CONSOLIDATED BALANCE SHEET
 |
| As at December 31 ($thousands) |
2001 |
2000 |
1999 |
|
| |
|
(Note 1) |
(Note 1) |
| Assets |
|
|
| Current assets |
|
|
|
| Cash and cash equivalents |
$ 979 |
$ 846 |
$ 2,482 |
| Accounts receivable |
100,089 |
77,086 |
15,506 |
| Other |
4,869 |
6,474 |
1,365 |
| | | |
| |
105,937 |
84,406 |
19,353 |
| | | |
| Property, plant and equipment |
2,667,504 |
1,791,649 |
789,174 |
| Accumulated depletion and depreciation |
(489,188) |
(308,356) |
(232,889) |
| | | |
| |
2,178,316 |
1,483,293 |
556,285 |
| | | |
Deferred reorganization charges,
net of amortization (Note 2) |
- |
253 |
1,263 |
| | | |
| |
$ 2,284,253 |
$ 1,567,952 |
$ 576,901 |
| | | |
| Liabilities and Equity |
|
|
|
| Current Liabilities |
|
|
|
| Accounts payable |
$ 72,341 |
$ 91,135 |
$ 19,705 |
| Distributions payable to Unitholders (Note 9) |
20,860 |
18,925 |
7,547 |
| Payable to related company (Note 6) |
7,915 |
14,222 |
2,852 |
| | | |
| |
101,116 |
124,282 |
30,104 |
| | | |
| Bank Debt (Note 3) |
412,589 |
275,944 |
131,315 |
| Future income taxes (Note 5) |
333,560 |
353,115 |
33,593 |
| Accumulated site restoration |
55,403 |
37,596 |
14,035 |
| Deferred credits (Note 2) |
6,591 |
- |
- |
| Payable to related party (Note 6) |
1,909 |
- |
- |
| Non-controlling interest (Note 7) |
- |
25,013 |
- |
| | | |
| |
810,052 |
691,668 |
178,943 |
| | | |
| Equity |
|
|
|
| Unitholders' capital (Note 4) |
1,826,507 |
1,054,859 |
592,693 |
| Accumulated income |
324,570 |
144,301 |
78,328 |
| Accumulated cash distributions (Note 9) |
(777,992) |
(447,158) |
(303,167) |
| | | |
| |
1,373,085 |
752,002 |
367,854 |
| | | |
| |
$ 2,284,253 |
$ 1,567,952 |
$ 576,901 |
|
| Signed on behalf of the Board: |
|
| "signed" |
"signed" |
| Douglas R. Martin |
Robert L. Normand |
| Director |
Director |
CONSOLIDATED STATEMENT OF INCOME
|
|
|
For the year ended December 31 ($thousands except per
Unit amounts) |
2001 |
2000 |
1999 |
|
| |
|
(Note 1) |
(Note 1) |
| Revenues |
|
|
|
| Oil and gas sales |
$ 639,379 |
$ 343,182 |
$ 169,541 |
| Crown royalties |
(101,114) |
(65,451) |
(23,902) |
| Freehold and other royalties |
(31,546) |
(15,492) |
(8,243) |
| | | |
| |
506,719 |
262,239 |
137,396 |
| Interest and other income |
858 |
611 |
1,045 |
| | | |
| |
507,577 |
262,850 |
138,441 |
| | | |
| Expenses |
|
|
|
| Operating |
120,082 |
54,997 |
37,228 |
| General and administrative |
12,971 |
7,202 |
5,726 |
| Management fee (Note 6) |
9,323 |
4,556 |
2,204 |
| Interest (Note 3) |
17,605 |
15,322 |
9,078 |
| Depletion, depreciation and amortization |
194,080 |
80,309 |
61,857 |
| | | |
| |
354,061 |
162,386 |
116,093 |
| | | |
| Income before taxes |
153,516 |
100,464 |
22,348 |
| | | |
| Capital taxes |
4,722 |
2,936 |
1,551 |
| Future income tax provision (recovery) (Note 5) |
(31,475) |
15,378 |
(4,957) |
| | | |
| |
(26,753) |
18,314 |
(3,406) |
| | | |
| Net Income |
$ 180,269 |
$ 82,150 |
$ 25,754 |
| | | |
| Net income per Trust Unit |
|
|
|
| Basic |
$ 3.28 |
$ 3.06 |
$ 1.25 |
| | | |
| Diluted |
$ 3.28 |
$ 3.05 |
$ 1.25 |
| | | |
Weighted average number of Trust Units
outstanding (thousands) |
|
|
|
| Basic |
54,907 |
26,841 |
20,532 |
| Diluted |
54,956 |
26,928 |
20,607 |
|
|
| CONSOLIDATED STATEMENT OF ACCUMULATED INCOME |
|
|
| For the year ended December 31 ($thousands) |
2001 |
2000 |
1999 |
|
| |
|
(Note 1) |
(Note 1) |
| Accumulated income, beginning of year |
$ 144,301 |
$ 78,328 |
$ 52,574 |
| Change in accounting policy (Note 2) |
- |
(16,177) |
- |
| Net income |
180,269 |
82,150 |
25,754 |
| | | |
| Accumulated income, end of year |
$ 324,570 |
$ 144,301 |
$ 78,328 |
|
|
| CONSOLIDATED STATEMENT OF CASH FLOWS |
|
|
| For the year ended December 31 ($thousands) |
2001 |
2000 |
1999 |
|
| |
|
(Note 1) |
(Note 1) |
| Operating Activities |
|
|
|
| Net income |
$ 180,269 |
$ 82,150 |
$ 25,754 |
| Depletion, depreciation and amortization |
194,080 |
80,309 |
61,857 |
| Future income taxes (recovery) (Note 5) |
(31,475) |
15,378 |
(4,957) |
| Site restoration and abandonment costs incurred |
(2,628) |
(1,471) |
(1,124) |
| Gain on sale of investment |
- |
- |
(565) |
| | | |
| Funds flow from operations |
340,246 |
176,366 |
80,965 |
| Decrease (increase) in non-cash operating working capital |
(52,928) |
(11,354) |
32 |
| | | |
| |
287,318 |
165,012 |
80,997 |
| | | |
| Financing Activities |
|
|
|
| Issue of Trust Units, net of issue costs (Note 4) |
151,411 |
120,600 |
54,689 |
| Cash distributions to Unitholders |
(328,899) |
(132,613) |
(70,603) |
| Bank debt (payments) proceeds |
58,021 |
77,765 |
(53,579) |
| | | |
| |
(119,467) |
65,752 |
(69,493) |
| | | |
| Investing Activities |
|
|
|
| Property, plant and equipment |
(228,345) |
(64,984) |
(25,509) |
| Proceeds on sale of property, plant and equiptment |
75,276 |
18,481 |
16,957 |
| Corporate acquisitions (Notes 1 and 7) |
(14,649) |
(186,897) |
(2,925) |
| Proceeds on sale of investments |
- |
1,000 |
773 |
| | | |
| |
(167,718) |
(232,400) |
(10,704) |
| | | |
| Increase (decrease) in cash |
133 |
(1,636) |
800 |
| Cash, beginning of year |
846 |
2,482 |
1,682 |
| Cash, end of year |
$ 979 |
$ 846 |
$ 2,482 |
|
| | | |
| Supplementary Cash Flow Information |
$ |
$ |
$ |
| Cash income taxes paid |
- |
- |
- |
| Cash interest paid |
$ 17,162 |
$ 15,199 |
$ 9,001 |
|
CONSOLIDATED STATEMENT OF ACCUMULATED CASH DISTRIBUTIONS
|
| For the year ended December 31 ($thousands) |
2001 |
2000 |
1999 |
|
| |
|
(Note 1) |
(Note 1) |
| Accumulated cash distributions, beginning of year |
$ 447,158 |
$ 303,167 |
$ 228,272 |
| Cash distributions |
330,834 |
143,991 |
74,895 |
| | | |
| Accumulated cash distributions, end of year (Note 9) |
$ 777,992 |
$ 447,158 |
$ 303,167 |
|
ENERPLUS RESOURCES FUND
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 2001, 2000 AND 1999
(Tabular amounts in thousands of Canadian dollars and thousands of Units except per Unit amounts)
1. ACQUISITION OF ENERPLUS RESOURCES FUND
The Merger of EnerMark Income Fund ("EnerMark") and Enerplus Resources Fund ("Enerplus" or the "Fund") which
occurred on June 21, 2001 ("Merger") was accounted for as a reverse takeover as the Unitholders of EnerMark became
the controlling Unitholders of the Fund after the Merger. Under this form of purchase accounting, EnerMark is deemed
to have acquired Enerplus and the consolidated financial statements of the Fund for the year ended
December 31, 2001 include only EnerMark’s operating results prior to the Merger and the results of the merged Fund
thereafter. All comparative figures and references to prior years are those of EnerMark. All disclosures of Trust Units,
warrants and options and per Unit data up to June 21, 2001 Merger date have been restated using the Merger
exchange ratio of 0.173 Enerplus Unit for each EnerMark Unit (the "Merger Exchange Ratio").
EnerMark is deemed to have acquired all of the outstanding Trust Units of Enerplus on June 21, 2001 for fair market
value consideration totalling $600,745,000. The 20,863,000 Trust Units of Enerplus which were outstanding prior to
the Merger were recorded as deemed consideration at a value of $582,817,000 representing an exchange value of
$27.94 per Trust Unit. In addition, costs and other charges of $17,928,000 related to the acquisition were recorded.
The net assets acquired and liabilities assumed are as follows:
|
| Property, plant and equipment |
$ 704,838 |
| Working capital deficiency |
(10,415) |
| Long-term debt assumed |
(78,624) |
| Site restoration and abandonment |
(14,530) |
| Future income taxes |
(524) |
| | |
| Net assets acquired |
$ 600,745 |
|
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The Management of Enerplus prepares the financial statements 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, if any, as at the date of the
financial statements and the reported amounts of revenues and expenses during the reporting period. The following
significant accounting policies are presented to assist the reader in evaluating these consolidated financial statements
and, together with the following notes, should be considered an integral part of the consolidated financial statements.
(a) Organization and Basis of Accounting
The Fund is an open-end investment trust created under the laws of the
Province of Alberta operating pursuant to the
Amended and Restated Trust Indenture between EnerMark Inc., its wholly-owned subsidiary Enerplus Resources
Corporation ("ERC") and CIBC Mellon Trust Company as Trustee. The beneficiaries of the Fund (the "Unitholders") are
holders of Trust Units (the "Trust Units") issued by the Fund . The Fund is a limited-purpose trust whose purpose is to
invest in securities of its
wholly-owned subsidiary EnerMark Inc., invest in royalties granted by EnerMark Inc. and ERC,
administer the assets and liabilities of the Fund and make distributions to the Unitholders.
The Fund’s financial statements include the accounts of the Fund, EnerMark Inc. and its subsidiaries on a consolidated
basis. All inter-entity transactions have been eliminated.
(b) Property, Plant and Equipment Oil and Natural Gas
The Fund follows the full cost method of accounting. All costs of acquiring oil and natural gas properties and related
development costs are capitalized and accumulated in one cost centre. Maintenance and repairs are charged against
earnings, and renewals and enhancements which extend the recoverable reserves of the property, plant and equipment
are capitalized. During 2001, general and administrative costs of $7,547,000 (2000 - $7,925,000,
1999 - $3,734,000) were capitalized.
Gains and losses are not recognized upon disposition of oil and natural gas properties unless such a disposition would
significantly alter the rate of depletion.
Other Equipment
All other equipment is carried at cost and is depreciated over the estimated useful lives of the assets at annual rates
varying from 10% to 30%.
(c) Ceiling Test
The Fund places a limit on the aggregate cost of property, plant and equipment, which may be carried forward for
amortization against revenues of future periods (the "Ceiling Test"). The Ceiling Test is a cost recovery test whereby
the capitalized costs less accumulated depletion and depreciation, accumulated site restoration and future income
taxes are limited to an amount equal to estimated undiscounted future net revenues from proven reserves, plus the
unimpaired costs of non-producing properties, less estimated future general and administrative expenses, site restoration
costs, management fees, financing costs and capital taxes. Costs and prices at the balance sheet date are used in
determining Ceiling Test amounts. Any costs carried on the balance sheet in excess of the Ceiling Test limitation are
charged to earnings.
(d) Depletion and Depreciation
The provision for depletion and depreciation of oil and natural gas assets is calculated using the unit-of-production
method based on the Fund’s share of estimated proven reserves before royalties. Reserves are converted to equivalent
units on the basis of approximate relative energy content based on the Fund’s share of estimated proven reserves
before royalties.
(e) Site Restoration and Abandonment
The provision for estimated site restoration costs is determined using the
unit-of-production method and is included
in depletion, depreciation and amortization expense. Actual site restoration costs are charged against the accumulated
liability.
(f) Joint Venture
Substantially all oil and natural gas production activities are conducted jointly with others. Accordingly, the accounts
reflect the Fund’s proportionate interest in these activities.
(g) Income Taxes
The Fund 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 Fund distributes all of its taxable income to the Unitholders and meets the
requirements of the Income Tax Act (Canada) applicable to the Fund, no provision for income tax has been made in
the Fund.
The Fund follows the liability method of accounting for income taxes. Under this methodology, 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 Fund’s corporate subsidiaries and their respective tax bases, using substantially
enacted income tax rates. The effect of a change in income tax rates on future income tax liabilities and assets is
recognized in income in the period that the change occurs.
(h) Deferred Reorganization Charges
Deferred reorganization charges were related to the inception of EnerMark and have been amortized over a five-year
period ended March 31, 2001.
(i) Deferred Credits
The deferred credits are costs associated with the mark-to-market valuation of Enerplus‘ natural gas price foward
contracts which were "out-of-the-money" at the date of the Merger. This deferred credit will be amortized to income
over the life of the natural gas financial contract ending October 31, 2004.
(j) Financial Instruments
The Fund uses various financial instruments to manage risks associated with crude oil and natural gas price fluctuations
and to manage interest rates. The instruments are not used for trading purposes and constitute effective hedges.
Proceeds and costs realized from holding the crude oil and natural gas contracts are recognized in oil and gas revenues
at the time each transaction under a contract is settled. The costs or proceeds realized from holding the interest rate
swaps are recognized in interest expense at the time each transaction is settled.
(k) Cash and Cash Equivalents
The Fund considers all highly liquid investments with a maturity of three months or less at the time of purchase to be
cash equivalents. These cash equivalents consist primarily of funds on deposit under various terms. Cash and cash
equivalents are stated at cost which approximates fair value.
(l) Change in Accounting Policy
Effective January 1, 2000 the Fund, on a retroactive basis, adopted the liability method of accounting for income taxes
in accordance with the new Canadian Institute of Chartered Accountants income tax standard. The cumulative effect
as at
January 1, 2000 was to increase future income taxes payable and decrease accumulated income by $16,177,000.
The 1999 financial statements have not been restated for the change. The new recommendations do not affect the
Fund’s cash flow or liquidity.
3. BANK DEBT
As at December 31, 2001 Enerplus had banking arrangements for each of ERC and EnerMark Inc. under separate,
syndicated, revolving, extendible production and operating facilities (the "Facilities") in an aggregate amount of
$585,000,000
(2000 - $420,000,000, 1999 - $200,000,000). The Facilities were secured by fixed and floating charge
debentures on substantially all of the assets held by EnerMark Inc. and ERC.
The terms of the banking arrangements provided Enerplus with various borrowing options including prime rate based
advances and bankers acceptances. The average borrowing rate for the year ended December 31, 2001 was 2.98%.
Interest on the bank loan amounted to $17,346,000 in 2001 (2000 - $14,418,000, 1999 - $9,031,000).
As at March 1, 2002, Enerplus renegotiated the Facilities into a single syndicated facility (the "Combined Facility") in
the amount of $620,000,000 which will be reviewed on May 31, 2002 and annually on May 31 of each year, thereafter.
The Combined Facility is unsecured and consists of a $590,000,000, 364 day revolving committed line, with an incremental
two year term and a $30,000,000 demand operating line. As with the former Facilities, the Combined Facility allows
various borrowing options including prime rate based advances and banker’s acceptances.
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, Enerplus will be
required to maintain certain minimum balances on deposit with the syndicate agent.
The Combined Facility is the legal obligation of EnerMark Inc. and is guaranteed by ERC. Although payments to
Unitholders are subordinated to the Combined Facility, Unitholders have no direct liability to EnerMark Inc. or ERC
should their revenues be insufficient to repay the bank loan. However, the bank debt has priority over claims of and
distributions to the Unitholders.
Since a demand for payment, with respect to the operating facility, would be financed by the revolving facility, no
portion of the operating facility has been considered as current.
4. FUND CAPITAL
(a) Unitholders’ Capital Trust Units
Authorized: Unlimited Number of Trust Units
|
| Issued: (thousands) |
2001 |
2000 |
1999 |
| Units |
Amount |
Units |
Amount |
Units |
Amount |
|
| Balance, beginning of year |
40,925 |
$ 1,050,986 |
21,761 |
$ 592,693 |
18,540 |
$ 538,004 |
| Issued for cash: |
|
|
|
|
|
|
| Pursuant to public offerings |
4,313 |
101,039 |
4,576 |
109,835 |
2,860 |
47,952 |
| Pursuant to Option Plans |
135 |
2,530 |
128 |
2,125 |
29 |
419 |
| Pursuant to the exercise of warrants |
1,197 |
33,319 |
17 |
404 |
- |
- |
| Pursuant to the expiry of warrants |
- |
2,846 |
- |
- |
- |
- |
Issued pursuant to the deemed
acquisition of Enerplus (Note 1) |
20,863 |
582,364 |
- |
- |
- |
- |
Issued pursuant to the management
agreement (Note 6) |
173 |
5,000 |
- |
- |
- |
- |
| Distribution Reinvestment Plan |
659 |
16,577 |
407 |
9,314 |
332 |
6,319 |
| Corporate acquisitions (Note 7) |
|
|
|
|
|
|
| Cabre Exploration Ltd. |
1,267 |
31,846 |
9,897 |
248,825 |
- |
- |
| Western Star Exploration Ltd. |
- |
- |
13 |
65 |
- |
- |
| Pursuit Resources Corp. |
- |
- |
2,988 |
64,228 |
- |
- |
| Acquisition of property interests |
- |
- |
1,138 |
23,509 |
- |
- |
| Redeemed for cash |
- |
- |
- |
(12) |
- |
(1) |
| | | |
| Balance, end of year |
69,532 |
$ 1,826,507 |
40,925 |
$ 1,050,986 |
21,761 |
$ 592,693 |
|
|
| Warrants (thousands) |
2001 |
2000 |
1999 |
| Warrants |
Amount |
Warrants |
Amount |
Warrants |
Amount |
|
| Balance, beginning of year |
3,045 |
$ 3,873 |
- |
$ - |
- |
$ - |
| Issued during the year |
390 |
496 |
3,065 |
3,873 |
- |
- |
| Exercised during the year |
(1,197) |
(1,523) |
(17) |
- |
- |
- |
| Expired during the year |
(2,238) |
(2,846) |
(3) |
- |
- |
- |
| | | |
| Balance, end of year |
- |
- |
3,045 |
$ 3,873 |
- |
- |
|
On November 15, 2001, the Fund issued 4,312,500 Trust Units at a price of
$24.75 per Trust Unit, pursuant to a short
form prospectus to raise gross proceeds of $106,734,000 ($101,039,000 net of issuance costs).
In accordance with the reverse takeover method of purchase accounting, as described in Note 1, Trust Units and
warrant amounts are those of EnerMark to June 21, 2001 together with changes in consolidated capital since that
date. Numbers of Trust Units and Warrants issued to June 21, 2001 have been restated on the basis of the Merger
Exchange Ratio. In addition, EnerMark is deemed to have acquired the net assets of Enerplus, in exchange for the
20,863,000 Trust Units of the Fund which were outstanding at June 21, 2001, the date of the acquisition. The deemed
Trust Unit gross consideration was recorded in the amount of $582,817,000 ($582,364,000 net of issuance costs).
Under the terms of an agreement for the provision of management, advisory and administrative services with a
related party (Note 6), the Fund issued 172,500
Trust Units at a recorded value of $5,000,000.
Pursuant to an offer to purchase, which initially expired on December 21, 2000, and was subsequently extended, to
January 8, 2001, the Fund acquired all of the outstanding common shares of Cabre Exploration Ltd. ("Cabre")
(Note 7). As at December 31, 2000, the Fund had completed the acquisition of an 88.65% controlling interest in Cabre.
The consideration for the controlling interest included the issuance of 9,897,000 Trust Units at $25.20 per Trust Unit
for a value of $249,434,000 ($248,825,000 net of issuance costs) and 3,045,000 warrants at $1.27 per warrant for an
ascribed value of $3,873,000. The warrants were exercisable into one Trust Unit at a price of $26.53 per Trust Unit at
any time, until December 17, 2001.
The acquisition of the remaining 11.35% non-controlling interest of Cabre was completed on January 8, 2001 and
resulted in the issuance of 1,267,000 additional Trust Units, at $25.20 per Trust Unit for gross consideration of $31,924,000
($31,846,000 net of issuance costs) and 390,000 additional warrants at
$1.27 per warrant for an ascribed value of
$496,000.
On September 12, 2000, the Fund completed an offering of 4,575,850 Trust Units, at a price of $25.14 per Trust Unit,
pursuant to a short form prospectus to raise gross proceeds of $115,061,000 ($109,835,000 net of issuance costs). The
net proceeds of the offering were used to repay a portion of bank indebtedness incurred in connection with the
acquisition of EBOC Energy Ltd. (Note 7).
On April 3, 2000, under the terms of an offer to purchase, the Fund successfully acquired Pursuit Resources Corp.
(Note 7). The total consideration included the issuance of 2,988,000 Trust Units at $21.68 per Trust Unit for a value of
$64,779,000 ($64,228,000 net of issuance costs).
On February 28, 2000, the Fund completed the acquisition of various property interests in the Hanna, Alberta area
from an affiliate of a major Canadian pension fund. Consideration paid for the property interests included the issuance
of
1,046,000 Trust Units recorded at $20.23 per Trust Unit. In addition, on
August 30, 2000, the Fund acquired various
property interests from two private corporations in exchange for 92,000 Trust Units valued at $25.78 per Trust Unit.
Gross consideration for these acquisitions totalled $23,539,000 ($23,509,000 net of issuance costs).
Pursuant to an offer to purchase which was completed on January 7, 2000, the Fund acquired all of the issued and
outstanding common shares of Western Star Exploration Ltd. (Note 7). The total consideration paid included the
issuance of 12,874 Trust Units recorded at $21.67 per Trust Unit, for gross consideration of $279,000
($65,000 net of
issuance costs). Total consideration also included the issuance of 20,000 warrants. Each warrant was exercisable into
one Trust Unit at a price of $23.12 per Trust Unit at any time until December 31, 2000, at which time 3,000 of the
warrants outstanding expired.
Pursuant to an offering, which closed August 26, 1999, the Fund issued
1,211,000 Units at a price of $21.97 per Unit for
gross proceeds of $26,606,000 ($25,076,000 net of issuance costs).
In February 1999 the Fund issued 1,649,000 Units at a price of $14.16 per Unit pursuant to an Offer of Rights to
subscribe for Trust Units which expired
February 26, 1999 for gross proceeds of $23,350,000 ($22,876,000 net of
issuance costs).
In each of 2001, 2000, and 1999, Enerplus entered into joint venture agreements (the "Arrangements") with independent
corporations (the "Corporations") whose sole purpose is to hold oil and natural gas interests earned under each
Arrangement. The terms of the Arrangements require the Corporations to commit funds to be spent in joint venture
with Enerplus as specified below. In addition, each Corporation has been granted the option to put its common shares
to Enerplus at their fair value as determined by an independent evaluator on specified dates (the "Specified Dates").
Enerplus may elect to pay for the shares by way of cash or through the issuance of Trust Units of the Fund. If Trust Units
are issued they are to be valued at 95% of their average closing price, for the 60 day period preceding the specified dates.
|
| Drilling Fund Corporations |
Approximate Funding Commitment |
Specified Date |
|
| 2001 Arrangement |
$ 2.7 million |
March 1, 2004 |
| 2000 Arrangement |
$ 5.4 million |
February 1, 2003 |
| 1999 Arrangement |
$ 2.7 million |
February 1, 2002 |
|
As at the date of preparation of these consolidated financial statements, the Corporation involved in the 1999
Arrangement may exercise its option to put its common shares to Enerplus. Enerplus has the option to acquire the
shares of the Corporation for cash or through the issuance of Trust Units.
Trust Units are redeemable at any time, on demand by Unitholders, at 85% of the market price in effect from time to
time. Redemptions cannot exceed $500,000 during any calendar month.
Pursuant to a revised monthly Distribution Reinvestment and Unit Purchase Plan, which became effective on
March 30, 2001, Unitholders are entitled to reinvest cash distributions in additional Units of the Fund. Units are issued
at a discount of 5% below the weighted average market price on the Toronto Stock Exchange for the twenty trading
days preceding a distribution payment date and without service charges or brokerage fees. Unitholders are also
entitled to make optional cash payments to acquire additional Units. Units issued pursuant to optional cash payments
are issued on the same basis as reinvested cash distributions except no discount applies.
(b) Trust Unit Option Plan
On August 22, 1996, a special resolution was passed approving the EnerMark Trust Unit Option Plan for trustees,
directors, officers, employees of EnerMark or its affiliates, and related parties involved with the management of
EnerMark. Enerplus had a similar plan for its directors, officers and employees. On June 21, 2001, in connection with
the Merger, the vesting of certain EnerMark Trust Unit options was accelerated and the equivalent of in-the-money
amounts on such vested options were paid out and have been included as a cost of the acquisition of Enerplus
(Note 1). All outstanding EnerMark Trust Unit options were then cancelled and the
363,000 Enerplus Trust Unit Options
outstanding as at June 21, 2001 were assumed.
Activity for the options issued pursuant to Option Plans are summarized as follows:
|
| (thousands except per Unit amounts) |
2001 |
2000 |
1999 |
| Number of Options |
Weighted Average Exercise Price |
Number of Options |
Weighted Average Exercise Price |
Number of Options |
Weighted Average Exercise Price |
|
| EnerMark Unit Options outstanding beginning of year |
609 |
$ 24.28 |
740 |
$ 28.32 |
814 |
$ 37.05 |
| Granted |
639 |
$ 26.53 |
294 |
$ 22.31 |
318 |
$ 14.62 |
| Exercised |
(80) |
$ 17.98 |
(128) |
$ 16.59 |
(29) |
$ 14.62 |
| Cancelled |
(321) |
$ 26.47 |
(297) |
$ 35.84 |
(363) |
$ 36.94 |
Accelerated due to
Merger |
(847) |
$ 25.72 |
|
|
|
|
| Enerplus Unit Options outstanding at June 21, 2001 |
363 |
$ 21.03 |
- |
|
- |
|
| Exercised |
(55) |
$ 21.94 |
- |
|
- |
|
| Cancelled |
(44) |
$ 20.47 |
- |
|
- |
|
Outstanding at end
of year |
264 |
$ 20.93 |
609 |
$ 24.28 |
740 |
$ 28.32 |
| Balance of Trust Units reserved but not issued |
- |
|
1,852 |
|
349 |
|
| Total Trust Units reserved as at the end of the year |
264 |
|
2,461 |
|
1,089 |
|
|
The following table summarizes information with respect to outstanding Unit Options as at December 31, 2001:
|
Number Outstanding At
December 31, 2001
(thousands) |
Exercise Prices |
Expiry Date
December 31 |
Number Exercisable
December 31, 2001
(thousands) |
|
| 27 |
$ 15.30 |
2002 |
27 |
| 52 |
$ 17.10 |
2003 |
23 |
| 185 |
$ 22.90 |
2004 |
49 |
|
| 264 |
$ 20.93 |
|
99 |
|
(c) Trust Unit Rights Incentive Plan
On June 21, 2001, a special resolution was passed to approve the adoption of a
Trust Unit Rights Incentive Plan
("Incentive Plan") pursuant to which rights to acquire Enerplus Trust Units may be granted to trustees, directors, officers,
employees, of the Fund or its affiliates and related parties involved in the management of the Fund. Under the Incentive
Plan, distributions per Trust Unit to Enerplus Unitholders in a calendar quarter which represent a return of more than 2.5%
of the net property, plant and equipment of Enerplus at the end of such calendar quarter would result in a reduction in the
exercise price of the Rights. No such reductions have occurred in 2001.
Activity for the options issued pursuant to the Incentive Plan is as follows:
|
| (thousands except per Unit amounts) |
2001 |
2000 |
1999 |
| Number of Rights |
Exercise Price |
Number of Rights |
Exercise Price |
Number of Rights |
Exercise Price |
|
| Incentive Plan Rights outstanding beginning of year |
- |
- |
- |
- |
- |
- |
| Granted |
1,360 |
$ 24.50 |
- |
- |
- |
- |
| Cancelled |
(42) |
$ 24.50 |
- |
- |
- |
- |
|
| Outstanding at end of year |
1,318 |
$ 24.50 |
- |
- |
- |
- |
| Balance of Trust Units reserved but not issued |
1,422 |
|
|
|
|
|
|
| Total Trusts Units reserved at the end of the year |
2,740 |
|
- |
|
- |
|
|
| Exercisable at December 31, 2001 |
- |
|
- |
|
- |
|
|
5. INCOME TAXES
(a) The Fund
The Fund is an inter vivos trust for income tax purposes. As such, the Fund is taxable on any income which is not
allocated to the Unitholders. The Fund intends to allocate all income to Unitholders. Should the Fund incur any
income taxes, the funds available for distribution will be reduced accordingly.
During 2001, the Fund had taxable income of $181.3 million (2000 - $69.1 million and 1999 - $20.0 million) or $4.71 per
Unit
(2000 - $2.44 per Unit and 1999 - $0.956 per Unit) which was allocated to the Unitholders. Taxable income of the
Fund is comprised of income on securities issued by EnerMark and royalty income, less deductions for Canadian oil and
gas property expense ("COGPE"), which is claimed at a rate of 10% on a declining balance basis and the allowable
portion of the cost of issuing new Trust Units during the period. Any losses which occur in the Fund must be retained
in the Fund and may be carried forward and deducted from taxable income for a period of seven years. As at
December 31, 2001, the Fund had no losses available for carry forward.
The amounts of COGPE and issue costs remaining in the Fund are as follows:
|
| |
2001 |
2000 |
1999 |
| Per Unit |
Amount |
Per Unit |
Amount |
Per Unit |
Amount |
|
| COGPE |
$ 5.49 |
$ 381,563 |
$ 2.14 |
$ 87,294 |
$ 4.45 |
$ 96,993 |
| Issue costs |
0.14 |
10,063 |
0.17 |
7,681 |
0.23 |
4,800 |
| | | |
| Total |
$ 5.63 |
$ 391,626 |
$ 2.31 |
$ 94,975 |
$ 4.68 |
$ 101,793 |
|
(b) Corporate Subsidiaries
The provision for future income taxes arises from temporary differences in the recognition of revenues and expenses
for income tax and accounting purposes. The temporary differences, tax effected at substantially enacted rates,
comprising the future income tax liability are as follows:
|
| |
2001 |
2000 |
|
| Excess of net book value of property, plant and equipment over the underlying tax basis |
$ 350,754 |
$ 367,486 |
| Future site restoration deductions |
(17,643) |
(14,318) |
| Other |
449 |
(53) |
| | | |
| Future income tax liability |
$ 333,560 |
$ 353,115 |
|
The provisions for income taxes vary from the amounts that would be computed by applying the combined Canadian
federal and provincial income tax rates for the following reasons:
|
| |
2001 |
2000 |
1999 ¹ |
|
| Net income before taxes |
$ 153,516 |
$ 100,464 |
$ 22,348 |
| | | |
| Computed income tax expense (recovery) at substantially enacted rates of 42.62% (44.62% for 2000 and 1999) |
$ 65,429 |
$ 44,827 |
$ 9,972 |
| Increase (decrease) resulting from: |
|
|
|
| Net income attributed to the Fund |
(95,671) |
(32,173) |
(14,755) |
| Non-deductable crown royalties and other payments |
43,309 |
29,166 |
11,279 |
| Federal resource allowance |
(43,658) |
(29,975) |
(9,935) |
| Non-deductable depletion |
- |
- |
1,176 |
| ARTC |
(214) |
(249) |
(614) |
| Other |
(670) |
782 |
(2,080) |
| | | |
| Future income taxes (recovery) |
$ (31,475) |
$ 15,378 |
$ (4,957) |
|
¹See Note 2 (I)
6. RELATED PARTY TRANSACTIONS
Management, advisory and administration services are supplied to the Fund on a fee and cost reimbursement basis,
pursuant to a new agreement with Enerplus Global Energy Management Company ("EGEM"), commencing on
June 21, 2001, and prior thereto with EMR Resource Management Ltd., a wholly-owned subsidiary of EGEM. As at
December 31, 2001, $7,406,000 was payable to EGEM, pursuant to this agreement.
Management fees equal to 2.2% of operating income to June 21, 2001 and 2.75%, thereafter, are reported on the
Consolidated Statement of Income. Pursuant to the agreement, prior to June 21, 2001, fees of $302,000 earned in
relation to certain property acquisitions and divestitures of Enerplus which are included in the cost of property, plant
and equipment. Under the new agreement, acquisition and divestment fees were eliminated and replaced with a
performance fee based on both the total return of the Fund and its relative performance, as compared to other senior
Canadian conventional oil and gas energy funds. For the year ended December 31, 2001, no amounts for performance
fees are included in the determination of management fees as reported on the Consolidated Statement of Income. In
conjunction with the Merger, EGEM received a minimum fee of 172,500 Enerplus Trust Units with an assigned value of
$5,000,000. The fee was accounted for as a cost of the Merger.
Pursuant to a share purchase agreement related to the Merger, EnerMark Inc. acquired all of the outstanding common
shares of ERC from EGEM resulting in ERC becoming a wholly-owned subsidiary of Enerplus. Consideration for the
shares was $2,545,000 and is payable over a five year period ending September 2006, through a reduction in management
fees. Of this amount, $509,000 has been classified as a current liability. The non-refundable fee advance and acquisition
cost of the ERC shares has been included as a cost of the acquisition of Enerplus Resources Fund.
In addition to the transactions described above, Enerplus has entered into a financial instrument contract with an
indirect subsidiary of El Paso Energy Corporation, the ultimate parent of EGEM, as described in Note 8.
7. CORPORATE ACQUISITIONS
(a) Cabre Exploration Ltd.
Pursuant to an offer to purchase, initially expiring December 21, 2000 and subsequently extended to January 8, 2001,
Enerplus acquired all of the outstanding common shares of Cabre Exploration Ltd. ("Cabre") a public Alberta corporation,
of which Enerplus held an 88.65% controlling interest as at December 31, 2000.
The 88.65% controlling interest in Cabre was acquired for a total consideration of $259,878,000 which consisted of
9,897,000 Trust Units with a recorded value of $249,434,000, costs associated with the acquisition of $6,571,000 and
3,045,000 warrants excercisable into one Trust Unit at a price of $26.53 until December 17, 2001 with a recorded value
of $3,873,000. A future tax cost of $46,077,000 plus an amount of $64,510,000 by which the total consideration
exceeded the proportionate carrying value recorded in the accounts of Cabre has been allocated as an increase to
property, plant and equipment.
The acquisition of the remaining 11.35% in common shares of Cabre was completed on January 8, 2001 for a total
consideration of $32,420,000 which consisted of
1,267,000 Trust Units with a recorded value of $31,924,000 and 390,000
warrants excercisable into one Trust Unit at a price of $26.53 until December 17, 2001 with a recorded value of
$496,000. A future tax cost of $11,396,000 plus an amount of $7,407,000 by which the total consideration exceeded
the proportionate carrying value recorded in the accounts of Cabre has been allocated as an increase to property,
plant and equipment.
The net assets acquired and liabilities assumed for the completed acquisition are summarized as follows:
|
| |
88.65%
December 31
2000 |
11.35%
January 8
2001 |
100.00%
Total |
|
| Property, plant and equipment |
$ 484,550 |
$ 18,803 |
$ 503,353 |
| Working capital deficiency |
(21,424) |
- |
(21,424) |
| Long-term debt assumed |
(18,213) |
- |
(18,213) |
| Site restoration and abandonment |
(19,196) |
- |
(19,196) |
| Future income taxes |
(140,826) |
(11,396) |
(152,222) |
| Non-controlling interest |
(25,013) |
25,013 |
- |
| | |
| Net assets acquired |
$ 259,878 |
$ 32,420 |
$ 292,298 |
|
Cabre was formally amalgamated effective January 17, 2001 with EnerMark Inc. and the amalgamated entity was
continued under the name EnerMark Inc.
(b) EBOC Energy Ltd.
On September 1, 2000, the Fund acquired all outstanding common shares of EBOC Energy Ltd. ("EBOC") a private
Alberta corporation for total consideration of $148,217,000 comprised of $143,585,000 in cash and related costs of
$4,632,000. A future income tax cost of $84,882,000 plus an amount of $105,761,000 by which the total consideration
paid exceeded the carrying value recorded in the accounts of EBOC has been allocated as an increase to property,
plant and equipment. The net assets acquired and liabilities assumed are summarized as follows:
|
| Property, plant and equipment |
$ 263,608 |
| Working capital deficiency |
(2,947) |
| Long-term debt assumed |
(6,428) |
| Site restoration and abandonment |
(287) |
| Future income taxes |
(105,729) |
| | |
| Net assets acquired |
$ 148,217 |
|
EBOC was amalgamated effective September 1, 2000 with EnerMark Inc. and the amalgamated entity was continued
under the name EnerMark Inc.
(c) Pursuit Resources Corp.
Pursuant to a takeover bid which was completed on April 3, 2000, the Fund acquired all outstanding common shares
of Pursuit Resources Corp. ("Pursuit") a public Alberta corporation. The total consideration of $81,670,000 consisted
of 2,988,000 Trust Units of the Fund with a recorded value of $64,779,000, cash of $14,693,000 and costs associated
with the acquisition in the amount of $2,198,000. A future income tax cost of $29,821,000 plus an amount of $37,060,000
by which the total consideration paid exceeded the carrying value recorded in the accounts of Pursuit has been
allocated as an increase to property, plant and equipment. The net assets acquired and liabilities assumed are summarized
as follows:
|
| Property, plant and equipment |
$ 159,213 |
| Working capital |
1,079 |
| Long-term debt assumed |
(37,195) |
| Site restoration and abandonment |
(1,381) |
| Future income taxes |
(40,046) |
| | |
| Net assets acquired |
$ 81,670 |
|
Pursuit remained a wholly-owned subsidiary of EnerMark Inc. until July 1, 2000 when it was amalgamated with
EnerMark Inc. and the amalgamated entity was continued under the name EnerMark Inc.
(d) Western Star Exploration Ltd.
Pursuant to a takeover bid which was completed on January 7, 2000, the Fund acquired all outstanding common
shares of Western Star Exploration Ltd. ("Western Star") a public Alberta corporation. The total consideration of
$22,035,000 consisted of 12,874 Trust Units of the Fund with a recorded value of $279,000, cash of $21,251,000 and
related costs of $505,000. Recipients of Trust Units also received 20,000 warrants, which were exercisable into one
Trust Unit at a price of
$23.12 per Trust Unit until December 31, 2000. The total consideration paid in excess of the
carrying value recorded in the accounts of Western Star has been allocated as an increase to property, plant and
equipment in the amount of $8,400,000. The net assets acquired and liabilities are summarized as follows:
|
| Property, plant and equipment |
$ 27,894 |
| Working capital deficiency |
(495) |
| Long-term debt assumed |
(5,028) |
| Site restoration and abandonment |
(336) |
| | |
| Net assets acquired |
$ 22,035 |
|
Western Star remained a wholly-owned subsidiary of EnerMark Inc. until April 1, 2000 when it was amalgamated with
EnerMark Inc. and the amalgamated entity was continued under the name EnerMark Inc.
(e) Derrick Energy Corporation
Pursuant to a plan of arrangement which closed June 4, 1999, the Fund acquired all of the outstanding shares of
Derrick Energy Corporation ("Derrick"), a public Alberta corporation, and immediately thereafter disposed of 80% of
Derrick’s petroleum and natural gas assets to predecessor companies of ERC. The total net consideration of $2,925,000
consisted of $26,888,000 in cash and $73,000 in costs associated with the arrangement less disposal proceeds of
$24,036,000. The carrying value recorded in the accounts of Derrick exceeded the total consideration paid net of
disposal proceeds by $2,575,000 and has been allocated as a decrease to property, plant and equipment. The net
assets acquired and liabilities assumed are summarized as follows:
|
| Property, plant and equipment |
$ 3,748 |
| Working capital deficiency |
(776) |
| Site restoration and abandonment |
(47) |
| | |
| Net assets acquired |
$ 2,925 |
|
Derrick remained a wholly-owned subsidiary of EnerMark Inc. until January 1, 2000 when it was amalgamated with
EnerMark Inc. and the amalgamated entity was continued under the name EnerMark Inc.
8. FINANCIAL INSTRUMENTS
The Fund’s financial instruments that are included in the balance sheet are comprised of current assets, current liabilities,
the bank debt and the long-term payable to related party.
The fair market values of these instruments approximate their carrying amount due to the short-term maturity of
these instruments and the variable interest rates applied to the bank debt. Virtually all of the Fund’s accounts receivable
are with customers in the oil and natural gas industry and are subject to normal industry credit risks.
The Fund uses various types of financial instruments to manage the risk related to fluctuating commodity prices. The
fair values of these instruments are based on an approximation of the amounts that would have been paid to or
received from counterparties to settle these instruments as at December 31, 2001. The Fund may be exposed to losses
in the event of default by the counterparties to these instruments. This credit risk is controlled by the Fund through
the selection of financially sound counterparties.
CRUDE OIL
As at December 31, 2001 Enerplus has three separate three-way financial option transactions that are designed to
reduce a downward impact of crude oil prices on 3,675 bbls/day of crude oil production. The total cost to be amortized
in 2002 is $859,000. The fair value of the financial crude oil hedges as at December 31, 2001 reflects an unrealized gain
of $274,000.
|
| Financial Instrument Type |
Daily Volumes bbls/day |
WTI US$/bbl |
| Sold Call |
Purchased Put |
Sold Put |
|
| Crude Oil 2002 |
|
|
|
|
| Financial Contracts |
|
|
|
|
| 3-Way option |
1,500 |
$ 27.00 |
$ 19.50 |
$ 16.00 |
| 3-Way option ¹ |
1,500 |
$ 25.00 |
$ 19.50 |
$ 17.00 |
| 3-Way option |
675 |
$ 27.00 |
$ 19.50 |
$ 17.00 |
| | |
| Total |
3,675 |
|
|
|
|
¹ The counterparty to one of the 3-way crude oil options above, is a subsidiary of
El Paso Energy Corporation which is the
ultimate parent of EGEM (refer to Note 6). The remaining option premiums for these instruments are $276,000 and are
being amortized over their remaining terms.
NATURAL GAS
As at December 31, 2001 Enerplus has physical and financial contracts in place on approximately 57 MMcf/day of
natural gas in 2002 and 20 MMcf/day of natural gas in 2003. The remaining costs to be amortized in 2002 are $2,032,000
and $1,696,000 in 2003. The fair value of the financial natural gas hedges as at December 31, 2001 reflects an unrealized
loss of $711,000.
The following table summarizes the commodity risk management positions as at December 31, 2001:
|
| Financial Instrument Type |
Annualized
Daily Volumes
Mcf/d |
AECO $/Mcf |
Sold
Call |
Purchased
Put |
Sold
Put |
Fixed
Price |
Escalated
Price |
|
| Natural Gas 2002 |
|
|
|
|
|
|
| Physical Contracts |
6,002 |
- |
- |
- |
$ 2.64 |
- |
| Physical Contracts |
1,967 |
- |
- |
- |
- |
$ 2.01 |
| |
7,969 |
|
|
|
|
|
| Financial Contracts |
|
|
|
|
|
|
| Collar ¹ |
9,084 |
$ 5.27 |
$ 3.69 |
- |
- |
- |
| Put ¹ |
9,084 |
- |
$ 3.69 |
- |
- |
- |
| Swap |
3,792 |
- |
$ 2.90 |
- |
- |
- |
| Collar |
7,584 |
$ 4.22 |
$ 3.43 |
- |
- |
- |
| Collar |
5,688 |
$ 4.81 |
$ 3.43 |
- |
- |
- |
| Collar |
14,220 |
$ 4.22 |
$ 3.32 |
- |
- |
- |
| | |
| Total |
57,421 |
|
|
|
|
|
| Natural Gas 2003 |
|
|
|
|
|
|
| Physical contracts |
2,369 |
- |
- |
- |
$ 2.64 |
- |
| Physical contracts |
1,967 |
- |
- |
- |
- |
$ 2.23 |
| | |
| |
4,336 |
|
|
|
|
|
| Financial contracts |
|
|
|
|
|
|
| Collar ¹ |
5,922 |
$ 5.27 |
$ 3.69 |
- |
- |
- |
| Put ¹ |
5,922 |
- |
$ 3.69 |
- |
- |
- |
| Swap |
3,792 |
- |
$ 2.90 |
- |
- |
- |
| | |
| Total |
19,972 |
|
|
|
|
|
| Natural Gas 2004 |
|
|
|
|
|
|
| Physical contracts |
1,967 |
- |
- |
- |
- |
$ 2.33 |
| Financial contracts swaps |
3,160 |
- |
$ 2.90 |
- |
- |
- |
| | |
| Total |
5,127 |
|
|
|
|
|
| Natural Gas 2005 - 2010 |
|
|
|
|
|
|
| Physical |
1,967 |
- |
- |
- |
- |
$ 2.43 |
|
¹ The counterparty to these natural gas collars and puts, is a subsidiary of El Paso Energy Corporation which is the ultimate
parent of EGEM (refer to Note 6). The option premiums for these instruments are $3,728,000 and are being amortized
over their remaining terms.
9. RESTATEMENT OF PRIOR YEARS DISTRIBUTION PAYABLE TO UNITHOLDERS
The comparative consolidated balance sheets for December 31, 2000 and 1999 and consolidated statements of
accumulated cash distributions for each of the years then ended have been restated to recognize a current liability to
Unitholders representing the monthly distribution that was declared on December 20, 2000 and
December 20, 1999
and paid on January 20, 2001 and January 20, 2000, respectively. The effect of this change is to increase distributions
payable to Unitholders and increase accumulated cash distributions by $18,925,000 and $7,547,000 as at
December 31, 2000 and 1999, respectively. There is no current or prior effect to the Fund’s cash flow or earnings.
10. DIFFERENCES BETWEEN CANADIAN AND UNITED STATES GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
The Fund’s consolidated financial statements have been prepared in accordance with Canadian generally accepted
accounting principles ("Canadian GAAP"). These principles, as they pertain to the Fund’s consolidated statements,
differ from
United States generally accepted accounting principles ("U.S. GAAP") as follows:
(a) Under U.S. GAAP, for Securities and Exchange Commission registrants following full cost accounting, the carrying
value of petroleum and natural gas properties and related facilities, net of future income taxes, is limited to the
present value of after tax future net revenue from proven reserves, discounted at 10 percent (based on prices and costs
at the balance sheet date), plus the lower of cost and fair value of unproven properties. Under Canadian GAAP, the
Ceiling Test is calculated without application of a discount factor, but includes general and administration, management
fees and interest expense.
Where the amount of a Ceiling Test write-down under Canadian GAAP differs from the amount of the write-down
under U.S. GAAP, the charge for depletion, depreciation, and amortization will differ in subsequent years. As at
December 31, 2001, the application of the Ceiling Test under U.S. GAAP resulted in a write down of
$744.3 million
($458.4 million after tax) of capitalized costs. At December 31, 2000 and 1999, the application of the Ceiling Test under
U.S. GAAP did not result in a write down of capitalized costs. Under Canadian GAAP, the application of the Ceiling Test
did not result in a write down for the years 2001, 2000 and 1999.
(b) SFAS 123, "Accounting for Stock-based Compensation", establishes financial accounting and reporting standards
for stock-based employee compensation plans as well as transactions in which an entity issues its equity instruments to
acquire goods or services from non-employees. As permitted by SFAS 123, Enerplus has elected to continue to follow
the intrinsic value method of accounting for stock-based compensation arrangements, as provided for in Accounting
Principles Board Opinion 25 ("APB 25"). Since all Unit Options and Trust Unit Rights were granted with an exercise
price equal to the market price at the date of the grant, no compensation cost has been charged to income. Had
compensation cost for Enerplus stock options been determined based on the fair market value at the grant dates of
the awards consistent with methodology prescribed by SFAS 123, Enerplus net income (loss) and net income (loss) per
Unit for years ended December 31, 2001, 2000 and 1999 would have been the pro forma amounts indicated below:
|
| Years ended December 31, thousands except per Unit amounts |
2001 |
2000 |
1999 |
|
| Net income (loss): |
|
|
|
| As reported under U.S. GAAP |
$ (261,288) |
$ 98,261 |
$ 48,024 |
| Pro forma |
(262,191) |
$ 96,813 |
$ 46,627 |
| Net income (loss) Per Unit |
|
|
|
| Basic |
|
|
|
| As reported under U.S. GAAP |
$ (4.76) |
$ 3.66 |
$ 2.34 |
| Pro forma |
$ (4.78) |
$ 3.61 |
$ 2.27 |
| Diluted |
|
|
|
| As reported under U.S. GAAP |
$ (4.76) |
$ 3.65 |
$ 2.33 |
| Pro forma |
$ (4.78) |
$ 3.60 |
$ 2.26 |
|
|
| The estimated fair value of the options issued under the Unit Options Plan and the Trust Unit Right Incentive Plan was
determined using the Black-Scholes model and the following assumptions: |
|
|
| |
2001 |
2000 |
1999 |
|
| Risk-free interest rate |
2.35% |
5.98% |
5.07% |
| Estimated hold period prior to exercise |
3 years |
3 years |
3 years |
| Volatility in the market price of the Trust Units |
24.5% |
33.5% |
36.3% |
| Estimated monthly cash distributions |
$ 0.11 / Unit |
$ 0.07 / Unit |
$ 0.05 / Unit |
|
|
As the exercise price of the rights is subject to downward revisions from time to time, the rights plan is a variable
compensation plan under U.S. GAAP. Accordingly, compensation expense is determined as the excess of the market
price over the exercise price of the rights at the end of each reporting period and is deferred and recognized in income
over the vesting period of the rights. At December 31, 2001, no downward revision in exercise price had occurred and
no compensation expense has been recognized for the rights. Due to the nature of the rights it is not possible to
estimate the fair value of the rights.
(c) U.S. GAAP requires the reporting of comprehensive income in addition to net earnings. Comprehensive income
includes net income plus certain other items not inlcuded in net income. The Fund’s Comprehensive income is the
same as its net income.
(d) Under U.S. GAAP the measurement date for acquisitions is the date the acquisition is announced. Under Canadian
GAAP the measurement date for the acquisition is the closing date. Under U.S. GAAP, Unitholders’ capital and property,
plant and equipment has been increased by $37.3 million in 2001 and decreased by $7.8 million in 2000 for differences
in the value of Trust Units issued to effect certain acquisitions.
(e) Effective January 1, 2000, the Fund adopted the recommendations of the Canadian Institute of Chartered Accountants
on accounting for future income taxes and changed from the deferral method to the liability method. This liability
method differs from U.S. GAAP due to the application of transitional provisions and the accounting for certain Canadian
income tax credits and allowances. In 1999, under U.S. GAAP future income taxes and property, plant and equipment
was increased by $4.5 million.
(f) Effective January 1, 2001, for U.S. reporting purposes, the Fund adopted Statement of Financial Accounting Standards
("SFAS") No. 133. "Accounting for Derivative Instruments and Hedging Activities". SFAS 133 establishes accounting
and reporting standards requiring that all derivative instruments (including derivative instruments embedded in other
contracts), as defined, be recorded in the balance sheet as either an asset or a liability measured at fair value and
requires that changes in fair value be recognized currently in income unless specific hedge accounting criteria are met.
There are no similar standards under Canadian GAAP.
Hedge accounting treatment allows unrealized gains and losses to be deferred in other comprehensive income (for
the effective portion of the hedge) until such time as the forecasted transaction occurs and requires that an entity
formally document, designate and assess effectiveness of derivative instruments that receive hedge accounting
treatment. The Fund has chosen to not formally document and designate its financial derivatives outstanding at
December 31, 2001 and 2000 as hedges for U.S. GAAP purposes.
The application of U.S. GAAP would have the following effects on net income as reported:
|
|
| ($thousands except per Unit amounts) |
2001 |
2000 |
1999 |
|
| Net income as reported in the Consolidated Statement of Income |
$ 180,269 |
$ 82,150 |
$ 25,754 |
| Adjustments, net of applicable income tax |
|
|
|
| Write-down of property, plant and equipment |
(458,474) |
- |
- |
| Depletion, depreciation and amortization |
17,168 |
16,111 |
22,270 |
| Unrealized gain on financial derivatives |
(251) |
- |
- |
| | | |
| Net income (loss) and comprehensive income (loss) |
$ (261,288) |
$ 98,261 |
$ 48,024 |
| | | |
| Net income (loss) per Unit |
|
|
|
| Basic |
$ (4.76) |
$ 3.66 |
$ 2.34 |
| Diluted |
$ (4.76) |
$ 3.65 |
$ 2.33 |
| Weighted average number of Units outstanding |
|
|
|
| Basic |
54,907 |
26,841 |
20,532 |
| Diluted |
54,956 |
26,928 |
20,607 |
|
The application of U.S. GAAP would have the following effects on the balance sheet as reported:
|
| ($thousands) |
Canadian GAAP |
Increase (decrease) |
U.S. GAAP |
|
| December 31, 2001 |
|
|
|
| Financial derivative assets |
$ - |
$ 274 |
$ 274 |
| Property, plant and equipment, net |
2,178,316 |
(1,018,610) |
1,159,706 |
| Financial derivative liabilities |
- |
711 |
711 |
| Future income taxes |
333,560 |
(406,556) |
(72,996) |
| Unitholders' capital |
1,826,507 |
29,626 |
1,856,133 |
| Accumulated income |
324,570 |
(642,117) |
(317,547) |
| December 31, 2000 |
|
|
|
| Property, plant and equipment, net |
1,483,293 |
(339,588) |
1,143,705 |
| Future income taxes |
353,115 |
(131,270) |
221,845 |
| Unitholders' capital |
1,054,859 |
(7,758) |
1,047,101 |
| Accumulated income |
144,301 |
(200,560) |
(56,259) |
| December 31, 1999 |
|
|
|
| Property, plant and equipment, net |
556,285 |
(359,183) |
197,102 |
| Future income taxes |
33,593 |
(126,335) |
(92,742) |
| Accumulated income |
$ 78,328 |
$ (232,848) |
$ (154,520) |
|
|
