The Benchmark of Energy Trusts

T h i r d Q u a r t e r , 2 0 0 1

R E P O R T T O U N I T H O L D E R S

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HIGHLIGHTS - CONSOLIDATED FINANCIAL STATEMENTS

INCOME STATEMENTOil and gas sales $ 115,847 $ 103,550 12% $ 379,851 $ 285,435 33%

Distributable income $ 48,324 $ 53,163 -9% $ 183,790 $ 146,724 25%Distributable income per trust unit

Based on weighted averageunits outstanding $ 0.641 $ 0.963 -33% $ 2.661 $ 2.691 -1%Based on actual distributionspaid or declared $ 0.630 $ 0.960 -34% $ 2.600 $ 2.675 -3%

Weighted average numberof units outstanding 75,342 55,215 36% 69,061 54,531 27%

BALANCE SHEETWorking capital $ (14,946) $ (18,290) -18% $ (14,946) $ (18,290) -18%Property, plant and equipment

and other assets $ 1,271,801 $ 814,002 56% $ 1,271,801 $ 814,002 56%Long-term debt $ 389,760 $ 257,242 52% $ 389,760 $ 257,242 52%Unitholders’ equity $ 771,792 $ 518,333 49% $ 771,792 $ 518,333 49%

DAILY PRODUCTIONCrude oil (barrels) 19,352 16,740 16% 19,808 17,129 16%Natural gas (thousands of

cubic feet) 106,579 68,752 55% 85,449 71,458 20%Natural gas liquids (barrels) 5,969 3,582 67% 4,956 4,027 23%Other – 104 – 87Total production (BOE) 6:1 43,083 31,884 35% 39,005 33,153 18%

PRODUCTION INCREASE(6:1 boe) (year over year) 35% -3% 18% 6%

PRODUCTION PROFILE(6:1 conversion)

Crude oil 45% 53% 51% 52%Natural gas 41% 36% 36% 36%Natural gas liquids 14% 11% 13% 12%

AVERAGE PRICESCrude oil (per barrel) $ 39.28 $ 41.31 -5% $ 39.69 $ 38.74 2%Natural gas (per mcf) $ 3.20 $ 4.70 -32% $ 5.39 $ 3.74 44%Natural gas liquids (per barrel) $ 27.98 $ 36.00 -22% $ 33.64 $ 31.78 6%Average price per BOE 6:1 $ 29.23 $ 35.30 -17% $ 35.67 $ 31.54 13%

UNIT TRADINGHigh $ 19.50 $ 20.35 $ 21.95 $ 20.35Low $ 14.05 $ 18.00 $ 14.05 $ 15.00Close $ 15.00 $ 19.20 $ 15.00 $ 19.20

Value $ 163,800 $ 92,953 76% $ 545,229 $ 292,846 86%Volume (thousands of units) 9,471 4,790 98% 28,303 16,182 75%

Three Months ended % Nine Months ended %(thousands, except per unit amounts) September 30 Change September 30 Change(unaudited) 2001 2000 2001 2000

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REPORT TO UNITHOLDERS

Distributable Income Increases 25% for the Nine months ended September 30, 2001

For the nine months ended September 30, 2001, Pengrowth recorded $183.8 million in distributableincome, a 25% increase compared to $146.7 million in the first nine months of 2000. The additional trustunits issued in the May 2001 equity offering have offset this increase when measured on a per trust unitbasis. For the nine months ended September 30, 2001, distributable income per trust unit was $2.60compared to $2.675 per trust unit in the first nine months of last year.

Pengrowth’s year-to-date distributions history is summarized below:

Ex-Distribution Distribution Distribution AmountDate * Record Date Payment Date per Trust Unit

December 27, 2000 December 29, 2000 January 15, 2001 $0.34January 30, 2001 February 1, 2001 February 15, 2001 0.40February 27, 2001 March 1, 2001 March 15, 2001 0.43March 28, 2001 March 30, 2001 April 15, 2001 0.38April 27, 2001 May 1, 2001 May 15, 2001 0.33May 30, 2001 June 1, 2001 June 15, 2001 0.29June 27, 2001 June 29, 2001 July 15, 2001 0.26July 27, 2001 July 31, 2001 August 15, 2001 0.28August 29, 2001 August 31, 2001 September 15, 2001 0.21September 26, 2001 September 28, 2001 October 15, 2001 0.21October 30, 2001 November 1, 2001 November 15, 2001 0.21November 29, 2001 December 3, 2001 December 15, 2001

*To benefit from the monthly cash distribution, unitholders must purchase or hold trust units prior to theex-distribution date

In the third quarter of 2001, distributable income decreased 9% to $48.3, compared to $53.2 million in2000. On a per trust unit basis, distributable income decreased 34% to $0.63 per trust unit in the thirdquarter of 2001 compared to $0.96 per trust unit for the same period in 2000. The decline in distributableincome for the quarter can be attributed to weaker natural gas and crude oil prices.

Pengrowth Monthly Cash Distributions

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At September 30, 2001, Pengrowth had $0.02 per trust unit in distributable income that had been earnedbut not yet paid or declared payable to unitholders. This surplus will be paid in the fourth quarter.

Pengrowth’s Average Price Per BOE Decreases 17% in the Third Quarter

Pengrowth’s average price per BOE of production decreased 17% from $35.30/boe in the third quarter of2000 to $29.23/boe in the third quarter of 2001. During this time period, Pengrowth’s average natural gasprice decreased 32% and its crude oil price decreased 5%.

Three months ended Nine months endedSeptember 30, % September 30, %

Average Prices C$ 2001 2000 Change 2001 2000 Change

Crude oil (per bbl) $39.28 $41.31 (5) $39.69 $38.74 2Natural gas (per mcf) $ 3.20 $ 4.70 (32) $ 5.39 $ 3.74 44Natural gas liquids (per boe) $27.98 $36.00 (22) $33.64 $31.78 6Total per boe (6:1) $29.23 $35.30 (17) $35.67 $31.54 13

The price that Pengrowth received for natural gas liquids (“NGL’s”) in the third quarter of 2001 was 22%lower than the comparable price in the third quarter of 2000. The lower NGL price reflects lower pricingfor ethane (which tracks the price of natural gas rather than oil) and lower pricing for condensate, propaneand butane. Pengrowth’s average NGL price averaged 85% of its crude oil price for the nine months endedSeptember 30th, 2001 compared to 82% in 2000.

The average prices in the table above include the following opportunity costs from commodity hedges:

• losses related to fixed price natural gas contracts (compared to monthly AECO average spot prices) of$15.8 million for the nine months ended September 30, 2001, of which $1 million related to the thirdquarter of 2001; and,

• losses related to crude oil price swap transactions of $3.1 million for the nine months endingSeptember 30, 2001, of which $0.7 million related to the third quarter of 2001.

Commodity Price Outlook

The record North American natural gas prices experienced in the first half of 2001 proved unsustainable inthe wake of conservation measures by industrial and retail consumers, fuel switching to coal, oil andnuclear power, and a slowing economy.

AECO gas index prices decreased 25% in the third quarter from $5.26/mcf in 2000 to $3.93/mcf in 2001.NYMEX Henry Hub gas prices decreased 33% in the third quarter from US$4.27/mmbtu in 2000 toUS$2.88/mmbtu in 2001.

In the near term, natural gas prices may continue to experience pressure due to high gas storage levels inNorth America and weak demand from a slowing economy. A recovery of natural gas prices will depend onwinter weather conditions, fuel switching back to natural gas, and economic recovery. The currentreduction in natural gas drilling activity and the inability of producers to replace production declines onexisting properties may limit supply and strengthen prices over the mid to long term.

Crude oil prices have been relatively stable for most of the year. Recently, crude prices have shownweakness in response to the tragic events of September 11th, slowing world energy demand, anduncertainty over OPEC’s ability to maintain price discipline. WTI crude oil prices decreased 16% in thethird quarter from US$31.58/bbl in 2000 to US$26.49/bbl in 2001 (a decrease of 13% in Canadian dollarterms from C$46.81/bbl to C$40.95/bbl after adjusting for exchange rate variations). In comparison, forthe nine months ended September 30th, WTI decreased 6% from US$29.60/bbl (C$43.59/bbl) in 2000 toUS$27.72/bbl (C$42.63/bbl) in 2001.

Third Quarter 2001 Average Production Rates

Judy Creek BHL Unit 100.00% 8,565 2.1 1,837 10,752

Judy Creek West BHL Unit 94.58% 1,703 0.6 266 2,066

Sable Island 8.40% – 42.5 1,572 8,655

Weyburn Unit 9.74% 1,941 0.2 – 1,968

McLeod River Various 9 9.1 423 1,942

Swan Hills Unit #1 10.45% 1,384 0.8 221 1,736

Goose River 42.25% 839 0.5 33 964

Monogram Gas Unit 53.82% – 7.5 – 1,255

Hanlan Swan Hills Gas Pool Unit #1 7.78% – 7.9 4 1,329

Nipisi Non-Unit 95.00% 1,091 0.2 153 1,276

Enchant Various 1,005 0.4 9 1,078

Minnehik Buck Lake 17.91% – 3.7 175 801

Dunvegan Gas Unit #1 7.97% – 4.4 248 984

Strachan Leduc D-3 Gas Unit #1 71.65% – 4.5 237 986

Other Swan Hills Various 859 1.9 303 1,471

Other Shallow Gas Various – 5.4 – 898

Other Various 1,956 14.9 488 4,922

Total Production 19,352 106.6 5,969 43,083

Production Increases 35% in the Third Quarter of 2001

Total BOE production increased 35% in the third quarter of 2001, compared to the third quarter of 2000.For the nine months ended September 30, 2001 production is 18% higher than the same period last year.

Three months ended Nine months endedSeptember 30, % September 30, %

Daily Production 2001 2000 Change 2001 2000 Change

Crude oil (bbls/d) 19,352 16,740 16 19,808 17,129 16Natural gas (mcf/d) 106,579 68,752 55 85,449 71,458 20Natural gas liquids (bbls/d) 5,969 3,582 67 4,956 4,027 23Sulphur (Lt) – 104 – – 87 –Total boe/d (6:1) 43,083 31,884 35 39,005 33,153 18

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Working Natural

Interest Natural Gas Oil

Owned Oil Gas Liquids Equivalent

(%) (bpd) (mmcf/d) (bpd) (boepd) (6:1)

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Pengrowth’s production portfolio in the third quarter was weighted 45% towards crude oil while natural gasaccounted for 41% of total production. Natural gas liquids represented the remaining 14% of production.

Oil production volumes have increased as a result of the acquisition of oil producing properties at GooseRiver, House Mountain, Weyburn and Nipisi in the fourth quarter of 2000. Judy Creek oil productionvolumes were down slightly in July and August as a result of an electrical outage. By September, JudyCreek crude oil production had increased to 10,474 bpd. Judy Creek production is demonstrating positiveresponse to the recent development drilling and miscible flooding that was initiated earlier this year.

Pengrowth Average Production

Third quarter natural gas production volumes have increased 55% when compared to the third quarter of2001. This increase can be attributed to the acquisition of interests in Minnihik Buck Lake in December2000, Kaybob Notikewan in March 2001, and the Sable Offshore Energy Project (“SOEP”) in June 2001.SOEP production volumes have been strong in the third quarter. Pengrowth has recorded natural gas salesof 42,774 mcf/d and NGL sales of 1,450 boepd with respect to SOEP since the acquisition on June 15, 2001.

Price Risk Management Program

Looking forward, Pengrowth has entered into financial swap transactions that fix the price on:• 4,000 barrels of oil per day for the remainder of 2001 (20% of estimated production) at an average

price of C$39.32/bbl.• 1,000 barrels of oil per day for the first six months of 2002 (5% of estimated production) at an

average price of C$42.20/bbl.

Pengrowth also has sales commitments to deliver natural gas at fixed prices in the future, as follows:• 1.0 bcf (10.5 mmcf/d or 10% of estimated production) for the remainder of 2001 at an average

plantgate price of $2.98/mcf; and• 2.8 bcf (7.7 mmcf/d or 7% of estimated production) for 2002 at an average plantgate price of

$2.98/mcf.

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At September 30, 2001 the mark-to-market value of these hedge positions was a positive $0.6 million(positive $1.9 million for crude oil offset by a negative $1.3 million for natural gas).

Net Income Increases 14% for the nine months ended September 30, 2001

Net income for the nine months ended September 30, 2001 increased 14% to $89.3 million compared to$78.1 million for the similar period last year.

Net income for the third quarter of 2001 decreased 57% to $13.5 million compared to $31.1 million forthe third quarter of 2000.

Operating Costs

For the nine months ended September 30th, 2001, operating costs were $76.3 million ($7.16 / boe),compared to $46.3 million ($5.10/boe) for the first nine months of 2000.

The increase in operating costs is attributable to property acquisitions in late 2000 and the first half of2001 and increased electricity rates. Alberta experienced very high electricity rates in the first half of2001; however, recent rates have declined significantly in response to lower natural gas prices. The SOEPacquisition in June 2001, with its related operating costs and processing fees has increased Pengrowth’saverage cost per boe.

Operating costs also include approximately $2 million of CO2 costs at Weyburn. Pengrowth hasconservatively chosen to expense the CO2 costs rather than defer and amortize these costs. The decisionto expense the CO2 costs is based on the limited information and history on the PanCanadian-operatedCO2 flood at Weyburn.

Injectants for Miscible Flood

Injectants (primarily ethane and methane) are used in the Judy Creek area miscible floods to stimulateincremental oil recovery. Pengrowth amortizes the cost of injectants purchased from third parties againstdistributable income over the period of expected future economic benefit, which is currently 30 months.In the nine months ended September 30, 2001 Pengrowth purchased $50.2 million of injectants formiscible floods. During this same period, we expensed a related $35.1 million against distributableincome. The remaining $15.1 million has been temporarily debt financed and is available for amortizationin future periods.

Pengrowth had expected the rate of amortization to match the rate of purchasing in 2001. However, theincreases in natural gas prices during the first quarter accounted for much of the $15.1 million deferralevidenced in 2001. In recent months, amortization has exceeded purchases and the deferred injectantcosts are being drawn down. For example, in the third quarter of 2001, Pengrowth purchased $10.1 millionworth of injectants and amortized $12.6 million against distributable income, with the difference of $2.5million going toward debt repayment.

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Pengrowth Generates proceeds of $23.6 Million in the Disposition of Non-Core Properties

As part of Pengrowth’s continuing program of reviewing its portfolio of properties, a number of minorproperties have been sold in 2001. The proceeds of $23.6 million have been applied to debt repayment.The following is a schedule of the properties sold including the associated 2001 production andestablished reserves.

Non-Core Property Dispositions Established9 months ended September 30, 2001 Estimated 2001 Production Reserves

Closing Crude Oil Natural Gas NGL’sProperty Date bbl/d mcf/d bbl/d Mboe (6:1)

West Eagle Unit June 164 158 3 587Meekwap D-2A Unit No.1 July 57 30 2 117Mitsue Gilwood Unit No. 1 May 258 229 39 951Portage Gas Unit April – 2,969 – 1,699Steelman Unit No.7 July 54 19 – 89Niton Non-Unit June – 379 10 182Total 533 3,784 54 3,624

Update on the Sable Project

On June 15, 2001 Pengrowth purchased a royalty on 8.4% of the natural gas and natural gas liquidsproduction from the Sable Offshore Energy Project ("SOEP").

The SOEP owners and Pengrowth recently entered into a Confidentiality Agreement providing Pengrowth with continuing access to confidential information regarding SOEP (includingproduction, geological and geophysical data and forecasts of production and costs prepared for the jointaccount). Pengrowth previously had limited access to information as a royalty owner.

Future public announcements with respect to SOEP must be coordinated through the SOEP ManagementCommittee in accordance with the arrangements with the other SOEP owners. However, Pengrowth hasretained the right to disclose certain information with respect to the SOEP royalty, subject to noticeprovisions in the agreement and applicable legal / regulatory requirements.

Access to confidential information assists in Pengrowth's negotiation of processing fees that will apply toSOEP onshore facilities. Emera Inc. acquired an 8.4% working interest in the flow lines and productionplatforms associated with the SOEP project. The other Sable owners exercised rights of first refusal withrespect to an 8.4% working interest in the balance of the Sable facilities. While Pengrowth had pre-arranged a processing agreement with Emera, it did not have a processing agreement with the other Sableowners.

The SOEP owners have proposed a processing fee arrangement that is higher than the original Emeraformula (the difference equates to a net present value of approximately $20 million over the full economiclife of the SOEP project). Pengrowth has not agreed to the proposal and is working towards a lower costfee structure. Access to ongoing confidential information will also facilitate Pengrowth's budgeting andgas marketing activities.

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Daily average raw gas production from SOEP for the third quarter was approximately 543 mmcf/d(45.6 mmcf/d net to Pengrowth) reflecting increases in operating rates at the SOEP processing facilities.Pengrowth's share of sales gas averaged 42.5 mmcf/d plus 1,572 bbls of natural gas liquids during thethird quarter. Pengrowth had previously anticipated gas sales from Sable of approximately 474 mmcf/d(39.8 mmcf/d net to Pengrowth) based upon the Gilbert Laustsen Jung Established reserve case (P-50) atthe time of purchase. As a result, the average production for the 3 month period is approximately 10%higher than our original expectations.

Pengrowth is currently negotiating a contract to sell 25,000 MMBTU per day of Sable natural gas to a U.S. based gas fired electrical generation facility which is currently under construction. The proposedcontract is for an initial term of five years commencing in the third quarter of 2002. The contract price willbe based upon a basket of floating index prices related to the Boston market. Upon completion of thiscontract, Pengrowth will have contracted 33,000 MMBTU per day of its SOEP gas under long term salesarrangements.

The original agreement with respect to the SOEP acquisition anticipated that PanCanadian Energy wouldacquire the shares of Nova Scotia Resources Limited ("NSRL") after the SOEP assets had been sold.However, PanCanadian exercised its right to withdraw from the share sale because it was not able toobtain all the waivers and agreements it required. Pengrowth had executed a Share Sale BackstopAgreement with the Province of Nova Scotia (the "Province"). Under the Share Sale Backstop Agreement,Pengrowth may be required to acquire the shares of NSRL for $65 million, subject to the satisfaction ofcertain conditions. Pengrowth provided the Province with a $3 million deposit and a promissory note assecurity for any obligation to pay the balance of the purchase price. Pengrowth has taken the position thatit is not required to close under the Backstop Share Sale Agreement for reasons that include the non-satisfaction of the conditions.

SOEP Gas Field

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Pengrowth and the Province have nonetheless entered into an agreement to seek an alternate buyer forthe shares of NSRL. If a mutually acceptable buyer to both Pengrowth and the Province is found for theshares of NSRL before December 17th, 2001 for a price less than $65 million, Pengrowth may be obligedto account to the Province for half of the shortfall. The Province and Pengrowth are also exploring otherdeal structures and potential transactions. An active sale solicitation process is being conducted inconjunction with the financial advisors to both Pengrowth and the Province and we anticipate an offer oroffers will be advanced to the Province with respect to the sale of NSRL.

The assets that remain in NSRL include interests in Significant Discovery Licenses, 2 production platformsand other assets. One of the production platforms is located in the previously abandoned Cohasset field,and the other is located in the Panuke field. The 11 Significant Discovery Licenses have modest directvalue to Pengrowth but may have farm-out or exploration potential to a conventional oil and gas company.The production platforms have abandonment liabilities associated with them, but may be useful in thedevelopment of other fields in the area.

Financial Resources

Pengrowth’s long-term debt at September 30, 2001 was $389.8 million, compared to $286.8 million atDecember 31, 2000. The increase in debt is attributed to acquisitions and capital spending offset byproceeds of trust units issued and property dispositions.

Long-term Debt Continuity $millionsBalance at December 31, 2000 $ 286.8Net Equity Proceeds (212.2)Proceeds from the issue of trust units pursuant to option exercises and DRIP (12.2)Acquisitions, net of adjustments 254.3Dispositions, net of adjustments (23.6)Capital expenditures, excluding acquisitions 54.6Difference between solvent purchases and expenses 15.1Change in working capital and Remediation Trust Fund 27.0Balance at September 30, 2001 $ 389.8

The ratio of debt to trailing 12-month distributable income at September 30, 2001 was 1.5 times. Inaddition, distributable income covered interest expense by 12 times in the first nine months of 2001.

Reconciliation of Funds Generated from Operations to Distributions

The following table demonstrates Pengrowth’s policy of distributing 100% of funds generated by operationsafter adjusting for the manner in which Pengrowth amortizes miscible injectant costs. The practice ofamortizing injectant costs over 30 months creates a temporary difference that reverses over time.

A meaningful comparison of “Funds Generated from Operations” to the “Distributions” amount shown onPengrowth’s Consolidated Statement of Cash Flow requires an adjustment for the two-month time lagbetween when funds are generated by the business and when they are paid to unitholders.

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Reconciliation of Distributions to Funds Generated From OperationsConsolidated Statement of Cash Flow Nine months ended September 30, 2001 $millions

Distributions per Statement of Cash Flow $198.6Subtract: Distributions paid in 2001 but earned in 2000Subtract: (Distributions payable December 31, 2000) (48.0)Add: Distributions earned in 2001 but unpaid at September 30, 2001Add: (October and November distributions and any balance unpaid) 33.2Total Adjusted Distributions for the period $183.8

Purchase of injectants for miscible flood (50.2)Amortization of injectants for miscible flood 35.1Items included in Distributable Income but not in Net Income(e.g. remediation trust fund contributions in excess of expenses) 0.5Funds Generated From Operations $169.2

Capital Spending

Capital expenditures for the nine months ending September 30, 2001 totaled $54.6 million as comparedwith $43.9 million for the same period in 2000. Of the $54.6 million, $45.1 million was spent on drilling,completion and tie-ins, and $9.5 million was spent on facilities. The major development programs wereconducted at Judy Creek ($22.9 million), McLeod River ($4.8 million), Sable ($4.2 million), Weyburn($4.0 million), Monogram ($4.0 million) and Nipisi ($2.7 million).

Review of Development Activities

Third quarter development activities at Pengrowth’s major properties include the following:

At Judy Creek:• Drilled a successful oil producer in the NW quadrant of “A” Pool (100% Pengrowth). The well is in

production at a rate exceeding 280 bopd.

Judy Creek – Swan Hills Development Activity

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Judy Creek – Viking Gas Development Activity

• Drilled a successful gas well (100% Pengrowth) which is currently being tied in.• Successfully shut down one gas plant by transferring loads to other plants and optimizing processing

conditions. This resulted in an annual cost saving of over $500,000 net to Pengrowth.• Drilled a water & solvent injection well in the NW quadrant of “A” pool.• Started production at another oil well drilled in the NW quadrant earlier in the year. The current oil

rate is 125 bopd net Pengrowth.• Started gas production from three successful workovers performed in Q2. Once optimization

activities are completed, total production from these three 100% Pengrowth wells is forecast to be1.5 mmcf/d.

• Started water injection at three injection wells drilled earlier in the year to enhance the waterfloodcapabilities of the reservoir.

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At McLeod River:• Completed two new gas wells drilled earlier in the year. The first well (100% Pengrowth) has

commenced production at a rate that is expected to stabilize at approximately 1.5 mmcf/d from twoproducing zones. The second well (87.5% Pengrowth) is on stream at 1.0 mmcf/d.

McLeod River Drilling Activity

At Enchant:• Installed a high volume pump on a 100% Pengrowth-owned well resulting in a 65 bpd production

increase.• Continued well optimization and development has reduced the reservoir decline rate over the last

year from 22% to 10%.

At Kaybob Notikewan:• Installed a wellhead compressor resulting in a production increase of 260 mcf/d net to Pengrowth• Removed gathering system restrictions for a production increase of 65 mcf/d net to Pengrowth.

At Nipisi:• Drilled one successful oil well and one water injector. Both wells are currently being tied in.

At Deer Mountain:• Pengrowth assumed the operatorship of this 78% Pengrowth-owned oil unit enabling Pengrowth to

better initiate optimization and development work. Several opportunities are being evaluated.

At Weyburn Unit:• Pengrowth has a 9.75% working interest in the PanCanadian operated Weyburn Unit. • The carbon dioxide (CO2) project has begun to show favorable performance in the third quarter of

2001. CO2 injection has commenced in seventeen of nineteen initial patterns and six patterns havealready exhibited production response. The incremental oil production is currently 1,900 bpd(185 bpd net to Pengrowth) and is increasing. The gross unit production for the third quarteraveraged 19,200 bpd, 1,872 bpd net to Pengrowth.

At House Mountain:• Oil production decreased approximately 20% in the month of September due to an Apache gas plant

maintenance turnaround. It is anticipated that oil production volumes will return to the pre-turnaround level in October.

At Monogram:• A number of compressor failures at this PanCanadian operated property have delayed the

incremental production expected from the recent 40 well infill drilling program. The compressorproblems are expected to be remedied during October.

• Pengrowth participated in the drilling of two successful non-unit Belly River wells during the thirdquarter. These wells will be placed on production in October.

At Minnehik Buck Lake:• Pengrowth holds a 17.9% working interest in the Minnehik Buck Lake Gas Unit #1 where gas

production for the third quarter averaged 3.8 mmcf/d and 175 bbls of NGLs net to Pengrowth. Theoperator, Penn West, has recently completed three successful gas wells which are currentlyproducing at a combined raw gas rate of 3.6 mmcf/d (Pengrowth share 640 mcf/d).

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Sable Island Complex

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At Sable:• Record levels of production were achieved from the Sable project in the third quarter with gross raw

gas volumes averaging 543 mmcf/d (45.6 mmcf/d Pengrowth share). Net sales gas volumes averaged42.5 mmcf/d during the quarter, 10% over our expectations.

• Venture 2, a successful development well, was placed on stream during August and averaged60 mmcf/d raw gas in September (Pengrowth share 5 mmcf/d).

• A well is currently being drilled in the Thebaud gas field. Testing and completion operations areexpected to occur during October.

2001 Tax Estimate Update

Pengrowth forecasts that in the current commodity price environment, approximately 60% ofdistributions paid in 2001 will be taxable to unitholders, with the remainder of distributions treated asreturn of capital and thus tax deferred. The taxability may be reduced if Pengrowth makes additionalacquisitions and issues new equity during the balance of the year.

New Capital Markets

Pengrowth continues its endeavours regarding the potential of listing on stock exchanges and raisingequity financing in the United States. Pengrowth has initiated this process with the intent of improvingmarket liquidity and investor demand.

PENGROWTH CORPORATIONJames S. Kinnear, President

November 26, 2001

For further information, please contact:

Dan Belot, Manager, Investor Relations, CalgaryTelephone: (403) 233-0224 Facsimile: (403) 294-0051 Toll Free: 1-800-223-4122

Sally Elliott, Investor Relations, TorontoTelephone: (416) 362-1748 Facsimile: (416) 362-8191 Toll Free: 1-888-744-1111

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(Stated in thousands of dollars)As at As at

September 30 December 312001 2000

ASSETS (unaudited) (audited)CURRENT ASSETSCash $ 6,719 $ 4,533 Deposit on acquisition 3,000 –Accounts receivable 31,157 33,103Inventory 3,123 8,509

43,999 46,145

REMEDIATION TRUST FUND 6,045 5,515

PROPERTY, PLANT AND EQUIPMENT AND OTHER ASSETS 1,271,801 1,038,823

$ 1,321,845 $ 1,090,483

LIABILITIES AND UNITHOLDERS' EQUITYCURRENT LIABILITIESAccounts payable and accrued liabilities $ 25,010 $ 40,396Distributions payable to unitholders 33,247 48,010Due to Pengrowth Management Limited 513 1,941Current portion of obligation under capital lease 175 553

58,945 90,900

LONG-TERM DEBT (Note 3) 389,760 286,823

FUTURE SITE RESTORATION COSTS 30,286 25,285

FUTURE INCOME TAXES (Note 7) 71,062 45,510

TRUST UNITHOLDERS' EQUITY (Note 4) 771,792 641,965

$ 1,321,845 $ 1,090,483

COMMITMENT (Note 8)

See accompanying notes to the consolidated financial statements.

CONSOLIDATED BALANCE SHEETS

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(Stated in thousands of dollars) Three months ended Nine months ended(unaudited) September 30 September 30

2001 2000 2001 2000REVENUES

Oil and gas sales $ 115,847 $ 103,550 $ 379,851 $ 285,435Processing and other income 2,024 1,228 5,383 3,738Crown royalties (14,282) (17,361) (56,197) (47,873)Alberta Royalty Tax Credit 125 125 375 392Freehold royalties and mineral taxes (1,586) (1,852) (5,861) (4,982)

102,128 85,690 323,551 236,710Interest and other income 99 2,298 1,162 3,538

NET REVENUE 102,227 87,988 324,713 240,248

EXPENSESOperating 32,479 16,767 76,269 46,288Amortization of injectants for miscible floods 12,553 9,021 35,071 22,980Interest 4,902 4,373 14,831 12,154General and administrative 1,712 1,862 5,339 5,129Management fee 1,420 1,479 6,134 4,890Capital taxes 400 412 2,212 1,166Depletion and depreciation 33,293 21,054 90,041 63,806Future site restoration 1,946 1,881 5,502 5,735

88,705 56,849 235,399 162,148

INCOME BEFORE THE FOLLOWING 13,522 31,139 89,314 78,100

ROYALTY INCOME ATTRIBUTABLE TO ROYALTY UNITSOTHER THAN THOSE HELD BY PENGROWTH ENERGY TRUST 12 17 52 48

NET INCOME 13,510 31,122 89,262 78,052

Add: Depletion, depreciation and future site restoration 35,239 22,935 95,543 69,541Alberta Royalty Credit received during period – – 517 1,378

Deduct: Alberta Royalty Credit accrued for period (125) (125) (375) (392)Remediation expenses and trust fund contributions (300) (769) (1,157) (1,855)

DISTRIBUTABLE INCOME $ 48,324 $ 53,163 $ 183,790 $ 146,724

NET INCOME PER UNIT (Note 4) Basic $ 0.179 $ 0.564 $ 1.293 $ 1.431

Diluted $ 0.179 $ 0.552 $ 1.288 $ 1.414

DISTRIBUTABLE INCOME PER UNIT (Note 4)Based on weighted average units outstanding $ 0.641 $ 0.963 $ 2.661 $ 2.691

Based on actual distributions paid or declared $ 0.630 $ 0.960 $ 2.600 $ 2.675

See accompanying notes to the consolidated financial statements.

CONSOLIDATED STATEMENTS OF INCOME AND DISTRIBUTABLE INCOME

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(Stated in thousands of dollars) Three months ended Nine months ended(unaudited) September 30 September 30

2001 2000 2001 2000CASH PROVIDED BY (USED FOR):

OPERATINGNet income $ 13,510 $ 31,122 $ 89,262 $ 78,052Items not involving cashDepletion, depreciation and future site restoration 35,239 22,935 95,543 69,541Amortization of injectants 12,553 9,021 35,071 22,980Purchase of injectants (10,082) (13,069) (50,196) (30,063)Expenditures on remediation (85) (332) (501) (694)

Funds generated from operations 51,135 49,677 169,179 139,816

Distributions (56,438) (46,329) (198,553) (136,415)Changes in non-cash operating working capital (Note 5) 8,416 471 (9,429) (4,323)

3,113 3,819 (38,803) (922)

FINANCINGChange in long-term debt 14,812 15,636 102,559 26,946Proceeds from issue of trust units 5,043 9,048 224,355 28,415

19,855 24,684 326,914 55,361

INVESTINGDeposit on acquisition – (7,740) (3,000) (7,740)Expenditures on property acquisitions (1,611) – (251,320) –Expenditures on property, plant and equipment (20,823) (16,204) (54,588) (43,865)Proceeds on property dispositions 1,520 – 23,566 –Change in Remediation Trust Fund (153) 163 (530) 336Marketable securities – 720 – 64Change in non-cash investing working capital (Note 5) 2,411 – (53) –

(18,656) (23,061) (285,925) (51,205)

INCREASE IN CASH 4,312 5,442 2,186 3,234

CASH AND TERM DEPOSITS (BANK INDEBTEDNESS)AT BEGINNING OF PERIOD 2,407 (3,463) 4,533 (1,255)

CASH AT END OF PERIOD $ 6,719 $ 1,979 $ 6,719 $ 1,979

See accompanying notes to the consolidated financial statements.

CONSOLIDATED STATEMENTS OF CASH FLOW

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(Stated in thousands of dollars) Three months ended Nine months ended(unaudited) September 30 September 30

2001 2000 2001 2000

Unitholders' equity at beginning of period $ 801,563 $ 531,326 $ 641,965 $ 558,590

Units issued, net of issue costs 5,043 9,048 224,355 28,415

Net income for period 13,510 31,122 89,262 78,052

Distributable income (48,324) (53,163) (183,790) (146,724)

TRUST UNITHOLDERS' EQUITY AT END OF PERIOD $ 771,792 $ 518,333 $ 771,792 $ 518,333

CONSOLIDATED STATEMENTS OF TRUST UNITHOLDERS' EQUITY

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PENGROWTH ENERGY TRUSTNOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTSSEPTEMBER 30, 2001(Tabular amounts are stated in thousands of dollars except per unit amounts)

1. SIGNIFICANT ACCOUNTING POLICYThe interim consolidated financial statements of Pengrowth Energy Trust (“Pengrowth”) have beenprepared by management in accordance with accounting principles generally accepted in Canada. Theinterim consolidated financial statements have been prepared following the same accounting policies andmethods of computation as the consolidated financial statements for the fiscal year ended December 31,2000. The disclosures provided below are incremental to those included with the annual consolidatedfinancial statements. The interim consolidated financial statements should be read in conjunction with theconsolidated financial statements and the notes thereto in Pengrowth’s annual report for the year endedDecember 31, 2000.

2. ACQUISITIONIn June 2001, Pengrowth acquired an interest in an oil and gas property for cash consideration of$228 million.

3. LONG-TERM DEBTPengrowth has a $415 million revolving credit facility syndicated among nine financial institutions withan extendible 364 day revolving period and a three year amortization term period. In addition, it has a$35 million demand operating line of credit that is currently reduced by outstanding letters of credit inthe amount of approximately $10 million. Pengrowth is currently negotiating an additional increase in itsborrowing capacity with lenders in recognition of recent acquisitions.

4. TRUST UNITSThe authorized capital of Pengrowth is 500,000,000 trust units.

September 30, 2001 December 31, 2000Number Number

Trust Units Issued of units Amount of units Amount

Balance, beginning of period 63,852,198 $ 974,724 53,639,338 $ 796,224

Issued for cash 10,895,000 225,526 8,165,000 155,135

Less: issue expenses – (13,415) – (8,303)

Issued for cash on exercise of stock options 623,428 9,992 1,915,833 29,299

Issued for cash under DistributionReinvestment (“DRIP”) Plan 116,631 2,252 132,027 2,369

Balance, end of period 75,487,257 $1,199,079 63,852,198 $ 974,724

The per unit amounts for net income and distributable income are based on weighted average unitsoutstanding for the period. The weighted average units outstanding for the three months endedSeptember 30, 2001 were 75,341,684 units and for the nine months ended September 30, 2001 were69,060,613 units (three months ended September 30, 2000 – 55,215,392 units, nine months endedSeptember 30, 2000 – 54,531,353 units). In computing diluted net income per unit, 82,479 units wereadded to the weighted average number of units outstanding during the quarter ended September 30,2001 (September 30, 2000 – 337,312 units) and 265,595 units were added for the nine months endedSeptember 30, 2001 (nine months ended September 30, 2000 – 296,226 units) for the dilutive effect ofemployee stock options. The per unit amount of distributions paid or declared reflect actual distributionspaid or declared based on units outstanding at the time.

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Trust Unit Option PlanAs at September 30, 2001, options to purchase 3,120,405 trust units were outstanding (December 31,2000 - 2,893,554) that expire at various dates to August 31, 2006.

September 30, 2001 December 31, 2000

Trust Unit Options Weighted WeightedNumber Average Number Average

of options Exercise price of options Exercise price

Outstanding at beginning of period 2,893,554 $ 17.45 4,041,287 $ 16.16

Granted 905,979 17.66 821,100 18.73

Exercised (623,428) 16.03 (1,915,833) 15.29

Cancelled (55,700) 19.01 (53,000) 16.85

Outstanding at period-end 3,120,405 $ 17.77 2,893,554 $ 17.45

Exercisable at period-end 2,013,452 $ 17.54 2,171,087 $ 17.51

5. CHANGE IN NON-CASH OPERATING WORKING CAPITAL

Three months ended Nine months endedSeptember 30 September 30

2001 2000 2001 2000

Accounts receivable $ 6,675 $(3,341) $ 5,739 $(11,721)

Inventory 4,143 675 5,386 (265)

Accounts payable and accrued liabilities (1,371) 2,649 (19,126) 7,587

Due to Pengrowth Management Limited (1,031) 488 (1,428) 76

$ 8,416 $ 471 $ (9,429) $ (4,323)

CHANGE IN NON-CASH INVESTING WORKING CAPITAL

Three months ended Nine months endedSeptember 30 September 30

2001 2000 2001 2000

Accounts payable for capital accruals $ 2,024 $ — $ 3,740 $ —

Note receivable on disposition of properties 387 — (3,793) —

$ 2,411 $ — $ (53) $ —

The cash payments made for taxes for the quarter ending September 30, 2001 were $405,000(September 30, 2000 – $413,000) and for the nine months ended September 30, 2001 were $2,234,000(nine months ended September 30, 2000 – $1,191,000). Cash payments for interest for the quarter endingSeptember 30, 2001 were $3,865,000 (September 30, 2000 – $1,588,000) and for the nine months endedSeptember 30, 2001 were $19,045,000 (nine months ended September 30, 2000 – $10,830,000)

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6. FINANCIAL INSTRUMENTSForward and Futures ContractsPengrowth has a price risk management program whereby the commodity price associated with a portionof its future production is fixed. Pengrowth sells forward a portion of its future production through acombination of fixed price sales contracts with customers and commodity swap agreements with financialcounterparties. The forward and futures contracts are subject to market risk from fluctuating commodityprices and exchange rates however, gains or losses on the contracts are offset by changes in the value ofPengrowth’s production.

As at September 30, 2001, Pengrowth had fixed the price applicable to future production as follows:

Crude Oil Natural GasVolume Price Volume Plantgate Price

(bbl/d) C$/bbl (mcf/d) C$/mcf

2001 4,000* $39.32 10,508 $2.982002 1,000* $42.20 7,736 $2.98

*Contract ends June 30, 2002

The estimated fair value of the crude oil financial swap contracts and the natural gas fixed price salescontracts have been determined based on the amounts Pengrowth would receive or pay to terminate thecontracts at period-end. At September 30, 2001 the amount Pengrowth would receive if the crude oilcontracts were terminated would be $1,861,000. Pengrowth would pay $1,271,000 at September 30,2001 to terminate the natural gas contracts.

7. INCOME TAXESThe net book value of property, plant and equipment exceed the cost basis for income tax purposes by$159,332,000 and a future income liability of $71,062,000 has been recorded in respect thereof.

8. COMMITMENTPengrowth has entered into an agreement with the Province of Nova Scotia whereby Pengrowth may berequired to purchase the shares of Nova Scotia Resources Limited for $65 million, subject to satisfactionof certain conditions by the Province of Nova Scotia.

DIRECTORS OF PENGROWTH CORPORATIONThomas A. CummingBusiness Consultant

James S. KinnearPresident, Pengrowth Management Limited

Francis G. VetschPresident, Quantex Resources Ltd.

Stanley H. WongPresident, Carbine Resources Ltd.

John B. ZaozirnyCounsel, McCarthy Tetrault

Director EmeritusThomas S. DobsonPresident, T.S. Dobson Consultant Ltd.

OFFICERS OF PENGROWTH CORPORATIONJames S. KinnearPresident and Chief Executive Officer

Robert J. WatersVice-President, Finance and Chief Financial Officer

Gordon M. AndersonVice-President, Treasurer

Henry D. McKinnonVice-President, Operations

Charles V. SelbyCorporate Secretary

TRUSTEEComputershare Trust Company of Canada

BANKERSBank Syndicate Agent: Royal Bank of Canada

AUDITORSKPMG LLP

ENGINEERING CONSULTANTSGilbert Laustsen Jung Associates Ltd.

STOCK EXCHANGE LISTINGSThe Toronto Stock ExchangeSymbol PGF.UN

PENGROWTH ENERGY TRUSTHead OfficeSuite 700, 112 - 4 Avenue S.W.Calgary, Alberta T2P 0H3 CanadaTelephone: (403) 233 0224Toll-Free: 1 800 223 4122Facsimile: (403) 265 6251Email: pengrowth@pengrowth.comWebsite: http://www.pengrowth.com

Toronto Investor Relations OfficeSuite 1200, 141 Adelaide Street W.Toronto, Ontario M5H 3L5 CanadaTelephone: (416) 362 1748Toll-Free: 1 888 744 1111Facsimile: (416) 362 8191

ABBREVIATIONSbbl barrelmbbls thousand barrelsmmbbls million barrelsbpd barrels per daybopd barrels of oil per dayboe* barrels of oil equivalentmboe* thousand barrels of oil equivalentmmboe* million barrels of oil equivalentboepd* barrels of oil equivalent per daymcf thousand cubic feetmcf/d thousand cubic feet per daymmcf million cubic feetmmcf/d million cubic feet per daybcf billion cubic feetPengrowth Energy Trust (EnergyTrust)Pengrowth Corporation (Corporation)*6 mcf of gas = 1 barrel of oil

Printed in Canada by Quebecor World Calgary.

C O R P O R A T E I N F O R M A T I O N

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The Benchmark of Energy Trusts

Head OfficeSun Life Plaza - East TowerSuite 700, 112 - 4th Avenue S.W.Calgary, Alberta T2P 0H3 CanadaWebsite: http://www.pengrowth.com