PrimeWest Energy Trust Announces First Quarter 2005
Results
CALGARY, ALBERTA--(CCNMatthews - May 5, 2005) - PrimeWest Energy Trust
(TSX:PWI.UN) (TSX:PWX) (TSX:PWI.DB.A) (TSX:PWI.DB.B) (NYSE:PWI)
(PrimeWest or the Trust) today announced interim operating and financial
results for the first quarter ended March 31, 2005. Unless otherwise
noted, all figures contained in this report are in Canadian dollars.
FIRST QUARTER HIGHLIGHTS:
- Distributions of $0.90 per unit represented a payout ratio of
approximately 80% of operating cash flow compared to fourth quarter 2004
distributions of $0.90 per unit, representing a payout ratio of 76%.
- First quarter production averaged 40,616 barrels of oil equivalent
(BOE) per day, compared to the fourth quarter 2004 rate of 44,368 BOE
per day. The decrease in volumes is due to fourth quarter 2004 asset
sales, temporary production constraints and natural decline. The
decrease is partially offset by the incremental volumes from capital
development activity.
- For the first quarter of 2005, a $60.0 million investment in
development capital represents the highest quarterly development
activity in PrimeWest's history. Twenty-nine (16.8 net) wells were
drilled with a success rate of 86%.
- Incremental production volumes from development activity averaged
approximately 950 BOE per day for the quarter. As a result of the
capital program, 2,000 BOE per day remains behind pipe at quarter end,
along with another 700 BOE per day that is shut-in due to regulatory and
capacity constraints, resulting in a total of 2,700 BOE per day behind
pipe.
- The Viking Energy Royalty Trust Units (Viking Trust Units), formerly
Calpine Natural Gas Trust Units, were sold in February for net proceeds
of $94.5 million, resulting in a gain of $26.9 million. These proceeds
were used to repay debt and to fund capital expenditures.
- $40.3 million of Series I and Series II Convertible Subordinated
Unsecured Debentures (Debentures) were converted into Trust Units of
PrimeWest Energy Trust (Trust Units).
- Cash flow from operations was $79.7 million ($1.12 per unit) compared
to $81.8 million ($1.15 per unit) in the fourth quarter of 2004.
- March 31, 2005 net debt to annualized first quarter 2005 cash flow was
1.6 times compared to December 31, 2004 net debt to annualized fourth
quarter cash flow of 1.7 times. PrimeWest has $307.7 million available
on its existing borrowing base.
SUBSEQUENT EVENTS
- Subject to regulatory approval, the Board of Directors today approved
offering the distribution reinvestment program (DRIP) to U.S. residents
holding PrimeWest units. This will allow both U.S. residents and
Canadian resident Unitholders the option of either reinvesting their
monthly distributions in units of PrimeWest or continuing to receive
cash payments. Previously only residents of Canada were eligible to
participate in the DRIP. Details regarding the program's implementation
will be released in the next few weeks.
MANAGEMENT'S DISCUSSION AND ANALYSIS AS OF MAY 5, 2005
The following is management's discussion and analysis (MD&A) of
PrimeWest's operating and financial results for the quarter ended March
31, 2005, 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, 2004
and 2003, together with accompanying notes, as contained in the Trust's
2004 Annual Report.
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", "forecast", "may", "will", "project", "should", "believe",
"plan", "outlook" and similar expressions are intended to identify
forward-looking statements. In addition, statements relating to
"reserves" or "resources" are deemed to be forward-looking statements,
as they involve implied assessment, based on certain estimates and
assumptions, that the resources and reserves described can be
profitability produced in the future. 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. Please refer to
PrimeWest's public disclosure documents for more information on these
risks and uncertainties as they apply to PrimeWest.
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 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. The forward-looking
statements contained in this report are expressly qualified by this
cautionary statement. We undertake no obligation to publicly update or
revise any forward-looking statements.
/T/
Financial and Operating Highlights - First Quarter
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Three Months Ended
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($ millions, except per BOE (1) Mar 31, Dec 31, Mar 31,
and per Trust Unit amounts) 2005 2004 2004
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Gross revenue
(net of transportation expense) 153.3 169.3 108.7
per BOE 41.94 41.46 38.28
Cash flow from operations 79.7 81.8 58.5
per BOE 21.79 20.05 20.59
per Trust Unit - basic (2) 1.12 1.15 1.16
per Trust Unit - diluted (3) 1.04 1.07 1.15
Royalty expense 36.0 41.8 23.3
per BOE 9.85 10.24 8.22
Operating expenses 24.4 28.3 19.7
per BOE 6.68 6.94 6.92
General and administrative
G&A expenses - Cash 5.5 7.9 4.2
per BOE 1.51 1.93 1.49
G&A expenses - Non-cash 15.1 2.3 0.4
per BOE 4.12 0.56 0.15
Interest expense (4) 9.1 11.7 3.2
per BOE 2.49 2.86 1.11
Distributions to Unitholders 63.8 62.6 41.1
per Trust Unit (5) 0.90 0.90 0.82
Net debt (6) 516.1 552.0 305.7
per Trust Unit (7) 7.01 7.77 5.99
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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 one 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) The basic per Trust Unit calculation includes the weighted
average Trust Units and Trust Units issuable upon exchange of the
Exchangeable Shares of PrimeWest Energy Inc.
(Exchangeable Shares).
(3) The diluted per Trust Unit calculation includes the weighted
average Trust Units, Trust Units issuable upon exchange of the
Exchangeable Shares, the deemed conversion of the Debentures and
Trust Units issuable pursuant to Long-Term Incentive Plan
(LTIP). Interest expense incurred on the Debentures is added back
to cash flow for the diluted per Trust Unit calculation.
(4) Interest expense includes the interest on the Debentures.
(5) Based on Trust Units outstanding at date of distribution.
(6) Net debt is long-term debt including Debentures less working
capital, excluding financial derivative assets and liabilities.
(7) The net debt per Trust Unit calculation includes outstanding
Trust Units, Trust Units issuable upon exchange of the
outstanding Exchangeable Shares and Trust Units issuable pursuant
to the LTIP at the end of the period.
Operating Highlights
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Three Months Ended
-----------------------------
Mar 31, Dec 31, Mar 31,
2005 2004 2004
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Daily Sales Volumes
Natural gas (mmcf/day) 180.6 187.2 123.9
Crude oil (bbls/day) 6,948 9,108 7,864
Natural gas liquids (bbls/day) 3,563 4,059 2,696
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Total (BOE/day) 40,616 44,368 31,202
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Realized Commodity Prices (Cdn $)
Natural gas ($/mcf) (1) 6.79 7.00 6.57
Without hedging 6.79 6.98 6.62
Crude oil ($/bbl) (1) 42.18 36.45 34.93
Without hedging 50.90 46.03 39.44
Natural gas liquids ($/bbl) 50.82 47.32 38.54
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Total ($ per BOE) (1) 41.88 41.37 38.21
Without hedging 43.35 43.24 39.56
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(1) Includes hedging losses
/T/
Evaluation of Disclosure Controls and Procedures
The Chief Executive Officer, Don Garner, and Chief Financial Officer,
Dennis Feuchuk, evaluated the effectiveness of PrimeWest's disclosure
controls and procedures as of March 31, 2005 and concluded that
PrimeWest'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.
Non-GAAP Measures
The quarterly report contains the following measurements that are not
defined by Canadian Generally Accepted Accounting Principles ("GAAP"):
- Cash flow from operations on a total and per Unit basis;
- Distributions per Trust Unit; and
- Net debt per Trust Unit.
These measurements do not have any standardized meaning prescribed by
GAAP and are, therefore, unlikely to be comparable to similar measures
presented by other entities.
Cash flow from operations is calculated from the Trust's cash flow
statement as cash flow from operating activities before changes in
working capital. Cash flow from operations per Trust Unit on a basic
basis is calculated by dividing cash flow by the weighted average number
of Trust Units and Trust Units issuable upon the exchange of
Exchangeable Shares. Cash flow from operations per Trust Unit on a
diluted basis is calculated using cash flow and adding back the interest
expense on the Debentures, divided by the diluted weighted average
number of Trust Units in the period. The diluted weighted average number
of Trust Units consists of the weighted average Trust Units and Trust
Units issuable upon the exchange of outstanding Exchangeable Shares and
includes the Trust Units issuable pursuant to the conversion of the
Debentures, and Trust Units issuable pursuant to the LTIP. Cash flow
from operations is a key performance indicator of PrimeWest's ability to
generate cash and finance operations and pay monthly distributions.
Distributions per Trust Unit disclose the cash distributions accrued in
the first quarter of 2005 based on the number of Trust Units outstanding
on the date the distributions were declared.
Net debt per Trust Unit is calculated as long-term debt, including
Debentures, less working capital, excluding financial derivative assets
and liabilities, divided by the number of Trust Units and Trust Units
issuable upon the exchange of outstanding Exchangeable Shares and Trust
Units issuable pursuant to the LTIP at March 31, 2005.
Critical Accounting Estimates
See pages 57 to 59 of the 2004 Annual Report for Discussion on Critical
Accounting Estimates.
Vision, Core Business and Strategy
PrimeWest 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 first quarter of 2005 and
our goals for the remainder of 2005 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 depletion optimization strategies 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. 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.
Financial Management
PrimeWest strives to maintain a conservative debt position to allow us
to fund smaller acquisitions without tapping into the capital markets,
and to fund ongoing development activities. Our long-term debt is
comprised of bank credit facilities through a bank syndicate, U.S.
dollar denominated Senior Secured Notes (Secured Notes) and the
Debentures. 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, are
denominated in US dollars. PrimeWest's commodity hedging approach helps
to stabilize cash flow, reduce volatility, and protect acquisition
economics.
PrimeWest continues to target a payout ratio between 70% and 90% of
annual operating cash flow to increase the Trust's financial
flexibility. The first quarter 2005 payout ratio was approximately 80%
of operating cash flow. The retained cash flow was utilized to fund the
Trust's capital spending program and repay debt. PrimeWest's net debt to
cash flow level was 1.6 times at the end of the first quarter using
annualized first quarter cash flows.
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. 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
DRIP, which represents a convenient way to maximize an investment in
PrimeWest. For alternate investment requirements, PrimeWest also has
Exchangeable Shares and Debentures 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 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 - 2005
PrimeWest expects full year 2005 production volumes to average between
40,000 - 41,000 BOE per day. Full year operating costs are expected to
be approximately $6.60 per BOE. PrimeWest expects to invest $170 million
in its capital development program, up from $125 million proposed in the
February 24, 2005 news release, as a result of first quarter drilling
success, increased land and seismic purchases, and to reflect higher
third party costs for development activities.
/T/
Cash Flow Reconciliation
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($ millions)
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Fourth quarter 2004 cash flow from operations $ 81.8
Volumes (19.0)
Commodity prices 1.0
Net hedging change from prior quarter 2.3
Operating expenses 3.9
Royalties 5.8
G&A expenses 2.4
Other 1.5
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First quarter 2005 cash flow from operations $ 79.7
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/T/
The above table includes non-GAAP measurements. (Refer to discussion on
Non-GAAP Measures on Page 5)
A key performance driver for the Trust is cash flow from operations,
which directly affects PrimeWest's ability to pay monthly distributions.
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, interest expense, general
and administrative (G&A), hedging gains or losses, royalties and
currency exchange rates. Some of these factors such as commodity prices,
the currency exchange rate and royalties are uncontrollable from
PrimeWest's perspective. Other factors that are, to a certain extent,
controllable by PrimeWest are production levels and operating expenses,
as well as interest and G&A expenses.
/T/
Quarterly Performance - Selective Measures
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($ millions,
except per Trust 2005 2004 2003
Unit amounts) Q1 Q4 Q3 Q2 Q1 Q4 Q3 Q2
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Net Revenues 109.3 155.7 82.5 83.1 73.4 73.0 77.3 85.6
Net Income 15.3 40.6 20.2 22.4 20.1 0.7 8.8 63.0
Cash Flow 79.7 81.8 68.3 58.2 58.5 43.2 51.8 57.2
Cash Flow Per Unit
- Basic 1.12 1.15 1.12 1.05 1.16 0.87 1.12 1.25
Cash Flow Per Unit
- Diluted 1.04 1.07 1.06 1.05 1.15 0.86 1.11 1.24
Net Income Per Unit
- Basic 0.21 0.57 0.31 0.41 0.40 0.01 0.19 1.38
Net Income Per Unit
- Diluted 0.21 0.56 0.31 0.40 0.40 0.01 0.19 1.37
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/T/
The above table highlights PrimeWest's performance for the first quarter
ended March 31, 2005, and the preceding seven quarters through 2004 and
2003.
Net revenues are primarily impacted by commodity prices, production
volumes and royalties.
Net income and net income per unit are secondary measures for a royalty
trust because they include both cash and non-cash items. The non-cash
items, which include depletion, depreciation and amortization (DD&A),
non-cash G&A, future income taxes, unrealized foreign exchange gains or
losses, and unrealized gains or losses on derivatives will not affect
PrimeWest's ability to pay a monthly distribution.
/T/
Capital Expenditures
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Three Months Ended
-----------------------------
Mar 31, Dec 31, Mar 31,
($ millions) 2005 2004 2004
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Land and lease acquisitions 6.7 1.8 1.8
Geological and geophysical 1.6 2.4 1.7
Drilling and completions 35.4 30.1 18.8
Investment in facilities
Equipping and tie-in 5.8 4.3 4.0
Compression and processing 6.8 0.9 2.0
Gas gathering 0.4 1.9 0.5
Production facilities 2.7 5.0 2.1
Capitalized G&A 0.6 0.4 0.4
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Development capital 60.0 46.8 31.3
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Corporate/property acquisitions 0.5 1.4 38.6
Dispositions (3.3) (88.1) (3.5)
Leasehold improvements, furniture and
equipment 1.1 3.2 0.2
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Net capital expenditures $ 58.3 $ (36.7) $ 66.6
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/T/
During the first quarter of 2005, PrimeWest's net capital expenditures
totalled $58.3 million, compared to $66.6 million invested in the first
quarter of 2004 and ($36.7 million) in the previous quarter. Of the
$60.0 million in development capital, $41.2 million or 69% was invested
on drilling, completions and tie-ins that contribute to new reserve
additions and help offset natural production decline. PrimeWest also
invested $6.7 million on land acquisitions within core areas, acquiring
approximately 30 sections for future development. The increasing costs
for goods and services impacted capital expenditures; however, increases
in commodity prices have offset these additional costs thereby
maintaining project economics.
Gross wells drilled in the first quarter totalled 29 (16.8 net wells),
with a success rate of approximately 86%. Capital development activity
in the first quarter of 2005 was focused on PrimeWest's tight gas play
in the areas of Caroline and Columbia. Twelve of the 29 wells drilled
were in the tight gas play and up to an additional 10 wells are planned
for the area during the remainder of 2005. The development capital
expenditures resulted in incremental volumes averaging 950 BOE per day
for the quarter and 2,000 BOE per day behind pipe at the end of the
quarter.
Through acquisitions as well as development drilling, workovers, and
recompletion activities, PrimeWest strives to offset natural production
decline and add to reserves in order to sustain cash flows. Capital
resources are allocated to projects on the basis of anticipated rate of
return. At PrimeWest, every capital project is measured against
stringent economic evaluation criteria prior to approval. These criteria
include expected return, risks and further development opportunities.
Capital Outlook
PrimeWest has increased its full year capital program from $125 to $170
million due to development opportunities in the first quarter. In
addition, an aggressive land acquisition program along with higher third
party costs for development activities have increased capital
expenditures.
In the first quarter of 2005, $6.7 million was invested in land in core
areas. Thirty sections of land were purchased, increasing PrimeWest's
drilling inventory by 10 to 15 locations. Additional seismic and
development results will be required to delineate the remaining sections.
The following describes the incremental amounts to be invested in the
2005 capital program for each of the core areas.
- In our tight gas play (Caroline/Columbia), an additional 4 to 5 wells
are planned in addition to land and seismic expenditures. In total an
incremental $15.0 million will be invested on this play.
- In Edson, a five-well program is being advanced for an additional
$12.0 million.
- In the Crossfield area our drilling program is being re-focused to
higher working interest locations resulting in an additional $5.0
million of capital investment. These wells require extensive planning
and as such volumes are not forecast until year end.
- In Brant Farrow and on our coal bed methane lands an additional $6.0
million will be expended for increased development and to test the
feasibility of commercial development of coal bed methane on lands
within the Horseshoe Canyon fairway located at Thorsby, Crossfield and
Brant Farrow.
/T/
Production Volumes
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Three Months Ended
-----------------------------
Mar 31, Dec 31, Mar 31,
2005 2004 2004
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Natural gas (mmcf/day) 180.6 187.2 123.9
Crude oil (bbls/day) 6,948 9,108 7,864
Natural gas liquids (bbls/day) 3,563 4,059 2,696
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Total (BOE/day) 40,616 44,368 31,202
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Gross Overriding Royalty volumes
included above (BOE/day) 1,521 1,643 1,397
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All production information is reported before the deduction of crown
and freehold royalties.
/T/
PrimeWest's production volumes averaged 40,616 BOE per day in the first
quarter of 2005 compared to 44,368 BOE per day in the fourth quarter of
2004. Production volumes decreased in the first quarter mainly due to
fourth quarter 2004 asset sales representing a reduction of
approximately 2,200 BOE per day. In addition, a third party pipeline
failure and regulatory restrictions reduced production volumes by 400
BOE per day and 200 BOE per day respectively with the remaining decrease
due to natural decline.
The decrease in production volumes in the first quarter was partially
offset by first quarter drilling, completion and tie-in activity which
added incremental volumes averaging approximately 950 BOE per day for
the quarter.
Approximately 2,700 BOE per day of production volumes remain behind pipe
at the end of the first quarter 2005, which includes 2,000 BOE per day
as a result of first quarter capital activity and 700 BOE per day that
is shut-in due to regulatory and capacity constraints. Included in the
volumes curtailed due to regulatory requirements is 500 BOE per day
relating to the Cecil area.
Production Outlook
PrimeWest expects full year production volumes to average between 40,000
- 41,000 BOE per day.
The shut-in volumes at Whiskey Creek area (400 BOE per day) are the
result of limited capacity at the Quirk Creek gas plant. With no
alternate facilities in the area, PrimeWest's production will remain
behind pipe until processing capacity becomes available at the Quirk
Creek facility which is expected to occur in the fourth quarter of 2005.
The production at Cecil (500 BOE per day) has been curtailed due to
regulatory restrictions and will resume once the lands have been pooled
and a waterflood has been initiated by the operator. PrimeWest is
continuing to work with the operator to resolve the outstanding issues,
with no volumes forecast for the
remainder of 2005.
A third party pipeline failure resulted in the temporary shut-in of
volumes (400 BOE per day) in the Kaybob area. The pipeline has been
repaired, however, a third party plant shutdown in April has further
delayed restoring full production until the end of May 2005.
/T/
Commodity Prices
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Three Months Ended
-----------------------------
Mar 31, Dec 31, Mar 31,
Benchmark Prices 2005 2004 2004
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Natural gas
NYMEX (U.S.$/mcf) 6.32 6.87 5.69
AECO (Cdn$/mcf) 6.69 7.09 6.61
Crude oil WTI (U.S.$/bbl ) 49.85 48.28 35.17
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Average Realized Sales Prices
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Three Months Ended
-----------------------------
Mar 31, Dec 31, Mar 31,
2005 2004 2004
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Natural gas ($/Mcf) (1)(2) 6.79 7.00 6.57
Without hedging 6.79 6.98 6.62
Crude oil ($/bbl)(1) 42.18 36.45 34.93
Without hedging 50.90 46.03 39.44
Natural gas liquids ($/bbl) 50.82 47.32 38.54
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Total Oil Equivalent (1) ($/BOE) 41.88 41.37 38.21
Without hedging 43.35 43.24 39.56
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Realized hedging loss included in
prices above ($/BOE) 1.47 1.87 1.35
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(1) Includes hedging losses.
(2) Excludes sulphur.
/T/
Canadian commodity prices were higher in the first quarter 2005 than
during the same period in 2004 resulting in higher average realized
selling prices per BOE.
Compared to the fourth quarter 2004, average realized sales prices per
BOE increased marginally in the first quarter of 2005 due to higher
crude oil and natural gas liquids prices offset by a lower average price
for natural gas.
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 first quarter 2005, PrimeWest had a $5.4
million hedging loss compared to a loss of $3.8 million for the same
period in 2004.
Benchmark Commodity Prices
The following table sets forth benchmark historical and estimated future
commodity prices.
/T/
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Past Four Quarters Next Four Quarters
(Actual) (Forward Markets)(1)
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Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1
2004 2004 2004 2005 2005 2005 2005 2006
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Natural gas
NYMEX
(US$/mcf) 5.97 5.84 6.87 6.32 7.51 7.88 8.25 8.72
AECO
($Cdn/mcf) 6.80 6.66 7.09 6.69 8.14 8.42 8.87 9.34
Crude oil WTI
(US$/bbl) 38.32 43.88 48.28 49.85 55.91 57.03 56.80 56.07
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(1) As at March 31, 2005
Sales Revenue
---------------------------------------------------------------------
Three Months Ended
---------------------------------------------------------------------
Revenue Mar 31, % of Dec 31, % of Mar 31, % of
($ millions)(1)(2) 2005 total 2004 total 2004 total
---------------------------------------------------------------------
Natural gas 110.4 72% 120.6 71% 74.0 68%
Crude oil 26.4 17% 30.5 18% 25.0 23%
Natural gas
liquids 16.3 11% 17.7 11% 9.5 9%
---------------------------------------------------------------------
Total 153.1 100% 168.8 100% 108.5 100%
---------------------------------------------------------------------
---------------------------------------------------------------------
Hedging losses
included above (5.4) (7.6) (3.8)
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Excludes sulphur.
(2) Net of transportation expenses.
/T/
First quarter 2005 revenues were 41% higher than the same period in
2004, due to higher commodity prices and increased production volumes.
Revenues are 9% lower in the first quarter of 2005 compared to the
fourth quarter 2004 due to lower volumes offset by slightly higher
realized prices.
PrimeWest derives approximately 72% of its revenues from natural gas;
therefore, the Trust has greater sensitivity to changes in natural gas
prices than crude oil prices.
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. The hedging policy reflects a willingness to risk
forfeiting a portion of the pricing upside in return for protection
against a significant downturn in prices.
The following table sets forth the approximate percentage of future
anticipated production volumes hedged at March 31, 2005, net of
anticipated royalties, reflecting full production declines with no
offsetting additions:
/T/
---------------------------------------------------------------------
Q2/05 Q3 /05 Q4/05 Q1/06 Q2/06 Q3/06
---------------------------------------------------------------------
Crude Oil 65 61 48 25 0 0
Natural Gas 52 56 53 40 0 0
---------------------------------------------------------------------
---------------------------------------------------------------------
/T/
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 hedging contracts in place at March 31, 2005 follows:
/T/
Crude Oil (US$/bbl)
---------------------------------------------------------------------
Volume
Period (bbls/d) Type WTI Price (US$/bbl)
---------------------------------------------------------------------
Apr - Jun 2005 500 Swap 27.07
Apr - Jun 2005 500 Swap 28.50
Apr - Jun 2005 500 Swap 30.00
Apr - Jun 2005 500 3 Way 25.00/30.00/36.75
Apr - Jun 2005 500 Costless Collar 35.00/47.00
Apr - Jun 2005 500 Costless Collar 35.00/46.90
Apr - Jun 2005 500 Costless Collar 37.50/50.90
Apr - Jun 2005 500 Costless Collar 37.50/56.70
Apr - Jun 2005 500 Costless Collar 40.00/60.75
Jul - Sep 2005 500 Swap 27.05
Jul - Sep 2005 500 Swap 28.50
Jul - Sep 2005 500 Costless Collar 35.00/44.90
Jul - Sep 2005 500 Costless Collar 35.00/44.35
Jul - Sep 2005 500 Costless Collar 35.00/51.30
Jul - Sep 2005 500 Costless Collar 35.00/56.50
Jul - Sep 2005 500 Costless Collar 40.00/55.30
Jul - Sep 2005 500 Costless Collar 40.00/65.00
Oct - Dec 2005 500 Swap 27.18
Oct - Dec 2005 500 Costless Collar 35.00/42.80
Oct - Dec 2005 500 Costless Collar 35.00/42.40
Oct - Dec 2005 500 Costless Collar 35.00/48.05
Oct - Dec 2005 500 Costless Collar 35.00/53.25
Oct - Dec 2005 500 Costless Collar 40.00/55.50
Jan - Mar 2006 1000 Costless Collar 35.00/49.90
Jan - Mar 2006 500 Costless Collar 40.00/60.25
---------------------------------------------------------------------
Natural Gas (Cdn$/Mcf)
---------------------------------------------------------------------
Volume AECO Price
Period (mmcf/d) Type (Cdn$/mcf)
---------------------------------------------------------------------
Apr 2005 - Jun 2005 10.0 Costless Collar 6.33/7.75
Apr 2005 - Jun 2005 10.0 Costless Collar 6.33/7.63
Apr 2005 - Jun 2005 10.0 Costless Collar 6.33/7.49
Apr 2005 - Jun 2005 10.0 Costless Collar 6.33/7.84
Apr 2005 - Jun 2005 5.0 Costless Collar 6.33/7.85
Apr 2005 - Jun 2005 5.0 Costless Collar 6.33/6.99
Apr 2005 - Jun 2005 5.0 Costless Collar 6.33/7.09
Apr 2005 - Jun 2005 5.0 Costless Collar 6.33/7.44
Apr 2005 - Jun 2005 5.0 Costless Collar 6.33/8.56
Apr 2005 - Jun 2005 5.0 Costless Collar 6.33/8.97
Apr 2005 - Jun 2005 5.0 Costless Collar 6.33/8.33
Jul 2005 - Sep 2005 10.0 Costless Collar 6.33/7.81
Jul 2005 - Sep 2005 10.0 Costless Collar 6.33/7.66
Jul 2005 - Sep 2005 10.0 Costless Collar 6.33/7.53
Jul 2005 - Sep 2005 10.0 Costless Collar 6.33/7.86
Jul 2005 - Sep 2005 2.4 Costless Collar 6.33/7.88
Jul 2005 - Sep 2005 5.0 Costless Collar 6.33/7.50
Jul 2005 - Sep 2005 5.0 Costless Collar 6.33/7.60
Jul 2005 - Sep 2005 5.0 Costless Collar 6.33/7.79
Jul 2005 - Sep 2005 5.0 Costless Collar 6.33/9.28
Jul 2005 - Sep 2005 5.0 Costless Collar 6.33/8.02
Jul 2005 - Sep 2005 5.0 Costless Collar 6.33/8.49
Jul 2005 - Sep 2005 5.0 Costless Collar 6.33/8.55
Oct 2005 - Dec 2005 10.0 Costless Collar 6.33/8.97
Oct 2005 - Dec 2005 10.0 Costless Collar 6.33/8.71
Oct 2005 - Dec 2005 10.0 Costless Collar 6.33/8.60
Oct 2005 - Dec 2005 10.0 Costless Collar 6.33/8.96
Oct 2005 - Dec 2005 5.0 3 Way 5.28/6.33/9.92
Oct 2005 - Dec 2005 5.0 3 Way 5.28/6.33/9.76
Oct 2005 - Dec 2005 5.0 3 Way 5.28/6.33/10.04
Oct 2005 - Dec 2005 5.0 Costless Collar 6.33/10.90
Oct 2005 - Dec 2005 5.0 Costless Collar 6.33/8.97
Oct 2005 - Dec 2005 5.0 Costless Collar 6.33/9.57
Jan 2006 - Mar 2006 10.0 Costless Collar 6.33/10.55
Jan 2006 - Mar 2006 10.0 Costless Collar 6.33/10.22
Jan 2006 - Mar 2006 10.0 Costless Collar 6.33/9.96
Jan 2006 - Mar 2006 5.0 Costless Collar 6.33/10.42
Jan 2006 - Mar 2006 5.0 Costless Collar 6.33/13.13
Jan 2006 - Mar 2006 5.0 Costless Collar 6.33/11.61
Jan 2006 - Mar 2006 5.0 Costless Collar 6.33/12.66
---------------------------------------------------------------------
/T/
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 $9.92,
purchased a put at $6.33, and resold the put at $5.28. Should the market
price drop below $6.33, PrimeWest will receive $6.33 until the price is
less than $5.28, at which time PrimeWest will then receive market price
plus $1.05. However, should market prices rise above $9.92, PrimeWest
will receive a maximum of $9.92. Should the market price remain between
$6.33 and $9.92, PrimeWest will receive the market price.
/T/
Electrical Power
---------------------------------------------------------------------
Power Amount Type Price
Period (MW) ($/MW-hr)
---------------------------------------------------------------------
Calendar 2005 5.0 Fixed Price Swap 51.65
---------------------------------------------------------------------
---------------------------------------------------------------------
/T/
PrimeWest's derivatives are mark-to-market at the end of each reporting
period with the resulting gain or loss reflected in earnings for that
period.
The first quarter 2005 income statement shows an unrealized loss of
$35.2 million on derivatives resulting from the change in the
mark-to-market valuation of the derivative financial instruments during
the period. The loss was comprised of a $9.6 million loss for crude oil
hedges; a $25.9 million loss for natural gas hedges and a $0.3 million
gain for electrical power hedges.
For the period ended March 31, 2005 the cash impact of contract
settlements was a $5.5 million loss comprised of a $5.5 million loss in
crude oil, a $0.1 million gain in natural gas, and a $0.1 million loss
on electrical power.
Royalties (Net of ARTC)
PrimeWest pays royalties to the owners of mineral rights with whom
PrimeWest holds leases. PrimeWest has mineral leases with the Crown
(Provincial and Federal Governments), freeholders (individuals or other
companies) and other operators. ARTC is the Alberta Royalty Tax Credit,
a tax rebate provided by the Alberta government to producers that paid
eligible Crown royalties in the year.
/T/
---------------------------------------------------------------------
Three Months Ended
---------------------------------------------------------------------
Mar 31, Dec 31, Mar 31,
($ millions, except per BOE) 2005 2004 2004
---------------------------------------------------------------------
Royalty expense (net of ARTC) $ 36.0 $ 41.8 $ 23.3
Per BOE $ 9.85 $ 10.24 $ 8.22
---------------------------------------------------------------------
Royalties as % of sales revenues
With hedge loss 23.5% 24.7% 21.5%
Excluding hedge loss 22.7% 23.7% 20.8%
---------------------------------------------------------------------
---------------------------------------------------------------------
/T/
Royalty expense in the first quarter of 2005 was approximately 54%
higher than the same quarter in the previous year due to higher
revenues. First quarter 2005 royalty expense is 13% lower than the
fourth quarter of 2004 due to lower revenues which are partially
attributable to the volume decrease resulting from the fourth quarter
2004 asset sales.
The Crown royalty system is based on a sliding scale structure that
increases the royalty rates as commodity prices rise. Because of the
sliding scale, future changes to commodity prices will result in changes
in royalty rates and expenses.
/T/
Operating Expenses
---------------------------------------------------------------------
Three Months Ended
---------------------------------------------------------------------
Mar 31, Dec 31, Mar 31,
($ millions, except per BOE) 2005 2004 2004
---------------------------------------------------------------------
Operating expense $ 24.4 $ 28.3 $ 19.7
Per BOE $ 6.68 $ 6.94 $ 6.92
---------------------------------------------------------------------
---------------------------------------------------------------------
/T/
The first quarter 2005 operating expenses are 14% lower than the
previous quarter due to fourth quarter 2004 asset sales and a lower
short-term incentive bonus accrual. The operating expenses are higher
than the first quarter of 2004 due to increased production volumes
resulting from 2004 acquisitions. On a per BOE basis operating costs for
the first quarter of 2005 are lower than the same period in 2004 due to
the impact of the Calpine assets acquired in 2004 which have a lower
operating cost per BOE.
Operating Expenses Outlook
General industry inflation is expected to increase overall field
operating expenses in 2005. PrimeWest expects 2005 operating expenses to
average approximately $6.60 per BOE which is 3% lower than 2004,
reflecting the impact of the Calpine acquisition and the asset
divestment program.
/T/
Operating Margin
---------------------------------------------------------------------
Three Months Ended
---------------------------------------------------------------------
Mar 31, Dec 31, Mar 31,
($/BOE) 2005 2004 2004
---------------------------------------------------------------------
Sales price and other revenue (1) $ 41.94 $ 41.46 $ 38.42
Royalties 9.85 10.24 8.22
Operating expenses 6.68 6.94 6.92
---------------------------------------------------------------------
Operating margin $ 25.41 $ 24.28 $ 23.28
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Includes hedging and sulphur
/T/
Operating margin per BOE increased 9% in the first quarter of 2005
compared to the same quarter in 2004. This is primarily due to higher
sales prices and production volumes and lower operating expenses offset
by 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 BOE that is produced, before head office expenses
and financing charges.
Operating margin is higher in the first quarter 2005 compared to the
fourth quarter 2004, primarily as a result of higher sales prices, lower
operating expenses and lower royalties.
The operating margin for 2005 will be heavily dependent on commodity
prices. PrimeWest will continue to pursue a strategy to maintain lower
than average operating expenses to maximize margins, which can help to
reduce the volatility of cash flows through commodity price cycles.
/T/
General & Administrative Expense
---------------------------------------------------------------------
Three Months Ended
---------------------------------------------------------------------
Mar 31, Dec 31, Mar 31,
($ millions, except per BOE) 2005 2004 2004
---------------------------------------------------------------------
Cash G&A expense $ 5.5 $ 7.9 $ 4.2
Per BOE $ 1.51 $ 1.93 $ 1.49
Non-cash G&A expense $ 15.1 $ 2.3 $ 0.4
Per BOE $ 4.12 $ 0.56 $ 0.15
---------------------------------------------------------------------
---------------------------------------------------------------------
/T/
Cash G&A expense in the first quarter of 2005 decreased from the
previous quarter due to lower short-term incentive bonuses and higher
overhead recoveries, offset by increases to salaries and benefits,
annual report costs and regulatory fees.
Expenses related to the Long Term Incentive Plan ("LTIP") are recorded
on a mark-to-market basis, whereby increases or decreases in the
valuation of the UAR liability are reflected in the income statement.
Included in the first quarter non-cash G&A expense is $14.7 million
relating to the change in the value of the Unit Appreciation Rights
(UARs) issued under the LTIP. UARs in a trust are similar to stock
options in a corporation. The LTIP program is based on total Unitholder
return, which is comprised of cumulative distributions on a reinvested
basis plus growth in unit price. No benefit accrues to the UARs until
the Unitholders have first achieved a 5% total annual return from the
time of the UAR grant. PrimeWest continues to pay for the exercise of
UARs in Trust Units.
PrimeWest's non-cash G&A expenses (on a total and per BOE basis)
increased in the first quarter of 2005 compared to the previous quarter.
The increase is due to the change in the value of the UARs resulting
from an increase in the Trust Unit price to $28.99 at March 31, 2005
from $26.62 at December 31, 2004.
G&A Expense Outlook
Cash G&A expenses in 2005 are expected to be lower than in 2004 and are
expected to be approximately $1.25 per BOE for the year.
/T/
Interest Expense
---------------------------------------------------------------------
Three Months Ended
---------------------------------------------------------------------
Mar 31, Dec 31, Mar 31,
($ millions, except per Trust Unit) 2005 2004 2004
---------------------------------------------------------------------
Interest expense $ 9.1 $ 11.7 $ 3.2
Period end net debt level $ 516.1 $ 552.0 $ 305.7
Debt per Trust Unit $ 7.01 $ 7.77 $ 5.99
---------------------------------------------------------------------
Average cost of debt 5.3% 5.1% 4.4%
---------------------------------------------------------------------
---------------------------------------------------------------------
/T/
Interest expense, representing interest on bank debt, the Secured Notes
and the Debentures decreased in the first quarter of 2005 compared to
the fourth quarter of 2004, due to a lower net debt balance.
The increase in interest expense in the first quarter 2005 compared to
the same period in 2004 is due to the issuance of the Debentures to
finance the acquisition of Calpine oil and gas assets in the third
quarter of 2004.
The decrease in the net debt level at March 31, 2005 compared to the
prior quarter is due to the reduction in the bank debt and to the
conversion of $39.1 million of the Debentures during the first quarter.
The increase in the average cost of debt in the first quarter is due to
the impact of the issuance of Series I and Series II Debentures which
bear interest at 7.5% and 7.75% respectively.
Foreign Exchange
The foreign exchange loss of $0.9 million for the three months ended
March 31, 2005 results from the translation of the U.S. dollar
denominated Secured Notes and related interest payable into Canadian
dollars.
/T/
Depletion, Depreciation and Amortization
---------------------------------------------------------------------
Three Months Ended
---------------------------------------------------------------------
Mar 31, Dec 31, Mar 31,
($ millions, except per BOE) 2005 2004 2004
---------------------------------------------------------------------
Depletion, depreciation & amortization $ 57.3 $ 64.0 $ 41.7
---------------------------------------------------------------------
$/BOE $ 15.67 $ 15.67 $ 14.68
---------------------------------------------------------------------
---------------------------------------------------------------------
/T/
The first quarter 2005 DD&A rate of $15.67 per BOE is higher than the
first quarter 2004 rate of $14.68 due to the impact of the Calpine asset
acquisition.
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 2005 contribution rate for the fund is unchanged from 2004
at $0.50 per BOE. As at March 31, 2005, the site reclamation fund
contained a balance of $11.3 million.
The abandonment and reclamation costs incurred in the first quarter 2005
were $0.9 million, compared to $0.9 million for the same period in 2004,
and $2.3 million for the previous quarter.
/T/
Income and Capital Taxes
---------------------------------------------------------------------
Three Months Ended
---------------------------------------------------------------------
Mar 31, Dec 31, Mar 31,
($ millions) 2005 2004 2004
---------------------------------------------------------------------
Income and capital taxes $ 0.7 $ 1.4 $ 0.3
Future income taxes recovery (19.6) 6.4 (18.2)
---------------------------------------------------------------------
Total $(18.9) $ 7.8 $(17.9)
---------------------------------------------------------------------
---------------------------------------------------------------------
Cash taxes paid $ 0.6 $ 0.9 $ 1.8
---------------------------------------------------------------------
---------------------------------------------------------------------
/T/
The increase in the future income tax recovery in the first quarter of
2005 compared to the previous quarter is mainly due to the increase in
the unrealized derivative and LTIP liabilities.
/T/
Net Income
---------------------------------------------------------------------
Three Months Ended
---------------------------------------------------------------------
Mar 31, Dec 31, Mar 31,
($ millions) 2005 2004 2004
---------------------------------------------------------------------
Net income $ 15.3 $ 40.7 $ 20.1
---------------------------------------------------------------------
---------------------------------------------------------------------
/T/
Cash flow from operations, as opposed to net income, is the primary
measure of performance for an energy trust. The generation of cash flow
is critical for an energy trust to continue paying its distributions to
unitholders.
Conversely, net income is an accounting measure impacted by both cash
and non-cash items. The largest non-cash items impacting PrimeWest's net
income are DD&A, the unrealized loss on derivatives, future taxes and
non-cash G&A.
First quarter 2005 net income was lower than the previous quarter due to
lower net oil and gas revenues, increases in non-cash G&A expenses and
unrealized losses on derivatives offset by higher future income tax
recoveries.
/T/
Liquidity & Capital Resources
Long Term Debt
---------------------------------------------------------------------
As at
---------------------------------------------------------------------
Mar 31, Dec 31, Mar 31,
($ millions) 2005 2004 2004
---------------------------------------------------------------------
Long-term debt $ 504.5 $ 656.3 $ 299.9
Deficit / (working capital) (1) 11.6 (104.3) 5.8
---------------------------------------------------------------------
Net debt $ 516.1 $ 552.0 $ 305.7
Market value of Trust Units and
Exchangeable Shares outstanding (2)(3) 2,112.6 1,877.7 1,355.7
---------------------------------------------------------------------
Total capitalization $ 2,628.7 $ 2,429.7 $ 1,661.4
---------------------------------------------------------------------
Net debt as a % of total capitalization 20% 23% 18%
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Does not include the derivative liability of $35.0 million
included in current liabilities
(2) Based on March 31, 2005 Trust Unit closing price of $28.99 and
March 15, 2005 exchange ratio of 0.51956
(3) Does not include the Debentures
/T/
Long-term debt is comprised of bank credit facilities, Secured Notes and
Debentures of $150.0 million, $151.2 million and $203.3 million
respectively.
PrimeWest had a borrowing base of $625 million at March 31, 2005. The
bank credit facilities consist of an available revolving term loan of
$437.5 million and an operating facility of $25 million with the balance
being attributed to the Secured Notes valued at $162.5 million based on
the U.S. dollar exchange rate at the time of the last renewal in 2004.
In addition to amounts outstanding under the facility, PrimeWest has
outstanding letters of credit in the amount of $4.8 million (2004 - $4.8
million). The credit facility revolves until June 30, 2005, by which
time the lenders will have conducted their annual borrowing base review.
PrimeWest's first quarter 2005 net debt of $516.1 was lower than
December 31, 2004 net debt of $552.0 million mainly due to the
conversion of $39.1 million of the Debentures. The sale of the Viking
Trust Units resulted in cash proceeds of $21.8 million in excess of
their initial cost. The cash was used to reduce the credit facility and
to fund the capital program in the first quarter.
At March 31, 2005 PrimeWest's net debt to annualized first quarter cash
flow was approximately 1.6 times compared to 1.7 times at December 31,
2004. Net debt as a percentage of total capitalization was 20% at March
31, 2005, compared to 23% at December 31, 2004.
In accordance with CICA Handbook Section 3860 - "Financial Instruments"
Series I and Series II Debentures were initially recorded in long-term
debt at their fair value of $147.0 million and $94.9 million
respectively. The difference between the fair value and proceeds was
recorded in unitholders' equity.
The Series I and Series II Debentures are being accreted such that the
liability at maturity will equal the initial proceeds of $150 and $100
million less conversions, respectively.
During the first quarter of 2005, $26.5 million of the Series I and
$12.6 million of the Series II Debentures long-term debt component were
converted to Trust Units. Accretion of $0.2 million was realized on each
of the Series I and Series II Debentures.
Unitholders' Equity
At April 30, 2005, the Trust had 72,427,230 Trust Units outstanding. In
addition, PrimeWest had 1,224,049 Exchangeable Shares outstanding that
are exchangeable into a total of 642,503 Trust Units using the April 15,
2005 exchange ratio of 0.52490:1.
The Series I and Series II Debentures equity components have been
reduced by $0.5 million and $0.7 million respectively due to conversions
to Trust Units in the quarter.
For Canadian resident unitholders, PrimeWest offers the DRIP. Components
of the DRIP include the Optional Trust Unit Purchase Plan (OTUPP) and
the Premium Distribution Plan (PREP). The DRIP gives Canadian
Unitholders the chance to reinvest their monthly distributions at a 5%
discount to the volume weighted average market price, while the OTUPP
gives Canadian Unitholders an opportunity to purchase additional Trust
Units directly from PrimeWest at the same 5% discount to the volume
weighted average market price. The 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. The DRIP
and PREP components are mutually exclusive. Participation in the OTUPP
requires enrolment in either the DRIP or the PREP. Subject to regulatory
approval, PrimeWest will be offering the DRIP to U.S. residents holding
PrimeWest units in the near future.
During the quarter, PrimeWest issued 65,052 Trust Units for $1.8 million
under
the DRIP, 291,695 Trust Units for $7.9 million pursuant to the PREP and
276,313 Trust Units for proceeds of $7.6 million from the OTUPP.
For further details on these plans or to obtain the enrolment forms,
please contact PrimeWest's Plan Agent, Computershare Trust Company of
Canada at 1-800-564-6253, or visit PrimeWest's website at
www.primewestenergy.com.
These plan components benefit Unitholders by offering alternatives to
maximize their investment in PrimeWest while providing the Trust with an
inexpensive method to raise additional capital. Proceeds from these
plans are used for debt reduction and to help fund ongoing capital
development programs.
Exchangeable Shares
Exchangeable Shares were issued in connection with both the Venator
Petroleum Company Ltd. acquisition in April 2000 and the Cypress Energy
Inc. acquisition in March 2001. These shares were issued to provide a
tax-deferred rollover of the adjusted cost base from the shares being
exchanged to the Exchangeable Shares. Canadian tax law does not permit a
tax deferral when shares are exchanged for Trust Units.
The Exchangeable Shares do not receive cash distributions. In lieu of
receiving distributions, the number of Trust Units that the exchangeable
shareholder will receive upon exchange increases each month based on the
distribution amount divided by the market price of the Trust Units on
the 15th day of that month.
At March 15, 2005, there were 1,226,049 Exchangeable Shares outstanding.
The exchange ratio on these shares was 0.51956:1 Trust Units for each
Exchangeable Share as at the end of the first quarter. For purposes of
calculating basic per Trust Unit amounts, the assumption is that these
Exchangeable Shares are exchanged into Trust Units at the current
exchange ratio.
Cash Distributions
Cash distributions to Unitholders are at the discretion of the Board of
Directors and can fluctuate depending on the cash flow generated from
operations. As discussed previously, the cash flow available for
distribution is dependent upon many factors including commodity prices,
production levels, debt levels, capital spending requirements, and
factors in the overall industry environment. In order to increase
PrimeWest's financial flexibility, the Board of Directors maintains a
longer-term target distribution payout ratio of approximately 70% to 90%
of cash flow from operations.
In the first quarter of 2005, cash distributions totalled $63.8 million,
or $0.90 per Trust Unit representing a payout ratio of approximately
80%, compared to $41.1 million, or $0.82 per Trust Unit (70% payout
ratio) for the same period in 2004. In the fourth quarter 2004 cash
distributions totalled $62.6 million, or $0.90 per Trust Unit
representing a payout ratio of approximately 76%.
Distribution payments to U.S. Unitholders are subject to a 15% Canadian
withholding tax, which is deducted from the entire distribution amount
prior to deposit into accounts.
Contractual Obligations
PrimeWest enters into many contractual obligations as part of conducting
day-to-day business. Material contractual obligations include debt
obligations, lease rental commitments that run from 2005 through 2009
and various pipeline transportation commitments that run through 2010.
The details of the timing of these contractual obligations are included
in the following table.
/T/
---------------------------------------------------------------------
As at March 31, 2005 Payments due by period ($ millions)
---------------------------------------------------------------------
Less More
than than
Total 1 year 1-3 years 4-5 years 5 years
---------------------------------------------------------------------
Long-term debt
obligations $ 301.2 $ - $ 187.8 $ 75.6 $ 37.8
Debentures 209.4 - - 122.7 86.7
Lease rental
obligations 13.8 3.7 6.8 3.3 -
Pipeline
transportation
obligations 13.5 6.5 6.3 0.6 0.1
---------------------------------------------------------------------
Total contractual
obligations $ 537.9 $ 10.2 $ 200.9 $ 202.2 $ 124.6
---------------------------------------------------------------------
---------------------------------------------------------------------
/T/
As part of PrimeWest's internalization transaction (see Note 14 in the
Consolidated Financial Statements of the 2004 Annual Report), PrimeWest
agreed to issue 377,360 Exchangeable Shares to the Executive Officers
pursuant to a Special Employee Retention Plan. One quarter (94,340
shares) of the Exchangeable Shares were issued to the Officers on
November 6, 2004. One third of the remaining Exchangeable Shares will be
issued on each of third, fourth and fifth anniversaries of the
transaction closing, November 6, 2002. As at March 31, 2005, $0.4
million has been accrued in non-cash G&A expenses related to the Special
Employee Retention Plan.
Business Risks
PrimeWest's operations are affected by a number of underlying risks,
both internal and external to the Trust. These risks are similar to
those affecting others in both the conventional oil and gas royalty
trust sector and the conventional oil and gas producers sector. The
Trust's financial position, results of operations, and cash available
for distribution to Unitholders are directly impacted by these factors.
These factors are discussed under two broad categories - "Commodity
Price, Foreign Exchange and Interest Rate Risk", and "Operational and
Other Business Risks."
Commodity Price, Foreign Exchange And Interest Rate Risk
The two most important factors affecting the level of cash distributions
available to unitholders are the level of production achieved by
PrimeWest, and the price received for its products. These prices are
influenced in varying degrees by factors outside the Trust's control.
Some of these factors include:
- World market forces, specifically the actions of OPEC and other large
crude oil producing countries including Russia, and their implications
on the supply of crude oil;
- World and North American economic conditions which influence the
demand for both crude oil and natural gas and the level of interest
rates set by the governments of Canada and the U.S.;
- Weather conditions that influence the demand for natural gas and
heating oil;
- The Canadian/U.S. dollar exchange rate that affects the price received
for crude oil as the price of crude oil is referenced in U.S. dollars;
- Transportation availability and costs; and
- Price differentials among World and North American markets based on
transportation costs to major markets and quality of production.
To mitigate these risks, PrimeWest has an active hedging program in
place based on an established set of criteria that has been approved by
the Board of Directors. The results of the hedging program are reviewed
against these criteria and the results actively monitored by the Board.
Beyond our hedging strategy, PrimeWest also mitigates risk by having a
well-diversified marketing portfolio and by transacting with a number of
counterparties and limiting exposure to each counterparty. For the first
quarter of 2005 approximately 25% of natural gas production was sold to
aggregators and 75% of production was sold into the Alberta short-term
or export long-term markets.
The contracts that PrimeWest has with aggregators vary in length. They
represent a blend of domestic and US markets and fixed and floating
prices designed to provide price diversification to our revenue stream.
The primary objective of our commodity risk management program is to
reduce the volatility of our cash distributions, to lock in the
economics on major acquisitions and to protect our capital structure
when commodity prices cycle downwards. In the first quarter 2005,
PrimeWest lost $5.4 million from commodity hedges.
Operational And Other Business Risks
PrimeWest is also exposed to a number of risks related to its activities
within the oil and gas industry that have an impact on the amount of
cash available to Unitholders. These risks, and the manner in which
PrimeWest seeks to mitigate these risks include, but are not limited to:
/T/
--------------------------------------------------------------------
RISK WE MITIGATE BY
--------------------------------------------------------------------
Production
Risk associated with the Performing regular and proactive
production of oil and gas - protective well, facility and
includes well operations, pipeline maintenance supported
processing and the physical by telemetry, physical
delivery of commodities to inspection and diagnostic tools.
market.
--------------------------------------------------------------------
Commodity Price
Fluctuations in natural gas, Hedging. See page 12 of this
crude oil and natural gas liquid news release.
prices.
--------------------------------------------------------------------
Transportation
Market risk related to the Diversifying the transportation
availability of transportation systems on which we rely to get
to market and potential our product to market.
disruption in delivery systems.
--------------------------------------------------------------------
Natural Decline
Development risk associated with Diversifying our capital
capital enhancement activities spending program over a large
undertaken - the risk that number of projects so that large
capital spending on activities amounts of capital are not
such as drilling, well risked on any one activity. We
completions, well workovers and also have a highly skilled
other capital activities will technical team of geologists,
not result in reserve additions geophysicists and engineers
or in quantities sufficient to working to apply the latest
replace annual production technology in planning and
declines. executing capital programs.
Capital is spent only after
strict economic criteria for
production and reserve additions
are assessed.
--------------------------------------------------------------------
Acquisitions
Acquisition risk associated with Continually scanning the
acquiring producing properties marketplace for opportunities to
at low cost to renew our acquire assets. Our technical
inventory of assets. acquisition specialists evaluate
potential corporate or property
acquisitions and identify areas
for value enhancement through
operational efficiencies or
capital investment. All
prospects are subjected to
rigorous economic review against
established acquisition and
economic hurdle rates. In some
cases we may also hedge
commodity prices to protect the
acquisition economics in the
near term period.
--------------------------------------------------------------------
Reserves
Reserve risk in respect of the Contracting our reserves
quantity and quality of evaluation to a reputable third
recoverable reserves. party consultant, Gilbert
Laustsen Jung Associates Ltd.
(GLJ). The Operations and
Reserves Committee of the Board
of Directors and PrimeWest
review the work and independence
of GLJ. Our strategy is to
invest in mature, longer life
properties having a higher
proved producing component where
the reserve risk is generally
lower and cash flows are more
stable and predictable.
--------------------------------------------------------------------
Environmental Health and Safety
(EH&S)
Environmental, health and safety Establishing and adhering to
risks associated with oil and strict guidelines for EH&S
gas properties and facilities. including training, proper
reporting of incidents,
supervision and awareness.
PrimeWest has active community
involvement in field locations
including regular meetings with
stakeholders in the area.
PrimeWest carries adequate
insurance to cover property
losses, liability and business
interruption. These risks are
reviewed regularly by the
Corporate Governance and EH&S
Committee of the Board.
--------------------------------------------------------------------
Regulation, Tax and Royalties
Changes in government Keeping informed of proposed
regulations including reporting changes in regulations and laws
requirements, income tax laws, to properly respond to and plan
operating practices, for the effects that these
environmental protection changes may have on our
requirements and royalty rates. operations.
--------------------------------------------------------------------
Historical Liability to
Unitholders is Uncertain
Because of uncertainties in the On July 1, 2004, a new statute
law prior to July 1, 2004, entitled the Income Trusts
relating to investments in Liability Act (Alberta) was
trusts, there is a risk that a proclaimed in force, creating a
Unitholder could be held statutory limitation on the
personally liable for liability of unitholders of
obligations of the Trust. Alberta income trusts such as
PrimeWest. The legislation
provides that a Unitholder is
not, as beneficiary, liable for
any act, default, obligation or
liability of the Trust that
arises after July 1, 2004.
Similar legislation was
proclaimed in force in Ontario
in December of 2004.
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/T/
Additional Information
Additional information pertaining to PrimeWest, including the Trust's
most recently filed Annual Report and Annual Information Form, is
available on SEDAR at www.sedar.com and on the PrimeWest website at
www.primewestenergy.com. PrimeWest 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 at our
website, www.primewestenergy.com. We make every effort to respond to
queries as quickly as possible, but during periods of heavy call volume,
our response time may take up to 2 business days.
/T/
PrimeWest Energy Trust
Quarterly Report for the Three Months Ended March 31, 2005
CONSOLIDATED BALANCE SHEET
---------------------------------------------------------------------
(Unaudited)
($ millions) March 31, 2005 Dec 31, 2004
---------------------------------------------------------------------
ASSETS
Current assets
Cash and cash equivalents $ 8.7 $ 54.4
Marketable securities (note 2) - 68.6
Accounts receivable 94.2 96.9
Assets held for sale - 5.4
Prepaid expenses 12.8 10.9
Inventory 6.8 5.8
---------------------------------------------------------------------
122.5 242.0
Cash reserved for site restoration
and reclamation 11.3 10.3
Other assets and deferred charges 10.5 10.9
Derivative asset - 0.6
Property, plant and equipment 1,904.4 1,908.6
Goodwill 68.5 68.5
---------------------------------------------------------------------
$ 2,117.2 $ 2,240.9
---------------------------------------------------------------------
---------------------------------------------------------------------
LIABILITIES AND UNITHOLDERS' EQUITY
Current liabilities
Accounts payable $ 34.5 $ 47.7
Accrued liabilities 81.0 72.3
Derivative liability 35.0 0.5
Accrued distributions to unitholders 18.6 17.7
---------------------------------------------------------------------
169.1 138.2
Long-term debt (note 4) 504.5 656.3
Future income taxes 191.6 211.2
Asset retirement obligation (note 3) 34.8 40.3
---------------------------------------------------------------------
900.0 1,046.0
UNITHOLDERS' EQUITY
Net capital contributions (note 5) 2,112.4 2,049.9
Capital issued but not distributed 3.0 3.3
Convertible unsecured subordinated
debentures 6.9 8.1
Long-term incentive plan equity (note 6) 29.9 20.1
Accumulated income 104.5 89.2
Accumulated cash distributions (1,031.5) (967.7)
Accumulated dividends (8.0) (8.0)
---------------------------------------------------------------------
1,217.2 1,194.9
---------------------------------------------------------------------
$ 2,117.2 $ 2,240.9
---------------------------------------------------------------------
---------------------------------------------------------------------
The accompanying notes form an integral part of these financial
statements.
CONSOLIDATED STATEMENTS OF UNITHOLDERS' EQUITY
---------------------------------------------------------------------
Mar 31, 2005 Mar 31, 2004
For the three months ended ($ millions) (Unaudited) (Unaudited)
---------------------------------------------------------------------
Unitholders' equity, beginning of period $ 1,194.9 $ 1,019.6
Adjustment to Unitholders' equity at
beginning of period to adopt:
New Asset Retirement Obligation - 5.6
New Oil and Gas Accounting Standard - (233.3)
Net income for the period 15.3 20.1
Net capital contributions 62.5 18.8
Convertible unsecured subordinated
debentures (1.2) -
Capital issued but not distributed (0.3) (2.8)
Long-term incentive plan equity 9.8 (1.6)
Cash distributions (63.8) (41.1)
---------------------------------------------------------------------
Unitholders' equity, end of period $ 1,217.2 $ 785.3
---------------------------------------------------------------------
---------------------------------------------------------------------
CONSOLIDATED STATEMENTS OF CASH FLOW
---------------------------------------------------------------------
Mar 31, 2005 Mar 31, 2004
For the three months ended ($ millions) (Unaudited) (Unaudited)
---------------------------------------------------------------------
OPERATING ACTIVITIES
Net income for the period $ 15.3 $ 20.1
Add/(deduct) items not involving
cash from operations
Depletion, depreciation and amortization 57.3 41.7
Non-cash general & administrative 15.1 0.4
Non-cash foreign exchange loss 0.9 1.9
Cash distributions from marketable
securities 1.0 -
Gain on sale of marketable securities (26.9) -
Unrealized loss on derivatives 35.2 12.3
Future income taxes recovery (19.6) (18.2)
Accretion on asset retirement obligation 0.6 0.3
Other non-cash items 0.8 -
---------------------------------------------------------------------
Cash flow from operations 79.7 58.5
Expenditures on site restoration
and reclamation (0.9) (0.9)
Change in non-cash working capital (21.6) 1.2
---------------------------------------------------------------------
57.2 58.8
---------------------------------------------------------------------
FINANCING ACTIVITIES
Proceeds from issue of Trust Units,
net of issue costs 7.6 2.8
Net cash distributions to unitholders (54.5) (29.9)
Increase/(decrease) in bank credit
facilities (114.0) 38.1
Change in non-cash working capital 0.4 (0.2)
---------------------------------------------------------------------
(160.5) 10.8
---------------------------------------------------------------------
INVESTING ACTIVITIES
Expenditures on property, plant & equipment (61.6) (31.5)
Acquisition of capital/corporate assets - (38.5)
Proceeds on disposal of property,
plant & equipment 8.7 3.5
Proceeds on sale of marketable securities 94.5 -
Increase in cash reserved for future site
restoration and reclamation (1.0) (0.5)
Change in non-cash working capital 17.0 1.3
---------------------------------------------------------------------
57.6 (65.7)
---------------------------------------------------------------------
(Decrease)/increase in cash for the period (45.7) 3.9
Cash beginning of the period 54.4 2.5
---------------------------------------------------------------------
Cash end of the period $ 8.7 $ 6.4
---------------------------------------------------------------------
---------------------------------------------------------------------
Cash interest paid $ 7.7 $ 1.2
---------------------------------------------------------------------
---------------------------------------------------------------------
Cash taxes paid $ 0.6 $ 1.0
---------------------------------------------------------------------
---------------------------------------------------------------------
Non-cash transactions - conversion of
Convertible Unsecured Subordinated
Debentures into Trust Units $ 40.3 $ -
---------------------------------------------------------------------
---------------------------------------------------------------------
CONSOLIDATED STATEMENTS OF INCOME
---------------------------------------------------------------------
For the three months ended ($ millions) Mar 31, 2005 Mar 31, 2004
(except per Trust Unit amounts) (Unaudited) (Unaudited)
---------------------------------------------------------------------
REVENUES
Sales of crude oil, natural gas and
natural gas liquids $ 155.2 $ 110.5
Transportation expenses (1.9) (1.8)
Crown and other royalties, net of ARTC (36.0) (23.3)
Unrealized loss on derivatives (35.2) (12.3)
Gain on sale of marketable securities 26.9 -
Other income 0.3 0.3
---------------------------------------------------------------------
109.3 73.4
---------------------------------------------------------------------
EXPENSES
Operating 24.4 19.7
Cash general and administrative 5.5 4.2
Non-cash general and administrative 15.1 0.4
Depletion, depreciation and amortization 57.3 41.7
Interest 9.1 3.2
Accretion on asset retirement obligation 0.6 0.3
Foreign exchange loss 0.9 1.7
---------------------------------------------------------------------
112.9 71.2
---------------------------------------------------------------------
Income before taxes for the period (3.6) 2.2
---------------------------------------------------------------------
Income and capital taxes 0.7 0.3
Future income taxes recovery (19.6) (18.2)
---------------------------------------------------------------------
(18.9) (17.9)
---------------------------------------------------------------------
Net income for the period $ 15.3 $ 20.1
---------------------------------------------------------------------
---------------------------------------------------------------------
Net income per Trust Unit - basic $ 0.21 $ 0.40
Net income per Trust Unit - diluted $ 0.21 $ 0.40
---------------------------------------------------------------------
---------------------------------------------------------------------
/T/
Notes to Consolidated Financial Statements
For the three months ended March 31, 2005, (except per Trust unit
amounts) all amounts are expressed in millions of Canadian dollars
unless otherwise indicated.
1. Significant Accounting Policies
These interim consolidated financial statements of PrimeWest 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
70 through 72 of the Trust's 2004 annual report and should be read in
conjunction with these interim financial statements.
/T/
2. Marketable Securities
---------------------------------------------------------------------
($ millions) Mar 31, 2005 Dec 31, 2004
---------------------------------------------------------------------
Investment in Viking Trust
(formerly Calpine Natural Gas Trust) $ - $ 68.6
---------------------------------------------------------------------
---------------------------------------------------------------------
/T/
PrimeWest sold its 8% interest in the Viking Energy Royalty Trust for
net proceeds of $94.5 million. The investment was accounted for using
the cost method. The sale resulted in a gain of $26.9 million.
3. Asset Retirement Obligations
Management has estimated the total future asset retirement obligation
based on the Trust's net ownership interest in all wells and facilities.
This includes all estimated costs to dismantle, remove, reclaim and
abandon the wells and facilities and the estimated time period during
which these costs will be incurred in the future.
The following table reconciles the asset retirement obligation
associated with the retirement of oil and gas properties:
/T/
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Asset Retirement Obligation ($ millions)
---------------------------------------------------------------------
Asset Retirement Obligation, December 31, 2004 $ 40.3
Change in estimate of liability (3.6)
Liabilities settled (0.9)
Accretion expense 0.6
Sale of capital assets (1.6)
---------------------------------------------------------------------
Asset Retirement Obligation, March 31, 2005 $ 34.8
---------------------------------------------------------------------
---------------------------------------------------------------------
/T/
As at March 31, 2005, the undiscounted amount of estimated cash flows
required to settle the obligation is $217.9 million. The estimated cash
flow has been discounted using a credit-adjusted risk free rate of 7.0
percent and an inflation rate of 1.5 percent. Although the expected
period until settlement ranges from a minimum of 1 year to a maximum of
50 years, the expectation is that costs will be paid over an average of
34 years. These future asset retirement costs will be funded from the
cash reserved for site restoration and reclamation. This cash reserve is
currently funded at $0.50 per BOE from PrimeWest's operating resources.
/T/
4. Long-Term Debt
---------------------------------------------------------------------
($ millions) Mar 31, 2005 Dec 31, 2004
---------------------------------------------------------------------
Bank credit facilities $ 150.0 $ 264.0
Senior Secured Notes 151.2 150.3
Convertible Unsecured
Subordinated Debentures 203.3 242.0
---------------------------------------------------------------------
$ 504.5 $ 656.3
---------------------------------------------------------------------
---------------------------------------------------------------------
5. Unitholders' Equity
The authorized capital of the Trust consists of an unlimited number
of Trust Units.
---------------------------------------------------------------------
Trust Units Number of Units ($ millions)
---------------------------------------------------------------------
Balance, December 31, 2004 69,886,111 $ 2,037.7
Conversion of Convertible Unsecured
Subordinated Debentures 1,521,231 40.3
Issued on exchange of Exchangeable
Shares 35,503 0.6
Issued pursuant to Distribution
Reinvestment Plan 65,052 1.8
Issued pursuant to the Premium
Distribution Plan 291,695 7.9
Issued pursuant to Long-Term
Incentive Plan 162,138 4.9
Issued pursuant to Optional Trust
Unit Purchase Plan 276,308 7.6
---------------------------------------------------------------------
Balance, March 31, 2005 72,238,038 $ 2,100.8
---------------------------------------------------------------------
---------------------------------------------------------------------
/T/
The weighted average number of Trust Units and Exchangeable Shares
outstanding for the three months ended March 31, 2005 was 71,239,168
(2004 - 50,483,218). For purposes of calculating diluted net income per
Trust Unit for the three months ended March 31, 2005, 5,432,754 (2004 -
0) and 3,677,367 (2004 - 0) Trust units issuable pursuant to the
conversion of the Convertible Unsecured Subordinated Debentures Series I
and II respectively and 699,737 Trust Units (2004 - 335,341) issuable
pursuant to the Long-Term Incentive Plan were added to the weighted
average number.
Exchangeable Shares
The Exchangeable Shares are exchangeable into Trust Units at any time up
to March 29, 2010 based on an exchange ratio that adjusts each time the
Trust makes a distribution to its Unitholders. The exchange ratio, which
was 1:1 on the date that the Exchangeable Shares were first issued, is
based on the total monthly distribution, divided by the closing unit
price on the distribution payment date. The exchange ratio effective
March 15, 2005 was 0.51956:1.
/T/
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Exchangeable Shares # of shares ($ millions)
---------------------------------------------------------------------
Balance, December 31, 2004 1,294,391 $ 12.2
Exchanged for Trust Units (68,342) (0.6)
---------------------------------------------------------------------
Balance, March 31, 2005 1,226,049 $ 11.6
---------------------------------------------------------------------
---------------------------------------------------------------------
/T/
6. Long-Term Incentive Plan
Under the terms of the Long-Term 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 Directors and employees of
PrimeWest. 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 those
issued to the members of the Board, which 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.
/T/
As at March 31, 2005
---------------------------------------------------------------------
UARs Current Total
Year of issued & UARs return equity Trust Unit
Grant outstanding vested per UARs ($millions) dilution
---------------------------------------------------------------------
1999 grants 25,047 25,047 $ 47.13 $ 1.2 40,717
2000 grants 77,912 77,912 $ 24.77 1.9 66,581
2001 grants 280,550 279,940(1) $ 15.38 4.3 148,508
2002 grants 733,737 515,011 $ 11.65 8.6 211,249
2003 grants 899,933 459,533 $ 10.31 8.3 166,654
2004 grants 1,415,630 309,953 $ 5.96 4.7 58,352
2005 grants 797,460 74,536 $ 2.97 0.9 7,676
---------------------------------------------------------------------
Total grants 4,230,269 1,741,932 $ 29.9 699,737
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) The UARs vested differs from the UARs issued and outstanding due
to a delay in the vesting period for employees on leave.
7. Cash Distributions
---------------------------------------------------------------------
Three Months Ended
---------------------------------------------------------------------
($ millions, except per
Trust Unit amounts) Mar 31, 2005 Mar 31, 2004
---------------------------------------------------------------------
Cash flow from operations $ 79.7 $ 58.5
Deduct amounts to reconcile to distribution:
Cash retained from cash available
for distribution (1) (13.9) (15.9)
Contribution to reclamation fund (2.0) (1.5)
---------------------------------------------------------------------
$ 63.8 $ 41.1
---------------------------------------------------------------------
Cash Distributions to Unitholders $ 63.8 $ 41.1
---------------------------------------------------------------------
Cash Distributions per Trust Unit $ 0.90 $ 0.82
---------------------------------------------------------------------
(1) The Board of Directors determines the cash distribution level
which results in a discretionary amount of cash being retained.
Trading Performance
---------------------------------------------------------------------
For the Mar Dec Sep Jun Mar
quarter ended 31/05 31/04 30/04 30/04 31/04
---------------------------------------------------------------------
TSX Trust Unit
prices (Cdn$ per
Trust Unit)
High 32.00 28.33 26.70 26.80 28.35
Low 26.15 25.06 23.29 22.18 22.70
Close 28.99 26.62 26.70 23.25 26.65
---------------------------------------------------------------------
Average daily
traded volume 269,714 255,944 254,219 187,767 256,922
---------------------------------------------------------------------
---------------------------------------------------------------------
For the Mar Dec Sep Jun Mar
quarter ended 31/05 31/04 30/04 30/04 31/04
---------------------------------------------------------------------
NYSE Trust Unit
prices (US$ per
Trust Unit)
High 26.60 22.98 21.16 20.44 22.14
Low 21.30 20.85 17.65 16.00 17.31
Close 23.96 22.18 21.16 17.43 20.31
---------------------------------------------------------------------
Average daily
traded volume 536,170 542,483 329,862 279,882 469,694
---------------------------------------------------------------------
---------------------------------------------------------------------
Number of Trust
Units outstanding
including
Exchangeable
Shares (millions
of units) 72.9 70.5 69.7 56.8 50.9
---------------------------------------------------------------------
---------------------------------------------------------------------
Distribution
paid per Trust
Unit (Cdn$) 0.90 0.90 0.83 0.75 0.82
---------------------------------------------------------------------
---------------------------------------------------------------------
/T/
-30-