EXHIBIT 7
---------
PRIMEWEST
GROWTH, RENEWAL, RESILIENCY
PRIMEWEST ENERGY TRUST 2001 REPORT TO OUR UNITHOLDERS
2
Operating and Financial
Highlights
4
Property Descriptions CORPORATE PROFILE
7 o NORTH AMERICA'S 4TH LARGEST
Message to Unitholders CONVENTIONAL OIL AND GAS ROYALTY TRUST
12 o 30,000 BOE PER DAY OIL EQUIVALENT
Questions & Answers PRODUCTION
20 o LOWEST OPERATING COSTS AMONG LARGE CAP
Management's Discussion PEER GROUP
and Analysis
o PRIMEWEST ENERGY TRUST TRADES ON THE
36 TORONTO STOCK EXCHANGE UNDER THE
Financial Statements and Notes SYMBOL PWI.UN
54 o PRIMEWEST ENERGY INC. EXCHANGEABLE
Supplemental Information SHARES TRADE ON THE TORONTO STOCK
EXCHANGE UNDER THE SYMBOL PWX
63
Corporate Governance
67
Environmental, Health
and Safety
68
Income Tax Considerations
69
Distribution Reinvestment
and Optional Trust Unit
Purchase Plans
70
Glossary
71
Corporate Information
GROWTH
WE'VE INCREASED PRODUCTION, RESERVES AND UNITHOLDER LIQUIDITY.
RENEWAL
WE'VE REPLENISHED OUR SUITE OF OPPORTUNITIES AND UPGRADED ASSET QUALITY.
RESILIENCY
WE'VE SIGNIFICANTLY MITIGATED THE IMPACT OF THE MOST RECENT
COMMODITY PRICE CYCLICAL DOWNTURN.
PRIMEWEST ENERGY TRUST
AT A GLANCE
- ----------------------------------------- ------------------------------------- -----------------------------------------
STRATEGY 2001 OBJECTIVES 2001 PERFORMANCE
- ----------------------------------------- ------------------------------------- -----------------------------------------
o Significantly increase the X Doubled production in 2001
ONE size of the Trust and with the acquisition of Cypress
ASSET GROWTH unitholder liquidity. Energy Inc. Unitholder liquidity
now best in sector.
o Acquisitions to improve X The percentage of proved
percentage of proved producing producing reserves up 2% to 72% at
reserves and increase investor year-end. Investor margin was
margin. $22.79 in 2001, compared to $21.27
in 2000.
o Review asset base to X PrimeWest undertook an asset
high-grade assets and identify rationalization program during the
potential disposition second half of 2001, netting
candidates. proceeds from high cost, non-core
assets of approximately $78 million.
- ----------------------------------------- ------------------------------------- -----------------------------------------
o Maintain a diversified X PrimeWest spent over $80
TWO approach to property million in 2001 on property
OPERATING EXCELLENCE development. Invest $37 million development activities.
in diversified projects.
o Capitalize on production X The drilling success rate was
optimization and development 91%. Proved producing reserves were
opportunities within asset base. added at an average cost of $7.89
per BOE.
o Reduce per BOE operating X Operating costs were $5.42 per BOE
costs. compared to $5.08 per BOE in 2000,
but best among our Peers.
- ----------------------------------------- ------------------------------------- -----------------------------------------
o Maintain appropriate and X The debt-to-annual cash flow
THREE prudent debt levels. ratio of 1.05 at the end of 2001
FINANCIAL PRUDENCE was the lowest among our Peers.
o Maintain a responsible X Distributions exceeded cash
distribution payout ratio. flow in 2001; a payout ratio of
112%. Having paid out only 71% of 2000 cash
flow, we were able to support the 2001
distribution level.
- ----------------------------------------- ------------------------------------- -----------------------------------------
o Use hedging instruments as X PrimeWest enhanced cash flow
FOUR appropriate to sustain by $39 million or $0.38 per Trust
RISK MANAGEMENT distribution rates. Unit in 2001 through hedging
activities.
o Maintain $0.22 per Trust
Unit total distribution payment X Maintained through August,
for as long as feasible. despite production disappointments
and falling oil and gas prices.
o Offer guidance to
investors about changes to the X The volatile commodity price
level of distribution rate. environment in 2001 made it
difficult to provide reliable
guidance.
- ----------------------------------------- ------------------------------------- -----------------------------------------
PRIMEWEST ENERGY TRUST
AT A GLANCE
- --------------------------------------------------------------------------------
STRATEGY
- --------
ONE
ASSET GROWTH
------------
PERFORMANCE TRENDS
----------------------------------------------------
1998 1999 2000 2001 2002
---- ---- ---- ---- ----
MMBOE at January 1
ESTABLISHED
RESERVES
GROWTH ....... 59.8 68.9 63.6 69.6 107.0
[CHART OMITTED]
2002 OBJECTIVES
-----------------------------
o Use the low cycles in
the commodity price
environment and strong
balance sheet to add high
quality reserves to our
asset base.
o Maintain or increase
our reserve life index.
- --------------------------------------------------------------------------------
STRATEGY
- --------
TWO
OPERATING EXCELLENCE
--------------------
PERFORMANCE TRENDS
----------------------------------------------------
1997 1998 1999 2000 2001
---- ---- ---- ---- ----
Average BOE per day
PRODUCTION
GROWTH ....... 11.913 15.497 14.995 16.237 29.774
[CHART OMITTED]
2002 OBJECTIVES
---------------------------------------
o Moderate natural
production decline through
prudent capital development.
o Add incremental production through
drilling, completions and workovers.
o Reduce per BOE operating expenses
from 2001 levels.
- --------------------------------------------------------------------------------
STRATEGY
- --------
THREE
FINANCIAL PRUDENCE
------------------
PERFORMANCE TRENDS
----------------------------------------------------
1997 1998 1999 2000 2001
---- ---- ---- ---- ----
per trust unit
NET DEBT PER
TRUST UNIT.... 2.60 2.44 2.41 1.52 1.72
[CHART OMITTED]
2002 OBJECTIVES
-------------------------------
o Maintain a strong
financial position as
measured by net debt per
Trust Unit and debt-to-cash
flow ratio.
- --------------------------------------------------------------------------------
STRATEGY
- --------
FOUR
RISK MANAGEMENT
---------------
PERFORMANCE TRENDS
----------------------------------------------------
1997 1998 1999 2000 2001
---- ---- ---- ---- ----
per trust unit
DISTRIBUTIONS.. 1.34 0.82 1.10 1.77 2.31
[CHART OMITTED]
2002 OBJECTIVES
-------------------------------
o Use hedging to
stabilize and protect
distribution levels.
o Manage distribution rates
as commodity prices cycle.
- --------------------------------------------------------------------------------
2001 TIMELINE OF KEY EVENTS
FEBRUARY
o ANNOUNCED INTENT TO ACQUIRE CYPRESS ENERGY INC. FOR A COMBINATION OF
TRUST UNITS, EXCHANGEABLE SHARES AND CASH.
MARCH
o CLOSED CYPRESS ACQUISITION WITH OVER 97% OF SHAREHOLDERS TENDERING.
VALUE OF THE TRANS-ACTION WAS OVER $800 MILLION.
APRIL
o INCREASED MONTHLY DISTRIBUTION RATE TO $0.22 PER TRUST UNIT.
JUNE
o CLOSED A $94.9 MILLION BOUGHT DEAL EQUITY FINANCING.
SEPTEMBER
o REDUCED MONTHLY DISTRIBUTION RATE TO $0.17 PER TRUST UNIT DUE TO
DELAYED DEVELOPMENT AND PRODUCTION SHORTFALLS AS WELL AS COMMODITY
PRICE DECLINES.
NOVEMBER
o CLOSED A $70.3 MILLION BOUGHT DEAL EQUITY FINANCING.
DECEMBER
o HELD SPECIAL UNITHOLDER MEETING TO APPROVE A REORGANIZATION OF THE
CORPORATE STRUCTURE.
o REDUCED MONTHLY DISTRIBUTION RATE TO $0.10 DUE TO CONTINUED WEAKNESS IN
THE COMMODITY PRICE OUTLOOK.
o SOLD NON-CORE ASSETS BRINGING TOTAL PROCEEDS FOR THE YEAR TO $78
MILLION.
PRIMEWEST ENERGY TRUST
HIGHLIGHTS
OPERATING AND FINANCIAL
OPERATING HIGHLIGHTS
2001 2000 Change
- -------------------------------------------------------------------------------------------
Daily sales volumes
Crude oil (BARRELS) 10,033 6,582 52%
Natural gas liquids (BARRELS) 2,273 1,483 53%
Natural gas (MILLIONS OF CUBIC FEET) 104.80 49.03 114%
------------- ------------ ---
Total (BARRELS OF OIL EQUIVALENT) (1) 29,774 16,237 83%
Average selling prices
Crude oil (DOLLARS PER BARREL) $ 32.21 $ 36.67 (12%)
Natural gas liquids (DOLLARS PER BARREL) $ 30.96 $ 34.42 (10%)
Natural gas (DOLLARS PER MCF) $ 6.16 $ 4.65 32%
------------- ------------ ---
Total (DOLLARS PER BARREL OF OIL EQUIVALENT) $ 34.80 $ 32.19 8%
Established reserves
Crude oil (MILLIONS OF BARRELS) 28.5 24.4 17%
Natural gas liquids (MILLIONS OF BARRELS) 9.5 6.4 48%
Natural gas (BILLIONS OF CUBIC FEET) 413.7 232.7 78%
------------- ------------ ---
Total (MILLIONS OF BARRELS OF OIL EQUIVALENT) 107.0 69.6 54%
------------- ------------ ---
Net asset value
(MILLIONS OF DOLLARS, EXCEPT PER-TRUST-UNIT)
Established reserves (DISCOUNTED AT 10 PERCENT) $ 872.6 $ 623.0
Hedging mark-to-market 39.7 (1.0)
Unproved lands 55.7 17.2
Other assets and working capital (29.7) 0.1
Long-term debt (195.0) (78.9)
------------- ------------
Total net asset value $ 743.3 $ 560.4 34%
------------- ------------ ---
Per Trust Unit $ 5.67 $ 10.73 (47%)
------------- ------------ ---
Distributions (PER-TRUST-UNIT)
Since inception $ 7.78 $ 5.47 42%
============= ============ ==
Since inception with re-investment $ 10.00 $ 8.89 12%
============= ============ ==
(1) NATURAL GAS CONVERTED TO BARRELS OF OIL ON A 6:1 BASIS.
PRIMEWEST ENERGY TRUST
HIGHLIGHTS
OPERATING AND FINANCIAL
FINANCIAL HIGHLIGHTS
Per Per
weighted weighted
average average
(THOUSANDS OF DOLLARS EXCEPT PER- Trust Per Trust Per
BOE AND PER-TRUST-UNIT AMOUNTS) 2001 Unit BOE 2000 Unit BOE
- ----------------------------------------------------------------------------------------------------------------
Operating revenues, net of royalties $306,515 $2.99 $28.20 $156,561 $3.51 $26.42
Operating expenses 58,951 0.57 5.42 30,175 0.68 5.09
Cash G&A expenses 10,394 0.10 0.96 4,140 0.09 0.70
Cash management fees 6,431 0.06 0.59 3,277 0.07 0.55
Financing costs 13,800 0.13 1.27 6,359 0.14 1.07
Cash flow from operations 214,511 2.09 19.74 112,062 2.51 18.91
Cash distributed to unitholders 234,465 2.31 21.57 79,033 1.77 13.33
Operating margin 247,564 2.41 22.78 126,386 2.83 21.33
Capital expenditures net of
property dispositions 828,358 143,592
Net debt (LONG-TERM DEBT NET OF
WORKING CAPITAL) 225,466 79,208
Net debt-to-annual-cash-flow ratio 1.05 0.71
Weighted average Trust Units and
exchangeables outstanding 102,533 44,652
Trust Units and exchangeables
outstanding at year-end (DILUTED) 132,387 53,196
OUR FOUNDATION IS A SUITE OF
HIGH QUALITY ASSETS
OPERATED PROPERTIES
LAPRISE
A low decline natural gas property. By adding compression, PrimeWest has
maintained production virtually flat since acquiring the property from BP Amoco
in 1996. PrimeWest operates and has a 76% working interest in the property.
THORSBY
Thorsby produces natural gas and natural gas liquids by-products. PrimeWest is
the operator. Despite a successful 5 well drilling program in 2001 which
resulted in over 0.85 million BOE of incremental reserves at a cost of about
$7.00 per BOE, production in 2001 came in below expectations. This shortfall was
due to under performance from the 2000/2001 drilling program and timing delays.
Development in 2002 will focus on production optimization and reduction of
operating costs. A total of 2 drilling locations have been budgeted for 2002.
SUNDRE
The Sundre area includes Caroline, Garrington, Ricinus and Westward Ho. In late
2001, the Garrington and Westward Ho areas were sold for proceeds totaling
approximately $54 million. The Caroline and Ricinus areas produce natural gas,
light oil and natural gas liquids. PrimeWest operates the property with an
average working interest of over 80%. In 2001, 1 well was drilled resulting in
initial production of about 1,000 mcf per day. Development plans for 2002
consist of continued field optimization and cost reduction activities.
BOUNDARY LAKE
Boundary Lake is a low decline, stable oil property. In 2001, an 11 well program
was 100% successful, adding over 600 barrels of production per day. Proved
producing reserves were added at a cost of $5.69 per BOE. For 2002, 6 drilling
locations have been identified and further waterflood optimization work is
anticipated.
STOWE CREEK
Stowe Creek produces both natural gas and oil. PrimeWest's working interest in
the property is approximately 96%. In 2001, a total of 19 wells were drilled
resulting in 11 producing wells, approximately 1.2 million BOE of incremental
proved reserves were added at a cost of $3.86 per BOE. Development work in 2002
will consist of optimization of the gas gathering system and field compression.
A total of 15 new drilling locations have been identified.
BRANT/FARROW
Brant/Farrow produces sweet gas. PrimeWest operates the property with an average
60% working interest. In 2001, PrimeWest drilled 12 wells, 9 of which were
successful adding 2,600 mcf per day of incremental production at a cost of
$11.50 per BOE. Over 18 potential drilling locations have been identified, 8 of
which are planned to be drilled in 2002.
CROSSFIELD/LONE PINE CREEK
This area produces natural gas and natural gas liquids by-products. PrimeWest
operates the Lone Pine Creek gas units, the Crossfield gas unit and the East
Crossfield Gas Conditioning Plant and has working interests varying from 29% to
87% in these units and facilities. In 2001, optimization of operations at the
East Crossfield plant resulted in fuel gas savings of over $1 million. In
addition, operating costs were reduced through an increase in third party
throughput by over 10%. Development in 2002 is expected to consist of continued
plant optimization and cost reduction, as well as development of shallow gas
reserves in the area with 2 recompletions budgeted.
DAWSON
Dawson is relatively undeveloped and has significant potential for reserve
additions. In 2001, a 12 well development program resulted in 1.9 million BOE at
a cost of $8.95 per BOE. Significant infrastructure was also developed in the
year. Notwithstanding, volumes from the area were curtailed due to weather
delays, regulatory restrictions and performance issues. All issues are now
behind us and the area is performing as expected. Development in 2002 will focus
on production maintenance and increasing system capacity to accommodate new
production and future natural gas drilling. PrimeWest is the operator of the
property and owns an average 50% working interest in the area.
SOUTHEASTERN ALBERTA
The largest property within this area is Grand Forks, acquired by PrimeWest in
March 1998. This PrimeWest operated property produces medium gravity crude oil
and natural gas. Since acquiring the property, PrimeWest has actively drilled
in-fill locations effectively arresting the decline and maintaining relatively
stable production over this time. In 2001, a 13 well program resulted in 12
producing wells adding substantial incremental natural gas production.
Development in 2002 will focus on pool optimization with some limited
development drilling.
81% INCREASE IN PRODUCTION
YEAR-OVER-YEAR, CRUDE OIL AND NATURAL GAS PRODUCTION INCREASED OVER 80% THROUGH
A COMBINATION OF THE ACQUISITION OF CYPRESS ENERGY INC. AND INCREMENTAL
PRODUCTION ACHIEVED THROUGH CAPITAL DEVELOPMENT ACTIVITIES.
54% INCREASE IN ESTABLISHED RESERVES
ESTABLISHED RESERVES INCREASED 54% YEAR-OVER-YEAR TO OVER 100 MILLION BARRELS OF
OIL EQUIVALENT. WITHIN THESE ESTABLISHED RESERVES, THE PROVED PRODUCTION
CATEGORY INCREASED FROM 70% TO 72% RESULTING IN MORE RESERVES PRODUCING
IMMEDIATE CASH FLOW THAN IN ANY PRIOR YEAR.
6% ROYALTY ASSETS
ROYALTY ASSETS PROVIDE CASH FLOW WITHOUT ANY DEDUCTION FOR ROYALTIES OR
OPERATING COSTS. AS A RESULT, THESE CASH FLOWS ARE SIGNIFICANTLY LESS VOLATILE
THAN OPERATING CASH FLOWS. FURTHER-MORE, EXPLORATION AND DEVELOPMENT ACTIVITIES
(OVER 200 WELLS DRILLED IN 2001) BY THE UNDERLYING LESSEES ON 245,000 ACRES OF
ROYALTY LANDS IN WESTERN CANADA PROVIDE PRODUCTION AND RESERVE ADDITIONS, AT NO
COST OR RISK TO PRIMEWEST.
58% INCREASE IN UNDEVELOPED LAND ACREAGE
With the Cypress acquisition, PrimeWest acquired 540,000 net acres of
undeveloped land bringing PrimeWest's net underlying land holdings to
approximately 950,000 net acres. Exploitation of this land is expected to add
incremental production and reserves for years to come. In addition, PrimeWest is
actively farming out opportunities to monetize the value of some of these lands.
SUCCESS
THROUGH
GROWTH,
RESILIENCY
AND
RENEWAL
WE ARE BUILDING A NEW TEAM
MESSAGE TO UNITHOLDERS
TO TAKE PRIMEWEST FORWARD STRONGLY AS A LARGE-CAP ROYALTY TRUST
In 2001, PrimeWest emerged as the fourth largest player in the North American
Oil and Gas Royalty Trust Sector; a year which also marked a major consolidation
in the Canadian oil and gas producer sector and the most volatility in natural
gas prices in history. We delivered growth in distributions to unitholders,
production, reserves and asset quality.
o set a record for distributions, $2.31 per unit;
o doubled production;
o increased PrimeWest's gas weighting to approximately 60 percent;
o maintained a strong balance sheet;
o improved the quality of oil and gas production;
o increased our portfolio of development opportunities;
o mitigated the impact of price declines for a significant portion of
production volumes for two years at record first quarter prices; and
o became the most actively traded oil and gas royalty trust in North
America.
Celebrating our fifth anniversary, we have provided unitholders over this
period:
o the highest rate of growth in distributable cash flow per unit amongst
our large cap royalty trust peers.
o cumulative distributions of $7.78 per unit (93 percent of cash flow per
unit since inception), which if reinvested, would total $10.00, equal
to our initial public offering issue price in 1996,
o an average cash-on-cash yield in excess of 20 percent on our initial
public offering price of $10.00 per unit, double the expectation set
forth at the time of our IPO,
o a total unitholder return since inception of 68 percent, outperforming
the TSE 300 at 52 percent and the Oil and Gas Producers Index at 28
percent as at December 31, 2001, and
o as at March 31, 2002, a total unitholder return of 98 percent.
The most significant corporate achievement in 2001 was the takeover of Cypress
Energy Inc. in March, which resulted in the doubling of production to over
30,000 BOE per day. Cypress represented an attractive acquisition opportunity,
an under exploited reserve base characterized by high netback production. In
excess of $100 million of low risk development opportunities identified to date
on Cypress properties will enable PrimeWest to add production and reserves on a
low cost basis in the years to come to help support and sustain distributions to
our unitholders. The transaction strategically positioned PrimeWest as the most
gas weighted, large cap royalty trust in Canada.
GROWTH
The Cypress acquisition was principally financed through a unit for share
exchange. Buoyant first quarter commodity prices enabled us to undertake the
transaction at an attractive exchange ratio supported by a unit price of $9.75,
the highest trading price PrimeWest had achieved since 1997. We also partially
protected the transaction and PrimeWest unitholders from the risk of downward
commodity price movements, by hedging 80 percent of 2001 production and 68
percent of anticipated 2002 production at record prices. The result was $39
million of hedging gains ($0.38 per unit) in 2001. A similar gain is expected in
2002.
The Cypress acquisition also brought challenges, both organizationally and
operationally. In part due to wet weather that restricted drilling access,
PrimeWest's expanded capital development program was late in delivering promised
production volumes in 2001, though actual program results, now in, are running
ahead of our initial expectations. Integration of a large compliment of Cypress
staff into a royalty trust cultural setting was more difficult than anticipated.
As a result, PrimeWest was slow to react to certain post closing production
performance and operating cost issues. These issues have now been substantially
resolved. We are now pleased to report that Cypress and PrimeWest operations are
fully and successfully integrated. We remain confident that we will meet or
exceed all expectations we set forth when the transaction was announced.
To reflect the increased scope, scale and complexity of PrimeWest, we added
significant new strength to our management team in 2001.
Don Garner, President and Chief Operating Officer, was formerly president of
Northstar Energy (Devon Canada), a producer twice the size of PrimeWest, and
prior thereto an executive at Imperial Oil.
Dennis Feuchuk, Vice-president, Finance and Chief Financial Officer, was
previously Vice President and Controller of Gulf Canada Resources and Vice
President and Treasurer Athabasca Oil Sands Trust. Bill Rowe, Vice-president,
Planning and Investor Relations joined PrimeWest from NOVA Chemicals Corporation
where he held a similar office.
Don, Dennis and Bill join Kent MacIntyre, Ron Ambrozy and Tim Granger as your
senior management team. The capabilities and depth of experience of this team
well positions PrimeWest to grow significantly as well as manage the existing
business.
RENEWAL
Moving into 2002, we have worked hard to position PrimeWest's balance sheet to
guard against lower commodity prices, and with $125 million of available credit,
we are in a strong financial position relative to our competitors. Our
opportunities to expand our business both through internal growth and through
acquisition, significantly exceed the $40 million we have committed to date for
capital programs in 2002. Look to PrimeWest to expand its capital development
program should a sustainable recovery in commodity prices become evident.
Increased emphasis will be placed on expanding our reserves position and
production platform as the year progresses, now that our drive to upgrade the
cash flow characteristics of our barrels has been achieved.
As a commodity based investment, we outperform our peers by focusing on
high-quality reserves and production, and controlling costs. PrimeWest is a low
cost leader among our large cap energy trust peers in operating, general and
administrative and all-in cash costs.
RESILIENCY
Today we offer, among our peers, many attractive investment attributes:
o most active trading of units;
o highest yield;
o highest level of distribution protection;
o one of the lowest debt-to-cash flow multiples; and
o highest exposure to a long term gas price recovery.
As evidenced in 2001, PrimeWest operates in an environment where commodity
prices can be highly volatile. Over the course of 2001, oil prices were off 30
percent and gas prices fell more than 60 percent, adversely affecting our
distribution rates and unit trading performance. Despite an aggressive commodity
risk management program to mitigate such effects, PrimeWest under-performed the
royalty trust peer group which is predominately oil weighted.
Moving into 2002, we have seen both commodities rally, with year-to-date oil and
gas prices up substantially as the economic recovery appears to take hold. While
there may be a short term pullback, we remain bullish on the long term prospects
for gas. The same supply and demand fundamentals that caused gas prices to reach
record levels a year ago appear to be forming again. Such a perspective is
certainly aligned with the expectations of the forward commodity markets, where
gas futures are priced to a significant premium to current price levels. As
importantly, the forward markets suggest that gas prices should consistently
outperform oil prices by more than 30 percent over the next five years,
positioning PrimeWest for out-performance relative to its oil weighted peer
group moving forward. Perhaps evidencing such an outlook, PrimeWest is the top
performing large cap royalty trust in the first quarter of 2002, posting an 18
percent total return.
Congratulations to all our employees and contractors for their focus and
outstanding performance in a difficult and challenging environment in 2001. We
could not have achieved our industry leadership position without your
contribution.
We wish to thank our unitholders for your patience and loyalty as we
transitioned from a junior to senior player in the energy trust sector in 2001.
With the overlay of a volatile commodity market, unitholders experienced
significant changes in our pattern of distributions through the year. Your
management team and the Board of Directors are focused on earning your
confidence in 2002 with predictable and sustainable distributions. Our
distribution level is presently $0.10 per unit. To sustain this level, we must
deliver on our first half production objective of 29,000 to 30,000 BOE per day
through the entire year, aggressively manage our costs and continue to enjoy the
commodity price rebound experienced from February through April. Management's
challenge is to mitigate both production and price uncertainty and further
reduce costs in order to maintain a sustainable and predictable distribution
level. We are confident in the capability of our management team to deliver on
these objectives.
PrimeWest has delivered on its strategic commitments of growth, operating
excellence, financial prudence and risk management in 2001.
Thank you for your continued support.
HAROLD P. MILAVSKY
CHAIRMAN
KENT J. MACINTYRE
VICE-CHAIRMAN AND
CHIEF EXECUTIVE OFFICER
DONALD A. GARNER
PRESIDENT AND
CHIEF OPERATING OFFICER
April 5, 2002
PRIMEWEST ENERGY TRUST
QUESTIONS & ANSWERS
WHAT IS AN OIL AND GAS ROYALTY TRUST?
An Oil and Gas Royalty Trust (Trust) owns, directly or indirectly, interests in
oil and gas producing properties in trust for its unitholders. The objective of
a Trust is to exploit already producing oil and gas properties to provide cash
flow which the Trust distributes monthly.
WHO ARE THE TRUSTS AND WHERE DO THEY FIT IN THE BIG PICTURE OF EQUITY INVESTMENT
OPPORTUNITIES?
Trusts are part of an equity investment sector called income trusts. In Canada,
there are over 100 income trusts with a total market capitalization exceeding
$30 billion, about 3 percent of the total market capitalization of the TSE 300.
Oil and gas trusts make up about one third of this total, real estate investment
trusts another third and the balance is widely distributed among other
businesses. As yet, the sector is not represented in the TSE 300,
notwithstanding that several trusts are larger and more liquid than many TSE 300
included companies. The Canadian Oil & Gas Royalty Trust Landscape:
MARKET CAPITALIZATION OF THE TRUSTS (MILLIONS OF DOLLARS) (1)
- -----------------------------------------------------------------------
CANADIAN OIL SANDS TRUST $ 2,508
ENERPLUS RESOURCES FUND 1,795
ARC ENERGY TRUST 1,420
PENGROWTH ENERGY TRUST 1,271
PRIMEWEST ENERGY TRUST 939
NCE PETROFUND 554
SHININGBANK ENERGY INCOME FUND 438
VIKING ENERGY ROYALTY TRUST 403
PROVIDENT ENERGY TRUST 339
NAL OIL AND GAS TRUST 308
FREEHOLD ROYALTY TRUST 301
ADVANTAGE ENERGY INCOME FUND 285
APF ENERGY TRUST 199
ULTIMA ENERGY TRUST 97
OTHER 150
--------
$ 11,007
========
(1) AS AT MARCH 22, 2002
HOW IS A TRUST DIFFERENT FROM ANY OTHER OIL AND GAS COMPANY?
Oil and gas companies, in addition to exploiting already known pools of oil and
gas, explore for significant new pools of hydro-carbons. Trusts do not undertake
such high risk exploration activities. Oil and gas companies use the cash flow
from producing properties to reinvest in exploration and development activities;
whereas Trusts return a significant majority of cash flow to unitholders,
through monthly, partially tax deferred distributions.
HOW ARE DISTRIBUTIONS DETERMINED?
Distributions from a Trust to unitholders are highly dependent upon the cash
flow generated by the Trust. By far, the largest variable in determining the
level of cash flow is prices for crude oil and natural gas. See the chart below
for PrimeWest's recent history.
DISTRIBUTIONS VS COMMODITY PRICES
[CHART OMITTED]
DISTRIBUTION HISTORY
------------------------------------------------------------------------------------
Jan-99 May-99 Sep-99 Jan-00 May-00 Sep-00 Jan-01 May-01 Sep-01 Jan-02
------- ------- ------ ------ ------- -------- ------ ------ ------- ------
Monthly
Distribution
Paid ($/unit) .6 .7-8 .9-13 .9 .9-15 .15-18 .18 .21 .16-20 .9
Blended
Commodity
Prices (1)
($/MCF) 1.8 1.9-2.2 2.2-4.0 2.2 2.2-4.1 4.1-5.0 5.0 5.5 5.5-4.2 2.2
COMMODITY PRICES
------------------------------------------------------------------------------------------
Jan-99 May-99 Sep-99 Jan-00 May-00 Sep-00 Jan-01 May-01 Sep-01 Jan-02
-------- --------- -------- -------- -------- -------- -------- ------- ------- -------
Monthly
Distribution
Paid ($/unit) .9-.11 .11-.14 .14-.15 .15-.17 .16-.22 .26-.35 .35-.24 .22-.18 .18-.13 1.3-1.5
Blended
Commodity
Prices (1)
($/MCF) 2.1-2.3 2.5-4.0 4.0 4.0-4.5 4.0-6.2 6.2-8.2 8.2-6.3 5.8-4.2 4.0-3.2 3.5-4.0
WHY ARE TRUST YIELDS SO HIGH COMPARED TO BONDS, GICS AND PREFERRED STOCK?
Bonds, GICs and preferred stock are generally referred to as "fixed income" or
"yield" investments. They offer economic rent in the form of interest or
dividends of a fixed amount for a fixed period of time. At maturity, an investor
receives back the amount of the original investment.
Trusts pay out variable amounts for whatever time period an investor chooses to
hold the Trust Units. The principal amount, that's the trading value on the
stock exchange, will vary significantly depending primarily on energy prices and
a Trust's ability to replace reserves and maintain production.
Thus, the primary difference between "fixed income" investments and Trusts is
the significant added risk of the underlying business, primarily oil and gas
production and commodity prices.
WE'VE
DOUBLED
PRODUCTION
AND
UPGRADED
RESERVES
PRIMEWEST ENERGY TRUST
ASSET GROWTH
TO REPLENISH OPPORTUNITIES AND SUSTAIN DISTRIBUTIONS.
Asset growth, through strategic acquisitions of businesses and assets, is the
key to ensuring sustainability and growth of the Trust over the long-term. In
assessing potential acquisitions, we look for high-quality assets, light gravity
crude oil, and high heat content natural gas with low operating costs, and
assets that will replenish our pool of development opportunities. We achieved
all of these objectives with our acquisition of Cypress Energy Inc. in March of
2001.
2001 ACTUAL 2001 PRO-FORMA (1) 2000 INCREASE
- -------------------- ----------------------- ---------- ---------------
29,774 33,850 16,237 108%
(1) THE 2001 ACTUAL FIGURE INCLUDES ONLY 9 MONTHS OF CYPRESS PRODUCTION;
THE PRO-FORMA FIGURE REFLECTS A FULL YEAR OF CYPRESS PRODUCTION.
UPGRADED RESERVES
With the acquisition of Cypress we acquired relatively light crude oil and high
heat content natural gas. In addition, we re-weighted our reserves portfolio to
emphasize natural gas.
JAN. 1, JAN. 1,
NATURAL 2002 2001
CRUDE NATURAL GAS TOTAL TOTAL
OIL GAS LIQUIDS RESERVES RESERVES
AS AT JANUARY 1, 2002 (MBBL) (MMCF) (MBBL) (MBOE) (MBOE)
- ------------------------------------------------------------------------------------------------------
RESERVES SUMMARY
Proved producing 22,486 287,143 6,505 76,848 48,900
Total proved 24,719 349,305 7,830 90,766 57,149
Probable 7,651 128,807 3,432 32,551 24,855
Total proved and probable 32,370 478,112 11,262 123,317 82,004
Established 28,545 413,708 9,546 107,042 69,577
% of total established reserves 27% 64% 9%
======================================================================================================
WE'VE
RENEWED
OUR FOCUS ON
NATURAL GAS
AND
OPERATING
EXCELLENCE
PRIMEWEST ENERGY TRUST
OPERATING EXCELLENCE
TO SUSTAIN AND GROW PRODUCTION LEVELS AND LOWER COSTS.
PrimeWest's daily production and sale of oil and gas drives our cash flow and,
in turn, our distributions. Our strategy of actively managing natural decline
rates through optimization programs, preventative maintenance and reservoir
management are key factors in delivering distribution predictability and
sustainability. Tight controls over field production costs help maximize our
netbacks, or the profit margin from each barrel of oil or Mcf of gas produced.
Capital development programs, add value through the low-cost addition of proved
producing reserves, reserves that help sustain production rates and generate
cash flow. We take a diversified approach to capital development activities,
taking care not to risk too much capital on any one project. Capital development
activities include development drilling, waterflood optimization, workovers and
facilities optimization.
WHY NATURAL GAS?
We believe natural gas will continue to be the fossil fuel of choice because
it's clean-burning and highly efficient. North American demand is expected to
grow to meet expanding residential, commercial and industrial markets in a
growing economy.
We bought Cypress anticipating a strong environment for natural gas prices
relative to crude oil. That's what the futures market foretold in the first
quarter of 2001 and the message is the same today.
WE'VE
MANAGED
VOLATILITY AND
MITIGATED
PRICE DECLINES
PRIMEWEST ENERGY TRUST
RISK MANAGEMENT
TO SAFEGUARD DISTRIBUTIONS AND REDUCE VOLATILITY.
During 2001, PrimeWest undertook the most active commodity risk management
program in the royalty trust sector. Given the extreme price volatility during
the year especially in natural gas, PrimeWest locked in pricing on 78 percent of
its total 2001 natural gas production after royalties and 84 percent of its
total crude oil production after royalties at record prices. In aggregate,
PrimeWest enhanced its cash flow by $39 million, or $0.38 Trust Unit
out-standing, through its hedging activities in 2001. Our aim is to reduce
distribution volatility and to maintain a predictable and sustainable
distribution level, currently $0.10 per Trust Unit per month.
PrimeWest continues to actively hedge its future production, having 68 percent
of estimated 2002 natural gas production after royalties and 65 percent of
estimated 2002 crude oil production after royalties currently hedged. The hedge
structures we have used are primarily fixed price swaps or collars to provide
stability to our distribution level. Hedging activities are managed through a
Commodity Risk Management Committee of key executives operating within a policy
framework established by and regularly reviewed by the Board of Directors.
Beyond our hedging activities, we also seek to reduce risk by maintaining a
reasonable balance between natural gas and crude oil. Also, a sizeable portion
of our cash flow is in the form of overriding royalties, which do not attract
royalties or operating expenses and therefore have higher profit margins and
less volatility, mitigating the impact of commodity price movements.
MD&A
OUR VISION
TO BE RECOGNIZED BY OUR INVESTORS AND EMPLOYEES AS THE BEST ENERGY TRUST AS
MEASURED BY BEING THE EMPLOYER AND INVESTMENT OF CHOICE WITHIN THE ENERGY TRUST
SECTOR, BY BEING A LEADER I N THE INDUSTRY, AND BY MAINTAINING A POSITIVE
CORPORATE CULTURE AND IMAGE.
NOTICE TO READERS:
In December of 2001, the Canadian Institute of Chartered Accountants (CICA)
published a Review Draft recommending an integrated disclosure framework whereby
companies structure and integrate their MD&A disclosures within a broad
organizational reporting context and disclosure framework. The Review Draft
emphasizes a balance between historical and forward-looking information and
analysis.
PrimeWest believes in improved disclosure as one means to increase transparency
and level the playing field among market participants. We strongly endorse the
proposals of the CICA as a major step towards improved disclosure.
Accordingly, our 2001 MD&A is prepared on a basis consistent with the CICA
proposals.
The following discussion is management's analysis (MD&A) of PrimeWest's
operating and financial results for the year ended December 31, 2001 compared
with the prior year as well as information and opinions concerning the Trust's
future outlook based on currently available information. This discussion should
be read in conjunction with the Trust's audited consolidated financial
statements for the years ended December 31, 2001 and 2000, together with
accompanying notes. These are included on pages 38 through 53 of this annual
report.
NATURAL GAS CONVERSION EQUIVALENT
All calculations required to convert natural gas to a crude oil equivalent (BOE)
have been made using a ratio of 6 thousand cubic feet of natural gas to 1 barrel
of crude oil.
FORWARD-LOOKING INFORMATION/OUTLOOK
The following discussion, as well as other sections within this annual report,
contain forward-looking or outlook information with respect to PrimeWest.
Because forward-looking information addresses future events and conditions, it
involves risks and uncertainties that could cause actual results to differ
materially from those contemplated by the forward-looking or outlook
information. These risks and uncertainties include: commodity price levels;
production levels; the recoverability of reserves; transportation availability
and costs; operating and other costs; interest rates and currency-exchange
rates; and changes in environmental and other legislation and regulations. The
nature of these risks are discussed in greater detail at pages 33 through 35 of
this MD&A.
2001 HIGHLIGHTS
o Distributions declared totaled a record $2.31 per Trust Unit, up 31%
from the $1.77 per Trust Unit declared in 2000.
o Cash flow per Trust Unit totaled $2.09, down 16% from $2.51 per Trust
Unit in 2000 due to delayed development, production shortfalls at
Thorsby and Dawson and the dilutive impact of equity issues to de-lever
the balance sheet.
o Added over 91% of established reserves in the year, through the
corporate acquisition of Cypress Energy Inc. and capital development
activities.
o Average daily production grew by over 80% compared to the prior year,
to 29,774 BOE per day. o Exit rate for average daily production of
approximately 30,500 BOE per day, after asset sales in the fourth
quarter.
o Posted an investor margin (operating margin less cash G&A, interest,
cash taxes and cash management fees) of $19.74 per BOE, an increase of
5% from the prior year.
o Exited 2001 with a debt-to-cash flow ratio of just over one times,
providing a high degree of financial flexibility. Available credit at
December 31, 2001 totaled approximately $125 million.
CASH FLOW RECONCILIATION
The following table shows a reconciliation of 2001 cash flow from operations to
the prior year.
INCREASE (DECREASE) IN CASH FLOW $'000
- --------------------------------------------------------------------------------
2000 Cash Flow from Operations $ 112,062
Effect of production volumes 150,261
Effect of natural gas price 23,079
Effect of hedging gas 34,530
Effect of crude oil price (21,283)
Effect of hedging crude oil 4,950
Effect of natural gas liquids price (2,871)
Effect of royalty expense (38,000)
Effect of operating expenses (28,776)
Effect of interest expense (7,440)
Effect of cash G&A and management fees (9,408)
Other (2,593)
---------
2001 Cash Flow from Operations $ 214,511
=========
PRODUCTION VOLUMES
Production volumes for 2001 averaged 29,774 BOE per day, up 83% from the prior
year. The major impact on production volumes was the effect of the Cypress
acquisition. Other factors affecting production year-over-year were as follows:
PRODUCTION RECONCILIATION BOE PER DAY
- --------------------------------------------------------------------------------
2000 Daily Production exit rate 17,672
Effect of Cypress acquisition (effective March 29, 2001) 12,933
Capital Development program 3,946
Asset Dispositions (311)
Natural Decline on 2001 Production (4,466)
---------
2001 Daily Average Production 29,774
=========
PRODUCTION SUMMARY 2001 % 2000 %
- --------------------------------------------------------------------------------
Crude Oil (BARRELS PER DAY) 10,033 34 6,582 41
Natural Gas Liquids (BARRELS PER DAY) 2,273 7 1,483 9
Natural Gas (MMCF PER DAY) 104.80 59 49.03 50
Total Oil Equivalent (BOE per day) 29,774 100 16,237 100
============== ===============
Of total production in 2001, 6% or 1,790 BOE per day was attributable to gross
overriding royalties. PrimeWest's production mix became weighted towards natural
gas with the Cypress acquisition.
OUTLOOK FOR PRODUCTION VOLUMES
We exited 2001 with a production level of approximately 30,500 BOE per day. Our
target for the first half of 2002 is to produce an average of 29,000 - 30,000
BOE per day. Our natural production decline rate is approximately 16% per year.
Our capital development program of $40 million for the first half of 2002 is
expected to substantially offset this decline.
COMMODITY PRICES
AVERAGE SALES PRICES (CANADIAN DOLLARS) 2001 2000 CHANGE
- --------------------------------------------------------------------------------
Natural Gas ($ PER MCF) 6.16 4.65 32%
Crude Oil ($ PER BARREL) 32.21 36.67 (12%)
Natural Gas Liquids ($ PER BARREL) 30.96 34.42 (10%)
Total Oil Equivalent ($ PER BOE) 34.80 32.19 8%
Crude oil, using West Texas Intermediate (WTI) as the benchmark, entered 2001 at
$US 26.80 per barrel, reached a high of $US 32.19 per barrel in January, and
exited 2001 at $US 19.84 per barrel, a decline of 26%.
Natural gas, using AECO as the benchmark, entered 2001 at $12.70 per Mcf and
exited 2001 at $3.56 per Mcf, a decline of 72%. In early 2001, supply concerns,
especially in certain U.S. markets, and high demand drove prices to record
levels. An increase in drilling activity and related gas supply, coupled with a
dramatic drop off in demand due to high prices and slowing economic growth
caused the sharp decline in natural gas prices over the year.
During 2001, PrimeWest actively protected against the risk of falling prices on
a major portion of its production by either fixing the price or protecting the
downside risk through a put or collar arrangement. In aggregate, total average
sales prices were higher by $3.63 per BOE than would otherwise have been the
case if PrimeWest had not entered into price protection arrangements.
SALES REVENUE
Gross sales revenues from crude oil, natural gas liquids and natural gas rose by
98% year-over-year, totaling $379.2 million for 2001. Total sales revenue is
influenced both by production volumes which increased year-over-year as
discussed above, and commodity prices, which are discussed below.
REVENUE ($ MILLIONS) 2001 % 2000 % CHANGE
- --------------------------------------------------------------------------------
Natural Gas 235.5 62 84.3 44 179%
Crude Oil 118.0 31 88.3 46 34%
Natural Gas Liquids 25.7 7 18.7 10 37%
-------------- ------------ ----
379.2 100 191.3 100 98%
============== ============ ====
NATURAL GAS REVENUES
Higher production volumes were attributable primarily to the Cypress
acquisition. Higher year-over-year average natural gas prices also contributed
to the increase. The average price was supported by an active and successful
hedging program that added $0.90 per Mcf ($34.5 million) to the average gas
price.
CRUDE OIL REVENUES
Increased crude oil production was offset by lower average crude oil prices in
the year. Included in the average price is a $1.35 per barrel ($5.0 million)
gain realized through hedging activities.
NATURAL GAS LIQUIDS REVENUES
Increased production volumes, offset by lower prices, resulted in the overall
increase. PrimeWest does not hedge its natural gas liquids prices.
PRICE OUTLOOK
Commodity prices at the outset of 2002 were relatively weak. In mid-February we
began to see an unanticipated strengthening in both crude oil and natural gas
prices.
We continue to be concerned about excessive levels of inventory for both crude
oil and natural gas. On the positive side, the anticipated economic recovery in
North America appears to be underway. Nevertheless, in the near-term, we are
cautious about the sustainability of current prices for both oil and gas. We
would look 12 months out before underlying supply conditions would support a
prolonged increase in prices for natural gas. We are concerned that the existing
excess supply of crude oil may continue for perhaps several years to come should
OPEC's discipline weaken and non-OPEC countries, particularly Russia, grow
supply. Our perspective is consistent with the current forward pricing curve for
both commodities.
ROYALTIES
2001 2000
- ------------------------------------------------------------------
Royalty Expense (MILLION) $ 73.2 $ 35.2
Per BOE 6.73 5.92
Royalties as % of Sales Revenue 19.3% 18.4%
==== ====
Higher royalties are the direct result of higher revenues. The overall increase
in the royalty rate is due to the higher proportion of natural gas sales as
compared to crude oil, as natural gas royalties are higher as a percentage of
sales than crude oil. Offsetting this is the effect of hedging gains that do not
attract royalties and would result in a lower royalty as a percentage of sales.
OPERATING EXPENSES
2001 2000
- -------------------------------------------------------------------
Operating Expenses (MILLION) $ 59.0 $ 30.2
Per BOE $ 5.42 $ 5.08
====== ======
In aggregate, operating expenses increased by $28.8 million, or 95% from the
prior year. This increase is largely due to the acquisition of Cypress in the
first quarter of the year. On a BOE basis, operating expenses increased by 6.7%
to $5.42. While PrimeWest benefited from the lower per BOE cost of the Cypress
assets, higher industry costs, in particular power, and maintenance and
work-over costs increased per BOE costs year-over-year.
OPERATING MARGIN
$ PER BOE 2001 2000 1999 1998
- --------------------------------------------------------------------------------
Sales Price and Other Revenue
(including hedging) $ 34.94 $ 32.27 $ 17.99 $ 13.63
Royalties (6.73) (5.92) (3.14) (2.28)
Operating Expenses (5.42) (5.08) (5.23) (5.40)
------- ------- ------ ------
Operating Margin $ 22.79 $ 21.27 $ 9.62 $ 5.95
======= ======= ====== ======
The improvement in operating netback reflects the financial benefits of the
price protection program, partially offset by a 7% increase in operating
expenses per BOE.
GENERAL AND ADMINISTRATIVE
Cash general and administrative expenses, net of overhead recoveries, were $0.96
per BOE in 2001, an increase of 37% from $0.70 per BOE in 2000. Restructuring
costs and other one time costs related to the integration of Cypress contributed
to the overall increase.
Non-cash general and administrative expenses of $4.2 million relate to
PrimeWest's long-term incentive program for employees. The program is a unit
appreciation rights plan, which rewards employees based on total unitholder
return (cumulative distributions on a reinvested basis plus growth in unit
price). No benefit accrues to employees with respect to the first 5% of total
unitholder return. Expenses related to the plan are recorded on a mark-to-market
basis, whereby increases or decreases in the valuation of the vested LTIP
liability for both distributions and changes in unit price are recorded monthly,
as a charge to the income statement, over the six year life of the unit
appreciation rights.
Unit appreciation rights in a trust are similar to stock options in a
corporation. The intent is to align employee and stakeholder interests. The
outcome is expected to be a modest dilution to unitholders' positions over time.
PrimeWest's Short Term Incentive Program, or "bonus" program, is tied entirely
to the following corporate objectives plus performance against personal
objectives:
o achieving 29,500 boe per day average production
o containing costs
o outperforming our industry peers in total unitholder return
COSTS OUTLOOK
We are targeting stabilization in our cost structure in 2002 as follows:
Operations:
o reduced power costs
o aggressive cost management
o continued rationalization of operations with full implementation of
independent north and south business units
o strategic alliances to maximize purchasing power
General and Administrative:
o a reduction of 10% in per boe costs by year end 2002
o reducing contract positions
o controlling third party service costs
o continued process improvements including eliminating low value added
activities.
Our ongoing objective in the field and at head office is to focus on containing
costs during all phases of the commodity price cycle.
MANAGEMENT FEES
As the manager of PrimeWest Energy Trust and its related entities, PrimeWest
Management Inc. receives a management fee of 2.5% of net production revenue as
well as a quarterly allocation of Trust Units and a 1% retained royalty, paid in
the form of a dividend, on payments made to the Trust in connection with the
Royalty Agreement. The 1% retained royalty is based on the net cash flow from
operations and the proceeds from property dispositions.
For the year ended December 31, 2001, management fees related to operating
activities totaled $8.3 million, compared to $4.0 million in 2000. The increase
in management fees reflects higher net production revenue year-over-year,
primarily due to the additional cash flow derived from the Cypress acquisition.
Of the $8.3 million of management fees in 2001, $6.4 million was paid in cash,
and the balance was paid by the issuance of 239,471 Trust Units from treasury.
The 1% royalty was $3.4 million in 2001 ($0.8 million - 2000). The increase in
the royalty is mainly attributable to the higher cash flows achieved during
2001.
In addition to the fees indicated above, the Manager is also entitled to an
acquisition fee representing 1.5% of capital spent on asset or corporate
acquisitions and a disposition fee representing 1.25% of proceeds received from
asset dispositions. In 2001, these fees totaled $13.0 million and have been
charged or credited as part of the cost of the assets purchased or sold.
INTEREST EXPENSE
Interest expense increased to $13.8 million in 2001 compared to
$6.4 million in 2000. Higher interest expense resulted from higher
year-over-year average debt levels offset by lower interest rates.
2001 2000
- ---------------------------------------------------------------------------
Interest Expense (MILLION) $ 13.8 $ 6.4
Year End Debt Level (MILLION) $ 195.1 $ 79.0
Year End Debt Level per Trust Unit $ 1.72 $ 1.52
Average Cost of Debt 5.6% 7.5%
======= ======
DEPLETION, DEPRECIATION AND AMORTIZATION
The 2001 depletion, depreciation and amortization (DD&A) rate was $14.66 per BOE
compared to $7.21 per BOE for 2000, primarily a result of the acquisition of
Cypress.
The 2001 DD&A rate is inflated relative to the acquisition cost of the Cypress
reserves due to the requirement to account for future income tax liabilities
associated with these reserves. Absent this tax adjustment, the 2001 DD&A rate
would have been $11.39.
CEILING TEST
In accordance with its stated accounting policies, PrimeWest performs a ceiling
test at each balance sheet date which compares the book value of capital assets
(i.e. the value of capital assets reflected on the balance sheet, net of DD&A)
with an estimate of the future net revenue from proved reserves (as determined
by independent engineers) less estimated future general and administrative
costs, debt servicing costs, management fees, and applicable income taxes.
Performing this test at the December 31, 2001, using commodity prices of AECO
$3.67 per Mcf for natural gas and $US 19.84 per barrel WTI for crude oil, would
result in a ceiling test deficiency of approximately $150 million.
PrimeWest is not required to account for any ceiling test impairment, that is
not permanent, within the first two years of the Cypress acquisition and
therefore no writedown is reflected in the 2001 financial statements.
If March 21, 2002 spot prices of $4.52 per Mcf for natural gas (AECO) and $US
25.61 per barrel (WTI) for crude oil were used in the ceiling test, a surplus of
$180 million is indicated.
SITE RECLAMATION AND RESTORATION RESERVE
A provision of $3.5 million was made for site reclamation and abandonment during
2001, compared to $2.9 million for 2000. The provision is based on site
reclamation and abandonment cost estimates made by both PrimeWest and external
engineers and is charged to expense on a unit of production basis.
To fund future costs related to well abandonment and site cleanup, PrimeWest
contributed $0.32 per BOE, totaling $4.2 million for 2001, to a segregated fund.
This fund is used to pay for reclamation and abandonment costs as they are
incurred. In 2001, a total of $3.8 million was paid out of the reserve leaving a
balance of $0.8 million in the fund at year end.
The 2002 contribution rate has been set at $0.37 per BOE which is expected to be
sufficient to meet the funding requirements for the future.
INCOME TAXES - TRUST
Current income tax expense of $2.4 million for 2001 (2000 - $0.5 million) is
comprised of the Federal Large Corporations Tax and other capital taxes payable
by PrimeWest Energy Inc. The increase in current income taxes year-over-year is
due to the addition of the Cypress properties.
PrimeWest Energy Inc. manages its operating and financing activities such that
it is not subject to current tax payable, other than the capital taxes noted
above.
Future income taxes are recorded on corporate acquisitions to the extent that
the book value of capital assets acquired exceeds the tax pools acquired. These
future taxes increase the cost basis
of the capital assets acquired and are recovered over time as royalties are paid
to the Trust. The income statement for the year ended December 31, 2001 reflects
a future income tax recovery of $30.3 million due primarily to the future income
tax liability of $376.3 million recorded as part of the Cypress acquisition.
The unitholders of the Trust are allocated taxable income based on the amount of
royalty revenue, interest and revenue from direct investments earned
(essentially distributions before crown royalty charges), less certain tax
deductions such as Canadian Oil and Gas Property Expense (COGPE), resource
allowance, unit issue expenses and other direct costs.
INCOME TAXES - UNITHOLDERS
For the 2001 taxation year, unitholders of the Trust were paid $2.41 per Trust
Unit in distributions. Of these distributions, 32.8%, or $0.79 per Trust Unit is
a tax deferred return of capital and 67.2%, or $1.62 per Trust Unit is taxable
to unitholders as other income (taxed the same as interest income). The tax
deferred return of capital reduces the unitholder's adjusted cost base for
purposes of calculating a capital gain or loss upon ultimate disposition of
their Trust Units. It should be noted that this represents the tax treatment for
Canadian residents.
For unitholders resident in the United States, the ultimate tax result is
similar to that for Canadian investors after the application of withholding
taxes in Canada and tax credits in the United States.
Unitholders resident outside of Canada and the United States should seek
independent competent tax advice.
INCOME TAXES - UNITHOLDERS - OUTLOOK
Based on current expectations for cash flow and distributions for 2002, it is
anticipated that approximately 55% of 2002 distributions will be taxable and 45%
will be tax deferred.
NET ASSET VALUE
Net asset value (NAV) is a measure of the worth of PrimeWest's underlying assets
- - primarily crude oil, natural gas and natural gas liquids reserves. The value
placed on these reserves is in reference to the pre-tax present value of future
net cash flows from these reserves, as independently assessed by Gilbert
Laustsen Jung Associates Ltd. (GLJ) as at January 1, 2002. The commodity price
forecast used in this assessment is based on the arithmetic average of three
independent consultants' price forecasts. The present value of reserves reflects
provision for royalties, operating costs, future capital costs and site
reclamation and abandonment costs but is prior to deduction for income taxes,
interest costs, general and administrative costs and management fees.
This calculation is a "snapshot" in time and is heavily dependent upon future
commodity price expectations at the point in time the "snapshot" is taken.
Accordingly, the NAV as at January 1, 2002 may not reflect fairly the equity
market trading value of PrimeWest.
It is also significant to note that NAV reduces as reserves are produced and net
operating cash flow is distributed. Value is delivered to unitholders through
such monthly distributions and through unit price appreciation.
The following table sets forth the calculation of net asset value:
AS AT JANUARY ($ MILLION EXCEPT PER TRUST UNIT AMOUNTS) 2002 2001
- ------------------------------------------------------------------------------
ASSETS
Present value of net cash flow from established
reserves discounted at 10% 872.6 623.0
Hedging mark-to-market 39.7 (1.0)
Unproved lands 55.7 17.2
Reclamation fund 0.8 --
------ -----
968.8 639.2
LIABILITIES
Working capital (deficiency) (30.5) 0.1
Long-term debt (195.0) (78.9)
------ -----
(225.5) (78.8)
------ -----
Total net asset value 743.3 560.4
====== =====
Net asset value pre-tax per Trust Unit 5.67 10.73
====== =====
Reference prices - Oil ($US WTI/BBL) 19.68 29.52
- Exchange rate ($US/$CDN) 0.63 0.67
- Natural gas ($CDN/MCF) 4.03 6.91
The NAV calculation is based on the commodity price forecast as of January 1,
2002 and is highly sensitive to changes in price forecasts over time. For
example, the NAV would have been $7.00 per Trust Unit if the prices in effect at
March 13, 2002 were used in the calculation. Also, the NAV calculation also
assumes a "blow down" scenario whereby existing reserves are produced out
without being replaced by acquisitions. A major cornerstone of PrimeWest's
strategy is to replace reserves through accretive acquisitions.
LIQUIDITY AND CAPITAL RESOURCES
LONG-TERM DEBT
At December 31, 2001, long-term debt, net of working capital was $225.5 million
or $1.72 per Trust Unit, compared to $79.2 million, or $1.52 per Trust Unit at
the end of 2000. The increase in long-term debt was due to debt of $257 million
assumed and incurred in connection with the acquisition of Cypress in March of
2001 as well as $84.2 million spent on the capital development program in 2001.
PrimeWest's credit facility was increased to $350 million during 2001, shared
among five major Canadian lenders. As at year end, available credit lines
totaled approximately $125 million (2000 - $67 million).
(THOUSANDS OF DOLLARS) 2001 2000 1999
- -------------------------------------------------------------------------------
Long-term debt 195,000 78,940 92,180
Working capital (deficit) 30,466 268 (5,850)
Net debt 225,466 79,208 86,330
Market value of Trust Units and exchangeable
shares outstanding (1) 834,053 467,172 237,863
Total capitalization 1,059,519 546,380 324,193
Net debt as a percentage of total capitalization 21.3% 14.5% 26.6%
(1) BASED ON DECEMBER 31 CLOSING PRICE
PROPERTY DISPOSITIONS
Shortly after the Cypress acquisition, PrimeWest initiated an asset
rationalization program to high grade the properties of the combined companies
of PrimeWest and Cypress. Generally, the properties targeted for divestment had
higher operating costs, higher future abandonment costs, lower net operating
income and less development opportunities than PrimeWest's corporate average for
these indicators.
PrimeWest conducted the divestment program over three phases. Phase 1 properties
that were sold were closed in Sept./Oct. of 2001 while the larger Phase 2
program consisting of the Garrington and Westward Ho properties was closed in
mid December 2001. Net cash proceeds on the Phase 1 and Phase 2 dispositions
totaled approximately $78 million. A number of smaller properties sold in Phase
3 will be closed in Q1 of 2002.
PrimeWest has a small group of minor non core assets totaling no more than 200
boepd that potentially could be sold during the balance of 2002.
OUTLOOK - LONG-TERM DEBT
Long term debt net of working capital in 2002 is expected to increase by
approximately $40 million to $265 million in the absence of any acquisitions or
expansion of our 2002 capital development program.
UNITHOLDERS' EQUITY
PrimeWest completed two bought deal financings in 2001, the first in June
raising $94.9 million of gross proceeds on the issuance of 9.89 million Trust
Units at $9.60 per Trust Unit and the second in October raising $70.3 million of
gross proceeds on the issuance of 9.9 million Trust Units at $7.10 per Trust
Unit. The net proceeds, after costs of these financings, totaled $156.2 million,
were used to fund the capital development program and to reduce outstanding
indebtedness.
CAPITAL SPENDING
Capital expenditures, including corporate acquisitions, totaled approximately
$0.9 billion in 2001 as summarized in the following table:
(THOUSANDS OF DOLLARS) 2001 2000 1999
- -------------------------------------------------------------------------------
Land and lease 6,831 545 323
Geological and geophysical 4,048 8178 93
Development drilling 47,766 16,416 10,199
Plant and facilities 21,802 5,665 2,335
Property acquisitions 1,754 2,223 11,084
Corporate acquisitions (see below) 820,844 116,433 13,563
Head office 3,457 2,348 422
------- ------- ------
Total additions 906,502 144,447 38,819
Property dispositions (78,144) (855) (5,909)
------- ------- ------
Net additions 828,358 143,592 32,910
======= ======= ======
Cypress Energy Inc. was acquired in 2001, Venator Petroleum Company Ltd. and
Reserve Royalty Corporation were acquired in 2000 and Aberdeen Petroleum
(Canada) Ltd. was acquired in 1999.
OUTLOOK FOR CAPITAL SPENDING
PrimeWest plans to spend approximately $40 million in the first half of 2002 on
capital development programs. Further spending of up to an additional $40
million in the second half of 2002 will be contingent upon prevailing market
conditions and commodity prices at the time.
The Trust has identified approximately $120 million, including the $40 million
mentioned above, of development projects which meet or exceed the risked hurdle
rates set by management for new investment. For competitive reasons, the Trust
does not disclose its hurdle rate for acquisitions, but guidance can be provided
in that the trust agreement requires the hurdle rate for acquisitions to be a
minimum of 400 basis points over intermediate to long-term Canada bonds. At
present, this minimum threshold rate would be approximately 10%, pre-tax. The
hurdle rate for development projects is significantly higher at a risk adjusted
20%, pre-tax.
UNITHOLDERS' EQUITY
The Trust had 125,965,607 Trust Units outstanding at December 31, 2001 compared
to 50,982,093 Trust Units at the end of 2000. In addition, there are 4.1 million
exchangeable shares (see below) outstanding, exchangeable into a total of
5,174,732 Trust Units at year end. The weighted average number of Trust Units,
including those issuable by the exchange of exchangeable shares, was 102.5
million Trust Units for 2001 compared to 44.6 million for 2000.
During 2001, PrimeWest issued 50.2 million Trust Units on the purchase of
Cypress, 19.8 million Trust Units pursuant to equity financings, 1.8 million
Trust Units pursuant to the Distribution Reinvestment Plan, 0.6 million pursuant
to the Long-Term Incentive Plan for employees and 0.2 million to the Manager
pursuant to the Management Agreement.
Equity issued, net of costs, totaled $646.0 million relating to the acquisition
of Cypress and the June and October bought deal financings. Dividends declared
were $4.1 million in 2001, compared to $1.6 million in 2000. Dividends are paid
to PrimeWest Management Inc. in conjunction with the Management Agreement (see
discussion under Management Fees) and were paid on the exchangeable shares
issued in conjunction with the Venator acquisition up to April 30, 2001.
EXCHANGEABLE SHARES
Exchangeable shares were issued in connection with both the Venator acquisition
in April 2000 and the Cypress 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.
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 based on the distribution amount divided by
the market price of the Trust Units on the 15th day of each month.
At December 31, 2001, there were 0.751 million exchangeable shares outstanding
issued in connection with the Venator acquisition (2000 - 1.112 million). The
exchange ratio on these shares was 1.36806 Trust Units for each exchangeable
share as at year end. In respect of the Cypress transaction, there were 3.317
million exchangeable shares outstanding at the end of the year, each of which
was exchangeable into 1.25020 Trust Units.
For purposes of calculating diluted per Trust Unit amounts, these exchangeable
shares have assumed to be exchanged into Trust Units at the current exchange
ratio.
CASH DISTRIBUTIONS
Cash distributions in 2001 totaled $234.5 million, or $2.31 per Trust Unit,
compared to $79.0 million, or $1.77 per Trust Unit in 2000. For tax purposes,
reflecting the fact that the December distribution is not paid until January 15,
distributions for 2001 were $2.41 per Trust Unit ($1.67 per Trust Unit in 2000).
The following table sets out the historical cash distributions per unit since
inception:
Distribution Date Month 2001 2000 1999 1998 1997 1996
- -------------------------------------------------------------------------------------------------------------------
February 15 January $ 0.20 $ 0.10 $ 0.06 $ 0.08 -- --
March 15 February 0.20 0.10 0.06 0.08 -- --
April 15 March 0.20 0.10 0.06 0.08 $ 0.35 --
May 15 April 0.22 0.10 0.07 0.08 -- --
June 15 May 0.22 0.13 0.09 0.08 -- --
July 15 June 0.22 0.16 0.10 0.06 0.30 --
August 15 July 0.22 0.16 0.07 0.06 -- --
September 15 August 0.22 0.16 0.14 0.06 -- --
October 15 September 0.17 0.16 0.10 0.06 0.30 --
November 15 October 0.17 0.20 0.10 0.06 -- --
December 15 November 0.17 0.20 0.15 0.06 -- --
JANUARY 15 DECEMBER 0.10 0.20 0.10 0.06 0.39 $ 0.44
===================================================================================================================
Total $ 2.31 $ 1.77 $ 1.10 $ 0.82 $ 1.34 $ 0.44
Cumulative Total $ 7.78 $ 5.47 $ 3.70 $ 2.60 $ 1.78 $ 0.44
===================================================================================================================
OUTLOOK FOR CASH DISTRIBUTIONS
PrimeWest distributed $0.10 per unit per month for the first quarter of 2002 and
has committed to distributing $0.10 per Trust Unit per month for the second
quarter of 2002, subject to revision should there be a material change to
expected cash flows for the second quarter. Beyond this time frame, the Board of
Directors will establish a distribution level commensurate with cash flow
expectations and any foreseen internal requirements. If current prices and
production levels prevail, distributions may be sustained at $0.10 per unit per
month for all of 2002.
CASH FLOW SENSITIVITIES
Impact on 2002 cash available for distribution per unit (increase/decrease):
Providing for Without the Effect
PRICE PROTECTION OF PRICE PROTECTION
Crude Oil Price ($US 1.00 per barrel WTI increase) $ 0.020 $ 0.040
Natural Gas Price ($0.10 per Mcf increase) 0.010 0.020
Interest Rate (1% increase) (0.006) (0.016)
Exchange Rate ($US 0.01 increase) (0.005) (0.030)
Production (1,000 BOE per day increase) 0.070 0.070
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 single most important factor affecting the level of cash distributions
available to unitholders is the price that PrimeWest receives for its products.
These prices are influenced in varying degrees by factors outside the Trust's
control. Some of these factors include:
o 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;
o 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.;
o weather conditions that influence the demand for natural gas and
heating oil;
o 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;
o transportation availability and costs;
o 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. This strategy paid
off in 2001 in connection with the Enron collapse whereby PrimeWest's exposure
was limited to only a few contracts representing less than 5% of PrimeWest's
total hedge contracts in 2001. PrimeWest incurred no significant losses on
closing out these Enron contracts. In 2001, approximately 30% of natural gas
production was sold to aggregators and 70% into the Alberta short and 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 2001, PrimeWest added $39.5 million ($0.38 per Trust Unit) to our
cash flow through various physical and financial hedging transactions. In total,
PrimeWest hedged 84% of full year crude oil production and 78% of full year
natural gas production.
2001 HEDGING RESULTS
HEDGING
FULL YEAR GAIN PER UNIT OF
PRODUCTION % HEDGED ($ MILLION) PRODUCTION
- --------------------------------------------------------------------------------
Natural Gas (MMCF/D) 104.80 78% 34.53 $ 0.90/Mcf
Crude Oil (BBLS/D) 10,033 84% 4.95 $ 1.35/bbl
2002/2003 HEDGING SUMMARY
For 2002, PrimeWest has 65% of its crude oil production after royalties and 68%
of its natural gas production after royalties hedged with a combination of
swaps, and option based instruments. As at March 13, 2002, the mark-to-market
valuation (including year-to-date settlements) of these hedges totals $31.1
million, $4.4 million for crude oil and $26.7 million for natural gas.
To March 13, 2002, PrimeWest has recorded a net gain of $19.4 million on hedge
contracts settled since the 2001 year end. This amount is included in the $31.1
million figure above.
For 2003, PrimeWest has 26% of its crude oil production after royalties and 50%
of its natural gas production after royalties hedged with a combination of
swaps, and option based investments. As at the date of this report there is no
material gain or loss on a mark-to-market valuation of these hedges.
OPERATIONAL AND OTHER 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: Operational 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.
RISK: 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.
RISK: Development risk associated with capital enhancement
activities undertaken - the risk that capital
spending on activities such as 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. As a
royalty trust, we concentrate on acquiring large
pool, mature and lower decline properties where high
risk capital programs are not normally required to
mitigate annual production declines.
RISK: 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.
RISK: 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, Gilbert Laustsen Jung
Associates Ltd. (GLJ). The work
and independence of GLJ is reviewed by the Audit
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.
RISK: 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 Compensation Committee of the Board,
which acts as PrimeWest's Environmental, Health and
Safety Committee.
RISK: Changes in government regulations including reporting
requirements, income tax laws, operating practices
and environmental protection requirements.
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.
FINANCIAL STATEMENTS & NOTES
MANAGEMENT RESPONSIBILITY FOR FINANCIAL STATEMENTS
The consolidated financial statements of PrimeWest Energy Trust were prepared
by, and are the responsibility of, the management of PrimeWest Management Inc.
as agreed in the management agreement between PrimeWest, the manager, and the
Trust. These statements have been prepared in accordance with accounting
principles generally accepted in Canada. The financial and operating information
presented in this annual report is consistent with that shown in the
consolidated financial statements.
Management has designed and maintains a system of internal controls to safeguard
assets and ensure that transactions are properly authorized and recorded and
form part of these financial statements. Where estimates are used in the
preparation of these financial statements, management has ensured that careful
judgement has been made and that these estimates are reasonable, based on all
information known at the time the estimates are made.
The Board of Directors of PrimeWest is responsible for ensuring that management
fulfils its responsibilities for financial reporting, and it has reviewed and
approved these financial statements. The Board carries out this responsibility
through the audit committee, which consists of the independent directors of the
Board.
The manager, acting on behalf of the unitholders, with approval of the Board of
Directors, has appointed the external audit firm of PricewaterhouseCoopers LLP
to express their opinion on the consolidated financial statements. The auditors
have full and unrestricted access to the audit committee to discuss their
findings.
KENT J. MACINTYRE DENNIS G. FEUCHUK
VICE-CHAIRMAN AND VICE-PRESIDENT, FINANCE AND
CHIEF EXECUTIVE OFFICER CHIEF FINANCIAL OFFICER
March 1, 2002
AUDITORS' REPORT
To the unitholders of PrimeWest Energy Trust:
We have audited the consolidated balance sheets of PrimeWest Energy Trust as at
December 31, 2001 and 2000, and the consolidated statements of income, cash
distributions, unitholders' equity, and cash flows for the years then ended.
These financial statements are the responsibility of the management of the
Trust. 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 required that we plan and perform an audit to obtain
reasonable assurance whether the financial statements are free from 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 Trust as at December 31, 2001
and 2000, and the results of its operations and cash flows for the years then
ended in accordance with Canadian generally accepted accounting principles.
PRICEWATERHOUSECOOPERS LLP
CHARTERED ACCOUNTANTS
CALGARY, ALBERTA
March 1, 2002
CONSOLIDATED BALANCE SHEETS
AS AT DECEMBER 31 ($ THOUSANDS) 2001 2000
- ----------------------------------------------------------------------------------------------
ASSETS
Current Assets
Accounts Receivable $ 55,465 $ 35,064
Prepaid Expenses and Inventory 11,200 3,400
66,665 38,464
Cash Reserved for Site
Restoration and Reclamation (NOTE 6) 755 398
Capital Assets (NOTE 3) 1,448,661 395,376
----------- ---------
$ 1,516,081 $ 434,238
=========== =========
LIABILITIES AND UNITHOLDERS' EQUITY
Current Liabilities
Bank Overdraft $ 14,613 $ 834
Accounts Payable & Accrued Liabilities 59,944 25,776
Accrued Distributions to Unitholders 11,980 9,961
Due to Related Company (NOTE 9) 10,527 2,057
Current Portion of Long-term Debt (NOTE 5) 67 106
----------- ---------
$ 97,131 $ 38,734
Long-term Debt (NOTE 5) 195,000 78,940
Future Income Taxes (NOTE 10) 362,595 16,596
Long-term Incentive Liability (NOTE 8) 7,932 8,930
Site Restoration and Reclamation Provision 6,113 1,958
----------- ---------
$ 668,771 $ 145,158
Unitholders' Equity
Net Capital Contributions (NOTE 7) 1,152,551 435,342
Accumulated Income 122,550 43,014
Accumulated Cash Distributions (420,983) (186,518)
Accumulated Dividends (6,808) (2,758)
847,310 289,080
----------- ---------
$ 1,516,081 $ 434,238
=========== =========
Commitments and Contingencies (NOTE 12)
HAROLD P. MILAVSKY KENT J. MACINTYRE
CHAIRMAN OF THE BOARD OF DIRECTORS VICE-CHAIRMAN AND CHIEF EXECUTIVE
OFFICER
CONSOLIDATED STATEMENTS OF
UNITHOLDERS' EQUITY
FOR THE YEARS ENDED DECEMBER 31 ($ THOUSANDS) 2001 2000
- ----------------------------------------------------------------------------------------------
Unitholders' Equity - Beginning of Year,
as previously reported $ 289,080 $ 200,039
Adjustment to Unitholders' Equity at the
Beginning of Year to Adopt New Future
Income Tax Standard (NOTE 10) -- (10,219)
Net Income for the Year 79,536 55,612
Capital Contributions, Net of Costs 717,209 124,293
Cash Distributions (234,465) (79,033)
Dividends (4,050) (1,612)
--------- ---------
Unitholders' Equity - End of Year $ 847,310 $ 289,080
========= =========
CONSOLIDATED STATEMENTS OF INCOME
FOR THE YEARS ENDED DECEMBER 31 ($ THOUSANDS EXCEPT
PER UNIT AMOUNTS) 2001 2000
REVENUES
Sales of Crude Oil, Natural Gas & Natural Gas Liquids $ 378,155 $ 191,339
Crown & Other Royalties, Net of ARTC (73,156) (35,157)
Other Income 1,516 379
---------- -------------
306,515 156,561
EXPENSES
Operating 58,951 30,174
Cash General & Administrative 10,394 4,140
Non-Cash General & Administrative 4,158 10,296
Interest 13,800 6,359
Cash Management Fees 6,431 3,277
Non-Cash Management Fees 1,819 731
Depletion, Depreciation & Amortization 159,332 42,865
---------- -------------
254,885 97,842
---------- -------------
Net Income Before Taxes 51,630 58,719
---------- -------------
Capital Taxes 2,428 549
Future Taxes (NOTE 10) (30,334) 2,558
---------- -------------
(27,906) 3,107
---------- -------------
Net Income for the Year $ 79,536 $ 55,612
========== =============
Net Income per Trust Unit
Basic $ 0.78 $ 1.25
Diluted $ 0.77 $ 1.21
========== =============
CONSOLIDATED STATEMENTS OF CASH DISTRIBUTIONS
FOR THE YEARS ENDED DECEMBER 31 ($ THOUSANDS EXCEPT
PER UNIT AMOUNTS) 2001 2000
- -----------------------------------------------------------------------------------------------
Net Income for the Year $ 79,536 $ 55,612
Add Back (Deduct)
Depletion, Depreciation & Amortization 159,332 42,865
Decrease in (Increase to) Reserve 25,822 (29,266)
Contribution to Reclamation Fund (3,499) (2,964)
Management Fees Paid by the Issuance of Trust Units 1,819 731
Employee Long Term Incentive Plan 4,158 10,296
Future Income Taxes (30,334) 2,558
------------ ----------
157,298 24,220
------------ ----------
$ 236,834 $ 79,832
------------ ----------
CASH DISTRIBUTIONS TO TRUST UNITHOLDERS (99%) $ 234,465 $ 79,033
============ ==========
Cash Distributions per Trust Unit $ 2.31 $ 1.77
============ ==========
CONSOLIDATED STATEMENTS OF CASH FLOW
FOR THE YEARS ENDED DECEMBER 31 ($ THOUSANDS) 2001 2000
- -----------------------------------------------------------------------------------------------
OPERATING ACTIVITIES
Net Income for the Year $ 79,536 $ 55,612
Add: Items Not Involving Cash
Flow from Operations
Depletion, Depreciation & Amortization 159,332 42,865
Non-Cash General and Administrative 4,158 10,296
Non-Cash Management Fees 1,819 731
Future Income Taxes (30,334) 2,558
----------- ----------
Cash Flow from Operations 214,511 112,062
Change in Non-Cash Working Capital (8,369) (7,599)
----------- ----------
206,142 104,463
----------- ----------
FINANCING ACTIVITIES
Proceeds from Issue of Trust Units, Net of Costs 156,221 39,896
Acquisition of Trust Units pursuant to
Normal Course Issuer Bid -- (926)
Cash Distributions to Unitholders (220,337) (79,033)
Dividends Paid (602) (1,612)
Decrease in Long-Term Debt (62,980) (41,449)
Change in Non-Cash Working Capital 2,019 6,291
----------- ----------
(125,679) (76,833)
----------- ----------
INVESTING ACTIVITIES
Expenditures on Capital Assets (84,206) (25,791)
Acquisition of Capital/Corporate Assets (NOTE 4) (84,054) (6,306)
Proceeds on Disposition of Capital Assets 78,144 855
Cash Reserved for Future Site Restoration & Reclamation (357) 661
Expenditures on Site Restoration & Reclamation (3,769) (3,561)
Proceeds on Disposition of Short Term Investments -- 174
----------- ----------
(94,242) (33,968)
----------- ----------
DECREASE IN CASH FOR THE YEAR (13,779) (6,338)
BANK OVERDRAFT, BEGINNING OF YEAR (834) 5,504
----------- ----------
BANK OVERDRAFT, END OF YEAR $ (14,613) $ (834)
=========== ==========
CASH INTEREST PAID $ 13,159 $ 6,872
----------- ----------
CASH TAXES PAID $ 460 $ 453
=========== ==========
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (ALL AMOUNTS ARE EXPRESSED IN
THOUSANDS 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 accordance with a declaration of trust dated August
2, 1996. The beneficiaries of the Trust are the holders of Trust Units (the
unitholders). The Trust owns a royalty entitling it to receive 99% of the net
cash flows generated by its subsidiary PrimeWest Oil & Gas Corp. referred to as
Oil & Gas Corp.) and by its subsidiary PrimeWest Energy Inc., and its
wholly-owned subsidiaries PrimeWest Resources Ltd. and PrimeWest Royalty Corp.
from its oil and gas properties (collectively referred to as Energy Inc.).
Oil & Gas Corp. and Energy Inc. (PrimeWest) acquire oil and gas properties, and
sell a royalty on the net cash flow from these properties to the Trust. The
royalty acquired by the Trust effectively transfers substantially all of the
economic interest in the properties to the Trust. Effective January 1, 2002, Oil
& Gas Corp. and Energy Inc. and its subsidiaries amalgamated and were continued
as PrimeWest Energy Inc. Subsequent to the amalgamation, the common shares of
PrimeWest Energy Inc. are 89% owned by the Trust and 11% by PrimeWest Management
Inc.
Pursuant to management agreements between Oil & Gas Corp., Energy Inc., the
Trust and PrimeWest Management Inc. (the Manager), the Manager is responsible
for the administration of the Trust, the management of the business affairs of
Oil & Gas Corp. and Energy Inc. and the operation of the oil and gas properties.
The Manager receives reimbursement for all of its costs associated with these
services as well as management fees from the Trust and PrimeWest for its
services (see Note 9). The Manager owns 11% of the shares of PrimeWest Energy
Inc., and a director of PrimeWest Energy Inc. controls the Manager.
2. ACCOUNTING POLICIES
CONSOLIDATION
These consolidated financial statements include the accounts of the Trust and
PrimeWest. The Trust owns 89% of the shares of PrimeWest (as of January 1,
2002). The Trust, through the royalty, obtains substantially all of the economic
benefits of the operations of PrimeWest. In addition, the unitholders of the
Trust elect the majority of the Board of Directors of PrimeWest. The accounts of
the Manager are not included in these financial statements.
CAPITAL ASSETS
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 net revenues of future periods (the
ceiling test). The ceiling test is a cost recovery test whereby: capitalized
costs, less accumulated depletion and site restoration and the lower of cost and
market value of unproved land, are limited to an amount equal to estimated
undiscounted future net revenues from proved reserves, less general and
administrative expenses, site restoration, management fees, 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 (see
Note 6).
iii) DEPLETION, DEPRECIATION AND AMORTIZATION
Provision for depletion and depreciation is calculated on the unit-of-production
method, based on proved reserves before royalties. 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 vested Unit Appreciation Rights that
are in the money using the unit price as at that date. Liabilities are recorded
through non-cash general and administrative costs, with an offsetting amount in
accrued liabilities. As Trust Units are issued under the plan, the exercise
value is recorded in unitholders' equity.
INCOME TAXES
The Trust is 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 (see Note
10).
FINANCIAL INSTRUMENTS
PrimeWest uses financial instruments to manage its exposure to fluctuations in
commodity prices, foreign currency exchange rates, 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 judgement. Such amounts are not expected to change materially in
the near term. They include:
o 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.
o the amounts recorded for assets and liabilities of acquired companies
which depend on estimates of their fair values on the acquisition date.
CASH AND SHORT TERM INVESTMENTS
Short term investments with maturities less than three months are considered to
be cash equivalents and are recorded at cost, which approximates market value.
3. CAPITAL ASSETS
2001 2000
- -----------------------------------------------------------------------------------------------------------------------
ACCUMULATED ACCUMULATED
DEPLETION, DEPLETION,
DEPRECIATION NET DEPRECIATION NET
AND BOOK AND BOOK
COST AMORTIZATION VALUE COST AMORTIZATION VALUE
Property acquisition oil and gas rights $ 1,608,435 $ (268,137) $ 1,340,298 $ 474,091 $ (135,256) $ 338,835
Drilling and completion 103,583 (24,074) 79,509 51,769 (10,216) 41,553
Production facilities and equipment 38,198 (11,537) 26,661 16,397 (3,249) 13,148
HEAD OFFICE FURNITURE AND EQUIPMENT 4,238 (2,045) 2,193 3,199 (1,359) 1,840
- -----------------------------------------------------------------------------------------------------------------------
$ 1,754,454 $ (305,793) $ 1,448,661 $ 545,456 $ (150,080) $ 395,376
=======================================================================================================================
Unproved land costs of $55.7 million (2000 - $17.2 million) are excluded from
costs subject to depletion and depreciation.
PrimeWest capitalized $2.2 million of general and administrative costs in 2001
($0.9 million in 2000).
In accordance with stated accounting policies, PrimeWest has performed a ceiling
test using commodity prices as at the measurement date of December 31, 2001.
Using December 31, 2001 commodity prices of AECO $3.67 per Mcf for natural gas
and WTI $US 19.84 per barrel for crude oil, the ceiling test results in a
deficiency of $150 million.
PrimeWest is not required to account for any ceiling test impairment, that is
not permanent, within the first two years of the Cypress acquisition, therefore
no writedown is reflected in the 2001 financial statements.
4. CORPORATE ACQUISITIONS
a) 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, 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. The acquisition was accounted for using the purchase
method of accounting with net assets acquired and consideration paid as
follows:
NET ASSETS ACQUIRED AT ASSIGNED VALUES CONSIDERATION PAID
- ---------------------------------------------------------------------------------------------------------
Petroleum and natural gas assets $ 1,201,485
Working capital (deficit) assumed (19,174) Cash $ 59,235
Long-term debt assumed (179,000) Trust Units issued 489,815
Site restoration provision (4,307) Exchangeable shares issued 50,254
FUTURE INCOME TAXES (376,334) COSTS ASSOCIATED WITH ACQUISITION 23,366
$ 622,670 $ 622,670
b) On April 19, 2000, PrimeWest Resources Ltd. ("Resources") completed the
acquisition of all of the issued and outstanding shares of Venator
Petroleum Company Limited ("Venator") on a unit/share for share exchange.
Resources issued 0.657 Trust Units or 0.657 exchangeable shares for each
Venator share. In aggregate, 2.4 million Trust Units and 2.0 million
exchangeable shares were issued for total consideration, including debt
assumed, of $32.5 million. Subsequent to the transaction, the assets of
Venator were transferred to Resources and Venator was dissolved. The
acquisition was accounted for using the purchase method of accounting with
the purchase price allocated as follows:
NET ASSETS ACQUIRED AT ASSIGNED VALUES CONSIDERATION PAID
- ---------------------------------------------------------------------------------------------------------
Petroleum and natural gas assets $ 34,392 Trust Units issued $ 15,637
Working capital (deficit) assumed (2,323) Exchangeable shares issued 13,282
FUTURE INCOME TAXES (1,898) COSTS ASSOCIATED WITH ACQUISITION 1,252
$ 30,171 $ 30,171
c) On July 27, 2000, PrimeWest Royalty Corp. ("Royalty Corp.") completed the
acquisition of all of the issued and outstanding shares of Reserve Royalty
Corporation on a unit for share exchange. Royalty Corp. issued 0.65 Trust
Units for each Reserve Royalty share. In aggregate, 6.67 million Trust
Units were issued for total consideration, including debt assumed, of $84.0
million. Subsequent to the transaction, Reserve Royalty was amalgamated
into Royalty Corp. and the majority of its assets transferred to the Trust.
The acquisition was accounted for using the purchase method of accounting
with the purchase price allocated as follows:
NET ASSETS ACQUIRED AT ASSIGNED VALUES CONSIDERATION PAID
- ---------------------------------------------------------------------------------------------------------
Petroleum and natural gas assets $ 85,860
Working capital assumed 1,049
Long term debt assumed (28,210) Trust Units issued 53,947
FUTURE INCOME TAXES (1,921) COSTS ASSOCIATED WITH ACQUISITION 2,831
$ 56,778 $ 56,778
5. LONG-TERM DEBT
2001 2000
- --------------------------------------------------------------------------------
Revolving credit facility $ 195,000 $ 78,879
CAPITAL LEASE OBLIGATION - 61
195,000 78,940
CURRENT PORTION 67 106
$ 195,067 $ 79,046
PrimeWest and the Trust (as co-borrowers) have a combined revolving credit
facility in the amount of $350 million (2000 - $150 million), with a borrowing
base at December 31, 2001 of $350 million (2000 - $150 million). The facility
consists of a revolving term loan of $325 million and an operating facility of
$25 million. In addition to amounts outstanding under the facility as indicated
in the table above, PrimeWest has outstanding letters of credit in the amount of
$2.8 million (2000 - $4.3 million). Collateral for the credit facility is
provided by a floating-charge debenture covering all existing and after acquired
property in the principal amount of $500 million. Each borrower under the
facility has also provided an unconditional full liability guarantee in respect
of amounts borrowed under the facility.
Advances under the facility are made in the form of Banker's Acceptances (BAs),
prime rate loans or letters of credit. In the case of BA's, 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.
The credit facility revolves until May 31, 2002, by which time the lender will
have conducted its 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 extend the 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, the amounts outstanding under
the facility become repayable over a three-year period, on a unit of production
basis.
6. 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 and $0.32 per BOE
produced in 2001). The cash amount contributed, including interest earned, was
$4.2 million in 2001 (2000 - $3.0 million). Actual costs of site restoration and
abandonment totaling $3.8 million were paid out of this cash reserve for the
year ended December 31, 2001 (2000 - $3.6 million).
7. UNITHOLDERS' EQUITY
PRIMEWEST ENERGY TRUST
The authorized capital of the Trust consists of an unlimited number of Trust
Units ($000's).
Number of
Trust Units Units Amounts
=============================================================================================
BALANCE, DECEMBER 31, 1999 35,768,801 $ 311,049
Issued for cash 4,830,000 40,331
Issue expenses - (2,741)
Retired pursuant to Normal Course Issuer Bid (141,900) (926)
Issued to acquire Venator Petroleum Company Ltd. 2,368,936 15,637
Issued to acquire Reserve Royalty Corporation 6,660,082 53,947
Issued for payment of management fees 82,203 616
Issued on exchange of exchangeable shares 922,073 5,940
Issued pursuant to Distribution Reinvestment Plan 265,475 2,307
Issued pursuant to Long-term Incentive Plan 226,423 1,841
===============================================================================================
BALANCE, DECEMBER 31, 2000 50,982,093 $ 428,001
Issued for cash 19,790,000 $ 165,234
Issue expenses - (9,013)
Issued to acquire Cypress Energy Inc. 50,234,771 489,815
Issued for payment of management fees 199,841 1,635
Issued on exchange of exchangeable shares 2,415,363 20,298
Issued pursuant to Distribution Reinvestment Plan 1,765,699 14,128
Issued pursuant to Long-term Incentive Plan 577,840 5,155
===============================================================================================
BALANCE, DECEMBER 31, 2001 125,965,607 $ 1,115,253
The weighted average number of Trust Units and exchangeable shares outstanding
in 2001 was 102,533,000 (2000 - 44,651,600). For purposes of calculating diluted
net income per Trust Unit, 1,247,154 Trust Units (2000 - 998,065) 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 declared to Trust Units outstanding on the record dates.
PRIMEWEST OIL & GAS CORP.
In connection with the Cypress transaction (see note 4a), PrimeWest Oil & Gas
Corp. 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, 2003, 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, 2001 was 1.25020:1.
Number of
Exchangeable Shares Units Amounts
==============================================================================================
BALANCE, DECEMBER 31, 2000 - -
Issued to acquire Cypress Energy Inc. 5,154,225 $ 50,254
EXCHANGED FOR TRUST UNITS (1,837,483) (17,916)
- ----------------------------------------------------------------------------------------------
BALANCE, DECEMBER 31, 2001 3,316,742 $ 32,338
PRIMEWEST RESOURCES LTD.
In connection with the Venator transaction (see note 4b), PrimeWest Resources
Ltd. amended its articles to create an unlimited number of exchangeable shares.
The exchangeable shares are exchangeable into Trust Units at any time up to 5
years after issuance, based on an exchange ratio that adjusts each time
PrimeWest makes a distribution to its unitholders. In certain circumstances,
PrimeWest has the right to force redemption prior to the 5 year expiry term. Up
until April 30, 2001, dividends were paid to holders of exchangeable shares
based on the estimated taxable portion of the monthly distribution paid. The
exchange ratio, which was 1:1 on the closing date of the Venator transaction, is
based on the total monthly distribution paid less the dividend paid divided by
the closing Trust Unit price on the distribution payment date. After May 1, 2001
dividends were no longer paid. The exchange ratio at December 31, 2001 was
1.36806:1.
Number of
Exchangeable Shares Units Amounts
- ----------------------------------------------------------------------------------------------
BALANCE, DECEMBER 31, 1999 - -
Issued to acquire Venator Petroleum Company Ltd. 2,012,422 $ 13,282
EXCHANGED FOR TRUST UNITS (900,052) (5,940)
- ----------------------------------------------------------------------------------------------
BALANCE, DECEMBER 31, 2000 1,112,370 7,342
EXCHANGED FOR TRUST UNITS (360,838) (2,382)
- ----------------------------------------------------------------------------------------------
BALANCE, DECEMBER 31, 2001 751,532 $ 4,960
==============================================================================================
NORMAL COURSE ISSUER BID
On November 29, 1999, the Trust received approval from the Toronto Stock
Exchange to make a normal course issuer bid. During 2000, the Trust acquired
141,900 Trust Units pursuant to the bid at an average cost of $6.53 per Trust
Unit. This bid expired on November 29, 2000. On December 15, 2000, the Trust
received approval from the Toronto Stock Exchange to renew its bid for a further
one year period. During 2001, no purchases were made under the renewed bid. This
bid expired on December 15, 2001.
UNITS ISSUED FOR PAYMENT OF MANAGEMENT FEES
Trust Units are issued to the Manager as payment for management fees earned
throughout the year. During 2001, 239,471 Trust Units were earned by the
Manager. The Trust Units earned for the period October 1, 2001 to December 31,
2001 of 65,834 (2000 - 26,204) were issued from treasury on January 15, 2002.
The value of the units was $418,704 (2000 - $234,526).
TRUST UNITS AND EXCHANGEABLE SHARES ISSUED & OUTSTANDING 2001 2000
- --------------------------------------------------------------------------------------------------
Trust Units issued & outstanding 125,965,607 50,982,093
Exchangeable shares
PrimeWest Resources Ltd. (1)
(751,532 shares exchangeable at 1.36806, 1,028,141 1,216,154
2000 - 1,112,370 exchangeable at 1.0933)
PrimeWest Oil and Gas Corp. (1)
(3,316,742 SHARES EXCHANGEABLE AT 1.25020) 4,146,591 -
Total units and exchangeable shares issued & outstanding 131,140,339 52,198,247
- --------------------------------------------------------------------------------------------------
UNIT APPRECIATION RIGHTS 1,247,154 998,065
- --------------------------------------------------------------------------------------------------
Total units and exchangeable shares issued & outstanding - diluted 132,387,493 53,196,312
==================================================================================================
(1) AMALGAMATED WITH PRIMEWEST ENERGY INC. EFFECTIVE JANUARY 1, 2002
8. TRUST UNIT INCENTIVE PLAN
Under the terms of the Trust Unit Incentive Plan, a maximum of 2.49 million
Trust Units are reserved for issuance pursuant to the exercise of Unit
Appreciation Rights (UARs) granted to employees of the Manager. 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 6 years and vest equally over a 3-year period, except for
the independent 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.
Current
return per
UARs "in the Total Trust
AS AT DECEMBER 31, 2001 issued & UARs money" liability unit
YEAR OF GRANT OUTSTANDING VESTED UARS '000 DILUTION
1996 526,875 526,875 $ 3.96 $ 2,086 328,039
1997 319,354 319,354 3.44 1,098 172,658
1998 511,826 511,826 6.20 3,171 498,615
1999 593,662 358,266 3.69 1,323 208,101
2000 963,655 347,802 0.73 254 39,741
2001 2,517,374 100,847 - - -
TOTAL 5,432,746 2,164,970 $ 3.66 $ 7,932 1,247,154
AS AT DECEMBER 31, 2000
YEAR OF GRANT
1996 543,875 543,875 $ 5.24 $ 2,849 318,431
1997 377,806 377,806 4.55 1,718 192,042
1998 647,549 403,613 6.83 2,785 311,176
1999 1,014,418 296,096 5.30 1,482 165,637
2000 1,369,490 94,717 1.99 96 10,779
Total 3,953,138 1,716,107 $ 5.20 $ 8,930 998,065
Cumulative to December 31, 2001, 1,596,796 UARs have been exercised (2000 -
739,343), resulting in the issuance of 820,010 Trust Units from treasury (2000 -
242,170).
9. RELATED-PARTY TRANSACTIONS
The Manager of PrimeWest receives a management fee of 2.5% of net production
revenue as well as a quarterly allocation of Trust Units. For the year ended
December 31, 2001, the Manager received management fees of $8.3 million (2000 -
$4.0 million). Of this amount, $6.4 million was paid in cash (2000 - $3.3
million) and the balance represents the issuance of 239,471 Trust Units from
Treasury (2000 - 90,411).
In addition to the fees above, the Manager is entitled to an acquisition fee
representing 1.5% of capital spent on asset or corporate acquisitions and a
disposition fee representing 1.25% of proceeds received from asset dispositions.
Acquisition and disposition fees in the amount of $13.0 million were paid to the
Manager during 2001 (2000 - $1.7 million). These fees were included in capital
assets as part of the cost or net proceeds relating to oil and gas properties
acquired or disposed.
The Manager also is entitled to receive a 1% retained royalty based on the net
cash flow from operations and the proceeds from property dispositions. The
royalty is paid by a dividend from PrimeWest. The dividend was $3.4 million for
2001 (2000 - $0.8 million).
As at December 31, 2001, the Trust and PrimeWest owed $10.5 million (2000 - $2.1
million) to the Manager for unpaid management and other fees and reimbursement
of general and administrative costs.
10. INCOME TAXES
The Trust, and consequently the unitholders of the Trust, had taxable income
totaling $155.8 million for 2001 representing approximately 67.2% of
distributions paid in the year (2000 - $38.3 million representing 53%).
PrimeWest and its subsidiaries had no taxable income for 2001 and 2000, as
tax-pool deductions and the royalty payable were sufficient to reduce taxable
income in these entities to nil.
Effective January 1, 2000, the Company changed the method of accounting for
income taxes from the deferral method to the liability method. The new method
was applied retroactively without restatement of prior periods. The effect of
the change in accounting policy on the financial statements was to decrease
unitholders' equity by $10.2 million with a corresponding increase in the
provision for future income tax liabilities on the balance sheet. The effect on
the provision for income taxes for the current year as a result of this change
in accounting policy was to decrease future income tax expense/liability by
$30.3 million (2000 increase by$2.6 million). The future income tax provision
results from the carrying value of the capital assets exceeding the available
tax pools.
The future tax provision results from temporary differences in the recognition
of revenues and expenses for income taxes and accounting purposes as follows:
2001 2000
- -------------------------------------------------------------------------------------------------------------
Loss carry forwards $ (10,601) $ -
Capital assets 378,015 21,455
Site restoration provision (2,283) (874)
LONG TERM INCENTIVE LIABILITY (2,536) $ (3,985)
- ------------------------------------------------------------------------------------------------------------
$ 362,595 $ 16,596
============================================================================================================
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:
2000 2000
- ------------------------------------------------------------------------------------------------------------
NET INCOME BEFORE TAXES $ 51,630 $ 58,719
- ------------------------------------------------------------------------------------------------------------
Computed income tax expense at the
Canadian statutory rate of 43.12% (2000 - 44.62%) 22,263 26,200
Increase (decrease) resulting from:
Non-deductible crown royalties and other payments, net of ARTC 273 157
Federal resource allowance (9,729) (1,447)
AMOUNTS INCLUDED IN TRUST INCOME AND OTHER (43,141) (22,352)
- ------------------------------------------------------------------------------------------------------------
Future income taxes $ (30,334) $ 2,558
============================================================================================================
11. FINANCIAL INSTRUMENTS
a) COMMODITY PRICE RISK MANAGEMENT
PrimeWest generally sells its oil and gas under short-term market-based
contracts. Occasionally, 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 as well as the mark-to-market position at
December 31, 2001 follows:
CRUDE OIL
Mark-to-
Volume Price Market
PERIOD (BBL/D) TYPE ($US/BBL) GAIN (LOSS)
- -------------------------------------------------------------------------------------------------------------------
$ millions
January 2002 - June 2002 1,000 Swap $25.14 1.4
January 2002 - June 2002 1,000 Swap $25.50 1.5
January 2002 - December 2002 1,000 Swap $24.58 2.4
January 2002 - March 2002 2,000 Swap $27.37 2.1
April 2002 - June 2002 2,000 Swap $26.23 1.7
July 2002 - September 2002 2,000 Swap $25.22 1.3
October 2002 - December 2002 2,000 Swap $24.45 1.1
JANUARY 2002 - DECEMBER 2002 1,000 COLLAR $20.00 BY $25.15 -
- -------------------------------------------------------------------------------------------------------------------
Total 11.5
===================================================================================================================
NATURAL GAS
Volume Price Mark-to-
PERIOD MMCFD TYPE ($CDN./MCF) MARKET GAIN
- -------------------------------------------------------------------------------------------------------------------
$ millions
January 2002 - March 2002 4.7 Fixed price $7.88 1.9
January 2002 - March 2002 23.7 Swap $7.12 7.7
January 2002 - March 2002 23.7 Swap $7.12 7.7
April 2002 - October 2002 4.7 Fixed price $6.50 3.0
April 2002 - October 2002 19.0 Swap $5.28 7.0
April 2002 - October 2002 9.5 Swap $5.28 3.5
April 2002 - October 2002 19.0 Swap $5.28 7.0
November 2002 - March 2003 4.7 3 Way $3.17/$4.48 by $6.59 -
November 2002 - March 2003 4.7 Collar $4.22 by $5.96 -
January 2002 - October 2003 4.7 Fixed price $3.98 -
January 2002 - October 2003 4.7 Fixed price $4.17 0.5
April 2003 - October 2003 4.7 Fixed price $4.75 0.5
APRIL 2003 - OCTOBER 2003 4.7 3 WAY $3.17/$4.48 BY $6.26 0.2
- -------------------------------------------------------------------------------------------------------------------
Total 39.0
===================================================================================================================
In 2001, the financial impact of contracts settling in the year was an increase
in sales revenues of $39.5 million (2000 - $2.2 million decrease in sales
revenues).
b) INTEREST RATE RISK MANAGEMENT
During 2001, PrimeWest entered into two interest rate swaps, each on $25 million
of debt. The first is for a 2 year term, commencing December 4, 2001 and
expiring December 4, 2003 at a fixed BA rate of 3.21%. The second is for at 2
1/2 year term, commencing November 26, 2001 and expiring May 26, 2004 at a fixed
BA rate of 3.85%. The mark-to-market valuation of these swaps was a loss of $0.3
million as at December 31, 2001.
In connection with the acquisition of Reserve Royalty, PrimeWest assumed the
obligation under an interest rate swap on $25 million of debt fixed at a BA rate
of 6.48% until May, 2002. The counter-party has the option to extend the swap to
May 2004. The effect of this swap was an increase in interest paid for 2001 of
$0.4 million (2000 - increase of $.07 million). The fair market value of this
interest rate swap at December 31, 2001 was a loss of $1.8 million (2000 - loss
of $0.9 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, 2001 and 2000, 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,
because the cost of borrowing approximates the market rate for similar
borrowings.
12. COMMITMENTS AND CONTINGENCIES
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 $1.3 million in 2002, $1.5 million in 2003,
$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.
PrimeWest is engaged in a number of matters of litigation, none of which could
reasonably be expected to result in any material adverse consequence.
SUPPLEMENTARY INFORMATION
OPERATING HIGHLIGHTS
4 mos.
2001 2000 1999 1998 1997 1996
- ----------------------------------------------------------------------------------------------------------------------------
DAILY SALES VOLUMES
Crude oil (BARRELS PER DAY) 10,033 6,582 5,958 5,868 3,737 3,372
Natural gas liquids (BARRELS PER DAY) 2,273 1,483 1,293 1,226 1,137 993
Natural gas (MILLIONS OF CUBIC FEET PER DAY) 104.80 49.03 46.46 50.41 42.22 31.47
- ----------------------------------------------------------------------------------------------------------------------------
29,774 16,237 14,995 15,497 11,913 9,610
============================================================================================================================
AVERAGE SELLING PRICES
Crude oil (DOLLARS PER BARREL) $32.21 $36.67 $21.69 $16.92 $25.93 $30.93
Natural gas liquids (DOLLARS PER BARREL) $30.96 $34.42 $19.09 $14.55 $22.65 $23.87
Natural gas (DOLLARS PER THOUSAND CUBIC FEET) $6.16 $4.65 $2.51 $1.83 $1.85 $1.59
- ----------------------------------------------------------------------------------------------------------------------------
Total (DOLLARS PER BARREL OF OIL EQUIVALENT) $34.80 $32.19 $17.95 $13.58 $16.94 $18.64
============================================================================================================================
2001 2000 1999 1998 1997 1996
- ----------------------------------------------------------------------- ------------ -------------------------- ------------
ESTABLISHED RESERVES
Crude oil (MILLIONS OF BARRELS) 28.5 24.4 20.0 21.7 15.3 12.6
Natural gas liquids (MILLIONS OF BARRELS) 9.5 6.4 6.1 6.5 6.7 4.5
Natural gas (BILLIONS OF CUBIC FEET) 413.7 232.7 224.0 243.5 227.3 191.0
Total (MILLIONS OF BARRELS OF OIL EQUIVALENT) 107.0 69.6 63.7 68.8 59.9 48.9
============================================================================================================================
NET ASSET VALUE (MILLIONS OF DOLLARS, EXCEPT PER-TRUST-UNIT)
Established reserves (DISCOUNTED AT 10 PERCENT) 872.6 623.0 328.0 313.0 298.0 226.6
Hedging mark-to-market 39.7 (1.0) - - - -
Unproved lands 55.7 17.2 10.2 10.6 8.4 2.3
Other assets and working capital (29.7) 0.1 6.9 4.2 3.5 3.5
Long-term debt (195.0) (78.9) (92.2) (73.0) (66.7) (14.2)
- ----------------------------------------------------------------------------------------------------------------------------
Total net asset value 743.3 560.4 252.9 254.8 243.2 218.2
============================================================================================================================
Per trust unit $5.67 $10.73 $7.07 $7.72 $9.75 $8.76
============================================================================================================================
SUPPLEMENTARY INFORMATION
RESERVES
Natural JANUARY 1, JANUARY 1, January 1, January 1, January 1,
Crude Natural gas 2002 TOTAL 2001 TOTAL 2000 total 1999 total 1998 total
AS AT JANUARY 1, 2002 oil gas liquids RESERVES RESERVES reserves reserves reserves
(MBBL) (MMCF) (MBBL) (MBOE) (MBOE) (MBOE) (MBOE) (MBOE)
- ---------------------------------------------------------------------------------------------------------------------------
RESERVES SUMMARY
Proved producing 22,486 287,143 6,505 76,848 48,900 45,326 45,868 40,624
Total proved 24,719 349,305 7,830 90,766 57,149 50,963 54,068 47,549
Probable 7,651 128,807 3,432 32,551 24,855 25,350 29,607 24,588
Total proved and probable 32,370 478,112 11,262 123,317 82,004 76,313 83,675 72,138
Established 28,545 413,708 9,546 107,042 69,577 63,638 68,871 59,843
% of total established reserves 27% 64% 9%
===========================================================================================================================
Established
2001 2001 2000 1999 1998 1997
PROVED ESTABLISHED
PRODUCING OIL Oil Oil Oil Oil
OIL EQUIVALENT EQUIVALENT equivalent equivalent equivalent equivalent
(MMBOE) (MMBOE) (MMBOE) (MMBOE) (MMBOE) (MMBOE)
- ----------------------------------------------------------------------------------- ------------- ------------- ------------
RESERVE RECONCILIATION
Opening reserves 48.9 69.6 63.6 68.9 59.8 48.9
Capital additions 9.6 6.1 0.6 0.8 6.4 6.2
Technical revisions (2.0) (5.2) 1.5 (4.7) 0.6 1.7
Acquisitions 36.7 57.4 10.9 6.6 10.4 7.7
Dispositions (5.9) (10.4) (1.1) (2.6) (2.6) (0.3)
Production (10.5) (10.5) (5.9) (5.3) (5.7) (4.3)
- ----------------------------------------------------------------------------------------------------------------------------
Ending reserves 76.8 107.0 69.6 63.7 68.9 59.9
============================================================================================================================
2001 2000
- ----------------------------------------------------------------------------------------------------------------------------
Acres Net value Acres Net Value
GROSS NET ($) Gross Net ($)
- -------------------------------------------------------------------------------- -------------- ----------------------------
UNPROVED LANDS
Sundre 47,489 35,063 1,402,550 111,265 80,482 3,931,650
Brant Farrow 78,609 60,414 4,228,980 - - -
Dawson 261,608 166,229 14,129,465 - - -
Stowe Creek 199,697 187,872 15,969,120 - - -
Thorsby 56,931 49,011 3,430,770 - - -
Thunder 67,680 33,813 2,366,910 - - -
Southeastern Alberta 70,438 48,768 1,950,720 53,648 30,397 981,642
Crossfield/Lone Pine Creek 46,468 35,781 2,504,670 55,060 42,181 4,659,092
Boundary Lake 2,900 2,780 194,600 4,820 4,620 9,900
Gross Overriding Royalty Interests 244,961 244,961 3,674,415 243,797 243,797 3,678,909
Others 192,815 88,735 5,808,803 61,840 46,686 3,976,909
- ----------------------------------------------------------------------------------------------------------------------------
Total 1,269,596 953,427 55,661,003 530,430 448,163 17,238,102
============================================================================================================================
SUPPLEMENTARY INFORMATION
RESERVES
AS AT JANUARY 1, 2002 Established Proved Probable
- --------------------------------------------------------------------------------------------
CRUDE OIL RESERVES BY MAJOR PROPERTY (MBBL)
Southeastern Alberta (2) 7,158 6,168 1,980
Boundary Lake 6,488 6,035 906
Dawson 2,259 1,903 712
Royalties 1,864 1,481 766
Kaybob 1,354 1,180 348
Northwestern Alberta (3) 1,184 976 416
Eagle Lake Viking Vol. Unit 701 642 118
Crossfield/Lone Pine Creek 329 292 73
Other 7,208 6,042 2,332
- --------------------------------------------------------------------------------------------
Total 28,545 24,719 7,651
============================================================================================
NATURAL GAS (BCF)
Thorsby 91.5 82.5 18.0
Crossfield/Lone Pine Creek 49.0 39.1 19.8
Laprise Creek 39.0 34.2 9.6
Sundre (1) 37.8 26.7 22.2
Southeastern Alberta (2) 33.6 29.2 8.8
Northwestern Alberta (3) 30.9 26.4 9.0
Brant/Farrow (4) 25.4 20.4 10.0
Royalties 13.8 11.3 5.0
Dawson 13.1 10.9 4.4
Other 79.6 68.6 22.0
- --------------------------------------------------------------------------------------------
Total 413.7 349.3 128.8
============================================================================================
NATURAL GAS LIQUIDS (MBBL)
Thorsby 3,270 2,968 604
Sundre (1) 1,804 1,252 1,104
Laprise Creek 1,002 676 652
Crossfield/Lone Pine Creek 607 495 224
Southeastern Alberta (2) 80 70 19
Other 2,783 2,369 829
- --------------------------------------------------------------------------------------------
Total 9,546 7,830 3,432
============================================================================================
(1) INCLUDES CAROLINE & RICINUS
(2) INCLUDES GRAND FORKS, MEDICINE HAT, PATRICIA/DINOSAUR, ETZIKON &
ENCHANT
(3) INCLUDES NAYLOR HILLS, HOTCHKISS, STOWE
(4) INCLUDES MOSSLEIGH/HERRONTON
(5) INCLUDES EAGLE LAKE VIKING VOL. UNIT
SUPPLEMENTARY INFORMATION
RESERVES
Discounted Discounted Discounted Discounted
AS AT JANUARY 1, 2002 (THOUSANDS OF DOLLARS) @ 0% @ 10% @ 12% @ 15%
- --------------------------------------------------------------------------------------------------------------
PRESENT WORTH OF RESERVES
Proved producing 1,172,601 658,735 610,302 551,485
Total proved 1,378,620 767,038 708,749 637,879
Probable 568,551 211,087 185,074 155,347
Total proved and probable 1,947,171 978,125 893,823 793,226
Established value January 1, 2002 1,622,895 872,581 801,286 715,553
Established value January 1, 2001 1,108,498 623,543 576,839 520,312
Established value January 1, 2000 624,050 327,601 299,360 265,392
Established value January 1, 1999 606,073 312,844 284,298 249,876
Established value January 1, 1998 627,402 298,011 268,345 233,217
Established value January 1, 1997 479,200 226,600 204,100 177,500
==============================================================================================================
Edmonton Exchange
WTI Par Rate
AS AT JANUARY 1, 2002 ($US/BBL) ($CDN/BBL) ($US/$CDN)
- ------------------------------------------------------------------------------------------
CRUDE OIL PRICING ASSUMPTIONS
2002 19.97 30.30 0.6363
2003 20.85 31.10 0.6450
2004 21.31 31.39 0.6550
2005 21.55 31.25 0.6550
2006 21.87 31.45 0.6717
Next 12 years average 24.38 35.21 0.6717
Thereafter 1% esc. 1% esc. 0.6717
==========================================================================================
Alberta
Government
Henry Reference AECO Spot
Hub Price @ AECO-C
AS AT JANUARY 1, 2002 ($US/MBTU) ($CDN/MBTU) ($CDN/MBTU)
- ------------------------------------------------------------------------------------------
NATURAL GAS PRICING ASSUMPTIONS
2002 3.06 3.83 4.13
2003 3.35 4.20 4.52
2004 3.42 4.27 4.56
2005 3.45 4.31 4.55
2006 3.50 4.36 4.58
Next 12 years average 3.86 5.02 4.81
Thereafter 1% esc. 1% esc. 1% esc.
------------------ ------------------ ------------------
2001 2000 1999 1998 1997 1996
- ---------------------------------------------------------------------------------------------
ESTABLISHED RESERVE LIFE INDEX (YEARS) 10.0 10.2 10.9 11.1 12.2 11.1
=============================================================================================
SUPPLEMENTARY INFORMATION
DAILY PRODUCTION VOLUMES BY MAJOR PROPERTY
2001 2000 1999 1998 1997
- ----------------------------------------------------------------------------------------------------------------------------
NATURAL GAS Thorsby 18,938 - - - -
(MCF PER DAY) Sundre (1) 13,226 12,041 13,512 11,252 11,746
Dawson 11,032 - - - -
Crossfield/Lone Pine Creek 10,173 12,157 12,775 14,416 12,708
Northwestern Alberta (3) 9,354 - - - -
Laprise Creek 9,006 9,294 9,797 11,521 10,492
Brant/Farrow 6,666 - - - -
Southeastern Alberta (2) 6,400 6,320 4,413 3,797 -
Royalties 4,122 - - - -
Other areas 15,885 9,220 5,961 9,423 7,275
- ----------------------------------------------------------------------------------------------------------------------------
Total 104,802 49,032 46,458 50,409 42,221
============================================================================================================================
CRUDE OIL Southeastern Alberta (2) 3,240 3,061 2,821 2,329 -
(BBL PER DAY) Boundary Lake 1,131 818 745 753 789
Royalties 858 - - - -
Sundre (1) 647 747 885 1,074 895
Dawson 597 - - - -
Northwestern Alberta (3) 348 - - - -
Brant/Farrow 170 - - - -
Thorsby 165 - - - -
Crossfield/Lone Pine Creek 79 100 94 80 71
Laprise Creek 27 25 27 37 32
Other areas 2,771 1,831 1,386 1,595 1,950
- ----------------------------------------------------------------------------------------------------------------------------
Total 10,033 6,582 5,958 5,868 3,737
============================================================================================================================
NATURAL GAS LIQUIDS Thorsby 623 - - - -
(BBL PER DAY) Sundre (1) 590 654 711 581 609
Crossfield/Lone Pine Creek 238 223 192 163 154
Laprise Creek 183 169 164 154 120
Royalties 94 - - - -
Southeastern Alberta (2) 29 31 13 8 -
Brant/Farrow 25 - - - -
Northwestern Alberta 11 - - - -
Boundary Lake 4 4 - 5 4
Other areas 476 402 213 315 250
- ----------------------------------------------------------------------------------------------------------------------------
Total 2,273 1,483 1,293 1,226 1,137
============================================================================================================================
TOTAL EQUIVALENT Southeastern Alberta (2) 4,336 4,145 3,570 2,970 -
(BOE PER DDAY) Thorsby 3,944 - - - -
Sundre (1) 3,441 3,408 3,848 3,530 3,462
Dawson 2,436 - - - -
Crossfield/Lone Pine Creek 2,013 2,349 2,415 2,646 2,343
Northwestern Alberta (3) 1,918
Laprise Creek 1,711 1,743 1,824 2,112 1,901
Royalties 1,639 - - - -
Brant/Farrow 1,306
Boundary Lake 1,139 822 765 798 804
Other areas 5,891 3,770 2,573 3,441 3,403
- ----------------------------------------------------------------------------------------------------------------------------
Total 29,774 16,237 14,995 15,497 11,913
============================================================================================================================
(1) includes Garrington, Caroline, West Ward Ho & Ricinus
(2) includes Grand Forks, Medicine Hat, Patricia/Dinosaur, Etzikom &
Enchant
(3) includes Stowe, Hotchkiss, Naylor
SUPPLEMENTARY INFORMATION
QUARTERLY PRODUCTION VOLUMES BY COMMODITY
4 mos.
2001 2000 1999 1998 1997 1996
- -------------------------------------------------------------------------------------------------------------------------
CRUDE OIL (BARRELS PER DAY)
First quarter 6,988 5,763 6,154 4,780 3,680 -
Second quarter 11,453 6,038 5,805 6,206 3,843 -
Third quarter 11,216 7,087 5,957 6,264 3,646 -
Fourth quarter 10,425 7,422 5,919 6,201 3,778 -
- -------------------------------------------------------------------------------------------------------------------------
Total average 10,033 6,582 5,958 5,868 3,737 3,372
=========================================================================================================================
NATURAL GAS LIQUIDS (BARRELS PER DAY)
First quarter 1,613 1,264 1,342 1,278 1,045 -
Second quarter 2,614 1,537 1,277 1,254 948 -
Third quarter 2,414 1,521 1,193 1,185 1,416 -
Fourth quarter 2,441 1,610 1,360 1,188 1,134 -
- -------------------------------------------------------------------------------------------------------------------------
Total average 2,273 1,483 1,293 1,226 1,137 993
=========================================================================================================================
NATURAL GAS (MMCF PER DAY)
First quarter 49.58 48.13 48.91 49.18 40.25 -
Second quarter 127.72 48.39 47.34 54.00 36.24 -
Third quarter 121.32 52.10 41.27 49.95 43.31 -
Fourth quarter 119.65 47.49 48.40 48.51 48.97 -
- -------------------------------------------------------------------------------------------------------------------------
Total average 104.80 49.03 46.50 50.41 42.22 31.47
=========================================================================================================================
TOTAL OIL EQUIVALENT (BOE PER DAY)
First quarter 16,864 15,044 15,648 14,255 11,433 -
Second quarter 35,353 15,642 14,972 16,460 10,831 -
Third quarter 33,849 17,291 14,028 15,774 12,280 -
Fourth quarter 32,807 16,949 15,346 15,474 13,073 -
- -------------------------------------------------------------------------------------------------------------------------
Total average 29,774 16,237 14,995 15,497 11,913 9,610
=========================================================================================================================
Natural gas as a percentage of production 59% 50% 52% 54% 59% 54%
=========================================================================================================================
AVERAGE SELLING PRICES
Crude oil ($/BBL) 32.21 36.67 21.69 16.92 25.93 30.93
Natural gas liquids ($/BBL) 30.96 34.42 19.09 14.55 22.65 23.87
Natural gas ($/MCF) 6.16 4.65 2.51 1.83 1.85 1.59
Combined ($/BOE) 34.80 32.19 17.95 13.58 16.94 18.64
=========================================================================================================================
OPERATING NETBACKS (DOLLARS PER BOE)
Revenue 34.80 32.19 17.95 13.58 16.94 18.64
Other revenue 0.14 0.08 0.04 0.05 0.04 -
Royalties (6.73) (5.92) (3.14) (2.28) (3.27) (3.25)
Operating expenses (5.42) (5.08) (5.23) (5.40) (4.89) (4.45)
- -------------------------------------------------------------------------------------------------------------------------
Operating netback 22.79 21,27 9.62 5.95 8.82 10.94
=========================================================================================================================
SUPPLEMENTARY INFORMATION
FINANCIAL HIGHLIGHTS
(THOUSANDS OF DOLLARS, EXCEPT PER-BOE AND 4 mos.
PER TRUST UNIT AMOUNTS) 2001 2000 1999 1998 1997 1996
- ----------------------------------------------------------------------------------------------------------------------------
Cash flow from operations 214,511 112,062 41,081 24,806 32,086 11,608
per BOE 19.74 18.91 7.51 4.39 7.38 9.90
per Trust Unit 2.09 2.51 1.21 0.79 1.29 0.46
Operating revenues, net of royalties 106,515 156,561 81,282 64,257 59,592 18,043
per BOE 28.20 26.42 14.85 11.36 13.71 15.39
per Trust Unit 2.99 3.51 2.39 2.04 2.39 2.17
Operating expenses 58,951 30,175 28,609 30,550 21,270 5,218
per BOE 5.42 5.09 5.23 5.40 4.89 4.45
per Trust Unit 0.57 0.68 0.84 0.97 0.85 0.63
Cash G&A expenses 10,394 4,140 5,321 5,108 3,708 787
per BOE 0.96 0.70 0.97 0.90 0.85 0.67
per Trust Unit 0.10 0.09 0.16 0.16 0.15 0.09
Cash management fees 6,431 3,277 1,386 882 923 335
per BOE 0.59 0.55 0.25 0.16 0.21 0.28
per Trust Unit 0.06 0.07 0.04 0.03 0.04 0.04
Interest expense 13,800 6,359 4,885 4,711 2,140 95
per BOE 1.27 1.07 0.89 0.83 0.49 0.08
per Trust Unit 0.13 0.14 0.14 0.15 0.09 0.01
Operating netback 247,564 126,386 52,673 33,707 38,322 12,825
per BOE 22.79 21.33 9.62 5.95 8.82 10.94
per Trust Unit 2.41 2.83 1.55 1.07 1.54 1.54
Cash distributed to unitholders 234,465 79,033 37,351 25,769 33,409 10,956
per Trust Unit 2.31 1.77 1.10 0.82 1.34 0.44
============================================================================================================================
SUPPLEMENTARY INFORMATION
FINANCIAL HIGHLIGHTS
4 mos.
(THOUSANDS OF DOLLARS, EXCEPT UNIT AND 2001 2000 1999 1998 1997 1996
PER-UNIT)
- ----------------------------------------------------------------------------------------------------------------------------
Cumulative cash distributions 420,983 186,518 107,485 70,134 44,365 10,956
Per Trust Unit 7.78 5.47 3.70 2.60 1.78 0.44
Units outstanding at year-end 125,966 50,982 35,769 33,023 24,950 24,900
Exchangeable shares outstanding 4,068 1,112 - - - -
Capital expenditures, net of dispositions 828,358 143,592 32,910 65,192 49,724 242,623
Working capital (deficit) (30,446) (254) 5,850 2,369 1,845 1,308
Reclamation fund balance 755 398 1,060 1,781 1,738 2,223
Total assets 1,516,081 434,238 320,210 316,140 285,765 254,480
Net asset value 743,300 561,400 252,900 254,800 243,200 218,200
Net asset value per Trust Unit 5.67 10.55 7.07 7.72 9.75 8.76
Total capitalization (including debt) 1,059,519 546,380 323,718 237,403 276,953 294,290
============================================================================================================================
DEBT ANALYSIS
Long-term debt, net of working capital 225,466 79,208 85,854 70,637 64,878 12,920
Debt-to-annual-cash flow ratio 1.05 0.71 2.10 2.85 2.02 0.37
Debt-to-equity ratio 26.6% 27.3% 46.1% 34.2% 34.5% 6.4%
Interest-coverage ratio 16.5 18.6 8.5 6.0 15.5 115.6
Average cost of debt 5.6% 7.4% 5.9% 6.3% 4.8% 3.8%
Net debt per Trust Unit 1.72 1.52 2.41 2.14 2.60 0.52
============================================================================================================================
TAX POOLS (CONSOLIDATED)
Canadian oil and gas property expense (COGPE) 424,000 299,000 255,000 263,400 225,600 221,800
Canadian exploration expense (CEE) 23,700 5,700 - 1,850 300 -
Canadian development expense (CDE) 11,100 9,000 - - 7,200 -
Capital cost allowance (CCA) 101,200 35,850 24,425 32,330 25,000 13,600
Losses available for carry forward 24,800 - - - - -
Unit issue expenses 12,171 6,245 8,300 14,600 11,900 15,100
============================================================================================================================
SUPPLEMENTARY INFORMATION
TRADING PERFORMANCE
TRUST UNIT TRADING PERFORMANCE
FIRST SECOND THIRD FOURTH
QUARTER QUARTER QUARTER QUARTER
2001 2001 2001 2001 2001 2000 1999 1998 1997 1996
- ---------------------------------------- --------- --------- ---------- --------- --------- -------- --------- --------- ---------
Trust unit price: High 9.90 10.54 8.77 7.51 10.54 $9.30 $7.70 $8.75 $11.45 $12.15
Low 8.72 8.45 6.42 5.95 5.95 $6.30 $4.75 $4.75 $7.50 $11.20
Close 9.00 8.85 6.46 6.36 6.36 $8.95 $6.65 $5.05 $8.50 $11.30
Average daily volume traded 338,084 959,063 608,209 596,623 624,488 121,256 49,767 55,318 42,323 273,763
===================================================================================================================================
MARKET INDICATORS
FIRST SECOND THIRD FOURTH
QUARTER QUARTER QUARTER QUARTER
2001 2001 2001 2001 2001 2000 1999 1998 1997 1996
- ---------------------------------------------- --------- --------- --------- -------- -------- --------- ------- ------- --------
WTI ($US PER BARREL) 28.72 27.96 26.76 20.43 25.97 30.20 19.24 14.43 20.61 22.01
Monthly AECO Spot ($CDN/MCF) 10.91 7.08 3.92 3.30 6.30 5.02 2.96 2.07 1.88 1.39
Exchange rate ($US/$CDN) 0.65 0.65 0.64 0.63 0.65 0.67 0.67 0.67 0.72 0.73
Closing prices
Government of Canada 10-year bond 5.40% 5.90% 5.34% 5.36% 5.35% 5.40% 6.26% 4.91% 5.62% 6.41%
yield
TSE 300 Index 7,608 7,736 6,838 7,688 7,688 8,934 8,414 6,486 6,699 5,927
TSE Oil and Gas Producers Index 7,525 7,505 6,834 7,467 7,467 7,271 4,976 4,074 5,869 6,577
==================================================================================================================================
DISTRIBUTION HISTORY
(DOLLARS PER TRUST UNIT) 2001 2000 1999 1998 1997 1996
- ---------------------------------------------------- ------------- ------------ ------------ ------------- ------------
First quarter 0.60 0.30 0.18 0.24 0.35 -
Second quarter 0.66 0.39 0.23 0.22 0.30 -
Third quarter 0.61 0.48 0.34 0.18 0.30 -
Fourth quarter 0.44 0.60 0.35 0.18 0.39 0.441
- -----------------------------------------------------------------------------------------------------------------------
Total 2.31 $1.77 $1.10 $0.82 $1.34 $0.44
- -----------------------------------------------------------------------------------------------------------------------
% Tax deferred 33% 47% 100% 100% 100% 100%
=======================================================================================================================
PRIMEWEST ENERGY TRUST
CORPORATE GOVERNANCE
STATEMENT The Board of Directors and the management team of
PrimeWest are committed to a high standard of
corporate governance. Effective corporate governance
requires specified reporting structures and business
processes, a strategic plan, and a commitment to work
according to these. We believe that sound corporate
governance contributes to unitholder value and to
trust and confidence in PrimeWest.
The Board of Directors of PrimeWest Energy Inc. is
ultimately responsible under law for the stewardship
of PrimeWest Energy Inc., including the business
affairs of PrimeWest Energy Trust. To help execute
this mandate, the Board has two standing committees,
each consisting of only independent directors. These
are the Audit Committee (which also functions as the
Reserves Committee) and the Corporate Governance and
Compensation Committee (which also functions as the
Environmental, Health and Safety Committee).
The Toronto Stock Exchange has published guidelines
for effective corporate governance, guidelines that
represent a minimum standard for PrimeWest. These are
set out below along with a notation as to PrimeWest's
conformity to them.
TSE CORPORATE GOVERNANCE GUIDELINES
DOES PRIMEWEST CONFORM 1. The Board of directors should explicitly assume
TO THE GUIDELINES? responsibility for the stewardship of the
company, specifically:
YES (A) ADOPTING A STRATEGIC PLANNING PROCESS
The Board receives presentations from management
with respect to the long-term direction of the
trust, strategic priorities and performance. The
Board reviews and analyses these presentations
to ensure that there is congruence among
strategic plans, performance and unitholder
expectations.
(B) IDENTIFYING PRINCIPAL RISKS AND ENSURING THE
IMPLEMENTATION OF SYSTEMS TO MANAGE THESE RISKS
YES The Board and management are well versed in the
principal risks associated with operating
PrimeWest. Management updates the Board
regularly about the corporate processes for
managing risks related to commodity prices and
differentials, production levels and trends, and
compliance with environment, health and safety
legislation and regulations.
(C) PLANNING FOR SUCCESSION, INCLUDING THE
APPOINTMENT, TRAINING AND MONITORING OF SENIOR
MANAGEMENT
YES The Corporate Governance and Compensation
Committee oversees PrimeWest'scompensation
programs, practices and the performance of
senior management. The Board also ensures that
adequate provisions have been made for senior
management training and succession.
(D) ASSUMING RESPONSIBILITY FOR A CORPORATE
COMMUNICATIONS POLICY
YES The Audit Committee reviews all operating and
financial results prior to public disclosure. In
addition, the Board has adopted written policies
governing communications, disclosure and insider
trading. These policies are responsive to
securities laws and guidelines issued by The
Toronto Stock Exchange and the Canadian Investor
Relations Institute.
(E) ASSUMING RESPONSIBILITY FOR THE INTEGRITY OF
INTERNAL CONTROL AND MANAGEMENT SYSTEMS
YES The Audit Committee oversees PrimeWest's
financial reporting processes, the systems for
internal control, the audit process, and the
management of risk.
2. The majority of the Board should be unrelated
(independent of management, free from conflict
of interest).
YES PrimeWest's Board of Directors currently
consists of five individuals, the majority of
whom are unrelated. There are four independent
directors and one management
director.
3. Disclose whether or not each director is
unrelated and explain.
Barry E. Emes Unrelated Non-management
Harold N. Kvisle Unrelated Non-management
Michael W. O'Brien Unrelated Non-management
Kent J. MacIntyre Related Management
Harold P. Milavsky Unrelated Non-management
4. The Board should appoint a committee of
independent directors to nominate new directors
and assess all directors' performance.
The Board has created Corporate Governance and
PARTIALLY Compensation Committee, consisting only of
unrelated directors, whose mandate is to carry
out this responsibility. Procedures for
assessing directors' performance are currently
being formulated and will be completed in 2002.
5. The Board should implement a process for
assessing the effectiveness of the Board as a
whole, the committees of the Board, and
individual directors.
PARTIALLY The Corporate Governance and Compensation
Committee has this responsibility and is
currently reviewing formal procedures in this
respect.
6. Every corporation should provide an orientation
and education program for new PARTIALLY recruits
to the Board.
YES In 2000, a new, unrelated director was appointed
to the Board. During the recruitment process and
following, he was briefed thoroughly about
PrimeWest and the oil and gas royalty trust
sector.
7. Every board should examine its size and, with a
view to effectiveness, consider YES reducing the
size to improve decision-making.
YES The Board has examined its size, and considers
that its current number is appropriate at this
time.
8. The Board should review directors' compensation
to ensure that it adequately reflects
responsibilities and risks.
YES The Corporate Governance and Compensation
Committee carries out this responsibility
annually.
9. Committees of the Board generally should be
composed of independent directors with the
majority being unrelated.
YES The two committees of the PrimeWest Board are
composed solely of independent and unrelated
directors.
10. Every board should expressly assume
responsibility for, or assign to a committee,
the responsibility for developing the company's
approach to corporate governance
issues.
YES The Corporate Governance and Compensation
Committee focuses on corporate governance and
ensures that PrimeWest's corporate governance
system is effective.
11. The Board, together with the CEO, should:
(A) DEVELOP POSITION DESCRIPTIONS FOR THE BOARD
AND FOR THE CEO, SETTING OUT LIMITS TO
MANAGEMENT'S RESPONSIBILITIES
YES The Corporate Governance and Compensation
Committee has established clear sets of
responsibilities for the Board as a whole and
for its committees. It has also done this for
the Vice-chairman and CEO, with defined limits
to his responsibilities. The Vice-chairman and
CEO delegates responsibility to senior officers
of PrimeWest, who have written descriptions of
their objectives.
(B)APPROVE OR DEVELOP THE CORPORATE OBJECTIVES
FOR THE BOARD AND FOR THE CEO
YES The full Board reviews and approves annual
strategic and operating and financial
objectives; management prepares these, and the
Vice-chairman and CEO is accountable for them.
12. Every board should have structures and
procedures to ensure that it can function
independently of management.
YES The Chairman of the Board is an unrelated
director and independent of management. YES Any
member of the Board may call a meeting to be
held without management present. Members of the
Audit Committee, which also functions as the
Reserves Committee, meet directly with the
Company's auditors and independent reserves
engineering firm, in part without management
present. The independent directors meet in
camera at the end of each meeting.
13. All boards should have an Audit Committee,
consisting only of non-management YES directors,
which has a clearly defined mandate and
appropriate oversight.
YES The Audit Committee consists only of unrelated
directors and has direct access to external
auditors. The Committee reviews financial
reporting processes of PrimeWest, its systems of
internal controls, and the audit process. The
Committee also reviews the annual reserves
engineering report and all operating and
financial results before disclosure.
14. The Board should enable an individual director
to engage an outside advisor in appropriate
circumstances, at the expense of the company.
YES In circumstances considered to be appropriate by
the Corporate Governance and YES Compensation
Committee, an individual director may engage an
outside advisor at company expense.
THE SAUCIER REPORT - BEYOND COMPLIANCE,
BUILDING A GOVERNANCE CULTURE
The Joint Committee on Corporate Governance (TSE, CDNX, CICA) delivered its
final report in November of 2001. The report contains 15 recommendations for
improved corporate governance. Among the recommendations, the following three
are most often identified as critical to successful governance practices:
ITEM PRIMEWEST COMPLIANCE
- ------------------------------------- -----------------------------------------
1. Independent board leader. Board chairman that is independent and
unrelated.
2. Board involvement in strategic See 1(a) above.
planning.
3. Complete disclosure of governance See 1 to 14 above.
system.
ENVIRONMENTAL, HEALTH AND SAFETY
ENVIRONMENT
PrimeWest believes that attaining a high standard of environmental stewardship
is a key component of our business objectives. To achieve these high standards,
PrimeWest focuses on the following components:
ENVIRONMENTAL COMPLIANCE
o Ensure complete compliance with environmental legislation and regulations;
o Develop and adhere to a company-specific system to manage environmental
activities; and
o Provide adequate training and support on environmental related matters to
field operations personnel
During 2001, PrimeWest conducted an inventory of all of its aboveground and
underground storage tanks to meet the guidelines as set out by the EUB Guide
G-55.
ENVIRONMENTAL LIABILITY
o Reduce long term environmental liabilities through timely decommissioning,
abandonment and reclamation of well leases and facilities;
o Monitor environmental liabilities through regular inspections;
o Respond to field and facility situations promptly to mitigate environmental
impacts; and
o Support new environmental research that has application to PrimeWest's
operations.
During 2001, PrimeWest continued an active lease reclamation program. Of the 700
leases identified for reclamation, 160 leases were addressed. PrimeWest received
24 reclamation certificates and 17 applications are pending.
EMISSIONS AND WASTE REDUCTION
o Increase electrical and fuel-gas efficiency at PrimeWest facilities;
o Reduce greenhouse gas emissions and flaring; and
o Minimize waste products by reducing, recycling and recovering
PrimeWest received Gold Medal standing from the federal Voluntary Challenge
Registry for its 2000 report sub-mission. This Registry is a means of promoting,
assessing and recognizing the effectiveness of the voluntary approach in
addressing climate change. PrimeWest's report received 93 points out of a
possible 100.
STAKEHOLDER RELATIONSHIPS
o Work to build long term relationships with environmental stakeholders and
community groups; and
o Respond promptly to landowner and community concerns
During 2001, PrimeWest amended its Emergency Response Plans to address its
contingency responsibilities in its major operating areas including Crossfield/
Lone Pine Creek, Meekwap, Kaybob and Enchant.
HEALTH AND SAFETY
PrimeWest is committed to safety in the workplace and ensuring that the health
of its employees and the surrounding communities is protected. It is a condition
of employment that PrimeWest personnel work safely and in accordance with
established regulations and procedures. The Occupational Health and Safety Group
within PrimeWest implements policy, provides training and conducts audits to
ensure that established policies are rigidly adhered to.
During 2001, PrimeWest implemented a comprehensive health and safety training
program for its employees and contractors. The training program will be provided
over a one-week period with elements including Work-place Hazardous Materials,
Transportation of Dangerous Goods, Gas Testing Safety, Industrial Fire Fighting,
Defensive Driving, Respiratory Protection, Accident/ Incident Reporting and
Standard First Aid/CPR.
INCOME TAX CONSIDERATIONS
One of the most frequently asked questions from our unitholders is "How are the
monthly distributions that I received treated for tax?" Distributions paid to
the Trust are both a return of capital (i.e. a repayment of a portion of your
investment) and a return on capital (i.e. income). The allocation depends on the
tax deductions that the Trust is entitled to claim against income it earns from
royalty income it receives from PrimeWest and income it earns directly. These
tax deductions are primarily COGPE (Canadian Oil and Gas Property Expenses) -
the cost of acquiring the royalty from the operating companies or the Trust's
direct investment in revenue producing property.
Each year, the return on capital, or taxable income portion, is calculated and
reported in the Trust's T3 return and allocated to each unitholder who received
distributions in that taxation year on the T3 supplementary forms which are
mailed out in late February or early March. The T3 slip will report only the
other income component in box 26. This income is taxed in the same manner as
interest expense.
The following is a summary of the split between other income and return of
capital since the Trust's inception:
PAYMENT DISTRIBUTION OTHER RETURN OF
RECORD DATE DATE AMOUNT INCOME CAPITAL
- -----------------------------------------------------------------------------------------------
31-Dec-96 to 30-Nov-97 15-Jan-97 to 15-Dec-97 1.39 - 1.39000
31-Dec-97 to 30-Nov-98 15-Jan-98 to 15-Dec-98 1.15 - 1.15000
31-Dec-98 to 30-Nov-99 15-Jan-99 to 15-Dec-99 1.06 - 1.06000
31-Dec-99 15-Jan-00 0.10 0.05300 0.04700
31-Jan-00 15-Feb-00 0.10 0.05300 0.04700
29-Feb-00 15-Mar-00 0.10 0.05300 0.04700
31-Mar-00 15-Apr-00 0.10 0.05300 0.04700
30-Apr-00 15-May-00 0.10 0.05300 0.04700
31-May-00 15-Jun-00 0.13 0.06890 0.06110
30-Jun-00 15-Jul-00 0.16 0.08480 0.07520
31-Jul-00 15-Aug-00 0.16 0.08480 0.07520
31-Aug-00 15-Sep-00 0.16 0.08480 0.07520
30-Sep-00 15-Oct-00 0.16 0.08480 0.07520
31-Oct-00 15-Nov-00 0.20 0.10600 0.09400
30-Nov-00 15-Dec-00 0.20 0.10600 0.09400
30-Dec-00 15-Jan-01 0.20 0.13430 0.06569
31-Jan-01 15-Feb-01 0.20 0.13430 0.06569
28-Feb-01 15-Mar-01 0.20 0.13430 0.06569
31-Mar-01 15-Apr-01 0.20 0.13430 0.06569
30-Apr-01 15-May-01 0.22 0.14774 0.07226
31-May-01 15-Jun-01 0.22 0.14774 0.07226
30-Jun-01 15-Jul-01 0.22 0.14774 0.07226
31-Jul-01 15-Aug-01 0.22 0.14774 0.07226
31-Aug-01 15-Sep-01 0.22 0.14774 0.07226
30-Sep-01 15-Oct-01 0.17 0.11416 0.05584
31-Oct-01 15-Nov-01 0.17 0.11416 0.05584
30-Nov-01 15-Dec-01 0.17 0.11416 0.05584
DISTRIBUTION REINVESTMENT AND
OPTIONAL TRUST UNIT PURCHASE PLANS
The Distribution Reinvestment Plan (commonly referred to as the DRIP) and our
Optional Trust Unit Purchase Plan provide our Canadian unitholders with an
economical, convenient way to maximize their investment in PrimeWest.
Participants do not pay any costs associated with these plans, including
brokerage commissions.
Since 1998, these plans have enabled unitholders to reinvest their monthly
distributions automatically and make additional annual investments of between
$100 and $100,000 - without incurring brokerage fees and with a 5% discount off
the 20-day weighted average market price at the time. To view the 5% discounted
unit prices by month, please refer to our DRIP section of the PrimeWest Web site
at WWW.PRIMEWESTENERGY.COM.
Some banks, trust companies or brokerage firms will allow participation in
PrimeWest's DRIP and others will not. You will need to make enquiries directly
with your account holder. If you cannot participate as a non-registered holder,
you must either transfer your units to hold them directly or transfer them to an
account that allows participation.
If you are a Canadian resident and a registered unitholder (you have a Trust
Unit certificate), you may fill out forms `Part A' and `Part B' located in the
DRIP section of the PrimeWest Web site at WWW.PRIMEWESTENERGY.COM.
For further information, contact Computershare Trust Company of Canada - by
phone toll-free phone (1-800-332-0095) or fax (403-982-766). You may also
contact PrimeWest Investor Relations - by phone (403-234-6600), toll-free phone
in Canada and the continental United States (1-877-968-7878), fax (403-699-7271)
or e-mail investor@primewestenergy.com).
GLOSSARY
AECO: refers to a pricing point for gas produced in Western Canada located at a
gas storage facility adjacent to the TransCanada mainline near the
Alberta-Saskatchewan border.
BARREL OF OIL EQUIVALENT (BOE): Natural gas production is converted using six
thousand cubic feet of gas for one barrel of oil, with this number added to the
actual number of barrels of crude oil and natural gas liquids on an average day
to derive the barrels of oil equivalent produced per day.
CASH DISTRIBUTION DATE: the date Distributable Income is paid to Unitholders,
currently being the 15th day of the month following any record date.
DECLARATION OF TRUST: refers to the declaration of trust dated August 2, 1996
among the Trustee, PrimeWest, and the Initial Unitholder (as therein defined),
as amended from time to time.
DISTRIBUTABLE INCOME: refers to the 99% of Royalty Income together with any
income earned by the Trust from Permitted short term investments plus any ARTC,
less Crown royalties and other Crown charges that are not deductible by
PrimeWest for income tax purposes and that are reimbursed by the Trust to
PrimeWest less general and administrative expense of the Trust.
ESTABLISHED RESERVES: indicates all proved and one half of probable reserves.
EX-DISTRIBUTION DATE: the holder of units purchased prior to the ex-distribution
date is entitled to the declared distribution paid on the 15th of the next
month. Ex-distribution date is 2 business days prior to the record date.
GENERAL AND ADMINISTRATIVE COSTS: refers to the aggregate representing all
expenditures and costs incurred under the Management Agreement in respect of
PrimeWest, the Trust or the Royalty or in management and administration of
PrimeWest, the Trust or the Royalty other than Management Fees.
MANAGEMENT FEE: refers to the fees payable to the Manager pursuant to the
Management Agreement. The Manager is PrimeWest Management Inc.
PEERS: include ARC Energy Trust, Enerplus Resources Fund and Pengrowth Energy
Trust.
RECORD DATE: means the last day in each month.
RESERVE LIFE INDEX: is the time span in years derived by dividing the quantity
of reserves by the total production of oil, natural gas, and natural gas liquids
during calendar year 2001.
ROYALTY: refers to the payment of monies by PrimeWest to the Trust pursuant to
the Royalty Agreement, which royalty equals 99% of Royalty Income.
TRUSTEE: refers to ComputerShare Trust Company of Canada, or its successor as
trustee of the Trust.
WEST TEXAS INTERMEDIATE (WTI): a high quality grade of crude oil produced in
West Texas whose price is most commonly used as a benchmark for crude oil
pricing internationally.
ABBREVIATIONS
bbls barrels
Mbbls one thousand barrels
MMbbls one million barrels
bblsper day barrels per day
Mcf one thousand cubic feet
MMcf one million cubic feet
Mcf per day one thousand cubic feet per day
Bcf one billion cubic feet
m3 one thousand cubic meters
BOE barrels of oil equivalent
BOE per day barrels of oil equivalent per day
MMBOE millions of barrels of oil equivalent
CONVERSION FACTORS:
1 cubic meter (liquids) = 6.29 barrels
1 cubic meter (natural gas) = 35.49 cubic feet
1 litre = 0.22 imperial gallon
1 hectare = 2.47
acres 1 cubic meter = 1000 litres
BIOGRAPHIES
INDEPENDENT DIRECTORS
BARRY E. EMES, LL.B.
INDEPENDENT DIRECTOR
Mr. Emes is a partner in the corporate/commercial group of the Calgary office of
Stikeman Elliott and a member of the firm's Partnership Board. In his practice,
he has counseled borrowers and lenders in financings; sellers and purchasers of
shares and other assets; and independent committees and financial advisors with
respect to corporate acquisitions.
HAROLD N. KVISLE, P. ENG.
INDEPENDENT DIRECTOR
Mr. Kvisle is President, Chief Executive Officer and a Director of TransCanada
PipeLines Limited, and he acts as a director of several companies and limited
partnerships within the TransCanada group. Mr. Kvisle also is a director of
Norske Skog Canada Limited. Mr. Kvisle was formerly president of Fletcher
Challenge Petroleum.
HAROLD P. MILAVSKY, FCA
CHAIRMAN, INDEPENDENT DIRECTOR
Mr. Milavsky is Chairman of Quantico Capital Corp., a privately held company
engaged in merchant banking, principal investments and acquisitions. Mr.
Milavsky serves as a director of Aspen Properties Ltd., various investment
trusts comprising the Citadel Group of Funds, ENMAX Corporation and Torode
Realty Limited. Mr. Milavsky was formerly Chief Executive Officer of Trizec
Corporation, and a director of TransCanada PipeLines Limited, Telus Corporation
Inc., Northrock Resources Ltd., Encal Energy Ltd. and Wascana Energy Inc.
MICHAEL W. O'BRIEN
INDEPENDENT DIRECTOR
Mr. O'Brien is a 35-year veteran of the petroleum business and currently is the
Executive Vice-president, Corporate Development and Chief Financial Officer of
Suncor Energy Inc. He serves, among other responsibilities, as the current Chair
of Canada's Climate Change Voluntary Challenge and Registry Inc. (VCR Inc.) and
also Chair of the Nature Conservancy of Canada.
BIOGRAPHIES
SENIOR OFFICERS
KENT MACINTYRE
VICE-CHAIRMAN AND CHIEF EXECUTIVE OFFICER, DIRECTOR
Mr. MacIntyre has over 22 years of oil and gas experience, the last 13 as a
principal in the start-up and management of oil and gas ventures. Prior to
establishing PrimeWest, he was President and CEO of Triad Energy Inc., and
before that, President and CEO of Olympia Energy Ventures Ltd. He is a director
of BlackRock Ventures Inc., Capture Energy Ltd., GLR Solutions Ltd. and various
investment trusts comprising the Citadel Group of Funds. Mr. MacIntyre holds a
B.Sc. (Engineering) degree from the University of Manitoba and an MBA from the
University of Calgary.
DON GARNER
PRESIDENT AND CHIEF OPERATING OFFICER
Mr. Garner has over 20 years experience in the oil and gas industry, most
recently as President and Chief Operating Officer of Northstar Energy
Corporation. He spent a good portion of his career at Imperial Oil Limited in
various capacities, including executive responsibility for the Oil Sands
Business Unit and as a director of Syncrude Canada Limited. An engineering
graduate of the University of Saskatchewan, Mr. Garner has undertaken
postgraduate studies through the Wharton School, The American Graduate School of
International Management and University of Calgary.
RON AMBROZY, P.ENG.
VICE-PRESIDENT, BUSINESS DEVELOPMENT
Mr. Ambrozy has been active in the oil and gas industry since 1975, initially
holding progressively more responsible positions with Gulf Canada. During the
last 13 years of his career, he has led the evaluation of properties and
completion of transactions worth more than $2 billion. Mr. Ambrozy joined
PrimeWest in 1997. For the last four years Mr. Ambrozy has been actively
involved with the Petroleum Acquisition and Divestment Association (PADA) and
currently is still co-chairman of PADA.
DENNIS FEUCHUK, CMA
VICE-PRESIDENT, FINANCE AND CHIEF FINANCIAL OFFICER
Mr. Feuchuk has spent over 26 years in the oil and gas industry in various
financial and accounting capacities. Prior to joining PrimeWest in October 2001,
Mr. Feuchuk was Vice President and Controller for Gulf Canada Resources Limited
and Vice President and Treasurer for Athabasca Oil Sands Trust.
TIM GRANGER, P.ENG.
VICE-PRESIDENT, OPERATIONS AND DEVELOPMENT
Mr. Granger is a graduate of Carleton University's Engineering program, and has
more than 22 years of oil and gas experience in drilling, production operations
and property development. Before taking a leadership role at PrimeWest in June
1999, Mr. Granger headed the Canadian operations of a company based in the
United States.
BILL ROWE, C.A.
VICE-PRESIDENT, PLANNING AND INVESTOR RELATIONS
Mr. Rowe is Past Chairman of the Canadian Investor Relations Institute (CIRI)
and the 2000 winner of CIRI's Award of Excellence and a Past Director of the
Washington, D.C. based National Investor Relations Institute (NIRI). Prior to
joining PrimeWest in December 2001, Mr. Rowe was Vice President, Investor
Relations for NOVA Chemicals Corporation. Prior to joining NOVA, Mr. Rowe was
engaged in the practice of auditing and consulting with Ernst & Young. Mr. Rowe
is a graduate of McMaster University, Bachelor of Commerce.
PRIMEWEST ENERGY TRUST
CORPORATE INFORMATION
BOARD OF DIRECTORS
Harold P. Milavsky1
CHAIRMAN
QUANTICO CAPITAL CORP.
Kent J. MacIntyre2
VICE-CHAIRMAN AND
CHIEF EXECUTIVE OFFICER
PRIMEWEST ENERGY INC.
Barry E. Emes1
PARTNER
STIKEMAN ELLIOTT
Harold N. Kvisle1
PRESIDENT AND
CHIEF EXECUTIVE OFFICER
TRANSCANADA PIPELINES LIMITED
Michael W. O'Brien1
EXECUTIVE VICE-PRESIDENT,
CORPORATE DEVELOPMENT AND
CHIEF FINANCIAL OFFICER
SUNCOR ENERGY INC.
1 MEMBER OF THE AUDIT
COMMITTEE AND THE CORPORATE
GOVERNANCE AND COMPENSATION
COMMITTEE
2 NOMINEE OF THE MANAGER
OFFICERS
Harold P. Milavsky
CHAIRMAN
Kent J. MacIntyre
VICE-CHAIRMAN AND
CHIEF EXECUTIVE OFFICER
Donald A. Garner
PRESIDENT AND
CHIEF OPERATING OFFICER
Ronald J. Ambrozy
VICE-PRESIDENT,
BUSINESS DEVELOPMENT
James T. Bruvall
SECRETARY
Dennis G. Feuchuk
VICE-PRESIDENT, FINANCE AND
CHIEF FINANCIAL OFFICER
Timothy S. Granger
VICE-PRESIDENT, PRODUCTION
William N. Rowe
VICE-PRESIDENT, INVESTOR
RELATIONS AND PLANNING
HEAD OFFICE
4700, 150 - 6 Avenue SW
Calgary, AB Canada T2P 3Y7
Telephone: 403-234-6600
Fax: 403-266-2825
Toll-free in Canada:
1-877-968-7878
WEB SITE:
WWW.PRIMEWESTENERGY.COM
TRUST UNITS AND
EXCHANGEABLE SHARES
TRADED
The Toronto Stock Exchange,
(PWI.UN; PWX)
REGISTRAR AND
TRANSFER AGENT
Computershare Trust
Company of Canada
Toll-free in Canada:
1-800-332-0095
AUDITOR
PricewaterhouseCoopers LLP,
Calgary
ENGINEERING CONSULTANTS
Gilbert Laustsen Jung Associates
Ltd., Calgary
LEGAL COUNSEL
Stikeman Elliott
FOR MORE INFORMATION
General inquiries
403-234-6600
Investor Relations
Toll-free:
1-877-968-7878
Fax: 403-699-7271
e-mail:
investor@primewestenergy.com