ZARGON ENERGY TRUST
TSX : ZAR.UN

ZARGON ENERGY TRUST
Zargon Oil & Gas Ltd.
TSX : ZAR

Zargon Oil & Gas Ltd.

March 15, 2005 16:02 ET

Zargon Energy Trust Announces 2004 Fourth Quarter and Full Year Results


NEWS RELEASE TRANSMITTED BY CCNMatthews

FOR: ZARGON ENERGY TRUST

TSX SYMBOL: ZAR.UN

AND ZARGON OIL & GAS LTD.

TSX SYMBOL: ZOG.B

MARCH 15, 2005 - 16:02 ET

Zargon Energy Trust Announces 2004 Fourth Quarter and
Full Year Results

CALGARY, ALBERTA--(CCNMatthews - March 15, 2005) - Zargon Energy Trust
(TSX:ZAR.UN) ("Zargon" or the "Trust") today announced record operating
and financial results for the fourth quarter and the year ended December
31, 2004. This was a year of transformation as Zargon Energy Trust was
initiated on July 15, 2004 with the acquisition of all of the
operational, financial and intellectual assets of its predecessor junior
exploration and production company, Zargon Oil & Gas Ltd. Going forward,
the Trust is proceeding in a tax-efficient format with the successful
value-focused business model that Zargon Oil & Gas Ltd. had followed for
twelve years.

The reorganization of Zargon Oil & Gas Ltd. into Zargon Energy Trust has
been accounted for using the continuity of interest method. Accordingly,
all financial and operating information has been reported as if Zargon
Energy Trust had always carried on the business of Zargon Oil & Gas Ltd.

Highlights from the fourth quarter and year ended December 31, 2004

- Zargon reported record results for the fourth quarter and the year
with commodity prices holding at historically high prices throughout.
Fourth quarter 2004 revenue of $32.90 million and cash flow from
operations of $15.36 million ($0.82 per diluted unit) were 34 percent
and 16 percent respectively higher than the prior year fourth quarter.
Revenue for the full year was $123.97 million and cash flow from
operations was $63.75 million, both far above any preceding year.

- Financial gains were enhanced by production growth with year-over-year
increases of 16 percent for natural gas to 28.84 million cubic feet per
day and four percent for oil and natural gas liquids to 3,416 barrels
per day. Fourth quarter production of 28.93 million cubic feet per day
of natural gas and 3,618 barrels per day of oil and natural gas liquids
provided Zargon record production volumes of 8,440 barrels of equivalent
per day.

- On a quarterly perspective, revenue and cash flow from operations in
the fourth quarter were little changed from the preceding quarter.
Compared to the third quarter of 2004, increases in production costs,
hedge losses and oil price differentials were largely offset by small
production increases and modestly higher gas prices.

- Net capital expenditures in 2004 were $56.27 million with $11.81
million of net property acquisitions, primarily related to the purchase
of producing oil property interests in the Weyburn area of Southeast
Saskatchewan, and $44.46 million for exploration and development. For
the year, Zargon drilled a record 49.5 net wells with an 85 percent
success ratio, yielding 35.4 net gas wells, 5.7 net oil wells, 7.6 net
dry holes and 0.8 service wells. Net capital expenditures were $15.25
million in the fourth quarter and were mostly allocated to an active
16.1 net well Alberta natural gas exploration drilling program that
resulted 10.2 net gas wells, 1.4 net oil wells, 3.7 net dry holes and
0.8 net service wells.

- The 2004 capital program replaced 140 percent of Zargon's 2004
production volumes. Year-end proved plus probable reserves increased
five percent to 25.95 million barrels of oil equivalent. Including
future development costs, Zargon's 2004 finding, development and
acquisition costs were $13.72 per barrel of equivalent. The three-year
average proved plus probable finding, development and acquisition costs
were $11.89 per barrel of equivalent.

- Cash distributions of $0.14 per trust unit were paid for each of the
five months August to December inclusive for an aggregate of $10.70
million. Fourth quarter distributions totalled $0.42 per trust unit
which represented 51 percent of the quarter's $0.82 per diluted unit
cash flow. Including the effect of the exchangeable shares, which do not
receive distributions, fourth quarter cash distributions totalled $6.43
million or 42 percent of the quarter's $15.36 million cash flow.

- Year-end net debt of $23.37 million is less than 0.4 times annualized
fourth quarter cash flow.

- On a per unit basis, Zargon's production increased seven percent in
2004 to 447 barrels of equivalent per million total trust units. For the
year, Zargon's proved and probable reserves increased one percent to
1.39 barrels of equivalent per total trust unit.



Three Months Ended Year Ended
December 31, December 31,
Percent Percent
2004 2003 Change 2004 2003 Change
------------------------------------------------------------------------
(unaudited) (unaudited)
FINANCIAL
HIGHLIGHTS

Income and
Investments
($ million)
Petroleum
and natural
gas revenue 32.9 24.5 34 124.0 101.7 22
Cash flow from
operations 15.4 13.2 16 63.7 54.3 17
Cash
distributions 6.4 - - 10.7 - -
Net earnings 5.3 4.1 30 20.6 24.4 (15)
Net capital
expenditures 15.3 12.8 19 56.3 39.9 41

Per Trust Unit,
Diluted
Cash flow from
operations 0.82 0.72 14 3.40 2.96 15
Net earnings 0.34 0.22 55 1.20 1.33 (10)
Cash
Distributions
($/trust unit) 0.42 - - 0.70 - -

Balance Sheet
at Period End
($ million)
Property and
equipment, net 209.7 167.9 25
Bank
indebtedness 14.2 7.0 103
Unitholders'
equity 120.6 112.5 7

Total Units
Outstanding
at Period End
(million) 18.61 17.99 3




Three Months Ended Year Ended
December 31, December 31,
Percent Percent
2004 2003 Change 2004 2003 Change
------------------------------------------------------------------------
(unaudited) (unaudited)

OPERATIONAL
HIGHLIGHTS

Average Daily
Production
Oil and
liquids
(bbl/d) 3,618 3,340 8 3,416 3,287 4
Natural gas
(mmcf/d) 28.93 28.08 3 28.84 24.95 16
Equivalent
(boe/d) 8,440 8,020 5 8,222 7,446 10
Equivalent
per million
total units
(boe/d) 454 448 1 447 418 7

Average Selling
Price (before
hedges)
Oil and
liquids
($/bbl) 47.13 32.91 43 45.37 36.66 24
Natural
gas ($/mcf) 6.46 5.57 16 6.37 6.33 1

Wells Drilled,
Net 16.1 16.1 - 49.5 38.6 28

Undeveloped
Land at
Period End 376 398 (6)
(thousand
net acres)

Notes:
(1) Comparative period numbers reflect retroactive restatement due
to a change in accounting policy.

(2) Total units outstanding include trust units plus exchangeable
shares outstanding at period end. The exchangeable shares are
converted at the exchange ratio at the end of the period.

(3) The calculation of barrels of equivalent (boe) is based on the
conversion ratio that six thousand cubic feet of natural gas is
equivalent to one barrel of oil. Average daily production per
million total trust units is calculated using the weighted
average number of trust units outstanding during the period, plus
the weighted average number of exchangeable shares outstanding
during the period converted at the exchange ratio at the end of
the period.


GUIDANCE (a)

In a November 2004 press release reporting third quarter results, the
Trust forecast that fourth quarter 2004 production would average 8,500
barrels of equivalent per day, comprised of 30 million cubic feet per
day of natural gas and 3,500 barrels per day of oil and liquids. Actual
production for the fourth quarter was very close at 8,440 barrels of
equivalent per day although the mix was a little lighter on natural gas
at 28.93 million cubic feet per day and a little stronger on oil and
liquids at 3,618 barrels per day. The Trust currently anticipates that
first half 2005 production will be consistent with the 2004 fourth
quarter rates with natural gas volumes of about 29.25 million cubic feet
per day and oil and natural gas liquids production of 3,625 barrels per
day.

Zargon's 2005 exploration and development capital budget has been set at
$40 million. This budget projects the drilling of 45 net wells and is
allocated $15 million to each of the Alberta Plains and Williston Basin
core areas with the remaining $10 million allocated to West Central
Alberta. The majority of this capital program will occur in the second
half of the year, as an early spring break-up and a scarcity of field
services has set back our drilling program schedules. Based on the
current consensus for commodity pricing, these expenditures will be
mostly funded from cash flow from operations after the distribution of
50 percent of the cash flows attributed to unitholders.

With our very low debt to cash flow ratio, Zargon can make value-added
acquisitions when and if they become available using funds from
increased bank debt and/or new equity issues.

(a) Please see comments on "Forward Looking Statements" on the last page
of this report.

RESERVES

Formal disclosure of oil and natural gas reserves as required by
National Instrument 51-101 Standards of Disclosure ("NI 51-101") will be
included in the Trust's Renewal Annual Information Form for the year
ended December 31, 2004 that will be filed on SEDAR.

Since 1993, the independent engineering firm of McDaniel & Associates
Consultants Ltd. ("McDaniel") has evaluated 100 percent of Zargon's
reserves. Commencing with the 2003 year-end report Zargon's reserve
estimates have been calculated in accordance with NI 51-101. Under NI
51-101, proved reserve estimates are defined as having a 90 percent
probability that actual reserves recovered over time will equal or
exceed proved reserve estimates. Probable reserves are defined under NI
51-101 so that there are equal (50 percent) probabilities that the
actual reserves to be recovered will be less than, or greater than, the
proved and probable reserves estimate.

In a report dated March 3, 2005, McDaniel assigned the following reserve
estimates based on forecast prices and costs as of December 31, 2004:



Trust Reserves (1)

Oil and Natural
At December 31, 2004 Liquids Gas Equivalents (2)
------------------------------------------------------------------------
(mmbbl) (bcf) (mmboe)

Proved producing 10.76 37.32 16.98
Proved non-producing 0.08 10.80 1.88
Proved undeveloped 0.11 0.45 0.19
------------------------------------------
Total proved 10.95 48.57 19.05
Probable additional 3.41 20.99 6.90
------------------------------------------
Total proved and probable 14.36 69.56 25.95
------------------------------------------
------------------------------------------

(1) Trust working interest reserves before royalties, boe (6:1).

(2) Boe's may be misleading, particularly if used in isolation. A boe
conversion ratio of 6 mcf: 1 bbl is based on an energy equivalency
conversion method primarily applicable at the burner tip and does
not represent a value equivalency at the wellhead.


In this report, proved producing reserves represented 89 percent of
Zargon's total proved reserves while total proved reserves accounted for
73 percent of proved plus probable reserves. These percentages are
similar to the respective 90 and 76 percentages reported in the 2003
year-end report. Zargon's proved non-producing reserves are comprised
primarily of natural gas reserves from recently drilled wells at the
West Central Alberta areas of Pembina, Greater Highvale and the Peace
River Arch properties and behind pipe natural gas reserves at the
Alberta Plains Jarrow and Hamilton Lake properties. Proved undeveloped
reserves represent only one percent of the total proved reserves.
McDaniel forecasts $6.41 million of net future (forecast prices) capital
costs to deliver the total proved reserve estimate. Zargon's probable
reserves generally reflect incremental waterflood recoveries on
producing oil properties and improved gas recoveries for currently
producing natural gas wells.

McDaniel forecasts $8.37 million of net future (forecast prices) capital
costs to deliver the total proved and probable reserve estimate.

Based on 2004 year-end reserves and Zargon's 2004 fourth quarter
production rates of 3,618 barrels of oil per day and 28.93 million cubic
feet of natural gas per day, Zargon's proved reserve life index is 8.3
years for oil, 4.6 years for natural gas and 6.2 years on an equivalent
basis. The corresponding proved and probable oil, natural gas and
equivalent reserve life indices are 10.9, 6.6 and 8.4 years,
respectively. The relatively high oil reserve life reflects Zargon's
portfolio of long-life shallow-decline Williston Basin waterflood
projects.



RESERVE RECONCILIATION

A reconciliation of the 2004 year-end reserve assignments with the
reserves reported in the 2003 year-end report is presented below.

Reserve Reconciliation

Oil and Liquids (mmbbl) Natural Gas (bcf)
Proved Proved
Proved Probable & Prob. Proved Probable & Prob.
------------------------------------------------------------------------
------------------------------------------------------------------------
December
31, 2003(1) 10.50 3.06 13.56 48.95 18.12 67.07

Discoveries
& extensions 0.36 0.24 0.60 8.96 5.33 14.29
Revisions 0.57 (0.12) 0.45 1.48 (2.40) (0.92)
Acquisitions &
dispositions 0.77 0.23 1.00 (0.27) (0.06) (0.33)
Production (1.25) - (1.25) (10.55) - (10.55)
------------------------------------------------------
December
31, 2004 10.95 3.41 14.36 48.57 20.99 69.56
------------------------------------------------------------------------
------------------------------------------------------------------------
(1) Certain comparative numbers reflect the retroactive restatement of
removing royalty interest reserves from trust interest reserves in
accordance with NI 51-101.


Reserve Reconciliation

Equivalents (mmboe)
Proved Probable Proved& Prob.
------------------------------------------------------------------------
------------------------------------------------------------------------
December 31, 2003(1) 18.66 6.08 24.74

Discoveries & extensions 1.85 1.12 2.97
Revisions 0.82 (0.52) 0.30
Acquisitions & dispositions 0.73 0.22 0.95
Production (3.01) - (3.01)
------------------------------------------
December 31, 2004 19.05 6.90 25.95
------------------------------------------------------------------------
------------------------------------------------------------------------
(1) Certain comparative numbers reflect the retroactive restatement of
removing royalty interest reserves from Trust interest reserves in
accordance with NI 51-101.


Proved reserves at December 31, 2004 increased two percent from the
prior year. Proved 2004 reserve additions were 3.40 million barrels of
equivalent (after revisions) or 2.58 million barrels of equivalent
(before revisions). Positive technical reserve revisions were 0.82
million barrels of equivalent, which equated to four percent of the 2004
proved reserves opening balance. The majority of the positive revisions
were attributed to performance related adjustments to waterflood oil
properties in the Williston Basin.

On a proved and probable basis, Zargon increased its reserves by five
percent in 2004, with the addition of 4.22 million barrels of equivalent
(after revisions) or 3.92 million barrels of equivalent (before
revisions), thereby replacing annual production by a factor of 140
percent (130 percent before revisions). Field capital exploration and
development programs provided 2.97 million barrels of equivalent of new
additions, while net acquisitions, primarily in Southeast Saskatchewan,
added 0.95 million barrels of equivalent. Positive technical revisions
were 0.30 million barrels of equivalent, which equated to one percent of
the 2004 proved and probable reserves opening balance. The 2004 reserve
additions were derived from a $56.27 million net capital expenditure
program. Included in the 2004 capital expenditure program was $9.10
million of undeveloped land and seismic costs that should provide for
future reserves additions in subsequent years.

FINDING, DEVELOPMENT AND ACQUISTION COSTS

For 2004, Zargon's proved and probable finding, development and
acquisition costs ("FD&A" costs), taking into account reserve revisions
and changes in estimated future development capital during the period,
were $13.72 per barrel of equivalent. For the purposes of this
calculation, the $56.27 million of 2004 net capital additions were
combined with an increase in estimated future development capital for
proved and probable reserves of $1.61 million ($8.37 million at December
31, 2004 compared to $6.76 million at December 31, 2003). If future
development costs are excluded, the 2004 proved and probable finding,
development and acquisition costs, taking into account reserve
revisions, were $13.33 per barrel of equivalent.



Proved and Probable Finding, Development and Acquisition Costs (1)

2004 2003 2002
------------------------------------------------------------------------
Total net capital expenditures
($ million) 56.27 39.91 35.55
---------------------------
Total net capital expenditures plus
change in forecast future development
costs ($ million) 57.88 39.00 35.57
Proved and probable reserves (mmboe) (2)
Open 24.74 23.98 22.86
Additions (discoveries, extensions,
net acquisitions) 3.92 4.48 4.68
Revisions 0.30 (1.00) (1.24)
Production (3.01) (2.72) (2.32)
---------------------------
Close 25.95 24.74 23.98
---------------------------
---------------------------
Proved and probable FD&A costs ($/boe) (2) 13.72 11.21 10.34
Proved and probable three year
FD&A cost ($/boe) (2) 11.89 9.85 7.91
------------------------------------------------------------------------
------------------------------------------------------------------------

(1) In this table, the established reserves (proved plus 50 percent
probable) for 2002 are used as a comparison to the December 31, 2003
and 2004 proved and probable reserves, so as to reflect the
difference in the risk applied to these reserves as a result of the
NI 51-101 guidelines.

(2) Certain comparative numbers reflect the retroactive restatement
of removing royalty interest reserves from Trust interest reserves
in accordance with NI 51-101.


Zargon experienced higher FD&A costs in 2004. The industry wide trend to
higher costs as well as weaker than expected drilling results in the
West Central Alberta area were key contributors to the increase in FD&A
costs.

NET ASSET VALUE

Zargon's oil, natural gas liquids and natural gas reserves were
evaluated using McDaniel product price forecasts effective January 1,
2005, prior to provisions for income taxes, interest, debt service
charges and general and administrative expenses. It should not be
assumed that the following discounted future net property cash flows
estimated by McDaniel represent the fair market value of the reserves:



Before Tax Present Value of Future Net Revenue
(Forecast Price Case)

Discount Factor
------------------------------------
($ million) 0% 5% 10% 15%
------------------------------------------------------------------------
Proved producing 276.8 237.9 208.5 186.2
Proved non-producing 38.2 33.4 29.6 26.6
Proved undeveloped 2.5 1.8 1.3 0.9
------------------------------------
Total proved 317.5 273.1 239.4 213.7
Probable 132.4 92.2 68.8 54.1
------------------------------------
Total proved and probable 449.9 365.3 308.2 267.8
------------------------------------------------------------------------
------------------------------------------------------------------------


Before Tax Present Value of Future Net Revenue
(Constant Price Case)

Discount Factor
------------------------------------
($ million) 0% 5% 10% 15%
------------------------------------------------------------------------
Proved producing 314.4 259.1 221.5 194.5
Proved non-producing 43.5 37.7 33.1 29.5
Proved undeveloped 3.0 2.1 1.5 1.1
------------------------------------
Total proved 360.9 298.9 256.1 225.1
Probable 148.2 101.3 75.0 58.6
------------------------------------
Total proved and probable 509.1 400.2 331.1 283.7
------------------------------------------------------------------------
------------------------------------------------------------------------


The following net asset value table shows what is customarily referred
to as a "produce-out" net asset value calculation under which the
current value of Zargon's reserves would be produced at McDaniel
forecast future prices and costs. The value is a snapshot in time as of
December 31, 2004 and is based on various assumptions including
commodity prices and foreign exchange rates that vary over time. In this
analysis, the present value of the proved and probable reserves is
calculated at a before tax 10 percent discount rate, and the value
assigned to the undeveloped land was provided by the independent firm of
Seaton-Jordan and Associates Ltd.



Net Asset Value

As at December 31 ($ million) 2004 2003 2002
------------------------------------------------------------------------
Proved and probable reserves
(PVBT 10%)(1) (2) 308.2 219.6 215.4
Undeveloped land (3) 32.2 29.0 22.4
Working capital (9.1) (6.1) (3.5)
Bank debt (14.2) (7.0) (25.3)
Proceeds from the exercise of all
trust unit rights 10.3 9.1 6.2
-----------------------------
Net asset value (including trust
unit rights dilution) 327.4 244.6 215.2
-----------------------------
-----------------------------
Net asset value per unit
Total ($/unit) 17.04 13.09 11.85
With full dilution ($/unit) (4) 17.06 12.68 11.42
-----------------------------
-----------------------------

(1) McDaniel estimate of future before tax cash flow discounted at
PV 10 percent. Reserves for December 31, 2002 are presented as
established (proved plus 50 percent probable) reserves as the best
comparison to December 31, 2003 and 2004 proved and probable
reserves, reflecting the difference in the risk applied to these
reserves as a result of the NI 51-101 guidelines.

(2) PVBT represents present value before taxes.

(3) Seaton-Jordan year-end estimates.

(4) Full dilution of units represent the year-end units outstanding
plus the presumed exercise of all trust unit rights and the
conversion of exchangeable shares converted at the exchange ratio
at the end of the period.


If the net asset value calculation is adjusted to assume that the
commodity prices received at year-end 2004 (Edmonton light crude oil at
$46.51 Cdn per barrel and Alberta AECO natural gas at $6.62 Cdn per
gigajoule) will remain constant throughout the future (McDaniel constant
price case), the equivalent analysis calculates a 10 percent present
value before tax (PVBT) net asset value of $18.25 per fully diluted unit.

PLAN OF ARRANGEMENT

On July 15, 2004, approval was given by the shareholders to a resolution
in favour of a Plan of Arrangement (the "Arrangement") reorganizing
Zargon Oil & Gas Ltd. (the "Company") into Zargon Energy Trust ("Zargon"
or the "Trust"). The Arrangement received court approval and also became
effective on July 15, 2004. The Arrangement resulted in shareholders of
the Company receiving either one trust unit or one exchangeable share
for each common share held. The unitholders of the Trust are entitled to
receive cash distributions paid by the Trust. Holders of exchangeable
shares are not eligible to receive distributions but rather on each
payment of a distribution, the number of trust units into which each
exchangeable share is exchangeable is increased on a cumulative basis in
respect of the distribution. The exchangeable shares are traded on the
Toronto Stock Exchange and can be converted, at the option of the
holder, into trust units at any time. On July 15, 2014, all the
remaining outstanding exchangeable shares will be redeemed into trust
units unless the Board of Directors of the Company elect to extend the
redemption period. In certain circumstances, the Company has the right
to require redemption of the exchangeable shares prior to July 15, 2014.
Upon completion of the Arrangement, 14.87 million trust units and 3.66
million exchangeable shares were issued. The Trust is an unincorporated
open-end investment trust governed by the laws of the Province of
Alberta. It is the intent of the Trust to distribute approximately 50
percent of the cash flow from operations attributable to outstanding
unitholders.

The reorganization of the Company into a Trust has been accounted for
using the continuity of interest method. Accordingly, the consolidated
financial statements for the year ended December 31, 2004 reflect the
financial position, results of operations and cash flows as if the Trust
had always carried on the business of the Company. All comparative
figures referred to in this press release reflect the previous
consolidated results of the Company.

Monthly distributions of $0.14 per unit from the Trust commenced in
August 2004, with a total of $10.70 million ($0.70 per unit) declared
distributable to unitholders. This monthly distribution matches what was
estimated at the time of the Arrangement. These distributions are a
return on capital and are 100 percent taxable income to unitholders.

2004 HIGHLIGHTS

The combination of high crude oil prices, continued strong natural gas
prices and production volume gains enabled Zargon to achieve record
revenues and cash flow from operations in 2004, showing gains of 22
percent and 17 percent, respectively, over the prior year. The annual
revenue gain came from a combination of factors, including a 24 percent
increase in oil and liquids prices, a four percent increase in oil and
liquids production and a 16 percent gain in natural gas production. The
percentage increase in cash flow from operations was not as high as the
increase in revenues due to increased royalties and operating costs. Net
earnings for the year were $20.63 million, a 15 percent reduction from
2003. Earnings for 2003 were enhanced significantly by the mid-year
announcement of future federal tax rate reductions that produced a large
one-time reduction in future tax provisions. Earnings for 2004 were
impacted by a significant one-time charge of $2.17 million related to
the accelerated vesting of stock options as a result of the July 15,
2004 Arrangement and also an increase in depletion and depreciation of
$7.75 million related to increased production volumes and upward
pressure on finding and development costs in the industry. Also, a
charge of $1.87 million for non-controlling interest related to the
exchangeable shares was incurred due to the adoption of the CICA
Emerging Issues Committee accounting standard EIC-151, "Exchangeable
Securities Issued by Subsidiaries of Income Trusts".

Net capital expenditures for 2004 totalled $56.27 million with $44.46
million allocated to field-related activities. The 2004 capital program
showed a 41 percent increase in overall net expenditures and a 19
percent increase in field-related expenditures. Net property
acquisitions increased by $9.20 million, primarily due to the
acquisition of a portfolio of oil properties in Weyburn and Elswick,
Saskatchewan of the Williston Basin. This acquisition occurred on July
26, 2004 and added approximately 250 barrels per day of oil production.
For the year ended December 31, 2004, Zargon spent $3.84 million to
maintain an undeveloped land base of 376,000 net acres (2003 - 398,000
net acres); shot or acquired seismic at a cost of $5.26 million;
drilled, equipped and tied-in wells for $35.36 million and made net
property acquisitions of $11.81 million. Also, costs incurred to
reorganize into a trust were $9.44 million (of which $7.87 million
relates to the settlement of employee and director stock options as part
of the Arrangement) and distributions to unitholders totalled $10.70
million during the year. All of these activities were funded by the high
cash flows received throughout the year plus an increase in debt net of
working capital of $10.27 million.



FINANCIAL HIGHLIGHTS

($ million, except per unit amounts) 2004 2003 2002
------------------------------------------------------------------------
------------------------------------------------------------------------
Petroleum and natural gas revenue 123.97 101.66 65.54

Cash flow from operations 63.75 54.35 32.12
Per unit - diluted 3.40 2.96 1.81

Net earnings (1) 20.63 24.36 10.70
Per unit - diluted (1) 1.20 1.33 0.60

Total assets (1) 226.96 181.05 160.01

Net capital expenditures 56.27 39.91 35.55

Bank indebtedness 14.23 6.98 25.28

Cash distributions 10.70 - -
------------------------------------------------------------------------
------------------------------------------------------------------------
(1) Comparative period numbers reflect the retroactive restatements
due to a change in accounting policy.


DETAILED FINANCIAL ANALYSIS

Petroleum and Natural Gas Revenue

Zargon derives its revenue from the production and sale of petroleum
(oil, natural gas liquids) and natural gas. Petroleum and natural gas
revenue, exclusive of hedges, increased 22 percent to $123.97 million in
2004 from $101.66 million in 2003 due to increased production and higher
prices. Because of the gains in both oil production volumes and prices
received, the allocation of production revenue in 2004 increased to 46
percent from the sale of oil and liquids and 54 percent from the sale of
natural gas, compared to 43 percent from oil and liquids and 57 percent
from natural gas in the preceding year. Production volumes in 2004
increased 10 percent from the prior year, made up of a natural gas
production increase of 16 percent and an oil and liquids production
increase of four percent. Production increases for natural gas resulted
primarily from the drilling and tie-in of new wells in the West Central
Alberta and the Alberta Plains core areas. Production increases in oil
and liquids resulted from Williston Basin property acquisitions and
field exploitation programs. The average price of oil and liquids
received by Zargon rose to $45.37 per barrel in 2004, up 24 percent from
2003. The average field price of natural gas was $6.37 per thousand
cubic feet in 2004, a one percent increase over $6.33 per thousand cubic
feet in 2003.

Petroleum (Oil and Natural Gas Liquids) Pricing

Zargon's field oil and natural gas liquids prices are adjusted at the
point of sale for transportation charges and oil quality differentials
from an Edmonton light sweet crude price that varies with world
commodity prices. In 2004, Zargon's average oil and liquids field price,
exclusive of price hedges, rose 24 percent to $45.37 per barrel from
$36.66 per barrel in 2003 and $34.45 per barrel in 2002. The field price
differential for Zargon's average blended 30 degree API crude stream was
$7.17 per barrel less than the 2004 Edmonton reference crude price,
which compares to the 2003 differential of $6.48 per barrel and the 2002
differential of $5.49 per barrel. As the quality and weight of Zargon's
crude stream have remained relatively consistent for several years, the
movements in the Zargon's price differential is derived from the North
American refinery supply and demand factors for light and medium crudes.

Natural Gas Pricing

The average field natural gas price exclusive of price hedges for 2004
remained strong at $6.37 per thousand cubic feet which is relatively
unchanged from the 2003 average of $6.33 per thousand cubic feet. The
average for 2003 was 66 percent above 2002, 22 percent above both 2001
and 2000 and far above all previous years.

Approximately 23 percent of Zargon's 2004 natural gas production was
sold under aggregator contracts pursuant to long-term contracts with
Cargill Gas Marketing Ltd. (Jarrow - 18 percent) and ProGas Limited
(Hamilton Lake - five percent), compared to 35 percent in the prior
year. The remainder of Zargon's natural gas production was sold by spot
sale contracts and Alberta index prices were received. In 2004, Zargon
continued with an ongoing trend to develop new sources of natural gas
production which receives spot sale natural gas prices and is not
subject to aggregator contract prices.

Hedging Activities

Zargon's commodity price risk management policy uses forward sales,
options, puts and costless collars for, on average, 20 to 35 percent of
our oil and natural gas working interest production in order to
partially offset the effects of large price fluctuations. As both
Canadian oil and natural gas field prices are closely correlated to US
dollar denominated markets, Zargon will also place US/Cdn. currency
exchange hedges when considered prudent. Because our hedging strategy is
protective in nature and is designed to guard the Trust against extreme
effects from sudden falls in prices and revenues, upward price spikes
and trends tend to produce overall losses. For 2004, the total hedging
loss was $4.57 million compared to a loss of $2.88 million in 2003 and a
gain of $0.67 million in 2002. Of the 2004 loss, $4.01 million
(equivalent to a reduction of $3.20 per barrel) is related to oil hedges
and $0.56 million (equivalent to a reduction of $0.05 per thousand cubic
feet) was related to gas hedges. In 2004, oil prices increased
throughout the year, peaking in the month of October. Natural gas prices
were volatile during the year but they did not have the same upward
trend as experienced by oil prices. The Trust also entered into fixed
price physical contracts which created a gain of $0.25 million
(equivalent to an increase of $0.02 per thousand cubic feet) in 2004.
Gains or losses on fixed price physical contracts are included in
petroleum and natural gas revenue in the statement of earnings. For a
summary of contracts outstanding as at December 31, 2004, please refer
to note 11 to the consolidated financial statements.

Royalties

Royalties include payments made to the Crown, freehold owners and third
parties. Reported royalties also include credits received through the
Alberta Royalty Tax Credit (ARTC) program, the cost of the Saskatchewan
Resource Surcharge (SRC) and the cost of North Dakota state taxes.
During 2004, total royalties were $28.05 million, an increase of 25
percent from $22.51 million in 2003. Royalties as a percentage of gross
revenue (before hedging adjustments) were 22.6 percent in 2004 compared
to 22.1 percent in 2003 and 20.6 percent in 2002. On a commodity basis,
oil royalties averaged 21.5 percent (before hedging) in 2004, a small
increase from the previous year's average of 20.2 percent. Natural gas
royalties averaged 23.5 percent, unchanged from the prior year.

During 2004, 59 percent of the total royalties were paid to provincial
and state governments, with the remainder paid to freehold owners and
other third parties. Royalties payable to the Province of Alberta on
qualifying properties are reduced through the ARTC program. Zargon
earned the maximum $0.50 million ARTC rebate in 2004, which is the same
amount received in 2003, compared to $0.32 million received in 2002. The
SRC charges were $0.64 million in 2004, up from $0.53 million in the
prior year and $0.52 million in 2002. North Dakota state taxes increased
to $1.25 million in 2004 from $0.52 million in the prior year, primarily
due to increased prices for oil, as well as increased production in the
state.

Production Expenses

Zargon's production expenses increased 26 percent to $21.69 million in
2004 from $17.20 million in 2003. On a unit of production basis,
production expenses increased 14 percent to $7.21 per barrel of
equivalent from $6.33 in 2003 ($6.75 in 2002).

Natural gas production expenses in 2004 rose 18 percent to $0.84 per
thousand cubic feet from $0.71 per thousand cubic feet in 2003. The
primary reasons for the increase are due to increased third-party
processing costs for new gas discoveries in areas where Zargon does not
own processing facilities, increased rentals for compression equipment,
increased chemical and lubricant costs for field site treatment of sour
gas wells and also the industry-wide trend to higher operating costs.

Oil production expenses also rose in 2004 to $10.30 per barrel, an
increase of 15 percent from $8.95 per barrel in 2003. With the strong
oil prices during the year, efforts were made to reactivate previously
uneconomic oil production, which caused additional well servicing and
workover costs. Also, chemicals, fuel and weather related road
maintenance costs increased during the year.

Due to the high levels of industry activity caused by the high commodity
price environment, there is increasing upward pressure on per unit
operating costs. This trend is expected to continue if industry activity
levels continue at the current record levels. In 2003, Zargon was able
to deliver a cost improvement on a per unit of production basis over the
prior year through the disposition of smaller, higher cost properties.
In 2004, Zargon's costs increased substantially due in general to the
effect of industry-wide higher cost trends and due in particular to the
impact of the addition of new higher cost natural gas and oil production
volumes. For 2005, Zargon expects the trend of increasing costs to
continue as the demand for services is expected to continue at
unprecedented levels.

Operating Netbacks

The average oil price received after hedges in 2004 of $42.17 per barrel
was 18 percent higher than the $35.79 per barrel received in 2003, while
the average natural gas price received after hedges in 2004 of $6.32 per
thousand cubic feet was three percent above the $6.13 per thousand cubic
feet received in 2002. Operating netbacks increased commensurately. Oil
and natural gas liquids netbacks rose 14 percent to $22.10 per barrel
from $19.42 per barrel in 2003. Natural gas netbacks increased one
percent to $3.98 per thousand cubic feet from $3.93 per thousand cubic
feet in 2003. On a barrel of oil equivalent basis, 2004 operating
netbacks rose seven percent to $23.15 from $21.73 in 2003.



OPERATING NETBACKS
2004 2003

Oil and Oil and
Liquids Natural Gas Liquids Natural Gas
------------------------------------------------------------------------
($/bbl) ($/mcf) ($/bbl) ($/mcf)

Production revenue 45.37 6.37 36.66 6.33
Hedging (3.20) (0.05) (0.87) (0.20)
Royalties (9.77) (1.50) (7.42) (1.49)
Production costs (10.30) (0.84) (8.95) (0.71)
-------------------------------------------------

Operating netbacks 22.10 3.98 19.42 3.93
------------------------------------------------------------------------
------------------------------------------------------------------------


General and Administrative Expenses

Gross general and administrative costs increased 22 percent in 2004 to
$7.23 million from $5.94 million in 2003. On a unit of production basis,
net general and administrative costs increased 12 percent to $1.45 per
barrel of equivalent, compared to $1.30 per barrel in 2003 and $1.49 per
barrel in 2002. In 2004, the increased general and administrative costs
on a per unit of production basis were due to increased staff costs,
performance-based compensation costs, increased regulatory reporting
requirements and the additional legal and other outside advisory costs
of operating as a trust. In the prior year, the improvement in per
barrel of equivalent costs was due to an increase in production volumes
and an increase in capital program overhead recoveries. Going forward in
a sustainable trust model, Zargon will attempt to maintain its general
and administrative costs on a per unit of production basis at current
levels.



GENERAL AND ADMINISTRATIVE EXPENSES

($ million, except as noted) 2004 2003 2002
------------------------------------------------------------------------

Gross general and
administrative expense 7.23 5.94 5.06
Overhead recoveries (2.87) (2.40) (1.61)
---------------------------

Net general and administrative expense 4.36 3.54 3.45
---------------------------

Net expense after recoveries ($/boe) 1.45 1.30 1.49
Number of office employees at year-end 35 34 30
------------------------------------------------------------------------
------------------------------------------------------------------------


Interest Expense

Zargon's borrowings are through its bank line of credit. Interest
charges were $0.44 million compared to $0.77 million in 2003. A
reduction in the average debt level is the primary reason for the
reduction in interest charges. Zargon's effective interest rate was 4.9
percent on an average bank debt of $8.88 million in 2004, compared to
4.5 percent on an average bank debt of $17.19 million in 2003 and 4.1
percent on an average bank debt of $26.72 million in 2002. At year-end
2004, Zargon's bank debt, net of working capital, totalled $23.37
million, up 78 percent from $13.09 million at December 31, 2003.

Capital and Current Income Taxes

During 2004, Zargon incurred $1.11 million of current income taxes
compared to $0.41 million in 2003. The increase is primarily due to
current taxes incurred in the United States of $0.61 million. If high
oil prices continue, there may be similar United States current income
taxes payable annually, that will be somewhat modified by Zargon's
United States capital program activity levels. The remaining amounts of
current income taxes relate to federal and provincial capital taxes,
which were $0.50 million in 2004 compared to $0.41 million in 2003. Tax
pools as at December 31, 2004 were approximately $79 million. The Trust
is a taxable entity under the Income Tax Act of Canada and is taxable
only on the income that is not distributed or declared distributable to
unitholders. It is anticipated that sufficient distributions will be
made to eliminate current Canadian income tax. For Canadian income tax
purposes, distributions are currently estimated to be 100 percent
taxable income to unitholders.

Trust Netbacks

Historically high oil prices and the continued strength of natural gas
prices in 2004 resulted in higher revenue netbacks and operating
netbacks. On a barrel of equivalent basis, revenue of $41.20 in 2004 was
10 percent higher than the prior year and operating netbacks as well as
cash flow netbacks increased seven percent and six percent over the
prior year to $23.15 and $21.18 per barrel of equivalent, respectively.



TRUST NETBACKS

($/boe) 2004 2003 2002
------------------------------------------------------------------------

Petroleum and natural gas revenue 41.20 37.40 28.28
Hedging (1.52) (1.06) 0.29
Royalties (9.32) (8.28) (5.83)
Production costs (7.21) (6.33) (6.75)
-----------------------------

Operating netbacks 23.15 21.73 15.99

General and administrative (1.45) (1.30) (1.49)
Interest (0.15) (0.28) (0.47)
Capital and current income taxes (0.37) (0.15) (0.17)
-----------------------------
Cash flow netbacks 21.18 20.00 13.86

Depletion and depreciation (1) (9.11) (7.23) (6.07)
Accretion of asset retirement
obligations (1) (0.36) (0.43) (0.31)
Unit-based compensation (1.22) (0.10) -
Unrealized foreign exchange 0.19 0.11 (0.03)
Future income taxes (1) (3.20) (3.38) (2.83)
-----------------------------

Earnings before non-controlling interest 7.48 8.97 4.62

Non-controlling interest (0.62) - -
-----------------------------

Net earnings 6.86 8.97 4.62
------------------------------------------------------------------------
------------------------------------------------------------------------

(1) Comparative period numbers reflect the retroactive restatements due
to a change in accounting policy.


Cash Flow from Operations

In 2004, a 10 percent gain in production volumes, in addition to
increases of 24 percent in oil and natural gas liquids prices and one
percent in natural gas prices, produced a 17 percent gain in cash flow
from operations to $63.75 million, compared to $54.35 million in 2003
and $32.12 million in 2002. The corresponding cash flow per diluted unit
was $3.40 in 2004, a 15 percent gain from $2.96 per diluted share in
2003 and compares to $1.81 in 2002. The diluted per unit statistics
reflected a two percent increase in the weighted average outstanding
units to 18.72 million in 2004 and a three percent increase in the
weighted average number of outstanding shares to 18.37 million in 2003,
from 17.79 million in 2002.

Depletion and Depreciation

In 2004, Zargon's depletion and depreciation provision increased 39
percent to $27.41 million, compared to $19.66 million in 2003 and $14.06
million in 2002. The higher charges reflect an increase of 10 percent in
production volumes and a 26 percent increase in the charge on a per
barrel of oil equivalent basis. This large increase in the per barrel of
oil equivalent depletion and depreciation expense is primarily due to a
December 31, 2003 year-over-year 14 percent reduction in the Trust's
proved reserves as calculated under the new policies of National
Instrument 51-101.

Depletion and depreciation charges calculated on a unit of production
method are based on total proved reserves with a conversion of six
thousand cubic feet of natural gas being equivalent to one barrel of
oil. The 2004 depletion calculation includes $6.41 million of future
capital expenditures to develop the Trust's reserves, but excludes
$14.68 million of unproven properties relating to undeveloped land.

Zargon's depletion and depreciation, on a barrel of equivalent basis,
increased 26 percent in 2004 to $9.11 from $7.23 in 2003 and $6.07 in
2002. Depletion and depreciation rates will be subject to continuing
upward pressure as industry finding and development costs increase to
reflect the new economics of the recent trends to substantially higher
commodity prices.

Accretion of Asset Retirement Obligations

In 2003, the CICA approved section 3110 (Asset Retirement Obligations)
effectively requires site restoration expense to be treated as a
discounted future liability that is recognized in the balance sheet and
amortized over the useful life of the related assets. The liability
accretes until the retirement obligations are settled. Zargon
retroactively adopted this standard effective January 1, 2004 and the
expense line formerly termed Site Restoration is now called Accretion of
Asset Retirement Obligations. For the year ended December 31, 2004, the
non-cash accretion expense is $1.08 million compared to $1.17 million in
2003 and $0.72 million in 2002. The significant assumptions used in this
calculation are a credit adjusted risk-free rate of 8.5 percent, an
inflation rate of two percent and the payments to settle the retirement
obligations will be made over the next 30 years with the majority of the
costs being incurred after 2012. The estimated net present value of the
total asset retirement obligation is estimated to be $14.39 million as
at December 31, 2004, based on a total future liability of $59.12
million.

Unit-Based Compensation

Unit-based compensation was $3.68 million in 2004 or $3.42 million
higher than compared to $0.26 million in 2003. Of this amount, $2.17
million is related to a one-time charge for the accelerated vesting of
stock options related to the July 15, 2004 Arrangement. The remainder is
primarily the expense for the new trust unit rights incentive plan,
which is calculated using the intrinsic value method which is based on
the amount that the market price of the trust unit right exceeds the
grant price for the rights issued. Prior to the effective date of the
Plan of Arrangement, expensing of stock-based compensation benefits in
the consolidated statement of earnings was calculated using the
Black-Scholes option-pricing model. These non-cash expenses will be
recurring charges in future years if Zargon continues to grant employee
and director trust unit rights.

The trust unit rights incentive plan allows the Trust to issue rights to
acquire trust units to directors, officers, employees and service
providers. The Trust is authorized to issue up to 1.82 million unit
rights; however, the number of trust units reserved for issuance upon
exercise of the rights shall not exceed 10 percent of the aggregate
number of issued and outstanding trust units of the Trust, and the plan
allows for the holder of rights to either exercise the right based on
the original grant price or on the original grant price reduced by a
portion of the future distributions. Unit right grant prices approximate
the market price for the trust units on the date the unit rights are
issued. Trust unit rights granted under the plan vest over a three-year
period and expire five years from the grant date.

Future Income Taxes

Zargon's 2004 future tax expense increased five percent to $9.64 million
from $9.19 million in 2003. The effective future tax rate in 2004 was
29.0 percent compared to 27.1 percent in 2003 and 37.2 percent in 2002.
Effectively, Zargon's future tax obligations are reduced as
distributions are made from the Trust, and consequently it is
anticipated that Zargon's effective 2005 future tax rate will continue
to decline in the Trust's first full year of operations. Comparisons
with the 2003 period are distorted by the significant one-time federal
tax rate adjustment that was booked to future taxes in 2003. In 2003,
Royal Assent was received, thereby legislating certain federal
reductions in corporate tax rates over a five-year period commencing in
2003. The rate changes incorporate a reduction in federal tax rates. The
future tax impact related to reorganization costs of $0.49 million was
charged to accumulated earnings.

Net Earnings

Zargon's 2004 net earnings were $20.63 million, a 15 percent reduction
from $24.36 million in 2003. The 2002 net earnings were $10.70 million.
The very strong 2003 increase was due primarily to the 69 percent
increase in cash flow from operations and secondarily to the downward
adjustment made in the 2003 future tax provision, which effectively
added about $4.31 million to net earnings. On a per diluted unit basis,
2004 net earnings were $1.20 compared to $1.33 in 2003 and $0.60 in 2002.

On a barrel of equivalent, the 2004 net earnings were $6.86 compared to
$8.97 in 2003 and $4.62 in 2002. In 2004, net earnings were 32 percent
of cash flow. Reflecting primarily the adjustment in future tax
calculations, the 2003 net earnings represented 45 percent of cash flow
compared to 33 percent of cash flow in 2002.

Capital Expenditures

Net capital expenditures in 2004 of $56.27 million increased 41 percent
over $39.91 million in 2003. This increase was due to a very active
drilling program of 60 gross (49.5 net) wells for the year and the net
$11.81 million purchase of producing Saskatchewan oil properties in the
Williston Basin core area. Drilling and completion expenditures were up
56 percent to $26.94 million. Of the total 2004 net capital
expenditures, $22.12 million was expended on West Central Alberta,
$14.57 million on Alberta Plains and $19.58 million on Williston Basin
properties.



CAPITAL EXPENDITURES

($ million) 2004 2003 2002
------------------------------------------------------------------------

Undeveloped land 3.84 6.98 4.46
Geological and geophysical (seismic) 5.26 5.69 2.47
Drilling and completion of wells 26.94 17.30 12.49
Well equipment and facilities 8.42 7.33 4.48
----------------------------

Exploration and development 44.46 37.30 23.90
----------------------------

Property acquisitions 12.09 7.83 7.39
Property dispositions (0.28) (5.22) (3.13)
----------------------------

Net property acquisitions 11.81 2.61 4.26
----------------------------

Corporate acquisitions - - 7.39
----------------------------

Total net capital expenditures 56.27 39.91 35.55
------------------------------------------------------------------------
------------------------------------------------------------------------


LIQUIDITY AND CAPITAL RESOURCES

Zargon relies on three sources of funding:

- Internally generated cash flow provides the basic level of funding for
the Trust's annual capital expenditures program and for distributions to
unitholders.

- Debt may be utilized for acquisitions or to expand capital programs
when it is deemed appropriate. The Trust has a $50 million revolving
demand credit facility. As at December 31, 2004, $35.77 million or 72
percent of this line is unutilized. The Trust has followed and intends
to maintain a conservative debt policy.

- New equity, if available and if on favourable terms, can be utilized
for acquisitions or to expand capital programs.

In 2004, cash flow from operations of $63.75 million, proceeds from the
exercise of stock options of $2.87 million and the increase in bank debt
covered the capital program, costs incurred for the trust reorganization
and the cash distributions to unitholders.



CAPITAL SOURCES

($ million) 2004 2003 2002
------------------------------------------------------------------------
Cash flow from operations 63.75 54.35 32.12
Changes in working capital and other 2.54 2.66 (3.58)
Change in bank indebtedness 7.25 (18.30) 1.14
Reorganization costs (9.44) - -
Cash distributions (10.70) - -
Issuance of common shares 2.87 1.20 5.87
----------------------------
Total capital sources 56.27 39.91 35.55
------------------------------------------------------------------------
------------------------------------------------------------------------


Cash Flow from Operations

It is anticipated that Zargon's 2005 capital budget and cash
distributions to unitholders will be financed through the Trust's cash
flow from operations. Cash flow is partially influenced by factors that
the Trust cannot control, such as commodity prices, the US/Canadian
dollar exchange rates and interest rates. Zargon's 2005 estimated
sensitivity to moderate fluctuations in these key business parameters is
shown in the accompanying table.



CASH FLOW SENSITIVITY SUMMARY

Change in 2005 Cash Flow
------------------------------------------------------------------------
($ million) ($/unit)
Change of $1.00 US/bbl in the price of WTI oil 1.00 0.05
Change in oil production of 100 bbl/d 0.64 0.03
Change of $0.10 US/mcf in the
price of NYMEX natural gas 0.89 0.04
Change in natural gas production of one mmcf/d 1.41 0.07
Change in $0.01 in the $US/$Cdn exchange rate 1.14 0.06
------------------------------------------------------------------------
------------------------------------------------------------------------


Bank Indebtedness

At December 31, 2004, bank debt was $14.23 million, an increase of 104
percent from the prior year-end amount of $6.98 million. In accordance
with Canadian GAAP, the revolving demand bank debt is treated as a
current liability.

Zargon's combined debt and working capital deficiency of $23.37 million
at December 31, 2004 was equivalent to 37 percent of the 2004 cash flow
from operations of $63.75 million. At December 31, 2003 the combined
debt and working capital deficiency was $13.09 million, equivalent to 24
percent of 2003 cash flow from operations.

Equity

At March 14, 2005, Zargon had 15.665 million trust units and 2.913
million exchangeable shares outstanding. Assuming full conversion of
exchangeable shares at the effective exchange ratio of 1.03726, there
would be 18.687 million trust units outstanding at this date. Pursuant
to the new trust unit rights incentive plan, there are currently an
additional 0.537 million trust unit rights issued and outstanding.

During 2004, 17.75 million Zargon trust units and common shares traded
on The Toronto Stock Exchange with a high of $24.90 per unit, a low of
$13.00 per share and a unit closing price of $23.85 per unit. The 2004
trading statistics show a 272 percent year-over-year increase in trading
volume, and a 77 percent increase in the closing stock price. Zargon's
market capitalization (including the market value of exchangeable
shares) at year-end 2004 was approximately $444 million, compared to
approximately $243 million at the end of 2003.

Segmented Geographic Information

In calendar 2004 and 2003, approximately 88 percent of Zargon's combined
petroleum and natural gas revenue came from Western Canada (Alberta,
Saskatchewan and Manitoba) properties, with the remaining 12 percent of
revenues generated in the United States (North Dakota and Montana).

CRITICAL ACCOUNTING ESTIMATES

The preparation of the consolidated financial statements in accordance
with Canadian generally accepted accounting principles requires
management to make judgments and estimates that affect the financial
results of the Trust. Zargon'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 critical estimates are discussed below:

Petroleum and Natural Gas Reserves

All of Zargon's petroleum and natural gas reserves are evaluated and
reported on by independent petroleum engineering consultants in
accordance with Canadian Securities Administrators' National Instrument
51-101 ("NI 51-101"). The estimation of reserves is a subjective
process. Forecasts are based on engineering data, projected future rates
of production, commodity prices and the timing of future expenditures,
all of which are subject to numerous uncertainties and various
interpretations. The Trust expects that its estimates of reserves will
change to reflect updated information. Reserve estimates can be revised
upward or downward based on the results of future drilling, testing,
production levels, and changes in costs and commodity prices.

Full Cost Accounting

Zargon follows the full cost method of accounting for petroleum and
natural gas operations as outlined in Canadian Institute of Chartered
Accountants ("CICA") accounting guideline "Oil and Gas Accounting - Full
Cost" (AcG-16). Under this accounting method, all costs related to the
exploration for and development of petroleum and natural gas reserves
are capitalized. Capitalized costs, as well as the estimated future
expenditures to develop proved reserves, are depleted using the
unit-of-production method based on estimated proved oil and natural gas
reserves.

In applying the full cost method, Zargon calculates a ceiling test on a
quarterly basis to ensure that the net carrying value of petroleum and
natural gas assets do not exceed the estimated undiscounted future net
cash flows from production of proved reserves. Accordingly, the Trust
must base this calculation of future net cash flows on estimated
forecasted sales prices, costs and regulations in effect at the period
end. AcG-16 limits the carrying value of petroleum and natural gas
properties to their fair value. The fair value is equal to estimated
future cash flows from proved and probable reserves using future price
forecasts and costs discounted at a risk-free rate.

Asset Retirement Obligations

Effective January 1, 2004, Zargon adopted CICA Section 3110, "Asset
Retirement Obligations", which requires liability recognition for
retirement obligations associated with the Trust's property, plant and
equipment. Under this policy, the Trust is required to provide for
future removal and site restoration costs. The Trust must estimate these
costs in accordance with existing laws, contracts or other policies and
must also estimate a credit adjusted risk-free rate and inflation rate
in this calculation. These estimated costs are charged to earnings and
the appropriate liability account over the expected life of the asset.
When the future removal and site restoration costs cannot be reasonably
determined, a contingent liability may exist. Contingent liabilities are
charged to earnings when management is able to determine the amount and
the likelihood of the future obligation.

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.

RECENT CANADIAN ACCOUNTING PRONOUNCEMENTS

During 2004, the following new or amended standards and guidelines were
issued:

Exchangeable Securities Issued by Subsidiaries of Income Trusts

On January 19, 2005 the Emerging Issues Committee of the CICA issued
revised draft EIC-151 "Exchangeable Securities Issued by Subsidiaries of
Income Trusts" that states that exchangeable securities issued by a
subsidiary of an Income Trust should be reflected as either
non-controlling interest or debt on the consolidated balance sheet
unless they meet certain criteria. The exchangeable shares issued by
Zargon Oil & Gas Ltd., a corporate subsidiary of the Trust, are publicly
traded and have an expiry term, which could be extended at the option of
the Board of Directors. Therefore, these securities are considered, by
EIC-151 to be transferable to third parties and to have an indefinite
life. EIC-151 states that if these criteria are met, the exchangeable
shares should be reflected as non-controlling interest. Previously, the
exchangeable shares were reflected as a component of unitholders' equity.

In accordance with the transitional provisions of EIC-151, the Trust
must retroactively restate prior periods dating back to the Plan of
Arrangement dated July 15, 2004. As a result of this change in
accounting policy, the Trust has reflected non-controlling interest of
$9.53 million on the Trust's consolidated balance sheet as at December
31, 2004. Consolidated net earnings have been reduced for net income
attributable to the non-controlling interest of $1.87 million in 2004.
In accordance with EIC-151 and given the circumstances in Zargon's case,
each redemption is accounted for as a step-purchase, which for 2004
resulted in an increase in property and equipment of $11.28 million, an
increase of unitholders' equity by $0.62 million, and an increase in
future income tax liability of $3.00 million. Cash flow was not impacted
by this change.

Hedge Accounting

The CICA issued Accounting Guideline 13 ("AcG-13") "Hedging
Relationships", effective January 1, 2004, to clarify circumstances in
which hedge accounting is appropriate. In addition, the CICA
simultaneously amended EIC-128, "Accounting for Trading, Speculative or
Non-Trading Derivative Financial Instruments" to require that all
derivative instruments that do not qualify as a hedge under AcG-13, or
are not designated as a hedge, be recorded in the consolidated balance
sheet as either an asset or a liability with the changes in fair value
recognized in earnings.

The Trust uses derivative instruments to reduce its exposure to
fluctuations in commodity prices, foreign exchange, and interest rates.
The Trust formally documents all relationships between hedging
instruments and hedged items, as well as its risk management objective
and strategy for undertaking various hedge transactions. This process
includes linking all derivatives to specific assets and liabilities on
the consolidated balance sheet or to specific firm commitments or
forecasted transactions. The Trust also formally assesses whether the
derivatives that are used in hedging transactions are highly effective
in offsetting changes in fair values or cash flows of hedged items.

Since the Trust has designated its derivative instruments as hedges, the
implementation of this accounting policy did not have any impact on the
consolidated financial statements of the Trust.

Petroleum and Natural Gas Assets - Full Cost Accounting

The new CICA Guideline 16, "Oil and Gas Accounting - Full Cost"
("AcG-16") is effective for fiscal years beginning on or after January
1, 2004. The most significant change between AcG-16 and the former
guideline is that AcG-16 limits the carrying value of petroleum and
natural gas properties to their fair value. The fair value is equal to
estimated future cash flows from proved and probable reserves using
future price forecasts and costs discounted at a risk-free rate. This
differs from the former cost recovery ceiling test that used
undiscounted cash flows, and constant prices, less general and
administrative and financing costs. No write-down of the Trust's
petroleum and natural gas properties was required when the new guideline
was adopted on January 1, 2004 or as at December 31, 2004.

Asset Retirement Obligations

Effective January 1, 2004, Zargon adopted CICA Section 3110, "Asset
Retirement Obligations", which requires liability recognition for
retirement obligations associated with the Trust's property, plant and
equipment. The obligations are initially measured at estimated fair
value, which is the discounted future value of the estimated liability.
The fair value is capitalized as part of the cost of the related assets
and amortized to expense over their useful lives. The liability accretes
until the retirement obligations are settled. Section 3110 is effective
for fiscal years beginning on or after January 1, 2004 on a retroactive
basis with restatement of prior periods. The site restoration liability
on the balance sheet at December 31, 2003 was replaced with a new "Asset
Retirement Obligation" liability in the amount of $12.19 million on
January 1, 2004.

BUSINESS RISKS

Zargon's external business risks arise from the uncertainty of oil and
natural gas pricing, the uncertainty of interest and exchange rates,
environmental and safety issues, and financial and liquidity
considerations. Additional risk arises from the production performance
of existing properties (including natural decline), the changes in tax,
royalty and other regulatory standards and, uncertain results from
capital expenditure programs.

Oil and natural gas prices may fluctuate widely in response to many
factors such as global and North American supply and demand, economic
conditions, weather conditions, political stability, the supply and
price of imported oil and liquefied natural gas, production and storage
levels of North American natural gas, and government regulations. Zargon
attempts to minimize pricing and currency exchange uncertainty with a
risk management program that encompasses a variety of financial
instruments. These include forward sales of oil and natural gas
production (either through financial derivative transactions such as
swaps or by physical contracts), put options on both oil and natural
gas, costless collars (in which some potential high price gain is given
up in return for potential low price support) and US dollar currency
hedges in different forms for up to 35 percent of its oil and natural
gas production volumes. In general, the Trust seeks to use strategies
that allow minimum price expectations to be met in order that
distributions and capital programs can be funded. This strategy is
designed mainly to protect the Trust against periods of unusually low
commodity prices and by its nature is likely to produce significant
hedging losses when prices are unusually high.

Environmental and safety risks are mitigated through compliance with
provincial and federal environmental and safety regulations, by
maintaining adequate insurance, and by adopting appropriate emergency
response and employee safety procedures.

The Trust is subject to a broad range of laws and regulatory
requirements. Changes in government regulations, including reporting
requirements, income tax laws, operating practices, environmental
protection requirements and royalty rates can have a significant impact
on Zargon. Although Zargon has no control over these regulatory risks,
the Trust actively monitors changes, participates in industry
organizations and, when required, engages the assistance of third-party
experts to assess the impact of such changes in the Trust's financial
and operating results.

Financial and liquidity risks are reduced by limiting debt financing to
conservative self-imposed debt to cash flow guidelines. Zargon maintains
a low cash distribution to cash flow from operations ratio to ensure
adequate funding is available for capital programs to sustain per unit
production and reserves. Access to capital markets, if required for
additional financing by either debt or equity issuances, is dependent
upon maintaining strong performance and relationships with investors. A
substantial portion of the Trust's accounts receivable are with
companies in the oil and gas industry and are subject to normal industry
credit risks. Management regularly monitors the ageing of receivable
balances to mitigate this risk. With respect to financial instruments
utilized for hedging purposes, the Trust partially mitigates associated
credit risk by limiting transactions to counterparties with investment
grade credit ratings.

Zargon actively manages the risks of its capital programs and reserves
by concentrating drilling and subsequent development activities in areas
where it has demonstrated proven technical capabilities and
understanding. Zargon's capital budget is managed to limit exposure so
that significant capital is not risked on any one project or concept.



SELECTED QUARTERLY INFORMATION (1)

($ million, except per unit amounts) 2004
------------------------------------------------------------------------
Q4 Q3 Q2 Q1
------------------------------------------------------------------------
Petroleum and natural gas revenue 32.90 32.41 30.96 27.70

Cash flow from operations 15.36 16.13 16.53 15.73
Per unit - diluted(1) 0.82 0.87 0.88 0.84

Net earnings (1) 5.33 4.22 5.54 5.54
Per unit - diluted (1) 0.34 0.28 0.29 0.30

Cash distributions 6.43 4.27 - -
Cash distribution - per trust unit 0.42 0.28 - -

Net capital expenditures 15.25 23.64 7.61 9.77
Total assets (1) 226.96 215.23 189.80 186.18
Bank indebtedness 14.23 9.77 - 3.67
------------------------------------------------------------------------
------------------------------------------------------------------------

(1) Comparative period numbers reflect the retroactive restatements
due to changes in accounting policies.


($ million, except per unit amounts) 2003
------------------------------------------------------------------------
Q4 Q3 Q2 Q1
------------------------------------------------------------------------
Petroleum and natural gas revenue 24.51 23.76 24.20 29.19

Cash flow from operations 13.24 12.34 13.53 15.23
Per unit - diluted(1) 0.72 0.67 0.74 0.84

Net earnings (1) 4.10 4.44 9.17 6.65
Per unit - diluted (1) 0.22 0.24 0.50 0.36

Cash distributions - - - -
Cash distribution - per trust unit - - - -

Net capital expenditures 12.84 12.11 8.10 6.86
Total assets (1) 181.05 172.81 165.98 165.12
Bank indebtedness 6.98 8.92 11.47 20.78
------------------------------------------------------------------------
------------------------------------------------------------------------

(1) Comparative period numbers reflect the retroactive restatements
due to changes in accounting policies.


Fourth Quarter 2004 Highlights

During the fourth quarter of 2004, Zargon increased petroleum and
natural gas revenues by two percent or $0.49 million to $32.90 million
from the third quarter of 2004. Production for the fourth quarter of
2004 was 8,440 barrels of equivalent per day compared to 8,405 barrels
of equivalent per day in the third quarter of 2004 and slightly under
the guidance of 8,500 barrels of equivalent per day that was given in
Zargon's third quarter report. Oil production increased six percent to
3,618 barrels per day and natural gas production decreased three percent
to 28.93 million cubic feet per day compared to the prior quarter.
Average prices received during the fourth quarter, before hedging, were
$47.13 per barrel for oil and $6.46 per thousand cubic feet for natural
gas, a five percent reduction and a six percent increase respectively,
compared to the third quarter of 2004. During the quarter, Zargon's
field price differential for its blended 30 degree API crude oil stream
increased to $10.58 per barrel less than the Edmonton reference crude
oil price. This differential compares to $6.09 per barrel for the first
nine months of 2004 and is a response to reduced demand for Zargon's
medium grades of crude oil during the quarter.

Cash flow from operations was $15.36 million in the fourth quarter, a
decrease of five percent or $0.77 million from the prior quarter. The
primary factors that caused this decrease from the prior quarter are as
follows:

- Hedging losses increased by $0.13 million to $1.56 million compared to
$1.43 million, a nine percent increase from the prior quarter. The
primary reason for the increase in the fourth quarter was due to losses
on oil hedging contracts as a result of the continuing strength of oil
prices throughout the quarter.

- Royalties for the fourth quarter were $7.84 million, an increase of
$0.45 million from the prior quarter. The average royalty rate for the
quarter increased to 23.8 percent from 22.8 percent from the third
quarter due to adjustments related to prior periods.

- Production expenses totalled $6.28 million for the quarter, a $0.51
million or nine percent increase from the third quarter of 2004. On a
per barrel of oil equivalent basis, production expenses were $8.09 in
the fourth quarter 2004 compared to $7.45 in the prior quarter, a nine
percent increase. During the quarter, increased compression, treating
and third-party processing costs were incurred for recently added
natural gas production volumes. Increased costs were also incurred for
well servicing and workovers related to oil production. Also, the fourth
quarter included $0.26 million or $0.34 per barrel of equivalent of
costs that related to prior periods.

- General and administrative expenses increased in the fourth quarter by
$0.26 million over the third quarter of 2004. This is a 25 percent
increase compared to the prior quarter and is primarily due to amounts
for performance-based compensation for employees.

- Interest expense in the fourth quarter was $0.21 million, an increase
of 109 percent or $0.10 million from the prior quarter. This increase is
primarily due to the increase in the average debt level for the fourth
quarter to $14.62 million compared to $9.35 million in the third quarter
of 2004 and costs incurred in relation to the renewal of the Trust's
credit facility in the fourth quarter.

- Capital and current income taxes decreased by $0.21 million or 40
percent from the third quarter of 2004. The decrease was due to United
States current income taxes incurred in the third quarter of 2004.

Net earnings for the quarter increased $1.11 million to $5.33 million, a
26 percent increase compared to the third quarter 2004 earnings of $4.22
million. Net earnings track the cash flow from operations for the
respective periods modified by non-cash charges, which included the
following for the fourth quarter of 2004:

- Unit-based compensation expense decreased by $1.95 million during the
fourth quarter of 2004 to $0.71 million, as the third quarter included
the one-time charge of $2.17 million pertaining to the accelerated
vesting of stock options related to the July 15, 2004 Arrangement.

- Depletion and depreciation expense increased by $0.76 million to $7.77
million in the fourth quarter. The additional expense resulted from the
use of an updated depletion and depreciation rate of $10.00 per barrel
of equivalent, compared to the prior quarter's $9.06 per barrel of
equivalent charge. The increased per unit charges are calculated on the
basis of the recently completed 2004 year-end reserve appraisal prepared
by independent engineers that reflects Zargon's and the ongoing industry
trend to higher finding and development costs, which are commensurate
with the new economics of this current era of substantially higher
commodity prices.

- Future income tax expense was $0.57 million during the quarter, a
reduction of $0.81 million from the third quarter of 2004. As cash
distributions are made from the Trust, the effective future tax rate is
lowered. During the third quarter of 2004, only two months of
distributions totalling $4.27 million were made, compared to three
months of distributions made in the fourth quarter of 2004 totalling
$6.43 million. This increase in the amount of distributions resulted in
the lower amount of future taxes in the fourth quarter of 2004.

- Non-controlling interest related to exchangeable shares increased to
$1.01 million in the fourth quarter, from $0.86 million in the third
quarter (on a restated basis). The increase was due to an increase in
net earnings before non-controlling interest in the fourth quarter.

Net capital expenditures were $15.25 million during the fourth quarter
of 2004, a 35 percent reduction from the prior quarter amount of $23.64
million. If the third quarter's $10 million Southeast Saskatchewan oil
property acquisition is excluded, the fourth quarter capital program
showed a 12 percent increase over the third quarter levels. During the
fourth quarter of 2004, 16.1 net wells were drilled, compared to 15.2
net wells in the third quarter of 2004.



Zargon Energy Trust
CONSOLIDATED BALANCE SHEETS

As at December 31
($ thousand)
2004 2003
--------------------
(restated
- note 3)
ASSETS (note 5)

Current
Accounts receivable (note 11) 14,275 12,183
Prepaid expenses and deposits 2,953 980
--------------------
17,228 13,163

Property and equipment (note 4) 209,736 167,888
--------------------
226,964 181,051
--------------------
--------------------

LIABILITIES

Current
Bank indebtedness (note 5) 14,230 6,978
Accounts payable and accrued liabilities 24,153 19,277
Cash distributions payable 2,210 -
--------------------
40,593 26,255

Asset retirement obligations (notes 3 and 6) 14,390 12,194

Future income taxes (note 9) 41,830 30,133
--------------------
96,813 68,582
--------------------
Commitments and contingencies (notes 11, 12 and 13)

NON-CONTROLLING INTEREST
Exchangeable shares (notes 3 and 8) 9,529 -
--------------------
UNITHOLDERS' EQUITY

Unitholders' capital/share capital (note 7) 45,755 42,200
Contributed surplus (note 7) 1,170 264
Accumulated earnings 84,399 70,005
Accumulated cash distributions (note 16) (10,702) -
--------------------
120,622 112,469
--------------------

226,964 181,051
--------------------
--------------------

See accompanying notes to the consolidated financial statements.




Zargon Energy Trust
CONSOLIDATED STATEMENTS OF EARNINGS AND ACCUMULATED EARNINGS

For the years ended December 31
($ thousand, except for per unit amounts)
2004 2003
--------------------
(restated
- note 3)
Revenue
Petroleum and natural gas revenue 123,968 101,657
Hedging (note 11) (4,568) (2,882)
Royalties (net of Alberta Royalty Tax Credit) (28,047) (22,508)
--------------------
91,353 76,267
--------------------
Expenses
Production 21,692 17,201
General and administrative (note 18) 4,358 3,542
Unit-based compensation (note 7) 3,682 264
Interest 440 771
Unrealized foreign exchange (gain) loss (564) (297)
Accretion of asset retirement obligations
(notes 3 and 6) 1,076 1,172
Depletion and depreciation 27,414 19,660
--------------------
58,098 42,313
--------------------
Earnings before income taxes 33,255 33,954
--------------------
Income taxes (note 9)
Future 9,639 9,187
Current 1,114 406
--------------------
10,753 9,593
--------------------
Earnings for the year before non-controlling
interest 22,502 24,361

Non-controlling interest - exchangeable
shares (notes 3 and 8) (1,870) -
--------------------
Earnings for the year 20,632 24,361
--------------------
Accumulated earnings, beginning of year

As previously reported 70,125 45,598
Retroactive application of change in
accounting policy (note 3) (120) 46
--------------------
As restated 70,005 45,644
--------------------
Reorganization costs (note 17) (6,238) -
--------------------
Accumulated earnings, end of year 84,399 70,005
--------------------
--------------------
Net earnings per unit/per common share (note 10)
Basic 1.23 1.37
Diluted 1.20 1.33

See accompanying notes to the consolidated financial statements.



Zargon Energy Trust
CONSOLIDATED STATEMENTS OF CASH FLOWS

For the years ended December 31
($ thousand)
2004 2003
--------------------
(restated
- note 3)
Operating activities
Net earnings for the year 20,632 24,361
Add (deduct) non-cash items:
Non-controlling interest - exchangeable
shares (notes 3 and 8) 1,870 -
Depletion and depreciation 27,414 19,660
Accretion of asset retirement obligations 1,076 1,172
Unit-based compensation (note 7) 3,682 264
Unrealized foreign exchange (gain) loss (564) (297)
Future income taxes 9,639 9,187
--------------------
63,749 54,347
Asset retirement expenditures (414) (287)
Changes in non-cash working capital 19 (936)
--------------------
63,354 53,124
--------------------
Financing activities
Advances (repayment) of bank indebtedness 7,252 (18,301)
Cash distributions to unitholders (10,702) -
Exercise of stock options 2,867 1,203
Changes in non-cash working capital 2,148 -
--------------------
1,565 (17,098)
--------------------
Investing activities
Additions to property and equipment (56,553) (45,124)
Proceeds on disposal of property and
equipment 280 5,215
Reorganization costs (note 17) (9,443) -
Changes in non-cash working capital 797 3,883
--------------------
(64,919) (36,026)
--------------------
Change in cash, and cash end of year - -
--------------------
--------------------

See supplementary information contained in Note 14.

See accompanying notes to the consolidated financial statements.


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
For the years ended December 31, 2004 and 2003.
All amounts are stated in Canadian dollars unless otherwise noted.


1. STRUCTURE OF THE TRUST

On July 15, 2004, Zargon Oil & Gas Ltd. (the "Company") was reorganized
into Zargon Energy Trust ("Zargon" or the "Trust") as part of a Plan of
Arrangement (the "Arrangement"). Shareholders of the Company received
one trust unit or one exchangeable share for each common share held. All
outstanding common share options were settled for cash prior to the
completion of the reorganization. The unitholders of the Trust are
entitled to receive cash distributions paid by the Trust. Holders of
exchangeable shares are not eligible to receive cash distributions paid,
but rather, on each payment of a distribution, the number of trust units
into which each exchangeable share is exchangeable is increased on a
cumulative basis in respect of the distribution. The trust units
commenced trading on the TSX under the symbol "ZAR.UN" on July 21, 2004.
The exchangeable shares commenced trading on the TSX under the symbol
"ZOG.B" on August 4, 2004. The Trust is an unincorporated open-ended
investment trust established under the laws of the Province of Alberta
and was created pursuant to a trust indenture ("Trust Indenture").
Valiant Trust Company has been appointed trustee under the Trust
Indenture.

The costs of the reorganization were $9.44 million and are described in
note 17.

The Trust's principal business activity is the exploration for and
development and production of petroleum and natural gas in Canada and
the United States ("U.S.").

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Consolidation and Basis of Presentation

These consolidated financial statements have been prepared by management
in accordance with Canadian generally accepted accounting principles.
Because a precise determination of many assets and liabilities is
dependent upon future events, the preparation of periodic financial
statements necessarily involves the use of estimates and approximations.
Accordingly, actual results could differ from those estimates. The
consolidated financial statements have, in management's opinion, been
properly prepared within reasonable limits of materiality and within the
framework of the Trust's accounting policies summarized below.

While the Trust commenced operations on July 15, 2004, these
consolidated financial statements follow the continuity of interest
basis of accounting as if the Trust had always existed. This basis is
intended to provide unitholders with meaningful and comparative
financial information. Also, certain comparative figures have been
reclassified to conform with the current presentation.

The consolidated financial statements include the accounts of Zargon
Energy Trust, all subsidiaries and a partnership. All subsidiaries and
the partnership are directly or indirectly owned and their operations
are fully reflected in the consolidated financial statements.

Revenue Recognition

Petroleum and natural gas revenue is recognized in earnings when
reserves are produced and delivered to the purchaser.

Joint Operations

The majority of the petroleum and natural gas operations of the Trust
are conducted jointly with others, and accordingly, these financial
statements reflect only the proportionate interests of the Trust in such
activities.

Property and Equipment

The Trust follows the full cost method of accounting for its oil and
natural gas operations whereby all costs relating to the acquisition,
exploration and development of oil and natural gas reserves are
capitalized and accumulated in separate cost centres for Canada and the
United States. Such costs include land acquisition costs, annual
carrying charges of non-producing properties, geological and geophysical
costs, and costs of drilling and equipping wells.

Depletion and depreciation of petroleum and natural gas properties and
equipment is computed using the unit of production method based on the
estimated proved reserves of petroleum and natural gas before royalties
determined by independent consultants. For purposes of this calculation,
reserves are converted to common units on the basis that six thousand
cubic feet of natural gas is equivalent to one barrel of oil. A portion
of the cost of petroleum and natural gas rights relating to undeveloped
properties is excluded from depletion calculations. Twenty percent of
the year-end balance of these costs is added to the depletion base each
year. Proceeds on the disposal of petroleum and natural gas properties
are applied against capitalized costs, with gains or losses not
ordinarily recognized, unless such a disposal would result in a change
in the depletion rate of 20 percent or more.

Depreciation of office equipment is provided using the declining balance
method at an annual rate of 20 percent.

Impairment Test

The Trust applies an impairment test to petroleum and natural gas
properties and equipment costs on an annual basis or as events or
circumstances dictate. This impairment test is performed on both the
Canadian and U.S. cost centres. An impairment loss exists when the
carrying amount of the Trust's petroleum and natural gas properties and
equipment exceeds the estimated undiscounted future net cash flows
associated with the Trust's proved reserves (before royalties). If an
impairment loss is determined to exist, the costs carried on the balance
sheet in excess of the discounted future net cash flows associated with
the Trust's proved and probable reserves are charged to income. Reserves
are determined pursuant to evaluation by independent engineers as
dictated by National Instrument 51-101. The calculation of future net
cash flow is based on future prices as estimated by management relative
to benchmark prices in future markets, discounted using a risk free rate
(see note 4).

Asset Retirement Obligations

Zargon recognizes the fair value of an Asset Retirement Obligation
("ARO") in the period in which it is incurred when a reasonable estimate
of the fair value can be made. The fair value of the estimated ARO is
recorded as a liability, with a corresponding increase in the carrying
amount of the related asset. The capitalized amount is depleted on the
unit-of-production method based on proved reserves. The liability amount
is increased each reporting period due to the passage of time and the
amount of accretion is expensed in the period. Actual costs incurred
upon the settlement of the ARO are charged against the liability.
Differences between the actual costs incurred and the fair value of the
liability recorded are recognized to earnings in the period incurred.

Financial Instruments

Derivative financial instruments are utilized from time to time to
reduce commodity price risk associated with the Trust's production of
oil and natural gas. The base prices for the commodities are sometimes
denominated in U.S. dollars and the Trust may also use such financial
instruments to reduce the related foreign currency risk. Financial
instruments may also be used from time to time to reduce interest rate
risk on outstanding debt. The Trust does not enter into financial
instruments for trading or speculative purposes.

The Trust follows a policy of using hedge instruments such as fixed
price swaps, forward sales, puts, options and costless collars. The
objective is to partially offset or mitigate the wide price swings
commonly encountered in oil and natural gas commodities and in so doing
to protect a minimum level of cash flow in periods of low commodity
prices. The Trust's policy is to designate each derivative financial
instrument employed as a hedge of a specific portion of projected
production over the term of the instrument. The Trust formally documents
its risk management objectives and strategies for undertaking the hedged
transactions, the hedging item, the nature of the specific risk
exposures being hedged, the intended term of the hedge relationship, the
method for assessing effectiveness and the method of accounting for the
hedging relationship. The effectiveness of the derivative is assessed on
an ongoing basis to ensure that the derivatives entered into are highly
effective in offsetting changes in fair values of the hedged items. The
instruments employed may be denominated in U.S. or Canadian dollars. The
Trust believes the derivative financial instruments used are effective
as hedges over their term. In the event that a designated hedged item
ceased to exist, any realized or unrealized gain or loss on such
derivative commodity instruments is recognized in income immediately. If
the hedge relationship is terminated, either via ineffectiveness or via
termination of the designation, gains or losses previously deferred
continue to be deferred and recognized when they are realized.

In the case of forward sales, the instrument can sometimes be satisfied
by physical delivery. In all other cases the instrument is satisfied by
payments or charges calculated by referring published prices to the
agreed reference price in the terms and manner set out in the contract
and paid or received monthly. In the case of physical delivery, the
payment is part of the normal revenue stream. All other payments or
charges are accounted for monthly as adjustments to revenue received.

Interest rate swap agreements may be used from time to time to manage
the floating interest rate on the Trust's revolving bank debt. Such
agreements involve the periodic exchange of payments without the
exchange of the notional principal amount on which the payments are
based. At December 31, 2004 and 2003 the Trust had no such financial
instruments.

Foreign currency swap agreements may be used from time to time to manage
the risk inherent in producing commodities whose price is based directly
or indirectly on U.S. dollars, using a notional principal equal to the
projected monthly revenue from their sale. Payments or charges are
calculated and paid according to the terms of the agreement, usually
with monthly settlement. Foreign currency swap agreements are designated
as hedges of revenue that is received in Canadian dollars, but whose
amount is determined in foreign currency. At December 31, 2004 and 2003
the Trust had no such financial instruments.

Gains or losses from all contracts, other than forward sales settled by
physical delivery, are recognized as hedging gains or losses when
realized.

Income Taxes

The Trust follows the liability method of tax allocation in accounting
for income taxes. Under this method, the Trust records future income
taxes for the effect of any differences between the accounting and
income tax basis of an asset or liability using income tax rates
expected to apply in the years in which these temporary differences are
expected to be recovered or settled. The effect on future income tax
assets and liabilities of a change in tax rates is recognized in net
earnings in the period in which the change is substantively enacted.

Foreign Currency Translation

The Trust uses the temporal method of foreign currency translation,
whereby the monetary assets and liabilities recorded in a foreign
currency are translated into Canadian dollars at year-end exchange
rates, and non-monetary assets and liabilities at the exchange rates
prevailing when the assets were acquired or liability incurred. Revenues
and expenses are translated at the average rate of exchange for the
year. Gains and losses on translation are included in the consolidated
statements of earnings.

Trust Unit Rights and Unit-Based Compensation

Under the Trust's unit rights incentive plan (the "Plan"), rights to
purchase trust units are granted to directors, officers and employees at
current market prices. Compensation expense for rights granted by the
Trust subsequent to the Arrangement is based on the amount that the
market price of the trust unit exceeds the original exercise price
(grant price) for rights as at the date of the financial statements and
is recognized in earnings over the vesting period of the Plan with an
offsetting amount recorded to contributed surplus. Forfeiture of rights
are recorded as a reduction in expense in the period in which they
occur. Stock options granted in 2003 and through to implementation of
the Arrangement are accounted for in accordance with the fair value
method of accounting for stock-based compensation, and as such, the cost
of the option is charged to earnings with an offsetting amount recorded
to contributed surplus, based on an estimate of the fair value using a
Black-Scholes option-pricing model. No compensation expense has been
recorded on options issued prior to 2003 (see note 7).

Per Unit Amounts

Per unit amounts are calculated using the weighted average number of
trust units outstanding during the period. Diluted per unit amounts are
calculated using the treasury stock method to determine the dilutive
effect of unit-based compensation. The Trust follows the treasury stock
method, which assumes that the proceeds received from "in-the-money"
trust unit rights are used to repurchase units at the average market
rate during the period. Diluted per unit amounts also include
exchangeable shares using the "if-converted" method, whereby it is
assumed the conversion of the exchangeable securities occurs at the
beginning of the reporting period (or at the time of issuance if later).

Measurement Uncertainty

The amounts recorded for depletion and depreciation of property and
equipment and the assessment of these assets for impairment are based on
estimates of proved reserves, production rates, petroleum and natural
gas prices, future costs and other relevant assumptions. By their
nature, these estimates are subject to measurement uncertainty and the
impact on the consolidated financial statements of changes in such
estimates in future periods could be material.

Inherent in the fair value calculation of asset retirement obligations,
are numerous assumptions and judgments including the ultimate settlement
amounts, inflation factors, credit adjusted discount rates, timing of
settlement, and changes in the legal and regulatory environments. To the
extent future revisions to these assumptions impact the fair value of
the existing asset retirement obligation liability, a corresponding
adjustment is made to the property and equipment balance.

Cash Distributions

The Trust declares monthly distributions of cash to unitholders of
record on the last day of each calendar month. Pursuant to the Trust's
policy, it will pay distributions to its unitholders subject to
satisfying its financing covenants. Such distributions are recorded as
distributions of equity upon declaration of the distribution.

3. CHANGES IN ACCOUNTING POLICIES

Exchangeable Shares - Non-Controlling Interest

On January 19, 2005, the CICA issued revised draft EIC-151 "Exchangeable
Securities Issued by Subsidiaries of Income Trusts" that states that
exchangeable securities issued by a subsidiary of an Income Trust should
be reflected as either non-controlling interest or debt on the
consolidated balance sheet unless they meet certain criteria. The
exchangeable shares issued by Zargon Oil & Gas Ltd., a corporate
subsidiary of the Trust, are publicly traded and have an expiry term,
which could be extended at the option of the Board of Directors.
Therefore, these securities are considered, by EIC-151, to be
transferable to third parties and to have an indefinite life. EIC-151
states that if these criteria are met, the exchangeable shares should be
reflected as non-controlling interest. Previously, the exchangeable
shares were reflected as a component of Unitholders' Equity.

In accordance with the transitional provisions of EIC-151, the Trust has
retroactively restated prior periods dating back to the Plan of
Arrangement dated July 15, 2004. As a result of this change in
accounting policy, the Trust has reflected a non-controlling interest of
$9.53 million on the Trust's consolidated balance sheet as at December
31, 2004. Consolidated net earnings have been reduced for net income
attributable to the non-controlling interest of $1.87 million in 2004.
In accordance with EIC-151 and given the circumstances in Zargon's case,
each redemption is accounted for as a step-purchase, which for 2004
resulted in an increase in property and equipment of $11.28 million, an
increase of unitholders' equity by $0.62 million, and an increase in
future income tax liability of $3.0 million. Cash flow was not impacted
by this change.

Full Cost Accounting

On January 1, 2004, Zargon adopted the new CICA Accounting Guideline 16
"Oil and Gas Accounting - Full Cost". The new guideline modifies how the
ceiling test is performed, and requires that cost centres be tested for
recoverability using undiscounted future cash flows from proved reserves
determined using forward indexed prices. When the carrying amount of a
cost centre is not recoverable, the cost centre would be written down to
its fair value. Fair value is estimated using accepted present value
techniques, which incorporate risks and other uncertainties when
determining expected cash flows. Since the fair values of the cost
centres exceed the carrying value, there is no impact on the Trust's
reported financial results as a result of applying the new Accounting
Guideline 16.

Asset Retirement Obligations

On January 1, 2004, Zargon retroactively adopted the Canadian accounting
standard outlined in CICA Handbook Section 3110, "Asset Retirement
Obligations". Previously, estimated future site restoration costs were
provided for over the life of the proved reserves on a unit of
production basis.

Under the new accounting standard, the Trust records the fair value of
legal obligations associated with the retirement of long-lived tangible
assets, such as petroleum and natural gas assets, in the period in which
they are acquired or drilled and a corresponding increase in the
carrying amount of the long-lived asset. The liability accretes until
the Trust expects to settle the retirement obligation. The asset
retirement costs assigned to the long-lived assets are depleted using
the unit of production method. Actual costs to retire the tangible
assets are deducted from the liability as incurred.

As required by the new standard, all prior periods have been restated
for the change in accounting policy. The effect of this change on the
consolidated balance sheet as of January 1, 2004 is an increase in net
capital assets of $5.98 million, recognition of an asset retirement
obligation liability of $12.19 million, elimination of the site
restoration liability of $6.03 million, recognition of a future tax
recovery of $0.06 million, and a decrease to retained earnings of $0.12
million. The impact on net earnings and per unit amounts for the year
ended December 31, 2004 and 2003 is negligible as a result of adopting
this new policy.



4. PROPERTY AND EQUIPMENT

($ thousand) 2004
------------------------------------
Accumulated
Depletion and Net Book
Cost Depreciation Value
------------------------------------
Petroleum and natural gas
properties and equipment 295,533 97,680 197,853
Adjustement due to conversion
of exchangeable shares
(see note 3) 11,279 - 11,279
Office equipment 1,304 700 604
------------------------------------
308,116 98,380 209,736
------------------------------------
------------------------------------



($ thousand) (restated - note 3) 2003
------------------------------------
Accumulated
Depletion and Net Book
Cost Depreciation Value
------------------------------------
Petroleum and natural gas
properties and equipment 237,860 70,351 167,509
Office equipment 1,009 630 379
------------------------------------
238,869 70,981 167,888
------------------------------------
------------------------------------


At December 31, 2004, petroleum and natural gas properties and equipment
include $14.7 million (2003 - $14.5 million) relating to undeveloped
properties that have been excluded from the depletion calculation.

An impairment test calculation was performed on the Trust's petroleum
and natural gas properties and equipment at December 31, 2004 in which
the estimated undiscounted future net cash flows associated with the
proved reserves exceeded the carrying amount of the Trust's petroleum
and natural gas properties and equipment. This impairment calculation
was performed separately on both the Canadian and U.S. cost centres.

The following table outlines benchmark prices used in the impairment
test at December 31, 2004:



WTI Crude Oil Exchange Rate WTI Crude Oil AECO Gas
Year ($US/bbl) $US/$Cdn ($Cdn/bbl) ($Cdn/gj)
----------------------------------------------------------------------
2005 42.60 0.83 51.33 6.02
2006 40.42 0.83 48.70 6.22
2007 39.11 0.83 47.12 5.85
2008 38.09 0.83 45.89 5.55
2009 37.37 0.83 45.02 5.26
2010-2014 37.35 0.83 45.00 5.09
----------------------------------------------------------------------
Thereafter
(inflation %) 2.0% 0.83 2.0% 2.0%
----------------------------------------------------------------------
----------------------------------------------------------------------


Actual prices used in the impairment test were adjusted for commodity
price differentials specific to Zargon.

5. BANK INDEBTEDNESS

The Trust has a revolving demand credit facility that provides for a
line of credit of $50.00 million bearing interest at prime (December 31,
2004 - 4.25 percent; 2003 - 4.50 percent) and has pledged an assignment
of accounts receivable, a first floating charge on all of the Canadian
assets and a fixed charge over certain property and equipment as
collateral. In the normal course of operations Zargon enters into
various letters of credit. At December 31, 2004 the approximate value of
these letters of credit totalled $0.46 million (2003 - $0.50 million).

6. ASSET RETIREMENT OBLIGATIONS

The total future asset retirement obligation was estimated by management
based on Zargon's net working interest in all wells and facilities,
estimated costs to reclaim and abandon wells and facilities and the
estimated timing of the costs to be incurred in future periods. Zargon
has estimated the net present value of its total asset retirement
obligations to be $14.39 million (2003 - $12.19 million) as at December
31, 2004, based on a total future liability of $59.12 million (2003 -
$50.85 million). These payments are expected to be made over the next 30
years with the majority of the costs being incurred after 2012. Zargon
used a discount note of 8.5 percent which is based on a risk-free rate
adjusted for credit risk and an inflation rate of two percent to
calculate the present value of the asset retirement obligation.

The following table reconciles Zargon's asset retirement obligation:



Year Ended
December 31,
($ thousand) 2004 2003
--------------------
Balance, beginning of year 12,194 10,560
Liabilities incurred 1,696 749
Liabilities settled (414) (287)
Accretion expense 1,076 1,172
Other (162) -
--------------------
Balance, end of year 14,390 12,194
--------------------
--------------------


7. UNITHOLDERS' EQUITY

Pursuant to the Plan of Arrangement on July 15, 2004, 14.87 million
units of the Trust and 3.66 million exchangeable shares (see note 8) of
the Company were issued in exchange for all of the outstanding shares of
the Company on a one-for-one basis.



Common Shares of
Zargon Oil & Gas Ltd.
(no par value) December 31, 2004 December 31, 2003
--------------------------------------------
Number Amount Number Amount
(thousand) of Shares ($) of Shares ($)
--------------------------------------------
Shares issued
Balance, beginning of year 17,992 42,200 17,637 40,997
Stock options exercised
for cash 534 2,867 355 1,203
Stock-based compensation
recognized - 69 - -
Trust units issued (14,866) (36,219) - -
Exchangeable shares
issued (3,660) (8,917) - -
--------------------------------------------
Balance, end of year - - 17,992 42,200
--------------------------------------------
--------------------------------------------


The Trust is authorized to issue an unlimited number of voting trust
units.



Trust Units December 31, 2004
--------------------
Number Amount
(thousand) of Units ($)
--------------------
Units issued
Issued pursuant to Plan of Arrangement
July 15, 2004 14,866 36,219
Issued on conversion of exchangeable shares 475 9,536
--------------------
Balance, end of year 15,341 45,755
--------------------
--------------------


Compensation Plans

A summary of the status of the Trust's compensation expense for the year
ended December 31, 2004 is presented below:



Compensation Expense Year Ended
December 31,
($ thousand) 2004 2003
--------------------

Stock-based compensation expense prior to 345 264
Plan of Arrangement July 15, 2004
Accelerated vesting of unvested stock options 2,167 -
pursuant to the Arrangement
Unit-based compensation recognized subsequent 1,170 -
to trust conversion
--------------------
Balance, end of year 3,682 264
--------------------
--------------------


A summary of the status of the Trust's compensation plans as at December
31, 2004 and 2003 and changes during the years ended on those dates is
presented below:

Stock Options

As part of the Arrangement to reorganize Zargon Oil & Gas Ltd. into a
Trust, all common share options, vested and unvested, were cancelled and
the optionholders received a cash payment for the intrinsic value of the
options.



December 31, 2004 December 31, 2003
--------------------------------------------
Weighted Weighted
Average Average
Exercise Exercise
Number Price Number Price
of Shares ($/stock of Shares ($/stock
(thousand) option) (thousand) option)
--------------------------------------------
Outstanding at beginning
of year 1,297 7.05 1,215 5.10
Granted 430 16.00 459 9.50
Exercised (534) 5.39 (355) 3.39
Cancelled prior to
trust conversion (9) 9.61 (22) 9.30
Cancelled immediately prior
to trust conversion (1,184) 11.03 - -
---------- ---------
Outstanding at end of year - - 1,297 7.05
---------- ---------
---------- ---------
Options exercisable
at year end - - 985 6.25
---------- ---------
---------- ---------


Stock-Based Compensation (see Compensation Expense table above)

Compensation expense of $0.34 million was recognized for the 2004 year
as a result of regular vesting of unvested stock options prior to the
Arrangement. Additionally, as a result of cancelling the stock-option
plan pursuant to the Arrangement, compensation expense for the year
ended December 31, 2004 of $2.17 million resulted from accelerating of
unvested stock options. Both of these non-cash expenses have been
recognized as part of unit-based compensation expense on the income
statement for the twelve month period.

Under this stock-option plan, the Company had calculated the value of
stock-based compensation using a Black-Scholes option-pricing model to
estimate the fair value of stock options at the date of grant.

Compensation expense for options granted under the stock option plan was
based on the estimated fair values at the time of the grant and the
expense was recognized over the vesting period of the option.

The assumptions made for the options granted in 2004 include an
annualized volatility factor of 26.30 percent, a weighted average
risk-free interest rate of 3.33 percent, no dividend yield and a
weighted average expected life of options of four years.

For purposes of pro forma disclosures relating to 2002 stock option
grants, the Company's net earnings for the year ended December 31, 2003
would be reduced by $0.21 million. Basic and diluted earnings per share
figures would have both been reduced by $0.01 for the 2003 year. There
is no effect in 2004 pertaining to 2002 stock option grants because the
options were fully vested prior to 2004.

Trust Unit Rights Incentive Plan

The Trust has a unit rights incentive plan (the "Plan") that allows the
Trust to issue rights to acquire trust units to directors, officers,
employees and service providers. The Trust is authorized to issue up to
1.82 million unit rights; however, the number of trust units reserved
for issuance upon exercise of the rights shall not at any time exceed 10
percent of the aggregate number of issued and outstanding trust units of
the Trust. At the time of grant, unit right exercise prices approximate
the market price for the trust units. At the time of exercise the rights
holder has the option of exercising at the original grant price or the
exercise price as calculated per the Arrangement. Rights granted under
the plan vest over a three-year period and expire five years from the
grant date.

The following table summarizes information about the Trust's unit rights:



December 31, 2004
--------------------------------
Number of Weighted Average
Unit Rights Exercise Price
(thousand) ($/unit right)
--------------------------------
Outstanding at beginning of year - -
Unit rights granted 579 17.79
-------------
Outstanding at end of year 579 17.79
-------------
-------------
Unit rights exercisable at year end - -
-------------
-------------


The following table summarizes information about unit rights outstanding
at December 31, 2004;

Unit Rights Outstanding Unit Rights Exercisable
------------------------------------ -----------------------

Weighted Weighted Weighted
Range of Number Average Average Number Average
Exercise Outstanding Remaining Exercise Exercisable Exercise
Prices at 12/31/04 Contractual Price at 12/31/04 Price
($/unit (thousand) Life ($/unit (thousand) ($/unit
right) right) right)
----------------------------------------------- -----------------------
17.70 546 4.1 years 17.70 - -
19.25 33 4.1 years 19.25 - -
----- ------- -----------------------
579 17.79 - -
----- ------- -----------------------
----- ------- -----------------------


Unit-Based Compensation (see Compensation Expense table above)

The Plan allows for the exercise price of rights to be reduced in future
periods by a portion of the future distributions. The Trust has
determined that the amount of the reduction cannot be reasonably
estimated, as it is dependent upon a number of factors including, but
not limited to, future oil and natural gas prices, production of oil and
natural gas, determination of amounts to be withheld from future
distributions to fund capital expenditures, and the purchase and sale of
oil and natural gas assets. Therefore, it is not possible to determine a
fair value for the rights granted under the Plan.

Compensation expense is therefore determined based on the amount that
the market price of the trust unit exceeds the original exercise price
(grant price) for rights issued as at the date of the interim unaudited
consolidated financial statements and is recognized in earnings over the
vesting period of the Plan. Compensation expense for the unit rights for
the year ended December 31, 2004 was $1.17 million.

Compensation expense associated with rights granted under the Plan is
recognized in earnings, on a straight-line basis, over the vesting
period of the Plan with a corresponding increase or decrease in
contributed surplus. Changes in the intrinsic value of unexercised
rights after the vesting period are recognized in earnings in the period
of change with a corresponding increase or decrease in contributed
surplus. The exercise of trust unit rights is recorded as an increase in
trust units with a corresponding reduction in contributed surplus.
Forfeiture of rights are recorded as a reduction in expense in the
period in which they occur.

This method of determining compensation expense may result in large
fluctuations, even recoveries, in compensation expense due to changes in
the underlying trust unit price. Recoveries of compensation expense will
only be recognized to the extent of previously recorded cumulative
compensation expense associated with rights outstanding at the date of
the financial statements.

Contributed Surplus

The following table summarizes information about the Trust's contributed
surplus account:



($ thousand)

Balance, December 31, 2002 -
Stock-based compensation expense for 2003 264
--------
Balance, December 31, 2003 264
Stock-based compensation expense prior to Plan of
Arrangement July 15, 2004 345
Stock-based compensation recognized on exercise
of stock options (69)
Accelerated vesting of unvested stock options pursuant
to the Arrangement 2,167
Stock-options cancelled immediately prior to trust
conversion (2,707)
--------
Balance at trust conversion -
Unit-based compensation recognized subsequent to trust
conversion 1,170
--------
Balance, December 31, 2004 1,170
--------
--------


8. NON-CONTROLLING INTEREST - EXCHANGEABLE SHARES

Zargon Oil & Gas Ltd. is authorized to issue a maximum of 3.66 million
exchangeable shares. The exchangeable shares are convertible into trust
units at the option of the shareholder based on the exchange ratio,
which is adjusted monthly to reflect the distribution paid on the trust
units. Cash distributions are not paid on the exchangeable shares.
During the year, a total of 474,000 exchangeable shares were converted
into 475,000 trust units based on the exchange ratio at the time of
conversion. At December 31, 2004, the exchange ratio was 1.02583 trust
units per exchangeable share. As set out in the Arrangement, the
exchangeable shares are entitled to vote equally to the number of trust
units for which each exchangeable share is convertible into a trust unit
on the record date. The Board of Directors of Zargon Oil & Gas Ltd. hold
the option to redeem all outstanding exchangeable shares for trust units
on or before July 15, 2014. At such time, should the Board not extend
the term of the shares, there will be no remaining non-controlling
interest.

The Trust retroactively applied EIC-151 "Exchangeable Securities Issued
by a Subsidiary of an Income Trust" in 2004. Per EIC-151, if certain
conditions are met, the exchangeable shares issued by a subsidiary must
be reflected as non-controlling interest on the consolidated balance
sheet and in turn, net earnings must be reduced by the amount of net
earnings attributed to the non-controlling interest.

The non-controlling interest on the consolidated balance sheet consists
of the book value of exchangeable shares at the time of the Plan of
Arrangement, plus net earnings attributable to the exchangeable
shareholders, less exchangeable shares (and related cumulative earnings)
redeemed. The net earnings attributable to the non-controlling interest
on the consolidated statement of earnings represents the cumulative
share of net earnings attributable to the non-controlling interest based
on the trust units issuable for exchangeable shares in proportion to
total trust units issued and issuable each period end.



Non-Controlling Interest - Exchangeable Shares December 31, 2004
---------------------
Number Amount
(thousand, except exchange ratio) of Shares ($)
---------------------
Non-controlling interest - exchangeable
shares issued
Issued pursuant to Plan of Arrangement
July 15, 2004 3,660 8,917
Exchanged for trust units at book value and
including earnings attributed since
Plan of Arrangement (474) (1,258)
Earnings attributable to non-controlling interest - 1,870
---------------------
---------------------
Balance, end of year 3,186 9,529
---------------------
---------------------

Exchange ratio, end of year 1.02583
Trust units issuable upon conversion of
exchangeable shares, end of year 3,268
-----------
-----------


The proforma total units outstanding at year-end, including trust units
outstanding, and trust units issuable upon conversion of exchangeable
shares and after giving rise to the exchange ratio at the end of the
year is 18.61 million units.

9. INCOME TAXES

The Trust is a taxable entity under the Income Tax Act (Canada) and is
taxable only on income that is not distributed or distributable to the
unitholders. As the Trust allocates all of its Canadian taxable income
to the unitholders in accordance with the Trust Indenture, and meets the
requirements of the Income Tax Act (Canada) applicable to the Trust, no
current tax provision for Canadian income tax expense has been made in
the Trust. Canadian Large Corporations tax, capital taxes and U.S.
income taxes are provided for under current income tax expense.

In the Trust structure, payments are made between the Company and the
Trust that result in the transferring of taxable income from the Company
to individual unitholders. These payments may reduce future income tax
liabilities previously recorded by the Company that would be recognized
as a recovery of income tax in the period incurred.

Income taxes differ from the amounts that would be obtained by applying
statutory income tax rates to earnings before income taxes as follows:



($ thousand) 2004 2003
---------------------
(restated
- note 3)

Statutory income tax rate 39.96% 41.58%

Expected income taxes 13,289 14,118
Add (deduct) income tax effect of:
Non-deductible Crown charges, net of
Alberta Royalty Tax Credit 4,928 3,856
Resource allowance (4,438) (4,724)
Rate adjustment 947 (4,314)
Cash distributions (4,277) -
Large corporation tax, capital taxes,
and U.S. income taxes 1,114 406
Other (810) 251
---------------------
10,753 9,593
---------------------
---------------------


As at December 31, 2004, Zargon has exploration and development costs,
unamortized petroleum and natural gas property expenditures,
undepreciated capital costs and unamortized share issue costs available
for deduction against future taxable earnings in aggregate of
approximately $79 million (December 31, 2003 - $79 million).

Future income taxes reflect the net tax effects of temporary differences
between the carrying amounts of assets and liabilities for financial
reporting purposes and the amounts used for income tax purposes. The
components of Zargon's net future income tax liability are as follows:



($ thousand) 2004 2003
---------------------
(restated
- note 3)

Net book value of property and equipment
in excess of tax pools 33,279 19,501
Deferred partnership earnings 14,153 13,637
Asset retirement obligation (5,107) (2,211)
Non-capital loss carry forwards - (395)
Share issue costs (126) (240)
Alberta royalty tax deduction (369) (159)
---------------------
41,830 30,133
---------------------
---------------------



10. WEIGHTED AVERAGE NUMBER OF TOTAL UNITS

(thousand) 2004 2003
---------------------
(units) (shares)

Basic 16,818 17,824
Diluted 18,723 18,373
---------------------
---------------------


Dilution amounts of 1,905,000 (2003 - 549,000) were added to the
weighted average number of units/common shares outstanding during the
year in the calculation of diluted per unit/common share amounts. These
unit/share additions represent the dilutive effect of unit rights/stock
options according to the treasury stock method, and also include
exchangeable shares using the "if-converted" method. In 2004, an
adjustment to the numerator amount was required in the diluted
calculation to provide for the earnings ($1.87 million) attributable to
the non-controlling interest pertaining to the exchangeable shareholders.

11. FINANCIAL INSTRUMENTS

Fair value of financial assets and liabilities

Financial instruments of the Trust consist of accounts receivable,
deposits, accounts payable and accrued liabilities, bank indebtedness,
and cash distributions payable. As at December 31, 2004 and 2003, there
are no significant differences between the carrying values of these
amounts and their estimated market values.

Credit risk management

Accounts receivable include amounts receivable for petroleum and natural
gas sales that are generally made to large credit-worthy purchasers, and
amounts receivable from joint venture partners that are recoverable from
production. Accordingly, the Trust views credit risks on these amounts
as low. Of Zargon's significant individual accounts receivable at
December 31, 2004, approximately 28 percent was owing from one company
(2003 - 21 percent).

The Trust is exposed to losses in the event of non-performance by
counterparties to hedge transactions. The Trust minimizes credit risk
associated with possible non-performance to these financial instruments
by entering into contracts with only investment grade counterparties,
limits on exposures to any one counterparty, and monitoring procedures.
The Trust believes these risks are minimal.

Interest rate risk management

Borrowings under bank credit facilities are for short periods and are
market-rate-based (variable interest rates); thus carrying values
approximate fair values.

Foreign currency risk management

The Trust is exposed to fluctuations in the exchange rate between the
Canadian dollar and the U.S. dollar. Crude oil, and to a large extent
natural gas prices, are based upon reference prices denominated in U.S.
dollars, while the majority of the Trust's expenses are denominated in
Canadian dollars. When appropriate, the Trust enters into agreements to
fix the exchange rate of Canadian dollars to U.S. dollars in order to
manage this risk.

Commodity price risk management

The Trust enters into hedge transactions on oil and natural gas. The
agreements entered into are forward transactions providing the Trust
with a range of fixed prices on the commodities sold.

The Trust has outstanding contracts at December 31, 2004 and 2003 as
follows:



At December 31, 2004

Volume Rate Price Range of Terms
------------------------------------------------------------------------
Financial Hedges

Oil
swaps 27,000 bbl 300 bbl/d $35.45 US/bbl Jan. 1/05-Mar. 31/05
146,000 bbl 400 bbl/d $44.05 US/bbl Jan. 1/05-Dec. 31/05

Oil 54,300 bbl 300 bbl/d $43.50 Cdn/bbl Put Jan. 1/05-Jun. 30/05
collars $54.50 Cdn/bbl Call

55,000 bbl 200 bbl/d $37.00 US/bbl Put Apr. 1/05-Dec. 31/05
$44.40 US/bbl Call

36,200 bbl 200 bbl/d $36.00 US/bbl Put Jan. 1/06-Jun. 30/06
$48.40 US/bbl Call

Natural
gas
swaps 180,000 gj 2,000 gj/d $6.27/gj Jan. 1/05-Mar. 31/05

856,000 gj 4,000 gj/d $6.49/gj Apr. 1/05-Oct. 31/05


Natural 180,000 gj 2,000 gj/d $6.75/gj Put Jan. 1/05-Mar. 31/05
gas $9.55/gj Call
collars
180,000 gj 2,000 gj/d $6.75/gj Put Jan. 1/05-Mar. 31/05
$9.80/gj Call

453,000 gj 3,000 gj/d $5.90/gj Put Nov. 1/05-Mar. 31/06
$10.00/gj Call

428,000 gj 2,000 gj/d $6.00/gj Put Apr. 1/05-Oct. 31/05
$8.01/gj Call

Natural 428,000 gj 2,000 gj/d $5.10/gj Apr. 1/05-Oct. 31/05
gas put

Physical Hedges

Natural 180,000 gj 2,000 gj/d $8.35/gj Jan. 1/05-Mar. 31/05
gas
swaps

Natural 428,000 gj 2,000 gj/d $6.05/gj Apr. 1/05-Oct. 31/05
gas put
------------------------------------------------------------------------



At December 31, 2003

Volume Rate Price Range of Terms
------------------------------------------------------------------------
Financial Hedges

Oil
swaps 36,400 bbl 200 bbl/d $26.44 US/bbl Jan. 1/04-Jun. 30/04

36,800 bbl 200 bbl/d $27.10 US/bbl Jul. 1/04-Dec. 31/04

Oil 36,400 bbl 200 bbl/d $22.50 US/bbl Put Jan. 1/04-Jun. 30/04
collars $26.85 US/bbl Call

36,400 bbl 200 bbl/d $24.00 US/bbl Put Jan. 1/04-Jun. 30/04
$27.65 US/bbl Call

36,800 bbl 200 bbl/d $24.00 US/bbl Put Jul. 1/04-Dec. 31/04
$27.80 US/bbl Call


Natural 364,000 gj 4,000 gj/d $7.21/gj Jan. 1/04-Mar. 31/04
gas
swaps
856,000 gj 4,000 gj/d $5.15/gj Apr. 1/04-Oct. 31/04

Natural 91,000 gj 1,000 gj/d $5.50/gj Put Jan. 1/04-Mar. 31/04
gas $7.90/gj Call
collars

428,000 gj 2,000 gj/d $5.00/gj Put Apr. 1/04-Oct. 31/04
$6.85/gj Call

Natural 273,000 gj 3,000 gj/d $5.00/gj Jan. 1/04-Mar. 31/04
gas put
------------------------------------------------------------------------


Oil swaps and collars are settled against the NYMEX pricing index,
whereas natural gas swaps, collars and puts are settled against the AECO
pricing index.

At December 31, 2004, $1.14 million would have been received to settle
the above contracts and, of this amount $0.71 million related to
financial hedges and $0.43 million related to physical hedges. At
December 31, 2003, the cost to settle the above contracts would have
been $0.89 million. These instruments have no book values recorded in
the consolidated financial statements.

12. COMMITMENTS

The Trust is committed to future minimum payments for natural gas
transportation contracts in addition to operating leases for office
space, office equipment, vehicles and field equipment. Payments required
under these commitments for each of the next four years are: 2005-$1.88
million; 2006-$0.71 million; 2007-$0.43 million; 2008-$0.07 million; and
thereafter $0.03 million.

13. CONTINGENCIES AND GUARANTEES

In the normal course of operations, Zargon executes agreements that
provide for indemnification and guarantees to counterparties in
transactions such as the sale of assets and operating leases.

These indemnifications and guarantees may require compensation to
counterparties for costs and losses incurred as a result of various
events, including breaches of representations and warranties, loss of or
damages to property, environmental liabilities or as a result of
litigation that may be suffered by counterparties.

Certain indemnifications can extend for an unlimited period and
generally do not provide for any limit on the maximum potential amount.
The nature of substantially all of the indemnifications prevents the
Trust from making a reasonable estimate of the maximum potential amount
that might be required to pay counterparties as the agreements do not
specify a maximum amount, and the amounts depend on the outcome of
future contingent events, the nature and likelihood of which cannot be
determined at this time.

The Trust indemnifies its directors and officers against any and all
claims or losses reasonably incurred in the performance of their service
to the Trust to the extent permitted by law. The Trust has acquired and
maintains liability insurance for its directors and officers. The Trust
is party to various legal claims associated with the ordinary conduct of
business. The Trust does not anticipate that these claims will have a
material impact on the Trust's financial position.



14. SUPPLEMENTAL CASH FLOW INFORMATION

($ thousand) 2004 2003
----------------
Cash interest paid 448 714
Cash taxes paid 794 360
----------------
----------------


15. SEGMENTED INFORMATION

Zargon's entire operating activities are related to exploration,
development and production of oil and natural gas in the geographic
segments of Canada and the U.S.



($ thousand) 2004
----------------------------------
United
Canada States Combined
----------------------------------
Petroleum and natural gas revenue 108,484 15,484 123,968
Property and equipment 184,860 24,876 209,736
Total assets 200,171 26,793 226,964
Net capital expenditures 51,464 4,809 56,273
----------------------------------
----------------------------------



($ thousand) (restated - note 3) 2003
----------------------------------
United
Canada States Combined
----------------------------------
Petroleum and natural gas revenue 90,034 11,623 101,657
Property and equipment 145,210 22,678 167,888
Total assets 157,583 23,468 181,051
Net capital expenditures 33,373 6,536 39,909
----------------------------------
----------------------------------



16. ACCUMULATED CASH DISTRIBUTIONS

During the year, the Trust paid or declared distributions to the
unitholders in the aggregate amount of $10.70 million (2003 - $nil) in
accordance with the following schedule:



Per Trust
Month Record Date Distribution Date Unit
----------------------------------------------------------------------

August 2004 August 31, 2004 September 15, 2004 $0.14
September 2004 September 30, 2004 October 15, 2004 $0.14
October 2004 October 31, 2004 November 15, 2004 $0.14
November 2004 November 30, 2004 December 15, 2004 $0.14
December 2004 December 31, 2004 January 17, 2005 $0.14
----------------------------------------------------------------------
----------------------------------------------------------------------


17. ZARGON ENERGY TRUST REORGANIZATION

The following costs were incurred to reorganize Zargon Oil & Gas Ltd.
into a trust, effective July 15, 2004:



($ thousand)

Cash payout of stock options 7,875
Financial advisory, accounting and legal fees,
and preparation and printing of the Information Circular 1,568
-------
Total reorganization costs 9,443
-------
-------


Of the above amounts, $2.71 million was charged to contributed surplus
relating to recognized stock-based compensation under the previous stock
option plan for the Company. The remaining $6.73 million ($6.24 million
net of taxes) was charged directly against accumulated earnings.

18. RELATED PARTY TRANSACTIONS

During the year, Zargon paid $0.15 million in consulting fees to a
company owned by the Chairman of the Board; $0.05 million for vehicle
leases to a company owned by a Board member; and $0.53 million for legal
services in conjunction with the Arrangement to a law firm in which a
Board member is a partner. These payments were in the normal course of
operations, on commercial terms, and therefore were recorded at the
exchange amount.

19. COMPARATIVE FIGURES

Certain comparative figures have been reclassified to conform with the
current year's financial statement presentation.




Forward Looking Statements - This document contains statements that are
forward-looking, such as those relating to results of operations and
financial condition, capital spending, financing sources, commodity
prices, costs of production and the magnitude of oil and natural gas
reserves. By their nature, forward-looking statements are subject to
numerous risks and uncertainties that could significantly affect
anticipated results in the future and, accordingly actual results may
differ materially from those predicted. The forward-looking statements
contained in this press release are as of March 14, 2005 and are subject
to change after this date. Readers are cautioned that the assumptions
used in the preparation of such information, although considered
reasonable at the time of preparation, may prove to be imprecise and, as
such, undue reliance should not be placed on forward-looking statements.
Zargon disclaims any intention or obligation to update or revise any
forward-looking statements, whether as a result of new information,
future events or otherwise.

Based in Calgary, Alberta, Zargon's securities trade on the Toronto
Stock Exchange (TSX). Trust units of Zargon trade under the symbol
"ZAR.UN", exchangeable shares of Zargon trade under the symbol "ZOG.B".

In order to learn more about Zargon, we encourage you to visit Zargon's
website at www.zargon.ca where you will find a current shareholder
presentation, financial reports and historical news releases.

-30-

Contact Information

  • FOR FURTHER INFORMATION PLEASE CONTACT:
    Zargon Energy Trust
    C.H. Hansen
    President and Chief Executive Officer
    or
    B.C. Heagy
    Vice President, Finance and Chief Financial Officer
    Phone: (403) 264-9992
    E-mail: zargon@zargon.ca
    Website: www.zargon.ca