SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 40-F
[_] Registration statement pursuant to Section 12 of the Securities
Exchange Act of 1934
or
[X] Annual report pursuant to Section 13(a) or 15(d) of the Securities
Exchange Act of 1934
For Fiscal year ended: DECEMBER 31, 2002
Commission file number: 0-30514
ARC ENERGY TRUST
(Exact name of Registrant as specified in its charter)
N/A
(Translation of Registrant's name into English (if applicable))
ALBERTA 1311 NOT APPLICABLE
(Province or other (Primary Standard Industrial (I.R.S. Employer
jurisdiction of Classification Code Number, Identification No.,
incorporation or organization) if applicable) if applicable)
2100, 440 2ND AVENUE S.W.
CALGARY, ALBERTA
CANADA T2P 5E9
(Address and telephone number of Registrant's principal executive offices)
CORPORATION SERVICE COMPANY
2711 CENTERVILLE ROAD, SUITE 400
WILMINGTON, DELAWARE
19805
(302) 636-5401
(Name, Address (including zip code) and telephone number (including area code)
of agent for service in the United States)
Securities registered or to be registered pursuant to Section 12(b) of the Act:
Title of each class: Name of each Exchange on which registered
N/A N/A
Securities registered or to be registered pursuant to Section 12(g) of the Act:
Title of each Class
TRUST UNITS
Securities for which there is a reporting obligation pursuant to section 15(d)
of the Act:
N/A
(Title of Class)
For annual reports, indicate by check mark the information filed with this form:
[X] Annual Information Form [X] Audited Annual Financial Statements
2
Indicate the number of outstanding shares of each of the issuer's classes of
capital or common stock as of the close of the period covered by the annual
report:
123,305,329 TRUST UNITS
Indicate by check mark whether the registrant by filing the information
contained in this Form is also thereby furnishing the information to the
Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934
(the "Exchange Act"). If "Yes" is marked, indicate the filing number assigned to
the Registrant in connection with such rule.
Yes [_] No [X]
Indicate by check mark whether the registrant: (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Exchange Act during the
preceding 12 months (or for such shorter period that the Registrant was required
to file such reports); and (2) has been subject to such filing requirements in
the past 90 days.
Yes [X] No [_]
3
FORM 40-F - TABLE OF CONTENTS
1. Consolidated Financial Statements for the fiscal year ended December
31, 2002 (note 18 to the Consolidated Financial Statements relates to
the United States Accounting Principles and Reporting (U.S. GAAP)).
2. Management's Discussion and Analysis and Results of Operations for the
fiscal year ended December 31, 2002.
3. Annual Information Form for the fiscal year ended December 31, 2002.
4. Disclosure Controls and Procedures
5. Exhibits
MANAGEMENT'S RESPONSIBILITY
Management is responsible for the preparation of the accompanying
consolidated financial statements and for the consistency therewith of
all other financial and operating data presented in this annual report.
The consolidated financial statements have been prepared in accordance
with the accounting policies detailed in the notes thereto. In
Management's opinion, the consolidated financial statements are in
accordance with Canadian generally accepted accounting principles, have
been prepared within acceptable limits of materiality, and have
utilized supportable, reasonable estimates.
Management maintains a system of internal controls to provide
reasonable assurance that all assets are safeguarded, transactions are
appropriately authorized and to facilitate the preparation of relevant,
reliable and timely information.
Deloitte & Touche LLP, independent auditors appointed by the Trustee,
have examined the consolidated financial statements of the Trust. The
Audit Committee, consisting of the independent directors of ARC
Resources Ltd., has reviewed these consolidated financial statements
with management and the auditors, and has recommended them to the Board
of Directors for approval. The Board has approved the consolidated
financial statements of the Trust.
SIGNED "JOHN P. DIELWART" SIGNED "STEVEN W. SINCLAIR"
- ----------------------------- -----------------------------
PRESIDENT AND CHIEF EXECUTIVE OFFICER CHIEF FINANCIAL OFFICER
Calgary, Alberta
January 27, 2003
Page 1
Deloitte & Touche LLP
3000, 700 Second Street SW
Calgary, AB Canada T2P 0S7
Telephone: +1-403-267-1700
Facsimile: +1-403-264-2871
INDEPENDENT AUDITORS' REPORT
To the Unitholders of
ARC ENERGY TRUST:
We have audited the consolidated balance sheets of ARC ENERGY TRUST as at
December 31, 2002 and 2001 and the consolidated statements of income and
accumulated earnings and of cash flows for the years then ended. These
consolidated financial statements are the responsibility of the Trust's
management. Our responsibility is to express an opinion on these consolidated
financial statements based on our audits.
We conducted our audits in accordance with Canadian generally accepted
accounting principles. Those standards require that we plan and perform an audit
to obtain reasonable assurance whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall consolidated financial
statement presentation.
In our opinion, these consolidated financial statements present fairly, in all
material respects, the financial position of the Trust as at December 31, 2002
and 2001 and the results of its operations and its cash flows for the years then
ended in accordance with Canadian generally accepted accounting principles.
On January 27, 2003, we reported separately to the unitholders of ARC Energy
Trust on the consolidated financial statements for the same period, prepared in
accordance with Canadian generally accepted accounting principles but which did
not include Note 18; Differences Between Canadian and United States Generally
Accepted Accounting Principles.
Calgary, Alberta (signed) "DELOITTE & TOUCHE" LLP
January 27, 2003 Chartered Accountants
Page 2
CONSOLIDATED BALANCE SHEET
As at December 31
(CDN$ thousands) 2002 2001
- ----------------------------------------------------------------------------------------
- ----------------------------------------------------------------------------------------
ASSETS
Current assets
Cash $ 835 $ 646
Accounts receivable 49,631 51,875
Prepaid expenses 6,965 6,030
- ----------------------------------------------------------------------------------------
57,431 58,551
Reclamation fund (Note 7) 12,924 10,147
Property, plant and equipment (Note 8) 1,397,563 1,311,306
- ----------------------------------------------------------------------------------------
Total assets $ 1,467,918 $ 1,380,004
========================================================================================
LIABILITIES
Current liabilities
Accounts payable and accrued liabilities $ 51,454 $ 35,595
Cash distributions payable 16,044 16,594
Payable to the Manager (Notes 5 and 16) -- 557
- ----------------------------------------------------------------------------------------
67,498 52,746
Long-term debt (Note 9) 337,728 294,489
Site reclamation and abandonment 36,421 28,837
Commodity and foreign currency contracts (Notes 6 and 10) 9,210 13,107
Retention Bonuses (Note 5) 4,000 --
Future income taxes (Note 15) 144,395 174,030
- ----------------------------------------------------------------------------------------
Total liabilities 599,252 563,209
- ----------------------------------------------------------------------------------------
UNITHOLDERS' EQUITY
Unitholders' capital (Note 11) 1,172,199 1,029,538
Exchangeable shares (Note 12) 35,326 10,392
Accumulated earnings (Note 3) 350,088 282,195
Accumulated cash distributions (Note 4) (688,947) (505,330)
- ----------------------------------------------------------------------------------------
Total unitholders' equity 868,666 816,795
- ----------------------------------------------------------------------------------------
Total liabilities and unitholders' equity $ 1,467,918 $ 1,380,004
========================================================================================
See accompanying notes to consolidated financial statements
Approval on behalf of the Board
(signed) Mac H. Van Wielingen (signed) John P. Dielwart
Director Director
Page 3
CONSOLIDATED STATEMENT OF INCOME AND ACCUMULATED EARNINGS
For the years ended December 31
(CDN$ thousands, except per unit amounts) 2002 2001
- ----------------------------------------------------------------------------------------------
REVENUE
Oil, natural gas, natural gas liquids and sulphur sales $ 444,835 $ 515,596
Royalties (85,155) (112,209)
- ----------------------------------------------------------------------------------------------
359,680 403,387
- ----------------------------------------------------------------------------------------------
EXPENSES
Operating 99,876 86,108
General and administrative (Note 16) 15,365 11,812
Management fee (Note 16) 5,161 8,789
Interest on long-term debt (Note 9) 12,606 17,138
Depletion, depreciation and amortization 161,759 165,050
Capital taxes 1,370 1,794
(Gain)/loss on foreign exchange (Note 3) (607) 3,297
Internalization of management contract (Note 5) 25,892 --
- ----------------------------------------------------------------------------------------------
321,422 293,988
- ----------------------------------------------------------------------------------------------
Income before future income tax recovery 38,258 109,399
Future income tax recovery (Note 15) 29,635 28,803
- ----------------------------------------------------------------------------------------------
Net income 67,893 138,202
Accumulated earnings, beginning of year 283,575 142,887
Retroactive application of change in accounting policy (Note 3) (1,380) 1,106
- ----------------------------------------------------------------------------------------------
Accumulated earnings, beginning of year, as restated 282,195 143,993
- ----------------------------------------------------------------------------------------------
Accumulated earnings, end of year $ 350,088 $ 282,195
==============================================================================================
- ----------------------------------------------------------------------------------------------
Net income per unit (Note 14)
Basic $ 0.57 $ 1.36
Diluted $ 0.56 $ 1.35
==============================================================================================
See accompanying notes to consolidated financial statements
Page 4
CONSOLIDATED STATEMENT OF CASH FLOWS
For the years ended December 31
(CDN$ thousands, except per unit amounts) 2002 2001
- ----------------------------------------------------------------------------------------------
CASH FLOW FROM OPERATING ACTIVITIES
Net income $ 67,893 $ 138,202
Add items not involving cash:
Future income tax recovery (29,635) (28,803)
Depletion, depreciation and amortization 161,759 165,050
Amortization of commodity and foreign currency contracts (1,766) (17,497)
Internalization of management contract (Note 5) 25,892 --
Unrealized (gain)/loss on foreign exchange (174) 3,318
- ----------------------------------------------------------------------------------------------
223,969 260,270
Change in non-cash working capital 999 (6,399)
- ----------------------------------------------------------------------------------------------
224,968 253,871
- ----------------------------------------------------------------------------------------------
CASH FLOW FROM FINANCING ACTIVITIES
Borrowing (repayments) of long-term debt, net (3,750) 13,103
Issue of Senior Secured Notes 47,163 --
Issue of Trust units 128,481 93,053
Trust unit issue costs (6,459) (4,654)
Cash distributions paid (184,167) (235,590)
- ----------------------------------------------------------------------------------------------
(18,732) (134,088)
- ----------------------------------------------------------------------------------------------
CASH FLOW FROM INVESTING ACTIVITIES
Acquisition of Startech, net of cash received (Note 6) -- (7,970)
Acquisition of oil and gas properties (131,761) (32,686)
Proceeds on disposition of oil and gas properties 12,647 19,775
Capital expenditures (75,796) (97,207)
Reclamation fund contributions and actual expenditures (Note 7) (5,806) (4,380)
Internalization of management contract (Note 5) (5,331) --
- ----------------------------------------------------------------------------------------------
(206,047) (122,468)
- ----------------------------------------------------------------------------------------------
INCREASE (DECREASE) IN CASH 189 (2,685)
CASH, BEGINNING OF YEAR 646 3,331
- ----------------------------------------------------------------------------------------------
CASH, END OF YEAR $ 835 $ 646
==============================================================================================
See accompanying notes to consolidated financial statements
Page 5
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2002 and 2001
(all tabular amounts in thousands, except per unit and volume amounts)
1. STRUCTURE OF THE TRUST
ARC Energy Trust ("the Trust") was formed on May 7, 1996 pursuant to a
trust indenture (the "Trust Indenture"). Computershare Trust Company of
Canada was appointed as Trustee under the Trust Indenture. The
beneficiaries of the Trust are the holders of the trust units.
The Trust was created for the purposes of issuing trust units to the
public and investing the funds so raised to purchase a royalty in the
properties of ARC Resources Ltd. ("ARC Resources"). The Trust Indenture
was amended on June 7, 1999 to convert the Trust from a closed-end to
an open-ended investment trust. The Trust Indenture was most recently
amended on May 23, 2000 to expand the scope of the business to include
the investment in all types of energy business-related assets
including, but not limited to, petroleum and natural gas-related
assets, oil sands interests, electricity or power generating assets and
pipeline, gathering, processing and transportation assets. The
operations of the Trust consist of the acquisition, development,
exploitation and disposition of these assets and the distribution of
net cash proceeds from these activities to the unitholders.
2. SUMMARY OF ACCOUNTING POLICIES
The consolidated financial statements have been prepared by management
following Canadian generally accepted accounting principles ("GAAP").
The preparation of financial statements requires management to make
estimates and assumptions that affect the reported amounts of assets
and liabilities and the disclosure of contingencies at the date of the
financial statements, and revenues and expenses during the reporting
period. Actual results could differ from those estimated.
In particular, the amounts recorded for depletion, depreciation and
amortization of the petroleum and natural gas properties, deferred
charges, and for site reclamation and abandonment are based on
estimates of reserves and future costs. By their nature, these
estimates, and those related to future cash flows used to assess
impairment, are subject to measurement uncertainty and the impact on
the financial statements of future periods could be material.
PRINCIPLES OF CONSOLIDATION
The consolidated financial statements include the accounts of the Trust
and its subsidiaries. All inter-entity transactions have been
eliminated.
PROPERTY, PLANT AND EQUIPMENT
The Trust follows the full-cost method of accounting. All costs of
acquiring petroleum and natural gas properties and related development
costs are capitalized and accumulated in one cost centre. Maintenance
and repairs are charged against income, and renewals and enhancements
which extend the economic life of the property, plant and equipment are
capitalized. Gains and losses are not recognized upon disposition of
petroleum and natural gas properties unless such a disposition would
alter the rate of depletion by 20 percent or more.
Page 6
DEPLETION, DEPRECIATION AND AMORTIZATION
Depletion of petroleum and natural gas properties and depreciation of
production equipment, except for major gas plant facilities, are
calculated on the unit-of-production method based on:
(a) total estimated proved reserves;
(b) total capitalized costs plus estimated future development
costs of proved undeveloped reserves less estimated net
realizable value of production equipment and facilities after
the proved reserves are fully produced; and
(c) relative volumes of petroleum and natural gas reserves and
production converted at the energy equivalent conversion ratio
of six thousand cubic feet of natural gas to one barrel of
oil.
Major gas plant facilities are depreciated on a straight-line basis
over their estimated useful lives.
CEILING TEST
The Trust 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, depreciation
and amortization, site reclamation and abandonment and future income
tax liabilities are limited to an amount equal to the estimated
undiscounted future net revenues from proved reserves less estimated
recurring general and administrative expenses, future site reclamation
and abandonment costs, future financing costs and income taxes.
FUTURE SITE RECLAMATION AND ABANDONMENT
Provisions for future site reclamation and abandonment costs are
calculated on the unit-of-production method over the life of the
petroleum and natural gas properties based on total estimated proved
reserves. Actual site reclamation costs incurred are charged against
the site reclamation and abandonment liability.
UNIT-BASED COMPENSATION PLAN
The Trust has a unit-based compensation plan for employees, independent
directors and long-term consultants who otherwise meet the definition
of an employee of the Trust. Compensation cost is measured based on the
intrinsic value of the award at the date of grant and is recognized
over the vesting period. Any consideration received by the Trust on
exercise of the unit rights is credited to unitholders' capital. See
Note 13 for a description of the plan and proforma disclosure of
associated compensation cost.
Page 7
INCOME TAXES
The Trust follows the liability method of accounting for income taxes.
Under this method, income tax liabilities and assets are recognized for
the estimated tax consequences attributable to differences between the
amounts reported in the financial statements of the Trust's corporate
subsidiaries and their respective tax base, using enacted income tax
rates. The effect of a change in income tax rates on future tax
liabilities and assets is recognized in income in the period in which
the change occurs. Temporary differences arising on acquisitions result
in future income tax assets and liabilities.
The Trust is a taxable entity under the INCOME TAX ACT (Canada) and is
taxable only on income that is not distributed or distributable to the
unitholders. As the Trust distributes all of its taxable income to the
unitholders and meets the requirements of the INCOME TAX ACT (Canada)
applicable to the Trust, no provision for income taxes has been made in
the Trust.
HEDGING
The Trust uses derivative instruments to reduce its exposure to
fluctuations in commodity prices and foreign exchange rates. Gains and
losses on these contracts, all of which constitute effective hedges,
are recognized as a component of the related transaction.
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.
3. CHANGE IN ACCOUNTING POLICY
Effective for fiscal years beginning on or after January 1, 2002, the
Canadian Institute of Chartered Accountants ("CICA") introduced new
recommendations for the accounting for foreign exchange translation
gains and losses on long-term monetary items. Such translation gains
and losses are no longer to be deferred and amortized over the
remaining term but rather are to be reflected in the statement of
income in the period incurred. This change in accounting policy has
been applied retroactively with restatement of prior periods.
As a result of this change, net income for the year ended December 31,
2002 increased by $525,000 and net income for the year ended December
31, 2001 decreased by $2.5 million from the net income which would have
been reported under the previous accounting policy. The change also
resulted in a decrease in the deferred foreign exchange translation
loss of $2.1 million and a decrease in future income taxes of $673,000
as at December 31, 2001.
Page 8
4. RECONCILIATION OF CASH FLOW AND DISTRIBUTIONS
2002 2001
-------------------------------------------------------------------------------------------
Cash flow from operations $ 223,969 $ 260,270
Add (deduct):
Cash withheld to fund capital expenditures (35,612) (27,933)
Reclamation fund contributions and interest earned on fund (4,777) (4,095)
Current period accruals 37 5,811
-------------------------------------------------------------------------------------------
Cash Distributions 183,617 234,053
Accumulated cash distributions, beginning of year 505,330 271,277
-------------------------------------------------------------------------------------------
Accumulated cash distributions, end of year $ 688,947 $ 505,330
===========================================================================================
Cash distributions per unit $ 1.56 $ 2.31
Accumulated cash distributions per unit, beginning of year 9.08 6.77
-------------------------------------------------------------------------------------------
Accumulated cash distributions per unit, end of year $ 10.64 $ 9.08
===========================================================================================
Cash distributions per trust unit reflect the sum of the per trust unit
amounts paid monthly to unitholders.
5. INTERNALIZATION OF MANAGEMENT CONTRACT
Effective August 29, 2002, the Trust acquired all of the outstanding
common shares of ARC Resources Management Ltd., ("ARML"), the Manager
of the Trust. Total consideration for the transaction consisted of a
cash payment of $4.3 million, the issuance of 298,648 Trust Units and
3,281,279 Exchangeable Shares to the Shareholders of ARML and the
assumption of a liability to pay retention bonuses to the Management of
the Trust in the amount of $5.0 million as detailed below:
Total consideration:
-----------------------------------------------------------------------
Cash $ 4,247
Trust units issued 3,802
Exchangeable shares issued 41,771
Assumption of liability for retention bonuses 5,000
Costs associated with the transaction 1,083
-----------------------------------------------------------------------
Total purchase price $ 55,903
=======================================================================
Prior to the acquisition, the Trust paid fees to ARML equal to three
per cent of net production revenue and fees of 1.5 per cent and 1.25
per cent, respectively on the purchase price of acquisitions and
dispositions in accordance with the terms of the management agreement
between the Trust and ARML. The acquisition resulted in the elimination
of all fees under the existing management agreement which would have
otherwise been in effect for a minimum five year period.
Of the total purchase price, $30.0 million was capitalized as property,
plant and equipment. The capitalized amount includes $25.0 million for
ARML's three per cent interest in the net production revenue of the
Trust over the agreement term based on existing established reserves at
the time of the transaction and $5.0 million for the retention bonuses.
The retention bonuses are to be paid over a five year period to former
management of ARML who are continuing in their capacities with the
Trust. The remaining portion of the purchase price of $25.9 million was
expensed in the current period. The expensed portion represents future
management, acquisition and disposition fees on incremental reserves
over the remaining five year term of the management agreement and the
value of directly hiring existing management and staff of ARML.
Page 9
6. ACQUISITION OF STARTECH ENERGY INC.
Effective January 31, 2001, the Trust acquired all of the issued and
outstanding shares of Startech Energy Inc. ("Startech"). The
transaction has been accounted for using the purchase method of
accounting with the allocation of the purchase price and consideration
paid as follows:
Net assets acquired:
-----------------------------------------------------------------------
Cash $ 12,319
Working capital 1,770
Property, plant and equipment 751,198
Site reclamation liability (5,130)
Commodity and foreign currency contracts (Note 10) (33,149)
Future income taxes (203,171)
-----------------------------------------------------------------------
Total net assets acquired $ 523,837
=======================================================================
Financed by:
-----------------------------------------------------------------------
Cash $ 20,289
Trust units issued 256,051
Exchangeable shares issued 84,497
Debt assumed 163,000
-----------------------------------------------------------------------
Total purchase price $ 523,837
=======================================================================
7. RECLAMATION FUND
2002 2001
Balance, beginning of year $ 10,147 $ 9,897
Contributions, net of actual expenditures 2,000 (245)
Interest earned on fund 777 495
-----------------------------------------------------------------------
Balance, end of year $ 12,924 $ 10,147
=======================================================================
A reclamation fund was established to fund future site reclamation and
abandonment costs. The Board of Directors of ARC Resources Ltd. has
approved contributions over a 20-year period which results in minimum
annual contributions of $4.0 million ($3.6 million in 2001) based upon
properties owned as at December 31, 2002. Contributions to the
reclamation fund and interest earned on the reclamation fund balance
have been deducted from the cash distributions to the unitholders.
During the year, $2.0 million ($3.8 million in 2001) of actual
expenditures were charged against the reclamation fund.
Page 10
8. PROPERTY, PLANT AND EQUIPMENT
2002 2001
-----------------------------------------------------------------------
Property, plant and equipment, at cost $ 1,888,122 $ 1,650,720
Accumulated depletion, depreciation and
amortization (490,559) (339,414)
-----------------------------------------------------------------------
Property, plant and equipment, net $ 1,397,563 $ 1,311,306
=======================================================================
The calculation of 2002 depletion, depreciation and amortization
included an estimated $190.1 million ($166.5 million in 2001) for
future development costs associated with proved undeveloped reserves
and excluded $12.6 million ($12.0 million in 2001) for the estimated
future net realizable value of production equipment and facilities and
$19.7 million ($22.3 million in 2001) for the estimated value of
unproved properties.
9. LONG-TERM DEBT
2002 2001
----------------------------------------------------------------------------
Revolving credit facilities $ 235,054 $ 238,748
Senior Secured Notes:
Senior Secured Notes (2000 Issue - US$35 million) 55,286 55,741
Senior Secured Notes (2002 Issue - US$30 million) 47,388 --
----------------------------------------------------------------------------
Total long-term debt $ 337,728 $ 294,489
============================================================================
The Trust has four revolving credit facilities to a combined maximum of
$300 million and US$65 million of Senior Secured Notes (the "Notes").
The revolving credit facilities each have a 364 day extendable
revolving period and a two year term. Borrowings under the facilities
bear interest at bank prime (4.5 per cent at December 31, 2002) or, at
the Trust's option, bankers' acceptance plus a stamping fee. The
lenders review the credit facilities by April 30 each year and
determine whether they will extend the revolving periods for another
year. In the event that the revolving periods are not extended, the
loan balance will become repayable over a two year term period with 20
per cent of the loan balance payable on April 30, 2004 followed by
three quarterly payments of five per cent of the loan balance and a
lump sum payment of 65 per cent of the loan balance at the end of the
term period. Collateral for the loans is in the form of floating
charges on all lands and assignments and negative pledges on specific
petroleum and natural gas properties.
The US$65 million Notes were issued in two separate issues pursuant to
an Uncommitted Master Shelf Agreement. The first issue of US$35 million
Notes were issued in 2000, bear interest at 8.05 per cent, and require
equal principal payments of US$7 million over a five year period
commencing in 2004. The second issue of US$30 million Notes were issued
in 2002, bear interest at 4.94 per cent, and require equal principal
payments of US$6 million over a five year period commencing in 2006.
Security for the Notes is in the form of floating charges on all lands
and assignments. The Uncommitted Master Shelf Agreement allows for the
issuance of an additional US$35 million of Notes at rates and maturity
dates to be agreed upon at the date of issuance. The Notes rank PARI
PASU to the revolving credit facilities.
The payment of principal and interest are allowable deductions in the
calculation of cash available for distribution to unitholders and rank
in priority to cash distributions payable to unitholders. Should the
properties securing this debt generate insufficient revenue to repay
the outstanding balances, the unitholders have no direct liability.
Interest paid during the year did not differ significantly from
interest expense.
Page 11
10. FINANCIAL INSTRUMENTS
The Trust is exposed to market risks resulting from fluctuations in
commodity prices, foreign exchange rates and interest rates in the
normal course of operations. A variety of derivative instruments are
used by the Trust to reduce its exposure to fluctuations in commodity
prices and foreign exchange rates. The fair values of these derivative
instruments are based on an estimate of the amounts that would have
been received or paid to settle these instruments prior to maturity.
The Trust is exposed to losses in the event of default by the
counterparties to these derivative instruments. The Trust manages this
risk by diversifying its derivative portfolio amongst a number of
financially sound counterparties.
Financial instruments of the Trust carried on the balance sheet consist
mainly of current assets, reclamation fund investments, current
liabilities, retention bonuses, commodity and foreign currency
contracts, and long-term debt. Except as noted below, as at December
31, 2002 and 2001, there were no significant differences between the
carrying value of these financial instruments and their estimated fair
value.
Substantially all of the Trust's accounts receivable are due from
customers in the oil and gas industry and are subject to the normal
industry credit risks. The carrying value of accounts receivable
reflects management's assessment of the associated credit risks.
The fair value of the US$65 million fixed rate Senior Secured Notes
approximated $109.5 million at December 31, 2002.
The following derivative contracts were outstanding as at December 31,
2002. Settlement of these contracts, which have no book value, would
have resulted in a net payment by the Trust of $17.5 million as at
December 31, 2002.
DAILY AVERAGE CONTRACT
COMMODITY CONTRACTS QUANTITY PRICES ($)(1) PRICE INDEX TERM
-------------------------------------------------------------------------------------------------------------------------
Crude oil fixed price contracts 7,100 bbls 41.88 WTI January 2003 - March 2003
4,000 bbls 39.78 WTI April 2003 - September 2003
Crude oil fixed price contracts
(embedded put option) (2) 4,000 bbls 39.51 (31.59) WTI January 2003 - December 2003
Crude oil collared contracts
(embedded put option) (2) 4,000 bbls 42.65 - 47.39 WTI April 2003 - June 2003
(35.78)
2,000 bbls 39.49 - 45.49 WTI July 2003 - December 2003
(33.17)
Natural gas fixed price contracts 1,000 GJ 4.00 AECO January 2003 - March 2003
27,823 GJ 4.50 AECO April 2003 - October 2003
Natural gas fixed differential 4,000 GJ AECO + $1.29 AECO January 2003 - March 2003
contracts
Natural gas put contracts 22,500 GJ 6.00 AECO January 2003 - March 2003
=========================================================================================================================
AVERAGE
AVERAGE MONTHLY CONTRACT CONTRACT
FOREIGN CURRENCY CONTRACTS AMOUNT (US$000) RATE TERM
-------------------------------------------------------------------------------------------------------------------------
Fixed rate foreign exchange
contracts (sell) 8,049 1.5809 January 2003 - March 2003
4,494 1.5900 April 2003 - December 2003
=========================================================================================================================
Page 12
The Trust entered into a contract to fix the price of electricity on
five megawatts per hour ("MW/h") for the period April 17, 2001 through
December 31, 2010 at a price of $63/MW/h. Settlement of this contract
would have required a net payment by the Trust of $4.3 million as at
December 31, 2002.
In addition to the contracts described above, the following contracts,
with a liability book value of $9.2 million, were outstanding as at
December 31, 2002. These contracts were acquired in conjunction with
the Startech acquisition at which time the market value of such
contracts acquired was a net liability of $33.1 million. Settlement of
these contracts would have resulted in a net payment by the Trust of
$11.2 million as at December 31, 2002.
DAILY AVERAGE CONTRACT
COMMODITY CONTRACTS QUANTITY PRICES ($)(1) PRICE INDEX TERM
-------------------------------------------------------------------------------------------------------------------------
Natural gas fixed price contracts 4,000 GJ 2.71 AECO January 2003 - October 2004
=========================================================================================================================
AVERAGE MONTHLY CONTRACT AVERAGE
FOREIGN CURRENCY CONTRACTS AMOUNT (US$000) CONTRACT TERM
RATE
-------------------------------------------------------------------------------------------------------------------------
Fixed rate foreign exchange
contracts (sell) 1,500 1.4106 January 2003 - December 2003
=========================================================================================================================
(1) Commodity contracts denominated in US$ have been converted to
CDN$ at the year end exchange rate.
(2) Counterparty may exercise a put option if index falls below
the specified price (as denoted in brackets) on a monthly
settlement basis.
11. UNITHOLDERS' CAPITAL
On June 3, 2002, the Trust issued 10,000,000 trust units at $12.05 per
unit for proceeds of $120.5 million ($114.3 million net of issue costs)
pursuant to a public offering prospectus dated May 22, 2002.
On August 29, 2002 the Trust issued 298,648 units to shareholders of
ARML at $12.73 per unit pursuant to the acquisition of all of the
outstanding common shares of ARML (see Note 5). The issue price of the
units was determined based on the 10 day weighted average trading price
of the trust units preceding the date of announcement of the
transaction.
The Trust established a Distribution Reinvestment Plan ("DRIP") in
conjunction with the Trust's transfer agent to provide the option for
Unitholders to reinvest cash distributions into additional trust units
issued from treasury. In 2002, the Trust issued 242,496 units for
proceeds of $2.9 million (57,177 units for proceeds of $650,000 in
2001).
The Trust has adopted a Unitholders' Rights Plan which provides for the
issuance of additional trust units in certain events when one party
acquires more than 20 percent of the outstanding units of the Trust.
The Trust is authorized to issue 650 million trust units.
Page 13
2002 2001
-----------------------------------------------------------------------------------------------------------------------
TRUST UNITS ISSUED NUMBER OF Number of
TRUST UNITS $ Trust Units $
-----------------------------------------------------------------------------------------------------------------------
Balance, beginning of year 110,609 1,029,538 72,524 610,645
Issued for cash 10,000 120,500 8,050 88,550
Issued on acquisition of Startech (Note 6) -- -- 22,540 256,051
Issued to ARML shareholders (Note 5) 299 3,802 -- --
Issued on conversion of ARML
exchangeable shares (Note 12) 1,086 13,683 -- --
Issued on conversion of ARL
exchangeable shares (Note 12) 343 3,154 6,867 74,105
Issued on exercise of employee rights 726 5,035 571 4,191
Distribution reinvestment program 242 2,946 57 650
Trust unit issue costs -- (6,459) -- (4,654)
-----------------------------------------------------------------------------------------------------------------------
Balance, end of year 123,305 1,172,199 110,609 1,029,538
=======================================================================================================================
12. EXCHANGEABLE SHARES
On August 29, 2002 the Trust issued 3,281,279 exchangeable shares of
ARML ("ARML Exchangeable Shares") to shareholders of ARML at $12.73 per
exchangeable share pursuant to the acquisition of all of the
outstanding common shares of ARML (see Note 5). The issue price of the
exchangeable shares was determined based on the 10 day weighted average
trading price of the trust units preceding the date of announcement of
the transaction. The exchangeable shares issued to ARML shareholders
are a new series of exchangeable shares which are not publicly traded.
The ARML Exchangeable Shares had an exchange ratio of 1:1 at the time
of issuance.
The ARML Exchangeable Shares can be converted (at the option of the
holder) into trust units at any time on or after August 29, 2002. The
number of trust units issuable upon conversion is based upon the
exchange ratio in effect at the conversion date. The exchange ratio is
calculated monthly based on the cash distribution paid to unitholders
divided by the ten day weighted average unit price preceding the record
date. The exchangeable shares are not eligible for distributions and,
in the event that they are not converted, any outstanding shares are
redeemable by the Trust for trust units on or after August 30, 2005
until August 29, 2012.
During the year, 1,074,870 ARML Exchangeable Shares were converted to
trust units at an average exchange ratio of 1.01002 trust units for
each ARML Exchangeable Share. At December 31, 2002 the ARML exchange
ratio was 1.04337 to 1.
2002 2001
-----------------------------------------------------------------------------------------------------------------------
NUMBER OF Number of
ARML EXCHANGEABLE SHARES SHARES $ Shares $
-----------------------------------------------------------------------------------------------------------------------
Balance, beginning of year -- -- -- --
Issued to ARML shareholders 3,281 41,771 -- --
Exchanged for trust units (1,075) (13,683) -- --
-----------------------------------------------------------------------------------------------------------------------
Balance, end of year 2,206 28,088 -- --
Exchange ratio, end of year 1.04337 -- -- --
-----------------------------------------------------------------------------------------------------------------------
Trust units issuable upon conversion, end of year 2,302 28,088 -- --
=======================================================================================================================
Page 14
On January 31, 2001, the Trust issued 7,438,129 million exchangeable
shares of ARC Resources Ltd. at $11.36 per exchangeable share ("ARL
Exchangeable Shares") as partial consideration for the Startech
acquisition. The issue price of the exchangeable shares was determined
based on the weighted average trading price of trust units preceding
the date of announcement of the acquisition. The ARL Exchangeable
Shares are publicly traded. The ARL Exchangeable Shares had an exchange
ratio of 1:1 at the time of issuance
The ARL Exchangeable Shares can be converted (at the option of the
holder) into trust units at any time on or after January 31, 2001. The
number of trust units issuable upon conversion is based upon the
exchange ratio in effect at the conversion date. The exchange ratio is
calculated monthly based on the cash distribution paid divided by the
ten day weighted average unit price preceding the record date. The
exchangeable shares are not eligible for distributions and, in the
event that they are not converted, any outstanding shares are
redeemable by the Trust for trust units on or after February 1, 2004
until February 1, 2010.
During the year, 277,608 ARL Exchangeable Shares (6,523,354 in 2001)
were converted to trust units at an average exchange ratio of 1.23661
(1.05227 in 2001) trust units for each ARML Exchangeable Share. At
December 31, 2002 the ARL exchange ratio was 1.31350 to 1.
2002 2001
-----------------------------------------------------------------------------------------------------------------------
NUMBER OF Number of
ARL EXCHANGEABLE SHARES SHARES $ Shares $
-----------------------------------------------------------------------------------------------------------------------
Balance, beginning of year 915 10,392 -- --
Issued on acquisition of Startech -- -- 7,438 84,497
Exchanged for trust units (278) (3,154) (6,523) (74,105)
-----------------------------------------------------------------------------------------------------------------------
Balance, end of year 637 7,238 915 10,392
Exchange ratio, end of year 1.31350 -- 1.18422 --
-----------------------------------------------------------------------------------------------------------------------
Trust units issuable upon conversion, end of year 837 7,238 1,083 10,392
=======================================================================================================================
13. UNIT BASED COMPENSATION PLAN
A Trust Unit Incentive Rights Plan (the "Plan") was established in
1999. The Trust is authorized to grant up to 8,000,000 rights to its
employees, independent directors and long-term consultants to purchase
trust units, of which 4,847,989 rights were granted to December 31,
2002. The initial exercise price of rights granted under the plan may
not be less than the current market price of the trust units as at the
date of grant and the maximum term of each right is not to exceed ten
years. The exercise price of the rights is to be adjusted downwards
from time to time by the amount, if any, that distributions to
unitholders in any calendar quarter exceeds 2.5 percent (10 percent
annually) of the Trust's net book value of property, plant and
equipment (the "Excess Distribution"), as determined by the Trust.
During the year, the Trust granted 1,334,072 rights (1,509,517 in 2001)
to employees, independent directors and long-term consultants to
purchase trust units at exercise prices ranging from $11.47 to $12.80
per trust unit ($10.49 to $12.70 in 2001). Rights granted under the
plan generally have a five year term and vest equally over three years
commencing on the first anniversary date of the grant. In accordance
with the Plan, the exercise price of the rights granted was reduced as
a result of calendar year distributions to unitholders exceeding 10
percent of the Trust's net book value of property, plant and equipment.
Page 15
A summary of the changes in rights outstanding under the plan is as
follows:
2002 2001
-----------------------------------------------------------------------------------------------------------------------
WEIGHTED Weighted
AVERAGE Average
NUMBER OF EXERCISE Number of Exercise
RIGHTS PRICE Rights Price
-----------------------------------------------------------------------------------------------------------------------
Balance, beginning of year 2,509 $ 9.05 1,722 $ 7.48
Granted 1,334 12.57 1,510 11.71
Exercised (726) 6.94 (571) 7.34
Cancelled (76) 10.91 (152) 9.69
-----------------------------------------------------------------------------------------------------------------------
Balance before reduction of exercise price 3,041 11.05 2,509 9.92
Reduction of exercise price -- (0.41) -- (0.87)
-----------------------------------------------------------------------------------------------------------------------
Balance, end of year 3,041 $ 10.64 2,509 $ 9.05
=======================================================================================================================
A summary of the plan as at December 31, 2002 is as follows:
Exercise Price Adjusted Number of Rights Remaining Contractual Number of
at Grant Date Exercise Price Outstanding Life of Right (years) Rights Exercisable
-----------------------------------------------------------------------------------------------------------------------
$ 8.20 $ 5.22 149 1.3 149
9.10 6.75 372 2.3 131
11.81 10.71 1,197 3.3 320
12.52 12.28 1,323 4.4 --
-----------------------------------------------------------------------------------------------------------------------
11.64 10.64 3,041 3.6 600
=======================================================================================================================
Effective for fiscal years beginning on or after January 1, 2002, the
Trust adopted the recommendations of the CICA on accounting for
stock-based compensation which apply to new rights granted on or after
January 1, 2002. The Trust 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. As the
exercise price of the rights granted approximates the market price of
the trust units at the time of the grant date, no compensation cost has
been provided in the statement of income.
As previously stated, the exercise price of the rights granted under
the Trust's rights plan may be reduced in future periods in accordance
with the terms of the rights plan. The amount of the reduction cannot
be reasonably estimated as it is dependent upon a number of factors
including, but not limited to, future prices received on the sale of
oil and natural gas, future production of oil and natural gas,
determination of 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.
As it is not possible to determine the fair value of rights granted
under the plan, compensation cost for proforma disclosure purposes has
been determined based on the excess of the unit price over the exercise
price at the date of the financial statements. For the year ended
December 31, 2002 there would be no change in net income for the
estimated compensation cost associated with rights granted under the
plan on or after January 1, 2002 as the adjusted exercise price of the
rights exceeded the market price of the trust units.
Page 16
14. NET INCOME AND CASH FLOW FROM OPERATIONS PER TRUST UNIT
Net income and cash flow from operations per trust unit are as follows:
2002 2001 (4)
-----------------------------------------------------------------------
Net income
Basic (1) $ 0.57 $ 1.36
Diluted (2) 0.56 1.35
Cash flow from operations (3)
Basic (1) 1.87 2.55
Diluted (2) 1.86 2.54
=======================================================================
(1) Basic per unit calculations are based on the weighted average
number of trust units outstanding in 2002 of 119,613,489
(101,979,000 in 2001) which includes outstanding exchangeable
shares converted at the year-end exchange ratio.
(2) Diluted calculations include 560,772 additional trust units in
2002 (620,000 additional trust units in 2001) for the dilutive
impact of employee rights. Calculations of diluted shares
excluded 1,326,490 rights in 2002 (621,830 rights in 2001)
which would have been anti-dilutive. There were no adjustments
to net income or cash flow from operations in calculating
diluted per share amounts.
(3) Calculated by adding future income tax recovery, unrealized
gain/loss on foreign exchange, amortization of commodity and
foreign currency contracts, depletion, depreciation and
amortization, and internalization of the management contract
to net income and dividing by the weighted average number of
trust units.
(4) 2001 net income per trust unit has been restated for the
change in accounting policy for foreign currency translation.
Page 17
15. INCOME TAXES
The tax provision differs from the amount computed by applying the
combined Canadian federal and provincial income tax statutory rate to
income before future income tax recovery as follows:
2002 2001
---------------------------------------------------------------------------------------------------------
Income before future income tax recovery $ 38,258 $ 109,399
=========================================================================================================
Expected income tax expense at statutory rates 16,298 46,604
Effect on income tax of:
Net income of the Trust (46,074) (72,852)
Effect of change in provincial tax rate -- (9,111)
Resource allowance (3,820) (3,121)
Non-deductible crown charges 3,681 8,431
Alberta Royalty Tax Credit (230) (191)
Capital Tax 584 764
Unrealized (gain) loss on foreign exchange (74) 673
---------------------------------------------------------------------------------------------------------
Future income tax recovery $ (29,635) $ (28,803)
=========================================================================================================
The net future income tax liability is comprised of:
2002 2001
---------------------------------------------------------------------------------------------------------
Future tax liabilities:
Capital assets in excess of tax value $ 165,351 $ 192,006
Future tax assets:
Attributed Canadian Royalty Income (6,356) (5,165)
Future removal and site restoration costs (13,773) (11,367)
Deductible share issue costs (827) (1,444)
---------------------------------------------------------------------------------------------------------
Net future income tax liability $ 144,395 $ 174,030
=========================================================================================================
The petroleum and natural gas properties and facilities owned by the
Trust's corporate subsidiaries have an approximate tax basis of $210.0
million ($203.6 million in 2001) available for future use as deductions
from taxable income. Included in this tax basis are estimated
non-capital loss carryforwards of $74.0 million ($65.2 million in 2001)
which expire in the years through 2009.
No current income taxes were paid or payable in 2002 or 2001.
Page 18
16. RELATED PARTY TRANSACTIONS
Effective August 29, 2002, all fees under the management agreement
between the Manager and the Trust were eliminated pursuant to the
acquisition of all of the outstanding shares of ARML (see Note 5).
Under the management agreement, fees were payable to the Manager for
management, advisory and administrative services including a fee equal
to three per cent of net production revenue; and fees of 1.5 per cent,
and 1.25 percent of the purchase price of acquisitions and the net
proceeds of dispositions, respectively. Total acquisition and
disposition fees paid to the Manager in 2002, prior to the elimination
of the management agreement on August 29, 2002, were $895,000 ($7.9
million in 2001). These fees were accounted for as either part of the
purchase price or as a reduction of the proceeds of disposition of
property, plant and equipment.
During 2002, the Manager was reimbursed $9,327,000 ($11,715,000 in
2001) for general and administrative expenses incurred on behalf of the
Trust to the date of the elimination of the management agreement on
August 29, 2002.
17. CONTINGENCIES
The Trust is involved in litigation and claims associated with normal
operations. Management is of the opinion that any resulting settlements
would not materially affect the Trust's financial position or reported
results of operations.
18. DIFFERENCES BETWEEN CANADIAN AND UNITED STATES GENERALLY ACCEPTED
ACCOUNTING PRINCIPLES
The consolidated financial statements have been prepared in accordance
with Canadian GAAP, which differ in some respects to those in the
United States. Any differences in accounting principles as they pertain
to the accompanying consolidated financial statements are immaterial
except as described below:
The application of US GAAP would have the following effect on net
income as reported:
2002 2001
-----------------------------------------------------------------------------------------------------------------------
Net income as reported $ 67,893 $ 138,202
-----------------------------------------------------------------------------------------------------------------------
Adjustments (net of applicable income taxes):
Write-down of property, plant and equipment(a) -- (110,635)
Depletion, depreciation and amortization(a) 26,986 10,338
Unrealized gain (loss) on derivative instruments(c) (16,613) 6,592
Unit based compensation(b) (4,040) (4,474)
-----------------------------------------------------------------------------------------------------------------------
Net income under US GAAP $ 74,226 $ 40,023
-----------------------------------------------------------------------------------------------------------------------
-----------------------------------------------------------------------------------------------------------------------
Net income per trust unit under US GAAP (Note 14)
Basic $ 0.62 $ 0.39
Diluted 0.62 0.39
-----------------------------------------------------------------------------------------------------------------------
Page 19
-----------------------------------------------------------------------------------------------------------------------
Comprehensive Income:
-----------------------------------------------------------------------------------------------------------------------
Net income under US GAAP $ 74,226 $ 40,023
Unrealized gain (loss) on derivative instruments (net of future
income taxes) (11,897) 8,251
-----------------------------------------------------------------------------------------------------------------------
Other comprehensive income(c) $ 62,329 $ 48,274
-----------------------------------------------------------------------------------------------------------------------
The application of US GAAP would have the following effect on the
consolidated balance sheets as reported:
2002 2001
-----------------------------------------------------------------------------------------------------------------------
CANADIAN US Canadian US
GAAP GAAP GAAP GAAP
-----------------------------------------------------------------------------------------------------------------------
Property, plant and equipment $ 1,397,563 $1,208,084 $ 1,311,306 $ 1,091,432
Commodity and foreign currency contracts (9,210) (33,020) (13,107) 12,753
Future income taxes (144,395) (107,697) (174,030) (155,083)
Unitholders' capital (1,172,199) (1,185,551) (1,029,538) (1,038,849)
Accumulated earnings (350,088) (163,791) (282,195) (89,566)
Accumulated other comprehensive income -- 3,646 -- (8,251)
-----------------------------------------------------------------------------------------------------------------------
The above noted differences between Canadian GAAP and US GAAP are the
result of the following:
(a) The Trust performs a cost recovery ceiling test for each cost
centre which limits net capitalized costs to the undiscounted
estimated future net revenue from proved oil and gas reserves
plus the cost of unproved properties less impairment, using
year end prices or average prices in that year if appropriate.
In addition, the aggregate value of all cost centres is
further limited by including financing costs, general and
administrative expenses, future removal and site restoration
costs and income taxes. Under US GAAP, companies using the
full cost method of accounting for oil and gas producing
activities perform a ceiling test on each cost centre using
discounted estimated future net revenue from proved oil and
gas reserves using a discount factor of 10 per cent. Prices
used in the US GAAP ceiling tests are those in effect at year
end and financing and general and administrative expenses are
excluded from the calculation. The amounts recorded for
depletion, and depreciation have been adjusted in the periods
following the additional write-downs taken under US GAAP to
reflect the impact of the reduction of depletable costs.
(b) Under Canadian GAAP, compensation expense is recognized based
on the intrinsic value of the rights granted to employees,
directors and long-term consultants of the Trust under its
Trust Unit Incentive Rights Plan. The effect of subsequent
reductions in the exercise price of the rights is not
recognized in income. For US GAAP purposes, the Trust uses the
intrinsic value method of accounting for rights issued to its
employees, directors and long-term consultants who meet the
definition of employees. As the exercise price of the rights
is subject to downward revisions from time to time, the rights
plan is a variable compensation plan. 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.
Page 20
(c) US GAAP requires that all derivative instruments (including
derivative instruments embedded in other contracts), as
defined, be recorded on the balance sheet as either an asset
or liability measured at fair value and requires that changes
in fair value be recognized currently in earnings unless
specific hedge accounting criteria are met. 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 a company formally document, designate, and
assess the effectiveness of derivative instruments that
receive hedge accounting treatment. The Trust formally
documented and designated all hedging relationships and
verified that its hedging instruments were effective in
offsetting changes in actual prices and rates received by the
Trust. Certain contracts entered into during 2001 and 2002
were not eligible for hedge accounting treatment under US GAAP
and the change in fair value of these contracts has been
reported in net income under US GAAP. Hedge effectiveness is
monitored and any ineffectiveness is reported in the
consolidated statement of income.
The Trust's derivative positions consist of contracts entered
into by the Trust and derivative positions assumed in
conjunction with the Startech acquisition.
At December 31, 2002, the fair value of the Trust's derivative
instruments represented a net liability of $4.3 million ($5.2
million at December 31, 2001).
On January 31, 2001, the $33.1 million fair value of
derivative positions assumed upon acquisition of Startech was
recorded as a liability (see Note 3). At December 31, 2002,
the fair value of these derivative instruments represented a
net liability of $11.2 million (net asset of $6.5 million as
December 31, 2001).
A reconciliation of the components of accumulated other
comprehensive income related to all derivative positions is as
follows:
2002 2001
------------------------------------------------------------------------------------------------------------------------
GROSS AFTERTAX Gross Aftertax
------------------------------------------------------------------------------------------------------------------------
Accumulated other comprehensive income, beginning of period $ 14,376 $ 8,251 $ -- $ --
Cumulative effect of change in accounting principle -- -- (5,251) (3,014)
Reclassification of net realized (gains) losses into earnings 1,038 596 (6,969) (4,000)
Net change in fair value of derivative instruments (21,764) (12,493) 26,596 15,265
------------------------------------------------------------------------------------------------------------------------
Accumulated other comprehensive income (loss), end of period (6,350) (3,646) 14,376 8,251
------------------------------------------------------------------------------------------------------------------------
Page 21
MANAGEMENT'S DISCUSSION AND ANALYSIS
The following discussion and analysis of financial results should be read in
conjunction with the audited consolidated financial statements for the year
ended December 31, 2002 and supplementary information in schedules 1 and 2
attached and is based on information available to January 31, 2003.
FORWARD LOOKING STATEMENTS
This disclosure contains certain forward-looking estimates that involve
substantial known and unknown risks and uncertainties, certain of which are
beyond ARC's control, including: the impact of general economic conditions in
Canada and the United States; industry conditions including changes in laws and
regulations including the adoption of new environmental laws and regulations and
changes in how they are interpreted and enforced, increased competition, and the
lack of availability of qualified personnel or management; fluctuations in
commodity prices, foreign exchange or interest rates; stock market volatility
and obtaining required approvals of regulatory authorities. In addition there
are numerous risks and uncertainties associated with oil and gas operations and
the evaluation of oil and gas reserves. Therefore ARC's actual results,
performance or achievement could differ materially from those expressed in, or
implied by, these forward-looking estimates and if such actual results,
performance or achievements transpire or occur, or if any of them do so, what
benefits that ARC will derive therefrom.
1
2002 HIGHLIGHTS
CDN$ millions, except per share and volume data 2002 2001
- --------------------------------------------------------------------------------
Cash Flow from Operations (1) $ 224 $ 260
Cash Flow from Operations per unit $ 1.87 $ 2.55
Net Income $ 68 $ 138
Net Income prior to non recurring items (2) $ 94 $ 138
Distributions per Unit $ 1.56 $ 2.31
Daily Production (boe/d) 42,425 43,111
================================================================================
(1) Before changes in non-cash working capital
(2) Prior to a one-time charge related to the internalization of the management
contract
Strong crude oil prices, moderate natural gas prices and excellent drilling
results combined to generate superior financial and operating results during
2002. Even with a 23% decline in natural gas and natural gas liquids prices in
2002, cash flow from operations was $224 million with $68 million of earnings
generated. The year-over-year decline in cash flow of $36 million was primarily
caused by weaker gas prices offset in part by the Trust's hedging activities
which resulted in a hedging gain on natural gas production of $0.55 per mcf in
2002 compared to a gain of $0.22 mcf in 2001. The Trust also experienced higher
operating costs on its non-operated properties, as discussed in the Netbacks
section of this report, but benefited from declining interest rates resulting in
a $5 million decrease in interest expense.
Net income was impacted by all the same factors as cash flow plus the one-time
non-cash expense of $25.9 million for the internalization of the management
contract that took place in the third quarter of 2002. Other non-cash expenses
were relatively consistent from 2001 to 2002.
A capital investment program of $207 million added reserves at an attractive
rate of $9.27/boe. Oil and gas production rates declined 1.6 per cent with
production additions offsetting natural production declines.
In 2002 ARC took advantage of a significant number of acquisition opportunities
in core areas for longer-term growth by purchasing reserves with substantial
development drilling upside. The initial development drilling program on newly
acquired lands was very successful, resulting in production additions in late
2002. ARC's strategy focused on development of the significant inventory of
internally generated development drilling prospects, which will continue to
provide a low-risk, stable source of longer-term growth.
ARC takes a very disciplined approach to making acquisitions to ensure accretion
to the existing asset base for unitholders. Net acquisitions of $119 million
were concentrated in the Trust's five core operating areas increasing production
by 4,100 boe per day and reserves by 13.0 mmboe for an average cost of
approximately $29,000 per producing boe per day and $9.18 per boe of established
reserves.
2
PRODUCTION
Production volumes for 2002 averaged 42,425 boe per day, representing a modest
decrease of 1.6 per cent from the 2001 average of 43,111 boe per day. The
Trusts' 2002 production portfolio was weighted 49% oil, 43% natural gas and 8%
natural gas liquids on a per boe basis.
In 2002, 56 properties located within the Trust's five core areas, accounted for
90% of the Trust's production with no one property accounting for more than
seven per cent of total production. This diversification of production enhances
the Trust's ability to predict ongoing production levels, cash flows from
operations and cash distributions.
2002 2001
- --------------------------------------------------------------------------------
Crude Oil (bbl/d) 20,655 20,408
Natural Gas Liquids (bbl/d) 3,479 3,511
Natural Gas (mcf/d) 109,745 115,150
- --------------------------------------------------------------------------------
TOTAL PRODUCTION - BOE/D 42,425 43,111
- --------------------------------------------------------------------------------
Crude Oil and Natural Gas Liquids 57% 55%
Natural Gas (1) 43% 45%
- --------------------------------------------------------------------------------
TOTAL PRODUCTION 100% 100%
================================================================================
(1) converted to boe on a 6:1 basis
MARKETING AND PRICES
CRUDE OIL PRICING
West Texas Intermediate at Cushing, Oklahoma (WTI) is the benchmark for North
American oil prices. The WTI oil price averaged US$26.10/bbl in 2002, up
slightly from US$25.93/bbl in 2001. Canadian crude oil prices are based upon
refiners' postings, primarily at Edmonton, Alberta and represent the WTI price,
adjusted for transportation and quality differentials and the Canadian/US
exchange rate. ARC's average field price reflects the refiners' posted price at
Edmonton, Alberta less deductions for transportation from the field and
adjustments for ARC's product quality relative to the posted price. ARC's
average field price in 2002 was $35.27/bbl ($33.00/bbl in 2001) as compared to
$39.71/bbl ($39.29/bbl in 2001) for the average of the light sweet postings at
Edmonton. This discount to the average Edmonton posted price reflects the high
quality of ARC's crude oil mix, which is comprised of 60 per cent light sweet
(greater than 35(0) API) crude, 30 per cent medium gravity and 10 per cent heavy
gravity oil (less than 23(0) API). ARC's average oil price, net of all hedging
transactions in 2002 was $31.63/bbl, very comparable to the 2001 average of
$31.70/bbl. Crude oil is sold under 30 day evergreen contracts while natural gas
liquids are sold under annual arrangements.
NATURAL GAS PRICING
US natural gas prices are typically referenced off NYMEX at Henry Hub,
Louisiana, while Alberta and British Columbia natural gas prices are referenced
off of the AECO Hub in Alberta and the Sumas Hub in Washington, respectively.
Natural gas prices fluctuated in 2002 with prices under $2.00/mcf in July to in
excess of $6.50/mcf in December. ARC's average wellhead gas price, prior to
hedging transactions, decreased by 30% to $3.86/mcf in 2002 from $5.50/mcf in
2001. ARC's prices, including hedging gains, were $4.41/mcf in 2002 and
$5.72/mcf in 2001. AECO Hub prices were $4.08/mcf and $6.28/mcf for 2002 and
2001, respectively.
3
HEDGING
The Trust's hedging activities are conducted by an internal Risk Management
Committee, which has the following objectives as its mandate:
o Protect Unitholder return on investment
o Stabilize monthly distributions
o Employ a portfolio approach to hedging by entering into a
number of small positions that build upon each other
o Participate in commodity price upturns to the greatest extent
possible, while limiting exposure to price downturns
o Ensure profitability of specific oil and gas properties that
are more sensitive to changes in market conditions
The 2002 prices included a hedging gain of $0.55/mcf for natural gas and a loss
of $3.64/bbl for oil; 2001 prices included a hedging gain of $0.22/mcf for
natural gas and a loss of $1.30/bbl for oil.
For 2003 ARC has hedged approximately 50% of oil production volumes at an
average price of approximately US $26.00/bbl and 30% of natural gas production
volumes utilizing a variety of contracts at an average price of approximately
$5.30/mcf. The Trust's Risk Management Committee is authorized by the Board of
Directors of ARC Resources Ltd. ("ARC Resources" or "ARL") to hedge up to 50% of
the Trust's production on a boe basis for a period of up to 12 months, and up to
25% of the Trust's production for the next consecutive 12 month period. The
Trust's hedging activities secured prices at a level sufficient enough to allow
the Trust to increase first quarter 2003 distributions to $0.15 per unit per
month.
REVENUE
Revenue, prior to hedging transactions, decreased to $451.9 million in 2002
compared to $516.6 million in 2001. The decrease was primarily due to lower
natural gas prices and a minor decline in total production volumes. Hedging
losses of $7.0 million in 2002 and $1.0 million in 2001 resulted in production
revenue net of hedging losses of $444.8 million in 2002 and $515.6 million in
2001.
NETBACKS
A 2002 operating netback of $16.78/boe compared to $20.15/boe in 2001 reflected
the 23% decline in natural gas and natural gas liquids prices and higher
operating costs in 2002. Operating costs, net of processing income, increased to
$6.45/boe in 2002 up from $5.47/boe in 2001. This increase can primarily be
attributed to higher costs on the Trust's non-operated properties as those
operators performed maintenance and conducted turnarounds which increased
operating costs and temporarily reduced volumes resulting in higher operating
costs per boe. The components of operating netbacks are shown below:
NETBACK ($/BOE) 2002 2001
- --------------------------------------------------------------------------------
Market Price 29.19 32.82
Cash hedging (loss) (0.61) (1.26)
Non-cash hedging gain 0.15 1.20
- --------------------------------------------------------------------------------
Selling Price 28.73 32.76
Royalties (5.50) (7.14)
Operating Costs (6.45) (5.47)
- --------------------------------------------------------------------------------
Netback 16.78 20.15
================================================================================
4
RECYCLE RATIO
A key indicator of profitability in the oil and gas sector is the recycle ratio,
which is defined as the operating netback divided by the three-year average
finding, development and acquisition costs ("FD&A"). ARC's recycle ratio
continues to be one of the highest in the industry.
RECYCLE RATIO 2002 2001
- --------------------------------------------------------------------------------
Netback ($/boe) 16.78 20.15
Three-Year average FD&A ($/boe) 8.21 6.94
Recycle Ratio 2.0 2.9
Inception-to-date FD&A ($/boe) 6.59 6.32
Recycle Ratio 2.5 3.2
================================================================================
GENERAL AND ADMINISTRATIVE EXPENSES
General and administrative ("G&A") expenses, net of overhead recoveries on
operated properties, increased in 2002 to $15.4 million ($0.99/boe) from $11.8
million ($0.75/boe) in 2001. The increase in G&A was due primarily to hiring
additional staff and changes to ARC's employee benefits program. This results in
a more complete staff compliment to provide for the Trust's future growth. The
Trust's G&A costs per boe are continuously monitored internally by management
and are benchmarked against other comparable sized Trusts. The Trust did not
capitalize any G&A in 2002 or 2001.
INTERNALIZATION OF MANAGEMENT CONTRACT
On August 29, 2002, the Trust eliminated the external management contract and
related fees through the purchase of ARC Resources Management Ltd. ("ARML" or
the "Manager").
Two assets were acquired in this transaction; a future cash flow equal to three
per cent of net operating income, and the direct hiring of existing management
and approximately 135 employees of the Manager. ARC has accounted for this
transaction by capitalizing the amount that relates to the three per cent of net
operating income (based upon an independent reserve evaluation) of ARC's
established reserves on a produce-out basis over the remaining five year term of
the management contract, and retention bonuses to be paid out over the next five
years to senior management. The remainder, which was expensed, consists of the
purchase of the three per cent revenue stream over and above the existing
established reserves for the next five years and future acquisition and
disposition fees.
The purchase price includes an obligation to pay $5.0 million of future
retention bonuses to senior management. The bonuses will be paid out in equal
amounts over a five year period if the officer stays employed by the Trust. In
the event of a departure of any officer, future bonus payments will be forfeited
to the benefit of the Trust. The $1.0 million current portion of the bonus is
included in accounts payable and accrued liabilities. The remaining $4.0 million
has been set up as a long-term liability.
The total purchase price of $55.9 million was paid for with cash, exchangeable
shares and trust units. The exchangeable shares and trust units are subject to
escrow and forfeiture provisions for most of the shareholders of ARML. The
provisions were put in place to ensure management and staff remain employees of
ARC and continue to add value for the Trust and its unitholders (see note 5 to
the Financial Statements for additional information).
The Manager received a management fee of three per cent of net operating income,
which amounted to $5.2 million or $0.33 per boe for the period ended August 29,
2002 compared to $8.8 million or $0.56 per boe for the year ended December 31,
2001.
5
INTEREST EXPENSE
Interest expense decreased to $12.6 million in 2002 from $17.1 million in 2001
as a result of a lower monthly average debt balance and lower interest rates.
Long-term debt was reduced in May with net proceeds of $114.5 million from the
issue of 10.0 million trust units. Interest expense was minimized over the
course of the year by financing debt through the issuance of lower cost bankers'
acceptances as opposed to borrowing at the prevailing bank prime interest rates.
FOREIGN CURRENCY GAINS AND LOSSES
ARC has $65 million in US denominated long-term debt that is subject to changes
in the Canadian/U.S. dollar exchange rate. The unrealized gains and losses
associated with the fluctuations in the exchange rate are now recorded in income
based upon change in foreign exchange rates between reporting periods.(see note
3 to the Financial Statements for additional information).
Prior to 2002, unrealized foreign exchange gains and losses were deferred and
amortized over the life of the debt. A new accounting policy effective January
1, 2002 required that such unrealized gains and losses be recorded in income in
the period in which they relate rather than be deferred and amortized. As a
result of this change in accounting policy, certain 2001 amounts have been
restated to reflect the impact of the new accounting policy which was applied
retroactively.
In 2002 ARC recorded a foreign exchange gain of $607,000 compared to a loss of
$3,297,000 in 2001.
TAXES
Capital taxes paid or payable by ARC, based on debt and equity levels at the end
of the year, amounted to $1.4 million in 2002 versus $1.8 million in 2001.
As a result of the Startech acquisition in 2001, a future income tax liability
of $203 million was recorded on the balance sheet in accordance with Canadian
Generally Accepted Accounting Principles ("Canadian GAAP" or "GAAP". This
liability was initially recorded by multiplying the corporate tax rate of
approximately 44% by the difference between the purchase price of the Startech
assets and the amount of tax pools at the date of the acquisition. In the
Trust's structure, payments are made between ARC Resources and the Trust
transferring both income and future tax liability from ARC Resources to the
individual unitholders. Therefore, it is the opinion of management that no cash
income taxes will be paid by ARC Resources in the future and as such the future
income tax liability recorded on the balance sheet will be recovered through
earnings over time. Future income tax recoveries of $30 million in 2002 and $29
million in 2001 have resulted in a remaining future income tax liability of $144
million at December 31, 2002. In 2002, the tax recovery was $1.91/boe ($1.83/boe
in 2001) for an effective net depletion, depreciation and amortization rate
("DD&A") of $8.54/boe ($8.66/boe in 2001).
At year-end 2002, the Trust has approximately $765 million ($657.4 million in
2001) in income tax pools, which will be utilized to reduce the taxable portion
of future cash distributions. In addition, ARC Resources has approximately $210
million ($203.6 million in 2001) of income tax pools as at December 31, 2002,
which will be utilized to minimize, and potentially eliminate, future corporate
income taxes.
6
DEPLETION, DEPRECIATION AND FUTURE SITE RECLAMATION EXPENSES
The 2002 depletion, depreciation and amortization (DD&A) rate decreased slightly
to $10.45/boe from $10.49/boe in 2001. The DD&A rate includes a provision for
future site reclamation and abandonment of $0.69/boe in 2002 compared to
$0.59/boe in 2001. The decrease in the DD&A rate in 2002 reflects the impact of
2002 drilling results and the positive year-over-year reserve revisions as
determined by the Trust's independent oil and gas reserves evaluators. Assets to
be depleted were increased by future development costs of $190.1 million and
reduced by $12.6 million for the estimated future net realizable value of
production equipment and $19.7 million for the value of unproven properties.
CAPITAL EXPENDITURES
Total capital expenditures including acquisitions aggregated $207 million in
2002 ($625 million in 2001). Of the total, $88 million was incurred on
development drilling, geological, geophysical and facilities expenditures as ARC
continues to develop its asset base, and $119 million of net acquisitions. Total
reserve acquisition and development costs for 2002 were $9.27/boe compared to
$9.75/boe in 2001. A breakdown of capital expenditures by category is shown
below:
2002 2001
- --------------------------------------------------------------------------------
CAPITAL EXPENDITURES ($ THOUSANDS):
Geological and geophysical 1,966 2,215
Development drilling 70,074 73,147
Plant and facilities 14,357 22,970
Other capital 1,881 3,886
Producing property net acquisitions (1) 119,113 522,659
- --------------------------------------------------------------------------------
Total capital expenditures 207,391 624,877
- --------------------------------------------------------------------------------
ESTABLISHED RESERVES (MBOE):
Net change in established reserves after production 6,875 48,344
Annual production 15,485 15,736
- --------------------------------------------------------------------------------
Annual established reserve additions 22,360 64,080
- --------------------------------------------------------------------------------
FINDING, DEVELOPMENT AND ACQUISITION COSTS (2) ($/BOE):
Current year 9.27 9.75
Three year rolling average 8.21 6.94
Cumulative since inception 6.59 6.32
================================================================================
(1) value is net of post-closing adjustments
(2) finding, development and acquisition costs ("FD&A") based on established
reserves
The Board of Directors of ARC Resources has approved a capital budget for 2003
of $115 million. This budget ranks individual projects to allow for revisions
during the year in the event the Trust acquires additional properties with
associated development opportunities, or there is a change in the business
environment which may result in the acceleration or delay of certain
expenditures.
7
ABANDONMENTS
ARC takes a proactive approach to environmental issues and abandonments and
reclamation of associated well and facility sites as required. ARC annually
carries out a program to abandon and reclaim wells and facilities, which have
reached the end of their economic lives. ARC has established a reclamation fund
into which $4.8 million cash and interest income was contributed during the year
($4.1 million in 2001). During 2002, $3.0 million of actual abandonment costs
were incurred of which $2.0 million was funded out of the reclamation fund
balance. At December 31, 2002 there was a fund balance of $12.9 million. This
fund, invested in money market instruments, is established to provide for future
abandonment liabilities. Future contributions are currently set at approximately
$4.0 million per year in order to provide for the total estimated future
abandonment and site reclamation costs. ARC has been active in improving the
quality of its oil and gas reserve base by purchasing properties and then
selling, smaller lower quality reserves which tend to have a shorter reserve
life and therefore a shorter time period to the eventual abandonment of the
property. This practice will continue in the future in order to mitigate actual
future abandonment costs.
CAPITALIZATION AND FINANCIAL RESOURCES
As at December 31, 2002 the Trust had a working capital deficiency of $10.1
million compared to a working capital balance of $5.8 million as at December 31,
2001. The 2002 year end working capital deficit is a result of normal operating
conditions in periods when the Trust incurs significant capital expenditures.
ARC participated in significant capital expenditures near the end of the year
resulting in accrued capital expenditures of $21.6 million at December 31, 2002.
Total debt outstanding at December 31, 2002 was $338 million, which includes
bank debt of $235 million and US$65 million (CDN$102.7 million) of Senior
Secured Notes. ARC's oil and gas properties secure the debt. The Trust's debt
increased by $71 million on December 23, 2002 with the closing of the
acquisition of properties in the Ante Creek and Brown Creek areas, resulting in
the available line of credit as at December 31, 2002 being reduced to $62
million with total available credit lines of $400 million. The Trust has
proceeded with its annual credit review with its lenders with a view of
increasing its credit lines from $400 million based upon the increase in the
Trust's reserves from 178 mmboe to 185 mmboe.
The Trust's lending facilities consist of bilateral agreements with four
Canadian chartered banks and one U.S. insurance company. In 2002, the Trust
borrowed an additional US$30 million in senior secured notes at a 4.94% interest
rate with an eight year term (six year average life) increasing the total U.S.
denominated debt of the Trust to US$65 million. As the Trust's major revenue
stream is tied to the value of oil in the United States the Trust has chosen to
borrow approximately one-third of its debt in U.S. dollars. Similarly the Trust
now has one-third of its debt locked in at fixed interest rates averaging 6.6
per cent and the remaining two-thirds floating based upon Canadian banker's
acceptance rates plus a bank stamping fee.
The Trust's current plans are to finance the approved 2003 capital budget of
$115 million with a combination of cash flow, debt, and equity by issuing units
from treasury.
End-of-year 2002 net debt to total capitalization was 18.8 per cent (17.6 per
cent in 2001) and debt to cash flow payout was approximately 1.6 years (1.1
years in 2001) based upon cash flow from operations of $224 million and net debt
of $348 million.
8
($ thousands except per unit and per cent amounts) 2002 2001
- -------------------------------------------------------------------------------------------------
Bank debt 337,728 294,489
Less: Working capital (deficiency) (10,067) 5,805
- -------------------------------------------------------------------------------------------------
Net debt obligations 347,795 288,694
Units outstanding and issuable for exchangeable shares (thousands) 126,444 111,693
Market price at end of period $ 11.90 $ 12.10
ARC market capitalization 1,504,684 1,351,485
Total capitalization 1,852,479 1,640,169
=================================================================================================
Net debt as a percentage of total capitalization 18.8% 17.6%
- -------------------------------------------------------------------------------------------------
Net debt obligations 347,795 288,694
- -------------------------------------------------------------------------------------------------
Cash flow 223,969 260,270
- -------------------------------------------------------------------------------------------------
Net debt to cash flow 1.6 1.1
=================================================================================================
Currently several Canadian conventional oil and gas trusts have obtained stock
exchange listings in the United States in order to make their trust units more
accessible to US investors. We are monitoring this situation and at this time
have chosen not to pursue a US listing. The Trust is a reporting company with
the Securities and Exchange Commission ("SEC") in the United States and
electronically files its financial statements and other disclosures as required
with the SEC for the benefit of current and potential unitholders residing in
the United States.
UNITHOLDERS' EQUITY
ARC's total capitalization increased 12 per cent to $1.9 billion during 2002
with the market value of trust units representing 81 per cent of total
capitalization. During 2002 the market price of the Trust units traded in a
fairly narrow range of $11.11 to $13.29 with an average daily trading volume of
305,000 units per day.
In May 2002, ARC completed an equity financing which raised $120.5 million of
gross proceeds ($114.3 million net) on the issuance of 10.0 million trust units
at $12.05 per trust unit. The proceeds were used to reduce existing debt levels
on an interim basis and to partially fund 2001 and 2002 capital expenditures.
In conjunction with the Startech acquisition which occurred in January of 2001,
ARC Resources issued Exchangeable Shares ("ARL Exchangeable Shares") which were
listed on the TSX under the symbol "ARX". The Exchangeable Shares can be
converted, at the option of the shareholder, into trust units. The number of
trust units issuable upon conversion is based on the exchange ratio in effect at
the conversion date. The exchange ratio is calculated monthly based on the cash
distribution paid divided by the ten day weighted average price preceding the
record date. The Exchangeable Shares are not eligible for monthly cash
distributions. As at December 31, 2002, there were 637,167 ARL Exchangeable
Shares outstanding (914,775 in 2001) at an exchange ratio of 1.3135. In
addition, a new series of Exchangeable Shares (ARML Exchangeable Shares) were
issued by a subsidiary of the Trust in conjunction with the purchase of the
Manager and internalization of the management contract on August 29, 2002. The
new series of Exchangeable Shares are not publicly traded. As at December 31,
2002, 2,206,409 ARML Exchangeable Shares were outstanding with a year-end
exchange ratio of 1.04337.
Unitholders electing to reinvest distributions or make optional cash payments to
acquire trust units from treasury under the Distribution Reinvestment Incentive
Plan (DRIP) resulted in an additional 242,496 trust units being issued in 2002
at an average price of $12.15 raising a total of $3.0 million. In 2001, 57,117
trust units were issued under the DRIP program at an average price of $11.38 per
trust unit.
9
During 2002, as part of ARC's long-term incentive plan, 1,334,072 trust unit
incentive rights (1,509,517 rights in 2001) were issued to office and field
employees, long-term consultants and independent directors at prices ranging
from $11.47 to $12.80 per trust unit ($10.49 to $12.70 in 2001). The exercise
price of the rights is adjusted downward over time by the amount, if any, that
annual distributions exceed 10 per cent of the net book value of property, plant
and equipment. The rights have a five-year term and vest equally over three
years from the date of grant. Rights to purchase 3,040,925 trust units at an
average adjusted exercise price of $10.64 were outstanding at December 31, 2002.
These rights have an average remaining contractual life of 3.6 years and expire
at various dates to December 2007. Of the rights outstanding at December 31,
2002, 599,608 were exercisable at that time.
CASH DISTRIBUTIONS
Total cash distributions of $1.56 per trust unit were made in fiscal year 2002
($2.31 in 2001) for total cumulative distributions since inception of $688.9
million ($10.64 per Trust unit). This distribution level was achieved after the
deduction of $35.6 million (16% of cash flow) to fund capital expenditures in
accordance with ARC's distribution policy to withhold up to 20% of cash flow,
net of the reclamation fund contributions, to fund capital expenditures. The
actual amount withheld is dependent on the commodity price environment and is at
the discretion of the Board of Directors. This holdback policy differs among the
conventional oil and gas trusts. ARC believes it is essential to focus on
production replacement activities partially funded by cash flow in order to
enhance long-term unitholder returns.
Monthly cash distributions for the first quarter of 2003 were set at $0.15 per
trust unit subject to review based on commodity price fluctuations. Revisions,
if any, to the monthly distribution are normally announced on a quarterly basis
in the context of prevailing and anticipated commodity prices at that time.
During periods of volatile commodity prices, the Trust may vary the distribution
rate monthly. Any differences between cash available for distribution and actual
cash distributions in any quarter are adjusted for in the ensuing quarter's
monthly distribution.
HISTORICAL DISTRIBUTIONS BY CALENDAR YEAR
($) DISTRIBUTIONS TAXABLE RETURN OF CAPITAL
- --------------------------------------------------------------------------------
CALENDAR YEAR
2003 0.13 (1) 0.08 (1) 0.05
2002 1.58 1.07 (2) 0.51 (2)
2001 2.41 1.64 0.77
2000 1.86 0.84 1.02
1999 1.25 0.26 0.99
1998 1.20 0.12 1.08
1997 1.40 0.31 1.09
1996 0.81 -- 0.81
- --------------------------------------------------------------------------------
CUMULATIVE 10.64 4.32 6.32
- --------------------------------------------------------------------------------
(1) based on estimated taxable portion of 60 to 70 per cent for 2003
distributions
(2) based on taxable portion of 68 per cent for 2002 distributions
10
TAXATION OF CASH DISTRIBUTIONS
Cash distributions are comprised of a return of capital portion (tax deferred)
and a return on capital portion (taxable). For cash distributions received by a
Canadian resident, outside of a registered pension or retirement plan in the
2002 taxation year, the split between the two is 68 per cent taxable with the
remaining 32 per cent being tax deferred. For a more detailed breakdown, please
visit our website at www.arcresources.com.
For 2003, ARC estimates that 60 to 70 per cent of cash distributions may be
taxable; 30 to 40 per cent may be return of capital and used to reduce a
unitholder's cost base on trust units held. Actual taxable amounts will be
dependent on commodity prices experienced throughout the year.
The exchangeable shares of ARC Resources Ltd. ("ARL"), a corporate subsidiary of
the Trust, may provide a more tax-effective basis for investment in the Trust.
The ARL exchangeable shares are traded on the TSX under the symbol "ARX" and are
convertible into trust units, at the option of the shareholder, based on the
current exchange ratio. The exchangeable shareholders are not eligible to
receive monthly cash distributions, however the exchange ratio increases on a
monthly basis by an amount equal to the current month's trust unit distribution
divided by the 10 day weighted average trading price of the trust units at the
end of each month. The gain realized as a result of the monthly increase in the
exchange ratio is taxed as a capital gain rather than income and is therefore
subject to a lower effective tax rate. Tax on the exchangeable shares is
deferred until the exchangeable share is sold or converted into a trust unit.
2002 DISTRIBUTIONS BY MONTH
TAX DEFERRED AMOUNT TOTAL
($) TAXABLE AMOUNT (RETURN OF CAPITAL) DISTRIBUTION
- --------------------------------------------------------------------------------
PAYMENT DATE
January 15, 2002 0.1020 0.0480 0.15
February 15, 2002 0.0884 0.0416 0.13
March 15, 2002 0.0884 0.0416 0.13
April 15, 2002 0.0884 0.0416 0.13
May 15, 2002 0.0884 0.0416 0.13
June 17, 2002 0.0884 0.0416 0.13
July 15, 2002 0.0884 0.0416 0.13
August 15, 2002 0.0884 0.0416 0.13
September 16, 2002 0.0884 0.0416 0.13
October 15, 2002 0.0884 0.0416 0.13
November 15, 2002 0.0884 0.0416 0.13
December 16, 2002 0.0884 0.0416 0.13
- --------------------------------------------------------------------------------
TOTAL 1.0744 0.5056 1.58 (1)
- --------------------------------------------------------------------------------
(1) Total is based upon cash distributions paid during 2002
11
ASSESSMENT OF BUSINESS RISKS
The ARC management team is focused on long-term strategic planning and has
identified the following items as risks and in certain cases opportunities
associated with the Trust's business: (a) operational risk associated with the
production of oil and natural gas; (b) reserve risk in respect to the quantity
and quality of recoverable reserves; (c) market risk relating to the
availability of transportation systems to move the product to market; (d)
commodity risk as oil and natural gas prices fluctuate due to market forces; (e)
financial risks such as the Canadian/US dollar exchange rate, interest rates and
debt service obligations; (f) environmental and safety risks associated with
well and production facilities; and (g) changing government royalty legislation,
income tax laws and incentive programs relating to the oil and gas industry.
The Trust's policies and procedures to mitigate these risks include to: (a)
acquire mature production to reduce technical uncertainty; (b) acquire long life
reserves to ensure more stable production and to reduce the economic risks
associated with commodity price cycles; (c) maintain a low cost structure to
maximize product netbacks; (d) diversify properties to mitigate individual
property risk; (e) seek to maintain a relatively balanced commodity exposure;
(f) subject all property acquisitions to rigorous review; (g) closely monitor
pricing trends and develop a mix of contractual arrangements for the marketing
of products with creditworthy counterparties; (h) maintain a hedging program to
hedge commodity prices and foreign currency rates with creditworthy counter
parties; (i) continuously retain the services of technical experts when
required; (j) ensure strong third-party operators for non-operated properties;
(k) adhere to the Trust's safety program and keep abreast of current operating
practices; (l) carry insurance to cover losses and business interruption; and
(m) establish and build cash resources to pay for future abandonment and site
restoration costs.
Below is a table that shows sensitivities to pre-hedging cash flow with
operational changes and changes to the business environment:
- --------------------------------------------------------------------------------
CHANGE TO CASH FLOW
- --------------------------------------------------------------------------------
CHANGE $000'S $/UNIT
BUSINESS ENVIRONMENT
- --------------------------------------------------------------------------------
Price per Barrel of Oil (US$ WTI) $1.00 10,500 $ 0.08
- --------------------------------------------------------------------------------
Price per Mcf of Natural Gas (CDN$ AECO) $0.10 3,200 $ 0.02
- --------------------------------------------------------------------------------
US CDN Exchange Rate $0.01 3,400 $ 0.02
- --------------------------------------------------------------------------------
Interest Rate on Debt 1.0% 2,500 $ 0.02
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
OPERATIONAL
- --------------------------------------------------------------------------------
Oil Production Volume - 100 bbl/d 0.5% 800 $ 0.01
- --------------------------------------------------------------------------------
Gas Production Volumes - 1 mmcf/d 0.9% 1,400 $ 0.01
- --------------------------------------------------------------------------------
Operating Exenses per $/Boe 10.0% 8,900 $ 0.06
- --------------------------------------------------------------------------------
General & Administrative Expenses per Boe 10.0% 1,500 $ 0.01
- --------------------------------------------------------------------------------
The Trust is continually evaluating potential acquisitions with all acquisitions
in excess of $10 million subject to Board approval. The Trust's business plan
could result in multiple acquisitions in one fiscal year. As the nature of
acquisitions in the energy business is usually by a competitive bid process we
cannot predict whether or not the Trust will execute any acquisitions in the
future. The Trust's scope of acquisitions being evaluating encompasses energy
assets, including conventional oil and gas assets, oil sands interests,
electricity or power generating assets and pipeline, gathering and
transportation assets.
The management of the Trust has financed the purchase of conventional oil and
gas assets in the past primarily by the issue of trust units and has ensured the
Trust's financial ratios are comparable to other similar organizations. If the
Trust acquired energy assets other than conventional oil and gas assets it would
review alternatives for financing such acquisitions which may result in a higher
use of debt but with the view of having the Trust's debt to total capitalization
being comparable to similar sized organizations with the similar mix of assets.
12
MANAGEMENT AND FINANCIAL REPORTING SYSTEMS
The Trust has continuously evolved and documented its management and internal
reporting systems to provide assurance that accurate, timely internal and
external information is communicated to users.
The Trust's financial and operating results incorporate certain estimates
including:
a) estimated revenues, royalties and operating costs on
production as at a specific reporting date but for which
actual revenues and costs have not yet been received;
b) estimated capital expenditures on projects which are in
progress; and
c) estimated depletion, depreciation and amortization and
reported FD&A costs which are based on estimates of oil and
gas reserves that the Trust expects to recover in the future.
The Trust has hired individuals and consultants who have the skill set to make
such estimates and ensures individuals or departments with the most knowledge of
the activity are responsible for the estimate. Further, past estimates are
reviewed and compared to actual results in order to make more informed decisions
on future estimates.
ARC's management team's mandate includes the ongoing development of procedures,
standards and systems to allow ARC staff to make the best decisions possible and
ensuring those decisions are in compliance with the Trust's environmental,
health and safety policies.
OUTLOOK
It is the Trust's objective to provide the highest possible long-term returns to
unitholders, by focusing on the key strategic objectives of the business plan.
This focus has resulted in ARC Energy Trust achieving superior results, since
inception in July 1996, by providing unitholders with cash distributions of
$10.64 per trust unit and capital appreciation of $1.90 per trust unit for a
total return of $12.54 per trust unit.
The key future objectives of the business plan, which is reviewed with the Board
of Directors, includes:
o Annual reserve replacement;
o Ensuring acquisitions are strategic and enhance unitholder
returns;
o Controlling costs - FD&A costs, operating costs and G&A
expenses;
o Actively hedging a portion of the Trust's production to
enhance long-term returns and stabilize distributions;
o Conservative utilization of debt;
o Continuously develop the expertise of our staff and hiring and
retaining the best in the industry;
o Building business relationships so as to be viewed as fair and
equitable in all business dealings;
o Promoting the use of proven and effective technologies;
o Being an industry leader in the environment, health and safety
area; and
o Continuing to actively support local initiatives in the
communities in which we operate and live.
In 2002 the Trust was successful in meeting or exceeding all of the above
objectives and will continue to focus on and closely monitor these core
objectives in 2003 and beyond.
13
SCHEDULE 1
ANNUAL HISTORICAL REVIEW
YEARS ENDED DECEMBER 31
($ thousands, except per unit and volume amounts) 2002 2001 2000 1999 1998
- -----------------------------------------------------------------------------------------------------------------
FINANCIAL
Revenue before royalties 444,835 515,596 316,270 155,191 67,124
Per unit (1) $ 3.72 $ 5.05 $ 4.97 $ 3.34 $ 2.62
Cash flow 223,969 260,270 179,349 80,814 30,040
Per unit (1) $ 1.87 $ 2.55 $ 2.82 $ 1.74 $ 1.17
Net income loss (5) 67,893 138,202 110,872 29,835 (14,093)
Per unit (1) $ 0.57 $ 1.36 $ 1.74 $ 0.64 $ (0.55)
Cash distributions 183,617 234,053 128,958 63,773 30,724
Per unit (2) $ 1.56 $ 2.31 $ 2.01 $ 1.35 $ 1.20
Working capital (deficit) (10,067) 5,805 6,339 15,761 (1,688)
Long-term debt 337,728 294,489 115,068 141,000 72,499
Weighted average trust units and exchangeable shares (3) 119,613 101,979 63,681 46,480 25,604
Trust units and units issuable for exchangeable shares
at end of period (4) 126,444 111,692 72,524 53,607 25,604
OPERATING
Production 42,425 43,111 27,355 22,172 12,737
Crude oil (bbl/d) 20,655 20,408 11,528 8,408 4,439
Natural gas (Mmcf/d) 109.8 115.2 77.2 66.5 37.7
Natural gas liquids (bbl/d) 3,479 3,511 2,965 2,687 2,018
Average prices
Crude oil ($/bbl) 31.63 31.70 36.74 24.85 18.99
Natural gas ($/Mcf) 4.41 5.72 4.48 2.54 1.93
Natural gas liquids ($/bbl) 24.01 31.03 31.52 17.43 13.17
Oil equivalent ($/Boe) 28.73 32.76 31.59 19.15 14.41
Established (proved plus risked probable) reserves
Crude oil and NGL (Mbbl) 117,241 114,243 82,419 59,712 35,034
Natural gas (Bcf) 408.8 385.5 286.4 241.0 121.9
Total (Mboe) 185,371 178,496 130,147 99,879 55,351
TRUST UNIT TRADING
(based on daily closing price)
Unit Prices ($)
High $ 13.29 $ 13.50 $ 12.15 $ 9.25 $ 11.40
Low $ 11.11 $ 10.41 $ 8.45 $ 6.15 $ 6.10
Close $ 11.90 $ 12.10 $ 11.30 $ 8.75 $ 6.15
Daily average trading volume (thousands) 305 414 155 68 32
- -----------------------------------------------------------------------------------------------------------------
(1) based on weighted average trust units and exchangeable shares
(2) based on number of trust units outstanding at each cash distribution date
(3) includes trust units issuable for outstanding exchangeable shares based on the period average exchange ratio
(4) natural gas converted at 6:1
(5) 2001 net income and net income per unit have been restated for the retroactive change in accounting policy
for deferred foreign exchange translation
- -----------------------------------------------------------------------------------------------------------------
SCHEDULE 2
QUARTERLY HISTORICAL REVIEW
2002 2001
---------------------------------------- ---------------------------------
($ thousands, except per unit and volume amounts) 4Q 3Q 2Q 1Q 4Q 3Q 2Q 1Q
- -----------------------------------------------------------------------------------------------------------------------------------
FINANCIAL
Revenue before royalties 117,639 113,625 112,707 100,864 102,609 116,307 132,287 164,393
Per unit (1) $ 0.93 $ 0.91 $ 0.98 $ 0.90 $ 0.94 $ 1.12 $ 1.29 $ 1.77
Cash flow 61,495 56,603 56,677 49,194 49,032 54,479 67,478 89,281
Per unit (1) $ 0.49 $ 0.45 $ 0.49 $ 0.44 $ 0.45 $ 0.53 $ 0.66 $ 0.96
Net income (loss) (5) 27,596 (3,505) 28,831 14,970 12,763 30,349 42,119 52,971
Per unit (1) $ 0.22 $ (0.03) $ 0.25 $ 0.13 $ 0.12 $ 0.29 $ 0.41 $ 0.57
Cash distributions 48,060 47,644 44,684 43,229 48,537 60,813 65,938 58,765
Per unit (2) $ 0.39 $ 0.39 $ 0.39 $ 0.39 $ 0.45 $ 0.60 $ 0.66 $ 0.60
Working capital (deficit) (10,067) 330 3,690 3,625 5,805 -- 3,617 9,978
Long-term debt 337,728 271,203 213,364 316,446 294,489 338,135 287,012 280,837
Weighted average units (thousands) (3) 126,370 124,794 115,235 111,838 108,585 103,449 102,942 92,941
Units outstanding at year-end (4) 126,444 126,270 122,359 111,957 111,692 103,523 103,249 102,692
OPERATING
Production
Crude oil (bbl/d) 20,256 20,809 20,366 21,196 20,753 20,066 20,202 20,614
Natural gas (Mmcf/d) 109.2 109.1 106.9 113.9 117.5 109.5 112.8 120.9
Natural gas liquids (bbl/d) 3,355 3,408 3,527 3,631 3,706 3,740 3,090 3,502
Total (Boe/d) 41,808 42,394 41,713 43,805 44,034 42,056 42,097 44,271
Average prices
Crude oil ($/bbl) 30.20 33.68 32.40 30.22 27.33 33.27 33.79 32.57
Natural gas ($/Mcf) 5.26 4.11 4.67 3.61 4.04 4.45 5.86 8.45
Natural gas liquids ($/bbl) 27.49 25.23 23.38 20.17 22.20 29.61 35.95 38.12
Oil equivalent ($/Boe) 30.58 29.13 29.69 25.58 25.31 30.05 34.53 41.26
(based on daily closing price)
TRUST UNIT TRADING
Prices ($)
High 12.63 12.90 13.29 13.14 12.10 12.59 13.50 11.89
Low 11.11 11.86 11.87 11.45 10.49 10.41 10.85 11.00
Close 11.90 12.80 12.77 13.14 12.10 10.61 11.55 11.24
Daily average trading volume (thousands) 269 256 252 446 316 391 447 499
- -----------------------------------------------------------------------------------------------------------------------------------
(1) based on weighted average trust units and exchangeable shares
(2) based on number of trust units outstanding at each cash distribution date
(3) includes trust units issuable for outstanding exchangeable shares based on the period average exchange ratio
(4) natural gas converted at 6:1
(5) 2001 quarterly net income and net income per unit have been restated for the retroactive change in accounting policy for
deferred foreign exchange translation
- -----------------------------------------------------------------------------------------------------------------------------------
ARC ENERGY TRUST
2002 ANNUAL INFORMATION FORM
MAY 16, 2003
TABLE OF CONTENTS
PAGE
GLOSSARY OF TERMS..............................................................1
ARC ENERGY TRUST...............................................................6
General.....................................................................6
General Development of the Business.........................................6
BUSINESS OF THE TRUST..........................................................9
Overview....................................................................9
Structure of the Trust......................................................9
Management Policies and Acquisition Strategy...............................10
Cash Distributions of Distributable Income and Distribution Policy.........11
Entitlement to Alberta Royalty Credits.....................................12
Potential Acquisition......................................................12
DESCRIPTION OF PROPERTIES.....................................................12
Principal Properties.......................................................13
OIL AND GAS RESERVES..........................................................16
Reconciliation of Reserves.................................................21
OTHER INFORMATION ABOUT THE PROPERTIES........................................22
Undeveloped Lands..........................................................22
Oil and Gas Wells..........................................................22
Production History.........................................................23
Drilling History...........................................................23
Capital Expenditures.......................................................24
Netback History............................................................24
Future Commitments.........................................................24
Marketing Arrangements.....................................................25
Acquisitions and Dispositions..............................................26
RECENT DEVELOPMENTS...........................................................26
Acquisition of Star Oil & GAS Ltd..........................................26
Amendments to Trust Indenture..............................................36
Exchangeable Share Reorganization..........................................37
SHARE CAPITAL OF ARC RESOURCES................................................38
Common Shares..............................................................38
ARC Resources Exchangeable Shares..........................................38
Second Preferred Shares....................................................40
SHARE CAPITAL OF ARML.........................................................40
OTHER INFORMATION RESPECTING ARC RESOURCES AND ARC SASK.......................40
Additional Properties......................................................40
Capital Expenditures.......................................................41
Deferred Purchase Price Obligation.........................................41
Borrowing..................................................................41
Escrow Agreements..........................................................42
Environmental Obligations - Reclamation Fund...............................43
Insurance..................................................................43
Retention Bonuses and Executive Employment Agreements......................43
INFORMATION RELATING TO THE TRUST.............................................44
Trust Units................................................................44
Special Voting Unit........................................................44
the Trust Indenture........................................................44
Trustee....................................................................44
Future Offerings...........................................................45
Meetings and Voting........................................................45
Management of the Trust....................................................45
ii
ARC Financial Advisory Agreement...........................................46
Special Debenture..........................................................46
Underlying Debentures......................................................50
Limitation On Non-resident Ownership.......................................56
Right of Redemption........................................................56
Termination of the Trust...................................................57
Reporting to Unitholders...................................................57
Distribution Reinvestment and Optional Trust Unit Purchase Plan............58
Unitholder Rights Protection Plan..........................................58
CORPORATE GOVERNANCE..........................................................60
General....................................................................60
Trust Indenture............................................................60
Decision Making............................................................60
Board of Directors of ARC Resources........................................61
THE MANAGER...................................................................62
Management Agreement.......................................................62
Compensation...............................................................62
CONFLICTS OF INTEREST.........................................................63
SELECTED CONSOLIDATED FINANCIAL INFORMATION...................................64
DISTRIBUTIONS TO UNITHOLDERS..................................................64
MANAGEMENT'S DISCUSSION AND ANALYSIS..........................................64
Environmental Regulation...................................................65
Quarterly Financial Information............................................66
MARKET FOR SECURITIES.........................................................66
RISK FACTORS..................................................................66
Purchase of Royalties......................................................66
Reserve Estimates..........................................................67
Volatility of Oil and Natural Gas Prices...................................67
Changes in Legislation.....................................................67
Investment Eligibility.....................................................67
Operational Matters........................................................68
Expansion of Operations....................................................68
Acquisitions...............................................................68
Environmental Concerns.....................................................68
Debt Service...............................................................69
Delay in Cash Distributions................................................69
Reliance On Management.....................................................69
Depletion of Reserves......................................................69
Net Asset Value............................................................70
Additional Financing.......................................................70
Competition................................................................70
Return of Capital..........................................................70
Limited Redemption Right...................................................70
Nature of Trust Units......................................................71
Unitholder Limited Liability...............................................71
ADDITIONAL INFORMATION........................................................72
APPENDIX "A" - CONSOLIDATED FINANCIAL STATEMENTS OF STAR OIL & GAS LTD.
APPENDIX "B" - PRO FORMA FINANCIAL STATEMENTS OF THE TRUST
iii
ABBREVIATIONS
bbl barrel mbbl one thousand barrels
bbl/d barrels per day mboe one thousand barrels of oil
equivalent
bcf billion cubic feet mcf one thousand cubic feet
boe barrels of oil equivalent mcf/d one thousand cubic feet per day
converting 6 mcf of
natural gas or one barrel of
natural gas liquids to one barrel
of oil equivalent
boe/d barrels of oil equivalent per day mlt thousand of long tons
lt long tons mmbbl one million barrels
lt/d long tons per day MMBTU one million British Thermal Units
mmcf one million cubic feet
mmcf/d one million cubic feet per day
$MM one million dollars
CONVERSIONS
The following table sets forth certain standard conversions between Standard
Imperial Units and the International System of Units (or metric units).
TO CONVERT FROM TO MULTIPLY BY
--------------- -- -----------
cubic metres cubic feet 35.315
bbls cubic metres 0.159
cubic metres bbls 6.290
feet metres 0.305
metres feet 3.281
miles kilometres 1.609
kilometers miles 0.621
acres hectares 0.4047
hectares acres 2.471
All dollar amounts set forth in this Annual Information Form are in Canadian
dollars, except where otherwise indicated.
ADVISORY
In the interest of providing the Unitholders and potential investors of ARC
Energy Trust (the "Trust") with information regarding the Trust and its
subsidiaries, including ARC Resources Ltd. ("ARC Resources"), including
management's assessment of the Trust's future plans and operations, this Annual
Information Form contains forward-looking information that represents the
Trust's internal projections, expectations, estimates or beliefs concerning,
among other things, future operating results and various components thereof or
the Trust's future economic performance. The projections, expectations,
estimates and beliefs contained in such forward-looking statements necessarily
involve known and unknown risks and uncertainties which may cause the Trust's
actual performance and financial results in future periods to differ materially
from any projections, expectations, estimates and beliefs of future performance
or results expressed or implied by such forward-looking statements. These risks
and uncertainties include, among other things, such risk and uncertainties
described in this Annual Information Form and in documents incorporated by
reference into this Annual Information Form and the Trust's other reports and
filings with the Canadian securities authorities. Accordingly, shareholders and
potential investors are cautioned that events or circumstances could cause
actual results to differ materially from those predicted.
NEITHER THE TRUST NOR ARC RESOURCES UNDERTAKES ANY OBLIGATIONS TO PUBLICLY
REVISE THESE FORWARD-LOOKING STATEMENTS TO REFLECT SUBSEQUENT EVENTS OR
CIRCUMSTANCES.
GLOSSARY OF TERMS
In this Annual Information Form, the following terms shall have the meanings set
forth below, unless otherwise indicated:
"AFFILIATE" and "ASSOCIATE" have the respective meanings ascribed thereto in the
BUSINESS CORPORATIONS ACT (Alberta);
"ANNUAL MEETING 2003 INFORMATION CIRCULAR" means the Information Circular -
Proxy Statement of the Trust dated March 17, 2003 for the annual and special
meeting of the Trust held on April 17, 2003;
"ARC ENERGY" means ARC Canadian Energy Ltd., a wholly-owned subsidiary of the
Trust;
"ARC RESOURCES EXCHANGE RATIO", at any time and in respect of each ARC Resources
Exchangeable Share, was initially equal to one and was 1.37557 as at May 16,
2003, and shall be increased on each Cash Distribution Date between June 1, 2003
and the time as of which the ARC Resources Exchange Ratio is being calculated by
an amount, rounded to the nearest five decimal places, equal to a fraction
having as its numerator the Distribution, expressed as an amount per Trust Unit,
paid on that Cash Distribution Date, and having as its denominator the current
market price (10 day weighted average trading price) on the first business day
following the Record Date for such Distribution and shall be reduced on each
Dividend Record Date between May 16, 2003 and the time as of which the ARC
Resources Exchange Ratio is calculated by an amount, rounded to the nearest five
decimal places, equal to a fraction having as its numerator the dividend
declared on that Dividend Record Date, expressed as an amount per ARC Resources
Exchangeable Share, and having as its denominator the current market price on
the date that is seven business days prior to that Dividend Record Date;
"ARC RESOURCES EXCHANGEABLE SHARE PROVISIONS" means the rights, privileges,
restrictions and conditions attaching to the ARC Resources Exchangeable Shares
as set forth in the Articles of ARC Resources;
"ARC FINANCIAL ADVISORY AGREEMENT" means the agreement dated August 28, 2002,
among ARC Financial Corporation, ARC Resources, ARML and the Trust;
"ARC RESOURCES" means ARC Resources Ltd., a subsidiary of the Trust;
"ARC RESOURCES EXCHANGEABLE SHARE SUPPORT AGREEMENT" means the amended and
restated support agreement dated May 16, 2003 among the Trust, ARC Resources,
ARC Subco and Computershare Trust Company of Canada;
"ARC RESOURCES EXCHANGEABLE SHARE VOTING AND EXCHANGE TRUST AGREEMENT" means the
amended and restated agreement dated May 16, 2003 among the Trust, ARC Subco,
ARC Resources and Computershare Trust Company of Canada;
"ARC RESOURCES EXCHANGEABLE SHARES" means the non-voting exchangeable shares in
the capital of ARC Resources;
"ARC SASK." means ARC (Sask.) Energy Trust, a trust formed under the laws of
Alberta;
"ARC SUBCO" means 908563 Alberta Ltd., a wholly-owned subsidiary of the Trust;
"ARML" or the "MANAGER" means, as the context requires: (i) the corporation
named ARC Resources Management Ltd., all of whose shares were acquired by 980445
Alberta Ltd. on August 28, 2002
2
pursuant to the Internalization Transaction and which was subsequently
amalgamated with its then parent, 980445 Alberta Ltd., a wholly-owned subsidiary
of the Trust, on August 29, 2002; or (ii) the corporation named ARC Resources
Management Ltd., which corporation is the continuing entity resulting from the
amalgamation on August 29, 2002, of 980445 Alberta Ltd. and its then
wholly-owned subsidiary, ARC Resources Management Ltd. or (iii) following the
Exchangeable Share Reorganization, a wholly-owned subsidiary of ARC Resources,
which was subsequently wound up into ARC Resources as of May 16, 2003;
"ARML EXCHANGEABLE SHARES" means non-voting exchangeable shares in the capital
of ARML;
"ARML OFFICERS" means Doug J. Bonner, David P. Carey, John P. Dielwart, Susan D.
Healy, Steven W. Sinclair and Myron J. Stadnyk;
"ARRANGEMENT" means the business combination of ARC Resources and Startech as
described under "ARC Energy Trust - General Development of the Business";
"ARTC" means Alberta Royalty Tax Credit;
"ASSET VALUE" means, for any property at any time, the present worth of all of
the estimated pre-tax net cash flow from the Proved Reserves and 50% of the
estimated pre-tax net cash flow from the Probable Reserves shown in the most
recent engineering report relating to such property, discounted at 15% and using
escalating price and cost assumptions;
"CASH DISTRIBUTION DATE" means the date Distributable Income is paid to
Unitholders, being the 15th day following any Record Date (or if such day is not
a business day, on the next business day);
"DEBT SERVICE CHARGES" means all interest and principal repayments and other
costs, expenses and disbursements relating to the borrowing of funds by ARC
Resources and ARC Sask. which are attributable to the Properties or which are
borrowed from the Trust. See "Other Information Respecting ARC Resources -
Borrowing";
"DEFERRED PURCHASE PRICE OBLIGATION" means the ongoing obligation of the Trust
to pay to ARC Resources and ARC Sask. an amount equal to 99% of the cost of, or
any amount borrowed to acquire, any additional "Canadian resource property" (as
defined in the Tax Act) acquired by ARC Resources and ARC Sask. (other than the
working, royalty and other interests acquired by ARC Resources pursuant to the
Arrangement) and of the cost of, or any amount borrowed to fund, "Canadian
Development Expense" and "Canadian Exploration Expense" (both as defined in the
Tax Act);
"DISTRIBUTABLE INCOME" means, for any particular period, the Royalties, other
income from permitted investments (including the Long Term Notes) and ARTC, if
any, received by the Trust less the Trust's share of Crown royalties (other than
Crown royalties which are deducted in the computation of the Royalties) and
direct expenses of the Trust;
"DISTRIBUTION" means a distribution paid by the Trust in respect of the Trust
Units, expressed as an amount per Trust Unit;
"DIVIDEND RECORD DATE" has the meaning given to that term in the ARC Resources
Exchangeable Share Provisions;
"ECONOMIC LIFE" means with respect to an oil and gas property, the time
remaining before production of Petroleum Substances from the property is
forecast to be uneconomic;
3
"ESCROW AGREEMENTS" means the escrow agreements dated August 28, 2002, among
certain holders of Trust Units and ARML Exchangeable Shares, 980445 Alberta
Ltd., the Trust and Computershare Trust Company of Canada providing for the
escrow of an aggregate of 2,017,782 Trust Units and ARML Exchangeable Shares on
the terms described in "Other Information Respecting ARC Resources and ARC Sask.
- - Escrow Agreements";
"ESTABLISHED RESERVES" means proved reserves plus probable reserves risked at
50%;
"EXCHANGEABLE SHARE REORGANIZATION" means the transaction encompassing the
merger of ARC Resources and ARML as described under "Recent Developments -
Exchangeable Share Reorganization";
"EXCHANGEABLE SHARES" means, collectively, the ARC Resources Exchangeable Shares
and, where the context requires, the ARML Exchangeable Shares;
"EXCHANGEABLE SHARES TRANSFER AGENT" means Computershare Trust Company of
Canada;
"GENERAL AND ADMINISTRATIVE COSTS" means the amount in aggregate representing
all expenditures and costs incurred under the Management Agreement in respect of
ARC Resources, the Trust or the Royalties or in the management and
administration of ARC Resources, the Trust, ARC Sask., Orion or the Royalties;
"GILBERT" means Gilbert Laustsen Jung Associates Ltd., independent petroleum
consultants of Calgary, Alberta;
"GILBERT REPORT" means the report prepared by Gilbert dated January 24, 2003 (as
updated by a report dated April 30, 2003 evaluating the impact of ARC Energy
Trust's hedge position and utilizing the Gilbert product price forecasts
effective April 1, 2003) evaluating the crude oil, natural gas, natural gas
liquids and sulphur reserves attributable to the Properties at January 1, 2003;
"INTERNALIZATION TRANSACTION" means the transaction encompassing the indirect
purchase by the Trust of all of the ARML shares and related transactions as
described under "ARC Energy Trust - General Development of the Business";
"LONG TERM NOTES" means the long term notes issued by ARC Resources to the Trust
on January 31, 2001, August 29, 2002 and April 16, 2003. Interest on the notes
is payable monthly and the principal is due and payable on December 31, 2016,
December 31, 2017 and December 31, 2018, respectively;
"MANAGEMENT AGREEMENT" means the agreement dated July 11, 1996, as amended,
between the Manager, ARC Resources and the Trustee for and on behalf of the
Trust. See "The Manager - Management Agreement";
"NEW GILBERT REPORT" means the report prepared by Gilbert dated May 12, 2003,
evaluating the crude oil, natural gas, natural gas liquids and sulphur reserves
at January 1, 2003 attributable to the New Properties utilizing the Gilbert
product price forecasts effective April 1, 2003;
"NEW PROPERTIES" means the working interest, royalty and other interests
acquired by ARC Resources pursuant to the Star Transaction other than the
working, royalty and other interests which were sold pursuant to the Property
Dispositions;
"ORION" means Orion Energy Trust, a trust formed under the laws of Alberta;
4
"PETROLEUM SUBSTANCES" means petroleum, natural gas and related hydrocarbons
(except coal) including, without limitation, all liquid hydrocarbons, and all
other substances, including sulphur, whether gaseous, liquid or solid and
whether hydrocarbon or not, produced in association with such petroleum, natural
gas or related hydrocarbons;
"PROPERTIES" means the working, royalty or other interests of ARC Resources and
ARC Sask. from time to time in any petroleum and natural gas rights, tangibles
and miscellaneous interests, including additional properties which may be
acquired by ARC Resources or ARC Sask. at a future date;
"PROPERTY DISPOSITIONS" means the sale by ARC Resources to third parties of
certain working, royalty and other interests of Star which was completed
immediately following the completion of the Star Transaction as defined in
"Recent Developments - Acquisition of Star Oil & Gas Ltd.";
"PROVED RESERVES" and "PROBABLE RESERVES" have the meanings given to those terms
under "Oil and Gas Reserves";
"RECORD DATE" means the last business day of each month;
"RESERVE LIFE INDEX" is an index reflecting the theoretical production life of a
property if the remaining reserves were to be produced out at current production
rates. The index is calculated by dividing the reserves in the selected reserve
category at a certain date by the estimated production for the following 12
month period;
"RETENTION BONUSES" means bonuses in the aggregate amount of $5,000,000 declared
by the board of directors of ARML on August 28, 2002, to the former ARML
Officers;
"ROYALTIES" means, collectively, the royalties payable by ARC Resources and ARC
Sask. to the Trust pursuant to the Royalty Agreements which equal 99% of royalty
income;
"ROYALTY AGREEMENTS" means, collectively, the agreements regarding the grant of
the Royalties made as of July 1, 2002, between each of ARC Resources and ARC
Sask. and Computershare Trust Company of Canada, as trustee for and on behalf of
the Trust;
"ROYALTY INCOME" in respect of any period for which Royalty Income is calculated
for the Royalties means: (a) the amount received in such period in respect of
the sale of Petroleum Substances collected from the Properties held by ARC
Resources or ARC Sask. (including the share reserved to the Crown) and any other
revenue received in such period other than the proceeds from the sale of the
Properties; less (b) the following costs and expenses paid in such period: all
costs and expenses (including both operating costs and capital costs) in respect
of the Properties held by ARC Resources or ARC Sask. (except to the extent that
such costs or expenses are funded by borrowing and in the case of capital costs
except to the extent designated as Deferred Purchase Price Obligations)
including, without limitation, income, capital and other direct taxes in respect
of the Properties; Debt Service Charges; net contributions to the reclamation
fund; and all other costs and expenses relating to the Properties held by ARC
Resources or ARC Sask. Any income derived from the Properties held by ARC
Resources or ARC Sask. which are not working interests in "Canadian resource
properties" (as defined in the Tax Act) or which do not relate to production
from working interests in "Canadian resource properties" or ARTC received by ARC
Resources with respect to payment of Crown Royalties, will not be included as
Royalty Income and will be used to defray other expenses and capital
expenditures of ARC Resources or ARC Sask.;
"SHARE SALE AGREEMENT" means the agreement dated March 31, 2003, among United
Energy, LLC, ARC Resources and the Trust pursuant to which ARC Resources agreed
to purchase and United Energy, LLC agreed to sell all of the outstanding shares
of Star;
5
"SHAREHOLDER AGREEMENT" means the agreement amended and restated as of January
31, 2001 among ARC Resources, the Manager and the Trustee for and on behalf of
Unitholders;
"SPECIAL DEBENTURE" means the special 8% special adjustable convertible
subordinated debenture dated April 16, 2003, in the principal amount of
$320,000,000 delivered by the Trust pursuant to the Share Sale Agreement in
partial payment of the purchase price payable thereunder;
"SPECIAL RESOLUTION" means a resolution passed by a majority of not less than 66
2/3 % of the votes cast, either in person or by proxy, at a meeting of
Unitholders, called for the purpose of approving such resolution, or approved in
writing by the holders of not less than 66 2/3% of the Trust Units entitled to
be voted on such resolution;
"SPECIAL VOTING UNIT" has the meaning set forth in "Information Relating to the
Trust - Special Voting Unit";
"STAR" means Star Oil & Gas Ltd.;
"STAR TRANSACTION" means the purchase by ARC Resources of all of the outstanding
shares of Star and related transactions pursuant to the Share Sale Agreement as
defined in "Recent Developments - Acquisition of Star Oil & Gas Ltd.";
"STARTECH" means Startech Energy Inc.;
"TAX ACT" means the INCOME TAX ACT (Canada) and the regulations thereunder;
"TRUST INDENTURE" means the trust indenture dated May 7, 1996 as amended and
restated as of April 10, 2002 between the Trustee and ARC Resources;
"TRUST UNITS" means the units of the Trust, each unit representing an equal
undivided beneficial interest therein;
"TRUST" means ARC Energy Trust;
"TRUSTEE" means Computershare Trust Company of Canada, the trustee of the Trust;
"TSX" means The Toronto Stock Exchange;
"UNDERLYING DEBENTURES" means up to $320,000,000 principal amount of 8%
adjustable convertible unsecured subordinated debentures due June 30, 2008
issuable on the conversion or deemed exercise of the Special Debenture;
"UNDERLYING DEBENTURE TRUST INDENTURE" means the trust indenture among the
Trust, ARC Resources and Computershare Trust Company of Canada dated April 16,
2003 providing for the issue of debentures of the Trust including the Underlying
Debentures; and
"UNITHOLDERS" means holders of Trust Units of the Trust.
6
ARC ENERGY TRUST
GENERAL
The Trust is an open-end investment trust created on May 7, 1996 under the laws
of the Province of Alberta pursuant to the Trust Indenture. The Trust Indenture
has been amended from time to time, the latest material amendments being those
set forth in the Annual Meeting 2003 Information Circular, which included an
amendment to eliminate the delegation of responsibilities and powers of the
Trustee to the Manager and to delegate to ARC Resources all of the matters
formerly delegated to the Manager. Computershare Trust Company of Canada has
been appointed as trustee under the Trust Indenture. The beneficiaries of the
Trust are holders of the Trust Units. The principal and head office of the
Trustee is located at Suite 600, 530 - 8th Avenue S.W., Calgary, Alberta, T2P
3S8.
ARC Resources was incorporated under the Business Corporations Act (Alberta) on
January 22, 1996 and was amalgamated with Orion Energy Holdings Inc. and Pencor
Petroleum Limited on March 31, 1999; amalgamated with Startech and ARC Resources
Finance Ltd. on January 31, 2001; amalgamated with its wholly owned
subsidiaries, FarPoint Energy Corporation, Erex Inc. and Erewhon Exploration
Ltd. on December 31, 2002, and amalgamated with its then wholly-owned
subsidiary, Star, on April 16, 2003. All of the issued and outstanding shares of
ARC Resources are held by the Trust except for the Exchangeable Shares issued in
conjunction with the acquisition of Startech on January 31, 2001 and the
Exchangeable Shares issued to the former holders of the ARML Exchangeable Shares
pursuant to the Exchangeable Share Reorganization. The business of ARC Resources
is the acquisition, development, exploitation, and disposition of all types of
petroleum and natural gas and energy related assets, including conventional oil
and gas assets, oil sands interests, electricity or power generating assets and
pipeline, gathering and transportation assets. The head and principal office of
ARC Resources is located at Suite 2100, 440 - 2nd Avenue S.W., Calgary, Alberta,
T2P 5E9. As at December 31, 2002 ARC Resources had 184 employees. Additionally,
ARC Resources utilized the services of 55 persons on a contract or consulting
basis.
GENERAL DEVELOPMENT OF THE BUSINESS
The following is a description of the general development of the business of the
Trust over its last three completed financial years.
On January 31, 2000, ARC Resources entered into an acquisition agreement with a
major oil and gas producer (the "Vendor") to purchase certain working, royalty
and other interests effective January 1, 2000 for an aggregate purchase price of
$135 million. ARC Resources closed the acquisition on April 4, 2000. The
properties acquired consisted of two major and 11 minor producing oil and gas
properties in Alberta and Saskatchewan. In 1999, production from the properties
acquired was approximately 5,790 barrels of oil equivalent per day comprised of
4,540 bbl/d of oil and natural gas liquids and 7.5 mmcf/d of natural gas. In
1999, the operating cash flow generated by the properties acquired was
approximately $29 million. The reserves attributed to the properties acquired as
at December 31, 1999 were 25.4 million barrels of oil equivalent and 30.4
million barrels of oil equivalent for total Proved Reserves and for total
Established Reserves, respectively. The reserve life index was 13.2 years for
Proved Reserves and 15.6 years for Established Reserves.
On March 1, 2000, the Trust sold 5,800,000 Trust Units to a syndicate of
underwriters at a price of $8.65 per Trust Unit for gross proceeds of $50.2
million through a short form prospectus offering. On March 10, 2000, the Trust
sold an additional 600,000 Trust Units through the exercise of an over-allotment
option granted to the underwriters for additional gross proceeds of $5.19
million. The net proceeds were used to partially fund the Trust's acquisition of
properties from a third party.
7
On October 10, 2000, the Trust issued 8,700,000 Trust Units at a price of $11.65
per Trust Unit for gross proceeds of $101.4 million pursuant to a short form
prospectus dated September 29, 2000. The offering was made through a syndicate
of underwriters. The net proceeds were used to repay outstanding indebtedness.
On November 16, 2000, ARC Finance Ltd., which company was subsequently
amalgamated with ARC Resources on January 31, 2001, issued U.S. $35 million of
8.05% Senior Secured Notes with principal payments due on November 17 in each of
2004, 2005, 2006, 2007 and 2008 to a U.S. financial institution pursuant to an
Uncommitted Master Shelf Agreement dated November 16, 2000 which, as at such
date also provided for the issuance of up to an additional U.S. $65 million
principal amount of notes at rates and maturity dates to be agreed upon.
The Trust, ARC Resources, Startech and Impact Energy Inc. entered into an
agreement as of December 20, 2000 which provided for the acquisition by ARC
Resources of all of the issued and outstanding shares of Startech in exchange
for, at the option of each holder of Startech shares, either 0.96 Trust Units or
0.96 Exchangeable Shares (to a maximum of 15,000,000 Exchangeable Shares) plus
one common share of Impact Energy Inc. for each Startech share. The Arrangement
was approved by the shareholders of Startech on January 25, 2001 and was
completed on January 31, 2001 on the basis that ARC Resources acquired all of
the issued and outstanding shares of Startech in consideration of the issuance
of approximately 22.6 million Trust Units and approximately 7.4 million
Exchangeable Shares to holders of Startech shares. ARC Resources also assumed
approximately $168 million of bank indebtedness. Concurrently, ARC Resources
amalgamated with Startech and ARC Resources' wholly-owned subsidiary, ARC
Resources Finance Ltd. In connection with the Arrangement, ARC Resources issued
the Long Term Notes in the principal amount of approximately $352 million to the
Trust. The reserves attributable to the properties as at January 1, 2001 were
58.3 million boe on the basis of proven reserves plus probable reserves risked
at 50 per cent. The properties acquired consisted of two major and 14 minor
producing oil and gas properties principally located in Alberta and
Saskatchewan. The reserve life index was 10.2 years for the proven reserves plus
probable reserves risked at 50 per cent.
Effective February 1, 2001, a number of transactions involving the Trust, ARC
Resources and ARC Sask. were completed pursuant to which ARC Resources disposed
of the oil and gas properties located in the Province of Saskatchewan which were
formerly held by Startech to ARC Sask., ARC Sask. granted a 99% royalty to ARC
Resources, such royalty was assigned by ARC Resources to the Trust and the Long
Term Notes were reduced by the fair market value of such royalty.
On November 5, 2001, the Trust sold 8,050,000 Trust Units to a syndicate of
underwriters at a price of $11.00 per Trust Unit for gross proceeds of
$88,550,000 pursuant to a short form prospectus dated October 29, 2001. The net
proceeds were initially used to repay outstanding indebtedness and then used to
finance a portion of the 2001 fourth quarter capital expenditure program, with
the remainder used to finance the 2002 capital expenditure program.
On June 3, 2002, The Trust sold 10,000,000 Trust Units to a syndicate of
underwriters at a price of $12.05 per Trust Unit for gross proceeds of
$120,500,000 pursuant to a short form prospectus dated May 22, 2002. The net
proceeds were initially used to fund approximately $35 million of crude oil and
natural gas property acquisitions as well as to repay outstanding indebtedness.
Effective July 1, 2002, a number of transactions involving the Trust, ARC
Resources, ARC Sask., Orion Energy Trust and ARC Canadian Oil & Gas Ltd. were
completed pursuant to which, following the completion of such transactions: (i)
the Trust holds a 99% royalty on all of the properties held by ARC Resources;
(ii) the Trust holds a 99% royalty on all of the properties held by ARC Sask.;
and (iii) ARC Canadian Oil & Gas Ltd. (which company is a wholly-owned
subsidiary of the Trust) holds all of the
8
issued and outstanding trust units of Orion Energy Trust which in turn holds all
of the issued and outstanding trust units of ARC Sask.
On August 28, 2002, the Internalization Transaction was approved by the
Unitholders of the Trust at a special meeting, resulting in a wholly-owned
subsidiary of the Trust, 980445 Alberta Ltd., acquiring all of the common shares
of ARML in exchange for $4,247,658 in cash, the assumption of the obligation of
ARML to pay retention bonuses in the aggregate amount of $5,000,000 over a
period of five years, 298,648 Trust Units and 3,281,279 ARML Exchangeable
Shares. As part of the transaction, an aggregate 9,013 Trust Units and 2,008,699
ARML Exchangeable Shares were placed in escrow in accordance with the terms of
Escrow Agreements. In addition, the ARC Financial Advisory Agreement was entered
into pursuant to which ARC Financial Corporation agreed to provide certain
ongoing research and strategic services to the Trust for a five year period
without cost to the Trust. Furthermore ARML agreed to waive its right under the
Shareholder Agreement to select three of the seven directors on the Board of
Directors of ARC Resources; thereby allowing Unitholders to select all of the
members of the Board of Directors commencing at the annual meeting of
Unitholders to be held in 2003. On August 29, 2002, 980445 Alberta Ltd.
amalgamated with its then wholly-owned subsidiary, ARML, and the amalgamated
company continued under the name "ARC Resources Management Ltd.".
On October 18, 2002 ARC Resources issued U.S. $30 million of 4.94% Senior
Secured Notes with principal payments due on October 19 in each of 2006, 2007,
2008, 2009 and 2010 to a U.S. Financial institution pursuant to an Uncommitted
Master Shelf Agreement dated November 16, 2000 which, as at October 18, 2002,
also provided for the issuance of up to an additional U.S. $35 million principal
amount of notes at rates and maturity dates to be agreed upon.
For information in respect of material developments in the business of ARC
Resources and the Trust since December 31, 2002, see "Recent Developments".
TRENDS
There are a number of trends in the oil and gas industry that are shaping the
near term future of the business. The first trend is the ongoing consolidation
phase that the industry has been going through which has affected companies of
all sizes from the small emerging companies to the senior integrated
organizations. Although consolidation is nothing new for the industry, the pace
at which it has occurred during the past 30 months and the nature of the
companies involved are unique. The companies which have been consolidated
include the traditional small to medium size companies as well as a number of
large, well established, big name companies. The most active acquirors have been
royalty trusts and large U.S. based independents and one large Canadian oil and
gas producer, which is a new trend.
Another continuing trend has been small to medium sized exploration and
production companies converting to royalty trusts. During the past 12 months,
three such conversions have occurred and these new trusts have become active in
the consolidation of the industry thereby increasing competition for the
previously existing trusts.
Including recently announced conversions of several exploration and production
companies to trusts, approximately half of the top 30 publicly listed oil and
gas issuers on the TSX are now trusts. Annual production declines from the
trusts will likely result in a continued high level of competition for available
oil and gas properties and companies. This increased competition within the
trust sector, as well as the influence of U.S. based companies, has resulted in
higher valuation parameters for corporate acquisitions. Those trusts with
substantial opportunities for production replacement through internal
development drilling should be in an advantaged position relative to those more
exposed to production replacement through acquisitions. With the acquisition of
Star, the Trust is very well positioned to maintain production for the next two
years with only minimal exposure to the acquisition market. The Board of
9
Directors had approved a capital budget of $115.0 million for internal
development drilling and other related capital activities prior to the Star
acquisition.
A direct consequence of the consolidation which has occurred is asset
rationalization by the acquiring companies. As a result, significant asset
acquisition opportunities have developed. ARC Resources expects this trend of
asset dispositions to continue with the quality of the available properties
becoming more attractive with time, thereby providing new acquisition
opportunities for the Trust.
Another ongoing trend is the continued volatility of oil and gas prices with oil
and gas company capital budgets highly responsive to commodity prices. As the
supply/demand balance for both natural gas and crude oil tightens, commodity
prices increase and drilling activity rises reflecting increased capital
spending by oil and gas companies. Conversely, as commodity prices decline,
capital budgets are reduced and drilling activity declines. In tight markets
such as those ARC Resources is currently encountering, especially for natural
gas, the supply response resulting from changing drilling activity has a
material impact on prices. In addition, oil prices have been volatile due to
lower demand associated with weak but recovering world economies. This has been
offset by the influence of both OPEC production cuts and the political
instability in the Middle East. Price volatility is expected to be an ongoing
characteristic of the oil and gas industry.
The Canadian/U.S. exchange rate also influences commodity prices received by
Canadian producers as oil and natural gas production is priced in U.S. dollars.
The recent strengthening of the Canadian dollar will have a negative impact on
Canadian oil and gas production revenue.
BUSINESS OF THE TRUST
OVERVIEW
The principal investments of the Trust are the Royalties granted by ARC
Resources and by ARC Sask. pursuant to the Royalty Agreements, the common shares
of ARC Resources, the Long Term Notes and the common shares of ARC Canadian Oil
& Gas Ltd. The Trust's investments in Royalties and Long Term Notes are made in
order to finance oil and gas acquisitions made by ARC Resources and ARC Sask.
The Royalties consist of a 99% share of royalty income on all of the Properties
held by ARC Resources and ARC Sask. On each Cash Distribution Date, ARC
Resources and ARC Sask. pay the Trust 99% of royalty income and ARC Resources
pays interest on the Long Term Notes. The Trust will make cash distributions of
such funds, subject only to required deductions and expenses of the Trust. Such
cash distributions may be wholly or in part taxable. See "Distributions to
Unitholders".
STRUCTURE OF THE TRUST
The Trust is structured with the objective of having income tax incurred only in
the hands of the Unitholders. Distributable Income received by Unitholders
consists essentially of the operating cash flow generated by the oil and natural
gas properties of ARC Resources and ARC Sask. More specifically, internally
generated cash flow, with the exception of cash flow used for capital
expenditures, reclamation fund contributions and debt repayments, is effectively
returned to the Unitholders.
The scope of the business of the Trust includes the acquisition and holding of
royalties on petroleum and natural gas properties and related assets and the
investment in securities of a company or other subsidiaries of the Trust to fund
the acquisition, development, exploitation and disposition of all types of
energy business related assets, including petroleum and natural gas related
assets, oil sands interests, electricity or power generating assets and
pipeline, gathering, processing and transportation assets. The Trust Indenture
also contemplates the issuance of securities of ARC Resources or an affiliate of
ARC
10
Resources which are exchangeable for Trust Units and to confer upon such
securities voting rights in the Trust. The Trust will not directly carry on the
oil and gas business or any other business.
The Trust is an open-ended investment trust. The Trust Indenture contains rights
attached to Trust Units entitling a Unitholder to require the Trust at any time
on the demand of the Unitholder to redeem his or her Trust Units. As with most
other open-end funds, it is anticipated that trading on the TSX and not the
right of retraction would continue as the primary mechanism for Unitholders to
dispose of their Trust Units. For more detailed information regarding the right
of redemption, see "Information Relating to the Trust - Right of Redemption".
The structure of the Trust and the cash flows to the Trust and from the Trust to
Unitholders are set forth below:
[GRAPHIC OMITTED]
------------------
Unitholders
------------------
| ^
| |
Trust Units | | Cash Distributions
v |
-----------------------
-----> ARC Energy Trust
| -----------------------
| | ^ |
| | | | Direct Interest
| | | | (100%)
| | | v
| | | ----------------------
| | | ARC Canadian Oil &
| | | Gas Ltd. (1)
| | | ----------------------
| | | |
| |Direct | | Direct Interest
| |Interest | | (100%)
| |(100%) | v
| | | ----------------------
| | | Orion Energy Trust
| | | ----------------------
| | | |
|Royalty | | |
|and | |Royalty |
|Interest | |Income | Direct Interest
|Interest | | | (100%)
| v | |
------------------------ | v
ARC Resources Ltd.(1)(2) -----------------------------------
------------------------ ARC (Sask.) Energy Trust (2)
-----------------------------------
Notes:
(1) Owned by the Trust
(2) ARC Resources is the holder of substantially all Properties and assets
other than the Properties and assets located in Saskatchewan which are held
by ARC (Sask.)
MANAGEMENT POLICIES AND ACQUISITION STRATEGY
Prior to the most recent amendments to the Trust Indenture which were made
effective on May 16, 2003 the Manager managed the Trust, Orion, ARC Sask. and
ARC Resources pursuant to the Management
11
Agreement. Commencing on May 16, 2003, ARC Resources now manages the Trust,
Orion, ARC Sask. and ARC Resources pursuant to the delegation of
responsibilities and powers by the Trustee under the Trust Indenture.
All activities undertaken by management are directed towards maximizing
Distributable Income to the Unitholders while at the same time striving for
long-term growth in the value of the assets of ARC Resources and ARC Sask. These
two objectives are fundamental to the operation of the Trust and are balanced to
maximize benefit to the Unitholders. Management directs its efforts to increase
the value of the assets of ARC Resources and ARC Sask. through the acquisition
of producing oil and gas properties. ARC Resources and ARC Sask. acquire
producing properties and participate in development activities that are
generally considered to be of a low risk nature in the oil and gas industry.
Also, a small percentage of each year's capital budget will be devoted to
moderate risk development and low risk exploration opportunities that either ARC
Resources or ARC Sask. may have.
Management's acquisition strategy will target individual properties, or groups
of properties, that generally comply with the following criteria and procedures:
1. a property, or group of properties, acquired in a single transaction
will provide a forecast internal rate of return that is greater than
400 basis points above long-term (ten year) Government of Canada bonds
over the life of the reserves associated with such property or
properties after deducting general and administrative expenses and
management fees and incorporating the impact of debt financing, but
before income taxes;
2. commodity price and exchange rate assumptions used in acquisition
evaluations will be from a major independent engineering firm, or ARC
Resources' estimate of current market price and exchange rate
expectations being reflected in significant oil and gas acquisition and
disposition transactions;
3. each acquisition of a property, or group of properties, for a purchase
price of $5 million or more, will be based on engineering in an
independent engineering report, which may be modified to incorporate
ARC Resources' views of the engineering analysis contained in the
report;
4. not more than 25% of the total Asset Value of the Trust will be
attributable to a single property; and
5. the expected Economic Life of a property, or group of properties,
acquired in a single transaction will be not less than ten years.
These criteria will serve as guidelines for presenting acquisitions for approval
by the Board of Directors of ARC Resources. The Board of Directors of ARC
Resources may vary these criteria for any particular acquisition based on
management's recommendations and consideration of the qualitative aspects of the
subject properties including risk profile, technical upside, reserve life index
and asset quality. In considering acquisitions, the Board of Directors of ARC
Resources considers the impact that such acquisition would have on anticipated
after-tax distributions to Unitholders.
CASH DISTRIBUTIONS OF DISTRIBUTABLE INCOME AND DISTRIBUTION POLICY
Cash distributions of Distributable Income are made on the 15th day (or if such
date is not a business day, on the next business day) following the end of each
calendar month to Unitholders of record on the last business day of each such
calendar month. Royalty Income, which comprises in part Distributable Income, is
determined on a cash basis.
12
The Board of Directors of ARC Resources on behalf of the Trust reviews the
distribution policy from time to time. The current distribution policy allows
the use of up to 20% of cash available for distribution for capital
expenditures. Depending upon commodity prices and the size of the capital
budget, it is expected that 20% of the cash available for distribution will fund
between 50% and 100% of the Trust's annual capital expenditure program,
including both exploitation expenditures and minor property acquisitions, but
excluding major acquisitions. The Trust's distribution policy includes
withholding approximately $4 million per annum to contribute to the Trust's
reclamation fund to provide a cash reserve for the eventual abandonment of oil
and gas properties (and subsequent to the Star Transaction has been increased to
$6 million per annum). In addition to the 20% holdback of cash flow to fund
capital expenditures, cash flow generated from the properties formerly held by
Star may be withheld from distributions and used to repay bank indebtedness or
the Underlying Debentures. The actual amount withheld is dependent on the
commodity price environment and is at the discretion of the Board of Directors.
This holdback policy is a key difference between the Trust and other
conventional oil and gas trusts, and is designed to focus on production
replacement activities partially funded by cash flow in order to enhance
long-term Unitholder returns.
Distributions are normally announced on a quarterly basis in the context of
prevailing and anticipated commodity prices. During periods of volatile
commodity prices, the Trust may vary the distribution rate monthly.
ENTITLEMENT TO ALBERTA ROYALTY CREDITS
The Trust and ARC Resources are entitled to claim ARTC in respect of properties
located in Alberta. Under current legislation, ARTC is based on a price
sensitive formula linked to crude oil prices. Credits vary from a high of 75% of
eligible Alberta Crown Royalties when the Royalty Tax Credit reference price
("RTCRP") is $100/m3 or less (approximately U.S. $12 per barrel), to a low of
25% of Alberta Crown Royalties when the RTCRP is $210/m3 or more (approximately
U.S. $25 per barrel). The maximum Alberta Crown Royalty to which the rate
applies annually is $2 million per applicant or associated group of applicants.
Currently the Trust and ARC Resources are each eligible to receive ARTC. ARC
Resources will use the ARTC to defray other expenses and capital expenditures of
ARC Resources thereby effectively increasing Royalty Income.
ARC Resources is entitled to claim ARTC in respect of the portion of the Royalty
which is not subject to the Trust's obligations to reimburse for Crown Royalties
and where the properties to which the Royalty relates are not otherwise
"restricted resource properties".
POTENTIAL ACQUISITION
The Trust continues to evaluate potential acquisitions of all types of petroleum
and natural gas and other energy-related assets as part of its ongoing
acquisition program. The Trust is normally in the process of evaluating several
potential acquisitions at any one time which individually or together could be
material. As of the date hereof, the Trust has not reached agreement on the
price or terms of any material potential acquisition that has not been
disclosed. The Trust cannot predict whether any current or future opportunities
will result in one or more acquisitions for the Trust.
DESCRIPTION OF PROPERTIES
ARC Resources' and ARC Sask.'s portfolio of Properties as at December 31, 2002
includes both unitized and non-unitized oil and natural gas production, all of
which are subject to the Royalties. In general, the Properties contain long
life, low decline rate reserves and include interests in several major oil and
gas fields.
13
The information provided below relates to all of the Properties and operations
of ARC Resources and ARC Sask. and various references to ARC Resources in this
section of the Annual Information Form should be read as including ARC Sask.
PRINCIPAL PROPERTIES
The following is a description of the principal oil and natural gas properties
of ARC Resources and ARC Sask. as at December 31, 2002. The term "net", when
used to describe ARC Resources' or ARC Sask.'s share of production, means the
total of ARC Resources' or ARC Sask.'s working interest share before deducting
royalties owned by others. Reserve amounts are stated, before deduction of
royalties, at January 1, 2003, based on escalated cost and price assumptions as
evaluated in the Gilbert Report prepared by Gilbert (see "Oil and Gas
Reserves"). Information in respect of gross and net acres and well counts are as
at December 31, 2002, and information in respect of production is for the year
ended December 31, 2002 except where indicated otherwise. Due to the fact that
ARC Resources and ARC Sask. have been active at acquiring additional interests
in their principal properties, the working interest share and interest in gross
and net acres and wells as at December 31, 2002 may not directly correspond to
the stated production for the year which only includes production since the date
the interests were acquired by ARC Resources or ARC Sask.
NORTHERN ALBERTA AND BC
The Northern Alberta and BC area comprise a wide geographic area consisting of
operations north of Edmonton and in northeast British Columbia. ARC Resources
operates or has interests in numerous properties of which the major ones, Ante
Creek, Dunvegan and House Mountain, are discussed below.
ANTE CREEK
ARC Resources owns an average working interest of 94 percent in 61,760 gross
acres in the partially developed Ante Creek Montney A pool, which produces sweet
light crude oil. During 2002 production from the area averaged 2,381 boe/d of
oil, gas, and natural gas liquids net to ARC Resources. In 2002, ARC Resources
recorded 100 percent drilling success in a development program that saw five
wells drilled. The first of ten wells planned for the next phase of the program
were drilled in late 2002 and the program continued into early 2003. Gilbert
assigned Established Reserves of 18,698 mboe of oil, gas and natural gas liquids
to this area.
DUNVEGAN GAS UNIT NO. 1
ARC Resources has a working interest in this natural gas unit of 5.1 percent.
The Dunvegan field was discovered in the early 1970s, and remains a hub of
development activity. Net production to ARC Resources in 2002 averaged 628
boe/d. Established Reserves of 4,350 mboe of gas and natural gas liquids were
assigned to this unit by Gilbert.
HOUSE MOUNTAIN UNIT NO. 1
ARC Resources owns a 9.2 percent working interest in this light crude oil unit
in the Beaverhill Lake formation operated by Apache Canada Ltd. ARC Resources'
share of net production averaged 447 boe/d in 2002 following a waterflood
optimization program and horizontal re-entry drilling. The Established Reserves
determined by Gilbert for this unit was 2,219 mboe of oil, gas and natural gas
liquids. Development activities are continuing in 2003 and will include further
horizontal re-entry drilling, well re-activations, fracture stimulations and
further waterflood optimization.
14
PEMBINA
The Pembina Cardium area is located approximately 75 miles west of Edmonton and
contains the largest conventional oilfield ever discovered in Canada. The field
extends over an area of 800 square miles and contains an estimated 7.44 billion
barrels of original oil in place. There are numerous ARC Resources properties of
which MIPA, Berrymoor and Lindale are discussed below.
MIPA
Through a series of acquisitions ARC Resources now holds close to a 100 percent
working interest in the MIPA producing properties. Development activity during
the year focused on maintaining production through a well optimization program,
improving water injection support and reducing operating expenses. These efforts
will continue in 2003 along with further detailed engineering and geological
work to identify drilling and recompletion opportunities. Net production to ARC
Resources in 2002 from this area averaged 1,552 boe/d. The Established Reserves
determined by Gilbert for this area are 12,447 mboe of oil, gas and natural gas
liquids.
BERRYMOOR CARDIUM UNIT
ARC Resources owns a 41.3 percent working interest in the Berrymoor Cardium Unit
which is operated by Imperial Oil. The unit produces high quality 40(degree) API
crude oil from the Cardium formation and is under waterflood. Gilbert allocated
Established Reserves of 6,726 mboe to this unit and ARC Resources' net
production from the unit in 2002 averaged 817 boe/d. Annual oil well and
injection well workover/stimulation programs are scheduled to maintain
production and injection rates in 2003.
LINDALE CARDIUM UNIT
With its 54.4 percent working interest, ARC Resources operates the Lindale
Cardium Unit. In 2002, development activity was focused on maintaining
production through well optimization and improvements to water injection
support. Development plans for 2003 include identification of stimulation
opportunities and optimization of the waterflood to support production. This
area contributed an average of 549 boe/d of net production to ARC Resources in
2002 and the Gilbert Report assigned Established Reserves to this unit of 2,964
mboe.
CENTRAL ALBERTA
The Central Alberta area is located in west central Alberta between Calgary and
Red Deer. The major ARC Resources interests at Sundre, East Garrington and
Caroline are discussed below.
SUNDRE ELKTON UNITS
The Sundre Rundle B Unit and Sundre Unit No. 1 are both operated by ARC
Resources which has an average working interest in the units of 75 percent.
These units produce oil from the Elkton formation and have been under waterflood
since the 1960s. These units contributed average net production of 1,030 boe/d
to the Trust in 2002. Established Reserves of 7,007 mboe have been assigned to
these two units in the Gilbert Report. In 2002 production was enhanced through
pump upgrades, well workovers and the start of a horizontal re-entry drilling
project. A waterflood optimization program and other development activities are
anticipated in 2003.
15
EAST GARRINGTON
East Garrington produces sweet, liquids-rich gas and sweet light crude oil from
the Mannville and Cardium formations. ARC Resources operates production in the
area, with an average working interest of 90 percent. During 2002, recompletions
were undertaken as well as pump upgrades and well workovers. Net production
volume to ARC Resources averaged 866 boe/d in 2002 with Established Reserves
evaluated in the Gilbert Report at 3,063 mboe. During 2003 additional
recompletions will be undertaken.
CAROLINE SWAN HILLS GAS UNIT NO. 1
Shell Canada Ltd. operates this major natural gas unit. ARC Resources' working
interest of 2.2 percent contributed an average of 1,433 boe/d net to ARC
Resources in 2002. Established Reserves of gas and natural gas liquids assigned
by Gilbert for this unit are 2,726 mboe. Shell plans to add additional
compression in 2003 to maintain production.
CAROLINE CARDIUM E POOL SOUTH UNIT
This property is operated by ARC Resources and produces light sweet crude oil
with associated gas and liquids. ARC Resources has over a 94 percent working
interest and net production averaged 582 boe/d in 2002 with Established Reserves
assigned by Gilbert of 2,133 mboe. In 2002, development activity was focused on
maintaining production through well optimization and improvements to water
injection support.
SOUTHEAST ALBERTA & SOUTHWEST SASKATCHEWAN
This area straddles the Alberta-Saskatchewan border and the two largest ARC
Resources fields, Jenner and Brooks, are discussed below.
JENNER
Jenner is ARC Resources' second largest producing property with average daily
production volumes in 2002 of 2,348 boe/d net to ARC Resources. Through an
active acquisition program in 2002, ARC Resources now holds an average working
interest of 91 percent in this area. Gilbert evaluated this area as having
12,034 mboe of Established Reserves. In 2002, ARC Resources optimized and
recompleted several shallow gas wells. Plans for 2003 include additional 80 acre
infill wells to be drilled in the primary shallow gas productive zone.
BROOKS
The Brooks shallow gas field, which averaged 1,943 boe/d in 2002 net to ARC
Resources is ARC Resources' fourth largest production area. ARC Resources
operates the field and holds an average 93 percent working interest in the area.
Established Reserves allocated to this area by Gilbert are 6,063 mboe. Activity
in 2002 included the drilling and tie-in of four shallow gas wells.
SOUTHEAST SASKATCHEWAN
The southeast Saskatchewan area is located southeast of Regina near Weyburn,
Saskatchewan. ARC Resources has working interests in several oil operations of
which Lougheed, Weyburn and Midale are discussed in more detail.
16
LOUGHEED
The Lougheed area is ARC Resources' highest volume producing property with
average production of 2,881 boe/d net to ARC Resources in 2002 and is a major
focus of development activity. ARC Resources has a high working interest in the
area, including a 98.6 percent interest in the ARC Resources-operated Lougheed
Unit. Gilbert estimated Established Reserves of 10,205 mboe for this area. The
past year saw the drilling of five operated horizontal wells and the conversion
of two wells to injection. A gas plant was brought on stream in early 2002 which
has added value via liquids recovery from rich solution gas in addition to a
reduction of sour gas flaring. In addition to development work, ARC Resources'
growth strategy for the area resulted in acquisitions to consolidate working
interests and gain additional interests in operated lands. During 2003 ARC
anticipates drilling several new production wells and plans to convert some
wells to water injection with the objective of enhancing the recovery of
reserves in place.
MIDALE UNIT
ARC Resources is the second largest working interest owner in the Midale Unit
and holds 15.5 percent interest in the Unit with production volumes in 2002
averaging 1,245 boe/d net to ARC Resources and Established Reserves of 6,503
mboe assigned to the property by Gilbert. Operated by Apache Canada Ltd.,
activities have focused on development and horizontal drilling to enhance the
performance of the waterflood. In addition, Apache is conducting engineering
studies for the second phase of a carbon dioxide flood demonstration project.
Drilling of infill development wells continued in 2002 along with monitoring and
optimization of the waterflood. It is expected that these and other drilling and
optimization activities will continue in 2003.
WEYBURN UNIT
ARC Resources is the third largest working interest owner in the Weyburn Unit,
which is operated by EnCana. ARC Resources has a working interest of 6.5
percent, with Gilbert assigning Established Reserves to the unit of 9,717 mboe.
Average production volumes to ARC Resources in this area for 2002 were 1,391
boe/d. The operator continues to optimize a large-scale carbon dioxide injection
scheme to augment an existing waterflood program in order to increase the
recovery of oil reserves. Activities in 2002 included infill drilling to improve
waterflood and carbon dioxide flood production and recoveries. EnCana will
continue to monitor the performance of the flood, adjust injection practices and
drill additional infill wells in 2003. The success of the carbon dioxide flood
recovery scheme is expected to lead to further phases of tertiary oil recovery
in this large field.
SOUTHEAST SASKATCHEWAN - OTHER PROPERTIES
ARC Resources currently produces an average of 3,520 boe/d net to ARC Resources
from other southeast Saskatchewan properties. Alida and Queensdale are
representative of several smaller properties in this area that produce high
quality 30(degree) to 42(degree) API crude oil from various formations. ARC
Resources drilled nine wells on a number of properties in southeast Saskatchewan
in 2002. Based on 2002 results further locations have been identified to be
drilled in 2003. ARC Resources' working interests in the new wells range from 50
to 100 percent.
OIL AND GAS RESERVES
Gilbert, independent petroleum consultants of Calgary, Alberta have prepared the
Gilbert Report evaluating as at January 1, 2003, the crude oil, natural gas,
natural gas liquids, and sulphur reserves attributable to the Properties
utilizing the most recent Gilbert product price forecasts effective April 1,
2003. THE GILBERT REPORT EVALUATES THE RESERVES ATTRIBUTABLE TO ARC RESOURCES
AND ARC SASK. PRIOR TO THE STAR TRANSACTION AND PRIOR TO PROVISION FOR INCOME
TAXES, INTEREST, DEBT SERVICE CHARGES
17
AND GENERAL AND ADMINISTRATIVE EXPENSES.
THE PROBABLE ADDITIONAL RESERVES (SET FORTH AS "RISKED PROBABLE" BELOW) AND THE
PRESENT WORTH VALUE OF SUCH RESERVES AS SET FORTH IN THE TABLES BELOW HAVE BEEN
REDUCED BY 50% TO REFLECT THE DEGREE OF RISK ASSOCIATED WITH RECOVERY OF SUCH
RESERVES. IT SHOULD NOT BE ASSUMED THAT THE DISCOUNTED FUTURE NET PRODUCTION
REVENUES ESTIMATED BY GILBERT REPRESENT THE FAIR MARKET VALUE OF THE RESERVES.
Other assumptions and qualifications relating to costs, prices for future
production and other matters are summarized in the notes following the tables.
PETROLEUM AND NATURAL GAS RESERVES OF ARC RESOURCES AND
ARC SASK PRIOR TO STAR TRANSACTION AND NET CASH FLOWS
ESCALATING COST AND PRICE CASE
COMPANY INTEREST RESERVES PRESENT WORTH OF FUTURE NET CASH FLOW
----------------------------------- ---------------------------------------------
CRUDE OIL AND
NATURAL GAS LIQUIDS NATURAL GAS
(MMBBL) (BCF) UNDISCOUNTED DISCOUNTED AT
------------------- --------------- ------------ ------------------------------
10% 15% 20%
------- ------- -------
($MM) ($MM)
GROSS NET GROSS NET
----- --- ----- ---
Proved
Producing 79.4 68.1 296.8 236.1 2,019.9 1,156.7 973.9 849.6
Non-Producing 17.0 14.6 59.6 45.8 384.8 165.3 119.2 89.0
----- ----- ----- ----- ------- ------- ------- -------
Total Proved 96.4 82.6 356.5 281.9 2,404.7 1,322.0 1,093.1 938.6
Total Proved Plus Probable 138.3 118.5 461.4 364.7 3,475.6 1,629.9 1,304.3 1,094.8
Risked Probable 20.9 17.9 52.5 41.4 535.5 154.0 105.6 78.1
Total Proved Plus
Risked Probable 117.3 100.6 408.9 323.3 2,940.1 1,475.9 1,198.7 1,016.7
===== ===== ===== ===== ======= ======= ======= =======
PETROLEUM AND NATURAL GAS RESERVES OF ARC RESOURCES AND
ARC SASK PRIOR TO STAR TRANSACTION AND NET CASH FLOWS
CONSTANT COST AND PRICE CASE
COMPANY INTEREST RESERVES PRESENT WORTH OF FUTURE NET CASH FLOW
----------------------------------- ---------------------------------------------
CRUDE OIL AND
NATURAL GAS LIQUIDS NATURAL GAS
(MMBBL) (BCF) UNDISCOUNTED DISCOUNTED AT
------------------- --------------- ------------ ------------------------------
10% 15% 20%
------- ------- -------
($MM) ($MM)
GROSS NET GROSS NET
----- --- ----- ---
Proved
Producing 80.9 69.2 298.2 237.2 3,061.8 1,632.9 1,344.0 1,150.3
Non-Producing 17.2 14.4 59.7 45.7 594.9 276.2 206.7 160.4
----- ----- ----- ----- ------- ------- ------- -------
Total Proved 98.1 83.5 357.9 283.0 3,656.7 1,909.1 1,550.7 1,310.7
Total Proved Plus Probable 139.7 118.8 462.9 365.8 5,134.6 2,367.0 1,871.3 1,551.5
Risked Probable 20.8 17.6 52.5 41.4 739.0 229.0 160.3 120.4
Total Proved Plus
Risked Probable 118.9 101.2 410.4 324.4 4,395.6 2,138.1 1,711.0 1,431.1
===== ===== ===== ===== ======= ======= ======= =======
Notes:
(1) Columns may not add due to rounding.
18
(2) The following definitions have been used in the Gilbert Report:
(a) "Proved Reserves" means those reserves estimated as recoverable
under current technology and existing economic conditions in the
case of constant price and cost analyses and anticipated economic
conditions in the case of escalated price and cost analyses, from
that portion of a reservoir which can be reasonably evaluated as
economically productive on the basis of analysis of drilling,
geological, geophysical and engineering data, including the
reserve to be obtained by enhanced recovery processes demonstrated
to be economic and technically successful in the subject
reservoir.
The proved reserves were subdivided into producing and
non-producing categories, consistent with National Policy
Statement 2-B of the Canadian Securities Administrators. The
non-producing reserves were not further divided into developed and
undeveloped reserves.
The proved reserves were sub-divided into the following
classifications, depending on their status of development:
(i) "Producing Reserves" are those reserves that are
actually on production and could be recovered from
existing wells and facilities or, if facilities have
not been installed, that would involve a small
investment relative to cash flow. In multi-well pools
involving a competitive situation, reserves may be
subdivided into producing and non-producing reserves
in order to reflect allocation of reserves to
specific wells and their respective development
status.
(ii) "Non-producing Reserves" means those reserves that
are not classified as producing.
(b) "Probable Reserves" are those reserves which analysis of drilling,
geological, geophysical and engineering data does not demonstrate
to be proved, but where such analysis suggests the likelihood of
their existence and future recovery under current technology and
existing or anticipated economic conditions. Probable additional
reserves to be obtained by the application of enhanced recovery
processes will be the increased recovery over and above that
estimated in the proved category which can be realistically
estimated for the pool on the basis of enhanced recovery processes
which can be reasonably expected to be instituted in the future.
(c) "Pipeline Gas Reserves" are gas reserves remaining after deducting
surface losses due to process shrinkage and raw gas used as lease
fuel.
(d) "Gross Reserves" are defined as the total remaining
recoverable reserves associated with the acreage of interest.
(e) "Company Interest Gross Reserves" are defined as the remaining
reserves owned by ARC Resources and ARC Sask., before
deduction of any royalties.
(f) "Company Interest Net Reserves" are defined as the gross
remaining reserves of the properties in which ARC Resources
and ARC Sask. have an interest, less all royalties and
interest owned by others.
(g) "Net Production Revenue" is income derived from the sale of
net reserves of oil, pipeline gas and gas by-products, less
all capital and operating costs.
(3) THE GILBERT REPORT FORECASTS OF UNRISKED PROBABLE RESERVES AND VALUES HAVE
BEEN REDUCED BY 50% TO REFLECT THE DEGREE OF RISK ASSOCIATED WITH THE
RECOVERY OF SUCH RESERVES.
(4) The Gilbert Report used the average yearly product prices from Gilbert's
then current price forecasts (at April, 2003) for natural gas, oil and
condensate, as outlined in the following table:
19
EDMONTON ALBERTA
WTI CUSHING PAR PRICE PENTANES SPOT PLANT BC SPOT
OKLAHOMA* 40 API PROPANE BUTANE PLUS GATE AVERAGE HENRY HUB PLANT GATE
YEAR $US/bbl $/bbl $/bbl $/bbl $/bbl $/MMBTU $US/MMBTU CDN$/MMBTU
---- ------- ----- ----- ----- ----- ------- --------- ----------
2003 30.75 44.50 29.75 33.25 45.00 6.35 5.25 6.60
2004 25.00 36.00 23.25 25.00 36.50 5.20 4.25 5.20
2005 23.00 33.00 21.00 23.00 33.50 4.85 4.00 4.85
2006 23.00 33.00 21.00 23.00 33.50 4.85 4.00 4.85
2007 23.00 33.00 21.00 23.00 33.50 4.85 4.00 4.85
2008 23.00 33.00 21.00 23.00 33.50 4.90 4.05 4.90
2009 23.00 33.00 21.00 23.00 33.50 5.00 4.10 5.00
2010 23.25 33.50 21.50 23.50 34.00 5.10 4.20 5.10
2011 23.75 34.00 21.75 24.00 34.50 5.20 4.25 5.20
2012 24.00 34.50 22.00 24.50 35.00 5.30 4.30 5.30
2013 24.50 35.00 22.50 24.75 35.50 5.40 4.35 5.40
Thereafter +1.5%/yr +1.5%/yr +1.5%/yr +1.5%/yr +1.5%/yr +1.5%/yr +1.5%/yr +1.5%/yr
* 40 degrees API, 0.43% sulphur.
Operating and capital costs have been escalated at 1.5% annually.
(5) The constant cost and price evaluation was based upon December 31, 2002
prices as outlined in the following table:
EDMONTON ALBERTA
WTI CUSHING PAR PRICE PENTANES SPOT PLANT BC SPOT
OKLAHOMA* 40 API PROPANE BUTANE PLUS GATE AVERAGE AECO SPOT PLANT GATE
$US/bbl $/bbl $/bbl $/bbl $/bbl $/MMBTU $/MMBTU CDN$/MMBTU
------- ----- ----- ----- ----- ------- ------- ----------
31.20 49.29 35.54 38.04 50.29 5.82 6.02 5.72
* 40 degrees API, 0.43% sulphur.
Operating and capital costs were not escalated.
(6) The $US/$Cdn exchange rate is assumed to be $0.675 to $0.68 throughout the
period of the Gilbert Report.
(7) The Gilbert Report estimates total capital expenditures (net to ARC
Resources and ARC Sask.) to achieve the estimated future net revenues from
the Proved Reserves based upon escalating cost and price assumptions to be
$200 million with $76 million, $36 million and $22 million of such costs
estimated for the calendar years 2003, 2004 and 2005, respectively. The
corresponding costs to achieve the estimated future net revenues from
Proved Reserves plus one half of Probable Reserves ("Established Reserves")
are $256 million with $83 million, $53 million and $28 million of such
costs estimated for the calendar years 2003, 2004 and 2005, respectively.
(8) The Gilbert Report estimates total capital expenditures (net to ARC
Resources and ARC Sask.) to achieve the estimated future net revenues from
the Proved Reserves based upon constant cost and price assumptions to be
$190 million with $75 million, $36 million and $21 million of such costs
estimated for the calendar years 2003, 2004 and 2005, respectively. The
corresponding costs to achieve the estimated future net revenues from the
Established Reserves are $242 million with $83 million, $52 million and $28
million of such costs estimated for the calendar years 2003, 2004 and 2005,
respectively.
(9) The Gilbert Report provides for estimated well abandonment and site
restoration costs, but does not provide for facilities abandonment and
reclamation costs.
(10) The benefit of ARTC eligibility has been included in the Gilbert Report on
the assumption that the existing ARTC program remains in place. On both a
Proved Reserve and an Established Reserve basis, the ARTC value discounted
at 12% is $8.8 million.
20
ESTIMATED FUTURE NET PRE-TAX CASH FLOWS &
ESTABLISHED RESERVES OF ARC RESOURCES AND
ARC SASK. PRIOR TO STAR TRANSACTION
ESCALATING COST AND PRICE CASE
($MM)
ROYALTY
BURDENS NET
COMPANY AFTER GAS REVENUE OPERATING NET NET NET CASH FLOW
INTEREST PROCESSING AFTER AND OTHER PRODUCTION OTHER ABANDONMENT CAPITAL BEFORE INCOME
YEAR REVENUE(1) ALLOWANCE(2) ROYALTY(2) EXPENSES REVENUE(3) INCOME COSTS INVESTMENT TAXES(4)(5)
---- ---------- ------------ ---------- -------- ---------- ------ ----- ---------- -----------
2003 606.3 115.8 490.5 96.4 394.0 (32.2) 2.5 83.4 275.9
2004 486.0 88.9 397.1 96.8 300.3 5.7 2.5 52.6 250.9
2005 418.1 74.5 343.6 95.0 248.6 5.6 2.6 28.4 223.3
2006 378.1 65.4 312.7 92.9 219.8 5.3 2.6 13.9 208.6
2007 335.3 56.7 278.6 88.9 189.7 5.0 2.7 9.8 182.3
2008 300.8 49.5 251.2 85.0 166.2 4.7 2.7 9.6 158.6
2009 272.4 43.7 228.7 81.9 146.7 4.4 2.7 5.5 142.9
2010 251.9 39.8 212.1 79.2 132.9 4.0 2.8 4.7 129.4
2011 233.6 36.6 197.0 76.5 120.6 3.7 2.8 5.9 115.6
2012 221.4 34.8 186.6 72.9 113.7 3.2 2.9 6.5 107.5
2013 207.0 32.4 174.6 67.5 107.1 2.7 2.9 4.6 102.3
2014 193.4 29.8 163.6 64.7 99.0 2.5 2.9 3.6 94.9
Remainder 2,401.0 330.0 2,071.0 1,037.4 1,033.7 52.5 111.2 27.0 947.9
Total 6,305.2 997.9 5,307.3 2,034.9 3,272.4 67.1 143.8 255.6 2,940.1
Net Cash Flow Before Income Taxes(5) Discounted to January 1, 2003 at:
10%: $1,476 million
12%: $1,349 million
15%: $1,199 million
Notes:
(1) Includes working interest revenue and royalty interest revenue.
(2) Net of ARTC.
(3) Company interest revenue less royalty burdens (net of ARTC) and operating
and other expenses.
(4) Undiscounted.
(5) Cash flow before income taxes includes other income and hedging gains
(losses) and is stated prior to interest and general and administrative
expenses. Hedging gains (losses) for 2003 and 2004 are $(38.6) million and
$(0.4) million, respectively.
(6) Production for 2003 based on 15,361 mboe Proved Reserves plus 352 mboe for
50% Probable Reserves and for 2004, based on 14,519 mboe for Proved
Reserves plus 883 mboe for 50% Probable Reserves.
(7) Based on the Gilbert Report with a January 1, 2003 effective date.
(8) Columns may not add due to rounding.
21
ESTIMATED FUTURE NET PRE-TAX CASH FLOWS &
ESTABLISHED RESERVES OF ARC RESOURCES AND
ARC SASK. PRIOR TO STAR TRANSACTION
CONSTANT COST AND PRICE CASE
($MM)
ROYALTY
BURDENS NET
COMPANY AFTER GAS REVENUE OPERATING NET NET NET CASH FLOW
INTEREST PROCESSING AFTER AND OTHER PRODUCTION OTHER ABANDONMENT CAPITAL BEFORE INCOME
YEAR REVENUE(1) ALLOWANCE(2) ROYALTY(2) EXPENSES REVENUE(3) INCOME COSTS INVESTMENT TAXES(4)(5)
---- ---------- ------------ ---------- -------- ---------- ------ ----- ---------- -----------
2003 624.1 118.1 506.0 98.1 408.0 (33.4) 2.5 83.3 288.7
2004 616.6 115.9 500.7 98.3 402.4 1.5 2.5 51.8 349.5
2005 576.3 107.1 469.1 95.8 373.3 5.6 2.5 27.5 348.9
2006 521.3 94.2 427.1 92.4 334.8 5.3 2.5 13.3 324.3
2007 463.3 82.0 381.3 87.1 294.2 5.0 2.5 9.2 287.5
2008 414.4 71.2 343.1 82.1 261.1 4.6 2.5 8.9 254.3
2009 372.7 62.5 310.2 77.7 232.5 4.3 2.5 5.0 229.3
2010 339.3 55.8 283.4 74.0 209.4 4.0 2.5 4.3 206.6
2011 309.7 50.2 259.5 70.3 189.2 3.7 2.5 5.2 185.1
2012 288.2 46.7 241.5 66.0 175.5 3.2 2.5 5.7 170.4
2013 265.4 42.6 222.8 60.6 162.2 2.7 2.5 4.0 158.4
2014 243.7 38.4 205.3 57.0 148.3 2.5 2.5 3.1 145.2
Remainder 2,647.8 364.3 2,283.5 796.3 1,487.1 52.6 72.1 20.4 1,447.3
Total 7,682.7 1,249.1 6,433.6 1,755.6 4,678.0 61.5 102.1 241.8 4,395.6
Net Cash Flow Before Income Taxes(5) Discounted to January 1, 2003 at:
10%: $2,138 million
12%: $1,943 million
15%: $1,711 million
Notes:
(1) Includes working interest revenue and royalty interest revenue.
(2) Net of ARTC.
(3) Company interest revenue less royalty burdens (net of ARTC) and operating
and other expenses.
(4) Undiscounted.
(5) Cash flow before income taxes includes other income and hedging gains
(losses) and is stated prior to interest and general and administrative
expenses. Hedging gains (losses) for 2003 and 2004 are $(39.7) million and
$(4.6) million, respectively.
(6) Production for 2003 based on 15,359 mboe Proved Reserves plus 352 mboe for
50% Probable Reserves and for 2004, based on 14,532 mboe for Proved
Reserves plus 880 mboe for 50% Probable Reserves.
(7) Based on the Gilbert Report with a January 1, 2003 effective date.\
(8) Columns may not add due to rounding.
RECONCILIATION OF RESERVES
The following table provides a summary of the changes in working interest share
of crude oil, natural gas liquids and natural gas reserves before royalties
which occurred in the year ended December 31, 2002:
JANUARY 1, JANUARY 1,
2002 OPENING 2003 OPENING
BALANCE NET ADDITIONS REVISIONS PRODUCTION BALANCE
(mboe) (mboe) (mboe) (mboe) (mboe)
------ ------ ------ ------ ------
Total Proved 147,739 15,041 8,345 (15,485) 155,640
Risked Probable 30,757 1,572 (2,598) -- 29,731
------- ------ ----- ------- -------
Total Proved Plus Risked Probable 178,496 16,613 5,747 (15,485) 185,371
======= ====== ===== ======= =======
22
OTHER INFORMATION ABOUT THE PROPERTIES
The information provided below relates to all of the Properties and operations
of ARC Resources and ARC Sask. and various references to ARC Resources in this
section of the Annual Information Form should be read as including ARC Sask.
UNDEVELOPED LANDS
The following table sets out ARC Resources' undeveloped land holdings as at
December 31, 2002 as compiled by ARC Resources:
GROSS(1) NET(2)
-------- -------
(acres)
Alberta 457,682 204,500
British Columbia 38,185 11,203
Saskatchewan 60,582 41,180
Northwest Territories 51,588 25,794
------- -------
Total 608,037 282,678
======= =======
Notes:
(1) "Gross" refers to the total acres in which ARC Resources has an interest.
(2) "Net" refers to the total acres in which ARC Resources has an interest,
multiplied by the percentage working interest therein owned by ARC
Resources.
OIL AND GAS WELLS
The following table sets forth the number and status of wells in which ARC
Resources had a working interest as at December 31, 2002, which are producing or
which are shut-in but which ARC Resources considers to be capable of production:
PRODUCING SHUT-IN(1)
-------------------------------------------- -------------------------------------------
CRUDE OIL NATURAL GAS CRUDE OIL NATURAL GAS
-------------------- ---------------------- ------------------- --------------------
GROSS(2) NET(3) GROSS(2) NET(3) GROSS(2) NET(3) GROSS(2) NET(3)
-------- -------- -------- -------- -------- ------ -------- ------
Alberta 3,599 839.5 2,686 1,215.5 698 91.2 274 61.7
British Columbia 145 1.9 217 16.0 31 2.8 33 5.2
Saskatchewan 1,754 573.8 1,224 50.0 274 86.7 21 0.3
-------- -------- -------- -------- -------- ------ -------- ------
Total 5,498 1,415.2 4,127 1,281.5 1,003 180.7 328 67.2
======== ======== ======== ======== ======== ====== ======== ======
Notes:
(1) "Shut-in" wells means wells which have encountered and are capable of
producing crude oil or natural gas but which are not producing due to lack
of available transportation facilities, available markets or other reasons.
Shut-in natural gas wells in which ARC Resources has an interest are
located no further than five kilometres from gathering systems, pipelines
or other means of transportation.
(2) "Gross" wells are defined as the total number of wells in which ARC
Resources has an interest.
(3) "Net" wells are defined as the aggregate of the numbers obtained by
multiplying each gross well by ARC Resources' percentage working interest
therein.
(4) Royalty interest wells have been assigned a net number of zero. The table
does not include water injection wells.
23
PRODUCTION HISTORY
ARC Resources' approximate net production, before deduction of royalties, for
the periods indicated is summarized below.
2002 2001
----------------------------------------- -----------------------------------------
FOURTH THIRD SECOND FIRST FOURTH THIRD SECOND FIRST
QUARTER QUARTER QUARTER QUARTER QUARTER QUARTER QUARTER QUARTER
------- ------- ------- ------- ------- ------- ------- -------
Crude Oil (bbl/d) 20,256 20,809 20,366 21,196 20,753 20,066 20,202 20,614
Natural Gas (mmcf/d) 109.2 109.1 106.9 113.9 117.5 109.5 112.8 120.9
Natural Gas Liquids (bbl/d) 3,355 3,408 3,527 3,631 3,706 3,740 3,090 3,502
Total (boe/d 6:1) 41,808 42,394 41,713 43,805 44,034 42,056 42,097 44,271
The mix of ARC Resources' crude oil production and natural gas liquids for the
year ended December 31, 2002 was approximately 54% light quality crude oil
(35(degree) API or greater) and 23% medium quality crude oil (25(degree) API to
35(degree) API), 2% condensate and 12% natural gas liquids. Heavier gravity
(less than 25% API) crude oil accounted for only 9% of production.
Approximately 34% of ARC Resources' gross revenue is derived from natural gas
production with the remainder from crude oil and natural gas liquids. On a boe
(6:1) basis, production is split between crude oil and natural gas liquids as to
approximately 57% and natural gas as to approximately 43%.
DRILLING HISTORY
The following table sets forth the gross and net exploration and development
wells in which ARC Resources participated during the periods indicated.
YEAR ENDED DECEMBER 31,
-------------------------------------------
2002 2001
-------------------- --------------------
GROSS(1) NET(2) GROSS(1) NET(2)
-------- ------ -------- ------
Exploration
Oil 4 2.2 3 2.0
Gas 3 0.8 11 5.9
Dry 1 -- 3 2.0
-------- ------ -------- ------
Total Exploration 8 2.9 17 9.9
-------- ------ -------- ------
Development
Oil 82 26.1 112 43.3
Gas 161 19.4 128 56.4
Dry 4 1.5 3 0.2
Service 5 1.2 15 2.3
-------- ------ -------- ------
Total Development 252 48.2 258 102.2
-------- ------ -------- ------
Total 260 51.1 275 112.1
======== ====== ======== ======
Notes:
(1) "Gross Wells" means the number of wells in which ARC Resources has an
interest.
(2) "Net Wells" means the aggregate of the numbers obtained by multiplying each
gross well by ARC Resources' percentage working interest therein.
Wells shown as exploratory are supported by technical work including seismic
information from nearby wells, reservoir engineering and other activities
designed to minimize risk and are similar to moderate risk development
activities.
24
CAPITAL EXPENDITURES
The following table summarizes capital expenditures (net of dispositions) made
by ARC Resources for the periods indicated.
2002 2001
----------------------------------------- -----------------------------------------
FOURTH THIRD SECOND FIRST FOURTH THIRD SECOND FIRST
QUARTER QUARTER QUARTER QUARTER QUARTER QUARTER QUARTER QUARTER
------- ------- ------- ------- ------- ------- ------- -------
Property acquisitions, net 61,952 46,018 9,344 1,799 603 14,645 495 506,917
Development drilling 21,047 12,025 13,538 23,464 19,894 23,673 11,345 20,450
Production and facilities 4,265 3,115 2,944 4,033 7,166 5,749 4,077 5,978
Other 1,417 999 804 627 2,402 160 800 524
------- ------- ------- ------- ------- ------- ------- -------
Total 88,681 62,157 26,630 29,923 30,065 44,227 16,717 533,869
======= ======= ======= ======= ======= ======= ======= =======
NETBACK HISTORY
The following table sets forth information respecting average net product prices
received, royalties paid, operating expenses and netbacks received by ARC
Resources in respect of ARC Resources' production of crude oil, natural gas
liquids and natural gas for the periods indicated.
2002 2001
--------------------------------------- --------------------------------------
FOURTH THIRD SECOND FIRST FOURTH THIRD SECOND FIRST
QUARTER QUARTER QUARTER QUARTER QUARTER QUARTER QUARTER QUARTER
------- ------- ------- -------- ------- ------- ------- -------
Average Net Production
Prices Received
Crude Oil ($/bbl) $30.20 $33.68 $32.40 $30.22 $27.33 $33.27 $33.79 $32.57
Natural Gas ($/mcf) 5.26 4.11 4.67 3.61 4.04 4.45 5.86 8.45
Natural Gas Liquids ($/bbl) 27.49 25.23 23.38 20.17 22.20 29.61 35.95 38.12
Oil Equivalent ($/boe 6:1) 30.58 29.13 29.69 25.58 25.31 30.05 34.53 41.26
Royalties Paid
Crude Oil ($/bbl) $6.95 $7.87 $6.30 $5.14 $5.47 $7.44 $6.70 $6.64
Natural Gas ($/mcf) 1.01 0.49 0.79 0.59 0.60 0.95 1.28 2.13
Natural Gas Liquids ($/bbl) 7.54 6.09 6.43 5.23 5.60 7.30 10.99 11.35
Oil Equivalent ($/boe 6:1) 6.48 5.51 5.58 4.45 4.65 6.67 7.45 9.79
Operating Expenses(1)(2)
Crude Oil ($/bbl) $7.31 $7.23 $7.08 $7.84 $6.10 $7.17 $7.03 $5.90
Natural Gas ($/mcf) 1.00 0.95 0.92 0.82 0.94 0.63 0.66 0.72
Natural Gas Liquids ($/bbl) 4.77 6.77 5.68 5.93 4.42 5.39 4.85 4.84
Oil Equivalent ($/boe 6:1) 6.54 6.54 6.30 6.41 5.75 5.54 5.51 5.09
Netback Received
Crude Oil ($/bbl) $15.95 $18.58 $19.02 $17.23 $15.76 $18.66 $20.06 $20.04
Natural Gas ($/mcf) 3.25 2.67 2.96 2.20 2.50 2.87 3.92 5.61
Natural Gas Liquids ($/bbl) 15.18 12.37 11.28 9.01 12.18 16.92 20.11 21.92
Oil Equivalent ($/boe 6:1) 17.56 17.08 17.81 14.72 14.91 17.85 21.57 26.37
Notes:
(1) Operating expenses are composed of direct costs incurred to operate both
oil and gas wells. A number of assumptions have been made in allocating
these costs between oil, natural gas and natural gas liquids production.
(2) Operating recoveries associated with operated properties were excluded from
operating costs and accounted for as a reduction to general and
administrative costs.
FUTURE COMMITMENTS
The Trust is exposed to market risks resulting from fluctuations in commodity
prices, foreign exchange rates and interest rates in the normal course of
operations. A variety of derivative instruments are used by
25
the Trust to reduce its exposure to fluctuations in commodity prices and foreign
exchange rates. The Trust is exposed to losses in the event of default by the
counterparties to these derivative instruments. The Trust manages this risk by
diversifying its derivative portfolio amongst a number of financially sound
counterparties.
Information respecting the Trust's financial instruments is contained in Note 10
to the Trust's audited consolidated financial statements for the year ended
December 31, 2002 and under the heading "Hedging" in the Trust's management
discussion and analysis for the year ended December 31, 2002 and which is
contained on page 38 of the Trust's 2002 Annual Report, both of which are
incorporated herein by reference.
MARKETING ARRANGEMENTS
NATURAL GAS
During 2002, ARC Resources continued its marketing strategy to diversify its
sales and transportation portfolio and increase the level of direct control over
the marketing of its natural gas production. This diversity provides the
combination of control and risk-management required to maximize production
netbacks.
The average natural gas price received during 2002 was $4.41 per mcf as compared
to $5.72 for 2001. This price was achieved with a portfolio mix that on average
through the year received fixed pricing for 28% of total production, AECO
pricing for 45%, NYMEX pricing for 17% and Station #2 pricing for the remaining
10% of production.
To manage natural gas price volatility and to stabilize the revenue stream, the
natural gas portfolio is directed towards maintaining:
1. a balanced exposure to both U.S., Canadian and fixed price markets;
2. market-sensitive and hedgeable pricing terms and contract flexibility; and
3. a high utilization of contracted pipeline and processing capacity.
CRUDE OIL AND NATURAL GAS LIQUIDS
Liquids production in 2002 was comprised of approximately 54% light quality
crude oil (greater than 35(degree) API), 23% medium quality crude oil
(25(degree) to 35(degree) API), 2% condensate and 12% natural gas liquids.
Heavier quality crude oil (less than 25(degree) API) accounted for only 9% of
production.
During 2002, average sales prices were $31.63 per bbl for oil and $24.01 per bbl
for natural gas liquids; these prices compare to 2001 prices of $31.70 per bbl
for oil and $31.03 per bbl for natural gas liquids. Crude oil is sold under
30-day evergreen contracts while natural gas liquids are sold under annual
arrangements. Industry pricing benchmarks for crude oil and natural gas liquids
are continuously monitored to ensure optimal netbacks.
HEDGING
ARC Resources' Board of Directors has approved a hedging program under which
financial and physical hedges can be entered into in respect of commodity prices
and foreign currency exchange rates. The Board has approved the hedging of up to
70% of the Trust's oil and natural gas liquids production for up to 12 months
and up to 35% of oil and natural gas liquids production for the period
commencing one year
26
in the future for a maximum of 12 months. With respect to natural gas hedging,
the Board has approved the hedging of up to 70% of the Trust's natural gas
production for up to 24 months and for the 36 month period thereafter (years
three to five in the future) up to 35% of natural gas production. The above
limits are restricted to a maximum of 50% on a boe basis for up to 12 months, up
to 25% on a boe basis for the 12 month period thereafter (year two in the
future) and up to 15% on a boe basis for the 36 month period thereafter (years
three to five in the future).
A summary of financial and physical contracts in respect of hedging activities
can be found in Note 10 to the Trust's audited consolidated financial statements
for the year ended December 31, 2002 and under the heading "Hedging" in the
Trust's management discussion and analysis for the year ended December 31, 2002
and which is contained on page 38 of the Trust's 2002 Annual Report, both of
which are incorporated herein by reference.
ACQUISITIONS AND DISPOSITIONS
ARC Resources made numerous minor property acquisitions and dispositions during
the more recently completed financial year. In aggregate, net of minor
dispositions, ARC Resources made $119 million of net acquisitions in 2002
concentrated in and around existing core areas. The largest acquisition in 2002
was the purchase of two oil and gas properties for $71.1 million in the Ante
Creek and Brown Creek areas.
RECENT DEVELOPMENTS
ACQUISITION OF STAR OIL & GAS LTD.
On March 31, 2003, ARC Resources and the Trust entered into the Share Sale
Agreement to acquire all of the outstanding shares and retire the debt of Star,
a private Canadian company, for total consideration of $710 million subject to
final adjustments (the "Star Transaction"). The Star Transaction was completed
on April 16, 2003.
In related transactions, ARC Resources entered into agreements to sell certain
working, royalty and other interests of Star (the "Property Dispositions") to
third parties for $78.2 million. The Property Dispositions were completed on or
prior to May 1, 2003.
Star is a gas focused, Alberta based company whose primary producing areas are
the Dawson, Pouce Coupe and Hatton gas fields. Net of the Property Dispositions,
approximately 75 per cent of Star's 20,000 boe/d of current production is
natural gas with just over half of the production coming from three fields.
With these transactions, the natural gas component of ARC Resources' production
increases to approximately 55 per cent (from 44 per cent prior to the
transactions) providing better commodity balance for the Trust. The natural gas
component of proved reserves increases to approximately 50 per cent (from 38 per
cent prior to the transactions).
The net acquisition price for the transaction of $631.8 million, prior to
adjustments, was funded through a combination of bank debt and through the
issuance to the vendor of the Special Debenture in the principal amount of $320
million. In conjunction with this transaction, ARC Resources' credit facilities
were increased to $650 million while outstanding debt post-closing and after the
Property Dispositions is approximately $500 million (excluding the Special
Debenture and prior to proposed second quarter asset sales).
27
The Star Transaction was structured so that the Trust issued to the vendor the
Special Debenture which entitled it to acquire the Underlying Debentures. The
Trust intends to file a short form prospectus to ensure that the Underlying
Debentures and underlying Trust Units are freely tradeable.
For a detailed description of the Special Debenture and the Underlying
Debentures, see "Information Relating to the Trust - Special Debenture" and
"Information Relating to the Trust - Underlying Debentures".
ARC Resources plans to sell approximately 4,000 boe/d of non-core properties
from its existing asset base in 2003 and proceeds from this sale will be
directed towards reducing debt incurred pursuant to the Star Transaction.
Effective April 16, 2003, following the completion of the Star Transaction, a
number of transactions involving the Trust, ARC Resources and ARC Sask. were
completed pursuant to which ARC Resources amalgamated with Star and disposed of
the oil and gas properties located in the Province of Saskatchewan, which were
formerly held by Star, to ARC Sask. for fair market value.
SELECTED PRO-FORMA COMBINED OPERATIONAL INFORMATION
The following table sets our certain operational information for Star and the
Trust on a pro forma combined basis after giving effect to the Star Transaction,
the Property Dispositions and certain other adjustments.
TRUST STAR(1) PRO FORMA
----- ------- ---------
AVERAGE DAILY PRODUCTION
(FOR THREE MONTHS ENDED MARCH 31, 2003) 24,761 6,728 31,489
Oil & NGL (Bbls/d) 117,310 88,000 205,310
Natural gas (Mcf/d)
PROVED RESERVES (as at January 1, 2003)
Oil & NGL (Mbbls) 96,401 14,972 111,373
Natural gas (Bcf) 356 313 669
PROVED AND RISKED PROBABLE RESERVES (as at January 1,
2003)
Oil & NGL (Mbbls) 117,332 18,163 135,495
Natural gas (Bcf) 409 372 781
VALUE OF PROVED AND RISKED PROBABLE RESERVES -
DISCOUNTED (as at January 1, 2003)
at 10% ($million) 1,476 716 2,192
at 15% ($million) 1,349 586 1,935
PROVED AND RISKED PROBABLE RESERVE LIFE INDEX (as at
January 1, 2003) (Years) 11.5 10.3 11.1
NET UNDEVELOPED LAND (acres) (as at January 1, 2003) 282,678 328,928 611,606
Note:
(1) After giving effect to the Property Dispositions.
ARC Resources is conducting a complete review of capital expenditures for 2003
for the combined asset base and some part of the currently budgeted capital
program on the combined asset base may be deferred until 2004 and the pro-forma
combined production may decrease over the course of 2003, in order to allow time
for the implementation of updated development and optimization plans.
For historical financial information in respect of Star, reference is made to
the Consolidated Financial Statements of Star for the years ended December 31,
2002, 2001 and 2000 and for the three months ended March 31, 2003 and 2002
attached as Appendix "A" to this Annual Information Form.
28
Pro-Forma Financial Statements of the Trust are attached as Appendix "B" to this
Annual Information Form.
DESCRIPTION OF THE NEW PROPERTIES
The following is a description of the principal oil and natural gas properties
of Star as at December 31, 2002, acquired by ARC Resources pursuant to the Star
Transaction other than those which were disposed of pursuant to the Property
Dispositions. The term "net", when used to describe ARC Resources' share of
production, means the total of ARC Resources' or ARC Sask.'s working interest
share before deducting royalties owned by others. Reserve amounts are stated,
before deduction of royalties, at January 1, 2003, based on escalated cost and
price assumptions as evaluated in the New Gilbert Report prepared by Gilbert
(see "Oil and Gas Reserves of the New Properties"). Information in respect of
gross and net acres and well counts are as at December 31, 2002, and in respect
of production is for the year ended December 31, 2002, except where indicated
otherwise.
Star's asset base was a portfolio of high working interest gas weighted
properties. The top three properties, Dawson, Pouce Coupe and Hatton account for
over 50 per cent of production, while the top six properties account for
approximately 70 per cent of production. The major properties contain numerous
low risk development drilling opportunities.
POUCE COUPE
Pouce Coupe is located 500 km northwest of Edmonton in Alberta and ARC Resources
has an average working interest of 70% in the area. Production consists of sweet
and sour gas from 31 wells. Production is from multiple zones including the
Kistkatinaw, Baldonnel, Halfway, Doig and Montney. Gilbert assigned Established
Reserves of 5,725 mboe of gas and natural gas liquids to this area. Continued
recompletion and drilling activities are planned for 2003.
HATTON
Hatton is located in southwest Saskatchewan and ARC Sask has varied working
interests ranging from 0% to 100% in this area. The production is predominantly
sweet dry natural gas from 1,900 wells in the Medicine Hat, Milk River, and
Second White Spec zones. Of the 1,900 wells, 700 are operated by ARC Sask.
During 2003 development drilling will be undertaken to increase production and
reserves. As at January 1, 2003 Gilbert assigned Established Reserves of 111.9
bcf of gas to this area.
DAWSON
Dawson is located in British Columbia 520 km northwest of Edmonton, Alberta, and
ARC Resources has an average working interest of 95%. The production is
predominantly from the Montney productive horizon and primarily produces sour
natural gas from 34 wells. Gilbert assigned Established Reserves of 146 bcf of
gas and 1.3 mboe of natural gas liquids to this area. 2003 plans include
installing a compressor as well as additional drilling and recompletion
projects.
CHINCHAGA
Chinchaga is located 600 km northwest of Edmonton, Alberta and primarily
produces sweet liquids rich natural gas. This area produces gas from the Slave
Point horizon. ARC Resources' working interests in 3 producing wells range
between 60% and 100%, and ARC Resources intends to perform tie in and completion
work in 2003. Established Reserves of 8.5 bcf of gas and 671 mboe of natural gas
liquids were assigned to this area by Gilbert.
29
SWAN HILLS
ARC Resources has an average working interest of 89% in the Swan Hills area
which is located 130 km northwest of Edmonton. Production consists of light oil
from 76 wells predominantly from the Swan Hills horizon. Water injector
conversion and production well drilling are projects planned for 2003. Gilbert
has assigned Established Reserves of 4,189 mboe of liquids and 1.2 bcf of gas to
this area.
MINEHEAD
The production in this area, which is located 200 km west of Edmonton, is
predominantly sweet liquid rich natural gas from 36 wells and production is
obtained from the Cardium formation. ARC Resources has an average working
interest of 65%. Established Reserves of 18.4 bcf of gas and 1.2 mboe of natural
gas liquids were assigned to this area by Gilbert.
OIL AND GAS RESERVES OF THE NEW PROPERTIES
Gilbert, independent petroleum consultants of Calgary, Alberta have prepared the
New Gilbert Report evaluating as at January 1, 2003, the crude oil, natural gas,
natural gas liquids, and sulphur reserves attributable to the New Properties
which were acquired pursuant to the Star Transaction utilizing the most recent
Gilbert product price forecasts effective April 1, 2003. THE NEW GILBERT REPORT
EVALUATES THE RESERVES ATTRIBUTABLE TO ARC RESOURCES PRIOR TO PROVISION FOR
INCOME TAXES, INTEREST, DEBT SERVICE CHARGES AND GENERAL AND ADMINISTRATIVE
EXPENSES. THE PROBABLE ADDITIONAL RESERVES (SET FORTH AS "RISKED PROBABLE"
BELOW) AND THE PRESENT WORTH VALUE OF SUCH RESERVES AS SET FORTH IN THE TABLES
BELOW HAVE BEEN REDUCED BY 50% TO REFLECT THE DEGREE OF RISK ASSOCIATED WITH
RECOVERY OF SUCH RESERVES. IT SHOULD NOT BE ASSUMED THAT THE DISCOUNTED FUTURE
NET PRODUCTION REVENUES ESTIMATED BY GILBERT REPRESENT THE FAIR MARKET VALUE OF
THE RESERVES. Other assumptions and qualifications relating to costs, prices for
future production and other matters are summarized in the notes following the
tables.
PETROLEUM AND NATURAL GAS RESERVES OF NEW PROPERTIES AND NET CASH FLOWS
ESCALATING COST AND PRICE CASE
COMPANY INTEREST RESERVES PRESENT WORTH OF FUTURE NET CASH FLOW
----------------------------------- ---------------------------------------------
CRUDE OIL AND
NATURAL GAS LIQUIDS NATURAL GAS
(MMBBL) (BCF) UNDISCOUNTED DISCOUNTED AT
------------------- --------------- ------------ ------------------------------
10% 15% 20%
------- ------- -------
($MM) ($MM)
GROSS NET GROSS NET
----- --- ----- ---
Proved
Producing 11.4 9.4 203.4 167.6 796.3 516.3 446.7 397.0
Non-Producing 3.5 2.6 109.3 86.6 282.4 127.8 90.4 65.2
---- ---- ----- ----- ------- ----- ----- -----
Total Proved 15.0 12.0 312.7 254.2 1,078.7 644.0 537.0 462.2
Total Proved Plus Probable 21.4 16.9 430.5 347.9 1,494.5 787.6 635.4 533.7
Risked Probable 3.2 2.4 58.9 46.9 207.9 71.8 49.2 35.7
Total Proved Plus
Risked Probable 18.2 14.5 371.6 301.0 1,286.6 715.8 586.2 498.0
==== ==== ===== ===== ======= ===== ===== =====
30
PETROLEUM AND NATURAL GAS RESERVES OF NEW PROPERTIES AND NET CASH FLOWS
CONSTANT COST AND PRICE CASE
COMPANY INTEREST RESERVES PRESENT WORTH OF FUTURE NET CASH FLOW
----------------------------------- ---------------------------------------------
CRUDE OIL AND
NATURAL GAS LIQUIDS NATURAL GAS
(MMBBL) (BCF) UNDISCOUNTED DISCOUNTED AT
------------------- --------------- ------------ ------------------------------
10% 15% 20%
------- ------- -------
($MM) ($MM)
GROSS NET GROSS NET
----- --- ----- ---
Proved
Producing 11.8 9.6 203.8 167.8 1,031.5 640.3 544.3 476.3
Non-Producing 3.5 2.5 109.4 86.7 393.0 188.1 138.6 104.9
---- ---- ----- ----- ------- ----- ----- -----
Total Proved 15.3 12.2 313.2 254.5 1,424.5 828.4 682.9 581.2
Total Proved Plus Probable 21.7 16.9 431.1 348.3 1,957.3 1,026.8 823.0 685.6
Risked Probable 3.2 2.4 58.9 46.9 266.4 99.2 70.1 52.2
Total Proved Plus
Risked Probable 18.5 14.5 372.1 301.4 1,690.9 927.6 753.0 633.4
==== ==== ===== ===== ======= ===== ===== =====
Notes:
(1) Columns may not add due to rounding.
(2) The following definitions have been used in the New Gilbert Report:
(a) "Proved Reserves" means those reserves estimated as recoverable
under current technology and existing economic conditions in the
case of constant price and cost analyses and anticipated economic
conditions in the case of escalated price and cost analyses, from
that portion of a reservoir which can be reasonably evaluated as
economically productive on the basis of analysis of drilling,
geological, geophysical and engineering data, including the
reserve to be obtained by enhanced recovery processes demonstrated
to be economic and technically successful in the subject
reservoir.
The proved reserves were subdivided into producing and
non-producing categories, consistent with National Policy
Statement 2-B of the Canadian Securities Administrators. The
non-producing reserves were not further divided into developed and
undeveloped reserves.
The proved reserves were sub-divided into the following
classifications, depending on their status of development:
(i) "Producing Reserves" are those reserves that are
actually on production and could be recovered from
existing wells and facilities or, if facilities have
not been installed, that would involve a small
investment relative to cash flow. In multi-well pools
involving a competitive situation, reserves may be
subdivided into producing and non-producing reserves
in order to reflect allocation of reserves to
specific wells and their respective development
status.
(ii) "Non-producing Reserves" means those reserves that
are not classified as producing.
(b) "Probable Reserves" are those reserves which analysis of drilling,
geological, geophysical and engineering data does not demonstrate
to be proved, but where such analysis suggests the likelihood of
their existence and future recovery under current technology and
existing or anticipated economic conditions. Probable additional
reserves to be obtained by the application of enhanced recovery
processes will be the increased recovery over and above that
estimated in the proved category which can be realistically
estimated for the pool on the basis of enhanced recovery processes
which can be reasonably expected to be instituted in the future.
(c) "Pipeline Gas Reserves" are gas reserves remaining after
deducting surface losses due to process shrinkage and raw gas
used as lease fuel.
31
(d) "Gross Reserves" are defined as the total remaining recoverable
reserves associated with the acreage of interest.
(e) "Company Interest Gross Reserves" are defined as the remaining
reserves owned by ARC Resources, before deduction of any
royalties.
(f) "Company Interest Net Reserves" are defined as the gross remaining
reserves of the properties in which ARC Resources has an interest,
less all royalties and interest owned by others.
(g) "Net Production Revenue" is income derived from the sale of net
reserves of oil, pipeline gas and gas by-products, less all
capital and operating costs.
(3) The New Gilbert Report forecasts of unrisked probable reserves and values
have been reduced by 50% to reflect the degree of risk associated with the
recovery of such reserves.
(4) The New Gilbert Report used the average yearly product prices from
Gilbert's then current price forecasts (at April, 2003) for natural gas,
oil and condensate, as outlined in the following table:
EDMONTON ALBERTA
WTI CUSHING PAR PRICE PENTANES SPOT PLANT BC SPOT
OKLAHOMA* 40 API PROPANE BUTANE PLUS GATE AVERAGE HENRY HUB PLANT GATE
YEAR $US/bbl $/bbl $/bbl $/bbl $/bbl $/MMBTU $US/MMBTU Cdn$/MMBTU
---- ------- ----- ----- ----- ----- ------- --------- -----------
2003 30.75 44.50 29.75 33.25 45.00 6.35 5.25 6.60
2004 25.00 36.00 23.25 25.00 30.50 5.20 4.25 5.20
2005 23.00 33.00 21.00 23.00 33.50 4.85 4.00 4.85
2006 23.00 33.00 21.00 23.00 33.50 4.85 4.00 4.85
2007 23.00 33.00 21.00 23.00 33.50 4.85 4.00 4.85
2008 23.00 33.00 21.00 23.00 33.50 4.90 4.05 4.90
2009 23.00 33.00 21.00 23.00 33.50 5.00 4.10 5.00
2010 23.25 33.50 21.50 23.50 34.00 5.10 4.20 5.10
2011 23.75 34.00 21.75 24.00 34.50 5.20 4.25 5.20
2012 24.00 34.50 22.00 24.50 35.00 5.30 4.30 5.30
2013 24.50 35.00 22.50 24.75 35.50 5.40 4.35 5.40
Thereafter +1.5%/yr +1.5%/yr +1.5%/yr +1.5%/yr +1.5%/yr +1.5%/yr +1.5%/yr +1.5%/yr
* 40 degrees API, 0.43% sulphur.
Operating and capital costs have been escalated at 1.5% annually.
(5) The constant cost and price evaluation was based upon December 31, 2002
prices as outlined in the following table:
EDMONTON ALBERTA
PAR PRICE PENTANES SPOT PLANT BC SPOT
WTI CUSHING 40 API PROPANE BUTANE PLUS GATE AVERAGE AECO SPOT PLANT GATE
OKLAHOMA $US/bbl $/bbl $/bbl $/bbl $/bbl $/MMBTU $/MMBTU Cdn$/MMBTU
---------------- ----- ----- ----- ----- ------- ------- ----------
31.20 49.29 35.54 38.04 50.29 5.82 6.02 5.72
* 40 degrees API, 0.43% sulphur.
Operating and capital costs were not escalated.
(6) The $US/$Cdn exchange rate is assumed to be $0.675 to $0.68 throughout the
period of the New Gilbert Report.
(7) The New Gilbert Report estimates total capital expenditures (net to ARC
Resources) to achieve the estimated future net revenues from the Proved
Reserves based upon escalating cost and price assumptions to be $117.0
million with $33.2 million, $39.7 million and $29.3 million of such costs
estimated for the calendar years 2003, 2004 and 2005, respectively. The
corresponding costs to achieve the estimated future net revenues from
Proved Reserves plus one half of Probable Reserves ("Established Reserves")
are $152.0 million with $37.4 million, $44.4 million and $33.0 million of
such costs estimated for the calendar years 2003, 2004 and 2005,
respectively.
32
(8) The New Gilbert Report estimates total capital expenditures (net to ARC
Resources) to achieve the estimated future net revenues from the Proved
Reserves based upon constant cost and price assumptions to be $112.4
million with $33.2 million, $39.1 million and $28.4 million of such costs
estimated for the calendar years 2003, 2004 and 2005, respectively. The
corresponding costs to achieve the estimated future net revenues from the
Established Reserves are $145.9 million with $37.4 million, $43.8 million
and $32.1 million of such costs estimated for the calendar years 2003, 2004
and 2005, respectively.
(9) The New Gilbert Report provides for estimated well abandonment and site
restoration costs, but does not provide for facilities abandonment and
reclamation costs.
ESTIMATED FUTURE NET PRE-TAX CASH FLOWS &
ESTABLISHED RESERVES OF NEW PROPERTIES
ESCALATING COST AND PRICE CASE
($MM)
ROYALTY NET CASH
BURDENS NET FLOW
COMPANY AFTER GAS REVENUE OPERATING NET NET BEFORE
INTEREST PROCESSING AFTER AND OTHER PRODUCTION OTHER ABANDONMENT CAPITAL INCOME
YEAR REVENUE(1) ALLOWANCE(2) ROYALTY(2) EXPENSES REVENUE(3) INCOME COSTS INVESTMENT TAXES(4)(5)
---- ---------- ------------ --------- ---------- ---------- ------ ----- ---------- -----------
2003 288.3 64.0 224.4 37.8 186.6 (3.8) 1.4 37.4 144.1
2004 228.2 48.5 179.7 38.0 141.7 1.8 1.4 44.4 97.7
2005 224.2 47.6 176.6 40.2 136.3 0.1 1.4 33.0 102.0
2006 212.0 43.9 168.1 39.2 128.9 0.1 1.5 20.2 107.4
2007 186.5 37.3 149.2 36.8 112.3 0.1 1.5 12.0 99.0
2008 171.4 34.1 137.3 36.4 100.9 0.1 1.5 2.4 97.1
2009 144.2 27.7 116.5 33.2 83.3 0.1 1.5 0.1 81.8
2010 125.7 23.5 102.3 31.1 71.2 0.1 1.6 0.1 69.6
2011 111.7 20.2 91.5 29.6 61.9 0.1 1.6 0.1 60.3
2012 99.2 17.6 81.6 26.7 54.8 0.1 1.6 0.2 53.1
2013 88.4 15.4 73.0 24.3 48.6 0.1 1.6 0.1 46.9
2014 80.2 13.6 66.6 23.2 43.4 0.1 1.6 0.1 41.7
Remainder 735.1 100.0 635.2 303.6 331.6 0.7 44.5 1.9 285.9
Total 2,695.1 493.3 2,201.7 699.9 1,501.6 (0.2) 62.8 152.0 1,286.6
Net Cash Flow Before Income Taxes(5) Discounted to January 1, 2003 at:
10%: $715.8 million
12%: $657.4 million
15%: $586.2 million
Notes:
(1) Includes working interest revenue and royalty interest revenue.
(2) Net of ARTC.
(3) Company interest revenue less royalty burdens (net of ARTC) and operating
and other expenses.
(4) Undiscounted.
(5) Cash flow before income taxes includes other income and hedging gains
(losses) and is stated prior to interest and general and administrative
expenses. Hedging gains (losses) for 2003 and 2004 are $(3.9) million and
$1.6 million, respectively.
(6) Production for 2003 based on 7,172 mboe Proved Reserves plus 134 mboe for
50% Probable Reserves and for 2004, based on 6,746 mboe for Proved Reserves
plus 350 mboe for 50% Probable Reserves.
(7) Based on the New Gilbert Report with a January 1, 2003 effective date.
(8) Columns may not add due to rounding.
33
ESTIMATED FUTURE NET PRE-TAX CASH FLOWS &
ESTABLISHED RESERVES OF NEW PROPERTIES
CONSTANT COST AND PRICE CASE
($MM)
NET CASH
ROYALTY NET FLOW
COMPANY BURDENS AFTER REVENUE OPERATING NET NET BEFORE
INTEREST GAS PROCESSING AFTER AND OTHER PRODUCTION OTHER ABANDONMENT CAPITAL INCOME
YEAR REVENUE(1) ALLOWANCE(2) ROYALTY(2) EXPENSES REVENUE(3) INCOME COSTS INVESTMENT TAXES(4)(5)
---- ---------- ------------ ---------- -------- ---------- ------ ----- ---------- -----------
2003 277.7 61.5 216.2 37.8 178.5 (6.0) 1.4 37.4 133.7
2004 270.3 58.6 211.8 37.5 174.3 1.0 1.4 43.8 130.2
2005 286.8 63.1 223.7 39.2 184.6 0.1 1.4 32.1 151.3
2006 271.6 58.7 212.9 37.6 175.3 0.1 1.4 19.3 154.7
2007 239.3 50.3 189.0 34.8 154.2 0.1 1.4 11.3 141.6
2008 217.9 45.7 172.2 34.0 138.2 0.1 1.4 0.3 136.7
2009 180.6 36.6 144.0 30.5 113.5 0.1 1.4 0.1 112.1
2010 154.4 30.3 124.1 28.2 95.9 0.1 1.4 0.1 94.5
2011 134.5 25.6 108.9 26.3 82.6 0.1 1.4 0.1 81.2
2012 118.4 21.9 96.5 24.3 72.1 0.1 1.4 0.2 70.6
2013 103.8 18.8 84.9 22.0 62.9 0.1 1.4 0.1 61.4
2014 91.8 16.2 75.6 20.4 55.2 0.1 1.4 0.1 53.8
Remainder 740.3 105.9 634.4 233.3 401.1 0.7 31.5 1.3 369.1
Total 3,087.4 593.1 2,494.3 606.0 1,888.4 (3.3) 48.3 145.9 1,690.9
Net Cash Flow Before Income Taxes(5) Discounted to January 1, 2003 at:
10%: $927.6 million
12%: $849.0 million
15%: $753.0 million
Notes:
(1) Includes working interest revenue and royalty interest revenue.
(2) Net of ARTC.
(3) Company interest revenue less royalty burdens (net of ARTC) and operating
and other expenses.
(4) Undiscounted.
(5) Cash flow before income taxes includes other income and hedging gains
(losses) and is stated prior to interest and general and administrative
expenses. Hedging gains (losses) for 2003 and 2004 are $(6.2) million and
$0.8 million, respectively.
(6) Production for 2003 based on 7,172 mboe Proved Reserves plus 135 mboe for
50% Probable Reserves and for 2004, based on 6,746 mboe for Proved Reserves
plus 350 mboe for 50% Probable Reserves.
(7) Based on the New Gilbert Report with a January 1, 2003 effective date.
(8) Columns may not add due to rounding.
UNDEVELOPED LANDS
The following table sets out ARC Resources' undeveloped land holdings as at
December 31, 2002 in the New Properties as compiled by ARC Resources:
GROSS(1) NET(2)
------- -------
(acres)
Arctic 224,675 2,086
Alberta 264,149 166,519
British Columbia 128,311 109,049
Saskatchewan 80,545 51,275
------- -------
Total 697,680 328,928
======= =======
Notes:
(1) "Gross" refers to the total acres in which ARC Resources has an interest.
34
(2) "Net" refers to the total acres in which ARC Resources has an interest,
multiplied by the percentage working interest therein owned by ARC
Resources.
OIL AND GAS WELLS
The following table sets forth the number and status of wells in which ARC
Resources had a working interest as at December 31, 2002 in the New Properties,
which are producing or which are shut-in but which ARC Resources considers to be
capable of production:
PRODUCING SHUT-IN(1)
-------------------------------------------- -------------------------------------------
CRUDE OIL NATURAL GAS CRUDE OIL NATURAL GAS
-------------------- ---------------------- ------------------- --------------------
GROSS(2) NET(3) GROSS(2) NET(3) GROSS(2) NET(3) GROSS(2) NET(3)
-------- -------- -------- -------- -------- ------ -------- ------
Alberta 740 246.0 575 131.3 240 54.1 83 11.8
British Columbia 18 0.5 37 31.2 9 0.3 12 4.4
Saskatchewan 127 81.0 596 330.4 7 3.2 26 5.2
-------- -------- -------- -------- -------- ------ -------- ------
Total 885 327.5 1,208 492.8 256 57.6 121 21.3
======== ======== ======== ======== ======== ====== ======== ======
Notes:
(1) "Shut-in" wells means wells which have encountered and are capable of
producing crude oil or natural gas but which are not producing due to lack
of available transportation facilities, available markets or other reasons.
Shut-in natural gas wells in which ARC Resources has an interest are
located no further than five kilometres from gathering systems, pipelines
or other means of transportation.
(2) "Gross" wells are defined as the total number of wells in which ARC
Resources has an interest.
(3) "Net" wells are defined as the aggregate of the numbers obtained by
multiplying each gross well by ARC Resources' percentage working interest
therein.
(4) Royalty interest wells have been assigned a net number of zero. The table
does not include water injection wells.
PRODUCTION HISTORY
ARC Resources' approximate net production in the New Properties, before
deduction of royalties, for the periods indicated is summarized below.
2002 2001
----------------------------------------- -----------------------------------------
FOURTH THIRD SECOND FIRST FOURTH THIRD SECOND FIRST
QUARTER QUARTER QUARTER QUARTER QUARTER QUARTER QUARTER QUARTER
------- ------- ------- ------- ------- ------- ------- -------
Crude Oil (bbl/d) 5,141 5,065 5,178 5,523 5,961 6,301 5,917 6,149
Natural Gas (mmcf/d) 90.6 78.3 76.2 78.9 80.3 87.0 90.8 93.9
Natural Gas Liquids (bbl/d) 1,615 1,364 1,301 1,352 1,455 1,179 1,318 1,312
Total (boe/d 6:1) 21,865 19,506 19,168 20,039 20,802 21,990 22,374 23,123
The mix of ARC Resources' crude oil production and natural gas liquids for the
New Properties for the year ended December 31, 2002 was approximately 68% light
quality crude oil (35(degree) API or greater) and 12% medium quality crude oil
(25(degree) API to 35(degree) API), 16% condensate and 10% natural gas liquids.
Heavier gravity (less than 25% API) crude oil accounted for only 2% of
production.
Approximately 65% of ARC Resources' gross revenue for the New Properties is
derived from natural gas production with the remainder from crude oil and
natural gas liquids. On a boe (6:1) basis, production is split between crude oil
and natural gas liquids as to approximately 69% and natural gas as to
approximately 31%.
35
DRILLING HISTORY
The following table sets forth the gross and net farmout and development wells
in which Star participated during the periods indicated.
YEAR ENDED DECEMBER 31,
2002 2001
GROSS(1) NET(2) GROSS(1) NET(2)
-------- ------ -------- ------
Exploration
Oil 1 0.2 4 2.5
Gas 1 0.3 13 6.2
Dry 1 0.5 2 2.0
-------- ------ -------- ------
Total Exploration 3 1.0 19 10.7
-------- ------ -------- ------
Development
Oil -- -- 22 11.0
Gas 74 55.1 41 18.0
Dry 1 1.0 1 0.3
Service 1 0.3 -- 0.0
-------- ------ -------- ------
Total Development 76 56.4 64 29.3
-------- ------ -------- ------
Total 79.0 57.4 83 40.0
======== ====== ======== ======
Notes:
(1) "Gross Wells" means the number of wells in which Star has an interest.
(2) "Net Wells" means the aggregate of the numbers obtained by multiplying each
gross well by Star's percentage working interest therein.
CAPITAL EXPENDITURES
The following table summarizes capital expenditures (net of dispositions) made
on the New Properties for the periods indicated.
2002 2001
----------------------------------------- -----------------------------------------
FOURTH THIRD SECOND FIRST FOURTH THIRD SECOND FIRST
QUARTER QUARTER QUARTER QUARTER QUARTER QUARTER QUARTER QUARTER
------- ------- ------- ------- ------- ------- ------- -------
Property acquisitions, net 942 1,708 922 2,271 457 3,216 1,207 (754)
Development drilling 12,679 16,631 1,774 6,304 8,434 8,344 4,729 8,080
Production and facilities 13,110 3,536 4,708 8,684 4,043 3,750 3,942 4,110
Other 2,602 2,412 1,125 2,696 4,694 7,928 3,541 5,343
------- ------- ------- ------- ------- ------- ------- -------
Total 29,333 24,287 8,529 19,955 17,628 23,238 13,419 16,779
======= ======= ======= ======= ======= ======= ======= =======
36
NETBACK HISTORY
The following table sets forth information respecting average net product prices
received, royalties paid, operating expenses and netbacks received in respect of
production of crude oil, natural gas liquids and natural gas from the New
Properties for the periods indicated.
2002 2001
--------------------------------------- --------------------------------------
FOURTH THIRD SECOND FIRST FOURTH THIRD SECOND FIRST
QUARTER QUARTER QUARTER QUARTER QUARTER QUARTER QUARTER QUARTER
------- ------- ------- ------- ------- ------- ------- -------
Average Net Production
Prices Received
Crude Oil ($/bbl) 35.70 35.28 33.76 31.66 35.06 37.08 35.70 36.22
Natural Gas ($/mcf) 3.77 3.31 3.33 3.09 5.14 5.76 6.82 7.98
Natural Gas Liquids ($/bbl) 29.23 26.57 24.74 21.05 34.63 38.70 33.03 46.73
Oil Equivalent ($/boe 6:1) 32.32 26.03 26.63 23.16 22.39 26.95 36.62 46.02
Royalties Paid
Crude Oil ($/bbl) 8.02 9.06 8.27 4.94 6.69 7.39 7.23 8.68
Natural Gas ($/mcf) 1.17 0.78 0.81 0.77 0.55 1.04 1.49 2.53
Natural Gas Liquids ($/bbl) 9.51 9.59 7.56 3.59 7.18 11.03 7.79 18.40
Oil Equivalent ($/boe 6:1) 7.42 6.18 5.95 4.63 4.56 6.83 8.40 13.62
Operating Expenses
Crude Oil ($/bbl)(1) (2) 5.42 5.89 6.44 5.14 5.58 6.29 5.89 5.41
Natural Gas ($/mcf) 0.95 0.97 1.02 0.81 0.82 0.95 0.96 0.86
Natural Gas Liquids ($/bbl) 6.39 6.21 6.51 5.14 6.32 5.71 5.01 5.25
Oil Equivalent ($/boe 6:1) 5.25 5.88 6.39 4.94 5.48 5.98 5.96 5.25
Netback Received
Crude Oil ($/bbl) 23.44 23.25 21.03 21.58 16.51 22.69 25.49 22.13
Natural Gas ($/mcf) 3.04 1.72 1.92 1.73 1.77 1.75 3.46 4.91
Natural Gas Liquids ($/bbl) 20.71 14.31 14.33 12.32 11.17 13.03 24.54 22.92
Oil Equivalent ($/boe 6:1) 19.65 13.97 14.30 13.58 12.35 14.15 22.25 27.15
Notes:
(1) Operating expenses are composed of direct costs incurred to operate both
oil and gas wells. A number of assumptions have been made in allocating
these costs between oil, natural gas and natural gas liquids production.
(2) Operating recoveries associated with operated properties were excluded from
operating costs and accounted for as a reduction to general and
administrative costs.
FUTURE COMMITMENTS
Information respecting Star's financial instruments is contained in Note 13 and
14 to the audited consolidated financial statements of Star for the year ended
December 31, 2002 which are attached hereto as Appendix A. All such financial
instruments were liquidated prior to the completion of the Star Transaction.
ACQUISITIONS AND DISPOSITIONS
There were no significant acquisitions or dispositions by Star within the most
recently completed financial year.
AMENDMENTS TO TRUST INDENTURE
At the Annual and Special Meeting of Unitholders (the "2003 Unitholders
Meeting") of the Trust held April 17, 2003, Unitholders approved a Special
Resolution approving a number of amendments to the Trust Indenture required to
clarify duties and responsibilities subsequent to the Internalization
Transaction
37
completed on August 29, 2002, along with a number of miscellaneous amendments.
The amendments to the Trust Indenture which were approved at the 2003
Unitholders Meeting, all of which have been made effective May 16, 2003, are
summarized below and are more particularly set forth and described in the Annual
Meeting 2003 Information Circular. A brief summary of the principal amendments
are as follows:
o The Trust Indenture was amended to effect a single global delegation by
the Trustee to ARC Resources, including in such delegation all of the
matters formerly delegated to the Manager under the Management
Agreement.
o The Trust Indenture was amended to stipulate that all directors of ARC
Resources are elected annually by the Unitholders at the annual meeting
of Unitholders and, in addition, the Shareholders Agreement was
terminated.
o The provisions of the Trust Indenture were amended to clarify that any
approval or consent of Unitholders in relation to any matter required
by any regulatory body will require a majority of, or such other level
of approval of Unitholders as may be stipulated by such regulatory
authority, including as to the exclusion of interested or other
Unitholders in the calculation of such level of approval.
o The provisions in the Trust Indenture relating to the authorized class
of Special Voting Units were amended to clarify that the entitlement
under such Special Voting Units is to such number of votes at meetings
of Unitholders equal to the number of Trust Units initially reserved
for issuance that such Special Voting Units represent, as opposed to a
number of votes which would increase as entitlement to Trust Units
increases under, for example, the exchange ratio for the ARC Resources
Exchangeable Shares.
o A number of inconsequential changes were made to the Trust Indenture
involving the elimination of references to the Manager, Management
Agreement and the Shareholder Agreement.
EXCHANGEABLE SHARE REORGANIZATION
On May 16, 2003, the Trust completed a merger of two of its wholly-owned
subsidiaries, ARC Resources and ARML (the "Exchangeable Share Reorganization")
which was accomplished in the following manner:
o ARC Resources amended its articles by replacing the ARC Resources
Exchangeable Share Provisions with rights, privileges, restrictions and
conditions which were in substance identical to the ARML Exchangeable
Share Provisions (the "ARC Resources Exchangeable Share Amendment").
o Immediately following the ARC Resources Exchangeable Share Amendment,
ARC Resources acquired all of the outstanding ARML Exchangeable Shares
in exchange for ARC Resources Exchangeable Shares which had been
amended to have rights, privileges, restrictions and conditions in
substance identical to the ARML Exchangeable Share Provisions (the
"Share Exchange"). Pursuant to the Share Exchange, holders of ARML
Exchangeable Shares received an aggregate 0.80676 ARC Resources
Exchangeable Shares, which number of Exchangeable Shares, on the
effective date of the Share Exchange, entitled the former holders of
ARML Exchangeable Shares to receive the same number of Trust Units that
such holders would have received if they had exercised their right,
immediately prior to the Share Exchange, to receive Trust Units of the
Trust.
38
o Following the completion of the ARC Resources Exchangeable Share
Amendment and the Share Exchange, ARC Resources acquired all of the
outstanding common shares of ARML in exchange for the issuance to the
Trust of common shares of ARC Resources (the "Common Share
Acquisition").
o Following the completion of the ARC Resources Exchangeable Share
Amendment, the Share Exchange and the Common Share Acquisition, ARC
Resources and its then wholly-owned subsidiary, ARML, executed an
agreement whereby ARML transferred and assigned all of its assets to
ARC Resources and ARC Resources assumed all of the liability of ARML.
ARML was subsequently dissolved.
Concurrent with the completion of the Exchangeable Share Reorganization, each of
the ARC Resources Exchangeable Share Support Agreement and the ARC Resources
Exchangeable Share Voting and Exchange Trust Agreement were amended so as to
apply to both the ARC Resources Exchangeable Shares which were outstanding
immediately prior to the completion of the Exchangeable Share Reorganization as
well as to the ARC Resources Exchangeable Shares which were issued to former
holders of ARML Exchangeable Shares pursuant to the Share Exchange. For more
information, see the Annual Meeting 2003 Information Circular and more
particularly the sections under the headings "Trust Indenture Amendment
Resolution" and "Exchangeable Share Reorganization, both of which are hereby
incorporated by reference into this Annual Information Form.
SHARE CAPITAL OF ARC RESOURCES
All information below in respect of the share capital of ARC Resources is stated
as at May 16, 2003.
COMMON SHARES
ARC Resources has authorized for issuance an unlimited number of common shares
of which 100 common shares are issued and outstanding and held by the Trust. The
voting of such shares is delegated to ARC Resources under the Trust Indenture.
The holders of common shares are entitled to notice of, to attend and to one
vote per share held at any meeting of the shareholders of ARC Resources; to
receive dividends as and when declared by Board of Directors of ARC Resources on
the common shares as a class, and subject to prior satisfaction of all
preferential rights to dividends attached to all shares of other classes; and in
the event of any liquidation, dissolution or winding-up of ARC Resources,
whether voluntary or involuntary, or any other distribution of the assets of ARC
Resources among its shareholders for the purpose of winding-up its affairs, and
subject to prior satisfaction of all preferential rights to return of capital on
dissolution attached to all shares of other classes of shares of ARC Resources
ranking in priority to the common shares in respect of return of capital on
dissolution, to share ratably, together with the shares of any other class of
shares of ARC Resources ranking equally with the common shares in respect of
return of capital on dissolution, in such assets of ARC Resources as are
available for distribution.
ARC RESOURCES EXCHANGEABLE SHARES
ARC Resources is authorized to issue an unlimited number of ARC Resources
Exchangeable Shares of which, as at May 16, 2003, 2,267,758 ARC Resources
Exchangeable Shares are outstanding. The ARC Resources Exchangeable Shares rank
prior to the common shares of ARC Resources, the second preferred shares of ARC
Resources and any other shares ranking junior to the ARC Resources Exchangeable
Shares with respect to the payment of dividends and the distribution of assets
in the event of the liquidation, dissolution or winding-up of ARC Resources;
provided that notwithstanding such ranking ARC Resources shall not be restricted
in any way from repaying indebtedness of ARC Resources to the Trust from time to
time.
39
Holders of ARC Resources Exchangeable Shares are entitled to receive, as and
when declared by the Board of Directors in its sole discretion, from time to
time, cumulative preferential cash dividends in an amount per share equal to the
ARC Resources Exchange Ratio on the preceding business day multiplied by the
fair market value of a Trust Unit as at the preceding business day (determined
on the basis of the weighted average price of the Trust Unit on the TSX for the
10 trading days preceding that date). It is not anticipated that dividends will
be declared or paid on the ARC Resources Exchangeable Shares, however the Board
of Directors has the right in its sole discretion to do so.
ARC Resources will not, without obtaining the approval of the holders of the ARC
Resources Exchangeable Shares:
(a) pay any dividend on the common shares of ARC Resources, second
preferred shares of ARC Resources or any other shares ranking
junior to the ARC Resources Exchangeable Shares, other than
the stock dividends payable in common shares of ARC Resources
or any such other shares ranking junior to the ARC Resources
Exchangeable Shares;
(b) redeem, purchase or make any capital distribution in respect
of the common shares of ARC Resources, second preferred shares
of ARC Resources or any other shares ranking junior to the ARC
Resources Exchangeable Shares;
(c) redeem or purchase any other shares of ARC Resources ranking
equally with respect to the payment of dividends or on any
liquidation distribution; or
(d) issue any shares, other than ARC Resources Exchangeable
Shares, second preferred shares of ARC Resources or common
shares of ARC Resources, which rank superior to the ARC
Resources Exchangeable Shares with respect to the payment of
dividends or on any liquidation distribution.
Notwithstanding the foregoing, the restrictions in paragraphs (a), (b) and (c)
above shall only be applicable if dividends which have been declared on the
outstanding ARC Resources Exchangeable Shares have not been paid in full.
The ARC Resources Exchangeable Share Provisions entitle the holder to exchange
each ARC Resources Exchangeable Share at any time into the number of Trust Units
equal to the ARC Resources Exchange Ratio then in effect. The ARC Resources
Exchange Ratio is determined by reference to the distributions paid on Trust
Units in a given month and the current market price of the Trust Units. On May
16, 2003, each ARC Resources Exchangeable Share was exchangeable for 1.37557
Trust Units.
The ARC Resources Exchangeable Shares provide holders with a security having
economic, ownership and voting rights which are substantially equivalent to
those of Trust Units. The ARC Resources Exchangeable Shares are maintained
economically equivalent to the Trust Units by the progressive increase in the
ARC Resources Exchange Ratio to reflect distributions paid by the Trust to
Unitholders. The ARC Resources Exchangeable Shares are provided equivalent
voting rights as Unitholders through the ARC Resources Exchangeable Share Voting
and Exchange Trust Agreement pursuant to which the holders of ARC Resources
Exchangeable Shares can direct the Trustee to vote at meetings of Unitholders.
Computershare Trust Company of Canada acts as the transfer agent for the ARC
Resources Exchangeable Shares.
40
SECOND PREFERRED SHARES
ARC Resources also has authorized an unlimited number of Second Preferred Shares
which may at any time or from time to time be issued in one or more series.
Before any shares of a particular series are issued, the Board of Directors of
ARC Resources shall, by resolution, fix the number of shares that will form such
series and shall, subject to the limitations set out herein, by resolution fix
the designation, rights, privileges, restrictions and conditions to be attached
to the Second Preferred Shares of such series. The Second Preferred Shares of
each series shall rank behind the Exchangeable Shares and on a parity with the
Second Preferred Shares of every other series with respect to accumulated
dividends and return of capital. The Second Preferred Shares are entitled to a
preference over the Common Shares and over any other shares of ARC Resources
ranking junior to the Second Preferred Shares with respect to priority in the
payment of dividends and in the distribution of assets in the event of the
liquidation, dissolution or winding-up of ARC Resources, whether voluntary or
involuntary, or any other distribution of the assets of ARC Resources among its
shareholders for the purpose of winding-up its affairs. As at the date hereof,
no Second Preferred Shares have been issued or are outstanding.
SHARE CAPITAL OF ARML
As at December 31, 2002 ARML had authorized for issuance an unlimited number of
common shares of which 100 common shares were issued and outstanding and held by
the Trust and an unlimited number of ARML Exchangeable Shares of which 2,206,409
ARML Exchangeable Shares were issued and outstanding.
Pursuant to the Exchangeable Share Reorganization which was completed on May 16,
2003 all of the then outstanding ARML Exchangeable Shares were acquired by
Resources and ARML was subsequently wound-up into ARC Resources.
OTHER INFORMATION RESPECTING ARC RESOURCES AND ARC SASK.
ADDITIONAL PROPERTIES
ARC Resources or ARC Sask. may acquire additional Properties and related
tangible equipment and fund such acquisitions from production revenues, the
proceeds of the Deferred Purchase Price Obligation (which, at the option of the
Trust, may be financed from the net proceeds of any issue by the Trust of
additional Trust Units or from the proceeds of disposition of the Royalties in
respect of Properties which are disposed of unless ARC Resources or ARC Sask.
determines not to reinvest such proceeds to pay down all or any portion of the
Deferred Purchase Price Obligation), borrowings, farmouts or with working
capital of ARC Resources or ARC Sask. Under the terms of the Royalty Agreements,
capital expenditures and the cost of acquiring additional properties in any
calendar year will not exceed 25% of the aggregate of all amounts received by
the Trust, directly or indirectly, from ARC Resources and ARC Sask. for such
year in royalty, interest distributions and other payments unless financed with
borrowings, additional issuances of Trust Units or Properties disposition
proceeds. See "Capital Expenditures".
ARC Resources or ARC Sask. may sell any of its interests in Properties and
release the Royalties therefrom provided that the sale is approved by a Special
Resolution of the Unitholders in the event the interests in the Properties being
sold constitute greater than 25% of the Asset Value of all Properties. Sales of
Properties for proceeds in excess of $10,000,000 are required to be approved by
the Board of Directors of ARC Resources. The proceeds of a disposition of an
interest in the Properties to the extent related to Canadian resource
properties, as defined in the Tax Act, will be allocated 99% to the Trust after
retiring any borrowing which relates to the Canadian resource property component
of such interest in consideration for the release of the Royalties from such
Properties.
41
In connection with the sale of any interests in the Properties, ARC Resources
will determine whether the net proceeds of the sale should be reinvested on
behalf of the Trust pursuant to the Deferred Purchase Price Obligation.
Otherwise such proceeds will be distributed to Unitholders by the Trust.
CAPITAL EXPENDITURES
ARC Resources may approve future capital expenditures or farmouts under the
terms of the Royalty Agreements. Future capital expenditures on the Properties
will generally be of the type which are intended to maintain or improve
production from the Properties. ARC Resources and ARC Sask. may finance capital
expenditures from production revenues, the proceeds of the Deferred Purchase
Price Obligation (which will be financed by the Trust issuing additional Trust
Units or from the proceeds of disposition of the Royalties in respect of
Properties which are disposed of), borrowings, farmouts or with working capital
of ARC Resources or ARC Sask. Under the terms of the Royalty Agreements, capital
expenditures and the cost of acquiring additional properties in any calendar
year, will not exceed 25% of the aggregate of all amounts received by the Trust,
directly or indirectly, from ARC Resources and ARC Sask. for such year in
royalty, interest distributions and other payments unless financed with
borrowings, additional issuances of Trust Units or Property disposition
proceeds.
DEFERRED PURCHASE PRICE OBLIGATION
Under the terms of the Royalty Agreements, the purchase price of the Royalties
includes the Deferred Purchase Price Obligation which recognizes that cash flows
from any after-acquired property and certain capital expenditures will be
subject to the Royalty for the benefit of Unitholders. The Deferred Purchase
Price Obligation consists of an amount equal to 99% of the cost of, or any
amount borrowed to acquire, a Canadian resource property (as defined under the
Tax Act) acquired by ARC Resources or ARC Sask. subsequent to the grant of the
Royalties and an amount equal to 99% of the cost of, or any amount borrowed to
fund, certain designated capital expenditures incurred on the Properties. The
Trust intends to finance the Deferred Purchase Price Obligations through
additional issues of Trust Units or the application of the Royalty disposition
proceeds.
BORROWING
ARC Resources and ARC Sask. borrow funds from time to time to finance the
purchase of Properties, for capital expenditures or for other financial
obligations or expenditures in respect of the Properties held by them or for
working capital purposes. Borrowings to fund the purchase of Canadian resource
properties, as defined in the Tax Act, may be repaid with funds received from
the Trust pursuant to the Deferred Purchase Price Obligation. The Board of
Directors of ARC Resources has approved a policy relating to borrowing which
requires a quarterly assessment by management, subject to review by the Board of
Directors of ARC Resources, of the appropriateness of borrowing levels. ARC
Resources and ARC Sask. have granted security in priority to the Royalties to
secure the loan of such funds.
Debt Service Charges will be deducted in computing Royalty Income. The debt
repayment will be scheduled to minimize any income tax payable by ARC Resources.
The Trust had four revolving credit facilities to a combined maximum of $300
million and US$65 million of Senior Secured Notes (the "Notes") at December 31,
2002. The revolving credit facilities each have a 364 day extendable period and
a two year term. Borrowings under the facilities bear interest at bank prime or,
at the Trust's option, bankers' acceptance plus a stamping fees. The first Notes
were issued for an aggregate of US$35 million during 2000 pursuant to an
Uncommitted Master Shelf Agreement. The first Notes bear interest at 8.05% and
require equal principal payments of US$7 million over a five year period
commencing in 2004. On October 18, 2002, ARC Resources issued a further US$30
million pursuant to the Master Shelf Agreement. These Notes bear interest at
4.94% and require equal principal
42
payments of US$6 million over a 5 year period commencing 2006. As at December
31, 2002, the Uncommitted Master Shelf Agreement allows for the issuance of an
additional US$35 million of Notes at rates and maturity to be agreed upon at the
date of issuance.
On April 16, 2003 the Trust renewed its four revolving credit facilities and
added a fifth revolving credit facility to a combined maximum of $551 million,
with the acquisition of Star resulting in the total borrowing base of the Trust
being equal to $650 million on April 16, 2003, consisting of credit facilities
of $551 million and Notes totaling US$65 million.
ESCROW AGREEMENTS
As a condition of preceding with the Internalization Transaction certain holders
of ARML shares entered into the Escrow Agreements, which are intended to enhance
alignment between management and Unitholder interests. As a result of the escrow
provision 9,013 Trust Units and 2,008,699 ARML Exchangeable Shares were placed
in escrow at such time.
All the distributions received on the Trust Units (or attributable to ARML
Exchangeable Shares) held in escrow flow through to the underlying holders of
the Trust Units or ARML Exchangeable Shares. Distributions on the Trust Units
are made directly to the holder of the escrowed Trust Units. Distributions
attributable to ARML Exchangeable Shares are, on the request of a holder of ARML
Exchangeable Shares, released periodically, by release of such number of ARML
Exchangeable Shares which reflect the increase in the number of Trust Units as a
result of the Distributions on Trust Units to which such escrowed holder is
entitled at the time. In the event of a change in control of ARML, ARC
Resources, or the Trust other than among affiliates, all Trust Units and ARML
Exchangeable Shares held in escrow are to be released. Securities held in escrow
may be charged, pledged or encumbered, provided that the securities remain in
escrow pursuant to the terms of the Escrow Agreements.
At the date of the Internalization Transaction:
o eight of the larger shareholders of ARML, who owned directly or
indirectly accounted for approximately 49% of the ARML shares, were
subject to 66 2/3% of the Trust Units or ARML Exchangeable Shares
received pursuant to the Internalization Transaction being held in
escrow and released as to one-fifth on each August 28 for the
immediately following five years.
o twenty-one substantial ARML shareholders, who directly or indirectly
accounted for approximately 43% of the ARML Shares, were subject to 50%
of the Trust Units or ARML Exchangeable Shares received being held in
escrow and released as to one-fifth on each August 28 for the
immediately following five years
o sixteen smaller ARML shareholders, who directly or indirectly accounted
for approximately 5% of the ARML shares, were subject to 50% of the
Trust Units or ARML Exchangeable Shares received being held in escrow
and released as to one-third on each August 28 for the immediately
following 3 years
o twenty-eight remaining ARML shareholders, who accounted for
approximately 3% of the ARML shares, were not subject to any escrow
provisions.
In addition, 30% of the Trust Units or ARML Exchangeable Shares held in escrow
for holders of ARML Shares who were, at the date of the Internalization
Transaction, officers of ARC Resources or directors of ARC Financial Corporation
will be forfeited if the individual ceases to be an employee, director, of
officer of ARC Resources, any other affiliate of the Trust, ARC Financial
Corporation or any other member of the ARC Financial group of companies in the
first year after the closing date of the
43
Internalization Transaction, such percentage declines evenly on August 28 over
the following five year period. Any such Trust Units or ARML Exchangeable Shares
will be redistributed among the remaining members of this group. In the event of
a change in control of the Trust, the forfeiture provisions will be cancelled.
The escrow provisions and forfeiture provisions are intended to enhance
alignment between management and unitholder interests.
In connection with the completion of the Exchangeable Share Reorganization on
May 16, 2003, all of the ARC Resources Exchangeable Shares which were issued in
exchange for the ARML Exchangeable Shares subject to the escrow and forfeiture
provisions noted above, remain subject to such escrow and forfeiture provisions.
ENVIRONMENTAL OBLIGATIONS - RECLAMATION FUND
ARC Resources and ARC Sask. will each be liable for its share of ongoing
environmental obligations and for the ultimate reclamation of the Properties
held by it upon abandonment. Ongoing environmental obligations are expected to
be funded out of cash flow.
ARC Resources and ARC Sask. currently estimate that the future environmental and
reclamation obligations in respect of the Properties held by them will aggregate
approximately $127.3 million. ARC Resources' and ARC Sask.'s aggregate minimum
annualized contributions are currently set at approximately $4.0 million (less
current year site reclamation and abandonment costs) to a reclamation fund, such
that the estimated future environmental and reclamation obligations associated
with the Properties held by them would be funded over 20 years. Contributions to
the fund may be adjusted by ARC Resources or ARC Sask. from time to time based
on its assessment of its share of expected environmental and final site
reclamation costs. The estimate of the future environmental and reclamation
obligations with respect to the New Properties is approximately $52.1 million.
As a result, ARC expects to contribute an additional $2.0 million (less current
year site reclamation and abandonment costs) to the reclamation fund.
The estimates of reserves and the present worth of future net cash flows from
such reserves contained in the Gilbert Report and in the New Gilbert Report are
stated after providing for estimated well abandonment and site restoration
costs.
INSURANCE
ARC Resources and ARC Sask. carry insurance policies to provide protection for
their working interests in the Properties at or above industry standards.
Insurance policies covers property damage, general liability and, for certain
properties, business interruption. The ongoing level, type and maintenance of
insurance are determined by ARC Resources based upon the availability and cost
of such insurance and ARC Resources' perception of the risk of loss.
RETENTION BONUSES AND EXECUTIVE EMPLOYMENT AGREEMENTS
As a condition of the Internalization Transaction, ARML declared the Retention
Bonuses to the ARML Officers, compromised of the Chief Executive Officer and the
five Vice-Presidents of ARC Resources on August 28, 2002. This payment is to be
made in equal increments of an aggregate of $1,000,000 per year for five years
but only if the individual remains employed by ARC Resources or another
affiliate of the Trust. The Retention Bonuses were funded by an effective
reduction in the purchase price resulting in the existing holders of ARML shares
paying for this management retention program. The relevant portion of the unpaid
Retention Bonus will not be paid to any departing officer.
44
INFORMATION RELATING TO THE TRUST
TRUST UNITS
A maximum of 650,000,000 Trust Units have been created and may be issued
pursuant to the Trust Indenture. The Trust Units represent equal undivided
beneficial interests in the Trust. All Trust Units share equally in all
distributions from the Trust and all Trust Units carry equal voting rights at
meetings of Unitholders. No Unitholder will be liable to pay any further calls
or assessments in respect of the Trust Units. No conversion, retraction,
redemption or preemptive rights attach to the Trust Units.
SPECIAL VOTING UNIT
The Trust Indenture also provides for the issuance of special voting units which
are to be issued to a trustee and which are entitled to such number of votes at
meetings of Unitholders equal to the number of Trust Units reserved for issuance
that such special voting units represent, such number of votes and any other
rights or limitations prescribed by the Board of Directors of ARC Resources when
the Board authorizes issuing such special voting units.
A Special Voting Unit has been designated by the Board of Directors of ARC
Resources as the "Special Voting Unit, Exchangeable Shares ("Special Voting
Unit"). The Special Voting Unit possesses a number of votes for the election of
directors of ARC Resources and on all other matters submitted to a vote of
Unitholders equal to the number of outstanding Exchangeable Shares from time to
time not owned by Trust or ARC Subco. The holders of Trust Units and the holder
of the Special Voting Unit vote together as a single class on all matters.
In the event of any liquidation, dissolution or winding-up of Trust, the holder
of the Special Voting Unit will not be entitled to receive any assets of Trust
available for distribution to its holders of Trust Units. The holder of the
Special Voting Unit will not be entitled to receive dividends. The Special
Voting Unit has been issued to Computershare Trust Company of Canada, as
trustee, under the Voting and Exchange Trust Agreement. At such time as the
Special Voting Unit has no votes attached to it because there are no
Exchangeable Share outstanding not owned by Trust or ARC Subco, the Special
Voting Unit will be cancelled.
THE TRUST INDENTURE
The Trust Indenture, among other things, provides for the calling of meetings of
Unitholders, the conduct of business thereof, notice provisions, the appointment
and removal of the Trustee and the form of Trust Unit certificates. The Trust
Indenture may be amended from time to time. Substantive amendments to the Trust
Indenture, including early termination of the Trust and the sale or transfer of
the property of the Trust as an entirety or substantially as an entirety
requires approval by Special Resolution of the Unitholders. See "Meetings and
Voting".
The following is a summary of certain provisions of the Trust Indenture. For a
complete description of such indenture, reference should be made to the Trust
Indenture, copies of which may be viewed at the offices of, or obtained from,
the Trustee.
TRUSTEE
Computershare Trust Company of Canada is the trustee of the Trust and also acts
as the transfer agent for the Trust Units. The Trustee is responsible for, among
other things: (a) accepting subscriptions for Trust Units and issuing Trust
Units pursuant thereto; (b) maintaining books and records of the Trust and
providing timely reports to holders of Trust Units; and (c) paying cash
distributions to Unitholders. The
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Trust Indenture provides that the Trustee shall exercise its powers and carry
out its functions thereunder as Trustee honestly, in good faith and in the best
interests of the Trust and the Unitholders and, in connection therewith, shall
exercise that degree of care, diligence and skill that a reasonably prudent
trustee would exercise in comparable circumstances.
The term of the Trustee's appointment is until the next annual meeting of
Unitholders. At each annual meeting the Trustee may be reappointed or changed as
determined by a majority of the votes cast at such meeting of the Unitholders.
The Trustee may resign upon 60 days' notice to the Trust. The Trustee may also
be removed by Special Resolution of the Unitholders. Such resignation or removal
becomes effective upon the acceptance or appointment of a successor trustee.
ARC Resources presently administers the Trust on behalf of the Trustee. ARC
Resources, on behalf of the Trustee, keeps such books and records as are
necessary for the proper recording of the business transactions of the Trust.
The Trust Indenture provides that the Trustee shall be under no liability for
any action or failure to act unless such liabilities arise out of the Trustee's
gross negligence, willful default or fraud. The Trustee, where it has met its
standard of care, shall be indemnified out of the assets of the Trust for any
taxes or other government charges imposed upon the Trustee in consequence of its
performance of its duties but shall have no additional recourse against
Unitholders. In addition, the Trust Indenture contains other customary
provisions limiting the liability of the Trustee.
FUTURE OFFERINGS
Under the Trust Indenture, the Trust may offer additional Trust Units or rights
to acquire additional Trust Units at such times and on such terms as the Board
of Directors of ARC Resources may determine. Pursuant to the Deferred Purchase
Price Obligation, the Royalties will attach to the interests of ARC Resources or
ARC Sask. in any additional Properties they may acquire from time to time. At
the option of the Trust, the net proceeds from any offerings may be used to
finance the acquisition of additional Properties should such interests be
available on terms and conditions acceptable to ARC Resources on behalf of
Unitholders or to repay indebtedness incurred by ARC Resources in connection
with such acquisitions.
MEETINGS AND VOTING
Annual meetings of the Unitholders will be held annually. Special meetings of
Unitholders may be called at any time by the Trustee and shall be called by the
Trustee upon the written request of Unitholders holding in aggregate not less
than 20% of the Trust Units. Notice of all meetings of Unitholders shall be
given to Unitholders at least 21 days prior to the meeting.
Unitholders will be entitled at each annual meeting to appoint the Trustee, to
appoint the auditors of the Trust and to elect all the members of the Board of
Directors of ARC Resources.
MANAGEMENT OF THE TRUST
The Trust Indenture provides for delegation to ARC Resources by the Trustee of
broad discretion to administer and manage the day to day operations of the Trust
Fund, which includes responsibility and authority to make executive decisions on
behalf of all of the direct or indirect subsidiaries of the Trust and to
exercise the powers of the Trustee. Without limitation of the foregoing, ARC
Resources has been specifically delegated to provide certain administrative and
support services to the Trust, including those necessary: (i) to ensure
compliance by the Trust with continuous disclosure obligations under applicable
securities legislation; (ii) to provide investor relations services; (iii) to
provide or cause to be provided to
46
Unitholders all information to which Unitholders are entitled under the Trust
Indenture; (iv) to call, hold and distribute materials including notices of
meetings and information circulars in respect of all necessary meetings of
Unitholders; (v) to determine the amounts payable from time to time to
Unitholders and to arrange for distributions to Unitholders of Distributable
Income; and (vi) to determine the timing and terms of future offerings of Trust
Units, if any.
ARC Resources has accepted all such delegation and has agreed that, in respect
of such matters, it shall carry out its functions honestly, in good faith and in
the best interests of the Trust and the Unitholders and, in connection
therewith, shall exercise that degree of care, diligence and skill that a
reasonably production person would exercise in comparable circumstances.
ARC FINANCIAL ADVISORY AGREEMENT
ARC Resources, the Trust, ARML and ARC Financial Corporation entered into the
ARC Financial Advisory Agreement dated August 28, 2002 whereby ARC Financial
Corporation agrees to provide certain ongoing research and strategic services to
the Trust for a five year period without cost to the Trust. This ensures the
continuing availability of research and strategic advise in the energy sector,
which has been beneficial to the Trust in the past. ARC Financial Corporation
has also agreed not to, and will use reasonable commercial efforts, to cause any
of the ARC Financial group of companies, not to act as manager or promoter of
another publicly listed energy related trust for a period of five years, with
certain exceptions relating to the ARC venture capital activities carried out by
any member of the ARC Financial group of companies.
SPECIAL DEBENTURE
The Special Debenture in the principal amount of $320,000,000 was issued
pursuant to the Star Transaction. The following is a summary of the material
attributes and characteristics of the Special Debenture. This summary does not
purport to be complete and is subject to, and qualified, by reference to the
terms of the Special Debenture.
GENERAL
The Special Debenture was issued on April 16, 2003 and matures on June 30, 2008.
The Special Debenture was issued in the principal amount of $320,000,000 and the
holder has the right at any time prior to the Time of Expiry (as defined below)
to convert the whole or any part of the Special Debenture which is $10,000,000
or an integral multiple thereof into new Underlying Debentures with a
denomination of $10,000,000 for each $10,000,000 principal amount of Special
Debenture so converted.
The Special Debenture bears interest from the date of issue at 8% per annum
until, but not including June 30, 2005, and from June 30, 2005 at 10% per annum,
which will be payable in cash in equal quarterly payments in arrears on March
31, June 30, September 30 and December 31 in each year, commencing on June 30,
2003. The first interest payment will include interest accrued from the date of
issue to June 30, 2003.
The principal amount of the Special Debenture is payable in lawful money of
Canada or, at the option of the Trust and subject to applicable regulatory
approval, by payment of Trust Units as further described under "Payment upon
Maturity". The interest on the Special Debenture will be payable in lawful money
of Canada including, at the option of the Trust and subject to applicable
regulatory approval, in accordance with the Unit Interest Payment Obligation as
described under "Interest Payment Option".
The Special Debenture is a direct obligation of the Trust and is not secured by
any mortgage, pledge, hypothec or other charge and is subordinated to other
liabilities of the Trust as described under
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"Subordination". The Special Debenture does not restrict the Trust from
incurring additional indebtedness for borrowed money or from mortgaging,
pledging or charging its properties to secure any indebtedness.
CONVERSION PRIVILEGE
The holder of the Special Debenture has the option, at any time prior to the
Time of Expiry (defined as 4:30 p.m. (Calgary time) on the earlier of: (a) one
(1) business day after the date of issuance of the receipt from the securities
commissions in the provinces of Alberta and Ontario (the "Securities
Commissions") for a prospectus qualifying the distribution of the Underlying
Debentures to be issued upon conversion of the Special Debenture (a "Qualifying
Prospectus"); (b) June 30, 2004 if a receipt for a Qualifying Prospectus has not
been obtained from the Securities Commissions due to circumstances beyond the
control of the Trust; and (c) June 30, 2005) and the last business day
immediately preceding the date specified by the Trust for redemption of the
whole or any portion of the Special Debenture, to convert the whole or any part
of the Special Debenture which is $10,000,000 or an integral multiple thereof
into an Underlying Debenture with a denomination of $10,000,000 for each
$10,000,000 principal amount of Special Debenture being so converted. The holder
of the Special Debenture shall be entitled to receive accrued and unpaid
interest in respect of the principal amount of the Special Debenture surrendered
for conversion up to but excluding the date of conversion.
The right of the holder of the Special Debenture to convert the Special
Debenture into an Underlying Debenture on the basis of an Underlying Debenture
with a denomination of $10,000,000 for each $10,000,000 principal amount of the
Special Debenture so converted shall be deemed to be exercised in respect of the
entire outstanding principal amount of the Special Debenture at the Time of
Expiry and the Underlying Debenture issuable thereby shall be deemed to be
issued to the holder at the Time of Expiry.
REDEMPTION AND PURCHASE
The Special Debenture may be redeemed in whole or in part in multiples of
$10,000,000 from time to time at the option of the Trust for cash on not more
than 60 days and not less than 30 days prior notice and before maturity, at a
redemption price of $10,000,000 per $10,000,000 principal amount of Special
Debenture, plus accrued and unpaid interest thereon, if any.
The Trust has the right to purchase the Special Debenture in the market, by
tender or by private contract.
PAYMENT UPON MATURITY
At maturity, the Trust will repay the indebtedness represented by the Special
Debenture by paying to the holder in lawful money of Canada an amount equal to
the principal amount of the outstanding Special Debenture which has matured,
together with accrued and unpaid interest thereon. The Trust may, at its option,
on not more than 60 days and not less than 30 days prior notice and subject to
applicable regulatory approval, elect to satisfy its obligation to pay the
principal amount of the Special Debenture which has matured by issuing Trust
Units to the holder of the Special Debenture. Any accrued and unpaid interest
thereon will be paid in cash. The number of Trust Units to be issued will be
determined by dividing the principal amount of the outstanding Special Debenture
which has matured by 97.5% of the current market price on the maturity date. No
fractional Trust Units will be issued on maturity but in lieu thereof the Trust
shall satisfy fractional interests by a cash payment equal to the current market
price of any fractional interest.
The term "current market price" is defined in the Special Debenture to mean the
weighted average trading price of the Trust Units on the TSX for the 10
consecutive trading days ending on the fifth trading day preceding the maturity
date.
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SUBORDINATION
The payment of the principal of, and interest on, the Special Debenture is
subordinated in right of payment, as set forth in the Special Debenture, to the
prior payment in full of all Senior Indebtedness of the Trust. "Senior
Indebtedness" of the Trust is defined in the Special Debenture as the principal
of and premium, if any, and interest on all indebtedness, liabilities and
obligations of the Trust (whether outstanding as at the date of the Special
Debenture or thereafter created, incurred, assigned or guaranteed) in connection
with the acquisition, holding or maintaining by the Trust of any businesses,
properties or other assets or for moneys borrowed or raised by whatever means
(including, without limitation, by means of commercial paper, bankers'
acceptances, letters of credit, debt instruments, bank debt and financial
leases, and any liability evidenced by bonds, debentures, notes or similar
instruments), or for any payment obligation under any hedging, swap or other
derivative agreement or in connection with the acquisition, holding or
maintaining of any businesses, properties or other assets or for moneys borrowed
or raised by whatever means (including, without limitation, by means of
commercial paper, bankers' acceptances, letters of credit, debt instruments,
bank debt and financial leases, and any liability evidenced by bonds,
debentures, notes or similar instruments) by others including, without
limitation, any subsidiary of the Trust, for payment of which the Trust is
responsible or liable, whether absolutely or contingently, and without
limitation of the foregoing pursuant to any indebtedness of any subsidiary of
the Trust payment for which the Trust is responsible or liable as obligor or
guarantor; and renewals, extensions, restructurings and refundings of any such
indebtedness, liabilities or obligations; other than indebtedness evidenced by
the Special Debenture and all other existing and future debentures or other
instruments of the Trust which, by the terms of the instrument creating or
evidencing the indebtedness, is expressed to be PARI PASSU with, or subordinate
in right of payment to, the Special Debenture.
The Special Debenture provides that in the event of any insolvency or bankruptcy
proceedings, or any receivership, liquidation, reorganization or other similar
proceedings relative to the Trust, or to its property or assets, or in the event
of any proceedings for voluntary liquidation, dissolution or other winding-up of
the Trust, whether or not involving insolvency or bankruptcy, or any marshalling
of the assets and liabilities of the Trust, then those holders of Senior
Indebtedness, including any indebtedness to trade creditors, will receive
payment in full before the holder of the Special Debenture will be entitled to
receive any payment or distribution of any kind or character, whether in cash,
property or securities, which may be payable or deliverable in any such event in
respect of the Special Debenture or any unpaid interest accrued thereon. The
Special Debenture also provides that the Trust will not make any payment, and
the holder of the Special Debenture will not be entitled to demand, institute
proceedings for the collection of, or receive any payment or benefit (including,
without any limitation, by set-off, combination of accounts or realization of
security or otherwise in any manner whatsoever) on account of indebtedness
represented by the Special Debenture (a) in a manner inconsistent with the terms
(as they exist on the date of issue) of the Special Debenture or (b) at any time
when an event of default has occurred under the Senior Indebtedness and is
continuing and notice of such event of default has been given by or on behalf of
the holders of Senior Indebtedness to the Trust, unless the Senior Indebtedness
has been repaid in full.
The Special Debenture is also effectively subordinate to claims of creditors of
the Trust's subsidiaries except to the extent the Trust is a creditor of such
subsidiaries ranking at least PARI PASSU with such other creditors.
Specifically, the Special Debenture is subordinated in right of payment to the
prior payment in full of all indebtedness under the credit facilities of ARC
Resources and ARC Sask.
PRIORITY OVER TRUST DISTRIBUTIONS
The Trust Indenture provides that certain expenses of the Trust must be deducted
in calculating the amount to be distributed to the Unitholders. Accordingly, the
funds required to satisfy the interest payable on the Special Debenture, as well
as the amount payable upon redemption or maturity of the Special
49
Debenture or upon an Event of Default (as defined below), will be deducted and
withheld from the amounts that would otherwise be payable as distributions to
Unitholders.
CHANGE OF CONTROL OF THE TRUST
Within 30 days following the occurrence of a change of control of the Trust
involving the acquisition of voting control or direction over 66?% or more of
the Trust Units (a "Change of Control"), the Trust will be required to make an
offer in writing to purchase the Special Debenture then outstanding (the
"Special Debenture Offer"), at a price equal to 101% of the principal amount
thereof plus accrued and unpaid interest (the "Special Debenture Offer Price").
The Special Debenture contains notification and repurchase provisions requiring
the Trust to give written notice to the holder of the occurrence of a Change of
Control within 30 days of such event together with the Special Debenture Offer.
INTEREST PAYMENT OPTION
The Trust may elect, from time to time, to satisfy its obligation to pay
interest on the Special Debenture (the "Interest Obligation"), on the date it is
payable under the Special Debenture (an "Interest Payment Date"), by designating
a number of Trust Units and issuing such Trust Units in accordance with
applicable securities legislation, on such terms and conditions as the Trust may
determine, for proceeds at least equal to the Interest Obligation and use such
proceeds to pay the Interest Obligation to the holder.
Neither the Trust's making of the Unit Interest Payment Election nor the
consummation of sales of Trust Units will (a) result in the holder of the
Special Debenture not being entitled to receive on the applicable Interest
Payment Date cash in an aggregate amount equal to the interest payable on such
Interest Payment Date, or (b) entitle such holder to receive any Trust Units in
satisfaction of the Interest Obligation.
EVENTS OF DEFAULT
The Special Debenture provides that an event of default ("Event of Default") in
respect of the Special Debenture will occur if any one or more of the following
described events has occurred and is continuing with respect of the Special
Debenture: (a) failure for 10 days to pay interest on the Special Debenture when
due; (b) failure to pay principal or premium, if any, on the Special Debenture
when due, whether at maturity, upon redemption, by declaration or otherwise; (c)
certain events of bankruptcy, insolvency or reorganization of the Trust under
bankruptcy or insolvency laws; or (d) default in the observance or performance
of any material covenant or condition of the Special Debenture and continuance
of such default for a period of 30 days after notice in writing has been given
by the Holder to the Trust specifying such default and requiring the Trust to
remedy such default. If an Event of Default has occurred and is continuing, the
holder may, in its discretion, declare the principal of and interest on the
Special Debenture to be immediately due and payable.
LIMITATION ON ISSUANCE OF ADDITIONAL DEBENTURES
The Special Debenture provides that the Trust shall not issue additional notes
or debentures of equal ranking to the Special Debenture if the principal amount
of all issued and outstanding debentures of the Trust exceeds 25% of the Total
Market Capitalization of the Trust immediately after the issuance of such
additional debentures. "Total Market Capitalization" is defined in the Special
Debenture as the total principal amount of all issued and outstanding debentures
of the Trust which are convertible at the option of the holder into Underlying
Debentures and/or Trust Units plus the amount obtained by multiplying the number
of issued and outstanding Trust Units of the Trust and Exchangeable Shares (such
number of outstanding Exchangeable Shares to be calculated by multiplying the
number of outstanding
50
Exchangeable Shares by the then current exchange ratio for exchange of such
Exchangeable Share into Trust Units) by the current market price of the Trust
Units on the relevant date.
REGISTRATION SYSTEM FOR DEBENTURES
The Special Debenture was issued in fully registered and certificate form.
Interest will be paid by prepaid mail to the registered holder or by such other
means as may be agreed to by the registered holder by cheque or by wire
transfer. Payment of principal and interest due, at maturity or on a redemption
date, will be paid by cheque or wire transfer or, if all or a portion of
principal is paid in the form of Trust Units, by issuing and delivering a
certificate for the applicable number of Trust Units.
UNDERLYING DEBENTURES
The Trust is authorized to issue up to $320,000,000 principal amount of
Underlying Debentures on the conversion or deemed conversion of the Special
Debenture. The following is a summary of the material attributes and
characteristics of the Underlying Debentures. This summary does not purport to
be complete and is subject to, and qualified by, reference to the terms of the
Underlying Debenture Trust Indenture with respect to the Underlying Debentures.
GENERAL
The Underlying Debentures will be issued under the Underlying Debenture Trust
Indenture dated as of April 16, 2003, made among the Trust, ARC Resources and
Computershare Trust Company of Canada (the "Debenture Trustee"), as trustee. The
Underlying Debentures authorized for issue immediately will be limited in
aggregate principal amount to $320,000,000. The Trust may, however, from time to
time, without the consent of the holders of the Underlying Debentures but
subject to the limitations described herein, issue additional debentures of a
different series under the Underlying Debenture Trust Indenture, in addition to
the Underlying Debentures offered hereby.
The Underlying Debentures will be dated as of the date of conversion of the
Special Debenture and will mature on June 30, 2008. The Underlying Debentures
will be issuable only in denominations of $10,000,000 and integral multiples
thereof.
The Underlying Debentures will bear interest from the date of issue at 8% per
annum until, but not including June 30, 2005, and from June 30, 2005 at 10% per
annum, which will be payable in cash in equal quarterly payments in arrears on
March 31, June 30, September 30 and December 31 in each year. The first interest
payment will include interest accrued from the date of issue to the first such
payment date.
The principal amount of the Underlying Debentures will be payable in lawful
money of Canada or, at the option of the Trust and subject to applicable
regulatory approval, by payment of Trust Units as further described under
"Payment upon Redemption or Maturity" and "Redemption and Purchase". The
interest on the Underlying Debentures will be payable in lawful money of Canada
including, at the option of the Trust and subject to applicable regulatory
approval, with proceeds from the sale of additional Trust Units in accordance
with the Unit Interest Payment Obligation as described under "Interest Payment
Option".
The Underlying Debentures will be direct obligations of the Trust and will not
be secured by any mortgage, pledge, hypothec or other charge and will be
subordinated to other liabilities of the Trust as described under
"Subordination". The Underlying Debenture Trust Indenture does not restrict the
Trust from incurring additional indebtedness for borrowed money or from
mortgaging, pledging or charging its
51
properties to secure any indebtedness except as set forth under "Limitation on
Issuance of Additional Debentures".
CONVERSION PRIVILEGE
The Underlying Debentures will be convertible at the holder's option into fully
paid and non-assessable Trust Units at any time prior to the close of business
on the earlier of June 30, 2008 and the business day immediately preceding the
date specified by the Trust for redemption of the Underlying Debentures, at a
conversion price of $11.84 per Trust Unit where the date of conversion is on or
before June 30, 2005, being a conversion rate of 844,595 Trust Units for each
$10,000,000 principal amount of Debentures and at a conversion price of $11.38
per Trust Unit where the date of conversion is after June 30, 2005, being a
conversion rate of 878,735 Trust Units for each $10,000,000 principal amount of
Debentures. No adjustment will be made for distributions on Trust Units issuable
upon conversion or for interest accrued on Debentures surrendered for
conversion; however, holders converting their Debentures will receive accrued
and unpaid interest thereon.
Subject to the provisions thereof, the Underlying Debenture Trust Indenture
provides for the adjustment of the conversion price in certain events including:
(a) the subdivision or consolidation of the outstanding Trust Units; (b) the
distribution of Trust Units to holders of Trust Units by way of distribution or
otherwise other than an issue of securities to holders of Trust Units who have
elected to receive distributions in securities of the Trust in lieu of receiving
cash distributions paid in the ordinary course; (c) the issuance of options,
rights or warrants to holders of Trust Units entitling them to acquire Trust
Units or other securities convertible into Trust Units at less than 95% of the
then current market price (as defined below under "Payment upon Redemption or
Maturity") of the Trust Units; and (d) the distribution to all holders of Trust
Units of any securities or assets (other than cash distributions and equivalent
distributions in securities paid in lieu of cash distributions in the ordinary
course). There will be no adjustment of the conversion price in respect of any
event described in (b), (c) or (d) above if the holders of the Underlying
Debentures are allowed to participate as though they had converted their
Debentures prior to the applicable record date or effective date. The Trust will
not be required to make adjustments in the conversion price unless the
cumulative effect of such adjustments would change the conversion price by at
least 1%.
In the case of any reclassification or capital reorganization (other than a
change resulting from consolidation or subdivision) of the Trust Units or in the
case of any consolidation, amalgamation or merger of the Trust with or into any
other entity, or in the case of any sale or conveyance of the properties and
assets of the Trust as, or substantially as, an entirety to any other entity, or
a liquidation, dissolution or winding-up of the Trust, the terms of the
conversion privilege shall be adjusted so that each holder of a Debenture shall,
after such reclassification, capital reorganization, consolidation,
amalgamation, merger, sale, conveyance, liquidation, dissolution or winding-up,
be entitled to receive the number of Trust Units such holder would be entitled
to receive if on the effective date thereof, it had been the holder of the
number of Trust Units into which the Debenture was convertible prior to the
effective date of such reclassification, capital reorganization, consolidation,
amalgamation, merger, sale, conveyance, liquidation, dissolution or winding-up.
No fractional Trust Units will be issued on any conversion but in lieu thereof
the Trust shall satisfy fractional interests by a cash payment equal to the
current market price of any fractional interest.
REDEMPTION AND PURCHASE
The Underlying Debentures may be redeemed in whole or in part from time to time
at the option of the Trust for cash on not more than 60 days and not less than
30 days prior notice, at a redemption price of $10,000,000 per Debenture and
before maturity, plus accrued and unpaid interest thereon, if any.
52
In connection with the redemption of the Underlying Debentures, the Trust may,
subsequent to June 30, 2003 at its option and subject to regulatory approval,
elect (the "Debenture Trust Unit Redemption Election") to satisfy its obligation
to pay up to, but not more than, 50% (the "Trust Unit Redemption Cap") of the
aggregate redemption price of the Underlying Debentures to be redeemed by
issuing and delivering to the holders of such Debentures, such number of Trust
Units as is obtained by dividing the portion of the redemption price to be
redeemed by the issuance and delivery of Trust Units by 97.5% of the then
current market price (as defined below under "Payment upon Redemption or
Maturity") in effect on such redemption date. Interest accrued and unpaid on the
Underlying Debentures on the redemption date will be paid to the holder in cash.
The Trust may not elect the Debenture Trust Unit Redemption Election at any time
in any quarter if the result of such election is that the holders of the
Underlying Debentures will receive Trust Units within a sixty day period from
the immediately preceding time that such holders received Trust Units as a
result of the Debenture Trust Unit Redemption Election. Subsequent to June 30,
2003 to and including June 30, 2005, the Trust may only make a Debenture Trust
Unit Redemption Election with respect to Debentures with an aggregate principal
amount of up to, but not more than, $40,000,000 in each calendar quarter at a
redemption price of $10,000,000 per Debenture plus accrued and unpaid interest,
subject, at all times, to the Trust Unit Redemption Cap. The aggregate principal
amount of Debentures available for the Debenture Trust Unit Redemption Election
in any calendar quarter after June 30, 2003 shall be increased to include any
amounts which the Trust was entitled to redeem using the Debenture Trust Unit
Redemption Election, but did not so redeem, in previous calendar quarters prior
to the redemption date. Subsequent to June 30, 2005, the Debenture Trust Unit
Redemption Election may be used to redeem, at the option of the Trust, the
entire principal amount, subject, at all times, to the Trust Unit Redemption
Cap, of the Underlying Debentures in whole or in part from time to time at a
redemption price of $10,000,000 per Debenture plus accrued and unpaid interest.
Notwithstanding the foregoing, the Trust may not elect the Debenture Trust Unit
Redemption Election at any time if the result of such election is that the
holders of the Underlying Debentures cannot convert the whole of the remaining
principal amount of such Debentures (after giving effect to the redemption of
Debentures pursuant to such Debenture Trust Unit Redemption Election) into Trust
Units at the conversion price in effect on the redemption date if, assuming such
conversion on the redemption date, the Trust may be required to issue an
aggregate in excess of 34,046,836 Trust Units under the Underlying Debentures.
In the case of redemption of less than all of the Underlying Debentures, the
Underlying Debentures to be redeemed will be selected by the Debenture Trustee
on a pro rata basis or in such other manner as the Debenture Trustee deems
equitable, subject to the consent of the TSX.
The Trust will have the right to purchase Debentures in the market, by tender or
by private contract.
PAYMENT UPON REDEMPTION OR MATURITY
At maturity, the Trust will repay the indebtedness represented by the Underlying
Debentures by paying to the Debenture Trustee in lawful money of Canada an
amount equal to the aggregate redemption price of the outstanding Debentures
which are to be redeemed or the principal amount of the outstanding Debentures
which have matured, together with accrued and unpaid interest thereon. The Trust
may, at its option, on not more than 60 days and not less than 30 days prior
notice and subject to applicable regulatory approval, elect to satisfy its
obligation to pay the redemption price of the Underlying Debentures which are to
be redeemed or the principal amount of the Underlying Debentures which have
matured, as the case may be, by issuing Trust Units to the holders of the
Underlying Debentures, subject in the case of redemption to the Trust Unit
Redemption Cap and other provisions described under "Redemption and Purchase".
Any accrued and unpaid interest thereon will be paid in cash. The number of
Trust Units to be issued will be determined by dividing the aggregate redemption
price of the
53
outstanding Debentures which are to be redeemed or the principal
amount of the outstanding Debentures which have matured, as the case may be, by
97.5% of the current market price on the date fixed for redemption or the
maturity date, as the case may be, subject in the case of redemption to the
Trust Unit Redemption Cap and other provisions described under "Redemption and
Purchase". No fractional Trust Units will be issued on redemption or maturity
but in lieu thereof the Trust shall satisfy fractional interests by a cash
payment equal to the current market price of any fractional interest.
The term "current market price" is defined in the Underlying Debenture Trust
Indenture to mean the weighted average trading price of the Trust Units on the
TSX for the 10 consecutive trading days ending on the fifth trading day
preceding the date fixed for redemption or the maturity date, as the case may
be.
SUBORDINATION
The payment of the principal of, and interest on, the Underlying Debentures is
subordinated in right of payment, as set forth in the Underlying Debenture Trust
Indenture, to the prior payment in full of all Senior Indebtedness of the Trust.
"Senior Indebtedness" of the Trust is defined in the Underlying Debenture Trust
Indenture as the principal of and premium, if any, and interest on all
indebtedness, liabilities and obligations of the Trust (whether outstanding as
at the date of the Underlying Debenture Trust Indenture or thereafter created,
incurred, assigned or guaranteed) in connection with the acquisition, holding or
maintaining by the Trust of any businesses, properties or other assets or for
moneys borrowed or raised by whatever means (including, without limitation, by
means of commercial paper, bankers' acceptances, letters of credit, debt
instruments, bank debt and financial leases, and any liability evidenced by
bonds, debentures, notes or similar instruments), or for any payment obligation
under any hedging, swap or other derivative agreement or in connection with the
acquisition, holding or maintaining of any businesses, properties or other
assets or for moneys borrowed or raised by whatever means (including, without
limitation, by means of commercial paper, bankers' acceptances, letters of
credit, debt instruments, bank debt and financial leases, and any liability
evidenced by bonds, debentures, notes or similar instruments) by others
including, without limitation, any subsidiary of the Trust, for payment of which
the Trust is responsible or liable, whether absolutely or contingently, and
without limitation of the foregoing pursuant to any indebtedness of any
subsidiary of the Trust payment for which the Trust is responsible or liable as
obligor or guarantor; and renewals, extensions, restructurings and refundings of
any such indebtedness, liabilities or obligations; other than indebtedness
evidenced by the Underlying Debentures and all other existing and future
debentures or other instruments of the Trust which, by the terms of the
instrument creating or evidencing the indebtedness, is expressed to be PARI
PASSU with, or subordinate in right of payment to, the Underlying Debentures.
The Underlying Debenture Trust Indenture provides that in the event of any
insolvency or bankruptcy proceedings, or any receivership, liquidation,
reorganization or other similar proceedings relative to the Trust, or to its
property or assets, or in the event of any proceedings for voluntary
liquidation, dissolution or other winding-up of the Trust, whether or not
involving insolvency or bankruptcy, or any marshalling of the assets and
liabilities of the Trust, then those holders of Senior Indebtedness, including
any indebtedness to trade creditors, will receive payment in full before the
holders of Debentures will be entitled to receive any payment or distribution of
any kind or character, whether in cash, property or securities, which may be
payable or deliverable in any such event in respect of any of the Underlying
Debentures or any unpaid interest accrued thereon. The Underlying Debenture
Trust Indenture also provides that the Trust will not make any payment, and the
holders of the Underlying Debentures will not be entitled to demand, institute
proceedings for the collection of, or receive any payment or benefit (including,
without any limitation, by set-off, combination of accounts or realization of
security or otherwise in any manner whatsoever) on account of indebtedness
represented by the Underlying Debentures (a) in a manner inconsistent with the
terms (as they exist on the date of issue) of the Underlying Debentures or (b)
at any time when an event of default has occurred under the Senior
54
Indebtedness and is continuing and notice of such event of default has been
given by or on behalf of the holders of Senior Indebtedness to the Trust, unless
the Senior Indebtedness has been repaid in full.
The Underlying Debentures will also be effectively subordinate to claims of
creditors of the Trust's subsidiaries except to the extent the Trust is a
creditor of such subsidiaries ranking at least PARI PASSU with such other
creditors. Specifically, the Underlying Debentures will be subordinated in right
of payment to the prior payment in full of all indebtedness under the credit
facilities of ARC Resources and ARC Sask.
PRIORITY OVER TRUST DISTRIBUTIONS
The Trust Indenture provides that certain expenses of the Trust must be deducted
in calculating the amount to be distributed to the Unitholders. Accordingly, the
funds required to satisfy the interest payable on the Underlying Debentures, as
well as the amount payable upon redemption or maturity of the Underlying
Debentures or upon an Event of Default (as defined below), will be deducted and
withheld from the amounts that would otherwise be payable as distributions to
Unitholders.
CHANGE OF CONTROL OF THE TRUST
Within 30 days following the occurrence of a change of control of the Trust
involving the acquisition of voting control or direction over 66?% or more of
the Trust Units (a "Change of Control"), the Trust will be required to make an
offer in writing to purchase all of the Underlying Debentures then outstanding
(the "Debenture Offer"), at a price equal to 101% of the principal amount
thereof plus accrued and unpaid interest (the "Debenture Offer Price").
The Underlying Debenture Trust Indenture contains notification and repurchase
provisions requiring the Trust to give written notice to the Debenture Trustee
of the occurrence of a Change of Control within 30 days of such event together
with the Debenture Offer. The Debenture Trustee will thereafter promptly mail to
each holder of Debentures a notice of the Change of Control together with a copy
of the Debenture Offer to repurchase all the outstanding Debentures.
If 90% or more of the aggregate principal amount of the Underlying Debentures
outstanding on the date of the giving of notice of the Change of Control have
been tendered to the Trust pursuant to the Debenture Offer, the Trust will have
the right and obligation to redeem all the remaining Debentures at the Debenture
Offer Price. Notice of such redemption must be given by the Trust to the
Debenture Trustee within 10 days following the expiry of the Debenture Offer,
and as soon as possible thereafter, by the Debenture Trustee to the holders of
the Underlying Debentures not tendered pursuant to the Debenture Offer.
INTEREST PAYMENT OPTION
The Trust may elect, from time to time, to satisfy its obligation to pay
interest on the Underlying Debentures (the "Interest Obligation"), on the date
it is payable under the Underlying Debenture Trust Indenture (an "Interest
Payment Date"), by delivering sufficient Trust Units to the Debenture Trustee to
satisfy all or any part of the Interest Obligation in accordance with the
Underlying Debenture Trust Indenture (the "Unit Interest Payment Election"). The
Underlying Debenture Trust Indenture provides that, upon such election, the
Debenture Trustee shall (a) accept delivery from the Trust of Trust Units, (b)
accept bids with respect to, and consummate sales of, such Trust Units, each as
the Trust shall direct in its absolute discretion, (c) invest the proceeds of
such sales in short-term permitted government securities (as defined in the
Underlying Debenture Trust Indenture) which mature prior to the applicable
Interest Payment Date, and use the proceeds received from such permitted
government securities, together with
55
any proceeds from the sale of Trust Units not invested as aforesaid, to satisfy
the Interest Obligation, and (d) perform any other action necessarily incidental
thereto.
The Underlying Debenture Trust Indenture sets forth the procedures to be
followed by the Trust and the Debenture Trustee in order to effect the Unit
Interest Payment Election. If a Unit Interest Payment Election is made, the sole
right of a holder of Debentures in respect of interest will be to receive cash
from the Debenture Trustee out of the proceeds of the sale of Trust Units (plus
any amount received by the Debenture Trustee from the Trust attributable to any
fractional Trust Units) in full satisfaction of the Interest Obligation, and the
holder of such Debentures will have no further recourse to the Trust in respect
of the Interest Obligation.
Neither the Trust's making of the Unit Interest Payment Election nor the
consummation of sales of Trust Units will (a) result in the holders of the
Underlying Debentures not being entitled to receive on the applicable Interest
Payment Date cash in an aggregate amount equal to the interest payable on such
Interest Payment Date, or (b) entitle such holders to receive any Trust Units in
satisfaction of the Interest Obligation.
EVENTS OF DEFAULT
The Underlying Debenture Trust Indenture provides that an event of default
("Event of Default") in respect of the Underlying Debentures will occur if any
one or more of the following described events has occurred and is continuing
with respect of the Underlying Debentures: (a) failure for 10 days to pay
interest on the Underlying Debentures when due; (b) failure to pay principal or
premium, if any, on the Underlying Debentures when due, whether at maturity,
upon redemption, by declaration or otherwise; (c) certain events of bankruptcy,
insolvency or reorganization of the Trust under bankruptcy or insolvency laws;
or (d) default in the observance or performance of any material covenant or
condition of the Underlying Debenture Trust Indenture and continuance of such
default for a period of 30 days after notice in writing has been given by the
Debenture Trustee to the Trust specifying such default and requiring the Trust
to remedy such default. If an Event of Default has occurred and is continuing,
the Debenture Trustee may, in its discretion, and shall upon request of holders
of not less than 25% of the principal amount of Debentures then outstanding,
declare the principal of and interest on all outstanding Debentures to be
immediately due and payable. In certain cases, the holders of more than 50% of
the principal amount of the Underlying Debentures then outstanding may, on
behalf of the holders of all Debentures, waive any Event of Default and/or
cancel any such declaration upon such terms and conditions as such holders shall
prescribe.
OFFERS FOR DEBENTURES
The Underlying Debenture Trust Indenture contains provisions to the effect that
if an offer is made for the Underlying Debentures which is a take-over bid for
Debentures within the meaning of the SECURITIES ACT (Alberta) and not less than
90% of the Underlying Debentures (other than Debentures held at the date of the
take-over bid by or on behalf of the offeror or associates or affiliates of the
offeror) are taken up and paid for by the offeror, the offeror will be entitled
to acquire the Underlying Debentures held by the holders of Debentures who did
not accept the offer for the same consideration per Underlying Debenture payable
or paid, as the case may be, under the offer.
MODIFICATION
The rights of the holders of the Underlying Debentures as well as any other
series of debentures that may be issued under the Underlying Debenture Trust
Indenture may be modified in accordance with the terms of the Underlying
Debenture Trust Indenture. For that purpose, among others, the Underlying
Debenture Trust Indenture contains certain provisions which make binding on all
Debenture holders resolutions
56
passed at meetings of the holders of Debentures by votes cast thereat by holders
of not less than 66?% of the principal amount of the Underlying Debentures
present at the meeting or represented by proxy, or rendered by instruments in
writing signed by the holders of not less than 66?% of the principal amount of
the Underlying Debentures then outstanding. In certain cases, the modification
will, instead or in addition, require assent by the holders of the required
percentage of Debentures of each particularly affected series.
LIMITATION ON ISSUANCE OF ADDITIONAL DEBENTURES
The Underlying Debenture Trust Indenture provides that the Trust shall not issue
additional convertible debentures of equal ranking to the Underlying Debentures
if the principal amount of all issued and outstanding convertible debentures of
the Trust exceeds 25% of the Total Market Capitalization of the Trust
immediately after the issuance of such additional convertible debentures. "Total
Market Capitalization" will be defined in the Underlying Debenture Trust
Indenture as the total principal amount of all issued and outstanding debentures
of the Trust which are convertible at the option of the holder into Trust Units
of the Trust plus the amount obtained by multiplying the number of issued and
outstanding Trust Units of the Trust and Exchangeable Shares (such number of
outstanding Exchangeable Shares to be calculated by multiplying the number of
outstanding Exchangeable Shares by the then current exchange ratio for exchange
of such Exchangeable Share into Trust Units) by the current market price of the
Trust Units on the relevant date.
REGISTRATION SYSTEM FOR DEBENTURES
The Underlying Debentures will be issued in fully registered and certificate
form. A purchaser acquiring a beneficial interest in the Underlying Debentures
will be entitled to a certificate or other instrument from the Debenture Trustee
evidencing that purchaser's interest therein.
Interest will be paid by cheque drawn on the Trust and sent by prepaid mail to
the registered holder or by such other means as may become customary for the
payment of interest. Payment of principal, including payment in the form of
Trust Units if applicable, and interest due, at maturity or on a redemption
date, will be paid upon surrender of Debenture certificates at any office of the
Debenture Trustee or as otherwise specified in the Underlying Debenture Trust
Indenture.
LIMITATION ON NON-RESIDENT OWNERSHIP
In order for the Trust to maintain its status as a mutual fund trust under the
Tax Act, the Trust must not be established or maintained primarily for the
benefit of non-residents of Canada ("non-residents") within the meaning of the
Tax Act. Accordingly, the Trust Indenture provides that the Trust, by or through
ARC Resources on the Trust's behalf, shall, among other things, take all
necessary steps to monitor the ownership of the Trust Units in order that the
Trust complies with the requirements under the Tax Act for "unit trusts" and
"mutual fund trusts" at all relevant times such that the Trust maintains the
status of a unit trust and a mutual fund trust for the purposes of the Tax Act.
The Trust Indenture also provides that if at any time the Trust or ARC Resources
becomes aware that the beneficial owners of 50% or more of the Trust Units then
outstanding are or may be non-residents or that such a situation is imminent,
the Trust, by or through ARC Resources on the Trust's behalf, shall take such
action as may be necessary to carry out the foregoing intentions.
RIGHT OF REDEMPTION
Trust Units will be redeemable at any time on demand by the holders thereof upon
delivery to the Trust of the certificate or certificates representing such Trust
Units, accompanied by a duly completed and properly executed notice requesting
redemption. Upon receipt of the redemption request by the Trust, all rights to
and under the Trust Units tendered for redemption shall be surrendered and the
holder thereof
57
shall be entitled to receive a price per Unit ("Market Redemption Price") equal
to the lesser of: (i) 90% of the market price, being the weighted average
trading price of the Trust Units on the principal market on which the Trust
Units are quoted for trading during the 10 trading day period commencing
immediately after the date on which the Trust Units are surrendered for
redemption; and (ii) the "closing market price" on the principal market on which
the Trust Units are quoted for trading on the date that the Trust Units are
surrendered for redemption.
The aggregate cash Market Redemption Price payable by the Trust in respect of
any Trust Units surrendered for redemption during any calendar month shall be
satisfied by way of a cash payment on the last day of the following month;
provided that the entitlement of Unitholders to receive cash upon the redemption
of their Trust Units is subject to a number of conditions, including the
condition that the total amount payable by the Trust in respect of such Trust
Units and all other Trust Units tendered for retraction in the same calendar
month must not exceed $100,000 provided that such condition may be waived at the
discretion of the Board of Directors of ARC Resources in respect of any calendar
month.
If a Unitholder is not entitled to receive cash upon the redemption of Trust
Units then the Market Redemption Price for such Trust Units shall be paid on the
last day of the following month by the Trust distributing unsecured promissory
notes of ARC Resources ("ARC Resources Notes") having an aggregate principal
amount equal to the aggregate Market Redemption Price of the Trust Units
tendered for redemption, which notes will bear interest at the rate of 6% per
annum and will mature on the 15th anniversary of the date of issuance.
It is anticipated that the foregoing retraction right will not be the primary
mechanism for holders of Trust Units to dispose of their Trust Units. ARC
Resources Notes which may be distributed IN SPECIE to Unitholders in connection
with a redemption will not be listed on any stock exchange and no market is
expected to develop in the ARC Resources Notes. ARC Resources Notes may be
subject to resale restrictions under applicable securities laws. ARC Resources
Notes so distributed may be qualified investments for trusts governed by
registered retirement savings plans, registered retirement income trusts and
deferred profit sharing plans.
TERMINATION OF THE TRUST
The Unitholders may vote to terminate the Trust at any meeting of the
Unitholders, subject to the following: (a) a vote may only be held if requested
in writing by the holders of not less than 20% of the Trust Units; (b) a quorum
of 50% of the issued and outstanding Trust Units is present in person or by
proxy; and (c) the termination must be approved by Special Resolution of the
Unitholders.
Unless the Trust is terminated or extended by vote of the Unitholders earlier,
the Trustee shall commence to wind-up the affairs of the Trust on December 31,
2095. In the event that the Trust is wound-up, the Trustee will liquidate all
the assets of the Trust, pay, retire, discharge or make provision for some or
all obligations of the Trust and then distribute the remaining proceeds of sale
to Unitholders.
REPORTING TO UNITHOLDERS
The financial statements of the Trust will be audited annually by an independent
recognized firm of chartered accountants. The audited financial statements of
the Trust, together with the report of such chartered accountants, will be
mailed by the Trustee to Unitholders and the unaudited interim financial
statements of the Trust will be mailed to Unitholders within the periods
prescribed by securities legislation. The year end of the Trust is December 31.
The Trust will be subject to the continuous disclosure obligations under all
applicable securities legislation.
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Unitholders are entitled to inspect, during normal business hours, at the
offices of the Trustee, and, upon payment of reasonable reproduction costs, to
receive photocopies of the Royalty Agreement, the Trust Indenture and a listing
of the registered holders of Trust Units.
DISTRIBUTION REINVESTMENT AND OPTIONAL TRUST UNIT PURCHASE PLAN
A Distribution Reinvestment and Optional Trust Unit Purchase Plan has been
established for the Trust to provide Unitholders who are residents of Canada
(within the meaning of the Tax Act) with a method of reinvesting cash
distributions by purchasing additional Trust Units.
UNITHOLDER RIGHTS PROTECTION PLAN
On June 7, 1999, the Unitholders approved a Unitholder Rights Protection Plan
(the "Rights Plan"), which was implemented pursuant to an agreement (the "Rights
Plan Agreement") between ARC Resources and Montreal Trust Company (as of April
10, 2002, Computershare Trust Company of Canada), as rights agent immediately
following approval by Unitholders at the meeting held on such date. The purposes
of the Rights Plan, are, firstly, to afford both Unitholders and the Board of
Directors of ARC Resources adequate time to assess an offer made for shares of
the Trust and to pursue, explore and develop alternative courses of action in an
attempt to maximize unitholder value. Secondly, the purpose of the Rights Plan
is to protect Unitholders from unfair, abusive or coercive takeover strategies,
including the acquisition of control of the Trust by a bidder in a transaction
or series of transactions that does not treat all Unitholders equally or fairly
or that does not afford all Unitholders an equal opportunity to share in any
premium paid upon an acquisition of control.
The Rights Plan is summarized below, subject to being qualified in its entirety
by the actual text of the Rights Plan Agreement.
SUMMARY OF THE OPERATION OF THE RIGHTS PLAN
In order to implement the Rights Plan, the Board of Directors of ARC Resources
authorized the issuance, on June 7, 1999, of one right (a "Right") in respect of
each outstanding Trust Unit to holders of record. Initially, the Rights are not
exercisable and the certificates representing Units also represent the Rights
and until the Separation Time, as defined below, the Rights will be transferred
with the associated Trust Units.
The Rights will be exercisable and begin to trade separately from the Trust
Units at the close of business on the tenth trading day after the earlier of:
(a) the first date of public announcement by the Trust or a person
or a group of affiliated or associated persons (an "Acquiring
Person") that an Acquiring Person has acquired beneficial
ownership of 20% or more of the outstanding Trust Units other
than as a result of:
(i) a reduction of the number of Trust Units outstanding;
(ii) a Permitted Bid or Competing Permitted Bid (as
defined below);
(iii) acquisitions of Units in respect of which the Board
of Directors of ARC Resources has waived the
provisions of the Rights Plan; or
(iv) certain types of proportionate acquisitions; and
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(b) the date of the commencement of, or the first public
announcement of the intent of any person to commence, a
takeover bid to acquire 20% or more of the outstanding Trust
Units (other than a Permitted Bid or Competing Permitted Bid,
as defined below);
or such later date as may from time to time be determined by the Board of
Directors of ARC Resources (the "Separation Time").
As soon as is practicable following the Separation Time, separate certificates
evidencing the Rights will be mailed to the holders of record of Trust Units as
of the Separation Time and the rights certificates alone will evidence the
Rights. The Rights will expire on the close of business on the business day
following the annual general meeting of unitholders of the Trust held in 2004.
However, the Rights may be redeemed earlier by the Trust in accordance with the
Rights Plan Agreement.
From and after the Separation Time, each Right will entitle the holder thereof
to acquire one Unit upon payment of the exercise price. The exercise price will
initially be $50.00.
Following a transaction that results in a person becoming an Acquiring Person (a
"Flip-in Event"), the Rights will entitle the holders to receive, upon exercise
of the Rights, Trust Units with a market value equal to twice the exercise price
of the Rights. In such event, however, any Rights beneficially owned by an
Acquiring Person (including such person's associates and affiliates and any
other person acting jointly or in concert with the Acquiring Person and any
direct or indirect transferee of such person) will be void.
An acquisition of Trust Units that would otherwise make a person an Acquiring
Person will not trigger the Rights if the acquisition is pursuant to a
"Permitted Bid" or a "Competing Permitted Bid". To be a Permitted Bid, among
other things, the bidder must make a takeover bid which complies with the
following:
(a) the take-over bid is made by way of take-over bid circular for
all of the outstanding Trust Units and is made to all holders
of Trust Units wherever resident, other than the offeror;
(b) the take-over bid contains, and the take-up and payment for
the securities deposited thereunder is subject to, irrevocable
and unqualified provisions that no Trust Units shall be
taken-up or paid for pursuant to the take-over bid (A) prior
to the close of business on the 45th day following the date of
the take-over bid and (B) if less than 50% of the Trust Units
held by independent unitholders have been deposited pursuant
to the take-over bid and not withdrawn.
A Competing Permitted Bid is a take-over bid that is made after a Permitted Bid
has been made but prior to its expiry and that satisfies all the requirements of
a Permitted Bid as described above, except that a Competing Permitted Bid is not
required to remain open for 45 days so long as it is open until the later of 21
days after the date of the Competing Permitted Bid or after the earliest date on
which Trust Units may be taken up and paid for under any other Permitted Bid
then in existence.
The Board of Directors of ARC Resources may, at its option, at any time prior to
the occurrence of a Flip-in Event, elect to redeem all but not less than all of
the then outstanding Rights at a redemption price of $0.0001 per Right. The
Board of Directors of ARC Resources may also, until a Flip-in Event shall occur,
waive application of the Rights Plan to any particular Flip-in Event, provided
that if the Board of Directors of ARC Resources waives any particular Flip-in
Event which results from a take-over bid, the Board of Directors of ARC
Resources is also deemed to have waived application of the Rights Plan to any
other Flip-in Event occurring by way of a take-over bid made by way of a
take-over bid circular to all holders of Trust Units prior to the expiry of the
take-over bid that has been waived.
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The Rights Plan terminates on the close of business on the first business day
following the annual general meeting of Unitholders held in 2004.
CORPORATE GOVERNANCE
GENERAL
In general, ARC Resources has been delegated substantially all of the management
decisions of the Trust. The Unitholders are entitled to elect all of the Board
of Directors of ARC Resources pursuant to the terms of the Trust Indenture. The
Articles of ARC Resources provides that the Board of Directors of ARC Resources
shall consist of a minimum of three and a maximum of nine directors.
TRUST INDENTURE
Pursuant to the Trust Indenture, Unitholders are entitled to direct the manner
in which the Trust will vote its shares in ARC Resources at all meetings in
respect of matters, relating to the election of the directors of ARC Resources,
approving its financial statements and appointing auditors of ARC Resources who
shall be the same as the auditors of the Trust. Prior to the Trust voting its
shares in ARC Resources, in respect of such matters, each Unitholder is entitled
to vote in respect of the matter on the basis of one vote per Trust Unit held,
and the Trust is required to vote its shares in ARC Resources in accordance with
the result of the vote of Unitholders.
DECISION MAKING
The Board of Directors of ARC Resources has a mandate to supervise the
management of the business and affairs of the Trust, ARC Resources and the other
direct or indirect subsidiaries of the Trust and to act with a view to the best
interests of the Trust and ARC Resources. The Board of Directors of ARC
Resources supervises the management of the business and affairs of the
subsidiaries of the Trust. The Board of Directors' mandate includes: (a) the
responsibility for managing its own affairs; (b) monitoring of management of and
activities of the Trust; (c) reviewing strategic operating, capital and
financial plans; and (d) compliance reporting and corporate communications. In
particular, significant operational decisions and all decisions relating to: (i)
the acquisition and disposition of properties for a purchase price or proceeds
in excess of $10,000,000; (ii) the approval of capital expenditure budgets; and
(iii) establishment of credit facilities are made by the Board of Directors of
ARC Resources. In addition, the Trustee has delegated broad discretion in
relation to the day to day operations of the Trust Fund to the Board of
Directors of ARC Resources including all decisions relating to: (i) matters
relating to any offers for Trust Units; (ii) issuances of additional Trust
Units; and (iii) the determination of the amount of distributable income. Any
amendment to the royalty agreement between either ARC Resources or ARC (Sask.)
Energy Trust and the Trust requires the approval of the Board of Directors of
ARC Resources on behalf of the Trust. The Board of Directors of ARC Resources
holds regularly scheduled meetings at least quarterly to review the business and
affairs of the subsidiaries of the Trust and make any necessary decisions
relating thereto.
The Trust Indenture gives to the Board of Directors of ARC Resources the
authority to exercise the rights, powers and privileges for all matters relating
to the maximization of Unitholder value in the context of an Offer including any
Unitholder rights protection plan, any defensive action to an Offer, any
Directors Circular in response to an Offer, any regulatory or court proceeding
relating to an Offer and any related or ancillary matter.
Additional information in respect of corporate governance matters is contained
in the Annual Meeting 2003 Information Circular.
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BOARD OF DIRECTORS OF ARC RESOURCES
ARC Resources has a Board of Directors consisting of eight individuals, all of
whom have been elected by the Unitholders, including by the holders of the ARC
Resources Exchangeable Shares through the Special Voting Unit.
The name, municipality of resident, position held and principal occupation of
each director and officer of ARC Resources are set out below:
NAME AND OFFICES HELD
MUNICIPALITY OF RESIDENCE AND TIME AS DIRECTOR PRINCIPAL OCCUPATION
- --------------------------- -------------------------------- -----------------------------------------------
Mac H. Chairman of the Board and Chairman of ARC Financial Corporation (an
Van Wielingen(1)(3)(4)(5) Director since May 3, 1996 investment management company)
Calgary, Alberta
Walter DeBoni(1)(3)(4) Vice Chairman and Director since Vice-President, Canada Frontier & International
Calgary, Alberta June 26, 1996 Business of Husky Energy Inc. (a public oil and
gas company)
John P. Dielwart President, Chief Executive President and Chief Executive Officer of ARC
Calgary, Alberta Officer and Director since Resources
May 3, 1996
John M. Beddome(2)(4) Director since May 3, 1996 Independent Businessman
Calgary, Alberta
Frederic C. Coles(2)(3) Director since May 3, 1996 Independent Businessman
Calgary, Alberta
Fred J. Dyment(1)(2) Director since April 17, 2003 Independent Businessman
Calgary, Alberta
Michael M. Kanovsky(1)(2) Director since May 3, 1996 Independent Businessman
Victoria, B.C.
John M. Stewart(3)(4)(5) Director since February 11, 1998 Vice Chairman and Secretary of ARC Financial
Calgary, Alberta Corporation
Doug J. Bonner Vice-President, Engineering Vice-President, Engineering of ARC Resources
Calgary, Alberta
David P. Carey Vice President, Business Vice President, Business Development of ARC
Calgary, Alberta Development Resources
Danny G. Geremia Treasurer Treasurer of ARC Resources
Calgary, Alberta
Susan D. Healy Vice-President, Land Vice-President, Land of ARC Resources
Calgary, Alberta
Steven W. Sinclair Vice-President, Finance and Vice-President, Finance and Chief Financial
Calgary, Alberta Chief Financial Officer Officer of ARC Resources
Myron M. Stadnyk Vice-President, Operations Vice-President, Operations of ARC Resources
Calgary, Alberta
Allan R. Twa Secretary Partner, Burnet, Duckworth & Palmer LLP
Calgary, Alberta (barristers and solicitors)
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Notes:
(1) Member of Audit Committee.
(2) Member of Reserve Audit Committee.
(3) Member of Human Resource and Compensation Committee.
(4) Member of Board Governance Committee.
(5) Member of Management Advisory Committee.
Each of the foregoing persons has held the same principal occupation for the
previous five years except for: Walter DeBoni who, prior to February 2002, was
the President and Chief Executive Officer of Bow Valley Energy Ltd. (an oil and
gas company), and Fred Dyment who prior to May 2001 was President and Chief
Executive Officer of Maxx Petroleum Ltd. (an oil and gas company) and prior to
July 2000 was President and Chief Executive Officer of Ranger Oil Ltd. (an oil
and gas company); Myron J. Stadnyk who, prior to June 1999, was the Operations
Manager of ARC Resources, Susan D. Healy who, prior to June 1999, was the Land
Manager of ARC Resources, David P. Carey who, prior to November 2001, was
Director of Investor Relations of Gulf Canada Resources and prior to May 1999
was the Vice President, Heavy Oil Division, Gulf Canada Resources and Danny G.
Geremia who, prior to October, 2002 was Treasury Manager of ARC Resources.
Allan R. Twa, the Secretary of ARC Resources, was a director of Bracknell
Corporation until November 1, 2001 at which time Mr. Twa and the other directors
of Bracknell resigned. At that time the principal bankers of Bracknell had given
notice of default under Bracknell's credit facilities and expressed their intent
to realize on their security. Bracknell consented to those proceedings.
All of the directors of ARC Resources were elected on April 17, 2003 to hold
office until the next annual general meeting of ARC Resources. As at April 30,
2003, the directors and officers of ARC Resources, as a group, beneficially
owned, directly or indirectly, or exercised control or direction over, 758,935
Trust Units or approximately 0.6 percent of the issued and outstanding Trust
Units, and 1,449,104 Exchangeable Shares or approximately 50.6% of the issued
and outstanding Exchangeable Shares.
THE MANAGER
MANAGEMENT AGREEMENT
Prior to the most recent amendments to the Trust Indenture which were made
effective May 16, 2003, he Manager managed the Trust, Orion, ARC Resources and
ARC Sask. pursuant to the Management Agreement. On May 16, 2003 the Management
Agreement was terminated.
The Manager was paid Management Fees for providing all of the management
services. The Manager was indemnified by ARC Resources in respect of certain
damages which it may have suffered in discharging its obligations under the
Management Agreement provided that such damages did not arise from the fraud,
willful default, gross negligence or bad faith of the Manager. The Board of
Directors of ARC Resources and the Trustee reviewed on an ongoing basis both the
nature and extent of the services required of the Manager and the costs of
providing the same.
COMPENSATION
In connection with the Internalization Transaction on August 29, 2002, all fees
payable to the Manager pursuant to the Management Agreement were eliminated. For
the period ending in August 29, 2002 the Manager was compensated as follows for
providing services pursuant to the Management Agreement.
63
MANAGEMENT FEES
Pursuant to the Management Agreement, the Manager received a management fee
equal to 3.0% of net production revenue plus ARTC, less Crown royalties and
other Crown charges attributable to the Properties. The Manager also received a
sum equal to $290,000 for each year of the initial five year term of the
Management Agreement. Management Fees were deducted in computing Royalty Income
to the extent not paid from the residual income of ARC Resources. The Manager
was paid $5.2 million ($0.043 per Trust Unit) of Management Fees for the period
ended August 29, 2002, $8.8 million ($0.086 per Trust Unit) in 2001 and $6.2
million ($0.097 per Trust Unit) in 2000.
GENERAL AND ADMINISTRATIVE COSTS
The Manager was also reimbursed for General and Administrative Costs. General
and Administrative Costs were deducted in computing Royalty Income to the extent
not paid from the residual income of ARC Resources. General and Administrative
Costs were generally charged to ARC Resources and the Trust by the Manager based
on time spent and direct costs incurred in fulfilling the obligations of the
Manager to ARC Resources and the Trust pursuant to the Management Agreement. The
Manager was reimbursed $9.327 million ($0.078 per boe) for General and
Administrative Costs for the period ended August 29, 2002, $11.715 million
($0.74 per boe) in 2001 and $5.017 million ($0.50 per boe) in 2000.
ACQUISITION AND DISPOSITION FEES
The Manager was paid an acquisition fee equal to 1.5% of the purchase price of
any assets acquired by ARC Resources. In the event that ARC Resources' interests
in the Properties or a portion thereof was sold, the Manager was, pursuant to
the Management Agreement, to receive a disposition fee equal to 1.25% of the
sale price of the Properties sold. In the case of property exchanges or swaps,
the Manager was to receive the 1.5% acquisition fee up to the purchase price of
any assets acquired and was to receive the 1.25% disposition fee to the extent
the value of the property being disposed of exceeds the purchase price. The
Manager received fees of $895,282 in connection with the acquisition and
disposition of Properties during the period ended August 29, 2002, $7,927,000 in
2001 and $2,680,000 in 2000.
CONFLICTS OF INTEREST
Circumstances may arise where members of the Board of Directors of ARC Resources
serve as directors or officers of corporations which are in competition to the
interests of ARC Resources and the Trust. No assurances can be given that
opportunities identified by such board members will be provided to ARC Resources
and the Trust.
The BUSINESS CORPORATIONS ACT (Alberta) provides that in the event that a
director has an interest in a contract or proposed contract or agreement, the
director shall disclose his interest in such contract or agreement and shall
refrain from voting on any matter in respect of such contract or agreement
unless otherwise provided under such Act. To the extent that conflicts of
interest arise, such conflicts will be resolved in accordance with the
provisions of such Act.
64
SELECTED CONSOLIDATED FINANCIAL INFORMATION
FINANCIAL SUMMARY
($000's, EXCEPT PER TRUST UNIT NUMBERS)
YEAR ENDED YEAR ENDED YEAR ENDED
DECEMBER 31, 2002 DECEMBER 31, 2001 DECEMBER 31, 2000
----------------- ----------------- -----------------
EARNINGS INFORMATION
Revenue $ 444,835 $ 515,596 $316,270
Royalties $ 85,155 $ 112,209 $ 64,188
Expenses $ 321,422 $ 293,988 $141,210
Future Income Tax Recovery $ 29,635 $ 28,803 --
Net Income (loss) $ 67,893 $ 138,202 $110,872
Income (loss) per Trust Unit
Basic $ 0.57 $ 1.36 $ 1.74
Diluted $ 0.56 $ 1.35 $ 1.72
DISTRIBUTABLE INCOME INFORMATION
Distributable Income $ 183,617 $ 234,053 $128,958
Distributable Income per Trust Unit $ 1.56 $ 2.31 $ 2.01
BALANCE SHEET INFORMATION
Total Assets $1,467,918 $1,380,004 $662,854
Long Term Debt $ 337,728 $ 294,489 $115,068
Trust Units Outstanding and Trust Units 126,444 111,692 72,524
Reserved for Exchangeable Shares at Year End
DISTRIBUTIONS TO UNITHOLDERS
The following per Trust Unit distributions have been made in the last three
completed financial years:
2000 DISTRIBUTION PER TRUST UNIT
-------------- ---------------------------
First Quarter $0.45
Second Quarter $0.45
Third Quarter $0.52
Fourth Quarter $0.59
2001
First Quarter $0.60
Second Quarter $0.66
Third Quarter $0.60
Fourth Quarter $0.45
2002
First Quarter $0.39
Second Quarter $0.39
Third Quarter $0.39
Fourth Quarter $0.39
Cash distributions paid to Unitholders in 2000 were 55 percent deferred, 2001
cash distributions were 32 percent tax deferred and 2002 cash distributions were
32 percent tax deferred.
MANAGEMENT'S DISCUSSION AND ANALYSIS
Reference is made to the information under the heading "Management's Discussion
and Analysis" on pages 33 to 49, inclusive, of the Trust's 2002 Annual Report,
which pages are incorporated herein by reference.
65
ENVIRONMENTAL REGULATION
The oil and natural gas industry is subject to environmental regulation pursuant
to local, provincial and federal legislation. Environmental legislation provides
for restrictions and prohibitions on releases or emissions of various substances
produced in association with certain oil and gas industry operations and can
affect the location of wells and facilities and the extent to which exploration
and development is permitted. In addition, legislation requires that well and
facilities sites be abandoned and reclaimed to the satisfaction of provincial
authorities. A breach of such legislation may result in the imposition of fines
or issuance of clean-up orders. Environmental legislation in Alberta has
undergone a major revision and has been consolidated into the ENVIRONMENTAL
PROTECTION AND ENHANCEMENT ACT. Under the new Act, environmental standards and
compliance for releases, clean-up and reporting are stricter. Also, the range of
enforcement actions available and the severity of penalties have been
significantly increased. These changes will have an incremental effect on the
cost of conducting operations in Alberta. British Columbia's ENVIRONMENTAL
ASSESSMENT ACT became effective June 30, 1995. This legislation rolled the
previous processes for the review of major energy projects into a single
environmental assessment process with public participation in the environmental
review process. ARC Resources is committed to meeting its responsibilities to
protect the environment wherever it operates and anticipates making increased
expenditures of both a capital and expense nature as a result of the
increasingly stringent laws relating to the protection of the environment. ARC
Resources' internal procedures are designed to ensure that the environmental
aspects of new developments are taken into account prior to proceeding.
Management believes that ARC Resources is in material compliance with applicable
environmental laws and regulations with respect to the Properties.
66
QUARTERLY FINANCIAL INFORMATION
2002 2001
-------------------------------------------- --------------------------------------------
FOURTH THIRD SECOND FIRST FOURTH THIRD SECOND FIRST
QUARTER QUARTER QUARTER QUARTER QUARTER QUARTER QUARTER QUARTER
------- ------- ------- ------- ------- ------- ------- -------
(thousands except per Trust Unit amounts)
EARNINGS INFORMATION
Revenue $117,639 $113,625 $112,707 $100,864 $102,609 $116,307 $132,287 $164,393
Royalties 24,906 21,493 21,195 17,561 18,850 25,791 28,544 39,024
Expenses 72,266 103,381 70,236 75,539 78,619 73,667 68,494 73,208
Future Income Tax
Recovery 7,130 7,744 7,555 7,206 8,455 13,500 6,870 810
------- ------- ------- ------- ------- ------- ------- -------
Net Income (loss) 27,597 (3,505) 28,831 14,970 12,763 30,349 42,119 52,971
Income (loss) per
Trust Unit
Basic 0.22 (0.03) 0.25 0.13 $0.12 $0.29 $0.41 $0.57
Diluted 0.21 (0.03) 0.25 0.13 $0.12 $0.29 $0.41 $0.57
DISTRIBUTABLE INCOME
INFORMATION
Distributable Income $48,060 $47,644 $44,684 $43,229 $48,537 $60,813 $65,938 $58,765
Distributable Income
per Trust Unit 0.39 0.39 0.39 0.39 0.45 0.60 0.66 0.60
BALANCE SHEET
INFORMATION
Total Assets $1,467,918 $1,413,412 $1,354,911 $1,365,927 $1,382,057 $1,391,543 $1,385,300 $1,410,920
Long Term Debt 337,728 271,533 213,364 316,446 294,489 338,135 287,012 280,837
Trust Units
Outstanding and Trust
Units Reserved for
Exchangeable Shares
at Quarter End 126,444 126,270 122,359 111,957 111,692 103,523 103,249 102,692
MARKET FOR SECURITIES
The Trust Units and the ARC Resources Exchangeable Shares are listed and traded
on the TSX. The trading symbol for the Trust Units is AET.UN and for the ARC
Resources Exchangeable Shares is ARX.
RISK FACTORS
The following is a summary of certain risk factors relating to the business of
the Trust which prospective investors should carefully consider before deciding
whether to purchase Trust Units or Exchangeable Shares.
PURCHASE OF ROYALTIES
The price paid for the purchase of the Royalties in the Properties is based on
engineering and economic assessments of the reserves made by independent
engineers modified to reflect the technical views of management. These
assessments include a number of material assumptions regarding such factors as
recoverability and marketability of oil, natural gas, natural gas liquids and
sulphur, future prices of oil, natural gas, natural gas liquids and sulphur and
operating costs, future capital expenditures and royalties and other government
levies which will be imposed over the producing life of the reserves. Many of
these factors are subject to change and are beyond the control of the operators
of the Properties, ARC Resources, management and the Trust. In particular,
changes in the prices of and markets for petroleum, natural gas, natural gas
liquids and sulphur from those anticipated at the time of making such
assessments will affect the amount of future distributions and as such the value
of the Trust Units. In addition, all such assessments involve a measure of
geological and engineering uncertainty which could result in lower production
and reserves than attributed to the Properties.
67
RESERVE ESTIMATES
The reserve and recovery information contained in the Gilbert Report and in the
New Gilbert Report is only an estimate and the actual production and ultimate
reserves from the properties may be greater or less than the estimates prepared
by Gilbert. A significant portion of the principal properties acquired in the
Star Acquisition have relatively short production histories which may make
estimates on those properties more subject to revisions. The reserve reports
under the heading "Oil and Gas Reserves" and "Recent Developments - Acquisition
of Star Oil & Gas Ltd. - Oil and Gas Reserves of the New Properties" have been
prepared using certain commodity price assumptions which are described in the
notes to the reserve tables. If lower prices for crude oil, natural gas liquids
and natural gas are realized by the Trust and substituted for the price
assumptions utilized in those reserve reports, the present value of estimated
future net cash flows for the Trust's reserves would be reduced and the
reduction could be significant, particularly based on the constant price case
assumptions.
VOLATILITY OF OIL AND NATURAL GAS PRICES
The Trust's operational results and financial condition, and therefore the
amounts paid to the Trust pursuant to the Royalties, will be dependent on the
prices received for oil and natural gas production. Oil and natural gas prices
have fluctuated widely during recent years and are determined by economic and in
the case of oil prices, political factors. Supply and demand factors, including
weather and general economic conditions as well as conditions in other oil and
natural gas regions impact prices. Any movement in oil and natural gas prices
could have an effect on the Trust's financial condition and therefore on the
Distributable Income to be distributed to holders of Trust Units. World oil
prices are quoted in Unites States dollars and the price received by Canadian
producers is therefore affected by the Canadian/U.S. dollar exchange rate that
may fluctuate over time. A material increase in the value of the Canadian dollar
may negatively impact the Trust's net production revenue. ARC Resources may
manage the risk associated with changes in commodity prices and foreign
exchanges rates by causing ARC Resources to, from time to time, enter into oil
or natural gas price hedges and forward foreign exchange contracts. If ARC
Resources hedges its commodity price exposure, the Trust will forego the
benefits it would otherwise experience if commodity prices were to increase. In
addition, commodity hedging activities could expose ARC Resources to losses. To
the extent that ARC Resources engages in risk management activities related to
commodity prices and foreign exchange rates, it will be subject to credit risks
associated with counterparties with which it contracts.
CHANGES IN LEGISLATION
There can be no assurance that income tax laws and government incentive programs
relating to the oil and gas industry, such as the status of mutual fund trusts,
will not be changed in a manner which adversely affects Unitholders.
INVESTMENT ELIGIBILITY
If the Trust ceases to qualify as a mutual fund trust, the Trust Units will
cease to be qualified investments for RRSPs, RRIFs and DPSPs ("Exempt Plans").
Where at the end of any month an Exempt Plan holds Trust Units that are not
qualified investments, the Exempt Plan must, in respect of that month, pay a tax
under Part XI.1 of the Tax Act equal to 1% of the fair market value of the Trust
Units at the time such Trust Units were acquired by the Exempt Plan. In
addition, where a trust governed by an RRSP holds Trust Units that are not
qualified investments, the trust will become taxable on its income attributable
to the Trust Units while they are not qualified investments.
68
OPERATIONAL MATTERS
The operation of oil and gas wells involves a number of operating and natural
hazards which may result in blowouts, environmental damage and other unexpected
or dangerous conditions resulting in damage to ARC Resources and other operating
subsidiaries of the Trust and possible liability to third parties. ARC Resources
will maintain liability insurance, where available, in amounts consistent with
industry standards. Business interruption insurance may also be purchased for
selected facilities, to the extent that such insurance is available. ARC
Resources may become liable for damages arising from such events against which
it cannot insure or against which it may elect not to insure because of high
premium costs or other reasons. Costs incurred to repair such damage or pay such
liabilities will reduce Royalty Income.
Continuing production from a property, and to some extent the marketing of
production therefrom, are largely dependent upon the ability of the operator of
the property. To the extent the operator fails to perform these functions
properly, revenue may be reduced. Payments from production generally flow
through the operator and there is a risk of delay and additional expense in
receiving such revenues if the operator becomes insolvent. Although satisfactory
title reviews are generally conducted in accordance with industry standards,
such reviews do not guarantee or certify that a defect in the chain of title may
not arise to defeat the claim of ARC Resources or ARC Sask. to certain
Properties. A reduction of the Royalty Income could result in such
circumstances.
EXPANSION OF OPERATIONS
The operations and expertise of management of the Trust are currently focused on
conventional oil and gas production and development in the Western Canadian
Sedimentary Basin. In the future, the Trust may acquire oil and gas properties
outside this geographic area. In addition, the Trust Indenture does not limit
the activities of the Trust to oil and gas production and development, and the
Trust could acquire other energy related assets, such as oil and natural gas
processing plants or pipelines, or an interest in an oil sands project.
Expansion of our activities into new areas may present challenges and risks that
management has not faced in the past. If management does not manage these
challenges and risks successfully, the results of operations and financial
condition of the Trust could be adversely affected.
ACQUISITIONS
The price that ARC Resources is willing to pay for reserve acquisitions is based
largely on its estimates of the reserves to be acquired. Actual reserves could
vary materially from these estimates. Consequently, the reserves acquired may be
less than expected, which could adversely impact cash flows and distributions to
Unitholders.
ENVIRONMENTAL CONCERNS
The oil and natural gas industry is subject to environmental regulation pursuant
to local, provincial and federal legislation. A breach of such legislation may
result in the imposition of fines or issuance of clean up orders in respect of
ARC Resources, ARC Sask. or the Properties. Such legislation may be changed to
impose higher standards and potentially more costly obligations on ARC Resources
or ARC Sask. See "Management's Discussion and Analysis - Environmental
Regulation". Although ARC Resources has established a reclamation fund for the
purpose of funding its currently estimated future environmental and reclamation
obligations based on its current knowledge, there can be no assurance that the
Trust will be able to satisfy its actual future environmental and reclamation
obligations. Additionally, the potential impact on the Trust's operations and
business of the December 1997 Kyoto Protocol, which has now been ratified by
Canada, with respect to instituting reductions of greenhouse gases is difficult
to quantify at this time as specific measures for meeting Canada's commitments
have not been developed. See "Other Information Respecting ARC Resources -
Environmental Obligations - Reclamation Fund".
69
DEBT SERVICE
Amounts paid in respect of interest and principal on debt incurred in respect of
the Properties will reduce Royalty Income. Variations in interest rates and
scheduled principal repayments could result in significant changes in the amount
required to be applied to debt service before payment of the Royalties and
Distributable Income. Certain covenants of the agreements with ARC Resources'
and ARC Sask.'s lenders may also limit distributions to the Trust. Although ARC
Resources believes the credit facilities will be sufficient for ARC Resources'
and ARC Sask.'s immediate requirements, there can be no assurance that the
amount will be adequate for the future financial obligations of ARC Resources
and ARC Sask. or that additional funds will be able to be obtained.
The lenders will be provided with security over substantially all of the assets
of ARC Resources. If ARC Resources becomes unable to pay its Debt Service
Charges or otherwise commits an event of default such as bankruptcy, the lender
may foreclose on or sell the Properties free from or together with the
Royalties.
DELAY IN CASH DISTRIBUTIONS
In addition to the usual delays in payment by purchasers of oil and natural gas
to the operators of the Properties, and by the operator to ARC Resources,
payments between any of such parties may also be delayed by restrictions imposed
by lenders, delays in the sale or delivery of products, delays in the connection
of wells to a gathering system, blowouts or other accidents, recovery by the
operator of expenses incurred in the operation of the Properties or the
establishment by the operator of reserves for such expenses.
RELIANCE ON MANAGEMENT
Unitholders will be dependent on the management of ARC Resources in respect of
the administration and management of all matters relating to the Properties, the
Royalty, the Trust and Trust Units. ARC Resources, as of December 31, 2002,
operated approximately 53% of the total daily production of the Properties.
Investors who are not willing to rely on the management of ARC Resources should
not invest in the Trust Units.
DEPLETION OF RESERVES
The Trust has certain unique attributes which differentiate it from other oil
and gas industry participants. Distributions of Distributable Income in respect
of Properties, absent commodity price increases or cost effective acquisition
and development activities, will decline over time in a manner consistent with
declining production from typical oil, natural gas and natural gas liquids
reserves. ARC Resources and ARC Sask. will not be reinvesting cash flow in the
same manner as other industry participants as ARC Resources and ARC Sask.
conduct only minimal exploratory activities; nor to the same extent as other
industry participants as one of the main objectives of the Trust is to maximize
long-term distributions. Accordingly, absent capital injections, ARC Resources'
and ARC Sask.'s initial production levels and reserves will decline.
ARC Resources' and ARC Sask.'s future oil and natural gas reserves and
production, and therefore its cash flows, will be highly dependent on ARC
Resources' and ARC Sask.'s success in exploiting its reserve base and acquiring
additional reserves. Without reserve additions through acquisition or
development activities, ARC Resources' and ARC Sask.'s reserves and production
will decline over time as reserves are exploited.
To the extent that external sources of capital, including the issuance of
additional Trust Units become limited or unavailable, ARC Resources' and ARC
Sask.'s ability to make the necessary capital
70
investments to maintain or expand its oil and natural gas reserves will be
impaired. To the extent that ARC Resources and ARC Sask. are required to use
cash flow to finance capital expenditures or property acquisitions, the level of
Distributable Income will be reduced.
There can be no assurance that the ARC Resources and ARC Sask. will be
successful in developing or acquiring additional reserves on terms that meet the
Trust's investment objectives.
NET ASSET VALUE
The net asset value of the assets of the Trust from time to time will vary
dependent upon a number of factors beyond the control of management, including
oil and gas prices. The trading prices of the Trust Units from time to time is
also determined by a number of factors which are beyond the control of
management and such trading prices may be greater than the net asset value of
the Trust's assets.
ADDITIONAL FINANCING
In the normal course of making capital investments to maintain and expand the
oil and gas reserves of the Trust additional Trust Units are issued from
treasury which may result in a decline in production per Trust Unit and reserves
per Trust Unit. Additionally, from time to time the Trust issues Trust Units
from treasury in order to reduce debt and maintain a more optional capital
structure. Conversely to the extent that external sources of capital, including
the issuance of additional Trust Units become limited or unavailable, the
Trust's, ARC Resources' and ARC Sask.'s ability to make the necessary capital
investments to maintain or expand its oil and gas reserves will be impaired. To
the extent that the Trust, ARC Resources or ARC Sask. are required to use cash
flow to finance capital expenditures or property acquisitions or to pay debt
service charges or to reduce debt, the level of Distributable Income will be
reduced.
COMPETITION
There is strong competition relating to all aspects of the oil and gas industry.
The Trust, ARC Resources and ARC Sask. will actively compete for reserve
acquisitions and skilled industry personnel with a substantial number of other
oil and gas companies, many of which have significantly greater financial and
other resources than the Trust, ARC Resources or ARC Sask.
RETURN OF CAPITAL
Trust Units will have no value when reserves from the Properties can no longer
be economically produced and, as a result, cash distributions do not represent a
"yield" in the traditional sense as they represent both return of capital and
return on investment.
LIMITED REDEMPTION RIGHT
Unitholders have a limited right to require the Trust to repurchase their Trust
Units, which is referred to as a redemption right. See "Information Relating to
the Trust - Right of Redemption". It is anticipated that the redemption right
will not be the primary mechanism for Unitholders to liquidate their investment.
The right to receive cash in connection with a redemption is subject to
limitations. Any securities which may be distributed IN SPECIE to Unitholders in
connection with a redemption may not be listed on any stock exchange and a
market may not develop for such securities. In addition, there may be resale
restrictions imposed by law upon the recipients of the securities pursuant to
the redemption right.
71
NATURE OF TRUST UNITS
The Trust Units do not represent a traditional investment in the oil and natural
gas sector and should not be viewed by investors as shares in ARC Resources. The
Trust Units represent a fractional interest in the Trust. As holders of Trust
Units, Unitholders will not have the statutory rights normally associated with
ownership of shares of a corporation including, for example, the right to bring
"oppression" or "derivative" actions. The Trust's sole assets will be the
Royalty and other investments in securities. The price per Trust Unit is a
function of anticipated Distributable Income, the Properties acquired by ARC
Resources and ARC Sask. and ARC Resources' ability to effect long-term growth in
the value of the Trust. The market price of the Trust Units will be sensitive to
a variety of market conditions including, but not limited to, interest rates and
the ability of the Trust to acquire suitable oil and natural gas properties.
Changes in market conditions may adversely affect the trading price of the Trust
Units.
THE TRUST UNITS ARE NOT "DEPOSITS" WITHIN THE MEANING OF THE CANADA DEPOSIT
INSURANCE CORPORATION ACT (CANADA) AND ARE NOT INSURED UNDER THE PROVISIONS OF
THAT ACT OR ANY OTHER LEGISLATION. FURTHERMORE, THE TRUST IS NOT A TRUST COMPANY
AND, ACCORDINGLY, IS NOT REGISTERED UNDER ANY TRUST AND LOAN COMPANY LEGISLATION
AS IT DOES NOT CARRY ON OR INTEND TO CARRY ON THE BUSINESS OF A TRUST COMPANY.
UNITHOLDER LIMITED LIABILITY
The Trust Indenture provides that no Unitholder will be subject to any liability
in connection with the Trust or its obligations and affairs and, in the event
that a court determines Unitholders are subject to any such liabilities, the
liabilities will be enforceable only against, and will be satisfied only out of
the Trust's assets. Pursuant to the Trust Indenture, the Trust will indemnify
and hold harmless each Unitholder from any costs, damages, liabilities,
expenses, charges and losses suffered by a Unitholder resulting from or arising
out of such Unitholder not having such limited liability.
The Trust Indenture provides that all written instruments signed by or on behalf
of the Trust must contain a provision to the effect that such obligation will
not be binding upon Unitholders personally. The principal investment of the
Trust is the Royalty Agreements which contain such provisions. Personal
liability may also arise in respect of claims against the Trust that do not
arise under contracts, including claims in tort, claims for taxes and possibly
certain other statutory liabilities. The possibility of any personal liability
of this nature arising is considered unlikely.
The operations of the Trust will be conducted, upon the advice of counsel, in
such a way and in such jurisdictions as to avoid as far as possible any material
risk of liability on the Unitholders for claims against the Trust.
72
ADDITIONAL INFORMATION
Additional information including remuneration of directors and officers of ARC
Resources and the Manager, principal holders of the Trust Units and rights to
purchase Trust Units, is contained in the Information Circular - Proxy Statement
of the Trust dated March 17, 2003 which relates to the Annual and Special
Meeting of Unitholders held on April 17, 2003, and additional financial
information is provided in the consolidated financial statements of the Trust
and ARC Resources for the year ended December 31, 2002.
The Trust shall provide to any person, upon request to the Secretary of ARC
Resources on behalf of the Trust:
1. when the securities of the Trust are in the course of a distribution
pursuant to a short form prospectus or a preliminary short form
prospectus has been filed in respect of a distribution of its
securities,
(a) one copy of the Annual Information Form of the Trust, together
with one copy of any document, or the pertinent pages of any
document, incorporated by reference in the Annual Information
Form;
(b) one copy of the consolidated financial statements of the Trust
for the most recently completed fiscal year together with the
accompanying report of the auditor and one copy of any
subsequent interim financial statements;
(c) one copy of the Information Circular - Proxy Statement of the
Trust dated March 17, 2003; and
(d) one copy of any other documents that are incorporated by
reference into the preliminary short form prospectus or the
short form prospectus and are not required to be provided
under (i) to (iii) above; or
2. at any other time, one copy of any other documents referred to in
(a)(i), (ii) and (iii) above, provided the Trust may require the
payment of a reasonable charge if the request is made by a person who
is not a security holder of the Trust.
For additional copies of the Annual Information Form and the materials listed in
the preceding paragraphs please contact:
ARC Energy Trust
c/o ARC Resources Ltd.
2100, 440 - 2nd Avenue S.W.
Calgary, Alberta, T2P 5E9
Toll free in Canada: 1-888-272-4900
Fax: (403) 503-8609
APPENDIX "A"
FINANCIAL STATEMENTS OF STAR OIL & GAS LTD.
A-1
STAR OIL & GAS LTD.
Consolidated Financial Statements
DECEMBER 31, 2002, 2001 AND 2000
(in thousands of Canadian dollars)
[GRAPHIC OMITTED]
[LETTERHEAD - PRICEWATERHOUSECOOPERS]
January 31, 2003
(except for note 15 which is at April 16, 2003)
AUDITORS' REPORT
TO THE DIRECTORS OF
STAR OIL & GAS LTD.
We have audited the consolidated balance sheet of STAR OIL AND GAS LTD. as at
December 31, 2002, 2001 and 2000 and the consolidated statements of income and
retained earnings and cash flows for each of the years then ended. These
financial statements are the responsibility of the company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with Canadian generally accepted auditing
standards. Those standards require that we plan and perform an audit to obtain
reasonable assurance whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
In our opinion, these consolidated financial statements present fairly, in all
material respects, the financial position of the company as at December 31,
2002, 2001 and 2000 and the results of its operations and its cash flows for
each of the years then ended in accordance with Canadian generally accepted
accounting principles.
(SIGNED) "PRICEWATERHOUSECOOPERS LLP"
CHARTERED ACCOUNTANTS
Calgary, Alberta
A-3
STAR OIL & GAS LTD.
CONSOLIDATED BALANCE SHEETS
AS AT DECEMBER 31, 2002, 2001 AND 2000
- --------------------------------------------------------------------------------
(in thousands of Canadian dollars)
2002 2001 2000
$ $ $
(restated -
ASSETS note 2)
CURRENT ASSETS
Short-term deposits -- -- 9,988
Accounts receivable 29,434 20,022 36,850
Prepaid expenses 1,191 1,348 1,197
Income taxes receivable -- 1,999 --
---------------------------
30,625 23,369 48,035
CAPITAL ASSETS (note 3) 474,319 445,756 429,125
OTHER ASSETS (note 5) 323 267 179
---------------------------
505,267 469,392 477,339
===========================
LIABILITIES
CURRENT LIABILITIES
Bank indebtedness (note 6) 2,424 1,591 1,850
Accounts payable 25,080 19,577 50,921
Income taxes payable 3,010 -- 29,710
---------------------------
30,514 21,168 82,481
LONG-TERM DEBT (note 7) 136,490 139,815 136,005
SHAREHOLDER LOANS (note 8) 48,458 48,783 46,473
SITE RESTORATION ACCRUAL (note 3) 4,958 4,359 4,511
DEFERRED LIABILITIES 1,244 1,747 2,307
FUTURE INCOME TAXES (note 10) 106,392 101,161 90,936
---------------------------
328,056 317,033 362,713
---------------------------
SHAREHOLDERS' EQUITY
CAPITAL STOCK (note 9) 33,371 33,371 33,371
RETAINED EARNINGS 143,840 118,988 81,255
---------------------------
177,211 152,359 114,626
---------------------------
505,267 469,392 477,339
===========================
COMMITMENTS AND CONTINGENCIES (note 14)
APPROVED BY THE BOARD OF DIRECTORS
"STEVEN W SINCLAIR" Director "DANNY G. GEREMIA" Director
- --------------------- --------------------
STEVEN W. SINCLAIR DANNY G. GEREMIA
A-4
STAR OIL & GAS LTD.
CONSOLIDATED STATEMENTS OF INCOME AND RETAINED EARNINGS
FOR THE YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000
- --------------------------------------------------------------------------------
(in thousands of Canadian dollars)
2002 2001 2000
$ $ $
(restated -
note 2)
REVENUE
Production and royalties 199,982 267,688 233,739
Crown and other royalties (44,763) (67,977) (54,506)
Alberta royalty tax credit 512 197 521
--------------------------------
155,731 199,908 179,754
--------------------------------
EXPENSES
Production 41,177 45,649 34,424
General and administrative 4,889 8,324 9,853
Interest on long-term debt 8,738 11,670 11,089
Depletion and depreciation 54,865 55,694 41,335
Foreign exchange (gain) loss (653) 4,595 2,853
--------------------------------
109,016 125,932 99,554
--------------------------------
INCOME BEFORE PROVISION FOR TAXES 46,715 73,976 80,200
--------------------------------
PROVISION FOR TAXES (note 10)
Current 16,632 27,151 32,517
Future 5,231 9,092 6,880
--------------------------------
21,863 36,243 39,397
--------------------------------
NET INCOME 24,852 37,733 40,803
RETAINED EARNINGS - BEGINNING OF YEAR 118,988 81,255 42,400
Adjustment - accounting policy change (note 2(a)) -- -- (1,564)
Adjustment - accounting policy change (note 2(b)) -- -- (384)
--------------------------------
RETAINED EARNINGS - END OF YEAR 143,840 118,988 81,255
===============================
A-5
STAR OIL & GAS LTD.
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000
- --------------------------------------------------------------------------------
(in thousands of Canadian dollars)
2002 2001 2000
$ $ $
(restated -
note 2)
CASH PROVIDED BY (USED IN)
OPERATING ACTIVITIES
Net income 24,852 37,733 40,803
Adjustments for
Depletion and depreciation 54,865 55,694 41,335
Future income taxes 5,231 9,092 6,880
Unrealized foreign exchange (gain) loss (650) 4,620 2,842
Amortization of deferred liability (560) (590) (551)
-------------------------------
83,738 106,549 91,309
-------------------------------
Changes in non-cash working capital items
(Increase) decrease in accounts receivable (9,412) 16,828 (13,697)
Increase (decrease) in prepaid expenses 157 (151) (165)
Increase (decrease) in accounts payable 2,768 (24,183) 12,781
Increase (decrease) in income taxes payable/receivable 5,009 (31,709) 22,932
-------------------------------
(1,478) (39,215) 21,851
-------------------------------
82,260 67,334 113,160
-------------------------------
INVESTING ACTIVITIES
Payment for land and property (5,843) (6,029) (19,411)
Expenditures on drilling and exploration (46,082) (50,008) (59,473)
Expenditures on production and other equipment (30,179) (16,969) (25,108)
-------------------------------
(82,104) (73,006) (103,992)
Changes in non-cash working capital items
Increase (decrease) in accounts payable 2,792 (7,131) 6,061
-------------------------------
(79,312) (80,137) (97,931)
Proceeds from sale of capital assets -- 2,979 2,728
Purchase of Place Resources Corporation -- -- (49,680)
Expenditures on site restoration (725) (1,317) (1,185)
Other assets (56) (88) 34
-------------------------------
(80,093) (78,563) (146,034)
-------------------------------
FINANCING ACTIVITIES
Increase in (repayments of) bank indebtedness 833 (259) (313)
(Repayments of) proceeds from long-term borrowings (3,000) 1,500 42,242
-------------------------------
(2,167) 1,241 41,929
-------------------------------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS -- (9,988) 9,055
CASH AND CASH EQUIVALENTS - BEGINNING OF YEAR (note A) -- 9,988 933
-------------------------------
CASH AND CASH EQUIVALENTS - END OF YEAR -- -- 9,988
===============================
A-6
STAR OIL & GAS LTD.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2002, 2001 AND 2000
- --------------------------------------------------------------------------------
(tabular amounts in thousands of Canadian dollars)
SUPPLEMENTAL INFORMATION FOR THE CASH FLOWS
A. CASH AND CASH EQUIVALENTS
Cash and cash equivalents consist of cash on hand and balances with banks,
and investments in money market instruments that mature within three
months. Cash and cash equivalents included in the cash flow statement
comprise the following balance sheet amounts:
2002 2001 2000
$ $ $
Short-term investments -- -- 9,988
---------------------------------
Total cash and cash equivalents -- -- 9,988
=================================
B. NON-CASH TRANSACTIONS
2002 2001 2000
$ $ $
Accounts payable 57 30 3,315
Deferred liabilities (57) (30) (3,315)
Long-term debt (325) (2,310) (1,421)
Shareholders' loans (325) (2,310) (1,421)
There were approximately $2,659,000 of properties swapped for other
properties in 2002 (2001 - $1,668,000; 2000 - $1,206,000).
C. CASH PAYMENTS
2002 2001 2000
$ $ $
Interest paid (7,985) (11,640) (10,650)
Interest received 45 63 76
Cash income taxes paid (17,949) (61,650) (13,642)
Cash income taxes received 4,326 634 795
The objectivity and integrity of data in these financial statements, including
estimates and judgements relating to matters not concluded by year end, are the
responsibility of management of the company. In management's opinion, the
financial statements have been properly prepared within reasonable limits of
materiality and within the framework of the company's accounting policies.
A-7
1 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
BASIS OF PRESENTATION
These consolidated financial statements include the accounts of the
company and its wholly owned subsidiary.
CAPITAL ASSETS - OIL AND GAS
The company follows the full cost method of accounting for oil and gas
operations as outlined in the guideline issued by the Canadian Institute
of Chartered Accountants, whereby all costs associated with the
exploration for and development of oil and gas reserves are capitalized.
Such amounts include land acquisition costs, geological and geophysical
expenditures, carrying charges on non-producing properties, costs of
drilling productive and non-productive wells, administration costs related
to exploration and development activities and related plant and equipment
expenditures. These amounts are accumulated in separate cost centres for
each country where the company is active. At present, all of the company's
operations are in Canada.
Depletion and depreciation are provided using the unit of production
method based on the company's share of gross proven reserves of oil and
gas. For purposes of this calculation, reserves and production of gas and
associated liquids are converted into equivalent barrels of oil based on
the relative energy content.
Proceeds on dispositions of oil and gas properties and production
equipment are recorded against accumulated costs. However, gains or losses
on the disposition of oil and gas properties are only recognized in the
statement of income when the depletion and depreciation rate would be
changed by a factor of 20% or more.
The company's oil and gas properties are subject to a ceiling test under
which the carrying value is limited to the future net revenue from
production of estimated proven oil and gas reserves valued at year end
"constant" prices or contractually determined prices plus the unimpaired
costs of non-producing properties less future administration costs,
financing costs, future restoration costs and income taxes.
Expenditures for repairs and maintenance are charged to production
expense. Betterments and major renewals are capitalized.
A-8
OTHER EQUIPMENT
Depreciation on other equipment is provided based on diminishing value
basis over the useful life of the assets.
SITE RESTORATION ACCRUAL
Estimated future costs of site restoration, including removal of
production facilities, are provided for on a unit of production basis.
Costs are based on estimates provided by independent reservoir engineers.
The annual charge is recorded as additional depletion and depreciation.
HEDGING
The company enters into various swap agreements to reduce its exposure to
interest rate, foreign exchange, and crude oil and natural gas commodity
price fluctuations related to future sales. Gains or losses on these
contracts, which constitute effective hedges, are deferred and recognized
as a component of the related transaction.
INCOME TAXES
The company follows the liability method of tax allocation accounting.
Under this method, recognition of a future tax liability or asset is
dependent on the expected tax outflows or benefits to be derived from
differences between the carrying value and tax basis of assets and
liabilities.
MANAGEMENT ESTIMATES
The accounts include management estimates relating to the amortization of
capital assets which are subject to revisions which could be significant
over time, depending on estimates of reserves. Future estimated
abandonment costs are subject to significant revision over time as they
are a current estimate of events which will occur in the future.
RECLASSIFICATION
Certain information provided in the prior years has been reclassified to
conform with the current period presentation.
A-9
2 CHANGES IN ACCOUNTING POLICIES
a) Effective January 1, 2001, the company changed from the deferral
method of accounting for exchange gains and losses on conversion of
foreign currency denominated long-term debt to the new standard set
by the Canadian Institute of Chartered Accountants. The new standard
requires recognition of the gains and losses in the period they
occur. This standard was applied retroactively with restatement of
prior period financial statements. The effect of this change on the
2001 amounts in the financial statements is to eliminate the deferred
foreign exchange loss asset on the balance sheet of $5,879,000 (2000
- $3,085,000), to increase the unrealized foreign exchange expense by
$2,793,000 (2000 - $1,521,000) and to reduce the opening retained
earnings in 2000 by $1,564,000.
b) Effective January 1, 2000, the company changed from the deferral
method of accounting for income taxes to the liability method in
accordance with the new standard set by the Canadian Institute of
Chartered Accountants. The new standard was applied retroactively
without restatement of prior period financial statements.
3 CAPITAL ASSETS
2002 2001 2000
$ $ $
Land and property acquisition 187,754 181,910 177,753
Drilling and exploration 392,653 346,571 296,464
Production and other equipment 228,543 198,365 181,565
-------------------------------------
808,950 726,846 655,782
Less: Accumulated depletion and depreciation (334,631) (281,090) (226,657)
-------------------------------------
474,319 445,756 429,125
=====================================
General and administrative costs of $1,555,520 (2001 - $2,451,605; 2000 -
$2,895,889) relating to exploration and development activities were
capitalized during the year. No interest costs have been capitalized.
The company's estimated average wellhead prices used in performing the
full cost ceiling test were $47.47 (2001 - $29.25; 2000 - $42.06) per
barrel for oil and $6.06 (2001 - $3.18; 2000 - $7.04) per mcf for natural
gas.
Future estimated abandonment costs identified in the "Constant Price"
Reserve Report are $19,463,000 (2001 - $18,221,000; 2000 - $14,662,000).
Depletion and amortization includes a charge of $1,324,000 for 2002 (2001
- $1,165,000; 2000 - $1,068,000) with respect to the site restoration
liability.
A-10
4 ACQUISITION OF PLACE RESOURCES CORPORATION
On October 16, 2000, the company made an offer for all of the outstanding
shares of Place Resources Corporation ("Place"), an oil and gas
exploration development and production company, for consideration of $3.00
cash for each Place common share outstanding. As at December 31, 2000, the
company was deemed to have acquired 100 percent of the outstanding shares
of Place.
The transaction, effective November 7, 2000, has been accounted for using
the purchase method with the results of operations included in the
consolidated statement of income from the date of acquisition. At December
31, 2000, the company allocated the purchase price to Place's assets and
liabilities as follows:
Net assets acquired and liabilities assumed
$
Capital assets 105,596
Working capital 556
Debt (25,497)
Site restoration (920)
Future income taxes (30,055)
-----------
49,680
===========
Consideration - cash 49,680
===========
In 2001, capital assets and future income taxes were increased by
$1,133,000 to reflect final income tax adjustments.
5 OTHER ASSETS
Drilling and operating deposits of $323,000 (2001 - $267,000; 2000 -
$179,000) are recorded at cost.
6 BANK INDEBTEDNESS
The bank indebtedness is funded by an operating facility with a
$20,000,000 limit. This facility is included in and has the same
attributes as the total credit facility described in long-term debt (note
7).
A-11
4. LONG-TERM DEBT
The company maintains various credit facilities under certain long-term
debt agreements as follows:
TOTAL CREDIT LONG-TERM CREDIT FACILITY USED AT
FACILITY DECEMBER 31,
--------------- -------------------------------------------------
2002, 2001
AND 2000 2002 2001 2000
$ $ $ $
Revolving Credit Facility 185,000,000 141,716,133 145,071,777 141,350,503
===================================================================
The revolving credit facility may be drawn down or repaid at any time. The
company may use the available credit facilities within certain limits as
direct Canadian or US dollar loans, short or long-term Bankers'
Acceptances, fixed loans, LIBOR US loans or letters of credit.
At December 31, 2002, various letters of credit totalling Cdn $5,226,133
(2001 - Cdn $5,256,777; 2000 - $5,345,503) were outstanding.
As at December 31, 2002, there was $39,490,000 (US $25,000,000) (2001 -
Cdn $39,815,000; 2000 - $37,505,000) of LIBOR dollar loans outstanding.
Interest rates on the US $25,000,000 of LIBOR loans vary from 2.60% to
2.98%.
At December 31, 2002, there was $97,000,000 of Bankers' Acceptances (2001
- $100,000,000; 2000 - $98,500,000) outstanding. On March 25, 1998, the
company entered into floating for fixed interest rate swaps, which
effectively fixed the interest rate on $10,000,000 of bankers' acceptances
at 6.120% until March 25, 2003. On September 25, 1998, the company entered
into floating for fixed interest rate swaps, which effectively fixed the
interest rate on $10,000,000 of Bankers' Acceptances at 6.520% until
September 25, 2008. The following is a listing of the Bankers' Acceptance
agreements as at December 31, 2002:
ISSUE DATE MATURITY DATE INTEREST RATE (%)
29 Aug-02 24 Jan-03 4.33
05 Sept-02 24 Jan-03 4.10
25 Sept-02 25 Feb-03 4.18
25 Nov-02 25 Feb-03 4.06
10 Oct-02 25 Mar-03 4.15
18 Dec-02 25 Mar-03 4.03
25 Oct-02 25 Apr-03 4.15
06 Nov-02 26 May-03 4.13
A-12
The mark to market value of the bankers' acceptance swaps is a $841,645
unrecorded loss at December 31, 2002.
As the long-term debt of the company consists of revolving credit
facilities and fluctuating interest rates, the carrying value approximates
fair market value, except for the long-term debt relating to the mark to
market values noted above.
At July 12, 2002, the company amended their credit agreement to extend the
term-out date to August 29, 2003. The company has the right to request an
extension to the credit facility within the revolving period which would
make the first payment due March 2004.
The credit facilities are secured by a floating charge debenture, a
general security agreement, including an assignment of book debts, and an
assignment of specific contracts. The debt would become a current
liability on a change of control.
8 SHAREHOLDER LOANS
An unsecured shareholder loan bears interest at the rate of a USA
chartered bank prime rate of 4.25% plus 1% at December 31, 2002. The
remaining unsecured shareholder loan bears interest at a Canadian
chartered banks prime rate of 4.50% at December 31, 2002. Pursuant to a
priorities agreement between the lender of the credit facilities and the
shareholders, the shareholders may demand payment only with the consent of
the bank. The current shareholders have no intention of calling these
loans unless otherwise negotiated as part of the banking facility. Of the
$48,458,470 in loans, $39,490,000 (US $25,000,000) is repayable in US
dollars.
9 CAPITAL STOCK
Authorized
Unlimited first preferred shares issuable in series
Unlimited second preferred shares issuable in series
Unlimited third preferred shares issuable in series
Unlimited common shares
Issued
2002, 2001 AND 2000
-----------------------------------------
NUMBER OF STATED VALUE
SHARES $
Preferred shares - 3% cumulative, redeemable, convertible first
preferred shares, Series 1 dividends are in arrears in the
amount of $4,756,027 (2001 - $4,173,504; 2000 - $3,590,980) 2,222,906 19,418
Common shares - Class A 6,111,111 13,953
------------------
33,371
==================
A-13
10 INCOME TAXES
2002 2001 2000
----------------- ------------------ ------------------
% $ % $ % $
Income before provision for taxes 46,715 73,976 80,200
------- ------ ------
Expected tax 43.3 20,227 43.8 32,401 44.9 36,010
Increase (decrease) resulting from
Non-deductible crown payments 35.5 16,581 35.6 26,375 27.2 21,791
Federal resource allowance (28.0) (13,088) (26.1) (19,332) (24.8) (19,929)
Alberta Royalty Tax Credit (0.5) (222) -- (86) (0.3) (234)
Foreign exchange (gain) loss (0.6) (281) 2.7 2,002 1.6 1,309
Large corporation tax 0.5 229 0.6 463 0.2 201
Rate adjustment (2.0) (924) (5.7) (4,208) -- --
Prior year (over provision) (4.3) (2,021) (2.8) (2,102) -- --
Other 2.9 1,362 0.9 730 0.3 249
------------------------------------------------------------------
Total taxes 46.8 21,863 49.1 36,243 49.1 39,397
==================================================================
The future income tax liability is composed of temporary differences and
future income tax reductions. These tax-effected differences are as
follows:
2002 2001 2000
$ $ $
Net book value of property, plant and equipment in
excess of tax basis (105,983) (103,734) (94,271)
Future site restoration deductions 1,551 1,837 1,998
Other (1,960) 736 1,337
---------------------------------------------
Future income tax liability (106,392) (101,161) (90,936)
=============================================
At December 31, 2002, the company had tax pools available for deduction
against future taxable income of approximately $211,789,481 (2001 -
$193,069,731; 2000 - $195,982,000).
11 FINANCIAL INSTRUMENTS
The company has determined the estimated fair values of its financial
instruments based on its best judgment of the appropriate valuation
methodologies. However, considerable judgement is necessary to develop
these estimates. Accordingly, the estimates presented herein are not
necessarily indicative of the amounts the company could realize in current
market exchanges. The use of different assumptions or methodologies may
have a material effect on the estimated fair value amounts.
A-14
The financial instruments of the company include short-term deposits,
accounts receivable, prepaid expenses, income taxes receivable, other
assets, bank indebtedness, accounts payable, income taxes payable,
long-term debt, shareholder loans and off balance sheet commodity
contracts. It is estimated that the fair values would not be materially
different than the book values, with the exception of the commodity
contracts (see note 13) and long-term debt (see note 7).
FOREIGN CURRENCY RISK
The shareholder loan (see note 8) and the LIBOR US $ bank loans (see note
7) are exposed to the fluctuations in the Cdn/US foreign exchange rate.
A $0.01 movement in the exchange rate will cause the carrying value of
these loans to fluctuate by $500,000.
The company also holds some accounts payable, including the interest
payable on the loans above, accounts receivable and short-term deposits in
US dollars, however, exposure to foreign exchange volatility is minimal
due to the relatively low amount of those balances.
INTEREST RATE RISK
The company's bank indebtedness, shareholder loans (see note 8) and
Canadian bankers' acceptance and US $ LIBOR loans (see note 7) totalling
Cdn $167,372,470 are exposed to the movement in interest rates. A 1% move
in the interest rate would cause the company's interest payments to
fluctuate by $1,673,725. The remaining bankers' acceptances are set at
fixed interest rates and are not exposed to interest rate fluctuations.
CREDIT RISK
The company's client portfolio consists of transactions with companies
which are subject to oil and gas industry credit risks.
12 PENSION PLAN
The company has a defined contribution pension plan. The company
contributes an amount equal to 5% of the employees' salaries to the plan.
The company's pension expense in 2002 was $220,488 (2001 - $212,831; 2000
- $185,357).
A-15
13 PRODUCT HEDGING ACTIVITIES
Losses resulting from crude oil and natural gas transactions amounted to
$5,577,920 in 2002 (2001 - $3,378,378 loss; 2000 - $13,432,142 loss).
At December 31, 2002, the company had no outstanding natural gas financial
hedge transactions.
At December 31, 2002, the company had the following outstanding crude oil
financial hedge transactions.
1,000 barrels per day at US $23.55 per barrel for January 2003 to
December 2003
A costless collar for 1,000 barrels per day with a floor of US $23.00
and a cap of US $25.80 per barrel for January 2003 to December 2003
The mark to market value of these agreements is a $2,564,941 unrecorded
loss at December 31, 2002.
14 COMMITMENTS AND CONTINGENCIES
FIXED PRICE GAS CONTRACTS AND PHYSICAL DELIVERY
At December 31, 2002, the company had the following fixed price gas sales
and commitments to deliver physical product:
7,000 GJ per day at $4.55 FLOOR and $7.15 CAP per GJ at AECO ending
March 2003
5,000 GJ per day at $4.00 FLOOR and $5.91 CAP per GJ at AECO ending
October 2003
2,000 GJ per day at $2.525 per GJ at AECO ending October 2003
1,000 GJ per day at $2.48 per GJ at AECO ending October 2003
5,000 GJ per day at $2.955 per GJ at AECO ending October 2004
PIPELINE TRANSPORTATION COMMITMENT
On October 26, 1999, the company entered into an agreement with a pipeline
company, whereby the company is committed to transport 5,000 mcf per day
of natural gas for nine years until 2008. As part of this transaction, the
company received a prepayment of $3,538,080 for taking the future
transportation commitment. The company is not committed to a set delivery
price. This commitment increased the existing commitment to transport
5,000 mcf per day to 10,000 mcf per day. The amount received is being
deferred and amortized over the commitment period.
On March 4, 1999, the company entered into an agreement which commits it
to transport 4,000 mcf per day until 2015.
OTHER
Commitments and contingencies exist under agreements and operations in the
normal course of business, the total amount of which, in the opinion of
management, is not significant to the financial position of the company.
A-16
LEASE COMMITMENTS
The company leases various types of property and equipment. Minimum
payments under non-cancellable operating leases with terms of one year or
more as at December 31, 2002 are as follows:
$
2003 483
2004 163
2005 8
--------
654
--------
ENRON CAPITAL AND TRADE RESOURCES CANADA CORP. ("ENRON")
The company had entered into an agreement with Enron to sell and deliver
5,000 GJ's of gas per day at $2.50 per GJ through November 1, 2003. Enron
failed to pay for sales of gas in the months of November and December 2001
in the amounts of $401,250 and $80,250, respectively. Accordingly, the
company made an allowance for doubtful accounts in the full amount of the
gas sales.
The company filed notice of default under the agreement, terminated the
agreement and discontinued gas deliveries to Enron effective December 7,
2001. Enron also filed a notice of default and terminated the agreement
effective December 24, 2001.
The company is of the opinion that it does not have a mark-to-market
liability with respect to the early cancellation of the agreement.
TERMINATED GAS CONTRACT
On February 18, 1999, the company had entered into an agreement with a
third party to sell and deliver 5,700 GJ's of Gas per day at Empress, and
3,800 GJ per day at AECO, through October 31, 2004. The fixed contract
price on the Empress delivery was $2.83 per GJ. The price of the AECO
delivery was contracted at either an index price without a ceiling, or a
price capped index price. The determination of the price of the AECO
delivery for each contract year (November to October) was subject to an
election to be made by the third party by September 30th prior to the
start of that contract year. As at September 30th, 2002, the third party
had not elected to take delivery at the capped price, therefore under the
terms of the contract the company invoiced the third party for delivery in
November and December of 2002 at the default pricing option, which was not
subject to a price cap. The third party paid for the deliveries at the
lower, price-capped rate, leaving total unpaid outstanding receivables
related to those two months of $345,900 as at December 31, 2002. The
company believes that this amount will be recoverable in some form during
negotiations relating to the termination of the contract, and accordingly
has made no allowance for doubtful accounts in respect of this amount.
A-17
In addition, the company filed notice of default under the agreement,
terminated the agreement, and discontinued gas deliveries effective
December 12, 2002. While the third party is claiming a mark-to-market
liability, the company is of the opinion that it does not have a
mark-to-market liability with respect to the cancellation of the
agreement. Currently the amount of any such future contingent liability is
undeterminable, and in the opinion of the company it is expected to be
negligible.
15 CHANGE OF CONTROL
On March 31, 2003, the company's shareholders entered into an acquisition
agreement with ARC Energy Trust ("ARC") whereby ARC offered to purchase
all of the issued and outstanding shares of Star Oil & Gas Ltd. for a
total purchase price of $710 million to be financed by cash and $320
million in convertible debentures. The sale closed on April 16, 2003.
Pursuant to the change in control, the company's long-term debt balance
became a current liability, and the full principal and interest owing on
the shareholder loans was repaid.
A-18
STAR OIL & GAS LTD.
Consolidated Financial Statements
MARCH 31, 2003 AND 2002
(in thousands of Canadian dollars)
A-19
STAR OIL & GAS LTD.
Consolidated Balance Sheets
(Unaudited)
- --------------------------------------------------------------------------------
(CDN $ - thousands)
MARCH 31, DECEMBER 31, MARCH 31, DECEMBER 31,
2003 2002 2002 2001
ASSETS
CURRENT ASSETS
Cash and short-term investments -- -- 2,028 --
Accounts receivable 33,880 29,434 18,602 20,022
Prepaid expenses 393 1,191 977 1,348
Income taxes receivable -- -- 1,813 1,999
-----------------------------------------------
34,273 30,625 23,420 23,369
CAPITAL ASSETS 479,346 474,319 452,517 445,756
OTHER ASSETS 323 323 252 267
-----------------------------------------------
513,942 505,267 476,189 469,392
===============================================
LIABILITIES
CURRENT LIABILITIES
Bank indebtedness 803 2,424 -- 1,591
Accounts payable 25,031 25,080 18,568 19,577
Income taxes payable 13,384 3,010 -- --
Current portion of shareholder loans (note 2) 45,701 -- -- --
Current portion of bank debt (note 2) 112,172 -- -- --
-----------------------------------------------
197,091 30,514 18,568 21,168
LONG-TERM DEBT (note 2) -- 136,490 144,837 139,815
SHAREHOLDER LOANS (note 2) -- 48,458 48,806 48,783
SITE RESTORATION 5,019 4,958 4,520 4,359
DEFERRED LIABILITIES 1,137 1,244 1,623 1,747
FUTURE INCOME TAXES 107,010 106,392 101,256 101,161
-----------------------------------------------
310,257 328,056 319,610 317,033
-----------------------------------------------
SHAREHOLDERS' EQUITY
CAPITAL STOCK 33,371 33,371 33,371 33,371
RETAINED EARNINGS 170,314 143,840 123,208 118,988
-----------------------------------------------
203,685 177,211 156,579 152,359
-----------------------------------------------
513,942 505,267 476,189 469,392
===============================================
A-20
STAR OIL & GAS LTD.
Consolidated Statements of Income and Retained Earnings
(Unaudited) FOR THE THREE MONTHS ENDED MARCH 31
- --------------------------------------------------------------------------------
(CDN $ - thousands)
2003 2002
REVENUE
Production and royalties 87,068 41,764
Crown and other royalties (20,470) (8,229)
-------------------
66,598 33,535
-------------------
EXPENSES
Production 10,429 8,912
General and administrative 1,250 1,065
Interest on long-term debt 2,074 2,224
Depletion and depreciation 15,442 13,520
Foreign exchange (gain) loss (5,489) 53
-------------------
23,706 25,774
-------------------
INCOME BEFORE PROVISION FOR TAXES 42,892 7,761
-------------------
PROVISION FOR TAXES
Current 15,800 3,446
Future 618 95
-------------------
16,418 3,541
-------------------
NET INCOME 26,474 4,220
RETAINED EARNINGS - BEGINNING OF PERIOD 143,840 118,988
-------------------
RETAINED EARNINGS - END OF PERIOD 170,314 123,208
===================
A-21
STAR OIL & GAS LTD.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited) FOR THE THREE MONTHS ENDED MARCH 31
- --------------------------------------------------------------------------------
(CDN $ - thousands)
2003 2002
CASH PROVIDED BY (USED IN)
OPERATING ACTIVITIES
Net income 26,474 4,220
Adjustments for
Depletion and depreciation 15,442 13,520
Future income taxes 618 95
Unrealized foreign exchange (gain) loss (5,514) 46
Amortization of deferred liability (125) (138)
-------------------
36,895 17,743
-------------------
Changes in non-cash working capital items
(Increase) decrease in accounts receivable (4,446) 1,420
Increase in prepaid expenses 798 371
Increase (decrease) in accounts payable 260 (2,002)
Increase in income taxes payable/receivable 10,374 186
-------------------
6,986 (25)
-------------------
43,881 17,718
-------------------
INVESTING ACTIVITIES
Payment for land and property (1,000) (2,128)
Expenditures on drilling and exploration (15,597) (8,981)
Expenditures on production and other equipment (7,563) (9,242)
-------------------
(24,160) (20,351)
Changes in non-cash working capital items
Increase (decrease) in accounts payable (291) 1,007
-------------------
(24,451) (19,344)
Proceeds from sale of capital assets 4,038 396
Expenditures on site restoration (286) (164)
Other assets -- 14
-------------------
(20,699) (19,098)
-------------------
FINANCING ACTIVITIES
Increase in (repayments of) bank indebtedness (1,621) (1,591)
(Repayments of) proceeds from long-term borrowings (21,561) 4,999
-------------------
(23,182) 3,408
-------------------
NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS -- 2,028
CASH AND CASH EQUIVALENTS - BEGINNING OF PERIOD -- --
-------------------
CASH AND CASH EQUIVALENTS - END OF PERIOD -- 2,028
===================
SUPPLEMENTAL INFORMATION
Interest paid 1,404 1,515
Taxes paid 5,915 3,746
A-22
STAR OIL & GAS LTD.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
- --------------------------------------------------------------------------------
1 SUMMARY OF ACCOUNTING POLICIES
These interim financial statements have been prepared based on the
consistent application of the accounting policies as set out in the most
recent annual financial statements. The note disclosure requirements for
annual financial statements provide additional disclosure that is required
for interim financial statements. Accordingly, these interim financial
statements should be read in conjunction with the financial statements
included in the company's 2002 audited financial statements.
2 SUBSEQUENT EVENTS
CHANGE OF CONTROL
On March 31, 2003, the company's shareholders entered into an acquisition
agreement with ARC Energy Trust ("ARC") whereby ARC offered to purchase
all of the issued and outstanding shares of Star Oil & Gas Ltd. for a
total purchase price of $710 million to be financed by cash and $320
million in convertible debentures. The sale closed on April 16, 2003.
LONG-TERM DEBT
Pursuant to the change in control on April 16, 2003, the company's
long-term debt balance became a current liability. The company has
reclassified the long-term balance to current liabilities as at March 31,
2003.
HEDGING ACTIVITY
On April 14, 2003 the company made a payment of $524,300 to terminate the
interest rate hedge contract which was in place at March 31, 2003. The
interest rate hedge fixed the interest rate on $10 million of Banker's
Acceptances at a rate of 6.520% to September 25, 2008.
On April 14, 2003, the company made a payment of $1,826,700 to terminate
crude oil contracts which were in place at March 31, 2003. The terminated
oil contracts consisted of a fixed price contract at US$23.55 per barrel
on 1,000 barrels-per-day for the period April through December 2003 and a
costless collar with a floor of US$23.00 and cap of US$25.80 per barrel on
1,000 barrels-per-day for the period April through December 2003.
On April 14, 2003, the company made a payment of $13,305,902 to terminate
the following physical delivery natural gas fixed price contracts that
were in place at March 31, 2003:
o 5,000 GJ-per-day AECO contract with a $4.00 per GJ floor and $5.91
per GJ cap through to October 2003
o 2,000 GJ-per-day AECO contract at $2.525 per GJ through to October
2003
o 1,000 GJ per day AECO contract at $2.48 per GJ through to October
2003
o 5,000 GJ per day AECO contract at $2.955 per GJ through to October
2004
SHAREHOLDER LOANS
On April 16, 2003, the full principal and interest owing on the
shareholder loans was repaid.
APPENDIX "B"
PRO FORMA FINANCIAL STATEMENTS OF ARC ENERGY TRUST
B-2
Deloitte & Touche LLP
3000, 700 Second Street SW
Calgary AB Canada T2P 0S7
Telephone: +1-403-267-1700
Facsimile: +1-403-264-2871 [GRAPHIC OMITTED]
[LOGO - DELOITTE
& TOUCHE]
COMPILATION REPORT
To the Directors of ARC Resources Ltd.:
We have reviewed, as to compilation only, the accompanying pro forma combined
balance sheets of ARC ENERGY TRUST as at March 31, 2003 and December 31, 2002
and the pro forma combined statements of income for the three month period ended
March 31, 2003 and the year ended December 31, 2002 which have been prepared for
inclusion in the Annual Information Form dated May 16, 2003. In our opinion, the
pro forma combined balance sheets as at March 31, 2003 and December 31, 2002 and
the pro forma combined statements of income for the three month period ended
March 31, 2003 and the year ended December 31, 2002, have been properly compiled
to give effect to the proposed transaction and the assumptions described in the
notes thereto.
Calgary, Alberta (signed) "DELOITTE & TOUCHE LLP"
May 16, 2003 Chartered Accountants
B-3
ARC ENERGY TRUST
PRO FORMA COMBINED BALANCE SHEET
AS AT MARCH 31, 2003
(UNAUDITED)
($ THOUSANDS)
PRO FORMA
ARC STAR ADJUSTMENTS PRO FORMA
- ---------------------------------------------------------------------------------------------------------------
$ $ $ $
ASSETS
Current assets
Cash 3,301 -- -- 3,301
Accounts receivable 66,168 33,880 -- 100,048
Prepaid expenses 6,084 393 (393) 2.1 6,084
- ---------------------------------------------------------------------------------------------------------------
75,553 34,273 (393) 2.1 109,433
Deposit for Star acquisition 40,000 -- (40,000) 2.1 --
Reclamation fund 14,053 -- -- 14,053
Other assets -- 323 (323) 2.1 --
Property, plant and equipment (net) 1,382,908 479,346 236,497 2.1 2,098,751
Goodwill -- -- 173,613 2.1 173,613
- ---------------------------------------------------------------------------------------------------------------
TOTAL ASSETS 1,512,514 513,942 369,394 2,395,850
===============================================================================================================
LIABILITIES
Current liabilities
Accounts payable and accrued
liabilities 61,787 25,031 -- 86,818
Bank indebtedness -- 803 (803) 2.1 --
Cash distributions payable 20,442 -- -- 20,442
Bank debt -- 112,172 (112,172) 2.1 --
Shareholder loans -- 45,701 (45,701) 2.1 --
Income taxes payable -- 13,384 -- 13,384
- ---------------------------------------------------------------------------------------------------------------
82,229 197,091 (158,676) 120,644
Long-term debt 219,907 -- 270,506 2.1 490,413
Site restoration and abandonment 38,622 5,019 -- 2.3 43,641
Commodity and foreign currency
contracts 7,799 1,137 (1,137) 2.1 7,799
Retention bonuses 4,000 -- -- 4,000
Future income taxes 147,466 107,010 137,098 2.1 391,574
- ---------------------------------------------------------------------------------------------------------------
TOTAL LIABILITIES 500,023 310,257 247,791 1,058,071
===============================================================================================================
UNITHOLDERS' EQUITY
Unitholders' capital 1,312,206 -- -- 1,312,206
Exchangeable shares and share
capital 33,496 33,371 (33,371) 2.1 33,496
Convertible debenture -- -- 320,000 2.1 320,000
Accumulated earnings 415,076 170,314 (165,026) 2.1 420,364
Accumulated cash distributions (748,287) -- -- (748,287)
- ---------------------------------------------------------------------------------------------------------------
TOTAL UNITHOLDERS' EQUITY 1,012,491 203,685 121,603 1,337,779
===============================================================================================================
TOTAL LIABILITY AND UNITHOLDERS'
EQUITY 1,512,514 513,942 369,394 2,395,850
===============================================================================================================
B-4
ARC ENERGY TRUST
PRO FORMA COMBINED STATEMENT OF INCOME
AS AT MARCH 31, 2003
(UNAUDITED)
($ THOUSANDS)
PRO FORMA
ARC STAR ADJUSTMENTS PRO FORMA
- ----------------------------------------------------------------------------------------------------------------
$ $ $ $
REVENUE
Oil, natural gas, natural gas liquids
and sulphur sales 176,629 87,068 (4,676) 2.2, 2.9 259,021
Royalties (36,439) (20,470) 1,078 2.2, 2.4 (55,831)
- ----------------------------------------------------------------------------------------------------------------
140,190 66,598 (3,598) 203,190
- ----------------------------------------------------------------------------------------------------------------
EXPENSES
Operating 28,959 10,429 (771) 2.2 38,617
General and administrative 4,009 1,250 -- 5,259
Interest on long-term debt 3,825 2,074 1,910 2.6 7,809
Capital taxes 100 -- 84 2.7 184
(Gain)/loss on foreign exchange (7,495) (5,489) 5,489 2.10 (7,495)
Depletion, deprecation and
amortization 42,734 15,442 7,450 2.8 65,626
- ----------------------------------------------------------------------------------------------------------------
72,132 23,706 14,162 110,000
- ----------------------------------------------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES 68,058 42,892 (17,760) 93,190
Current income taxes -- (15,800) 15,800 2.11 --
Future income taxes (3,070) (618) 3,109 2.12 (579)
- ----------------------------------------------------------------------------------------------------------------
NET INCOME 64,988 26,474 1,149 92,611
================================================================================================================
NET INCOME PER UNIT (NOTE 3)
Basic 0.49 0.70
================================================================================================================
Diluted 0.40 0.58
================================================================================================================
B-5
ARC ENERGY TRUST
PRO FORMA COMBINED BALANCE SHEET
AS AT DECEMBER 31, 2002
(UNAUDITED)
($ THOUSANDS)
PRO FORMA
ARC STAR ADJUSTMENTS PRO FORMA
- ----------------------------------------------------------------------------------------------------------------
$ $ $ $
ASSETS
Current assets
Cash 835 -- -- 835
Accounts receivable 49,631 29,434 -- 79,065
Prepaid expenses 6,965 1,191 (1,191) 2.1 6,965
- ----------------------------------------------------------------------------------------------------------------
57,431 30,625 (1,191) 86,865
Reclamation fund 12,924 -- 12,924
Other assets -- 323 (323) 2.1 --
Property, plant and equipment, net 1,397,563 474,319 236,497 2.1 2,108,379
Goodwill -- -- 173,613 2.1 173,613
- ----------------------------------------------------------------------------------------------------------------
TOTAL ASSETS 1,467,918 505,267 408,596 2,381,781
================================================================================================================
LIABILITIES
Current liabilities
Accounts payable and accrued
liabilities 51,454 25,080 -- 76,534
Bank indebtedness -- 2,424 (2,424) 2.1 --
Cash distributions payable 16,044 -- -- 16,044
Income taxes payable -- 3,010 -- 3,010
- ----------------------------------------------------------------------------------------------------------------
67,498 30,514 (2,424) 2.1 95,588
Long-term debt 337,728 136,490 174,016 2.1 648,234
Shareholder loans -- 48,458 (48,458) 2.1 --
Site reclamation and abandonment 36,421 4,958 61 2.3 41,440
Commodity and foreign currency
contracts 9,210 -- -- 9,210
Deferred liabilities -- 1,244 (1,244) 2.1 --
Retention bonuses 4,000 -- -- 4,000
Future income taxes 144,395 106,392 137,098 2.1 387,885
- ----------------------------------------------------------------------------------------------------------------
TOTAL LIABILITIES 599,252 328,056 259,049 1,186,357
- ----------------------------------------------------------------------------------------------------------------
UNITHOLDERS' EQUITY
Unitholders' capital 1,172,199 - -- 1,172,199
Exchangeable shares and share capital 35,326 33,371 (33,371) 2.1 35,326
Convertible debenture - - 320,000 2.1 320,000
Accumulated earnings 350,088 143,840 (137,082) 2.1 356,846
Accumulated cash distributions (688,947) - -- (688,947)
- ----------------------------------------------------------------------------------------------------------------
TOTAL UNITHOLDERS' EQUITY 868,666 177,211 149,547 1,195,424
- ----------------------------------------------------------------------------------------------------------------
TOTAL LIABILITIES AND UNITHOLDERS'
EQUITY 1,467,918 505,267 408,596 2,381,781
================================================================================================================
B-6
ARC ENERGY TRUST
PRO FORMA COMBINED STATEMENT OF INCOME
AS AT DECEMBER 31, 2002
(UNAUDITED)
($ THOUSANDS)
PRO FORMA
ARC STAR ADJUSTMENTS PRO FORMA
- ----------------------------------------------------------------------------------------------------------------
$ $ $ $
REVENUE
Oil, natural gas, natural gas liquids
and sulphur sales 444,835 199,982 (20,344) 2.2, 2.9 624,473
Royalties (85,155) (44,251) 3,488 2.2, 2.4 (125,918)
- ----------------------------------------------------------------------------------------------------------------
359,680 155,731 (16,856) 498,555
- ----------------------------------------------------------------------------------------------------------------
EXPENSES
Operating 99,876 41,177 (3,627) 2.2 137,426
General and administrative 15,365 4,889 -- 20,254
Management fee 5,161 -- 2,027 2.5 7,188
Interest on long-term debt 12,606 8,738 3,993 2.6 25,337
Capital taxes 1,370 -- 338 2.7 1,708
(Gain)/loss on foreign exchange (607) (653) 653 2.10 (607)
Depletion, depreciation and
amortization 161,759 54,865 24,610 2.8 241,234
Internalization of management
contract 25,892 -- -- 25,892
- ----------------------------------------------------------------------------------------------------------------
321,422 109,016 27,994 458,432
- ----------------------------------------------------------------------------------------------------------------
Income before income taxes 38,258 46,715 (44,850) 40,123
Current income taxes -- (16,632) 16,632 2.11 --
Future income taxes 29,635 (5,231) 10,272 2.12 34,676
- ----------------------------------------------------------------------------------------------------------------
NET INCOME 67,893 24,852 (17,946) 74,799
- ----------------------------------------------------------------------------------------------------------------
NET INCOME PER UNIT (NOTE 3)
Basic 0.57 0.63
================================================================================================================
Diluted 0.56 0.51
================================================================================================================
B-7
ARC ENERGY TRUST
NOTES TO PRO FORMA COMBINED FINANCIAL STATEMENTS
(UNAUDITED)
(ALL AMOUNTS IN $ THOUSANDS)
- --------------------------------------------------------------------------------
1. BASIS OF PRESENTATION
On April 16, 2003 ARC Energy Trust ("ARC") completed the acquisition of Star Oil
& Gas Ltd. ("Star") for total consideration of $710 million, subject to final
adjustments. In conjunction with this acquisition, ARC entered into agreements
to sell certain of Star's producing properties and undeveloped acreage to third
parties for net proceeds of $78 million. The net purchase price of approximately
$631 was funded through a combination of bank debt using ARC's existing
facilities and the issuance to the vendor of $320 million in special convertible
debentures.
The special convertible debentures are convertible at any time into the
underlying debentures by the holders, and will be automatically converted into
the underlying debentures on the Trust securing a receipt for a final prospectus
for the distribution of the underlying debentures and on certain other events
and in any event by June 30, 2005. The special convertible debentures are
identical to the underlying debentures in respect of subordination to senior
debt, redemption for cash, interest rates and rights of payment on maturity for
Trust Units.
The underlying debentures have the following terms:
o Subordinate to senior debt.
o A coupon rate of 8 per cent per annum payable quarterly
commencing on June 30, 2003. The coupon will increase to 10 per
cent per annum commencing June 30, 2005.
o Maturity on June 30, 2008 can be satisfied by issuing Trust
Units.
o The Trust has the right to redeem in full with cash at any time
or redeem $40 million per quarter subsequent to June 30, 2003
using a combination of cash (minimum of 50 per cent) and Trust
Units.
o Holders of the debentures have a conversion privilege at $11.84
per Trust Unit through June 30, 2005 and $11.38 per Trust Unit
after that date.
The accompanying unaudited pro forma combined financial statements as at and for
the three months ended March 31, 2003 have been prepared from information
derived from the following:
a) unaudited interim consolidated financial statements as at and for
the three months ended March 31, 2003 for ARC; and
b) unaudited interim consolidated financial statements as at and for
the three months ended March 31, 2003 for Star.
B-8
ARC ENERGY TRUST
NOTES TO PRO FORMA COMBINED FINANCIAL STATEMENTS
(UNAUDITED)
(All amounts in $ thousands)
PAGE 2
- --------------------------------------------------------------------------------
The accompanying unaudited pro forma combined financial statements as at and for
the year ended December 31, 2002 have been prepared from information derived
from the following:
a) audited consolidated financial statements as at and for the year
ended December 31, 2002 for ARC; and
b) audited consolidated financial statements as at and for the year
ended December 31, 2002 for Star.
In the opinion of the management of ARC, the accompanying pro forma combined
financial statements ("pro forma statements") include all material adjustments
necessary for fair presentation in accordance with Canadian generally accepted
accounting principles. The pro forma combined balance sheets as at March 31,
2003 and December 31, 2002 give effect to the transactions described in note 2
as if they had occurred on March 31, 2003 and December 31, 2002, respectively,
while the pro forma combined statements of income give effect to the
transactions as if they had occurred on January 1, 2002.
The pro forma statements should be read in conjunction with the audited
consolidated financial statements of ARC and Star.
Accounting policies used in the preparation of the pro forma statements are in
accordance with those used in the preparation of the audited consolidated
financial statements of ARC for the year ended December 31, 2002.
THE PRO FORMA STATEMENTS ARE NOT NECESSARILY INDICATIVE EITHER OF THE RESULTS OF
OPERATIONS THAT WOULD HAVE OCCURRED IF THE EVENTS REFLECTED HEREIN HAD BEEN IN
EFFECT ON THE DATES INDICATED OR OF THE RESULTS OF OPERATIONS EXPECTED IN FUTURE
YEARS. IN PREPARING THESE PRO FORMA STATEMENTS, NO ADJUSTMENTS HAVE BEEN MADE TO
REFLECT THE OPERATING SYNERGIES AND THE RESULTING COST SAVINGS EXPECTED TO
RESULT FROM COMBINING THE OPERATIONS OF ARC AND STAR.
B-9
ARC ENERGY TRUST
NOTES TO PRO FORMA COMBINED FINANCIAL STATEMENTS
(Unaudited) (All amounts in $ thousands)
PAGE 3
- --------------------------------------------------------------------------------
2. Pro Forma Assumptions and Adjustments
The pro forma statements give effect to the following assumptions and
adjustments:
2.1 The transaction will be accounted for using the purchase method. The
following table shows the assumptions made with respect to the
allocation of the aggregate purchase price based on estimated fair
values of Star's net assets and the necessary adjustments to their
historical carrying value.
ALLOCATION PRO FORMA
ADJUSTMENT
DR/(CR)
----------------------------------
$ $
NET ASSETS ACQUIRED:
Current Assets 44,249
Current Liabilities (54,072)
Property, Plant and Equipment 715,843 236,497
Site Restoration Liability (5,019)
Future Income Tax (244,108) (137,098)
Goodwill 173,613 173,613
-------
630,506
=======
FINANCED BY:
Cash (including $40 million deposit) 127,844
Long-term Debt Assumed 182,662
Special Convertible Debentures Issued 320,000
-------
630,506
=======
The above allocation includes:
o Estimated transaction costs of $6,100.
o Repayment of shareholder loans.
o Write-off of deferred liabilities, prepaid expenses and other assets.
2.2 Adjustments have been made to reflect the reduction of revenues,
royalties and operating expenses associated with the properties sold to
third parties in conjunction with the Star acquisition.
2.3 The estimated actual liability for site reclamation and abandonment is
assumed to equal the future site reclamation and abandonment balances
carried on Star's balance sheet.
B-10
ARC ENERGY TRUST
NOTES TO PRO FORMA COMBINED FINANCIAL STATEMENTS
(Unaudited) (All amounts in $ thousands)
PAGE 4
- --------------------------------------------------------------------------------
2.4 The impact of the association rules on ARC and Star for Alberta Royalty
Tax Credit ("ARTC") purposes reduces ARTC by $123 and $512 for the
three months ended March 31, 2003 and the year ended December 31, 2002,
respectively.
2.5 Management fees have been calculated at a rate of 3% of net production
revenue for the period January 1, 2002 to August 29, 2002, when ARC
eliminated the external contract.
2.6 Interest expense has been increased to reflect the additional debt
drawn on existing facilities required to finance the Star acquisition.
The debenture interest is not included in the Statement of Income as
the debentures are considered to be equity under Canadian generally
accepted accounting principles.
2.7 Capital taxes have been adjusted to reflect the increase in the taxable
capital of ARC's corporate subsidiaries.
2.8 Depletion, depreciation and amortization has been adjusted to reflect
the pro forma value of the oil and gas assets, the reserves acquired
and the production for the respective periods.
2.9 Star's hedging losses of $2,454 and $5,578 for the three months ended
March 31, 2003 and the year ended December 31, 2002, respectively, have
been eliminated. All of Star's hedges were terminated on April 14, 2003
for $15,657.
2.10 Star's foreign exchange gain of $5,489 and foreign exchange loss of $53
for the three months ended March 31, 2003 and the year ended December
31, 2002, respectively, have been eliminated. All U.S. dollar debt was
retired on the closing date.
2.11 Current taxes of $15,800 and $16,632 for the three months ended March
31, 2003 and the year ended December 31, 2002, respectively, have been
eliminated. In ARC's structure, payments are made between ARC's
corporate subsidiaries and ARC, transferring both income and tax
liability from the corporate subsidiaries to the unitholders.
2.12 The future income tax recovery (provision) reflects changes based upon
the above adjustments.
B-11
ARC ENERGY TRUST
NOTES TO PRO FORMA COMBINED FINANCIAL STATEMENTS
(Unaudited) (All amounts in $ thousands)
PAGE 5
- --------------------------------------------------------------------------------
3. Per Unit Information
Pro forma per unit information has been calculated using the weighted average
number of units outstanding as follows:
March 31, 2003 December 31, 2002
--------------------------------------
Basic 131,378,771 119,613,489
Diluted 158,789,794 147,201,288
4
DISCLOSURE CONTROLS AND PROCEDURES
As of February 25, 2003, the Trust's Chief Executive Officer and Chief Financial
Officer conducted an evaluation of the effectiveness of the Trust's disclosure
controls and procedures. Based on that evaluation, the Chief Executive Officer
and Chief Financial Officer concluded that as of such date the design and
operation of the Trust's disclosure controls and procedures were effective.
Additionally, there has been no significant changes in the Trust's internal
controls or in other factors that could significantly affect these controls
subsequent to the date of their evaluation, including any corrective actions
with regard to significant deficiencies and material weaknesses.
UNDERTAKING AND CONSENT TO SERVICE OF PROCESS
A. UNDERTAKING
Registrant undertakes to make available, in person or by telephone,
representatives to respond to inquiries made by the Commission staff, and to
furnish promptly, when requested to do so by the Commission staff, information
relating to: the securities registered pursuant to Form 40-F; the securities in
relation to which the obligation to file an annual report on Form 40-F arises;
or transactions in said securities.
B. CONSENT TO SERVICE OF PROCESS
The Registrant has previously filed with the Commission a Form F-X in connection
with the Trust Units.
SIGNATURES
Pursuant to the requirements of the Exchange Act, the Registrant certifies that
it meets all of the requirements for filing on Form 40-F and has duly caused
this annual report to be signed on its behalf by the undersigned, thereto duly
authorized.
Registrant: ARC ENERGY TRUST
-------------------------------------------------
By: (Signature and Title) "ALLAN R. TWA, SECRETARY"
-------------------------------------------------
by ARC Resources Ltd., Allan R. Twa, Secretary
-------------------------------------------------
Date: May 16, 2003
-------------------------------------------------
CERTIFICATIONS
I, John P. Dielwart, certify that:
1. I have reviewed this annual report on Form 40-F of ARC Energy Trust;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this annual
report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this annual report;
5
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:
a) designed such disclosure controls and procedures to ensure that material
information relating to the registrant, including its consolidated subsidiaries,
is made known to us by others within those entities, particularly during the
period in which this annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this annual
report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the effectiveness of
the disclosure controls and procedures based on our evaluation as of the
Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (and persons performing the
equivalent function):
a) all significant deficiencies in the design or operation of internal controls
which could adversely affect the registrant's ability to record, process,
summarize and report financial data and have identified for the registrant's
auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in this
annual report whether there were significant changes in internal controls or in
other factors that could significantly affect internal controls subsequent to
the date of our most recent evaluation, including any corrective actions with
regard to significant deficiencies and material weaknesses.
Date: May 16, 2003
ARC ENERGY TRUST
by ARC Resources Ltd.
/s/ JOHN P. DIELWART
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John P. Dielwart - President and
Chief Executive Officer
I, Steven W. Sinclair , certify that:
1. I have reviewed this annual report on Form 40-F of ARC Energy Trust;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this annual
report;
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3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:
a) designed such disclosure controls and procedures to ensure that material
information relating to the registrant, including its consolidated subsidiaries,
is made known to us by others within those entities, particularly during the
period in which this annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this annual
report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the effectiveness of
the disclosure controls and procedures based on our evaluation as of the
Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (and persons performing the
equivalent function):
a) all significant deficiencies in the design or operation of internal controls
which could adversely affect the registrant's ability to record, process,
summarize and report financial data and have identified for the registrant's
auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in this
annual report whether there were significant changes in internal controls or in
other factors that could significantly affect internal controls subsequent to
the date of our most recent evaluation, including any corrective actions with
regard to significant deficiencies and material weaknesses.
Date: May 16, 2003
ARC Energy Trust
by ARC Resources Ltd.
/s/ STEVEN W. SINCLAIR
- --------------------------------------------
Steven W. Sinclair - Vice-President, Finance
and Chief Financial Officer
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INDEX TO EXHIBITS
EXHIBIT NUMBER TITLE
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23.1 Consent of Deloitte & Touche LLP to the inclusion of
the Auditor's Report dated January 27, 2003 on the
financial statements of ARC Energy Trust.
23.2 Consent of PricewaterhouseCoopers LLP to the
inclusion of the Auditor's Report dated January 31,
2003 except for note 15 which is as at April 16, 2003
on the financial statements of Star Oil & Gas Ltd.
23.3 Consent of Gilbert Laustsen Jung Associates Ltd. to
the inclusion of the Reports dated January 24, 2003,
April 30, 2003 and May 12, 2003 evaluating the
reserves of ARC Resources Ltd. and ARC (Sask.) Energy
Trust
99.1 CEO Certification pursuant to 18 U.S.C. Section 1350,
as adopted pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002
99.2 CFO Certification pursuant to 18 U.S.C. Section 1350,
as adopted pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002