PrimeWest Energy Trust

PrimeWest Energy Trust

February 24, 2005 23:55 ET

PrimeWest Energy Trust Announces Operating and Financial Results for the Fourth Quarter and Year Ended December 31, 2004


NEWS RELEASE TRANSMITTED BY CCNMatthews

FOR: PRIMEWEST ENERGY TRUST

TSX SYMBOL: PWI.UN
TSX SYMBOL: PWX
TSX SYMBOL: PWI.DB.A
TSX SYMBOL: PWI.DB.B
NYSE SYMBOL: PWI

FEBRUARY 24, 2005 - 23:55 ET

PrimeWest Energy Trust Announces Operating and
Financial Results for the Fourth Quarter and Year
Ended December 31, 2004

CALGARY, ALBERTA--(CCNMatthews - Feb. 24, 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 fourth quarter and year ended December 31, 2004. Unless
otherwise noted, all figures contained in this report are in Canadian
dollars.

Fourth Quarter Highlights:

- In the fourth quarter PrimeWest closed non-core asset sales for net
proceeds of $88.1 million. These funds were used to reduce the amount
drawn on the bank credit facility. In addition another $5.4 million of
assets were held for sale and closed in February 2005.

- Year-end net debt to annualized fourth quarter 2004 cash flow is 1.7
times.

- Fourth quarter production averaged 44,368 barrels of oil equivalent
(BOE) per day, compared to the third quarter 2004 rate of 35,460 BOE/day.

- Distributions of $0.90 per unit represent a payout ratio of
approximately 76%, compared to third quarter 2004 distributions of $0.83
per unit, representing a payout ratio of approximately 74%.

- Cash flow from operations of $81.8 million ($1.07 per unit) compared
to $68.3 million ($1.06 per unit) in the third quarter of 2004,
primarily due to a continued strong commodity price environment and
increased production volumes from the Calpine asset acquisition.

- Year end Proved plus Probable Reserve Life Index increased to 10.3
years from 9.8 years at the end of 2003.

Subsequent Events

- On January 26, 2005 Standard and Poors announced the inclusion of
income trusts in the S&P/TSX Composite Index, Canada's benchmark stock
index. Specifics regarding the inclusion process, including the impact
on PrimeWest is expected to be announced by mid-year 2005.

- On January 27, 2005 the unitholders of Calpine Natural Gas Trust
approved the business combination of Calpine Natural Gas Trust and
Viking Energy Royalty Trust. As a result PrimeWest's 25% unit ownership
of Calpine Natural Gas Trust has been converted into an 8.3% ownership
of Viking Energy Trust. As of February 24, 2005, PrimeWest has sold its
8.3% ownership of Viking Energy Trust and has received gross proceeds of
$95.8 million.

Legislative Changes

- On December 6, 2004, the Government of Canada suspended legislation
that would have restricted the non-resident ownership of income trusts.
The Government proceeded with the proposed changes to non-resident
withholding tax and non-resident unitholders are encouraged to contact
their tax advisors.

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 speak only 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, operations 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 there from;

- 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 and natural gas;

- The impact of weather conditions on seasonal demand;

- 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 and
natural gas;

- 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;

- OPEC's ability to control production to balance global supply and
demand at desired price levels;

- Political uncertainty, including the risks of hostilities, in the
petroleum producing regions of the world;

- 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.

Management's Discussion and Analysis

The following is management's discussion and analysis (MD&A) of
PrimeWest's operating and financial results for the three months and the
twelve months ended December 31, 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, 2004
and 2003, together with accompanying notes.



Financial and Operating Highlights - Fourth Quarter

Financial Highlights Three Months Ended
---------------------------------------
($ millions, except per BOE Dec 31, Sep 30, Dec 31,
and per Trust Unit amounts) 2004 2004 2003
---------------------------------------------------------------------
Gross revenue (net of
transportation) 169.3 125.4 97.1
per BOE(1) 41.46 38.43 32.88
Cash flow from operations 81.8 66.8 43.2
per BOE 20.05 20.48 14.62
per Trust Unit(2) 1.07 1.04 0.86
Royalty expense 41.8 28.9 21.1
per BOE 10.24 8.86 7.13
Operating expenses 28.3 21.4 21.2
per BOE 6.94 6.56 7.18
G&A expenses - Cash 7.9 3.4 4.1
per BOE 1.93 1.03 1.37
G&A expenses - Non-cash 2.3 14.1 8.5
per BOE 0.56 4.31 2.88
Interest expense(3) 11.7 4.4 4.1
per BOE 2.86 1.35 1.37
Distributions to unitholders 62.6 50.4 46.3
per Trust Unit(4) 0.90 0.83 0.96
Net debt(5) 552.0 464.8 255.9
per Trust Unit(6) 7.77 5.84 5.07
---------------------------------------------------------------------
---------------------------------------------------------------------

(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) Weighted Average Trust Units, Exchangeable Shares, Convertible
Unsecured Subordinated Debentures and Trust Units issuable
pursuant to Long-Term Incentive Plan (diluted). Cash flow is
increased to adjust for the interest on Convertible Unsecured
Subordinated Debentures.

(3) Interest expense includes the interest on the Convertible
Unsecured Subordinated Debentures.

(4) Based on Trust Units outstanding at date of distribution.

(5) Net debt is long-term debt adjusted for working capital excluding
financial derivative assets and liabilities.

(6) Trust Units and Exchangeable Shares outstanding and Trust Units
issuable pursuant to the Long-Term Incentive Plan December 31,
2004.




Operating Highlights Three Months Ended
---------------------------------------
Dec 31, Sep 30, Dec 31,
2004 2004 2003
---------------------------------------------------------------------
Daily Sales Volumes
Natural gas (mmcf/day) 187.2 143.5 126.9
Crude oil (bbls/day) 9,108 8,447 8,189
Natural gas liquids (bbls/day) 4,059 3,096 2,779
---------------------------------------------------------------------
Total (BOE/day) 44,368 35,460 32,111
---------------------------------------------------------------------
---------------------------------------------------------------------
---------------------------------------------------------------------




Outlook - 2005

PrimeWest expects full year 2005 production volumes to average
approximately 41,000 BOE/day. Full year operating costs are expected to
be approximately $6.60/BOE. PrimeWest expects to invest approximately
$125 million in its capital development program with the focus on
further development of our Alberta natural gas assets. Approximately $50
million will be invested in development of tight gas assets at Caroline
and Columbia; $20 million will be invested in developing shallow gas
assets in southeastern Alberta; and $55 million will be invested in
development of natural gas at Crossfield and conventional development.
The Trust plans to begin evaluating Coal Bed Methane potential on our
land holdings in the Horseshoe Canyon fairway.



Cash Flow Reconciliation - Fourth Quarter

($ millions)
---------------------------------------------------------------------
Third quarter 2004 cash flow from operations $ 66.8
Volumes 32.3
Commodity prices 10.1
Net hedging change from prior quarter 1.3
Operating expenses (6.9)
Royalties (12.9)
General and administrative expenses (4.5)
Interest Expense (7.3)
Other 2.9
---------------------------------------------------------------------
Fourth quarter 2004 cash flow from operations 81.8
---------------------------------------------------------------------
---------------------------------------------------------------------


The above table includes non-GAAP measurements that may not be
comparable to other companies. Refer to the section on Non-GAAP Measures.

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, hedging gains or losses,
royalties and currency exchange rates. Some of these factors are
uncontrollable from PrimeWest's perspective such as commodity prices,
the currency exchange rate and royalties. Other factors that are
controllable by PrimeWest are production levels 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.

Taxability of Distributions

Canadian Unitholders

The Trust has determined that 45% of distributions declared, or $1.49
per Trust Unit are deemed a tax-deferred return of capital and 55% or
$1.81 per Trust Unit are taxable to Canadian unitholders as "other
income" (taxed at the same rate as interest income.)

United States and Other Non-Resident Unitholders

For unitholders resident in the United States, the taxability of
distributions is derived using US tax rules, which permit the deduction
of Crown royalties and accounting-based depletion. In the case of a US
resident, 45% of the distributions are taxable as a "qualified dividend"
with the remaining 55% treated as a tax-deferred return of capital.

Investors who do not qualify as residents of Canada for income tax
purposes should seek advice from a qualified tax advisor in their
country of residency regarding the tax treatment of the distributions
paid by PrimeWest. Monthly distributions payable to non-residents of
Canada are normally subject to a withholding tax of 25% as prescribed by
the Canadian Income Tax Act. However, the level of withholding tax may
be reduced in accordance with reciprocal tax treaties. In the case of
the Canada - United States Tax Convention, US residents are subject to a
15% withholding tax on the distributions paid by PrimeWest.

For further information on taxability of distributions paid by
PrimeWest, please refer to the Taxation section of our website at
www.primewestenergy.com and your qualified tax advisor.



Capital Expenditures

Three Months Ended
---------------------------------------------------------------------
($ millions) Dec 31, Sep 30, Dec 31,
2004 2004 2003
---------------------------------------------------------------------
Land & lease acquisitions $ 1.8 $ 2.0 $ 2.1
Geological and geophysical 2.4 3.3 4.4
Drilling and completions 30.1 12.0 16.9
Investment in facilities
Equipping & tie-in 4.3 1.0 3.4
Compression & processing 0.9 1.3 0.5
Gas gathering 1.9 1.8 1.4
Production facilities 5.0 3.6 2.2
Capitalized G&A 0.4 0.4 0.2
---------------------------------------------------------------------
Development capital 46.8 25.4 31.1
---------------------------------------------------------------------
Corporate/property acquisitions 1.4 767.0 23.9
Dispositions (88.1) (6.3) (1.5)
Leasehold improvements
furniture and equipment 3.2 0.6 1.2
---------------------------------------------------------------------
Total $ (36.7) $ 786.7 $ 54.7
---------------------------------------------------------------------
---------------------------------------------------------------------


During the fourth quarter of 2004, PrimeWest's net capital expenditures
totaled $(36.7) million as proceeds from dispositions exceeded capital
expenditures. Development capital of $46.8 million invested in the
fourth quarter 2004 included $34.4 million or 74% for drilling,
completions and tie-ins that contribute to new reserve additions and
help offset natural production decline. In the fourth quarter,
PrimeWest's capital spending was focused primarily in the areas of
Caroline, Columbia, Brant Farrow, Boundary Lake and Princess. Gross
wells drilled in the fourth quarter totaled 69 (38.6 net wells), with a
success rate of 97%.

Compared to the third quarter of 2004, development capital spending of
$46.8 million in the fourth quarter of 2004 was higher due to a higher
level of drilling activity as a result of the Calpine acquisition.

During the fourth quarter of 2004, PrimeWest incurred leasehold
improvement expenditures on office space acquired to accommodate
additional staff, resulting from the Calpine acquisition.

In the fourth quarter PrimeWest engaged in a divestiture program
targeting non-core assets which resulted in proceeds of $88.1 million.
An additional $5.4 million of assets were held for sale at year-end and
closed in February 2005. These asset sales reduced production volumes by
approximately 2,700 BOE/day, however due to the timing of these sales,
the fourth quarter average daily production volume impact was a
reduction of 400 BOE/day.



Production Volumes

Three Months Ended
---------------------------------------
Dec 31, Sep 30, Dec 31,
2004 2004 2003
---------------------------------------------------------------------
Natural gas (mmcf/day) 187.2 143.5 126.9
Crude oil (bbls/day) 9,108 8,447 8,189
Natural gas liquids (bbls/day) 4,059 3,096 2,779
---------------------------------------------------------------------
Total (BOE/day) 44,368 35,460 32,111
---------------------------------------------------------------------
---------------------------------------------------------------------
Gross Overriding Royalty volumes
included above (BOE/day) 1,643 1,404 1,595
---------------------------------------------------------------------
---------------------------------------------------------------------


All production information is reported before the deduction of crown and
freehold royalties.

PrimeWest's production volumes in the fourth quarter 2004 were higher
when compared with the third quarter of 2004 and the fourth quarter of
2003 due to volumes contributed by the Calpine assets. PrimeWest's
development activity also added volumes, which partially offset natural
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. In October 2004, the Government of
Alberta enacted amendments to the Natural Gas Royalty Regulations of
2002 specifically with respect to gas production in the affected area.
This amendment provides for a technical change to the royalty
calculation for gas producers adversely affected by the EUB shut-in
orders. This technical change to the calculation of royalties represents
a reduction in royalties paid by PrimeWest to the Province of Alberta.
PrimeWest is evaluating the change to the royalty calculation and its
impact as well as any further steps to be taken in relation to the gas
over bitumen issue.

PrimeWest expects full year 2005 production to average approximately
41,000 BOE/day. This estimate incorporates PrimeWest's expected natural
production declines and shut-in volumes, offset by volume additions from
the 2005 capital development program.



Average Realized Sales Prices

Three Months Ended
---------------------------------------
Dec 31, Sep 30, Dec 31,
(Canadian Dollars) 2004 2004 2003
---------------------------------------------------------------------
Natural gas ($/Mcf)(1)(2) 7.00 6.14 5.52
Without hedging 6.98 6.31 5.50
Crude oil ($/bbl)(1) 36.45 39.95 31.27
Without hedging 46.03 48.58 33.43
Natural gas liquids ($/bbl) 47.32 45.30 34.49
---------------------------------------------------------------------
Total Oil Equivalent ($/BOE) 41.37 38.31 32.78
Without hedging 43.24 41.06 33.25
---------------------------------------------------------------------
---------------------------------------------------------------------
Realized hedging loss included in
prices above ($/BOE) 1.87 2.75 0.47
---------------------------------------------------------------------
---------------------------------------------------------------------

(1) Includes hedging gains / losses.

(2) Excludes sulphur.


Canadian commodity prices were higher in the fourth 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 prices are denominated in US dollars; therefore, a
strengthened Canadian dollar translates into lower realized prices and
lower Canadian revenue for producers.

Compared to the third quarter 2004, average realized sales prices per
BOE increased marginally in the fourth quarter 2004 due to a higher
average price for natural gas and natural gas liquids, partially offset
by lower crude oil prices.

PrimeWest's cash flow from operations is directly impacted by the
volatility in commodity prices, but the use of hedging can reduce the
impact of the price volatility by locking in prices in advance. This can
increase or decrease the prices realized by the Trust. In the fourth
quarter of 2004, PrimeWest reported a $7.6 million hedging loss
representing the amount of additional revenue that could have been
earned without hedging. This compared to a loss of $9.0 million in the
third quarter of 2004 and a loss of $1.4 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)
---------------------------------------------------------------------
Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4
2004 2004 2004 2004 2005 2005 2005 2005
---------------------------------------------------------------------
Natural gas
NYMEX (US$/mcf) 5.69 5.97 5.84 6.87 6.23 6.10 6.19 6.55
AECO (Cdn$/mcf) 6.61 6.80 6.66 7.09 6.28 6.24 6.40 6.88
Crude oil WTI
(US$/bbl) 35.15 38.32 43.88 48.28 43.54 42.97 42.25 41.65
---------------------------------------------------------------------

(1) As December 31, 2004


Financial and Operating Highlights - Full Year
---------------------------------------------------------------------
($ millions, except per BOE
and per Trust Unit Amounts) 2004 2003 Change (%)
---------------------------------------------------------------------
FINANCIAL
Gross revenue
(net of transportation expense) 513.7 434.6 18
per BOE(1) 39.45 35.74 10
Cash flow from operations 266.8 216.6 23
per BOE 20.49 17.82 15
per Trust Unit(2)(6) 4.33 4.67 (7)
Royalty expense 119.8 101.9 18
per BOE 9.20 8.38 10
Operating expenses 88.9 79.4 12
per BOE 6.83 6.53 5
G&A expenses - Cash 19.0 14.5 31
per BOE 1.46 1.20 22
G&A expenses - Non-cash 9.4 14.4 (35)
per BOE 0.73 1.19 (39)
Interest expense (3) 20.6 15.1 36
per BOE 1.58 1.24 27
Net income 103.4 95.9 8
Per Trust Unit - diluted 1.74 2.07 (16)
Distributions to unitholders 196.1 192.6 2
per Trust Unit(4) 3.30 4.32 (24)
Net debt(5) 552.0 255.9 116
per Trust Unit(6) 7.77 5.07 53
---------------------------------------------------------------------

(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) Weighted Average Trust Units, Exchangeable Shares, Convertible
Unsecured Subordinated Debentures and Trust Units issuable
pursuant to Long-Term Incentive Plan (diluted). Cash flow is
increased to adjust for the interest on Convertible Unsecured
Subordinated Debentures.

(3) Interest expense includes the interest on the Convertible
Unsecured Subordinated Debentures.

(4) Based on Trust Units outstanding at date of distribution.

(5) Net debt is long-term debt adjusted for working capital excluding
financial derivative assets and liabilities.

(6) Trust Units and Exchangeable Shares outstanding and Trust Units
issuable pursuant to the Long-Term Incentive Plan December 31,
2004.


Operating

---------------------------------------------------------------------
2004 2003 Change (%)
---------------------------------------------------------------------
Daily Sales Volume
Natural gas (mmcf/day) 145.1 134.1 8
Crude oil (bbls/day) 8,282 8,116 2
Natural gas liquids (bbls/day) 3,107 2,855 9
---------------------------------------------------------------------
Total (BOE/day) 35,578 33,316 7
---------------------------------------------------------------------
---------------------------------------------------------------------


Realized Commodity Prices

---------------------------------------------------------------------
(Canadian Dollars) 2004 2003 Change (%)
---------------------------------------------------------------------
Natural gas ($/Mcf)(1)(2) 6.61 6.05 9
Without hedging 6.70 6.51 3
Crude oil ($/bbl)(1) 36.83 33.94 9
Without hedging 44.46 36.55 22
Natural gas liquids ($/bbl) 43.69 35.34 24
---------------------------------------------------------------------
Total Oil Equivalent (1) ($/BOE) 39.35 35.63 10
Without hedging 41.51 38.14 9
---------------------------------------------------------------------
---------------------------------------------------------------------

(1) Includes hedging gains/losses.

(2) Excludes sulphur.


Financial and Operating Highlights - Full Year

- Production in 2004 averaged 35,578 BOE/day, up 7% from 2003 level of
33,316 BOE/day as a result of the Calpine and Seventh Energy
acquisitions and development capital volume additions, offset by natural
production declines.

- Operating margin of $23.47/BOE for 2004, up 14% from 2003 primarily
due to higher commodity prices throughout the year, offset by higher
operating costs in 2004.

- Distributions of $3.30 per Trust Unit in 2004 compared to $4.32 in
2003 due partially to a lower payout ratio of 74% in 2004 compared to
89% in 2003.

- Hedging loss of $28.2 million ($2.16/BOE) in 2004, compared to losses
of $30.5 million ($2.51/BOE) in 2003 and gains of $28.1 million
($2.55/BOE) in 2002.

- Capital development program of $125.1 million added 10.3 mmBOE of
Proved plus Probable reserves on a Company Interest basis at $12.15/BOE,
which excludes $0.92/BOE for future development capital. (Refer to the
"Reserves and Production" section later in this release for reserve
definitions).

- In 2004, PrimeWest's corporate and asset acquisitions which included
Seventh Energy and the Calpine assets were $807.4 million.

- Operating expenses of $6.83/BOE were 5% higher on a per BOE basis in
2004 compared to 2003, primarily due to rising industry costs.

- Company Interest Proved plus Probable reserves of 155.2 mmBOE at
December 31, 2004, represents an increase of 45% from 106.8 mmBOE
reported as at December 31, 2003. PrimeWest's current Reserve Life Index
(RLI) is 10.3 years on a Company Interest Proved plus Probable basis.

- Company Interest Proved Producing reserves of 105.8 mmBOE at December
31, 2004, represent an increase of 37% over December 31, 2003 Company
Interest Proved Producing reserves of 77.5 mmBOE. The Company Interest
Proved Producing RLI is 7.6 years.

- Cash general and administrative expenses increased $4.5 million over
2003 reflecting higher salaries, higher short-term incentive bonuses,
increased information technology expenditures, one-time consulting costs
associated with potential acquisitions, and increased board of directors
costs. These increases were partially offset by increases in overhead
recoveries.

- Interest expense during 2004 is 36% higher compared to 2003 as a
result of higher average debt levels during the fourth quarter due to
the acquisition of the Calpine assets.

- The Distribution Reinvestment, Premium Distribution and Optional Trust
Unit Purchase Plans added $60.0 million of proceeds that were used for
the capital development program and to repay debt.

Non-GAAP Measures

The MD&A 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;

- 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 is calculated
using cash flow and adding back the interest expense on the convertible
unsecured subordinated debentures, divided by the diluted weighted
average units outstanding in the year. The diluted weighted average
units outstanding consists of the weighted average Trust Units and
Exchangeable Shares outstanding, and includes the Trust Units issuable
pursuant to the conversion of the Convertible Unsecured Subordinated
Debentures, and Trust Units issuable pursuant to the Long-Term Incentive
Plan. 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
2004 based on the number of Trust Units outstanding on the date the
distributions were declared.

Net debt per Trust Unit is calculated using working capital, excluding
derivative assets and liabilities, less long term debt divided by the
number of Trust Units and exchangeable shares outstanding and Trust
Units issuable pursuant to the Long Term Incentive Plan at December 31,
2004.

The Trust's cash flow from operations, distributions per Trust Unit and
net debt per Trust Unit may not be directly comparable to similar
measures presented by other companies or Trusts.

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 December 31, 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
under the Securities Exchange Act of 1934 is recorded, processed,
summarized and reported, within the time periods specified in the
Commission'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 December 31, 2004.

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 2004 and our goals for 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 to 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, senior
secured notes and convertible unsecured subordinated 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 senior secured notes, are denominated
in US 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 from operations to increase the Trust's financial
flexibility. The 2004 payout ratio was approximately 74%, and the
retained cash flow was utilized to fund the Trust's capital spending
program to repay debt. PrimeWest's net debt to cash flow level was 1.7
times at 2004 year end using annualized fourth 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 US unitholders to
conveniently trade in our Trust Units, and allows us to access the US
capital markets in the future. Our status as a corporation for US tax
purposes simplifies tax reporting for our US 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 and
Convertible Unsecured Subordinated 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 2005 production volumes to average approximately
41,000 BOE/day. Full year operating costs are expected to be
approximately $6.60/BOE, while full year G&A costs are expected to be
approximately $1.25/BOE. Approximately $50 million will be invested in
development of tight gas assets at Caroline and Columbia; $20 million
will be invested in developing shallow gas assets in southeastern
Alberta; and $55 million will be invested in development of natural gas
at Crossfield and Conventional Development. PrimeWest plans to begin
evaluating Coal Bed Methane potential on our land holdings in the
Horseshoe Canyon fairway.



Cash Flow Reconciliation - Full Year 2004

($ millions)
---------------------------------------------------------------------
2003 cash flow from operations $ 216.6
Production volumes 33.1
Commodity prices 43.8
Net hedging change from prior year 2.3
Operating expenses (9.5)
Royalties (17.9)
Interest (5.5)
G&A (4.5)
Other 8.4
---------------------------------------------------------------------
2004 cash flow from operations $ 266.8
---------------------------------------------------------------------
---------------------------------------------------------------------

The above table includes non-GAAP measurements (Refer to Non-GAAP
Measures on Page 9).


The key performance driver for the Trust is cash flow from operations
that 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, 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 not controllable by PrimeWest. Other factors that are to a
certain extent controllable by PrimeWest include production levels and
operating expenses, as well as interest and general and administrative
(G&A) expenses.

Capital Spending

Capital expenditures, including development, acquisitions and
divestitures totaled approximately $837.6 million in 2004, versus $334.4
million in 2003.



($ millions, except per BOE) 2004 2003
---------------------------------------------------------------------
Land & lease acquisitions $ 8.3 $ 6.0
Geological and geophysical 8.2 5.8
Drilling and completions 69.8 58.4
Equipping and tie-in 12.1 19.0
Compression and processing 4.7 6.3
Gas gathering 4.4 2.3
Production facilities 15.8 5.7
Capitalized G&A 1.8 1.0
---------------------------------------------------------------------
Development capital $ 125.1 $ 104.5
---------------------------------------------------------------------
Corporate/property acquisitions 807.4 230.9
Dispositions (99.5) (2.3)
Leasehold improvements,
furniture and equipment 4.6 1.3
---------------------------------------------------------------------
Total $ 837.6 $ 334.4
---------------------------------------------------------------------
---------------------------------------------------------------------


In 2004 PrimeWest completed $807.4 million of corporate and property
acquisitions that included the Calpine assets and Seventh Energy. Total
capital and corporate acquisitions added 46.5 mmBOE of Company Interest
Proved reserves and 58.3 mmBOE of Company Interest Proved plus Probable
reserves. Property dispositions of $104.9 million, including assets held
for sale of $5.4 million resulted in a reduction of the Company Interest
Proved Plus Probable reserves of 5.1 mmBOE.

PrimeWest's 2004 capital development program totaled $125.1 million
(2003 - $104.5 million). The program focused on core areas of Caroline,
Columbia, Princess, Boundary Lake, Brant Farrow and Valhalla. The
development program added 7.3 mmBOE of Company Interest Proved reserves
and 10.3 mmBOE of Company Interest Proved plus Probable reserves.

Leasehold improvements during 2004 of $2.5 million were incurred as a
result of additional office space requirements associated with the
Calpine acquisition.



---------------------------------------------------------------------
2004 2003
---------------------------------------------------------------------
Development Program:
Proved reserve additions (mmBOE) 7.3 6.9
Average cost ($/BOE)(1)(3) $ 17.76 $ 15.98
---------------------------------------------------------------------
Proved plus Probable reserve additions (mmBOE) 10.3 7.9
Average cost ($/BOE)(3) $ 13.07 $ 14.29
---------------------------------------------------------------------
Acquisition Program:(2)
Proved reserve additions (mmBOE) 42.4 12.7
Average cost ($/BOE)(1) $ 16.57 $ 18.84
---------------------------------------------------------------------
Proved plus Probable reserve additions (mmBOE) 53.2 15.6
Average cost ($/BOE)(1)(3) $ 13.20 $ 15.71
---------------------------------------------------------------------
---------------------------------------------------------------------

(1) Under NI 51-101 the implied methodology to be used to calculate
FD&A costs includes incorporating future development capital
(FDC) required to bring the Company Interest Proved Undeveloped
and Probable reserves to production. The average cost per BOE
from Company Interest Proved reserve additions includes FDC of
$0.62/BOE ($0.84/BOE for 2003), and the average cost per BOE
from Company Interest Proved plus Probable reserve additions
includes FDC of $0.92/BOE ($1.06/BOE for 2003).

(2) Net of dispositions

(3) The aggregate of the costs incurred under the capital development
program incurred in 2004 and the estimated future development
costs generally will not reflect total finding and development
costs related to reserve additions for that year.


Drilling, completions and tie-in spending represent 65% of development
capital that contributed to new reserve additions. 20% or $24.9 million
of the development capital was invested in facilities that represents
debottlenecking, increasing capacity or other activities that contribute
to future production volumes.

In 2005, PrimeWest plans to invest approximately $125 million on its
capital development program. The 2005 program will focus on further
development of our Alberta natural gas assets.

Given that production volumes will decline naturally over time as oil or
gas reservoirs are depleted, PrimeWest is always striving to offset this
natural production decline, and add to reserves in an effort to sustain
cash flows. Investment in activities such as development drilling,
workovers, and recompletions can add incremental production volumes and
reserves.

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. These
criteria 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 Canada Sedimentary Basin. Within this
focused area, we have a diversified, multi-zone suite of assets
stretching from northeast B.C., and across much of Alberta. 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.

Reserves and Production

National Instrument (NI 51-101) was introduced by the Alberta Securities
Commission in 2003 to improve the standards and quality of reserve
reporting and to achieve a higher industry consistency. Under NI 51-101,
"Proved" reserves are those reserves that can be estimated with a high
degree of certainty to be recoverable (i.e. it is likely that the actual
remaining quantities recovered will exceed the estimated Proved
reserves). In accordance with this definition, the level of certainty
targeted by the reporting company should result in at least a 90%
probability that the quantities actually recovered will equal or exceed
the estimated reserves. In the case of "Probable" reserves, which are
obviously less certain to be recovered than Proved reserves, NI 51-101
states that it must be equally likely that the actual remaining
quantities recovered will be greater or less than the sum of the
estimated Proved plus Probable reserves. With respect to the
consideration of certainty, in order to report reserves as Proved plus
Probable, the reporting company must believe that there is at least a
50% probability that the quantities actually recovered will equal or
exceed the sum of the estimated Proved plus Probable reserves.

In accordance with NI 51-101, six thousand cubic feet (6 mcf) of natural
gas and one barrel of natural gas liquids (1 bbl NGL) each equal one
barrel of oil equivalent (BOE). This conversion rate is not based on
price or energy content. As such, BOE's may be misleading, particularly
if used in isolation. A BOE
conversion ratio of 6 mcf of natural gas to 1 barrel of crude oil is
based on an energy equivalency conversion method primarily applicable at
the burner tip and does not represent a value equivalency at the
wellhead.

The following table sets forth a reconciliation of light, medium and
heavy crude oil, natural gas, natural gas liquids and barrels of oil
equivalent of the Company Interest Reserves of PrimeWest for the year
ended December 31, 2004 derived from the report of the independent
reserve evaluators, Gilbert Lausten Jung Associated Ltd. (GLJ) using
Consultant's Average Forecast Price and Cost estimates, and reconciled
to December 31, 2003. PrimeWest's Company Interest Reserves include
working interest and royalties receivable. This definition is consistent
with the basis on which Reserves were reported in prior years.



Company Interest Reserves - Consultant's Average Pricing

Light, Medium and Heavy Crude Oil (mbbls)
---------------------------------------------
Proved Total Proved Plus
Producing Proved Probable Probable
---------------------------------------------------------------------
December 31, 2003 18,854.0 19,554.6 3,324.4 22,879.0
Capital additions 680.3 704.9 545.4 1,250.3
Improved Recovery 356.1 329.1 20.1 349.2
Technical Revisions 1,233.5 1,193.9 107.1 1,301.0
Acquisitions 3,033.7 3,306.1 600.4 3,906.5
Dispositions (2,074.3) (2,292.3) (459.4) (2,751.7)
Economic Factors (1) - - - -
Production (3,031.3) (3,031.3) - (3,031.3)
---------------------------------------------------------------------
December 31, 2004 19,052.0 19,765.0 4,138.0 23,903.0
---------------------------------------------------------------------
---------------------------------------------------------------------


Natural Gas (Bcf)
---------------------------------------------
Proved Total Proved Plus
Producing Proved Probable Probable
---------------------------------------------------------------------
December 31, 2003 304.9 343.2 89.0 432.2
Capital additions 10.5 19.8 5.6 25.4
Improved Recovery 11.9 13.2 6.7 19.9
Technical Revisions (6.3) (3.2) (7.7) (10.9)
Acquisitions 194.2 224.7 58.7 283.4
Dispositions (6.6) (10.1) (3.1) (13.2)
Economic Factors (1) (5.0) (5.1) (0.3) (5.4)
Production (53.4) (53.4) - (53.4)
---------------------------------------------------------------------
December 31, 2004 450.2 529.2 148.7 677.9
---------------------------------------------------------------------
---------------------------------------------------------------------


Natural Gas Liquids (mbbls)
---------------------------------------------
Proved Total Proved Plus
Producing Proved Probable Probable
---------------------------------------------------------------------
December 31, 2003 7,798.0 8,975.1 2,887.7 11,862.8
Capital additions 259.1 294.0 61.3 355.3
Improved Recovery 398.3 458.6 311.1 769.7
Technical Revisions (365.4) (243.5) (349.0) (592.5)
Acquisitions 4,838.6 5,706.4 1,406.0 7,112.4
Dispositions (52.3) (65.3) (35.1) (100.4)
Economic Factors (2) - - - -
Production (1,137.3) (1,137.3) - (1,137.3)
---------------------------------------------------------------------
December 31, 2004 11,739.0 13,988.0 4,282.0 18,270.0
---------------------------------------------------------------------
---------------------------------------------------------------------


Barrel of oil equivalent (mmboe)
---------------------------------------------
Proved Total Proved Plus
Producing Proved Probable Probable
---------------------------------------------------------------------
December 31, 2003 77.5 85.7 21.1 106.8
Capital additions 2.7 4.3 1.5 5.8
Improved Recovery 2.7 3.0 1.4 4.4
Technical Revisions (0.2) 0.4 (1.5) (1.1)(1)
Acquisitions 40.3 46.5 11.8 58.3
Dispositions (3.2) (4.0) (1.1) (5.1)
Economic Factors (2) (0.8) (0.9) - (0.9)
Production (13.1) (13.1) - (13.1)
---------------------------------------------------------------------
December 31, 2004 105.8 121.9 33.3 155.2
---------------------------------------------------------------------
---------------------------------------------------------------------
Columns may not add due to rounding

(1) Approximately 0.8 mmboe of this amount is attributable to the
cessation of liquids stripping, resulting in a higher heat
content gas stream.

(2) Economic factors relate to reserves that have been shut-in due
to the EUB gas over bitumen issue. Due to the uncertainty of
their future production these reserves have been removed from the
corporate total.


The following table sets forth a reconciliation of PrimeWest's Net
Reserves for the year ended December 31, 2004 derived from the report of
the independent reserve evaluators, GLJ, using consultant's Average
Forecast Price and Cost estimates. These year-end reserves are
reconciled to December 31, 2003 reserves. PrimeWest's Net Reserves
include working interest reserves plus royalties receivable less
royalties payable, as stipulated by NI 51-101. All data in the following
tables was provided by GLJ.



Net Reserves - Consultant's Average Pricing

Light and Medium Crude Oil (mbbls)
---------------------------------------------
Proved Total Proved Plus
Producing Proved Probable Probable
---------------------------------------------------------------------
December 31, 2003 14,284 14,829 2,504 17,333
Extensions 460 482 427 909
Improved Recovery 312 286 17 303
Technical Revisions 126 5 69 74
Discoveries 82 82 28 110
Acquisitions 2,415 2,602 458 3,060
Dispositions (1,331) (1,417) (454) (1,871)
Economic Factors (1) 268 276 49 325
Production (1,849) (1,849) - (1,849)
---------------------------------------------------------------------
December 31, 2004 14,767 15,296 3,098 18,394
---------------------------------------------------------------------
---------------------------------------------------------------------


Heavy Oil (mbbls)
---------------------------------------------------------------------
Proved Total Proved Plus
Producing Proved Probable Probable
---------------------------------------------------------------------
December 31, 2003 2,856 2,959 435 3,394
Extensions - - - -
Improved Recovery 4 4 1 5
Technical Revisions (40) (1) (14) (15)
Discoveries - - - -
Acquisitions 297 352 74 426
Dispositions (454) (570) (136) (706)
Economic Factors (1) 762 763 143 906
Production (884) (884) - (884)
---------------------------------------------------------------------
December 31, 2004 2,541 2,623 503 3,126
---------------------------------------------------------------------
---------------------------------------------------------------------


Associated and Non-Associated Gas
(Natural Gas) (bcf)
---------------------------------------------------------------------
Proved Total Proved Plus
Producing Proved Probable Probable
---------------------------------------------------------------------
December 31, 2003 240.7 269.9 70.1 339.9
Extensions 7.3 14.9 4.1 19.1
Improved Recovery 9.5 10.6 5.3 15.9
Technical Revisions (0.8) 1.8 (6.1) (4.4)
Discoveries 0.9 1.2 0.4 1.6
Acquisitions 154.5 179.0 46.6 225.6
Dispositions (9.3) (12.1) (2.9) (15.0)
Economic Factors (1) (2.4) (2.6) 0.1 (2.4)
Production (42.2) (42.2) 0.0 (42.2)
---------------------------------------------------------------------
December 31, 2004 358.2 420.4 117.6 538.0
---------------------------------------------------------------------
---------------------------------------------------------------------


Natural Gas Liquids (mbbls)
---------------------------------------------------------------------
Proved Total Proved Plus
Producing Proved Probable Probable
---------------------------------------------------------------------
December 31, 2003 5,570 6,381 2,051 8,433
Extensions 174 205 40 245
Improved Recovery 278 320 214 534
Technical Revisions (305) (189) (259) (448)
Discoveries 3 6 2 8
Acquisitions 3,405 4,021 980 5,001
Dispositions (37) (46) (23) (69)
Economic Factors (1) 20 13 2 15
Production (800) (800) - (800)
---------------------------------------------------------------------
December 31, 2004 8,308 9,911 3,008 12,919
---------------------------------------------------------------------
---------------------------------------------------------------------


Total (mmboe)
---------------------------------------------------------------------
Proved Total Proved Plus
Producing Proved Probable Probable
---------------------------------------------------------------------
December 31, 2003 62.8 69.1 16.7 85.8
Extensions 1.9 3.2 1.2 4.3
Improved Recovery 2.2 2.4 1.1 3.5
Technical Revisions (0.4) 0.1 (1.2) (1.1)(1)
Discoveries 0.2 0.3 0.1 0.4
Acquisitions 31.9 36.8 9.3 46.1
Dispositions (3.4) (4.1) (1.1) (5.2)
Economic Factors (2) 0.6 0.6 0.2 0.8
Production (10.6) (10.6) 0.0 (10.6)
---------------------------------------------------------------------
December 31, 2004 85.3 97.9 26.2 124.1
---------------------------------------------------------------------
---------------------------------------------------------------------
Columns may not add due to rounding

(1) Approximately 0.8 mmboe of this amount is attributable to the
cessation of liquids stripping, resulting in a higher heat
content gas stream.

(2) Economic factors relate to reserves that have been shut-in due to
the EUB gas bitumen issue. Due to the uncertainty of their future
production these reserves have been removed from the corporate
total.


Forecast Prices and Costs

The following tables provide Reserves data and a breakdown of Future Net
Revenue by component and production group using Forecast Prices and
Costs on a Company Interest, Gross and Net basis.



Summary of Oil and Natural Gas Reserves
and Net Present Values of Future Net Revenue
as of December 31, 2004
Forecast Prices and Costs
---------------------------------------------------------------------
RESERVES
----------------------------------------------
Light And Medium
Crude Oil (mbbl) Heavy Oil (mbbl)
----------------------------------------------
Company Company
RESERVES CATEGORY Interest Gross Net Interest Gross Net
---------------------------------------------------------------------
PROVED
Developed Producing 16,272 14,701 14,767 2,780 2,766 2,541
Developed Non-Producing 267 267 249 61 61 54
Undeveloped 354 335 280 32 32 28
---------------------------------------------------------------------
TOTAL PROVED 16,893 15,303 15,296 2,872 2,859 2,623

PROBABLE 3,587 3,295 3,098 551 548 503
---------------------------------------------------------------------
TOTAL PROVED
PLUS PROBABLE 20,480 18,597 18,394 3,423 3,407 3,126
---------------------------------------------------------------------
---------------------------------------------------------------------
Columns may not add due to rounding


---------------------------------------------------------------------
RESERVES
----------------------------------------------
Natural Gas
Natural Gas (Bcf) Liquids (mbbl)
----------------------------------------------
Company Company
RESERVES CATEGORY Interest Gross Net Interest Gross Net
---------------------------------------------------------------------
PROVED
Developed Producing 450.2 440.8 358.2 11,739 11,494 8,308
Developed Non-Producing 38.1 38.0 30.2 1,089 1,089 808
Undeveloped 40.9 40.9 32.0 1,160 1,160 795
---------------------------------------------------------------------
TOTAL PROVED 529.2 519.8 420.4 13,988 13,743 9,911

PROBABLE 148.7 147.3 117.6 4,282 4,243 3,008
---------------------------------------------------------------------
TOTAL PROVED
PLUS PROBABLE 677.9 667.0 538.0 18,270 17,986 12,919
---------------------------------------------------------------------
---------------------------------------------------------------------
Columns may not add due to rounding


---------------------------------------------------------------------
RESERVES
--------------------------------
Total (mboe)
--------------------------------
Company
RESERVES CATEGORY Interest Gross Net
---------------------------------------------------------------------
PROVED
Developed Producing 105,825 102,431 85,316
Developed Non-Producing 7,761 7,753 6,143
Undeveloped 8,368 8,349 6,441
---------------------------------------------------------------------
TOTAL PROVED 121,954 118,533 97,900

PROBABLE 33,208 32,629 26,207
---------------------------------------------------------------------
TOTAL PROVED PLUS PROBABLE 155,162 151,162 124,107
---------------------------------------------------------------------
---------------------------------------------------------------------
Columns may not add due to rounding


---------------------------------------------------------------------
NET PRESENT VALUES OF FUTURE NET REVENUE
---------------------------------------------
BEFORE FUTURE INCOME
TAX EXPENSES DISCOUNTED AT (%)
---------------------------------------------
0% 5% 10% 15% 20%
RESERVES CATEGORY (MM$) (MM$) (MM$) (MM$) (MM$)
---------------------------------------------------------------------
PROVED
Developed Producing 2,263.6 1,655.8 1,331.5 1,129.6 990.8
Developed
Non-Producing 165.2 99.4 71.7 56.6 47.2
Undeveloped 137.5 84.1 56.4 40.0 29.2
---------------------------------------------------------------------
TOTAL PROVED 2,566.2 1,839.3 1,459.6 1,226.1 1,067.2

PROBABLE 731.8 392.1 254.8 184.9 143.3
---------------------------------------------------------------------
TOTAL PROVED
PLUS PROBABLE 3,298.1 2,231.4 1,714.4 1,411.0 1,210.5
---------------------------------------------------------------------
---------------------------------------------------------------------


---------------------------------------------------------------------
NET PRESENT VALUES OF FUTURE NET REVENUE
---------------------------------------------
BEFORE FUTURE INCOME
TAX EXPENSES DISCOUNTED AT (%)
---------------------------------------------
0% 5% 10% 15% 20%
RESERVES CATEGORY (MM$) (MM$) (MM$) (MM$) (MM$)
---------------------------------------------------------------------
PROVED
Developed Producing 2,263.6 1,655.8 1,331.5 1,129.6 990.8
Developed
Non-Producing 165.2 99.4 71.7 56.6 47.2
Undeveloped 137.5 84.1 56.4 40.0 29.2
---------------------------------------------------------------------
TOTAL PROVED 2,566.2 1,839.3 1,459.6 1,226.1 1,067.2

PROBABLE 731.8 392.1 254.8 184.9 143.3
---------------------------------------------------------------------
TOTAL PROVED
PLUS PROBABLE 3,298.1 2,231.4 1,714.4 1,411.0 1,210.5
---------------------------------------------------------------------
---------------------------------------------------------------------
Columns may not add due to rounding


PRODUCTION VOLUMES

2004 2003 Change (%)
---------------------------------------------------------------------
Natural gas (mmcf/day) 145.1 134.1 8
Crude oil (bbls/day) 8,282 8,116 2
Natural gas liquids (bbls/day) 3,107 2,855 9
Total (BOE/day) 35,578 33,316 7
---------------------------------------------------------------------
Gross Overriding Royalty volumes
included above (BOE/day) 1,440 1,604 (10)
---------------------------------------------------------------------
---------------------------------------------------------------------


All production information is reported before the deduction of Crown and
freehold royalties.

The 7% increase in production volumes year-over-year is due to the
acquisition of Seventh Energy and the Calpine assets during the year,
combined with development additions, and offset by asset divestitures
and natural decline. During 2004, approximately 2,900 BOE/day of
annualized incremental production was brought on-line from development
activities to mitigate decline. Approximately 1,900 BOE/day of new
production remained behind pipe at the end of 2004.

The acquisition of the Calpine assets, with current production volumes
of approximately 14,360 BOE/day, added the equivalent of 4,759 BOE/day
to 2004 average daily production volumes. Assets acquired from Seventh
Energy contributed 1,198 BOE/day to 2004 average daily production
volumes.

Production from PrimeWest's non-operated Ells property in Northeast
Alberta was shut-in by the Alberta Energy and Utilities Board effective
July 1, 2004, as a result of the gas over bitumen issue. The gas over
bitumen issue refers to the announcement on June 3, 2003 by the Alberta
Energy and Utilities Board ("EUB") proposing a change in policy
respecting gas production from the Wabiskaw and McMurray formations in
the Athabasca Oil Sands area of Northeastern Alberta. The process
outlined by the EUB resulted in the shut-in of approximately 330 BOE/day
of PrimeWest production. In October 2004, the Government of Alberta
enacted amendments to the Natural Gas Royalty Regulations of 2002
specifically with respect to gas production in the affected area. This
amendment provides for a technical change to the royalty calculation for
gas producers adversely affected by the EUB shut-in orders. This
technical change to the calculation of royalties represents a reduction
in royalties paid by PrimeWest to the Province of Alberta. PrimeWest is
evaluating the change to the royalty calculation and its impact as well
as any further steps to be taken in relation to the gas over bitumen
issue.

An additional shut-in of 300 BOE/day at PrimeWest's non-operated Whiskey
Creek area is as a result of the 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 be mid-2005.

PrimeWest expects production for full year 2005 to be approximately
41,000 BOE/day. This estimate incorporates PrimeWest's expected natural
decline rate and production volume shut-ins, offset by production
additions resulting from the capital development program.



Commodity Prices

Benchmark Prices 2004 2003 Change (%)
---------------------------------------------------------------------
Natural gas
NYMEX (US$/mcf) $ 6.09 $ 5.44 12
AECO (Cdn$/mcf) $ 6.79 $ 6.70 1
Crude oil WTI (US$/bbl) $ 41.40 $ 31.04 33
---------------------------------------------------------------------


Average Realized Sales Prices (1)

(Canadian Dollars) 2004 2003 Change (%)
---------------------------------------------------------------------
Natural gas ($/mcf)(2) $ 6.61 $ 6.05 9
Crude oil ($/bbl) $ 36.83 $ 33.94 9
Natural gas liquids ($/bbl) $ 43.69 $ 35.34 24
---------------------------------------------------------------------
Total Oil Equivalent ($/BOE) $ 39.35 $ 35.63 10
---------------------------------------------------------------------
---------------------------------------------------------------------
Realized hedging loss included
in prices above ($/BOE) $ (2.16) $ (2.51) (14)
---------------------------------------------------------------------
---------------------------------------------------------------------

(1) Includes hedging gains/losses.

(2) Excludes sulphur.


Commodity prices were generally higher in 2004 than in 2003, with the
average realized selling price per BOE of PrimeWest's production
increasing by 10% before hedging impact. The effect of hedging reduced
PrimeWest's 2004 realized price by $2.16/BOE, compared to a reduction of
$2.51/BOE in 2003. The use of financial hedges is designed to reduce the
impact of commodity price volatility and improve the predictability of
cash flow from operations.

The realized Canadian selling price that PrimeWest receives for its oil
production is also impacted by currency exchange rates. Canadian oil
prices are benchmarked in US dollars, therefore a stronger Canadian
dollar translates into lower realized prices and revenue, when measured
in Canadian dollars.

Crude Oil Prices

Crude oil prices rose strongly in 2004, reflecting higher global demand
and continued concerns over supply amidst political uncertainty in a
number of the producing regions around the world. Strong economic growth
in China and India, together with a recovering US economy, has
significantly increased oil consumption and tightened the supply/demand
balance. On the supply side, the anticipated increase in Iraqi export
capability did not occur due to continued violence and sabotage of
production and pipeline infrastructures within the country. With rising
demand, excess production capacity that existed within OPEC was used up,
leaving Saudi Arabia, Kuwait and UAE as the only OPEC members with
surplus capability to increase production quickly to offset any supply
disruptions that may occur in other parts of the world. As a result,
prices fluctuated in response to world events and weather conditions.
During 2004, oil prices increased from US$32.50/Bbl at the beginning of
the year to a historical high of US$55.17/Bbl on October 22, before
dropping back to US$43.45/Bbl by year-end.

As at December 31, 2004, the forward market for crude oil indicated a
gradual lessening of prices over the next 12 months to approximately
US$41.50/Bbl by next year-end. However, prices rebounded once again in
late January 2005, nearing US$50.00/Bbl, reflecting continued market
nervousness with potential supply disruptions. Key factors that could
influence prices in 2005 include: potential for a slow down in demand
growth in Asia in response to higher prices, particularly in China and
India; OPEC's ability to control production to balance supply and demand
at their desired price levels; Iraq's ability to restore oil export
capability; non OPEC production growth and the impact of higher oil
prices on world consumption.

Canadian companies that produce crude oil of a heavier grade will be
required to contend with the widening of the price differential versus
lighter, sweet crude oil. As the majority of the new crude production
brought into the markets is of heavier and sourer quality that requires
special refinery handling capability, the price differential has
increased over the course of 2004. In addition, the realized price for
heavy oil producers has been negatively affected by the large premium
being priced into the cost of diluents, natural gas by-products that are
used to blend heavier crude oil to improve transportability. PrimeWest's
crude oil production consists of 70% light and 30% medium to slightly
heavy grade. The medium and slightly heavy grade oil does not require
any diluent blending and attracts a better pricing differential than the
heavier crude oil production.

Natural Gas Prices

PrimeWest's realized natural gas price increased approximately 3% from a
2003 average of $6.51/mcf to $6.70/mcf during 2004. Industry outlook for
natural gas prices was bullish at the beginning of 2004 as North
American gas storage levels were being drawn down to below historical
averages due to late cold winter weather. Even though gas storage
recovered and exceeded historical levels later in the year, higher crude
oil prices helped sustain gas prices in the summer. However, cool summer
temperatures that reduced electricity demand coupled with mild winter
weather during the latter part of 2004 dampened previously bullish gas
price expectations. North American gas storage levels at 2004 year-end
were higher than the 5-year average. As of December 31, 2004, forward
gas prices had also retracted from previous high levels, with the NYMEX
price increasing only slightly from US$6.15/Mmbtu at 2004 year-end to
US$6.88/Mmbtu by December 2005. However, it should be noted that this
forward price curve is still considerably higher than the forward curve
at 2003 year-end.

Early in 2005, gas prices have partly recovered from the more bearish
view at year end with brief periods of cold weather in many of the US
gas consuming regions. Although gas storage levels remain high by
historical standards, the market will likely accept higher storage
levels going forward as the operating norm for fear of shortages during
extreme weather conditions. A continued buoyant crude oil market should
serve as a support for gas prices. Based on energy equivalent, natural
gas is currently trading at the low end of the price range established
by distillates and fuel oil. With demand remaining strong after
adjusting for weather related factors, the upside potential for gas
price is favourable. Key factors which will influence gas prices in 2005
include: North American weather patterns in the upcoming summer and
winter seasons; the ability of producers in Canada and the US to replace
and add to production levels with increased drilling; the growth of gas
demand in the electricity sector; the impact of government regulations;
and the market response to conservation.



Sales Revenue

Revenue % of % of
($ millions)(2) 2004 total 2003 total Change(%)
---------------------------------------------------------------------
Natural gas (1) $351.0 69 $297.3 68 18
Crude oil 111.7 22 100.5 23 11
Natural gas liquids 49.7 9 36.8 9 35
---------------------------------------------------------------------
Total $512.4 $434.6
---------------------------------------------------------------------
---------------------------------------------------------------------
Hedging loss included above $(28.2) 100 $(30.5) 100 (8)
---------------------------------------------------------------------
---------------------------------------------------------------------

(1) Excludes sulphur.

(2) Net of transportation expense.


Revenues for 2004 were $512.4 million compared to $434.6 million in the
previous year, including the effect of hedging. Higher gas sales volumes
as a result of the Calpine asset and Seventh Energy acquisitions
completed in 2004 along with higher crude oil and natural gas liquids
prices were the major contributors to the increased revenue in 2004.

Based on the forward markets, the overall outlook for commodity prices
in 2005 is lower, and has been reflected in PrimeWest's internal price
forecasts. If the pricing environment softens in 2005, and the Canadian
dollar remains strong, oil and gas revenues will be negatively impacted.
Since a greater portion of PrimeWest's revenue (69%) is derived from
natural gas, the Trust has greater sensitivity to changes in natural gas
prices than crude oil prices.

2004 Hedging Results

As part of our financial management strategy, PrimeWest uses a
consistent commodity hedging approach. The purposes of the hedging
program are to reduce volatility in cash flows, protect acquisition
economics and stabilize cash flow against the unpredictable commodity
price environment. PrimeWest's hedging policy reflects a willingness to
forfeit a portion of the pricing upside in return for protection against
a significant downturn in prices.



Crude Oil Natural Gas BOE
($/bbl) ($/mcf) ($/BOE)(1)
---------------------------------------------------------------------
2004 2003 2004 2003 2004 2003
-----------------------------------------------------
Unhedged price $ 44.46 $ 36.55 $ 6.70 $ 6.51 $ 41.51 $ 38.14
Hedging loss (7.63) (2.61) (0.09) (0.46) (2.16) (2.51)
---------------------------------------------------------------------
Realized price $ 36.83 $ 33.94 $ 6.61 $ 6.05 $ 39.35 $ 35.63
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Excludes sulphur


2004 Hedge Loss 2003 Hedge Loss
---------------------------------------------------------------------
% Hedged $ millions % Hedged $ millions
---------------------------------------------------------------------
Crude oil 58% $ 23.1 65% $ 7.7
Natural gas 54% 5.1 61% 22.8
---------------------------------------------------------------------
Total loss $ 28.2 $ 30.5
---------------------------------------------------------------------
---------------------------------------------------------------------


The table below shows the approximate percentage of future anticipated
production volumes hedged at December 31, 2004, net of anticipated
royalties, reflecting full production declines with no offsetting
additions:




2005 Q1 Q2 Q3 Q4 Full Year
---------------------------------------------------------------------
Crude Oil 72% 68% 47% 41% 57%
Natural Gas 59% 56% 49% 49% 53%
---------------------------------------------------------------------
---------------------------------------------------------------------
2006
---------------------------------------------------------------------
Crude Oil 17% 0% 0% 0% 4%
Natural Gas 35% 0% 0% 0% 9%
---------------------------------------------------------------------
---------------------------------------------------------------------


A summary of hedging contracts in place as at December 31, 2004 is
available under Note 16 in the Notes to the Consolidated Financial
Statements.

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 a result, PrimeWest's derivatives are
marked-to-market with the resulting gain or loss reflected in earnings
for the reporting period.

The 2004 income statement shows an unrealized gain of $0.1 million on
derivatives resulting from the change in the mark-to-market valuation of
the derivative financial instruments during the period. The gain was
comprised of an $8.9 million loss for crude oil hedges, a $9.1 million
gain for natural gas hedges and a $0.1 million loss for electrical power
hedges.

For the year ended December 31, 2004 the cash impact of contracts
settling was a $28.1 million loss comprised of a $23.1 million loss in
crude oil, a $5.1 million loss in natural gas, a $0.8 million gain on
electrical power and a $0.7 million loss in interest rate swaps.

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) and freeholders (individuals or
other companies). 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.



($ millions, except per BOE) 2004 2003 Change (%)
---------------------------------------------------------------------
Royalty expense (net of ARTC) $ 119.8 $ 101.9 18
Per BOE $ 9.20 $ 8.38 10
---------------------------------------------------------------------
Royalties as % of sales revenues
With hedge revenue 23% 24% (4%)
Excluding hedge revenue 22% 22% 0%
---------------------------------------------------------------------
---------------------------------------------------------------------


Royalty expense in 2004 was 18% higher than in 2003 due to higher
revenues year over year. 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 crown royalty system, future changes to
prices will be accompanied by changes in royalty rates and royalty
expense.



Operating Expenses

($ millions, except per BOE) 2004 2003 Change (%)
---------------------------------------------------------------------
Operating expense $ 88.9 $ 79.4 12
Per BOE $ 6.83 $ 6.53 5
---------------------------------------------------------------------
---------------------------------------------------------------------


Operating expenses for 2004 are $9.5 million higher than 2003. A primary
contributor to the increase in operating expense was the increased
production volume from the Seventh Energy and Calpine asset acquisitions
in 2004. On a per BOE basis, operating expenses increased 5% over the
2003 level reflecting the impact on costs of high activity in the
industry.

Operating expenses are primarily impacted by labour and power costs,
which represent approximately 29% of PrimeWest's costs. Other costs that
are difficult to influence, including partner-operated expenses,
property taxes and lease rentals, make up approximately 32% of our
costs. PrimeWest is targeting 2005 operating expenses at approximately
$6.60/BOE.



Operating Margin

($/BOE) 2004 2003 Change (%)
---------------------------------------------------------------------
Sales price and other revenue (1) $ 40.13 $ 36.20 11
Transportation Expense (0.63) (0.68) (7)
Royalties (9.20) (8.38) 10
Operating expenses (6.83) (6.53) 5
---------------------------------------------------------------------
Operating margin $ 23.47 $ 20.61 14
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Includes hedging and sulphur


Operating margins increased 14% from 2003 on a per BOE basis. The
increase in 2004 compared to 2003 is primarily due to higher sales
prices, offset by higher unit operating expenses and higher royalties.
Operating margin measures the level of cash flow per barrel of oil
equivalent at the field level and before head office expenses.

The operating margin for 2005 will be heavily dependent on actual
commodity prices. PrimeWest will continue to emphasize the maintenance
of lower than average operating expenses to maximize margins, which can
reduce the volatility of cash flows through commodity price cycles.



General & Administrative Expense

($ millions, except per BOE) 2004 2003 Change (%)
---------------------------------------------------------------------
Cash G&A expense $ 19.0 $ 14.5 31
Per BOE $ 1.46 $ 1.20 22
Non-cash G&A expense $ 9.4 $ 14.4 (35)
Per BOE $ 0.73 $ 1.19 (39)
---------------------------------------------------------------------
---------------------------------------------------------------------


Cash general and administrative expenses increased $4.5 million over
2003 reflecting higher salaries, higher short-term incentive bonuses,
increased information technology expenditures, one-time consulting costs
associated with potential acquisitions, and increased board of directors
costs. These increases were partially offset by increases in overhead
recoveries.

Included in non-cash G&A expense is $8.5 million relating to the change
in the value of the Unit Appreciation Rights (UARs), granted under the
Long-Term Incentive Plan (LTIP). UARs in a Trust are similar to stock
options in a corporation. The 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 grant. PrimeWest continues to pay for the exercise of UARs in
Trust Units. 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. Also included in non-cash G&A expense is $0.9 million related
to the special employee retention plan. See note 14 to the consolidated
financial statements.



Interest Expense

($ millions, except per Trust Unit) 2004 2003 Change (%)
---------------------------------------------------------------------
Interest expense $ 20.6 $ 15.1 36
Period end net debt level $552.0 $255.9 116
Debt per Trust Unit $ 7.7 $ 5.07 53
---------------------------------------------------------------------
Average cost of debt 4.8% 4.7%
---------------------------------------------------------------------
---------------------------------------------------------------------


Interest expense, representing interest on bank debt, the senior secured
notes, and the convertible unsecured subordinated debentures increased
to $20.6 million from $15.1 million in 2003 due to higher average debt
balances in 2004 compared to 2003. Debt levels increased in the third
quarter of 2004 with the issuance of additional bank debt and the
Convertible Debentures to fund the acquisition of the Calpine assets.

The average cost of debt has increased due to the issuance of the
convertible unsecured subordinated debentures in the third quarter 2004.
The $150 million Series I and $100 million Series II debentures bear
annual interest at 7.5% and 7.75% respectively.

Foreign Exchange Gain

The foreign exchange gain of $11.7 million results from the translation
of the US dollar denominated senior secured notes and related interest
payable. The notes were issued at 1.3923:1 Canadian to US dollars, and
the close rate on December 31, 2004 was 1.2020:1 Canadian to US dollars.

Depletion, Depreciation and Amortization

The 2004 DD&A rate of $15.15/BOE is lower than the 2003 rate of
$16.70/BOE due to the January 1, 2004 ceiling test write down of $309
million offset by the impact of the Calpine asset acquisition.

Ceiling Test

Effective January 1, 2004, PrimeWest adopted CICA Accounting Guideline
16 (AcG-16), "Oil and Gas Accounting - Full Cost".

The guideline is effective for fiscal years beginning on or after
January 1, 2004. The cost impairment test is a two-stage process that is
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 properties
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 $5.90 per Mcf for natural gas and
US$ 29.21 per barrel WTI for crude oil resulted in a before tax
impairment of $308.9 million, and an after tax impairment of $233.3
million. The write down was booked to accumulated income in the first
quarter of 2004.

Performing this test at December 31, 2004, using consultant's average
prices as at January 1, 2005, of AECO $6.79 per mcf for natural gas and
US$ 42.76 per barrel WTI for crude oil results in a ceiling test surplus.

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 was unchanged from
2003 at $0.50 per BOE, which was expected to be sufficient to meet
expenditure requirements for the future. As at December 31, 2004, the
site reclamation fund had a balance of $10.3 million.

The reclamation and abandonment costs incurred for 2004 were $4.6
million, compared to $2.2 million in 2003.

The 2005 contribution rate has been set at $0.50 per BOE.

Asset Retirement Obligation

PrimeWest retroactively 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.

Net Asset Value

Net asset value (NAV) measures the net worth of PrimeWest by subtracting
the value of debt from the estimated economic value of its underlying
assets - primarily crude oil, natural gas and natural gas liquids
reserves. The value placed on these reserves is the pre-tax present
value of future net cash flows, discounted at 10%, as independently
assessed by GLJ as at January 1, 2005. The present value of reserves
reflects provisions for royalties, operating costs, future capital costs
and site reclamation and abandonment costs, but is prior to deductions
for income taxes, interest costs and general and administrative costs.

This calculation is a "snapshot" in time and is heavily dependent upon
future commodity price expectations at the point in time the "snapshot"
is taken. Accordingly, the NAV as at January 1, 2005 may not reflect
fairly the equity market trading value of PrimeWest. It is also
significant to note that NAV reduces as reserves are produced and net
operating cash flow is distributed to unitholders. Value is delivered to
unitholders through such monthly distributions.

The following table sets forth the calculation of NAV:



2004 2003
Consultant's Consultant's
Average Average
---------------------------------------------------------------------
As at December 31
($ millions except per Trust Unit Amounts) 2004 2003
---------------------------------------------------------------------
Assets
PV 10 of future cash flow (1)(3) $ 1,714.4 $ 904.6
Market value of Calpine Trust units 91.0 -
Mark to market value of hedging
contracts 0.1 (0.5)
Unproved lands 103.9 36.0
Reclamation fund 10.3 8.2
---------------------------
1,919.7 948.3
Liabilities
Debt and working capital deficiency (2) (378.5) (255.9)
---------------------------------------------------------------------
Net Asset Value $ 1,541.2 $ 692.4
---------------------------------------------------------------------

---------------------------------------------------------------------
Outstanding Trust Units - millions, diluted 80.5 50.4
NAV per Trust Unit $ 19.15 $ 13.74
---------------------------------------------------------------------
---------------------------------------------------------------------

(1) 100% of Company Interest Proved plus Probable Reserves
(2) Debt excludes Convertible Unsecured Subordinated Debentures
(3) Refer to Summary of Oil and Natural Gas Reserves and Net Present
Values of Future Net Revenue Table under the Section "Reserves
and Production")

2004 2003
Consultant's Consultant's
Pricing Assumptions Average Average
---------------------------------------------------------------------
Edmonton Par Oil - Cdn. $/bbl
2004 - $37.81
2005 $50.37 $34.10
2006 $47.46 $32.79
2007 $43.88 $32.72
2008 $40.89 $32.89
2009 $39.20 -
Spot Gas at AECO-C - Cdn. $/mcf
2004 - $5.90
2005 $6.79 $5.33
2006 $6.52 $4.98
2007 $6.25 $4.95
2008 $5.95 $4.92
2009 $5.79 -
---------------------------------------------------------------------
---------------------------------------------------------------------


The NAV calculation is based on the above reference prices as of
December 31, 2004 and 2003 and is highly sensitive to changes in price
forecasts over time as well as the exchange rate. In addition, the
year-over-year change is impacted by the cash distributions made
throughout the year, which totaled $196.1 million or $3.30 per trust
unit. Also, the NAV calculation assumes a "blow down" scenario whereby
existing reserves are produced without being replaced by acquisitions
and development. A major cornerstone of PrimeWest's strategy is to
replace reserves through accretive acquisitions and capital development.



Income and Capital Taxes

($ millions) 2004 2003 Change (%)
---------------------------------------------------------------------
Income and capital taxes $ 3.3 $ 3.8 (13)
Future income taxes recovery (37.6) (79.9) (53)
---------------------------------------------------------------------
$ (34.3) $ (76.1) (55)
---------------------------------------------------------------------
---------------------------------------------------------------------


The Alberta Government enacted a tax rate reduction of 1% in the first
quarter of 2004, reducing the rate from 12.5% to 11.5% effective April
1, 2004.

During 2003, the Canadian Government enacted Federal income tax changes
for the oil and gas resource sector. The Federal income tax changes
effectively reduced the statutory tax rates for current and future
periods. Specifically, the 100% deductibility of the resource allowance
will be completely phased out by the year 2007. During the same time
frame, Crown charges will become 100% deductible and resource tax rates
will decline from the current 27% to 21%. These tax rate reductions
contributed to the large future tax recovery in 2003.

Cash taxes paid include tax installments for current and prior years and
payments for taxes owing upon the filing of year end tax returns. Cash
taxes paid in 2004 include $1.3 million relating to prior years. Income
and capital tax expense includes the estimate of the current year's
taxes and any adjustments resulting from prior year tax assessments. The
year ending December 31, 2004 includes $0.5 million related to prior
years.



Net Income

($ millions) 2004 2003
---------------------------------------------------------------------
Net Income $ 103.4 $ 95.9
---------------------------------------------------------------------
---------------------------------------------------------------------


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 to the ability of an energy trust to continue to sustain the
monthly distribution of cash 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 foreign exchange gains, depletion, depreciation, and
amortization (DD&A) and future taxes.

Net income of $103.4 million exceeded 2003 net income of $95.9 million
due to higher revenues offset by increased operating expenses,
royalties, general and administrative expenses and lower future tax
recoveries.



Liquidity & Capital Resources

Long-term Debt

($ millions) 2004 2003 Change (%)
---------------------------------------------------------------------

Long-term debt $ 656.3 $ 250.1 162
Working capital deficit/(surplus) (104.3) 5.8 1,898
---------------------------------------------------------------------
Net debt $ 552.0 $ 255.9 116

Market value of Trust Units and
exchangeable shares outstanding (1) 1,877.7 1,380.7 36
---------------------------------------------------------------------
Total capitalization $2,429.7 $1,636.6 48
---------------------------------------------------------------------
Net debt as a % of total
capitalization 23% 16% 44
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Based on December 31 Trust Unit closing price of $26.62 and
exchangeable ratio of 0.50408:1


Long-term debt is comprised of bank credit facilities, senior secured
notes and convertible unsecured subordinated debentures of $264.0
million, $150.3 million and $242.0 million respectively.

PrimeWest had a borrowing base of $625 million at year end 2004. 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 the maximum amount of
Senior Secured Notes of $162.5 million. In addition to amounts
outstanding under the facility, PrimeWest has outstanding letters of
credit in the amount of $4.9 million (2003 - $5.1 million). The credit
facility revolves until June 30, 2005, by which time the lenders will
have conducted their annual borrowing base review.

The Senior Secured Notes in the amount of US$125 million have a final
maturity date of May 7, 2010, and bear interest at 4.19% per annum, with
interest paid semi-annually on November 7 and May 7 of each year. The
Note Purchase Agreement requires PrimeWest to make four annual principal
repayments of US$31,250,000 commencing May 7, 2007.

PrimeWest issued 7.5% (Series I) and 7.75% (Series II) convertible
unsecured subordinated debentures in the third quarter of 2004 for
proceeds of $150.0 million and $100.0 million respectively.

The Series I Debentures pay interest semi-annually on March 31 and
September 30 and have a maturity date of September 30, 2009. The Series
I Debentures are convertible at the option of the holder at a conversion
price of $26.50 per Trust Unit. PrimeWest has the option to redeem the
Series I Debentures at a price of $1,050 per Series I Debenture after
September 30, 2007 and on or before September 30, 2008, and at a price
of $1,025 per Series I Debenture after September 30, 2008 and before
maturity. On redemption or maturity the Trust may elect to satisfy its
obligation to repay the principal by issuing PrimeWest Trust Units.

The Series II Debentures pay interest semi-annually on June 30 and
December 30 and have a maturity date of December 31, 2011. The Series II
Debentures are convertible at the option of the holder at a conversion
price of $26.50 per Trust Unit. PrimeWest has the option to redeem the
Series II Debentures at a price of $1,050 per Series II Debenture after
December 31, 2007 and on or before December 31, 2008, at a price of
$1,025 per Debenture after December 31, 2008 and on or before December
31, 2009 and after December 31, 2009 and before maturity at $1,000 per
Series II Debenture. On redemption or maturity the Trust may elect to
satisfy its obligations to repay the principal by issuing PrimeWest
Trust Units.

PrimeWest has early adopted CICA Handbook Section 3860 - "Financial
Instruments". In accordance with this new section, the Convertible
Unsecured Subordinated Debentures were initially recorded at their fair
value of $147.0 million (Series I) and $94.9 million (Series II). The
difference between the fair value and the issue proceeds of $8.1 million
was recorded in unitholders' equity ($3.0 million Series I and $5.1
million Series II).

Unitholders' Equity

The Trust had 69,886,111 Trust Units outstanding at December 31, 2004
compared to 48,751,883 Trust Units at the end of 2003. In addition,
there were 1,294,391 exchangeable shares (see below) outstanding at year
end, exchangeable into a total of 652,477 Trust Units. The weighted
average number of Trust Units, including those issuable by the exchange
of exchangeable shares, was 59,482,034 Trust Units for 2004 compared to
46,015,519 for 2003.

During 2004, 116,233 Trust Units were issued to employees pursuant to
the LTIP.

In 2004, PrimeWest completed two equity offerings. The first closed on
April 22, 2004 raising net proceeds of $134.9 million on the issuance of
5.4 million Trust Units at $26.30 per Trust Unit. Proceeds were used to
reduce the indebtedness of PrimeWest under its credit facility. The
second offering closed on September 2, 2004 raising net proceeds of
$285.1 million on the issuance of 12.3 million Trust Units at $24.40 per
Trust Unit. Proceeds were used in the acquisition of the Calpine assets.

Under the Distribution Reinvestment Plan (DRIP), in 2004 PrimeWest
issued 268,677 Trust Units for $6.5 million (465,969 Trust Units, $11.4
million in 2003), 1,311,462 Trust Units for $32.0 million pursuant to
the Premium Distribution (PREP) component (134,629 Trust Units, $3.4
million in 2003) and 894,167 Trust Units for $21.5 million pursuant to
the Optional Trust Unit Purchase Plan component (OTUPP) (721,209 Trust
Units, $17.6 million in 2003).

As an alternative to the DRIP component of the Plan, 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 gives Canadian unitholders the chance to reinvest their monthly
distributions at a 5% discount to the volume weighted average market
price of the Trust Units, 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
DRIP and PREP components are mutually exclusive, and participation in
the OTUPP requires enrollment in either the DRIP or PREP.

These plan components benefit the unitholders by offering alternatives
to maximize their investment in PrimeWest, while providing the Trust
with an inexpensive method to raise additional capital. The Trust
expects interest in these plans in 2005 to be similar to 2004. Proceeds
from these plans are used for debt reduction of PrimeWest's credit
facility and to help fund ongoing capital development programs.

For additional information or to join these plans, contact PrimeWest's
Plan Agent, Computershare Trust Company of Canada at 1-800-564-6253 or
visit PrimeWest's website at www.primewestenergy.com.

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 of PrimeWest. Canadian law does not
permit a tax deferral when shares are exchanged for Trust Units.

In 2004, 94,340 exchangeable shares were issued pursuant to the special
employee retention plan. During 2003, 161,717 exchangeable shares were
issued in relation to the termination of the management incentive
program of PrimeWest Management Inc. (see Note 14 in the Consolidated
Financial Statements). The exchangeable shares do not receive cash
distributions. In lieu of receiving cash 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 each month.

At December 31, 2004, there were 1,294,391 exchangeable shares
outstanding. The exchange ratio on the shares was 0.50408:1 Trust Units
for each exchangeable share as at year end.

For purposes of calculating basic per Trust Unit amounts, these
exchangeable shares have been assumed to be 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.

Cash distributions for 2004 were $196.1 million or $3.30 per Trust Unit
representing a payout ratio of approximately 74% versus 2003 amounts of
$192.6 million or $4.32 per Trust Unit representing a payout ratio of
approximately 89%.

Distribution payments to US unitholders are subject to 15% Canadian
withholding tax, which is deducted from the distribution amount prior to
deposit into accounts.

Cash Flow Sensitivities

The table below is designed to provide the directional impact on 2005
annual cash available for distribution per unit (increase/decrease)
depending on changes in the following:



$/Trust Unit (1)
----------------
Crude oil price (US$1.00/bbl WTI increase) 0.04
Natural gas price ($0.10/mcf increase) 0.06
Exchange rate (US$0.01 decrease) 0.03
Interest rate (1% decrease) 0.02
Production (1,000 BOE/day increase) 0.12
---------------------------------------------------------------------
(1) Without the effect of hedging


The figures in this table are provided for directional information only
and are based on the units outstanding as at December 31, 2004. Should
changes to the commodity price, interest rate, exchange rate or
production levels noted above take place, it should not be assumed that
a corresponding change would be made to the distribution level.

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.



As at December 31, 2004 Payments due by period ($ millions)
---------------------------------------------------------------------
Less More
than 1 1-3 4-5 than 5
Total year years years years
---------------------------------------------------------------------
Long-term debt obligations 414.2 - 339.1 75.1 -
Series I and II convertible
unsecured subordinated
debentures 250.0 - - 150.0 100.0
Lease rental obligations 14.7 3.6 10.3 0.8 -
Pipeline transportation
obligations 15.1 7.1 7.6 0.4 -
---------------------------------------------------------------------
Total contractual obligations 694.0 10.7 357.0 226.3 100.0
---------------------------------------------------------------------
---------------------------------------------------------------------


As part of PrimeWest's internalization transaction (see Note 14 in the
Consolidated Financial Statements) PrimeWest agreed to issue 377,360
Exchangeable Shares pursuant to a Special Employee Retention Plan. One
quarter of the Exchangeable Shares were issued to the executive officers
of PrimeWest on November 6, 2004. One third of the remaining
exchangeable shares will be issued on each of the third, fourth and
fifth anniversary of transaction closing, November 6, 2002. As at
December 31, 2004, $0.2 million has been accrued in non-cash general and
administrative expenses related to the Special Employee Retention Plan.

Critical Accounting Estimates

PrimeWest's financial statements have been prepared in accordance with
Canadian generally accepted accounting principles. Certain accounting
policies require that management make appropriate decisions with respect
to the formulation of estimates and assumptions that affect the reported
amounts of assets, liabilities, revenues and expenses. The following
discussion reviews such accounting policies and is included in
Management's Discussion and Analysis to aid the reader in assessing the
critical accounting policies and practices of the Trust and the
likelihood of materially different results being reported. PrimeWest's
management reviews its estimates regularly, but new information and
changed circumstances may result in actual results or changes to
estimated amounts that differ materially from current estimates.

The following assessment of significant accounting policies is not meant
to be exhaustive. The Trust may realize different results from the
application of new accounting standards proposed and/or implemented,
from time to time, by various rule-making bodies.

Proved and Probable Oil and Gas Reserves

Proved oil and gas reserves, as defined by the Canadian Securities
Administrators' National Instrument 51-101 (NI 51-101), are the
estimated quantities of crude oil, natural gas liquids, including
condensate, and natural gas that geological and engineering data
demonstrate with reasonable certainty can be recovered in future years
from known reservoirs under existing economic and operating conditions,
(i.e., prices and costs as of the date the estimate is made).

Proved reserves are those reserves that can be estimated with a high
degree of certainty to be recoverable (i.e. it is likely that the actual
remaining quantities recovered will exceed the estimated proved
reserves). In accordance with this definition, the level of certainty
targeted by the reporting company should result in at least a 90%
probability that the quantities actually recovered will equal or exceed
the estimated proved reserves.

For Probable reserves, which are by definition less certain to be
recovered than Proved reserves, NI 51-101 states that it must be equally
likely that the actual remaining quantities recovered will be greater or
less than the sum of the estimated Proved plus Probable reserves. With
respect to the consideration of certainty, in order to report reserves
as Proved plus Probable, the level of certainty targeted by the
reporting company should result in at least a 50% probability that the
quantities actually recovered will equal or exceed the sum of the
estimated Proved plus Probable reserves.

The oil and gas reserve estimates are made using all available
geological and reservoir data as well as historical production data.
Estimates are reviewed and revised as appropriate. Revisions occur as a
result of changes in prices, costs, fiscal regimes, reservoir
performance or a change in PrimeWest's plans. The effect of changes in
proved oil and gas reserves on the financial results and position of
PrimeWest is described under the heading "Full Cost Accounting for Oil
and Gas Activities".

Full Cost Accounting For Oil and Gas Activities

PrimeWest adopted CICA Accounting Guideline 16 (AcG-16), "Oil and Gas
Accounting - Full Costs" on January 1, 2004. The new guideline modifies
how the ceiling test is performed and requires that cost centers be
tested for recoverability using undiscounted future cash flows from
Proved reserves, which are determined by using forward indexed prices.
When the carrying amount of a cost center is not recoverable, the cost
center must be written down to its fair value. Fair value is estimated
using accepted present value techniques that incorporate risks and other
uncertainties when determining expected cash flows.

Depletion Expense

PrimeWest uses the full cost method of accounting for exploration and
development activities. In accordance with this method of accounting,
all costs associated with exploration and development be capitalized
whether successful or not. The aggregate of net capitalized costs and
estimated future development costs less estimated salvage values is
amortized using the unit of production method based on estimated Proved
oil and gas reserves. An increase in estimated proved oil and gas
reserves would result in a corresponding reduction in depletion expense.
A decrease in estimated future development costs would result in a
corresponding reduction in depletion expense.

Fair Value of Derivative Instruments

As part of its financial management strategy, PrimeWest utilizes
financial derivatives to manage market risk. The purpose of the hedge is
to provide an element of stability to PrimeWest's cash flow in a
volatile commodity price environment. Effective January 1, 2004,
PrimeWest adopted CICA Accounting Guideline 13, "Hedging Relationships"
("AcG-13").

The estimation of the fair value of certain hedging derivatives requires
considerable judgment. The estimation of the fair value of commodity
price hedges requires sophisticated financial models that incorporate
forward price and volatility data and, which when compared with
PrimeWest's outstanding hedging contracts, produce cash inflow or
outflow variances over the contract period.

Asset Retirement Obligations

Effective January 1, 2004, PrimeWest changed its accounting policy with
respect to accounting for asset retirement obligations. CICA section
3110 requires the fair value of asset retirement obligations to be
recorded when they are incurred rather than merely accumulated or
accrued over the useful life of the respective asset.

PrimeWest, under the current policy, is required to provide for future
removal and site restoration costs. PrimeWest must estimate these costs
in accordance with existing laws, contracts or other policies. These
estimated costs are charged to earnings and the appropriate liability
account over the expected service life of the asset.

Legal, Environmental Remediation and Other Contingent Matters

The Trust is required to both determine whether a loss is probable based
on judgment and interpretation of laws and regulations and whether that
loss can reasonably be estimated. When the loss is determined, it is
charged to earnings. PrimeWest's management must continually monitor
known and potential contingent matters and make appropriate provisions
through charges to earnings when warranted by circumstance.

Income Tax Accounting

The determination of the Trust's income and other tax liabilities
requires interpretation of complex laws and regulations. All tax filings
are subject to audit and potential reassessment after the lapse of
considerable time. Accordingly, the actual income tax liability may
differ significantly from that estimated and recorded by management.

Business Combinations

Since inception, PrimeWest has grown considerably through combining with
other businesses. PrimeWest acquired Seventh Energy Ltd. in the first
quarter of 2004 and the assets of Calpine Canada in the third quarter of
2004. These transactions were accounted for using what is now the only
accounting method available, the purchase method. Under the purchase
method, the acquiring company includes the fair value of the assets of
the acquired entity on its balance sheet. The determination of fair
value necessarily involves many assumptions. The valuation of oil and
gas properties primarily involves placing a value on the oil and gas
reserves. The valuation of oil and gas reserves entails the process
described above under the caption "Proved and Probable Oil and Gas
Reserves" but also incorporates the use of economic forecasts that
estimate future changes in prices and costs. This methodology is also
used to value unproved oil and gas reserves. The valuation of these
reserves, by their nature, is less certain than the valuation of Proved
reserves.

Goodwill

The process of accounting for the purchase of a company, described
above, results in recognizing the fair value of the acquired company's
assets on the balance sheet of the acquiring company. Any excess of the
purchase price over fair value is recorded as goodwill. Since goodwill
results from the culmination of a process that is inherently imprecise,
the determination of goodwill is also imprecise. In accordance with the
recent issuance of CICA section 3062, "Goodwill and Other Intangible
Assets", goodwill is no longer amortized but assessed periodically for
impairment. The process of assessing goodwill for impairment necessarily
requires PrimeWest to determine the fair value of its assets and
liabilities. Such a process involves considerable judgment.

Recent Accounting Pronouncements Issued But Not Implemented

The following new or amended standards and guidelines were issued but
not implemented by PrimeWest.

Exchangeable Share Accounting

In January 2005 the CICA issued EIC 151 "Exchangeable Securities Issued
by Subsidiaries of Income Trusts." The EIC deals with the presentation
of exchangeable securities on the balance sheet. The EIC states that
exchangeable securities should be included as part of unitholders'
equity only if the holders of the exchangeable securities are entitled
to receive distributions of earnings economically equivalent to
distributions received by units of the income trust and if the
exchangeable securities ultimately are required to be exchanged for
units of the income trust as a result of the passage of a fixed period
of time. The Trust has reviewed the impact of the pronouncement and
determined that it does not materially impact the financial statements.

Variable Interest Entities

In June 2003 the CICA issued Accounting Guideline 15 "Consolidation of
Variable Interest Entities" which deals with the consolidation of
entities that are subject to control on a basis other than ownership of
voting interests. This guideline is effective for annual and interim
periods beginning on or after November 1, 2004. The Trust has determined
that this new guideline is not applicable based on the current structure
of the Trust and therefore will have no impact on the financial
statements of the Trust.

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 US;

- weather conditions that influence the demand for natural gas and
heating oil;

- the Canadian/US exchange rate that affects the price received for
crude oil as the price of crude oil is referenced in US dollars;

- transportation availability and costs; and

- price differentials between 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
counter-parties and limiting exposure to each counter party. In 2004,
approximately 25% of natural gas production was sold to aggregators and
75% 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 2004, PrimeWest recognized a
commodity hedging loss of $28.2 million ($0.45 per Trust Unit), compared
to a loss of $30.5 million ($0.66 per Trust Unit) in 2003.

Operational And Other Business Risks

PrimeWest is exposed to a number of risks related to its activities
within the oil and gas industry that also have an impact on the amount
of cash available to unitholders. These risks, and the ways in which
PrimeWest seeks to mitigate these risks include, but are not limited to:

Risk:

Production

Risk associated with the production of oil and gas - includes well
operations, processing and the physical delivery of commodities to
market.

We mitigate by:

Performing regular and proactive protective well, facility and pipeline
maintenance supported by telemetry, physical inspection and diagnostic
tools.

Commodity Price

Fluctuations in natural gas, crude oil and natural gas liquid prices.

We mitigate by:

Hedging. Refer to page 21 of this MD&A.

Transportation

Market risk related to the availability of transportation to market and
potential disruption in delivery systems.

We mitigate by:

Diversifying the transportation systems on which we rely to get our
product to market.

Natural decline

Development risk associated with capital enhancement activities
undertaken - the risk that capital spending on activities such as
drilling, well completions, well workovers and other capital activities
will not result in reserve additions or in quantities sufficient to
replace annual production declines.

We mitigate by:

Diversifying our capital spending program over a large number of
projects so that large amounts of capital are not risked on any one
activity. We also have a highly skilled technical team of geologists,
geophysicists and engineers working to apply the latest technology in
planning and executing capital programs. Capital is spent only after
strict economic criteria for production and reserve additions are
assessed.

Acquisitions

Acquisition risk associated with acquiring producing properties at low
cost to renew our inventory of assets.

We mitigate by:

Continually scanning the marketplace for opportunities to acquire
assets. Our technical 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 quantity and quality of recoverable
reserves.

We mitigate by:

Contracting our reserves evaluation to a reputable third party
consultant, GLJ. The Operations and Reserves Committee of the Board of
Directors of 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 risks associated with oil and gas
properties and facilities.

We mitigate by:

Establishing and adhering to strict guidelines for EH&S 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, which acts as PrimeWest's Environmental, Health
and Safety Committee.

Regulation, Tax and Royalties

Changes in government regulations including reporting requirements,
income tax laws, operating practices and environmental protection
requirements and royalty rates.

We mitigate by:

Keeping informed of proposed changes in regulations and laws to properly
respond to and plan for the effects that these changes may have on our
operations.

Liability to unitholders is uncertain

Because of uncertainties in the law relating to investment trusts, there
is a risk that a Unitholder could be held personally liable for
obligations of the Trust.

Mitigated by:

On July 1, 2004 a new statute entitled the Income Trusts Liability Act
(Alberta) was proclaimed in force, creating a statutory limitation on
the liability of unitholders of Alberta income trusts such as PrimeWest.
The legislation provides that a Unitholder is not, as a 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.

Income Taxes - Unitholders - 2004

For the 2004 taxation year, Canadian unitholders of PrimeWest were paid
$3.30 Canadian per Trust Unit in distributions. Of this distribution
amount, 45% or $1.49 per Trust Unit is deemed a tax deferred return of
capital, and 55% or $1.81 per Trust Unit is taxable to unitholders as
other income (taxed at the same rate as interest income).

For unitholders resident in the United States, the taxability of
distributions is calculated using US tax rules which allow for the
deduction of crown royalties and accounting based depletion. As a result
of these deductions, distributions are taxable as dividends and 45% of
the 2004 distributions are taxable as a "qualified dividend" with the
remaining 55% treated as a tax-deferred return of capital. A 15%
withholding tax applies to distributions paid to US unitholders. Further
details regarding the withholding tax is available on PrimeWest's
website at www.primewestenergy.com.

For both Canadian and United States unitholders, the tax deferred return
of capital portion reduces the unitholders' adjusted cost base for
purposes of calculating a capital gain or loss upon ultimate disposition
of their Trust Units. Unitholders contemplating a disposition may wish
to consult the "Unitholder Info" section on PrimeWest's website and use
the adjusted cost base calculator.



Quarterly Performance - Selected Measures

---------------------------------------------------------------------
($ millions,
except per 2004 2003 2002
Trust Unit --------------------------------------------------------
amounts) Q4 Q3 Q2 Q1 Q4 Q3 Q2 Q1 Q4
---------------------------------------------------------------------
Net
Revenues 126.8 97.2 84.9 85.7 73.0 77.3 85.6 94.0 68.8
Net Income 40.6 20.2 22.4 20.1 0.7 8.8 63.0 23.4 (7.3)
Net Income
Per Unit
- Basic 0.57 0.31 0.41 0.40 0.01 0.19 1.38 0.56 (0.20)
Net Income
Per Unit
- Diluted 0.56 0.31 0.40 0.40 0.01 0.19 1.37 0.55 (0.20)
---------------------------------------------------------------------
---------------------------------------------------------------------


The above table highlights PrimeWest's performance by selected measures
for the fourth quarter ended 2004, and the preceding eight quarters
through 2003 and 2002.

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 such as depletion, depreciation and amortization (DD&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.

Questions

PrimeWest Energy Trust welcomes questions from unitholders and potential
investors; call Investor Relations at 403-234-6600 or toll-free in
Canada and the US at 1-877-968-7878; or visit us on the Internet at our
website, www.primewestenergy.com. We make every effort to reply within 2
business days, but during periods of heavy call volume, our response
time may increase.



Don Garner
President and Chief Executive Officer

February 24, 2005



Consolidated Balance Sheets
As at December 31 2003
(millions of dollars) 2004 (restated)
---------------------------------------------------------------------
ASSETS
Current assets
Cash and cash equivalents $ 54.4 $ 2.5
Marketable securities (note 4) 68.6 -
Accounts receivable 96.9 65.4
Assets held for sale (note 6) 5.4 -
Prepaid expenses 10.9 6.5
Inventory 5.8 2.1
---------------------------------------------------------------------
242.0 76.5

Cash reserved for site restoration
and reclamation (note 10) 10.3 8.2
Other assets and deferred charges
(note 7) 10.9 1.5
Derivative asset (note 16) 0.6 -
Property, plant and equipment
(note 6) 1,908.6 1,548.2
Goodwill (note 5) 68.5 56.1
---------------------------------------------------------------------
$ 2,240.9 $ 1,690.5
---------------------------------------------------------------------
---------------------------------------------------------------------
LIABILITIES AND UNITHOLDERS' EQUITY
Current liabilities
Accounts payable $ 47.7 $ 26.7
Accrued liabilities 72.3 45.3
Derivative liability (note 16) 0.5 -
Accrued distributions to unitholders 17.7 10.3
---------------------------------------------------------------------
138.2 82.3
Long-term debt (note 8) 656.3 250.1
Future income taxes (note 5) 211.2 313.2
Asset retirement obligation (note 9) 40.3 19.7
---------------------------------------------------------------------
1,046.0 665.3

UNITHOLDERS' EQUITY
Net capital contributions (note 11) 2,049.9 1,565.9
Capital issued but not distributed 3.3 5.2
Convertible unsecured subordinated
debentures (note 8) 8.1 -
Long-term incentive plan equity
(note 12) 20.1 14.6
Accumulated income 89.2 219.1
Accumulated cash distributions (967.7) (771.6)
Accumulated dividends (8.0) (8.0)
---------------------------------------------------------------------
1,194.9 1,025.2
---------------------------------------------------------------------
$ 2,240.9 $ 1,690.5
---------------------------------------------------------------------
---------------------------------------------------------------------
Commitments and Contingencies (Note 17)
The accompanying notes form an integral part of these financial
statements.



Consolidated Statements of Unitholders' Equity

For the years ended December 31 2003 2002
(millions of dollars) 2004 (restated) (restated)
---------------------------------------------------------------------
Unitholders' equity,
beginning of year $ 1,025.2 $ 847.1 $ 856.3
Adjustment to unitholder's
equity at beginning of
period to adopt:

New asset retirement
obligation - - 1.2
New oil and gas accounting
standard (233.3) - -
Net income for the year 103.4 95.9 (0.6)
Net capital contributions 484.0 265.9 147.4
Capital issued but not
distributed (1.9) 4.3 (0.1)
Convertible unsecured
subordinated debentures 8.1 - -
Long-term incentive plan equity 5.5 4.6 2.1
Cash distributions (196.1) (192.6) (158.0)
Dividends - - (1.2)
---------------------------------------------------------------------
Unitholders' equity,
end of year $ 1,194.9 $ 1,025.2 $ 847.1
---------------------------------------------------------------------
---------------------------------------------------------------------



Consolidated Statements of Cash Flow
For the years ended December 31 2003 2002
(millions of dollars) 2004 (restated) (restated)
---------------------------------------------------------------------
OPERATING ACTIVITIES
Net income for the year $ 103.4 $ 95.9 $ (0.6)
Add/(deduct):
Items not involving cash
from operations
Depletion, depreciation
and amortization 197.3 197.4 183.2
Non-cash general &
administrative 9.4 14.4 6.1
Non-cash foreign exchange gain (11.9) (12.1) -
Cash distributions from
marketable securities 4.1 - -
Non-cash management fees - - 1.4
Non-cash internalization - - 13.1
Unrealized gain on derivatives (0.1) - -
Future income taxes recovery (37.6) (79.9) (33.2)
Accretion on asset retirement
obligation 2.0 1.2 0.9
Other non-cash items 0.2 (0.3) -
---------------------------------------------------------------------
Cash flow from operations 266.8 216.6 170.9
Expenditures on site
restoration and reclamation (4.6) (2.2) (3.9)
Change in non-cash working
capital 11.9 5.3 (10.7)
---------------------------------------------------------------------
$ 274.1 $ 219.7 $ 156.3
---------------------------------------------------------------------
FINANCING ACTIVITIES
Proceeds from issue of Trust
Units (net of costs) $ 441.0 $ 240.3 $ 118.3
Proceeds from issue of
debentures 250.0 - -
Net cash distributions
to unitholders (note 13) (159.6) (172.5) (145.1)
Dividends - - (1.2)
Increase (decrease) in bank
credit facilities 166.0 (137.0) 29.9
Increase in senior secured
notes - 174.0 -
Increase in deferred charges (10.0) (1.5) -
Change in non-cash working
capital 10.9 (3.6) 1.0
---------------------------------------------------------------------
$ 698.3 $ 99.7 $ 2.9
---------------------------------------------------------------------
INVESTING ACTIVITIES
Expenditures on property,
plant & equipment $ (129.7) $ (105.8) $ (69.1)
Acquisition of
capital/corporate assets (807.4) (210.1) (59.6)
Proceeds on disposal of
property, plant & equipment 96.5 2.3 4.5
Investment in marketable
securities (72.7) - -
(Increase) decrease in cash
reserved for future site
restoration and reclamation (2.1) (6.6) 0.7
Expenditures on future
acquisitions - - (14.1)
Change in non-cash working
capital (5.1) 6.4 (10.1)
---------------------------------------------------------------------
$ (920.5) $ (313.8) $ (147.7)
---------------------------------------------------------------------
INCREASE IN CASH FOR THE YEAR $ 51.9 $ 5.6 $ 11.5
CASH (BANK OVERDRAFT)
BEGINNING OF THE YEAR 2.5 (3.1) (14.6)
---------------------------------------------------------------------
CASH (BANK OVERDRAFT)
END OF THE YEAR $ 54.4 $ 2.5 $ (3.1)
---------------------------------------------------------------------
---------------------------------------------------------------------
CASH INTEREST PAID $ 15.0 $ 13.1 $ 10.3
---------------------------------------------------------------------
---------------------------------------------------------------------
CASH TAXES PAID $ 3.8 $ 3.9 $ 4.0
---------------------------------------------------------------------
---------------------------------------------------------------------


Consolidated Statements of Income
For the years ended December 31
(millions of dollars except 2003 2002
per Trust Unit amounts) 2004 (restated) (restated)
---------------------------------------------------------------------
REVENUES
Sales of crude oil, natural gas
and natural gas liquids $ 521.9 $ 442.9 $ 326.8
Transportation expenses (8.2) (8.3) (6.3)
Crown and other royalties,
net of ARTC (119.8) (101.9) (56.5)
Unrealized gain on derivatives 0.1 - -
Other income 0.6 (2.8) 0.3
---------------------------------------------------------------------
394.6 329.9 264.3
---------------------------------------------------------------------
EXPENSES
Operating 88.9 79.4 60.8
Cash general and administrative 19.0 14.5 11.3
Non-cash general and
administrative 9.4 14.4 6.1
Interest 20.6 15.1 10.8
Depletion, depreciation
and amortization 197.3 197.4 183.2
Cash management fees (note 14) - - 4.0
Cash internalization costs - - 3.6
Non-cash management fees (note 14) - - 1.4
Non-cash internalization costs
(note 14) - - 13.1
Accretion on asset retirement
obligation 2.0 1.2 0.9
Foreign exchange gain (11.7) (11.9) -
---------------------------------------------------------------------
325.5 310.1 295.2
---------------------------------------------------------------------
Income (loss) before taxes for
the year 69.1 19.8 (30.9)
---------------------------------------------------------------------
Income and capital taxes 3.3 3.8 2.9
Future income taxes recovery
(note 15) (37.6) (79.9) (33.2)
---------------------------------------------------------------------
(34.3) (76.1) (30.3)
---------------------------------------------------------------------
Net income for the year $ 103.4 $ 95.9 $ (0.6)
---------------------------------------------------------------------
---------------------------------------------------------------------
Net income per Trust Unit $ 1.74 $ 2.08 $ (0.02)
Diluted net income per
Trust Unit $ 1.74 $ 2.07 $ (0.02)
---------------------------------------------------------------------
---------------------------------------------------------------------


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(all amounts are expressed in millions of Canadian dollars unless
otherwise indicated)

1. Structure Of The Trust

PrimeWest Energy Trust (the Trust) is an open-ended investment trust
formed under the laws of Alberta in accordance with a declaration of
trust dated August 2, 1996, as Amended. The beneficiaries of the Trust
are the holders of Trust Units (the unitholders).

The principal undertaking of the Trust's operating companies, PrimeWest
Energy Inc. and PrimeWest Gas Corp. (collectively referred to as
PrimeWest), is to acquire and hold, directly and indirectly, interests
in oil and gas properties. One of the Trust's primary assets is a
royalty entitling it to receive 99% of the net cash flow generated by
the oil and gas interests owned by PrimeWest. The royalty acquired by
the Trust effectively transfers substantially all of the economic
interest in the properties to the Trust.

The common shares of PrimeWest Energy Inc. are 100% owned by the Trust.
PrimeWest Gas Corp. is a wholly owned subsidiary of PrimeWest Energy Inc.

On November 4, 2002, unitholders voted, by a 92% majority, to
internalize management. PrimeWest Management Inc. and its shareholders
received a total of $26.3 million in connection with that transaction.
Approximately $13.2 million related to the acquisition of the 1%
retained royalty and was recorded as an acquisition in property, plant
and equipment. The balance was charged to non-cash internalization
expense. In addition, retention provisions for senior management to
receive 94,340 exchangeable shares on each of the second, third, fourth
and fifth anniversaries of the completion of the internalization
transaction were agreed to and $1.5 million was accrued relating to the
termination of the management incentive program (see Note 14).

2. Accounting Policies

Consolidation

These consolidated financial statements include the accounts of the
Trust and its wholly-owned subsidiaries, PrimeWest Energy Inc. and
PrimeWest Gas Corp. The Trust, through the royalty, obtains
substantially all of the economic benefits of the operations of
PrimeWest.

Cash And Cash Equivalents

Short-term investments, with maturities less than three months at the
date of acquisition, are considered to be cash equivalents and are
recorded at cost, which approximates market value.

Marketable Securities

Marketable securities are carried at the lower of cost or market.

Inventory

Inventory is measured at lower of cost and net realizable value.

Goodwill

Goodwill represents the excess of purchase price over fair value of net
assets acquired and liabilities assumed. Goodwill is assessed for
impairment at least annually. To assess impairment, the fair value of
each reporting unit is determined and compared to the book value of the
reporting unit. The amount of the impairment is determined by deducting
the fair value of the reporting unit's assets and liabilities from the
fair value of the reporting unit to determine the implied fair value of
goodwill and comparing that amount to the book value of the reporting
unit's goodwill. Any excess of the book value of goodwill over the
implied fair value of goodwill is the impairment amount.

Property, Plant And Equipment

PrimeWest follows the full cost method of accounting. All costs of
acquiring oil and gas properties and related development costs are
capitalized and accumulated in one cost centre. Maintenance and repairs
are charged against earnings. Renewals and enhancements that extend the
economic life of the capital asset are capitalized.

Gains and losses are not recognized on disposition of oil and gas
properties unless that disposition would alter the rate of depletion by
20% or more.

i) Ceiling test

PrimeWest places a limit on the aggregate cost of capital assets that
may be carried forward for depletion against net revenues of future
periods (the ceiling test). The ceiling test is an impairment test
whereby the carrying amount of capitalized assets is compared to the
undiscounted cash flows from Proved reserves plus Unproved properties
using management's best estimate of future prices. If the asset value
exceeds the undiscounted cash flows the impairment is measured as the
amount by which the carrying amount of the capitalized asset exceeds the
future discounted cash flows from Proved plus Probable reserves. The
discount rate used is the risk free rate.

ii) Asset retirement obligation

PrimeWest recognizes the future retirement obligations associated with
the retirement of property, plant and equipment. The obligations are
initially measured at fair value and subsequently adjusted for accretion
of discount and changes in the underlying liability. The asset
retirement cost is capitalized to the related asset and amortized to
earnings over time.

iii) Depletion, depreciation and amortization

Provision for depletion and depreciation is calculated on the
unit-of-production method, based on Proved reserves before royalties.
Reserves are estimated by independent petroleum engineers. Reserves are
converted to equivalent units on the basis of approximate relative
energy content. Depreciation and amortization of head office furniture
and equipment is provided for at rates ranging from 10% to 30%.

Joint Venture Accounting

PrimeWest conducts substantially all of its oil and gas production
activities through joint ventures, and the accounts reflect only
PrimeWest's proportionate interest in such activities.

Long-Term Incentive Plan

Liabilities under the Trust's Long-term Incentive Plan are estimated at
each balance sheet date, based on the amount of Unit Appreciation Rights
that are in the money using the unit price as at that date. Expenses are
recorded through non-cash general and administrative costs, with an
offsetting amount in long-term incentive plan equity. As Trust Units are
issued under the plan, the exercise value is recorded in net capital
contributions.

Income Taxes

The Trust is considered an inter-vivos trust for income tax purposes. As
such, the Trust is subject to tax on any taxable income that is not
allocated to the unitholders. Periodically, current taxes may be payable
by PrimeWest, depending upon the timing of income tax deductions. Should
these taxes prove to be unrecoverable, they will be deducted from
royalty income in accordance with the royalty agreement.

Future income taxes are recorded for PrimeWest using the liability
method of accounting. Future income taxes are recorded to the extent
that the carrying value of PrimeWest's capital assets exceeds the
available tax pools.

Financial Instruments

PrimeWest uses financial instruments to manage its exposure to
fluctuations in commodity prices and interest rates. PrimeWest does not
use financial instruments for speculative trading purposes. The
financial instruments are marked- to-market with the resulting gain or
loss reflected in earnings for the reporting period.

Measurement Uncertainty

Certain items recognized in the financial statements are subject to
measurement uncertainty. The recognized amounts of such items are based
on PrimeWest's best information and judgment. Such amounts are not
expected to change materially in the near term. They include the amounts
recorded for depletion, depreciation and future site restoration costs
which depend on estimates of oil and gas reserves or the economic lives
and future cash flows from related assets.

3. Changes in Accounting Policies

Full Cost Accounting

The adoption of AcG-16 modifies how the ceiling test is performed
resulting in a two stage process. 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 properties 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.

PrimeWest has performed the ceiling test under AcG-16 as of January 1,
2004. The impairment test was calculated using the consultant's average
prices at January 1 for the years 2004 to 2008 as follows:



Consultant's Average Price Forecasts Year
---------------------------------------------------------------------
2004 2005 2006 2007 2008
-----------------------------------
WTI (US$/bbl) 29.21 26.43 25.42 25.38 25.51
AECO ($Cdn/mcf) 5.90 5.33 4.98 4.95 4.92
---------------------------------------------------------------------
---------------------------------------------------------------------


The ceiling test resulted in a before tax impairment of $308.9 million
and an after tax impairment of $233.3 million. This write down was
recorded to accumulated income in the first quarter of 2004 with the
adoption of AcG-16.

Asset Retirement Obligation

Effective January 1, 2004, the Trust retroactively adopted the CICA
Handbook section 3110, "Asset Retirement Obligations". The new standard
requires the recognition of the liability associated with the future
site reclamation costs of tangible long-lived assets. This liability
would be comprised of the Trust's net ownership interest in producing
wells and processing plant facilities. The liability for future
retirement obligations is to be recorded in the financial statements at
the time the liability is incurred.

The asset retirement obligation is initially recorded at the estimated
fair value as a long-term liability with a corresponding increase to
property, plant and equipment. The depreciation of property, plant and
equipment is allocated to expense on the unit-of-production basis. The
liability is increased each reporting period for the fair value of any
new future site reclamation costs and the corresponding accretion on the
original provision. The accretion is charged to earnings in the period
incurred. The provision will also be revised for any changes to timing
related to cash flows or undiscounted reclamation costs. Actual
expenditures incurred for the purpose of site reclamation are charged to
the asset retirement obligation to the extent that the liability exists
on the balance sheet. Differences between the actual costs incurred and
the fair value of the liability recorded are recognized to earnings in
the period incurred.

The adoption of CICA Handbook section 3110 allows for the cumulative
effect of the change in accounting policy to be recorded to accumulated
income with retroactive restatement of prior period comparatives. At
January 1, 2004, this resulted in an increase to the asset retirement
obligation of $19.7 million (2003 - $15.3 million, 2002 - $11.8
million), an increase to PP&E of $10.6 million (2003 - $9.0 million,
2002 $7.7 million), a $5.6 million (2003 - $0.04 million, 2002 - $1.2
million) increase to accumulated income, a decrease of site restoration
provision of $17.8 million (2003 - $6.2 million, 2002 - $6.1 million)
and an increase to the future tax liability of $3.1 million (2003 -
$(0.03) million, 2002 - $0.9 million). See Note 10 for the
reconciliation of the asset retirement obligation.

Implementation of this accounting standard did not affect the Trust's
cash flow or liquidity.

Financial Derivatives

Effective January 1, 2004, the Trust has implemented CICA Accounting
Guideline (AcG-13), "Hedging Relationships", which is 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
established 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 position hedges with derivatives. The
trust is not applying hedge accounting to its hedging relationships.

As of January 1, 2004, the Trust recorded $6.0 million for the
mark-to-market value of the outstanding hedges as a derivative liability
and a $6.0 million deferred derivative loss, to be realized upon
settlement of the corresponding derivative instrument. The deferred loss
at January 1, 2004 was comprised of a $3.9 million loss for crude oil,
$2.1 million loss for natural gas, $0.6 million loss for interest rate
swaps and a gain of $0.6 million for electrical power.



4. Marketable Securities

($ millions) 2004 2003
-------------------
Investment in Calpine Natural Gas Trust $ 68.6 $ --
---------------------------------------------------------------------
---------------------------------------------------------------------


As at December 31, 2004, PrimeWest had a 25% ownership in Calpine
Natural Gas Trust. The investment is accounted for using the cost
method. The market value of the investment at December 31, 2004 is $91.0
million.

5. Acquisitions

a) On September 2, 2004, PrimeWest Gas Corp. acquired oil and gas assets
from Calpine Canada. The acquisition was accounted for using the
purchase method of accounting with the net assets acquired and
consideration paid as follows:



Net Assets Acquired
at Assigned Values ($ millions) Consideration Paid ($ millions)
---------------------------------------------------------------------
Petroleum and natural
gas assets $ 746.9
Inventory 4.2 Cash $ 747.0
Working capital 2.9 Net closing adjustments (10.3)
Asset Retirement Obligation (12.0) Costs associated
with acquisition 5.3
---------------------------------------------------------------------
$ 742.0 $ 742.0
---------------------------------------------------------------------
---------------------------------------------------------------------


b) On March 16, 2004, PrimeWest Gas Corp. completed the acquisition of
Seventh Energy Ltd. Subsequent to the acquisition, Seventh Energy was
amalgamated with PrimeWest Gas Corp. The acquisition was accounted for
using the purchase method of accounting with net assets acquired and
consideration paid as follows:



Net Assets Acquired
at Assigned Values ($ millions) Consideration Paid ($ millions)
---------------------------------------------------------------------
Petroleum and natural
gas assets $ 46.5
Goodwill 12.4
Working capital (2.5)
Long-term debt assumed (9.9)
Office lease obligation (0.1)
Asset retirement obligation (0.5) Cash $ 34.6
Future income taxes (11.1) Costs associated
with acquisition 0.2
---------------------------------------------------------------------
$ 34.8 $ 34.8
---------------------------------------------------------------------
---------------------------------------------------------------------


c) On January 23, 2003, PrimeWest Gas Inc. completed the acquisition of
two private Canadian oil and gas companies. Subsequent to the
transaction, PrimeWest Gas Inc. was wound up into PrimeWest Energy Inc.
The acquired companies were amalgamated with PrimeWest Gas Corp. The
acquisition was accounted for using the purchase method of accounting
with net assets acquired and consideration paid as follows:



Net Assets Acquired
at Assigned Values ($ millions) Consideration Paid ($ millions)
---------------------------------------------------------------------
Petroleum and natural
gas assets $ 220.9
Goodwill 56.1
Working capital,
including cash of $3.9 0.7
Site restoration provision (5.4) Cash $ 212.7
Future income taxes (53.2) Costs associated
with acquisition 6.4
---------------------------------------------------------------------
$ 219.1 $ 219.1
---------------------------------------------------------------------
---------------------------------------------------------------------

6. Property, Plant and Equipment

2004
---------------------------------------------------------------------
Accumulated depletion
depreciation and
($ millions) Cost amortization Net book value
---------------------------------------------------------------------
Property acquisition
oil and gas rights $ 2,671.2 $ (1,081.0) $ 1,590.2
Drilling and
completion 298.0 (77.1) 220.9
Production facilities
and equipment 125.1 (34.0) 91.1
Head office furniture
and equipment 12.6 (6.2) 6.4
---------------------------------------------------------------------
$ 3,106.9 $ (1,198.3) $ 1,908.6
---------------------------------------------------------------------
---------------------------------------------------------------------

2003
---------------------------------------------------------------------
Accumulated depletion
depreciation and
($ millions) Cost amortization Net book value
---------------------------------------------------------------------
Property acquisition
oil and gas rights $ 1,933.3 $ (612.3) $ 1,321.0
Drilling and
completion 208.0 (52.1) 155.9
Production facilities
and equipment 91.0 (23.1) 67.9
Head office furniture
and equipment 8.0 (4.6) 3.4
---------------------------------------------------------------------
$ 2,240.3 $ (692.1) $ 1,548.2
---------------------------------------------------------------------
---------------------------------------------------------------------


Unproved land costs of $103.9 million (2003 - $36.0 million) are
excluded from costs subject to depletion and depreciation.

PrimeWest capitalized $2.9 million of general and administrative costs
in 2004 (2003 - $2.5 million).

On February 4, 2005, PrimeWest closed the disposition of a property
receiving the balance of the proceeds of $5.4 million. At December 31,
2004, the amount was recorded as assets held for sale in current assets.

PrimeWest has performed a ceiling test as at December 31, 2004. The
impairment test was calculated using the consultant's average prices at
January 1 for the years 2005 to 2009 as follows:



Consultant's Average Price Forecasts Year
---------------------------------------------------------------------
2005 2006 2007 2008 2009
-----------------------------------
WTI ($US/bbl) 42.76 40.37 37.36 34.82 33.45
AECO ($Cdn/Mcf) 6.79 6.52 6.25 5.95 5.79
---------------------------------------------------------------------
---------------------------------------------------------------------


The December 31, 2004, ceiling test resulted in a surplus.

A ceiling test was performed at December 31, 2003 in accordance with
CICA Accounting Guideline 5 (AcG-5), "Full Cost Accounting in the Oil
and Gas Industry", using December 31, 2003 commodity prices of AECO
$6.09/mcf for natural gas and WTI US$ 32.52/bbl for crude oil. The
December 31, 2003 ceiling test resulted in a surplus.



7. Other Assets and Deferred Charges

($ millions) 2004 2003
---------------------------
Deferred charges $ 10.6 $ 1.3
Other assets 0.3 0.2
-----------------------------------------------------------
$ 10.9 $ 1.5
-----------------------------------------------------------
-----------------------------------------------------------


8. Long-Term Debt

($ millions) 2004 2003
---------------------------
Bank credit facility $ 264.0 $ 88.0
Senior secured notes 150.3 162.1
Convertible unsecured
subordinated debentures 242.0 -
-----------------------------------------------------------
$ 656.3 $ 250.1
-----------------------------------------------------------
-----------------------------------------------------------


Long-term debt is comprised of bank credit facilities, senior secured
notes and convertible unsecured subordinated debentures of $264.0
million, $150.3 million and $242.0 million respectively.

PrimeWest has a maximum borrowing base of $625 million at December 31,
2004 (2003 - $390 million) as established by the lenders. The bank
credit facilities consist of a revolving term loan to a maximum of
$437.5 million and an operating facility of $25 million, with the
balance of $162.5 million being the maximum amount of Senior Secured
Notes. In addition to amounts outstanding under the facility, PrimeWest
has outstanding letters of credit in the amount of $4.9 million (2003 -
$5.1 million).

Advances under the bank credit facility are made in the form of Banker's
Acceptances (BA), prime rate loans or letters of credit. In the case of
BAs, interest is a function of the BA rate plus a stamping fee based on
the Trust's current ratio of debt to cash flow. In the case of prime
rate loans, interest is charged at the bank's prime rate.

The bank credit facility revolves until June 30, 2005, by which time the
lenders will have conducted their annual borrowing base review. The
lenders also have the right to re-determine the borrowing base at one
other time during the year. During the revolving phase, the bank credit
facility has no specific terms of repayment. At the end of the revolving
period, the lender has the right to extend the revolving period for a
further 364-day period or to convert the facility to a term facility. If
the lender converts to a non-revolving facility, 60% of the aggregate
principal amount of the loan shall be repayable on the date that is 366
days after such conversion date and the remaining 40% of the aggregate
principal amount outstanding shall be repayable on the date that is 365
days after the initial term repayment date.

The Senior Secured Notes (the "Notes") in the amount of US$125 million
have a final maturity of May 7, 2010, and bear interest at 4.19% per
annum, with interest paid semi-annually on November 7 and May 7 of each
year. The Note Purchase Agreement requires PrimeWest to make four annual
principal repayments of US$31,250,000 commencing May 7, 2007.

Collateral for the Notes and the bank credit facility is a floating
charge debenture covering all existing and after acquired property in
the principal amount of US$1 billion. The secured parties under the bank
credit facility and Notes have agreed to share the security interests
on a pari passu basis.

The costs incurred in connection with the Notes, in the amount of $1.5
million, are classified as deferred charges on the balance sheet and are
being amortized over the term of the Notes.

The Notes are the legal obligation of PrimeWest Energy Inc. and are
guaranteed by PrimeWest Energy Trust.

The 7.5% (Series I) and 7.75% (Series II) Convertible Unsecured
Subordinated Debentures were issued on September 2, 2004 for proceeds of
$150 million and $100 million respectively.

The Series I Debentures pay interest semi-annually on March 31 and
September 30 and have a maturity date of September 30, 2009. The Series
I Debentures are convertible at the option of the holder to Trust Units
at a conversion price of $26.50 per Trust Unit. PrimeWest has the option
to redeem the Series I
Debentures at a price of $1,050 per Series I Debenture after September
30, 2007 and on or before September 30, 2008, and at a price of $1,025
per Series I Debenture after September 30, 2008 and before maturity. On
redemption or maturity the Trust may elect to satisfy its obligation to
repay the principal by issuing PrimeWest Trust Units.

The Series II Debentures pay interest semi-annually on June 30 and
December 30 and have a maturity date of December 31, 2011. The Series II
Debentures are convertible at the option of the holder to Trust Units at
conversion price of $26.50 per Trust Unit. PrimeWest has the option to
redeem the Series II Debentures at a price of $1,050 per Series II
Debenture after December 31, 2007 and on or before December 31, 2008, at
a price of $1,025 per Debenture after December 31, 2008 and on or before
December 31, 2009 and after December 31, 2009 and before maturity at
$1,000 per Series II Debenture. On redemption or maturity the Trust may
elect to satisfy its obligations to repay the principal by issuing
PrimeWest Trust Units.

Debenture issue costs of $10.0 million are included in deferred charges
on the balance sheet and are being amortized over the terms of the
debentures.

In accordance with CICA Handbook section 3860 - "Financial Instruments,"
the Convertible Unsecured Subordinated Debentures were initially
recorded at their fair value of $147.0 million (Series I) and $94.9
million (Series II). The difference between the fair value and proceeds
of $8.1 million was recorded in unitholders' equity ($3.0 million
(Series I) and $5.1 million (Series II)).

The Series I and Series II debentures are being accreted such that the
liability at maturity will equal the proceeds of $150 million and $100
million less conversions respectively. As at December 31, 2004, $0.3
million of the Series I Debentures had been converted to equity and $0.2
million of accretion was realized. Series II accretion was $0.2 million.

9. 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:



Asset Retirement Obligation ($ millions) 2004 2003
---------------------------------------------------------------------
Asset Retirement Obligation, January 1 $ 19.7 $ 15.3
Liabilities incurred 13.1 5.4
Liabilities settled (4.6) (2.2)
Accretion expense 2.0 1.2
Acquisition of capital assets 12.0 -
Disposal of capital assets (2.4) -
Acquisition of Seventh Energy 0.5 -
---------------------------------------------------------------------
Asset Retirement Obligation December 31 $ 40.3 $ 19.7
---------------------------------------------------------------------
---------------------------------------------------------------------


As at December 31, 2004, the undiscounted amount of estimated cash flows
required to settle the obligation is $238.6 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 costs are expected to be paid over an average of 33.2
years. These future asset retirement costs will be funded from the cash
reserved for site restoration and reclamation. This cash reserve of
$10.3 million is currently funded at $0.50 per BOE from PrimeWest's
operations.

10. Cash Reserve For Site Restoration And Reclamation

Commencing in 1998, funding for the reserve was provided for by reducing
distributions otherwise payable based on an amount per BOE produced
($0.50 per BOE produced for 2004 and 2003). The cash amount contributed,
including interest earned, was $6.7 million in 2004 (2003 - $8.7
million). Actual costs of site restoration and abandonment totaling $4.6
million were paid out of this cash reserve for the year ended December
31, 2004 (2003 - $2.2 million).

11. Unitholders' Equity

The authorized capital of the Trust consists of an unlimited number of
Trust Units.



---------------------------------------------------------------------
---------------------------------------------------------------------
Amounts
Trust Units Number of Units ($ millions)
---------------------------------------------------------------------
Balance, December 31, 2002 37,004,522 $ 1,252.2

Issued for cash 9,100,000 234.8
Issue expenses - (12.1)
Issued on exchange of exchangeable shares 964,897 21.2
Issued pursuant to Distribution
Reinvestment Plan 600,598 14.8
Issued pursuant to Long-Term Incentive Plan 360,608 9.4
Issue of units due to odd lot program 38 -
Issue of fractional units due to
4 to 1 consolidation 11 -
Issued pursuant to Optional Trust Unit
Purchase Plan 721,209 17.6
---------------------------------------------------------------------

Balance, December 31, 2003 48,751,883 $ 1,537.9

Issued for cash 17,700,000 420.0
Issue expenses - (0.5)
Issued on exchange of exchangeable shares 833,162 17.0
Issued pursuant to Distribution
Reinvestment Plan 268,677 6.5
Issued pursuant to Premium Distribution Plan 1,311,462 32.0
Issued pursuant to Long-Term Incentive Plan 116,233 3.0
Issue pursuant to conversion of debentures 10,527 0.3
Issued pursuant to Optional Trust Unit
Purchase Plan 894,167 21.5
---------------------------------------------------------------------

Balance, December 31, 2004 69,886,111 $ 2,037.7
---------------------------------------------------------------------
---------------------------------------------------------------------


The weighted average number of Trust Units and exchangeable shares
outstanding in 2004 was 59,482,034 (2003 - 46,015,519). For purposes of
calculating diluted net income per Trust Unit 1,868,995 and 1,247,551
Trust Units issuable pursuant to the conversion of the Series I and
Series II Convertible Unsecured Subordinated Debentures respectively and
525,129 Trust Units (2003 - 345,278) issuable pursuant to the long-term
incentive plan were added to the weighted average number. The per unit
cash distribution amounts paid or declared reflects distributions paid
or declared to Trust Units outstanding on the record dates.

PrimeWest Exchangeable Class A Shares

PrimeWest has an unlimited number of exchangeable shares. The
exchangeable shares are exchangeable into PrimeWest Trust Units at any
time up to March 29, 2010; based on an exchange ratio that adjusts each
time the Trust makes distribution to its unitholders. The exchange
ratio, which was 1:1 on the date of the initial exchangeable share
offering, is based on the total monthly distribution, divided by the
closing unit price on the distribution payment date. The exchange ratio
on December 31, 2004 was 0.50408:1 (2003 - 0.44302:1).



---------------------------------------------------------------------
---------------------------------------------------------------------
Exchangeable Shares # of shares ($ millions)
---------------------------------------------------------------------
Balance, December 31, 2002 5,179,278 $ 47.7
Issued for management incentive program 161,717 1.5
---------------------------------------------------------------------
---------------------------------------------------------------------
Exchanged for Trust Units (2,299,872) (21.2)
---------------------------------------------------------------------
Balance, December 31, 2003 3,041,123 28.0
Issued for special employee incentive
program 94,340 1.2
Exchanged for Trust Units (1,841,072) (17.0)
---------------------------------------------------------------------
Balance, December 31, 2004 1,294,391 $ 12.2
---------------------------------------------------------------------
---------------------------------------------------------------------

Trust Units and Exchangeable Shares Issued & Outstanding

---------------------------------------------------------------------

# of Shares 2004 2003
---------------------------------------------------------------------
Trust Units issued & outstanding 69,886,111 48,751,883
Exchangeable shares
Class A Shares
(2004 - 1,294,391 shares exchangeable at
0.50408; 2003 - 3,041,123 shares
exchangeable at 0.44302) 652,477 1,347,277

---------------------------------------------------------------------
Total units and exchangeable shares issued
& outstanding 70,538,588 50,099,160
Convertible Unsecured Subordinated
Debentures
Series I 5,649,849 -
Series II 3,773,585 -
Unit Appreciation Rights 525,129 345,278
---------------------------------------------------------------------
Trust Units and Exchangeable Shares,
issued and outstanding, and Trust Units
issuable pursuant to the conversion of
the Convertible Unsecured Subordinated
Debentures and Long-Term Incentive Plan 80,487,151 50,444,438
---------------------------------------------------------------------
---------------------------------------------------------------------


12. 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 employees and directors 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 the
members of the Board, whose UARs vest immediately. The Board of
Directors has the option of settling payouts under the plan in PrimeWest
Trust Units or in cash. To date, all payouts under the plan have been in
the form of Trust Units.



As at December 31, 2004

---------------------------------------------------------------------
Current
UARs return per Total Trust
Year of issued & UARs "in the money" equity Unit
Grant outstanding vested UARs ($ millions) dilution
---------------------------------------------------------------------
1999 35,919 35,919 $ 38.55 $ 1.4 52,020
2000 110,985 110,985 19.42 2.2 80,979
2001 323,235 322,444 10.11 3.3 122,424
2002 825,982 585,423 7.67 6.3 160,042
2003 962,043 382,801 6.48 5.0 90,987
2004 1,445,467 163,912 $ 2.87 1.9 18,677
---------------------------------------------------------------------
Total 3,703,631 1,601,484 $ 20.1 525,129
---------------------------------------------------------------------
---------------------------------------------------------------------

As at December 31, 2003

---------------------------------------------------------------------
Current
UARs return per Total Trust
Year of issued & UARs "in the money" equity Unit
Grant outstanding vested UARs ($ millions) dilution
---------------------------------------------------------------------
1998 10,391 10,391 $ 49.98 $ 0.5 18,844
1999 55,160 55,160 34.92 1.9 69,892
2000 120,137 119,387 16.40 2.0 71,007
2001 383,424 265,645 7.81 3.0 74,891
2002 961,405 447,562 6.09 4.7 86,694
2003 1,085,031 141,896 $ 4.75 2.5 23,950
---------------------------------------------------------------------
Total 2,615,548 1,040,041 $ 14.6 345,278
---------------------------------------------------------------------
---------------------------------------------------------------------


Cumulative to December 31, 2004, 1,287,601 UARs have been exercised
(cumulative to December 31, 2003 - 1,030,850), resulting in the issuance
of 835,213 Trust Units from treasury (cumulative to December 31, 2003 -
719,374).

13. Cash Distributions



($ millions) 2004 2003 2002
---------------------------------------------------------------------
Cash flow from operations $266.8 $216.6 $170.9
Deduct amounts to reconcile to distribution:
Cash retained from cash available for
Distribution(1) (64.0) (15.3) (7.3)
Contribution to reclamation fund (6.7) (8.7) (4.1)
---------------------------------------------------------------------
$196.1 $192.6 $159.5
---------------------------------------------------------------------
---------------------------------------------------------------------
Cash Distributions to Trust Unitholders $196.1 $192.6 $158.0
---------------------------------------------------------------------
---------------------------------------------------------------------
Cash Distributions per Trust Unit $ 3.30 $ 4.32 $ 4.80
---------------------------------------------------------------------
---------------------------------------------------------------------

(1) The Board of Directors determines the cash distribution level
which results in a discretionary amount of cash being retained.


14. Related-Party Transactions

On September 26, 2002, the Trust announced the planned elimination,
effective October 1, 2002, of its external management structure and all
related management, acquisition and disposition fees, as well as the
acquisition of the right to mandatory quarterly dividends commonly
referred to as the "1% retained royalty". The transaction was approved
by the unitholders and the holders of Exchangeable Shares on November 4,
2002 and closed November 6, 2002. The transaction resulted in the
elimination of the 2.5% management fee on net production revenue,
quarterly incentive payments payable in the form of Trust Units, the
1.5% acquisition fee and the 1.25% disposition fee, which resulted in
payments to PrimeWest Management Inc. in 2002 totaling $5.8 million. In
addition, the amount of the 1% retained royalty paid in 2002 was $1.3
million.

The internalization transaction was achieved through the purchase by
PrimeWest of all of the issued and outstanding shares of PrimeWest
Management Inc. for a total consideration of approximately $26.3 million
comprised of a cash payment of $13.2 million and the issuance of
Exchangeable Shares exchangeable, based on an agreed exchange ratio, for
approximately 491,000 Trust Units and valued at approximately $13.1
million based on the closing price of the Trust Units on the TSX on
September 26, 2002. The $13.2 million that related to the acquisition of
the 1% retained royalty was capitalized; an additional $9.5 million was
capitalized with an offset to future tax liability as a result of the
property, plant and equipment having no tax basis. In addition,
PrimeWest agreed to issue Exchangeable Shares valued at $1.5 million to
certain executive officers to terminate a management incentive program
of PrimeWest Management Inc. and to create a special employee retention
plan for those executive officers which provides for long-term incentive
bonuses in the form of Exchangeable Shares. Under the special employee
retention plan, PrimeWest agreed to issue 94,340 exchangeable shares on
each of the second, third, fourth and fifth anniversaries of the
completion of the internalization transaction. In November 2004, 94,340
exchangeable shares were issued relating to the special employee
retention plan at a value of $1.2 million. As at December 31, 2004, $0.2
million has been accrued in non-cash general and administrative expenses
related to the special employee retention plan.

15. Income Taxes

PrimeWest and its subsidiaries had no taxable income for 2004, 2003, and
2002, as tax pool deductions and the royalty payable were sufficient to
reduce taxable income in these entities to nil.

The future tax provision results from temporary differences between the
financial statement carrying amounts of assets and liabilities and their
respective tax bases.



($ millions) 2004 2003
---------------------------------------------------------------------
Loss carry forwards $ (1.4) $ -
Capital assets 230.2 318.9
Foreign exchange gain on long-term debt 3.7 2.1
Asset retirement obligation (13.5) (2.9)
Long-term incentive liability (6.8) (4.9)
---------------------------------------------------------------------
$ 212.2 $ 313.2
---------------------------------------------------------------------
---------------------------------------------------------------------


The provisions for income taxes varies from the amounts that would be
computed by applying the combined Canadian federal and provincial income
tax rates due to the following:



($ millions) 2004 2003 2002
---------------------------------------------------------------------
Net income (loss) before taxes $ 69.1 $ 19.8 $ (30.9)
---------------------------------------------------------------------
Computed income tax expense (recovery) at
the Canadian statutory rate of 38.87%
(2003 - 40.62%; 2002 - 42.12%) 26.9 7.6 (13.0)
Increase (decrease) resulting from:
Non-deductible crown royalties and other
payments, net of ARTC 0.3 0.3 5.7
Federal resource allowance (8.9) (16.2) (3.5)
Change in income tax rate (8.6) (43.1) (4.2)
Foreign exchange gain on long-term debt (2.2) (2.4) -
Amounts included in trust income
and other (45.1) (26.1) (18.2)
---------------------------------------------------------------------
Future income taxes $ (37.6) $ (79.9) $ (33.2)
---------------------------------------------------------------------
---------------------------------------------------------------------


16. Financial Instruments

a) Commodity Price Risk Management

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 summary of these derivative financial instruments, options and swaps
in place at December 31, 2004 follows:



CRUDE OIL
Volume
Period (bbls/d) Type WTI Price (US$/bbl)
---------------------------------------------------------------------
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
Jan - Mar 2005 500 Costless Collar 35.00/49.80
Jan - Mar 2005 500 Costless Collar 35.00/50.00
Jan - Mar 2005 500 Costless Collar 40.00/51.50
Jan - Mar 2005 500 Costless Collar 40.00/57.60
Jan - Mar 2005 500 Costless Collar 40.00/65.80
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
Apr - June 2005 500 Costless Collar 35.00/47.00
Apr - June 2005 500 Costless Collar 35.00/46.90
Apr - June 2005 500 Costless Collar 37.50/50.90
Apr - June 2005 500 Costless Collar 37.50/56.70
Apr - June 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
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
Jan - Mar 2006 1000 Costless Collar 35.00/49.90


NATURAL GAS (AECO)
Volume
Period (mmcf/day) Type AECO Price (Cdn$/mcf)
---------------------------------------------------------------------
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
Jan 2005 - Mar 2005 10.0 Costless Collar 6.33/11.18
Jan 2005 - Mar 2005 10.0 Costless Collar 6.33/10.76
Jan 2005 - Mar 2005 10.0 Costless Collar 6.33/10.55
Jan 2005 - Mar 2005 10.0 Costless Collar 6.33/12.13
Jan 2005 - Mar 2005 5.0 3 Way 5.28/6.33/10.44
Jan 2005 - Mar 2005 5.0 3 Way 5.28/6.33/10.35
Jan 2005 - Mar 2005 5.0 3 Way 5.28/6.33/12.53
Jan 2005 - Mar 2005 5.0 Costless Collar 6.33/16.40
Feb 2005 - Mar 2005 5.0 Costless Collar 6.33/10.76
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
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
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
---------------------------------------------------------------------
---------------------------------------------------------------------


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 $10.44,
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 would then receive market price
plus $1.05. However, should market prices rise above $10.44, PrimeWest
would receive a maximum price of $10.44. Should the market price remain
between $6.33 and $10.44 PrimeWest would receive the market price.

In 2004, the financial impact of contracts settling in the year was a
decrease in sales revenues of $28.2 million (2003 - $30.5 million
decrease in sales revenues; 2002 - $28.1 million increase in sales
revenues).

The mark-to-market value of the hedges in place as at December 31, 2004
is a $0.2 million gain of which $9.1 million gain is attributable to
natural gas and an $8.9 million loss is attributable to crude oil.



Electrical Power

Period Power Amount (MW) Type Price ($/MW-hr)
---------------------------------------------------------------------
Calendar 2005 5.0 Fixed Price Swap 51.65
---------------------------------------------------------------------
---------------------------------------------------------------------


The mark to market value of the hedges at December 31, 2004 is a $0.1
million loss.

b) Fair Value Of Financial Instruments

Financial instruments include cash, marketable securities, accounts
receivable, accounts payable and accrued liabilities, accrued
distributions to unitholders, long-term debt and financial hedges. As at
December 31, 2004, 2003, and 2002, the fair market value of the
financial instruments, other than long-term debt and financial hedges,
approximate their carrying value, due to the short-term maturity of
these instruments. The fair value of long-term debt approximates its
carrying value in all material respects, because the cost of borrowing
approximates the market rate for similar borrowings.

17. Commitments And Contingencies

a) PrimeWest has lease commitments relating to office buildings. The
estimated annual minimum operating lease rental payments for the
buildings, after deducting sublease income will be $3.6 million in 2005,
$3.6 million in 2006 and $3.4 million in 2007, $3.3 million in 2008 and
$0.8 million in 2009.

b) As part of PrimeWest's internalization transaction (see Note 15),
PrimeWest agreed to issue 377,360 exchangeable shares as a special
employee retention plan. One quarter of the exchangeable shares (94,340)
were issued to the executive officers of PrimeWest on November 6, 2004.
An additional 94,340 exchangeable shares will be issued each on November
6, 2005, November 6, 2006 and November 6, 2007. As at December 31, 2004
$0.2 million has been accrued in non-cash general and administrative
expenses related to the special employee retention plan.

c) PrimeWest is engaged in a number of matters of litigation, none of
which could reasonably be expected to result in any material adverse
consequence.

d) PrimeWest has various pipeline transportation commitments that run
through 2010. The estimated annual payments are $7.1 million in 2005,
$4.1 million in 2006, $2.9 million in 2007, $0.4 million in 2008 and
$0.2 million in 2009.

e) Pursuant to the purchase of the Calpine assets, PrimeWest entered
into a natural gas purchase and sale agreement where the purchaser has
the right to purchase natural gas in an amount based on a notional
quantity of natural gas produced from certain of the Calpine Assets. The
gas purchase and sale arrangement is on a firm basis for a seven-year
term, based on a monthly index price, with predetermined declining
quantities. As part of the arrangement, the purchase obligations will be
secured by credit support acceptable to PrimeWest provided by the
purchaser. The parties will share in the proceeds of sale of the natural
gas subject to this purchase and sale arrangement realized between
December 31, 2004 and December 31, 2006. The sale proceeds will only be
shared if gas prices exceed an agreed forward strip pricing prevailing
at the time that the Purchase and Sale Agreement was executed, plus
$1.00/mcf, and the maximum amount that will be paid by PrimeWest Gas
under that price sharing mechanism is $2,500,000 in any calendar quarter
to a maximum aggregate amount of $25,000,000.

18. Prior Years' Comparative Numbers

Certain prior years' comparative numbers have been restated to conform
to the current year's presentation.

19. Differences Between Canadian And United States Generally Accepted
Accounting Principles

PrimeWest's financial statements are prepared in accordance with
generally accepted accounting principles (GAAP) in Canada, which, in
some respects, differ from those generally accepted in the United States
(US). The following are those policies that result in significant
measurement differences.

1. Property, Plant And Equipment

PrimeWest adopted CICA Accounting Guideline 16 (AcG-16), "Oil and Gas
Accounting - Full Costs" on January 1, 2004. The new guideline modifies
how the ceiling test is performed and requires that cost centers be
tested for recoverability using undiscounted future cash flows from
Proved reserves, which are determined by using forward indexed prices.
When the carrying amount of a cost center is not recoverable, the cost
center must be written down to its fair value. Fair value is estimated
using accepted present value techniques that incorporate risks and other
uncertainties when determining expected cash flows.

In accordance with the full cost method of accounting under US GAAP, the
net carrying value is limited to a standardized measure of discounted
future cash flows, before financing and general administrative costs.
Where the amount of a ceiling test write down under Canadian GAAP
differs from the amount of a write down under US GAAP, the charge for
depreciation and depletion under US and Canadian GAAP will differ in
subsequent years.

Under Canadian GAAP, depletion charges are calculated by reference to
Proved Reserves estimated using future prices and estimated future
costs. Under US GAAP, depletion charges are calculated by reference to
Proved Reserves using constant costs.

2. Asset Retirement Obligation

Effective January 1, 2004, PrimeWest changed its accounting policy with
respect to accounting for asset retirement obligations. CICA section
3110 requires the fair value of asset retirement obligations to be
recorded when they are incurred rather than merely accumulated or
accrued over the useful life of the respective asset. The change in
accounting policy is recorded as an adjustment to accumulated income
with retroactive restatement of prior period comparatives.

This change in accounting policy is consistent with the Trust's adoption
of FAS 143 Accounting for Asset Retirement Obligations effective January
1, 2003. The standard requires the recognition of the liability
associated with the future site reclamation costs of the long-lived
assets. The liability for future retirement obligations is to be
recorded in the financial statements at the time the liability is
incurred.

The asset retirement obligation is initially recorded at the estimated
fair value as a long-term liability with a corresponding increase to
property, plant and equipment. The depreciation of property, plant and
equipment is allocated to expense on the unit-of-production basis.

The adoption of FAS 143 allows for the cumulative effect of the change
in accounting policy to be booked as a transitional adjustment to net
income with no restatement of prior period comparatives. At January 1,
2003, this resulted in an increase to the asset retirement obligation of
$15.3 million, an increase to PP&E of $8.4 million in 2003, a $0.4
million decrease to net income after tax, a decrease in the site
restoration provision of $6.2 million and a decrease to future tax
liability of $0.3 million.

Implementation of this accounting standard did not affect the Trust's
cash flow or liquidity.

3. Marketable Securities

PrimeWest follows the cost method of accounting for the investment in
marketable securities as established by the CICA. Under this accounting
policy, the investment is initially recorded at cost with the
corresponding distributions received in excess of earnings recorded as a
reduction to the carrying amount of the investment. Under US GAAP, the
marketable securities are considered held for trading and recorded on
the balance sheet at fair value. The corresponding after tax difference
between the cost method and fair value is recorded to earnings in the
current year and results in a Canadian / US GAAP difference.

Recent US Accounting Pronouncements Issued But Not Implemented

Share-Based Payment

On December 15, 2004 the Financial Accounting Standards Board (FASB) in
the United States issued FASB Statement No. 123R "Share-Based Payment".
The standard mandates that a public entity measure the cost of equity
based service awards based on the fair value of the award at grant date.
That cost will be recognized over the period during which an employee is
required to provide service in exchange for the award or the requisite
service period. No compensation cost is recognized for equity
instruments for which employees do not render the requisite service. The
public entity will initially measure the cost of the liability based
service awards based on its current fair value. The fair value of that
award will be re-measured subsequently at each reporting date through
the settlement date. Changes in fair value during the requisite service
period will be recognized as compensation cost over that period. The
Trust is currently assessing the impact of the pronouncement on the
financial statements.

The following tables set out the significant differences in the
consolidated financial statements using US GAAP.

a) Consolidated Net Income



($ millions, except per Trust Unit amounts) 2004 2003 2002
---------------------------------------------------------------------
Net income/(loss) as reported $103.4 $ 95.9 $ (0.6)
Adjustments
Depletion and depreciation (4.2) 35.4 67.3
FAS 115 adjustment 22.6 - -
FAS 133 adjustment 5.4 6.1 (55.8)
Accretion of asset retirement obligation - - 0.9
Future income tax expense (4.3) (42.3) (1.4)
---------------------------------------------------------------------
Adjusted net income before change in
accounting policy 122.9 95.1 10.4
Cumulative effect of change in accounting
policy, net of tax of $0.3 million - (0.4) -
---------------------------------------------------------------------
Adjusted net income $122.9 $ 94.7 $ 10.4
---------------------------------------------------------------------
---------------------------------------------------------------------
Net income per Trust Unit
US GAAP - basic $ 2.07 $ 2.01 $ 0.30
- diluted $ 2.05 $ 1.99 $ 0.30

Cumulative effect of change in accounting
policy per Trust Unit
US GAAP - basic - $ 0.01 -
- diluted - $ 0.01 -


b) Pro Forma Consolidated Net Income

US GAAP requires the cumulative impact of a change in accounting policy
to be presented in the current year's consolidated statement of income
with no restatement of the comparative prior periods. The following
table illustrates the pro forma impact on the Trust's 2002 net income
under US GAAP had the prior period been restated.



($ millions, except per Trust Unit amounts) 2002
---------------------------------------------------------------------
Net income
As reported $ 10.4
As restated $ 11.2

Net income per Trust Unit (Basic)
As reported $ 0.30
As restated $ 0.33

Net income per Trust Unit (Diluted)
As reported $ 0.30
As restated $ 0.32

Asset retirement obligation at January 1, 2002 $ 11.8
---------------------------------------------------------------------
---------------------------------------------------------------------

c) Consolidated Unitholders' Equity

($ millions) 2004 2003
---------------------------------------------------------------------
Unitholders' Equity as reported $ 1,194.9 $ 1,025.2
Adjustments
Depletion and depreciation (270.3) (493.6)
FAS 115 adjustment 22.6 -
FAS 133 adjustment - (5.4)
Future income tax recovery 119.2 127.0
--------------------------------------------------------------------
$ 1,066.4 $ 653.2
---------------------------------------------------------------------
---------------------------------------------------------------------

d) Consolidated Balance Sheets

($ millions) 2004 2003
---------------------------------------------------------------------
Cdn GAAP US GAAP Cdn GAAP US GAAP
---------------------------------------------------------------------
Property, plant and
equipment (net) 1,908.6 1,699.4 1,548.2 1,042.1
Marketable securities 68.6 91.2 - -
Derivative liability 0.5 0.5 - 5.4
Future income tax liability 211.2 153.2 313.2 183.0
Accumulated income/(deficit) 89.2 (39.3) 219.1 (162.2)
---------------------------------------------------------------------
---------------------------------------------------------------------


e) Consolidated Cash Flows

The consolidated statements of cash flows prepared in accordance with
Canadian GAAP conform in all material respects with US GAAP, except that
Canadian GAAP allows for the presentation of operating cash flow before
changes in non-cash working capital items in the consolidated statement
of cash flows. This total cannot be presented under US GAAP.

FAS 69 Supplemental Reserve Information (Unaudited)

The following data supplements oil and gas disclosure in the Trust's
Annual Report, and is provided in accordance with the provisions of FAS
69.

Oil and Gas Reserves

Users of this information should be aware that the process of estimating
quantities of "Proved" and "Proved developed" crude oil and natural gas
reserves is very complex, requiring significant subjective decisions in
the evaluation of all available geological, engineering and economic
data for each reservoir. The data for a given reservoir may also change
substantially over time as a result of the numerous factors including,
but not limited to, additional development activity, evolving production
history and continual reassessment of the viability of production under
varying economic conditions. Consequently, material revisions to
existing reserve estimates occur from time to time. Although every
reasonable effort is made to ensure that reserve estimates reported
represent the most accurate assessments possible, the significance of
the subjective decisions required and variances in available data for
various reservoirs make these estimates generally less precise than
other estimates presented in connection with financial statement
disclosures.

Proved oil and gas reserves are the estimated quantities of crude oil,
natural gas and natural gas liquids which geological and engineering
data demonstrate with reasonable certainty to be recoverable in future
years from known reservoirs under existing economic and operating
conditions.

Proved developed oil and gas reserves are reserves that can be expected
to be recovered through existing wells with existing equipment and
operating methods.

Canadian provincial royalties are determined based on a graduated
percentage scale, which varies with prices and production volumes.
Canadian reserves, as presented on a net basis, assume prices and
royalty rates in existence at the time the estimates were made, and the
Trust's estimate of future production volumes. Future fluctuations in
prices, production rates, or changes in political or regulatory
environments could cause the Trust's share of future production from
Canadian reserves to be materially different from that presented.

Subsequent to December 31, 2004, no major discovery or other favorable
or adverse event is believed to have caused a material change in the
estimates of Proved or Proved developed reserves as of that date.



Results of Oil and Gas Operations
($ millions) 2004 2003 2002
---------------------------------------------------------------------
Revenues $ 394.6 $ 329.9 $ 264.3
Expenses
Production costs 88.9 79.4 60.8
Depreciation, depletion and
amortization 201.5 170.3 113.5
Accretion 2.0 1.2 -
Tax recovery (30.0) (39.9) (26.0)
---------------------------------------------------------------------
262.4 211.0 148.3
---------------------------------------------------------------------
Results of operations from
oil and gas operations $ 132.2 $ 118.9 $ 116.0
---------------------------------------------------------------------
---------------------------------------------------------------------

Costs Incurred
($ millions) 2004 2003 2002
---------------------------------------------------------------------
Property acquisition costs
Proved properties $ 770.5 $ 202.4 $ 57.7
Unproved properties 52.1 34.0 5.7
Exploration costs 16.0 5.7 1.8
Development costs 123.6 101.5 56.8
---------------------------------------------------------------------
$ 962.2 $ 343.6 $ 122.0
---------------------------------------------------------------------
---------------------------------------------------------------------


Acquisition costs include costs incurred to purchase, lease, or
otherwise acquire oil and gas properties.

Development costs include the costs of drilling and equipping
development wells and facilities to extract, treat and gather and store
oil and gas, along with an allocation of overhead.

There were no oil and gas property costs not being amortized in any of
the years presented.



Capitalized Costs
($ millions) 2004 2003 2002
---------------------------------------------------------------------
Proved properties $ 2,599.1 $ 2,189.0 $ 1,838.8
Unproved properties 103.9 36.0 44.2
---------------------------------------------------------------------
2,703.0 2,225.0 1,883.0
Less related accumulated
depreciation, depletion
and amortization (1,010.0) (1,186.2) (1,011.6)
---------------------------------------------------------------------
$ 1,693.0 $ 1,038.8 $ 871.4
---------------------------------------------------------------------
---------------------------------------------------------------------


Proved Oil & Gas Reserve Quantities

2004 2004 2003 2003 2002 2002
---------------------------------------------------------------------
Crude Crude Crude
Oil & Oil & Oil &
Natural Natural Natural
Gas Natural Gas Natural Gas Natural
Liquids Gas Liquids Gas Liquids Gas
(mbbls) (mmcf) (mbbls) (mmcf) (mbbls) (mmcf)
---------------------------------------------------------------------
Opening balance 25,643 272,897 25,989 279,106 26,657 267,371
Revision of
previous
estimates (806) 2,640 225 (33,640) 1,737 5,700
Purchase of
reserves in
place 6,940 180,914 1,640 50,389 954 18,929
Sale of
reserves
in place (2,120) (8,027) (28) (803) (568) (5,328)
Discoveries
and
extensions 791 16,018 941 14,742 736 25,337
Production (2,649) (42,215) (3,124) (36,897) (3,527) (32,903)
---------------------------------------------------------------------
Closing Balance 27,799 422,227 25,643 272,897 25,989 279,106
---------------------------------------------------------------------
---------------------------------------------------------------------


Standardized Measure of Discounted Future Net Cash Flows Relating to
Proved Reserves

The standardized measure for calculating the present value of future net
cash flows from Proved oil and gas reserves is based on current costs
and prices and a ten percent discount factor as prescribed by FASB 69.

Accordingly, the estimated future net cash inflows were computed by
applying prevailing selling prices at year end to the estimated future
production of Proved reserves. Estimated future expenditures are based
on future development costs.

Although these calculations have been prepared according to the
standards described above, it should be emphasized that due to the
number of assumptions and estimates required in the calculation, the
amounts are not indicative of the amount of net revenue that the Trust
expects to receive in future years. They are also not indicative of the
current value or future earnings that may be realized from the
production of Proved reserves, nor should it be assumed that they
represent the fair market value of the reserves or of the oil and gas
properties.

Although the calculations are based on existing economic conditions at
each year end, such economic conditions have changed and may continue to
change significantly due to events such as the continuing changes in the
natural gas market and changes in government policies and regulations.
While the calculations are based on the Trust's understanding of the
established FASB guidelines, there are numerous other equally valid
assumptions under which these estimates could be made that would produce
significantly different results.



Standardized Measure

($ millions) 2004 2003 2002
---------------------------------------------------------------------
Future cash inflows $ 4,187.1 $ 2,631.1 $ 2,890.5
Future production costs (1,186.6) (804.9) (699.0)
Future development costs (72.0) (69.4) (73.4)
Other related future costs (37.1) (42.1) (43.4)
---------------------------------------------------------------------
Future net cash flows 2,891.4 1,714.7 2,074.7
Discount at 10% (1,242.7) (721.6) (919.4)
---------------------------------------------------------------------
Standardized measure of
discounted future net cash flow
related to proved reserves $ 1,648.7 $ 993.1 $ 1,155.3
---------------------------------------------------------------------
---------------------------------------------------------------------


Summary of Changes in the Standardized Measure During the Year

($ millions) 2004 2003 2002
---------------------------------------------------------------------
Sales of oil and gas produced,
net of production costs $ (312.2) $ (255.0) $ (203.5)
Net change in sales and
transfer prices, net of
development and production
costs 144.4 (106.2) 672.6
Sales of reserves in place (54.4) (2.3) (4.5)
Purchases of reserves in place 630.4 156.4 45.6
Extensions, discoveries and
improved recovery, less related
costs 106.7 48.5 52.3
Changes in timing of future
net cash flows and other 37.1 (60.6) (93.6)
Revisions of previous quantity
estimates 4.3 (58.5) 28.3
Accretion of discount 99.3 115.5 59.8
---------------------------------------------------------------------
---------------------------------------------------------------------
Net change 655.6 (162.2) 557.0
Balance at beginning of year 993.1 1,155.3 598.3
---------------------------------------------------------------------
Balance at end of year $ 1,648.7 $ 993.1 $ 1,155.3
---------------------------------------------------------------------
---------------------------------------------------------------------


Trading Performance

For the quarter
ended Dec 31/04 Sep 30/04 Jun 30/04 Mar 31/04 Dec 31/03
---------------------------------------------------------------------
TSX Trust Unit
prices ($ per
Trust Unit)
High $ 28.33 $ 26.70 $ 26.80 $ 28.35 $ 27.34
Low $ 25.06 $ 23.29 $ 22.18 $ 22.70 $ 24.48
Close $ 26.62 $ 26.70 $ 23.25 $ 26.65 $ 24.51
---------------------------------------------------------------------
Average daily
traded volume 255,944 259,219 187,767 256,922 184,428
---------------------------------------------------------------------
---------------------------------------------------------------------


For the quarter
ended Dec 31/04 Sep 30/04 Jun 30/04 Mar 31/04 Dec 31/03
---------------------------------------------------------------------
NYSE Trust Unit
prices (US$
per Trust Unit)
High $ 22.98 $ 21.16 $ 20.44 $ 22.14 $ 21.48
Low $ 20.85 $ 17.65 $ 16.00 $ 17.31 $ 18.67
Close $ 22.18 $ 21.16 $ 17.43 $ 20.31 $ 21.27
---------------------------------------------------------------------
Average daily
traded volume 542,483 329,862 279,882 469,694 243,921
---------------------------------------------------------------------
---------------------------------------------------------------------

Number of
Trust Units
outstanding
including
exchangeable
shares (millions
of units) 70.5 69.7 56.8 50.87 50.10
---------------------------------------------------------------------
---------------------------------------------------------------------

Distribution
paid per
Trust Unit $ 0.90 $ 0.83 $ 0.75 $ 0.82 $ 0.96
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Total Compound Annual Return(%)(1)

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S&P
Cdn TSX
TSX Oil Energy
and Gas S&P 500 S&P 500 Trust
PrimeWest Index TSX S&P $Cdn US$ Index
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Five Year 21.5% 23.4% 3.6% (5.9)% (2.3)% 13.4%
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Three Year 18.5% 24.9% 7.7% (6.5)% 2.9% 15.7%
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One Year 9.7% 40.5% 14.4% 2.8% 10.8% 29.6%
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(1) Total return equals unit price plus distributions re-invested


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Contact Information

  • FOR FURTHER INFORMATION PLEASE CONTACT:
    PrimeWest Energy Trust
    George Kesteven
    Manager, Investor Relations
    (403) 699-7367 or Toll-free: 1-877-968-7878
    Email: investor@primewestenergy.com
    or
    PrimeWest Energy Trust
    Diane Zuber
    Investor Relations Advisor
    (403) 699-7356