PrimeWest Energy Trust announces second quarter 2004 results and
increased distribution level for September 2004 CALGARY, Aug. 3
/PRNewswire-FirstCall/ -- (TSX: PWI.UN, PWX; NYSE: PWI) - PrimeWest
Energy Trust (PrimeWest or the Trust) today announced interim
operating and financial results for the second quarter ended June
30, 2004, and such information is provided as of August 3, 2004.
Unless otherwise noted, all figures contained in this report are in
Canadian dollars. Second Quarter Highlights: - Second quarter
production averaged 31,185 barrels of oil equivalent (BOE) per day,
compared to the first quarter 2004 rate of 31,202 BOE/day(1). -
Distributions of $0.75 per unit represent a payout ratio of
approximately 72%, compared to first quarter 2004 distributions of
$0.82 per unit, representing a payout ratio of 70%. - Cash flow
from operations of $58.2 million ($1.05 per unit) compared to $58.5
million ($1.15 per unit) in the first quarter of 2004, primarily
due to a continued strong commodity price environment and sustained
volumes. - At PrimeWest's Annual Meeting of unitholders held May
6th, unitholders voted 98% in favor of an amendment to the
Declaration of Trust, which eliminates residency restriction
provisions. PrimeWest now has until January 1st, 2007 to develop
alternatives to the proposed non-residency requirement of the
Canadian federal government budget. PrimeWest believes that a key
element of its long-term strategy is continued access to the North
American capital markets. - On June 8th the Alberta Energy and
Utilities Board (AEUB) definitively issued rulings regarding the
natural gas over bitumen issue in the Wabiskaw-McMurray area of
Northeast Alberta. Effective July 1st approximately 330 BOE per day
of natural gas production from PrimeWest's Ells field has been
shut-in to comply with this order. PrimeWest expects to receive
compensation from the Province of Alberta for this shut-in volume.
- During the quarter, PrimeWest concluded a bought deal financing
of 5.4 million units at $26.30 per unit, raising gross proceeds
totaling approximately $142 million, and net proceeds after
commissions of $134.9 million. The funds were used to reduce debt,
including the debt incurred with respect to the $46 million
acquisition cost of Seventh Energy, and funding of the 2004 capital
program. Debt to annualized second quarter 2004 cash flow is 0.7
times. Net debt at June 30, 2004, is $2.97 per unit, down $3.02 per
unit from March 31, 2004 level of $5.99. Subsequent Events - The
distribution payable September 15th, 2004 will increase by 10% to
$0.275 Canadian per trust unit payable to all unitholders of record
on August 23rd, 2004, with an ex-distribution date of August 19th,
2004. Continued strength in oil and gas prices, higher production,
a strong balance sheet, and the expiry of a portion of the
out-of-the-money hedges all contributed to this distribution
increase. - Following the end of the second quarter, PrimeWest
entered into two asset acquisitions, one of which closed on July
12th, 2004 and the other is scheduled to close August 5, 2004. On a
net running rate basis PrimeWest will have acquired approximately
700 BOE/D for a total cash consideration of $28.1 million. After
the application of enhanced recovery methods, production is
expected to increase by approximately 300 BOE per day. - These
transactions will increase PrimeWest's working interest in both the
Lone Pine Creek and Princess areas. PrimeWest has also entered into
agreements to divest of approximately 290 BOE/D of low margin
non-core production for proceeds of approximately $5.8 M.
Management's Discussion and Analysis The following is management's
discussion and analysis (MD&A) of PrimeWest's operating and
financial results for the quarter ended June 30, 2004 compared with
the preceding quarter and the corresponding period in the prior
year as well as information and opinions concerning the Trust's
future outlook based on currently available information. This
discussion should be read in conjunction with the Trust's audited
consolidated financial statements for the years ended December 31,
2003 and 2002, together with accompanying notes, as contained in
the Trust's 2003 Annual Report. Financial and Operating Highlights
- Second Quarter Financial Highlights Three Months Ended Six Months
Ended ------------------------------------------------- (millions
of dollars, except per BOE and June 30, Mar 31, June 30, June 30,
June 30, per Trust Unit amounts) 2004 2004 2003 2004 2003
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Net revenue 84.9 85.7 85.6 170.6 179.7 per BOE(1) 29.91 30.20 27.67
30.05 28.96 Cash flow from operations 58.2 58.5 57.2 116.7 122.0
per BOE 20.52 20.59 18.45 20.56 19.67 per Trust Unit(2) 1.05 1.15
1.24 2.20 2.75 Royalty expense 25.7 23.3 25.0 49.0 57.7 per BOE
9.06 8.22 8.08 8.64 9.30 Operating expenses 19.6 19.7 20.3 39.2
41.0 per BOE 6.89 6.92 6.57 6.91 6.60 G&A expenses - Cash 3.5
4.2 3.2 7.7 7.0 per BOE 1.23 1.49 1.04 1.36 1.13 G&A expenses -
Non-cash (7.3) 0.4 3.2 (6.8) 3.6 per BOE (2.57) 0.15 1.05 (1.21)
0.59 Interest expense 2.8 3.2 3.4 6.0 7.0 per BOE 1.00 1.11 1.11
1.06 1.13 Distributions to unitholders 42.0 41.1 52.8 83.1 102.6
per Trust Unit(3) 0.75 0.82 1.20 1.57 2.40 Net debt(4) 169.2 305.7
286.4 169.2 286.4 per Trust Unit(5) 2.97 5.99 6.17 2.97 6.17
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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. BOE's may be misleading,
particularly if used in isolation. The BOE conversion ratio is
based on an energy equivalency conversion method primarily
applicable at the burner tip and does not represent a value
equivalency at the wellhead. (2) Weighted average Trust Units &
Exchangeable Shares (diluted). (3) Based on Trust Units outstanding
at date of distribution. (4) Net debt is long-term debt adjusted
for working capital excluding financial derivative liabilities. (5)
Trust Units and Exchangeable Shares outstanding (diluted) at end of
period. Operating Highlights Three Months Ended Six Months Ended
-------------------------------------------------- June 30, Mar 31,
June 30, June 30, June 30, 2004 2004 2003 2004 2003
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Daily Sales Volumes Natural gas (mmcf/day) 125.5 123.9 137.9 124.7
139.1 Crude oil (bbls/day) 7,699 7,864 8,222 7,782 8,182 Natural
gas liquids (bbls/day) 2,569 2,696 2,800 2,632 2,914
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Total (BOE/day) 31,185 31,202 34,004 31,193 34,277
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Realized Commodity Prices(1) (Cdn $) Natural gas ($/Mcf) 6.59 6.57
6.10 6.58 6.51 Without hedging 6.82 6.62 6.69 6.72 7.26 Crude oil
($/bbl) 35.83 34.93 33.60 35.38 35.94 Without hedging 43.20 39.44
34.82 41.30 39.19 Natural gas liquids ($/bbl) 41.22 38.54 32.71
39.85 36.88
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Total ($ per BOE) 38.77 38.21 35.54 38.49 38.13 Without hedging
41.51 39.56 38.23 40.54 41.97
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(1) Includes hedging gains (losses) Forward Looking Information
This MD&A contains forward-looking or outlook information with
respect to PrimeWest. The use of any of the words "anticipate,
"continue, "estimate", "expect", "may", "will", "project",
"should", "believe", "outlook" and similar expressions are intended
to identify forward-looking statements. These statements involve
known and unknown risks, uncertainties and other factors that may
cause actual results or events to differ materially from those
anticipated in our forward-looking statements. We believe the
expectations reflected in those forward-looking statements are
reasonable. However, we cannot assure you that these expectations
will prove to be correct. You should not unduly rely on
forward-looking statements included in this report. These
statements are made as of the date of this MD&A. In particular,
this MD&A contains forward-looking statements pertaining to the
following: - The quantity and recoverability of our reserves; - The
timing and amount of future production; - Prices for oil, natural
gas, and natural gas liquids produced; - Operating and other costs;
- Business strategies and plans of management; - Supply and demand
for oil and natural gas; - Expectations regarding our ability to
raise capital and to add to our reserves through acquisitions and
exploration and development; - Our treatment under governmental
regulatory regimes; - The focus of capital expenditures on
development activity rather than exploration; - The sale, farming
in, farming out or development of certain exploration properties
using third party resources; - The objective to achieve a
predictable level of monthly cash distributions; - The use of
development activity and acquisitions to replace and add to
reserves; - The impact of changes in oil and natural gas prices on
cash flow after hedging; - Drilling plans; - The existence,
operation and strategy of the commodity price risk management
program; - The approximate and maximum amount of forward sales and
hedging to be employed; - The Trust's acquisition strategy, the
criteria to be considered in connection therewith and the benefits
to be derived therefrom; - The impact of the Canadian federal and
provincial governmental regulation on the Trust relative to other
oil and gas issuers of similar size; - The goal to sustain or grow
production and reserves through prudent management and
acquisitions; - The emergence of accretive growth opportunities,
and - The Trust's ability to benefit from the combination of growth
opportunities and the ability to grow through the capital markets.
Our actual results could differ materially from those anticipated
in these forward-looking statements as a result of the risk factors
set forth below and elsewhere in this MD&A: - Volatility in
market prices for oil, natural gas and natural gas liquids; - Risks
inherent in our oil and gas operations; - Uncertainties associated
with estimating reserves; - Competition for, among other things;
capital, acquisitions of reserves, undeveloped lands and skilled
personnel; - Incorrect assessments of the value of acquisitions; -
Geological, technical, drilling and processing problems; - General
economic conditions in Canada, the United States and globally; -
Industry conditions, including fluctuations in the price of oil,
natural gas and natural gas liquids; - Royalties payable in respect
of PrimeWest's oil and gas production; - Governmental regulation of
the oil and gas industry, including environmental regulation; -
Fluctuation in foreign exchange or interest rates; - Unanticipated
operating events that can reduce production or cause production to
be shut-in or delayed; - Failure to obtain industry partner and
other third party consents and approvals, when required; - Stock
market volatility and market valuations; - The need to obtain
required approvals from regulatory authorities, and - The other
factors discussed under "Operational and Other Business Risks" in
this MD&A. These factors should not be construed as exhaustive.
Evaluation of Disclosure Controls and Procedures The Chief
Executive Officer, Don Garner, and Chief Financial Officer, Dennis
Feuchuk, evaluated the effectiveness of PrimeWest Energy's
disclosure controls and procedures as of June 30, 2004 and
concluded that PrimeWest Energy's disclosure controls and
procedures were effective to ensure that information PrimeWest is
required to disclose in its filings with the Securities and
Exchange Commission (SEC) under the Securities Exchange Act of 1934
(Exchange Act) is recorded, processed, summarized and reported,
within the time periods specified in the (SEC's) rules and forms,
and to ensure that information required to be disclosed by
PrimeWest in the reports that it files under the Exchange Act is
accumulated and communicated to PrimeWest's management, including
its principal executive officer and principal financial officer, as
appropriate to allow timely decisions regarding required
disclosure. Changes to Internal Controls and Procedures for
Financial Reporting There were no significant changes to
PrimeWest's internal controls or in other factors that could
significantly affect these controls subsequent to the evaluation
date. Vision, Core Business and Strategy PrimeWest Energy Trust is
a conventional oil and gas royalty trust actively managed to
generate monthly cash distributions for unitholders. The Trust's
operations are focused in Canada, with its assets concentrated in
the Western Canadian Sedimentary Basin. PrimeWest is one of North
America's largest natural gas weighted energy trusts. Maximizing
total return to unitholders, in the form of cash distributions and
change in unit price, is PrimeWest's overriding objective. Our
strategies for asset management and growth, financial management
and corporate governance are outlined in this MD&A, along with
a discussion of our performance in the second quarter of 2004 and
our goals for the remainder of 2004 and beyond. We believe that
PrimeWest can maximize total return to unitholders through the
continued development of our core properties, making opportunistic
acquisitions that emphasize value creation, exercising disciplined
financial management which broadens access to capital while
minimizing risk to unitholders, and complying with strong corporate
governance to protect the interests of all stakeholders. Asset
Management and Growth PrimeWest has a strategy to focus our
expansion efforts on existing Canadian core areas, and pursue field
optimization within those core areas to maximize asset value. We
strive to control our operations whenever possible, and maintain
high working interests. Maintaining control of 80% of operations
allows us to use existing infrastructure and synergies within our
core areas. We believe this high level of operatorship can
translate into control over costs and timing of capital outlays and
projects. We will continue to be an opportunistic acquirer who uses
the business cycles to make accretive acquisitions. The current
size of the Trust gives us the ability and critical mass to make
acquisitions of significant size, while still being able to add
value by transacting smaller acquisitions. During the second
quarter of 2004, assets acquired from Seventh Energy Ltd. (Seventh)
contributed 1,315 BOE per day to production volumes. PrimeWest
plans to spend approximately $7 million in 2004 to develop the
Seventh assets, and expects this acquisition to be accretive to its
unitholders on both a cash flow and net asset value per unit basis.
Financial Management PrimeWest strives to maintain a conservative
debt position, to allow us to take advantage of opportunities that
arise in the acquisition market, as well as fund development
activities. Our diversified debt instruments help to reduce our
reliance on the bank syndicate, as well as afford additional
foreign exchange protection because a portion of our debt, the
secured notes, is denominated in U.S. dollars. PrimeWest's
commodity hedging approach helps to stabilize cash flow, reduce
volatility, and protect transaction economics. PrimeWest continues
to target a payout ratio between 70% and 90% of annual cash flow to
increase the Trust's financial flexibility. The second quarter 2004
payout ratio was approximately 72%, and the retained cash flow was
utilized primarily for debt repayment, and towards the Trust's
capital spending program. PrimeWest's success in executing
conservative financial management is demonstrated by our debt to
cash flow level of 0.7 times for the second quarter, significantly
less than our internal limit of 2.0 times and less than our level
of 1.25 times for the same period the previous year. PrimeWest's
dual listing on both the Toronto Stock Exchange (TSX) and New York
Stock Exchange (NYSE) provide increased liquidity and a broadened
investor base. The NYSE listing enables U.S. unitholders to
conveniently trade in our Trust Units, and allows us to access the
U.S. capital markets in the future, and our status as a corporation
for U.S. tax purposes simplifies tax reporting for our U.S.
unitholders. For eligible Canadian unitholders, PrimeWest offers
participation in the Distribution Reinvestment Plan (DRIP), Premium
Distribution Plan (PREP), and Optional Trust Unit Purchase Plan
(OTUPP), which represent a convenient way to maximize an investment
in PrimeWest. For alternate investment styles, PrimeWest also has
Exchangeable Shares available, which permit participation in
PrimeWest without the ongoing tax implications associated with
receiving a distribution. Corporate Governance PrimeWest remains
committed to the highest standards of corporate governance and
upholds the rules of the governing regulatory bodies under which it
operates. Full disclosure of our compliance with existing corporate
governance rules and regulations is available on our website at
http://www.primewestenergy.com/. PrimeWest actively monitors the
corporate governance and disclosure environment to ensure
compliance with current and future requirements. Our high standards
of corporate governance are not limited to the boardroom. At the
field level, PrimeWest proactively manages environmental, health
and safety issues. We place a great deal of importance on community
involvement and maintaining good relationships with landowners.
Outlook - 2004 PrimeWest expects 2004 production volumes to average
approximately 30,500 BOE/day. Full year operating costs are
expected to be approximately $6.75/BOE. PrimeWest expects to invest
approximately $90 million in its capital development program, with
the focus primarily in the core areas of Caroline, Valhalla,
Brant/Farrow and Princess/Hays. For unitholders resident in Canada,
PrimeWest anticipates that approximately 60% of 2004 distributions
will be taxable and 40% will be deemed return of capital. The
taxability of 2004 distributions for U.S. unitholders cannot be
accurately estimated at this time, but will be confirmed after year
end. For residents of the U.S., Canadian withholding tax of 15%
applies to the distribution. In addition, the Canadian Federal
Government announced a proposal on March 23, 2004 which would
expand Canadian withholding tax on non- Canadian residents (15% for
U.S. unitholders) by applying it to both the "taxable income"
portion, as well as the return of capital portion of the
distributions effective January 1, 2005. A withholding tax of 15%
has always been applied to the total value of distributions paid to
U.S. unitholders. For more details on withholding tax, please visit
our website at http://www.primewestenergy.com/. Cash Flow
Reconciliation ($ millions)
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First quarter 2004 cash flow from operations $ 58.5 Commodity
prices 5.5 Net hedging change from prior quarter (3.9) Operating
expenses 0.1 Royalties (2.4) Other 0.4
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Second quarter 2004 cash flow from operations $ 58.2
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The above table includes non-GAAP measurements which may not be
comparable to other companies. The basis of PrimeWest's business
and a key performance driver for the Trust is cash flow from
operations. Cash flow is generated through the production and sale
of crude oil, natural gas and natural gas liquids, and is dependent
on production levels, commodity prices, operating expenses, hedging
gains or losses, royalties and currency exchange rates. Cash flow
from operations can be impacted by macro factors such as commodity
prices, the currency exchange rate, royalties and the forward
markets for oil and gas. Cash flow can also be impacted by factors
specific to PrimeWest such as production levels, hedging gains or
losses, and operating expenses, as well as interest and general and
administrative (G&A) expenses. It is expected that these
factors will impact cash flows in the future. Quarterly Performance
($ millions, except per 2004 2003 2002 Trust Unit
-------------------------------------------------------- amounts)
Q2 Q1 Q4 Q3 Q2 Q1 Q4 Q3
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Net Revenues 84.9 85.7 73.0 77.3 85.6 94.0 68.8 63.8 Net Income
22.4 20.1 (0.7) 7.4 61.4 22.4 (7.3) 8.2 Net Income Per Unit - Basic
0.41 0.40 (0.01) 0.16 1.34 0.53 (0.20) 0.24 Net Income Per Unit -
Diluted 0.40 0.40 (0.01) 0.16 1.33 0.53 (0.20) 0.24
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The above table highlights PrimeWest's performance for the second
quarter ended 2004, and the preceding seven quarters through 2003
and 2002. Net revenues are primarily impacted by commodity prices,
production volumes and royalties. As a result of higher royalty
expenses, the second quarter 2004 net revenues were slightly lower
compared to the first quarter of 2004. Net income and net income
per unit are secondary measures for a royalty trust because net
income includes both cash and non-cash items. The non-cash items
such as depletion, depreciation and amortization (DD&A), future
income taxes, foreign exchange, and unrealized gain or loss on
derivatives can cause the net income to vary significantly. Capital
Expenditures Three Months Ended Six Months Ended
-------------------------------------------------- ($ millions,
June 30, Mar 31, June 30, June 30, June 30, except per BOE) 2004
2004 2003 2004 2003
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Land & lease acquisitions $ 2.7 $ 1.8 $ 1.1 $ 4.5 $ 2.3
Geological and geophysical 0.8 1.7 0.4 2.5 1.0 Drilling and
completions 9.0 18.8 7.6 27.8 22.6 Investment in facilities
Equipping & tie-in 2.8 4.0 3.7 6.8 6.7 Compression &
processing 0.5 2.0 1.0 2.5 2.7 Gas gathering 0.2 0.5 1.7 0.7 4.0
Production facilities 5.1 2.1 2.0 7.2 2.8 Capitalized G&A 0.6
0.4 0.3 1.0 0.5
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Development capital 21.7 31.3 17.8 53.0 42.6
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Corporate/property acquisitions 0.4 38.6 7.3 39.0 205.7
Dispositions (1.6) (3.5) 0.0 (5.1) (0.2) Head office equipment 0.5
0.2 0.1 0.6 0.1
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Total $ 21.0 $ 66.6 $ 25.2 $ 87.5 $ 248.2
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During the second quarter of 2004, PrimeWest's capital expenditures
totaled $21.0 million, compared to $25.2 million invested in the
same quarter the previous year. Development capital of $21.7
million invested in the second quarter 2004 was higher than the
second quarter 2003 investment of $17.8 million. Of the $21.7
million in development capital, $9.0 million or 41.5% was spent on
drilling and completions, which contribute to new reserve additions
and help offset natural production decline. Of the $8.6 million
investments made in facilities, $2.8 million or 32.6% represents
equipping and volume tie-ins, with the remainder invested in other
activities that contribute to future production volumes. In the
second quarter, PrimeWest's capital spending was focused primarily
in the areas of Caroline, Brant Farrow, and Valhalla. Gross wells
drilled in the second quarter totaled 16 (11.8 net wells), with a
success rate of approximately 88%. Year to date 47 gross wells
(30.8 net wells) have been drilled with a success rate of
approximately 89%. Compared to the first quarter of 2004,
development capital spending of $21.7 million in the second quarter
of 2004 was lower due to location access as a result of Spring
break-up and wet weather. Higher level of drilling activity and gas
plant modifications at Valhalla in the first half of 2004 resulted
in 2004 development expenses being approximately $10.4 million
higher than the same period of 2003, which were $42.6 million.
Corporate acquisitions in 2003 included the purchase of two private
Canadian companies. In 2004 PrimeWest completed the corporate
acquisition of Seventh Energy. Through acquisitions as well as
development drilling, workovers, and recompletion activities,
PrimeWest strives to offset the natural production decline, and add
to reserves in an effort to sustain cash flows. Capital is
allocated on the basis of anticipated rate of return on projects
undertaken. At PrimeWest, every capital project is measured against
stringent economic evaluation criteria prior to approval that
include expected return, risks and further development
opportunities. Assets Since inception, PrimeWest has focused on the
conventional oil and natural gas plays of the Western Canadian
Sedimentary Basin. Within this focused area, we have a diversified,
multi-zone suite of assets stretching from northeast B.C., across
much of Alberta and down through southwest Saskatchewan. We believe
this diversity reduces risks to overall corporate production and
cash flow, while the core area focus allows us to capitalize on our
existing technical knowledge in each of the core areas. PrimeWest
currently has 15 primary assets, with no single asset producing
greater than 20% of PrimeWest's total volumes. As a result of the
Seventh Energy acquisition, PrimeWest's 2004 capital spending
program includes investment in the expanded Princess/Hays region of
southeast Alberta. This is an example of the Trust's strategy to
expand on existing areas or build new core areas within which we
retain control of operations. Production Volumes Three Months Ended
Six Months Ended --------------------------------------------------
June 30, Mar 31, June 30, June 30, June 30, 2004 2004 2003 2004
2003
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Natural gas (mmcf/day) 125.5 123.9 137.9 124.7 139.1 Crude oil
(bbls/day) 7,699 7,864 8,222 7,782 8,182 Natural gas liquids
(bbls/day) 2,569 2,696 2,800 2,632 2,914
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Total (BOE/day) 31,185 31,202 34,004 31,193 34,277
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Gross Overriding Royalty volumes included above (BOE/day) 1,355
1,397 1,754 1,355 1,727
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All production information is reported before the deduction of
crown and freehold royalties. PrimeWest's production volumes in the
second quarter remained relatively flat when compared with the
first quarter of 2004 due to additional volumes contributed by the
Seventh Energy assets and volumes resulting from development
activity offsetting natural production decline. Compared to the
first six months of 2003, production in the first half of 2004 was
9% lower, primarily attributable to production decline. In the
second quarter of 2004, the Alberta Energy and Utilities Board
ruled on the natural gas over bitumen issue, which resulted in
approximately 330 BOE/day of production at Ells being permanently
shut-in effective July 1, 2004. The impact of this shut-in has
already been factored into PrimeWest's 2004 full year production
guidance. With the operator, PrimeWest intends to seek compensation
for the shut-in production from the Province of Alberta. Production
at PrimeWest's non-operated Whiskey Creek area is expected to
remain restricted for the remainder of 2004 due to third party
facility capacity constraints. PrimeWest expects full year 2004
production to average approximately 30,500 BOE/day. This estimate
incorporates PrimeWest's expected natural decline rate, the
production volume shut-ins described above, offset by production
additions due to the capital development program, the acquired
production from Seventh Energy and recent acquisitions through
swaps. Commodity Prices Three Months Ended Six Months Ended
-------------------------------------------------- June 30, Mar 31,
June 30, June 30, June 30, Benchmark Prices 2004 2004 2003 2004
2003
-------------------------------------------------------------------------
Natural gas ($/mcf AECO) 6.80 6.61 7.00 6.71 7.46 Crude oil
(U.S.$/bbl WTI) 38.32 35.15 28.91 36.74 31.39
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Average realized prices in the marketplace are indicated by these
benchmark prices. Average Realized Sales Prices Three Months Ended
Six Months Ended --------------------------------------------------
June 30, Mar 31, June 30, June 30, June 30, (Canadian Dollars) 2004
2004 2003 2004 2003
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Natural gas ($/mcf)(1)(2) 6.59 6.57 6.10 6.58 6.51 Without hedging
6.82 6.62 6.69 6.72 7.26 Crude oil ($/bbl)(1) 35.83 34.93 33.60
35.38 35.94 Without hedging 43.20 39.44 34.82 41.30 39.19 Natural
gas liquids ($/bbl) 41.22 38.54 32.71 39.85 36.88
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Total Oil Equivalent(2) ($/BOE) 38.77 38.21 35.54 38.49 38.13
Without hedging 41.51 39.56 38.23 40.54 41.97
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Realized hedging gain (loss) included in prices above ($/BOE)
(2.74) (1.35) (2.69) (2.05) (3.84)
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(1) Includes hedging gains/losses. (2) Excludes sulphur. Canadian
commodity prices were higher in the second quarter 2004 than during
the same period in 2003 resulting in higher average realized
selling prices per BOE. The realized selling price in Canadian
dollars is impacted by currency exchange rates. Oil and gas prices
are denominated in U.S. dollars, therefore, a strengthened Canadian
dollar translates into lower realized prices and lower Canadian
revenue for producers. Compared to the first quarter 2004, average
realized sales prices per BOE increased marginally in the second
quarter 2004 due to higher average prices for crude oil, natural
gas and liquids. In the first half of 2004, PrimeWest has realized
higher average prices for its product relative to prices realized
in the first six months of 2003. PrimeWest's cash flow from
operations is directly impacted by commodity prices, but the use of
hedging can increase or decrease the prices realized by the Trust.
In the second quarter of 2004, PrimeWest had a $7.8 million hedging
loss compared to a loss of $8.3 million for the same period in
2003. The following table sets forth benchmark historical and
estimated future commodity prices. Benchmark Past Four Quarters
Next Four Quarters Commodity Prices (Actual) (Forward Markets)(1)
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Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 2003 2003 2004 2004 2004 2004 2005 2005
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Natural gas NYMEX ($U.S./Mcf) 5.10 4.58 5.69 5.97 6.17 6.45 6.73
5.88 AECO ($Cdn/Mcf) 6.29 5.59 6.61 6.80 6.75 7.39 7.88 6.76 Crude
oil WTI ($U.S./bbl) 30.20 31.18 35.15 38.32 37.04 36.55 35.81 35.18
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(1) As at June 30, 2004 Sales Revenue Three Months Ended Six Months
Ended
--------------------------------------------------------------
Revenue June 30, % of Mar 31, % of June 30, % of June 30, June 30,
($ millions) 2004 total 2004 total 2003 total 2004 2003
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Natural gas(1) $ 75.3 68% $ 74.0 68% $ 76.5 70% $149.3 $163.9 Crude
oil 25.1 23% 25.0 23% 25.1 23% 50.1 53.2 Natural gas liquids 9.6 9%
9.5 9% 8.3 7% 19.1 19.5
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Total $110.0 100% $108.5 100% $109.9 100% $218.5 $236.6
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Hedging (loss)/ gains included above(2) $ (7.8) $ (3.8) $ (8.3)
$(11.6) $(23.8)
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(1) Excludes sulphur. (2) Net of amortized premiums. Second quarter
2004 revenues were marginally higher than the same period in 2003,
due to higher commodity prices offset by lower production volumes.
Revenues are higher in the second quarter 2004 compared to the
first quarter 2004 due to the higher commodity price environment.
Revenues are lower in the first six months of 2004 compared to the
same period in 2003 due to reduced production volumes offset by
higher commodity prices. If the pricing environment softens in
2004, and the Canadian dollar remains strong, oil and gas revenues
will be negatively impacted. Since a greater portion of PrimeWest's
revenues (68%) is derived from natural gas, the Trust has greater
sensitivity to changes in natural gas prices than crude oil prices.
Natural decline is expected to reduce production volumes, some of
which may be offset by development projects and any acquisition
activity. Financial Derivatives As part of our financial management
strategy, PrimeWest uses a consistent commodity hedging approach.
The purpose of the hedging program is to reduce volatility in cash
flows, protect acquisition economics and to stabilize cash flow
against the unpredictable commodity price environment. PrimeWest's
hedging program delivered gains of $26.0 million over the period
from January 1, 2001 to June 30, 2004. Hedging is an important
element in PrimeWest's financial management strategy. It is
designed to reduce commodity price volatility, increase cash flow
stability, and protect the economics of asset acquisitions. The
hedging policy reflects a willingness to forfeit a portion of the
pricing upside in return for protection against a significant
downturn in prices. Approximate percentage of future anticipated
production volumes hedged at June 30, 2004, net of anticipated
royalties, reflecting full production declines with no offsetting
additions: -------------------------- 2004 Q3 Q4 Q3-Q4
-------------------------------------------------------------------------
Crude Oil 59% 55% 57% Natural Gas 57% 36% 47%
-------------------------------------------------------------------------
-------------------------------------------------------------------------
---------------------------------------------- Full 2005 Q1 Q2 Q3
Q4 Year
-------------------------------------------------------------------------
Crude Oil 41% 34% 18% 9% 26% Natural Gas 25% 0% 0% 0% 6%
-------------------------------------------------------------------------
PrimeWest generally sells its oil and gas under short-term
market-based contracts. Derivative financial instruments, options
and swaps may be used to hedge the impact of oil and gas price
fluctuations. A listing of these contracts in place at June 30,
2004 follows: Crude Oil ($U.S./bbl)
-------------------------------------------------------------------------
Period Volume (bbls/d) Type WTI Price ($U.S./bbl)
-------------------------------------------------------------------------
Jul - Aug 2004 500 Swap 31.55 Jul - Sep 2004 500 Swap 26.07 Jul -
Sep 2004 500 Swap 27.04 Jul - Sep 2004 500 Swap 28.51 Jul - Sep
2004 500 Swap 30.23 Jul - Sep 2004 500 Costless Collar 24.00/30.75
Jul - Sep 2004 500 Costless Collar 25.00/28.30 Jul - Sep 2004 500
Costless Collar 26.00/32.05 Oct - Dec 2004 500 Swap 26.00 Oct - Dec
2004 500 Swap 27.03 Oct - Dec 2004 500 Swap 28.53 Oct - Dec 2004
500 Swap 30.10 Oct - Dec 2004 500 Costless Collar 24.00/30.00 Oct -
Dec 2004 500 Costless Collar 25.00/28.30 Oct - Dec 2004 500
Costless Collar 26.00/32.72 Jan - Mar 2005 500 Swap 27.25 Jan - Mar
2005 500 Swap 28.60 Jan - Mar 2005 500 Swap 30.00 Jan - Mar 2005
500 Costless Collar 28.00/34.35 Jan - Mar 2005 500 3 Way
25.00/30.00/35.50 Apr - Jun 2005 500 Swap 27.07 Apr - Jun 2005 500
Swap 28.50 Apr - Jun 2005 500 Swap 30.00 Apr - June 2005 500 3 Way
25.00/30.00/36.75 Jul - Sep 2005 500 Swap 27.05 Jul - Sep 2005 500
Swap 28.50 Oct - Dec 2005 500 Swap 27.18
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Natural Gas (Cdn$/mcf)
-------------------------------------------------------------------------
Period Volume (mmcf/d) Type AECO Price (Cdn$/bbl)
-------------------------------------------------------------------------
Jan 2004 - Oct 2004 9.5 3 Way 3.17/4.22/6.09 Jan 2004 - Dec 2004
1.0 Swap 6.02 Apr 2004 - Oct 2004 4.7 Swap 5.45 Apr 2004 - Oct 2004
4.7 Swap 6.02 Apr 2004 - Oct 2004 4.7 Swap 6.06 Apr 2004 - Oct 2004
4.7 Costless Collar 5.01/6.06 Apr 2004 - Oct 2004 4.7 Costless
Collar 5.28/7.39 Apr 2004 - Oct 2004 4.7 Swap 6.25 Apr 2004 - Oct
2004 4.7 Swap 6.20 Nov 2004 - Mar 2005 4.7 Costless Collar
5.80/7.91 Nov 2004 - Mar 2005 4.7 Swap 6.71 Nov 2004 - Mar 2005 4.7
Costless Collar 6.33/11.87 Nov 2004 - Mar 2005 4.7 Costless Collar
6.86/11.61
-------------------------------------------------------------------------
-------------------------------------------------------------------------
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
natural gas contract above as an example, PrimeWest has sold a call
at $6.09, purchased a put at $4.22, and resold the put at $3.17.
Should the market price drop below $4.22 PrimeWest will receive
$4.22 until the price is less than $3.17, at which time PrimeWest
would then receive market price plus $1.05. However, should market
prices rise above $6.09, PrimeWest would receive a maximum of
$6.09. Should the market price remain between $4.22 and $6.09,
PrimeWest would receive the market price. Natural Gas Basis
Differential
-------------------------------------------------------------------------
Period Volume (mmcf/day) Type Basis Price ($U.S./mcf)
-------------------------------------------------------------------------
Apr - Oct 2004 5 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 basis
swap above as an example, PrimeWest has fixed this price difference
between the two markets at $U.S. 0.71 per mcf from April 2004
through October 2004. If the NYMEX price for the period turned out
to be $U.S. 5.00 per mcf, PrimeWest would receive an AECO
equivalent price of $U.S. 4.29 per mcf. Electrical Power
-------------------------------------------------------------------------
Period Power Amount (MW) Type Price ($/MW-hr)
-------------------------------------------------------------------------
Q3 2004 5 Fixed Price Swap 46.50 Q4 2004 5 Fixed Price Swap 44.00
Calendar 2004 5 Fixed Price Swap 45.65
-------------------------------------------------------------------------
-------------------------------------------------------------------------
CICA Accounting Guideline 13 (AcG-13), "Hedging Relationships,"
became effective for fiscal years beginning on or after July 1,
2003. AcG-13 addresses the identification, designation,
documentation and effectiveness of hedging transactions for the
purposes of applying hedge accounting. It also establishes
conditions for applying or discontinuing hedge accounting. Under
the new guideline, hedging transactions must be documented and it
must be demonstrated that the hedges are sufficiently effective in
order to continue accrual accounting for positions hedged with
derivatives. PrimeWest is not applying hedge accounting to its
hedging relationships. As of June 30, 2004, PrimeWest had an
outstanding derivative loss of $1.5 million, comprised of $1.0
million loss for crude oil, $0.9 million for natural gas, and a
$0.4 million gain for electrical power. The derivative loss is
shown as a current asset on the balance sheet. The loss will
continue to be amortized to earnings upon settlement of the
corresponding hedges, which are expected to expire by March 2005.
The unrealized loss on derivatives on the income statement results
from the change in the mark-to-market valuation of the derivative
financial instruments during the period. It represents the loss
that would be incurred if the contracts were settled on the period
end date. The unrealized loss on derivatives for the six months
ended June 30, 2004 was $14.1 million. The loss was comprised of a
$10.3 million loss for crude oil, $4.2 million loss for natural
gas, and a $0.4 million gain for electrical power. The $1.8 million
unrealized derivative loss for the three months ended June 30, 2004
was comprised of a $4.0 million loss on crude oil, $1.8 million
gain on natural gas, $0.3 million gain on electrical power and a
$0.1 million gain upon the settlement of the interest rate swaps.
The mark-to-market valuation of the derivatives in place at June
30, 2004 was a $15.6 million loss consisting of an $11.3 million
loss in crude oil, $5.1 million loss in natural gas, and a $0.8
million gain on electrical power. $14.3 million of the derivative
loss is shown as a current liability on the balance sheet as these
derivatives will be settled in the next twelve months. The
remaining liability of $1.3 million is reported as a long term
derivative liability. For the three months ended June 30, 2004, the
cash impact of contracts settling was a $7.5 million loss
consisting of a $5.2 million loss in crude oil, $2.6 million loss
in natural gas, $0.5 million gain on electrical power and a $0.2
million loss in interest rate swaps. For the six months ended June
30, 2004 the cash impact of contracts settling was a $11.9 million
loss comprised of a $8.4 loss in crude oil, $3.2 million loss in
natural gas, a $0.4 million gain on electrical power and a $0.7
million loss in interest rate swaps. Royalties (Net of ARTC)
Royalties are paid by PrimeWest to the owners of mineral rights
with whom PrimeWest holds leases. PrimeWest has mineral leases with
the Crown (Provincial and Federal Governments), freeholders
(individuals or other companies) and other operators. ARTC is the
Alberta Royalty Tax Credit, a tax rebate provided by the Alberta
government to producers that paid eligible Crown royalties in the
year. Three Months Ended Six Months Ended
-------------------------------------------------- ($ millions,
June 30, Mar 31, June 30, June 30, June 30, except per BOE) 2004
2004 2003 2004 2003
-------------------------------------------------------------------------
Royalty expense (net of ARTC) $ 25.7 $ 23.3 $ 25.0 $ 49.0 $ 57.7
Per BOE $ 9.06 $ 8.22 $ 8.08 $ 8.64 $ 9.30
-------------------------------------------------------------------------
Royalties as % of sales revenues With hedge loss 23.4% 21.5% 22.7%
22.4% 24.4% Excluding hedge loss 21.8% 20.8% 21.1% 21.3% 22.1%
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Royalty expense in the second quarter of 2004 is marginally higher
than the same period the previous year. For the first half of 2004,
royalties were $49.0 million, lower than the same period in 2003
due to lower production volumes. Royalty rates are based on
commodity prices so future changes to prices will be accompanied by
changes in royalty expense. Operating Expenses Three Months Ended
Six Months Ended --------------------------------------------------
($ millions, June 30, Mar 31, June 30, June 30, June 30, except per
BOE) 2004 2004 2003 2004 2003
-------------------------------------------------------------------------
Operating expense ($ millions) $ 19.6 $ 19.7 $ 20.3 $ 39.2 $ 41.0
Per BOE $ 6.89 $ 6.92 $ 6.57 $ 6.91 $ 6.60
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Compared to both the second quarter of 2003 and the previous
quarter in 2004, PrimeWest's total operating expenses for the
second quarter 2004 are virtually unchanged. On a per BOE basis,
operating costs are higher in the second quarter in 2004 compared
to the same quarter in the previous year due to lower production
volumes. Operating expenses are slightly lower in the first half of
2004 compared to the first half of 2003, but are higher on a per
BOE basis due to lower volumes. Operating Expenses Outlook
Operating costs for the year are expected to be higher than in
2003, and PrimeWest expects 2004 operating expenses to be
approximately $6.75/BOE. Operating Margin Three Months Ended Six
Months Ended --------------------------------------------------
June 30, Mar 31, June 30, June 30, June 30, ($/BOE) 2004 2004 2003
2004 2003
-------------------------------------------------------------------------
Sales price and other revenue(1) $ 38.96 $ 38.42 $ 35.75 $ 38.69 $
38.26 Royalties 9.06 8.22 8.08 8.64 9.30 Operating expenses 6.89
6.92 6.57 6.91 6.60
-------------------------------------------------------------------------
Operating margin $ 23.01 $ 23.28 $ 21.10 $ 23.14 $ 22.36
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Includes hedging and sulphur Operating margin per BOE increased
9% during the second quarter 2004 compared to the same quarter in
2003. This is primarily due to higher sales prices offset by higher
operating expenses and higher royalties. Operating margin is an
important measure of our business because it gives an indication of
the amount of cash flow PrimeWest realizes per barrel of oil
equivalent that is produced, before head office expenses and
financing charges. Operating margin decreased in the second quarter
compared to the first quarter 2004, primarily as a result of higher
royalty expense. Compared to the first six months of 2003,
operating margin in the first half of 2004 was 3% higher. Based on
PrimeWest's outlook on commodity prices, the Canadian / U.S. dollar
exchange rate, operating expense expectations and hedge positions,
margins are expected to be higher in 2004 than 2003. PrimeWest will
continue to focus on achieving lower than average operating
expenses to maximize margins, which can reduce the volatility of
cash flows through commodity price cycles. General &
Administrative Expense Three Months Ended Six Months Ended
-------------------------------------------------- ($ millions,
June 30, Mar 31, June 30, June 30, June 30, except per BOE) 2004
2004 2003 2004 2003
-------------------------------------------------------------------------
Cash G&A expense ($ millions) $ 3.5 $ 4.2 $ 3.2 $ 7.7 $ 7.0 Per
BOE $ 1.23 $ 1.49 $ 1.04 $ 1.36 $ 1.13 Non-cash G&A expense ($
millions) $ (7.3) $ 0.4 $ 3.2 $ (6.8) $ 3.6 Per BOE $ (2.57) $ 0.15
$ 1.05 $ (1.21) $ 0.59
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Cash G&A expense in the second quarter 2004 decreased 17% on a
gross and per BOE basis from the previous quarter due to lower
salaries, benefits, legal costs and engineering fees. Cash G&A
expense in the second quarter has increased marginally compared to
the second quarter of 2003. Due to lower production volumes in 2004
G&A on a per BOE basis increased 18% for the period compared to
2003. The increase in the year to date gross and per BOE cash
G&A compared to the same period in 2003 is mainly due to
increases in salaries associated with higher technical staff levels
and lower production volumes. PrimeWest's total and per BOE
non-cash G&A expense has decreased significantly in the second
quarter of 2004 and on a year to date basis compared to the prior
quarter and same periods in 2003 due to a lower average Unit
Appreciation Rights (UARs) value under PrimeWest's Long Term
Incentive Plan (LTIP). The large negative non-cash G&A number
reflects the movement in the trading price of PrimeWest units
during the first half of 2004. Non-cash G&A expense consists
mainly of the change in the value of the UARs. UARs in a trust are
similar to stock options in a corporation. Consistent with the
resolution approved by unitholders at the last annual meeting of
unitholders, PrimeWest continues to pay for the exercise of UARs in
Trust Units. The intent of PrimeWest's LTIP is to align employee
and unitholder interests. The program rewards employees based on
total unitholder return, which is comprised of cumulative
distributions on a reinvested basis plus growth in unit price. No
benefit accrues to employees who hold UARs until the unitholders
have first achieved a 5% total annual return from the time of
grant. Expenses related to the LTIP are recorded on a
mark-to-market basis, whereby increases or decreases in the
valuation of the UAR liability are reported quarterly, as a charge
to the income statement. G&A Expense Outlook Cash G&A
expenses in 2004 are expected to be higher than in 2003 and are
expected to be approximately $1.25 per BOE for the year. Interest
Expense Three Months Ended Six Months Ended
-------------------------------------------------- ($ millions,
June 30, Mar 31, June 30, June 30, June 30, except per Trust Unit)
2004 2004 2003 2004 2003
-------------------------------------------------------------------------
Interest expense $ 2.8 $ 3.2 $ 3.4 $ 6.0 $ 7.0 Period end net debt
level $ 169.2 $ 305.7 $ 286.4 $ 169.2 $ 286.4 Debt per Trust Unit $
2.97 $ 5.99 $ 6.17 $ 2.97 $ 6.17
-------------------------------------------------------------------------
Average cost of debt 4.4% 4.4% 4.9% 4.4% 4.8%
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Interest expense, representing interest on bank debt and private
placement debt, decreased in the second quarter 2004 to $2.8
million from $3.4 million in the same quarter 2003, and decreased
from $3.2 million in the previous quarter due to lower average
interest rates and a lower debt balance in 2004 compared to 2003.
For the first six months of 2004, interest expense was $6.0
million, compared to $7.0 million for the same period in 2003. In
May of 2003, PrimeWest closed a private placement debt financing of
$U.S. 125 million at a U.S. fixed coupon rate of 4.19%,
successfully diversifying its debt. The actual Canadian interest
expense will fluctuate with any changes in the Canadian/U.S.
foreign exchange rates. Canadian interest rates are expected to be
lower through 2004 compared to 2003. Foreign Exchange Loss The
foreign exchange loss of $3.2 million for the three months ended
June 30, 2004 and $4.9 million for the six months ended June 30,
2004, results from the translation of the U.S. dollar denominated
secured notes and related interest payable in Canadian dollars.
Depletion, Depreciation and Amortization Three Months Ended Six
Months Ended -------------------------------------------------- ($
millions, June 30, Mar 31, June 30, June 30, June 30, except per
BOE) 2004 2004 2003 2004 2003
-------------------------------------------------------------------------
Depletion, depreciation and amortization $ 41.4 $ 41.7 $ 49.9 $
83.0 $ 102.6
-------------------------------------------------------------------------
$/BOE $ 14.59 $ 14.68 $ 16.13 $ 14.63 $ 16.54
-------------------------------------------------------------------------
-------------------------------------------------------------------------
The second quarter 2004 DD&A rate of $14.59/BOE is lower than
the 2003 second quarter rate of $16.13/BOE due to the January 1,
2004 ceiling test write down of $309 million. Ceiling Test
Effective January 1, 2004, PrimeWest has adopted CICA Accounting
Guideline 16 (AcG-16), "Oil and Gas Accounting - Full Cost". This
new standard replaces the CICA Accounting Guideline 5 (AcG-5),
"Full Cost Accounting in the Oil and Gas Industry". Under AcG-5,
the cost recovery test is calculated based on undiscounted future
net revenues for proved reserves, less general and administrative
expenses, site restoration, future financing costs and applicable
income taxes. The aggregate result is limited to capitalized costs,
less accumulated depletion and site restoration, the lower of cost
and market value of unproved land and future taxes. The cost
recovery test is based on costs and commodity prices existing at
the balance sheet date. AcG-16 impacts the application of the cost
centre impairment test (ceiling test). The guideline is effective
for fiscal years beginning on or after January 1, 2004. The cost
impairment test is now a two stage process which is to be performed
at least annually. The first stage of the test determines if the
cost pool is impaired. An impairment loss exists when the carrying
amount of an asset is not recoverable and exceeds its fair value.
The carrying amount is not recoverable if it exceeds the sum of the
undiscounted cash flows from Proved reserves plus unproved costs
using management's best estimate of future prices. The second stage
determines the amount of the impairment loss to be recorded. The
impairment is measured as the amount by which the carrying amount
of capitalized assets exceeds the future discounted cash flows from
Proved plus Probable reserves. The discount rate used is the risk
free rate. Performing this test at January 1, 2004, using
consultant's average prices as at January 1, 2004 of AECO $5.90 per
mcf for natural gas, $U.S. 29.21 per barrel WTI for crude oil
results in a before tax impairment of $308.9 million, and an after
tax impairment of $233.2 million. The write down was booked to
accumulated income in the first quarter of 2004. Site Reclamation
and Restoration Reserve Since the inception of the Trust, PrimeWest
has maintained a site reclamation fund to pay for future costs
related to well abandonment and site clean-up. The fund is used to
pay for such costs as they are incurred. The 2004 contribution rate
for the fund is unchanged from 2003 at $0.50/BOE, which is expected
to be sufficient to meet expenditure requirements for the future.
The reclamation and abandonment costs in the second quarter of 2004
were $0.3 million, compared to $0.3 million for the same period in
2003, and $0.9 million for the previous quarter. Asset Retirement
Obligation PrimeWest adopted the new CICA Handbook section 3110,
"Asset Retirement Obligations" in the first quarter of 2004. This
standard focuses on the recognition and measurement of liabilities
related to legal obligations associated with the retirement of
property, plant and equipment. Under this standard, these
obligations are initially measured at fair value and subsequently
adjusted for the accretion of discount and any changes in the
underlying cash flows. The asset retirement cost is capitalized to
the related asset and amortized into earnings over time. FIRST AND
FINAL ADD TO FOLLOW DATASOURCE: PrimeWest Energy Trust CONTACT: For
Investor Relations inquiries, please contact: George Kesteven,
Manager, Investor Relations, (403) 699-7367, 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.
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