Filed by Filing Services Canada inc. 403-717-3898

6-K 1 paramount.htm Filed by Filing Services Canada inc. 403-717-3898

FORM 6-K
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

Report of Foreign Private Issuer

Pursuant to Rule 13a-16 or 15d-16
of the Securities Exchange Act of 1934

For the month of May 9, 2005

PARAMOUNT ENERGY TRUST

(Translation of registrant's name into English)

SUITE 500, 630 - 4 AVENUE SW, CALGARY, AB T2P 0J9

(Address of principal executive offices)

Indicate by check mark whether the registrant files or will file annual reports under cover Form 20-F or Form 40-F.

Form 20-F_ __ Form 40-F _X__

Indicate by check mark whether the registrant by furnishing the information contained in this Form is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934.

Yes ..... No ..X...

If "Yes" is marked, indicate below the file number assigned to the registrant in connection with Rule 12g3-2(b): 82-________

EXHIBITS

The following documentation is being submitted herewith:

Exhibits:

Press Release dated May 9, 2005

Signatures

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

PARAMOUNT ENERGY TRUST

By its Administrator PARAMOUNT

ENERGY OPERATING CORP.

(Registrant)

By:/s/ Cameron R. Sebastian

(Signature)

Cameron R. Sebastian

Vice President, Finance & CFO

Date: May 9, 2005

[pr002.gif]

NEWS RELEASE

PARAMOUNT ENERGY TRUST RELEASES

FIRST QUARTER 2005 FINANCIAL AND OPERATING RESULTS

Calgary, AB – May 9, 2005 - Paramount Energy Trust (“PET" or the “Trust”) is pleased to release its results for the first quarter of 2005. Significantly increased production, continued strong commodity prices and the full effects of the Trust’s 2004 acquisition activities contributed to another quarter of exceptional financial results. The above factors combined to increase cash flow from operations to $40.8 million for the three months ended March 31, 2005 from $25.9 million in the 2004 period, a 58 percent increase.

FIRST QUARTER HIGHLIGHTS

Production averaged 122.0 MMcf/d representing an increase of 37% from the first quarter of 2004 despite the additional shut-in of over 12 MMcf/d of sales gas production on July 1, 2004 related to the gas over bitumen decisions. Factoring in the deemed production volume related to the gas over bitumen financial solution, average daily production (actual and deemed) increased 47% to 145.4 MMcf/d from 98.8 MMcf/d in the first quarter of 2004.

PET’s monthly distributions to Unitholders were increased to $0.22 in January 2005 which resulted in aggregate distributions for the period exceeding cash flow by approximately $2.8 million. The increase in distributions was based on the gas over bitumen financial solution and its retroactive effect, as well as very strong winter gas prices. The Trust received more than $11 million at the end of 2004 related to gas over bitumen royalty adjustments from previous periods which were not factored into previous distributions. PET’s estimated pro forma payout ratio for the second half of 2005 is expected to be approximately 70 percent due to the highly accretive nature of the Northeast Alberta Acquisition.

Distributions payable for the quarter totaled $0.66 per Trust Unit representing $0.22 per Trust Unit paid on February 15, March 15, and April 15, 2005.

On March 23, 2005 PET announced that it had entered into an agreement to acquire natural gas producing properties in Northeast Alberta for $290 million, subject to closing adjustments (the “Northeast Alberta Acquisition”). The Northeast Alberta Acquisition is expected to close on or about May 17, 2005 with an effective date of January 1, 2005. The 100% natural gas assets being acquired are located in close proximity to the Trust’s Northeast Alberta Core Areas but well outside the defined boundaries of the Alberta Energy and Utilities Board (“AEUB”) gas over bitumen area of concern. The Northeast Alberta Acquisition will add 48 MMcf/d of gas production and 103.8 Bcf of proved plus probable reserves based on PET’s internal evaluation. Despite the effective date of January 1, 2005, no operational or financial information, except the payment of a deposit in the amount of $14.5 million, is included in the Trust’s first quarter 2005 financial or operating results. Instead, net cash flow from the operation of the Northeast Alberta Assets related to the period from the effective date until closing will be reflected as a downward adjustment to the acquisition price at closing. The Trust estimates the interim revenue adjustment will be approximately $20 million.

Concurrent with the announcement of the Northeast Alberta Acquisition, PET also entered into an agreement to sell on a bought deal basis, 9,500,000 Subscription Receipts at a price of $16.85 each for gross proceeds of approximately $160 million, and $100 million of 6.25% Debentures to a syndicate of underwriters. The offering closed as scheduled on April 26, 2005. Each Subscription Receipt represents the right to receive one Trust Unit on the closing of the Northeast Alberta Acquisition. The initial maturity date of the 6.25% Debentures is June 30, 2005, with an automatic extension to June 30, 2010 upon the closing of the Northeast Alberta Acquisition. The proceeds from the offering of Subscription Receipts have been deposited in escrow pending closing of the Northeast Alberta Acquisition. If the Northeast Alberta Acquisition closes on or before June 30, 2005, the net proceeds will be released to PET and used along with the proceeds of the Debentures, whose maturity date will automatically be extended to June 30, 2010, to pay part of the purchase price of the Northeast Alberta Acquisition. Closing of the Northeast Alberta Acquisition is expected to occur on or about May 17, 2005. Upon closing of the Acquisition, holders of record of the Subscription Receipts will then be entitled to receive a payment equivalent to the amount of the cash distribution, $0.22 per Subscription Receipt, in respect of income received by PET for the month of April 2005. If the Northeast Alberta Acquisition fails to close by June 30, 2005 or the Northeast Alberta Acquisition is terminated at an earlier time, the escrow agent will return the issue proceeds and the pro rata entitlement to interest thereon to holders of the Subscription Receipts and the Debentures. The Debentures would then mature on June 30, 2005.

The Trust successfully closed two consolidating acquisitions in the Ells/Legend and Wabasca areas of Northeast Alberta. These acquisitions currently produce a net 1.3 MMcf/d and also include a net 900 Mcf/d of deemed production shut-in or not producing as a result of the gas over bitumen issue.

PET closed the previously-announced strategic joint venture with a private junior exploration and production company covering 5% of the Trust’s extensive undeveloped land base. PET exchanged a 50% interest in selective undeveloped acreage for a 14% ownership interest in the private company and then farmed out the remaining 50% interest in the same lands to that company. This farm-out/joint venture will allow for immediate activity on lands with prospects outside PET’s risk profile while also providing upside exposure to the other corporate activities of the proven management team. A portion of the farm-in commitments were completed during the first quarter, with the remainder scheduled to be conducted during the summer months and early next winter as access permits.

PET successfully completed the execution of a $40 million winter capital program in Northeast Alberta which included the drilling of 37 gas wells and over 150 recompletions distributed throughout the Trust’s three core areas in the region. Approximately 18 MMcf/d of new production was brought onstream from the winter program by the end of the quarter.

In March 2005, PET participated in the start-up of a physical gas marketing limited partnership, Eagle Canada Limited Partnership. As partial consideration for the Trust’s indirect 5% interest, PET will make available for delivery at market prices an average of 30,000 gigajoules/d of natural gas over a five year term, to be marketed on PET’s behalf by the gas marketing limited partnership.

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

Annual General Meeting

Unitholders are cordially invited to attend the Trust’s Annual General Meeting scheduled for today, Monday May 9, 2005 at 3:00 pm at the Calgary Petroleum Club, Devonian Room, 319 Fifth Avenue S.W., Calgary, Alberta.

Conference Call and Webcast

PET will be presenting a live webcast of the presentation to Unitholders in attendance at the Annual General Meeting of Unitholders at approximately 3:15 p.m., Calgary time, Monday, May 9, 2005 to review this information. 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, Subscription Receipts related to PET’s recent equity offering are listed on the TSX under the symbol “PMT.R”. Further information with respect to PET can be found at its website at www.paramountenergy.com. The Toronto Stock Exchange has neither approved nor disapproved the information contained herein.

FOR ADDITIONAL INFORMATION, PLEASE CONTACT:

Paramount Energy Operating Corp., Administrator of Paramount Energy Trust

Suite 500, 630 – 4 Avenue SW Calgary, Alberta, Canada T2P 0J9

Telephone: 403 269-4400

Fax: 403 269-6336

Email: info@paramountenergy.com

Susan L. Riddell Rose

President and Chief Operating Officer

Cameron R. Sebastian

Vice President, Finance and CFO

Sue M. Showers

Investor Relations and Communications Advisor

Page 2

FINANCIAL AND OPERATING HIGHLIGHTS	Three Months Ended March 31
($CDN thousands, except volume and per Trust Unit amounts)	2005	2004 ⁽³⁾	% Change
FINANCIAL
Revenue before royalties	76,346	51,232	49
Cash flow ⁽¹⁾	40,801	25,857	58
Per Trust Unit ⁽²⁾	0.62	0.58	7
Net earnings ⁽³⁾	2,153	1,997	8
Per Trust Unit ⁽²⁾	0.03	0.04	(25)
Cash distributions	43,602	23,281	87
Per Trust Unit ⁽⁴⁾	0.66	0.52	27
Total assets	599,938	286,488	109
Net bank and other debt outstanding ⁽⁵⁾	239,926	97,208	147
Convertible debentures	34,289	-	-
Total net debt	274,215	97,208	182
Unitholder’s equity	233,148	146,494	59
Capital expenditures
Exploration and development	40,228	12,981	210
Acquisitions, net	26,798	32,954	(18)
Other	150	14	971
Net capital expenditures	67,176	45,949	47
TRUST UNITS OUTSTANDING (thousands)
End of period	66,294	44,799	48
Weighted average	65,849	44,731	47
Pro forma for April 2005 financing	75,349	n/a	n/a
Incentive Rights outstanding	1,303	1,251	4
Trust Units outstanding at May 6, 2005	66,404	n/a	n/a
OPERATING
Production
Total natural gas (Bcfe)	11.0	8.1	36
Daily average natural gas (MMcf/d)	122.0	88.8	37
Gas over bitumen deemed production (MMcf/d)	23.4	10.0	134
Average daily (actual and deemed - MMcf/d)	145.4	98.8	47
Per Trust Unit (cubic feet/d/Unit) ⁽²⁾	2.21	2.21	-
Average prices
Natural gas ($/Mcf), pre-hedging	6.59	6.32	4
Natural gas ($/Mcf), including hedging	6.95	6.34	10
LAND (thousands of net acres)
Undeveloped land holdings	766	348	120
DRILLING
Wells Drilled (gross)
Gas	34	13	162
Service	-	-	-
Dry	3	-	-
Total	37	13	185
Success Rate	92	100	(8)

⁽¹⁾

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

Page 3

⁽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 cash distribution date.

⁽⁵⁾

Net debt includes net working capital (deficiency).

CORPORATE

The first quarter of 2005 marked another significant milestone in the evolution of Paramount Energy Trust both in terms of its size and scale but also with respect to the sustainability of its business model. On March 23, 2005 PET entered into an agreement to acquire natural gas producing properties in Northeast Alberta for $290 million, subject to closing adjustments. The Northeast Alberta Acquisition is expected to close on or about May 17, 2005 with an effective date of January 1, 2005. The Trust’s first quarter capital expenditures include a deposit of $14.5 million with respect to the Northeast Alberta Acquisition and closing adjustments are expected to reduce the net purchase price by more than $20 million.

The 100% natural gas assets being acquired are located in the Teepee, Marten Hills, Cherpeta and Darwin areas of Northeast Alberta in close proximity to the Trust’s Northeast Alberta Core Areas but well outside the defined boundaries of the AEUB gas over bitumen area of concern. The assets are an excellent fit with PET’s existing operations and will be managed from the Trust’s Athabasca field office.

As a result of the Acquisition, the Trust’s current daily production will increase to over 170 MMcf/d and PET’s proved plus probable reserves will increase by 44% to 337 Bcf as at January 1, 2005. The Acquisition will result in an increase of approximately 19% to PET’s estimated cash flow per Trust Unit on a pro forma basis for the second half of 2005 and approximately 24% for 2006. In addition, the Acquisition is 22% accretive to current production per Unit and 26% accretive to proved plus probable reserves per Unit as at January 1, 2005.

Highlights of the Northeast Alberta acquisition include:

This highly accretive transaction will reduce PET’s projected 2005 payout ratio to approximately 79% of estimated cash flow which significantly enhances the sustainability of PET’s current level of monthly distributions of $0.22 per Trust Unit;

Current average daily production of approximately 48 MMcf/d (8,000 BOE/d; 100 percent natural gas);

103.8 Bcf (17.3 MMBOE) of proved plus probable reserves, as evaluated by the Trust’s internal engineers, as at January 1, 2005 (131.7 Bcf (22.0 MMBOE) of proved plus probable reserves as evaluated by the Vendor’s third party independent engineering consultants);

Proved reserves are 81% of PET’s estimated proved plus probable reserves and proved developed producing reserves are 100% of PET’s internal proved reserve estimate;

Favorable transaction metrics of $33,750 per flowing BOE of production at January 1, 2005 (48 MMcf/d) and $15.61 per proved plus probable BOE based on PET’s internal reserve estimates; excluding $20 million assigned to undeveloped land and seismic;

Approximately 412,000, net acres of undeveloped land at an average 80% working interest;

Average 2004 operating costs of $0.85 per Mcf enhance PET’s high field netbacks and reduce the Trust’s overall operating costs per Mcf by approximately 3%; and

Monthly cash flow from operations of approximately $6 million per month at current natural gas prices.

Other operational highlights include:

A licensed copy of a minimum of 4,627 km of seismic to assist the Trust in the ongoing identification and evaluation of the multi-zone upside potential associated with these assets;

High working interest of approximately 72%;

Operatorship in excess of 75%;

The Northeast Alberta Acquisition includes various working interests in 17 gas plants through which the acquired production is processed as well as numerous booster compressor stations;

The majority of the gas is uncontracted and therefore available for PET to market or hedge as opportunities in the forward market arise.

Subsequent to the end of the quarter, The Trust’s major Unitholder enrolled approximately 19 million Trust Units in PET’s Distribution Reinvestment Plan (“DRIP”) for the month of April 2005. This will result in more than $4 million per month in additional equity for the Trust and further reflects the alignment between the Trust and its Unitholders and confidence in the value opportunity presented by ownership of PET’s Units.

Page 4

OPERATIONS

Natural gas production for the first quarter of 2005 averaged 122.0 MMcf/d, a five percent decrease from the fourth quarter of 2004 related to natural production declines and typical seasonal downtime. Production in PET’s Northeast Alberta fields typically falls slightly during the winter months due to operational issues related to cold weather. With the onset of spring and the production additions from the Trust’s winter capital program onstream, production is now in excess of 130 MMcf/d. Factoring in the deemed production volume related to the gas over bitumen financial solution, daily production (actual and deemed) averaged 145.4 MMcf/d in the first quarter of 2005.

CAPITAL EXPENDITURES, DRILLING AND ACQUISITIONS

Exploration and Development

PET completed its very successful winter capital program in Northeast Alberta near the end of March. The Trust invested approximately $40 million in its winter-access properties with new drilling, completions and tie-ins, recompletion and facilities optimization work distributed throughout PET’s three core areas in the Northeast Alberta. The program included the drilling of 37 gross wells (30.8 net) which resulted in 34 gross (27.8 net) gas wells and an extensive recompletion program of more than 150 workovers. The expenditures resulted in approximately 18 MMcf/d of new production coming onstream by the end of the quarter. Production addition costs of approximately $13,500 per flowing BOE/d, including significant facilities investments that were directed primarily at reducing operating costs rather than adding production, were consistent with PET’s internal targets.

Facilities optimization projects included:

the installation of sales and booster compression in the Panny area;

the tie-in of additional stranded gas in the South Leismer area;

consolidation of facilities at Saleski for operating cost and fuel gas savings estimated at $800,000 per year; and

gas over bitumen infrastructure optimization and consolidation.

PET has now turned to planning its capital activities for the remainder of 2005 in the year-round access areas in its Southern Core Area. New drilling at Kirkpatrick and Sedalia, continued participation in the coal bed methane project at Craigmyle and infill drilling programs at Abbey and Unity are in the planning stages for execution during the remainder of the year.

Acquisitions

PET successfully closed the acquisition of an 11% interest in the Ells area and a further 17% interest in the Birch/Tar area, both situated in Northeast Alberta immediately east of the Trust’s Legend field. The effective date of the acquisition was September 1, 2004. These assets currently produce a net 900 Mcf/d. In addition, there is a net 900 Mcf/d of deemed production shut-in or not producing as a result of the gas over bitumen issue and the Trust also purchased the shut-in reserves and corresponding Crown royalty reductions from the date of shut-in of July 1, 2004. The Trust also acquired a consolidating interest in the Wabasca area of Northeast Alberta consisting of approximately 400 Mcf/d. Acquisition spending for the first quarter of 2005, including the $14.5 million deposit required for the Northeast Alberta Acquisition, totaled $26.8 million.

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. The Trust’s current net deemed production volume for purposes of the royalty adjustment is 23.7 MMcf/d. According to IL 2004-36, the deemed production volume will be reduced by 10% at the end of every year of shut-in.

During the three months ended March 31, 2005, the Trust received $4.8 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 March 31, 2005 to $16.0 million. The royalty adjustments are being excluded from earnings pending such future determination. Royalty adjustments although not included in earnings are recorded as a component of funds from operations and as such are considered distributable income.

The final hearing with respect to the AEUB’s bitumen conservation requirements is scheduled to begin on June 14, 2005. Parties wishing to contest the production status of an interval or intervals were required to file evidence with the

Page 5

AEUB by February 14, 2005 for the final hearing. PET filed detailed evidence supporting the resumption of production for six pools representing approximately 8.5 MMcf/d of shut-in production the Trust currently has shut-in pursuant to AEUB Orders. PET also reiterated to the AEUB its continued objection to all zones that have been shut-in as a result of the interim hearing, based on the new evidence that the Trust has submitted.

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

OUTLOOK

The Northeast Alberta Acquisition represents another significant step towards PET’s goal to establish a dominant position in Northeast Alberta shallow natural gas production. The combination of that acquisition, the Trust’s successful winter capital program and continued robust gas prices significantly enhance the sustainability of the Trust’s current level of distributions.

To lock in attractive economics on the Northeast Alberta Acquisition, PET significantly added to its hedging portfolio in mid to late March. PET currently has the following natural gas hedges in place:

Volumes at AECO
(Gigajoules/day)(“GJ/d”)	Price ($/GJ)	Term
10,000 GJ/d	$ 6.81	April 2005 – June 2005
55,000 GJ/d	$ 7.06	April 2005 – October 2005
5,000 GJ/d	$ 6.50 to 7.30	April 2005 – October 2005
15,000 GJ/d	$ 7.53	July 2005 – October 2005
60,000 GJ/d	$ 8.00	November 2005 – March 2006

2005 GUIDANCE AND SENSITIVITIES

Incorporating the Northeast Alberta Acquisition and current natural gas prices, PET herein provides updated guidance for its operating and financial performance for 2005.

		Annual 2005		July 1 to December 31, 2005
		Previous Guidance⁽¹⁾	New Guidance ⁽²⁾⁽⁴⁾	Previous Guidance⁽¹⁾	New Guidance ⁽²⁾⁽⁴⁾

Natural gas production	(MMcf/d)	120	148	118	160

Gas prices
AECO Monthly Index	($/GJ)	$7.10	$7.05	$7.75	$7.35
PET realized	($/Mcf)	$7.50	$7.50	$8.15	$7.75

Cash flow⁽³⁾	($ millions)	$205	$250	$113	$145
Cash flow per Unit	($/Unit/month)	$0.260	$0.278	$0.286	$0.315

Payout ratio		85%	79%	77%	70%

Ending debt to cash flow ratio	Times	1.0	0.9	0.9	0.9

Notes:

Previous guidance refers to that included in PET’s press release dated March 18, 2004.

The updated 2005 guidance reflects the results of the Northeast Alberta Acquisition. Cash flow from the January 1, 2005 effective date to closing, estimated at $20 million, will be recorded as a reduction in the purchase price.

Cash flow incorporates royalty adjustments in 2005 for gas over bitumen shut-in gas.

Includes forward gas prices as of May 4, 2005, PET hedging activity and physical forward sales and PET contracts but no future acquisitions.

Page 6

Below is a table that demonstrates the sensitivity of PET’s 2005 cash flow to operational changes and changes in the business environment:

		Impact on Cash Flow per Trust Unit ($/Unit)
	Change	Annual	Monthly
Business Environment
Price per Mcf of natural gas
(PET Avg.)	$ 0.25/Mcf	0.150	0.013
Operational
Gas production volume	5 MMcf/d	0.124	0.010
Operating costs	$ 0.10/Mcf	0.075	0.006
Cash G&A expenses	$ 0.10/Mcf	0.075	0.006

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

MANAGEMENT’S DISCUSSION AND ANALYSIS

The following is management’s discussion and analysis (“MD&A”) of PET’s operating and financial results for the three months ended March 31, 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 for the three months ended March 31, 2005 and 2004, together with accompanying notes.

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, PET’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 and compliance with environmental regulations, commodity prices, and the impact of the adoption of various Canadian Institute of Chartered Accounts 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 PET’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 entirely by this cautionary statement. We undertake no obligation to update our forward-looking statements except as required by law.

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

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

Page 7

HIGHLIGHTS

	Three Months Ended March 31
($Cdn millions, except per Unit and volume data)	2005	2004

Cash flow ⁽¹⁾	$ 40.8	$ 25.9
Cash flow per Unit	$ 0.62	$ 0.58
Net earnings	$ 2.2	$ 2.0
Net earnings per Unit	$ 0.03	$ 0.04
Distributions	$ 43.6	$ 23.3
Distributions per Unit	$ 0.66	$ 0.52
Payout ratio (%)	106.9%	90.0%
Production (MMcf/d) ⁽²⁾
Daily average production	122.0	88.8
Gas over bitumen deemed production	23.4	10.0
Total average daily (actual and deemed)	145.4	98.8

⁽¹⁾

Before changes in non-cash working capital, includes gas over bitumen royalty adjustments.

⁽²⁾

Production amounts are based on company interest before royalties.

Natural gas revenue increased 49 percent to $76.3 million for the three months ended March 31, 2005, compared to $51.2 million for the three months ended March 31, 2004. Increased production volumes resulted in a $20.1 million increase in revenue while higher natural gas prices increased revenue by $5.0 million.

Realized natural gas prices increased by 10 percent for the three months ended March 31, 2005 to $6.95 per Mcf from $6.34 per Mcf in 2004. PET’s blend of aggregator contracts, forward sales and AECO Monthly Index and daily spot market sales resulted in a realized natural gas price of approximately 104 percent of the AECO average Monthly Index for the first three months of 2005 versus 96 percent for the first three months of 2004. Average AECO Monthly Index prices increased 1 percent from $6.61 per Mcf for the three months ended March 31, 2004 to $6.69 per Mcf for the three months ended March 31, 2005. The increase in PET’s gas prices exceeded that for the reference price as the Trust fixed the price on a portion of its production at prices above spot market prices during the first three months of 2005. Before hedging, PET’s realized natural gas price was $6.59 for the three months ended March 31, 2005 compared to $6.32 for the same period in 2004.

For the three months ended March 31, 2005, PET’s average royalty rate was 19.2 percent compared to 18.9 percent for the three months ended March 31, 2004. Royalty rates in Alberta are calculated on a sliding scale sensitive to prices and well production rates. Consequently, the increase in the average royalty rate is consistent with the increase in the reference prices in 2005 compared to 2004.

Total production costs increased $5.9 million in the three months ended March 31, 2005 compared to the same period in 2004. Unit production costs were $1.51 per Mcf in the three months ended March 31, 2005 compared to $1.32 per Mcf for the same period in 2004. Unit production costs have increased in 2005 due to fixed operated costs related to the operation of additional plants and reduced throughput volumes in some of the plants due to the gas over bitumen shut-in of wells July 1, 2004. PET’s operating costs are typically highest during the winter months when access to its northern fields is available for preventative maintenance programs and the annual restocking of consumables. Average operating costs are expected to decrease below $1.00 for the remainder of the year.

The higher commodity prices combined with higher production volumes, offset by higher royalties and higher production costs resulted in a $13.0 million increase in operating income from $29.1 million for the three months ended March 31, 2004 to $42.1 million for the three months ended March 31, 2005.

($Cdn millions)
Production increase	$ 20.1
Price increase	5.0
Royalty increase	(5.4)
Transportation cost increase	(0.8)
Operating cost increase	(5.9)
Increase in net operating income	$ 13.0

Page 8

	Three Months Ended March 31,
Netbacks ($/Mcf)	2005	2004
Gross revenue	$ 6.95	$ 6.34
Royalties	(1.33)	(1.14)
Operating costs	(1.51)	(1.32)
Transportation costs	(0.27)	(0.28)
Operating netback	3.84	3.60
General and administrative ⁽¹⁾	(0.23)	(0.22)
Interest ⁽²⁾	(0.21)	(0.14)
Capital taxes	(0.01)	-
Exploration expenses	(0.10)	(0.04)
Gas over bitumen royalty adjustments	0.43	-
Cash flow netback	$ 3.72	$ 3.20

⁽¹⁾

Excluding non-cash general and administrative expenses.

⁽²⁾

Includes interest on bank debt and interest on Convertible Debentures.

General and administrative expenses were $3.0 million in the first three months of 2005 compared to $2.5 million in 2004. Expenses in 2005 include $0.6 million related to the preparation of technical evidence for the upcoming gas over bitumen final hearing. In addition, the scale of PET’s operation has increased significantly with the acquisitions consummated during 2004. Cash general and administrative expenses on a unit-of-production basis were $0.23 per Mcf in 2005 and $0.22 per Mcf in 2004, including $0.06 of expenses related to the gas over bitumen issue in each period.

For the first quarter of 2005 $0.4 million related to Incentive Right compensation costs were included in general and administrative expenses compared to $0.7 million for the same period in 2004.

Interest expense on bank debt was $1.6 million in the first three months of 2005 compared to $1.1 million in 2004. Interest expense has increased due to the debt financing of portions of the Cavell Energy Corp. and Athabasca Assets acquisitions in second half of 2004, in addition to increased interest rates.

The above factors combined to increase cash flow from operations to $40.8 million for the three months ended March 31, 2005 from $25.9 million in the 2004 period, a 58 percent increase.

Depletion, depreciation and accretion expense increased from $23.0 million in the first quarter of 2004 to $35.0 million in 2005 due principally to increased production volumes. PET’s depletion rate also increased from $2.84 per Mcf in the three months ended March 31, 2004 to $3.18 per Mcf in 2005.

The Trust reported net earnings of $2.2 million in the first quarter of 2005 compared to net earnings of $2.0 million in the 2004 period.

QUARTERLY INFORMATION

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

Natural gas revenues before royalties	$ 76,346	$ 79,665	$ 59,156	$ 49,904
Net earnings (loss)	$ 2,153	$ (29,685)	$ 4,781	$ 5,016
Net earnings (loss) per Unit - basic	$ 0.03	$ (0.46)	$ 0.08	$ 0.11
- diluted	$ 0.03	$ (0.46)	$ 0.08	$ 0.11

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

Natural gas revenues before royalties	$ 51,232	$ 43,022	$ 48,812	$ 53,643
Net earnings (loss)	$ 1,997	$ (2,812)	$ 12,316	$ 16,984
Net earnings (loss) per Unit - basic	$ 0.04	$ (0.06)	$ 0.27	$ 0.41
- diluted	$ 0.04	$ (0.06)	$ 0.27	$ 0.41

Page 9

CAPITAL EXPENDITURES

	Three Months Ended March 31,
($ thousands except where noted)	2005	2004
Exploration and development expenditures	$ 40,228	$ 12,981
Acquisitions	26,798	32,954
Asset retirement obligations	7,236	1,706
Other	150	14
Total capital expenditures and net acquisitions	$ 74,412	$ 47,655

For the three months ended March 31, 2005, exploration and development expenditures totalled $40.2 million, compared to $13.0 million for the same period in 2004. This increase was due to PET’s very successful winter capital program in Northeast Alberta. The Trust invested approximately $40 million in its winter-access properties with new drilling, completions and tie-ins, recompletions and facilities optimization work distributed throughout PET’s three core areas in Northeast Alberta.

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 $220 million. The facility consists of a demand loan of $210 million and a working capital facility of $10 million. Bank debt was $214.1 million at March 31, 2005. The Trust’s winter capital expenditure program as well as the deposit paid on the Northeast Alberta Acquisition resulted in a working capital deficiency of $25.9 million at March 31, 2005 which is expected to be eliminated in the coming months. 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 after acquired property of the Trust as well as unconditional full liability guarantees from all subsidiaries in respect of amounts borrowed under the facility.

In addition, $34.3 million remained outstanding under the Trust’s 8% convertible debentures at March 31, 2005. Approximately $4.1 million of debentures were converted to Trust Units at a price of $14.20 per Trust Unit during the first quarter of 2005.

Cumulative distributions for the first three months of 2005 totaled $0.66 per Trust Unit. A distribution of $0.22 per Unit for the month of April, payable on May 16, 2005 was announced on April 20, 2005.

RISK AND UNCERTAINTIES

PET’s operations are affected by a number of underlying risks, both internal and external to the Trust. These risks are similar to those affecting others in both the conventional oil and gas royalty trust sector and the conventional oil and gas producers sector. The Trust’s financial position, results of operations, and cash available for distribution to Unitholders are directly impacted by these factors.

Reserve Estimates

The reserve and recovery information contained in PET’s independent reserve evaluation is only an estimate. The actual production and ultimate reserves from the properties may be greater or less than the estimates prepared by the independent reserve evaluator.

Cyclical and Seasonal Impact on Industry

The Trust's operational results and financial condition will be dependent on the prices received for natural gas production. Natural gas prices have fluctuated widely during recent years and are determined by supply and demand factors including weather and general economic conditions, as well as conditions in other oil and natural gas producing regions.

Operational Matters

The operation of oil and gas wells involves a number of operating and natural hazards that may result in blowouts, environmental damage and other unexpected or dangerous conditions resulting in damages to operating subsidiaries of the Trust and possible liability to third parties.

Acquisitions

The price paid for reserve acquisitions is based on engineering and economic estimates of the reserves made by independent engineers modified to reflect the technical views of management. These assessments include a number of material assumptions regarding such factors as recoverability and marketability of oil and natural gas, future prices of oil and natural gas, and operating costs, future capital expenditures and royalties and other government levies which

Page 10

will be imposed over the producing life of the reserves. Many of these factors are subject to change and are beyond the control of the operators of the working interests, management and the Trust.

Depletion of Reserves

The Trust has certain unique attributes which differentiate it from other oil and gas industry participants. Distributions, absent commodity price increases or cost effective acquisition and development activities, will decline over time in a manner consistent with declining production from typical oil and natural gas reserves. PET will not be reinvesting cash flow in the same manner as other industry participants as one of the main objectives of the Trust is to maximize long-term distributions. Accordingly, absent capital injections, PET’s initial production levels and reserves will decline.

Additional Financing

In the normal course of making capital investments to maintain and expand the oil and natural gas reserves of the Trust, additional Trust Units are issued from treasury which may result in a decline in production per Trust Unit and reserves per Trust Unit. Conversely, to the extent that external sources of capital, including the issuance of additional Trust Units, become limited or unavailable, the Trust’s ability to make the necessary capital investments to maintain or expand its oil and natural gas reserves will be impaired.

Competitive Conditions

The Trust is a member of the petroleum industry which is highly competitive at all levels. The Trust competes with other companies and other energy trusts for all of its business inputs including exploitation and development prospects, access to commodity markets, property and corporate acquisitions, and available capital.

Government Regulation Risk

PET operates in a highly regulated industry and it is possible any changes in such regulation or adverse regulatory decisions could affect our production which could reduce distributions to Unitholders. Additional details with respect to the gas over bitumen regulatory issue are described elsewhere in this MD&A.

Commodity Price, Foreign Exchange and Interest Rate Risk

The two most important factors affecting the level of cash distributions available to Unitholders are the level of production achieved by PET, and the price received for its products. These prices are influenced in varying degrees by factors outside the Trust’s control. Some of these factors include:

economic conditions which influence the demand for natural gas and the level of interest rates set by the governments of Canada and the U.S.;

weather conditions that influence the demand for natural gas;

transportation availability and costs; and

price differentials among markets based on transportation costs to major markets.

Nature of Trust Units

The Trust Units do not represent a traditional investment in the oil and natural gas sector and should not be viewed by investors as shares in a corporation. The Trust Units represent a fractional interest in the Trust. As holders of Trust Units, Unitholders will not have the statutory rights normally associated with ownership of shares of a corporation.

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.

The 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 (loss) in the period incurred. The application of

Page 11

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 exploratory costs related to drilling activity 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, 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, as well as estimates for petroleum and 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.

Page 12

Paramount Energy Trust

Consolidated Balance Sheets

As at	March 31, 2005	December 31, 2004
($ thousands)	(unaudited)	(audited)
		(restated, note 2)
Assets
Current assets
Accounts receivable	$ 33,940	$ 32,128
Investments (note 3)	5,243	-
Property, plant and equipment (notes 4 and 5)	531,057	494,885
Goodwill	29,698	29,698
	$ 599,938	$ 556,711

Liabilities
Current liabilities
Accounts payable and accrued liabilities	$ 45,215	$ 21,674
Distributions payable	14,585	13,065
Bank and other debt (note 6)	214,066	171,698
	273,866	206,437

Gas over bitumen royalty adjustments (note 14)	15,960	11,200
Asset retirement obligations (note 10)	42,106	34,116
Convertible debentures (note 7)	34,289	38,419
Future income taxes (note 13)	569	2,088

Unitholders’ equity
Unitholders’ capital (note 8)	507,339	495,695
Contributed surplus (note 2)	2,963	4,461
Equity adjustments	(16,172)	(16,172)
Accumulated earnings	27,136	24,983
Accumulated distributions	(288,118)	(244,516)
	233,148	264,451
	$ 599,938	$ 556,711
See accompanying notes Basis of presentation: note 1 Contingency: note 14 Subsequent events: note 15

Page 13

Paramount Energy Trust

Consolidated Statements of Earnings and Accumulated Earnings

	Three Months
	Ended March 31,
	2005	2004
($ thousands except per unit amounts)	(unaudited)	(unaudited)
		(restated, note 2)

Revenue
Natural gas	$ 76,346	$ 51,232
Royalties	(14,639)	(9,239)
	61,707	41,993

Expenses
Operating	16,604	10,665
Transportation costs	2,978	2,224
Exploration expenses	1,046	559
General and administrative (notes 2 and 9)	2,348	1,915
Gas over bitumen costs (note 14)	644	541
Interest	1,638	1,128
Interest on convertible debentures	667	-
Depletion, depreciation and accretion	34,994	22,964
	60,919	39,996
Earnings before income taxes	788	1,997
Future income tax reduction (note 13)	1,519	-
Capital taxes	(154)	-
	1,365	-
Net earnings	2,153	1,997

Accumulated earnings net of distributions at beginning of period, as previously reported	(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	(219,533)	(80,327)
Distributions paid or payable	(43,602)	(23,281)
Accumulated earnings net of distributions at end of period	$(260,982)	$ (101,611)

Earnings per Trust Unit (note 8(c))
Basic and diluted	$ 0.03	$ 0.04

Distributions per Trust Unit	$ 0.66	$ 0.52

See accompanying notes

Page 14

Paramount Energy Trust

Consolidated Statements of Cash Flows

	Three Months
	Ended March 31,
	2005	2004
($ thousands)	(unaudited)	(unaudited)
		(restated, note 2)

Cash provided by (used for)
Operating activities
Net earnings	$ 2,153	$ 1,997
Items not involving cash
Gas over bitumen royalty adjustments	4,759	-
Depletion, depreciation and accretion	34,994	22,964
Trust Unit compensation	414	680
Future income tax reduction	(1,519)	-
Items not associated with operations
Exploration expenses	-	216
Funds from operations	40,801	25,857
Change in non-cash working capital	159	5,460
	40,960	31,317

Financing activities
Issue of Trust Units	2,534	571
Distributions to Unitholders	(40,917)	(23,281)
Change in bank and other debt	42,368	31,426
Change in non-cash working capital	393	(1,760)
	4,378	6,956

	$ 45,338	$ 38,273


Investing activities
Exploration expenses	$ -	$ (216)
Acquisition of investments (note 3)	(1,243)	-
Acquisition of properties and corporate assets	(26,948)	(32,954)
Change in non-cash working capital and asset retirement obligation	23,081	7,892
Exploration and development expenditures	(40,228)	(12,995)
	$ (45,338)	$ (38,273)

Interest paid	$ 3,771	$ 885
Taxes paid	$ 35	$ -

See accompanying notes

Page 15

PARAMOUNT ENERGY TRUST

Notes to Consolidated Financial Statements

(dollar amounts in $Cdn except as noted)

BASIS OF PRESENTATION AND ACCOUNTING POLICIES

These interim consolidated financial statements of Paramount Energy Trust (“PET”) have been prepared by management in accordance with Canadian generally accepted accounting principles following the same accounting principles and methods of computation as the consolidated financial statements for the year ended December 31, 2004 except as described 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.

CHANGE IN ACCOUNTING POLICY

Trust Unit-based compensation

On January 1, 2005 the Trust retroactively applied the fair value based method of accounting for Incentive 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, rather 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 deemed a fair value calculation to be 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 retained earnings and an increase in contributed surplus for 2003 of $0.2 million. Further, reported Trust Unit compensation expense for the three months ended March 31, 2004 decreased by $0.3 million to $0.7 million with a corresponding increase in contributed surplus. The change in accounting policy had no effect on reported earnings per Trust Unit.

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 share capital on exercise of Incentive Rights	(807)
Balance, as at December 31, 2004, as restated	4,461
Trust Unit-based compensation expense	414
Transfer to share capital on exercise of Incentive Rights	(1,912)
Balance, as at March 31, 2005	$ 2,963

INVESTMENTS

Investments include $4.0 million related to PET’s 14 percent interest in Sebring Energy Inc. and $1.2 million related to the Trust’s 5 percent interest in the Eagle Canada natural gas Limited Partnership.

ACQUISITIONS AND DISPOSITIONS

During the three months ended March 31, 2005 PET acquired producing natural gas properties in northeast Alberta for $12.3 million in addition to the $14.5 million deposit paid on the Northeast Alberta Acquisition (note 15). These acquisitions also resulted in an increase of $0.5 million in PET’s estimated future asset retirement obligations (note 10) and were financed from existing credit facilities.

Page 16

PROPERTY, PLANT AND EQUIPMENT

	March 31, 2005	December 31, 2004

Petroleum and natural gas properties	$ 1,017,376	$ 954,351
Asset retirement costs	38,024	30,787
Corporate assets	14,904	14,754
	1,070,304	999,892
Accumulated depletion and depreciation	(539,247)	(505,007)
	$ 531,057	$ 494,885

Property, plant and equipment costs at March 31, 2005 included $68.5 million (March 31, 2004 - $57.2 million) currently not subject to depletion.

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 $220 million. The Credit Facility consists of a demand loan of $210 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 after 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 average interest rate at March 31, 2005 was 3.80%.

CONVERTIBLE DEBENTURES

The Trust’s 8.0% convertible unsecured subordinated debentures (the “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 Convertible Debentures are convertible at the option of the holder into Trust Units at any time prior to September 30, 2009 at a conversion price of $14.20 per unit. The Convertible Debentures are not redeemable by PET on or before September 30, 2007 but may be redeemed in whole or in part at the option of PET at a price of $1,050 per Convertible Debenture after September 30, 2007 and prior to September 30, 2008 and at a price of $1,025 per Convertible Debenture thereafter until their maturity. Redemption and conversions entitle the holder to accrued and unpaid interest to and including the effective date thereof.

At the option of PET, the repayment of the principal amount of the Convertible Debentures may be settled in Trust Units. The number of Trust Units to be issued upon redemption by PET will be calculated by dividing the principal by 95% of the weighted average trading price. The interest payable may also be settled with the issuance and sale of sufficient Trust Units to satisfy the interest obligation. At March 31, 2005, the fair market value of the Convertible Debentures was $41.5 million.

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.

Page 17

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	$ 260,018,741
Units issued pursuant to Unit offerings	12,295,547	146,675,005
Units issued pursuant to corporate acquisition	6,931,633	78,674,035
Units issued pursuant to Unit Incentive Plan	153,875	1,371,737
Units issued pursuant to Distribution Reinvestment Plan	632,829	8,184,906
Units issued pursuant to conversion of Debentures	674,711	9,580,889
Issue costs on Convertible Debentures converted to Trust Units	-	(383,240)
Trust Unit issue costs	-	(8,427,210)
Balance, December 31, 2004	65,326,971	495,694,863
Units issued pursuant to Unit Incentive Plan	361,375	2,631,277
Units issued pursuant to Distribution Reinvestment Plan	314,445	5,058,944
Units issued pursuant to conversion of Debentures	290,835	4,129,829
Trust Unit issue costs	-	(175,609)
Balance, March 31, 2005	66,293,626	$ 507,339,304

Per Unit Information

Basic earnings per Unit were calculated using the weighted average number of Trust Units outstanding during the three month period ended March 31, 2005 of 65,849,320, (2004 – 44,730,516). The Trust uses the treasury stock method where only “in the money” dilutive instruments impact the diluted calculations. In computing diluted earnings from operations per Unit 521,264 Units were added to the weighted average number of Trust Units outstanding during the three month period ended March 31, 2005 (2004 – 603,356) for the dilutive effect of Incentive Rights.

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, which amount per Trust Unit will be the lesser of 90% 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, with the interest to 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.

UNIT INCENTIVE PLAN

At March 31, 2005 PET had granted 1,302,875 Incentive Rights to purchase PET Trust Units to directors, officers and employees of the administrator of PET under its Unit Incentive Plan.

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

At March 31, 2005 a total of 3,963,838 units had been reserved under the Unit Incentive Plan. As at March 31, 2005 12,500 Incentive Rights granted under the Unit Incentive Plan had vested but were unexercised, 100,000 as of March 31, 2004.

Incentive Rights
	Average grant price	Incentive Rights
Balance, December 31, 2004	$ 8.41	1,612,750
Granted	16.44	91,500
Exercised	5.38	(361,375)
Cancelled	12.25	(40,000)
Balance, March 31, 2005	$ 9.70	1,302,875
Incentive Rights exercisable, end of period	$ 11.12	12,500

The following summarizes information about Incentive Rights outstanding at March 31, 2005:

Range of Exercise Prices	Number outstanding at March 31, 2005	Weighted average contractual life (years)	Weighted average exercise price/ Right	Number exercisable at March 31, 2005	Weighted average exercise price/Right
$1.05	482,750	3	$ 1.05	-	-
$8.84-$8.97	147,500	4	8.91	12,500	$ 8.91
$9.65-$14.63	581,125	5	10.91	-	-
$15.69-$16.84	91,500	5	16.11	-	-
Total	1,302,875	4	$ 7.39	12,500	$ 8.91

The Trust recorded compensation expense of $0.4 million for the three month period ended March 31, 2005 ($0.7 million in 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 March 31, 2005:

	2005
Expected annual Right’s exercise price reduction	$ 1.48
Expected volatility	55.0%
Risk-free interest rate	3.78%
Expected life of Rights (years)	5.0
Expected forfeitures	-

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 $42.1 million as at March 31, 2005 based on total future liability of $90.0 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:

	March 31, 2005	December 31, 2004
Obligation, beginning of period	$ 34,116	$ 21,701
Increase in liabilities during the period	7,236	10,325
Settlement of liabilities during the period	-	-
Accretion expense	754	2,090
	$ 42,106	$ 34,116

11.

FINANCIAL INSTRUMENTS

Financial instruments

The Trust’s financial instruments included in the consolidated balance sheet consist of accounts receivable, accounts payable and accrued liabilities, distributions payable and bank and other debt. The fair value of these items approximated their carrying amount at March 31, 2005 and December 31, 2004 due to their short-term nature, except for Convertible Debentures, which had a fair market value at March 31, 2005 of $41.5 million.

Page 18

Natural gas commodity price hedges

At March 31, 2005, the Trust had entered into financial forward gas sales arrangements as follows:

Type	Volume	Term	Fixed ($/GJ)	Floor ($/GJ)	Ceiling ($/GJ)

AECO fixed price	10,000 GJ/d	Apr 05 - June 05	$6.81	-	-
AECO collar	5,000 GJ/d	Apr 05 - Oct 05	-	$6.50	$7.30
AECO fixed price	55,000 GJ/d	Apr 05 – Oct 05	$7.06	-	-
AECO fixed price	15,000 GJ/d	July 05 – Oct 05	$7.53	-	-
AECO fixed price	60,000 GJ/d	Nov 05 - Mar 06	$8.00	-	-

Had these contracts been settled on March 31, 2005, using prices in effect at that time, the mark-to-market settlement payment by PET would have totaled $13.0 million.

12.

COMMITMENTS

PET has committed to supply an average of 30 MMcf/d of physical natural gas deliveries for a five year period commencing March 1, 2005.

13.

INCOME TAXES

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

	Three Months Ended
	March 31, 2005	March 31, 2004
Earnings before income taxes	$ 788	$ 1,997
Less non-taxable earnings of the Trust	(4,833)	(1,997)
Loss subject to tax	(4,045)	-
Combined federal and provincial tax rate	40.15%	-
Computed income tax reduction	(1,624)	-
Increase (decrease) in income taxes resulting from:
Non-deductible Crown charges	123	-
Resource allowance	(104)	-
Capital taxes	154	-
Change in tax rate	86	-
Future income tax reduction	$ (1,365)	$ -

The components of the Trust’s subsidiaries’ future income tax liability are as follows:

	March 31, 2005	December 31, 2004
Future income taxes:
Property, plant and equipment	$ 9,559	$ 11,865
Asset retirement obligations	(1,571)	(1,450)
Non-capital losses	(7,881)	(8,048)
Other	462	(279)
	$ 569	$ 2,088

14.

GAS OVER BITUMEN ISSUE

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

Following the completion of a Regional Geological Study by the AEUB and an interim hearing held in March 2004, the AEUB ordered the shut-in, effective July 1, 2004, of Wabiskaw-McMurray natural gas production in northeast Alberta totaling approximately 123 MMcf/d. PET currently has approximately 17.4 MMcf/d of sales gas shut-in pursuant to AEUB order. During the three months ended March 31, 2005, the Trust incurred $0.6 million in legal and consulting expenditures directly related to the gas over bitumen issue (2004 - $0.5 million).

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 March 31, 2005 PET had recorded $16.0 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.

15.

SUBSEQUENT EVENTS

On March 23, 2005, the Trust announced that it had entered into an agreement to purchase certain petroleum and natural gas properties in northeast Alberta (the “Acquisition”) for an aggregate purchase price of approximately $290.0 million, prior to any purchase price adjustments. The Acquisition is anticipated to be completed on or about May 17, 2005. A $14.5 million deposit to the vendor is included in property, plant and equipment as at March 31, 2005.

On March 23, 2005, the Trust also announced that in connection with the Acquisition it had entered into an agreement with a syndicate of underwriters to issue 9.5 million subscription receipts (the “Subscription Receipts”) each representing the right to receive one Trust Unit at $16.85 per Subscription Receipt for gross proceeds of approximately $160.0 million and $100.0 million of 6.25% Convertible Extendible Unsecured Subordinated Debentures (the “6.25% Debentures”). The Trust’s offering of Subscription Receipts and 6.25% Debentures closed on April 26, 2005. Each Subscription Receipt represents the right to receive one Trust Unit upon the closing of the Acquisition. The proceeds from the offering of Subscription Receipts have been deposited in escrow pending closing of the Acquisition. If the Acquisition closes on or before June 30, 2005, the net proceeds will be released to PET and used along with the proceeds of the 6.25% Debentures, whose maturity date will automatically be extended to June 30, 2010, to pay part of the purchase price of the Acquisition. If the Acquisition fails to close by June 30, 2005 or the Acquisition is terminated at an earlier time, the escrow agent will return the issue proceeds and the pro rata entitlement to interest thereon to holders of the Subscription Receipts and the Debentures. The debentures would then mature on June 30, 2005.

Page 19