EXHIBIT 9
---------
PRIMEWEST ENERGY TRUST 2002 QUARTERLY REPORT TO THE UNITHOLDERS
FOR THE SIX MONTHS ENDED JUNE 30, 2002
PRIMEWEST 2
- --------------------------------------------------------------------------------
CALGARY, JULY 29, 2002 (TSX: PWI.UN; PWX) -- PRIMEWEST ENERGY TRUST (PRIMEWEST)
TODAY ANNOUNCED UNAUDITED INTERIM OPERATING AND FINANCIAL RESULTS FOR THE SECOND
QUARTER.
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PRIMEWEST ENERGY TRUST PRODUCTION VOLUMES IN TARGET RANGE
FOR QUARTER, CASH FLOW $0.31 PER TRUST UNIT
SECOND QUARTER HIGHLIGHTS
- - Cash flow from operations of $40.2 million ($0.31 per unit) compared to
$48.3 million for the first quarter, reflecting lower volumes and increased
royalties for the second quarter. Distributions remained unchanged from the
first quarter at $0.30 per unit. This level of distribution represents a
17% cash-on-cash yield based on the July 26th closing price of $6.90.
- - Production averaged 29,559 barrels of oil equivalent per day (BOE/day) for
the second quarter, within the target range of 29,000 - 30,000 BOE/day, but
6% below the first quarter result. Scheduled turnarounds for facility
maintenance and new well tie-ins as well as unplanned outages at certain
non-operated facilities contributed to the decrease.
- - Operating expenses increased to $5.44 per BOE for the quarter compared to
$5.10 per BOE for the first quarter. Lower volumes and turnaround
maintenance expenses led to the increase.
- - Royalty expenses increased to $14.6 million in the second quarter from
$10.7 million in the first quarter, reflecting higher operating revenues
before hedging gains. Also, the first quarter benefited from a one-time
$1.8 million mineral tax adjustment.
- - Net debt increased to $240.9 million at June 30, 2002 from $234.4 million
at March 31, 2002. Capital expenditures of $12.4 million were partially
offset by proceeds from the Distribution Reinvestment and Optional Trust
Unit Purchase programs. The debt-to-cash flow ratio increased to 1.5 times
at June 30 compared to 1.2 times at March 31.
"Production volumes were lower in the second quarter, reflecting several
scheduled maintenance outages combined with several third party processing
outages," said Don Garner, President and Chief Operating Officer. "Based on the
success of our development program, we remain confident that we will meet our
target of 29,000 - 30,000 BOE/day average production for the full year 2002."
CASH FLOW RECONCILIATION (THOUSANDS)
First quarter cash flow $48,301
Production volume (3,531)
Commodity price 15,762
Hedging gain (16,736)
Royalty expense (3,900)
Other 330
-------
Second quarter cash flow $40,226
=======
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WE ARE ONE OF NORTH AMERICA'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 PREDICTABLE AND SUSTAINABLE CASH DISTRIBUTIONS
MONTHLY, WITHIN THE CONTEXT OF A COMMODITY-BASED BUSINESS ENVIRONMENT.
PRIMEWEST ENERGY TRUST
FINANCIAL & OPERATING HIGHLIGHTS
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FINANCIAL HIGHLIGHTS
(THOUSANDS OF DOLLARS EXCEPT PER-BOE AND PER-TRUST-UNIT AMOUNTS)
THREE MONTHS ENDED SIX MONTHS ENDED
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JUN. 30, MAR. 31, JUN. 30, JUN. 30, JUN. 30,
2002 2002 2001 2002 2001
---------- ----------- ---------- ----------- ----------
Net revenue $62,198 $69,442 $87,974 $131,640 $144,964
Per BOE 23.13 24.60 27.35 23.88 30.62
Cash flow from operations 40,226 48,301 61,825 88,527 105,359
Per BOE 14.95 17.11 19.22 16.06 22.25
Royalty expense 14,566 10,666 27,650 25,232 43,301
Per BOE 5.41 3.78 8.59 4.58 9.14
Operating expenses 14,639 14,393 15,704 29,033 24,044
Per BOE 5.44 5.10 4.88 5.27 5.08
G&A expenses - Cash 2,915 2,635 2,795 5,549 5,068
Per BOE 1.08 0.93 0.87 1.01 1.07
- Non-cash 1,623 5,351 2,294 6,973 7,489
Per BOE 0.60 1.90 0.71 1.26 1.58
Management fees - Cash 1,264 1,418 1,862 2,682 3,131
Per BOE 0.47 0.50 0.58 0.49 0.66
- Non-cash 485 479 528 965 1,011
Per BOE 0.18 0.17 0.16 0.17 0.21
Cash distributed to unitholders 38,418 38,131 70,288 76,548 111,072
Per Trust Unit 0.30 0.30 0.66 0.60 1.26
Cash flow from operations
Per Trust Unit 0.31 0.37 0.58 0.69 1.19
Net debt (1) 240,913 234,415 290,233 240,913 290,233
Per Trust Unit 1.79 1.77 2.40 1.79 2.40
(1) NET DEBT IS LONG-TERM DEBT PLUS NEGATIVE WORKING CAPITAL.
OPERATING HIGHLIGHTS
THREE MONTHS ENDED SIX MONTHS ENDED
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JUN. 30, MAR. 31, JUN. 30, JUN. 30, JUN. 30,
2002 2002 2001 2002 2001
---------- ----------- ---------- ----------- ----------
Daily sales volumes
Natural gas (MMCF/DAY) 111.09 113.31 127.72 112.19 88.86
Crude oil (BBLS/DAY) 8,990 10,244 11,453 9,614 9,233
Natural gas liquids (BBLS/DAY) 2,055 2,240 2,614 2,147 2,117
Total (BOE/DAY) 29,559 31,370 35,353 30,460 26,160
Prices (CDN $)
Natural gas ($/MCF) 4.47 4.57 6.21 4.52 7.37
Crude oil ($/BBL) 32.96 32.09 33.59 32.50 33.12
Natural gas liquids ($/BBL) 25.77 20.87 35.35 23.23 37.19
Total ($ PER BOE) 28.61 28.49 35.94 28.55 39.73
PRIMEWEST ENERGY TRUST
MANAGEMENT'S DISCUSSION & ANALYSIS (MD&A)
3 [GRAPHIC OMITTED -- COMPANY LOGO]
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The following discussion is management's analysis of PrimeWest's operating and
financial results for the quarter ended June 30, 2002 compared with the previous
quarter and the second quarter of 2001 as well for the six month periods ended
June 30, 2002 and June 30, 2001. This discussion also contains information and
opinions concerning the Trust's future outlook based on currently available
information. This discussion should be read in conjunction with the Trust's
annual MD&A and audited consolidated financial statements for the years ended
December 31, 2001 and 2000, together with the accompanying notes, as contained
in the Trust's 2001 Annual Report.
FORWARD-LOOKING INFORMATION
Because forward-looking information addresses future events and conditions, it
involves risks and uncertainties that could cause actual results to differ
materially from those contemplated by the forward-looking information. These
risks and uncertainties include commodity price levels; production levels; the
recoverability of reserves; transportation availability and costs; operating and
other costs; interest rates and currency-exchange rates; and changes in
environmental and other legislation and regulations. Please refer to the Trust's
annual report for more detail as to the nature of these risks and uncertainties.
STRATEGY 2002 OBJECTIVES YEAR-TO-DATE PERFORMANCE
ASSET GROWTH - Use the low cycles in the - Low commodity price cycle short-lived.
commodity price environment and Available acquisition targets generally
strong balance sheet to add poor quality in nature. No
high quality reserves to our acquisitions in the first half of 2002.
asset base.
- Maintain or increase our - Development program successful in
reserve life index. adding reserves and production.
OPERATING EXCELLENCE - Moderate natural production - Production met expectations for the
decline through prudent capital second quarter of 2002.
development.
- Add incremental production - Second quarter development success with
through drilling, completions 9 gross wells drilled at a 78% success
and workovers. rate.
- Reduce per BOE operating - Operating expenses increased to $5.44
expenses from 2001 levels. per BOE ($5.10 in the first quarter of
2002).
Year-to-date, per BOE costs of $5.27,
below the $5.42 full
year 2001 result.
FINANCIAL PRUDENCE - Maintain a strong financial - Debt-to-cash flow ratio has increased
position as measured by net to 1.50 at June 30, 2002 from 1.21 at
debt per Trust Unit and March 31, 2002. Net debt per trust
debt-to-cash flow ratio. unit $1.79 at June 30, 2002 compared to
$1.72 at December 31, 2002
RISK MANAGEMENT - Use hedging to stabilize and - Stabilized at $0.10 per month through
protect distribution levels; October of 2002.
manage distribution rates as
commodity prices cycle.
PRIMEWEST ENERGY TRUST
MANAGEMENT'S DISCUSSION & ANALYSIS (MD&A)
4 [GRAPHIC OMITTED -- COMPANY LOGO]
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PRODUCTION VOLUMES
THREE MONTHS ENDED SIX MONTHS ENDED
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JUN. 30, MAR. 31, JUN. 30, JUN. 30, JUN. 30,
2002 2002 2001 2002 2001
---------- ----------- ---------- ----------- ----------
Natural gas (MMCF/DAY) 111.09 113.31 127.72 112.19 88.86
Crude oil (BBLS/DAY) 8,990 10,244 11,453 9,614 9,233
Natural gas liquids (BBLS/DAY) 2,055 2,240 2,614 2,147 2,117
Total (BOE/DAY) 29,559 31,370 35,353 30,460 26,160
========== =========== ========== =========== ==========
Gross Overriding Royalty volumes
included above (BOE/DAY) 1,571 2,076 2,043 1,857 1,971
========== =========== ========== =========== ==========
Production volumes fell from first quarter levels as a result of scheduled
turnarounds for facility maintenance, planned production outages to accommodate
new gas well tie-ins, unplanned outages at several non-operated properties and
minor dispositions.
Despite these outages, gas volumes fell only 2% compared to the first quarter of
2002. Successful development activities, particularly at Dawson, mitigated the
impact of the outages.
Oil volumes fell 12% when compared to the first quarter of 2002. Approximately
42% of this decrease is the result of reduced GORR volumes. The first quarter of
2002 GORR volumes included an adjustment to reflect underaccrued volumes at the
end of 2001. A further 20% related to a temporary production curtailment at
Dawson. The balance reflects minor asset dispositions late in the first quarter
(200BOE/day) and natural decline as our 2002 development program is focused on
natural gas.
During the quarter, scheduled turnarounds were performed by PrimeWest at the
East Crossfield Gas Plant (occurs every two years) and the Laprise Creek gas
processing facility. The Dawson (Roxanna) and Brant Farrow gathering and
processing facilities were also shut-in to facilitate pipeline tie-ins and
compressor modifications to add incremental capacity for new gas wells drilled
by PrimeWest over the past six months. The production impairment related to
these scheduled activities was approximately 545 BOE/day for the quarter.
Unplanned outages at third party operated gas processing or gas transmission
facilities, since resolved in the third quarter, restricted production at the
Caroline, Medicine Hat and Brant Farrow areas by 180 BOE/day. A pipeline failure
at Whiskey Creek resulted in approximately 400 BOE/day production being shut-in
in May and June. The operator has advised PrimeWest that the necessary pipeline
system modifications required to resume production should be completed by
year-end. At Dawson (Normandville), production curtailments resulted in 250
bbls/day of oil production being shut-in by the operator through the quarter
pursuant to temporary allowable restrictions imposed by regulatory authorities
pending completion of a gas conservation and waterflood project.
Compared to the second quarter of 2001, volumes are lower, primarily as a result
of significant dispositions in the second half of 2001 combined with the outages
noted above.
PRIMEWEST ENERGY TRUST
MANAGEMENT'S DISCUSSION & ANALYSIS (MD&A)
5 [GRAPHIC OMITTED -- COMPANY LOGO]
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PRODUCTION OUTLOOK
PrimeWest maintains its prior guidance that it expects third quarter and full
year volumes to fall within the 29,000 - 30,000 BOE/day target range.
Only the Whiskey Creek and Normandville outages are expected to impact volumes
for the balance of 2002. Volumes should increase from all other areas impacted
by second quarter maintenance activities. These volumes, together with further
development activities, are expected to mitigate natural decline.
REALIZED COMMODITY PRICES
Benchmark prices THREE MONTHS ENDED SIX MONTHS ENDED
- ------------------------------------------------------------------------------ --------------------------
JUN. 30, MAR. 31, JUN. 30, JUN. 30, JUN. 30,
2002 2002 2001 2002 2001
---------- ----------- ---------- ----------- ----------
Natural gas ($/MCF AECO) 4.42 3.34 7.08 3.88 8.99
Crude oil ($U.S./BBL WTI) 26.25 21.64 27.96 23.95 28.34
Average PrimeWest realized selling
prices (CDN DOLLARS) THREE MONTHS ENDED SIX MONTHS ENDED
- ------------------------------------------------------------------------------ --------------------------
JUN. 30, MAR. 31, JUN. 30, JUN. 30, JUN. 30,
2002 2002 2001 2002 2001
---------- ----------- ---------- ----------- ----------
Natural gas ($/MCF) 4.47 4.57 6.21 4.52 7.37
Crude oil ($/BBL) 32.96 32.09 33.59 32.50 33.12
Natural gas liquids ($/BBL) 25.77 20.87 35.35 23.23 37.19
Total Oil Equivalent ($ PER BOE) 28.61 28.49 35.94 28.55 39.73
========== =========== ========== =========== ==========
Realized hedging gain (loss)
included in prices above ($ PER BOE) 1.32 7.06 (1.83) 4.26 (1.37)
========== =========== ========== =========== ==========
Realized prices for natural gas and crude oil in the second quarter of 2002 were
little changed from the first quarter of 2002. Although benchmark prices
improved in the quarter, PrimeWest's hedging program had assured the benefit of
those increases.
PrimeWest's hedging gain fell to $3.6 million in the second quarter of 2002
compared to $19.9 million in the first quarter, again reflecting the increase in
benchmark prices for crude oil and natural gas in the second quarter.
For the six months ended June 30, prices for 2002 fell 28% compared to the
previous year, with natural gas down 39%.
PRIMEWEST ENERGY TRUST
MANAGEMENT'S DISCUSSION & ANALYSIS (MD&A)
6 [GRAPHIC OMITTED -- COMPANY LOGO]
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SALES REVENUE (1)
($ THOUSANDS)
THREE MONTHS ENDED SIX MONTHS ENDED
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JUN. 30, MAR. 31, JUN. 30, JUN. 30, JUN. 30,
2002 2002 2001 2002 2001
---------- ----------- ---------- ----------- ----------
Natural gas 45,186 46,645 72,218 91,831 118,536
Crude oil 26,962 29,585 35,010 56,546 55,343
Natural gas liquids 4,820 4,207 8,408 9,027 14,248
Total 76,968 80,437 115,636 157,404 188,127
========== =========== ========== =========== ==========
Hedging gains (losses) (2) for
natural gas and crude oil
included above 3,550 19,926 (5,902) 23,491 (6,484)
========== =========== ========== =========== ==========
(1) Excludes sulphur
(2) Net of amortized premiums
Sales revenues were down 4% quarter-over-quarter in 2002, reflecting lower
production volumes in the second quarter.
Of the realized hedging gains of $3.6 million during the second quarter, a $4.2
million ($0.42/Mcf) gain was attributable to natural gas offset by a $0.67
million ($0.82/bbl) loss attributable to crude oil.
Compared to the first half of 2001, revenues were lower as the benefit of full
year to date Cypress volumes was more than offset by significantly weaker
prices.
PRICE OUTLOOK
The following table sets forth benchmark future commodity prices.
BENCHMARK COMMODITY PRICES PAST FOUR QUARTERS NEXT FOUR QUARTERS
(ACTUAL) (FORWARD MARKETS)(1)
- ------------------------------------------------------------------- ----------------------------------------
Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2
2001 2001 2002 2002 2002 2002 2003 2003
--------- --------- --------- --------- ----------------------------------------
Natural gas
NYMEX ($U.S./MCF) 2.98 2.50 2.38 3.37 3.09 3.30 3.21 3.65
AECO ($CDN/MCF) 3.92 3.30 3.34 4.42 3.26 4.21 5.09 4.96
Crude oil ($U.S./BBL WTI) 26.76 20.43 21.64 26.25 27.43 26.64 25.87 25.20
(1) As at July 18, 2002
The world crude oil supply/demand fundamentals have come back into a close
balance. While the crude oil demand recovery is not occurring as quickly as
anticipated, OPEC has maintained a level of discipline over their quotas, and
Iraq has reduced output over a pricing dispute with the United Nations Oil for
Food Program. The balanced fundamentals combined with continued instability in
the Middle East has kept oil prices supported over the past quarter and could
continue to provide support in the medium term.
Natural gas prices through this summer have experienced some recent softening
due to record natural gas storage levels both in Canada and the U.S., although
the year-over-year storage overhang has continued to decline over the past
several months. The futures prices for the November 2002 to October 2003 gas
year have remained firm and pricing beyond October 2003 has increased. This
PRIMEWEST ENERGY TRUST
MANAGEMENT'S DISCUSSION & ANALYSIS (MD&A)
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would suggest that there is likely to be some continued short-term soft gas
pricing through the third quarter but that the medium- to long-term fundamentals
for gas are still very positive.
ROYALTIES
($ THOUSANDS)
THREE MONTHS ENDED SIX MONTHS ENDED
- ----------------------------------------------------------------------------- --------------------------
JUN. 30, MAR. 31, JUN. 30, JUN. 30, JUN. 30,
2002 2002 2001 2002 2001
---------- ----------- ---------- ----------- ----------
Royalty expense 14,566 10,666 27,650 25,232 43,301
Per BOE 5.41 3.78 8.59 4.58 9.14
Royalties as % of sales revenue
- including hedging 18.9% 13.3% 23.9% 16.0% 23.0%
- excluding hedging 19.8% 17.6% 22.8% 18.8% 22.3%
========== =========== ========== =========== ==========
Royalties as a percent of sales revenue increased from first quarter levels as a
result of reduced hedging gains, which do not attract royalties, as well as a
one-time mineral tax adjustment of $1.8 million, which reduced royalty expenses
in the first quarter of 2002.
The second quarter and first half of 2001 royalty rates reflect higher gas
prices.
OPERATING EXPENSES
($ THOUSANDS)
THREE MONTHS ENDED SIX MONTHS ENDED
- ----------------------------------------------------------------------------- --------------------------
JUN. 30, MAR. 31, JUN. 30, JUN. 30, JUN. 30,
2002 2002 2001 2002 2001
---------- ----------- ---------- ----------- ----------
Operating expenses 14,639 14,393 15,704 29,033 24,044
Per BOE $5.44 $5.10 $4.88 $5.27 $5.08
========== =========== ========== =========== ==========
Operating expenses per BOE increased 7% compared to the first quarter of 2002,
primarily the result of lower production volumes. Providing for approximately
$500,000 of costs related to the Crossfield and Laprise Creek turnarounds,
operating expenses were 2% less than the previous quarter.
The increase in year to date operating expenses reflects six months of Cypress
activity compared to only three months in 2001.
OPERATING EXPENSES OUTLOOK
Operating expenses are expected to decrease in the third quarter of 2002,
principally as a result of the absence of costs associated with the turnarounds
at Laprise Creek and Crossfield incurred in the second quarter of 2002, as well
as ongoing cost control measures.
PRIMEWEST ENERGY TRUST
MANAGEMENT'S DISCUSSION & ANALYSIS (MD&A)
8 [GRAPHIC OMITTED -- COMPANY LOGO]
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OPERATING MARGIN
($ PER BOE)
THREE MONTHS ENDED SIX MONTHS ENDED
- ----------------------------------------------------------------------------- --------------------------
JUN. 30, MAR. 31, JUN. 30, JUN. 30, JUN. 30,
2002 2002 2001 2002 2001
---------- ----------- ---------- ----------- ----------
Sales price and other revenue
(including hedging) 28.53 28.37 35.94 28.45 39.76
Royalties 5.41 3.78 8.59 4.58 9.14
Operating costs 5.44 5.10 4.88 5.27 5.08
---------- ----------- ---------- ----------- ----------
Operating margin 17.68 19.49 22.47 18.60 25.54
========== =========== ========== =========== ==========
Operating margin fell 9% from quarter-to-quarter reflecting higher royalty and
operating expenses which are discussed earlier in this MD&A.
Margins were much higher in the second quarter and first half of 2001 as a
result of very strong natural gas and natural gas liquids prices.
CASH G&A EXPENSES AND MANAGEMENT FEES
($ THOUSANDS)
THREE MONTHS ENDED SIX MONTHS ENDED
- ----------------------------------------------------------------------------- --------------------------
JUN. 30, MAR. 31, JUN. 30, JUN. 30, JUN. 30,
2002 2002 2001 2002 2001
---------- ----------- ---------- ----------- ----------
Cash G&A Expenses 2,915 2,635 2,795 5,549 5,068
Per BOE $ 1.08 $ 0.93 $ 0.87 $ 1.01 $ 1.07
Cash Management Fees 1,264 1,418 1,862 2,682 3,131
Per BOE $ 0.47 $ 0.50 $ 0.58 $ 0.49 $ 0.66
========== =========== ========== =========== ==========
Cash G&A expenses in the second quarter included annual report and related
document expenses for printing and mailing to the unitholders along with
unitholder meeting costs that totalled an incremental $250,000. These costs
represent the majority of the increase over the first quarter of 2002 as well as
the increase over the same period of 2001.
The year over year increase is a result of 2002 representing a full six months
of G&A costs associated with the Cypress acquisitions, whereas 2001 reflects
only the second quarter costs of Cypress; the transaction closed on March 29,
2001.
Cash management fees for the second quarter were lower compared to the previous
quarter and the same period in 2001, in line with lower netbacks.
PRIMEWEST ENERGY TRUST
MANAGEMENT'S DISCUSSION & ANALYSIS (MD&A)
9 [GRAPHIC OMITTED -- COMPANY LOGO]
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NON-CASH G&A EXPENSES AND MANAGEMENT FEES
($ THOUSANDS)
THREE MONTHS ENDED SIX MONTHS ENDED
- ----------------------------------------------------------------------------- --------------------------
JUN. 30, MAR. 31, JUN. 30, JUN. 30, JUN. 30,
2002 2002 2001 2002 2001
---------- ----------- ---------- ----------- ----------
Non-cash G&A Expenses 1,623 5,351 2,294 6,973 7,489
Non-cash Management Fees 485 479 528 965 1,011
---------- ----------- ---------- ----------- ----------
Total 2,108 5,830 2,822 7,938 8,500
========== =========== ========== =========== ==========
Per BOE $ 0.78 $ 2.07 $ 0.87 $ 1.43 $ 1.79
========== =========== ========== =========== ==========
Non-cash G&A expenses consists of Unit Appreciation Rights (UARs) under the
Trust's long-term incentive program. It has been PrimeWest's practice to expense
the cost of the UARs which are similar to granting a stock option in a
conventional business. The UARs are marked- to-market each quarter and the
impact is recognized as an expense in the income statement of the Trust.
The decrease in non-cash G&A expenses comparing the second quarter of 2002 to
the first quarter of 2002 reflects a modest unit price appreciation in the
second quarter to $7.23 from $7.20 at the end of the first quarter combined with
the impact of distributions, offset by the 5% annual hurdle rate. The first
quarter expense was higher reflecting a $6.36 unit price at the end of 2001. The
first quarter of 2002 expense also reflects the implementation of the new CICA
accounting standard 3870 effective January 1, 2002, whereby vested and unvested
UARs are included in the calculation of non-cash G&A expenses. Previously, only
the vested UARs were included. The effect of this change was to increase
non-cash G&A expenses by $2.4 million for the six months ended June 30, 2002.
Non-cash G&A expenses in the first half of 2001 reflect a higher Trust Unit
price driven by record natural gas and natural gas liquids prices.
Non-cash management fees increased slightly compared to the first quarter
reflecting a modest unit price appreciation.
INTEREST EXPENSE
($ THOUSANDS)
THREE MONTHS ENDED SIX MONTHS ENDED
- ----------------------------------------------------------------------------- --------------------------
JUN. 30, MAR. 31, JUN. 30, JUN. 30, JUN. 30,
2002 2002 2001 2002 2001
---------- ----------- ---------- ----------- ----------
Interest expense 2,530 2,053 5,115 4,583 6,631
Period end debt level 240,913 234,415 290,233 240,913 290,233
Debt per Trust Unit $ 1.79 $ 1.77 $ 2.40 $ 1.79 $ 2.40
Average cost of debt - % 4.5% 4.0% 6.4% 4.5% 6.5%
========== =========== ========== =========== ==========
Interest expense increased quarter-over-quarter on higher interest rates and
increasing debt levels through the quarter. On a per unit basis, debt remained
essentially flat quarter-over-quarter, and was down 25% from a year earlier.
At June 30, 2002, approximately 70% of the debt was at a floating rate, with the
balance at a fixed rate.
The Cypress acquisition was closed on March 29, 2001, adding incremental debt
during the second quarter of 2001.
PRIMEWEST ENERGY TRUST
MANAGEMENT'S DISCUSSION & ANALYSIS (MD&A)
10 [GRAPHIC OMITTED -- COMPANY LOGO]
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DEPLETION, DEPRECIATION AND AMORTIZATION
($THOUSANDS)
THREE MONTHS ENDED SIX MONTHS ENDED
- ------------------------------------------------- --------------------------
JUN. 30, MAR. 31, JUN. 30, JUN. 30, JUN. 30,
2002 2002 2001 2002 2001
---------- ----------- ---------- ----------- ----------
45,212 45,895 50,280 91,107 61,700
========== =========== ========== =========== ==========
Depletion, depreciation and amortization (DD&A) for the second quarter of 2002
is down modestly from the first quarter level, in part due to lower production
volume in the quarter.
Compared to a year ago, the second quarter DD&A for 2002 is lower than 2001
reflecting reduced volumes as a result of asset dispositions late in 2001 and
second quarter 2002 production outages.
For the six months ended June 30, the 2002 figure reflects a full six months of
Cypress activity versus only three months in 2001.
CEILING TEST
Principally as a result of very weak spot prices for Alberta gas, $2.02 per Mcf
at June 28, 2002, the ceiling test deficiency increased to $354 million at
quarter end from $150 million at year end 2001 when the Alberta spot gas price
was $3.67 per Mcf.
Using average prices for the second quarter of 2002 would result in a cushion of
$210 million.
INCOME AND CAPITAL TAXES
($THOUSANDS)
THREE MONTHS ENDED SIX MONTHS ENDED
- ----------------------------------------------------------------------------- --------------------------
JUN. 30, MAR. 31, JUN. 30, JUN. 30, JUN. 30,
2002 2002 2001 2002 2001
---------- ----------- ---------- ----------- ----------
Capital taxes 624 642 673 1,266 731
Future income taxes recovery (900) (9,400) (25,509) (10,300) (23,263)
---------- ----------- ---------- ----------- ----------
(276) (8,758) (24,836) (9,034) (22,532)
========== =========== ========== =========== ==========
The future income tax recovery for the second quarter and the first six months
of 2002, has decreased in comparison to the comparable periods of 2001, as a
result of lower income before tax and adjustments to the operating company tax
pools upon the filing of the tax returns in the second quarter of 2002.
PRIMEWEST ENERGY TRUST
MANAGEMENT'S DISCUSSION & ANALYSIS (MD&A)
11 [GRAPHIC OMITTED -- COMPANY LOGO]
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LIQUIDITY AND CAPITAL RESOURCES
($ THOUSANDS)
AS AT
- --------------------------------------------------------------------------------------
JUN. 30, MAR. 31, JUN. 30,
2002 2002 2001
--------- --------- ---------
Long-term debt 235,000 136,670 335,011
(Working capital)/ deficit 5,913 97,745 (44,778)
Net debt 240,913 234,415 290,233
Market value of Trust Units and
exchangeable shares outstanding 966,985 954,722 1,053,841
Total capitalization 1,207,898 1,189,137 1,344,074
Net debt as a % of total capitalization 19.94% 19.71% 21.60%
========= ========= =========
Net debt increased modestly in the quarter reflecting capital spending of $12.4
million, which was partially funded by proceeds from the DRIP and Optional Trust
Unit Purchase programs and minor dispositions.
Unutilized credit facilities were $58 million at June 30, 2002, compared to $115
million at March 31, 2002. The credit facility was reduced during the second
quarter to $310 million from $350 million, reflecting significant property
dispositions in late 2001 and reduced commodity pricing assumptions.
Net debt is significantly lower than the second quarter of 2001 as a result of
equity issued in the last nine months of 2001 to de-lever the balance sheet,
along with the application of proceeds from non-core asset sales.
CAPITAL SPENDING
($ THOUSANDS)
THREE MONTHS ENDED SIX MONTHS ENDED
- ------------------------------------------------- --------------------------
JUN. 30, MAR. 31, JUN. 30, JUN. 30, JUN. 30,
2002 2002 2001 2002 2001
---------- ----------- ---------- ----------- ----------
12,415 24,874 16,707 37,289 23,570
========== =========== ========== =========== ==========
Capital spending during the second quarter and first half of 2002 is in line
with the Trust's commitment to invest approximately $70 million during 2002 in
development activities.
PrimeWest's capital development program continues to yield results in line with
expectations. Although second quarter activities were restricted by spring
break-up, PrimeWest participated in the drilling of 9 gross (5 net) wells. Eight
wells were cased, with one subsequently abandoned. On a year-to-date basis, 40
gross (25.6 net) wells have been drilled, achieving a 90% success rate. The
major areas of development activity in the first half of the year included
Dawson and Brant Farrow.
Additional activities in the quarter included completion of upgrades to the
Dawson (Roxanna) and Brant Farrow compression facilities and gas gathering
systems, as well as the installation of gas conservation and waterflood
facilities at Dawson (Normandville).
PrimeWest expects that internally generated retained cash flow, proceeds from
the DRIP and the Optional Trust Unit Purchase programs plus unutilized credit
facilities will be sufficient to fund the 2002 capital program, assuming no
material adverse developments in commodity prices.
PRIMEWEST ENERGY TRUST
MANAGEMENT'S DISCUSSION & ANALYSIS (MD&A)
12 [GRAPHIC OMITTED -- COMPANY LOGO]
================================================================================
HEDGING PROGRAM
Approximate percentage of future anticipated production volumes hedged through
June 30, 2002; net of anticipated royalties, reflecting full production declines
with no offsetting additions:
Q3/Q4 2002 2003
---------- ----
Crude Oil 70% 34%
Natural Gas 70% 51%
The mark-to-market valuation of these hedges was a $4.1 million gain at June 30,
2002.
A summary of contracts in place as at June 30, 2002 is as follows:
CRUDE OIL
Volume WTI Price
Period (bbl/d) Type (U.S.$/bbl)
- --------------------------------------------------------------------------------
May - June 2002 2,000 Swap 26.23
July - September 2002 2,000 Swap 25.22
October - December 2002 2,000 Swap 24.45
January - December 2002 1,000 Costless Collar 20.00/25.15
July - December 2002 1,000 Costless Collar 20.50/24.95
July - September 2002 350 Costless Collar 22.00/29.25
October - December 2002 350 Costless Collar 22.00/28.15
January - December 2003 1,000 3 Way 17.00 / 20.50 / 25.50
January - March 2003 1,000 Costless Collar 21.00/27.70
January - June 2003 1,000 3 Way 18.50 / 22.50 / 27.70
July - December 2003 1,000 3 Way 18.50 / 22.50 / 27.20
NATURAL GAS
Volume AECO Price
Period (MMcf/d) Type (Cdn$/Mcf)
- --------------------------------------------------------------------------------
May - October 2002 4.7 Fixed Price 6.50
May - October 2002 18.9 Swap 5.28
May - October 2002 18.9 Swap 5.28
May - October 2002 9.5 Swap 4.39
November 2002 - March 2003 4.7 Costless Collar 4.22 by 5.96
November 2002 - March 2003 4.7 3 Way 3.17 / 4.48 / 6.59
November 2002 - March 2003 4.7 3 Way 3.17 / 3.96 / 5.46
November 2002 - March 2003 4.7 3 Way 4.22 / 5.28 / 7.04
November 2002 - March 2003 4.7 Swap 5.43
April - October 2003 4.7 Fixed Price 4.75
April - October 2003 4.7 Swap 5.05
April - October 2003 4.7 3 Way 3.17 / 4.48 / 6.26
April - October 2003 4.7 3 Way 3.17 / 3.96 / 5.39
April - October 2003 4.7 3 Way 3.69 / 4.75 / 6.65
November 2002 - October 2004 9.5 3 Way 3.17 / 4.22 / 6.09
January 2002 - October 2003 4.7 Swap 3.98
January 2002 - October 2003 4.7 Swap 4.17
PRIMEWEST ENERGY TRUST
MANAGEMENT'S DISCUSSION & ANALYSIS (MD&A)
13 [GRAPHIC OMITTED -- COMPANY LOGO]
================================================================================
A 3 way option is like a traditional collar, except that PrimeWest has resold
the put at a lower price. Utilizing the first 3 way crude oil contract above as
an example, PrimeWest has sold a call at $25.50, purchased a put at $20.50, and
resold the put at $17.00. Should the market price drop below $20.50 PrimeWest
will receive $20.50 until the price is less than $17.00, at which time PrimeWest
would then receive market price plus $3.50. However, should market prices rise
above $25.50, PrimeWest would receive a maximum of $25.50. Should the market
price remain between $20.50 and $25.50, PrimeWest would receive the market
price.
DISTRIBUTIONS
PrimeWest has distributed $0.10 per unit monthly year-to-date. PrimeWest has
previously announced it will distribute, barring material adverse developments,
$0.10 per unit on each of August 15, September 15 and October 15, 2002.
DISTRIBUTION REINVESTMENT (DRIP) DISCOUNT
PrimeWest's Distribution Reinvestment and Optional Trust Unit Purchase Plan
(Plan) enables participants to reinvest their monthly cash distributions and/or
purchase additional Trust Units at a 5% discount to the 20-day weighted average
monthly market price. There is a $100,000 per calendar year limit per individual
to the purchase of additional Trust Units.
To join the Plan, you must be a registered unitholder or have your units in an
account that allows participation. Not all brokerage firms and banks will allow
you to participate. Please check directly with your account representative as to
their participation.
For further information or to join this Plan, contact our Plan Agent,
Computershare Trust Company of Canada, at 1-800-332-0095.
CHAIRMAN HONOURED BY CHARTERED ACCOUNTANTS OF ALBERTA
Harold Milavsky, FCA, Chairman of the Board of Directors and Audit Committee of
PrimeWest is the recipient of the Institute of Chartered Accountants of
Alberta's Lifetime Achievement Award. This award is reserved for Fellows of the
Chartered Accountants (FCA's) who, through their entire career, have rendered
meritorious service to the profession, and whose career and achievements in the
community have brought honour to the profession.
SECOND QUARTER CONFERENCE CALL AND WEBCAST
PrimeWest will be conducting a conference call and Webcast for interested
analysts, brokers, investors and media representatives about its second quarter
results and outlook at 10:00 a.m. Mountain daylight time (12:00 p.m. Eastern
daylight time) on Tuesday, July 30, 2002.
Callers may dial 1-888-881-4892 a few minutes prior to start and request the
PrimeWest conference call. The call also will be available for replay by dialing
1-877-289-8525, and entering pass code 197123 followed by the pound (#) key.
PRIMEWEST ENERGY TRUST
MANAGEMENT'S DISCUSSION & ANALYSIS (MD&A)
14 [GRAPHIC OMITTED -- COMPANY LOGO]
================================================================================
Interested users of the Internet are invited to go to
WWW.NEWSWIRE.CA/WEBCAST/PAGES/ PRIMEWESTENERGY20020730/ for the live Webcast
and/or replay or access the Webcast at the PrimeWest Web site,
WWW.PRIMEWESTENERGY.COM.
QUESTIONS
PrimeWest Energy Trust welcomes questions from unitholders and potential
investors; call Investor Relations at 403-234-6600 or toll-free in Canada and
the U.S. at 1-877-968-7878; or visit us on the Internet at our Web site,
WWW.PRIMEWESTENERGY.COM.
On behalf of the Board of Directors:
July 29, 2002
Kent J. MacIntyre
Vice-chairman and
Chief Executive Officer
PRIMEWEST ENERGY TRUST
CONSOLIDATED BALANCE SHEET
15 [GRAPHIC OMITTED -- COMPANY LOGO]
================================================================================
(UNAUDITED)
AS AT AS AT
JUNE 30, DEC. 31,
(THOUSANDS OF DOLLARS) 2002 2001
- ----------------------------------------------------------------------- -----------------
ASSETS
Current assets
Accounts receivable $ 55,423 $ 55,465
Prepaid expenses and inventory 7,102 11,200
----------------- -----------------
62,525 66,665
Cash reserved for site restoration and reclamation 766 755
Capital assets (NOTE 3) 1,393,924 1,448,661
----------------- -----------------
$ 1,457,215 $ 1,516,081
================= =================
LIABILITIES AND UNITHOLDERS' EQUITY
Current liabilities
Bank overdraft $ 16,693 $ 14,613
Accounts payable and accrued liabilities 38,215 59,944
Accrued distributions to unitholders 11,946 11,980
Due to related company 1,569 10,108
Current portion of long-term debt (NOTE 4) 15 67
----------------- -----------------
68,438 96,712
Long-term debt (NOTE 4) 235,000 195,000
Future income taxes 352,295 362,595
Site restoration and reclamation provision 6,927 6,113
----------------- -----------------
662,660 660,420
UNITHOLDERS' EQUITY
Net capital contributions (NOTE 5) $ 1,165,635 $ 1,152,551
Capital issued but not distributed 485 419
Long-term incentive plan equity (NOTE 6) 11,244 7,932
Accumulated income 122,332 122,550
Accumulated cash distributions (497,531) (420,983)
Accumulated dividends (7,610) (6,808)
----------------- -----------------
794,555 855,661
----------------- -----------------
$ 1,457,215 $ 1,516,081
================= =================
CONSOLIDATED STATEMENTS OF UNITHOLDERS' EQUITY
FOR THE SIX MONTHS ENDED (UNAUDITED)
(THOUSANDS OF DOLLARS) JUNE 30, 2002 JUNE 30, 2001
- ----------------------------------------------------------------------- -----------------
Unitholders' equity, beginning of the period,
as previously reported $ 855,661 $ 298,245
Net income/(loss) for the period (218) 58,422
Net capital contributions 13,084 641,009
Capital issued but not distributed 66 294
Long-term incentive plan equity 3,312 3,231
Cash distributions (76,548) (111,072)
Dividends (802) (1,726)
----------------- -----------------
Unitholders' equity, end of the period $ 794,555 $ 888,403
================= =================
PRIMEWEST ENERGY TRUST
CONSOLIDATED STATEMENTS OF CASH FLOW (UNAUDITED)
16 [GRAPHIC OMITTED -- COMPANY LOGO]
================================================================================
THREE MONTHS ENDED SIX MONTHS ENDED
- ----------------------------------------------------------------------------- -----------------------------
JUN. 30 JUN. 30 JUN. 30 JUN. 30
(THOUSANDS OF DOLLARS) 2002 2001 2002 2001
-------------- -------------- -------------- --------------
OPERATING ACTIVITIES
Net income/(loss) for the period $ (6,194) $ 34,232 $ (218) $ 58,422
Add: Items not involving cash from
operations
Depletion, depreciation and
amortization 45,212 50,280 91,107 61,700
Non-cash general and administrative 1,623 2,294 6,973 7,489
Non-cash management fees 485 528 965 1,011
Future income taxes recovery (900) (25,509) (10,300) (23,263)
-------------- -------------- -------------- --------------
Cash flow from operations 40,226 61,825 88,527 105,359
Change in non-cash working capital (36,101) (8,126) (26,060) 2,260
-------------- -------------- -------------- --------------
4,125 53,699 62,467 107,619
-------------- -------------- -------------- --------------
FINANCING ACTIVITIES
Proceeds from issue of Trust Units
(net of costs) 4,949 94,253 8,525 95,964
Cash distributions to unitholders (38,428) (70,289) (76,514) (111,072)
Dividends -- (986) -- (1,726)
Increase in long-term debt 29,974 14,975 39,948 77,071
Change in non-cash working capital (1,244) 4,154 (938) 13,657
-------------- -------------- -------------- --------------
(4,749) 42,107 (28,979) 73,894
-------------- -------------- -------------- --------------
INVESTING ACTIVITIES
Expenditures on capital assets (12,415) (16,707) (37,289) (23,570)
Corporate acquisitions -- (4,201) -- (80,842)
Acquisitions of capital assets -- (512) -- (512)
Proceeds on disposal of capital assets 662 2,185 2,843 5,518
Decrease (increase) in cash reserved for
future site restoration and reclamation -- (404) (11) (12)
Expenditures on site restoration and
reclamation (395) (100) (1,111) (881)
-------------- -------------- -------------- --------------
(12,148) (19,739) (35,568) (100,299)
-------------- -------------- -------------- --------------
INCREASE/(DECREASE) IN CASH (12,772) 76,067 (2,080) 81,214
FOR THE PERIOD
CASH (BANK OVERDRAFT) BEGINNING
OF THE PERIOD (3,921) 4,313 (14,613) (834)
-------------- -------------- -------------- --------------
CASH, (BANK OVERDRAFT) END
OF THE PERIOD $ (16,693) $ 80,380 $ (16,693) $ 80,380
============== ============== ============== ==============
CASH INTEREST PAID $ 2,795 $ 5,122 $ 4,560 $ 6,636
============== ============== ============== ==============
CASH TAXES PAID $ 2,983 -- $ 2,983 $ 10
============== ============== ============== ==============
PRIMEWEST ENERGY TRUST
CONSOLIDATED STATEMENTS OF INCOME (LOSS) (UNAUDITED)
17 [GRAPHIC OMITTED -- COMPANY LOGO]
================================================================================
PRIMEWEST ENERGY TRUST
CONSOLIDATED STATEMENTS OF INCOME (LOSS) (UNAUDITED)
THREE MONTHS ENDED SIX MONTHS ENDED
- ----------------------------------------------------------------------------- -----------------------------
(THOUSANDS OF DOLLARS, EXCEPT FOR PER-TRUST- JUN. 30 JUN. 30 JUN. 30 JUN. 30
UNIT AND NUMBER OF UNITS) 2002 2001 2002 2001
-------------- -------------- -------------- --------------
REVENUES
Sales of crude oil, natural gas and
natural gas liquids $ 76,809 $ 115,609 $ 156,799 $ 188,148
Crown and other royalties, net of ARTC (14,566) (27,650) (25,232) (43,301)
Other income (45) 15 73 117
-------------- -------------- -------------- --------------
62,198 87,974 131,640 144,964
-------------- -------------- -------------- --------------
EXPENSES
Operating 14,639 15,704 29,033 24,044
Cash general and administrative 2,915 2,795 5,549 5,068
Non-cash general and administrative 1,623 2,294 6,973 7,489
Interest 2,530 5,115 4,583 6,631
Cash management fees 1,264 1,862 2,682 3,131
Non-cash management fees 485 528 965 1,011
Depletion, depreciation and amortization 45,212 50,280 91,107 61,700
-------------- -------------- -------------- --------------
68,668 78,578 140,892 109,074
-------------- -------------- -------------- --------------
Income (loss) before taxes for the period (6,470) 9,396 (9,252) 35,890
-------------- -------------- -------------- --------------
Capital taxes 624 673 1,266 731
Future income taxes recovery (900) (25,509) (10,300) (23,263)
-------------- -------------- -------------- --------------
(276) (24,836) (9,034) (22,532)
-------------- -------------- -------------- --------------
Net income/(loss) for the period (6,194) 34,232 (218) 58,422
============== ============== ============== ==============
Net income/(loss) per Trust Unit (0.05) 0.33 -- 0.71
============== ============== ============== ==============
Diluted net income/(loss) per Trust Unit (0.05) 0.33 -- 0.70
============== ============== ============== ==============
CONSOLIDATED STATEMENTS OF CASH DISTRIBUTIONS (UNAUDITED)
THREE MONTHS ENDED SIX MONTHS ENDED
- ----------------------------------------------------------------------------- -----------------------------
(THOUSANDS OF DOLLARS, EXCEPT FOR PER-TRUST- JUN. 30 JUN. 30 JUN. 30 JUN. 30
UNIT AND NUMBER OF UNITS) 2002 2001 2002 2001
-------------- -------------- -------------- --------------
Net income/(loss) for the period $ (6,194) $ 34,232 $ (218) $ 58,422
Add back (deduct) amounts to reconcile
to distribution:
Increase in reserve (419) 10,205 (9,160) 8,365
Depletion, depreciation and amortization 45,212 50,280 91,107 61,700
Contribution to reclamation fund (1,001) (1,032) (2,046) (1,530)
Non-cash general and administrative 1,623 2,294 6,973 7,489
Management fees paid in Trust Units 485 528 965 1,011
Future income taxes (recovery) (900) (25,509) (10,300) (23,263)
-------------- -------------- -------------- --------------
$ 45,000 $ 36,766 $ 77,539 $ 53,772
-------------- -------------- -------------- --------------
$ 38,806 $ 70,998 $ 77,321 $ 112,194
============== ============== ============== ==============
Cash Distributions to Trust Unitholders (99%) $ 38,418 $ 70,288 $ 76,548 $ 111,072
============== ============== ============== ==============
Cash Distributions per Trust Unit $ 0.30 $ 0.66 $ 0.60 $ 1.26
============== ============== ============== ==============
Trust Units issued and outstanding 128,441,771 113,551,534 128,441,771 113,551,534
Weighted average Trust Units and
exchangeable shares outstanding (diluted) 134,347,196 103,344,228 133,851,104 81,834,023
PRIMEWEST ENERGY TRUST
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
For the six months ended June 30, 2002 (THOUSANDS OF DOLLARS EXCEPT TRUST
UNIT/SHARE AMOUNTS)
18 [GRAPHIC OMITTED -- COMPANY LOGO]
================================================================================
1) SIGNIFICANT ACCOUNTING POLICIES
These interim consolidated financial statements of PrimeWest Energy Trust have
been prepared in accordance with Canadian generally accepted accounting
principles. The specific accounting principles used are described in the annual
consolidated financial statements of the Trust appearing on pages 36 through 53
of the Trust's 2001 annual report and should be read in conjunction with these
interim financial statements.
2) AMALGAMATION
Effective January 1, 2002, PrimeWest Oil & Gas Corp. and PrimeWest Energy Inc.
and its subsidiaries amalgamated and were continued as PrimeWest Energy Inc.
Subsequent to the amalgamation, the common shares of PrimeWest Energy Inc. are
89% owned by the Trust and 11% by PrimeWest Management Inc. The Trust continues
to own a royalty entitling it to receive 99% of the net cash flows generated by
PrimeWest Energy Inc. The beneficiaries of the Trust are the holders of Trust
Units.
3) CAPITAL ASSETS
In accordance with its stated accounting policies, PrimeWest has performed a
ceiling test using commodity prices as at the measurement date of June 28, 2002.
Using June 28, 2002 (the last business day of the period) commodity prices of
AECO $2.02 per Mcf for natural gas and WTI US$26.86 per barrel of oil would
result in a ceiling test deficiency of $354 million. However, using the average
prices for the second quarter ending June 30, 2002 of AECO $4.42 per Mcf for
natural gas and WTI US$26.25 per barrel of oil would result in a cushion.
PrimeWest is not required to account for any ceiling test impairment that is not
permanent, within the first two years of the Cypress acquisition, therefore no
writedown is reflected in the June 30, 2002 financial statements.
4) LONG-TERM DEBT
PrimeWest Energy Inc. and the Trust (as co-borrowers) have a combined revolving
credit facility in the amount of $310 million. The facility consists of a
revolving term loan of $285 million and an operating facility of $25 million. In
addition to amounts outstanding under the facility as indicated in the table
below, PrimeWest Energy Inc. has outstanding letters of credit in the amount of
$2.8 million. Collateral for the credit facility is provided by a
floating-charge debenture covering all existing and after acquired property in
the principal amount of $500 million. Each borrower under the facility has also
provided an unconditional full liability guarantee in respect of amounts
borrowed under the facility.
Revolving credit facility utilized $ 251,693
Capital lease obligation 15
---------------
$ 251,708
===============
Advances under the revolving and operating loan facility are made in the form of
Banker's Acceptances (BA's), prime rate loans or letters of credit. In the case
of BA's, interest is a function of the BA rate plus a stamping fee based on the
Trust's current ratio of debt-to-cash flow. In the case of prime rate loans,
interest is generally charged at the bank's prime rate.
PRIMEWEST ENERGY TRUST
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
19 [GRAPHIC OMITTED -- COMPANY LOGO]
================================================================================
The credit facility revolves until April 30, 2003 at which time the lender will
conduct its annual borrowing base review. The lender has the right to
re-determine the borrowing base at one other time during the year. During the
revolving phase, the facility has no specific terms of repayment. At the end of
the revolving period, the lender has the right to extend the revolving period
for a further 364-day period or to convert the facility to a term facility. If
the lender converts to a non-revolving facility 60% of the aggregate principal
amount of the loan shall be repayable on the date which is 366 days after such
conversion date and the remaining 40% of the aggregate principal amount
outstanding shall be repayable on the date which is 365 days after the initial
term repayment date.
5) UNITHOLDERS' EQUITY
PRIMEWEST ENERGY TRUST
The authorized capital of the Trust consists of an unlimited number of Trust
Units.
Trust Units # OF UNITS AMOUNT
- ------------------------------------------------------------ ------------
Balance at December 31, 2001 125,965,607 $ 1,115,253
Issued pursuant to Long-term Incentive Plan 561,219 3,672
Issued pursuant to Dividend Reinvestment Plan 1,447,342 8,492
Issued for payment for management fees 132,400 898
Issued on exchange of exchangeable shares 335,203 2,103
Issue expenses incurred -- 22
------------- ------------
Balance at June 30, 2002 128,441,771 $ 1,130,440
============= ============
The per unit amount of distributions paid or declared reflects distributions
paid for units outstanding on the record dates.
PRIMEWEST EXCHANGEABLE CLASS A SHARES
In connection with the Cypress acquisition, PrimeWest Oil & Gas Corp. (now
amalgamated with PrimeWest Energy Inc.) amended its articles to create an
unlimited number of exchangeable shares. The exchangeable shares are
exchangeable into PrimeWest Trust Units at any time up to March 29, 2010; based
on an exchange ratio that adjusts each time PrimeWest makes a distribution to
unitholders. The exchange ratio, which was 1:1 on the date the transaction
closed, is based on the total monthly distribution, divided by the closing unit
price on the distribution payment date. The exchange ratio, effective June 15,
2002, was 1.36684:1.
Exchangeable shares # OF SHARES AMOUNT
- ------------------------------------------------------------- -------------
Balance at December 31, 2001 3,316,742 $ 32,338
Exchanged for Trust Units (146,733) (1,430)
Conversion of Exchangeable B shares to
Exchangeable A shares 710,795 4,287
--------------- -------------
Balance at June 30, 2002 3,880,804 $ 35,195
=============== =============
PRIMEWEST EXCHANGEABLE CLASS B SHARES
In connection with the acquisition of Venator Petroleum Company Limited,
PrimeWest Resources Ltd. (now amalgamated with PrimeWest Energy Inc.) amended
its articles to create an unlimited number of exchangeable shares. At special
meetings held in May and June of 2002, holders of Class B
PRIMEWEST ENERGY TRUST
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
20 [GRAPHIC OMITTED -- COMPANY LOGO]
================================================================================
Exchangeable Shares and Class A Exchangeable Shares voted to approve a special
resolution amending the articles of the Corporation to convert all Class B
Exchangeable Shares to Class A Exchangeable Shares. As at June 14, 2002 649,561
Class B Exchangeable Shares were converted to Class A Exchangeable Shares using
an exchange ratio of 1.09427:1
Exchangeable shares # OF SHARES AMOUNT
- ------------------------------------------------------------- --------------
Balance at December 31, 2001 751,532 $ 4,960
Exchanged for Trust Units (101,971) (673)
Conversion of Exchangeable B shares to
Exchangeable A shares (649,561) (4,287)
-------------- --------------
Balance at June 30, 2002 -- $ --
============== ==============
6) 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. UARs have a
term of up to 6 years and vest equally over a three-year period, except for the
independent members of the Board, whose UARs vest immediately. The Board of
Directors has the option of settling payouts under the plan in PrimeWest Trust
Units or in cash. To date, all payouts under the plan have been in the form of
Trust Units.
UARS ISSUED UARS CURRENT RETURN TOTAL TRUST UNIT
AS AT JUNE 30, 2002 AND OUTSTANDING VESTED PER UAR EQUITY DILUTION
- ------------------------------------------ --------------- ---------------- -------------- --------------
1997 grants 236,786 236,786 $6.30 1,491 210,610
1998 grants 431,079 431,079 8.98 3,870 535,240
1999 grants 478,483 354,409 6.15 2,943 309,755
2000 grants 826,074 390,607 2.71 1,999 146,925
2001 grants 2,211,504 358,574 0.72 729 16,196
2002 grants 509,662 - $1.23 212 -
------------------ --------------- ---------------- -------------- --------------
4,693,588 1,771,455 $11,244 1,218,726
================== =============== ============== ==============
Cumulative to June 30, 2002, 2,481,436 UARs have been exercised resulting in the
issuance of 1,379,666 Trust Units from treasury.
Effective January 1, 2002 the method of accounting for the long-term incentive
plan was changed to comply with new CICA accounting standard 3870. The
calculation of the long-term incentive liability now includes vested and
unvested UARs. Previously, only vested UARs were included. In addition, the
long-term incentive liability has been reclassified as equity on the balance
sheet as the Trust intends to settle the liability in the form of Trust Units.
PRIMEWEST ENERGY TRUST
TRADING PERFORMANCE
21 [GRAPHIC OMITTED -- COMPANY LOGO]
================================================================================
FOR THE QUARTER ENDED JUN. 30/02 MAR. 31/02 DEC. 31/01 SEP. 30/01 JUN. 30/01
- -------------------------------------------------------- ------------ ------------ ------------ ------------
TRUST UNIT PRICES (DOLLARS PER TRUST UNIT)
High 7.33 7.23 7.51 8.77 10.54
Low 6.45 5.92 5.95 6.42 8.45
Close 7.23 7.20 6.36 6.46 8.85
Volume traded (MILLIONS OF UNITS) 31.13 34.48 37.59 37.10 60.42
Number of Trust Units outstanding
(MILLIONS OF UNITS) 128.4 127.4 125.9 115.3 113.6
Including exchangeable shares
(ISSUED IN RESPECT OF VENATOR AND
CYPRESS ACQUISITIONS) 133.7 132.6 131.1 120.1 119.1
Distribution paid per Trust Unit $0.30 $0.30 $0.44 $0.61 $0.66
============= ============ ============ ============ ============
FOR FURTHER INFORMATION PLEASE CONTACT: PRIMEWEST ENERGY TRUST
INVESTOR RELATIONS AND COMMUNICATIONS 4700, 150 - 6 AVENUE SW
TOLL-FREE IN CANADA AND U.S.: 1-877-968-7878 CALGARY, ALBERTA T2P 3Y7
FAX: 403-699-7271 TELEPHONE: 403-234-6600
E-MAIL: INVESTOR@PRIMEWESTENERGY.COM FAX: 403-266-2825