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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
------------------------------------------------------------
------------------------------------------------------------
(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
-------------------------------------------------------------------------
Sep 30, Jun 30, Sep 30, Sep 30, Sep 30,
2003 2003 2002 2003 2002
-------------------------------------------------------------------------
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
-------------------------------------------------------------------------
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
-------------------------------------------------------------------------
Total ($ per BOE) 33.29 35.54 28.09 36.55 28.40
-------------------------------------------------------------------------
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
-------------------------------------------------------------------------
Sep 30, Jun 30, Sep 30, Sep 30, Sep 30,
2003 2003 2002 2003 2002
-------------------------------------------------------------------------
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 $12 million,
representing 100 BOE/day, has not closed as anticipated.
Compared to the third quarter of 2002, production volumes are higher, primarily
as a result of production acquired in the Caroline/Peace River Arch areas.
PRODUCTION OUTLOOK
PrimeWest continues to expect full year volumes to be approximately 33,500
BOE/day.
REALIZED COMMODITY PRICES
Benchmark prices Three months ended Nine months ended
-------------------------------------------------------------------------
Sep 30, Jun 30, Sep 30, Sep 30, Sep 30,
2003 2003 2002 2003 2002
-------------------------------------------------------------------------
Natural gas ($/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 $25.39
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Average PrimeWest realized
commodity prices (Cdn dollars) Three months ended Nine months ended
-------------------------------------------------------------------------
Sep 30, Jun 30, Sep 30, Sep 30, Sep 30,
2003 2003 2002 2003 2002
-------------------------------------------------------------------------
Natural gas ($/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
-------------------------------------------------------------------------
Sep 30, Jun 30, Sep 30, Sep 30, Sep 30,
2003 2003 2002 2003 2002
-------------------------------------------------------------------------
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
-------------------------------------------------------------------------
Total $100.0 $109.9 $77.9 $336.5 $235.4
-------------------------------------------------------------------------
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
--------------------------------------------- ---------------------------
(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 $U.S. 0.637 during the calendar year
2002.
ROYALTIES
Three months ended Nine months ended
-------------------------------------------------------------------------
Sep 30, Jun 30, Sep 30, Sep 30, Sep 30,
2003 2003 2002 2003 2002
-------------------------------------------------------------------------
Royalty expense
($ millions) $23.1 $25.0 $14.0 $80.8 $39.2
$/ BOE $7.70 $8.08 $5.04 $8.77 $4.73
Royalties as %
of sales revenue
- including hedging 23.1% 22.7% 18.0% 24.0% 16.7%
- excluding hedging 21.9% 21.1% 20.0% 22.1% 19.3%
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Royalty rates increased in the third quarter compared to the second quarter of
2003 as a result of thirteenth month adjustments from the Crown and revenue
adjustments on some properties. Hedging gains do not attract royalties and hedge
losses do not provide for royalty reductions.
As a result of significantly higher commodity prices realized in the third
quarter of 2003 compared to the same period in 2002, the royalty expense and
royalty rates were higher.
OPERATING EXPENSES
Three months ended Nine months ended
-------------------------------------------------------------------------
Sep 30, Jun 30, Sep 30, Sep 30, Sep 30,
2003 2003 2002 2003 2002
-------------------------------------------------------------------------
Operating expenses
($ millions) $17.2 $20.3 $14.9 $58.2 $44.0
$ / BOE $5.73 $6.57 $5.38 $6.32 $5.30
-------------------------------------------------------------------------
-------------------------------------------------------------------------
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
-------------------------------------------------------------------------
Sep 30, Jun 30, Sep 30, Sep 30, Sep 30,
2003 2003 2002 2003 2002
-------------------------------------------------------------------------
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
-------------------------------------------------------------------------
Operating margin $19.97 $21.10 $17.62 $21.59 $18.28
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Including hedging gains and other revenue/losses
The operating margin declined from the second quarter 2003 level reflecting
lower natural gas prices and crude oil prices, and a strengthened Canadian
dollar offset by reduced hedging losses, lower royalties and lower operating
costs.
Operating margins year to date 2003 are higher than the same period in 2002 as a
result of higher commodity prices for both oil and natural gas offset by
increased royalty, operating costs, and a strengthened Canadian dollar.
GENERAL & ADMINISTRATIVE EXPENSE
Three months ended Nine months ended
-------------------------------------------------------------------------
Sep 30, Jun 30, Sep 30, Sep 30, Sep 30,
2003 2003 2002 2003 2002
-------------------------------------------------------------------------
G&A expense ($ millions) $3.5 $3.2 $2.4 $10.5 $8.0
$/BOE $1.15 $1.04 $0.88 $1.14 $0.96
-------------------------------------------------------------------------
-------------------------------------------------------------------------
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 $1.15 per BOE for the year.
MANAGEMENT FEES EXPENSE
Three months ended Nine months ended
-------------------------------------------------------------------------
Sep 30, Jun 30, Sep 30, Sep 30, Sep 30,
2003 2003 2002 2003 2002
-------------------------------------------------------------------------
Cash management fees
($ millions) $- $- $1.3 $- $4.0
$/ BOE $- $- $0.47 $- $0.48
Non-cash management fees
($ millions) $- $- $0.4 $- $1.4
$/ BOE $- $- $0.16 $- $0.17
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-------------------------------------------------------------------------
On November 4, 2002, unitholders approved the internalization of management
effective October 1, 2002. Accordingly, there are no cash or non- cash
management fees after that date.
NON-CASH G&A EXPENSES
Three months ended Nine months ended
-------------------------------------------------------------------------
Sep 30, Jun 30, Sep 30, Sep 30, Sep 30,
2003 2003 2002 2003 2002
-------------------------------------------------------------------------
Non-cash G&A expenses
($ millions) $2.3 $3.2 $(0.9) $5.9 $6.0
$/ BOE $0.76 $1.05 $(0.34) $0.64 $0.73
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Non-cash G&A expenses consist mainly of Unit Appreciation Rights. UARs are
similar to stock options in a conventional business. The UARs are
marked-to-market each quarter and the impact is recognized as an expense or
recovery in the income statement of the Trust.
INTEREST EXPENSE
($ millions) Three months ended Nine months ended
-------------------------------------------------------------------------
Sep 30, Jun 30, Sep 30, Sep 30, Sep 30,
2003 2003 2002 2003 2002
-------------------------------------------------------------------------
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 $U.S. 125 million
private placement debt financing of secured notes at a coupon rate of 4.19% with
a seven year term.
DEPLETION, DEPRECIATION AND AMORTIZATION (DD&A)
Three months ended Nine months ended
-------------------------------------------------------------------------
Sep 30, Jun 30, Sep 30, Sep 30, Sep 30,
2003 2003 2002 2003 2002
-------------------------------------------------------------------------
Depletion, depreciation &
amortization ($ millions) $50.7 $49.9 $46.0 $153.3 $137.1
$/ BOE $16.91 $16.13 $16.56 $16.66 $16.49
-------------------------------------------------------------------------
-------------------------------------------------------------------------
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
-------------------------------------------------------------------------
Sep 30, Jun 30, Sep 30, Sep 30, Sep 30,
2003 2003 2002 2003 2002
-------------------------------------------------------------------------
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)
-------------------------------------------------------------------------
$(7.9) $(50.5) $(11.5) $67.6 $(20.5)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
On June 9, 2003, the Canadian Government substantially enacted Federal income
tax changes for the oil and gas resource sector as outlined in its 2003 Budget.
The Federal income tax changes effectively reduced the statutory tax rates for
current and future periods, resulting in a significant increase in the future
tax recovery (a non-cash item) compared to the first quarter and prior years.
Specifically, the current 100% deductibility of the resource allowance will be
completely phased out by the year 2007. During the same time frame, Crown
charges will become 100% deductible and resource tax rates will decline from the
current 27% to 21%.
NET INCOME (LOSS)
($ millions) Three months ended Nine months ended
-------------------------------------------------------------------------
Sep 30, Jun 30, Sep 30, Sep 30, Sep 30,
2003 2003 2002 2003 2002
-------------------------------------------------------------------------
Net income (loss) $7.3 $61.7 $8.2 $91.0 $8.0
-------------------------------------------------------------------------
-------------------------------------------------------------------------
During the second quarter of 2003 substantial income tax recoveries and foreign
exchange gains contributed to net income. In addition to these items, third
quarter net income is lower than the previous quarter due to lower production
levels and commodity prices.
LIQUIDITY AND CAPITAL RESOURCES
($ millions) As at
-------------------------------------------------------------------------
Sep 30, 2003 Jun 30, 2003 Sep 30, 2002
-------------------------------------------------------------------------
Long-term debt $247.7 $298.4 $255.0
Working capital deficit/(surplus) (14.3) (12.0) 15.9
-------------------------------------------------------------------------
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
-------------------------------------------------------------------------
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
-------------------------------------------------------------------------
Sep 30, Jun 30, Sep 30, Sep 30, Sep 30,
2003 2003 2002 2003 2002
-------------------------------------------------------------------------
Expenditures on property,
plant and equipment $31.4 $18.8 $12.0 $75.6 $49.2
-------------------------------------------------------------------------
-------------------------------------------------------------------------
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%
-------------------------------------------------------------------------
-------------------------------------------------------------------------
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.$/bbl)
-------------------------------------------------------------------------
Oct - Dec 2003 1,000 3 Way 17.00/20.50/25.50
Oct - Dec 2003 1,000 3 Way 18.50/22.50/27.20
Oct - Dec 2003 500 Swap 27.49
Oct - Dec 2003 500 Swap 29.07
Oct - Dec 2003 500 Swap 30.51
Oct - Dec 2003 500 Costless Collar 24.00/30.00
Oct - Dec 2003 500 Costless Collar 26.00/32.45
Jan - Mar 2004 1000 Swap 27.29
Jan - Mar 2004 500 Swap 28.87
Jan - Mar 2004 500 Costless Collar 22.00/26.70
Jan - Mar 2004 500 Costless Collar 23.00/33.30
Jan - Mar 2004 500 Costless Collar 24.00/31.20
Jan - Mar 2004 500 Costless Collar 25.00/28.16
Apr - Apr 2004 500 Swap 27.02
Apr - Jun 2004 500 Swap 27.21
Apr - Jun 2004 500 Costless Collar 22.00/26.12
Apr - Jun 2004 500 Costless Collar 24.00/30.50
Apr - Jun 2004 500 Costless Collar 25.00/28.07
Jul - Jul 2004 500 Swap 27.12
Jul - Aug 2004 500 Swap 26.08
-------------------------------------------------------------------------
Natural Gas (Cdn$/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.