SECURITIES AND EXCHANGE COMMISSION

FORM 6-K

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

For the period February 24, 2004 to March 2, 2004

PENGROWTH ENERGY TRUST

Petro-Canada Centre – East Tower
2900, 111 – 5^th Avenue S.W.
Calgary, Alberta T2P 3Y6 Canada
(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.]

     [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 Security Exchange Act of 1934.

     [If “Yes” is marked, indicate below the file number assigned to the registrant in connection with Rule 12g3-2(b): __________]

DOCUMENTS FURNISHED HEREUNDER:

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.

NEWS RELEASE

PENGROWTH ENERGY TRUST ANNOUNCES FISCAL 2003 RESULTS AND YEAR END RESERVES

(Calgary, March 1, 2004) /CNW/ - Pengrowth Corporation, administrator of Pengrowth Energy Trust, announced today results for the year ended December 31, 2003.

FINANCIAL AND OPERATING HIGHLIGHTS

The following discussion and analysis of financial results should be read in conjunction with the unaudited consolidated financial statements for the year ended December 31, 2003 and is based on information available to February 29, 2004.

Note Regarding Forward-Looking Statements

This discussion and analysis contains forward-looking statements. These statements relate to future events or our future performance. In some cases, you can identify forward-looking statements by terminology such as “may”, “will”, “should”, “expect”, “plan”, “anticipate”, “believe”, “estimate”, “predict”, “potential”, “continue”, or the negative of these terms or other comparable terminology. These statements are only predictions. A number of factors may cause actual results to vary materially from these estimates. Actual events or results may differ materially. In addition, this discussion contains forward-looking statements attributed to third party industry sources. Readers should not place undue reliance on these forward-looking statements.

Conversion and currency

When converting natural gas to equivalent barrels of oil within this discussion, Pengrowth has adopted the international standard of 6 thousand cubic feet (mcf) to one barrel of oil equivalent (boe). All amounts are stated in Canadian dollars unless otherwise specified.

YEAR 2003 OVERVIEW

Record high commodity prices in 2003, partially offset by a decline in the U.S. dollar relative to the Canadian dollar, and increased production from the acquisition of producing properties in British Columbia in the fourth quarter of 2002, contributed to the strong performance by Pengrowth Energy Trust in 2003.

Highlights

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RESULTS OF OPERATIONS

Production

Average daily production increased 12 percent to 49,033 boe per day in 2003 compared to 43,785 boe per day in 2002. This increase is attributable mainly to the acquisition of Calpine Canada’s British Columbia properties on October 1, 2002, and development activities at some of Pengrowth’s other properties which partially offset normal production declines. 2003 fourth quarter production of 47,653 boepd was 9 percent lower than 2002 fourth quarter production of 52,253 boepd, reflecting the production decline over this period, offset in part by development activities and minor acquisition volumes. Production from the SOEP Alma field which came onstream at the end of November 2003, and incremental gas volumes from new wells drilled at Cessford and Dunvegan near year-end 2003 should have a positive impact on first quarter 2004 production. At this time, Pengrowth is forecasting average 2004 production of approximately 44,000 to 45,000 boepd from our existing properties.

Pricing and Commodity Price Hedging

The increase in U.S. based prices for North American crude oil and natural gas were partially offset by the negative impact of the rising Canadian dollar relative to the U.S. dollar. Pengrowth’s average realized commodity price for 2003 was the highest for any year since inception of the Trust.

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Pengrowth’s average crude oil price increased 7 percent in 2003 to $40.64 per barrel compared to $38.06 per barrel in 2002. Although the 2003 average WTI benchmark crude price increased 19 percent to $31.02 per barrel in 2003, much of this increase was offset by the decline in the U.S. dollar relative to the Canadian dollar.

In 2003 Pengrowth had 10,838 bbls per day, or 46 percent of crude oil production hedged at an average price of Cdn$41.41 per bbl. Pengrowth’s hedging program resulted in a total hedging loss on crude oil for the year of $7.8 million or $0.92 per bbl, compared to a loss of $6.1 million or $0.83 per bbl in 2002.

Pengrowth’s average natural gas price increased 61 percent from $3.85 per mcf in 2002 to $6.21 per mcf in 2003. In comparison the average AECO and NYMEX benchmark gas prices increased 65 percent and 67 percent respectively.

Pengrowth sold a total of 30.4 mmcf per day or approximately 26 percent of 2003 natural gas production under fixed price or financial swap contracts, at an average price of $6.60 per mcf and realized a net hedging loss of $16.0 million, or $0.37 per mcf in 2003, compared to a net loss of $1.8 million or $0.04 per mcf in 2002.

Pengrowth’s average price for natural gas liquids (“NGLs”) increased 26 percent to $35.46 in 2003 compared to $28.11 in 2002. Approximately one third of Pengrowth’s NGL production is condensate and pentane for which market prices are impacted more by the price of crude, while prices for propane, butane and ethane, which comprise the balance of Pengrowth’s NGL’s, track more closely with natural gas prices.

Oil and Gas Sales

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As a result of the 12 percent increase in production volumes, and the 26 percent increase in the average realized price per boe, as discussed above, Pengrowth’s total oil and gas sales reported in 2003 increased by 42 percent to $682.8 million. The following table illustrates in detail the effect of changes in prices and volumes on the components of oil and gas sales.

Royalties

Crown royalties, net of incentives and freehold royalties and mineral taxes increased to $114.9 million in 2003 from $80.6 million in 2002. Royalties as a percentage of oil and gas sales were consistent with 2002 at 17 percent. Although the effective royalty rate was somewhat higher for most properties in 2003 due to higher commodity prices, particularly natural gas, this increase was offset by increased injection credits at Judy Creek as a result of higher miscible flood injection costs.

Operating Expenses

Operating expenses increased to $149.0 million in 2003 compared to $129.8 million in 2002, mainly as a result of the B.C. properties acquired in the fourth quarter of 2002, offset to some extent by a reduction of SOEP processing fees, following the acquisition of an interest in the facilities downstream of the Thebaud Central Platform in May 2003. Operating costs per boe increased 3 percent to $8.33 per boe compared to $8.12 per boe in 2002. Higher electricity rates in 2003, an increase in CO2 costs at Weyburn, general cost increases in the industry, and production declines contributed to higher operating costs per boe in 2003, despite cost savings on processing fees of approximately $9.5 million realized as a result of the purchase of the Sable on-shore facilities. 2003 fourth quarter operating costs were $3.0 million lower than the fourth quarter of 2002, due to the reduction of SOEP processing fees in 2003 and some additional costs incurred in the last quarter of 2002. Fourth quarter 2003 operating expenses were $3.2 million higher than the third quarter of 2003, due to a number of factors including additional well workover costs on operated properties, prior period adjustments billed by other operators on non-operated properties, and lower casinghead revenues (which is netted against operating expenses at Judy Creek).

At this time, based on our current property portfolio, Pengrowth’s total operating costs are expected to decline by approximately $10 to $15 million in 2004. This reduction is anticipated as a result of decreased processing fees at SOEP due to the purchase of the SOEP off-shore facilities at the end of December 2003, and the SOEP on-shore facilities in May 2003, offset in part by higher costs at some of our other properties and general cost increases. If we continue to see strong market prices for commodities, there is likely to be continued upward pressure on operating costs, due to factors including increased demand for skilled industry workers as companies expand exploration and development projects, higher fuel costs and higher electricity rates. In order to help mitigate the risk of higher electricity rates, Pengrowth has fixed the price on approximately 20 percent of our estimated operated properties electricity requirements for 2004.

Amortization of Injectants for Miscible Floods

The cost of injectants (primarily ethane and methane) purchased for injection in miscible flood

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programs is amortized over the period of expected future economic benefit, which is estimated at 30 months. In 2003, the total cost of purchased injectants increased to $23.0 million in 2003 from $15.1 million in 2002. In 2003, $32.5 million was amortized and deducted from distributable cash (2002 – $44.3 million). As at December 31, 2003, Pengrowth had deferred injectant costs of $24.3 million, which will be amortized and charged against distributable cash of future periods.

The value of Pengrowth’s proprietary injectants is not recorded until reproduced from the flood and sold, although the cost of producing these products for reinjection is included in operating costs. Total injectant costs are expected to increase in 2004 due to higher forecasted prices for natural gas and ethane and increased activity at the Swan Hills flood. The amount of injectants amortized against distributable cash is expected to decline in 2004 as the deferred portion of prior years’ costs has declined.

Interest

Although Pengrowth’s average long term debt was marginally lower in 2003 compared to 2002, interest expense increased to $18.2 million in 2003 from $15.2 million in 2002, reflecting a higher average interest rate on the term debt issued in 2003 compared to floating rates on bank debt in 2002. Also, included in interest expense in 2003 is $2.2 million related to the cancellation of interest rate swaps. These swaps were cancelled after all of Pengrowth’s floating rate debt was either replaced with fixed rate term debt in April of 2003, or repaid with the July 2003 equity proceeds.

The average interest rate on all of Pengrowth’s long term debt outstanding at December 31, 2003 is 5.07 percent and is payable in U.S. dollars and therefore subject to fluctuations in the exchange rate. The Note Payable is non-interest bearing.

Foreign Currency Gains and Losses

Pengrowth recorded a net foreign exchange gain of $29.9 million in 2003, compared to a foreign exchange loss of $0.2 million in 2002. Included in the 2003 net gain of $29.9 million, is $30.9 million unrealized foreign exchange gain related to the U.S. dollar denominated debt. This arises as a result of the increase in the Canadian dollar since the debt was issued in April 2003, from a rate of approximately $0.69 to $0.77 at year end. The balance, a foreign exchange loss of $1.0 million relates mainly to U.S. dollar denominated natural gas sales from SOEP. Pengrowth has hedged the exchange rate on a portion of these U.S. denominated gas sales. Revenues are recorded at the average exchange rate for the production month in which they accrue, with payment being received on or about the 25th of the month following production. As a result of the increase in the Canadian dollar relative to the U.S. dollar over the course of the year, a foreign exchange loss was recorded to the extent of the differential between the average exchange rate for the month of production and the exchange rate at the date the payments were received on un-hedged gas sales.

General and Administrative

General and administrative expenses (“G&A”) increased to $16.0 million ($0.89 per boe) from $11.0 million ($0.69 per boe) in 2002. G&A costs have increased in 2003 due to a number of factors including an increase in office rent and staffing levels following the acquisition of Calpine’s B.C. properties in October of 2002, and additional costs of administering an expanding unitholder base. Legal and regulatory costs have also increased as a result of listing on the New York Stock Exchange in the second quarter of 2002 and recent changes to regulatory requirements arising from the Sarbanes Oxley Act and similar new or proposed legislation in Canada. Included in 2003 G&A is $0.2 million in non-cash compensation expense related to the estimated fair value of trust unit rights granted in 2003 (see Note 3 and Note 11 to the Financial Statements for details).

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Management Fees

Management fees paid to Pengrowth Management Limited (“the Manager”) increased to $10.2 million in 2003 from $6.6 million in 2002. Although the management fee rate decreased effective July 1, 2003, there is an increase in total management fees due to growth in the size of the business and net operating income as management fees are calculated on a percentage of “net operating income” (oil and gas sales and other income, less royalties, operating costs, solvent amortization and reclamation funding).

A new management agreement, which was approved at the annual general meeting on June 17, 2003, was effective July 1, 2003. Under the terms of this agreement, the base fee has been reduced from a sliding scale between 3.5 percent and 2.5 percent, to 2 percent on the first $200 million of net operating income and 1 percent on net operating income over $200 million for the first three year term; acquisition fees have been eliminated, and the manager will receive a ‘performance fee’ if certain performance criteria are met — in particular should returns exceed 8 percent per annum on a three year rolling average basis. The maximum fees, including the performance fee, is limited to 80 percent of the fees that would otherwise have been paid under the old management agreement (including acquisition fees) for the first three years, and 60 percent for the second three years. Management fees for 2003 include a performance fee of $520,000, which represents 80 percent of the amount that would have been earned as an ‘acquisition fee’ under the old agreement, and together with the base fee for the second half of 2003, is equivalent to 80 percent of total fees that would have been earned by the Manager for that period.

Related Party Transactions

Details of related party transactions incurred in 2003 and 2002 are provided in Note 16 to the financial statements. These transactions include the Management fees paid to the Manager, as discussed in the preceding paragraphs. The Manager is controlled by James S. Kinnear, the Chairman, President and Chief Executive Officer of Pengrowth Corporation. As discussed above, the management fees paid to the Manager are pursuant to a management agreement which has been approved by the trust unitholders. Mr. Kinnear is not entitled to receive any salary or bonus in his capacity as a director and officer of Pengrowth Corporation.

Related party transactions in 2003 also include $675,692 paid to a firm controlled by the Corporate Secretary of Pengrowth Corporation, Mr. Charles V. Selby. These fees are paid in respect of legal and advisory services provided by the Corporate Secretary.

Taxes

In determining its taxable income, Pengrowth Corporation deducts royalty payments to unitholders, and historically, this has been sufficient to reduce taxable income to nil. The recent change to Pengrowth’s distribution approach, whereby approximately 10 percent of funds available for distribution are withheld to fund future capital expenditures, could result in taxable income in the Corporation in the future, however there are, at present, sufficient tax pools available in the Corporation to offset the expected level of income to be retained.

Capital taxes of $1.8 million in 2003 (2002 - $0.5 million) consists of Federal Large Corporations Tax (LCT) of $0.6 million and $1.2 million Saskatchewan Capital Tax and Resource Surcharge. Included in the amount recorded in 2002 is a LCT recovery of $1.3 million related to prior year reassessments. Under new Federal tax legislation passed in 2003, commencing in 2004, the taxable capital threshold will increase to $50 million and the LCT rate will gradually decline and be eliminated completely by 2008.

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Depletion and Depreciation

Depletion and depreciation of property, plant and equipment and other assets is provided on the unit of production method based on total proved reserves. The provision for depletion and depreciation increased 32 percent in 2003 to $185.3 million from $140.8 million in 2002 due to a larger depletable asset base and higher depletion rate (production as a percentage of total proved reserves). On a unit of production basis, depletion increased 17 percent to $10.35 per boe in 2003 from $8.81 per boe in 2002. The retroactive application of the new accounting policy for asset retirement obligations required restatement of prior periods, and this resulted in an increase in the 2002 depletion and depreciation rate to $8.81 per boe from $8.69 per boe. The increase in the per boe depletion amount in 2003 reflects the acquisition of the Sable facilities in 2003 without any associated reserves. With respect to the fourth quarter depletion provision, the increase also reflects the reduction in total proved reserves recognized at year end, which increases the depletion rate.

Ceiling Test

In 2003 Pengrowth adopted AcG-16 “Oil and Gas Accounting – Full Cost” a new CICA guideline which replaces AcG-5 “Full Cost Accounting in the Oil and Gas Industry”. AcG-16 includes changes to the way the ceiling test must be calculated, the details of which are provided in Note 2 to the financial statements. Implementation of this guideline had no impact on Pengrowth’s 2003 financial results.

Asset Retirement Obligations

In 2003, the CICA issued Section 3110, “Asset Retirement Obligations” which harmonizes Canadian GAAP requirements with the corresponding U.S. GAAP requirements under SFAS 143. Under these standards, the fair value of a liability for asset retirement obligations must be recognized in the period in which it is incurred, and a corresponding asset retirement cost is to be added to the carrying amount of the related asset. The new Canadian standard is effective for fiscal years beginning on or after January 1, 2004 with earlier adoption encouraged. Pengrowth has elected to implement this standard in 2003. As a result of implementation, the liability for future site restoration costs (now called “asset retirement obligations” under the new standard) increased by $41 million and property, plant and equipment increased by $70 million as at December 31, 2003. Opening 2003 unitholders’ equity increased by $19 million to reflect the cumulative impact of accretion and depletion expense, net of the cumulative change to the site restoration provision.

Under the previous accounting method for future site restoration costs, the provision for future site restoration costs was made over the life of the oil and gas properties and facilities using the unit of production method. Accretion, as recorded under the new Section 3110, represents the change in the discounted value of the liability due to the passage of time.

Remediation Trust Funds & Remediation and Abandonment Expenses

Pursuant to the purchase of the Judy Creek and Swan Hills properties from Imperial Oil Resources in 1997, Pengrowth established a trust fund to fund certain obligations of these properties. Following the acquisition of a working interest in the Sable facilities in 2003, Pengrowth has also contributed to a trust fund in respect to the future remediation costs of these facilities

Pengrowth takes a pro-active approach to managing our well abandonment and site restoration obligations on our operated properties. Operations personnel have completed a detailed analysis of expected future site restoration and abandonment costs for all of the major operated properties. Pengrowth expects to spend approximately $6 million per year over the next 10 years on remediation and abandonment expenses at operated properties.

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Netbacks

Pengrowth recorded an operating netback of $22.17 per boe in 2003 compared to $14.70 in 2002, mainly due to higher average commodity prices in 2003. For the fourth quarter of 2003 the operating netback of $20.43 was higher than the fourth quarter of 2002, mainly due to lower royalties and amortization of injectants.

Distributions and Taxability of Distributions

Pengrowth paid $313.4 million ($2.68 per unit) in distributions related to 2003 cash flow, compared to $194.5 million ($2.07 per unit) in 2002. This equates to 88 percent of funds generated from operations, compared to 85 percent in 2002.

Commencing with the January 15, 2003 distribution to unitholders, approximately 10 percent of cash available for distribution has been withheld to fund capital expenditures as well as to stabilize monthly distributions. Subject to a limit of 20 percent of gross revenues, as approved by unitholders at the 2002 annual general meeting, the Board of Directors may decide to increase (or decrease) the amount withheld in the future, depending on a number of factors, including future commodity prices, capital expenditure requirements, and the availability of debt and equity capital.

Cash distributions are paid to unitholders on the 15th of the second month following the month of production. Pengrowth Energy Trust paid $2.66 per unit as cash distributions during the 2003 calendar year. For Canadian tax purposes 55.23 percent of these distributions or $1.4692 per unit is taxable income to unitholders for the 2003 tax year. The remaining 44.77 percent or $1.1908 per unit is a tax deferred return of capital which will reduce the unitholder’s cost base of the unit for purposes of calculating a capital gain or loss upon ultimate disposition of the trust units.

At December 31, 2003, the trust had unused tax deductions of $10.27 per unit (2002 – $10.64 per unit). At this time, Pengrowth anticipates that approximately 55-60 percent of 2004 distributions will be taxable; this estimate is subject to change depending on a number of factors including, but not limited to, the level of commodity prices, acquisitions, dispositions, and new equity offerings.

Non-Resident Ownership

Pengrowth’s ability to continue to qualify as a mutual fund trust is dependent on both the interpretation of the Income Tax Act (Canada) and its level of foreign ownership. The latest ownership report received by Pengrowth dated effective January 31, 2004 indicated that foreign ownership of trust units was less than but approaching 50 percent. The level of foreign ownership of Pengrowth trust units has increased steadily since trust units were listed on the New York Stock Exchange during April 2002 and following the cross-border equity offering of Pengrowth trust units completed in November 2002. Unitholder approval will be sought at Pengrowth’s Annual General

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Meeting for amendments to Pengrowth’s trust indenture and other constating documents that will enable the trust to manage foreign ownership levels and continue to maintain the trust primarily for the benefit of Canadian residents while encouraging orderly markets for trust units in Canada and the United States.

Acquisitions and Dispositions

On May 8, 2003, Pengrowth acquired an 8.4 percent working interest in the SOEP natural gas processing facilities downstream of the Thebaud Central Processing Platform for a net purchase price of $57 million. On December 31, 2003, Pengrowth acquired an 8.4 percent working interest in the SOEP offshore platforms and associated sub-sea field gathering lines from Emera Offshore Incorporated (“Emera”) and exchanged the royalty interest previously held for a working interest in the SOEP reserves, for a total purchase price of $65 million. As a result of these two transactions, Pengrowth now holds an 8.4 percent working interest in the entire SOEP project. In addition, in June of 2003 Pengrowth acquired interests in eleven significant discovery licenses (“SDL’s”) related to potential future offshore Nova Scotia resources, for $4.5 million.

Capital Expenditures

Pengrowth spent $85.7 million in capital expenditures in 2003 compared to $55.6 million in 2002. In 2004, Pengrowth expects to spend approximately $135 million on development opportunities at our existing properties. The majority of this will be spent at Judy Creek, SOEP, and Monogram.

Review of Development Activities

Operated Properties:

At Judy Creek, 2003 development activity included four producing oil wells, two vertical water injection wells, one horizontal miscible injection well, and two shallow gas wells. The 2004 development plan for Judy Creek includes four horizontal miscible injection wells, up to three oil wells in Judy “A” Pool, and up to three shallow gas wells.

At McLeod River Pengrowth drilled a total of eight wells in 2003 (4.9 net to Pengrowth) — three are producing natural gas wells, one is awaiting tie-in, and the remaining four are currently under

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evaluation. The 2004 development plan at McLeod River includes 13 new natural gas wells (7.2 wells net to Pengrowth).

In 2003, Pengrowth drilled 10 wells (7.4 net) in Northeast British Columbia. In addition, Pengrowth completed 23 additional farm-out transactions in 2003 on higher risk development lands. These transactions have resulted in 14 new wells drilled and commitments for the drilling of 13 additional wells in 2004. Pengrowth holds gross overriding royalty interests in these farm-out lands – ranging from 0.5 percent to 15 percent. Approximately $17 million of Pengrowth’s 2004 capital budget is targeted for further development opportunities at the B.C. properties.

Non-operated Properties:

At the Sable Offshore Energy Project (SOEP), where Pengrowth now holds an 8.4 percent working interest, the major milestone for 2003 was the successful startup of Alma, the first Tier II field. The Alma platform is located in 67 metres of water and is connected to the SOEP Thebaud central processing platform via a 52-kilometre sub-sea pipeline. The Alma field is currently producing approximately 120 mmcf per day of natural gas and 3,000 barrels per day of condensate and natural gas liquids. With the addition of Alma, average daily production from the SOEP is approximately 500 million cubic feet per day of natural gas and 20,000 barrels per day of associated condensate and natural gas liquids. Natural declines in production are expected to be supplemented by production from South Venture when production starts in late 2004 and the installation of compression in 2006/2007.

SOEP activity for 2004 will be concentrated on the development of South Venture, SOEP compression and future field development.

At the Dunvegan Gas Unit, where Pengrowth holds a 7.98 percent working interest, the operator drilled 13 successful gas wells during the latter part of 2003. The wells are anticipated to commence production at an average gross rate of 1.0 mmcf/d per well. Three wells from the 2003 program were carried over and were drilled in January and fourteen existing producers were also re-completed in 2003 with an average anticipated gross incremental rate of 250 mcf/d per well. The operator’s 2004 plans include drilling an additional 24 wells and re-completing 12 existing producers.

At the Monogram Gas Unit, where Pengrowth holds a 53.82 percent working interest, 2004 plans include an extensive infill drilling program of approximately 150 wells along with facility upgrades such as line looping and additional compression.

At Swan Hills Unit #1, three successful wells were drilled in the fourth quarter of 2003 and up to five additional wells are planned for 2004. Other major 2004 projects include a CO2 pilot and additional miscible pattern development. Pengrowth has a 10.45 percent working interest in this unit.

At the Weyburn Unit, where Pengrowth has a 9.75 percent working interest, there are now 32 active CO2 patterns and the operator is proposing to develop an additional 10 patterns in 2004.

At Cessford, Pengrowth participated in a 73 well shallow gas program and also drilled 8 operated wells in the fourth quarter of 2003. Prior to the infill program Pengrowth’s working interest share of production was approximately 650 mcf/d and production had tripled as of year end. Pengrowth holds a 60 percent working interest in the 73 non-operated wells, and an 87.5 percent working interest in the 8 operated wells.

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Reserves

Pengrowth reported year-end Proved plus Probable reserves of 184.4 mmboe compared to 214.8 mmboe of Established reserves reported at year end 2002. Most of the decline of 30.4 mmboe relates to 2003 production of 17.9 mmboe, and year-end revisions to SOEP reserves, as previously reported by Pengrowth in a News release on February 2, 2004. Further details of Pengrowth’s 2003 year-end reserves are provided later in this news release.

Pengrowth is now required to comply with the National Instrument 51-101, issued by the Canadian Securities Administrators, in all its reserves related disclosures. NI 51-101 came into effect on September 30, 2003 and is applicable for financial years ended on or after December 31, 2003. NI 51-101 brought about significant changes in which reporting issuers manage and publicly disclose information relating to their oil and gas reserves, mandates annual disclosure requirements and prescribes new reserve definitions as follows:

Proved reserves (P90) - this is a conservative estimate of remaining reserves. For reported reserves this means there must be at least a 90 percent probability that the quantities actually recovered will equal or exceed the estimated proved reserves.

Proved plus Probable (P50) - this is a reasonable estimate of remaining reserves. For reported reserves there must be at least a 50 percent probability that the quantities actually recovered will equal or exceed the sum of the proved plus probable reserves. The probable reserves will no longer be risked by 50 percent as they are implicitly risked due to the nature of the new definition of reserves.

The purpose of NI 51-101 is to enhance the quality, consistency, timeliness and comparability of oil and gas activities by reporting issuers and elevate reserves reporting to a higher level of accountability.

Financial Resources and Liquidity

In 2003, Pengrowth continued its policy of maintaining a conservative capital structure, capitalizing on opportunities to issue new equity when appropriate, while maintaining a high distribution pay-out ratio to unitholders. At year-end 2003, Pengrowth was in a strong financial position, with long term debt to long term debt plus equity ratio of 18 percent. Pengrowth has $235 million in committed credit facilities which is currently reduced by $22 million in letters of credit (reduced from $47 million outstanding at year end 2003). With additional cash and term deposits of $64 million, Pengrowth is well positioned to fund its 2004 development program of $135 million, and to take advantage of acquisition opportunities as they arise.

In 2003, Pengrowth raised a total of $210.2 million net proceeds from new equity — $136.3 million net equity proceeds from an equity issue in July, with the balance coming from the employee trust unit option and trust unit rights plans, and the distribution reinvestment plan.

Pengrowth’s long-term debt at December 31, 2003 was fixed rate term debt denominated in U.S. dollars and translated to $259 million. Due to the increase in the $Cdn/$U.S. exchange rate in 2003, an unrealized gain of $31 million has been recorded since the $US denominated debt was issued in April of 2003.

Pengrowth’s long-term debt decreased by $58 million in fiscal 2003 to $259 million at December 31, 2003. The factors contributing to the change in long-term debt are shown in the following table:

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At December 31, 2003 Pengrowth also had a $45 million non-interest bearing note payable to Emera Offshore Incorporated related to instalments due upon the purchase of the SOEP offshore facilities from Emera on December 31, 2003. The terms of this note are provided in Note 9 to the financial statements.

At December 31, 2003 Pengrowth had cash and term deposits of $64 million, which are available to fund future capital expenditures and/or future acquisitions.

Risk Management

Pengrowth uses forward and futures contracts to manage its exposure to commodity price fluctuations. Commodity price hedges in place at December 31, 2003 are provided in Note 18 to the Financial Statements. Subsequent to year end, Pengrowth has entered into additional contracts and now has the following volumes hedged for 2004:

In addition, subsequent to year-end, Pengrowth has entered into an agreement to purchase 5 MW of electricity from February 1, 2004 to December 31, 2004 at a price of $53.00 per MWH. This constitutes approximately 20 percent of our operated properties electricity requirements for the period.

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Trust Unit Information

Pengrowth had 123,873,651 trust units outstanding at December 31, 2003, compared to 110,562,327 trust units at December 31, 2002. The weighted average number of units during the year was 115,912,374 (2002: 89,922,886).

In 2003, Pengrowth raised a total of $210.2 million net proceeds from new equity, issuing a total of 13.3 million additional trust units. On July 23, 2003 Pengrowth completed a public offering of 8.5 million units at $16.95 per unit to raise total gross proceeds of $144.1 million, and net proceeds of $136.3 million. During 2003, 1.5 million units were issued under the DRIP plan at an average price of $15.31 per unit, raising additional equity of $22.2 million, and 3.4 million units were issued under the employee trust unit option and rights plans, at an average price of $15.39 per trust unit, to raise an additional $51.7 million in new equity.

Outlook

Our focus in 2004 continues to be on creating Unitholder value. We successfully accomplished this mission in 2003 delivering distributions of $2.68 per unit and appreciation of trust units in the market place. In 2004 we will again optimize the distributions to our Unitholders within the parameters of maintaining a prudent financial structure and allowing us to act on longer term growth opportunities for our Unitholders.

We will continue in 2004 to strive to accomplish many of the objectives which have successfully grown the business and Unitholders’ value over the years including:

In 2004 we have the largest planned capital program of the company’s history of $135 million which we will strive to deploy in a manner which enhances value for our Unitholders.

Conference Call and Webcast

Pengrowth will be conducting a conference call and webcast for analysts, brokers, investors and media representatives regarding its 2003 fiscal results at 9:00 A.M. Mountain Standard Time (11:00 A.M. Eastern Standard Time) on Tuesday, March 2, 2004.

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Callers may dial 1-800-796-7558 or Toronto local (416) 640-4127 a few minutes prior to start and request the Pengrowth conference call. The call will also be available for replay by dialing 1-877-289-8525 or Toronto local (416) 640-1917 and entering passcode number 21034612 followed by the pound key.

Interested users of the internet are invited to go to:

http://www.newswire.ca/en/webcast/viewEvent.cgi?eventID=722920 or www.pengrowth.com for replay.

PENGROWTH CORPORATION

James S. Kinnear, President

For further information about Pengrowth, please visit our website www.pengrowth.com or contact:

Bob Hodgins, Chief Financial Officer, Calgary E-mail: rbh@pengrowth.com

Telephone: (403) 233-0224 Toll Free: 1-800-223-4122 Facsimile: (403) 294-0051

Sally Elliott, Investor Relations, Toronto E-mail: sallye@pengrowth.com

Telephone: (416) 362-1748 Toll Free: 1-888-744-1111 Facsimile: (416) 362-8191

15

PENGROWTH ENERGY TRUST

UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2003

16

PENGROWTH ENERGY TRUST
CONSOLIDATED BALANCE SHEETS
AS AT DECEMBER 31
(Stated in thousands of dollars)

* See Note 3

See accompanying notes to the consolidated financial statements.

17

PENGROWTH ENERGY TRUST
CONSOLIDATED STATEMENTS OF INCOME
YEARS ENDED DECEMBER 31
(Stated in thousands of dollars)

*See Note 3

See accompanying notes to the consolidated financial statements.

18

PENGROWTH ENERGY TRUST
CONSOLIDATED STATEMENTS OF CASH FLOW
YEARS ENDED DECEMBER 31
(Stated in thousands of dollars)

*See Note 3

See accompanying notes to the consolidated financial statements.

19

PENGROWTH ENERGY TRUST
CONSOLIDATED STATEMENTS OF TRUST UNITHOLDERS’ EQUITY
YEARS ENDED DECEMBER 31
(Stated in thousands of dollars)

*See Note 3

See accompanying notes to the consolidated financial statements.

20

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2003 AND 2002
(Tabular amounts are stated in thousands of dollars except per unit amounts.)

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