Paramount Energy Trust

Paramount Energy Trust

March 18, 2005 09:00 ET

Paramount Energy Trust Releases Year End 2004 Reserves And Financial Results


NEWS RELEASE TRANSMITTED BY CCNMatthews

FOR: PARAMOUNT ENERGY TRUST

TSX SYMBOL: PMT.UN
TSX SYMBOL: PMT.DB

MARCH 18, 2005 - 09:00 ET

Paramount Energy Trust Releases Year End 2004 Reserves
And Financial Results

CALGARY, ALBERTA--(CCNMatthews - March 18, 2005) -

March 2005 Distribution Confirmed

Paramount Energy Trust ("PET" or the "Trust") (TSX:PMT.UN)(TSX:PMT.DB)
is pleased to release its fourth quarter and year-end 2004 results as
well as it's year end reserves information. Strong commodity prices,
increased production, four substantial acquisitions and a measure of
resolution to the gas over bitumen issue contributed to exceptional
financial results in 2004.

PET is also pleased to confirm that its distribution to be paid on April
15, 2005 in respect of income received by PET for the month of March
2005, for Unitholders of record on March 31, 2005, will be $0.22 per
Trust Unit. The ex-distribution date is March 29, 2005. This represents
the third consecutive payment of $0.22 following implementation of the
gas over bitumen financial solution announced by the Trust in January.
Cumulative distributions paid since the inception of the Trust to-date
are $5.724 per Trust Unit.

PET expects that monthly cash distributions will be maintained at $0.22
per Trust Unit in respect of production through the remainder of 2005.
PET estimates that this level of monthly distributions of $0.22 per Unit
per month will be sustainable for the foreseeable future, based upon the
Trust's current hedges and the forward market for natural gas prices,
however distributions are subject to change as dictated by actual
conditions.

Forward-Looking Information

This news release contains forward-looking information. Implicit in this
information, particularly in respect of cash distributions, are
assumptions regarding natural gas prices, production, royalties and
expenses which, although considered reasonable by PET at the time of
preparation, may prove to be incorrect. These forward-looking statements
are based on certain assumptions that involve a number of risks and
uncertainties and are not guarantees of future performance. Actual
results could differ materially as a result of changes in PET's plans,
changes in commodity prices, general economic, market, regulatory and
business conditions as well as production, development and operating
performance and other risks associated with oil and gas operations.
There is no guarantee by PET that actual results achieved will be the
same as those forecast herein.

Conference Call and Webcast

PET will be hosting a conference call and webcast at 11:00 a.m., Calgary
time, Friday March 18, 2005 to review this information. Interested
parties are invited to take part in the conference call by dialing one
of the following telephone numbers 10 minutes before the start time:
Toronto and area - 1 416 695-6120; outside Toronto - 1 888 789-0150. For
a replay of this call please dial 1 888 509-0082 until March 23, 2005.
To participate in the live webcast please visit www.paramountenergy.com
or www.fulldisclosure.com. The webcast will also be archived shortly
following the presentation.

Paramount Energy Trust is a natural gas-focused Canadian energy trust.
PET's Trust Units are listed on the Toronto Stock Exchange under the
symbol "PMT.UN". Further information with respect to PET can be found at
its website at www.paramountenergy.com.



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FINANCIAL AND OPERATING HIGHLIGHTS (1)

Three Months Year
Ended Ended
December 31 December 31
---------------------------------------------------------------------
($CDN thousands, except
volume and per Trust % %
Unit amounts) 2004 2003 Change 2004 2003 Change
---------------------------------------------------------------------
---------------------------------------------------------------------
FINANCIAL
Revenue before
royalties 79,665 43,022 85 239,957 209,806 14
Cash flow (3) 56,521 25,138 125 143,592 126,360 14
Per Trust Unit (2) 0.87 0.52 67 2.65 2.97 (11)
Net earnings (loss)
(4) (12) (30,484) (2,812) (984) (20,663) 52,434 -
Per Trust Unit (2) (0.47) (0.06) (683) (0.38) 1.23 -
Cash distributions 39,135 26,783 46 121,314 123,202 (2)
Per Trust Unit (5) 0.60 0.60 - 2.18 2.884 (25)
---------------------------------------------------------------------
Total assets 557,957 260,984 114 557,957 260,984 114
Net bank and
other debt
outstanding (9) 174,309 53,368 227 174,309 53,368 227
Convertible
debentures 38,419 - - 38,419 - -
Total net debt 212,728 53,368 299 212,728 53,368 299
Unitholder's
Equity 264,451 166,065 59 264,451 166,065 59
--------------------------------------------------------------------
Capital
expenditures
Exploration and
development 2,247 286 686 28,869 8,327 247
Acquisitions, net 14,141 13,771 (3) 385,029 32,252 1,094
Other 11,118 757 1,369 11,169 757 1,376
Net capital
expenditures 27,506 14,814 86 425,089 41,336 928
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TRUST UNITS OUTSTANDING
(thousands)
End of period (7) 65,327 44,638 46 65,327 44,638 46
Weighted
average (7) 65,082 44,638 46 54,188 42,597 27
Diluted 65,082 45,322 44 54,188 43,238 25
March 15, 2005 66,113 66,113
---------------------------------------------------------------------
OPERATING

Production
Total natural
gas (Bcfe) 11.8 7.5 57 37.5 31.2 20
Daily average natural
gas (MMcfe/d) 128.0 81.2 58 102.5 85.6 20
Gas over bitumen
deemed production
(MMcf/d) 22.8 9.6 138 16.7 3.2 422
Average daily
(actual and deemed
- MMcf/d) 150.8 90.8 66 119.2 88.8 34
Per Trust Unit
(MMcf/d/Unit) (2) 2.32 2.03 14 2.20 2.08 6

Exit rate (actual
and deemed - MMcf/d)
(5) (11) 146.5 91.0 61 146.5 91.0 61
Per Trust Unit
(MMcf/d/Unit)
(5) 2.24 2.04 10 2.24 2.04 10

Average prices
Natural gas ($/Mcfe),
pre-hedging 6.74 5.33 27 6.51 6.39 2
Natural gas ($/Mcfe),
including hedging 6.78 5.76 18 6.40 6.72 (5)
---------------------------------------------------------------------
RESERVES (Bcfe)
Proved (6) 181.4 123.3 47 181.4 123.3 47
Proved plus
probable (6) 233.5 148.8 57 233.5 148.8 57
Per Trust Unit
(Mcfe/Unit) (5) 3.59 3.33 8 3.59 3.33 8
Estimated present
value before tax
($ millions) (8)
Proved 518.0 239.1 117 518.0 239.1 117
Proved plus
probable 606.2 273.9 121 606.2 273.9 121
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LAND (thousands
of net acres)
Total land holdings 2,304 1,263 83 2,304 1,263 83
Undeveloped
land holdings 726 322 126 726 322 126
---------------------------------------------------------------------


DRILLING

Wells Drilled (gross)
Gas (10) 26 - 49 16 206
Service - - - 1 (100)
Dry 1 - 1 - 100
Total 27 - 50 17 200
Success Rate 96 - 98 100 (2)
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(1) All amounts in this report include the operations and results of the
northeast Alberta properties of Paramount Resources Ltd. ("PRL") which
were acquired by PET during the three months ended March 31, 2003. The
consolidated financial statements have been prepared on a continuity of
interests basis which recognizes PET as the successor entity to PRL's
northeast Alberta core area of operations as PET acquired substantially
all of PRL's natural gas assets in that region.

(2) Based on weighted average Trust Units outstanding for the period.

(3) Management uses cash flow (before changes in non-cash working
capital) to analyze operating performance and leverage. Cash flow as
presented does not have any standardized meaning prescribed by Canadian
GAAP and therefore it may not be comparable with the calculation of
similar measures for other entities. Cash flow as presented is not
intended to represent operating cash flow or operating profits for the
period nor should it be viewed as an alternative to cash flow from
operating activities, net earnings or other measures of financial
performance calculated in accordance with Canadian GAAP. All references
to cash flow throughout this report are based on cash flow before
changes in non-cash working capital and include gas over bitumen royalty
adjustments for shut-in production.

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

(5) Based on Trust Units outstanding at period end.

(6) As evaluated by McDaniel & Associates Consultants Ltd. in accordance
with National Instrument NI 51-101. See "Reserves".

(7) The Trust Units indicated for periods prior to March 31, 2003 are
pro forma. Actual Units were issued by PET in the first and second
quarters of 2003. 9.9 million Units were issued to PRL on February 3,
2003 which in turn issued these Units to shareholders as a dividend
in-kind. 29.7 million Units were issued March 10, 2003 pursuant to a
rights offering.

(8) Discounted at 10% using consultant's forecast pricing. Includes gas
over bitumen royalty adjustments ($82.7 million) and gas over bitumen
shut-in reserves (proved - $8.7 million; proved plus probable - $17.1
million). Proved plus probable undiscounted future net revenue - $845.5
million, including gas over bitumen royalty adjustments ($115.7 million)
and gas over bitumen shut-in reserves ($51.8 million).

(9) Net debt includes net working capital.

(10) Includes 9 (1.0 net) coal bed methane evaluation wells.

(11) Exit production is average production from last month in period.

(12) See "Cost Recovery Test".

FOURTH QUARTER HIGHLIGHTS

- Distributions payable for the quarter totaled $0.60 per Trust Unit
representing $0.20 per Trust Unit paid on November 15, 2004, December
15, 2004 and January 17, 2005.

- On October 4, 2004 the Government of Alberta enacted amendments to the
Natural Gas Royalty Regulations (the "Regulation") providing royalty
adjustments for wells which have been denied the right to produce by the
Alberta Energy and Utilities Board ("AEUB") as a result of the gas over
bitumen regulatory issue. The Minister of Energy signed a Ministerial
Order in late December prescribing the additional royalty calculation
components retroactive to the dates of shut-in. PET received a total of
$11.2 million in royalty adjustments for the retroactive component of
the royalty adjustment and for gas shut-in to the end of the fourth
quarter of 2004 and continues to receive more than $1.5 million in
monthly royalty adjustments based on the formula in the Regulation.

- Production averaged a record 128.0 MMcf/d representing an increase of
58% from the fourth quarter of 2003 despite the additional shut-in of
over 12 MMcf/d on July 1, 2004 related to the gas over bitumen issue.
Factoring in the deemed production volume related to the gas over
bitumen financial solution, average daily production (actual and deemed)
increased 66% to 150.8 MMcf/d from 90.8 MMcf/d in the fourth quarter of
2003.

- Production (actual and deemed) per Trust Unit increased by 14% in 2004
compared to the fourth quarter of 2003.

- The Trust planned and began the execution of a $35 million winter
capital program throughout PET's three Northeast Alberta core areas.

- In November, PET closed the purchase of the downtown Calgary office
building it occupies, thereby reducing future general and administrative
costs through the elimination of future head office rent aside from
operating costs of its premises.

- In December, PET consummated a strategic joint venture with a private
junior exploration and production company covering 5% of the Trust's
extensive undeveloped land base. PET exchanged a 50% interest in
selective undeveloped acreage for a 14% ownership interest in the
private company and then farmed out the remaining 50% interest in the
same lands to that company. This farm-out/joint venture will allow for
immediate activity on lands with prospects outside PET's risk profile
while also providing upside exposure to the other corporate activities
of the proven management team.

SUBSEQUENT EVENTS

- PET has announced monthly distributions of $0.22 per Trust Unit for
each of the first three months of 2005.

- The Trust successfully closed the acquisition of an 11% interest in
the Ells area and a further 17% interest in the Birch/Tar area, both
situated in Northeast Alberta immediately east of the Trust's Legend
field. The effective date of the acquisition was September 1, 2004.
These assets currently produce a net 900 Mcf/d. In addition, there is a
net 900 Mcf/d of deemed production shut-in or not producing as a result
of the gas over bitumen issue and the Trust also purchased the shut-in
reserves and corresponding Crown royalty reductions from the date of
shut-in of July 1, 2004.

- PET closed a transaction in March 2005 whereby it acquired an indirect
5% interest in a gas marketing limited partnership, Eagle Canada Limited
Partnership, for $US 1 million. In conjunction with the acquisition of
the ownership interest, PET will make available for delivery at market
prices an average of 30,000 Gigajoules/d of natural gas over a five year
term, to be marketed on PET's behalf by the gas marketing limited
partnership.

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

FULL YEAR HIGHLIGHTS

- PET Unitholders received a total annual return of 54.6% in 2004. The
Trust Unit price increased 35 percent in 2004 from $11.68 to $15.88 per
Trust Unit and the Trust paid distributions of $2.18 per Trust Unit.

- PET's natural gas production averaged 102.5 MMcf/d in 2004, an
increase of 20% from 85.6 MMcf/d in 2003. The positive effects of four
substantial acquisitions consummated during the year in the Marten Hills
(7.5 MMcf/d; $30 million; January), Athabasca (47.5 MMcf/d; $208
million; August), and Saleski (2.5 MMcf/d; $20 million; September)
areas, as well as the Cavell Energy Corp. ("Cavell") (11.3 MMcf/d; $116
million; July) acquisition (net of the disposition of Cavell's Southeast
Saskatchewan assets), more than offset gas over bitumen shut-ins which
averaged 14.6 MMcf/d in 2004.

- Factoring in the deemed production volume related to the gas over
bitumen financial solution, average daily production (actual and deemed)
increased 34% to 119.2 MMcf/d from 88.8 MMcf/d in 2003. Exit rates
(actual and deemed) increased 61% year over year to 146.5 MMcf/d at year
end 2004.

- Production (actual and deemed) per Trust Unit increased by 6% in 2004
compared to 2003. Exit rates (actual and deemed) per Trust Unit
increased by 10% year over year.

- In addition to the four major acquisitions, five other minor asset
acquisitions were closed during 2004 which consolidated interests within
existing operated properties.

- PET realized cash flow of $144 million in 2004 and paid distributions
of $121 million, resulting in a payout ratio of 84%. The remainder of
the Trust's cash flow was used to fund the majority of PET's $29 million
2004 exploration and development capital expenditure program.

- PET successfully completed two bought-deal equity financings in May
and August for net proceeds of $47.9 million and $91.5 million for the
issuance of 4.5 million Trust Units at $11.20 per Unit and 7.8 million
Trust Units at $12.65 per Unit, respectively. In addition 6.9 million
Trust Units were issued to the holders of Cavell Energy Corp. shares in
July. Further, as part of the financing for the Athabasca Assets
acquisition, $48 million of 8% convertible debentures with a conversion
price of $14.20 per Trust Unit were issued in August.

- At December 31, 2004 PET's balance sheet remained very healthy with
ending net debt, including the convertible debentures, to trailing cash
flow of 1.5 times and to 2005 estimated cash flow of 1.0 times.

GAS OVER BITUMEN ISSUE

On October 4, 2004 the Government of Alberta enacted amendments to the
Natural Gas Royalty Regulation with respect to natural gas which provide
a mechanism whereby the Government may prescribe additional royalty
components to effect a reduction in the royalty calculated through the
Crown royalty system for operators of gas wells which have been denied
the right to produce by the AEUB as a result of recent bitumen
conservation decisions. The Minister of Energy signed a Ministerial
Order in late December prescribing the additional royalty calculation
components retroactive to the dates of shut-in.

The Department of Energy issued an Information Letter 2004-36 ("IL
2004-36") which, in conjunction with the Regulation, sets out the
details of the gas over bitumen financial solution. The formula for
calculation of the royalty reduction provided in the Regulation is:

0.5 x ((deemed production volume x 0.80) x (Alberta Gas Reference Price
- $0.4293/GJ))

The deemed production volume includes all gas shut-in or denied
production pursuant to a Decision Report, corresponding AEUB Order or
General Bulletin, or through correspondence in relation to an AEUB ID
99-1 application. The Trust's current net deemed production volume for
purposes of the royalty adjustment is 22.8 MMcf/d. According to IL
2004-36, the deemed production volume will be reduced by 10% at the end
of every year of shut-in.

If gas production recommences from zones previously ordered to be
shut-in, gas producers may pay an incremental royalty to the Crown on
production from the reinstated pools along with Alberta Gas Crown
Royalties otherwise payable. The incremental royalty will apply only to
the pool or pools reinstated for production and will be established at
1% after the first year of shut-in increasing at 1% per annum based on
the period of time such zones remained shut-in to a maximum of 10%. The
incremental royalties payable to the Crown would be limited to amounts
recovered by a gas well operator through the reduced royalty.

At December 31, 2004 the Trust had recorded $11.2 million on its balance
sheet for cumulative gas over bitumen royalty adjustments to that date,
as the Trust cannot determine if, when or to what extent the royalty
adjustments may be repayable through incremental royalties if and when
gas production recommences. The royalty adjustments are being excluded
from earnings pending such future determination. Royalty adjustments
although not included in earnings are recorded as a component of funds
from operations and as such are considered distributable income.

Lease rental remission will also be granted for a mineral license or
lease issued by the Crown that has a well or wells shut-in, according to
IL 2004-36.

Parties wishing to contest the production status of an interval or
intervals were required to file evidence with the AEUB by February 14,
2005 for a final hearing pursuant to Phase 3 of General Bulletin
2003-28. PET filed detailed evidence supporting the resumption of
production for six pools representing approximately 8.5 MMcf/d of
shut-in production or half of the production the Trust currently has
shut-in pursuant to AEUB Orders. PET also reiterated to the AEUB its
continued objection to all zones that have been shut-in as a result of
the interim hearing, based on the new evidence that the Trust has
submitted.

In addition, PET has reviewed the evidence submissions of all other
parties and found that five additional producing wells, representing a
total of less than 0.2 MMcf/d net to the Trust, have been further
requested shut-in by other parties. As a result PET, concludes that it
will have very little incremental gas beyond that already shut-in
subject to review at the final hearing. Any changes in productive status
resulting from the final hearing should result in increased gas
production for PET. The AEUB intends to make final decisions and issue
final orders, when appropriate, confirming the production status of
every interval within the scope of the Phase 3 proceedings, including
those intervals whose production status is not contested in the final
hearing. PET anticipates final decisions will be issued in late 2005 or
early 2006 after the conclusion of the final hearing, which is currently
scheduled to begin June 14, 2005.

RESERVES

PET's complete NI 51-101 reserves disclosure as at December 31, 2004
including underlying assumptions regarding commodity prices, expenses
and other factors and reconciliation of reserves on a Net Interest Basis
(working interest less royalties payable), will be available soon in the
Trust's Annual Information Form and on the Trust's website at
www.paramountenergy.com.

The reserves data set out below (the "Reserves Data") is based upon an
evaluation by McDaniel and Associates Consultants Ltd. ("McDaniel") with
an effective date of December 31, 2004 contained in a report of McDaniel
dated March 4, 2005. The Reserves Data summarizes the natural gas
reserves of the Trust and the net present values of future net revenue
for these reserves using McDaniel forecast prices and costs. The oil and
natural gas liquids reserves of PET are immaterial.

As the Trust has reserves which have been shut-in as a result of AEUB
Decisions and Orders related to the gas over bitumen issue, McDaniel
prepared two separate additional reports dated March 4, 2005 with
respect to the shut-in gas over bitumen reserves of PET as at December
31, 2004. The first additional report sets forth the estimated future
net revenue (before deduction of income taxes) attributed to the Crown
royalty adjustments for PET's reserves which have been shut-in as a
result of the gas over bitumen issue as per the amendments to the
Natural Gas Royalty Regulation, 2002 enacted on October 4, 2004. The
second additional report sets out the estimated future net revenue
(before deduction of income taxes) attributed to the reserves which have
been shut-in as a result of the gas over bitumen issue if they were to
recommence production. For the purposes of this valuation, McDaniel has
assumed that these reserves will recommence production in the year 2014
and will be subject to an additional 10% gross overriding royalty
payable to the Crown. The Reserves Data presents the summation of the
three McDaniel reports.



SUMMARY OF GAS RESERVES AND NET PRESENT VALUES OF
FUTURE NET REVENUE
TOTAL RESERVES
as of December 31, 2004
FORECAST PRICES AND COSTS

NET PRESENT VALUES
OF FUTURE REVENUE
RESERVES BEFORE TAX DISCOUNTED AT
CATEGORIES NATURAL GAS (%/year) (1)
------------ ----------------- ------------------------------------
Gross Net 0% 10% 15% 20%
MMcf MMcf (M$) (M$) (M$) (M$)
----- ---- ---- ---- ---- ----
PROVED
Developed
Producing 162,597 132,120 541,787 426,545 387,106 355,349
Developed
Non-Producing 3,647 2,909 (6,745) (4,212) (3,394) (2,492)
Gas over
Bitumen Royalty
Adjustments - - 115,736 82,706 72,125 63,934
Shut-in Gas
over Bitumen
Reserves (2) 11,988 8,851 23,024 8,710 5,479 3,512
Undeveloped 3,181 2,851 6,597 4,265 3,470 2,838
-------- ------ ------- ------- ------- ---------
TOTAL PROVED 181,413 146,731 680,399 518,014 464,786 423,141

PROBABLE
Developed
Producing,
Developed
Non-Producing
and
Undeveloped 40,162 32,633 136,331 79,826 64,891 54,286
Shut-in Gas over
Bitumen
Reserves (2) 11,969 8,821 28,753 8,383 4,742 2,774
-------- ------ ------- ------- ------- ---------
TOTAL PROBABLE 52,131 41,454 165,084 88,209 69,633 57,060
-------- ------ ------- ------- ------- ---------
TOTAL PROVED
PLUS
PROBABLE 233,544 188,185 845,483 606,223 534,419 480,201
-------- ------ ------- ------- ------- ---------
-------- ------ ------- ------- ------- ---------


Notes:

(1) For income tax purposes we are able to and intend to claim deduction
for all amounts paid or payable to the Unitholder and then allocate
remaining taxable income, if any, to the Unitholders. Accordingly, no
income tax amounts have been reported in this Reserves Data.

(2) The McDaniel Report for Shut-in Gas over Bitumen Reserves assumes
that 50% of the shut-in reserves are proved non-producing and 50% are
probable, that the reserves return to production after 10 years of
shut-in and that such production is subject to an incremental 10% gross
overriding royalty pursuant to the amended Royalty Regulation.



RECONCILIATION OF TRUST GROSS RESERVES
TOTAL RESERVES (1)
FORECAST PRICES AND COSTS
-----------------------------------------------
Gross Proved
Gross Proved Gross Probable Plus Probable
FACTORS (Bcf) (Bcf) (Bcf)
-------------------- ------------- --------------- ---------------

December 31, 2003 (2) 123.3 25.5 148.8
Improved Recoveries - - -
Extensions - - -
Discoveries
(net of 2004 production) 1.5 0.6 2.1
Technical Revisions (5.5) 1.9 (3.6)
Acquisitions 99.6 24.1 123.7
Dispositions - - -
Economic Factors - - -
Production (37.5) - (37.5)

December 31, 2004 181.4 52.1 233.5


Notes:

(1) Reserves are the Trust's net share of remaining reserves and
includes reserves from zones not affected by gas over bitumen issue and
reserves shut-in pursuant to AEUB Decisions and Orders.

(2) The opening balance on December 31, 2003 includes all of our
reserves, including reserves that were shut-in or identified for shut-in
as a result of the gas over bitumen issue. Reserves that were shut-in
were categorized as probable reserves on December 31, 2003 with an
assumed production commencement date of 2014.

According to the McDaniel Report, over 95% of the Trust's proved
reserves from zones not affected by the gas over bitumen issue, both on
a proved and a proved and probable basis, are developed producing
reserves. The McDaniel report identifies minimal future capital
expenditures to realize the estimated production potential of the
reserves identified, $10 million for the proved reserves and $1.9
million for the probable reserves, $8.8 million (74%) of which are
specified for 2005. Internally, the Trust has a significant inventory of
opportunities which exceeds the forecast future capital expenditures
recognized in the reserve report, including the opportunities currently
being pursued in the Trust's 2005 exploration and development capital
program.

OUTLOOK

As activities draw to a close for the Trust's $35 million winter capital
program, preliminary results are very encouraging. Production additions
are expected to be approximately 14 MMcf/d, the vast majority of which
will be onstream prior to April 1, 2005. Natural gas production for 2005
is expected to average 120 MMcf/d and deemed production volumes for
royalty reduction calculations as per the financial solution for the
shut-in gas over bitumen reserves is expected to average 21.5 MMcf/d for
total average actual and deemed production of 141.5 MMcf/d anticipated
for 2005.

Natural gas prices have again strengthened considerably in recent weeks.
With current calendar 2005 average prices of more than $7.00 per
Gigajoule at AECO, PET has taken the opportunity to supplement its
hedging portfolio. PET currently has the following natural gas hedges in
place after March 2005:




Volumes at AECO
---------------------------------------------------------------------
(Gigajoules/day)("GJ/d") Price ($/GJ) Term
---------------------------------------------------------------------
10,000 GJ/d $ 6.81 April 2005 - June 2005
---------------------------------------------------------------------
55,000 GJ/d $ 7.06 April 2005 - October 2005
---------------------------------------------------------------------
5,000 GJ/d $ 6.50 to 7.30 April 2005 - October 2005
---------------------------------------------------------------------
5,000 GJ/d $ 7.33 July 2005 - October 2005
---------------------------------------------------------------------
50,000 GJ/d $ 7.89 November 2005 - March 2006
---------------------------------------------------------------------


2005 GUIDANCE AND SENSITIVITIES

Based on current commodity prices, PET's hedging portfolio, production
levels and exploration and development capital expenditure budget,
following are PET's current estimates of its 2005 results:



2004 2005E (1)(2)
---------------------------------------------------------------------
Natural Gas Production MMcf/d 103 120
Gas Prices
AECO Monthly Index $/GJ $ 6.46 $ 7.10
PET Realized $/Mcf $ 6.40 $ 7.50
Monthly Cash Flow $/Unit/Month $0.205 $0.260
Monthly Average Distributions $/Unit/Month $0.182 $0.220
Payout Ratio % 84% 85%
Ending Debt to Cash Flow Ratio (3) Times 1.5 1.0
---------------------------------------------------------------------


(1) Cash flow incorporates royalty adjustments for gas over bitumen
shut-in gas

(2) Includes forward gas prices as of March 15, 2005 gas prices, PET
hedging activity and physical forward sales and PET contracts but no
future acquisitions

(3) Calculated as ending net debt including convertible debentures as
debt divided by annualized cash flow

Below is a table that shows sensitivities of PET's 2005 cash flow to
operational changes and changes in the business environment:



Impact on Cash Flow per Trust Unit
-------------------------------------
Change Annual Monthly
---------------------------------------------------------------------
Business Environment
Price per Mcf of natural gas
(PET Avg.) $ 0.25/Mcf 0.14 0.012
Interest rate on debt 2% 0.05 0.004
---------------------------------------------------------------------
Operational
Gas production volume 5 MMcf/d 0.13 0.011
Operating costs $ 0.10/Mcf 0.07 0.006
Cash G&A expenses $ 0.10/Mcf 0.07 0.006
---------------------------------------------------------------------


These sensitivities assume operating costs of $1.10 per Mcf, cash
general and administrative expenses of $0.15 per Mcf, and an interest
rate on long term bank debt of 5.25 percent.

MANAGEMENT'S DISCUSSION AND ANALYSIS

The following is management's discussion and analysis ("MD&A") of PET's
operating and financial results for the year ended December 31, 2004 as
well as information and estimates concerning the Trust's future outlook
based on currently available information. This discussion should be read
in conjunction with the Trust's audited consolidated financial
statements for the years ended December 31, 2004 and 2003, together with
accompanying notes.

The Trust follows the "successful efforts" method of accounting for its
petroleum and natural gas operations. This method, unlike the
alternative "full cost accounting" method, usually generates a more
conservative value for net earnings and cash flow as exploration
expenditures, including exploratory dry hole costs, geological and
geophysical costs, lease rentals on undeveloped properties as well as
the cost of surrendered leases and abandoned wells, are expensed rather
than capitalized in the year incurred. However, to make reported cash
flow results comparable to industry practice, the Trust reclassifies
geological and geophysical costs as well as surrendered leases and
abandonment costs from operating to investing activities.

Management uses cash flow (before changes in non-cash working capital)
to analyze operating performance and leverage. Cash flow as presented
does not have any standardized meaning prescribed by Canadian Generally
Accepted Accounting Principles ("GAAP") and therefore it may not be
comparable to the calculation of similar measures for other entities.
Cash flow as presented is not intended to represent operating cash flow
or operating profits for the period nor should it be viewed as an
alternative to cash flow from operating activities, net earnings or
other measures of financial performance calculated in accordance with
Canadian GAAP. All references to cash flow throughout this MD&A are
based on cash flow before changes in non-cash working capital.

FORWARD LOOKING INFORMATION

This MD&A contains forward-looking information with respect to PET.

The use of any of the words "anticipate", "continue", estimate",
"expect", "may", "will", "project", "should", "believe", "outlook" and
similar expressions are intended to identify forward-looking statements.
These statements involve known and unknown risks, uncertainties and
other factors that may cause actual results or events to differ
materially from those anticipated in our forward-looking statements. We
believe the expectations reflected in these forward-looking statements
are reasonable. However, we cannot assure the reader that these
expectations will prove to be correct. The reader should not unduly rely
on forward-looking statements included in this report. These statements
speak only as of the date of the MD&A.

In particular, this MD&A contains forward-looking statements pertaining
to the following:

- the quantity and recoverability of PET's reserves;

- the timing and amount of future production;

- prices for natural gas produced;

- operating and other costs;

- business strategies and plans of management;

- supply and demand for natural gas;

- expectations regarding PET's ability to raise capital and to add to
it's reserves through acquisitions as well as through exploration and
development;

- the focus of capital expenditures on development activity rather than
exploration;

- the sale, farming in, farming out or development of certain
exploration properties using third party resources;

- the use of development activity and acquisitions to replace and add to
reserves;

- the impact of changes in natural gas prices on cash flow after hedging;

- drilling plans;

- the existence, operations and strategy of the commodity price risk
management program;

- the approximate and maximum amount of forward sales and hedging to be
employed;

- the Trust's acquisition strategy, the criteria to be considered in
connection therewith and the benefits to be derived there from;

- the impact of Canadian federal and provincial governmental regulation
on the Trust relative to other issuers of similar size;

- PET's treatment under governmental regulatory regimes;

- the goal to sustain or grow production and reserves through prudent
management and acquisitions;

- the emergence of accretive growth opportunities; and

- PET's Trust's ability to benefit from the combination of growth
opportunities and the ability to grow through the capital markets.

PET's actual results could differ materially from those anticipated in
these forward-looking statements as a result of the risk factors set
forth below and elsewhere in this MD&A which include but are not limited
to:

- volatility in market prices for natural gas;

- risks inherent in PET's operations;

- uncertainties associated with estimating reserves;

- competition for, among other things; capital, acquisitions of
reserves, undeveloped lands and skilled personnel;

- incorrect assessments of the value of acquisitions;

- geological, technical, drilling and process problems;

- general economic conditions in Canada, the United States and globally;

- industry conditions including fluctuations in the price of natural gas;

- royalties payable in respect of PET's production;

- governmental regulation of the oil and gas industry, including
environmental regulation;

- fluctuation in foreign exchange or interest rates;

- unanticipated operating events that can reduce production or cause
production to be shut-in or delayed;

- stock market volatility and market valuations; and

- the need to obtain required approvals from regulatory authorities.

The above list of risk factors should not be construed as exhaustive.

HIGHLIGHTS



(CDN$ millions, except per
Unit and volume data) 2004 2003 2002
---------------------------------------------------------------------
Cash flow (1) $ 143.6 $ 126.4 $ 59.7
Cash flow per Unit $ 2.65 $ 2.97 $ 1.51
Net earnings (loss) $ (20.6) $ 52.4 $ 7.4
Distributions $ 121.3 $ 123.2 -
Distributions per Unit $ 2.18 $ 2.884 -
Payout ratio (%) 84.5% 97.5% -
Production (Mcfe/d)
Daily average production (2) 102,472 85,574 94,842
Gas over bitumen deemed
production 16,724 3,198 -
Total average daily
(actual and deemed) 119,196 88,772 94,842
---------------------------------------------------------------------
---------------------------------------------------------------------


(1) Before changes in non-cash working capital, includes gas over
bitumen royalty adjustment.

(2) Production amounts are based on company interest before royalties.

On February 5, 2004 PET closed the acquisition of producing natural gas
properties in northeast Alberta for $30.3 million, effective January 1,
2004. This acquisition was financed from existing credit facilities.

Decision 2004-045, resulting from the AEUB Interim Hearing related to
the ongoing gas over bitumen issue, was released June 8, 2004 and called
for the shut-in of an additional 12.5 MMcf/d of PET's net gas production
effective July 1, 2004. This decision, combined with gas shut-in since
September 1, 2003 as a result of General Bulletin 2003-28 brought PET's
total shut-in volumes to 17.2 MMcf/d. An additional 0.2 MMcf/d of
production in the Chard-Leismer area was shut-in September 1, 2004 as
required by Shut-In Order 04-003. The total shut-in volume of 17.4
MMcf/d is significantly less than the approximately 44 MMcf/d of
production initially targeted by the AEUB in 2003.

On July 16, 2004 PET acquired Cavell Energy Corporation ("Cavell") for
consideration of 6,931,933 Trust Units with an ascribed value of $78.7
million plus acquisition costs, net of stock option proceeds of $8.0
million. Cavell was a public oil and gas exploration and production
company active in Western Canada.

On August 17, 2004 the Trust closed an acquisition of producing
petroleum and natural gas properties and assets in Northeast Alberta
(the "Athabasca Assets Acquisition") for an aggregate purchase price of
$208.3 million ($197 million net of adjustments to the adjustment date
of July 1, 2004). The acquisition was financed through the issuance of
7,795,547 Trust Units for gross proceeds of $96,275,005, in addition to
the issuance of $48,000,000 in 8% convertible extendible unsecured
subordinated debentures ("Convertible Debentures"), and through existing
credit facilities. Convertible Debentures in the amount of $9.6 million
were subsequently converted into 674,711 Trust Units between August and
December 2004.

On August 24, 2004 PET concluded the sale of the oil producing
properties in Southeast Saskatchewan acquired as part of the Cavell
acquisition for $32.75 million.

On September 30, 2004 PET closed the acquisition of producing petroleum
and natural gas properties in the Saleski area of Northeast Alberta for
an aggregate purchase price of $20.0 million. The acquisition was
financed through existing credit facilities and had an effective date of
April 1, 2004.

Strong commodity prices, excellent drilling results and increased
production volumes as a result of the above noted acquisitions resulted
in record cash flow of $143.6 million ($2.65 per Trust Unit) in 2004
compared to $126.4 million ($2.97 per Trust Unit) for 2003. The
year-over-year increase in cash flow of $18.0 million was due primarily
to the above noted acquisitions. Despite the royalty reductions credited
as per the gas over bitumen financial solution with the Crown, the
Trust's cash flow was reduced by $9 million as a result of the gas over
bitumen shut-ins.

PET declared distributions of $121.3 million in 2004 ($2.18 per unit)
and $123.2 million in 2003 ($2.884 per unit), representing 85 percent of
2004 cash flow and 97 percent in 2003.

The Trust successfully completed two major equity offerings in May 2004
and August 2004 netting $47.9 million and $91.5 million, respectively.

The Board of Directors of the Administrator of PET has approved a
capital expenditure program of up to $45 million in 2005.

EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

The Chief Executive Officer, Clayton Riddell, and Chief Financial
Officer, Cameron Sebastian, evaluated the effectiveness of PET's
disclosure controls and procedures as of December 31, 2004 (the
"Evaluation Date"), and concluded that PET's disclosure controls and
procedures were effective to ensure that information PET is required to
disclose in its filings with the Securities and Exchange Commission
under the Securities Exchange Act of 1934 (the "Exchange Act") is
recorded, processed, summarized and reported, within the time periods
specified in the Commission's rules and forms, and to ensure that
information required to be disclosed by PET in the reports that it files
under the Exchange Act is accumulated and communicated to PET's
management, including its principal executive officer and principal
financial officer, as appropriate to allow timely decisions regarding
required disclosure.

CHANGES TO INTERNAL CONTROLS AND PROCEDURES FOR FINANCIAL REPORTING

There were no significant changes to PET's internal controls or in other
factors that could significantly affect these controls subsequent to the
Evaluation Date.

MECHANICS OF CREATION OF THE TRUST

PET was formed through a series of transactions as described below:

On February 3, 2003:

(1) Paramount Operating Trust ("POT") acquired the Legend property from
Paramount Resources Ltd. ("PRL") for an $81 million promissory note;

(2) PET issued approximately 9.9 million Trust Units to PRL, and

(3) PRL declared a dividend to be paid to its shareholders on February
12, 2003 of these Trust Units, at 1 Unit per 6.071646 shares, valued at
$5.15 per Trust Unit, or approximately $0.85 per PRL Common Share.

On February 17, 2003:

(4) PET issued 3 rights per Trust Unit to acquire additional Trust Units
at $5.05 per Unit.

On March 11, 2003:

(5) With proceeds of the rights offering of approximately $150 million,
which was successfully closed with full subscription on March 10, 2003,
plus bank debt, PET purchased from PRL the majority of PRL's remaining
Northeast Alberta natural gas assets for $220 million. The effective
date of the property transactions was July 1, 2002 which, after
adjustment for net cash flow and interest, resulted in the Trust
assuming $70 million in bank debt.

BUSINESS PLAN AND STRATEGY

PET is a natural gas focused Canadian energy royalty trust actively
managed to generate monthly cash distributions for Unitholders. The
Trust's operations are based entirely in Canada with the majority of its
core assets presently concentrated in Northeast Alberta. PET is
currently Canada's only 100 percent natural gas royalty trust.

PET seeks to be highly profitable, generating premium after-tax returns
at an acceptable risk for all stakeholders. Maximizing total return to
Unitholders in the form of cash distributions and change in Unit price
is a paramount objective. Strategies for achieving this objective
include attentive management of all costs and capital expenditures,
prudent use of financial leverage, optimization of our existing asset
base, infrastructure management, land stewardship and the pursuit of
accretive acquisitions. At the same time, Management also attempts to
mitigate commodity price volatility through an active hedging and price
management program.

PET has a strategy to focus its vision of accretive growth on existing
core areas and pursue field optimization and cost control within those
core areas to maximize asset value. The Trust strives to maximize
control over its operations through operatorship whenever possible, and
to maintain high working interests. PET operates over 90 percent of its
production. PET believes this high level of operatorship can translate
to control over costs, timing of capital outlays and projects as well as
providing competitive advantages for future opportunities.

CORPORATE GOVERNANCE

PET is committed to maintaining high standards of corporate governance.
Each regulatory body has a different set of rules pertaining to
corporate governance including the Toronto Stock Exchange, the Canadian
provincial securities commissions and the Securities and Exchange
Commission whose responsibilities include implementing rules under the
United States Sarbanes-Oxley Act of 2002. PET fully conforms to the
rules of the governing bodies under which it operates and, in many
cases, already complies with proposals and recommendations that have not
come into force. Full disclosure of this compliance is provided in PET's
information circular and on PET's website.

PRODUCTION VOLUMES

Production volumes during 2004 averaged 102.5 MMcfe/d compared to 85.6
MMcfe/d in 2003, a 20 percent increase. The increase in production was
attributed to the Marten Hills acquisition that was effective January 1,
2004 in addition to the acquisition of Cavell, the Athabasca
acquisition, the Saleski property purchase and the results of the 2004
capital expenditure program. These acquisitions resulted in an increase
in average 2004 production of approximately 63 MMcfe/d while the Trust's
2004 winter capital program added approximately 7 MMcf/d of production
above the McDaniel's base case forecast.

In 2004, five properties located within the Trust's four core areas
accounted for 41 percent of the Trust's production with one property
accounting for 16 percent of the total production. This diversification
of production minimizes the risk that operating problems at a specific
property will materially impact the Trust.



Production 2004 2003 2002
---------------------------------------------------------------------
Natural Gas (Mcf/d) 102,323 85,574 94,842
Oil (Bbls/d) 25 - -
---------------------------------------------------------------------
Total Production (Mcfe/d) 102,472 85,574 94,842
---------------------------------------------------------------------
---------------------------------------------------------------------


PET expects 2005 production to average approximately 122 MMcfe/d after
incorporating production declines on existing properties and the
positive impact of ongoing exploration and development activities on the
assets. PET does not budget for acquisitions due to uncertainty
regarding their completion and the timing thereof.

COMMODITY PRICES



Prices and Marketing

2004 2003 2002
--------------------------------------------------------------------
Reference prices
AECO gas ($/Mcf) $ 6.54 $ 6.70 $ 4.07
Alberta Gas Reference Price ($/Mcf) $ 6.28 $ 6.13 $ 3.88

Average PET prices
Natural gas, before hedging ($/Mcfe) $ 6.51 $ 6.39 $ 3.83
% AECO, before hedging 100% 95% 94%
% Alberta Gas Reference Price,
before hedging 104% 104% 99%
Natural gas, after hedging ($/Mcfe) $ 6.40 $ 6.72 $ 3.83
% AECO, after hedging 98% 100% 94%
% Alberta Gas Reference Price,
after hedging 102% 110% 99%
---------------------------------------------------------------------
---------------------------------------------------------------------


U.S. natural gas prices are typically referenced off NYMEX at the Henry
Hub, Louisiana while western Canada natural gas prices are referenced to
the AECO Hub in Alberta. AECO Hub prices were $6.54 per Mcf and $6.70
per Mcf for 2004 and 2003 respectively; a decrease of 2 percent.

The Alberta Gas Reference Price is the monthly weighted average of an
intra-Alberta consumers' price and an ex-Alberta border price, reduced
by allowances for transporting and marketing gas. The Alberta Gas
Reference Price is used to calculate Alberta Gas Crown Royalties. The
Alberta Gas Reference Price increased 2 percent from $6.13 per Mcf in
2003 to $6.28 per Mcf in 2004.

PET's average well head gas price, prior to hedging transactions,
increased by 2 percent to $6.51 per Mcf in 2004 from $6.39 per Mcf in
2003. PET's average gas price after hedging transactions was $6.40 per
Mcf and $6.72 per Mcf in 2004 and 2003 respectively.

HEDGING AND RISK MANAGEMENT

PET's hedging activities are conducted in consultation with the Board of
Directors of the administrator of the Trust with the objective of using
a proactive and opportunistic approach to hedging in order to maximize
distributable income while managing price risk rather than a routine
portfolio approach. A number of market analysis tools are used in an
attempt to identify perceived anomalies or trends in natural gas
markets. In addition hedging may be used to ensure or enhance the
economics related to significant acquisitions. The Trust limits its
hedging activity for any given period to 50 percent of forecast
production for that period.

In 2004, the Trust's hedging activities resulted in a net payment of
$4.3 million or $0.11 per Mcf (2003 - $10.3 million net receipt: $0.33
per Mcf). Activity in 2002 did not include any hedging as the 2002
results represent an allocation of the northeast Alberta operations of
PRL.

REVENUE

Oil and natural gas revenue in 2004 was $240.0 million, representing a
14 percent increase from $209.8 million in 2003. Revenue growth was
achieved via higher natural gas volumes.



Revenue
---------------------------------------------------------------------
($ thousands) 2004 2003 2002
---------------------------------------------------------------------
---------------------------------------------------------------------
Oil and natural gas revenue,
before hedging 244,303 199,488 132,631
Hedging receipts (4,346) 10,318 -
---------------------------------------------------------------------
Total revenue 239,957 209,806 132,631
---------------------------------------------------------------------
---------------------------------------------------------------------


OPERATING NETBACKS

A 2004 operating netback of $4.00 per Mcfe compared to $4.33 per Mcfe in
2003 reflected the 5 percent decline in natural gas prices and a 16
percent increase in unit operating costs.

Operating costs include all costs associated with the production of oil
and natural gas from the time the well commences commercial production
to the point at which the product enters a pipeline for transport.
Gathering and processing costs are also included in operating costs.
Revenue received from the processing of third-party production at PET's
facilities is netted against operating costs.

Operating costs increased by 40 percent (16 percent per Mcfe) to $38.8
million ($1.03 per Mcfe) in 2004 from $27.7 million ($0.89 per Mcfe) in
2003. Operating costs increased by $11.2 million in 2004 due to the
increased production volumes related to the Marten Hills, Athabasca, and
Cavell acquisitions. Unit costs increased as a result of ongoing fixed
costs for facilities with lost production from the gas over bitumen
shut-ins and an overall industry trend towards increasing operating
costs resulting from competitive conditions and a shortage of oilfield
services.

PET pays Crown, freehold and overriding royalties that are dependent
upon production volumes, commodity prices, location and age of producing
wells and type of production. Gas Crown royalties are reduced by Gas
Cost Allowance ("GCA") deductions. The GCA deductions are based on
processing fees and allowable capital cost incurred at a property and
are in accordance with Crown royalty regulations. Royalty income
received is included in revenue. The effective royalty rate applicable
to the Trust in 2004 was 17.3 percent (2003 - 18.2 percent) or $1.11 per
Mcfe (2003 - $1.22 per Mcfe).

Costs to transport the product from the wellsite to the commercial
market are not reflected as an operating cost but rather are recorded as
transportation costs for the product. Total transportation costs
increased by 14 percent to $9.8 million ($0.26 per Mcfe) in 2004 from
$8.6 million ($0.28 per Mcfe) in 2003. The increased transportation
costs are a factor of the 20 percent increase in production from 2003 to
2004. In 2004, PET retroactively adopted the new accounting standard
requiring that revenue be reported before transportation costs with
separate disclosure of transportation costs in net earnings.

The components of operating netbacks are shown below:



Netback
---------------------------------------------------------------------
($ per Mcfe) 2004 2003 2002

---------------------------------------------------------------------
---------------------------------------------------------------------
Gas price 6.40 6.72 3.83
Royalties (1.11) (1.22) (0.63)
Operating costs (1.03) (0.89) (0.87)
Transportation costs (0.26) (0.28) (0.26)
---------------------------------------------------------------------
Netback 4.00 4.33 2.07
---------------------------------------------------------------------
---------------------------------------------------------------------


SHUT-IN GAS OVER BITUMEN NETBACKS

A 2004 netback of $2.29 per Mcfe compared to $1.86 per Mcfe in 2003
reflected the gas over bitumen financial solution implemented at year
end as a result of the amendments to the Natural Gas Royalty Regulation.
The formula contained in the amended Regulation allows for a royalty
adjustment of:

0.5 x ((deemed production volume x 0.80) x (Alberta Gas Reference Price
- $0.4293/GJ))

Through this formula, operating costs are effectively deemed to be $0.45
Per Mcf, royalties are deemed to be 20%, the deemed production is
assigned the Alberta Gas Reference Price, which includes a
transportation component and the entire formula is assigned an arbitrary
50% reduction factor. The components of netbacks for the gas over
bitumen shut-in reserves can be derived as below:



Netback
---------------------------------------------------------------------
($ per Mcfe) 2004 2003 (1) 2002
---------------------------------------------------------------------
---------------------------------------------------------------------
Average deemed volume (MMcf/d) (2) 16.7 9.6 -
--------------------------------------------------------------------
Gas price 6.28 5.20 -
Royalties (1.26) (1.04) -
Operating costs (0.45) (0.45) -
Arbitrary multiplier (2.28) (1.85) -
---------------------------------------------------------------------
Netback 2.29 1.86 -
---------------------------------------------------------------------
---------------------------------------------------------------------


(1) From September 1, 2003 to December 31, 2003

(2) Represents 14.6 MMcf/d of shut-in production (2003 - 7.4 MMcf/d) and
2.1 MMcf/d of wells denied production under AEUB ID 99-1 (2003 - 2.1
MMcf/d)

(3) All actual Gas over Bitumen Royalty Adjustments received in 2004,
including retroactive payments for shut-in during the period September 1
through December 31, 2003, have been recorded as an adjusting item for
cash flow from operations in 2004. Gas over Bitumen Royalty Adjustments
have not been restated for 2003.

The deemed production volume includes all gas shut-in or denied
production pursuant to a Decision Report, corresponding AEUB Order or
General Bulletin, or through correspondence in relation to an AEUB ID
99-1 application. The Trust's current net deemed production volume for
purposes of the royalty adjustment is 22.8 MMcf/d. According to Alberta
Department of Energy Information Letter 2004-36, the deemed production
volume will be reduced by 10% at the end of every year of shut-in.

GENERAL AND ADMINISTRATIVE EXPENSE

General and administrative expenses ("G&A") include costs incurred by
PET which are not directly associated with the production of oil and
natural gas. The most significant components of G&A expenses are office
employee compensation costs, office rent and gas over bitumen costs.
Field employee compensation costs for field employees are charged to
operating expenses. Overhead recoveries resulting from the allocation of
administrative costs to partners are recorded as a reduction of G&A
expenses.

G&A expenses, net of overhead recoveries on operated properties,
increased to $13.8 million ($0.37 per Mcf) in 2004 from $4.7 million
($0.15 per Mcfe) in 2003. The 2004 total included $1.2 million in legal
and consulting expenditures directly related to the AEUB gas over
bitumen issue ($0.7 million - 2003). In addition, PET has expensed $5.5
million in 2004 related to Trust Unit-based compensation costs charged
to earnings under new accounting rules adopted for 2004. The Trust
Unit-based compensation costs were not restated for 2003. The Trust
expects 2005 G&A costs excluding non-cash G&A to increase slightly as a
result of a full year of increased G&A costs following the Cavell and
Athabasca acquisitions and the increased capital expenditure program in
2005, offset by reduced costs associated with office rent as the Trust
purchased the building occupied by its head office in November 2004.



General and
Administrative Expense 2004 2003 2002
---------------------------------------------------------------------
$000's $/Mcfe $000's $/Mcfe $000's $/Mcfe
---------------------------------------------------------------------
---------------------------------------------------------------------
Cash general &
administrative 7,119 0.19 3,980 0.13 3,987 0.12
Gas over bitumen costs 1,160 0.03 696 0.02 - -
---------------------------------------------------------------------
---------------------------------------------------------------------
Trust unit
compensation 5,493 0.15 - - - -
---------------------------------------------------------------------
Total general &
administrative 13,772 0.37 4,676 0.15 3,987 0.12
---------------------------------------------------------------------
---------------------------------------------------------------------


INTEREST EXPENSE

Interest expense increased to $4.8 million in 2004 from $2.4 million in
2003 as a result of a higher monthly average debt balance following the
Cavell and Athabasca acquisitions. This was offset by a slightly lower
interest rate as a result of the reduction of the Bankers' Acceptance
stamping fee rate from 1.50% to 1.25% in August of 2004. Interest
expense was minimized over the course of the year by financing debt
through the issuance of lower cost bankers' acceptances as opposed to
borrowing at the prevailing bank prime interest rates.

On August 10th, the Trust issued $48 million of convertible debentures
to finance the Athabasca acquisition. Throughout the remainder of the
year, $9.6 million debentures were converted into 674,711 Trust Units.
In 2004, $1.4 million of interest on the convertible debentures was
expensed.

DEPLETION, DEPRECIATION AND ACCRETION

PET's 2004 depletion, depreciation and accretion (DD&A) rate increased
to $2.90 per Mcfe from $2.01 per Mcfe in 2003, primarily due to the
negative revisions in the Trust's proved reserves at December 31, 2004
and the reduction of proved reserves for the Trust's Saskatchewan assets
acquired through the Cavell plan of arrangement during 2004. The Trust
calculates its depletion factor using proved reserves and production and
as such neither the shut-in gas over bitumen reserves nor the gas over
bitumen royalty adjustment are included in the DD&A calculation. The
DD&A rate includes accretion expense on the asset retirement obligation
of $2.1 million in 2004 ($1.2 million in 2003).



Depletion, Depreciation and Accretion
---------------------------------------------------------------------
($ thousands except where noted) 2004 2003 2002
---------------------------------------------------------------------

Depletion expense 106,777 61,436 50,383
Accretion of asset retirement obligation 2,090 1,239 1,163
---------------------------------------------------------------------
Total 108,867 62,675 51,546
---------------------------------------------------------------------
Per Unit ($/Mcfe) 2.90 2.01 1.49
---------------------------------------------------------------------
---------------------------------------------------------------------


Property, plant and equipment costs included undeveloped land of $72.5
million (2003 - $46.8 million) and $35.4 of costs related to shut-in gas
over bitumen reserves which are currently not subject to depletion.

INCOME TAXES

The Trust, and its principal operating entities are taxable entities
under the Income Tax Act (Canada) and are taxable only on income that is
not distributed or distributable to the Unitholders. As the Trust
distributes all of its taxable income to the Unitholders pursuant to its
Trust Indenture and meets the requirements of the Income Tax Act
(Canada) applicable to the Trust, no provision for income taxes has been
made relative to the Trust. The Administrator has no tax balances.

The Trust's corporate subsidiaries follow the tax liability method of
accounting for income taxes. Under this method, income tax liabilities
and assets are recognized for the estimated tax consequences
attributable to differences between the amounts reported in the
financial statements and their respective tax bases, using enacted
income tax rates. The effect of a change in income tax rates on future
income tax liabilities and assets is recognized in income in the period
that the change occurs.

CAPITAL EXPENDITURES

Total capital expenditures, including net property and corporate
acquisitions, aggregated to $425.1 million in 2004 ($310.5 million in
2003). Of the total, $28.9 million was incurred on drilling and
completions, geological, geophysical and facilities expenditures, with
the remaining $396.2 million attributable to net property and corporate
acquisitions.

In late 2004 PET acquired the five story office building in downtown
Calgary which has housed its offices since the formation of the Trust
from Paramount Resources Limited for $10.5 million. The building which
has an appraised value of $12.6 million provides effective facilities
for the Trust, shields PET from escalating rental rates and provides
potential for increasing real estate values.

A breakdown of capital expenditures by category is shown below:



Capital Expenditures
---------------------------------------------------------------------
($ thousands except where noted) 2004 2003 2002
---------------------------------------------------------------------
---------------------------------------------------------------------
Exploration and development expenditures 28,891 8,327 11,468
Acquisitions 417,779 32,252 -
Dispositions (32,750) - -
Oil and gas properties acquired from PRL - 269,162 -
Other 11,169 757 2,828
---------------------------------------------------------------------
Total capital expenditures and
net acquisitions 425,089 310,498 14,296
---------------------------------------------------------------------
---------------------------------------------------------------------


The Board of Directors of the Administrator of PET has approved a
capital budget for exploration and development expenditures of up to $45
million for 2005.

COST RECOVERY TEST

PET performs cost recovery tests annually or as economic events dictate.
An impairment loss is recognized when the carrying amount of a property
or project is greater than the sum of the expected future cash flows
(undiscounted and without interest charges) from that property or
project. The amount of the impairment loss is calculated as the
difference between the carrying amount and the present value of
estimated future cash flows.

The sum of the expected future cash flows for the total of all of PET's
properties greatly exceeds the carrying amount of its property, plant
and equipment. The successful efforts accounting methodology followed by
PET prescribes that each constituent property group be tested
individually for impairment. Testing of the Saskatchewan property
grouping resulted in an impairment amount of $65.4 million as at
December 31, 2004 and as a result the entire property, plant and
equipment account of PET has been reduced by that amount through an
additional charge to depletion and depreciation. Such adjustments relate
to prescribed determinations under the successful efforts method of
accounting and should not be taken to represent indications of the fair
market value of PET's assets or the possible impairment of such value.

This impairment charge arose primarily in connection with the year end
reserve evaluation in the Trust's Saskatchewan cost centre. The
properties acquired in the Cavell acquisition in the West Central
Saskatchewan and Abbey areas have been affected by technical and well
performance difficulties. Consequently, assignment of reserves at
December 31, 2004 was less than anticipated when evaluated by the
Trust's independent reserve consultants, McDaniel and Associates. PET's
technical teams continue to evaluate the properties in an ongoing effort
to solve the technical challenges of this area.

At December 31, 2003, PET recorded a writedown of property, plant and
equipment of $9.8 million related to the gas over bitumen issue. The
estimated value of the reduced royalties associated with the gas over
bitumen financial solution significantly exceeds the net book value of
the shut-in reserves; therefore no further writedown for the shut-in
reserves has been recorded in 2004.



CAPITALIZATION AND FINANCIAL RESOURCES

Capitalization and Financial Resources
---------------------------------------------------------------------
$ thousands except per Trust Unit
and percent amounts 2004 2003
---------------------------------------------------------------------
---------------------------------------------------------------------
Bank and other debt 171,698 55,564
Convertible debentures 38,419 -
Working capital deficiency (surplus) 2,611 (2,196)
---------------------------------------------------------------------
Net debt 212,728 53,368
Trust Units outstanding (000's) 65,327 44,638
Market price at end of period 15.88 11.68
Market value of Trust Units 1,037,392 521,376
Total capitalization (1) 1,250,120 574,744
---------------------------------------------------------------------
Net debt as a percent of total capitalization 17.0% 9.3%
Cash flow 143,592 126,360
Net debt to cash flow ratio 1.5 0.4
---------------------------------------------------------------------
---------------------------------------------------------------------


(1) Total capitalization as presented does not have any standardized
meaning prescribed by Canadian GAAP and therefore it may not be
comparable with the calculation of similar measures for other entities.
Total capitalization is not intended to represent the total funds from
equity and debt received by the Trust.

PET commenced bank borrowing in March 2003. At December 31, 2004, PET
had bank debt outstanding of $171.7 million compared to $55.6 million at
December 31, 2003, $38.4 million in convertible debentures versus nil at
December 31, 2003, and a working capital deficit of $1.8 million versus
a working capital surplus of $2.2 million at the end of 2003. The 2004
year-end working capital deficit is a result of normal operating
conditions in periods when the Trust incurs significant capital
expenditures. PET participated in significant capital projects near the
end of the year resulting in accrued capital expenditures of $7.6
million at December 31, 2004 compared to $1.2 million at December 31,
2003.

PET has a revolving credit facility with a syndicate of five Canadian
Chartered Banks. As at the date of this report the revolving credit
facility had a borrowing base of $220 million. The facility consists of
a demand loan of $210 million and a working capital facility of $10
million. In addition to amounts outstanding under the facility, PET has
outstanding letters of credit in the amount of $2.85 million. Collateral
for the credit facility is provided by a floating-charge debenture
covering all existing and after acquired property of the Trust as well
as unconditional full liability guarantees from all subsidiaries in
respect of amounts borrowed under the facility.

Advances under the facility are made in the form of Banker's Acceptances
("BA"), prime rate loans or letters of credit. In the case of BA
advances, interest is a function of the BA rate plus a stamping fee
based on the Trust's current ratio of debt to cash flow. In the case of
prime rate loans, interest is charged at the lenders' prime rate. The
average interest rate at December 31, 2004 was 3.78%.

December 31, 2004 net debt to total capitalization was 17.0 percent (9.3
percent in 2003) and net debt to 2004 cash flow was 1.5 years (0.4 times
in 2003) based upon cash flow from operations of $143.6 million and net
debt of $212.7 million.

The Trust's current plans are to finance the approved 2005 capital
budget of $45 million from cash flow.

CONVERTIBLE DEBENTURES

On August 10, 2004, PET issued $48 million of 8.0% Convertible
Extendible Unsecured Subordinated Debentures (the "Convertible
Debentures") for net proceeds of $46.1 million. The Convertible
Debentures have a maturity date of September 30, 2009.

The Convertible Debentures bear interest at 8.0% per annum, paid
semi-annually on March 31 and September 30 of each year and are
subordinated to substantially all other liabilities of PET, including
its credit facility. The Convertible Debentures are convertible at the
option of the holder into PET Trust Units at any time prior to September
30, 2009 at a conversion price of $14.20 per Unit. The Convertible
Debentures are not redeemable by PET on or before September 30, 2007 but
may be redeemed in whole or in part at the option of PET at a price of
$1,050 per Convertible Debenture after September 30, 2007 and prior to
September 30, 2008 at a price of $1,025 per Convertible Debenture
thereafter until their maturity. Redemption and conversions entitle the
holder to accrued and unpaid interest to and including the effective
date.

At the option of PET, the repayment of the principal amount of the
Convertible Debentures may be settled in Trust Units. The number of
Trust Units to be issued upon redemption by PET will be calculated by
dividing the principal by 95% of the weighted average trading price. The
interest payable may also be settled with the issuance and sale of
sufficient Trust Units to satisfy the interest obligation. At December
31, 2004, $9.6 million in Convertible Debentures had been converted into
674,711 Trust Units and the fair market value of the outstanding
Convertible Debentures was $43.9 million.

In 2004 PET early-adopted the new accounting rules in effect for fiscal
years ending on or after November 1, 2004, which will require the
Convertible Debentures to be disclosed as financial liabilities rather
than equity on the balance sheet.

UNITHOLDERS' EQUITY

PET's total capitalization was $1,250.1 million at December 31, 2004
with the market value of the Trust Units representing 83 percent of
total capitalization. During 2004, the market price of the Trust Units
ranged from $9.92 to $16.87 with an average daily trading volume of
268,000 Units.

PET implemented an industry-leading distribution reinvestment and
optional Trust Unit purchase plan ("DRIP Plan") for eligible Unitholders
of the Trust in February 2004. The DRIP Plan provides Unitholders with
the opportunity to reinvest monthly cash distributions to acquire
additional Trust Units at 94 percent of the Treasury Purchase Price,
which is defined as the daily volume weighted average trading prices of
the Trust Units for the 10 trading days immediately proceeding a
distribution payment date. As well, subject to thresholds and
restrictions described in the DRIP Plan, it contains a provision for the
purchase of additional Trust Units with optional cash payments of up to
$100,000 per participant per fiscal year of PET to acquire additional
Trust Units at the same 6 percent discount to the Treasury Purchase
Price. No additional commissions, service or brokerage fees will be
charged to the Unitholder for these transactions. The DRIP Plan resulted
in an additional 632,829 Trust Units being issued in 2004 at an average
price of $12.93 raising a total of $8.2 million.

On December 31, 2004 there were 65.3 million Trust Units outstanding.
Trust Units were issued during 2004 as follows:

- On May 18, 2004 PET closed an equity financing issuing 4.5 million
Trust Units at $11.20 per Unit for net proceeds of $47.9 million.

- On July 16, 2004 PET issued 6.9 million units as a part of the Cavell
acquisition at $11.35 for net proceeds of $78.7 million.

- On August 10, 2004 PET closed an equity financing issuing 7.8 million
Trust Units at $12.65 for net proceeds of $91.5 million.

- During 2004, 0.2 million Trust Units were issued by way of exercised
incentive rights for net proceeds of $1.9 million.

- During 2004, 0.6 million Trust Units were issued through the DRIP Plan
for net proceeds of $8.2 million.

- In 2004, 0.7 million Trust Units were issued through the conversion of
Convertible Debentures to Trust Units.

CASH DISTRIBUTIONS

PET declared cash distributions of $121.3 million ($2.18 per Unit) in
2004 representing 84 percent of 2004 cash flow, bringing total
cumulative distributions since inception to $244.5 million, ($5.064 per
Trust Unit). In 2003, declared cash distributions were $123.2 million
($2.884 per Trust Unit), representing 97 percent of cash flow.

Historical Distributions by Calendar Year



Calendar Year Distributions Taxable Return of Capital
---------------------------------------------------------------------
2004 $ 2.180 1.713 0.467
2003 2.884 1.500 1.384
---------------------------------------------------------------------
Cumulative $ 5.064 3.213 1.851

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


Taxation of 2004 Cash Distributions

Cash distributions are comprised of a return of capital portion (tax
deferred) and a return on capital portion (taxable). For cash
distributions received or receivable by a Canadian resident, outside of
a registered pension or retirement plan in the 2004 taxation year, the
split between the two is 78.58 percent taxable and 21.42 percent tax
deferred.

PET, in consultation with its tax advisors, is of the view that the 2004
distributions paid to non-corporate Unitholders who are U.S. residents
are "Qualified Dividends" for U.S. tax purposes. With respect to
distributions paid in 2004, 82.39 percent would be reported as qualified
dividends and 17.61 percent would be reported as non-taxable return of
capital for U.S. Persons. PET performed an Earnings and Profits
calculation for U.S. tax purposes in order to make this determination.



2004 Distributions by Month
($ per Trust Unit)
Tax Deferred
Amount
Taxable (Return of Total
Payment Date Amount Capital) Distribution
---------------------------------------------------------------------
February 16, 2004 $ 0.157 $ 0.043 $ 0.200
March 15, 2004 0.126 0.034 0.160
April 15, 2004 0.126 0.034 0.160
May 17, 2004 0.126 0.034 0.160
June 15, 2004 0.126 0.034 0.160
July 15, 2004 0.126 0.034 0.160
August 16, 2004 0.141 0.039 0.180
September 15, 2004 0.157 0.043 0.200
October 15, 2004 0.157 0.043 0.200
November 15, 2004 0.157 0.043 0.200
December 15, 2004 0.157 0.043 0.200
January 17, 2005 0.157 0.043 0.200
---------------------------------------------------------------------
Total $ 1.713 $ 0.467 $ 2.180 (1)
---------------------------------------------------------------------
Percent 78.58% 21.42% 100.0%
---------------------------------------------------------------------
---------------------------------------------------------------------


(1) Total is based upon cash distributions paid and payable during 2004

2005 Cash Distributions

PET has declared three consecutive payments of $0.22 per Trust Unit in
2005 following implementation of the gas over bitumen financial solution
announced by the Trust in January.

PET estimates that this level of monthly distributions of $0.22 per Unit
per month will be sustainable for the foreseeable future, based upon the
Trust's current hedges and the forward market for natural gas prices,
however distributions are subject to change as dictated by actual
conditions.

FINANCIAL REPORTING AND REGULATORY UPDATE

There have been several changes in the financial reporting and
securities regulatory environment in 2004 that have impacted PET and all
public entities. Canadian securities regulators and the Canadian
Institute of Chartered Accountants ("CICA") are undertaking these
measures to increase investor confidence through increased transparency,
consistency and comparability of financial statements and financial
information. As well, the changes have been brought about by a goal of
aligning Canadian standards more closely with those in the United States.

The following new and amended standards were implemented by the Trust in
2004 and their impact as reflected in the 2004 financial statements:

Stock Based Compensation and Other Stock Based Payments - In September
2003, the CICA issued an amendment to section 3870 "Stock based
compensation and other stock based payments". The amended section was
effective for fiscal years beginning on or after January 1, 2004.

Transportation Costs - New accounting standards effective for fiscal
years beginning on or after October 1, 2003 focus on what constitutes
Canadian GAAP and its sources, including the primary sources of
generally accepted accounting principles. In prior years, it had been
industry practice to record revenue net of related transportation costs.
In accordance with the new accounting standard, revenue is now reported
before transportation costs with separate disclosure in the consolidated
statement of earnings and accumulated earnings of transportation costs.
This change in classification has no impact on net earnings, earnings
per Trust Unit or working capital and the comparative figures have been
restated to conform to the presentation adopted for the current year.

Hedging Relationships - In December 2001, the CICA issued Accounting
Guideline 13 "Hedging Relationships" that deals with the identification,
designation, documentation and measurement of effectiveness of hedging
relationships for the purposes of applying hedge accounting. Accounting
Guideline 13 is intended to harmonize Canadian GAAP with SFAS No.133
"Accounting for Derivatives Instruments and Hedging Activities". The
guideline is effective for fiscal years beginning on or after July 1,
2003.

Continuous Disclosure Obligations - Effective March 31, 2004, the Trust
and all reporting issuers in Canada will be subject to new disclosure
requirements as per National Instrument 51-102 Continuous Disclosure
Obligations. This new instrument is effective for fiscal years beginning
on or after January 1, 2004. The instrument proposes shorter reporting
periods for filing of annual and interim financial statements, MD&A and
the Annual Information Form ("AIF"). The instrument also proposes
enhanced disclosure in the annual and interim financial statements, MD&A
and AIF. Under this new instrument, it will no longer be mandatory for
the Trust to mail annual and interim financial statements and MD&A to
Unitholders, but rather these documents will be provided on an "as
requested" basis. It is PET's intention to make these documents
available on the Trust's website on a continuous basis.

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

Impact on Net Earnings of Change in Accounting Policies

The implementation of a new accounting policy relating to asset
retirement obligations has resulted in restatement of previously
reported annual and quarterly net earnings. The restatement was required
per the transitional provisions of the accounting standard.

The following table illustrates the impact of the new accounting policy
on annual net income for the years and quarters which have been
presented for comparative purposes:



2004
($ thousands) Q4 Q3 Q2 Q1 Total
---------------------------------------------------------------------
---------------------------------------------------------------------
Net Earnings (loss)
before changes
in accounting
policies (1) (30,484) 2,890 5,029 1,902 (20,663)
---------------------------------------------------------------------
Increase (decrease)
in net earnings
Asset retirement
obligation (2) - - - - -
---------------------------------------------------------------------
Net Earnings (loss) after
change in accounting
policies (30,484) 2,890 5,029 1,902 (20,663)
---------------------------------------------------------------------
---------------------------------------------------------------------
2003

($ thousands) Q4 Q3 Q2 Q1 Total
---------------------------------------------------------------------
---------------------------------------------------------------------
Net Earnings (loss)
before changes in
accounting policies (1) (2,574) 11,993 17,502 26,416 53,337
---------------------------------------------------------------------
Increase (decrease)
in net earnings
Asset retirement
obligation (2) (238) 323 (518) (470) (903)
---------------------------------------------------------------------
Net Earnings (loss)
after change
in accounting policies (2,812) 12,316 16,984 25,946 52,434
---------------------------------------------------------------------
---------------------------------------------------------------------


(1) This represents net earnings as reported before retroactive
restatement for changes in accounting policies.

(2) The new accounting policy for asset retirement obligations was
implemented in the fourth quarter of 2003. This new standard requires
retroactive application with restatement of all periods presented for
comparative purposes.



Paramount Energy Trust
Consolidated Balance Sheets

As at December 31, December 31,
2004 2003
---------------------------------------------------------------------
---------------------------------------------------------------------
($ thousands)

Assets
Current Assets
Accounts Receivable $ 32,128 $ 19,029
Property, Plant and Equipment
(Notes 4 and 5) 494,885 241,955
Goodwill (Note 4) 29,698 -
---------------------------------------------------------------------
$ 556,711 $ 260,984
---------------------------------------------------------------------
---------------------------------------------------------------------

Liabilities
Current Liabilities
Accounts Payable and Accrued
Liabilities $ 21,674 $ 7,905
Distributions Payable 13,065 8,928
Bank and Other Debt (Note 6) 171,698 55,564
---------------------------------------------------------------------
206,437 72,397
---------------------------------------------------------------------

Gas over Bitumen Royalty
Adjustments (Note 13) 11,200 821
Asset Retirement Obligations
(Notes 5 and 10) 34,116 21,701
Convertible Debentures (Note 7) 38,419 -
Future Income Taxes (Note 12) 2,088 -

Unitholders' Equity
Unitholders' Capital (Note 8) 496,192 260,018
Contributed Surplus (Note 3) 6,929 -
Equity Adjustments (Notes 1 and 5) (16,172) (16,172)
Accumulated Earnings 22,120 45,421
Accumulated Distributions (244,618) (123,202)
---------------------------------------------------------------------
264,451 166,065
---------------------------------------------------------------------
$ 556,711 $ 260,984
---------------------------------------------------------------------
---------------------------------------------------------------------

See Accompanying Notes
Basis of Presentation: Notes 1 and 2
Contingency: Note 13


Paramount Energy Trust
Consolidated Statements of Earnings and Accumulated Earnings

Year Ended
December 31
2004 2003
---------------------------------------------------------------------
---------------------------------------------------------------------
($ thousands except per unit amounts)

Revenue
Oil and Natural Gas $ 239,957 $ 209,806
Royalties (41,661) (38,209)
---------------------------------------------------------------------
198,296 171,597
---------------------------------------------------------------------
---------------------------------------------------------------------

Expenses
Operating 38,818 27,727
Transportation Costs (Note 3) 9,782 8,567
Exploration Expenses 2,867 3,278
General and Administrative 7,119 3,980
Trust Unit Compensation (Note 3) 5,493 -
Gas Over Bitumen Costs (Note 13) 1,160 696
Interest on Bank and Other Debt (Note 6) 4,817 2,440
Interest on Convertible Debentures
(Note 7) 1,410 -
Write-down of Property, Plant
and Equipment (Note 5) 65,384 9,800
Depletion, Depreciation and
Accretion (Notes 5 and 10) 108,867 62,675
---------------------------------------------------------------------
245,717 119,163
---------------------------------------------------------------------
Earnings (Loss) before Income Taxes (47,421) 52,434
---------------------------------------------------------------------
Future Income Tax Reduction (Note 12) (27,610) -
Capital Taxes 852 -
---------------------------------------------------------------------
(26,758) -
---------------------------------------------------------------------
Net Earnings (Loss) (20,663) 52,434

Accumulated Earnings Net of
Distributions at Beginning of Year,
as previously reported (77,781) 238,203
Retroactive Effect of Change in
Accounting Policies (Note 3 and 10) (2,740) (3,640)
---------------------------------------------------------------------
Accumulated Earnings Net of Distributions
at Beginning of Year, as restated (80,521) 234,563
Reduction in Net Investment on
Restructuring (Notes 1 and 2) - (241,576)
Distributions Paid or Payable (121,314) (123,202)

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

Accumulated Earnings Net of
Distributions at End of Year $ (222,498) $ (77,781)
---------------------------------------------------------------------
---------------------------------------------------------------------

Earnings (Loss) Per Trust Unit (Note 2(d))
Basic $ (0.38) $ 1.23
Diluted $ (0.38) $ 1.21
---------------------------------------------------------------------

Distributions Per Trust Unit $ 2.18 $ 2.88
---------------------------------------------------------------------

See Accompanying Notes


Paramount Energy Trust
Consolidated Statements of Cash Flows
Year Ended
December 31
2004 2003
---------------------------------------------------------------------
---------------------------------------------------------------------
($ thousands)

Cash Provided By (Used For)
Operating Activities
Net Earnings (Loss) $ (20,663) $ 52,434
Adjusting Items
Gas over Bitumen Royalty
Adjustments (Note 13) 11,200 -
Depletion, Depreciation and Accretion 108,867 62,675
Amortization of Convertible Debenture
Issue Costs 147 -
Trust Unit Compensation 5,493 -
Write-down of Property, Plant
and Equipment 65,384 9,800
Future Income Tax Reduction (Note 12) (27,610) -
Items not Associated with Operations
Exploration Expenses 774 1,451
---------------------------------------------------------------------
Funds from Operations 143,592 126,360
Change in Non-Cash Working Capital (6,377) (13,941)
---------------------------------------------------------------------
137,215 112,419
---------------------------------------------------------------------

Financing Activities
Issue of Trust Units 142,364 260,018
Distributions to Unitholders (116,680) (123,202)
Issue of Convertible Debentures 46,080 -
Change in Bank and Other Debt 116,134 53,441
Change in Non-Cash Working Capital 5,263 8,928
---------------------------------------------------------------------
193,161 199,185
---------------------------------------------------------------------

Funds Available for Investment 330,376 311,604
---------------------------------------------------------------------
---------------------------------------------------------------------

Investing Activities
Exploration Expenses (774) (1,451)
Acquisition of Properties (339,105) (301,414)
Disposition of Properties 32,750 -
Change in Non-Cash Working Capital 16,813 345
Acquisition of Corporate Assets (11,169) (757)
Exploration and Development Expenditures (28,891) (8,327)
---------------------------------------------------------------------
$ (330,376) $ (311,604)
---------------------------------------------------------------------
---------------------------------------------------------------------

See Accompanying Notes


PARAMOUNT ENERGY TRUST
Notes to Consolidated Financial Statements
(dollar amounts in $Cdn except as noted)


1. PARAMOUNT ENERGY TRUST CREATION AND FINANCING

Paramount Energy Trust ("PET" or the "Trust") is an unincorporated trust
formed under the laws of the Province of Alberta pursuant to a trust
indenture ("PET Trust Indenture") dated June 28, 2002. The beneficiaries
of PET are the holders of the Trust Units of PET (the "Unitholders").
PET was established for the purposes of issuing Trust Units and
acquiring and holding royalties and other investments. The consolidated
financial statements of PET consist of 100 percent ownership of
Paramount Energy Operating Corp. (the "Administrator") and 100 percent
ownership of the beneficial interests of Paramount Operating Trust
("POT"). PET utilizes a calendar fiscal year for financial reporting
purposes.

The Administrator was incorporated primarily to act as trustee of POT.
As trustee of POT, the Administrator will hold legal title to the
properties and assets of POT on behalf of and for the benefit of POT and
will administer, manage and operate the oil and gas business of POT. In
addition, the Administrator provides certain management and
administrative services for PET and its trustee pursuant to a delegation
of power and authority to it under the PET PET Trust Indenture.

On July 1, 2002, PET entered into an agreement with a subsidiary of
PET's then-parent Paramount Resources Ltd. ("PRL") to acquire corporate
assets. As the transaction was between related parties, the assets
acquired were recognized at a value equal to their net book value in the
books of the vendor. This resulted in an increase in the carrying value
of the assets of $1.3 million and an equivalent increase in unitholders'
equity (Note 8).

The issuance of a receipt for a prospectus was made by Canadian
securities regulatory authorities on January 29, 2003 and by securities
regulators in the United States on February 3, 2003. Subsequent to the
issuance of these receipts, PET, POT, the Administrator and PRL
completed a series of transactions pursuant to which PET, on a
consolidated basis, acquired oil and gas properties and related assets
with an estimated value of $301,000,000 from PRL. PET raised equity of
approximately $150,000,000 from the exercise of rights and obtained bank
financing of approximately $100,000,000. The series of transactions were
as follows:

On February 3, 2003, PRL, effective July 1, 2002, sold its interest in
certain assets (the "Initial Assets") to POT for consideration
consisting of a promissory note in PRL's favor of $81,000,000. Interest
on the $81,000,000 purchase price accrued at a rate of 6.5 percent per
annum. At that time a secured guarantee was given by both POT and PET in
respect of $20,000,000 of PRL's indebtedness to PRL's lenders. At the
same time PRL and POT executed the take-up agreement which required PRL
to sell and POT to purchase 100 percent of PRL's interest in certain
additional assets (the "Additional Assets"). The purchase price was
$220,000,000. POT paid a $5,000,000 deposit on the purchase price of
these assets through the issuance of a non-interest bearing promissory
note. As related party transactions, the purchase price of the acquired
Initial and Additional Assets was adjusted to reflect the seller's net
book value of the assets. This resulted in a reduction in the carrying
value of petroleum and natural gas properties of $17.5 million. This
amount was recorded as a reduction in Unitholders' Equity;

- POT, effective July 1, 2002, granted to PET a royalty (the "Royalty")
of 99 percent of the net revenue less permitted deductions with respect
to debt payments, capital expenditures and certain other amounts from
the Canadian resource properties comprised in the Initial Assets and all
after-acquired Canadian resource properties of POT including the
Additional Assets in exchange for consideration consisting of
$64,152,000 to be paid in accordance with an agreement between POT, PET
and PRL whereby PET issued and delivered to PRL a first promissory note
in the amount of $30,000,000 and a second promissory note in the amount
of $34,152,000. The first promissory note carried annual interest equal
to the prime rate of a major Canadian chartered bank from time to time
plus 1.875 percent. This payment reduced the amount of indebtedness that
POT owed to PRL to approximately $16,848,000 which was represented by a
promissory note that carried annual interest from the date of issue
equal to the prime rate of a major Canadian chartered bank from time to
time plus 1.875 percent. PET granted a security interest to PRL in PET's
assets as security for its indebtedness under the first promissory note
and POT granted a guarantee to PRL for such indebtedness and granted PRL
a security interest over its assets for the guarantee;

- PET issued 6,636,045 Trust Units to PRL in full repayment of the
indebtedness under the second promissory note;

- PET purchased from PRL the remaining $16,848,000 indebtedness owed by
POT to PRL in exchange for the issuance and delivery to PRL of an
additional 3,273,721 Trust Units;

- PRL did, on February 3, 2003, by way of a dividend, distribute all of
the PET Trust Units held by PRL, being all 9,909,767 Trust Units, to the
holders of PRL common shares;

- PET issued to each of the holders of the Trust Units distributed by
PRL, three rights to subscribe for additional PET Trust Units. Each
right entitled the holder to purchase one additional PET Trust Unit at a
subscription price of $5.05 per Trust Unit. On March 11, 2003, PRL did,
effective July 1, 2002, sell to POT 100 percent of PRL's interest in the
Additional Assets for an aggregate consideration of $220,000,000. This
was funded by the exercise and payment of 100 percent of the rights
granted, resulting in proceeds of $150,129,475 (before issue costs).
These funds together with bank financing of $100,000,000 were also used
to repay the $30,000,000 promissory note to PRL and to complete the
acquisition of the Additional Assets.

- Effective March 19, 2003 POT acquired a 100 percent interest in the
Ells property in northeast Alberta from PRL for $19.9 million.

2. BASIS OF PRESENTATION AND ACCOUNTING POLICIES

The accompanying financial statements have been prepared by management
of the Administrator (as agent for the trustee of PET) on behalf of PET
in accordance with Canadian generally accepted accounting principles
("Canadian GAAP").

Prior to the asset acquisitions on February 3, 2003 and March 11, 2003
described in Note 1, the consolidated financial statements include the
operations and results of the northeast Alberta properties of PRL which
were acquired by PET on those dates. The consolidated financial
statements have been prepared on a continuity of interests basis which
recognizes the Trust as the successor entity to PRL's northeast Alberta
core area of operations given that the Trust acquired substantially all
of PRL's natural gas assets in that region. Certain of PRL's properties
in northeast Alberta were not acquired by the Trust and the results of
such properties have been excluded from these consolidated financial
statements. While the amounts applicable to PRL's northeast Alberta
properties for certain revenues, royalties, expenses, assets and
liabilities could be derived directly from the accounting records of
PRL, it was necessary to allocate certain other items between PRL's core
areas. In the opinion of management, the consolidated balance sheet and
statements of earnings include all adjustments necessary for the fair
presentation of the transactions in accordance with Canadian GAAP.

a) Principles of Consolidation The consolidated financial statements
include the accounts of the Trust and its subsidiaries, all of which are
wholly-owned.

b) Petroleum and Natural Gas Operations PET follows the successful
efforts method of accounting for petroleum and natural gas operations.
Under this method, PET capitalizes only those costs that result directly
in the discovery of petroleum and natural gas reserves. Exploration
expenses including geological and geophysical costs, lease rentals and
exploratory dry hole costs are charged to earnings as incurred.
Leasehold acquisition costs including costs of drilling and equipping
successful wells are capitalized. The net cost of unproductive wells,
abandoned wells and surrendered leases are charged to earnings in the
year of abandonment or surrender. Gains or losses are recognized on the
disposition of properties and equipment.

Depletion and depreciation of petroleum and natural gas properties
including well development expenditures, production equipment, gas
plants and gathering systems are provided on the unit-of-production
method based on estimated proven recoverable reserves of each producing
property or project. Depreciation of other equipment is provided on a
declining balance method at rates varying from 20 to 30 percent.

The net amount at which petroleum and natural gas costs on a property or
project are carried is subject to a cost-recovery test annually or as
economic events dictate. An impairment loss is recognized when the
carrying amount of the asset is greater than the sum of the expected
future cash flows (undiscounted and without interest charges). The
amount of the impairment loss is calculated as the difference between
the carrying amount and the discounted present value of estimated future
cash flows. The carrying values of capital assets including the costs of
acquiring proven and probable reserves are subject to uncertainty
associated with the quantity of oil and gas reserves, future production
rates, commodity prices and other factors.

Many of the exploration, development and production activities of the
Trust are conducted jointly with others. These financial statements
reflect only the Trust's proportionate interest in such activities.

The Trust's corporate assets are recorded at cost and are depreciated on
a straight line basis at rates ranging from 2.5 percent to 20 percent.

c) Asset Retirement Obligations The Trust 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 long-term liability,
with a corresponding increase in the carrying amount of the property,
plant and equipment. The liability amount is increased each reporting
period due to the passage of time and the amount of accretion is charged
to earnings in the period. Revisions to the estimated timing of cash
flows or to the original estimated undiscounted cost would also result
in an increase or decrease to the ARO. Actual costs incurred upon
settlement of the ARO are charged against the ARO to the extent of the
liability recorded. Any difference between the actual costs incurred
upon settlement of the ARO and the recorded liability is recognized as a
gain or loss in the Trust's earnings in the period in which the
settlement occurs.

d) Per Unit Information Per Unit amounts for all periods prior to March
31, 2003 have been presented on a pro forma basis as if the Trust Units
outstanding at March 31, 2003 were all outstanding for each period shown
(see Note 1). Basic earnings (loss) per Trust Unit were calculated using
the weighted average number of Trust Units outstanding during the year
(2004 - 54,187,525; 2003 - 42,597,280). PET uses the treasury stock
method where only "in the money" dilutive instruments impact the diluted
calculations. In computing diluted earnings (loss) per Unit nil net
Units were added to the weighted average number of Trust Units
outstanding during the year ended December 31, 2004 (2003 - 640,751 net
Units) for the dilutive effect of incentive rights.

e) Foreign Currency Translation Monetary assets and liabilities
denominated in a foreign currency are translated at the rate of exchange
in effect at year end while non-monetary assets and liabilities are
translated at historical rates of exchange. Revenues and expenses are
translated at monthly average rates of exchange. Translation gains and
losses are reflected in earnings in the period in which they arise.

f) Financial Instruments Financial instruments may be utilized by PET to
manage its exposure to commodity price fluctuations, foreign currency
and interest rates. PET's policy is not to utilize financial instruments
for trading or speculative purposes.

PET formally documents 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 balance sheet
or to specific firm commitments or forecasted transactions. PET also
formally assesses, both at the hedge's inception and on an ongoing
basis, whether the derivatives that are used in hedging transactions are
highly effective in offsetting changes in fair value or cash flows of
hedged items.

PET uses forward, futures and swap contracts to manage its exposure to
commodity price fluctuations. The net receipts or payments arising from
these contracts are recognized in earnings as a component of natural gas
revenue during the same period as the corresponding hedged position.

g) Income Taxes PET, and its principal operating entity POT, are taxable
entities under the Income Tax Act (Canada) and are taxable only on
income that is not distributed or distributable to the Unitholders. As
the Trust distributes all of its taxable income to the Unitholders
pursuant to the PET Trust Indenture and meets the requirements of the
Income Tax Act (Canada) applicable to the Trust, no provision for income
taxes has been made in these consolidated financial statements related
to the operations of the Trust. The Administrator has no tax balances.

PET's corporate subsidiaries follow the tax liability method of
accounting for income taxes. Under this method, income tax liabilities
and assets are recognized for the estimated tax consequences
attributable to differences between the amounts reported in the
financial statements and their respective tax bases, using enacted
income tax rates. The effect of a change in income tax rates on future
income tax liabilities and assets is recognized in income in the period
that the change occurs.

h) Unit Incentive Plan PET has a Unit Incentive Plan as described in
Note 9. Effective January 1, 2004, PET retroactively adopted the revised
Canadian accounting standard for incentive rights granted without
restatement of prior periods. These standards require the Trust to
record compensation expenses in the statement of earnings for incentive
rights granted after January 1, 2002.

Upon the exercise of the incentive rights, consideration received,
together with the amount previously recognized in contributed surplus,
is recorded as an increase to unitholders' capital. The effect of
adoption of the revised standard on the financial statements is
disclosed in Note 3.

Prior to January 1, 2004, no compensation cost was recorded for
incentive rights granted to employees and directors. PET previously
disclosed the pro forma effect of accounting for these awards under the
fair value based method.

i) Uncertainty The preparation of financial statements in conformity
with Canadian GAAP requires management to make estimates and assumptions
that affect the reported amounts of assets and liabilities at the date
of the financial statements and the reported amounts of revenues and
expenses during the reporting period.

The amounts recorded for depletion, depreciation and accretion are based
on estimates. The asset impairment test calculation is based on
estimates of reserves, production rates, oil and natural gas prices,
future costs and other relevant assumptions. By their nature, these
estimates are subject to measurement uncertainty and may impact the
consolidated financial statements of future periods.

j) Revenue Recognition Revenue associated with the sale of crude oil,
natural gas, and natural gas liquids owned by PET are recognized when
title passes from the Trust to its customers.

k) Goodwill Goodwill is recorded upon a corporate acquisition when the
total purchase price exceeds the net identifiable assets and liabilities
of the acquired company. The goodwill balance is not amortized but
instead is assessed for impairment annually or more frequently, if
necessary. Impairment is determined based on the fair value of the
reporting entity compared to the carrying value of the reporting entity.
Any impairment will be charged to earnings in the period in which the
fair value of the reporting entity is below the carrying value.

3. CHANGE IN ACCOUNTING POLICY

a) Trust Unit-based compensation

At January 1, 2004, PET retroactively adopted the revised Canadian
accounting standard for incentive rights granted without restatement of
prior periods. The effect of the change resulted in an increase to
contributed surplus and a corresponding decrease to accumulated earnings
of $2.7 million or $0.06 per Trust Unit. The related impact to 2004
results is $4.2 million or $0.06 per Trust Unit. A reconciliation of
contributed surplus resulting from adoption is provided below:



---------------------------------------------------------------------
Balance, as at January 1, 2004, as previously reported $ -
Adoption of change in accounting policy 2,740
---------------------------------------------------------------------
Balance, as at January 1, 2004, as restated 2,740
Trust Unit-based compensation expense 5,493
Transfer to share capital on exercise of incentive rights (1,304)
---------------------------------------------------------------------
Balance, as at December 31, 2004 $ 6,929
---------------------------------------------------------------------
---------------------------------------------------------------------


b) Transportation Costs

In accordance with new accounting standards, revenue is now reported
before deduction of transportation costs. Natural gas revenue and
transportation costs correspondingly increased by $9.8 million for the
year ended December 31, 2004 (2003 - $8.6 million) as a result of this
change. This change in classification has no impact on net earnings,
earnings per Trust Unit or working capital. The comparative figures have
been restated to conform to the presentation adopted for the current
period.

4. ACQUISITION AND DISPOSITIONS

On January 5, 2004 PET closed the acquisition of producing natural gas
properties in the Marten Hills area of northeast Alberta for $30.3
million. This acquisition was financed from existing credit facilities.

On July 16, 2004 PET acquired Cavell Energy Corporation ("Cavell") for
consideration of 6,931,633 Trust Units with an ascribed value of $78.7
million plus acquisition costs, net of stock option proceeds, of $8.0
million. Cavell was a public oil and gas exploration and production
company active in Western Canada. This transaction has been accounted
for using the purchase method with the allocation of the purchase price
as follows:



NET ASSETS ACQUIRED AND LIABILITIES ASSUMED
-------------------------------------------
($000's)
Property, plant and equipment $ 143,822
Land 13,000
Goodwill 29,698
Working capital deficiency (5,572)
Bank debt (28,729)
Asset retirement obligation (5,847)
Future income taxes (29,698)
----------
$ 116,674
----------
CONSIDERATION
-------------
Acquisition costs $ 8,000
Cash 30,000
Trust Units issued 78,674
---------
$ 116,674
----------


On August 17, 2004 PET closed the acquisition of producing petroleum and
natural gas properties and assets in northeast Alberta (the "Athabasca
Acquisition") for an aggregate purchase price of $208.3 million
effective, July 1, 2004. The acquisition was financed through the
issuance of 7,795,547 Trust Units for gross proceeds of $96,275,005, in
addition to the issuance of $48,000,000 in 8% convertible extendible
unsecured subordinated debentures ("Convertible Debentures") (see Note
7) and through existing credit facilities.

On August 24, 2004 PET concluded the sale of the oil producing
properties in southeast Saskatchewan acquired as part of the Cavell
acquisition for $32.75 million.

On September 30, 2004 PET closed the acquisition of producing petroleum
and natural gas properties in the Saleski area of northeast Alberta for
an aggregate purchase price of $20.0 million. The acquisition was
financed through existing credit facilities.

On February 10, 2005 PET closed the acquisition of producing natural gas
properties in the Trust's West Side Core Area of northeast Alberta for
$8.4 million. This acquisition was financed from existing credit
facilities.

5. PROPERTY, PLANT AND EQUIPMENT



December 31, 2004 December 31, 2003
---------------------------------------------------------------------
---------------------------------------------------------------------
Petroleum and Natural Gas
Properties $ 985,138 $ 571,216
Corporate Assets 14,754 3,585
999,892 574,801
Accumulated Depletion and
Depreciation (505,007) (332,846)
---------------------------------------------------------------------
$ 494,885 $ 241,955
---------------------------------------------------------------------
---------------------------------------------------------------------


Property, plant and equipment costs include undeveloped land of $72.5
million (2003 - $46.8 million) and $35.4 of costs related to shut-in gas
over bitumen reserves (Note 13) currently not subject to depletion.

Property, plant and equipment costs include $30.8 million (2003 - $20.5
million) related to estimated future asset retirement obligations.

At December 31, 2004 the Trust recorded a write-down to property, plant
and equipment in the amount of $65.4 million calculated primarily as a
result of prescribed successful efforts accounting tests related to the
Trust's Saskatchewan cost centre (2003 - $9.8 million related to gas
over bitumen issue (Note 13)).

Corporate assets include $10.5 million related to the acquisition of
PET's head-office building acquired from PRL in November 2004.

6. BANK AND OTHER DEBT

PET has a revolving credit facility with a syndicate of Canadian
chartered banks. As at the date of the audit report the revolving credit
facility had a borrowing base of $220 million. The facility consists of
a demand loan of $210 million and a working capital facility of $10
million. In addition to amounts outstanding under the facility, PET has
outstanding letters of credit in the amount of $2.85 million. Collateral
for the credit facility is provided by a floating-charge debenture
covering all existing and after acquired property of PET as well as
unconditional full liability guarantees from all subsidiaries in respect
of amounts borrowed under the facility.

Advances under the facility are made in the form of Banker's Acceptances
("BA"), prime rate loans or letters of credit. In the case of BA
advances, interest is a function of the BA rate plus a stamping fee
based on the Trust's current ratio of debt to cash flow. In the case of
prime rate loans, interest is charged at the Lenders' prime rate. The
average interest rate for 2004 was 3.78% (2003 - 4.46%).

7. CONVERTIBLE DEBENTURES

On August 10, 2004, PET issued $48 million of 8.0% Convertible
Debentures for net proceeds of $46.1 million. The Convertible Debentures
have a maturity date of September 30, 2009.

The Convertible Debentures bear interest at 8.0% per annum, paid
semi-annually on March 31 and September 30 of each year and are
subordinated to substantially all other liabilities of PET, including
its credit facility.

The Convertible Debentures are convertible at the option of the holder
into PET Trust Units at any time prior to September 30, 2009 at a
conversion price of $14.20 per Unit. The Convertible Debentures are not
redeemable by PET on or before September 30, 2007 but may be redeemed in
whole or in part at the option of PET at a price of $1,050 per
Convertible Debenture after September 30, 2007 and prior to September
30, 2008 at a price of $1,025 per Convertible Debenture thereafter until
their maturity. Redemption and conversions entitle the holder to accrued
and unpaid interest to and including the effective date.

At the option of PET, the repayment of the principal amount of the
Convertible Debentures may be settled in Trust Units. The number of
Trust Units to be issued upon redemption by PET will be calculated by
dividing the principal by 95% of the weighted average trading price. The
interest payable may also be settled with the issuance and sale of
sufficient Trust Units to satisfy the interest obligation. At December
31, 2004, the fair market value of the outstanding Convertible
Debentures was $43.9 million.

8. UNITHOLDERS' CAPITAL

a) Authorized

Authorized capital consists of an unlimited number of Trust Units and an
unlimited number of special voting units. No Special Voting Units have
been issued to date.

b) Issued and Outstanding

The following is a summary of changes in unitholders' capital during the
year ended December 31, 2004:



Number
Trust Units Of Units Amount
---------------------------------------------------------------------
---------------------------------------------------------------------
Balance, December 31, 2002 1 $ 100
Units Issued on Settlement of
Promissory Note (Note 1) 6,636,045 34,152,000
Units Issued on Settlement of
Promissory Note (Note 1) 3,273,721 16,848,000
Units Cancelled after Declaration
of Dividend by PRL (173) (874)
Units Issued Pursuant to Rights
Offering (Note 1) 29,728,782 150,130,349
Units Issued Pursuant to Unit Offering 5,000,000 63,250,000
Trust Unit Issue Costs - (4,360,834)
---------------------------------------------------------------------
Balance, December 31, 2003 44,638,376 260,018,741
Units Issued Pursuant to Unit Offerings 12,295,547 146,675,005
Units Issued Pursuant to Corporate
Acquisition (Note 4) 6,931,633 78,674,035
Units Issued Pursuant to Unit
Incentive Plan 153,875 1,868,864
Units Issued Pursuant to Distribution
Reinvestment Plan 632,829 8,184,906
Units Issued Pursuant to Conversion
of Debentures 674,711 9,580,889
Issue Costs on Convertible Debentures
Converted to Trust Units - (383,240)
Trust Unit Issue Costs - (8,427,210)
---------------------------------------------------------------------
Balance, December 31, 2004 65,326,971 $ 496,191,990
---------------------------------------------------------------------
---------------------------------------------------------------------


Redemption Right

Unitholders may redeem their Trust Units at any time by delivering their
Unit Certificates to the Trustee, together with a properly completed
notice requesting redemption. The redemption amount per Trust Unit will
be the lesser of 90 percent of the weighted average trading price of the
Trust Units on the principal market on which they are traded for the 10
day period after the Trust Units have been validly tendered for
redemption and the "closing market price" of the Trust Units. The
redemption amount will be payable on the last day of the following
calendar month. The "closing market price" will be the closing price of
the Trust Units on the principal market on which they are traded on the
date on which they were validly tendered for redemption, or, if there
was no trade of the Trust Units on that date, the average of the last
bid and ask prices of the Trust Units on that date.

9. UNIT INCENTIVE PLAN

PET has adopted a Unit Incentive Plan which permits the Administrator's
Board of Directors to grant non-transferable rights to purchase Trust
Units ("Incentive Rights") to its and affiliated entities' employees,
officers, directors and other service providers. The purpose of the Unit
Incentive Plan is to provide an effective long-term incentive to
eligible participants and to reward them on the basis of PET's long-term
performance and distributions. The Administrator's Board of Directors
will administer the Unit Incentive Plan and determine participants,
numbers of Incentive Rights and terms of vesting. The grant price of the
Incentive Rights ("Grant Price") shall equal the per Trust Unit closing
price on the trading date immediately preceding the date of the grant,
unless otherwise permitted. The strike price of the Incentive Rights
("Strike Price"), shall be reduced by deducting from the Grant Price the
aggregate amounts of all distributions on a per Trust Unit basis that
PET pays its Unitholders after the date of grant which represent a
return of more than 2.5 percent per quarter on PET's consolidated net
fixed assets on its balance sheet at each calendar quarter end.

The Strike Price will be adjusted on a quarterly basis and in no case
may it be reduced to less than $0.001 per Trust Unit.

At December 31, 2004 PET had granted 1,612,750 (2003 - 1,145,500)
Incentive Rights to purchase PET Trust Units to directors, officers and
employees of the Administrator under its Unit Incentive Plan.

The Incentive Rights are only dilutive to the calculation of earnings
per Trust Unit if the exercise price is below the fair value of the Unit.

At December 31, 2004 a total of 3,963,838 (2003 - 3,963,838) Units had
been reserved under the Unit Incentive Plan. As at December 31, 2004
123,500 Incentive Rights granted under the Unit Incentive Plan had
vested but were unexercised, nil as of December 31, 2003.



Incentive Rights Average Incentive
grant price Rights
---------------------------------------------------------------------
Balance, December 31, 2002 - -
Granted $ 6.04 1,145,500
Exercised - -
Cancelled - -
---------------------------------------------------------------------
Balance, December 31, 2003 $ 6.04 1,145,500
Granted $ 12.06 621,125
Exercised $ 5.55 (153,875)
Cancelled - -
---------------------------------------------------------------------
Balance, December 31, 2004 $ 8.41 1,612,750
---------------------------------------------------------------------
Incentive Rights exercisable,
December 31, 2004 $ 6.21 123,500
---------------------------------------------------------------------
---------------------------------------------------------------------


The following summarizes information about Incentive Rights outstanding
at December 31, 2004 assuming the reduced Strike Price described above:



Weighted
average Weighted Weighted
Number con- average Number average
Range of outstanding tractual exercise exercisable exercise
Exercise at December life price/ at December price/
Prices 31, 2004 (years) Right 31, 2004 Right
---------------------------------------------------------------------
---------------------------------------------------------------------
$1.51 824,125 4 $ 1.51 100,000 $ 1.51
$9.31-$9.43 167,500 5 $ 9.37 23,500 $ 9.37
$10.12-$15.09 621,125 5 $ 11.38 - -
---------------------------------------------------------------------
Total 1,612,750 4 $ 8.41 123,500 $ 6.21
---------------------------------------------------------------------
---------------------------------------------------------------------


10. ASSET RETIREMENT OBLIGATIONS

The total future asset retirement obligation was estimated based on
PET's net ownership interest in all wells and facilities, estimated
costs to reclaim and abandon the wells and facilities and the estimated
timing of the costs to be incurred in future periods. PET has estimated
the net present value of its total asset retirement obligations to be
$34.1 million as at December 31, 2004 based on an undiscounted total
future liability of $68.2 million. These payments are expected to be
made over the next 25 years with the majority of costs incurred between
2010 and 2015. PET used a credit adjusted risk free rate of 7.83% to
calculate the present value of the asset retirement obligation.

The following table reconciles PET's asset retirement obligations:



2004 2003
---------------------------------------------------------------------
---------------------------------------------------------------------
Obligation, beginning of year $ 21,701 $ 20,039
Increase in obligation during the year 10,325 423
Expenditures incurred during the year - -
Accretion expense 2,090 1,239
---------------------------------------------------------------------
Obligation, end of year $ 34,116 $ 21,701
---------------------------------------------------------------------
---------------------------------------------------------------------


11. FINANCIAL INSTRUMENTS

PET's financial instruments included in the Consolidated Balance Sheet
consist of accounts receivable, accounts payable and accrued
liabilities, distributions payable and bank and other debt. The fair
value of these items approximated their carrying amount at December 31,
2004 and 2003 due to their short-term nature.

Natural gas commodity price hedges

At December 31, 2004, PET had entered into financial forward sales
arrangements summarized as follows:



Volumes at AECO
---------------------------------------------------------------------
(Gigajoules/day)("GJ/d") Price ($/GJ) Term
---------------------------------------------------------------------
---------------------------------------------------------------------
35,000 GJ/d $ 7.38 November 2004 - March 2005
---------------------------------------------------------------------
5,000 GJ/d $ 6.60 to 8.35 November 2004 - March 2005
---------------------------------------------------------------------
10,000 GJ/d $ 6.75 to 8.50 November 2004 - March 2005
---------------------------------------------------------------------
5,000 GJ/d $ 6.75 to 10.60 November 2004 - March 2005
---------------------------------------------------------------------
10,000 GJ/d $ 6.81 April 2005 - June 2005
---------------------------------------------------------------------
5,000 GJ/d $ 6.95 April 2005 - October 2005
---------------------------------------------------------------------
5,000 GJ/d $ 6.50 to 7.30 April 2005 - October 2005
---------------------------------------------------------------------
---------------------------------------------------------------------


Had these contracts been settled on December 31, 2004 using prices in
effect at that time, the mark-to-market gain would have totaled $4.3
million.

12. INCOME TAXES

The Trust recognized a future income tax liability of $29.7 million in
2004 related to the acquisition of Cavell.

The provision for income taxes in the financial statements differs from
the result that would have been obtained by applying the combined
federal and provincial tax rate to PET's earnings before income taxes.
This difference results from the following items:



2004 2003
---------------------------------------------------------------------
---------------------------------------------------------------------
Earnings (loss) before income taxes $ (47,421) $ 52,434
Less non-taxable earnings of the Trust (25,291) (52,434)
---------------------------------------------------------------------
Taxable earnings (loss) (72,712) -
Combined federal and provincial tax rate 40.43%
Computed income tax reduction (29,398) -
Increase (decrease) in income taxes
resulting from:
Non-deductible Crown charges 587 -
Resource allowance (748) -
Capital taxes 852
Change in tax rate 1,949 -
---------------------------------------------------------------------
Future income tax expense (reduction) $ (26,758) $ -
---------------------------------------------------------------------
---------------------------------------------------------------------


The components of the Trust's subsidiaries' future income tax liability
at December 31 are as follows:



2004 2003
---------------------------------------------------------------------
Future income taxes:
Oil and natural gas properties $ 11,865 $ -
Asset retirement obligations (1,450) -
Non-capital losses (8,048) -
Other (279) -
---------------------------------------------------------------------
$ 2,088 $ -
---------------------------------------------------------------------
---------------------------------------------------------------------


13. GAS OVER BITUMEN ISSUE

The Alberta Energy and Utilities Board ("AEUB" or the "Board") issued
General Bulletin 2003-28 ("GB 2003-28") on July 22, 2003. The AEUB
continues to consider that gas production in pressure communication with
associated potentially recoverable bitumen places future bitumen
recovery at an unacceptable risk.

Following the completion of a Regional Geological Study by the AEUB and
an interim hearing held in March 2004, the AEUB ordered the shut-in,
effective July 1, 2004, of Wabiskaw-McMurray natural gas production in
northeast Alberta totaling approximately 123 MMcf/d. As of July 1, 2004,
PET had shut-in wells producing approximately 17.2 MMcf/d pursuant to
Decision 2004-045 and Interim Shut-In Orders 04-001 and 04-002 including
4.5 MMcf/d from the zones shut-in on September 1, 2003 pursuant to the
GB 2003-28 and Interim Shut-In Order 03-001. An additional 0.2 MMcf/d
was shut-in September 1, 2004 pursuant to Decision 2004-064 and Interim
Shut-in Order 04-003 related to wells in the Chard and Leismer areas. In
2004, the Trust incurred $1.2 million in legal and consulting
expenditures directly related to the gas over bitumen issue ($10.7
million in 2003).

On October 4, 2004 the Government of Alberta enacted amendments to the
Natural Gas Royalty Regulation with respect to natural gas which provide
a mechanism whereby the Government may prescribe a reduction in the
royalty calculated through the Crown royalty system for operators of gas
wells which have been denied the right to produce by the AEUB as a
result of recent bitumen conservation decisions. Such royalty reduction
was prescribed in December 2004, retroactive to the date of shut-in of
the gas production.

If production recommences from zones previously ordered to be shut-in,
gas producers may pay an incremental royalty to the Crown on production
from the reinstated pools, along with Alberta Gas Crown Royalties
otherwise payable. The incremental royalty will apply only to the pool
or pools reinstated to production and will be established at 1% after
the first year of shut-in increasing at 1% per annum based on the period
of time such zones remained shut-in to a maximum of 10%. The incremental
royalties payable to the Crown would be limited to amounts recovered by
a gas well operator through the reduced royalty.

At December 31, 2004 PET had recorded $11.2 million for cumulative gas
over bitumen royalty adjustments received to that date on the Trust's
balance sheet. Royalty adjustments received are not included in earnings
but are recorded as a component of funds from operations. As PET cannot
determine if, when or to what extent the royalty adjustments may be
repayable through incremental royalties if and when gas production
recommences, the royalty adjustments are being excluded from earnings
pending such determination.

-30-

Contact Information

  • FOR FURTHER INFORMATION PLEASE CONTACT:
    Paramount Energy Trust
    Susan L. Riddell Rose
    President and Chief Operating Officer
    (403) 269-4400
    or
    Paramount Energy Trust
    Cameron R. Sebastian
    Vice President, Finance and CFO
    (403) 269-4400
    or
    Paramount Energy Trust
    Sue M. Showers
    Investor Relations and Communications Advisor
    (403) 269-4400
    (403) 269-6336 (FAX)
    info@paramountenergy.com
    or
    Paramount Energy Operating Corp.,
    Administrator of Paramount Energy Trust
    Suite 500, 630 - 4 Avenue SW
    Calgary, Alberta, Canada T2P 0J9
    The Toronto Stock Exchange has neither approved nor disapproved the
    information contained herein.