PrimeWest Energy Trust announces third quarter 2003 results. Cash
flow from operations of $1.11 per unit CALGARY, Nov. 6
/PRNewswire-FirstCall/ -- (TSX: PWI.UN, PWX; NYSE: PWI) --
PrimeWest Energy Trust (PrimeWest) today announced unaudited
interim operating and financial results for the third quarter.
Unless otherwise noted, all figures contained in this report are in
Canadian dollars. THIRD QUARTER HIGHLIGHTS - Distributions payable
for the quarter totalled $0.96 per unit representing $0.32 per unit
paid in August, September and October. This represents a payout
ratio of approximately 86% of cash flow available in the quarter. -
A distribution of $0.32 per unit is payable on November 14 for
unitholders of record on October 31, 2003. - Production averaged
32,628 barrels of oil equivalent (BOE) per day versus the second
quarter rate of 34,004 BOE/day.(1) - Operating costs were reduced
from $6.57 per BOE in the second quarter to $5.73 per BOE in the
third quarter due to operating synergies realized through the
rationalization of the recently acquired Caroline properties,
declining labour costs resulting from field personnel restructuring
and lower power costs. - Cash flow from operations was $51.8
million ($1.11 per unit) compared to $57.2 million ($1.24 per unit)
in the second quarter of 2003, primarily as a result of lower
volumes and commodity prices and the strengthened Canadian dollar.
- PrimeWest issued 3.1 million trust units at a price of $25.90 per
unit raising net proceeds of $76.3 million. The proceeds were used
to reduce bank indebtedness and pursue development opportunities in
the Caroline, Valhalla and Brant Farrow areas. Debt levels are now
approximately one times annual cash flow. Debt per unit is $4.68 at
the end of the third quarter versus $6.17 at the end of the second
quarter. - The Optional Trust Unit Purchase Program raised $17.6
million from January through September 2003. The program was fully
subscribed and will re-commence in January 2004. Subscription is
limited by the Toronto Stock Exchange to 2% of the number of units
outstanding at the end of the prior year. - Subsequent to the
quarter end, PrimeWest introduced a Premium Distribution Component
within its Distribution Reinvestment (DRIP) and Optional Trust Unit
Purchase (OTUPP) Plans, which enables eligible Canadian unitholders
to elect to receive up to 102% of the normal distribution amount
commencing in December, 2003. CASH FLOW RECONCILIATION (MILLIONS)
The table below provides a reconciliation of the changes to cash
flows from the second quarter to the third quarter 2003. Second
quarter 2003 cash flow from operations $ 57.2 Production volumes
(3.6) Commodity prices (9.4) Reduced hedging loss 3.0 Operating
expenses 3.1 Royalties 1.9 Other (0.4)
------------------------------------------------------------ Third
quarter 2003 cash flow from operations $ 51.8
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------------------------------------------------------------ (1)
All calculations required to convert natural gas to a crude oil
equivalent (BOE) have been made using a ratio of 6,000 cubic feet
of natural gas to 1 barrel of crude oil. FINANCIAL & OPERATING
HIGHLIGHTS FINANCIAL HIGHLIGHTS (millions of dollars except per-BOE
and per Trust Unit amounts) Three months ended Nine months ended
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Sep 30, Jun 30, Sep 30, Sep 30, Sep 30, 2003 2003 2002 2003 2002
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Net revenue $ 77.2 $ 85.6 $ 63.8 $ 256.9 $ 195.5 per BOE 25.70
27.67 23.00 27.91 23.58 Cash flow from operations 51.8 57.2 40.9
173.7 129.4 per BOE 17.25 18.45 14.71 18.88 15.61 per Trust Unit(1)
1.11 1.24 1.20 3.85 3.86 Royalty expense 23.1 25.0 14.0 80.8 39.2
per BOE 7.70 8.08 5.04 8.77 4.73 Operating expenses 17.2 20.3 14.9
58.2 43.9 per BOE 5.73 6.57 5.38 6.32 5.30 G&A expenses - Cash
3.5 3.2 2.4 10.5 8.0 per BOE 1.15 1.04 0.88 1.14 0.96 G&A
expenses - Non-cash 2.3 3.2 (0.9) 5.9 6.0 per BOE 0.76 1.05 (0.34)
0.64 0.73 Interest expense 4.0 3.4 3.0 11.0 7.6 per BOE 1.32 1.11
1.09 1.20 0.92 Management fees - Cash - - 1.3 - 4.0 per BOE - -
0.47 - 0.48 - Non-cash - - 0.4 - 1.4 per BOE - - 0.16 - 0.17
Distributions to unitholders 43.7 52.8 38.8 146.3 115.4 per Trust
Unit(4) 0.96 1.20 1.20 3.36 3.60 Net debt(3) 233.4 286.4 270.9
233.4 270.9 per Trust Unit(2) 4.68 6.17 7.94 4.68 7.94
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(1) Weighted average Trust Units & exchangeable shares
outstanding (diluted) (2) Trust Units and exchangeable shares
outstanding (diluted) (3) Net debt is long-term debt & working
capital (4) Based on Trust Units outstanding at date of
distribution OPERATING HIGHLIGHTS Three months ended Nine months
ended
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Sep 30, Jun 30, Sep 30, Sep 30, Sep 30, 2003 2003 2002 2003 2002
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DAILY SALES VOLUMES Natural gas (MMcf/day) 131.4 137.9 115.5 136.5
113.3 Crude oil (bbls/day) 7,913 8,222 8,975 8,091 9,399 Natural
gas liquids (bbls/day) 2,811 2,800 1,950 2,879 2,081 Total
(BOE/day) 32,628 34,004 30,169 33,722 30,362 REALIZED COMMODITY
PRICES (CDN $) Natural gas ($/Mcf) 5.59 6.10 4.07 6.21 4.37 Without
hedging 5.93 6.69 3.10 6.83 3.35 Crude oil ($/bbl) 32.65 33.60
35.97 34.85 33.61 Without hedging 34.40 34.82 38.82 37.61 33.58
Natural gas liquids ($/bbl) 33.06 32.71 28.09 35.62 24.76
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Total ($ per BOE) 33.29 35.54 28.09 36.55 28.40
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Without hedging 35.07 38.23 25.24 39.72 24.61
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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.
MANAGEMENT'S DISCUSSION & ANALYSIS (MD&A) The following
discussion is management's analysis of PrimeWest's operating and
financial results for the quarter ended September 30, 2003,
compared with the previous quarter and the third quarter of 2002.
This discussion also contains information and opinions concerning
the Trust's future outlook based on current 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 2002, together with the
accompanying notes, as contained in the Trust's 2002 Annual Report.
STRATEGY YEAR-TO-DATE PERFORMANCE CURRENT 2003 OUTLOOK Asset Growth
- Closed the acquisition of - Continue to pursue the Caroline /
Peace River value added Arch properties. acquisitions in existing
core areas or to create a new core area, although asset supply is
currently limited and the acquisition market is very competitive.
Operating - Production year to date is - Average 33,500 BOE/day
Excellence 33,722 BOE/day. of production for the calendar year
2003. - Third quarter capital - Invest up to spending was $31.4
million $100 million in value and year to date added incremental
$75.6 million. production through drilling and completions,
facility optimization and workovers. - Year to date operating -
Operating expenses are expenses are targeted to be between $6.32
per BOE. $6.00 - $6.50 per BOE. Financial - Debt-to-cash flow ratio
for - Year end debt levels are Prudence the quarter annualized was
expected to be 1.13 versus 1.25 at the end conservative and well of
the second quarter. within our long term strategy of maintaining a
debt-to-cash flow ratio of less than 2.0 times. - Un-utilized
credit facility of $129 million at September 30, 2003. -
Distributions payable for - Anticipated 2003 payout the quarter
totalled $0.96 ratio of approximately per unit - $0.32 per unit 90%
relative to our paid in August, September longer term payout ratio
and October. The year to target of approximately date payout ratio
is 87%. 70 - 90%. Risk - Ongoing hedges continue to - At the end of
the third Management reduce volatility; however, quarter,
approximately strong commodity prices year 54% of production for
the to date in 2003 have resulted fourth quarter is hedged. in a
hedging loss of Our hedging strategy is $29.2 million to September
to reduce distribution 30, 2003. PrimeWest's volatility by hedging
program has delivered maintaining price gains of $37.8 million over
protection to a maximum the period January 1, 2001 to of 70% of
production net September 30, 2003. of royalties and development
additions. PRODUCTION VOLUMES Three months ended Nine months ended
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Sep 30, Jun 30, Sep 30, Sep 30, Sep 30, 2003 2003 2002 2003 2002
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Natural gas (MMcf/day) 131.4 137.9 115.5 136.5 113.3 Crude oil
(bbls/day) 7,913 8,222 8,975 8,091 9,399 Natural gas liquids
(bbls/day) 2,811 2,800 1,950 2,879 2,081 Total (BOE/day) 32,628
34,004 30,169 33,722 30,362
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Gross Overriding Royalty volumes included above (BOE/day) 1,270
1,754 1,560 1,607 1,757
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The 4% decrease in production volumes quarter over quarter is due
to a prior period gross overriding royalty adjustment (195
BOE/day), shutdown of a third party gas plant forcing the
redirection of Caroline volumes (153 BOE/day), facility capacity
restraints at Whiskey Creek (153 BOE/day) and natural decline.
Through the quarter, approximately 625 BOE/day of incremental
production was brought on-line to mitigate decline. Approximately
1,500 BOE/day remain behind pipe at the end of the quarter. Subject
to an ongoing review by the EUB relating to the gas / bitumen issue
in NE Alberta, PrimeWest's Ells production of approximately 450
BOE/day remains on-stream. The previously disclosed asset
divestment of $12 million, representing 100 BOE/day, has not closed
as anticipated. Compared to the third quarter of 2002, production
volumes are higher, primarily as a result of production acquired in
the Caroline/Peace River Arch areas. PRODUCTION OUTLOOK PrimeWest
continues to expect full year volumes to be approximately 33,500
BOE/day. REALIZED COMMODITY PRICES Benchmark prices Three months
ended Nine months ended
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Sep 30, Jun 30, Sep 30, Sep 30, Sep 30, 2003 2003 2002 2003 2002
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Natural gas ($/Mcf AECO) $6.29 $7.00 $3.25 $7.07 $3.67 Crude oil
($U.S./bbl WTI) $30.20 $28.91 $28.27 $30.99 $25.39
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Average PrimeWest realized commodity prices (Cdn dollars) Three
months ended Nine months ended
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Sep 30, Jun 30, Sep 30, Sep 30, Sep 30, 2003 2003 2002 2003 2002
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Natural gas ($/Mcf) $5.59 $6.10 $4.07 $6.21 $4.37 Crude oil ($/bbl)
32.65 33.60 35.97 34.85 33.61 Natural gas liquids ($/bbl) 33.06
32.71 28.09 35.62 24.76 Total Oil Equivalent ($ per BOE) $33.29
$35.54 $28.09 $36.55 $28.40
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Realized hedging gain (loss) included in prices above($ per BOE)
$(1.78) $(2.69) $2.85 $(3.17) $3.71
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PrimeWest's hedging program has delivered gains of $37.8 million
over the period January 1, 2001 to September 30, 2003. PrimeWest
uses hedging to reduce volatility in cash flows, protect
acquisition economics and to stabilize distributions against the
unpredictable commodity price environment. Although hedging is
designed to protect from the downside risk, it can result in
PrimeWest not participating fully in the upside. SALES REVENUE(1)
($ millions) Three months ended Nine months ended
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Sep 30, Jun 30, Sep 30, Sep 30, Sep 30, 2003 2003 2002 2003 2002
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Natural gas $67.6 $76.5 $43.2 $231.5 $135.1 Crude oil 23.8 25.1
29.7 77.0 86.2 Natural gas liquids 8.6 8.3 5.0 28.0 14.1
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Total $100.0 $109.9 $77.9 $336.5 $235.4
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Hedging (loss)/gains included above(2) $(5.4) $(8.3) $7.9 $(29.2)
$30.8
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(1) Excludes sulphur (2) Net of amortized premiums Revenues for the
third quarter of 2003 were $100 million compared to $109.9 million
in the previous quarter as a result of lower commodity prices and
production volumes and the strengthened Canadian dollar. The recent
strength of the Canadian dollar versus its American counterpart
continues to negatively impact the oil and gas sector. Oil and gas
prices are denominated in U.S. dollars, therefore, a strengthened
Canadian dollar translates into lower Canadian revenue for
producers. Revenues for the third quarter of 2003 were 28% higher
than the third quarter of 2002. The major factor is the overall
higher commodity prices realized thus far in 2003, along with
higher production levels associated with the acquisition of the
Caroline/Peace River Arch properties. PRICE OUTLOOK The following
table sets forth benchmark historical and estimated future
commodity prices. Benchmark Past Four Quarters Next Four Quarters
Commodity Prices (Actual) (Forward Markets)(1)
---------------------------------------------
--------------------------- Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 2002 2003 2003
2003 2003 2004 2004 2004
---------------------------------------------
--------------------------- Natural gas NYMEX ($U.S./Mcf) 3.99 6.61
5.48 5.10 4.81 5.19 4.74 4.72 AECO ($Cdn/Mcf) 5.26 7.92 7.00 6.29
5.85 6.14 5.52 5.48 Crude oil WTI ($U.S./bbl) 28.15 33.86 28.91
30.20 28.74 27.64 26.82 26.25
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--------------------------- (1) As at September 30, 2003 Crude oil
prices fluctuated during the third quarter reflecting the announced
intention of the U.S. to again start the flow of Iraqi oil, the
intervention of OPEC, ongoing civil unrest in Nigeria and
Venezuela, the low storage levels of crude oil in the contiguous
U.S., and the end of the "driving season" in North America. During
the quarter, oil reached a low of $U.S. 26.93 on September 23rd and
a high of $U.S. 32.39 on August 7th. On September 24, 2003 OPEC
announced production would be curtailed by some 900,000 barrels per
day, and the markets immediately reacted as the price of benchmark
WTI closed at $U.S. 28.05 up over a dollar over the previous day's
close. By September month-end, WTI crude had reached over $U.S.
29.00. The forward market for crude oil indicates future prices in
steady decline over the next four quarters. The forward market for
WTI averaged for the next 12 months is $U.S. 27.36 per barrel,
compared to $U.S. 30.20 per barrel for the third quarter 2003.
Natural gas prices declined about 10% from the second to the third
quarter, as a result of higher injection rates of gas into storage
and a significant recovery of natural gas inventories. Sustained
high natural gas pricing has resulted in ongoing demand destruction
in the U.S. gas fired electrical generation and industrial use
sectors contributing to higher injection rates. Very high drilling
levels, additional pipeline capacity out of the U.S. Rocky Mountain
Basin, and additional imports to North America of Liquified Natural
Gas ("LNG") have also resulted in additional natural gas supplies
being available to the market. Despite the rebalancing of supply
and demand forces mentioned above, the forward market for natural
gas still represents historically high pricing throughout the next
four quarters. The forward market for AECO averaged for the next
twelve months is $5.75 per mcf, compared to $6.29 per mcf for the
third quarter 2003. With oil and gas prices denominated in U.S.
dollars, the strengthening Canadian dollar has continued to
negatively impact Canadian dollar realizations. During the third
quarter of 2003 the foreign exchange rate for the Canadian dollar
averaged $U.S. 0.75 compared to an average exchange rate of $U.S.
0.64 during the third quarter of 2002. Year to date 2003, the
exchange rate for the Canadian dollar has averaged $U.S. 0.70
compared to $U.S. 0.637 during the calendar year 2002. ROYALTIES
Three months ended Nine months ended
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Sep 30, Jun 30, Sep 30, Sep 30, Sep 30, 2003 2003 2002 2003 2002
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Royalty expense ($ millions) $23.1 $25.0 $14.0 $80.8 $39.2 $/ BOE
$7.70 $8.08 $5.04 $8.77 $4.73 Royalties as % of sales revenue -
including hedging 23.1% 22.7% 18.0% 24.0% 16.7% - excluding hedging
21.9% 21.1% 20.0% 22.1% 19.3%
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Royalty rates increased in the third quarter compared to the second
quarter of 2003 as a result of thirteenth month adjustments from
the Crown and revenue adjustments on some properties. Hedging gains
do not attract royalties and hedge losses do not provide for
royalty reductions. As a result of significantly higher commodity
prices realized in the third quarter of 2003 compared to the same
period in 2002, the royalty expense and royalty rates were higher.
OPERATING EXPENSES Three months ended Nine months ended
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Sep 30, Jun 30, Sep 30, Sep 30, Sep 30, 2003 2003 2002 2003 2002
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Operating expenses ($ millions) $17.2 $20.3 $14.9 $58.2 $44.0 $ /
BOE $5.73 $6.57 $5.38 $6.32 $5.30
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The third quarter operating expenses are significantly lower than
the previous quarter due to operating synergies realized through
the rationalization of the recently acquired Caroline property,
declining labour costs resulting from field personnel restructuring
and lower power costs. Expenses in the third quarter 2003 are $2.3
million higher than the same period in 2002 due to operating costs
associated with the Caroline/Peace River Arch acquisition.
OPERATING EXPENSES OUTLOOK Operating costs for the full year are
expected to be higher than 2002, due to higher power costs and
one-time employee and contractor restructuring expenses. We
continue to expect full year costs to be approximately $6.00 to
$6.50 per BOE. OPERATING MARGIN ($ per BOE) Three months ended Nine
months ended
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Sep 30, Jun 30, Sep 30, Sep 30, Sep 30, 2003 2003 2002 2003 2002
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Sales price(1) $33.40 $35.75 $28.04 $36.68 $28.31 Royalties 7.70
8.08 5.04 8.77 4.73 Operating costs 5.73 6.57 5.38 6.32 5.30
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Operating margin $19.97 $21.10 $17.62 $21.59 $18.28
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(1) Including hedging gains and other revenue/losses The operating
margin declined from the second quarter 2003 level reflecting lower
natural gas prices and crude oil prices, and a strengthened
Canadian dollar offset by reduced hedging losses, lower royalties
and lower operating costs. Operating margins year to date 2003 are
higher than the same period in 2002 as a result of higher commodity
prices for both oil and natural gas offset by increased royalty,
operating costs, and a strengthened Canadian dollar. GENERAL &
ADMINISTRATIVE EXPENSE Three months ended Nine months ended
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Sep 30, Jun 30, Sep 30, Sep 30, Sep 30, 2003 2003 2002 2003 2002
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G&A expense ($ millions) $3.5 $3.2 $2.4 $10.5 $8.0 $/BOE $1.15
$1.04 $0.88 $1.14 $0.96
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Third quarter G&A costs were higher than the second quarter of
2003 due to higher salary costs as a result of hiring additional
technical staff, and one time costs of approximately $0.4 million
associated with evaluating international opportunities. Compared to
the third quarter of 2002, G&A costs were higher due to higher
payouts under the Short-Term Incentive Plan as well as higher
salary, benefit, restructuring, information systems and office
lease costs. G&A EXPENSE OUTLOOK Cash G&A expenses are
expected to be approximately $1.15 per BOE for the year. MANAGEMENT
FEES EXPENSE Three months ended Nine months ended
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Sep 30, Jun 30, Sep 30, Sep 30, Sep 30, 2003 2003 2002 2003 2002
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Cash management fees ($ millions) $- $- $1.3 $- $4.0 $/ BOE $- $-
$0.47 $- $0.48 Non-cash management fees ($ millions) $- $- $0.4 $-
$1.4 $/ BOE $- $- $0.16 $- $0.17
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On November 4, 2002, unitholders approved the internalization of
management effective October 1, 2002. Accordingly, there are no
cash or non- cash management fees after that date. NON-CASH G&A
EXPENSES Three months ended Nine months ended
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Sep 30, Jun 30, Sep 30, Sep 30, Sep 30, 2003 2003 2002 2003 2002
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Non-cash G&A expenses ($ millions) $2.3 $3.2 $(0.9) $5.9 $6.0
$/ BOE $0.76 $1.05 $(0.34) $0.64 $0.73
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Non-cash G&A expenses consist mainly of Unit Appreciation
Rights. UARs are similar to stock options in a conventional
business. The UARs are marked-to-market each quarter and the impact
is recognized as an expense or recovery in the income statement of
the Trust. INTEREST EXPENSE ($ millions) Three months ended Nine
months ended
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Sep 30, Jun 30, Sep 30, Sep 30, Sep 30, 2003 2003 2002 2003 2002
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Interest expense $4.0 $3.4 $3.0 $11.0 $7.6 Period end net debt
level $233.2 $286.4 $270.9 $233.2 $270.9 Debt per Trust Unit $4.67
$6.17 $8.01 $4.67 $8.01 Average cost of debt 4.7% 4.4% 4.5% 4.5%
4.3%
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The period end net debt level decreased significantly as a result
of the equity offering which was used to repay debt. At September
30, 2003, approximately 98% of the debt was at a fixed rate, with
the balance at a floating rate. PrimeWest utilizes interest rate
swaps that permit greater flexibility in the maintenance of fixed
versus floating interest rates. During the second quarter,
PrimeWest completed a $U.S. 125 million private placement debt
financing of secured notes at a coupon rate of 4.19% with a seven
year term. DEPLETION, DEPRECIATION AND AMORTIZATION (DD&A)
Three months ended Nine months ended
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Sep 30, Jun 30, Sep 30, Sep 30, Sep 30, 2003 2003 2002 2003 2002
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Depletion, depreciation & amortization ($ millions) $50.7 $49.9
$46.0 $153.3 $137.1 $/ BOE $16.91 $16.13 $16.56 $16.66 $16.49
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Year to date 2003 DD&A is higher than 2002 reflecting higher
production volumes and reserves as a result of additional volumes
associated with the Caroline / Peace River Arch acquisition. The
DD&A rate is inflated relative to the acquisition cost of
certain reserves due to the requirement to account for future
income tax liabilities associated with the acquisition of those
reserves. The offset is in the income tax recovery. Absent this tax
adjustment, the DD&A rate would be lower by approximately $3.50
per BOE in the third quarter of 2003. SITE RESTORATION AND CLEAN-UP
PrimeWest has contributed $0.50 per BOE year to date in 2003 to pay
for future costs related to well abandonment and site clean-up. The
monies are then used to pay for reclamation and abandonment costs
as they are incurred. This allows PrimeWest to fund abandonment on
an ongoing basis, rather than incur a major cost at the conclusion
of the productive life of an oil or gas asset. CEILING TEST
PrimeWest has performed a ceiling test using commodity prices as at
the measurement date of September 30, 2003. Using September 30,
2003, commodity prices of AECO $5.75 per mcf for natural gas and
WTI U.S. $29.20 per barrel of oil would result in a significant
cushion of approximately $525 million. INCOME AND CAPITAL TAXES ($
millions) Three months ended Nine months ended
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Sep 30, Jun 30, Sep 30, Sep 30, Sep 30, 2003 2003 2002 2003 2002
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Income and capital taxes $0.8 $1.5 $1.3 $3.5 $2.6 Future income
taxes recovery (8.7) (52.0) (12.8) (71.1) (23.1)
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$(7.9) $(50.5) $(11.5) $67.6 $(20.5)
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On June 9, 2003, the Canadian Government substantially enacted
Federal income tax changes for the oil and gas resource sector as
outlined in its 2003 Budget. The Federal income tax changes
effectively reduced the statutory tax rates for current and future
periods, resulting in a significant increase in the future tax
recovery (a non-cash item) compared to the first quarter and prior
years. Specifically, the current 100% deductibility of the resource
allowance will be completely phased out by the year 2007. During
the same time frame, Crown charges will become 100% deductible and
resource tax rates will decline from the current 27% to 21%. NET
INCOME (LOSS) ($ millions) Three months ended Nine months ended
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Sep 30, Jun 30, Sep 30, Sep 30, Sep 30, 2003 2003 2002 2003 2002
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Net income (loss) $7.3 $61.7 $8.2 $91.0 $8.0
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During the second quarter of 2003 substantial income tax recoveries
and foreign exchange gains contributed to net income. In addition
to these items, third quarter net income is lower than the previous
quarter due to lower production levels and commodity prices.
LIQUIDITY AND CAPITAL RESOURCES ($ millions) As at
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Sep 30, 2003 Jun 30, 2003 Sep 30, 2002
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Long-term debt $247.7 $298.4 $255.0 Working capital
deficit/(surplus) (14.3) (12.0) 15.9
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Net debt 233.4 286.4 270.9 Market value of Trust Units and
exchangeable shares outstanding 1,247.3 1,151.7 894.0
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Total capitalization $1,480.7 $1,438.1 $1,164.9
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Net debt as a % of total capitalization 15.8% 19.9% 23.25%
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Third quarter 2003 debt levels are down significantly when compared
to the second quarter of 2003 due to the September equity offering
of $76.3 million which was used to pay down debt. At September 30,
2003, the long-term debt was comprised of bank credit facilities
and senior secured notes for $79 million and $168.7 million,
respectively. The notes were issued on May 6, 2003 for a principal
value of U.S. $125 million. Debt levels now stand at approximately
1x cash flow, well below our target of 2x cash flow allowing for
greater financial flexibility. CAPITAL SPENDING ($ millions) Three
months ended Nine months ended
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Sep 30, Jun 30, Sep 30, Sep 30, Sep 30, 2003 2003 2002 2003 2002
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Expenditures on property, plant and equipment $31.4 $18.8 $12.0
$75.6 $49.2
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Capital spending of $31.4 million during the third quarter was
behind year to date expectations due to timing of capital project
execution. Full year capital spending estimates continue to be
approximately $100 million. Of the $31.4 million, $19.0 million was
spent on drilling and completions, and $9.4 million on facilities
and infrastructure, with the remainder on lease acquisitions and
other. The focus of the development program centered on properties
in the Caroline, Valhalla and Brant Farrow areas, with 4, 7 and 8
wells drilled in those areas respectively. During the third quarter
PrimeWest drilled a total of 24 gross wells with a success rate of
96%. HEDGING PROGRAM Approximate percentage of future anticipated
production volumes hedged at September 30, 2003; net of anticipated
royalties, reflecting full production declines with no offsetting
additions: Q4 2003 Q1 2004 Q2 2004
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Crude Oil 63% 51% 33% Natural Gas 49% 49% 18%
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The mark-to-market valuation of these hedges was a $0.5 million
loss at September 30, 2003 consisting of a $0.6 million loss in
crude oil and a $0.1 million gain in natural gas. A summary of
contracts in place as at September 30, 2003 is as follows: Crude
Oil (U.S.$/bbl) Period Volume WTI Price (bbl/d) Type (U.S.$/bbl)
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Oct - Dec 2003 1,000 3 Way 17.00/20.50/25.50 Oct - Dec 2003 1,000 3
Way 18.50/22.50/27.20 Oct - Dec 2003 500 Swap 27.49 Oct - Dec 2003
500 Swap 29.07 Oct - Dec 2003 500 Swap 30.51 Oct - Dec 2003 500
Costless Collar 24.00/30.00 Oct - Dec 2003 500 Costless Collar
26.00/32.45 Jan - Mar 2004 1000 Swap 27.29 Jan - Mar 2004 500 Swap
28.87 Jan - Mar 2004 500 Costless Collar 22.00/26.70 Jan - Mar 2004
500 Costless Collar 23.00/33.30 Jan - Mar 2004 500 Costless Collar
24.00/31.20 Jan - Mar 2004 500 Costless Collar 25.00/28.16 Apr -
Apr 2004 500 Swap 27.02 Apr - Jun 2004 500 Swap 27.21 Apr - Jun
2004 500 Costless Collar 22.00/26.12 Apr - Jun 2004 500 Costless
Collar 24.00/30.50 Apr - Jun 2004 500 Costless Collar 25.00/28.07
Jul - Jul 2004 500 Swap 27.12 Jul - Aug 2004 500 Swap 26.08
-------------------------------------------------------------------------
Natural Gas (Cdn$/Mcf) Period Volume AECO Price (MMcf/d) Type
(Cdn$/Mcf)
-------------------------------------------------------------------------
Oct - Oct 2003 4.7 Fixed Price 4.75 Oct - Oct 2003 4.7 Swap 3.98
Oct - Oct 2003 4.7 Swap 4.17 Oct - Oct 2003 4.7 Swap 5.05 Oct - Oct
2003 4.7 Swap 6.57 Oct - Oct 2003 4.7 Swap 6.45 Oct - Oct 2003 4.7
3 Way 3.17/3.96/5.39 Oct - Oct 2003 4.7 3 Way 3.17/4.48/6.26 Oct -
Oct 2003 4.7 3 Way 3.69/4.75/6.65 Oct 2003 - Oct 2004 9.5 3 Way
3.17/4.22/6.09 Nov 2003 - Mar 2004 4.7 Costless Collar 6.33/7.91
Nov 2003 - Mar 2004 4.7 3 Way 4.22/5.28/8.23 Nov 2003 - Mar 2004
4.7 Costless Collar 6.33/11.87 Nov 2003 - Mar 2004 4.7 Costless
Collar 5.80/8.23 Nov 2003 - Mar 2004 4.7 Costless Collar 6.33/8.58
Jan 2004 - Mar 2004 4.7 Costless Collar 4.75/7.91 Jan 2004 - Dec
2004 4.7 Swap 6.02
-------------------------------------------------------------------------
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 $3.00. 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 $25.50,
PrimeWest would receive the market price. Natural Gas Basis Swaps
($U.S./mcf) Period Volume AECO Price Differential (MMcf/d) Type
($U.S./Mcf)
-------------------------------------------------------------------------
Oct - Oct 2003 5.0 Basis Swap 0.45 Nov 2003 - Mar 2004 7.5 Basis
Swap 0.63 Apr - Oct 2004 5.0 Basis Swap 0.71
-------------------------------------------------------------------------
The AECO basis is the difference between the NYMEX gas price in
$U.S. per mcf and the AECO price in $U.S. per mcf. Using the first
basis swap above as an example, PrimeWest has fixed this price
difference between the two markets at $U.S. 0.45 per mcf for the
summer period. If the NYMEX price for the period turned out to be
$U.S. 4.00 per mcf, PrimeWest would receive an AECO equivalent
price of $U.S. 3.55 per mcf. Electrical Power Period Power Amount
Heat Rate (MW) Type (GJ/MW-hr)
-------------------------------------------------------------------------
Calendar 2003 2.5 Heat Rate Swap 8.75 Calendar 2003 5.0 Heat Rate
Swap 9.0
-------------------------------------------------------------------------
Period Power Amount Price (MW) Type ($/MW-hr)
-------------------------------------------------------------------------
Q1 2004 5.0 Fixed Price Swap 58.50 Q2 2004 7.5 Fixed Price Swap
40.25 Q3 2004 5.0 Fixed Price Swap 45.60 Q4 2004 5.0 Fixed Price
Swap 44.00 Calendar 2004 5.0 Fixed Price Swap 45.65
-------------------------------------------------------------------------
A heat rate swap fixes the amount of natural gas required to
generate a corresponding unit of electricity. PrimeWest produces
natural gas and consumes power. Using the first heat rate swap as
an example, PrimeWest will set aside 8.75 GJ of natural gas for
sale at daily market pricing in order to receive 1 MW-hr of
electrical power at daily market pricing. For the 2.5 MW of power
consumption, this equates to approximately 500 mcf per day of
natural gas supply. PREMIUM DISTRIBUTION, DISTRIBUTION REINVESTMENT
AND OPTIONAL TRUST UNIT PURCHASE PLAN PrimeWest is pleased to offer
its eligible Canadian unitholders an opportunity to enhance their
returns through participation in the new Premium Distribution
Component (PREP) of its existing Distribution Reinvestment (DRIP)
and Optional Trust Unit Purchase Plan (OTUPP). As an alternative to
the existing DRIP Component of the Plan, which allows eligible
Canadian unitholders to reinvest their monthly distributions at a
5% discount to the average market price, the new PREP allows
eligible Canadian unitholders to elect to receive a premium cash
distribution of up to 102% of the cash that the unitholder would
otherwise have received on the distribution date, subject to
proration in certain events. Canaccord Capital Corporation will act
as Plan Broker under the PREP Component of the Plan. The OTUPP has
been fully subscribed for the calendar year 2003 and will
re-commence in January 2004. For additional information or to join
these plans, contact PrimeWest's Plan Agent, Computershare Trust
Company of Canada at 1-800-564-6253 or visit PrimeWest's website at
http://www.primewestenergy.com/. PrimeWest has completed a review
of the requirements necessary for the establishment of a U.S. DRIP
program and has concluded that such a program for American
unitholders is not presently feasible. NON-RESIDENT OWNERSHIP
PrimeWest continues to monitor its level of non-resident ownership.
At the end of the third quarter approximately 36% of the
outstanding units of PrimeWest were held by non-residents. INCOME
TAXES - UNITHOLDERS - OUTLOOK Based on current expectations for
cash flow for 2003, it is anticipated that approximately 55% of
2003 distributions will be taxable and 45% will be tax deferred for
unitholders resident in Canada. The taxability of 2003
distributions for U.S. unitholders cannot be accurately estimated
and will be confirmed after year end. For residents of the U.S.,
Canadian withholding tax of 15% applies to the distribution. For
more details on withholding tax, please visit our website at
http://www.primewestenergy.com/. THIRD QUARTER CONFERENCE CALL AND
WEBCAST PrimeWest will be conducting a conference call and Web cast
for interested analysts, brokers, investors and media
representatives about its third quarter results and outlook at 9:00
a.m. Mountain time (11:00 a.m. Eastern time) on November 7, 2003.
Callers may dial 1-800-814-4860 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 21013347 followed by the pound (number sign) key. Interested
users of the Internet are invited to go to
http://www.newswire.ca/webcast/viewEventCNW.html?eventID(equal
sign)654940 for the live Web cast and/or replay or access the Web
cast at the PrimeWest website, http://www.primewestenergy.com/.
QUESTIONS PrimeWest Energy Trust welcomes questions from
unitholders and potential investors; call Investor Relations at
403-234-6600 or toll-free in Canada and the U.S. at 1-877-968-7878;
or visit us on the Internet at our website,
http://www.primewestenergy.com/. On behalf of the Board of
Directors: November 6, 2003 Don Garner President and Chief
Executive Officer CONSOLIDATED BALANCE SHEETS (Unaudited) (Audited)
As at Sep As at Dec (millions of dollars) 30, 2003 31, 2002
-------------------------------------------------------------------------
ASSETS Current assets Cash and short term deposits $ 21.9 $ -
Accounts receivable 74.3 71.6 Prepaid expenses 6.6 9.8 Inventory
2.7 2.2
-------------------------------------------------------------------------
105.5 83.6 Cash reserved for site restoration and reclamation 6.4 -
Other assets 0.3 14.4 Deferred charges 1.3 - Property, plant and
equipment 1,556.7 1,404.5 Goodwill (note 2) 53.9 -
-------------------------------------------------------------------------
$ 1,724.1 $ 1,502.5
-------------------------------------------------------------------------
-------------------------------------------------------------------------
LIABILITIES AND UNITHOLDERS' EQUITY Current liabilities Bank
overdraft $ - $ 3.1 Accounts payable & accrued liabilities 76.7
67.3 Accrued distributions to unitholders 14.5 13.9
-------------------------------------------------------------------------
91.2 84.3 Long-term debt (note 3) 247.7 225.0 Future income taxes
321.9 339.9 Site restoration and reclamation provision 16.6 6.2
-------------------------------------------------------------------------
677.4 655.4 UNITHOLDERS' EQUITY Net capital contributions (note 4)
1,553.1 1,300.0 Capital issued but not distributed 0.9 0.9
Long-term incentive plan equity 11.8 10.0 Accumulated income 214.2
123.2 Accumulated cash distributions (725.2) (578.9) Accumulated
dividends (8.1) (8.1)
-------------------------------------------------------------------------
1,046.7 847.1
-------------------------------------------------------------------------
$ 1,724.1 $ 1,502.5
-------------------------------------------------------------------------
CONSOLIDATED STATEMENTS OF UNITHOLDERS' EQUITY (Unaudited) Sep 30,
Sep 30, For the nine months ended 2003 2002
-------------------------------------------------------------------------
Unitholders' equity, beginning of the period $ 847.1 $ 856.3 Net
income for the period 91.0 8.0 Net capital contributions 253.1 20.9
Capital issued but not distributed - (0.7) Long-term incentive plan
equity 1.8 2.3 Cash distributions (146.3) (115.4) Dividends - (1.2)
-------------------------------------------------------------------------
Unitholders' equity, end of the period $ 1,046.7 $ 770.2
-------------------------------------------------------------------------
-------------------------------------------------------------------------
CONSOLIDATED STATEMENTS OF CASH FLOW (Unaudited) (millions of
dollars) Three months ended Nine months ended
-------------------------------------------------------------------------
Sep 30, Sep 30, Sep 30, Sep 30, 2003 2002 2003 2002
-------------------------------------------------------------------------
OPERATING ACTIVITIES Net income for the period $ 7.3 $ 8.2 $ 91.0 $
8.0 Add/(deduct): Items not involving cash from operations
Depletion, depreciation and amortization 50.7 46.0 153.3 137.1
Non-cash general & administrative 2.3 (0.9) 5.9 6.0 Non-cash
foreign exchange gain 0.2 - (5.4) - Non-cash management fees - 0.4
- 1.4 Future income taxes recovery (8.7) (12.8) (71.1) (23.1)
-------------------------------------------------------------------------
Cash flow from operations 51.8 40.9 173.7 129.4 Expenditures on
site restoration and reclamation (0.4) (1.5) (0.8) (2.6) Change in
non-cash working capital 5.4 2.6 0.1 (25.8)
-------------------------------------------------------------------------
56.8 42.0 173.0 101.0
-------------------------------------------------------------------------
FINANCING ACTIVITIES Proceeds from issue of Trust Units (net of
costs) 80.1 3.6 240.3 7.9 Net cash distributions to unitholders
(40.8) (35.6) (137.3) (107.9) Dividends - (1.2) - (1.2) Increase
(decrease) in bank credit facilities (51.0) 20.0 (146.0) 59.9
Increase in senior secured notes - - 174.0 - Increase in deferred
charges 0.1 - (1.3) - Change in non-cash working capital (2.5) 1.4
0.5 0.7
-------------------------------------------------------------------------
(14.1) (11.8) 130.2 (40.6)
-------------------------------------------------------------------------
INVESTING ACTIVITIES Expenditures on property, plant &
equipment (31.4) (12.0) (75.6) (49.2) Corporate acquisitions (0.5)
- (200.9) - Acquisition of capital assets (0.2) (26.2) (4.0) (26.2)
Proceeds on disposal of property, plant & equipment 0.6 0.9 0.8
3.7 Increase in cash reserved for future site restoration and
reclamation (3.7) - (6.4) - Change in non-cash working capital 5.2
(2.1) 7.9 -
-------------------------------------------------------------------------
(30.0) (39.4) (278.2) (71.7)
-------------------------------------------------------------------------
INCREASE (DECREASE) IN CASH FOR THE PERIOD 12.7 (9.2) 25.0 (11.3)
CASH (BANK OVERDRAFT) BEGINNING OF THE PERIOD 9.2 (16.7) (3.1)
(14.6)
-------------------------------------------------------------------------
CASH (BANK OVERDRAFT) END OF THE PERIOD $ 21.9 $ (25.9) $ 21.9 $
(25.9)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
CASH INTEREST PAID $ 1.2 $ 2.8 $ 6.3 $ 7.3
-------------------------------------------------------------------------
-------------------------------------------------------------------------
CASH TAXES PAID $ 2.6 $ 0.3 $ 3.4 $ 3.1
-------------------------------------------------------------------------
-------------------------------------------------------------------------
CONSOLIDATED STATEMENTS OF INCOME (Unaudited) (millions of dollars,
except for per-trust-unit amounts) Three months ended Nine months
ended
-------------------------------------------------------------------------
Sep 30, Sep 30, Sep 30, Sep 30, 2003 2002 2003 2002
-------------------------------------------------------------------------
REVENUES Sales of crude oil, natural gas and natural gas liquids $
100.2 $ 77.8 $ 337.4 $ 234.6 Crown and other royalties, net of ARTC
(23.1) (14.0) (80.8) (39.2) Other income 0.1 - 0.3 0.1
-------------------------------------------------------------------------
77.2 63.8 256.9 195.5
-------------------------------------------------------------------------
EXPENSES Operating 17.2 14.9 58.2 43.9 General and administrative
3.5 2.4 10.5 8.0 Non-cash general and administrative 2.3 (0.9) 5.9
6.0 Interest 4.0 3.0 11.0 7.6 Cash management fees - 1.3 - 4.0
Non-cash management fees - 0.4 - 1.4 Foreign exchange (gain)/loss
0.1 - (5.4) - Depletion, depreciation and amortization 50.7 46.0
153.3 137.1
-------------------------------------------------------------------------
77.8 67.1 233.5 208.0
-------------------------------------------------------------------------
Income (loss) before taxes for the period (0.6) (3.3) 23.4 (12.5)
-------------------------------------------------------------------------
Income and capital taxes 0.8 1.3 3.5 2.6 Future income taxes
recovery (8.7) (12.8) (71.1) (23.1)
-------------------------------------------------------------------------
(7.9) (11.5) (67.6) (20.5)
-------------------------------------------------------------------------
Net income for the period $ 7.3 $ 8.2 $ 91.0 $ 8.0
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net income per Trust Unit $ 0.16 $ 0.24 $ 2.03 $ 0.24 Diluted net
income per Trust Unit $ 0.16 $ 0.24 $ 2.02 $ 0.24
-------------------------------------------------------------------------
-------------------------------------------------------------------------
CONSOLIDATED STATEMENTS OF CASH DISTRIBUTIONS (UNAUDITED) (millions
of dollars, except for per-trust-unit and number of units) Three
months ended Nine months ended
-------------------------------------------------------------------------
Sep 30, Sep 30, Sep 30, Sep 30, 2003 2002 2003 2002
-------------------------------------------------------------------------
Net income for the period $ 7.3 $ 8.2 $ 91.0 $ 8.0 Add back
(deduct) amounts to reconcile to distribution: Depletion,
depreciation and amortization 50.7 46.0 153.3 137.1 Undistributed
cash (4.0) (0.6) (20.2) (9.8) Contribution to reclamation fund
(4.1) (1.1) (7.2) (3.1) Non-cash general and administrative 2.3
(0.9) 5.9 6.0 Non-cash foreign exchange 0.2 - (5.4) - Management
fees paid in Trust Units - 0.4 - 1.4 Future income taxes recovery
(8.7) (12.8) (71.1) (23.1)
-------------------------------------------------------------------------
$ 36.4 $ 31.0 $ 55.3 $ 108.5
-------------------------------------------------------------------------
-------------------------------------------------------------------------
$ 43.7 $ 39.2 $ 146.3 $ 116.5
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Cash Distributions to Trust Unitholders $ 43.7 $ 38.8 $ 146.3 $
115.4
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Cash Distributions per Trust Unit $ 1.04 $ 1.20 $ 3.44 $ 3.60
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Trust Units and exchangeable shares issued and outstanding
(diluted) 49,903,296 34,107,072 49,903,296 34,107,072
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Weighted average Trust Units and exchangeable shares outstanding
(diluted) 46,808,859 33,929,397 45,154,073 33,514,149
-------------------------------------------------------------------------
-------------------------------------------------------------------------
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) For the nine
months ended September 30, 2003 (millions of dollars except per
Trust Unit/share amounts) 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 43 through 63 of the Trust's 2002 annual
report and should be read in conjunction with these interim
financial statements. Under the revised terms of section 1580 of
the CICA handbook, the excess of the cost of the purchase price
over the acquiring company's interest in identifiable assets
acquired, and liability assumed, should be reflected as goodwill.
The tax basis deficiency that would previously be added to the
depletable pool is now accounted for as goodwill that would not be
subject to amortization. A periodic impairment test is then carried
out to prove the validity of the goodwill account. 2. ACQUISITION
On January 23, 2003, PrimeWest Energy Inc. completed the
acquisition of two private Canadian companies. The acquisition was
accounted for using the purchase method of accounting with net
assets acquired and consideration paid as follows: Net Assets
Acquired at Assigned Values Consideration Paid
-------------------------------------------------------------------------
Petroleum and natural gas assets $220.9 Goodwill 53.9 Working
capital, including cash of $4.0 2.9 Site restoration provision
(5.4) Cash $212.7 Future income taxes (53.2) Costs associated with
acquisition 6.4
-------------------------------------------------------------------------
$219.1 $219.1
-------------------------------------------------------------------------
-------------------------------------------------------------------------
3. LONG-TERM DEBT 2003 2002
-------------------------------------------------------------------------
Bank credit facilities $79.0 $225.0 Senior secured notes 168.7 -
-------------------------------------------------------------------------
$247.7 $225.0
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Bank Credit Facilities The facility consists of a revolving term
loan of $188 million and an operating facility of $25 million. In
addition to amounts outstanding under the facility, PrimeWest has
outstanding letters of credit in the amount of $5.0 million (2002 -
$4.3 million). Collateral for the credit facility is provided by a
floating-charge debenture covering all existing and after acquired
property in the principal amount of $1.0 billion. Each borrower
under the facility has also provided an unconditional full
liability guarantee in respect of amounts borrowed under the
facility. Advances under the facility are made in the form of
Banker's Acceptances (BA), prime rate loans or letters of credit.
In the case of BA, interest is a function of the BA rate plus a
stamping fee based on the Trust's current ratio of debt to cash
flow. In the case of prime rate loans, interest is charged at the
bank's prime rate. For the quarter ended September 30, 2003, the
effective rate was 4.7% (2002 - 4.5%). The credit facility revolves
until June 30, 2004, by which time the lender will have conducted
its annual borrowing base review. The lender also has the right to
re-determine the borrowing base at one other time during the year.
During the revolving phase, the facility has no specific terms of
repayment. At the end of the revolving period, the lender has the
right to extend the revolving period for a further 364-day period
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 that is 366 days after
such conversion date and the remaining 40% of the aggregate
principal amount outstanding shall be repayable on the date that is
365 days after the initial repayment date. Senior Secured Notes On
May 7, 2003, PrimeWest replaced a portion of its bank debt with
Senior Secured Notes (the "Notes") in the amount of U.S. $125
million. They have a final maturity of May 7, 2010, and bear
interest at 4.19% per annum, with interest paid semi-annually on
November 7 and May 7 of each year. The Note Purchase Agreement
requires PrimeWest to make four annual principal repayments of U.S.
$31,250,000 commencing May 7, 2007. The costs incurred in
connection with the Notes, in the amount of $1.4 million, are
classified as deferred charges on the balance sheet and are being
amortized over the term of the Notes. The Senior Secured Notes are
the legal obligation of PrimeWest Energy Inc. and are guaranteed by
PrimeWest Energy Trust. 4. UNITHOLDERS' EQUITY PrimeWest Energy
Trust The authorized capital of the Trust consists of an unlimited
number of Trust Units. Trust Units No. of Units Amounts
-------------------------------------------------------------------------
Balance at December 31, 2002 37,004,522 $1,252.2 Issued pursuant to
Prospectus Offering 9,100,000 234.8 Issued pursuant to Long-term
Incentive Plan 146,180 3.8 Issued pursuant to Dividend Reinvestment
Plan 366,004 9.0 Issued pursuant to Optional Trust Issuance Plan
721,209 17.6 Issued on exchange of Exchangeable Shares 483,401 11.2
Issue of units due to Odd Lot Program 42 - Issue expenses incurred
- (12.1)
-------------------------------------------------------------------------
Balance at September 30, 2003 47,821,358 1,516.5
-------------------------------------------------------------------------
-------------------------------------------------------------------------
The per unit amount of distributions paid or declared reflects
distributions paid for units outstanding on the record dates.
PrimeWest Exchangeable Class A 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 September
15, 2003, was 0.42720 and December 31, 2002 was 0.37454.
Exchangeable shares No. of Shares Amounts
-------------------------------------------------------------------------
Balance at December 31, 2002 5,179,278 $47.7 Exchanged for Trust
Units (1,211,268) (11.1)
-------------------------------------------------------------------------
Balance at September 30, 2003 3,968,010 $36.6
-------------------------------------------------------------------------
-------------------------------------------------------------------------
5. TRUST UNIT INCENTIVE PLAN Under the terms of the Trust Unit
Incentive Plan, a maximum of 1,800,000 Trust Units are reserved for
issuance pursuant to the exercise of Unit Appreciation Rights
(UARs) granted to employees. Payouts under the plan are based on
total unitholder return, calculated using both the change in the
Trust Unit price as well as cumulative distributions paid. The plan
requires that a hurdle return of 5% per annum be achieved before
payouts accrue. UARs have a term of up to six years and vest
equally over a three-year period, except for the members of the
Board, whose UARs vest immediately. The Board of Directors has the
option of settling payouts under the plan in PrimeWest Trust Units
or in cash. To date, all payouts under the plan have been in the
form of Trust Units. As at UARs Current Trust Unit September issued
and UARs return Total outstanding 30, 2003 outstanding vested per
UAR equity(1) dilution
-------------------------------------------------------------------------
1998 grants 88,022 88,022 $41.07 $3.6 143,508 1999 grants 94,297
94,297 27.34 2.6 102,352 2000 grants 149,054 142,151 11.91 1.8
68,352 2001 grants 424,182 269,073 4.13 1.5 38,092 2002 grants
975,534 443,659 2.14 1.6 26,945 2003 grants 1,072,740 141,896 1.44
0.7 7,555
-------------------------------------------------------------------------
2,803,829 1,179,098 $11.8 386,804
-------------------------------------------------------------------------
(1)Includes vested and unvested units "in the money" Cumulative to
September 30, 2003, 836,843 UARs have been exercised resulting in
the issuance of 504,946 Trust Units from treasury. The 386,804
Trust Unit outstanding dilution represents less than 1% of the
total Trust Units outstanding as at September 30, 2003. TRADING
PERFORMANCE Sep Jun Mar Dec Sep For the quarter ended 30/03 30/03
31/03 31/02 30/02
-------------------------------------------------------------------------
TSX Trust Unit prices ($ per Trust Unit) High 26.80 27.75 27.34
27.68 29.56 Low 25.19 23.40 24.48 24.23 24.48 Close 25.19 25.04
24.51 25.40 26.45
-------------------------------------------------------------------------
Average daily traded volume 149,148 234,477 184,428 123,964 109,216
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Sep Jun Mar Dec Sep For the quarter ended 30/03 30/03 31/03 31/02
30/02
-------------------------------------------------------------------------
NYSE Trust Unit prices ($U.S. per Trust Unit) High 19.29 20.60
17.96 16.69 Low 18.08 15.97 16.05 15.62 Close 18.68 18.53 16.73
16.16
-------------------------------------------------------------------------
Average daily traded volume 151,813 166,722 111,605 39,276
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Number of Trust Units outstanding including exchangeable shares
(millions of units) 49.52 45.99 45.43 38.94 33.80
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Distribution paid per Trust Unit $1.04 $1.20 $1.20 $1.20 $1.20
-------------------------------------------------------------------------
-------------------------------------------------------------------------
TOTAL COMPOUND ANNUAL RETURN (%)(1)
-------------------------------------------------------------------------
Q3, 2003 Five Years Three Years One Year YTD
-------------------------------------------------------------------------
PrimeWest 14.6 23.6 19.5 12.9(x)
-------------------------------------------------------------------------
OGPI 8.4 20.7 16.2 7.7
-------------------------------------------------------------------------
TSX S&P 1.3 -6.3 -12.4 13.8
-------------------------------------------------------------------------
S&P 500 1.4 -12.1 -22.9 14.7
-------------------------------------------------------------------------
S&P TSX Cndn Energy Trust Index 25.6
-------------------------------------------------------------------------
(1) Total return (equal sign) unit price plus distributions
re-invested (x) On a U.S. dollar basis, the total return to
PrimeWest unitholders has been 31.6% year to date, 2003 DATASOURCE:
PrimeWest Energy Trust CONTACT: For Investor Relations inquiries,
please contact: George Kesteven, Manager, Investor Relations, (403)
699-7367; Cindy Gray, Investor Relations Advisor, (403) 699-7356,
Toll-free: 1-877-968-7878, e-mail: ; To request a free copy of this
organization's annual report, please go to http://www.newswire.ca/
and click on reports@cnw.
Copyright
