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/FIRST AND FINAL ADD - TO153 - PrimeWest Energy Trust Earnings
UNITHOLDERS' EQUITY
The Trust had 48,751,883 Trust Units outstanding at December 31, 2003 compared
to 37,004,522 Trust Units at the end of 2002. In addition, there are 3,041,123
exchangeable shares (see below) outstanding at year end, exchangeable into a
total of 1,347,277 Trust Units. The weighted average number of Trust Units,
including those issuable by the exchange of exchangeable shares, was 46,015,519
Trust Units for 2003 comparedto 34,135,576 for 2002.
During the year, 360,608 Trust Units were issued pursuant to the Unit
Appreciation Rights Plan for employees.
During the year, PrimeWest completed 2 bought deal financings. The first closed
on February 13, 2003 raising net proceeds of $146.6 million on the issuance of 6
million Trust Units at $25.75 per Trust Unit. Proceeds were used to reduce the
indebtedness of PrimeWest under its credit facility, including a portion
incurred in connection with the January 2003 acquisitionof two private Canadian
exploration and production companies with properties in the Caroline and Peace
River Arch areas of Alberta. The second financing closed on September 26, 2003
raising net proceeds of $76.1 million on the issuance of 3.1 million Trust Units
at $25.90 per Trust Unit. Proceeds were used to reduce bank indebtedness and
pursue development opportunities in the Caroline, Valhalla and Brant Farrow
areas.
PrimeWest issued 465,969 Trust Units for $11.4 million pursuant to the
Distribution Reinvestment component (476,106 Trust Units, $10.1 million in
2002), 134,629 Trust Units for $3.4 million pursuant to the Premium Distribution
component (0 Trust Units in 2002) and 721,209 Trust Units for $17.6 million
pursuant to the Optional Trust Unit Purchase Plan component (OTUPP) in 2003
(503,103 Trust Units, $13.9 million in 2002).
For the first time in PrimeWest's history, the OTUPP sold out before the end of
the calendar year, demonstrating the strong support of existing unitholders.
During the fourth quarter, PrimeWest enhanced its existing plan with the Premium
Distribution (PREP) component.
As an alternative to the existing DRIP Component of the Plan, the new PREP
allows eligible Canadian unitholders to elect to receive a premium cash
distribution of up to 102% of the cash that the unitholder would otherwise have
received on the distribution date, subject to proration in certain events.
The DRIP gives Canadian unitholders the chance to reinvest their monthly
distributions at a 5%discount to the 20 day volume weighted average market
price, while the OTUPP gives Canadian unitholders an opportunity to purchase
additional Trust Units directly from PrimeWest at the same 5% discount to the 20
day volume weighted average market price. The DRIP and PREP components are
mutually exclusive, and participation in the OTUPP requires enrollment in either
the DRIP or PREP.
These plan components benefit the unitholders by offering alternatives to
maximize their investment in PrimeWest, while providing the Trust with an
inexpensive method to raise additional capital. The Trust expects interest in
these plans in 2004 to be similar to 2003. Proceeds from these plans are used
for debt reduction of PrimeWest's credit facility and to help fund ongoing
capital development programs.
In 2003 PrimeWest completed a review of the requirements necessary for the
establishment of a U.S. DRIP program and concluded that such a program for U.S.
resident unitholders is not presently feasible.
For additional information or to join these plans, contact PrimeWest's Plan
Agent, Computershare Trust Company of Canada at 1-800-564-6253 or visit
PrimeWest's website at http://www.primewestenergy.com/.
Exchangeable shares
Exchangeable shares were issued in connection with both the Venator Petroleum
Company Ltd. acquisition in April 2000 and the Cypress Energy Inc. acquisition
in March 2001. These shares were issued to provide a tax-deferred rollover of
the adjusted cost base from the shares being exchanged to the exchangeable
shares of PrimeWest. A tax deferral is not permitted by Canadian tax law when
shares are exchanged for Trust Units.
In 2002 1,363,714 exchangeable shares were issued in connection with the
management internalization transaction. During 2003, 1,500,000 exchangeable
shares were issued in relation to the termination of the management incentive
program of PrimeWest Management Inc. (see Note 11 in the Consolidated Financial
Statements).
The exchangeable shares do not receive cash distributions. In lieu of receiving
cash distributions, the number of Trust Units that the exchangeable shareholder
will receive upon exchange increases each month based on the distribution amount
divided by the market price of the Trust Units on the 15th day of each month.
At December 31, 2003, there were 3,041,123 exchangeable shares outstanding. The
exchange ratio on these shares was 0.44302 Trust Units for each exchangeable
share as at year-end.
For purposes of calculating basic per Trust Unit amounts, these exchangeable
shares have been assumed to be exchanged into Trust Units at the current
exchange ratio.
CASH DISTRIBUTIONS
Cash distributions to unitholders are at the discretion of the Board of
Directors and can fluctuate depending on the cash flow generated from
operations. As discussed previously, the cash flow available for distribution is
dependent upon many factors including commodity prices, production levels, debt
levels, capital spending requirements, and factors in the overall environment.
In 2003, cash distributions totaled $192.6 million, or $4.40 per Trust Unit,
compared to $158.0 million, or $4.80 per Trust Unit in 2002. Since inception in
October of 1996 to December 31, 2003, PrimeWest has distributed $39.92 per Trust
Unit;just under the initial public offering price of $40.00 (through December
31, 2002 - $35.92 per Trust Unit). In June, 2003 PrimeWest's Board of Directors
announced its intention to distribute 70-90% of cash flow, as opposed to the
Trust's historical 95%average annual payout ratio. Withholding some internally
generated cash increases PrimeWest's financial flexibility.
Payments to U.S. unitholders are subject to 15% Canadian withholding tax, which
applies to the taxable portion of the distribution.
CASH FLOW SENSITIVITIES
The table below is designed to provide the directional impact on 2004 annual
cash available for distribution per unit (increase/decrease) depending on
changes in the following:
$ per Trust Unit(1)
-------------------------------------------------------------------------
Crude oil price ($US 1.00/bbl WTI increase) 0.07
Natural gas price ($0.10/mcf increase) 0.06
Exchange rate ($US 0.01 decrease) 0.07
Interest rate (1% decrease) 0.01
Production (1,000 BOE/day increase) 0.14
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(1) Without the effect of price protection
The figures in this table are provided for directional information only and are
based on the units outstanding as at December 31, 2003. Should changes to
commodity price, interest rate, exchange rate or production levels noted above
take place, it should not be assumed that a corresponding change would be made
to the distribution level.
CONTRACTUAL OBLIGATIONS
PrimeWest enters into many contract obligationsas part of conducting day-
to-day business. Material contract obligations that PrimeWest has currently in
place are lease rental commitments that run from 2004 through 2009 and require
annual payments after deducting sub-lease income of $1.2 million in2004, $1.1
million in 2005 and 2006, and $2.4 million in 2007 through 2009, the remaining
term of the lease. In addition, PrimeWest also has a pipeline transportation
commitment that runs to October 31, 2007 and has minimum annual payment
requirements of $U.S. 2.1 million.
As part of PrimeWest's internalization transaction (see Note 11 in the Notes to
the Consolidated Financial Statements), PrimeWest agreed to pay $3.5 million in
exchangeable shares pursuant to a special employee retention plan. Onequarter
of the exchangeable shares will be issuable to the Senior Managers of PrimeWest
on each of the second, third, fourth and fifth anniversary of transaction
closing, November 6, 2002. As at December 31, 2003 $0.5 million has been accrued
in non-cash general and administrative expenses related to the special employee
retention plan.
RECENT ACCOUNTING PRONOUNCEMENTS ISSUED BUT NOT IMPLEMENTED
During 2003, the following new or amended standards and guidelines were issued:
Hedging Transactions
The CICA has issued Accounting Guideline 13, "Hedging Relationships," (AcG 13)
which will be effective for fiscal years beginning on or after July 1, 2003. AcG
13 addresses the identification, designation, documentation and effectiveness of
hedging transactions for the purposes of applying hedge accounting. It also
establishes conditions for applying or discontinuing hedge accounting. Under the
new guideline, hedging transactions must be documented and it must be
demonstrated that the hedges are sufficiently effective in order to continue
accrual accounting for positions hedged with derivatives. The Trust does not
anticipate applying hedge accounting to its hedging relationships.
Asset Retirement Obligations
In March 2003, the CICA issued a new section in the CICA Handbook, section 3110,
Asset Retirement Obligations. This standard focuses on the recognition and
measurement of liabilities related to legal obligations associated with the
retirement of property, plant and equipment. Under this standard, these
obligations are initially measured at fair value and subsequently adjusted for
the accretion of discount and any changes in the underlying cash flows. The
asset retirement cost is to be capitalized to the related asset and amortized
into earnings over time. This section comes into effect for the Trust in 2004.
The Trust is currently evaluating the impact of this standard on its
consolidated financial statements and does not anticipate it will have a
material impact.
Oil and Gas Assets - Full Cost Accounting
In 2003, the CICA issued Accounting Guideline 16 impacting the application of
the cost centre impairment test (ceiling test). The guideline is effective for
fiscal years beginning on or after January 1, 2004. The cost impairment testis
now a two stage process which is to be performed at least annually. The first
stage of the test determines if the cost pool is impaired. An impairment loss
exists when the carrying amount of an asset is not recoverable and exceeds its
fair value. The carrying amount is not recoverable if it exceeds the sum of the
undiscounted cash flows from Proved reserves plus unproved costs using
management's best estimate of future prices. The second stage determines the
amount of the impairment loss to be recorded. The impairment is measured as the
amount by which the carrying amount of capitalized assets exceeds the future
discounted cash flows from Proved plus Probable reserves. The discount rate used
is the company's risk free rate. The guideline requires disclosure of the prices
used for purposes of the impairment test.
The impact of this new guideline on the Trust would be an impairment to capital
assets of $460 million before tax or $300 million after tax. The after tax
impairment of $300 million will be booked to retained earnings in the first
quarter of 2004.
Exchangeable Share Accounting
In November 2003 the CICA issued a draft EIC (D37) on "Income Trusts -
Exchangeable Units". The EIC proposes that the retained interest of the
exchangeable shareholders should be presented on the balance sheet as a
non-controlling interest separate and distinct from unitholder's equity. This
draft EIC is currently under review and was not enacted in final form as of the
time of publication of the Trust's consolidated financial statements.
Variable Interest Entities
In June 2003 the CICA issued Accounting Guideline 15 "Consolidation of Variable
Interest Entities" which deals with the consolidation of entities that are
subject to control on a basis otherthan ownership of voting interests. This
guideline is effective for annual and interim periods beginning on or after
November 1, 2004. The Trust has assessed that this new guideline is not
applicable based on the current structure of the Trust and therefore will have
no impact on the financial statements of the Trust.
BUSINESS RISKS
PrimeWest's operations are affected by a number of underlying risks, both
internal and external to the Trust. These risks are similar to those affecting
others in both the conventional oil and gas royalty trust sector and the
conventional oil and gas producers sector. The Trust's financial position,
results of operations, and cash available for distribution to unitholders are
directly impacted by these factors. These factors are discussed under two broad
categories - Commodity Price, Foreign Exchange and Interest Rate Risk; and
Operational and Other Business Risks.
Commodity Price, Foreign Exchange And Interest Rate Risk
The two most important factors affecting the level of cash distributions
available to unitholders are the level of production achieved by PrimeWest, and
the price received for its products. These prices are influenced in varying
degrees by factors outside the Trust's control. Some of these factors include:
- world market forces, specifically the actions of OPEC and other large
crude oil producing countries including Russia, and their
implications on the supply of crude oil;
- world and North American economic conditions which influence the
demand for both crude oil and natural gas and the level of interest
rates set by the governments of Canada and the U.S.;
- weather conditions that influence the demand for natural gas and
heating oil;
- the Canadian/U.S. exchange rate that affects the price received for
crude oil as the price of crude oil is referenced in U.S. dollars;
- transportation availability and costs; and
- price differentials among world and North American markets based on
transportation costs to major markets and quality of production.
To mitigate these risks, PrimeWest has an active hedging program in place based
on an established set of criteria that has been approved by the Board of
Directors. The results of the hedging program are reviewed against these
criteria and the results actively monitored by the Board.
Beyond our hedging strategy, PrimeWest also mitigates risk by having a
well-diversified marketing portfolio and by transacting with a number of
counter-parties and limiting exposure to each counter-party. In 2003,
approximately 25% of natural gas production was sold to aggregators and 75% into
the Alberta short-term or export long-term markets.
The contracts that PrimeWest has with aggregators vary in length. They represent
a blend of domestic and U.S. markets and fixed and floating prices designed to
provide price diversification to our revenue stream.
The primary objective of our commodity risk management program is to reduce the
volatility of our cash distributions, to lock in the economics on major
acquisitions and to protect our capital structure when commodity prices cycle
downwards. In 2003, PrimeWest lost $30.5 million from commodity hedges ($0.66
per trust unit), while in 2002,PrimeWest added $28.1 million ($0.82 per Trust
Unit) to our cash flow through various physical and financial hedging
transactions. Over the three year period 2001 to 2003, PrimeWest's hedging
program has added $37.1 million to revenue.
Operational AndOther Business Risks
PrimeWest is also exposed to a number of risks related to its activities within
the oil and gas industry that also have an impact on the amount of cash
available to unitholders. These risks, and the ways in which PrimeWest seeks to
mitigate these risks include, but are not limited to:
RISK:
Production
----------
Risk associated with the production of oil and gas - includes well operations,
processing and the physical delivery of commodities to market.
We mitigate by:
Performing regular and proactive protective well, facility and pipeline
maintenance supported by telemetry, physical inspection and diagnostic tools.
Commodity Price
---------------
Fluctuations in natural gas, crude oil and natural gas liquid prices.
We mitigate by:
Hedging. See 2003 Hedging Results of this press release.
Transportation
--------------
Market risk related to the availability of transportation to market and
potential disruption in delivery systems.
We mitigate by:
Diversifying the transportation systems on which we rely to get our product to
market.
Natural decline
---------------
Development risk associated with capital enhancement activities undertaken - the
risk that capital spending on activities suchas drilling, well completions,
well workovers and other capital activities will not result in reserve additions
or in quantities sufficient to replace annual production declines.
We mitigate by:
Diversifying our capital spending program over a large number of projects so
that too much capital is not risked on any one activity. We also have a highly
skilled technical team of geologists, geophysicists and engineers working to
apply the latest technology in planning and executing capital programs. Capital
is spent only after strict economic criteria for production and reserve
additions are assessed.
Acquisitions
------------
Acquisition risk associated with acquiring producing properties at low cost to
renew our inventory of assets.
We mitigate by:
Continually scanning the marketplace for opportunities to acquire assets. Our
technical acquisition specialists evaluate potential corporate or property
acquisitions and identify areas for value enhancement through operational
efficiencies or capital investment. All prospects are subjected to rigorous
economic review against established acquisition and economic hurdle rates. In
some cases we may also hedge commodity prices to protect the acquisition
economics in the near term period.
Reserves
--------
Reserve risk in respect of the quantity and quality of recoverable reserves.
We mitigate by:
Contracting our reserves evaluation to a reputable third party consultant, GLJ.
The work and independence of GLJ is reviewed by the Audit andReserves Committee
of the Board of Directors of PrimeWest. Our strategy is to invest in mature,
longer life properties having a higher proved producing component where the
reserve risk is generally lower and cash flows are more stable and predictable.
Environmental Health and Safety (EH&S)
--------------------------------------
Environmental, health and safety risks associated with oil and gas properties
and facilities.
We mitigate by:
Establishing and adhering to strict guidelines for EH&S including training,
proper reporting of incidents, supervision and awareness. PrimeWest has active
community involvement in field locations including regular meetings with
stakeholders in the area. PrimeWest carries adequate insurance to cover property
losses, liability and business interruption.
These risks are reviewed regularly by the Corporate Governance and Nominating
Committee of the Board, which acts as PrimeWest's Environmental, Health and
Safety Committee.
Regulation, Tax and Royalties
-----------------------------
Changes in government regulations including reporting requirements, income tax
laws, operating practices and environmental protection requirements and royalty
rates.
We mitigate by:
Keeping informed of proposed changes in regulations and laws to properly respond
to and plan for the effects that these changes may have on our operations.
Liability to unitholders
------------------------
There is no statutory protection for unitholders from liabilities of the Trust.
We mitigate by:
Limiting the business of the Trust to the right to receive the net cash flow of
PrimeWest Energy Inc. All of the oil and gas business operations of PrimeWest
are conducted by PrimeWest Energy Inc. PrimeWest Energy Inc. has a vigorous EH&S
program as well as significant insurance protection.
INCOME TAXES - UNITHOLDERS - 2003
For the 2003 taxation year, Canadian unitholders of PrimeWest were paid $4.40
Canadian per Trust Unit in distributions. Of this distribution amount, 42% or
$1.85 per Trust Unit is deemed a tax deferred return of capital, and 58% or
$2.55 per Trust Unit is taxable to unitholders as other income (taxed at the
same rate as interest income).
For unitholders resident in the United States, the taxability of distributions
is calculated using U.S. tax rules which allow for the deduction of crown
royalties and accounting based depletion. As a result of these deductions, none
of the 2003 distribution is taxable as dividends and 100% of the 2003
distributions are atax deferred return of capital. A 15% withholding tax
applies to distributions paid to U.S. unitholders. Further details regarding the
withholding tax is available on PrimeWest's website at
http://www.primewestenergy.com/.
For both Canadian and UnitedStates unitholders, the tax deferred return of
capital portion reduces the unitholder's adjusted cost base for purposes of
calculating a capital gain or loss upon ultimate disposition of their Trust
Units. Unitholders contemplating a disposition may wish to consult the
"Unitholder Info" section on PrimeWest's website and use the adjusted cost base
calculator.
QUARTERLY PERFORMANCE
2003 2002
------------------------------------------------------
($ millions, except
per Trust Unit
amounts) Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4
-------------------------------------------------------------------------
Net Revenues 94.0 85.6 77.273.1 69.4 62.3 63.8 68.8
Net Income 22.1 61.7 7.3 (0.7) 6.0 (6.2) 8.2 (7.4)
Income Per Unit 0.52 1.35 0.16 (0.10) 0.20 (0.05) 0.24 (0.20)
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The above table highlights PrimeWest's quarterly performance for the years ended
2003 and 2002.
Net revenues were primarily impacted by higher commodity prices and production
volumes in 2003. Net income was higher in 2003 as a result of foreign exchange
gains along with increased tax recoveries.
FOURTH QUARTER AND YEAR END 2003 CONFERENCE CALL AND WEBCAST
PrimeWest will be conducting a conference call and Web cast for interested
analysts, brokers, investors and media representatives about its fourth quarter
and year end 2003 results at 9:00 a.m. Mountain time (11:00 a.m. Eastern time)
on February 20th, 2004.
Callers may dial 800-814-3911 a few minutes prior to start and request the
PrimeWest conference call. The call also will be available for replay by dialing
1-877-289-8525, and entering pass code 21028779 followed by the pound key.
Webcast listeners are invited to go to
http://www.newswire.ca/en/webcast/viewEvent.cgi?eventID(equal sign)701580 for
the live Web cast and/or replay or access the Web cast at the PrimeWest website,
http://www.primewestenergy.com/.
QUESTIONS
PrimeWest Energy Trust welcomes questions from unitholders and potential
investors; call Investor Relations at 403-234-6600 or toll-free in Canada and
the U.S. at 1-877-968-7878; or visit us on the Internet at our website,
http://www.primewestenergy.com/. We make every effort to reply within 2 business
days, but during periods of heavy call volume, our response time may increase.
On behalf of the Board of Directors:
February 19, 2004
Don Garner
President and Chief Executive Officer
CONSOLIDATED BALANCE SHEETS
As at December 31
(millions of dollars) 2003 2002 2001
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ASSETS
Current assets
Cash and short term deposits $ 2.5 $ - $ -
Accounts receivable 65.4 71.6 60.6
Prepaid expenses 6.5 9.8 9.1
Inventory 2.1 2.2 3.2
-------------------------------------------------------------------------
76.5 83.6 72.9
Cash reserved for site restoration
and reclamation (note 7) 8.2 - 0.7
Other assets (note 5) 0.2 14.4 -
Deferred charges 1.3 - -
Property, plant and equipment
(note 4) 1,537.6 1,404.5 1,448.7
Goodwill (note 3) 56.1 - -
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$ 1,679.9 $ 1,502.5 $ 1,522.3
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LIABILITIES AND UNITHOLDERS' EQUITY
Current liabilities
Bank overdraft $ - $ 3.1 $ 14.6
Accounts payable 26.7 43.1 26.2
Accrued liabilities 45.3 24.2 39.4
Accrued distributions
to unitholders 10.3 13.9 12.0
Due to related company (note 11) - - 10.1
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82.3 84.3 102.3
Long-term debt (note 6) 250.1 225.0 195.0
Future income taxes (note 12) 310.1 339.9 362.6
Site restoration and
reclamation provision 17.8 6.2 6.1
-------------------------------------------------------------------------
660.3 655.4 666.0
UNITHOLDERS' EQUITY
Net capital contributions
(note 8) 1,565.9 1,300.0 1,152.6
Capital issued but not
distributed 5.2 0.9 1.0
Long-term incentive plan
equity (note 9) 14.6 10.0 7.9
Accumulated income 213.5 123.2 122.6
Accumulated cash distributions (771.5) (578.9) (421.0)
Accumulated dividends (8.1) (8.1) (6.8)
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1,019.6 847.1 856.3
-------------------------------------------------------------------------
$ 1,679.9 $ 1,502.5 $ 1,522.3
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Commitments and Contingencies (Note 14)
The accompanying notes form an integral part of these financial
statements.
CONSOLIDATED STATEMENTS OF UNITHOLDERS' EQUITY
For the years ended December 31
(millions of dollars) 2003 2002 2001
-------------------------------------------------------------------------
Unitholders' equity,
beginning of year $ 847.1 $ 856.3 $ 298.6
Net income for the year 90.3 0.6 79.5
Net capital contributions 265.9 147.4 717.2
Capital issued but not
distributed 4.3 (0.1) 0.4
Long-term incentive plan equity 4.6 2.1 (1.0)
Cash distributions (192.6) (158.0) (234.4)
Dividends - (1.2) (4.0)
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Unitholders' equity, end of year $ 1,019.6 $ 847.1 $ 856.3
-------------------------------------------------------------------------
-------------------------------------------------------------------------
CONSOLIDATED STATEMENTS OF CASH FLOW
For the years ended December 31
(millions of dollars) 2003 2002 2001
-------------------------------------------------------------------------
OPERATING ACTIVITIES
Net income for the year $ 90.3 $ 0.6 $ 79.5
Add/(deduct):
Items not involving cash
from operations
Depletion, depreciation
and amortization 207.3 182.0 159.3
Non-cash general &
administrative 14.4 6.1 4.2
Non-cash foreign exchange
gain (12.1) - -
Non-cash management fees - 1.4 1.8
Non-cash internalization - 13.1 -
Future income taxes recovery (83.0) (32.3) (30.3)
Other non-cash items (0.3) - -
-------------------------------------------------------------------------
Cash flow from operations 216.6 170.9 214.5
Expenditures on site
restoration and reclamation (2.2) (3.9) (3.7)
Change in non-cash working
capital 5.3 (10.7) (20.5)
-------------------------------------------------------------------------
$ 219.7 $ 156.3 $ 190.3
-------------------------------------------------------------------------
FINANCING ACTIVITIES
Proceeds from issue of Trust
Units (net of costs) $ 240.3 $ 118.3 $ 159.5
Net cash distributions to
unitholders (note 10) (172.5) (145.1) (222.7)
Dividends - (1.2) (0.6)
Increase (decrease) in bank
credit facilities (137.0) 29.9 (62.9)
Increase in senior
secured notes 174.0 - -
Increase in deferred charges (1.5) - -
Change in non-cash working
capital (3.6) 1.0 1.0
-------------------------------------------------------------------------
$ 99.7 $ 2.9 $ (125.7)
-------------------------------------------------------------------------
INVESTING ACTIVITIES
Expenditures on property,
plant & equipment $ (105.8) $ (69.1) $ (84.2)
Acquisition of capital /
corporate assets (210.1) (59.6) (84.1)
Proceeds on disposal of
property, plant & equipment 2.3 4.5 78.1
(Increase) decrease in cash
reserved for future site
restoration and reclamation (6.6) 0.7 (0.3)
Expenditures on future
acquisitions - (14.1) -
Change in non-cash working
capital 6.4 (10.1) 12.1
-------------------------------------------------------------------------
$ (313.8) $ (147.7) $ (78.4)
-------------------------------------------------------------------------
INCREASE (DECREASE) IN CASH
FOR THE YEAR $ 5.6 $ 11.5 $ (13.8)
BANK OVERDRAFT
BEGINNING OF THE YEAR (3.1) (14.6) (0.8)
-------------------------------------------------------------------------
CASH (BANK OVERDRAFT)
END OF THE YEAR $ 2.5 $ (3.1) $ (14.6)
-------------------------------------------------------------------------
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CASH INTEREST PAID $ 13.1 $ 10.3 $ 13.2
-------------------------------------------------------------------------
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CASH TAXES PAID $ 3.9 $ 4.0 $ 0.5
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CONSOLIDATED STATEMENTS OF INCOME
For the years ended December 31
(millions of dollars,
except for per Trust Unit amounts) 2003 2002 2001
-------------------------------------------------------------------------
-------------------------------------------------------------------------
REVENUES
Sales of crude oil, natural
gas and natural gas liquids $ 434.6 $ 320.5 $ 378.2
Crown and other royalties,
net of ARTC (101.9) (56.5) (73.2)
Other income (2.8) 0.3 1.5
-------------------------------------------------------------------------
329.9 264.3 306.5
-------------------------------------------------------------------------
EXPENSES
Operating 79.4 60.8 59.0
Cash general and
administrative 14.5 11.3 10.4
Non-cash general and
administrative 14.4 6.1 4.2
Interest 15.1 10.8 13.8
Cash management fees (note 11) - 4.0 6.4
Cash internalization costs - 3.6 -
Non-cash management fees
(note 11) - 1.4 1.8
Non-cash internalization costs
(note 11) - 13.1 -
Foreign exchange (gain)/loss (11.9) - -
Depletion, depreciation
and amortization 207.3 182.0 159.3
-------------------------------------------------------------------------
318.8 293.1 254.9
-------------------------------------------------------------------------
Income (loss) before taxes
for the year 11.1 (28.8) 51.6
-------------------------------------------------------------------------
Income and capital taxes 3.8 2.9 2.4
Future income taxes recovery
(note 12) (83.0) (32.3) (30.3)
-------------------------------------------------------------------------
(79.2) (29.4) (27.9)
-------------------------------------------------------------------------
Net income for the year $ 90.3 $ 0.6 $ 79.5
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net income per Trust Unit $ 1.96 $ 0.02 $ 3.12
Diluted net income
per Trust Unit $ 1.95 $ 0.02 $ 3.08
-------------------------------------------------------------------------
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(all amounts areexpressed in millions of Canadian dollars unless
otherwise indicated)
1. Structure Of The Trust
--------------------------
PrimeWest Energy Trust (the Trust) is an open-ended investment trust
formed under the laws of Alberta in accordancewith a declaration of
trust dated August 2, 1996, as Amended. The beneficiaries of the Trust
are the holders of Trust Units (the unitholders).
The principal undertaking of the Trust's operating companies,
PrimeWest Energy Inc. and PrimeWest Gas Corp. (collectively referred to
as PrimeWest), is to acquire and hold, directly and indirectly, interests
in oil and gas properties. One of the Trust's primary assets is a royalty
entitling it to receive 99% of the net cash flow generated by theoil and
gas interests owned by PrimeWest. The royalty acquired by the Trust
effectively transfers substantially all of the economic interest in the
properties to the Trust.
The common shares of PrimeWest Energy Inc. are 100% owned by the Trust.
PrimeWest Gas Corp. is a wholly owned subsidiary of PrimeWest Energy Inc.
On November 4, 2002, unitholders voted, by a 92% majority, to internalize
management. PrimeWest Management Inc. and its shareholders received a
total of $26.3 million in connection with that transaction. Approximately
$13.2 million related to the acquisition of the 1% retained royalty and
was recorded as an acquisition in property, plant and equipment. The
balance was charged to non-cash internalization expense.In addition,
retention provisions for senior management totaling $3.5 million were
agreed to and $1.5 million was accrued relating to the termination of the
management incentive program (see Note 11).
2. Accounting Policies
-----------------------
Consolidation
These consolidated financial statements include the accounts of the Trust
and its wholly-owned subsidiaries, PrimeWest Energy Inc and PrimeWest Gas
Corp. The Trust, through the royalty, obtains substantially all of the
economic benefits of the operations of PrimeWest.
Cash And Short Term Investments
Short term investments, with maturities less than three months at the
date of acquisition, are considered to be cash equivalents and are
recorded at cost, which approximates market value.
Inventory
Inventory is measured at lower of cost and net realizable value.
Goodwill
Goodwill represents the excess of purchase price over fair value of net
assets acquired and liabilities assumed. Goodwill is assessed for
impairment at least annually. To assess impairment, the fair value of
each reporting unit is determined and compared to the book value of the
reporting unit. The amount of the impairment is determined by deducting
the fair value of the reporting unit's assets and liabilities from the
fair value of the reporting unit to determine the implied fair value of
goodwill and comparing that amount to the book value of the reporting
unit's goodwill. Any excess of the book value of goodwill over the
implied fair value of goodwill is the impairment amount.
Property, Plant And Equipment
PrimeWest follows the full cost method of accounting. All costs of
acquiring oil and gas properties and related development costs are
capitalized and accumulated in one cost centre. Maintenance and repairs
are charged against earnings. Renewals and enhancements that extend the
economic life of the capital asset are capitalized.
Gains and losses are not recognized on disposition of oil and gas
properties unless that disposition would alter the rate of depletion by
20% or more.
i) Ceiling test
---------------
PrimeWest places a limit on the aggregate cost of capital assets which
may be carried forward for depletion against netrevenues of future
periods (the ceiling test). The ceiling test is a cost recovery test
whereby; capitalized costs, less accumulated depletion and site
restoration, the lower of cost and market value of unproved land and
future income taxes, are limited to an amount equal to estimated
undiscounted future net revenues from Proved reserves, less general and
administrative expenses, site restoration, future financing costs and
applicable income taxes. Costs and prices at the balance sheet date are
used. Any costs carried on the balance sheet in excess of the ceiling
test limitation are charged to income.
ii) Site restoration and reclamation provision
----------------------------------------------
PrimeWest provides for the cost of future site restoration and
reclamation, based on estimates by management, using the
unit-of-production method. Actual site restoration costs are charged
against the accumulated liability. PrimeWest places cash in reserve to
fund actual expenditures as they are incurred.
iii) Depletion, depreciation and amortization
---------------------------------------------
Provision for depletion and depreciation is calculated on the
unit-of-production method, based on Proved reserves beforeroyalties.
Reserves are estimated by independent petroleum engineers. Reserves are
converted to equivalent units on the basis of approximate relative energy
content. Depreciation and amortization of head office furniture and
equipment is provided for at rates ranging from 10% to 30%.
Joint Venture Accounting
PrimeWest conducts substantially all of its oil and gas production
activities through joint ventures, and the accounts reflect only
PrimeWest's proportionate interest in such activities.
Long-Term Incentive Plan
Liabilities under the Trust's Long-term Incentive Plan are estimated at
each balance sheet date, based on the amount of Unit Appreciation Rights
that are in the money using the unit price as at that date. Expenses are
recorded through non-cash general and administrative costs, with an
offsetting amount in long-term incentive plan equity. As Trust Units are
issued under the plan, the exercise value is recorded in net capital
contributions.
Income Taxes
The Trust is considered an inter-vivos trust for income tax purposes. As
such, the Trust is subject to tax on any taxable income that is not
allocated to the unitholders. Periodically, current taxes may be payable
by PrimeWest, depending upon the timing of income tax deductions. Should
these taxes prove to be unrecoverable, they will be deducted from royalty
income in accordance with the royalty agreement.
Future income taxes are recorded for PrimeWest using the liability method
of accounting. Future income taxes are recorded to the extent that the
carrying value of PrimeWest's capital assets exceeds the available tax
pools.
Financial Instruments
PrimeWest uses financial instruments to manage its exposure to
fluctuations in commodity prices and interest rates. PrimeWest does not
use financial instruments for speculative trading purposes and,
accordingly, they are accounted for as hedges. Gains and losses on
hedging activity are reflected in revenue, or in the case of interest
rate hedges, in interest expense, at the time of sale of the related
hedged production, or when the monthly exchange contracts expire.
Measurement Uncertainty
Certain items recognized in the financial statements are subject to
measurement uncertainty. The recognized amounts of such items are based
on PrimeWest's best information and judgment. Such amounts are not
expected to change materially in the near term. They include the amounts
recorded for depletion, depreciation and future site restoration costs
which depend on estimates of oil and gas reserves or the economic lives
and future cash flows from related assets.
3. Corporate Acquisitions
--------------------------
a) On January 23, 2003, PrimeWestGas Inc. completed the acquisition of
two private Canadian oil and gas companies. Subsequent to the
transaction, PrimeWest Gas Inc. was wound up into PrimeWest Energy Inc.
The acquired companies were amalgamated with PrimeWest Gas Corp. The
acquisition was accounted for using the purchase method of accounting
with net assets acquired and consideration paid as follows:
Net Assets Acquired at Consideration
Assigned Values Paid
-------------------------------------------------------------------------
Petroleum and natural
gas assets $ 220.9
Goodwill 56.1
Working capital, including
cash of $3.9 0.7
Site restoration provision (5.4) Cash $ 212.7
Future income taxes (53.2) Costs associated
with acquisition 6.4
-------------------------------------------------------------------------
$ 219.1 $ 219.1
-------------------------------------------------------------------------
-------------------------------------------------------------------------
b) On March 29, 2001, PrimeWest Oil & Gas Corp. (Oil & Gas) completed the
acquisition of all of the issued and outstanding shares of Cypress Energy
Inc. (Cypress) pursuant to a takeover bid. In aggregate, PrimeWest issued
50.2 million Trust Units and PrimeWest issued 5.2 million exchangeable
shares of Oil & Gas and paid $59.2 million in exchange for the shares of
Cypress. Subsequent to the transaction, Cypress and Oil & Gas were
amalgamated. On January 1, 2002, PrimeWest Oil and Gas Corp. and
PrimeWest Energy Inc. were amalgamated. The acquisition was accounted for
using the purchase method of accounting with net assets acquired and
consideration paid as follows:
Net Assets Acquired at Consideration
Assigned Values Paid
-------------------------------------------------------------------------
Petroleum and natural gas
assets $ 1,201.5
Working capital deficit
assumed (19.2) Cash $ 59.2
Long-term debt assumed (179.0) Trust Units issued 489.8
Site restoration provision (4.3) Exchangeable
shares issued 50.3
Futureincome taxes (376.3) Costs associated
with acquisition 23.4
-------------------------------------------------------------------------
$ 622.7 $ 622.7
-------------------------------------------------------------------------
-------------------------------------------------------------------------
4. Property, Plant and Equipment
---------------------------------
2003
-----------------------------------------
Accumulated depletion
depreciation and Net book
Cost amortization value
-----------------------------------------
Property acquisition oil and
gas rights $ 1,917.4 $ (607.0) $ 1,310.4
Drilling and completion 208.0 (52.1) 155.9
Production facilities
and equipment 91.0 (23.1) 67.9
Head office furniture
and equipment 8.0 (4.6) 3.4
-------------------------------------------------------------------------
$ 2,224.4 $ (686.8) $ 1,537.6
-------------------------------------------------------------------------
-------------------------------------------------------------------------
2002
-----------------------------------------
Accumulated depletion
depreciation and Net book
Cost amortization value
-----------------------------------------
Property acquisition oil and
gas rights $ 1,682.6 $ (430.6) $ 1,252.0
Drilling and completion 139.9 (34.7) 105.2
Production facilities
and equipment 60.5 (15.4) 45.1
Head office furniture
and equipment 5.2 (3.0) 2.2
-------------------------------------------------------------------------
$ 1,888.2 $ (483.7) $ 1,404.5
-------------------------------------------------------------------------
-------------------------------------------------------------------------
2001
-----------------------------------------
Accumulated depletion
depreciation and Net book
Cost amortization value
-----------------------------------------
Property acquisition oil and
gas rights $ 1,608.4 $ (268.1) $ 1,340.3
Drilling and completion 103.6 (24.1) 79.5
Production facilities
and equipment 38.2 (11.5) 26.7
Head office furniture
and equipment 4.2 (2.0) 2.2
-------------------------------------------------------------------------
$ 1,754.4 $ (305.7) $ 1,448.7
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Unproved land costs of $ 36.0 million (2002 - $44.2 million,
2001 - $55.7 million) are excluded from costs subject to depletion and
depreciation.
PrimeWest capitalized $2.5 million of general and administrative costs in
2003 ($2.5 million in 2002; $2.2 million in 2001).
In accordance with stated accounting policies, PrimeWest has performed a
ceiling test using commodity prices as at the measurement date of
December 31, 2003. Using December 31, 2003 commodity prices of
AECO $6.09 per mcf for natural gas and WTI $US 32.52 per barrel for crude
oil, results in a ceiling test surplus.
A ceiling test surplus existed as at December 31, 2002.
At December 31, 2001, PrimeWest performed its ceiling test using
commodity prices as at that measurement date of AECO $3.67 per mcf for
natural gas, and WTI $U.S. 19.84 per barrel for crude oil. The ceiling
test resulted in a deficiency of $150 million. PrimeWest did not record a
write-down at that time as the write-down occurred within the first two
years of the acquisition of Cypress Energy Inc.
5. Other Assets
----------------
2003 2002 2001
-----------------------------------------
Deposit on acquisition $ - $ 10.9 $ -
Expenditures incurred
on acquisition - 3.3 -
Other assets 0.2 0.2 -
-------------------------------------------------------------------------
$ 0.2 $ 14.4 $ -
-------------------------------------------------------------------------
-------------------------------------------------------------------------
6. Long-Term Debt
------------------
2003 2002 2001
-----------------------------------------
Revolving credit facility $ 88.0 $ 225.0 $ 195.0
Senior secured notes 162.1 - -
-------------------------------------------------------------------------
250.1 225.0 195.0
-------------------------------------------------------------------------
-------------------------------------------------------------------------
PrimeWest and the Trust (as co-borrowers) have combined revolving
credit facilities in the amount of $213 million (2002 - $335 million;
2001 - $350 million), with a borrowing base at December 31, 2003 of
$390 million (2002 - $335 million; 2001 - $350 million). The facilities
consists of a revolving term loan of $188 million and an operating
facility of $25 million. In addition to amounts outstanding under the
facilities as indicated in the table above, PrimeWest has outstanding
letters of credit in theamount of $5.1 million (2002 - $3.8 million;
2001 - $2.8 million).
Advances under the facility are made in the form of Banker's Acceptances
(BA), prime rate loans or letters of credit. In the case of BA, interest
is a function of the BA rate plus a stamping fee based on the Trust's
current ratio of debt to cash flow. In the case of prime rate loans,
interest is charged at the bank's prime rate. While any amounts are
outstanding under the bridge facility, the interest rates and stamping
fees increase by 50 basis points. For 2003, the effective interest rate
was 4.7% (2002 - 4.6%, 2001 - 5.6%).
The credit facility revolves until June 30, 2004, by which time the
lenders will have conducted their annual borrowing base review. The
lender also has the right to re-determine the borrowing base at one other
time during the year. During the revolving phase, the facility has no
specific terms of repayment. At the end of the revolving period, the
lender has the right to extendthe revolving period for a further 364-day
period or to convert the facility to a term facility. If the lender
converts to a non-revolving facility, 60% of the aggregate principal
amount of the loan shall be repayable on the date which is 366 days after
such conversion date and the remaining 40% of the aggregate principal
amount outstanding shall be repayable on the date which is 365 days after
the initial term repayment date.
On May 7, 2003, PrimeWest replaced a portion of its bank debt with Senior
Secured Notes (the "Notes") in the amount of $U.S. 125 million. They have
a final maturity of May 7, 2010, and bear interest at 4.19% per annum,
with interest paid semi-annually on November 7 and May 7 of each year.
The Note Purchase Agreement requires PrimeWest to make four annual
principal repayments of $U.S. 31,250,000 commencing May 7, 2007.
Collateral for the secured note and credit facility is a floating charge
debenture covering all existing and after acquired property in the
principal amount of $U.S. 1 billion. The secured parties for the
revolving credit facility and senior secured notes have agreed to share
the security interests on a pari passu basis.
The costs incurred in connection with the Notes, in the amount of
$1.5 million, are classified as deferred charges on the balance sheet and
are being amortized over the term of the Notes.
The Senior Secured Notes are the legal obligation of PrimeWest Energy
Inc. and are guaranteed by PrimeWest Energy Trust.
7. Cash Reserve For Site Restoration And Reclamation
-----------------------------------------------------
Commencing in 1998, funding for the reserve was provided for by reducing
distributions otherwise payable based on an amount per BOE produced
($0.15 per BOE produced for 1998 and 1999, $0.24 per BOE produced in
2000, $0.32 per BOE produced in 2001, $0.37 per BOE produced in 2002 and
$0.50 per BOE produced in 2003). The cash amount contributed, including
interestearned, was $6.2 million in 2003 (2002 - $4.1 million;
2001 - $4.2 million). During 2003, an additional contribution of
$4.2 million was made to fund reclamation expenditures associated with
properties acquired in 2002. Actual costs of site restoration and
abandonment totaling $2.2 million were paid out of this cash reserve for
the year ended December 31, 2003 (2002 - $3.9 million;
2001 - $3.8 million).
8. Unitholders' Equity
-----------------------
PrimeWest Energy Trust
Theauthorized capital of the Trust consists of an unlimited number of
Trust Units.
Trust Units Number of Units Amounts ($)
-------------------------------------------------------------------------
Balance, December 31, 2000 50,982,093 $ 428.0
Issued for cash 19,790,000 165.2
Issue expenses - (9.0)
Issued to acquire Cypress Energy Inc. 50,234,771 489.8
Issued for payment of management fees 199,841 1.7
Issued on exchange of exchangeable shares 2,415,363 20.3
Issued pursuant to Distribution
Reinvestment Plan 1,623,171 10.8
Issued pursuant to Long-Term Incentive Plan 577,840 5.2
Issued pursuant to Optional Trust Unit
Purchase Plan 142,528 3.3
-------------------------------------------------------------------------
Balance, December 31, 2001 125,965,607 $ 1,115.3
Restated giving effect for 4 to 1 Trust Unit
consolidation on August 16, 2002 31,491,402 $ -
Issued for cash 4,200,000 $ 110.0
Issue expenses - (5.6)
Issued for payment of management fees 66,853 1.8
Issued on exchange of exchangeable shares 106,934 2.7
Issued pursuant to Distribution
Reinvestment Plan 476,106 10.1
Issued pursuant to Long-Term Incentive Plan 153,749 4.0
Issue of units due to odd lot program 111 -
Issue of fractional units due to
4 to 1 consolidation 6,264 -
Issued pursuant to Optional Trust Unit
Purchase Plan 503,103 13.9
-------------------------------------------------------------------------
Balance, December 31, 2002 37,004,522 $ 1,252.2
Issued for cash 9,100,000 $ 234.8
Issue expenses - (12.1)
Issued on exchange of exchangeable shares 964,897 21.2
Issued pursuant to Distribution
Reinvestment Plan 600,598 14.8
Issued pursuant to Long-Term Incentive Plan 360,608 9.4
Issue of units due to odd lot program 38 -
Issue of fractional units due to
4 to 1 consolidation 11 -
Issued pursuant to Optional Trust Unit
Purchase Plan 721,209 17.6
-------------------------------------------------------------------------
Balance, December 31, 2003 48,751,883 $ 1,537.9
-------------------------------------------------------------------------
-------------------------------------------------------------------------
The number of units was restated giving effect of four for one Trust Unit
consolidation effective August 16, 2002.
The weighted average number of Trust Units and exchangeable shares
outstanding in 2003 was 46,015,519 (2002 - 34,135,576;
2001 - 25,633,271). For purposes of calculating diluted net income per
Trust Unit, 345,278 Trust Units (2002 - 341,315; 2001 - 311,789) issuable
pursuant to the long-term incentive plan were added to the weighted
average number. The per unit cash distribution amounts paid or declared
reflects distributions paid or declaredto Trust Units outstanding on the
record dates.
PrimeWest Exchangeable Class A Shares
In connection with the Cypress transaction (see Note 3b),
PrimeWest Oil & Gas Corp. (now amalgamated with PrimeWest Energy Inc.)
amended its articles to create an unlimited number of exchangeable
shares. The exchangeable shares are exchangeable into PrimeWest Trust
Units at any time up to March 29, 2010, based on an exchange ratio that
adjusts each time the Trust makes distribution to its unitholders. The
exchange ratio, which was 1:1 on the date that the transaction closed, is
based on the total monthly distribution, divided by the closing unit
price on the distribution payment date. The exchange ratio on
December 31, 2003 was 0.44302:1 (2002 - 0.37454:1; 2001 - 0.3126:1,
restated effecting 4 to 1 Trust Unit consolidation).
Exchangeable Shares No. of shares Amounts ($)
-------------------------------------------------------------------------
Balance,December 31, 2001 3,316,742 $ 32.3
Issued for internalization 1,363,714 13.1
Conversion of Class B shares 710,795 4.3
Exchanged for Trust Units (211,973) (2.0)
-------------------------------------------------------------------------
Balance, December 31, 2002 5,179,278 47.7
Issued for management incentive program 161,717 1.5
Exchanged for Trust Units (2,299,872) $ (21.2)
-------------------------------------------------------------------------
Balance, December 31, 2003 3,041,123 $ 28.0
-------------------------------------------------------------------------
-------------------------------------------------------------------------
PrimeWest Exchangeable Class B Shares
In connection with a transaction in 2000, PrimeWest Resources Ltd. (now
amalgamated with PrimeWest Energy Inc.) amended its articles to create an
unlimited number of exchangeable shares. At special meetings held in May
and June of 2002, holders of Class B Exchangeable Shares and Class A
Exchangeable shares voted to approve a special resolution amending the
articles of the Corporation to convert all Class B Exchangeable shares to
Class A Exchangeable Shares. As at June 14, 2002, 649,561 Class B
Exchangeable shares were converted to Class A Exchangeable Sharesusing
an exchange ratio of 1.09427:1.
Exchangeable Shares No. of shares Amounts ($)
-------------------------------------------------------------------------
Balance, December 31, 2001 751,532 $ 5.0
Exchanged for Trust Units (101,971) (0.7)
Converted to Class A Exchangeable Shares (649,561) (4.3)
-------------------------------------------------------------------------
Balance, December 31, 2002 - $ -
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Trust Units and Exchangeable Shares Issued & Outstanding(1)
2003 2002 2001
-----------------------------------------
Trust Units issued & outstanding 48,751,883 37,004,522 31,491,402
Exchangeable shares
Class A Shares
(2003 - 3,041,123 shares
exchangeable at 0.44302;
2002 - 5,179,278 shares
exchangeable at 0.37454;
2001 - 3,316,742 shares
exchangeable at 0.3126) 1,347,277 1,939,864 1,036,648
Class B Shares
(2001 - 751,532 shares
exchangeable at 0.34201) - - 257,035
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Total units and exchangeable
shares issued & outstanding 50,099,160 38,944,386 32,785,085
Unit Appreciation Rights 345,278 341,315 311,788
-------------------------------------------------------------------------
Total units and exchangeable
shares issued & outstanding -
diluted 50,444,438 39,285,701 33,096,873
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Restated Trust Units to give effect to 4 for 1 unit consolidation
effective August 16, 2002.
9. Trust Unit Incentive Plan
-----------------------------
Under the terms of the Trust Unit Incentive Plan, a maximum of 1,800,000
Trust Units are reserved for issuance pursuant to the exercise of Unit
Appreciation Rights (UARs) granted to employees of PrimeWest. Payouts
under the plan are based on total unitholder return, calculated using
both the change in the Trust Unit price as well as cumulative
distributions paid. The plan requires that a hurdle return of 5% per
annum be achieved before payouts accrue. UARs have a term of up to six
years and vest equally over a three-year period, except for the members
of the Board, whose UARs vest immediately. The Board of Directors has the
option of settling payouts under the plan in PrimeWest Trust Units or in
cash. To date, all payouts under the plan have been in the form of Trust
Units.
As at December 31, 2003
-------------------------------------------------------------------------
Current return Trust
Year UARs issued per "in the Total Unit
of Grant & outstanding UARs vested money" UARs equity dilution
-------------------------------------------------------------------------
1998 10,391 10,391 $ 49.98 $ 0.5 18,844
1999 55,160 55,160 34.92 1.9 69,892
2000 120,137 119,387 16.40 2.0 71,007
2001 383,424 265,645 7.81 3.0 74,891
2002 961,405 447,562 6.09 4.7 86,694
2003 1,085,031 141,896 4.75 2.5 23,950
-------------------------------------------------------------------------
Total 2,615,548 1,040,041 $ 14.6 345,278
-------------------------------------------------------------------------
-------------------------------------------------------------------------
As at December 31, 2002
-------------------------------------------------------------------------
Current return Trust
Year UARs issued per "in the Total Unit
of Grant & outstanding UARs vested money" UARs equity dilution
-------------------------------------------------------------------------
1997 52,927 52,927 $ 22.98 $ 1.2 47,883
1998 105,798 105,798 33.99 3.6 141,563
1999 115,215 114,667 22.38 2.6 101,076
2000 187,984 125,661 8.22 1.5 37,831
2001 515,634 185,780 2.12 0.6 12,861
2002 1,120,142 82,097 1.97 0.5 101
-------------------------------------------------------------------------
Total 2,097,700 666,930 $ 10.0 341,315
-------------------------------------------------------------------------
-------------------------------------------------------------------------
As at December 31, 2001
-------------------------------------------------------------------------
Current return Trust
Year UARs issued per "in the Total Unit
of Grant & outstanding UARs vested money" UARs equity dilution
-------------------------------------------------------------------------
1996 131,719 131,719 $ 15.84 $ 2.1 82,010
1997 79,839 79,839 13.76 1.1 43,165
1998 127,956 127,957 24.80 3.2 124,654
1999 148,416 89,566 14.76 1.3 52,025
2000 240,914 86,951 2.92 0.2 9,935
2001 629,343 25,211 - - -
-------------------------------------------------------------------------
Total 1,358,187 541,243 $ 7.9 311,789
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Cumulative to December 31, 2003, 1,030,850 UARs have been exercised
(Cumulative to December 31, 2002 - 640,503; Cumulative to December 31,
2001 - 399,199), resulting in the issuance of 719,374 Trust Units from
treasury (Cumulative to December 31, 2002 - 358,766; Cumulative to
December 31, 2001 - 205,017).
10. Cash Distributions
----------------------
2003 2002 2001
-------------------------------------------------------------------------
Netincome for the year $ 90.3 $ 0.6 $ 79.5
Add back (deduct) amounts to
reconcile to distribution:
Depletion, depreciation and
amortization 207.3 182.0 159.3
Cash (retained) / paid from
cash available for distribution (15.6) (7.3) 25.8
Contribution to reclamation fund (8.7) (4.1) (3.5)
Non-cash general and
administrative 14.4 6.14.2
Non-cash foreign exchange (12.1) - -
Internalization costs paid
in trust units - 13.1 -
Management fees paid in
Trust Units - 1.4 1.8
Future income taxes recovery (83.0) (32.3) (30.3)
-------------------------------------------------------------------------
$ 192.6 $ 159.5 $ 236.8
Cash Distributions to Trust
Unitholders $ 192.6 $ 158.0 $ 234.5
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Cash Distributions per
Trust Unit $ 4.40 $ 4.80 $ 9.24
-------------------------------------------------------------------------
-------------------------------------------------------------------------
11. Related - Party Transactions
--------------------------------
On September 26, 2002, the Trust announced the planned elimination,
effective October 1, 2002, of its external management structure and all
related management, acquisition and disposition fees, as well as the
acquisition of the right to mandatory quarterly dividends commonly
referred to as the "1% retained royalty". The transaction was approved by
the Unitholders and the holders of Exchangeable Shares on November 4,
2002 and closed November 6, 2002. The transaction resulted in the
elimination of the 2.5% management fee on net production revenue,
quarterly incentive payments payable in the form of Trust Units, the 1.5%
acquisition fee and the 1.25% disposition fee, which resulted in payments
to PrimeWest Management Inc. in 2002 totaling $5.8 million
(2001 - $21.3 million). In addition, the amount of the 1% retained
royalty paid in 2002 was $1.3 million (2001 - $3.4 million).
As at December 31, 2002, the Trust and PrimeWest owed $nil
(2001 - $10.1 million) to PrimeWest Management Inc. for unpaid management
and other fees and reimbursement of general and administrative costs.
The internalization transaction was achieved through the purchase by
PrimeWest of all of the issued and outstanding shares of PrimeWest
Management Inc. for a total consideration of approximately $26.3 million
comprised of a cash payment of $13.2 million and the issuance of
Exchangeable Shares exchangeable, based on an agreed exchange ratio, for
approximately 491,000 Trust Units and valued at approximately
$13.1 million based on the closing price of the Trust Units on the TSX on
September 26, 2002. The $13.2 million that related to the acquisition of
the 1% retained royalty was capitalized; an additional $9.5 million was
capitalized with an offset to future tax liability as a result of the
property, plant and equipment having no tax basis. In addition, PrimeWest
agreed to issue Exchangeable Shares valued at $1.5 million to certain
senior managers to terminate a management incentive program of PrimeWest
Management Inc. and to create a special employee retention plan for
those senior managers which provides for long term incentive bonuses in
the form of Exchangeable Shares valued, in the aggregate, at
$3.5 million. Exchangeable Shares will be issued pursuant to the
retention plan on each of the second, third, fourth and fifth
anniversaries of the completion of the internalization transaction. As at
December 31, 2003, $0.5 million has been accrued in non-cash general and
administrative expenses related to the special employee retention plan.
12. Income Taxes
----------------
PrimeWest and its subsidiaries had no taxable income for 2003, 2002, and
2001, as tax-pool deductions and the royalty payable were sufficient to
reduce taxable income in these entities to nil.
The future tax provision results from temporary differences between the
financial statement carrying amounts of assets and liabilities and their
respective tax bases.
2003 2002 2001
-------------------------------------------------------------------------
Loss carry forwards $ - $ (5.0) $ (10.6)
Capital assets 318.9 350.0 378.0
Foreign exchange gain
on long term debt 2.1 - -
Site restoration provision (6.0) (1.9) (2.3)
Long-term incentive liability (4.9) (3.2) (2.5)
-------------------------------------------------------------------------
$ 310.1 $ 339.9 $ 362.6
-------------------------------------------------------------------------
-------------------------------------------------------------------------
The provisions for income taxes varies from the amounts that would be
computed by applying the combined Canadian federal and provincial income
tax rates for the following reasons:
2003 2002 2001
-------------------------------------------------------------------------
Net income (loss) before taxes $ 11.1 $ (28.8) $ 51.6
-------------------------------------------------------------------------
Computed income tax expense
(recovery) at the Canadian
statutory rate of 40.62%
(2002 - 42.12%; 2001 - 43.12%) 4.5 (12.1) 22.3
Increase (decrease) resulting from:
Non-deductible crown royalties
and other payments, net of ARTC 0.3 5.7 0.2
Federalresource allowance (16.2) (3.5) (9.7)
Change in income tax rate (43.1) (4.2) -
Amounts included in trust
income and other (28.5) (18.2) (43.1)
-------------------------------------------------------------------------
Future income taxes $ (83.0) $ (32.3) $ (30.3)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
13. Financial Instruments
-------------------------
a) Commodity Price Risk Management
PrimeWest generally sells its oil and gas under short-term market-based
contracts. Derivative financial instruments, options and swaps may be
used to hedge the impact of oil and gas price fluctuations.
A summary of these contracts in place at December 31, 2003 follows:
CRUDE OIL
Period Volume (bbls/d) Type WTI Price ($U.S./bbl)
-------------------------------------------------------------------------
Jan - Jan 2004 500 Swap $ 33.30
Jan - Mar 2004 1000 Swap 27.29
Jan - Mar 2004 500 Swap 28.87
Jan - Mar 2004 500 Swap 30.21
Jan - Mar 2004 500 Swap 31.60
Jan - Mar 2004 500 Costless Collar 22.00/26.70
Jan - Mar 2004 500 Costless Collar 23.00/33.30
Jan - Mar 2004 500 Costless Collar 24.00/31.20
Jan - Mar 2004 500 Costless Collar 25.00/28.16
Apr - Jun 2004 1000 Swap 27.13
Apr - Jun 2004 500 Swap 28.64
Apr - Jun 2004 500 Swap 30.06
Apr - Jun 2004 500 Costless Collar 22.00/26.12
Apr - Jun 2004 500 Costless Collar 24.00/30.50
Apr - Jun 2004 500 Costless Collar 25.00/28.07
Apr - Jun 2004 500 Costless Collar 26.00/32.07
Jul - Sep 2004 500 Swap 26.07
Jul - Sep 2004 500 Swap 27.04
Jul - Sep 2004 500 Swap 28.51
Jul - Sep 2004 500 Costless Collar 24.00/30.75
Jul - Sep 2004 500 Costless Collar 25.00/28.30
Jul - Sep 2004 500 Costless Collar 26.00/32.05
Oct - Dec 2004 500 Swap 26.00
Oct - Dec 2004 500 Swap 27.03
Oct - Dec 2004 500 Swap 28.53
Oct - Dec 2004 500 Costless Collar 24.00/30.00
Oct - Dec 2004 500 Costless Collar 25.00/28.30
Jan 2005 - Mar 2005 500 Swap 27.25
Apr 2005 - Jun 2005 500 Swap 27.07
Jul 2005 - Sep 2005 500 Swap 27.05
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NATURAL GAS
(AECO)
Period Volume (mmcf/day) Type AECO Price (Cdn$/mcf)
-------------------------------------------------------------------------
Jan 2004 - Mar 2004 4.7 Swap $ 6.19
Jan 2004 - Mar 2004 4.7 3 Way 4.22/5.28/8.23
Jan 2004 - Mar 2004 4.7 3 Way 4.48/5.54/6.52
Jan 2004 - Mar 2004 4.7 Costless Collar 6.33/7.91
Jan 2004 - Mar 2004 4.7 Costless Collar 6.33/11.87
Jan 2004 - Mar 2004 4.7 Costless Collar 5.80/8.23
Jan 2004 - Mar 2004 4.7 Costless Collar 5.80/8.33
Jan 2004 - Mar 2004 4.7 Costless Collar 6.33/8.58
Jan 2004 - Mar 2004 4.7 Costless Collar 4.75/7.91
Jan 2004 - Oct 2004 9.5 3 Way 3.17/4.22/6.09
Jan 2004 - Dec 2004 1.0 Swap 6.02
Apr 2004 - Oct 2004 4.7 Swap 5.45
Apr 2004 - Oct 2004 4.7 Swap 6.02
Apr 2004 - Oct 2004 4.7 Swap 6.06
Apr 2004 - Oct 2004 4.7 Costless Collar 5.01/6.06
Apr 2004 -Oct 2004 4.7 Costless Collar 5.28/7.39
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A 3-way option is like a traditional collar, except that PrimeWest has
resold the put at a lower price. Utilizing the first 3-way natural gas
contract above as an example, PrimeWest has sold a call at $8.23,
purchased a put at $5.28, and resold the put at $4.22. Should the market
price drop below $5.28 PrimeWest will receive $5.28 until the price is
less than $4.22, at which time PrimeWest would then receive market price
plus $1.06. However, should market prices rise above $8.23, PrimeWest
would receive a maximum of $8.23. Should the market price remain between
$5.28 and $8.23, PrimeWest would receive the market price.
NATURAL GAS (BASIS DIFFERENTIAL $US / MCF)
Period Volume (mmcf/day) Type Basis Price ($US/mcf)
-------------------------------------------------------------------------
Jan - Mar 2004 10.0 Basis Swap $ 0.63
Apr - Oct 2004 5.0 Basis Swap $ 0.71
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The AECO basis is the difference between the NYMEX gas price in $U.S. per
mcf and the AECO price in $U.S. per mcf. Using the first basis swap above
as an example, PrimeWest has fixed this price difference between the two
markets at $U.S. 0.63 per mcf from January 2004 through March 2004. If
the NYMEX price for the period turned out to be $U.S. 4.00 per mcf,
PrimeWest would receive an AECO equivalent price of $U.S. 3.37 per mcf.
In 2003, the financial impact of contracts settling in the year was a
decrease in sales revenues of $30.5 million (2002 - $28.1 million
increase in sales revenues; 2001 - $39.5 million increase in sales
revenues).
The mark-to-market value of the hedges in place as at December 31, 2003
is a $6.0 million loss of which $2.1 million is attributable to natural
gas and $3.9 million is attributable to crude oil.
Electrical Power
Period Power Amount (MW) Type Price ($/MW-hr)
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Q1 2004 5 Fixed Price Swap $ 58.50
Q2 2004 7.5 Fixed Price Swap 40.25
Q3 2004 5 Fixed Price Swap 46.50
Q4 2004 5 Fixed Price Swap 44.00
Calendar 2004 5 Fixed Price Swap 45.65
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The mark to market value of the hedges at December 31, 2003 is a
$0.6 million gain.
b) InterestRate Risk Management
PrimeWest has the following interest rate swaps outstanding at
December 31, 2003.
Interest Rate Risk Management
Notional
amount
Term ($ millions) Fixed BA rate (%)
-------------------------------------------------------------------------
May 24/98 - May 25/04 $25 6.48
Nov 26/01 - May 26/04 $25 3.85
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The mark to market value of the interest rate swaps is a $0.6 million
loss at December 31, 2003.
The effect of the interest rates swaps was to increase interest paid in
2003 by $0.9 million (2002 - $1.5 million; 2001 - $0.4 million).
c) Fair Value Of Financial Instruments
Financial instruments include cash, accounts receivable, accounts payable
and accrued liabilities, accrued distributions to unitholders, long-term
debt and financial hedges. As at December 31, 2003, 2002, and 2001, the
fair market value of the financial instruments, other than long-term debt
and financial hedges, approximate their carrying value, due to the
short term maturity of these instruments. The fair value of long-term
debt approximates its carrying value in all material respects, because
the cost of borrowing approximates the market rate for similar
borrowings.
14. Commitments And Contingencies
---------------------------------
a) PrimeWest has lease commitments relating to office buildings. The
estimated annual minimum operating lease rental payments for the
buildings, after deducting sublease income will be $1.2 million in 2004,
$1.1 million in 2005, $1.1 million in 2006 and $2.4 million in
2007 - 2009, the remaining term of the leases.
b) As part of PrimeWest's internalization transaction (see Note 11),
PrimeWest agreed to pay $3.5 million in exchangeable shares as a special
employee retention plan. One quarter of the exchangeable shares will be
issuable to the Senior Managers of PrimeWest on each of the second,
third, fourth and fifth anniversary of transaction closing, November 6,
2002. As at December 31, 2003 $0.5million has been accrued in non-cash
general and administrative expenses.
c) PrimeWest is engaged in a number of matters of litigation, none of
which could reasonably be expected to result in any material adverse
consequence.
d) PrimeWest has a pipeline transportation commitment that runs to
October 31, 2007 and has a minimum annual payment requirement of
$U.S. 2.1 million.
15. Subsequent Event
--------------------
On January 27th, 2004, PrimeWest announced that it had agreedto make an
offer to acquire all of the shares of Seventh Energy. Seventh Energy's
Board and executive unanimously approved the transaction and have agreed
to tender their approximately 24% ownership interest. The acquisition
cost is expected tobe $42.6 million comprised of the assumption of
$8.3 million of debt and working capital and a cash payment of $34.3
million. To protect the transaction economics, PrimeWest hedged
approximately 70% of Seventh Energy's gas production at a price of $6.18
per mcf for one year. PrimeWest's existing credit line will be used to
fund the cash portion of the acquisition. The offer is currently set to
expire on March 15, 2004.
16. Prior Years' Comparative Numbers
------------------------------------
Certain prior years' comparative numbers have been restated to conform
with the current year's presentation.
17. Differences Between Canadian And United States Generally Accepted
---------------------------------------------------------------------
Accounting Principles
---------------------
PrimeWest's financial statements are prepared in accordance with
accounting principles generally accepted (GAAP) in Canada which, in some
respects, differ from those generally accepted in the United States
(U.S.). Those policies that result in measurement differences will be
available under the "Investor Relations - Financial Information" section
of PrimeWest's website at a later date.
TRADING PERFORMANCE
For the
quarter ended Dec 31/03 Sep 30/03 Jun 30/03 Mar 31/03 Dec 31/02
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TSX Trust Unit
prices ($ per
Trust Unit)
High $ 28.15 $ 26.80 $ 27.75 $ 27.34 $ 27.68
Low $ 25.06 $ 25.19 $ 23.40 $ 24.48 $ 24.23
Close $ 27.56 $ 25.19 $ 25.04 $ 24.51 $ 25.40
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Average daily
traded volume 202,661 149,148 234,477 184,428 123,964
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For the
quarter ended Dec 31/03 Sep 30/03 Jun 30/03 Mar 31/03 Dec 31/02
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NYSE Trust Unit
prices ($U.S.
per Trust Unit)
High $ 21.48 $ 19.29 $ 20.60 $ 17.96 $ 16.69
Low $ 18.67 $ 18.08 $ 15.97 $ 16.05 $ 15.62
Close $ 21.27 $ 18.68 $ 18.53 $ 16.73 $ 16.16
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Average daily
traded volume 243,921 151,813 166,722 111,605 39,276
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Number of TrustUnits
outstanding including
exchangeable shares
(millions of units) 50.44 49.52 45.99 45.43 39.29
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Distribution paid
per Trust Unit $0.96 $1.04 $1.20 $1.20 $1.20
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TOTAL COMPOUND ANNUAL RETURN (%) (1)
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S&P TSX
Cdn Energy
S&P 500 S&P 500 Trust
PrimeWest OGPI TSX S&P $Cdn $US Index
-------------------------------------------------------------------------
Five Year 30.3% 20.8% 6.3% (4.0)% (0.9)%
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Three Year 12.7% 12.7% (1.4)% (8.8)% (4.5)%
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One Year 28.0% 20.1% 26.7% 5.9% 28.5% 46.4%
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(1) Total return is equal to unit price plus distributionsre-invested
END FIRST AND FINAL ADD
DATASOURCE: PrimeWest Energy Trust
CONTACT: PR NewsWire -- Feb. 20