|
CONSOLIDATED BALANCE SHEET
 |
| Assets |
| Current assets |
| Cash |
$ |
718 |
$ |
979 |
| Accounts receivable |
|
92,986 |
|
100,089 |
| Other current |
|
1,975 |
|
4,869 |
|
| |
|
95,679 |
|
105,937 |
|
| Property, plant and equipment |
|
3,071,298 |
|
2,667,504 |
| Accumulated depletion and depreciation
| |
(697,153) |
|
(489,188) |
|
| Property, plant and equipment |
|
2,374,145 |
|
2,178,316 |
|
| Deferred charges (Note 2) |
|
1,807 |
|
- |
|
| |
$ |
2,471,631 |
$ |
2,284,253 |
|
| Liabilities |
| Current liabilities |
| Accounts payable |
$ |
79,189 |
$ |
72,341 |
| Distributions payable to unitholders |
|
24,870 |
|
20,860 |
| Payable to related party (Note 5) |
|
19,038 |
|
7,915 |
|
| |
|
123,097 |
|
101,116 |
|
| Long-term debt (Note 2) |
|
361,729 |
|
412,589 |
| Future income taxes (Note 4) |
|
340,269 |
|
333,560 |
| Accumulated site restoration |
|
59,038 |
|
55,403 |
| Deferred credits |
|
4,266 |
|
6,591 |
| Payable to related party (Note 5) |
|
1,400 |
|
1,909 |
|
| |
|
766,702 |
|
810,052 |
|
| Equity |
| Unitholders’ capital (Note 3) |
|
2,156,999 |
|
1,826,507 |
| Accumulated income |
|
440,446 |
|
324,570 |
| Accumulated cash distributions |
|
(1,015,613) |
|
(777,992) |
|
| |
|
1,581,832 |
|
1,373,085 |
|
| |
$ |
2,471,631 |
$ |
2,284,253 |
|
Signed on behalf of the Board:
Douglas R. Martin
Director
Robert L. Normand
Director
|
CONSOLIDATED STATEMENT OF INCOME
|
| Revenues |
| Oil and gas sales |
$ |
621,450 |
$ |
639,379 |
| Crown royalties |
|
(99,503) |
|
(101,114) |
| Freehold and other royalties |
|
(32,334) |
|
(31,546) |
|
| |
|
489,613 |
|
506,719 |
| |
|
559 |
|
858 |
|
| |
|
490,172 |
|
507,577 |
|
| Expenses |
| Operating |
|
134,387 |
|
120,082 |
| General and administrative |
|
16,039 |
|
12,971 |
| Management fees (Note 5) |
|
21,576 |
|
9,323 |
| Interest on long-term debt |
|
18,287 |
|
17,605 |
| Depletion, depreciation and amortization |
|
213,908 |
|
194,080 |
|
| |
|
404,197 |
|
354,061 |
|
| Income before taxes |
|
85,975 |
|
153,516 |
|
| Capital taxes |
|
5,483 |
|
4,722 |
| Future income tax (Note 4) |
|
(35,384) |
|
(31,475) |
|
| |
|
(29,901) |
|
(26,753) |
|
| Net Income |
$ |
115,876 |
$ |
180,269 |
|
| Net Income per trust unit |
| Basic |
$ |
1.61 |
$ |
3.28 |
| Diluted |
$ |
1.61 |
$ |
3.28 |
|
| Weighted average number of trust units outstanding ($ thousands) |
| Basic |
|
71,946 |
|
54,907 |
| Diluted |
|
72,084 |
|
54,956 |
|
CONSOLIDATED STATEMENT OF ACCUMULATED INCOME
|
| Accumulated income, beginning of year |
$ |
324,570 |
$ |
144,301 |
| Net income |
|
115,876 |
|
180,269 |
|
| Accumulated income, end of year |
$ |
440,446 |
$ |
324,570 |
|
CONSOLIDATED STATEMENT OF CASH FLOWS
|
| Operating Activities |
| Net income |
$ |
115,876 |
$ |
180,269 |
| Depletion, depreciation and amortization |
|
213,908 |
|
194,080 |
| Future income taxes (recovery) |
|
(35,384) |
|
(31,475) |
| Site restoration and abandonment costs incurred |
|
(4,548) |
|
(2,628) |
|
| Funds flow from operations |
|
289,852 |
|
340,246 |
| Decrease (increase) in non-cash operating working capital |
|
15,162 |
|
(52,928) |
|
| Financing Activities |
| Issue of trust units, net of issue costs (Note 3) |
|
329,752 |
|
151,411 |
| Cash distributions to unitholders |
|
(233,611) |
|
(328,899) |
| Increase (decrease) in bank credit facilities |
|
(319,188) |
|
58,021 |
| Issuance of senior unsecured notes |
|
268,328 |
|
- |
| Payment to related party |
|
(509) |
|
(127) |
| Deferred charges (Note 2) |
|
(1,892) |
|
- |
|
| |
|
42,880 |
|
(119,594) |
|
| Investing Activities |
| Capital expenditures |
|
(146,116) |
|
(143,280) |
| Capital expenditures |
|
(146,116) |
|
(143,280) |
| Property acquisitions |
|
(60,581) |
|
(77,432) |
| Property dispositions |
|
3,058 |
|
68,496 |
| Corporate acquisitions (Note 6) |
|
(161,403) |
|
(14,522) |
| Change in non-cash investing working capital |
|
16,887 |
|
(853) |
|
| |
|
(348,155) |
|
(167,591) |
|
| Change in cash |
|
(261) |
|
133 |
| Cash, beginning of year |
|
979 |
|
846 |
| Cash, beginning of year |
|
979 |
|
846 |
|
| Cash, end of year |
$ |
718 |
$ |
979 |
|
| Supplementary Cash Flow Information |
| Cash income taxes paid |
$ |
- |
$ |
- |
| Cash interest paid |
$ |
17,740 |
$ |
17,162 |
|
CONSOLIDATED STATEMENT OF ACCUMULATED CASH DISTRIBUTIONS
|
| Accumulated cash distributions, beginning of year |
$ |
777,992 |
$ |
447,158 |
| Cash distributions |
|
237,621 |
|
330,834 |
|
| Accumulated cash distributions, end of year |
$ |
1,015,613 |
$ |
777,992 |
|
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Tabular amounts in thousands of Canadian dollars and thousands of units except per unit amounts)
1. Summary of Significant Accounting Policies
The Management of Enerplus Resources Fund ("Enerplus" or the "Fund") prepares the financial statements in accordance with
Canadian generally accepted accounting principles ("GAAP"). A reconciliation between Canadian GAAP and United States
GAAP is disclosed in Note 10. 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
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.
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.
(c) Ceiling Test
The Fund places a limit on the aggregate carrying value of property, plant and equipment which may be amortized 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 income
taxes. Costs and prices at the balance sheet date are used in determining ceiling test amounts. Any costs carried on the balanc e
sheet in excess of the ceiling test limitation are charged to income.
(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 and production are converted to equivalent
units on the basis of 6Mcf = 1bbl reflecting the approximate relative energy content.
(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) 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, except for
its subsidiaries as noted below.
The Fund follows the liability method of accounting for income taxes. Under this method, income tax liabilities and assets are
recognized for the estimated tax consequences attributable to differences between the amounts reported in the financial
statements of the Fund’s corporate subsidiaries and their respective tax bases, using 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.
(g) Financial Instruments
The Fund is exposed to market risks resulting from fluctuations in commodity prices, and interest rates in the normal course
of operations. The Fund uses various types of financial instruments to manage these market risks. 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.
(h) Foreign Currency Translation
Monetary assets and liabilities denominated in a foreign currency are translated at the rate of exchange in effect at the balance
sheet date. Revenues and expenses are translated at the monthly average rates of exchange. Translation gains and losses are
included in income in the period in which they arise.
(i) Accounting for Stock Based Compensation
Effective for the fiscal years beginning on or after January 1, 2002, the Fund adopted the recommendations of the CICA on
accounting for stock based compensation which apply to new rights granted on or after that date. The Fund has elected to
continue to measure compensation cost based on the intrinsic value of the award at the date of the grant and recognize that
cost over the vesting period. The cash received upon exercise of the rights is credited to unitholders’ capital.
2. Long-Term Debt
|
| Bank credit facilities (a) |
$ |
93,401 |
$ |
412,589 |
| Senior unsecured notes (b) |
|
268,328 |
|
- |
|
| Total long-term debt |
$ |
361,729 |
$ |
412,589 |
|
(a) Bank Credit Facilities
On March 1, 2002, Enerplus renegotiated its bank facilities into a single unsecured syndicated facility (the "Facility") in the
amount of $620,000,000. The Facility consisted of a $590,000,000 revolving committed line with an incremental two-year
term, and a $30,000,000 demand operating line. The Facility amounts were adjusted upon the issuance of the Senior
Unsecured Notes on June 19, 2002, as described below, to a $322,000,000 revolving committed line and a $29,672,000
demand operating line. On November 7, 2002, the Fund’s borrowing base was increased by $80,000,000 to $700,000,000
and accordingly the revolving committed line was increased to $402,000,000 along with the total Facility, which at
December 31, 2002 was $431,672,000. Various borrowing options are available under the Facility including prime rate based
advances and banker’s acceptance loans.
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.
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.
(b) Senior Unsecured Notes
On June 19, 2002 Enerplus replaced a portion of its bank debt with senior unsecured notes ("the Notes") in the amount of
US$175,000,000. They have a final maturity of June 19, 2014 and bear interest at 6.62% per annum, with interest paid semiannually
on June 19 and December 19 of each year. The Notes Purchase Agreement requires the Fund to make five annual
amortizing principal repayments of 20% of the initial principal amount, commencing on June 19, 2010.
Concurrent with the issuance of the Notes, the Fund entered into a cross currency swap, with a syndicate of major financial
institutions. Under the terms of the swap, the amount of the Notes was fixed for purposes of interest and principal repayments
at a notional amount of CDN$268,328,000. Interest payments are made on a floating rate basis, set at the rate for three-month
Canadian banker’s acceptances, plus 1.18%. Costs incurred in connection with issuing the Notes, in the amount of $1,892,000
are classified as deferred charges on the balance sheet and are being amortized over the term of the Notes. As at December 31,
2002, the amount remaining to be amortized associated with these costs was $1,807,000.
The Bank Credit Facilities and the Senior Unsecured Notes (the "Combined Facilities") are the legal obligation of EnerMark
Inc. and are guaranteed by ERC. Although payments to unitholders are subordinated to the Combined Facilities, unitholders
have no direct liability should cash flow be insufficient to repay the Combined Facilities. However, payments with respect to
the Combined Facilities have priority over claims of and future distributions to the unitholders.
3. Fund Capital
(a) Unitholders’ Capital
Trust Units ($ thousands)
|
| Issued: |
Units |
Amount |
Units |
Amount |
| Balance, beginning of year |
69,532 |
$1,826,507 |
40,925 |
$1,050,986 |
| Issued for cash: |
| Pursuant to public offerings |
112,709 |
314,624 |
4,313 |
101,039 |
| Pursuant to option and rights plans |
140 |
2,844 |
135 |
2,530 |
| Pursuant to the exercise of warrants |
- |
- |
1,197 |
33,319 |
| Expiry of warrants |
- |
- |
- |
2,846 |
| Issued pursuant to the deemed |
| acquisition of Enerplus (Note 6) |
- |
- |
20,863 |
582,364 |
| Issued pursuant to the management |
| agreement |
- |
- |
173 |
5,000 |
| Distribution Reinvestment and Unit |
| Purchase Plan |
486 |
12,284 |
659 |
16,577 |
| Issued for acquisition of corporate |
| and property interests |
31 |
740 |
1,267 |
31,846 |
|
| Balance, end of year |
82,898 |
$2,156,999 |
69,532 |
$1,826,507 |
|
During the fourth quarter 2002, the Fund completed an equity offering of 7,959,300 trust units at a price of $26.00 per trust
unit for gross proceeds of $206,942,000 ($193,738,000 net of issuance costs).
On September 12, 2002, Enerplus completed an equity offering of 4,750,000 trust units at a price of $26.85 per trust unit
for gross proceeds of $127,538,000 ($120,886,000 net of issuance costs).
On November 15, 2001, the Fund issued 4,312,500 trust units at a price of $24.75 per trust unit, to raise gross proceeds of
$106,734,000 ($101,039,000 net of issuance costs).
At January 1, 2001, Enerplus had 3,045,000 warrants outstanding with an additional 390,000 issued during the year. During
2001, 1,197,000 warrants were exercised and the remaining 2,238,000 warrants expired.
In accordance with the merger of EnerMark Income Fund ("EnerMark") and Enerplus, (the "Merger"), EnerMark was 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 the agreement for the provision of management, advisory and administrative services with a related party
(Note 5), the Fund issued 172,500 trust units at a recorded value of $5,000,000.
The acquisition of the remaining 11.35% non-controlling interest of Cabre Exploration Ltd. ("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.
Enerplus has 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 ventures with Enerplus. 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. On May 22, 2002, the Corporations involved in the 1999 Arrangement, exercised the option to
put their common shares to Enerplus. Enerplus acquired the shares of the Corporation by issuing 31,000 trust units with a
value of $740,000. The 2000 Arrangement has an approximate funding commitment of $5,400,000 and a Specified Date of
February 1, 2003. The 2001 Arrangement has an approximate funding commitment of $2,700,000 and a Specified Date of
March 1, 2004.
Pursuant to the monthly Distribution Reinvestment and Unit Purchase Plan ("DRIP") which applies only to Canadian
unitholders, unitholders are entitled to reinvest cash distributions in additional trust units of the Fund. Trust 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 trust units. Trust units issued pursuant to optional cash payments are issued on
the same basis as reinvested cash distributions except no discount applies. During 2002, $12,284,000 was raised pursuant to
the DRIP (2001 - $16,577,000).
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.
(b) Trust Unit Option Plan
As at December 31, 2002, 123,000 options issued pursuant to the Trust Unit Option Plan were outstanding, representing
0.1% of the total trust units outstanding. Activity for the options issued pursuant to The Trust Unit Option Plan is
summarized as follows:
|
|
| Enerplus Unit Options outstanding |
| Beginning of year |
264 |
$20.93 |
363¹ |
$21.03 |
| Exercised |
(118) |
$19.53 |
(55) |
$21.94 |
| Cancelled |
(23) |
$22.78 |
(44) |
$20.47 |
|
| Outstanding at end of year |
123 |
$21.93 |
264 |
$20.93 |
|
| Options exercisable at the end of the year |
67 |
$21.43 |
99 |
$19.48 |
|
| (1) Number of options represent the balance at June 21, 2001 after the Merger of EnerMark and Enerplus. |
The following table summarizes information with respect to outstanding Unit Options as at December 31, 2002:
No new options have been granted under the Trust Unit Option Plan as this plan has been superseded by the Trust Unit Rights
Incentive Plan as discussed below.
(c) Trust Unit Rights Incentive Plan
As at December 31, 2002, a total of 2,028,000 rights, representing 2.0% of the total trust units were outstanding pursuant to
the Trust Unit Rights Incentive Plan ("Rights Plan") of which 571,000 rights were exercisable. Under the Rights 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 result in a reduction in the exercise price
of the rights. As at December 31, 2002, the exercise price has been calculated to be reduced by $0.53 per trust unit of which
a $0.14 reduction is effective January 2003 and a $0.20 reduction is effective April 2003.
The exercise price of the rights granted under the Fund’s Rights Plan may be reduced in the future. The amount of the
reduction cannot be reasonably determined as it is dependent on a number of factors including but not limited to, future prices
received on the sale of oil and natural gas, future production of oil and natural gas, determination of the amounts to be
withheld from future distributions to fund capital expenditures and the purchase and sale of property, plant and equipment.
Therefore, it is not possible to determine a fair value for the rights granted under the plan.
Compensation costs for pro forma disclosure purposes have been determined based on the excess of the trust unit price over
the exercise price of the rights at the date of the financial statements. For the year ended December 31, 2002, net income
would be reduced by $181,000 for the estimated compensation cost associated with the rights granted under the Rights Plan
on or after January 1, 2002 with a negligible impact on net income per trust unit.
Activity for the rights issued pursuant to the Rights Plan is as follows:
|
|
| Trust Unit Rights outstanding |
| Beginning of year |
1,318 |
$24.50 |
- |
- |
| Granted |
873 |
26.18 |
1,360 |
$ 24.50 |
| Exercised |
(22) |
24.31 |
- |
- |
| Cancelled |
(141) |
24.44 |
(42) |
24.50 |
|
| Outstanding at end of year |
2,028 |
25.11 |
1,318 |
$24.50 |
|
| Rights exercisable at the end of the year |
571 |
$24.31 |
- |
- |
|
The following table summarizes information with respect to outstanding Unit Rights as at December 31, 2002:
|
| |
1,159 |
$24.31 |
2007 |
571 |
| |
24 |
25.38 |
2008 |
- |
| |
64 |
27.33 |
2008 |
- |
| |
728 |
26.09 |
2008 |
- |
|
| |
2,028 |
$25.11 |
|
571 |
|
4. Income Taxes
(a) Enerplus Resources 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 cash
flow available for distribution will be reduced accordingly.
For 2002, the Fund had taxable income of $157,100,000 (2001 - $181,300,000) or $2.15 per trust unit (2001 - $4.71 per
trust unit) which was allocated to 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, 2002, the Fund had no losses available for carry forward.
The amounts of COGPE and issue costs remaining in the Fund at December 31, 2002 are $355,456,000 and $22,608,000
respectively (2001 - $381,563,000 and $10,063,000).
(b) Corporate Subsidiaries
The temporary differences, tax effected at the enacted rate, comprising the future income tax liability are as follows:
|
Excess of net book value of property, plant and equipment over
the underlying tax bases |
$ |
358,058 |
$ |
350,754 |
|
| Future site restoration deductions |
|
(18,584) |
|
(17,643) |
| Other |
|
795 |
|
449 |
|
| Future income tax liabilityr |
$ |
340,269 |
$ |
333,560 |
|
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:
|
| Net income before taxes |
$ |
85,975 |
$ |
153,516 |
|
Computed income tax expense at the enacted
rate of 42.12% (42.62% for 2001) |
$ |
36,213 |
$ |
65,429 |
| Increase (decrease) resulting from: |
| Effect of change in tax rate |
|
(1,668) |
|
(7,062) |
| Net income attributed to the Fund |
|
(65,803) |
|
(95,671) |
| Non-deductible crown royalties and other payments |
|
30,962 |
|
43,309 |
| Federal resource allowance |
|
(24,135) |
|
(43,658) |
| ARTC |
|
(311) |
|
(214) |
| Adjustments related to prior acquisitions |
|
(10,642) |
|
6,392 |
|
| Future income taxes (recovery) |
$ |
(35,384) |
$ |
(31,475) |
|
5. Related Party Transactions
Management, advisory and administration services are supplied to the Fund on a fee and cost reimbursement basis, pursuant
to an agreement with Enerplus Global Energy Management Company ("EGEM"). As at December 31, 2002, $18,529,000
(2001 - $7,406,000) was payable to EGEM, pursuant to this agreement.
Management fees of $21,576,000 are reported on the Consolidated Statement of Income for the year ended
December 31, 2002 (2001 - $9,323,000). This amount is comprised of a base management fee earned equal to $9,208,000
(2001 - $9,323,000) and a performance fee of $12,368,000 (2001 - nil). Performance fees are based on both the total return
of the Fund and its relative performance as compared to other senior conventional oil and gas trusts. For the year ended
December 31, 2002, performance fees were calculated at 3.5% of net operating income. There was no performance fee
recorded for 2001 pursuant to the terms of the management agreement however, 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, the Fund 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 five years in installments of $509,000 through a reduction in management fees. At December 31, 2002,
the amount remaining pursuant to this agreement was $1,909,000 ($1,400,000 long term and $509,000 current).
In addition to the transactions described above, Enerplus has entered into financial instrument contracts at prevailing market
rates with an indirect subsidiary of El Paso Corporation, the ultimate parent of EGEM, as described in Note 7.
On March 6, 2003 Enerplus announced plans to internalize its management structure by acquiring the shares of the
management company, Enerplus Global Energy Management Company ("EGEM"), from an indirect subsidiary of El Paso
Corporation ("El Paso") for consideration of approximately $48,900,000. In addition, El Paso agreed to fix the management
fee for the period January 1, 2003 to April 23, 2003 in an amount of $3,200,000. The proposed transaction will eliminate
all management fees effective April 23, 2003. The transaction is subject to unitholder approval at the annual general and
special meeting to be held on April 23, 2003.
6. Corporate Acqusitions
The fair value of the assets acquired and liabilities assumed for the following acquisitions are summarized as follows:
|
| Property, plant and equipment |
$ |
200,156 |
$ |
18,803 |
$ |
704,838 |
| Working capital |
|
3,340 |
|
- |
|
(10,415) |
| Long-term debt assumed |
|
- |
|
- |
|
(78,624) |
| Site restoration and abandonment |
|
- |
|
- |
|
(14,530) |
| Future income taxes |
|
(42,093) |
|
(11,396) |
|
(524) |
| Non-controlling interest |
|
- |
|
25,013 |
|
- |
|
| Net assets acquired |
$ |
161,403 |
$ |
32,420 |
$ |
600,745 |
|
(a) Celsius Energy Resources Ltd.
On October 21, 2002, the Fund acquired all the outstanding common shares and retired the debt of Celsius Energy Resources
Ltd. ("Celsius"), a private Alberta corporation, for consideration of $161,403,000 which comprised of $160,950,000 in cash
and related costs of $453,000. Available lines of credit financed the acquisition which is being accounted for using the purchase
method of accounting for business combinations. Results from operations subsequent to October 21, 2002 are included in the
Fund’s financial statements.
Celsius was amalgamated with EnerMark Inc. effective October 22, 2002 and the amalgamated entity was continued under
the name of EnerMark Inc.
(b) Cabre Exploration Ltd.
On January 8, 2001, 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, a public Alberta corporation, of which
Enerplus held an 88.65% controlling interest as at December 31, 2000.
On January 17, 2001, Cabre was formally amalgamated with EnerMark Inc. Total consideration for the remaining 11.35%
interest was $32,420,000 which consisted of 1,267,000 trust units with a recorded value of $31,924,000 and 390,000 warrants
with a recorded value of $496,000.
(c) Enerplus Resources Fund
The Merger of EnerMark and Enerplus which occurred on June 21, 2001 was accounted for using the reverse take-over form
of the purchase method of accounting for business combinations as the unitholders of EnerMark became the controlling
unitholders of the Fund after the Merger. EnerMark is deemed to have acquired all of the outstanding trust units of Enerplus
on June 21, 2001 for fair market value consideration totaling $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.
All disclosures of trust units, warrants and options and per unit data up to the June 21, 2001 Merger date have been restated
using the Merger exchange ratio of 0.173 Enerplus unit for each EnerMark unit.
7. Financial Instruments
The Fund’s financial instruments that are included in the balance sheet are comprised of current assets, current liabilities, bank
credit facilities, and the senior unsecured notes.
The fair values of the current assets and liabilities approximate their carrying amounts due to the short-term maturity of these
instruments. The carrying value of the bank credit facilities approximate their fair value as the borrowings have been made
through short term banker's acceptances. The fair value of the senior unsecured notes is approximately $305,456,000 which
represents the discounted net present value of the future U.S. dollar interest and principal payments based on current interest
and foreign exchange rates.
The Fund is exposed to market risks resulting from fluctuations in commodity prices, foreign exchange rates and interest rates
in the normal course of operations. The Fund uses various types of financial instruments to manage these market risks. 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 the instruments outstanding as at December 31, 2002 with reference to forward prices and mark-tomarket
valuations provided by independent sources. 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.
Interest Rate and Cross Currency Swaps
In addition to the cross currency swap described in Note 2, the Fund has entered into interest rate swaps on $75,000,000 of
bank debt at an average fixed interest rate of 4.40% before banking fees that are expected to range between 0.85% and 1.05%.
These interest rate swaps are outstanding for three year terms and mature between January 18th and June 4th 2005.
The mark-to-market value of the $75,000,000 interest rate swaps as at December 31, 2002 represents an unrealized loss of
$2,000,000. The mark-to-market value of the cross currency swap related to the Senior Unsecured Notes as at December 31,
2002 represents an unrealized gain of $37,100,000.
Crude Oil Instruments
Enerplus has entered into the following financial option contracts that are designed to reduce a downward impact of crude oil
prices. The mark-to-market value of the financial crude oil contracts outstanding as at December 31, 2002 reflects an
unrealized cost of $8,514,000.
The following table summerizes the Fund’s crude oil risk management positions at December 31, 2002:
|
|
| Term |
Jul. 1, 2003 - Sep. 30, 2003
3-Way option ¹ |
1,000 |
|
$32.00 |
|
$28.00 |
|
$23.75 |
Oct. 1, 2003 - Dec. 31, 2003
3-Way option ¹ |
1,000 |
|
$30.00 |
|
$28.00 |
|
$23.95 |
Jan. 1, 2003 - Sep. 30, 2004
3-Way option |
1,500 |
|
$29.00 |
|
$22.00 |
|
$19.25 |
Jan. 1, 2003 - Sep. 30, 2004
3-Way option |
1,500 |
|
$30.00 |
|
$23.00 |
|
$20.00 |
Jan. 1, 2003 - Dec. 31, 2003
3-Way option |
1,500 |
|
$27.00 |
|
$19.50 |
|
$17.00 |
| 3-Way option |
1,500 |
|
$28.00 |
|
$20.15 |
|
$17.00 |
| 3-Way option |
1,500 |
|
$28.51 |
|
$22.00 |
|
$19.50 |
Jan. 1, 2003 - Jun. 30, 2004
3-Way option |
1,500 |
|
$28.00 |
|
$22.50 |
|
$19.60 |
| 3-Way option |
500 |
|
$28.00 |
|
$22.50 |
|
$19.90 |
Jan. 1, 2003 - Dec. 31, 2004
3-Way option |
1,500 |
|
$29.50 |
|
$22.00 |
|
$20.00 |
Jan. 1, 2004 - Dec. 31, 2004
3-Way option |
1,000 |
|
$28.10 |
|
$23.00 |
|
$20.50 |
| 3-Way option |
1,000 |
|
$28.50 |
|
$25.00 |
|
$22.00 |
|
Natural Gas Instruments
Enerplus has the following physical and financial contracts in place on its gross natural gas production as described below. The
mark-to-market value of the financial natural gas contracts outstanding as at December 31, 2002 reflects an unrealized cost
of $34,190,000.
The following table summarizes the Fund’s natural gas risk management positions as at December 31, 2002:
|
|
| Term |
| Jan. 1, 2003 - Mar. 31, 2003 |
| 3-way option ³ |
4.8 |
$7.39 |
$5.28 |
$4.22 |
- |
- |
| 3-way option &sup4; |
4.8 |
$7.39 |
$5.28 |
$4.22 |
- |
- |
| Jan. 1, 2003 - Oct. 31, 2003 |
| Call |
9.5 |
$6.33 |
- |
- |
- |
- |
| Jan. 1, 2003 - Oct. 31, 2003 |
| Physical |
2.8 |
- |
- |
- |
$2.64 |
- |
| Collar ¹ |
7.1 |
$5.27 |
$3.69 |
- |
- |
- |
| Put ¹ |
7.1 |
- |
$3.69 |
- |
- |
- |
| Jan. 1, 2003 - Dec. 31, 2003 |
| Physical |
2.0 |
- |
- |
- |
- |
$2.23 |
| 3-way option |
9.5 |
$7.91 |
$4.27 |
$3.17 |
- |
- |
| Swap |
5.7 |
- |
- |
- |
$5.80 |
- |
| Jan. 1, 2003 - Jun. 30, 2004 |
| 3-way option |
9.5 |
$7.39 |
$4.75 |
$3.17 |
- |
- |
| Jan. 1, 2003 - Sep. 30, 2004 |
| 3-way option |
9.5 |
$6.67 |
$4.75 |
$3.17 |
- |
- |
| 3-way option |
9.5 |
$7.39 |
$4.75 |
$3.69 |
- |
- |
| Jan. 1, 2003 - Oct. 31, 2006 |
| Swap |
9.5 |
- |
- |
- |
$5.47 |
- |
| Swap |
4.8 |
- |
- |
- |
$5.25 |
- |
| Swap |
4.8 |
- |
- |
- |
$5.24 |
- |
| Swap |
4.8 |
- |
- |
- |
$5.28 |
- |
| Apr. 1, 2003 - Oct. 31, 2003 |
| Collar |
4.8 |
$6.33 |
$4.75 |
- |
- |
- |
| Collar |
4.8 |
$6.18 |
$4.75 |
- |
- |
- |
| Apr. 1, 2003 - Dec. 31, 2004 |
| 3-way option ² |
9.5 |
$7.91 |
$5.80 |
$4.22 |
- |
- |
| Jan. 1, 2003 - Oct. 31, 2004 |
| Swap |
3.8 |
- |
- |
- |
$2.90 |
- |
| Jan. 1, 2004 - Dec. 31, 2004 |
| Swap |
2.8 |
- |
- |
- |
$5.51 |
- |
| 2004 - 2010 |
| Physical |
2.0 |
- |
- |
- |
- |
$2.52 |
|
8. Commitments and Contingences
Pipeline Transportation
Enerplus has contracted to transport natural gas with various pipelines totaling 15 MMcf per day until 2008 and a further
5 MMcf per day until 2015. These transportation contracts apply to approximately 10% of the Fund’s natural gas production.
Oil Sands Lease #24
During 2002, the Fund acquired a 16% working interest in the Oil Sands Lease #24 (Josyln Creek Lease). The acquisition
included the assumption of approximately $4,179,000 in contingent project debt that was comprised of $3,360,000 of
principal and approximately $819,000 in accrued interest at December 31, 2002. Interest is accrued at the Bank of Canada
prime business rate and is not compounded. The debt is contingent on both production and pricing hurdles with respect to
development on the lease. As it is too early in the development of this project to determine if these hurdles will be satisfied,
the contingent debt has not been accrued in the consolidated financial statements.
9. Event Subsequent to December 31, 2002
Subsequent to December 31, 2002, the Fund acquired all of the issued and outstanding shares of PCC Energy Inc. and PCC
Energy Corp. (collectively "PCC") for total cash consideration of $167,600,000. The acquisition will be accounted for using
the purchase method of accounting for business combinations with the results of operations included in the consolidated
financial statements of the Fund from the closing date of March 5, 2003.
10. Differences Between Canadian and United States Generally Accepted Accounting Principles
The Fund’s consolidated financial statements have been prepared in accordance with Canadian GAAP. These principles, as they
pertain to the Fund’s consolidated statements, differ from United States GAAP ("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 deferred income taxes, is limited to the present value of
after tax future net revenue from proven reserves, discounted at ten 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 administrative expenses, 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, 2002, the
application of the ceiling test under U.S. GAAP did not result in a write-down of capitalized costs. At December 31, 2001,
the application of the ceiling test under U.S. GAAP resulted in a write down of $744,300,000 ($458,400,000 after tax) of
capitalized costs. Under Canadian GAAP, the application of the ceiling test did not result in a write down in either year.
(b) The Financial Accounting Standards Board’s ("FASB") Statement of Financial Standards ("SFAS") No. 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 measure compensation expense based on the
intrinsic value of the award when accounting for stock-based compensation arrangements, as provided for in Accounting
Principles Board Opinion 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
Unit Options granted prior to January 1, 2002 been determined based on the fair market value at the grant dates of the awards
consistent with the methodology prescribed by SFAS 123, Enerplus’ net income (loss) and net income (loss) per unit for years
ended December 31, 2002 and 2001 would have been the pro forma amounts indicated below:
|
| Net income (loss) |
| As reported under U.S. GAAP |
$ |
149,384 |
$ |
(261,288) |
| Pro forma |
|
148,859 |
|
(262,191) |
| Net income (loss) Per Trust Unit |
| Basic |
| As reported under U.S. GAAP |
$ |
2.08 |
$ |
(4.76) |
| Pro forma |
$ |
2.07 |
$ |
(4.78) |
| Diluted |
| As reported under U.S. GAAP |
$ |
2.07 |
$ |
(4.76) |
| Pro forma |
$ |
2.07 |
$ |
(4.78) |
|
As the exercise price of the trust unit 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 on the rights 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. During 2002, a $0.19 per right downward reduction in the exercise price on 1,400,000
rights had occurred. Accordingly, a charge to net income was recognized for the year ended December 31, 2002 of $3,406,000.
For the year ended December 31, 2001 no downward revision in exercise price had occurred and no compensation expense
was recognized for the rights.
(c) Under U.S. GAAP the measurement date for acquisitions is the date the acquisition is announced. Previously to June 1,
2001 under Canadian GAAP the measurement date for the acquisition was the closing date. Therefore, under U.S. GAAP,
unitholders’ capital and property, plant and equipment have been increased by $37,300,000 in 2001 for differences in the value
of trust units issued to effect the Merger.
(d) Effective January 1, 2001, for U.S. reporting purposes, the Fund adopted Statement of SFAS 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.
With respect to its crude oil and natural gas contracts that do not qualify for hedge accounting treatment under SFAS 133,
the Fund has recognized in earnings a loss of $25,312,000 ($14,529,000 net of tax) in 2002 compared to a loss of $437,000
($251,000 net of tax) in 2001.
(e) U.S. GAAP requires the reporting of comprehensive income in addition to net earnings. The Fund’s comprehensive
income for the year ended December 31, 2002 includes a net unrealized gain of $10,415,000 on instruments qualifying for
hedge accounting under SFAS 133. The net unrealized gain is comprised of $2,000,000 ($1,148,000 net of tax) unrealized
hedging loss on the $75,000,000 interest rate swap, an unrealized hedging gain of $37,100,000 ($21,295,000 net of tax)
relating to the combined cross currency and interest rate swap on the senior unsecured notes and an unrealized loss of
$16,955,000 ($9,732,000 net of tax) relating to the change in fair value of certain of the Fund’s natural gas contracts. For the
year ended December 31, 2001, the Fund’s net income was equal to its comprehensive income.
(f) Recent Developments in U.S. Accounting Standards
In June 2001, the FASB issued SFAS 143, "Accounting for Asset Retirement Obligations." SFAS 143 requires liability
recognition for retirement obligations associated with tangible long-lived assets. The obligations included within the scope of
SFAS 143 are those for which the Fund faces a legal obligation for settlement. The initial measurement of the asset retirement
obligation is to be capitalized as part of the cost of the related long-lived asset and amortized to expense over the useful life of
the asset. SFAS 143 is effective for all fiscal years beginning on or after June 15, 2002. The total impact on the Fund’s financial
statements has not yet been determined.
The application of U.S. GAAP would have the following effects on net income as reported:
|
| Net income as reported in the Consolidated |
| Statement of Income - Canadian GAAP |
$ |
115,876 |
$ |
180,269 |
| Adjustments, net of tax |
| Write-down of property, plant and equipment |
|
- |
|
(458,474) |
| Depletion, depreciation and amortization |
|
51,443 |
|
17,168 |
| Compensation expense |
|
(3,406) |
|
- |
| Unrealized (loss) on financial derivatives |
|
(14,529) |
|
(251) |
|
| Net income (loss) - U.S. GAAP |
$ |
149,384 |
$ |
(261,288) |
| Net unrealized gain on hedging instruments, net of tax |
|
10,415 |
|
- |
|
| Comprehensive income (loss) |
$ |
159,799 |
$ |
(261,288) |
|
| Net income (loss) per trust unit |
| Basic |
$ |
2.08 |
$ |
(4.76) |
| Diluted |
$ |
2.07 |
$ |
(4.76) |
| Weighted average number of trust units outstanding |
| Basic |
|
71,946 |
|
54,907 |
| Diluted |
|
72,084 |
|
54,956 |
|
| Accumulated other comprehensive income |
$ |
- |
$ |
- |
| Balance, beginning of year |
|
- |
|
- |
| Net unrealized gain on hedging instruments, net of tax |
|
10,415 |
|
- |
| Balance, end of year |
$ |
10,415 |
$ |
- |
|
The application of U.S. GAAP would have the following effects on the balance sheet as reported:
|
| December 31, 2002 |
| Financial derivative assets |
|
- |
$ |
37,100 |
$ |
37,100 |
| Property, plant and equipment, net |
$ |
2,374,145 |
|
(935,099) |
|
1,439,046 |
| Financial derivative liabilities |
|
- |
|
44,704 |
|
44,704 |
| Future income taxes |
|
340,269 |
|
