Paramount Energy Trust
TSX : PMT.DB
TSX : PMT.UN
TSX : PMT.DB.A

Paramount Energy Trust

November 10, 2005 05:30 ET

Paramount Energy Trust Releases Third Quarter 2005 Financial and Operating Results

CALGARY, ALBERTA--(CCNMatthews - Nov. 10, 2005) - Paramount Energy Trust ("PET" or the "Trust") (TSX:PMT.UN)(TSX:PMT.DB)(TSX:PMT.DB.A) is pleased to release its results for the third quarter of 2005. Record production, continued strong commodity prices, and the full effect of acquisition activities contributed to another quarter of exceptional financial results. As a result of the above factors, cash flow from operations increased 139 percent to $74.7 million for the three months ended September 30, 2005 from $31.3 million in the 2004 period. Stable production performance from the Trust's assets and continued strength in natural gas prices enabled PET to increase its monthly distribution to $0.24 per Trust Unit per month, effective with the September distribution paid on October 17, 2005. The Trust estimates that the current distribution level is sustainable for the foreseeable future given PET's current hedges and physical forward natural gas sales, the forward market for natural gas prices and the Trust's opportunity inventory for production additions to offset natural production declines from PET's base assets.

THIRD QUARTER HIGHLIGHTS

- Production averaged 159.4 MMcf/d, representing an increase of 52 percent from the third quarter of 2004. Including the deemed production volume related to the gas over bitumen financial solution, average daily production (actual and deemed) increased 42 percent to 180.9 MMcf/d from 127.5 MMcf/d in the third quarter of 2004. The significant production increase is a result of several factors:

1. The effect of the previously-announced Northeast Alberta Acquisition which is fully reflected in the 2005 third quarter results;

2. The acquisitions of Cavell Energy Corporation ("Cavell") and certain assets in the Athabasca area of Northeast Alberta (the "Athabasca Assets") in 2004, which were only partially reflected in the results for the third quarter of 2004; and

3. The positive results from PET's 2005 capital program to date, largely completed in the first quarter of 2005.

PET's current actual daily production is approximately 156 MMcf/d excluding the gas over bitumen deemed production volume which is now approximately 22 MMcf/d, for a total current actual and deemed production of 178 MMcf/d.

- On September 21, 2005 the Trust announced that distributions would be increased by 9 percent to $0.24 per Trust Unit per month, beginning with the September distribution paid on October 17, 2005. Total distributions for the quarter were $0.68 per Trust Unit or $54.1 million. PET's distributions as a percentage of cash flow were 72.4 percent, which is consistent with the Trust's earlier guidance. With the Trust's current estimates for production, natural gas prices and cash flow, the payout ratio for 2006 is expected to continue to be approximately 70 percent.

- During the quarter, $21.1 million of PET's outstanding 8% Convertible Debentures and $23.5 million of PET's outstanding 6.25% Convertible Debentures were converted into a total of 2.7 million Trust Units. PET committed an additional $48.4 million of net cash flow to bank debt reduction during the quarter, resulting in total net debt outstanding of $270.0 million at September 30, 2005, including the $87.5 million of convertible debentures outstanding, as compared to $356.6 million at June 30, 2005. The Trust's ratio of net debt to annualized third quarter cash flow measured 0.9 times as at September 30, 2005.

- On September 8, 2005 Canada's Federal Department of Finance issued a consultation paper entitled "Tax and Other Issues Related to Publicly Listed Flow-Through Entities", inviting interested parties to make a submission to the Finance Department regarding income and royalty trusts by December 31, 2005. PET will be highly involved in this very important federal government consultation process through a number of initiatives. We strongly encourage all of our Unitholders to make some form of contact with the Canadian federal government as soon as possible to ensure that their perspective is factored in to any decisions the Department of Finance will make on this issue.

Conference Call and Webcast

PET will be hosting a conference call and webcast at 9:30 a.m., Calgary time, Thursday November 10, 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 - 416 406-6419; outside Toronto - 1 888 575-8232. 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.

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.

About PET

Paramount Energy Trust is a natural gas-focused Canadian energy trust. PET's Trust Units are listed on the Toronto Stock Exchange ("TSX") under the symbol "PMT.UN". In addition, the Trust has two debenture listings on the TSX; "PMT.DB" which have a coupon rate of 8.0% and "PMT.DB.A" with a coupon rate of 6.25%. Further information with respect to PET can be found at its website at www.paramountenergy.com.



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FINANCIAL AND OPERATING HIGHLIGHTS

Three Months Ended Nine Months Ended
September 30 September 30
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($CDN thousands,
except volume and
per Trust Unit % %
amounts) 2005 2004(3) Change 2005 2004(3) Change
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FINANCIAL
Revenue before
royalties 118,928 59,156 101 295,508 160,292 84
Cash flow(1) 74,726 31,301 139 182,018 87,070 109
Per Trust Unit(2) 0.95 0.52 83 2.50 1.72 45
Net earnings(3) 30,432 4,781 537 43,942 11,794 273
Per Trust Unit(2) 0.39 0.08 388 0.60 0.23 161
Distributions 54,138 35,925 51 146,042 82,179 78
Per Trust Unit(4) 0.68 0.58 17 2.00 1.58 27
Payout
ratio (%)(1)(7) 72.4% 114.8% (37) 80.2% 94.3% (15)
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Total assets 814,203 604,588 35 814,203 604,588 35
Net bank and
other debt
outstanding(5) 182,518 167,021 9 182,518 167,021 9
Convertible
debentures 87,486 45,251 93 87,486 45,251 93
Total net debt(5) 270,004 212,272 27 270,004 212,272 27
Unitholders'
equity 404,686 322,559 25 404,686 322,559 25
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Capital
expenditures
Exploration and
development 3,882 1,476 163 48,494 14,992 223
Acquisitions, net
of dispositions (4,004) 261,141 (101) 279,583 294,095 (5)
Other 264 36 633 549 51 976
Net capital
expenditures 142 262,668 (100) 328,626 309,138 6
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TRUST UNITS
OUTSTANDING
(thousands)
End of period 80,794 64,567 25 80,794 64,567 25
Weighted average 78,762 59,738 32 72,764 50,530 44
Incentive Rights
outstanding 1,625 1,566 4 1,625 1,566 4
Trust Units
outstanding at
November 3, 2005 81,346 - 81,346 -
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OPERATING
Production
Total natural
gas (Bcf) 14.7 9.6 53 39.2 25.8 52
Daily average
natural gas
(MMcf/d) 159.4 104.8 52 143.4 94.0 53
Gas over
bitumen deemed
production
(MMcf/d)(6) 21.5 22.7 (5) 22.7 14.2 60
Average daily
(actual and
deemed -
MMcf/d)(6) 180.9 127.5 42 166.1 108.2 54
Per Trust Unit
(cubic feet/d/
Unit)(2) 2.30 2.13 8 2.28 2.14 7
Average prices
Natural gas
($/Mcf),
pre-hedging 8.29 6.29 32 7.61 6.43 18
Natural gas
($/Mcf),
including
hedging 8.11 6.14 32 7.55 6.22 21
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LAND (thousands
of net acres)
Undeveloped land
holdings 1,084 791 37 1,084 791 37
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DRILLING
Wells drilled
(gross/net)
Gas 36/15.5 10/10.0 260/55 87/46.5 23/22.7 278/105
Dry - - - 4/4.0 - -
Total 36/15.5 10/10.0 260/55 91/50.5 23/22.7 296/122
Success rate
(% gross/% net) 100/100 100/100 - 96/92 100/100 4/8
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(1) These are non-GAAP measures; please refer to "Significant
Accounting Policies and Non-GAAP Measures" included in
management's discussion and analysis.
(2) Based on weighted average Trust Units outstanding for the period.
(3) Net earnings for 2004 have been restated to reflect the
retroactive effect of a change in accounting policy related to
Trust Unit-based compensation.
(4) Based on Trust Units outstanding at each distribution date.
(5) Net debt includes net working capital (deficiency). Total net
debt includes convertible debentures.
(6) The deemed production volume describes 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. This deemed production volume is
not actual gas sales but represents shut-in gas that is the basis
of the gas over bitumen financial solution which is received
monthly from the Alberta Crown as a reduction against other
royalties payable.
(7) The payout ratio in 2004 reflects the payout of cash flow in the
third quarter of 2004 related to the assets acquired as part of
the Cavell and the Athabasca Assets Acquisitions, although the
net cash flow from these assets was not recorded as cash flow to
PET but rather dealt with as an adjustment to the purchase price
at closing of the transactions on July 16 and August 18, 2004
respectively.


CORPORATE

In the third quarter of 2005 PET continued to enhance the sustainability of its business model. A low-risk $15 million shallow gas development program initiated in the second quarter, combined with natural gas price risk management, have allowed the Trust to further mitigate natural production declines and provide cash flow stability while distributing a portion of its capital expenditures program outside PET's winter-access only operating areas. As a result of these initiatives and continued strong natural gas prices, the Trust increased distributions by nine percent to $0.24 per Trust Unit per month beginning with the September 2005 distribution which was paid on October 17, 2005.

Strong participation in PET's industry-leading Distribution Reinvestment and Optional Trust Unit Purchase Plan ("DRIP") including the enrollment of the Trust's major Unitholder, resulted in a significant contribution of cost-effective equity capital during the third quarter, and continues to reflect the alignment between the Trust and its Unitholders and overall confidence in the value of PET's Trust Units. Through the DRIP a total of $20.6 million was invested into the Trust by existing Unitholders in the third quarter.

The sustainability of the Trust's distributions is a function of its ability to offset base production declines with efficient capital spending on development and low exposure exploration activities on the Trust's asset base. Sustainability occurs when total distributions plus capital spending are equal to or less than cash flow from operations while maintaining base production levels, excluding acquisitions, and assuming constant commodity prices.

The pillars to the long-term sustainability of PET's business model are:

- A predictable production base;

- A low operating cost structure;

- An opportunity inventory for cost-effective production additions; and

- Undeveloped land to feed the prospect inventory.

PET's asset base is 100 percent shallow natural gas. Long production histories, well understood geological play types and a lack of exposure to single production entities which are statistically material provide confidence in the extrapolation of future production estimates. High working interest and operatorship allow for control of the operating cost structure. Shallow gas opportunities are characterized by relatively low cost drilling and completion operations resulting in high deliverability which translate into low cost production additions. Historically, PET has been able to add production for less than $3.0 million per MMcf/d (or $18,000 per flowing BOE) and expects to continue to do so for the foreseeable future given its extensive inventory of development and low exposure exploration opportunities and the Trust's undeveloped land base.

Federal Government Consultation Process on Trusts

On September 8, 2005 Canada's Federal Department of Finance issued a consultation paper entitled "Tax and Other Issues Related to Publicly Listed Flow-Through Entities" (the "Consultation Paper"), inviting interested parties to make a submission to the Finance Department by December 31, 2005 regarding flow-through entities which, as defined, include income and royalty trusts. PET will be making a submission through this consultation process in the very near future regarding the positive impact that cash distributions have had on our investors and the direct and indirect benefits that the Trust structure has had on the Canadian economy. Further, PET as a member of the Canadian Association of Income Funds ("CAIF"), is supporting technical analysis regarding the effect of the trust structure on the Canadian tax system.

The consultation process is an opportunity for all stakeholders to communicate specific perspectives to the Department of Finance in order to help shape policy which is in the best interest of Canadians. Our hope is that the review will be balanced, particularly considering the $170 billion commitment, largely by individual Canadians, to this sector over the past decade. The release of the Consultation Paper and the announcement by the Federal Government of its intention to study tax and other related issues with respect to flow-through entities ("FTE's") has already created significant uncertainty in the capital markets. This ambiguity has translated into erosion of market valuations of income trusts, including PET's, affecting trust investors and the Canadian economy. PET believes that the government must be accountable and conduct the consultation process in an open, inclusive and transparent fashion so as to gain the required insights from all stakeholders to make decisions which are best for Canadians.

Income trusts comprise a significant portion of the public issuers in Canada and offer investors a tax effective form of income. Since PET's spin out from Paramount Resources Ltd. as a dividend-in-kind and the initial follow on Rights Offering in February 2003, the Trust has provided Unitholders who subscribed to the Rights Offering with 310 percent capital appreciation in the Unit price and an additional 137 percent return in the form of distributions of $7.06 per Unit. Significant tax revenues have been generated as PET's Unitholders pay tax both on the distributions and as capital gains are crystallized.

PET has raised over $735 million of equity in the capital markets which now has a market valuation of almost $2.0 billion, representing either current or deferred potential capital gains tax revenue for governments. This would not have been possible without the royalty trust structure. Canadian individual savers and investors as well as governments have been winners as PET continues to make substantial contributions to the Canadian economy. Ongoing access to capital is critical to PET's growth strategy, including capital invested by both Canadian and foreign sources. Canadian capital markets represent only 2% of the world's invested capital, while the US market represents approximately 40 percent of global invested capital, and ongoing efficient access to this large capital base is beneficial to Canadians through added capital values, improved liquidity and an overall lower cost of capital. The cost of attracting this capital and its outright availability are highly sensitive to fiscal policy, including taxation levels. Equitable access to capital markets is imperative for all parties. Therefore, it is critical that the tax system be efficient, effective and neutral for making appropriate investment decisions.

Further PET has reinvested close to $800 million in building its business, funding both acquisitions and low risk exploration and development activities on the Trust's expanding asset base to an extent greater than that pursued by the previous owners. Had the assets which are currently held by the Trust remained in their original corporations, capital spending levels on the assets would have been a small fraction of the capital spending pursued in the trust structure, as the corporate entities evaluated and prioritized investment in the context of their myriad of opportunities. In many cases additional development on these properties may not even otherwise have been pursued. PET has thereby increased the supply of natural gas production and reserves to North America. PET's remaining free cash flow is available for distribution to investors who either currently or ultimately will pay tax at a generally higher personal rate than do corporations. In our close to three year history, PET has put over $400 million into the hands of investors in the form of cash distributions of which 74 percent or almost $300 million was deemed a return on capital and taxable. After taxation in the hands of our Unitholders, much of the distributions have undoubtedly been reinvested back into the economy either in the form of additional investment or spending.

PET believes that significant changes to fiscal policy are ill-suited to a progressive economy where investment decisions are made with confidence under established guidelines and are expected to be respected. Regulatory certainty is critical to continuation of Canada's positive investment climate. Taxation is an extremely important public policy tool. We urge the federal government to ensure clarity, expediency and equity in reviewing taxation issues and maintain the status quo for Trusts and their investors.

We would encourage all Unitholders or potential investors to make some form of contact with the Canadian government as soon as possible to ensure their perspective is heard in this extremely important call for input. The following information will assist you in obtaining the information you may need to formulate your opinions and voice your concerns directly:



FTE White Paper: http://www.fin.gc.ca/toce/2005/toirplf_e.html

For written submissions by e-mail to: trusts-fiducies@fin.gc.ca;

Direct contact with the Minister of Finance:
The Honourable Ralph Goodale
Department of Finance Canada
140 O'Connor Street
Ottawa, Ontario K1A 0A6
Phone: 613-996-4743 / Fax: 613-996-9790
E-Mail: goodale.R@parl.gc.ca;

Contact your Member of Parliament:
www.canada.gc.ca/directories/direct_e.html


PET will also continue to provide additional information on its website to assist Unitholders in their efforts to participate in this very important consultation process.

OPERATIONS

Actual natural gas production for the third quarter of 2005 averaged 159.4 MMcf/d, a 7 percent increase from the second quarter of 2005, primarily due to a full quarter of production from the Northeast Alberta Acquisition. Factoring in the deemed production volume related to the gas over bitumen financial solution, daily production (actual and deemed) averaged 180.9 MMcf/d in the third quarter of 2005 versus 171.6 MMcf/d for the second quarter of 2005.

CAPITAL EXPENDITURES

Exploration and Development

Exploration and development expenditures totaled approximately $3.9 million in the third quarter with the continuation of the year round access capital program, estimated at $15 million over the final three quarters of 2005. This program is concentrated in the Trust's Southern Core Area in southwest Saskatchewan and southern Alberta as well as in the Trust's East Side Core Area at Cold Lake and Craigend. During the quarter the Trust drilled 10 wells (10.0 net) for Milk River production at Abbey, Saskatchewan, all of which are tied in and producing, and participated in 22 wells (3.5 net) as part of its non-operated coal bed methane project at Craigmyle which is scheduled to commence full-scale production prior to year end.

2006 Capital Program

Extensive technical evaluation and planning are underway for the upcoming winter capital program, scheduled to begin once cold weather conditions persist, allowing access to the Trust's winter-only access properties. The Board of Directors of the Trust has unanimously approved a $100 million capital expenditure program for 2006, the majority of which will be spent prior to the end of the first quarter, targeting production additions of 30 to 35 MMcf/d. This is expected to offset the Trust's natural production declines. PET has secured the necessary drilling rigs, service rigs, facilities, construction equipment and crews to execute this program in the short winter time frame. These are conditions that PET has grown accustomed to working under as a result of the winter-only access nature of its properties in northeast Alberta.

GAS OVER BITUMEN ISSUE

On October 4, 2004 the Government of Alberta enacted amendments to the 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 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. In July 2005, further amendments were enacted to the Royalty Regulation with respect to natural gas, implementing a positive correction to the royalty calculation formula to provide a $0.05 per Mcf reduction in the effective operating costs adjustment. This effectively increases the net royalty adjustment by $0.025 per Mcf of deemed production and is retroactive to the date of shut-in. The revised 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 - $0.3791/GJ))

The Trust's net deemed production volume for purposes of the royalty adjustment in the third quarter was 21.5 MMcf/d. In accordance with IL 2004-36, the deemed production volume related to wells shut-in is reduced by 10 percent at the end of every year of shut-in. PET's current deemed production is approximately 21.5 MMcf/d.

During the three months ended September 30, 2005, the Trust received $5.7 million in gas over bitumen royalty adjustments which have been recorded on its balance sheet rather than reported as income 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. This brings cumulative royalty adjustments received to September 30, 2005 to $32.0 million. Royalty adjustments, although not included in earnings, are recorded as a component of funds from operations and as such are considered distributable income.

The Phase 3 Final Hearing with respect to the AEUB's bitumen conservation requirements commenced on June 14, 2005 and ended on August 12, 2005. PET, an active participant in the hearing, filed detailed evidence supporting the resumption of production from six gas pools representing approximately 8.5 MMcf/d of 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. PET believes that there will be very little incremental gas ordered shut-in as a result of this final proceeding, and that any changes in productive status resulting from the hearing should result in increased gas production for the Trust. PET anticipates that the AEUB will render its final decision on the Phase 3 proceeding in November 2005.

OUTLOOK

PET projects that monthly cash distributions are sustainable at $0.24 per Trust Unit for the foreseeable future, based upon the Trust's current hedges, physical forward natural gas sales, the forward market for natural gas prices and the Trust's opportunity inventory for production additions to offset natural declines from PET's base assets. With the Trust's current estimates for exploration and development capital expenditures, production, natural gas prices and cash flow, this level of distribution reflects a payout ratio for 2006 of approximately 70 percent of PET's estimated cash flow. Future distributions are subject to change as dictated by changes in commodity price markets, operations and future business development opportunities.

The Trust currently has the following financial hedges in place:



Volumes at AECO
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Price
(Gigajoules/day)("GJ/d") ($/GJ) Term
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55,000 GJ/d $ 8.19 November 2005 - March 2006
20,000 GJ/d $ 8.01 April 2006 - October 2006
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In addition, the Trust has sold forward physical natural gas as
described below to partially fix the price that these financial
hedges will settle against.

Volumes at AECO
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Price
(Gigajoules/day)("GJ/d") ($/GJ) Term
---------------------------------------------------------------------
75,000 GJ/d $ 8.62 November 2005 - March 2006
25,000 GJ/d $ 8.03 April 2006 - October 2006
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Sensitivity Analysis

The Trust's current hedging and physical forward sales portfolio has significantly reduced PET's exposure to the downside in natural gas prices. The following table reflects PET's projected realized gas price, monthly cash flow and payout ratio at the current monthly distribution of $0.24 per Trust Unit, and at certain AECO gas price levels, assuming PET's projected average production of 152 MMcf/d for the fourth quarter of 2005 and incorporating all of the Trust's current financial hedges and physical forward sales contracts.



Natural Gas Prices
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AECO Monthly Index ($/GJ) 8.00 9.00 10.00 11.00 12.00
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PET realized ($/Mcf) 8.85 9.00 9.06 9.28 9.47
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Monthly cash flow ($MM) 26.9 27.0 27.2 27.6 27.7
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Cash flow per Unit ($/Unit/month) 0.331 0.333 0.336 0.340 0.342
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Payout ratio (%) 72.5 72.1 71.5 70.5 70.3
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MANAGEMENT'S DISCUSSION AND ANALYSIS

The following is management's discussion and analysis ("MD&A") of PET's operating and financial results for the three and nine months ended September 30, 2005 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 consolidated financial statements and accompanying notes for the three and nine months ended September 30, 2005 and 2004, as well as the Trust's consolidated financial statements and accompanying notes and MD&A for the years ended December 31, 2004 and 2003. The date of this MD&A is November 8, 2005.

This MD&A contains forward-looking statements within the meaning of applicable securities laws. Forward-looking statements include estimates, plans, expectations, opinions, forecasts, projections, guidance or other statements that are not statements of fact. The forward-looking statements in the MD&A include statements with respect to, among other things, the Trust's business strategy, the Trust's intent to control marketing and transportation activities, reserve estimates, production estimates, hedging policies, asset retirement costs, the size of available tax pools, the Trust's credit facility, the funding sources for the Trust's capital expenditure program, cash flow estimates, environmental risks faced by the Trust's compliance with environmental regulations, commodity prices and the impact of the adoption of various Canadian Institute of Chartered Accountants Handbook sections and accounting guidelines.

Although PET believes that the expectations reflected in such forward-looking statements are reasonable, undue reliance should not be placed on them because the Trust can give no assurance that such expectations will prove to have been correct. There are many factors that could cause forward-looking statements to be incorrect including known and unknown risks and uncertainties inherent in the Trust's business. These risks include, but are not limited to: natural gas price volatility, exchange rate and interest rate fluctuations, availability of services and supplies, market competition, uncertainties in the estimates of reserves, the timing of development expenditures, production levels and the timing of achieving such levels, the Trust's ability to replace and expand oil and gas reserves, the sources and adequacy of funding for capital investments, future growth prospects and current and expected financial requirements of the Trust, the cost of future asset retirement obligations, the Trust's ability to enter into or renew leases, the Trust's ability to secure adequate production transportation, changes in environmental and other regulations, the Trust's ability to extend its debt on an ongoing basis, and general economic conditions. The Trust's forward-looking statements are expressly qualified in their entirety by this cautionary statement. We undertake no obligation to update our forward-looking statements except as required by law.



HIGHLIGHTS

Three Months Ended Nine Months Ended
September 30 September 30
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($Cdn millions, except
per Unit and volume data) 2005 2004 2005 2004
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Cash flow(1) $ 74.7 $ 31.3 $ 182.0 $ 87.1
Cash flow per Unit $ 0.95 $ 0.52 $ 2.50 $ 1.72
Net earnings $ 30.4 $ 4.8 $ 43.9 $ 11.8
Net earnings per Unit $ 0.39 $ 0.08 $ 0.60 $ 0.23
Distributions $ 54.1 $ 35.9 $ 146.0 $ 82.2
Distributions per Unit $ 0.68 $ 0.58 $ 2.00 $ 1.58
Payout ratio (%)(1)(4) 72.4 114.8 80.2 94.3
Production (MMcf/d)(2)
Actual daily average
production 159.4 104.8 143.4 94.0
Gas over bitumen
deemed production(3) 21.5 22.7 22.7 14.2
Total average daily
(actual and deemed)(3) 180.9 127.5 166.1 108.2
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(1) These are non-GAAP measures; please refer to "Significant
Accounting Policies and Non-GAAP Measures" in this MD&A.
(2) Production amounts are based on company interest before
royalties.
(3) The deemed production volume describes 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. This deemed production volume is
not actual gas sales but represents shut-in gas that is the basis
of the gas over bitumen financial solution which is received
monthly from the government of Alberta as a reduction against
other royalties payable.
(4) The payout ratio in 2004 reflects the payout of cash flow in the
third quarter of 2004 related to the assets acquired as part of
the Cavell and the Athabasca Assets Acquisitions, although the
net cash flow from these assets was not recorded as cash flow to
PET but rather dealt with as an adjustment to the purchase price
at closing of the transactions on July 16 and August 18, 2004
respectively.


Natural gas revenue increased 101 percent to $118.9 million for the three months ended September 30, 2005 compared to $59.2 million for the three months ended September 30, 2004. Increased production volumes resulted in a $30.8 million increase in revenue while higher natural gas prices increased revenue by $28.9 million.

Realized natural gas prices increased by 32 percent for the three months ended September 30, 2005 to $8.11 per Mcf from $6.14 per Mcf in 2004, largely as a result of a 21 percent increase in AECO average monthly index prices from quarter to quarter. Before hedging, PET's realized natural gas price was $8.29 per Mcf for the three months ended September 30, 2005 compared to $6.29 per Mcf for the same period in 2004. Realized natural gas prices for the nine months ended September 30, 2005 increased 21 percent to $7.55 per Mcf from $6.22 per Mcf in 2004, also as a result of generally higher AECO average monthly index prices in 2005 as compared to 2004.

For the three months ended September 30, 2005, PET's average royalty rate was 18.8 percent compared to 17.4 percent for the three months ended September 30, 2004. PET's average royalty rate for the nine months ended September 30, 2005 was 18.6 percent as compared to 16.4 percent in 2004. The increase in the average royalty rates is primarily a result of the increase in the Alberta Reference Price in 2005 compared to 2004, as well as a higher royalty rate for the Northeast Alberta Assets as the average production rate per well for the newly acquired assets is higher than that for the Trust's other assets.

Production costs increased to $15.9 million ($1.09 per Mcf) in the three months ended September 30, 2005 from $9.4 million ($0.98 per Mcf) for the same period in 2004. Production costs for the nine months ended September 30, 2005 totaled $47.2 million ($1.20 per Mcf) as compared to $28.0 million ($1.09 per Mcf) in 2004. Unit production costs have increased in 2005 due to fixed operating costs related to the operation of additional plants, additional maintenance on several of the newly acquired facilities, lower throughput volumes in certain facilities due to gas over bitumen shut-ins and a general increase in the cost of field supplies and services.

Higher commodity prices combined with higher production volumes, offset by higher royalties and higher production and transportation costs resulted in a $39.8 million increase in PET's operating netback (revenue less royalties, transportation costs and operating costs) to $76.8 million for the three months ended September 30, 2005 from $37.0 million for the three months ended September 30, 2004.



($Cdn millions)
-----------------------------------------------------
Production increase $ 30.8
Price increase 28.9
Royalty increase (12.0)
Transportation cost increase (1.4)
Operating cost increase (6.5)
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Increase in operating netback $ 39.8
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Three Months Ended Nine Months ended
September 30 September 30
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Netbacks ($/Mcf) 2005 2004 2005 2004
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Gross revenue $ 8.11 $ 6.14 $ 7.55 $ 6.22
Royalties (1.52) (1.07) (1.40) (1.03)
Operating costs (1.09) (0.98) (1.20) (1.09)
Transportation costs (0.26) (0.25) (0.26) (0.26)
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Operating netback 5.24 3.84 4.69 3.84
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General and administrative(1) (0.17) (0.29) (0.23) (0.22)
Interest(1)(2) (0.28) (0.20) (0.26) (0.15)
Capital taxes (0.01) - (0.01) -
Exploration expenses(1) (0.07) (0.08) (0.07) (0.06)
Gas over bitumen royalty
adjustments 0.38 - 0.53 -
---------------------------------------------------------------------
Cash flow netback $ 5.09 $ 3.27 $ 4.65 $ 3.41
---------------------------------------------------------------------

(1) Excluding non-cash expenses. General and administrative expenses
include gas over bitumen costs.
(2) Includes interest on bank debt and convertible debentures.


General and administrative expenses were $2.8 million for the three months ended September 30, 2005 compared to $3.5 million for the three months ended September 30, 2004. This decrease was due to the rationalization of the operations of the Cavell and Athabasca acquisitions into PET and higher non-cash Unit incentive rights compensation in the third quarter of 2004. For the nine months ended September 30, 2005 general and administrative expenses totaled $9.5 million compared to $7.8 million in 2004. The scale of PET's operations increased significantly with the acquisitions consummated during 2004 and with the Northeast Alberta Acquisition in May 2005 and, as a result, general and administrative expenses have increased. Cash general and administrative expenses on a unit-of-production basis were $0.16 per Mcf for the three months ended September 30, 2005 as compared to $0.29 per Mcf in 2004.

Interest expense totaled $4.3 million for the three months ended September 30, 2005, as compared to $2.0 million for the comparable period in 2004. Interest expense has increased due to the full effect of the debt financing of portions of the Cavell and Athabasca Assets acquisitions in second half of 2004 as well as the Northeast Alberta Acquisition in May 2005. Interest expense has also increased due to higher coupon rates on the Trust's convertible debentures as compared to the interest rates on bank debt.

The above factors combined to increase cash flow from operations by 139 percent, to $74.7 million for the three months ended September 30, 2005 from $31.3 million in the 2004 period. Cash flow per Trust Unit increased 83 percent to $0.95 from $0.52 per Trust Unit for the comparable quarter in 2004.

Exploration expenses were $1.1 million for the three months ended September 30, 2005 as compared to $1.0 million for the third quarter of 2004.

Depletion, depreciation and accretion ("DD&A") expense increased from $25.6 million in the third quarter of 2004 to $37.9 million in 2005 due to increased production volumes offset somewhat by a reduction in the Trust's depletion rate. PET's depletion rate decreased from $2.65 per Mcf in the three months ended September 30, 2004 to $2.59 per Mcf in 2005. DD&A expense for the nine months ended September 30, 2005 totaled $107.3 million or $2.74 per Mcf, as compared to $72.7 million or $2.83 per Mcf in 2004.

The Trust reported net earnings of $30.4 million for the three months ended September 30, 2005, an increase of $25.6 million over the 2004 period. The increase is primarily a result of increased cash flows due to higher production levels and natural gas prices as compared to the third quarter of 2004, offset somewhat by higher royalties and DD&A expense. Net earnings for the nine months ended September 30, 2005 were $43.9 million, a 273 percent increase over 2004.



QUARTERLY INFORMATION

(thousands of Three Months Ended
dollars, except Sept 30, June 30, Mar 31, Dec 31,
per Unit amounts) 2005 2005 2005 2004
---------------------------------------------------------------------

Natural gas revenues
before royalties $ 118,928 $ 100,234 $ 76,346 $ 79,665
Net earnings (loss) $ 30,432 $ 11,357 $ 2,153 $ (29,685)
Net earnings (loss)
per Unit - basic $ 0.39 $ 0.15 $ 0.03 $ (0.46)
- diluted $ 0.38 $ 0.15 $ 0.03 $ (0.46)


(thousands of Three Months Ended
dollars, except Sept 30, June 30, Mar 31, Dec 31,
per Unit amounts) 2004 2004 2004 2003
---------------------------------------------------------------------

Natural gas revenues
before royalties $ 59,156 $ 49,904 $ 51,232 $ 43,022
Net earnings (loss) $ 4,781 $ 5,016 $ 1,997 $ (2,812)
Net earnings (loss)
per Unit - basic $ 0.08 $ 0.11 $ 0.04 $ (0.06)
- diluted $ 0.08 $ 0.11 $ 0.04 $ (0.06)


Natural gas revenues have trended steadily higher over the eight quarters shown above. The increase is primarily a result of higher production volumes due to acquisition activity in the second half of 2004 and early 2005, as well as increased natural gas prices over the two-year period.

The increased net earnings in the second and third quarters of 2005 are due to higher production and natural gas prices, offset somewhat by higher royalties and DD&A expenses as compared to prior quarters. The net loss in the fourth quarter of 2004 was a result of an after-tax write-down of property, plant and equipment of $39 million pertaining to the Trust's Saskatchewan cost centre.



CAPITAL EXPENDITURES

Three Months Ended Nine Months Ended
September 30 September 30
---------------------------------------------------------------------
($ thousands except
where noted) 2005 2004 2005 2004
---------------------------------------------------------------------
Exploration and
development expenditures $ 3,882 $ 1,491 $ 48,494 $ 14,992
Acquisitions, net of
dispositions (4,004) 261,141 279,583 294,095
Other 264 36 549 51
---------------------------------------------------------------------
Total capital expenditures $ 142 $ 262,668 $ 328,626 $ 309,138
---------------------------------------------------------------------


For the nine months ended September 30, 2005, acquisitions totaled $279.6 million reflecting primarily the $272.3 million paid for the Northeast Alberta Assets.

Exploration and development expenditures were $3.9 million for the current quarter as compared to $1.5 million for the 2004 period. In the second quarter of 2005, PET initiated a $15 million summer capital expenditure program to exploit opportunities in its year-round access areas. During the third quarter, the Trust drilled 10 wells (10.0 net) in southeast Saskatchewan, experiencing a 100% success rate. PET also participated in 22 wells (3.5 net) in the third quarter as part of its non-operated coalbed methane project in the Craigmyle area of southern Alberta.

For the nine months ended September 30, 2005, exploration and development expenditures totalled $48.5 million compared to $15.0 million for the same period in 2004. The Trust invested approximately $40 million in its winter-access properties in the first quarter with seismic programs, new drilling, completions and tie-ins, recompletions and facilities optimization work distributed throughout PET's three core areas in northeast Alberta.

Net capital dispositions of $4.0 million for the three months ended September 30, 2005 included positive adjustments of $3.0 million related to the 2004 acquisition of Cavell Energy Corp.

LIQUIDITY AND CAPITAL RESOURCES

PET has a demand credit facility with a syndicate of Canadian chartered banks. The credit facility presently has a borrowing base of $310 million. The Trust's lenders reconfirmed the borrowing base under its credit facility at $310 million for a further six months as at October 31, 2005. The facility consists of a demand loan of $300 million and a working capital facility of $10 million. Collateral for the credit facility is provided by a floating-charge debenture covering all existing and acquired property of the Trust as well as unconditional full liability guarantees from all subsidiaries in respect of amounts borrowed under the facility. Bank debt was $182.2 million at September 30, 2005. In addition to amounts outstanding under the credit facility, PET has outstanding letters of credit in the amount of $2.87 million.

At September 30, 2005 PET had $76.6 million in 6.25% convertible debentures outstanding, of which $76.0 million are classified as debt with the remaining $0.6 million classified as equity. These debentures were issued in April 2005 as partial funding for the Northeast Alberta Acquisition. PET also had $11.5 million of 8.0% convertible debentures outstanding at the end of the current quarter all of which are classified as debt. The fair values of the convertible debentures at September 30, 2005 were $91.9 million and $18.6 million, respectively. The fair value of debentures is calculated by multiplying the number of debentures outstanding at September 30, 2005 by the quoted market price per debenture at that date. During the third quarter $23.5 million of the 6.25% debentures and $21.1 million of the 8.0% debentures were converted, resulting in the issuance of 2.7 million Trust Units.

Cash flow for the three months ended September 30, 2005 exceeded distributions and capital expenditures by a total of $20.4 million, which excess was used to reduce the Trust's outstanding bank debt. Including debenture conversions and proceeds from the Trust's DRIP plan, total net debt was reduced to $270.0 million at September 30, 2005 from $356.6 million at June 30, 2005.

Cumulative distributions for the third quarter of 2005 totaled $0.68 per Trust Unit, consisting of $0.22 per Trust Unit paid on August 15 and September 15, and a distribution of $0.24 per Trust Unit paid on October 17. The Trust's payout ratio, which is the ratio of distributions to cash flow, was 72.4% in the third quarter of 2005, as compared to 114.8% for the third quarter of 2004 and 72.6% for the second quarter of 2005. The lower payout ratio is primarily a result of the accretive nature of the Northeast Alberta Acquisition, as well as increased commodity prices as compared to prior quarters. The payout ratio in 2004 reflects the payout of cash flow in the third quarter of 2004 related to the assets acquired as part of the Cavell and the Athabasca Assets Acquisitions, although the net cash flow from these assets was not recorded as cash flow to PET but rather dealt with as an adjustment to the purchase price at closing of the transactions on July 16 and August 18, 2004 respectively.

INCOME TAXES

Each year the Trust is required to file a trust income tax return and any otherwise taxable income of the Trust is allocated to Unitholders. Income of the Trust that has been paid or is payable to Unitholders, whether in cash, additional Trust Units or otherwise, will be deductible by the Trust in computing its income for tax purposes.

Future income taxes may arise from differences between the accounting and tax basis of the operating entities' assets and liabilities. In our current structure, payments are made between the operating entities and the Trust, ultimately transferring any current income tax liabilities to the Unitholders. The tax-efficient structure of the Trust should preclude any income taxes from being payable in the Trust or other direct/indirect subsidiaries of the Trust, and as such, no current or future income tax liabilities have been recognized in the financial statements. However, the determination of the Trust and its direct/indirect subsidiaries' income and other tax liabilities require interpretation of complex laws and regulations over multiple jurisdictions. All tax filings are subject to audit and potential reassessment after the lapse of considerable time.

The Trust qualifies as a mutual fund trust under the Income Tax Act (Canada) and accordingly, Trust Units are qualified investments for Registered Retirement Savings Plans, Registered Retirement Income Funds, Registered Education Savings Plans and Deferred Profit Sharing Plans (subject to the specific provisions of any of these particular plans). To the best of our knowledge, PET's current foreign ownership level is approximately 26 percent. The Trust will continue to monitor the progress of any legislative changes to maintain its mutual fund trust status.

A Canadian Unitholder generally will be required to include in computing income for a particular taxation year, such portion of the net income of the Trust for a taxation year, including net realized taxable capital gains paid or payable to the Unitholder in that particular taxation year, whether received in cash, additional Trust Units or otherwise. An investor's adjusted cost basis ("ACB") in a Trust Unit generally equals the purchase price of the unit less any tax deferred returns of capital included in cash distributions received from the date of acquisition. To the extent a Unitholder's ACB is reduced to below zero, such amount will be deemed to be a capital gain to the Unitholder and the Unitholder's ACB will be nil.

Uniholders are advised to seek legal advice from their professional advisors with respect to their particular circumstances.

RISK MANAGEMENT

To protect cash flow and distributions against commodity price volatility, and to lock in attractive economics on acquisitions, the Trust maintains a balanced gas price risk management portfolio using both financial hedge arrangements and physical forward sales.

At September 30, 2005, the Trust had entered into financial hedge arrangements as follows:



Fixed Floor Ceiling
Type Volume Term ($/GJ) ($/GJ) ($/GJ)
---------------------------------------------------------------------
AECO fixed price 40,000 GJ/d Oct 05 $7.01 - -
AECO fixed price 55,000 GJ/d Nov 05 - Mar 06 $8.19 - -
AECO fixed price 20,000 GJ/d Apr 06 - Oct 06 $8.01 - -
---------------------------------------------------------------------


Had these contracts been settled on September 30, 2005, using forward prices in effect at that time, the mark-to-market settlement payment by PET would have totaled $60.0 million. As the Trust follows hedge accounting for these instruments this amount has not been recorded in the financial statements. As at November 8, 2005 the October financial hedges had settled, and the mark-to-market settlement payment by PET for the remaining financial hedges, using forward prices in effect at that time, would have totaled $26.9 million.

At September 30, 2005, the Trust had entered into forward physical gas sales arrangements as follows:



Fixed Floor Ceiling
Type Volume Term ($/GJ) ($/GJ) ($/GJ)
---------------------------------------------------------------------
AECO collar 5,000 GJ/d Oct 05 - $6.50 $7.30
AECO fixed price 70,000 GJ/d Oct 05 $7.64 - -
AECO fixed price 75,000 GJ/d Nov 05 - Mar 06 $8.62 - -
AECO fixed price 25,000 GJ/d Apr 06 - Oct 06 $8.03 - -
---------------------------------------------------------------------


SIGNIFICANT ACCOUNTING POLICIES AND NON-GAAP MEASURES

Successful Efforts Accounting

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, 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.

Cash Flow

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 GAAP. All references to cash flow throughout this MD&A are based on cash flow before changes in non-cash working capital and include gas over bitumen royalty adjustments for shut-in production.

Payout Ratio

Payout ratio refers to distributions measured as a percentage of cash flow for the period and is used by management to analyze cash flow available for development and acquisition opportunities as well as overall sustainability of distributions. Cash flow does not have any standardized meaning prescribed by GAAP and therefore payout ratio may not be comparable to the calculation of similar measures for other entities.

Operating and Cash Flow Netbacks

Operating and cash flow netbacks are used by management to analyze margin and cash flow on each Mcf of natural gas production. Operating and cash flow netbacks do not have any standardized meaning as prescribed by GAAP and therefore may not be comparable to the calculation of similar measures for other entities. Operating and cash flow netbacks should not be viewed as an alternative to cash flow from operations, net earnings per Trust Unit or other measures of financial performance calculated in accordance with GAAP.

RISK AND UNCERTAINTIES

On September 8, 2005 the Department of Finance released its consultation paper "Tax and Other Issues Related to Publicly Listed Flow-Through Entities (Income Trusts and Limited Partnerships)". The Department of Finance stated the purpose of the paper is to promote discussion and third-party input on a number of key questions by providing background information on, among other things, the estimated impact of flow-through entities on federal tax revenues. At this time it is unknown whether legislation will result from this consultation process. Any legislation could materially affect the Trust or its Unitholders.

All other risks and uncertainties affecting PET's operations are substantially unchanged from those presented in the MD&A for the year ended December 31, 2004.

CRITICAL ACCOUNTING ESTIMATES

The MD&A is based on the Trust's consolidated financial statements which have been prepared in Canadian dollars in accordance with GAAP. The application of GAAP requires management to make estimates, judgments and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. PET bases its estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances. Actual results could differ from these estimates under different assumptions or conditions.

Following is a discussion of the critical accounting estimates that are inherent in the preparation of the Trust's consolidated financial statements and notes thereto.

Accounting for petroleum and natural gas operations

Under the successful efforts method of accounting, the Trust capitalizes only those costs that result directly in the discovery of petroleum and natural gas reserves including acquisitions, successful exploratory wells, development costs and the costs of support equipment and facilities. Exploration expenditures including geological and geophysical costs, lease rentals and exploratory dry holes are charged to earnings in the period incurred. The application of the successful efforts method of accounting requires management's judgment to determine the proper designation of wells as either developmental or exploratory which will ultimately determine the proper accounting treatment of the costs incurred. The results of a drilling operation can take considerable time to analyze and the determination that proved reserves have been discovered requires both judgment and application of industry experience. The evaluation of petroleum and natural gas leasehold acquisition costs requires management's judgment to evaluate the fair value of land in a given area.

Reserve estimates

Estimates of the Trust's reserves included in its consolidated financial statements are prepared in accordance with guidelines established by the Alberta Securities Commission. Reserve engineering is a subjective process of estimating underground accumulations of petroleum and natural gas that cannot be measured in an exact manner. The process relies on interpretations of available geological, geophysical, engineering and production data. The accuracy of a reserve estimate is a function of the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions and the judgment of the persons preparing the estimate.

PET's reserve information is based on estimates prepared by its independent petroleum consultants. Estimates prepared by others may be different than these estimates. Because these estimates depend on many assumptions, all of which may differ from actual results, reserve estimates may be different from the quantities of petroleum and natural gas that are ultimately recovered. In addition, the results of drilling, testing and production after the date of an estimate may justify revisions to the estimate. The present value of future net revenues should not be assumed to be the current market value of the Trust's estimated reserves. Actual future prices, costs and reserves may be materially higher or lower than the prices, costs and reserves used for the future net revenue calculations. The estimates of reserves impact depletion, dry hole expenses and asset retirement obligations. If reserve estimates decline, the rate at which the Trust records depletion increases thereby reducing net earnings. In addition, changes in reserve estimates may impact the outcome of PET's assessment of its petroleum and natural gas properties for impairment.

Impairment of petroleum and natural gas properties

The Trust reviews its proved properties for impairment on a cost center basis. For each cost center, an impairment provision is recorded whenever events or circumstances indicate that the carrying value of those properties may not be recoverable. The impairment provision is based on the excess of carrying value over fair value. Fair value is defined as the present value of the estimated future net revenues from production of total proved and probable petroleum and natural gas reserves as estimated by the Trust on the balance sheet date. Reserve estimates and estimates for natural gas prices and production costs may change and there can be no assurance that impairment provisions will not be required in the future.

Management's assessment of, among other things, the results of exploration activities, commodity price outlooks and planned future development and sales, impacts the amount and timing of impairment provisions.

Asset retirement obligations

The asset retirement obligations recorded in the consolidated financial statements are based on an estimate of the fair value of the total costs for future site restoration and abandonment of the Trust's petroleum and natural gas properties. This estimate is based on management's analysis of production structure, reservoir characteristics and depth, market demand for equipment, currently available procedures, the timing of asset retirement expenditures and discussions with construction and engineering consultants. Estimating these future costs requires management to make estimates and judgments that are subject to future revisions based on numerous factors including changing technology and political and regulatory environments.

CHANGE IN ACCOUNTING POLICY

On January 1, 2005 the Trust retroactively applied the fair value based method of accounting for Trust Unit incentive rights (the "Rights"). Under the fair value method of accounting, compensation expense is based on the fair value of the Unit-based compensation at the date of grant using a modified Black-Scholes option pricing model. Compensation expense associated with the Rights is recognized in earnings over the vesting period and credited to contributed surplus. Consideration received upon the exercise of the Rights together with the amount previously recognized in contributed surplus is recorded as an increase in Unitholders' capital. The Trust has not incorporated an estimated forfeiture rate for Rights that will not vest, and accounts for actual forfeitures as they occur.

Previously, the Trust applied the intrinsic value methodology due to the number of uncertainties regarding the reduction in the exercise price of the Rights which made a fair value calculation inappropriate. The Trust has now applied the fair value calculation as the variables have become more certain, including the life of the plan, future expected distributions and expected reduction in the Rights price where applicable.

As a result of the change in accounting policy, PET restated previously reported annual and quarterly net earnings for 2004 as follows:



Three months ended
(thousands of dollars, Dec 31, Sep 30, Jun 30, Mar 31,
except per Unit amounts) 2004 2004 2004 2004
---------------------------------------------------------------------
Reported net earnings
(loss) before change in
accounting policy $ (30,484) $ 2,890 $ 5,029 $ 1,902
Effect of change in
accounting policy $ 799 $ 1,891 $ (13) $ 95
Restated net earnings
(loss) $ (29,685) $ 4,781 $ 5,016 $ 1,997

Net earnings (loss) per
Unit, as reported
- basic & diluted $ (0.47) $ 0.05 $ 0.11 $ 0.04
Net earnings (loss) per
Unit, as restated
- basic & diluted $ (0.46) $ 0.08 $ 0.11 $ 0.04
---------------------------------------------------------------------


NEW ACCOUNTING POLICIES

Financial Instruments

On January 1, 2005, the Trust retroactively adopted the amendment to the Canadian Institute of Chartered Accountants ("CICA") Handbook section 3860 "Financial Instruments". These changes require that fixed-amount contractual obligations that can be settled by issuing a variable number of equity instruments be classified as liabilities. The convertible debentures previously issued by the Trust have characteristics that meet the noted criteria and therefore we have retroactively accounted for these instruments as debt, with a portion, representing the value of the equity conversion feature, in equity, and reflected interest costs as interest expense in the statement of earnings.

Variable Interest Entities ("VIEs")

In June 2003, the CICA issued Accounting Guideline 15 "Consolidation of Variable Interest Entities" ("AcG-15"). AcG-15 defines VIEs as entities in which either: the equity at risk is not sufficient to permit that entity to finance its activities without additional financial support from other parties or equity investors lack voting control, an obligation to absorb expected losses or the right to receive expected residual returns. AcG-15 harmonizes Canadian and U.S. GAAP and provides guidance for companies consolidating VIEs in which they are the primary beneficiary. The guideline is effective for all annual and interim periods beginning on or after November 1, 2004. We have performed a review of entities in which PET has an interest and have determined that we do not have any variable interest entities at this time.

Additional information on PET, including the most recent filed Annual Report and Annual Information Form, can be accessed from SEDAR at www.sedar.com or from the Trust's website at www.paramountenergy.com.



Paramount Energy Trust
Consolidated Balance Sheets

As at September 30, December 31,
2005 2004
---------------------------------------------------------------------
($ thousands) (unaudited) (restated, note 2)

Assets
Current assets
Accounts receivable $ 50,305 $ 30,355
Property, plant and equipment
(notes 4 and 5) 727,306 494,885
Goodwill (note 4) 29,129 29,698
Other assets (note 3) 7,463 1,773
---------------------------------------------------------------------
$ 814,203 $ 556,711
---------------------------------------------------------------------

Liabilities
Current liabilities
Accounts payable and accrued
liabilities $ 31,236 $ 21,674
Distributions payable 19,391 13,065
Bank and other debt (note 6) 182,196 171,698
---------------------------------------------------------------------
232,823 206,437
---------------------------------------------------------------------

Gas over bitumen royalty
adjustments (note 13) 31,966 11,200
Asset retirement obligations (note 10) 57,242 34,116
Convertible debentures (note 7) 87,486 38,419
Future income taxes - 2,088

Unitholders' equity
Unitholders' capital (note 8) 738,126 495,695
Equity component of convertible
debentures (note 7) 648 -
Contributed surplus (note 2) 3,717 4,461
Equity adjustments (16,172) (16,172)
Accumulated earnings 68,925 24,983
Accumulated distributions (390,558) (244,516)
---------------------------------------------------------------------
404,686 264,451
---------------------------------------------------------------------
$ 814,203 $ 556,711
---------------------------------------------------------------------

See accompanying notes
Commitments: note 12
Contingency: note 13



Paramount Energy Trust
Consolidated Statements of Earnings and Accumulated Earnings

Three Months Nine Months
Ended September 30 Ended September 30
2005 2004 2005 2004
---------------------------------------------------------------------
($ thousands except (restated, (restated,
per Unit amounts, note 2) note 2)
unaudited)
Revenue
Natural gas $ 118,928 $ 59,156 $ 295,508 $ 160,292
Royalties (22,328) (10,298) (54,828) (26,319)
---------------------------------------------------------------------
96,600 48,858 240,680 133,973
---------------------------------------------------------------------

Expenses
Operating 15,936 9,436 47,179 27,969
Transportation costs 3,840 2,452 10,130 6,794
Exploration expenses 1,076 1,046 12,258 2,119
General and
administrative
(notes 2 and 9) 2,784 3,533 9,451 7,822
Gas over bitumen
costs (note 13) 163 65 866 1,044
Interest 2,152 1,372 5,928 3,150
Interest on convertible
debentures 2,193 600 4,871 600
Depletion, depreciation
and accretion 37,926 25,573 107,292 72,681
---------------------------------------------------------------------
66,070 44,077 197,975 122,179
---------------------------------------------------------------------
Earnings before income
taxes 30,530 4,781 42,705 11,794
---------------------------------------------------------------------
Future income tax
reduction - - 1,519 -
Capital taxes (98) - (282) -
---------------------------------------------------------------------
(98) - 1,237 -
---------------------------------------------------------------------
Net earnings 30,432 4,781 43,942 11,794

Accumulated earnings
net of distributions
at beginning of period,
as previously reported (297,927) (119,568) (219,533) (77,781)
Retroactive effect of
change in accounting
policy (note 2) - - - (2,546)
---------------------------------------------------------------------
Accumulated earnings
net of distributions
at beginning of
period, as restated (297,927) (119,568) (219,533) (80,327)
---------------------------------------------------------------------
Distributions paid
or payable (54,138) (35,925) (146,042) (82,179)
---------------------------------------------------------------------
Accumulated earnings
net of distributions
at end of period $ (321,633) $ (150,712) $ (321,633) $ (150,712)
---------------------------------------------------------------------

Earnings per Trust
Unit (note 8(c))
Basic $ 0.39 $ 0.08 $ 0.60 $ 0.23
Diluted $ 0.38 $ 0.08 $ 0.60 $ 0.23

Distributions per
Trust Unit $ 0.68 $ 0.58 $ 2.00 $ 1.58
---------------------------------------------------------------------

See accompanying notes



Paramount Energy Trust
Consolidated Statements of Cash Flows

Three Months Nine Months
Ended September 30 Ended September 30
2005 2004 2005 2004
---------------------------------------------------------------------
($ thousands, unaudited) (restated, (restated,
Cash provided by (used for) note 2) note 2)
---------------------------------------------------------------------
Operating activities
Net earnings $ 30,432 $ 4,781 $ 43,942 $ 11,794
Items not involving
cash
Gas over bitumen
royalty adjustments 5,660 - 20,766 -
Depletion,
depreciation and
accretion 37,926 25,573 107,292 72,681
Trust Unit
compensation 414 680 1,416 2,041
Future income
tax reduction - - (1,519) -
Amortization of
other assets 294 - 513 -
Exploration expenses - 267 9,608 554
---------------------------------------------------------------------
Funds from operations 74,726 31,301 182,018 87,070
Change in non-cash
working capital 4,228 (11,982) (6,551) (6,021)
---------------------------------------------------------------------
78,954 19,319 175,467 81,049
---------------------------------------------------------------------

Financing activities
Issue of Trust Units 9,948 94,097 166,735 143,505
Distributions to
Unitholders (42,724) (33,266) (121,271) (79,520)
Issue of convertible
debentures - 43,384 96,000 43,384
Change in bank and
other debt (48,437) 132,400 10,498 115,249
Change in non-cash
working capital and
other assets 2,815 5,555 5,972 4,532
---------------------------------------------------------------------
(78,398) 242,170 157,934 227,150
---------------------------------------------------------------------

$ 556 $ 261,489 $ 333,401 $ 308,199
---------------------------------------------------------------------


Investing activities
Acquisition of
investments - - (1,243) -
Acquisition of
properties and
corporate assets (590) (293,891) (285,498) (326,845)
Exploration and
development
expenditures (3,882) (1,527) (48,494) (15,043)
Proceeds on sale
of property and
equipment 4,330 32,750 5,366 32,750
Change in non-cash
working capital and
asset retirement
obligation (414) 1,179 (3,532) 939
---------------------------------------------------------------------
$ (556) $ (261,489) $ (333,401) $ (308,199)
---------------------------------------------------------------------

Interest paid $ 3,480 $ 1,393 $ 10,596 $ 2,832
Taxes paid $ 97 $ - $ 203 $ -
---------------------------------------------------------------------

See accompanying notes



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


1. BASIS OF PRESENTATION AND ACCOUNTING POLICIES

These interim consolidated financial statements of Paramount Energy Trust ("PET" or "the Trust") have been prepared by management in accordance with Canadian generally accepted accounting principles ("GAAP") following the same accounting principles and methods of computation as the consolidated financial statements for the year ended December 31, 2004, except as described in note 2 below. The disclosures provided below are incremental to those included with the annual consolidated financial statements. The specific accounting principles used are described in the annual consolidated financial statements of the Trust appearing on pages 52 through 54 of the Trust's 2004 annual report and should be read in conjunction with these interim financial statements.

2. CHANGE IN ACCOUNTING POLICY

Trust Unit-based compensation

On January 1, 2005 the Trust retroactively applied the fair value based method of accounting for Trust Unit incentive rights ("Rights"). Under the fair value based method of accounting, compensation expense is based on the fair value of the Unit-based compensation at the date of grant using a modified Black-Scholes option pricing model. Compensation expense associated with Rights is recognized in earnings over the vesting period. Consideration received upon the exercise of the Rights together with the amount previously recognized in contributed surplus is recorded as an increase in Unitholders' capital. The Trust has not incorporated an estimated forfeiture rate for Rights that will not vest. The Trust accounts for actual forfeitures as they occur.

Previously, the Trust applied the intrinsic value methodology due to the number of uncertainties regarding the reduction in the exercise price of the Rights which made a fair value calculation inappropriate. The Trust has now applied the fair value calculation as the variables have become more certain, including the life of the plan; future expected distributions and expected reduction in the Rights price where applicable.

Retroactive application of the fair value method resulted in a decrease in accumulated earnings and an increase in contributed surplus for 2003 of $0.2 million. Further, reported Trust Unit compensation expense for the year ended December 31, 2004 decreased by $2.8 million to $2.7 million with a corresponding increase in contributed surplus. The change in accounting policy resulted in increases in reported earnings for the three and nine months ended September 30, 2004 of $1.9 million and $2.0 million, respectively.

A reconciliation of contributed surplus resulting from adoption of the new policy is provided below:



---------------------------------------------------------------------
Balance, as at January 1, 2004, as previously reported $ 2,740
Adoption of fair value method (194)
---------------------------------------------------------------------
Balance, as at January 1, 2004, as restated 2,546
Trust Unit-based compensation expense, as
previously reported 5,493
Reduction in Trust Unit-based compensation
expense upon restatement (2,771)
Transfer to Unitholders' capital on exercise of Rights (807)
---------------------------------------------------------------------
Balance, as at December 31, 2004, as restated 4,461
---------------------------------------------------------------------
Trust Unit-based compensation expense 1,416
Transfer to Unitholders' capital on exercise of Rights (2,160)
---------------------------------------------------------------------
Balance, as at September 30, 2005 $ 3,717
---------------------------------------------------------------------


3. OTHER ASSETS

September 30, 2005 December 31, 2004
---------------------------------------------------------------------

Convertible debenture issue costs $ 3,220 $ 1,773
Investments 4,243 -
---------------------------------------------------------------------
$ 7,463 $ 1,773
---------------------------------------------------------------------


Convertible debenture issue costs are amortized to earnings over the life of the debentures and reclassified to Unitholders' capital as and when debentures are converted to Trust Units.

Investments include $3.0 million related to PET's interest in Sebring Energy Inc. and $1.2 million related to the Trust's five percent interest in the Eagle Energy Marketing Canada Limited Partnership. These investments are accounted for on a cost basis.

4. ACQUISITIONS

On May 17, 2005 the Trust closed the acquisition of producing natural gas properties in Northeast Alberta (the "Northeast Alberta Acquisition") for an aggregate purchase price of $272.3 million. The acquisition was financed through the issuance of 9,500,000 Trust Units for gross proceeds of $160.1 million in addition to the issuance of $100.0 million in 6.25% convertible extendible unsecured subordinated debentures (see note 7), and through existing credit facilities.



---------------------------------------------------------------------
Property, plant and equipment acquired $ 285,594
Asset retirement obligation (13,267)
---------------------------------------------------------------------
Net purchase price $ 272,327
---------------------------------------------------------------------


Goodwill recorded on the purchase of Cavell Energy Corporation has been reduced by $0.5 million to reflect adjustments to tax balances at the closing date of the acquisition.

5. PROPERTY, PLANT AND EQUIPMENT



September 30, 2005 December 31, 2004
---------------------------------------------------------------------

Petroleum and natural gas
properties $ 1,270,389 $ 954,351
Asset retirement costs 51,292 30,787
Corporate assets 15,303 14,754
---------------------------------------------------------------------
1,336,984 999,892
Accumulated depletion and
depreciation (609,678) (505,007)
---------------------------------------------------------------------
$ 727,306 $ 494,885
---------------------------------------------------------------------


Property, plant and equipment costs at September 30, 2005 included $88.4 million (September 30, 2004 - $72.5 million) currently not subject to depletion.

6. BANK AND OTHER DEBT

PET has a revolving credit facility with a syndicate of Canadian Chartered Banks (the "Credit Facility"). The Credit Facility currently has a borrowing base of $310 million, consisting of a demand loan of $300 million and a working capital facility of $10 million. In addition to amounts outstanding under the Credit Facility, PET has outstanding letters of credit in the amount of $2.87 million. Collateral for the Credit Facility is provided by a floating-charge debenture covering all existing and acquired property of the Trust as well as unconditional full liability guarantees from all subsidiaries in respect of amounts borrowed under the Credit Facility.

Advances under the Credit 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 effective interest rate on outstanding amounts at September 30, 2005 was 3.81%.

7. CONVERTIBLE DEBENTURES

As at January 1, 2005, the Trust adopted new accounting standards for the classification of liabilities that may be settled with a variable number of equity instruments such as Trust Units. The adoption has resulted in the convertible debentures being classified as debt with a portion of the proceeds allocated to equity representing the value of the conversion feature. As the debentures are converted, a portion of debt and equity amounts are transferred to Unitholders' capital. The debt balance associated with the convertible debentures accretes over time to the amount owing on maturity and such increases in the debt balance are reflected as non-cash interest expense in the statement of earnings.

The Trust's 8% convertible unsecured subordinated debentures (the "8% Convertible Debentures") mature on September 30, 2009, 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 the Credit Facility. The 8% Convertible Debentures are convertible at the option of the holder into Trust Units at any time prior to the maturity date at a conversion price of $14.20 per Trust Unit. During the nine months ended September 30, 2005, $26.9 million of 8% Convertible Debentures were converted, resulting in the issuance of 1,895,187 Trust Units.

The Trust's 6.25% convertible unsecured subordinated debentures (the "6.25% Convertible Debentures") mature on June 30, 2010, bear interest at 6.25% per annum paid semi-annually on June 30 and December 31 of each year and are subordinated to substantially all other liabilities of PET including the Credit Facility. The 6.25% Convertible Debentures are convertible at the option of the holder into Trust Units at any time prior to the maturity date at a conversion price of $19.35 per Trust Unit. During the nine months ended September 30, 2005, $23.5 million of 6.25% Convertible Debentures were converted, resulting in the issuance of 1,212,029 Trust Units.

At September 30, 2005, the Trust had $11.5 million in 8% Convertible Debentures outstanding with a fair market value of $18.6 million, and $76.6 million in 6.25% Convertible Debentures outstanding with a fair market value of $91.9 million.



8% Series 6.25% Series Total
--------------------------------------------------
Number of Number of
debentures Amount debentures Amount Amount
---------------------------------------------------------------------
August 10, 2004
issuance 48,000 $ 48,000 - $ - $ 48,000
Portion allocated
to equity - - - - -
Converted into
Trust Units (9,581) (9,581) - - (9,581)
---------------------------------------------------------------------
December 31, 2004 38,419 38,419 - - 38,419
---------------------------------------------------------------------
April 26, 2005
issuance - - 100,000 100,000 100,000
Portion allocated
to equity - - - (846) (846)
Accretion of non-cash
interest expense - - - 80 80
Converted into Trust
Units (26,912) (26,912) (23,453) (23,255) (50,167)
---------------------------------------------------------------------
As at
September 30, 2005 11,507 $ 11,507 76,547 $ 75,979 $ 87,486
---------------------------------------------------------------------
---------------------------------------------------------------------


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:

Number
Trust Units Of Units Amount
---------------------------------------------------------------------
Balance, December 31, 2003, as restated 44,638,376 $ 260,019
Units issued pursuant to Unit offerings 12,295,547 146,675
Units issued pursuant to corporate
acquisition 6,931,633 78,674
Units issued pursuant to Unit Incentive Plan 153,875 1,371
Units issued pursuant to Distribution
Reinvestment Plan 632,829 8,185
Units issued pursuant to conversion of
Debentures 674,711 9,581
Issue costs on Convertible Debentures
converted to Trust Units - (383)
Trust Unit issue costs - (8,427)
---------------------------------------------------------------------
Balance, December 31, 2004 65,326,971 495,695
Units issued pursuant to Unit offerings 9,500,000 160,075
Units issued pursuant to Unit Incentive Plan 420,125 3,518
Units issued pursuant to Distribution
Reinvestment Plan 2,439,908 41,041
Units issued pursuant to conversion
of Debentures 3,107,216 50,365
Issue costs on Convertible Debentures
converted to Trust Units (1,983)
Trust Unit issue costs (10,585)
---------------------------------------------------------------------
Balance, September 30, 2005 80,794,220 $ 738,126
---------------------------------------------------------------------


c) Per Unit Information

Basic earnings per Trust Unit were calculated using the weighted average number of Trust Units outstanding during the three months and nine months ended September 30, 2005 of 78,761,798 and 72,764,410 respectively (2004 - 59,738,337 and 50,529,515, respectively). The Trust uses the treasury stock method where only "in the money" dilutive instruments impact the diluted calculations. In computing diluted earnings per Unit for the three and nine month periods ended September 30, 2005, 632,416 and 561,186 Units respectively were added to the weighted average number of Trust Units outstanding for the dilutive effect of Rights (2004 - 405,313 and 123,835 respectively).

d) Redemption Right

Unitholders may redeem their Trust Units at any time by delivering their Unit Certificates to the Trustee of PET. Unitholders have no rights with respect to the Trust Units tendered for redemption other than a right to receive the redemption amount. 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.

In the event that the aggregate redemption value of Trust Units tendered for redemption in a calendar month exceeds $100,000 and PET does not exercise its discretion to waive the $100,000 limit on monthly redemptions, PET will not use cash to pay the redemption amount for any of the Trust Units tendered for redemption in that month. Instead, PET will pay the redemption amount for those Trust Units, subject to compliance with applicable laws including securities laws of all jurisdictions and the receipt of all applicable regulatory approvals, by the issuance of promissory notes of PET (the "Notes") to the tendering Unitholders.

The Notes delivered as set out above will be unsecured and bear interest at a market rate of interest to be determined at the time of issuance by the Board of Directors based on the advice of an independent financial advisor. The interest will be payable monthly. The Notes will be subordinated and, in certain circumstances, postponed to all of PET's indebtedness. Subject to prepayment, the Notes will be due and payable 5 years after issuance.

9. UNIT INCENTIVE PLAN

At September 30, 2005 a total of 3,963,838 PET Trust Units had been reserved under the Unit Incentive Plan. A summary of the changes in Rights outstanding under the plan is as follows:



Rights
---------------------------------------------------------------------
Average
exercise price Rights
---------------------------------------------------------------------
Balance, December 31, 2004 $ 6.13 1,612,750
Granted 16.58 547,125
Exercised 3.23 (420,125)
Cancelled 11.40 (115,000)
---------------------------------------------------------------------
Balance, September 30, 2005 $ 9.08 1,624,750
---------------------------------------------------------------------
Rights exercisable, end of period $ 9.35 25,000
---------------------------------------------------------------------


The following summarizes information about Unit Incentive Rights
outstanding at September 30, 2005:

Number Weighted Number Weighted
outstanding Weighted average Exercisable average
Range of at average exercise at exercise
Exercise September 30, contractual price/ September 30, price/
Prices 2005 life (years) Right 2005 Right
---------------------------------------------------------------------
$0.18 482,750 3 $ 0.18 - -
$7.97-$8.10 147,500 4 $ 8.04 12,500 $ 8.04
$8.79-$13.76 447,375 4.5 $ 9.85 12,500 $10.65
$14.82-$21.32 547,125 5 $16.58 - -
---------------------------------------------------------------------
Total 1,624,750 4 $ 9.08 25,000 $ 9.35
---------------------------------------------------------------------


The Trust recorded compensation expense in respect of Rights of $0.4 million for the three month period ended September 30, 2005, and $1.4 million for the nine month period ended September 30, 2005 ($0.7 million for the three months ended September 30, 2004 and $2.0 million for the nine months ended September 30, 2004).

PET used the Black-Scholes option-pricing model to calculate the estimated fair value of the outstanding Rights issued on or after January 1, 2003. The following assumptions were used to arrive at the estimate of fair value as at the date of grant:



---------------------------------------------------------------------
Expected annual Right's exercise price reduction $ 1.48
Expected volatility 48.0 - 55.0%
Risk-free interest rate 3.27 - 4.26%
Expected life of Rights (years) 5.0
---------------------------------------------------------------------


10. ASSET RETIREMENT OBLIGATIONS

The total future asset retirement obligation was estimated by management based on the Trust'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. The Trust has estimated the net present value of its total asset retirement obligations to be $57.2 million as at September 30, 2005 based on a total future liability of $125.1 million. These payments are expected to be made over the next 25 years with the majority of costs incurred between 2010 and 2015. The Trust used a credit adjusted risk free rate of 7.82% to calculate the present value of the asset retirement obligation.

The following table reconciles the Trust's asset retirement obligations:



September 30, December 31,
2005 2004
---------------------------------------------------------------------
Obligation, beginning of period $ 34,116 $ 21,701
Liabilities incurred 7,238 -
Liabilities acquired (note 4) 13,267 10,325
Accretion expense 2,621 2,090
---------------------------------------------------------------------
$ 57,242 $ 34,116
---------------------------------------------------------------------


11. FINANCIAL INSTRUMENTS

Natural gas commodity price hedges

At September 30, 2005, the Trust had entered into financial hedge
arrangements as follows:

Fixed Floor Ceiling
Type Volume Term ($/GJ) ($/GJ) ($/GJ)
---------------------------------------------------------------------
AECO fixed price 40,000 GJ/d Oct 05 $7.01 - -
AECO fixed price 55,000 GJ/d Nov 05 - Mar 06 $8.19 - -
AECO fixed price 20,000 GJ/d Apr 06 - Oct 06 $8.01 - -
---------------------------------------------------------------------


Had these contracts been settled on September 30, 2005, using forward
prices in effect at that time, the mark-to-market settlement payment
by PET would have totaled $60.0 million.

12. COMMITMENTS

At September 30, 2005, the Trust had entered into physical gas sales
arrangements as follows:

Fixed Floor Ceiling
Type Volume Term ($/GJ) ($/GJ) ($/GJ)
---------------------------------------------------------------------
AECO collar 5,000 GJ/d Oct 05 - $6.50 $7.30
AECO fixed price 70,000 GJ/d Oct 05 $7.64 - -
AECO fixed price 75,000 GJ/d Nov 05 - Mar 06 $8.62 - -
AECO fixed price 25,000 GJ/d Apr 06 - Oct 06 $8.03 - -
---------------------------------------------------------------------


PET has committed to supply to Eagle Energy Marketing Canada Limited Partnership for marketing on behalf of the Trust at market prices as directed by PET a minimum average of 30 MMcf/d of physical natural gas deliveries for a five year period commencing March 1, 2005.

13. GAS OVER BITUMEN ISSUE

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. During the three and nine month periods ended September 30, 2005 the Trust incurred $0.2 million and $0.9 million, respectively, in legal and consulting expenditures directly related to the gas over bitumen issue (2004 - $0.1 million and $1.0 million, respectively).

On October 4, 2004 the Government of Alberta enacted amendments to the 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 initially 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 percent after the first year of shut-in increasing at 1 percent per annum based on the period of time such zones remained shut-in to a maximum of 10 percent. The incremental royalties payable to the Crown would be limited to amounts recovered by a gas well operator through the reduced royalty.

At September 30, 2005 PET had recorded $32.0 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 adjustment may be repayable through incremental royalties if and when gas production recommences, the royalty adjustments are being excluded from earnings pending such determination.

The TSX has neither approved nor disapproved the information contained herein.

Contact Information

  • Paramount Energy Trust
    Susan L. Riddell Rose
    President and Chief Executive Officer
    (403) 269-4400
    or
    Paramount Energy Trust
    Cameron R. Sebastian
    Vice President Finance and Chief Financial Officer
    (403) 269-4400
    or
    Paramount Energy Trust
    Sue M. Showers
    Investor Relations and Communications Advisor
    (403) 269-4400
    (403) 269-4444 (FAX)
    or
    Paramount Energy Operating Corp.,
    Administrator of Paramount Energy Trust
    Suite 500, 630 - 4 Avenue SW, Calgary, AB T2P 0J9
    Email: info@paramountenergy.com
    Website: www.paramountenergy.com