EXHIBIT 3
---------
WE ARE
DELIVERING
STABILITY,
PREDICTABILITY
AND
SUSTAINABLE GROWTH
2000 REPORT TO OUR UNITHOLDERS
PrimeWest Energy Trust
WE ARE
NOW
CANADA'S
LARGEST
GAS-WEIGHTED
ROYALTY TRUST
PrimeWest/
Cypress combined
PrimeWest as at as at
Dec. 31, 2000 Dec. 31, 2000
Gas Reserves (as a % of total) 56% 66%
Gas Production (as a % of total) 50% 60%
Total Enterprise Value ($ millions) $546 $1,000+
BEGINNING WITH THIS ANNUAL REPORT, WE ARE USING A 6:1 RATIO FOR CONVERTING
NATURAL GAS (MCF) TO BARRELS OF OIL EQUIVALENT (BOE) FOR CURRENT AND PRIOR
PERIODS, ONE THAT WILL BE A REGULATORY REQUIREMENT IN 2002 AND ONE THAT BETTER
REFLECTS THE ECONOMIC VALUE OF THE COMMODITY. IN PRIOR YEARS, PRIMEWEST HAS
REPORTED ITS RESULTS USING A 10:1 RATIO.
Message to Unitholders
5
Strategic Results
9
Management's Discussion and Analysis
17
Financial Statements
29
Supplemental Information
43
Corporate Governance
52
GAS CONVERSION NOTE
Beginning with this annual report, we are using a 6:1 ratio for converting
natural gas (Mcf) to barrels of oil equivalent (BOE) for current and prior
periods, one that will be a regulatory requirement in 2002 and one that better
reflects the economic value of the commodity. In prior years, PrimeWest has
reported its results using a 10:1 ratio.
ANNUAL MEETING
Annual Meeting - The Annual General and Special Meeting of Unitholders is
scheduled for Tuesday, June 5, 2001, beginning at 3:00 p.m. at the Metropolitan
Centre in Calgary.
WHY INVEST IN PRIMEWEST?
We are one of Canada's largest conventional oil and gas royalty trusts. We
manage PrimeWest carefully for the ongoing benefit of our unitholders, and in
doing so are guided by the operating principle of responsible stewardship.
Our main objective is to deliver stable, predictable and sustainable cash
distributions monthly, within the context of a commodity-based business
environment.
Our total monthly distribution of $0.22 per trust unit consists of both regular
and special components. The regular distribution is 10 cents per trust unit and
is sustainable based on normalized, or `mid-cycle', commodity prices. The
special monthly rate -- 12 cents beginning with the May 2001 payment -- has
reflected our performance in an escalating commodity price environment.
Over the last three years we have outperformed the Toronto Stock Exchange's Oil
and Gas Producers Index and the TSE 300. An investment in PrimeWest has provided
a high cash-on-cash yield, an attractive rate of return and a favourable tax
structure. Last year, 47% of the distribution paid was considered a tax-deferred
return of capital.
PrimeWest has quadrupled in size since inception over four years ago. We have
improved our capabilities and discipline. And, we are excited by the prospect of
delivering incremental growth, prosperity and value to investors in the future.
Our model for SUCCESS
ASSETS
Quality reserves and infrastructure. Oil and gas production provides cash flow.
TACTICS
Adjusted to reflect the business environment.
STRATEGIES
Four core strategies, coupled with strong corporate governance.
GOALS
Top-quartile total return (unit price plus cumulative distributions) on a
rolling three-year basis. Distributions that are stable, predictable and
sustainable within the context of a cyclical underlying commodity.
VISION
To be recognized by our investors and employees as the best energy trust company
as measured by:
o being the investment and employer of choice within the energy trust sector;
o being a leader in the industry, and;
o maintaining a positive corporate culture and image.
VALUE TO UNITHOLDERS
Tax-effective distributions paid monthly.
THE LATEST STEP FORWARD IN GROWTH
In March 2001, PrimeWest Energy Trust successfully acquired Cypress Energy Inc.,
and in so doing vaulted into the large-cap tier of the royalty trust sector. Not
only are we now a much larger and more liquid investment, we are differentiated
from our top-tier peers through our weighting toward natural gas. Unitholders
are already benefitting: beginning in May, monthly distributions rose 10%, to
$0.22 per trust unit, a rate we expect to be able to pay at least through
January 2002.
- ----------------------------------------------------------------------------------------------------------------------------
STRATEGY 2000 OBJECTIVES 2000 PERFORMANCE 2001 OBJECTIVES
- ----------------------------------------------------------------------------------------------------------------------------
Financial Prudence o Maintain a prudent debt level o Year-beginning net debt was o Maintain debt at a level
1 considering the position in $2.41 per trust unit. Year-end appropriate to permit
the commodity price cycle. net debt was $1.52 per trust acquisitions, to fund the
o Maintain a prudent unit - down 37%. capital program and/or to
distribution policy. o Distribution payout ratio was withstand lower commodity
o Fund future liabilities in a 70.5% versus 91% in 1999. An prices.
way that is fair to current undistributed reserve, $0.56 o Maintain a responsible
and future unitholders. per trust unit, reduced debt. distribution payout ratio to
o Contributed $0.24 per
produced backstop the
current special BOE to
the reclamation fund -
distribution rate and
maintain up over
previous years and a
prudent capital
structure. higher than
the sector average. A
special contribution of
$1.5 million was made
in Q3.
- ----------------------------------------------------------------------------------------------------------------------------
RISK MANAGEMENT o Increase the stability and o Used hedging to help protect o Layer in hedging instruments
2 predictability of the $0.10-per-trust-unit as required to backstop the
distributions. regular and special regular and special
distribution rates over the distribution rates.
long-term. Gradually increased o Maintain $0.22-per-trust-unit
the special distribution rate, total distribution payment for
from $0.03, to $0.06, to $0.10 as long as feasible.
per trust unit. o Continue to offer advance
o Provided guidance to
our guidance to
investors about
investors about our
changes to the level of
the expectations for
distribution special
distribution rate.
payments.
o Sought and acquired
high-netback reserves
to reduce distribution
volatility.
- ----------------------------------------------------------------------------------------------------------------------------
OPERATING o Temper natural production o Initiated 94 separate o Maintain diversified approach.
EXCELLENCE declines through a low-risk, projects, which delivered Invest $37 million in
3 well diversified development 1,135 BOE per day of new diversified projects.
program. production. Lowered finding o Capitalize on production
o Minimize cost structures. and development costs. optimization and development
o Held 2000 base production opportunities arising from
(not including 2000 acquired new acquisitions, including
volumes) to 97% of the 1999 Cypress.
year-end level, substantially o Maintain 2001 base production
arresting natural production to within 95% of the 2000
decline rates. year-end level.
o Reduced 2000 operating o Despite increases in power
and G&A costs per BOE by costs, continue to reduce
3% and 28% respectively. operating costs on a per-BOE
basis.
- ----------------------------------------------------------------------------------------------------------------------------
ASSET GROWTH o Improve cash flow quality by o The percentage of proved o Continue to closely evaluate
4 enhancing netbacks. producing reserves to total asset attributes of
o Improve the reserve quality, established reserves was 70%, acquisition targets to improve
considering reserve life index compared with 63% at IPO. the percentage of proved
and the percentage of proved o Acquisitions added 9.8 million producing reserves and to
reserves. BOE of established reserves. increase average netbacks
o Increase the size and o Established Reserve Life Index (profit margins).
diversity of our asset base declined from 10.9 to 10.2 o Significantly increase the
and replenish development years. size of the Trust and
opportunities. o Net asset value increased 49% unitholder liquidity.
o Maximize net asset value per to $10.55 per trust unit. o Review asset base to
unit. high-grade assets and identify
potential disposition
candidates.
- ----------------------------------------------------------------------------------------------------------------------------
JANUARY 2000
o Became operator of Crossfield gas plant; initiated programs for cost
efficiency and throughput growth.
APRIL
o Acquired Venator Petroleum Company Limited for $32 million.
MAY
o Initiated a special distribution, of $0.03 per trust unit per month.
o Introduced 5% discount on purchases within the Distribution Reinvestment
and Optional Trust Unit Purchase plans.
o Appointed Michael O'Brien to the Board as the fourth independent director.
JUNE
o Increased the special distribution to $0.06 per trust unit per month.
JULY
o Acquired Reserve Royalty Corporation for $84 million.
SEPTEMBER
o Closed a $40.3-million equity financing.
o Increased the special distribution to $0.10 per trust unit per month, with
expected payments from November through April 2001.
NOVEMBER
o Held successful investor information sessions in various Canadian centres.
DECEMBER
o Received approval from The Toronto Stock Exchange for trust unit buy-back
program.
OPERATING & FINANCIAL
HIGHLIGHTS
OPERATING HIGHLIGHTS
2000 1999 Change
Daily sales volumes
Crude oil (barrels) 6,582 5,958 10%
Natural gas liquids (barrels) 1,483 1,293 15%
Natural gas (millions of cubic feet) 49.03 46.46 5%
Total (barrels of oil equivalent) 16,237 14,995 8%
Average selling prices
Crude oil (dollars per barrel) 36.67 21.69 69%
Natural gas liquids (dollars per barrel) 34.42 19.09 80%
Natural gas (dollars per thousand cubic feet) 4.65 2.51 85%
Total (dollars per barrel of oil equivalent) 32.19 17.95 79%
Established reserves
Crude oil (millions of barrels) 24.4 20.1 22%
Natural gas liquids (millions of barrels) 6.4 6.2 3%
Natural gas (billions of cubic feet) 232.7 224.5 4%
Total (millions of barrels of oil equivalent) 69.6 63.7 9%
Net asset value
(millions of dollars, except per-trust-unit amounts)
Established reserves (discounted at 10%) 623.0 328.0 90%
Unproved lands 17.2 10.2 69%
Other assets 0.1 6.9 (100%)
Long-term debt (78.9) (92.2) (14%)
Total net asset value 558.4 252.9 121%
Per trust unit 10.55 7.07 49%
Cumulative distributions declared per trust unit 5.47 3.70 48%
FINANCIAL HIGHLIGHTS
(thousands of dollars except per-BOE and per-trust-unit amounts) 2000 1999 Change
Operating revenues, net of royalties 156,561 81,282 93%
Operating expenses 30,175 28,609 5%
Cash G&A expenses 4,140 5,321 (22%)
Cash management fees 3,277 1,386 136%
Financing costs 6,359 4,885 30%
Cash flow from operations 112,062 41,081 173%
Cash distributed to unitholders 79,033 37,351 112%
Operating netback 126,386 52,673 140%
Capital expenditures net of property dispositions 143,592 32,910 336%
Net debt (long-term debt net of working capital) 79,208 85,854 (8%)
Debt-to-annual-current-cash-flow ratio 0.71 2.10 (66%)
Weighted average trust units outstanding 44,652 33,965 32%
Units outstanding at year-end 50,982 35,769 43%
WE CONTINUE TO
GROW
THROUGH
STRATEGIC
ACQUISITIONS
MESSAGE TO UNITHOLDERS
It would be easy to be complacent about our 2000 results. They are, by far, the
best we've ever recorded. For example, cash flow from operations in the fourth
quarter alone exceeded cash flow in all of 1998.
The year 2000 was an exceptionally good one for the two commodities that
underlie your investment. Prices for both crude oil and natural gas were at
ten-year highs. Strong prices conferred a great deal of success upon us and
others in the industry.
Having said this, we don't think that high commodity prices should overshadow
what our employees delivered last year. And, we think it is important to spell
out just how materially they have improved prospects for the future.
We enhanced production, reserves and profit margins through the acquisitions of
Venator Petroleum Company Limited and Reserve Royalty Corporation. We brought
down cost structures and debt levels. And, we became positioned to initiate an
extraordinary transformation in early 2001, through the acquisition of Cypress
Energy Inc.
AN EXTRAORDINARY TRANSFORMATION
With the Cypress acquisition, PrimeWest has become the largest gas-weighted
royalty trust in Canada. We are one of only four trusts with enterprise values
of more than a billion dollars. More to the point, we are the only large-cap
trust with a majority of its assets in natural gas.
The Cypress transaction will improve the liquidity of your investment. It will
make it easier in the future for us to access capital at a lower cost. And, this
in turn will increase our competitiveness in delivering value-added growth.
The accretiveness of the Cypress acquisition enables PrimeWest to deliver an
immediate and tangible benefit to unitholders. Distribution payments increased
10% beginning in May -- from 20 to 22 cents per trust unit per month.
Backstopped by our commodity risk-management program, we expect to pay at this
level at least through January 2002, which will make 2001 another record year.
EXCEPTIONAL ASSET QUALITY
To be sure, assets are the main drivers of value for unitholders. Reserves drive
production, which drives cash flow, which drives distributions. Since inception,
we have worked steadily to assemble what is now an exceptional array of
high-quality producing and prospective properties. Our netback (profit margin)
is now the sector's best.
PrimeWest's reserves -- including the newly acquired Cypress assets -- are split
66% natural gas and 34% crude oil and liquids. On a production basis, we are 60%
natural gas and 40% crude oil and liquids. Reserve life index with Cypress?
About 9.4 years -- below the sector average, but something we can build with our
larger inventory of development opportunities.
Without doubt, assets are important. But, consider also the people of PrimeWest.
THE PEOPLE AND THE VALUE THEY CREATE FOR YOU
The people of PrimeWest work everyday to maximize your distributions, while at
the same time preserve the value of your underlying asset base. They do it by
being committed and staying focussed. And, they do it by following four
strategies:
o FINANCIAL PRUDENCE - FOR THE PRESENT AND FUTURE
o RISK MANAGEMENT - TO HELP PROTECT YOUR INVESTMENT
o OPERATING EXCELLENCE - TO CONTROL COSTS AND create asset value
o ASSET GROWTH - TO HELP SUSTAIN DISTRIBUTIONS
The work of the people of PrimeWest, at head office and in the field, has now
distinguished this Trust from all others. Their performance in 2001 and beyond
will drive growth and prosperity for many years to come. We have matured as an
organization. We welcome Michael O'Brien, Executive Vice-president, Corporate
Development and Chief Financial Officer of Suncor Energy Inc., as our fourth
independent director. Additional talent has been added from Cypress.
So, what have the people of PrimeWest done for you lately? Well, in 2000:
o RECORD per-trust-unit DISTRIBUTIONS of $1.77 DECLARED ON RECORD CASH FLOW
of $2.51.
o RECORD TOTAL RETURN OF 68%, TOP-QUARTILE FOR THE SECTOR.
o MORE STABLE AND PREDICTABLE DISTRIBUTIONS, BACKSTOPPED BY COMMODITY
RISK-MANAGEMENT INSTRUMENTS.
o TWO ACQUISITIONS, INCREASing Daily PRODUCTION more than 20%.
o TOTAL PRODUCTION UP TO A DAILY AVERAGE OF 16,237 BOE PER DAY.
o IMPROVED FINANCIAL FLEXIBILITY THROUGH REDUCED DEBT.
o CONTINUED REDUCTION OF OPERATING and G&A COSTS.
And, since our inception to December 31, 2000, we generated cash flow available
for distribution of $6.26 per trust unit, which exceeds the expectations we set
forth at the time of our initial public offering by 38%.
A UNIQUE BASIS FOR PROSPERITY
Where does this powerful combination of assets and people take PrimeWest and
your investment? Let's review the strengths:
o A BILLION-DOLLAR MARKET CAP, AND THE INCREASED LIQUIDITY THIS BRINGS.
o AN OPPOSITE WEIGHTING TOWARDS NATURAL GAS COMPARED WITH OUR PEERS, AND THE
MARKET FAVOUR THAT comes FROM IT.
o AN EXPANDING TRACK RECORD OF RESULTS BUILT WITH CARE AND DISCIPLINE, AND
THE CONFIDENCE THIS INDUCES.
o A SUITE OF UNTAPPED EXPLORATION AND DEVELOPMENT OPPORTUNITIES ON MORE THAN
ONE MILLION ACRES OF LANDS, AND THE UPSIDE THEY PROMISE.
o A TEAM OF VETERAN PERFORMERS IN ALL THE NECESSARY DISCIPLINES, AND THE
VALUE THEY ADD.
These are compelling attributes. They position us for one-of-a-kind prosperity
in the royalty trust sector. They align with your interests: stable, predictable
and sustainable distributions. And, they bring truth to the promise of growth.
The year 2001 should be a watershed for the royalty trusts, PrimeWest in
particular. In outperforming the Oil and Gas Producers Index by a handsome
margin over the past few years, the trusts have been rewarded with a preferred
cost of capital. The sector is poised for significant growth, in part because of
the tax-effectiveness of the trust structure and the maturity of the Western
Canada Sedimentary Basin, which offers a deep inventory of acquisition
opportunities. Some observers suggest that the trusts will become the new
intermediate class of producers in the Canadian industry. We agree. And, we
consider PrimeWest to be superbly positioned to compete successfully as a
consolidator of assets and harvester of full economic value from oil and gas
reserves.
We are justifiably proud of how far we have come in a few short years and of the
reasons for our progress. A strategic plan. Extremely valuable underlying
assets. A fervent attitude of professionalism and determination. Smart people
working hard.
These have led to stability, predictability and sustainable growth. And, they
have provided a unique foundation for future prosperity.
Thank you for your continued support.
April 10, 2001
HAROLD P. MILAVSKY
Chairman
KENT J. MACINTYRE
Vice-chairman and Chief Executive Officer
WE BUILT
FLEXIBILITY
AND
FINANCIAL
STRENGTH
FINANCIAL PRUDENCE
FOR THE
PRESENT AND FUTURE
There are two main thrusts to our financial prudence strategy -- managing our
capital structure well and providing for the future. Both are equally important.
We manage our capital structure -- debt and equity -- to give us financial
flexibility near-term. We also set aside funds for future obligations, like
distributions in times of low commodity prices and the proper abandonment and
reclamation of facilities and sites.
2000 result -- We posted a 173% year-over-year increase in our cash flow -- $112
million or $2.51 per trust unit -- a record for the Trust. Of this cash flow, we
distributed $79 million or $1.77 per trust unit, representing a payout ratio of
70.5%.
2000 result -- We increased total monthly distributions to a record level -- 20
cents per trust unit. In graduated steps, we added supplementary monthly
payments onto the regular monthly distribution rate of 10 cents per trust unit,
as commodity prices improved. These were backstopped by our risk management
program.
2000 result -- We reduced net debt to $79 million, down from $86 million a year
ago. By year-end, our debt-to-cash-flow ratio was down to 0.7 times. This gave
us extraordinary financial flexibility -- either for an acquisition or for
weathering a possible downturn in commodity prices.
2000 result -- We raised $40.3 million by issuing 4.83 million trust units on a
bought-deal basis.
2000 result -- We contributed nearly $3 million to our site reclamation and
restoration fund. Our contribution rate was much greater than in 1999 -- a
conservative approach we consider to be among the most prudent in the royalty
trust sector.
WE USE
PRUDENT
MEASURES TO HELP
SAFEGUARD
DISTRIBUTIONS
2001
% of production hedged (net of royalties) 1st quarter 2nd quarter 3rd quarter 4th quarter
(pre-Cypress)
Natural gas - Fixed price 6% 15% 15% 7%
- Insured* 38% 34% 28% 30%
Crude oil - Fixed price 0% 45% 45% 45%
- Insured* 58% 51% 51% 51%
* PROVIDES DOWNSIDE PROTECTION AND PERMITS SUBSTANTIVE PARTICIPATION IN UPSIDE
RISK MANAGEMENT
TO HELP
PROTECT YOUR INVESTMENT
Commodity prices are the largest determinants of distribution rates and
volatility. Our risk-management strategies aim to reduce these effects, so we
can deliver distributions with an element of stability and predictability. Not
every trust does this; we believe it is what most of our unitholders want.
Our aim is not to speculate on future commodity price performance. Rather, our
objectives are to:
o support the distribution rate expectations that we set forth to the market;
o lock in transaction economics associated with material acquisitions; and
o protect our capital structure should commodity prices cycle downwards.
We use a variety of hedging structures, many of which are `option'- or
`put'-based. These have the advantage of mitigating downside exposure while
providing substantial upside participation in commodity prices. In essence, they
provide a form of insurance.
We have a Commodity Risk Management Committee. It manages risks related to
commodities, interest rates, foreign exchange and credit through established
policies that require periodic reporting to the Board.
We also manage the composition of our asset portfolio to reduce distribution
risk. Crude oil and natural gas prices rise and fall on different cycles that
don't necessarily coincide. Our relatively balanced mix can provide a `natural'
hedge. And, our Gross Overriding Royalty interests enhance our high netback.
They give more support to distributions when commodity prices decline.
WE
BALANCE
LOWERING COSTS
WITH
ENHANCING
ASSET VALUE
OPERATING EXCELLENCE
TO CREATE VALUE BY
ASSET DEVELOPMENT AND
COST CONTROL
As operator of 75% of our production, we actively manage our asset portfolio.
Our operating excellence strategy is focussed on creating value through asset
enhancement. Our aim is to increase value through prudent development and the
management of our cost structures. We are also guided by environmental and
safety imperatives.
We use a portfolio approach to property development, with a well-diversified
suite of risk-adjusted projects. These include in-fill and step-out drilling,
waterflood optimization, work-overs and the use of new technologies.
2000 result -- We reduced operating costs per BOE by 3% to an average of $5.08.
Savings came from capacity and efficiency gains made as operator of the
Crossfield gas plant.
2000 result -- We tempered natural decline rates in our base production. Capital
development and technical revisions, excluding acquisitions, replaced 35% of
annual production. Base production was held to 97% of the 1999 level.
2000 result -- On a full-year basis, some 94 separate development projects
delivered 1,135 BOE per day of new production. 2000 capital expenditures were
focussed in Grand Forks, Crossfield and Boundary Lake with a 90% drilling
success rate. Development activities were successful in improving our asset
quality through the conversion of probable reserves to proven. In total 3.9
MMBOE of proven reserves were added at a cost of $5.75/BOE.
2000
Established Property
Reserves Production Cash Flow(3) Main products produced
(Thousands (Thousands
of BOE) (BOE/d) of dollars) Oil/NGLs Gas
Sundre(1) 15,472 3,408 24,782 41% 59%
Southeastern Alberta(2) 13,573 4,145 33,428 75% 25%
Crossfield/Lone Pine Creek 9,132 2,349 14,461 14% 86%
Laprise Creek 8,714 1,743 14,034 12% 88%
Boundary Lake 5,286 822 7,117 100% 0%
Kaybob South 1,945 721 5,801 94% 6%
Other properties 15,455 3,049 29,226 58% 42%
TOTAL 69,577 16,237 128,849
(1) Includes Garrington, Caroline, Westward Ho and Ricinus properties
(2) Includes Grand Forks, Medicine Hat, Patricia/Dinosaur and Enchant
properties
(3) Excludes hedging, G&A, interest and management fees
WE
INCREASED
RESERVES
AND
PRODUCTION
ASSET GROWTH
TO HELP
SUSTAIN DISTRIBUTIONS
The continued growth of PrimeWest is an absolute must. We are focussed and
disciplined in our drive to increase the size, diversity and quality of our
asset base.
Growth increases the liquidity of our trust units; this reduces our cost of
capital and enhances our access to capital. These are key ingredients for adding
unitholder value and sustaining distributions over the long term.
In evaluating acquisition opportunities we consider an array of criteria:
o We look for companies or properties with high netbacks (profit margins) to
help make our future cash flows more stable and predictable.
o We also look for companies or properties that will strengthen our existing
reserve base or replenish our development opportunity portfolio for future
low-cost reserve additions.
Our aim is to sustain distributions.
2000 result -- We focussed on acquiring undervalued junior oil and gas
companies. The Venator transaction brought us a high-quality suite of properties
with several development opportunities that we began to exploit with success,
increasing production by more than 10%.
2000 result -- The Reserve Royalty assets were mainly a well-diversified suite
of gross overriding royalties (GORRs).
A GORR is entitlement to a percentage of a well's gross revenue -- without
obligation to pay any operating costs or lessor royalties. Very good assets.
Our GORR interests represented our largest single asset. They complement the
rest of our portfolio, which is mainly high-percentage working interests. The
GORRs on the undeveloped lands have begun to generate incremental production and
reserve additions without risk or cost to us.
MANAGEMENT'S
DISCUSSION AND ANALYSIS
YEAR ENDED DECEMBER 31, 2000
COMPARED WITH YEAR ENDED
DECEMBER 31, 1999
THE FOLLOWING DISCUSSION IS MANAGEMENT'S OPINION ABOUT PRIMEWEST'S OPERATING AND
FINANCIAL RESULTS FOR 2000 AND PREVIOUS YEARS, AND THE TRUST'S FUTURE OUTLOOK
BASED ON CURRENTLY AVAILABLE INFORMATION. THIS SHOULD BE READ IN CONJUNCTION
WITH THE TRUST'S AUDITED CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEARS ENDED
DECEMBER 31, 2000 AND 1999, TOGETHER WITH THE ACCOMPANYING NOTES. THESE ARE
INCLUDED ON PAGES 29 THROUGH 42 OF THIS ANNUAL REPORT.
HIGHLIGHTS
Year over year, cash flow improved dramatically, up 173% and increasing steadily
throughout 2000 as commodity prices rose. While commodity prices had the
greatest effect on cash flow, PrimeWest also executed on the key operational
drivers within its control -- production, asset growth and cost control. Among
the year's highlights:
o Cash flow per trust unit was a record $2.51, up 107% and distributions
declared per trust unit were a record $1.77, up 61%.
o Average daily production grew by 8% compared with 1999, to a record 16,237
BOE per day.
o We posted a record operating netback of $21.27 per BOE, up 116% over 1999.
o Operating expenses per BOE were brought down by 3% to $5.08.
o Cash G&A expenses were reduced by 28% to $0.70 per BOE.
o In September we raised $40.3 million by issuing 4.83 million trust units at
$8.35 per trust unit. Net proceeds from this issue were used to strengthen
our balance sheet.
o We completed two major acquisitions of junior oil and gas companies, having
a total value of $116 million. The result was a net increase of 3,230 BOE
per day of production (1,768 BOE per day annualized) at an average
established reserve cost of $12.35 per BOE.
o Through acquisitions and capital development we added 13.0 million BOE to
both proved and established reserves. After deducting 5.9 million BOE of
production for 2000 as well as 1.1 million BOE of property dispositions,
proved and established reserves are up 6.1 million BOE and 6.0 million BOE
respectively year over year. Established reserves were 69.6 million BOE at
the end of 2000, up 9% from 63.6 million BOE at the end of 1999.
o Capital development activities, including technical revisions, replaced 35%
of 2000 production while acquisition activities, net of property
dispositions, replaced 158% of 2000 production.
o Using a 10% discount rate, our net asset value was $10.55 per trust unit at
December 31, 2000 compared with $7.07 per trust unit the year before, an
increase of 49%. During the year, we paid $79 million in cash distributions
to unitholders. Accordingly, the total of net asset value plus cumulative
distributions to the end of 2000 rose by 48%, from $10.77 to $16.02.
o We recorded a total return of 67.8% per trust unit year over year, up from
56.3% per trust unit in 1999. Our 2000 year-end unit price rose by 35%
compared with year-end 1999 and our 2000 distributions declared climbed by
61% per unit.
o The year-end 2000 debt-to-annual-cash-flow ratio was 0.7:1. Long-term debt,
net of working capital, was down $6.6 million year over year, despite
spending more than $32 million in capital and assuming debt and negative
working capital of $31 million through corporate acquisitions. Debt was
managed through applying excess cash flow above our distributions as well
as through our equity issue in September.
RESULTS OF OPERATIONS
PRODUCTION VOLUMES
Production volumes for 2000 averaged 16,237 BOE per day, up 8% from 1999 levels.
About 70% of the incremental production came from our two acquisitions and 30%
from our capital development program. At year-end, GORR volumes were 2,229 BOE
per day, or 13% of total year-end volumes, with the remainder being working
interest volumes.
Acquisition activities replaced 166% of 2000 production, and development
activities, including technical revisions, replaced 35%.
Production Summary
2000 % 1999 %
----------------------------
Oil (BARRELS PER DAY) 6.582 41 5,958 39
NGLs (BARRELS PER DAY) 1,483 9 1,293 9
Gas (MMCF PER DAY) 49.03 50 46.46 52
----------------------------
TOTAL BOE PER DAY 16.237 100 14,995 100
Together, these acquisition and development additions more than offset naturally
occurring declines in the productive capacity of the existing properties. This
result has been accomplished by greater project diversification coupled with an
increased emphasis on technology and stewardship.
PrimeWest's production mix was balanced in 2000, with approximately 41% being
crude oil, 9% natural gas liquids, and 50% natural gas.
SALES REVENUES
Gross sales revenues from crude oil, natural gas and natural gas liquids rose by
95% for the year ended December 31, 2000 to $191.3 million. The increase was due
to higher sales prices received for all commodities and higher production
volumes.
PRICES
Throughout 2000 and into 2001, world oil prices have remained at high levels due
to low inventories and high demand. Natural gas prices rose dramatically during
the year and have remained strong in 2001, as North American consumer and
industrial demand continues to grow at rates greater than supply.
Sales Prices
(CANADIAN DOLLARS) 2000 1999 Change
Crude oil ($BARREL) 36.67(1) 21.69 69%
NGLs ($/BARREL) 34.42 19.09 80%
Natural gas ($/MCF) 4.65(2) 2.51 85%
Total BOE ($/BOE) 32.19 17.95 79%
(1) After deducting $1.82 per barrel for hedging
(2) After deducting $0.31 per McF for hedging
A strengthening Canadian dollar and widening crude-oil quality differentials
toward the end of the year only slightly offset the effects of rising WTI oil
prices and the resulting increase in revenues (sales of crude oil are
denominated in U.S. dollars).
PrimeWest's crude oil is a mix of light and medium gravity, averaging 32 degrees
API. Crude oil is sold to various companies and markets under a number of
different contracts at prevailing market prices.
In 2000, approximately 46% of our natural gas was sold to aggregators in Alberta
and British Columbia, which offer a mix of prices and access to a number of
markets in Canada and the United States. The remaining 54% of our gas was sold
directly into the Alberta short- and long-term markets.
Crude oil revenues rose 87% from 1999 levels, to $88.3 million, because of
stronger prices and increasing production. Crude oil revenues also reflect the
effects of a number of hedging transactions entered into for 2000 to provide
increased stability in cash distributions. These financial and physical hedging
transactions resulted in opportunity costs of $4.4 million ($1.82 per produced
barrel).
Natural gas revenues increased by 96% over 1999, to $83.4 million, due mainly to
higher prices and sales volumes. Financial and physical hedging activities
during 2000 resulted in opportunity costs of $5.6 million ($0.31 per produced
Mcf).
During 2000, essentially all of our natural gas liquids were sold to BP Canada
Petroleum Company at prevailing market prices. Natural gas liquids revenues
increased by 108% to $18.7 million, again due to stronger prices and higher
volumes. PrimeWest did not hedge any prices on sales of natural gas liquids in
2000.
ROYALTIES
Total royalties net of Alberta Royalty Tax Credit (ARTC) paid during 2000 were
$35.2 million, an increase of 105% from $17.2 million paid in 2000 due mainly to
increased prices received. As a percentage of gross sales revenues for the year
ended December 31, 2000, royalty expense was 18.4%, up marginally from 17.5% in
1999.
ARTC was $0.56 million in 2000, compared with $0.8 million in 1999. The decrease
is due to a lower ARTC claim rate arising from higher commodity prices.
OPERATING EXPENSES
Operating expenses, net of processing income, were $30.2 million for 2000. This
is an increase of 5% from 1999 in aggregate but a reduction of 3% on a per-BOE
basis. Controlling operating costs and other expenses was a priority for us
during 2000 and continues to be. While increased power costs are a concern, we
expect that our per-BOE costs will decline again in 2001 with further
cost-reduction initiatives. Also, we will register the full-year impacts of the
Reserve Royalty GORRs and the lower cost structure of the Cypress properties.
OPERATING NETBACK
PrimeWest's operating netback (before G&A, management fees and interest expense)
of $21.27 per BOE was 121% higher than in 1999, due mainly to significantly
higher average selling prices and lower operating expenses.
Operating Netbacks
(DOLLARS PER BOE) 2000 1999 1998
---------------------------
Revenue 32.27 17.99 13.63
Royalties (5.92) (3.14) (2.28)
Operating expenses (5.08) (5.23) (5.40)
---------------------------
Operating netback 21.27 9.62 5.95
- --------------------------------------------------
GENERAL AND
ADMINISTRATIVE EXPENSES
Cash general and administrative expenses, net of overhead recoveries, were $0.70
per BOE in 2000, a decrease of 28% from 1999. This resulted from a 22% reduction
in aggregate expenses and an increase in production. Also, there were a number
of one-time restructuring charges in 1999. We expect general and administrative
costs to remain relatively flat on a per-BOE basis in 2001.
Non-cash general and administrative expenses of $10.3 million (1999 -- $0.5
million) relate to our Long-term Incentive Program for employees. The program is
a `phantom option' plan, whereby employees are rewarded only if PrimeWest
achieves a unitholder return (cumulative distributions plus growth in unit
price) above 5% per annum. The significant increase in the expense year over
year is due to the dramatic increase in both distributions and unit price in
2000. Pursuant to this plan, PrimeWest issued 226,423 trust units during the
year (1999 -- 15,806). The expense relates to the `in the money' Unit
Appreciation Rights vested, but not exercised, as at year-end.
MANAGEMENT FEES
As the Manager of PrimeWest Energy Trust, PrimeWest Management Inc. receives a
management fee of 2.5% of net production revenue, plus a specified number of
trust units.
For the year ended December 31, 2000, management fees were $4.0 million,
compared with $1.8 million in 1999, reflecting the dramatically higher cash
flow. Of the $4.0 million, $3.3 million was paid in cash, and the balance was
paid by the issuance of 90,411 trust units from treasury.
The above figures do not include acquisition or disposition fees totalling $1.7
million for 2000 (1999 -- $0.6 million), which are charged to capital assets as
part of properties acquired. They also do not include the 1% retained royalty
totalling $0.8 million for 2000 (1999 -- $0.4 million), which is paid as a
dividend by PrimeWest Energy Inc. to PrimeWest Management Inc.
INTEREST EXPENSE
Interest expense increased to $6.4 million in 2000 from $4.9 million in 1999.
This reflects higher average debt year over year and higher prime borrowing
rates. Also contributing was the assumption, in connection with the acquisition
of Reserve Royalty Corporation, of an obligation under an interest rate swap,
whereby $25 million of debt is locked in at a rate of 6.48% plus stamping fee
until 2004. PrimeWest also has a further $15 million of debt locked in at a rate
of 5.535% plus stamping fee until June 2001. The average cost of debt increased
from 5.9% in 1999 to 7.4% in 2000.
Interest costs are managed through a revolving facility and through the issuance
of bankers' acceptances. In the near term, PrimeWest expects to benefit from
recent and anticipated reductions in short-term interest rates for the unhedged
portion of the debt.
DEPLETION, DEPRECIATION
AND AMORTIZATION
The 2000 and 1999 depletion, depreciation, and amortization rates were $7.21 and
$6.34 per BOE, respectively. Higher depletion rates are due in part to the
Reserve Royalty acquisition, given the higher BOE value of the gross overriding
royalty reserves compared with working interest reserves. This higher value
comes from the fact that GORR production is not burdened with royalties,
operating expenses or capital costs.
SITE RECLAMATION
AND RESTORATION RESERVE
A provision of $2.9 million was made for site reclamation and abandonment during
2000, compared with $0.8 million in 1999. Costs are estimated by PrimeWest based
on independently prepared studies and charged to operations on a
unit-of-production basis.
To fund anticipated increased costs, PrimeWest contributed $0.24 per BOE or $1.4
million in 2000, up from $0.15 per BOE or $0.8 million in 1999. A special
contribution of $1.5 million also was made. In 2000, $3.6 million was paid out
of the cash reserve to abandon and reclaim wells and properties, compared with
$1.8 million in 1999.
As actual reclamation and abandonment costs are trending higher than in prior
years, PrimeWest
intends to maintain a prudent level of cash funding to the Site Restoration
Reserve. This will enable us to meet our obligations under the Alberta Energy
and Utilities Board's Long-term Inactive Well Program. And it will ensure that
we maintain a reasonable reserve to meet future obligations for abandonment and
reclamation work that arise from ongoing operations and acquisitions.
The Site Restoration Reserve had a balance of $0.4 million at year-end compared
with $1.1 million at year-end 1999.
INCOME TAXES
The Trust is able to claim certain tax deductions, for the benefit of
unitholders, that shelter a portion of cash distributions from income tax until
the units are sold or deemed to have been sold. These tax pools result from
acquiring properties that have sufficient tax pools to shelter income in the
Trust. Distributions received in 1999 were fully tax-deferred and 100% of their
value will be used to reduce the adjusted cost base of trust units held by
unitholders. Distributions received in 2000 were determined to be 53% taxable as
other income and 47% tax-deferred return of capital.
The increased taxability of distributions is due mainly to increased cash flow
received, which, in turn, is due primarily to higher commodity prices and
increased production. PrimeWest expects that a comparable level of taxability
will apply to its 2001 distributions, should similar commodity prices and
operating results continue.
NET ASSET VALUE
Net asset value is a measure of the net value of PrimeWest's underlying assets
- -- crude oil, natural gas and natural gas liquids reserves. These reserves are
based on consultant average escalating commodity price forecasts, prior to
provision for income taxes, interest costs, general and administrative costs and
management fees, but after providing for estimated royalties, operating costs,
other income, capital costs and abandonment costs. The net asset value includes
the value of unproved lands, working capital, funds held for reclamation, and it
deducts debt outstanding.
Based on an independent evaluation of PrimeWest's established reserves by
Gilbert Laustsen Jung Associates Ltd., discounted at 10%, our net asset value
was $10.55 per trust unit at the end of 2000, up 49% from 1999.
This rise reflects a 9% increase in established reserves -- due mainly to the
acquisitions of Venator Petroleum Company and Reserve Royalty Corporation -- as
well as higher commodity price forecasts. It was offset by a 43% increase in the
number of trust units and exchangeable shares outstanding year over year.
In addition to our net asset value, distributions paid to the end of the year
since inception in October 1996, were $5.47 per trust unit.
Net Asset Value
(MILLIONS OF DOLLARS, EXCEPT 2000 1999 1998
FOR PER-TRUST-UNIT)
- ----------------------------------------------------------
Established reserves (1) 623.0 328.0 313.0
Unproved lands 17.2 10.2 10.6
Reclamation fund 0.4 1.1 1.8
Working capital (deficit) (0.3) 5.8 2.4
Long-term debt (78.9) (92.2) (73.0)
---------------------------
Net asset value 561.4 252.9 254.8
- ----------------------------------------------------------
Trust units outstanding (2) 53.2 35.77 33.02
Net asset value per trust unit 10.55 7.07 7.72
Cumulative distributions
declared per trust unit 5.47 3.70 2.60
- ----------------------------------------------------------
(1) DISCOUNTED AT 10%
(2) FULLY DILUTED (TO ACCOUNT FOR EXCHANGEABLE SHARES AND THE EFFECTS OF THE
LONG-TERM INCENTIVE PROGRAM.)
LIQUIDITY AND
CAPITAL RESOURCES
In September 2000, we completed a $40.3-million equity financing, with the
issuance of 4.83 million trust units at $8.35 per unit. The proceeds were used
to reduce debt.
At year-end 2000, long-term debt was $78.9 million, or $1.52 per trust unit
(including the PrimeWest Resources Ltd. exchangeable shares), as compared with
$92.2 million, or $2.41 per trust unit at the end of 1999. During 2001 we will
continue to manage our debt prudently by applying undistributed cash flow to a
combination of debt reduction, contributions to an undistributed reserve, unit
buy-backs and/or additional supplementary distributions.
Capital Expenditures
(THOUSANDS OF DOLLARS) 2000 1999 1998
Land and lease 545 323 535
Geological and geophysical 817 893 1,496
Development drilling 16.416 10,199 13,110
Plant and facilities 5,665 2,335 1,646
Property acquisitions 2,223 11,084 64,200
Property dispositions (855) (5,909) (16,424)
Corporate acquisitions 116,433 13,563 --
Head office 2,348 422 629
- --------------------------------------------------------------------
Total capital expenditures 143,592 32,910 65,192
- --------------------------------------------------------------------
Corporate Acquisitions
Venator Reserve
Royalty
-------------------------
Acquisitions cost (millions of dollars) 32.5 84.0
Established reserves acquired (millions) 3.0 6.1
Acquired production (BOE/d) 1,486 1,744
Production (BOE/d annualized) 1,039 729
Acquisition cost/established BOE 10.81 13.12 *
- ----------------------------------------------------------------------
* EXCLUDES THE VALUE OF UNPROVED LANDS
PrimeWest's year-end debt-to-unitholder-equity ratio was 26%, compared with 46%
at December 31, 1999. At the end of 2000, PrimeWest's ratio of debt to trailing
annual operating cash flow was 0.7 times compared with just over 2.0 times at
the end of 1999. We expect the debt-to-operating-cash-flow ratio will remain in
the range of 1.0 times for 2001. We will continue to strengthen our balance
sheet to provide financial flexibility to enable us to pursue other acquisition
and property-enhancement activities.
At December 31, 2000, PrimeWest had a negative working capital balance of $0.3
million, however, we had unused credit lines of approximately $70 million.
Debt Analysis
(THOUSANDS OF DOLLARS) 2000 1999 1998
- --------------------------------------------------------------------------------
Long-term debt 78,940 92,180 73,006
Working capital (deficit) (268) 5,850 2,369
Net debt 79,208 86,330 70,637
Market value of unitholders' equity (1) 467,172 237,863 166,767
Total capitalization 546,380 324,193 237,404
- --------------------------------------------------------------------------------
UNITHOLDER'S EQUITY
Net income was $55.6 million compared with $6.0 million in 1999. Net income
increased due to 88% higher revenues offset by 31% higher total expenses. Equity
issued, net of costs, totalled $124.3 million in 200, relating to the
acquisitions of Venator and Reserve Royalty as well as the equity issue of $40.3
million in September. Cash distributed totalled $79 million, up 112% from 1999.
Dividends declared were $1.6 million, up from $0.4 million in 199. The higher
level of dividends is due to the PrimeWest Resources exchangeable shares issued
in conjunction with the Venator acquisition (which receive dividends on the
taxable portion of the distribution) as well as higher dividends paid to the
Manager.
On November 29, 1999, the Trust received approval from The TSE to make a normal
course issuer bid. With this bid, the Trust acquired 263,100 trust units at an
average cost of $6.39 per unit. The bid expired on November 28, 2000. December
2000, the Trust received approval to renew its bid for a further one-year
period. To December 31, 2000, no purchases has been made.
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 operating in the conventional oil and gas royalty trust sector. The
Trust's financial position, results of operations, and cash available for
distribution to unitholders are directly impacted by these factors.
COMMODITY PRICE
FOREIGN-EXCHANGE AND
INTEREST-R ATE RISKS
Prices received for production are impacted in varying degrees by factors
outside the Trust's control. These include but are not limited to:
o World market forces, most importantly the actions of OPEC, and their
implications for the price of crude oil.
o Increases or decreases in crude-oil quality differentials, and their
implications for prices received by PrimeWest on the portion of our oil
production that is medium gravity crude (about 40% at year-end).
o North American market forces, most notably shifts in the balance between
supply and demand for natural gas and the implications for the price of
natural gas. n And, to the extent that crude oil and natural gas prices
received by PrimeWest are referenced to WTI oil, which is denominated in
U.S. dollars, prices and revenue streams are impacted by changes in value
between the Canadian and U.S. dollars.
Fluctuations in commodity prices, quality differentials, foreign exchange and
interest rates are outside the control of PrimeWest and yet can have a
significant impact on the level of cash available for distribution to
unitholders. To mitigate a portion of this risk, we actively initiate, manage
and disclose the effects of our hedging activities. We evaluate these activities
against criteria established under a commodity risk-assessment and management
program, which is regularly reviewed by the Board.
As part of PrimeWest's risk-management strategy in 2000, we hedged 44% of our
full-year crude oil production and 27% of our full-year natural gas production,
net of royalties. We used physical and financial instruments with a primary
objective of enhancing the stability of cash distributions.
In connection with the acquisition of Cypress Energy Inc. in March 2001,
PrimeWest entered into a series of pr price hedging contracts on 8,400 BOE per
day of natural gas production and 6,000 BOE per day of crude oil production
(annualized). The gas hedging instruments are floors, swaptions and swaps. The
swaptions will give PrimeWest the future right to enter into swap transactions
for fixed prices and terms. The oil hedging transactions consist of floors,
swaps, costless collars and calls.
The natural gas hedges have an effective term until the end of the 2002 summer
season. The crude oil hedges are for the period April through December 2001.
The cost of these risk-management activities equates to approximately $0.06 per
trust unit over 2001 and approximately $0.03 per trust unit in 2002.
The combined effect of all oil-related transactions executed at the date of this
annual report is downside protection below $U.S.25.00 per barrel on about 70%
annualized of our overall crude production, net of royalties. As conditions
warrant, PrimeWest may layer in additional risk-management instruments
throughout the year.
For gas for 2001, we have layered in other hedging structures - swaps, floors
and costless collars - representing about 38% of total gas production, net of
royalties. The combined effect of all gas-
related transactions executed at the date of this annual report is downside
protection below $7.25 per Mcf.
Our marketing strategy for natural gas is to create a diversified market
portfolio. This is accomplished by selling approximately 46% of natural gas
production to aggregators and 54% of production into the Alberta short- and
long-term markets.
The contracts that PrimeWest has with aggregators vary in length. They also
relate to a blend of domestic and U.S. markets, with fixed and floating prices
designed to provide price diversification to our revenue stream.
In addition to these noted risk-management tactics, PrimeWest also works to
maintain a relatively balanced production portfolio. Because oil and gas price
cycles do not often coincide, such a balance can provide some natural mitigation
of price risk.
At year-beginning 2001, our commodity mix was 50% oil and NGLs, and 50% natural
gas, the same as it was at year-beginning 2000.
After the acquisition of Cypress, the ratio became 66% gas and 34% oil and NGLs.
OPERATIONAL RISK
PrimeWest is exposed to a number of uncontrollable risks, which may affect our
ability to achieve the corporate objective of maximizing cash available for
distribution to unitholders while preserving underlying asset value. These risks
include:
Acquisition risk: There is risk that PrimeWest may not be able to acquire
producing properties at low cost to renew our inventory of assets.
To mitigate this risk, PrimeWest has a four-person acquisition and divestiture
team, headed by one of the Trust's three vice-presidents. The team employs the
talents of technical specialists within PrimeWest and external consultants, and
continually scans the industry for opportunities. It evaluates potential
corporate or property acquisitions and, where it makes sense to do so,
rationalizes Trust properties.
Development risk: There is no certainty that the development and enhancement
programs undertaken will result in reserve additions on an economic basis or in
quantities sufficient to replace annual production.
Given the natural decline rates on our trust-like properties -- typically mature
fields with significant oil and/or gas in place -- it becomes increasingly
difficult to replace annual production with development work alone. Acquisitions
are key. To maintain a successful development program, our technical team
geologists, geophysicists, and engineers, working with the direction of a
vice-president, apply a prudent development strategy. Risk is mitigated through
project diversification and rigorous technical
and economic assessments. Base production for 2000 was maintained at 97% of the
1999 level. For 2001 we are targeting 95% of the 2000 level.
Production risk: Well operations and the processing and physical delivery of
commodities for sale can be subject to unexpected delays. We offset these risks
by contracting with a range of service providers. We also perform proactive
protective maintenance and surveillance on our facilities and wells. This is
supported by telemetry, physical inspection and diagnostic tools. Our field
production teams are headquartered in six field sites.
Marketing risk: Markets for oil and natural gas are not stable and PrimeWest's
access to markets via pipelines and trucking are also exposed to interruption.
We do several things to mitigate this risk. We try to coordinate our planned
maintenance with other industry planned outages. Our production base at year-end
was diversified through interests in more than 2000 oil and gas wells. We also
manage a sophisticated commodity-price hedging program. A risk-management
committee meets regularly to monitor and discuss the commodity markets and to
develop recommendations for transactions. The vice-chairman can approve most
price hedging decisions; major recommendations are subject to Board approval.
The Board has stipulated that not more than 70% of natural gas production and
not more than 70% of crude oil production may be hedged on a swapped basis
(excluding `insured' volumes) during a rolling 24-month period.
To mitigate these business risks, the Manager employs experienced senior-level
personnel, who use a hands-on approach to operating PrimeWest's properties and
managing its financial affairs. Capital is spent only after strict economic
criteria for production and reserve additions are assessed.
OUTLOOK AND SENSITIVITIES
During the first quarter of 2001, we continued to enjoy the unprecedented
benefits of strong commodity prices for both crude oil and natural gas. It is
not often that the price cycles for both commodities correlate, because the
fundamental factors that affect their supply and demand are often different.
At the time of writing this annual report, most investment analysts were
estimating average prices for 2001 in the range of $U.S.27.00 per barrel for WTI
crude oil and $6.50 per Mcf for AECO natural gas. Meanwhile, actual prices
received to date plus the forward market for the balance of 2001 were indicating
$U.S.27.40 per barrel for \A/TI oil and $8.25 per Mcf for gas.
For business planning and budgeting purposes, PrimeWest normally uses a price
forecast that lies somewhere in between the two above-cited sources.
Expectations are that OPEC will continue to discipline production; this would
support an expectation of similar prices to those experienced in the latter part
of 2000 and the early part of 2001.
For natural gas, expectations are that North American supply and demand will
remain out of balance for some time, perhaps as long as three years. Drilling in
Canada and the U.S. does not appear to be
keeping up with consumer and industrial demand. There may be some price-related
fuel switching as time goes by. Although gas prices have fallen from their
highs, they are still very strong.
Given these expectations plus our expectations for increasing production, and
factoring the hedging we already have in place, we expect 2001 cash flow to be
very healthy. On March 6, 2001 we announced an increase and extension of our
$O.2O-per-month distribution rate to $0.22 until at least the December 2001
distribution, paid January 15, 2002. Our intention is to maintain this
distribution rate as long as possible through active risk management, asset
growth, financial prudence and operating excellence.
CASH FLOW SENSITIVITIES FOR 2001 (AS AT APRIL 10, 2001)
INSPECT EN ANNUAL CASH AVAILABLE FOR DISTRIBUTION PER UNIT (INCLUDING HEDGING)
CHANGE PER-UNIT IMPACT ($)
- ----------------------------------------------------
Price
Oil ($U.S.1.00 per barrel WTI rise)
Below $U.S.25.00 0.02
Above $U.S.25.00 0.04
Above $U.S.27.00 0.03
Natural gas ($0.10 per Mcf rise)
Below $7.25 0.02
Above $7.25 0.03
Financial
Interest rate (1% rise) (0.02)
Exchange rate ($U.S.0.01 rise) (0.01)
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
fulfills 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 examine the corporate and accounting records of PrimeWest and the Trust in
order 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. Mac Intyre Susan M. Duncan
VICE-CHAIRMAN AND CHIEF EXECUTIVE OFFICER VICE-PRESIDENT, FINANCE
April 10, 2001
AUDITORS' REPORT
To the unitholders of PrimeWest Energy Trust:
We have audited the consolidated balance sheets of PrimeWest Energy Trust as at
December 31, 2000 and 1999, and the consolidated statements of income and cash
available for distribution, 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, 2000
and 1999, and the results of its operations and cash flows for the years then
ended in accordance with Canadian generally accepted accounting principles.
PricewaterhouseCoopers LLP March 16, 2001. except for note 12,
CHARTERED ACCOUNTANTS which is as of March 29, 2001
Calgary, Alberta
CONSOLIDATED
BALANCE SHEETS
AS AT DECEMBER 31 2000 1999
ASSETS
Current Assets
Cash $ -- $5,503,885
Short-term Investments -- 174,284
Accounts Receivable 35,063,628 21,810,905
-------------------------------
Prepaid Expenses and Inventory 3,400,435 2,452,218
38,464,063 29,941,292
Cash Reserved for Site Restoration and Reclamation (NOTE 6) 398,300 1,059,679
Capital Assets (NOTE 3) 395,375,685 289,209,067
-------------------------------
$434,238,048 $320,210,038
===============================
LIABILITIES AND UNITHOLDERS' EQUITY
Current Liabilities
Bank Overdraft $ 833,655 $ -
Accounts Payable and Accrued Liabilities 25,774,998 18,674,861
Accrued Distributions to Unitholders 9,960,899 3,554,729
Due to Related Company (NOTE 9) 2,057,032 1,279,988
Current Portion of Long-term Debt (NOTE 5) 106,437 106,437
-------------------------------
$ 38,733,021 23,616,015
Long-term Debt (NOTE 5) 78,940,471 92,179,517
Future Income Taxes (NOTE 10) 16,595,723 -
Long-term Incentive Liability (NOTE 8) 8,930,062 475,594
Site Restoration and Reclamation Provision 1,958,296 3,899,296
$ 145,157,573 $120,170,422
===============================
Unitholders' Equity
Net Capital Contributions (NOTE 7) 435,341,898 311,048,889
Accumulated Income (Loss) 43,014,175 (2,379,130)
Accumulated Cash Distributions (186,518,031) (107,484,698)
Accumulated Dividends (2,757,567) (1,145,445)
-------------------------------
2,89,080,475 200,039,616
-------------------------------
$434,238,048 $320,210,038
===============================
Harold P. Milavsky Kent J. MacIntyre
CHAIRMAN OF THE BOARD OF DIRECTORS VICE-CHAIRMAN AND CHIEF EXCEUTIVE OFFICER
CONSOLIDATED STATEMENTS OF
UNITHOLDERS' EQUITY
FOR THE YEARS ENDED DECEMBER 31 2000 1999
- -------------------------------------------------------------------------------------------------
Unitholders' Equity - Beginning of Year,
as previously reported $200,039,616 213,213,317
Adjustment to Unitholders' Equity at the
Beginning of Year to Adopt New Future
Income Tax Standard (NOTE 10) (10,218,312) -
Net Income for the Year 55,611,617 5,984,752
Capital Contributions, Net of Costs 124,293,009 18,598,244
Cash Distributions (79,033,333) (37,350,697)
Dividends (1,612,122) (406,000)
----------------------------
Unitholders' Equity - End of Year $289,080,475 $200,039,616
============================
CONSOLIDATED STATEMENTS OF
INCOME AND CASH AVAILABLE
FOR DISTRIBUTION
FOR THE YEARS ENDED DECEMBER 31 2000 1999
- -------------------------------------------------------------------------------------------------
REVENUE
Sales of Crude Oil, Natural Gas and Natural Gas Liquids $191,338,570 $98,246,904
Crown and Other Royalties, Net of ARTC (35,157,085) (17,182,292)
Other Income 379,114 1,998,099
-----------------------------
$156,560,599 $83,062,711
=============================
EXPENSES
Operating 30,174,655 28,608,863
Cash General and Administrative 4,139,881 5,321,415
Non-cash General and Administrative 10,295,591 586,292
Interest 6,359,041 4,855,309
Attempted Takeover Costs -- 1,144,595
Cash Management Fees 3,276,7888 1,385,887
Non-cash Management Fees 731,154 446,484
Depletion, Depreciation and Amortization 42,864,711 34,699,114
-----------------------------
$97,841,821 $77,077,959
=============================
Net Income before Taxes for the Year $58,718,778 $5,984,752
=============================
Capital Taxes 548,707 --
Future Taxes (NOTE 10) 2,558,454 --
-----------------------------
3,107,161 --
-----------------------------
Net Income for the Year 55,611,617 5,984,752
=============================
Add Back (Deduct) Amounts to Reconcile to Distributions
Depletion, Depreciation and Amortization 42,864,711 34,699,114
Undistributed Reserve (29,265,995) (2,484,813)
Contribution to Reclamation Fund and Interest thereon (2,963,883) (868,450)
Attempted Takeover Costs, Net of Income -- (635,402)
Management Fees Paid by the Issuance of Trust Units 731,154 446,484
Employee Long-term Incentive Plan 10,295,591 586,292
Future Income Taxes 2,558,454 --
-----------------------------
$24,220,032 $31,743,225
CASH AVAILABLE FOR DISTRIBUTION $79,831,649 $37,727,977
-----------------------------
Cash Available for Distribution to Trust Unitholders (99%) $79,033,333 $37,350,697
=============================
Cash Available for Distribution per Trust Unit $1.77 $1.10
Net Income per Trust Unit $1.25 $0.18
Fully Diluted Net Income per Trust Unit $1.21 $0.18
CONSOLIDATED STATEMENTS OF
CASH FLOW
FOR THE YEARS ENDED DECEMBER 31 2000 1999
- -------------------------------------------------------------------------------------------------
OPERATING ACTIVITIES
Net Income for the Year $55,611,617 $5,984,752
Add: Items Not Involving Cash Flow from Operations
Depletion, Depreciation and Amortization 42,864,711 34,699,114
Attempted Takeover Costs -- 1,144,595
Investment Income -- (1,779,997)
Non-cash General and Administrative 10,295,591 586,292
Non-cash Management Fees 731,154 446,484
Future Income Taxes 2,558,454 --
------------------------------
Cash Flow from Operations 112,061,527 41,081,240
Change in Non-cash Working Capital (7,598,072) (7,456,903)
------------------------------
104,463,455 33,624,337
==============================
FINANCING ACTIVITIES
Proceeds from Issue of Trust Units, net of Costs 39,896,212 18,829,242
Acquisition of Trust Units pursuant to Normal Course Issuer Bid (926,162) (754,976)
Cash Distributions to Unitholders (79,033,333) (37,350,697)
Dividends Paid (1,612,122) (406,000)
Increase (Decrease) in Long-term Debt (41,449,046) 19,173,121
Change in Non-cash Working Capital 6,291,954 1,540,138
------------------------------
(76,833,397) 1,030,828
==============================
INVESTING ACTIVITIES
Expenditures on Capital Assets (25,791,235) (14,170,151)
Acquisition of Capital/Corporate Assets (NOTE 4) (6,306,029) (24,647,847)
Proceeds on Disposition of Capital Assets 855,002 5,908,540
Cash Reserved for Future Site Restoration and Reclamation 661,379 721,048
Expenditures on Site Restoration and Reclamation (3,560,999) (1,835,258)
Proceeds on Disposition of Short-term Investments 174,284 4,817,715
Attempted Takeover Costs Expensed - (1,144,595)
------------------------------
(33,967,598) (30,350,548)
------------------------------
INCREASE (DECREASE) IN CAHS FOR THE YEAR (16,337,540) 4,304,617
------------------------------
CASH, BEGINNING OF YEAR 5,503,885 1,199,268
CASH (BANK OVERDRAFT), END OF YEAR $ (833,655) $ 5,503,885
==============================
CASH INTERST PAID $ 6,872,448 $ 4,867,353
==============================
CASH TAXES PAID $ 452,896 $ --
==============================
NOTES TO CONSOLIDATED
FINANCIAL STATEMENTS
1. STRUCTURE OF THE TRUST
PrimeWest Energy Trust (the Trust) is an open-ended investment trust formed
under the laws of Alberta pursuant to a declaration of trust dated August 2,
1996 as amended from time to time. The beneficiaries of the Trust are the
holders of the trust units (the unitholders). Operations of the Trust consist of
acquiring and holding, as the Trust's principal asset, a royalty entitling the
Trust to receive 99% of the net cash flows generated by PrimeWest Energy Inc.
and its wholly-owned subsidiaries PrimeWest Resources Ltd. and PrimeWest Royalty
Corp. (collectively PrimeWest) from its oil and gas properties.
PrimeWest acquires oil and gas properties for its own account and sells a
royalty to the Trust. The royalty acquired from PrimeWest effectively transfers
substantially all of the economic interest in the properties acquired by
PrimeWest to the Trust.
Pursuant to management agreements between PrimeWest, 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 PrimeWest and the
operation of the properties acquired by PrimeWest. 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 the shares of PrimeWest, and a director of PrimeWest controls the
Manager.
2. ACCOUNTING POLICIES CONSOLIDATION
These consolidated financial statements include the accounts of the Trust and
PrimeWest. Although there is no legal ownership between these entities, 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.
CAPITA! 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. Depreciation of major
facilities is provided on a straight-line basis over the estimated useful life
of the facilities. 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 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
long-term 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 y6 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 for PrimeWest are recorded 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 and other
temporary differences. (SEE NOTE 10).
SHORT-TERM INVESTMENTS
Investments are reported on the balance sheet at the lower of cost or market
value. The quoted market value approximated cost at December 31, 1999. There
were no short-term investments held at December 21, 2000.
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 contract expires.
3. CAPITAL ASSETS
2000 1999
- ------------------------------------------------------------------------------------------------------------------------------
ACCUMULATED ACCUMULATED
DEPLETION, DEPLETION,
DEPRECIATION NET DEPRECIATION NET
AND BOOK AND BOOK
COST AMORTIZATION VALUE COST AMORTIZATION VALUE
- ------------------------------------------------------------------------------------------------------------------------------
Property acquisition
oil and gas rights $474,090,551 $135,255,909 $338,834,642 $350,641,363 $100,160,392 $250,480,971
Drilling and completion 51,768,617 10,216,012 41,552,605 31,175,388 5,047,405 26,127,983
Production facilities
and equipment 16,397,401 3,249,347 13,148,054 14,126,269 2,720,322 11,405,947
Head office furniture
and equipment 31,99,504 1,359,120 1,840,384 2,101,723 907,557 1,194,166
------------------------------------------------------------------------------------------------
$545,456,073 $150,080,388 $395,375,685 $398,044,743 $108,835,676 $289,209,067
================================================================================================
Unproved land costs of $17,238,100 (1999 - $10,165,500) are excluded from costs
subject to depletion and depreciation.
4. CORPORATE ACQUISITIONS
a) 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 and costs associated with
the acquisition, 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 net assets
acquired and liabilities assumed summarized as follows:
Net assets acquired at assigned values
Petroleum and natural gas assets $34,391,703
Working capital (deficit) (2,322,872)
Future income taxes (1,898,262)
-----------
$30,170,569
===========
Consideration
Trust units issued $15,637,149 Petroleum and natural gas $13,357,717
Exchangeable shares issued 13,281,985 Working capital assumed 205,806
Costs associates with acquisition 1,251,435 Purchase Price 13,563,523
$30,170,569
b) 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 and costs associated with
the acquisition, 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 net assets acquired and liabilities assumed
summarized as follows:
Net assets acquired at assigned values
Petroleum and natural gas assets $ 85,860,409
Working capital 1,048,560
Long-term debt assumed (28,210,000)
Future income taxes (1,920,694)
$ 56,778,275
Consideration
Trust units issued $ 53,946,664
Costs associated with acquisition 2,831,611
$ 56,778,275
c) On November 3, 1999, PrimeWest Resources Ltd. ("Resources") completed the
acquisition of all of the issued and outstanding shares of Aberdeen Petroleum
(Canada) Ltd. ("Aberdeen") for cash consideration of $13,563,523. Subsequent to
the purchase, Aberdeen was dissolved, and all of the assets were distributed to
Resources. The acquisition was accounted for using the purchase method with the
price allocated as follows:
5. LONG-TERM DEBT
2000 1999
- --------------------------------------------------------------
Revolving credit facility $78,879,200 $92,022,190
Capital lease obligation 61,271 157,327
$78,940,471 $92,179,517
Current position 106,437 106,437
Total $79,046,908 $92,285,954
PrimeWest and the Trust (as co-borrowers) have a combined revolving credit
facility in the amount of $150 million, with a borrowing base at December 31,
2000 of $150 million. In addition to amounts outstanding under the facility,
PrimeWest has outstanding letters of credit in the amount of $4.3 million.
Collateral for the credit facility is provided by a floating-charge debenture in
the principal amount of $200 million. PrimeWest has provided a guarantee on any
advances made by the Trust under the facility.
Advances under the facility are made in the form of either Banker's Acceptances
(BAs) or prime rate loans. In the case of BA~, interest is a function of the BA
rate plus a stamping fee based on the Trust's current ratio of debt to cash
flow. In the case of prime rate loans, interest is charged at the bank's prime
rate.
The credit facility will revolve until April 30, 2001, 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. It
the lender converts the revolving facility to a non-revolving facility, the
amounts outstanding under the facility become repayable in ten equal semi-annual
instalments, commencing six months from the maturity date of the facility. The
Manager does not expect the lender to require any principal repayments within
the next year.
During 1997, PrimeWest entered into a capital lease in the amount of $471,328,
to finance the purchase of field equipment. The lease bears interest at 5% and
matures in September 2002. PrimeWest has the option, in May 2002, to purchase
the asset for 10% of the lease cost. Payments on the lease, including principal
and interest, total $106,437 per year.
6. RESERVES
CASH RESERVE FOR SITE RESTORATION AND RECLAMATION
In 1996, an amount of $2,720,000 was contributed to this reserve from the
proceeds of the initial public offering, representing 1996 and 1997 funding
contributions. 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 and $0.24 per BOE produced in 2000).
The cash amount contributed, including interest earned, was $2,963,883 in 2000
(1999 -- $868,450). Actual costs of site restoration and abandonment totalling
$3,560,999 were paid out of this cash reserve for the year ended December 31,
2000 (1999 -- $1,835,258).
Pursuant to a royalty agreement between the Trust and PrimeWest, PrimeWest also
may establish the following reserves:
RESERVE TO FUND FUTURE PRODUCTION COSTS
This reserve must be used to pay operating expenses in a future period or,
should the funds not be required for this purpose, the unitholder shall be
entitled to 99% of these funds. For the year ended December 31, 2000 the amount
reserved was $29,265,995 (1999 -- $2,484,813) and has been used to reduce
long-term debt.
RESERVE TO HOLD CERTAIN EXCESS REVENUES
A reserve will be established if other revenues exceed total revenues by 10% or
more. Since inception, other revenues have not exceeded this threshold and,
therefore, no reserve has been established.
7. UNITHOLDERS' EQUITY PrimeWest Energy Trust
The authorized capital of the Trust consists of an unlimited number of trust
units.
TRUST UNITS NUMBER OF UNITS AMOUNTS
- -------------------------------------------------------------------------------------------------
BALANCE, DECEMBER 31, 1998 33,023,084 $292,405,645
Issued for cash 2,750,000 19,800,000
Issue expenses -- (1,220,101)
Retired pursuant to Normal Course Issuer Bid (121,200) (754,976)
Issued for payment of management fees 66,384 413,280
Issued pursuant to Distribution Reinvestment Plan 34,727 249,343
Issued pursuant to Long-term Incentive Plan 15,806 110,698
- -------------------------------------------------------------------------------------------------
BALANCE, DECEMBER 31, 1999 35,768,801 $311,048,889
Issued for cash 4,830,000 40,330,500
Issue expenses -- (2,741,213)
Retired pursuant to Normal Course Issuer Bid (141,900) (926,162)
Issued to acquire Venator Petroleum Company Ltd. 2,368,936 15,637,149
Issued to acquire Reserve Royalty Corporation 6,660,082 53,946,664
Issued for payment of management fees 82,203 616,038
Issued on exchange of exchangeable shares 922,073 4,871,480
Issued pursuant to Distribution Reinvestment Plan 265,475 2,306,926
Issued pursuant to Long-term Incentive Plan 226,423 1,841,122
- -------------------------------------------------------------------------------------------------
BALANCE, DECEMBER 31, 2000 50,982,093 $426,931,393
=================================================================================================
The weighted average number of trust units outstanding in 2000 was 44,651,600
(1999 - 33,965,152).
PRIME I/VEST RESOURCES LTD.
In connection with the Venator transaction (see note 4a), 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 five
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 five-year expiry term.
Dividends are paid to holders of exchangeable shares based on the estimated
taxable portion of the monthly distribution paid. The exchange ratio, which was
11 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. The exchange ratio at December 31, 2000
was 1.0933:1.
EXCHANGEABLE SHARES NUMBER OF SHARES AMOUNT
- -----------------------------------------------------------------------------------------------
Balance, December 31, 1999 -- --
Issued to acquire Venator Petroleum Company Ltd. 2,012,422 13,281,985
EXCHANGED FOR TRUST UNITS (900,052) (4,871,480)
Balance, December 31, 2000 1,112,370 8,410,505
NORMA! 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 (1999 --121,200 trust units) pursuant to the bid at an
average cost of $6.53 per trust unit (1999 -- average cost of $6.23 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. As at December 31, 2000, no purchases had been made under the
renewed bid.
UNITS ISSUED FOR PAYMENT OF MANAGEMENT FEES
On January 15, 2001, the Trust issued 26,204 trust units in respect of
management fees earned for the period October 1, 2000 to December 31, 2000 (1999
- -- 17,956). The value of the units was $234,526 (1999 -- $119,408).
8. TRUST UNIT INCENTIVE PLAN
Under the terms of the Trust Unit Incentive Plan, a maximum of 2,490,000 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. UAR5 have a
term of up to six years and vest equally over a three-year period, except for
the independent members of the Board, whose UAR5 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.
Long-term incentive liability:
Current
UARs issued UARs return
AS AT DECEMBER 31, 2000 AND OUTSTANDING VESTED PER UAR
- --------------------------------------------------------------------------------------------------
1996 grants 543,875 543,875 $5.24
1997 grants 377,806 377,806 4.55
1998 grants 647,549 403,613 6.83
1999 grants 1,014,418 296,096 5.30\
2000 GRANTS 1,369,490 94,717 1.99
- --------------------------------------------------------------------------------------------------
3,953,138 1,716,107 $5.20
==================================================================================================
UAR5 vested are multiplied by the current return per UAR to derive the balance
sheet liability at December 31, 2000 of $8,930,062 (1999 -- $475,594).
Cumulative to December 31, 2000, 739,343 UAR5 have been exercised (1999 --
62,616), resulting in the cumulative issuance of 242,229 trust units from
treasury (1999 -- 15,806).
9. RELATED-PARTY TRANSACTIONS
For the year ended December 31, 2000, the Manager received management fees of
$4,007,942 (1999 -- $1,832,371). Of this amount, $3,276,788 was paid in cash
(1999 -- $1,385,887) and the balance represents the issuance of 90,411 trust
units from Treasury (1999 -- 67,762).
In addition, acquisition and disposition fees in the amount of $1,722,653 were
paid to the Manager during 2000 (1999 -- $615,406). 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 one-percent retained royalty from the
net cash flow from the properties and is paid by dividend from PrimeWest. This
amounted to $835,000 for 2000 (1999 -- $406,000).
As at December 31, 2000, the Trust and PrimeWest owed $2,057,032 (1999 --
$1,279,988) to the Manager for reimbursement of general and administrative and
other costs incurred by the Manager on behalf of the Trust and PrimeWest.
10. INCOME TAXES
The Trust, and consequently the unitholders of the Trust, had taxable income
totalling $38.3 million for 2000 representing approximately 53% of distributions
paid in the year. The taxable income of the Trust in 1999 was nil.
PrimeWest and its subsidiaries had no taxable income for 2000 and 1999, 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
unitholder's equity by $10,218,312 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 increase future tax expense/liability by $2,558,454.
The future income tax provision results from temporary differences in the
recognition of revenues and expenses for income tax and accounting purposes as
follows:
2000
- ----------------------------------------------------------------
Capital assets $ 11,737,337
Site restoration provision 873,792
long-term incentive liability 3,984,594
- ----------------------------------------------------------------
$ 16,595,723
================================================================
The provision for income taxes varies from amounts that would be computed by
applying the combined Canadian federal and provincial income tax rates for the
following reasons:
2000
- --------------------------------------------------------------------
Net income before taxes $ 58,718,778
====================================================================
Computed income tax expense at the Canadian
statutory rate of 44.62% $ 26,200,319
Increase (decrease) resulting from:
Non-deductible crown royalties and other
payments, net of ARTC 156,871
Federal resource allowance (171,928)
Amounts included in trust income and other (23,626,808)
- --------------------------------------------------------------------
Future income taxes $ 2,558.454
====================================================================
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.
During 2000, PrimeWest entered into a number of different financial arrangements
to hedge the sales price of its crude oil and natural gas production. In
addition, in connection with the Reserve Royalty transaction, PrimeWest assumed
the obligations pursuant to a number of financial hedging arrangements entered
into by Reserve Royalty and its subsidiaries. For the fiscal year ended December
31, 2000, the effect of these transactions was a reduction in revenue of
$2,177,236 (1999 --reduction of revenue of $3,861,681). The fair market value of
all outstanding commodity price arrangements at December 31, 2000 was a loss of
approximately $1.0 million. These hedges expire on March 31, 2001.
Market
Instrument Volume Floor Ceiling Contract Term Value
- ------------------------------------------------------------------------------------------------------------------------
Natural Gas Costless Collar 5,000 Gj/day $5.Ooigj $10.00/Gj Nov. '00 - Mar. '01 $(1,383,750)
Crude Oil Costless Collar 1,000 Bbl/day $U.s.29.00/bbl $U.s.34.50/bbl Jan. '01 - Mar. '01 414,002
- ------------------------------------------------------------------------------------------------------------------------
(969,748)
============
b) FOREIGN-EXCHANGE-RATE RISK MANAGEMENT
PrimeWest is exposed to foreign currency fluctuations on its operations, because
crude oil prices received are referenced to U.S.-dollar-denominated prices.
Effective January 1, 1998, PrimeWest entered into a foreign exchange swap
agreement with a Canadian chartered bank. The agreement fixed the exchange rate
at $1.42 ($Cdn/$U.S.), based on a notional principal amount of $U.S.1,000,000
per month. On June 19, 1998, PrimeWest renegotiated a new rate of $1.4487
($Cdn/$U.S.), with a maturity date of December 31, 1999. The effect of this swap
agreement was a reduction in sales revenue of $444,100 in 1999. This swap
expired on December 31, 1999. There were no foreign exchange rate hedges in
place in 2000.
c) INTEREST-RATE RISK MANAGEMENT
During 1998, PrimeWest entered into two agreements to fix the interest rate on
$25 million of debt at BA rates of 5.495 percent until June 2000, and on $15
million of debt at BA rates of 5.535 percent until June 2001. The effect of
these swaps was an increase in the interest paid for 2000 by $60,150 (1999 --
$228,403). The fair value of the unexpired interest rate swap at December 31,
2000 was a gain of $6,095 (1999 -- gain of $63,420).
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 fair market value of this interest rate swap at December 31, 2000
was a loss of $858,767.
d) FAIR VALUE OF FINANCIAL INSTRUMENTS
Financial instruments include cash, short-term investments, accounts receivable,
accounts payable and accrued liabilities, accrued distributions to unitholders,
long-term debt and financial hedges. As at December 31, 2000 and 1999, 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. SUBSEQUENT EVENT
On February 16th, 2001, PrimeWest and Cypress Energy Inc. announced that they
had entered into an agreement where PrimeWest offered to purchase all of the
issued and outstanding Class A and B common shares of Cypress. On March 29,
2001, PrimeWest announced the successful completion of the transaction whereby
97% of the outstanding Cypress shares were tendered to the bid. PrimeWest
acquired the remaining shares under the compulsory acquisition provisions of
Canadian corporate law. Accordingly, Pr i meWest issued 50.2 million trust
units, 5.44 million exchangeable shares and paid $58.4 million in cash pursuant
to the takeover bid offer.
ADDITIONAL INFORMATION ABOUT PRIMEWEST IS CONTAINED IN THE ANNUAL
INFORMATION FORM (AIF) AND OTHER DOCUMENTS CONTAINED ON THE PRIMEWEST WEB
SITE, LOCATED AT WWW.PRIMEWESTENERGY.COM.
WITHIN PRIMEWEST'S AIF, UNITHOLDERS CAN FIND A DETAILED DESCRIPTION OF
PRIMEWEST'S MAJOR PROPERTIES (INCLUDING 2000 DEVELOPMENT
ACTIVITIES AND 2001 PLANS).
SUPPLEMENTARY INFORMATION
OPERATING HIGHLIGHTS
4 mos
2000 1999 1998 1997 1996
- --------------------------------------------------------------------------------------------------------------
DAILY SALES VOLUMES
Crude oil (barrels per day) 6,582 5,958 5,868 3,737 3,372
Natural gas liquids (barrels per day) 1,483 1,293 1,226 1,137 993
Natural gas (millions of cubic feet per day) 49.03 46.46 50.41 42.22 31.47
----------------------------------------------------------
16,237 14,995 15,497 11,913 9,610
==========================================================
AVERAGE SELLING PRICES
Crude oil (dollars per barrel) $36.67 $21.69 $16.92 $25.93 $30.93
Natural gas liquids (dollars per barrel) $34.42 $19.09 $14.55 $22.65 $23.87
Natural gas (dollars per thousand cubic feet) $ 4.65 $ 2.51 $ 1.83 $ 1.85 $ 1.59
----------------------------------------------------------
Total (dollars per barrel of oil equivalent) $32.19 $17.95 $13.58 $16.94 $18.64
==========================================================
2001 2000 1999 1998 1997
- --------------------------------------------------------------------------------------------------------------
ESTABLISHED RESERVES
Crude oil (millions of barrels) 24.4 20.0 21.7 15.3 12.6
Natural gas liquids (millions of barrels) 6.4 6.1 6.5 6.7 4.5
Natural gas (billions of cubic feet) 232.7 224.0 243.5 227.3 191.0
----------------------------------------------------------
Total (millions of barrels of oil equivalent) 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%) 623.0 328.0 313.0 298.0 226.6
Unproved lands 17.2 10.2 10.6 8.4 2.3
Other assets 0.1 6.9 4.2 3.5 3.5
Long-term debt (78.9) (92.2) (73.0) (66.7) (14.2)
----------------------------------------------------------
Total net asset value 561.4 252.9 254.8 243.2 218.2
==========================================================
Per trust unit $10.55 $ 7.07 $ 7.72 $ 9.75 $ 8.76
==========================================================
SUPPLEMENTARY INFORMATION
RESERVES
Jan. 1, Jan. 1, Jan. 1, Jan. 1,
Natural 2001 2000 1999 1998
Natural gas total total total total
Crude oil gas liquids reserves reserves reserves reserves
(MBBL) (MMCF) (MBBL) (MBOE) (MBOE) (MBOE) (MBOE)
- ---------------------------------------------------------------------------------------------------------------
RESERVES SUMMARY
As at January 1, 2001
Proved producing 17,804 162,133 4,074 48,900 45,326 45,868 40,624
Total proved 20,166 192,590 4,885 57,149 50,963 54,068 47,549
Probable 8,405 80,256 3,072 24,855 25,350 29,607 24,588
Total proved and probable 28,571 272,846 7,957 82,004 76,313 83,675 72,138
Established 24,369 232,725 6,421 69,577 63,638 68,871 59,843
% of total established reserves 35% 56% 9%
==============================
NOTE: GAS CONVERTED TO BOE ON THE BASIS OF 6:1
2000 1999 1998 1997
(MMBOE) (MMBOE) (MMBOE) (MMBOE)
- --------------------------------------------------------------------------------------------
Opening reserves 63.6 68.9 59.8 48.9
Capital additions 0.6 0.8 6.4 6.2
Technical revisions 1.5 (4.7) 0.6 1.7
Acquisitions 10.9 6.6 10.4 7.7
Dispositions (1.1) (2.6) (2.6) (0.3)
Production (5.9) (5.3) (5.7) (4.3)
------------------------------------------
Ending reserves 69.6 63.6 68.9 59.8
==========================================
Acres Net value
GROSS NET ($)
- ------------------------------------------------------------------------------------
UNPROVED LANDS
Sundre
Caroline 71,237 56,841 3,279,350
Garrington 23,638 12,329 206,100
Westward Ho 9,230 8,448 193,100
Kobes Creek 7,160 2,864 253,100
Southeastern Alberta 53,648 30,397 981,642
Crossfield/Lone Pine Creek 55,060 42,181 4,659,092
Boundary Lake 4,820 4,620 9,900
Gross Overriding Royalty Interests 243,797 243,797 3,678,909
Others 61,840 46,686 3,976,909
------------------------------------
Total 530,430 448,163 17,238,102
====================================
SUPPLEMENTARY INFORMATION
RESERVES
AS AT JANUARY 1, 2001 ESTABLISHED PROVED PROBABLE
- -----------------------------------------------------------------------------------------
RESERVES BY MAJOR PROPERTY
CRUDE OIL (Mbbl)
Sundre(1) 2,012 1,491 1,041
Laprise Creek -- -- --
Southeastern Alberta(2) 7,923 6,554 2,737
Crossfield/Lone Pine Creek 314 260 107
Boundary Lake 5,151 4,674 953
Kaybob 1,624 1,382 483
Others 7,345 5,805 3,084
------------------------------------------
Total 24,369 20,166 8,405
NATURAL GAS (Bcf)
Sundre(1) 60.9 45.0 31.8
Laprise Creek 45.3 40.2 10.2
Southeastern Alberta(2) 33.5 29.3 8.5
Crossfield/Lone Pine Creek 49.4 40.3 18.1
Boundary Lake .5 .5 -
Kaybob 1.2 1.0 .3
Others 41.9 36.3 11.3
------------------------------------------
Total 232.7 192.6 80.2
NATURAL GAS LIQUIDS (Mbbl)
Sundre(1) 3,309 2,410 1,797
Laprise Creek 1,157 809 695
Southeastern Alberta(2) 61 55 12
Crossfield/Lone Pine Creek 584 466 236
Boundary Lake 45 42 6
Kaybob 125 110 30
Others 1,140 993 296
------------------------------------------
Total 6,421 4,885 3,072
(1) INCLUDES GARRINGTON, CAROLINE, WESTWARD HO & RICINUS PROPERTIES
(2) INCLUDES GRAND FORKS, MEDICINE HAT, PATRICIA/DINOSAUR & ENCHANT PROPERTIES
SUPPLEMENTARY INFORMATION
RESERVES
Discounted Discounted Discounted Discounted
AS AT JANUARY 1, 2001 @ 0% @ 10% @ 12% @ 15%
- ----------------------------------------------------------------------------------------------------------
PRESENT WORTH OF RESERVES
(THOUSANDS OF DOLLARS)
Proved producing 784,004 484,709 453,689 415,511
Total proved 907,679 549,580 512,361 466,610
Probable 401,638 147,927 128,958 107,405
Total proved and probable 1,309,317 697,507 641,318 574,015
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
($U.S./BBL) ($/BBL) ($U.S./$C)
- -----------------------------------------------------------------------------------------------------------
CRUDE OIL PRICING ASSUMPTIONS
2001 26.73 39.67 0.6587
2002 23.80 34.63 0.6667
2003 21.51 30.56 0.6800
2004 21.58 30.20 0.6900
2005 21.90 30.24 0.7000
Next 10 years 24.04 32.39 0.7180
Thereafter (annual escalation) 1% 1% 0.7200
==========================================
Alberta
Henry Hub Government BC direct
($U.S./ market wellhead
MMBTU) ($/MMBTU) ($/MMBTU)
- -----------------------------------------------------------------------------------------------------------
NATURAL GAS PRICING ASSUMPTIONS
2001 5.35 7.04 7.42
2002 4.13 5.11 5.42
2003 3.57 4.32 4.46
2004 3.38 3.99 4.11
2005 3.37 3.96 4.03
Next 10 years 3.68 4.23 4.26
Thereafter (annual escalation) 1% 1% 1%
2001 2000 1999 1998 1997
- ----------------------------------------------------------------------------------------------------------
ESTABLISHED RESERVE LIFE INDEX 10.2 10.9 11.1 12.2 11.1
============================================================
(YEARS)
SUPPLEMENTARY INFORMATION
PRODUCTION
Natural
Crude Natural gas
oil gas liquids Total
(BBL/D) (MCF/D) (BBL/D) (BOE/D)
- ----------------------------------------------------------------------------------------------------------
2000
Sundre(1) 747 12,041 654 3,408
Laprise Creek 25 9,294 169 1,743
Southeastern Alberta(2) 3,061 6,320 31 4,145
Crossfield/Lone Pine Creek 100 12,157 223 2,349
Boundary Lake 818 -- 4 822
Kaybob 611 259 67 721
Other areas 1,220 8,961 335 3,049
------------------------------------------------------
Total 6,582 49,032 1,483 16,237
======================================================
1999
Sundre(1) 885 13,512 711 3,848
Laprise Creek 27 9,797 164 1,824
Southeastern Alberta(2) 2,821 4,413 13 3,570
Crossfield/Lone Pine Creek 94 12,775 192 2,415
Boundary Lake 745 118 - 765
Kaybob 775 469 73 926
Other areas 611 5,374 140 1,647
-----------------------------------------------------
Total 5,958 46,458 1,293 14,995
=====================================================
1998
Sundre(1) 1,074 11,252 581 3,530
Laprise Creek 37 11,521 154 2,112
Southeastern Alberta(2) 2,329 3,797 8 2,970
Crossfield/Lone Pine Creek 80 14,416 163 2,646
Boundary Lake 753 240 5 798
Kaybob 898 393 137 1,101
Other areas 697 8,790 178 2,340
-----------------------------------------------------
Total 5,868 50,409 1,226 15,497
=====================================================
1997
Sundre(1) 895 11,746 609 3,462
Laprise Creek 32 10,492 120 1,901
Southeastern Alberta(2) - - - -
Crossfield/Lone Pine Creek 71 12,708 154 2,343
Boundary Lake 789 67 4 804
Kaybob 1,223 613 80 1,405
Other areas 727 6,595 169 1,998
-----------------------------------------------------
Total 3,737 42,221 1,137 11,913
=====================================================
(1) INCLUDES GARRINGTON, CAROLINE, WESTWARD HO & RICINUS PROPERTIES
(2) INCLUDES GRAND FORKS, MEDICINE HAT, PATRICIA/DINOSAUR & ENCHANT PROPERTIES
SUPPLEMENTARY INFORMATION
PRODUCTION
4 mos
2000 1999 1998 1997 1996
- ----------------------------------------------------------------------------------------------------------
CRUDE OIL (barrels per day)
First quarter 5,763 6,154 4,780 3,680 --
Second quarter 6,038 5,805 6,206 3,843 --
Third quarter 7,087 5,957 6,264 3,646 --
Fourth quarter 7,422 5,919 6,201 3,778 --
------------------------------------------------------------
Total average 6,582 5,958 5,868 3,737 3,372
============================================================
NATURAL GAS LIQUIDS (barrels per day)
First quarter 1,264 1,342 1,278 1,045 --
Second quarter 1,537 1,277 1,254 948 --
Third quarter 1,521 1,193 1,185 1,416 --
Fourth quarter 1,610 1,360 1,188 1,134 --
------------------------------------------------------------
Total average 1,483 1,293 1,226 1,137 993
============================================================
NATURAL GAS (MMcf per day)
First quarter 48.13 48.91 49.18 40.25 --
Second quarter 48.39 47.34 54.00 36.24 --
Third quarter 52.10 41.27 49.95 43.31 --
Fourth quarter 47.49 48.40 48.51 48.97 --
------------------------------------------------------------
Total average 49.03 46.50 50.41 42.22 31.47
============================================================
TOTAL OIL EQUIVALENT (BOE per day)
First quarter 15,044 15,648 14,255 11,433 --
Second quarter 15,642 14,972 16,460 10,831 --
Third quarter 17,291 14,028 15,774 12,280 --
Fourth quarter 16,949 15,346 15,474 13,073 --
------------------------------------------------------------
Total average 16,237 14,995 15,497 11,913 9,610
============================================================
Natural gas as a percentage of production 50% 52% 54% 59% 54%
AVERAGE SELLING PRICES
Crude oil ($/bbl) $36.67 $21.69 $16.92 $25.93 $30.93
Natural gas liquids ($/bbl) $34.42 $19.09$ $14.55 $22.65 $23.87
Natural gas ($/Mcf) $ 4.65 $2.51 $1.83 $1.85 $1.59
------------------------------------------------------------
Combined ($/BOE) $32.19 $17.95 $13.58 $16.94 $18.64
============================================================
OPERATING NETBACK (dollars per BOE)
Sales revenue 32.19 17.95 13.58 16.94 18.64
Other revenue 0.08 0.04 0.05 0.04 --
Royalties (5.92) (3.14) (2.28) (3.27) (3.25)
Operating expenses (5.08) (5.23) (5.40) (4.89) (4.45)
Operating netback 21.27 9.62 5.95 8.82 10.94
============================================================
SUPPLEMENTARY INFORMATION
FINANCIAL HIGHLIGHTS
4 mos
2000 1999 1998 1997 1996
- -----------------------------------------------------------------------------------------------------------
Cash flow from operations 112,062 41,081 24,806 32,086 11,608
per BOE 18.86 7.51 4.39 7.38 9.90
per trust unit 2.51 1.21 0.79 1.29 0.46
Operating revenues, net of royalties 156,561 81,282 64,257 59,592 18,043
per BOE 26.34 14.85 11.36 13.71 15.39
per trust unit 3.51 2.39 2.04 2.39 2.17
Operating expenses 30,175 28,609 30,550 21,270 5,218
per BOE 5.08 5.23 5.40 4.89 4.45
per trust unit 0.68 0.84 0.97 0.85 0.63
Cash G&A expenses 4,140 5,321 5,108 3,708 787
per BOE 0.70 0.97 0.90 0.85 0.67
per trust unit 0.09 0.16 0.16 0.15 0.09
Cash management fees 3,277 1,386 882 923 335
per BOE 0.55 0.25 0.16 0.21 0.28
per trust unit 0.07 0.04 0.03 0.04 0.04
Financing costs 6,359 4,885 4,711 2,140 95
per BOE 1.07 0.89 0.83 0.49 0.08
per trust unit 0.14 0.14 0.15 0.09 0.01
Operating netback 126,386 52,673 33,707 38,322 12,825
per BOE 21.27 9.62 5.95 8.82 10.94
per trust unit 2.83 1.55 1.07 1.54 1.54
Cash distributed to unitholders 79,033 37,351 25,769 33,409 10,956
per trust unit 1.77 1.10 0.82 1.34 0.44
================================================================
SUPPLEMENTARY INFORMATION
FINANCIAL HIGHLIGHTS
4 mos
(THOUSANDS OF DOLLARS, EXCEPT UNIT AND PER-UNIT) 2000 1999 1998 1997 1996
- ----------------------------------------------------------------------------------------------------------
Cumulative cash distributions 186,518 107,485 70,134 44,365 10,956
Per trust unit 5.47 3.70 2.60 1.78 0.44
Units outstanding at year-end 50,982 35,769 33,023 24,950 24,900
Weighted average trust units outstanding 44,652 33,965 31,426 24,931 24,900
Exchangeable shares outstanding 1,112 -- -- -- --
Exchange ratio at year-end 1.0933 -- -- -- --
Capital expenditures, net of dispositions 143,592 32,910 65,192 49,724 242,623
Working capital (deficit) (254) 5,850 2,369 1,845 1,308
Reclamation fund balance 398 1,060 1,781 1,738 2,223
Total assets 434,238 320,210 316,140 285,765 254,480
Net asset value 561,400 252,900 254,800 243,200 218,200
Net asset value per trust unit 10.55 7.07 7.72 9.75 8.76
Total capitalization (including debt) 546,380 323,718 237,403 276,953 294,290
====================================================
DEBT ANALYSIS
Long-term debt, net of working capital 79,208 85,854 70,637 64,878 12,920
Debt-to-annual-cash-flow ratio 0.71 2.10 2.85 2.02 0.37
Debt-to-equity ratio 27.3% 46.1% 34.2% 34.5% 6.4%
Interest-coverage ratio 17.6 8.5 6.0 15.5 115.6
Average cost of debt 7.4% 5.9% 6.3% 4.8% 3.8%
Net debt per trust unit 1.52 2.41 2.14 2.60 0.52
====================================================
TAX POOLS (consolidated)
Canadian oil and gas property expense (COGPE) 299,000 255,000 263,400 225,600 221,800
Canadian exploration expense (CEE) 5,700 -- 1,850 300 --
Canadian development expense (CDE) 9,000 -- -- 7,200 --
Capital cost allowance (CCA) 35,850 24,425 32,330 25,000 13,600
Unit issue expenses 6,245 8,300 14,600 11,900 15,100
====================================================
SUPPLEMENTARY INFORMATION
TRADING PERFORMANCE
First Second Third Fourth
quarter quarter quarter quarter
2000 2000 2000 2000 2000 1999 1998 1997 1996
- ----------------------------------------------------------------------------------------------------------
TRUST UNIT
TRADING
PERFORMANCE
Trust unit price: High 7.40 8.10 8.85 9.30 9.30 7.70 8.75 11.45 12.15
($) Low 6.30 6.30 7.75 8.45 6.30 4.75 4.75 7.50 11.20
Close 6.40 8.05 8.40 8.95 8.95 6.65 5.05 8.50 11.30
Average daily
volume traded 72,532 126,301 152,142 135,041 121,256 49,767 55,318 42,323 273,763
=================================================================================
MARKET INDICATORS
Average prices
WTI ($U.S. per barrel) 28.91 28.95 31.65 31.98 30.37 19.27 19.40 20.58 22.00
Exchange rate
($U.S./$Cdn) 0.69 0.68 0.67 0.66 0.67 0.67 0.67 0.72 0.73
Closing prices
Government of Canada
10-year bond yield 5.92% 5.86% 5.74% 5.40% 5.40% 6.26% 4.91% 5.62% 6.41%
TSE 300 Index 9,462 10,195 10,378 8,934 8,934 8,414 6,486 6,699 5,927
TSE Oil and Gas
Producers Index 5,184 6,383 6,916 7,271 7,271 4,976 4,074 5,869 6,577
=================================================================================
2000 1999 1998 1997 1996
DISTRIBUTIONS DECLARED
(dollars per trust unit)
First quarter 0.30 0.18 0.24 0.35 --
Second quarter 0.39 0.23 0.22 0.30 --
Third quarter 0.48 0.34 0.18 0.30 --
Fourth quarter 0.60 0.35 0.18 0.39 0.44(1)
------------------------------------------------------------
Total $1.77 $1.10 $0.82 $1.34 $0.44
------------------------------------------------------------
% tax-deferred 47% 100% 100% 100% 100%
============================================================
(1) REPRESENTS FOUR MONTHS
PRIMEWEST
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.
DOES PRIMEWEST CONFORM TO THE GUIDELINES?
TSE CORPORATE GOVERNANCE GUIDELINES
1. The Board of directors should explicitly assume responsibility for the
stewardship of the company, specifically:
(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 monitors
to ensure that there is congruence between strategic plans, performance and
unitholder expectations.
(b.) IDENTIFYING PRINCIPAL RISKS AND ENSURING THE IMPLEMENTATION OF SYSTEMS TO
MANAGE THESE RISKS 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 The Corporate Governance and Compensation Committee
oversees PrimeWest's compensation 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
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.
(e.) ASSUMING RESPONSIBILITY FOR THE INTEGRITY OF INTERNAL CONTROL AND
MANAGEMENT SYSTEMS
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).
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 Compensation Committee,
consisting only of unrelated directors, whose mandate is to carry out this
responsibility. Procedures for assessing performance are currently being
formulated.
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.
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 recruits to the Board.
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 reducing to improve decision-making. 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.
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.
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.
The Corporate Governance and Compensation Committee focusses 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 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 the
company, who have written descriptions of their objectives.
(B.) APPROVE OR DEVELOP THE CORPORATE OBJECTIVES FOR THE BOARD AND FOR THE
CEO 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.
The Chairman of the Board is an unrelated director and independent of
management. 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 directors, which has a clearly defined mandate and
appropriate oversight.
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.
In circumstances considered to be appropriate by the Corporate Governance
and Compensation Committee, an individual director may engage an outside
advisor at company expense.
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 monitors 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's compensation
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.
(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
Compensation Committee, consisting only of
unrelated directors, whose mandate is to carry
out this responsibility. Procedures for
assessing performance are currently being
formulated.
PARTIALLY 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.
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 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 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.
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:
YES (A) DEVELOP POSITION DESCRIPTIONS FOR THE BOARD
AND FOR THE CEO, SETTING OUT LIMITS YES TO
MANAGEMENT'S RESPONSIBILITIES
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.
YES (B)APPROVE OR DEVELOP THE CORPORATE OBJECTIVES
FOR THE BOARD AND FOR THE CEO
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. 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 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 Compensation
Committee, an individual director may engage an
outside advisor at company expense.
DISTRIBUTION REINVESTMENT AND OPTIONAL TRUST UNIT PURCHASE PLAN
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, the plans have enabled unitholders to reinvest their monthly
distributions automatically and make additional annual investments of between
$100 and $20,000 -- without incurring brokerage fees and with a 5% discount off
the market price at the time.
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. Directions
for mailing are also there.
For further information, contact Computershare Trust Company of Canada, formerly
The Trust Company of Bank of Montreal -- using a toll-free phone number
(800-332-0095) or fax (514-982-7665). Or, consult the DRIP section of the
PrimeWest Web site located at www.primewestenergy.com.
FORWARD-LOOKING
STATEMENTS
This annual report contains forward-looking statements with respect to
PrimeWest.
Because forward-looking statements address future events and conditions, they
involve risks and uncertainties that could cause actual results to differ
materially from those contemplated by the forward-looking statements. These
risks and uncertainties include: commodity price levels and differentials;
production levels; new information about the recoverability of reserves;
operating and other costs; interest rates and currency-exchange rates; and
changes in environmental and other legislation and regulations.
They also include other risks detailed from time to time in other publicly filed
disclosure documents and securities commission reports of PrimeWest.
INDEPENDENT DIRECTORS
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HAROLD P. MILAVSKY, FCA HAROLD N. KVISLE, P. MICHAEL W. O'BRIEN BARRY E. EMES, LL.B.
CHAIRMAN, ENG. INDEPENDENT INDEPENDENT DIRECTOR INDEPENDENT DIRECTOR
INDEPENDENT DIRECTOR DIRECTOR
MR. MILAVSKY IS CHAIRMAN OF
QUANTICO CAPITAL CORP., A MR. KVISLE IS PRESIDENT MR. O'BRIEN IS A 30-YEAR MR. EMES IS MANAGING
PRIVATELY HELD COMPANY AND CHIEF EXECUTIVE VETERAN OF THE PETROLEUM PARTNER OF THE CALGARY
ENGAGED IN MERCHANT OFFICER OF TRANSCANADA BUSINESS AND CURRENTLY OFFICE OF STIKEMAN
BANKING, PRINCIPAL PIPELINES LIMITED, AND IS THE EXECUTIVE ELLIOTT AND A PARTNER IN
INVESTMENTS AND HE ACTS AS A DIRECTOR VICE-PRESIDENT, THE FIRM'S
ACQUISITIONS. MR. MILAVSKY OF SEVERAL COMPANIES CORPORATE DEVELOPMENT CORPORATE/COMMERCIAL
SERVES AS A DIRECTOR OF AND LIMITED AND CHIEF FINANCIAL GROUP. IN HIS PRACTICE,
ASPEN PROPERTIES LTD., PARTNERSHIPS WITHIN THE OFFICER OF SUNCOR ENERGY HE HAS COUNSELLED
TELUS CORPORATION INC., TRANSCANADA GROUP. MR. INC. HE SERVES, AMONG BORROWERS AND LENDERS IN
CITADEL DIVERSIFIED KVISLE ALSO IS A HIS OTHER FINANCINGS; SELLERS AND
MANAGEMENT LTD., CITADEL S1 DIRECTOR OF NORSKE SKOG RESPONSIBILITIES, AS THE PURCHASERS OF SHARES AND
MANAGEMENT LTD., CITADEL CANADA AND OF ARC CURRENT CHAIR OF OTHER ASSETS; AND
TEF MANAGEMENT LTD., ENCAL STRATEGIC ENERGY FUND. CANADA'S CLIMATE CHANGE INDEPENDENT COMMITTEES
ENERGY INC., ENMAX VOLUNTARY CHALLENGE AND AND FINANCIAL ADVISORS
CORPORATION, TORODE REALTY REGISTRY INC. (VCR WITH RESPECT TO
LIMITED AND TRANSCANADA INC.). CORPORATE ACQUISITIONS.
PIPELINES LIMITED.
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SENIOR OFFICERS
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KENT J. MACINTYRE RONALD J. AMBROZY, P. ENG. SUSAN M. DUNCAN, CA TIMOTHY S. GRANGER,
VICE-CHAIRMAN AND CHIEF VICE-PRESIDENT, VICE-PRESIDENT, FINANCE P. ENG.
EXECUTIVE OFFICER, DIRECTOR BUSINESS DEVELOPMENT VICE-PRESIDENT, PRODUCTION
MR. MACINTYRE HAS MORE THAN
21 YEARS OF OIL AND GAS MR. AMBROZY HAS BEEN A GRADUATE OF THE COMMERCE MR. GRANGER IS A GRADUATE
EXPERIENCE, THE LAST 12 AS A ACTIVE IN THE OIL AND GAS PROGRAM AT THE UNIVERSITY OF CARLETON UNIVERSITY'S
PRINCIPAL IN THE START-UP AND INDUSTRY SINCE 1975, OF LETHBRIDGE, MS. DUNCAN ENGINEERING PROGRAM. HE
MANAGEMENT OF OIL AND GAS INITIALLY HOLDING HAS MORE THAN 16 YEARS OF HAS MORE THAN 21 YEARS OF
VENTURES. PRIOR TO PROGRESSIVELY MORE EXPERIENCE IN FINANCE, OIL AND GAS EXPERIENCE IN
ESTABLISHING PRIMEWEST, HE RESPONSIBLE POSITIONS WITH ACCOUNTING, AUDITING AND DRILLING, PRODUCTION
WAS PRESIDENT AND CEO OF GULF CANADA. DURING THE TAX. FOR TEN YEARS OF HER OPERATIONS AND PROPERTY
TRIAD ENERGY INC., AND BEFORE LAST 12 YEARS OF HIS CAREER, SHE WORKED IN DEVELOPMENT INCLUDING
THAT, PRESIDENT AND CEO OF CAREER, HE HAS LED THE PUBLIC PRACTICE, BECOMING POSITIONS AT PETRO-CANADA
OLYMPIA ENERGY VENTURES LTD. EVALUATION OF PROPERTIES A PRINCIPAL AT THE AND AMERADA HESS. BEFORE
HE IS A DIRECTOR OF BLACKROCK AND COMPLETION OF CHARTERED ACCOUNTING FIRM TAKING A LEADERSHIP ROLE
VENTURES INC., CAPTURE ENERGY TRANSACTIONS WORTH MORE OF COOPERS AND LYBRAND. AT PRIMEWEST IN JUNE 1999,
LTD., CITADEL DIVERSIFIED THAN $3 BILLION. A PRIOR TO JOINING PRIMEWEST MR. GRANGER HEADED THE
MANAGEMENT LTD., CITADEL S1 GRADUATE OF THE UNIVERSITY IN 1996, MS. DUNCAN WAS CANADIAN OPERATIONS OF A
MANAGEMENT LTD., CITADEL TEF OF MANITOBA'S ENGINEERING TREASURER OF TRIAD ENERGY COMPANY BASED IN THE
MANAGEMENT LTD., AND GLR PROGRAM, MR. AMBROZY INC. UNITED STATES.
SOLUTIONS LTD. MR. MACINTYRE JOINED PRIMEWEST IN 1997.
HOLDS A B.SC. (ENGINEERING) HE CHAIRS THE PETROLEUM
DEGREE FROM THE UNIVERSITY OF ACQUISITION AND DIVESTMENT
MANITOBA AND AN MBA FROM THE ASSOCIATION.
UNIVERSITY OF CALGARY.
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CORPORATE INFORMATION
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DIRECTORS OFFICERS REGISTRAR AND TRANSFER AGENT
HAROLD P. MILAVSKY(1) HAROLD P. MILAVSKY Computershare Trust Company
Chairman Chairman of Canada
Quantico Capital Corp. Toll-free in Canada:
KENT J. MACINTYRE 1-800-332-0095
KENT J. MACINTYRE(2) Vice-chairman and Chief Executive
Vice-chairman and Officer AUDITOR
Chief Executive Officer PricewaterhouseCoopers LLP, Calgary
PrimeWest Energy Inc. RONALD J. AMBROZY
Vice-president, Business Development ENGINEERING CONSULTANT
BARRY E. EMES(1) Gilbert Laustsen Jung
Partner JAMES T. BRUVALL Associates Ltd., Calgary
Stikeman Elliott Secretary
LEGAL COUNSEL
HAROLD N. KVISLE(1) SUSAN M. DUNCAN Stikeman Elliott,
President and Chief Executive Officer Vice-president, Finance Calgary
TransCanada Pipelines Limited
TIMOTHY S. GRANGER FOR FURTHER INFORMATION
MICHAEL W. O'BRIEN(1) Vice-president, Production General inquiries
Executive Vice-president 403-234-6600
Corporate Development and ANN C. LANIEL
Chief Financial Officer Land Manager Investor Relations
Suncor Energy Inc. Toll-free in Canada:
HEAD OFFICE 1-877-968-7878
(1) MEMBER OF THE AUDIT COMMITTEE AND 4700, 150 - 6 Avenue SW
THE CORPORATE GOVERNANCE AND Calgary, AB Canada T2P 3Y7 e-mail: investor@primewestenergy.com
COMPENSATION COMMITTEE Telephone: 403-234-6600
(2) NOMINEE OF THE MANAGER Toll-free in Canada:
1-877-968-7878
WEB SITE:
www.primewestenergy.com
TRUST UNITS TRADED
The Toronto Stock Exchange, (PWI.UN)
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