004 2003
- --------------------------------------------------------------------------------
Senior term notes (U.S. $165.0 million)
Proceeds on issuance $ 259,051 $ 259,051
Cumulative unrealized foreign exchange gain (60,457) (45,805)
--------- ---------
$ 198,594 $ 213,246
========= =========
The senior term notes bear interest at 9.90%, semi-annual, with principal
repayable on May 15, 2009 and are subordinate to the Company's bank credit
facilities.
The notes are not redeemable prior to May 15, 2006, except in limited
circumstances. After that time, they can be redeemed in whole or part, at the
rates indicated below:
May 15, 2006 104.950%
May 15, 2007 102.475%
May 15, 2008 and thereafter 100.000%
The Company entered into a cross currency, interest rate swap arrangement with
its banking syndicate whereby interest paid by the Company on the U.S. $165.0
million principal amount is based upon the 90 day Bankers' Acceptance rate plus
4.85%, calculated on the $259.0 million proceeds of issuance. This arrangement
resulted in an effective interest rate of 7.24% during year ended December 31,
2004 (2003 - 7.85%) net of gains realized on the swap arrangement, see Note
15a)iv).
The unrealized foreign exchange gain recognized in 2004 was $14.7 million (2003
- - $47.4 million), and the accumulated unrealized gain to December 31, 2004 is
$60.5 million.
8. INTEREST AND FINANCE CHARGES
Amounts charged to expense during the year ended are as follows:
YEARS ENDED DECEMBER 31, 2004 2003 2002
- --------------------------------------------------------------------------------
Interest on bank debt, net $ 9,662 $ 6,611 $ 5,339
Interest on senior term notes 21,281 21,711 15,932
Finance charges 2,790 2,273 1,926
------- ------- -------
Total $33,733 $30,595 $23,197
======= ======= =======
Finance charges include the amortization of deferred charges and current year
expenses.
9. ASSET RETIREMENT OBLIGATIONS
The following table presents the reconciliation of the beginning and ending
aggregate carrying amount of the obligations associated with the retirement of
oil and natural gas assets:
As at December 31, 2004 2003
- --------------------------------------------------------------------------------
Asset retirement obligations, beginning of year $ 17,329 $ 17,335
Liabilities incurred 3,357 1,241
Liabilities settled and disposed (4,350) (2,683)
Accretion expense 1,670 1,436
-------- --------
Asset retirement obligations, end of year $ 18,006 $ 17,329
======== ========
The total undiscounted amount of estimated cash flows required to settle the
obligations is $148.9 million (2003 - $135.1 million), which has been discounted
using a credit-adjusted risk free rate of 10.8%. The majority of these
obligations are not expected to be settled for several years or decades into the
future. Settlements will be funded from general Company resources at the time of
retirement and removal.
10. CAPITAL STOCK
a) AUTHORIZED
The Company is authorized to issue an unlimited number of common shares
and an unlimited number of preferred shares, issuable in series.
b) ISSUED AND OUTSTANDING
As at December 31, 2004 2003
- ------------------------------------------------------------- --------------------------
NUMBER OF Number of
SHARES AMOUNT shares Amount
--------- --------- --------- ---------
(000s) (000s)
Common shares outstanding,
beginning of year 116,423 $ 131,577 116,271 $ 128,079
Shares issued for cash, net -- -- 587 2,712
Shares issued for property 110 875 15 81
Shares issued under stock
option plan 1,271 3,589 913 2,296
Shares repurchased (450) (515) (1,363) (1,591)
--------- --------- --------- ---------
Common shares outstanding,
end of year 117,354 $ 135,526 116,423 $ 131,577
========= ========= ========= =========
Effective March 10, 2004, the Company received approval from the Toronto
Stock Exchange for a Normal Course Issuer Bid (the "Bid"). Under the Bid,
the Company could purchase for cancellation up to 5,800,000 of its common
shares, representing 4.95% of the 117,242,073 common shares outstanding as
of February 29, 2004. The Bid expired on March 9, 2005 and was
subsequently renewed.
During the year, the Company purchased for cancellation 450,100 common
shares at an average price of $8.90 per share (2003 - 1,363,400 shares at
an average price of $5.83 per share) pursuant to a normal course issuer
bid. The excess of the purchase price over book value has been charged to
retained earnings.
In February 2005, the Company issued 7,500,000 common shares in the
capital of the Company for gross proceeds of $90.0 million before
underwriters' fees of $3.6 million and expenses of issue estimated to be
$0.4 million. The net proceeds of this offering were initially used to
repay a portion of the current indebtedness of the Company under the
credit facilities and thereafter, to expand and accelerate the Company's
capital expenditure program.
c) SHAREHOLDER RIGHTS PLAN
The Company has a shareholder rights plan (the "Plan") to ensure all
shareholders are treated fairly in the event of a take-over offer or other
acquisition of control of the Company.
Pursuant to the Plan, the Board of Directors authorized and declared the
distribution of one Right in respect of each common share outstanding. In
the event that an acquisition of 20% or more of the Company's shares is
completed and the acquisition is not a permitted bid, as defined by the
Plan, each Right will permit the holder to acquire common shares at a 50%
discount to the market price at that time.
11. STOCK-BASED COMPENSATION PLANS
a) STOCK OPTION PLAN
The Company has implemented a stock option plan for Directors, Officers and
employees. The exercise price of each option approximates the market price for
the common shares on the date the option was granted. Options granted under the
plan before June 1, 2003 are generally fully exercisable after four years and
expire ten years after the grant date. Options granted under the plan after June
1, 2003 are generally fully exercisable after four years and expire five years
after the grant date.
The following tables summarize the information relating to stock options:
As at December 31, 2004 2003
---------------------------------------------------------------- --------------------------------
WEIGHTED Weighted
AVERAGE average
EXERCISE exercise
STOCK OPTIONS PRICE Stock Options price
------------- ------------ ------------- ------------
(000S) (000s)
Outstanding, beginning
of year 10,672 $ 2.54 10,357 $ 2.21
Granted 2,549 $ 7.34 1,503 $ 5.18
Exercised (1,271) $ 2.56 (913) $ 2.52
Cancelled (295) $ 5.26 (275) $ 4.63
--------- --------- --------- --------
Outstanding, end of year 11,655 $ 3.51 10,672 $ 2.54
========= ========= ========= ========
Exercisable, end of year 7,812 $ 2.19 7,763 $ 1.77
========= ========= ========= ========
The range of exercise prices of stock options outstanding and exercisable at
December 31, 2004 are as follows:
Outstanding Options Exercisable Options
-------------------------------------------------- --------------------------------
Weighted
average Weighted Weighted
Number of remaining average Number of average
options contractual exercise options exercise
Range of Exercise Prices outstanding life (years) price outstanding price
------------- --------------- ------------- -------------- ------------
(000s) (000s)
$0.60 - $0.99 2,875 1.8 $ 0.64 2,875 $ 0.64
$1.00 - $2.99 2,168 4.1 1.73 2,166 1.73
$3.00 - $3.99 1,702 6.3 3.43 1,279 3.32
$4.00 - $4.99 1,799 7.1 4.29 992 4.19
$5.00 - $6.99 1,335 4.0 5.86 392 5.89
$7.00 - $10.80 1,776 4.4 7.88 108 7.58
------------- --------------- ------------- -------------- ------------
11,655 4.3 $ 3.51 7,812 $ 2.19
============= =============== ============= ============== ============
b) STOCK OPTIONS GRANTED PRIOR TO JANUARY 1, 2003
The Company has not recorded stock-based compensation expense in the
consolidated statements of earnings related to stock options granted prior to
2003. If the Company had applied the fair-value method to options granted prior
to 2003, the Company's pro-forma net earnings and net earnings per share would
have been as indicated below:
Years ended December 31, 2004 2003 2002
- ------------------------------------------------------------------------------------------------------
Net earnings
As reported $ 63,633 $ 118,880 $ 18,312
Less fair value of stock options (1,545) (2,317) (3,317)
========= ========== =========
Pro-forma $ 62,088 $ 116,563 $ 14,995
========= ========== =========
Net earnings per common share - basic
As reported $ 0.54 $ 1.02 $ 0.16
Pro-forma $ 0.53 $ 1.00 $ 0.13
Net earnings per common share - diluted
As reported $ 0.51 $ 0.97 $ 0.16
Pro-forma $ 0.50 $ 0.95 $ 0.13
c) STOCK OPTIONS GRANTED AFTER JANUARY 1, 2003
The Company has recorded stock-based compensation expense in the consolidated
statement of earnings for stock options granted to Directors, Officers and
employees after January 1, 2003 using the fair value method.
The fair value of each option granted is estimated on the date of grant using
the Black-Scholes option pricing model with weighted average assumptions for
grants as follows:
Years ended December 31, 2004 2003
- ----------------------------------------------------------------------------------- -------
Weighted average fair value of options granted $ 3.70 $ 3.01
Risk-free interest rate 3.9% 4.3%
Expected lives (years) 5.0 6.1
Expected volatility 49.6% 56.0%
The following table presents the reconciliation of contributed surplus with
respect to stock-based compensation:
As at December 31 2004 2003
- ---------------------------------------------------------------------------------- --------
Contributed surplus, beginning of year $ 760 $ --
Stock-based compensation expense 3,410 760
Stock options exercised (330) --
---------- --------
Contributed surplus, end of year $ 3,840 $ 760
========== ========
d) SHARE APPRECIATION RIGHTS PLAN
CICA Handbook section 3870 requires recognition of compensation costs with
respect to changes in the intrinsic value for the variable component of fixed
options. During the year ended December 31, 2004, there were no significant
compensation costs related to the outstanding variable component of these share
appreciation rights (2003 - $33,000; 2002 - $190,000). The liability related to
the variable component of these options amounts to $1.7 million, which is
included in accounts payable as at December 31, 2004 (2003 - $2.4 million). All
outstanding options having a variable component expire at various times through
2011.
12. PER SHARE AMOUNTS
The following table summarizes the common shares used in calculating net
earnings per common share:
As at December 31, 2004 2003 2002
- ------------------------------------------------------------------------ ------------ -------------
(000S) (000s) (000s)
Weighted average common shares outstanding - basic 117,244 116,267 113,428
Effect of stock options 6,789 5,856 4,572
------------ ------------ -------------
Weighted average common shares outstanding - diluted 124,033 122,123 118,000
============ ============ =============
In calculating diluted earnings per common share for the year ended December 31,
2004, the Company excluded 288,000 options (2003 - 615,100; 2002 - 2,193,662),
as the exercise price was greater than the average market price of its common
shares in those years.
13. DEFINED BENEFIT PENSION PLAN
Substantially all of the employees of MPP are enrolled in a co-sponsored,
defined benefit pension plan. The Company does not have a pension plan for other
employees. Information relating to the MPP retirement plan is outlined below:
As at December 31, 2004 2003
- -------------------------------------------------------------------------------- -----------
Accrued benefit obligation $ 5,855 $ 5,331
---------- ----------
Fair value of plan assets $ 5,221 $ 4,488
---------- ----------
Funded status
Plan assets less than benefit obligation $ (634) $ (843)
Unamortized net actuarial gain (269) (221)
Unamortized past service costs 933 1,000
---------- ----------
Accrued benefit (liability), included in deferred financing
charges and other $ 30 $ (64)
========== ==========
Economic assumptions used to determine benefit obligation and periodic
expense are:
Years ended December 31, 2004 2003
- -------------------------------------------------------------------------------- ----------
Discount rate 6.3% 6.3%
Expected rate of return on assets 7.0% 7.0%
Rate of compensation increase 4.5% 4.0%
Average remaining service period of covered employees 15 years 15 years
Actuarial evaluations are required every three years, the most recent being
January 1, 2003.
Pension expense, included in MPP operating costs, is as follows:
Years ended December 31, 2004 2003
- -------------------------------------------------------------------------------- -----------
Current service cost $ 190 $ 111
Interest on accrued benefit obligation 336 173
Interest on assets (333) (152)
Amortization on past service cost 67 37
----------- ------------
Pension expense $ 260 $ 169
----------- ------------
MPP expects to contribute $354 thousand to the plan in 2005. Contributions by
the participants to the pension plan were $66 thousand for the year ended
December 31, 2004.
14. INCOME TAXES
a) The following table reconciles income taxes calculated at the Canadian
statutory rate with actual income taxes:
Years ended December 31, 2004 2003 2002
------------------------------------------------------------------- --------- ---------
Earnings before taxes $ 103,234 $ 142,093 $ 38,282
--------- --------- ---------
Canadian statutory rate 38.6% 40.6% 42.1%
Expected income taxes $ 39,848 $ 57,690 $ 16,117
Effect on taxes resulting from:
Non-deductible crown charges 17,611 23,922 17,103
Resource allowance (13,535) (16,485) (14,471)
Federal capital tax 2,526 2,497 1,428
Statutory tax rate reductions (8,359) (37,130) (1,340)
Non-taxable portion of foreign exchange (gain) loss (2,831) (8,202) 334
Other 923 1,031 799
--------- --------- ---------
Provision for income taxes $ 36,183 $ 23,323 $ 19,970
========= ========= =========
Current
Income taxes $ 225 $ 785 $ --
Federal capital taxes 2,526 2,497 1,428
Future 33,432 20,041 18,542
--------- --------- ---------
$ 36,183 $ 23,323 $ 19,970
========= ========= =========
Effective tax rate 35.0% 16.4% 52.2%
--------- --------- ---------
A significant portion of the Company's taxable income is generated by a
partnership. Income taxes are incurred on the partnership's taxable income in
the year following its inclusion in the Company's consolidated net earnings.
Current income tax will vary and is dependent upon the amount of capital
expenditures incurred and the method of deployment.
In 2004, the Government of Alberta introduced legislation to reduce its
corporate income tax rate from 12.5% to 11.5% and retain the resource allowance
and non-deductible crown royalties regime until 2007.
b) The net future income tax liability is comprised of:
As at December 31, 2004 2003
------------------------------------------------------------------------------- -------------
Future income tax liabilities
Property and equipment in excess of tax values $ 199,931 $ 169,855
Timing of partnership items 67,089 62,975
Foreign exchange gain on long-term debt 10,169 7,934
Future income tax assets
Attributed Canadian royalty income (9,015) (9,667)
Asset retirement obligations (6,057) (6,024)
Non-capital losses carried forward (53) (789)
Other (868) (477)
------------- -------------
Net future income tax liability $ 261,196 $ 223,807
============= =============
15. FINANCIAL INSTRUMENTS
a) DERIVATIVE FINANCIAL INSTRUMENTS AND RISK MANAGEMENT ACTIVITIES
The Company is exposed to risks from fluctuations in commodity prices,
interest rates and Canada/US currency exchange rates. The Company utilizes
various derivative financial instruments for non-trading purposes to
manage and mitigate its exposure to these risks. As outlined in Note 2,
effective January 1, 2004, the Company elected to account for all
derivative financial instruments using the mark-to-market method.
Risk management activities during the year, utilizing derivative
instruments, relate to commodity price hedges and cross currency interest
rate swap arrangements and are summarized below:
i) COMMODITY PRICE HEDGES
The Company enters into hedge transactions relating to crude oil
and natural gas prices to mitigate volatility in commodity prices.
The contracts entered into are forward transactions providing the
Company with a range of prices on the commodities sold. Outstanding
hedge contracts at December 31, 2004 are:
NOTIONAL PRICE MARK-TO-MARKET
COMMODITY TERM VOLUME/DAY COLLAR GAIN (LOSS)
Natural Gas Jan.1-Mar.31/05 23,810 mcf $7.51-$11.56/mcf $ 2,348
Crude oil Jan.1-Dec. 31/05 1,000 bbls US $35.00-$48.75/bbl (363)
----------------
Unrealized hedge gain $ 1,985
=================
The following table outlines the financial agreements entered into subsequent to December 31, 2004:
Natural gas April 1 - Oct. 31/05 14,286 mcf $6.21 - $8.87/mcf
Crude oil Feb. 1 - Dec. 31/05 500 bbls US $43.00 - $49.51/bbl
ii) DEFERRED RISK MANAGEMENT LOSS
At the beginning of the year, the Company elected not to designate
any of its risk management activities as accounting hedges under
Accounting Guideline 13 and accordingly accounts for all derivative
instruments using the mark-to-market method. As a result, on
January 1, 2004, the
Company recorded a liability and a deferred risk management loss of
$10.9 million relating to then outstanding commodity hedges and the
interest rate swap. During the year $3.6 million of the deferred
loss was charged to earnings. The remaining balance of $7.3 million
relates to the interest rate swap and will be charged to earnings
in annual amounts of $1.6 million until eliminated in 2009.
iii) CROSS CURRENCY INTEREST RATE SWAP
Concurrent with the closing of the senior notes offering, the
Company entered into interest rate swap arrangements with its
banking syndicate that convert fixed rate U.S. dollar denominated
interest obligations into floating rate Canadian dollar denominated
interest obligations. At December 31, 2004, the Company valued the
liability relating to future unrealized losses on the swap
arrangements to be $11.4 million on a mark-to-market basis.
iv) RISK MANAGEMENT LOSSES (GAINS)
Risk management (gains) and losses recognized during the year
relating to the above are summarized below:
INTEREST
COMMODITY RATE
CONTRACTS SWAP TOTAL
--------- ------- -------
Unrealized
Amortization of deferred loss $ 2,001 $ 1,642 $ 3,643
Change in fair value (3,986) 2,522 (1,464)
------- ------- -------
(1,985) 4,164 2,179
Realized
Cash settlements 9,151 (2,522) 6,629
------- ------- -------
Total $ 7,166 $ 1,642 $ 8,808
======= ======= =======
Risk management losses (gains) of $4,132 and ($4,424) for 2003 and 2002
respectively reflect realized (gains) and losses recognized under hedge
accounting.
b) OTHER FINANCIAL INSTRUMENTS AND RISK
i) CREDIT RISK MANAGEMENT
Accounts receivable include amounts receivable for oil and natural
gas sales which are generally made to large credit worthy
purchasers and amounts receivable from joint venture partners which
are recoverable from production. Accordingly, the Company views
credit risks on these amounts as low.
The Company is exposed to losses in the event of non-performance by
counter-parties to financial instruments. The Company deals with
major institutions and believes these risks are minimal.
ii) FAIR VALUE OF FINANCIAL ASSETS AND LIABILITIES
Other than its senior term notes, the fair values of the Company's
financial assets and liabilities that are included in the Company's
consolidated balance sheet as at December 31, 2004, approximate
their carrying value. The estimated fair value of senior term notes
is $218.5 million as of December 31, 2004 (2003 - $231.6 million)
based upon market information.
iii) FOREIGN CURRENCY RISK MANAGEMENT
The Company is exposed to fluctuations in the exchange rate between
the Canadian dollar and the U.S. dollar. Crude oil and to a certain
extent natural gas prices are based upon reference prices
denominated in U.S. dollars, while the majority of the Company's
expenses are denominated in Canadian dollars. When appropriate, the
Company enters into agreements to fix the exchange rate of
Canadian dollars to U.S. dollars in order to manage the risk.
During 2003, a gain of $2.5 million was realized and included in
revenue (2002 - $0.4 million). At December 31, 2003, all swaps
expired and the Company has not entered into any new arrangements.
16. CASH FLOW
Changes in non-cash working capital items increased (decreased) cash as follows:
Years ended December 31, 2004 2003 2002
- --------------------------------------------------- -------- ---------
Accounts receivable and other $(20,176) $(16,593) $ 1,312
Accounts payable 39,598 23,635 (2,608)
Taxes payable (2,526) 1,541 656
-------- -------- --------
$ 16,896 $ 8,583 $ (640)
======== ======== ========
Operating activities
Accounts receivable and other $(19,309) $ (3,675) $ (6,480)
Accounts payable 9,241 3,452 658
Taxes payable (2,526) 1,541 656
-------- -------- --------
(12,594) 1,318 (5,166)
-------- -------- --------
Financing activities
Accounts receivable and other 367 (467) --
Accounts payable (43) (920) 3,514
-------- -------- --------
324 (1,387) 3,514
-------- -------- --------
Investing activities
Accounts receivable and other (1,233) (12,451) 7,792
Accounts payable 30,399 21,103 (6,780)
-------- -------- --------
29,166 8,652 1,012
======== ======== ========
$ 16,896 $ 8,583 $ (640)
======== ======== ========
Amounts paid during the year relating to interest expense and capital taxes are
as follows:
Years ended December 31, 2004 2003 2002
- --------------------------------------------------- -------- ---------
Interest paid $28,604 $26,923 $15,042
Current income taxes paid $ 4,952 $ 1,485 $ 1,084
17. COMMITMENTS AND CONTINGENT LIABILITIES
a) COMMITMENTS
The Company has committed to certain payments over the next five years,
as follows:
2005 2006 2007 2008 2009
-------- -------- -------- -------- --------
Operating leases $ 5,025 $ 10,985 $ 4,548 $ -- $ --
Office rent 1,268 1,356 249 -- --
MPP partnership distributions 9,172 9,172 9,172 9,172 3,057
Senior notes (US $165 million) -- -- -- -- 198,594
Other 136 243 -- -- --
-------- -------- -------- -------- --------
$ 15,601 $ 21,756 $ 13,969 $ 9,172 $201,651
======== ======== ======== ======== ========
b) LEGAL PROCEEDINGS
The Company is involved in various legal claims associated with normal
operations. These claims, although unresolved at the current time, in
management's opinion, are minor in nature and are not expected to have a
material impact on the financial position or results of operations of the
Company.
18. UNITED STATES ACCOUNTING PRINCIPLES AND REPORTING
RECONCILIATION OF CONSOLIDATED FINANCIAL STATEMENTS TO UNITED STATES GENERALLY
ACCEPTED ACCOUNTING PRINCIPLES
These consolidated financial statements have been prepared in accordance with
accounting principles generally accepted in Canada ("Canadian GAAP") which, in
most respects, conforms to accounting principles generally accepted in the
United States of America ("U.S. GAAP"). The significant differences in those
principles, as they apply to the Company's statements of earnings, balance
sheets and statements of cash flows, are described below.
RECONCILIATION OF NET EARNINGS UNDER CANADIAN GAAP TO U.S. GAAP:
For the years ended December 31, NOTE 2004 2003 2002
- ------------------------------------------------------------------ ----------- ---------- ------------
(restated
note F)
Net earnings for year, as reported $ 63,633 $ 118,880 $ 18,312
Adjustments
Accretion of asset retirement obligations H - - 1,241
Depreciation and depletion H - - 542
Site restoration provision H - - (1,072)
Related income taxes H - - (225)
Accounting for income taxes D - (743) (5,402)
Risk management gain (loss), net F 2,236 (14,425) 8,659
----------- ---------- ------------
Net earnings before change in accounting
principle - U.S. GAAP 65,869 103,712 22,055
Cumulative effect of change in accounting
principle, net H - (5,681) -
----------- ---------- ------------
Net earnings - U.S. GAAP $ 65,869 $ 98,031 $ 22,055
========== ========= ===========
CONSOLIDATED STATEMENTS OF EARNINGS - U.S. GAAP
For the years ended December 31, NOTE 2004 2003 2002
- ------------------------------------------------------------------ ----------- ---------- ------------
Revenue, net of royalties $ 298,243 $ 263,999 $ 179,100
Expenses
Operating 55,655 49,916 45,546
Transportation 8,595 8,447 8,167
General and administrative 15,215 12,206 9,845
Interest and finance charges 33,733 30,595 23,197
Depletion and depreciation H 82,554 61,749 54,931
Foreign exchange (gain) loss (14,631) (47,368) 1,583
Accretion of asset retirement obligations H 1,670 1,436 1,072
Stock-based compensation 3,410 793 190
Risk management loss (gain) F 5,165 28,428 (13,083)
----------- ---------- ------------
Net earnings before taxes and non-controlling 106,877 117,797 47,652
interest
Income tax expense F 37,590 14,195 25,597
Non-controlling interest 3,418 (110) --
----------- ---------- ------------
Net earnings before change in accounting
Principle - U.S. GAAP 65,869 103,712 22,055
Cumulative effect of change in accounting
principle, net H -- (5,681) --
----------- ---------- ------------
Net earnings - U.S. GAAP $ 65,869 $ 98,031 $ 22,055
=========== ========== ============
Net earnings per common share before change in
Accounting principle - U.S. GAAP
Basic $ 0.56 $ 0.89 $ 0.19
Diluted $ 0.53 $ 0.85 $ 0.19
Net earnings per common share - U.S. GAAP
Basic $ 0.56 $ 0.84 $ 0.19
Diluted $ 0.53 $ 0.80 $ 0.19
STATEMENTS OF OTHER COMPREHENSIVE INCOME
For the years ended December 31, NOTE 2004 2003 2002
- ------------------------------------------------------------------ ----------- ---------- ------------
Net earnings for the year - U.S. GAAP $ 65,869 $ 98,031 $ 22,055
Accounting for hedging F - 858 (1,741)
----------- ---------- ------------
Comprehensive income E $ 65,869 $ 98,889 $ 20,314
========== ========= ===========
CONDENSED CONSOLIDATED BALANCE SHEETS
As at December 31, NOTE 2004 2003
- ------------------------------------------ ---------- -- ------------------------------- --------------------------------
AS REPORTED U.S. GAAP As reported U.S. GAAP
Assets
Cash D $ 10,068 $ 10,068 $ 15,548 $ 11,378
Other current assets D 117,098 117,098 94,937 99,107
Property and equipment 1,178,550 1,178,550 942,303 942,303
Goodwill 7,914 7,914 - -
Deferred financing charges and other G 9,729 6,944 11,532 8,109
Deferred risk management loss F 7,252 - - -
Unrealized loss on guarantee I - 1,623 - -
------------- ------------- -------------- -------------
$ 1,330,611 $ 1,322,197 $ 1,064,320 $ 1,060,897
============= ============= ============== =============
Liabilities and shareholders' equity
Current liabilities $ 345,784 $ 345,784 $ 253,142 $ 253,142
Senior term notes G 198,594 195,809 213,246 209,823
Asset retirement obligations 18,006 18,006 17,329 17,329
Unrealized hedge liability F 11,416 11,416 - 10,895
Guarantee obligation I - 1,623 - -
Future income taxes C,F,H 261,196 258,357 223,807 219,561
Non-controlling interest 71,537 71,537 (110) (110)
------------- ------------- -------------- -------------
906,533 902,532 707,414 710,640
------------- ------------- -------------- -------------
Capital stock D 135,526 165,513 131,577 161,564
Contributed surplus 3,840 3,840 760 760
Retained earnings 284,712 250,312 224,569 187,933
------------- ------------- -------------- -------------
424,078 419,665 356,906 350,257
------------- ------------- -------------- -------------
$ 1,330,611 $ 1,322,197 $ 1,064,320 $ 1,060,897
============= ============= ============== =============
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the years ended December 31, 2004 2003 2002
- -------------------------------------------------------- ---- ------------- ------------- --------------
Operating activities
Net earnings $ 65,869 $ 98,031 $ 22,055
Amortization of deferred charges and other 2,101 2,208 1,367
Depletion and depreciation 82,554 61,749 54,931
Accretion of asset retirement obligations 1,670 7,117 1,072
Unrealized foreign exchange (gain) loss (14,652) (47,388) 1,583
Future income taxes 34,839 10,913 24,169
Unrealized risk management (gain) loss (1,464) 24,296 (8,659)
Other 6,214 (2,033) (446)
Change in non-cash working capital 20,742 20,525 (16,702)
------------- ------------- --------------
Cash from operating activities 197,873 175,418 79,370
------------- ------------- --------------
Cash from financing activities 111,179 121,443 75,780
------------- ------------- --------------
Cash used in investing activities (310,362) (285,483) (155,150)
------------- ------------- --------------
Change in cash (1,310) 11,378 --
Cash, beginning of year 11,378 -- --
------------- ------------- --------------
Cash, end of year $ 10,068 $ 11,378 $ --
============= ============= ==============
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
a) FULL COST ACCOUNTING
The full cost method of accounting for crude oil and natural gas
operations under Canadian and U.S. GAAP differ in the following respects.
Under U.S. GAAP, an impairment test is applied to ensure the unamortized
capitalized costs in each cost centre do not exceed the sum of the present
value, discounted at 10%, of the estimated constant dollar, future net
operating revenue from proved reserves plus unimpaired unproved property
costs less applicable taxes. Under Canadian GAAP, a similar impairment
test calculation is performed with the exception that cash flows from
proved reserves are undiscounted and utilize escalated pricing to
determine whether impairments exist. If an impairment exists, then the
amount of the write down is determined using the fair value of reserves.
The Company has completed a impairment test calculation at December 31,
2004 and for all prior years, with no write-downs required under either
Canadian or U.S. GAAP.
b) STOCK-BASED COMPENSATION
Under Canadian GAAP, compensation costs have been recognized in the
consolidated financial statements for stock options granted to employees
and directors on or after January 1, 2003. For the effect on periods prior
to 2003 of stock-based compensation on the Canadian GAAP financials, which
would be the same adjustment under U.S. GAAP, see Note 11.
c) FUTURE INCOME TAXES
Under U.S. GAAP enacted tax rates are used to calculate future taxes,
whereas Canadian GAAP uses substantively enacted tax rates. The future
income tax adjustments included in the reconciliation of net earnings
under Canadian GAAP to U.S. GAAP and the balance sheet effects include the
effect of such rate differences, if any, as well as the tax effect of the
other reconciling items noted.
The net future income tax liability is comprised of:
As at December 31, 2004 2003
---------------------------------------------------------------- ----------- ------------
Future income tax liabilities
Property and equipment $ 199,931 $ 169,855
Timing of partnership items 67,089 62,975
Foreign exchange gain on long-term debt 10,169 7,934
Future income tax assets
Attributed Canadian royalty income (9,015) (9,667)
Asset retirement obligations (6,057) (6,024)
Non-capital losses carried forward (53) (789)
Other (3,707) (4,723)
---------- -----------
$ 258,357 $ 219,561
========== ===========
d) FLOW THROUGH SHARES
U.S. GAAP requires flow-through shares be recorded at their fair value
without any adjustment for the renouncement of the tax deductions and any
temporary difference resulting from the renouncement must be recognized in
the determination of tax expense in the year incurred.
There were no flow-through shares issued in 2004. The impact of recording
flow-through shares at their fair value for the year ended December 31,
2003, was to increase the future income tax provision by $0.7 million
(2002 - $5.4 million) and to increase capital stock by a corresponding
amount.
During 2003, the Company received $4.2 million in proceeds from the
issuance of flow-through shares of which $4.2 million remained unspent as
at December 31, 2003 (2002 - $17.6 million). Accordingly, under U.S. GAAP,
these proceeds would be disclosed separately on the balance sheet as
restricted cash and would not be treated as cash or cash equivalents for
statement of cash flow reporting purposes. At December 31, 2002, the
separate disclosure of restricted cash resulted in a negative ending cash
balance which was reallocated to short term debt and reflected as a
financing activity in the consolidated statements of cash flow.
e) COMPREHENSIVE INCOME
Statement of Financial Accounting Standards 130, "Comprehensive Income",
requires the reporting of comprehensive income in addition to net
earnings. Comprehensive income includes net income plus other
comprehensive income. Management believes that it has no comprehensive
income other than as described under Note 18(f).
f) DERIVATIVE INSTRUMENTS AND HEDGING
On January 1, 2004, the Company implemented under Canadian GAAP, EIC 128
which requires derivatives not designated as hedges to be recorded on the
balance sheet as either assets or liabilities at their fair value. Changes
in the derivative's fair value are recognized in current period earnings.
Under the transitional rules, any gain or loss at the implementation date
is deferred and recognized into revenue once realized. At January 1, 2004
a deferred loss was recognized in the amount of $10.9 million. During the
year, $3.6 million of the deferred loss was charged to earnings. The
remaining balance of $7.3 million relates to the interest rate swap and
will be recognized in annual amounts of $1.6 million until eliminated in
2009. Currently, the Company has not designated any of its financial
instruments as hedges for accounting purposes.
For U.S. GAAP, the Company adopted Statement of Financial Accounting
Standards ("SFAS") 133 effective January 1, 2001. SFAS 133 requires all
derivatives to be recorded on the balance sheet as either assets or
liabilities at their fair value. Changes in the derivative's fair value
are recognized in current period earnings unless specific hedge accounting
criteria are met. To eliminate future GAAP reconciling items the Company
has not designated any of its financial instruments, for year ended
December 31, 2004, as hedges for U.S. GAAP purposes under SFAS 133.
The deferred loss, recognized at January 1, 2004 under the Canadian GAAP
transitional provision of EIC 128, has already been recognized in earnings
for U.S. GAAP and becomes a reconciling item at December 31, 2004.
f) DERIVATIVE INSTRUMENTS AND HEDGING (CONTINUED)
Prior to January 1, 2004, the natural gas and crude oil futures contracts
were accounted for as cash flow hedges. These contracts were recorded at
fair value on the balance sheet as a $2.0 million liability at December
31, 2003 . The effective portion of the change in fair value is recorded
in comprehensive income, net of tax. The ineffective portion of the change
in fair value was recorded in net earnings, net of tax. The effective
portion of these commodity contracts was a $0.9 million gain, which is
recorded in comprehensive income as at December 31, 2003 (2002 - $1.7
million loss). The ineffective portion of these commodity contracts is
$nil which is recorded in net earnings as at December 31, 2003 (2002 -
$253 thousand loss).
During 2003, it was determined that the interest rate swap arrangements
relating to the Company's senior term notes, Note 7, do not qualify for
hedge accounting in accordance with SFAS 133 and should be accounted for
on a mark-to-market basis. Accordingly, 2002 comparative amounts have been
restated to reflect the appropriate accounting treatment. As a result, the
change in the fair value of the interest rate swap arrangements of $15.4
million, previously recorded as an increase to the senior term notes, was
charged to earnings, net of the future income taxes of $6.5 million, with
a corresponding increase in net earnings and retained earnings of $8.9
million. Basic earnings per share and diluted earnings per share for the
year ended December 31, 2002, increased $0.07 and $0.08 per share
respectively, as a result of the restatement.
g) DEFERRED FINANCING CHARGES
Under U.S. GAAP, discounts on long-term debt are classified as a reduction
of long-term debt rather than as deferred financing charges. At December
31, 2004 deferred financing charges and senior term notes were reduced by
$2.8 million (2003 - $3.4 million).
h) ASSET RETIREMENT OBLIGATIONS
In 2003, the Company early adopted the Canadian Accounting Standard for
asset retirement obligations, as outlined in the CICA handbook, section
3110. This standard is equivalent to U.S. SFAS 143, "Accounting for Asset
Retirement Obligations", which was effective for fiscal periods beginning
on or after January 1, 2003. Early adopting the Canadian standard
eliminated a U.S. GAAP reconciling item in respect to accounting for the
obligations. However, a difference is created in how the transition
amounts are disclosed. U.S. GAAP requires the cumulative impact of a
change in an accounting principle be presented in the current year
consolidated statement of earnings and prior periods not be restated.
Consequently, prior year comparative periods, under U.S. GAAP, have been
revised to eliminate the prior period restatement made under Canadian
GAAP.
i) GUARANTEE
As discussed in Note 4 to the consolidated financial statements, Mazeppa
Processing Partnership ("MPP") has guaranteed payment of certain
obligations of its limited partner under a credit agreement between the
limited partner and a syndicate of lenders. Canadian GAAP requires
disclosure only, of this type of financial arrangement. U.S. GAAP under
FIN 45 "Guarantor's Accounting and Disclosure Requirements for Guarantees,
Including Indirect Guarantees of Indebtedness of Others", requires the
fair valuation of the guarantee and the inclusion of the liability in the
consolidated balance sheets.
j) STATEMENTS OF CASH FLOW
The consolidated statements of cash flow include under investing
activities, changes in working capital for items not affecting cash, such
as accounts payable and accounts receivable, related to the non-cash
elements of property and equipment additions. This presentation is not
permitted under U.S. GAAP. The amount at December 31, 2004 of $29.2
million (2003 - $8.7 million, 2002 - $1.0 million) has been reallocated to
the change in non-cash operating working capital for U.S. GAAP
presentation purposes.
k) RECEIVABLE AND PAYABLE AMOUNTS
As at December 31, 2004 2003
--------------------------------------------------------------------- ------------ -----------
(in thousands of Canadian dollars)
Accounts receivable and other includes the following:
Revenue receivable $ 72,510 $ 63,687
Joint interest receivable 32,077 21,685
Other receivables 12,511 13,735
------------ -----------
$ 117,098 $ 99,107
=========== ===========
As at December 31, 2004 2003
--------------------------------------------------------------------- ------------ -----------
(in thousands of Canadian dollars)
Accounts payable and accrued liabilities includes the following:
Trade payables $ 97,608 $ 67,753
Royalties payable 18,488 10,920
Other payables 9,387 7,212
------------ -----------
$ 125,483 $ 85,885
=========== ===========
l) RECENT ACCOUNTING PRONOUNCEMENTS
During 2004, the following new standards were issued:
EXCHANGE OF NON-MONETARY ASSETS
In December 2004, the FASB issued Statement of Financial Accounting
Standards No. 153 "Exchanges of Non-monetary Assets - an amendment of APB
Opinion No. 29". This Statement amends APB Opinion 29 to eliminate the
exception for non-monetary exchanges of similar productive assets and
replaces it with a general exception for exchanges of non-monetary assets
that do not have commercial substance. A non-monetary exchange has
commercial substance if the future cash flows of the entity are expected
to change significantly as a result of the exchange. The adoption of this
Standard is not expected to have any material impact on the Company's
financial position or results of operations.
SHARE-BASED PAYMENT
Also in December 2004, the FASB issued revised SFAS No. 123 "Share-Based
Payment". This Statement requires that the cost resulting from all
share-based transactions be recorded in the financial statements. The
Statement establishes fair value as the measurement objective in
accounting for share-based payment arrangements and requires all entities
to apply a fair-value-based measurement in accounting for share-based
payment transactions with employees. The Statement also establishes fair
value as the measurement objective for transactions in which an entity
acquires goods or services from non-employees in share-based payment
transactions. The Statement replaces FASB Statement No. 123 "Accounting
for Stock-Based Compensation" and supersedes APB Opinion No. 25
"Accounting for Stock Issued to Employees". The provisions of this
Statement will be effective for the Company beginning with its fiscal year
ending 2006. The Company is currently evaluating the impact this new
Standard will have on its operations, but believes that it will not have a
material impact on the Company's financial position or results of
operations.
SUPPLEMENTAL OIL AND NATURAL GAS INFORMATION (UNAUDITED)
A) NET PROVED OIL AND NATURAL GAS RESERVES
The net proved oil and natural gas reserve estimates as at December 31, 2004,
2003 and 2002 set forth below were prepared in accordance with guidelines
established by the Securities and Exchange Commission and accordingly were based
on existing economic and operating conditions. Oil and natural gas prices in
effect as of the respective year ends were used without any escalation except in
those instances where the sale is covered by contract, in which case the
applicable contract price is used. Operating costs, royalties and future
development costs were based on current costs with no escalation.
There are numerous uncertainties inherent in estimating quantities of proved
reserves and in projecting the future rates of production and timing of
development expenditures. The following reserve data represents estimates only
and should not be construed as being exact. Moreover, the present value should
not be construed as the current market value of the Company's oil and natural
gas reserves or the costs that would be incurred to obtain equivalent reserves.
All of the reserves are located in Canada.
Estimated Quantities of Reserves
Years ended December 31,
--------------------------------------------------------------------------------
2004 2003 2002
--------------------------------------------------------------------------------
CRUDE OIL NATURAL Crude oil Natural Crude oil Natural
& NGL'S GAS & NGL's Gas & NGL's Gas
(MBBLS) (MMCF) (mbbls) (mmcf) (mbbls) (mmcf)
--------------------------------------------------------------------------------
Balance, beginning of year 14,542 326,573 10,723 314,501 9,777 262,448
Revisions of previous estimates 2,797 16,547 2,297 (12,821) 529 11,712
Extensions, discoveries and
other additions 3,026 47,713 2,869 54,128 1,829 58,853
Acquisitions of minerals in place 427 9,444 404 2,333 514 18,805
Dispositions of minerals in place (440) (3,160) - - (84) (5,343)
Production (1,581) (37,142) (1,751) (31,568) (1,842) (31,974)
--------------------------------------------------------------------------------
Balance, end of year 18,771 359,975 14,542 326,573 10,723 314,501
================================================================================
Proved developed reserves
Balance, beginning of year 10,309 288,899 9,723 293,836 8,938 232,319
Balance, end of year 14,265 292,306 10,309 288,899 9,723 293,836
================================================================================
B) CAPITALIZED COSTS RELATED TO OIL AND NATURAL GAS ACTIVITIES
The aggregate capitalized costs of oil and natural gas activities and costs
incurred in oil and natural gas property acquisitions, development and
exploration activities are as follows (excluding MPP and parts inventory):
Capitalized costs
As at December 31, 2004 2003
-------------------------------------------------------------------------------- ------------- ------------
(in thousands of Canadian dollars)
Proved properties $ 1,218,826 $ 939,598
Unproved properties:
Acquisition 117,194 103,977
Exploration 83,238 69,820
Accumulated depletion and depreciation (318,583) (238,413)
------------- ------------
$ 1,100,675 $ 874,982
============= ============
Costs incurred on unproved properties
Includes costs incurred in
----------------------------------------------------------
As at December 31, CUMM. Prior
2004 2004 2003 2002 Years
------------------------------------ ---------- ---------- ---------- ---------- ----------
(in thousands of Canadian dollars)
Acquisition $ 117,194 $ 13,217 $ 2,933 $ (9,720) $ 110,764
Exploration 83,238 13,418 15,615 4,000 50,205
---------- ---------- ---------- ---------- ----------
$ 200,432 $ 26,635 $ 18,548 $ (5,720) $ 160,969
========== ========== ========== ========== ==========
Costs incurred
Years ended December 31, 2004 2003 2002
------------------------------------------------------------ ------------- -------------- -------------
(in thousands of Canadian dollars)
Acquisition costs (net of disposition)
Proved properties $ 12,686 $ 11,224 $ 27,157
Unproved properties 13,217 2,933 (9,720)
Development costs
Development of proved undeveloped reserves 60,227 25,232 21,280
Other 136,198 115,612 52,971
Exploration costs 76,648 64,615 63,462
------------- -------------- -------------
Total costs incurred $ 298,976 $ 219,616 $ 155,150
============= ============== =============
Costs are transferred into the depletion base on an ongoing basis as the
undeveloped properties are evaluated and proved reserves are established or
impairment determined. Pending determination of proved reserves attributable to
the above costs, the Company cannot assess the future impact on the amortization
rate.
C) STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS AND CHANGES
THEREIN RELATING TO PROVED OIL AND NATURAL GAS RESERVES
The standardized measure of discounted future net cash flows and changes therein
relating to proved oil and natural gas reserves ("Standardized Measure") does
not purport to present the fair market value of the Company's oil and natural
gas properties. An estimate of such value should consider, among other factors,
anticipated future prices of oil and natural gas, the probability of recoveries
in excess of existing proved reserves and acreage prospects, and perhaps
different discount rates. It should be noted that estimates of reserve
quantities, especially from new discoveries, are inherently imprecise and
subject to substantial revisions. The computation also excludes values
attributable to the Company's midstream interests, referred to in the Financial
Statements as MPP.
Under the Standardized Measure, future cash inflows were estimated by applying
year end prices, adjusted for contracts currently in place to deliver production
to the estimated future production of year end proved reserves. Future cash
inflows were reduced by estimated future production and development costs based
on year end costs to determine pre-tax cash inflows. Future taxes were computed
by applying the statutory tax rate to the excess of pre-tax cash inflows over
the Company's tax basis in the associated proved oil and natural gas properties.
Tax credits and net operating loss carry forwards were also considered in the
future income tax calculation. Future net cash inflows after income taxes were
discounted using a 10 percent annual discount rate to arrive at the Standardized
Measure.
Years ended December 31, 2004 2003 2002
----------------------------------------------------------- -------------- -------------- -------------
(in thousands of Canadian dollars)
Future cash inflows $ 3,160,270 $ 2,467,604 $ 2,460,747
Future production costs (971,392) (785,187) (507,576)
Future development costs (102,557) (76,708) (56,209)
-------------- -------------- -------------
Future net cash flows 2,086,321 1,605,709 1,896,962
Income taxes (539,539) (460,291) (733,434)
-------------- -------------- -------------
Total undiscounted future net cash flows 1,546,782 1,145,418 1,163,528
10 percent annual discount for estimated timing of
cash inflows (793,904) (592,409) (509,831)
-------------- -------------- -------------
Standardized measure of discounted
future net cash flows $ 752,878 $ 553,009 $ 653,697
============= ============== =============
(1) The Company estimates that it will incur $31.4 million in 2005, $24.1 million in 2006 and $5.6 million in
2007 to develop proved undeveloped reserves.
The following table sets forth an analysis of changes in the standardized
measure of discounted future net cash flows from proved oil and natural gas
reserves:
Years ended December 31, 2004 2003 2002
----------------------------------------------------------- -------------- -------------- -------------
(in thousands of Canadian dollars)
Beginning of year $ 553,009 $ 653,697 $ 317,461
Sales of production, net of production costs (226,408) (197,323) (126,745)
Net change in sales prices, net of production costs 42,728 (64,509) 502,652
Extensions, discoveries and additions 161,106 144,565 198,811
Changes in estimated future development costs (54,838) (39,965) (58,187)
Development costs incurred during the period which
reduced future development costs 184,053 85,586 66,881
Revisions in quantity estimates 306,271 (69,386) 70,721
Accretion of discount 75,908 101,612 42,348
Purchase of reserves (7,749) 6,328 55,129
Sales of reserves 4,416 - (20,051)
Net change in income tax (42,270) 156,350 (234,813)
Changes in production rates (timing) and other (243,348) (223,946) (160,510)
-------------- -------------- -------------
Standardized measure, end of year $ 752,878 $ 553,009 $ 653,697
============== ============== =============