Pengrowth Energy Trust
TSX : PGF.A
TSX : PGF.B
NYSE : PGH

Pengrowth Energy Trust
Pengrowth Corporation

Pengrowth Corporation

November 03, 2005 22:50 ET

Pengrowth Energy Trust Announces Third Quarter 2005 Results

CALGARY, ALBERTA--(CCNMatthews - Nov. 3, 2005) - Pengrowth Corporation ("Pengrowth"), administrator of Pengrowth Energy Trust (TSX:PGF.A) (TSX:PGF.B) (NYSE:PGH), announced the interim unaudited operating and financial results for the three month and nine month periods ended September 30, 2005.

- During the third quarter of 2005, Pengrowth generated record distributable cash at $162 million versus $104 million in the third quarter of 2004, an increase of more than 55 percent. This is the third consecutive quarter of record distributable cash. Distributable cash for the first nine months of 2005 increased 43 percent to $424 million from $296 million in the comparable period of 2004 representing the highest level of distributable cash generated over any three consecutive quarters in Pengrowth's history.

- Distributions to unitholders in the quarter totaled $0.69 per trust unit representing a payout ratio of 69 percent of cash generated from operations. Pengrowth's year-to-date payout ratio decreased to approximately 77 percent of cash generated from operations, representing the lowest payout ratio for any nine month period on record. The decrease in payout ratio is mainly a result of higher commodity prices and production.

- Pengrowth is pleased to announce an increase in monthly distributions for the fourth quarter of 2005 from $0.23 to $0.25 per trust unit beginning with the December 15, 2005.

- Capital expenditures for the first nine months of 2005 of $115 million were fully funded with retained cash and proceeds from the exercise of trust unit rights and options. Pengrowth currently anticipates the full year 2005 capital program to total $185 million.

- During the third quarter, Pengrowth executed purchase and sale agreements with several parties for the sale of certain non-core Pengrowth properties with associated production estimated at 200 barrels of oil equivalent per day for gross proceeds of approximately $19 million. In addition, Pengrowth is working towards finalizing purchase and sale agreements with several parties for gross proceeds of $20 million and associated production estimated at 400 barrels of oil equivalent per day.

- At the end of the third quarter of 2005, Pengrowth was capitalized with 12 percent net debt (long-term debt less working capital) representing a net debt to annualized cash flow from operations of 0.8 times.

- The strategy of Pengrowth's board is to continue to seek long life reservoirs with large reserves in place particularly where Pengrowth can augment value through enhanced recovery techniques. In order to increase the efficiency of our operations and to add momentum to value enhancing activities, Pengrowth has actively sought and successfully retained senior operations management. Pengrowth is pleased to welcome Larry Strong, Vice President, Geosciences; Jim Causgrove, Vice President, Production and Operations; and Bill Christensen, Vice President, Strategic Planning and Reservoir Exploitation to the Pengrowth team.

Note regarding currency: All figures contained within this report are quoted in Canadian dollars unless otherwise indicated.



Summary of Financial and Operating Results

Three Months ended
September 30 %
($thousands, except per unit amounts) 2005 2004 Change

INCOME STATEMENT
Oil and gas sales $ 304,484 $ 226,514 34%

Net income $ 100,243 $ 51,271 96%
Net income per unit $ 0.63 $ 0.38 66%

Cash generated from operations $ 158,976 $ 116,258 37%
Cash generated from operations
per unit $ 1.00 $ 0.86 16%

Distributable cash(1) $ 162,009 $ 104,304 55%
Distributable cash per unit(1) $ 1.02 $ 0.77 32%
Distributions $ 109,853 $ 93,870 17%
Distributions paid or declared
per unit $ 0.69 $ 0.67 3%

Weighted average number of
units outstanding 158,789 135,906 17%

BALANCE SHEET
Working capital $ (77,528) $ (311,352) (75)%
Property, plant and equipment
and other assets $ 2,090,399 $1,985,737 5%
Long-term debt $ 422,220 $ 355,320 19%
Unitholders' equity $ 1,467,859 $1,235,575 19%
Unitholders' equity per unit $ 9.22 $ 9.06 2%

Number of units outstanding
at period end 159,263 136,449 17%

DAILY PRODUCTION
Crude oil (barrels) 20,660 20,735 0%
Heavy oil (barrels) 5,405 6,507 (17)%
Natural gas (thousands of
cubic feet) 164,288 166,618 (1)%
Natural gas liquids (barrels) 5,448 5,139 6%
Total production (boe) 58,894 60,151 (2)%

TOTAL PRODUCTION (mboe) 5,418 5,534 (2)%

PRODUCTION PROFILE
Crude oil 35% 34%
Heavy oil 9% 11%
Natural gas 47% 46%
Natural gas liquids 9% 9%

AVERAGE REALIZED PRICES
Crude oil (per barrel) $ 63.95 $ 45.15 42%
Heavy oil (per barrel) $ 47.74 $ 37.96 26%
Natural gas (per mcf) $ 8.57 $ 6.36 35%
Natural gas liquids (per barrel) $ 57.75 $ 42.33 36%
Average realized price per boe $ 56.07 $ 40.90 37%


(1) See the section entitled "Non-GAAP Financial Measures"


Nine Months ended
September 30 %
($thousands, except per unit amounts) 2005 2004 Change

INCOME STATEMENT
Oil and gas sales $ 797,587 $ 592,569 35%

Net income $ 209,663 122,607 71%
Net income per unit $ 1.34 $ 0.93 44%

Cash generated from operations $ 421,482 $ 310,880 36%
Cash generated from operations
per unit $ 2.70 $ 2.35 15%

Distributable cash(1) $ 423,860 $ 296,220 43%
Distributable cash per unit(1) $ 2.71 $ 2.24 21%
Distributions $ 326,119 $ 266,595 22%
Distributions paid or declared
per unit $ 2.07 $ 1.94 7%

Weighted average number of units
outstanding 156,318 132,213 18%

BALANCE SHEET
Working capital $ (77,528)$ (311,352) (75)%
Property, plant and equipment
and other assets $ 2,090,399 $ 1,985,737 5%
Long-term debt $ 422,220 $ 355,320 19%
Unitholders' equity $ 1,467,859 $ 1,235,575 19%
Unitholders' equity per unit $ 9.22 $ 9.06 2%

Number of units outstanding
at period end 159,263 136,449 17%

DAILY PRODUCTION
Crude oil (barrels) 20,670 21,051 (2)%
Heavy oil (barrels) 5,695 2,799 103%
Natural gas (thousands of
cubic feet) 158,426 140,133 13%
Natural gas liquids (barrels) 5,885 5,246 12%
Total production (boe) 58,654 52,452 12%

TOTAL PRODUCTION (mboe) 16,013 14,372 11%

PRODUCTION PROFILE
Crude oil 35% 40%
Heavy oil 10% 5%
Natural gas 45% 45%
Natural gas liquids 10% 10%

AVERAGE PRICES
Crude oil (per barrel) $ 58.31 $ 42.71 37%
Heavy oil (per barrel) $ 33.82 $ 36.25 (7)%
Natural gas (per mcf) $ 7.61 $ 6.72 13%
Natural gas liquids (per barrel) $ 52.59 $ 40.21 31%
Average price per boe $ 49.66 $ 41.05 21%


(1) See the section entitled "Non-GAAP Financial Measures"


Summary of Trust Unit Trading Data




(thousands, Three Months ended Nine Months ended
except per September 30 September 30
unit amounts) 2005 2004 2005 2004

TRUST UNIT
TRADING
(Class A)
PGH (NYSE)
after unit
re-class(1)
High $ 25.75 U.S. $ 18.94 U.S. $ 25.75 U.S $ 18.94 U.S.
Low $ 21.55 U.S. $ 14.40 U.S. $ 18.11 U.S $ 14.40 U.S.
Close $ 25.42 U.S. $ 17.93 U.S. $ 25.42 U.S $ 17.93 U.S.
Value $340,318 U.S. $350,374 U.S. $1,190,435 U.S $350,374 U.S.
Volume
(thousands
of units) 14,502 21,200 55,276 21,200
PGF.A (TSX)(1)
High $ 30.10 $ 24.19 $ 30.10 $ 24.19
Low $ 26.30 $ 19.10 $ 22.15 $ 19.10
Close $ 29.50 $ 22.67 $ 29.50 $ 22.67
Value $ 58,000 $ 35,524 $ 157,672 $ 35,524
Volume
(thousands
of units) 2,047 1,672 5,894 1,672

TRUST UNIT
TRADING
(Class B)
PGF.B (TSX)(1)
High $ 21.26 $ 20.00 $ 21.26 $ 20.00
Low $ 18.25 $ 18.03 $ 16.10 $ 18.03
Close $ 20.58 $ 18.87 $ 20.58 $ 18.87
Value $441,039 $105,650 $1,327,210 $105,650
Volume
(thousands
of units) 22,738 5,588 71,326 5,588

TRUST UNIT
TRADING
(before unit
re-class)
PGH (NYSE)
before unit
re-class(1)
High $ 14.95 U.S. $ 14.95 U.S.
Low $ 13.84 U.S. $ 11.62 U.S.
Close $ 14.64 U.S. $ 14.64 U.S.
Value $ 84,506 U.S. $905,950 U.S.
Volume
(thousands
of units) 5,797 64,890
PGF.UN (TSX)(1)
High $ 19.75 $ 21.25
Low $ 18.52 $ 15.55
Close $ 19.42 $ 19.42
Value $ 68,531 $964,766
Volume
(thousands
of units) 3,554 52,319

(1) July 27, 2004, all trust units were re-classified into Class A or
Class B trust units.

Class A trust units trade on the NYSE under PGH and on the TSX under
PGF.A. Class B trust units trade only on the TSX under PGF.B.


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, including the business risks discussed below, 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.

When converting natural gas to equivalent barrels of oil within this discussion, Pengrowth uses the international standard of 6 thousand cubic feet (mcf) to one barrel of oil equivalent (boe). Production volumes and revenues are reported on a gross basis (before royalties) in accordance with Canadian practice. All amounts are stated in Canadian dollars unless otherwise specified.

Non-GAAP Financial Measures

This discussion and analysis refers to certain financial measures that are not determined in accordance with Canadian Generally Accepted Accounting Principals (GAAP). These measures do not have standardized meanings and may not be comparable to similar measures presented by other trusts or corporations. Measures such as distributable cash, distributable cash per trust unit and operating netbacks do not have standardized meanings prescribed by GAAP. During the second quarter of 2005, Pengrowth's withholding practice and presentation of distributable cash changed. The impact of the new practice is discussed in the Distributions and Taxability of Distributions section of this report, while the remaining non-GAAP measures are determined by reference to our financial statements. We discuss these measures because we believe that they facilitate the understanding of the results of our operations and financial position.

Overview

For the third consecutive quarter, Pengrowth achieved record net income and cash generated from operations in the third quarter of 2005. Also during the third quarter, Pengrowth divested certain non-core oil and natural gas properties for proceeds of approximately $19 million.

Continued strength in commodity prices and additional production from the Swan Hills Unit No. 1 and Crispin Energy Inc. acquisitions, which closed on February 28, 2005 and April 29, 2005, respectively, had a favourable impact on 2005 third quarter results relative to the third quarter of 2004.

Net Income

Net income for the third quarter of 2005 was $100.2 million ($0.63 per trust unit) compared to $51.3 million ($0.38 per trust unit) for the third quarter of 2004. For the first nine months of 2005 Pengrowth recorded net income of $209.7 million ($1.34 per trust unit) compared to $122.6 million ($0.93 per trust unit) for the first nine months of 2004. The increase in net income for the third quarter of 2005 compared to the same period last year is due mainly to a 37 percent increase in average commodity prices.

Production

Production for the third quarter of 2005 decreased approximately two percent compared to the third quarter of 2004. Natural production declines more than offset the increased production associated with ongoing development activities, the increased working interest in Swan Hills Unit No. 1, the Crispin acquisition and an additional shipment of condensate from the Sable Offshore Energy Project (SOEP). Third quarter production increased approximately two percent versus the second quarter of 2005 largely as a result of increased gas production at SOEP and Judy Creek.

On a year-to-date basis, production for the nine months ended September 30, 2005 was 12 percent higher than the same period last year, primarily due to the Murphy, Swan Hills Unit No. 1 and Crispin acquisitions and the contributions from ongoing development activities.



Daily Production
Three months ended Nine months ended
Sept 30, Jun 30, Sept 30, Sept 30, Sept 30,
2005 2005 2004 2005 2004
---------------------------------------------------------------------

Light crude oil (bbls) 20,660 20,906 20,735 20,670 21,051
Heavy oil (bbls) 5,405 5,641 6,507 5,695 2,799
Natural gas (mcf) 164,288 153,423 166,618 158,426 140,133
Natural gas liquids
(bbls) 5,448 5,870 5,139 5,885 5,246
---------------------------------------------------------------------
Total boe per day 58,894 57,988 60,151 58,654 52,452
---------------------------------------------------------------------
---------------------------------------------------------------------


Third quarter 2005 light crude oil production volumes remained relatively flat versus both the second quarter of 2005 and the third quarter of 2004. The Swan Hills Unit No. 1 and Crispin acquisitions, in addition to development activities over the past year, combined to offset natural production declines.

Heavy oil production decreased 17 percent in the third quarter of 2005 compared to the same period in 2004 and approximately four percent from the second quarter of 2005. The decrease is due to natural production declines, particularly at Tangleflags and Bodo.

Natural gas production remained unchanged in the third quarter of 2005 compared to the third quarter of 2004. Incremental volumes from development activities, including the Monogram area, as well as the Crispin acquisition largely offset the impact of natural production declines. Natural gas production was up seven percent versus the second quarter of 2005 resulting from additional volumes from SOEP and Judy Creek.

Natural gas liquids (NGL) production increased by six percent in the third quarter of 2005 over the same quarter of 2004 while decreasing seven percent versus the second quarter of 2005. The fluctuation in NGL sales is due in part to the timing of condensate sales from SOEP.

Prices

Pengrowth's average commodity price per boe for the third quarter of 2005, after the impact of hedging, was 37 percent higher than the third quarter of 2004 and 17 percent higher than the second quarter of 2005.



Average realized
prices Cdn$ Three months ended Nine months ended
(after the Sept 30, Jun 30, Sept 30, Sept 30, Sept 30,
impact of hedging) 2005 2005 2004 2005 2004
---------------------------------------------------------------------
Light crude oil
(per bbl) $63.95 $56.44 $45.15 $58.31 $42.71
Heavy oil (per bbl) 47.74 30.32 37.96 33.82 36.25
Natural gas (per mcf) 8.57 7.34 6.36 7.61 6.72
Natural gas liquids
(per bbl) 57.75 50.03 42.33 52.59 40.21
---------------------------------------------------------------------
Total per boe $56.07 $47.79 $40.90 $49.66 $41.05
---------------------------------------------------------------------
---------------------------------------------------------------------


Pengrowth's average realized light crude oil price, net of hedging losses, increased 42 percent in the third quarter of 2005 and 37 percent for the first nine months compared to the same periods of 2004. The West Texas Intermediate (WTI) benchmark price increased 44 percent in the third quarter of 2005 compared to the same period last year. This was partially offset by the appreciation in the Canadian dollar relative to the U.S. dollar. Pengrowth's average realized light crude oil price for the third quarter of 2005, net of hedging losses, increased 13 percent compared to the second quarter of 2005.

Pengrowth's average realized heavy oil price increased 26 percent in the third quarter of 2005 compared with the third quarter of 2004 and 57 percent versus the second quarter of 2005. The year-to-date average realized heavy oil price for the first nine months of 2005 compared to the same period of 2004 decreased seven percent largely as a result of widening in the light/heavy price differential and the increasing cost of diluent used to process the oil for transport.

Pengrowth's average realized natural gas price, net of hedging losses, for the third quarter of 2005 increased 35 percent to $8.57 per mcf compared to $6.36 per mcf over the same period last year, while also increasing 17 percent versus the second quarter of 2005 price of $7.34 per mcf. Pengrowth's average natural gas price increased year over year by 13 percent to $7.61 per mcf. By comparison on a year to date basis, the NYMEX last day average price increased by 23 percent while the AECO monthly spot price increased 11 percent. Certain fixed price gas contracts which were associated with the Murphy acquisition also partially offset the increase in market prices.

Price Risk Management Program

Pengrowth uses forward price swap and option contracts to manage its exposure to commodity price fluctuations, to provide a measure of stability to our monthly cash distributions and to partially secure returns on new acquisitions. On a combined basis, oil and gas hedging losses were $21.6 million ($3.99 per boe) for the third quarter and $38.1 million ($2.38 per boe) for the first nine months of 2005 compared to $18.9 million ($3.42 per boe) and $46.4 million ($3.23 per boe) for the respective periods of 2004.

With the continued strength in crude oil prices in the third quarter, Pengrowth realized a net hedging loss of $19.8 million ($10.42 per bbl) on crude oil price swap transactions, compared to a loss of $17.9 million ($9.38 per bbl) in the third quarter of 2004. On a year-to-date basis, Pengrowth has realized a net hedging loss of $37.4 million ($6.63 per bbl) for the first nine months of 2005 on crude oil price swap transactions, compared to a net hedging loss of $37.8 million ($6.55 per bbl) for the first nine months of 2004.

In the third quarter of 2005, Pengrowth realized a net hedging loss of $1.8 million ($0.12 per mcf) related to natural gas financial swap contracts, compared to a net hedging loss of $1.0 million ($0.07 per mcf) for the same period last year. On a year-to-date basis, Pengrowth has realized a net hedging loss of $0.7 million ($0.02 per mcf) in the first nine months of 2005 related to natural gas financial swap contracts, compared to a net hedging loss of $8.6 million ($0.22 per mcf) for the same period of last year.

In conjunction with the Murphy acquisition on May 31, 2004, Pengrowth assumed certain fixed price natural gas sales contracts associated with the Murphy reserves. Under these contracts, Pengrowth is obligated to sell 3,886 mmbtu per day, until April 30, 2009 at an average contract price of Cdn $2.27 per mmbtu. As required by GAAP, the fair value of the contract was recognized as a liability based on the mark-to-market value at May 31, 2004. The liability at September 30, 2005 of $19.7 million will continue to be drawn down and recognized in income as the contract is settled. As this is a non-cash component of income, it is not included in the calculation of distributable cash. At September 30, 2005, the mark-to-market value of Pengrowth's fixed price physical sales contract represented a potential loss of $37.8 million.

In addition, the following table lists the hedging contracts Pengrowth has in place at September 30, 2005.



Crude Oil
Volume Reference Price
Remaining Term (bbl per day) Point per bbl
---------------------------------------------------------------------
2005 - Financial
Oct 1, 2005 - Dec 31, 2005 10,000 WTI (1) $54.39 Cdn

2006 - Financial
Jan 1, 2006 - Dec 31, 2006 4,000 WTI (1) $64.08 Cdn


Natural Gas

Volume Reference Price
Remaining Term (mmbtu per day) Point per mmbtu
---------------------------------------------------------------------
2005 - Financial
Oct 1, 2005 - Dec 31, 2005 11,000 Tetco M3 (1) $ 9.27 Cdn
Oct 1, 2005 - Dec 31, 2005 5,000 Transco Z6 (1) $10.11 Cdn
Oct 1, 2005 - Dec 31, 2005 2,500 NGI Chicago (1) $ 9.41 Cdn
Oct 1, 2005 - Dec 31, 2005 2,500 Nymex (1) $14.07 Cdn
Oct 1, 2005 - Dec 31, 2005 2,370 AECO $ 8.35 Cdn

2006 - Financial
Jan 1, 2006 - Dec 31, 2006 2,500 Transco Z6 (1) $10.63 Cdn
Jan 1, 2006 - Dec 31, 2006 2,370 AECO $ 8.03 Cdn
Jan 1, 2006 - Mar 31, 2006 2,500 Nymex (1) $14.56 Cdn

(1) Associated Cdn$/US$ foreign exchange rate has been fixed.


At September 30, 2005, the mark-to-market value of Pengrowth's commodity hedges represented a potential loss of $64.2 million which consisted of a loss of $25.0 million on natural gas contracts and $39.2 million for crude oil contracts.

Royalties

Royalties, including crown, freehold and overriding royalties, were 19 percent of oil and gas sales in the third quarter of 2005, compared to 22 percent in the third quarter of 2004 and 19 percent in the second quarter of 2005. The decrease in royalty rate from the third quarter of 2004 to the third quarter of 2005 is primarily due to the non-recurring nature of a $4.4 million adjustment for Judy Creek royalties that was included in the third quarter of 2004. For the first nine months, royalties were 18 percent and 19 percent in 2005 and 2004, respectively.

Operating Costs

Operating costs were $57.4 million ($10.59 per boe) for the third quarter of 2005, compared to $47.2 million ($8.53 per boe) for the third quarter of 2004 and $50.4 million ($9.56 per boe) for the second quarter of 2005. For the nine months ended September 30, 2005, operating costs were $156.9 million ($9.80 per boe) compared to $117.1 million ($8.15 per boe) for the same period of 2004. The Murphy, Swan Hills Unit No. 1 and Crispin acquisitions, higher utility and oilfield services costs and the expense associated with the trust unit award plan contributed to higher operating costs in total as well as on a per boe basis compared to the third quarter of 2004 and the second quarter of 2005.

Heavy oil operating costs in 2005 have been impacted by a $2.1 million adjustment related to a prior period expense on a non-operated property and higher costs associated with rising natural gas costs at thermal recovery operations.

Injectants for Miscible Floods

During the third quarter of 2005, Pengrowth purchased and capitalized $6.9 million of injectants and amortized $6.0 million against third quarter net income and distributable cash, compared to $3.0 million and $4.7 million, respectively, in the third quarter of 2004 and $5.7 million and $6.0 million in the second quarter of 2005. On a year-to-date basis, Pengrowth has purchased and capitalized $20.2 million of injectants and amortized $17.3 million, compared to $12.2 million and $14.7 million, respectively, in the same period last year. The increase in injectant costs year over year is due mainly to Pengrowth's increased working interest at Swan Hills Unit No. 1. The majority of ethane and natural gas volumes injected at Judy Creek are proprietary volumes produced from Judy Creek and the Swan Hills area. Revenue is not recorded for volumes that are produced and subsequently re-injected.

At September 30, 2005, the balance of unamortized injectant costs was $27.9 million.

Operating Netbacks

There is no standardized measure of operating netbacks and therefore, operating netbacks, as presented below, may not be comparable to similar measures presented by other companies. Certain assumptions have been made in allocating operating expenses, other production income, other income and royalty injection credits between light crude oil, heavy oil, natural gas and natural gas liquids production.

Operating netbacks during the quarter increased by approximately 49 percent reflecting the overall increase in oil and gas prices, net of hedging, offset partially by the increase in operating costs per boe.



-------------------- -------------------
Three months ended Nine months ended
Combined Netbacks Sept 30, Sept 30, Sept 30, Sept 30,
($ per boe) 2005 2004 2005 2004
-------------------- -------------------
Sales price $ 56.07 $ 40.90 $ 49.66 $ 41.05
Other production income 0.13 0.02 0.15 0.18
-------------------- -------------------
56.20 40.92 49.81 41.23
Processing and other income 0.39 0.53 0.86 0.70
Royalties (10.60) (8.88) (9.11) (7.73)
Operating costs (10.59) (8.51) (9.80) (8.18)
Transportation costs (0.36) (0.44) (0.35) (0.40)
Amortization of injectants (1.10) (0.85) (1.08) (1.02)
-------------------- -------------------
Operating netback $ 33.94 $ 22.77 $ 30.33 $ 24.60
-------------------- -------------------
-------------------- -------------------


-------------------- -------------------
Three months ended Nine months ended
Light Crude Netbacks Sept 30, Sept 30, Sept 30, Sept 30,
($ per bbl) 2005 2004 2005 2004
-------------------- -------------------
Sales price $ 63.95 $ 45.15 $ 58.31 $ 42.71
Other production income 0.37 0.06 0.44 0.44
-------------------- -------------------
64.32 45.21 58.75 43.15
Processing and other income 0.64 0.25 0.51 0.45
Royalties (11.03) (10.29) (9.39) (6.96)
Operating costs (12.85) (9.38) (11.58) (9.34)
Transportation costs (0.29) (0.23) (0.30) (0.23)
Amortization of injectants (3.14) (2.46) (3.07) (2.55)
-------------------- -------------------
Operating netback $ 37.65 $ 23.10 $ 34.92 $ 24.52
-------------------- -------------------
-------------------- -------------------


-------------------- -------------------
Three months ended Nine months ended
Heavy Oil Netbacks Sept 30, Sept 30, Sept 30, Sept 30,
($ per bbl) 2005 2004 2005 2004
-------------------- -------------------
Sales price $ 47.74 $ 37.96 $ 33.82 $ 36.25

Processing and other income (0.83) - 0.24 -
Royalties (8.00) (5.55) (5.03) (5.35)
Operating costs (16.30) (11.20) (16.95) (10.14)
-------------------- -------------------
Operating netback $ 22.61 $ 21.21 $ 12.08 $ 20.76
-------------------- -------------------
-------------------- -------------------



-------------------- -------------------
Three months ended Nine months ended
Natural Gas Netbacks Sept 30, Sept 30, Sept 30, Sept 30,
($ per mcf) 2005 2004 2005 2004
-------------------- -------------------
Sales price $ 8.57 $ 6.36 $ 7.61 $ 6.72

Processing and other income 0.09 0.16 0.24 0.19
Royalties (1.47) (1.27) (1.36) (1.22)
Operating costs (1.31) (1.22) (1.19) (1.15)
Transportation costs (0.09) (0.13) (0.09) (0.11)
-------------------- -------------------
Operating netback $ 5.79 $ 3.90 $ 5.21 $ 4.43
-------------------- -------------------
-------------------- -------------------


-------------------- -------------------
Three months ended Nine months ended
NGL Netbacks Sept 30, Sept 30, Sept 30, Sept 30,
($ per bbl) 2005 2004 2005 2004
-------------------- -------------------
Sales price $ 57.75 $ 42.33 $ 52.59 $ 40.21

Royalties (20.57) (14.19) (16.27) (14.07)
Operating costs (10.13) (8.07) (8.65) (7.95)
Transportation costs - (0.10) - (0.10)
-------------------- -------------------
Operating netback $ 27.05 $ 19.97 $ 27.67 $ 18.09
-------------------- -------------------
-------------------- -------------------


General and Administrative

General and administrative expenses (G&A) were $7.6 million ($1.40 per boe) in the third quarter of 2005 compared to $6.1 million ($1.11 per boe) for the third quarter of 2004. For the first nine months of 2005, G&A was $21.8 million ($1.36 per boe) compared to $17.5 million ($1.22 per boe) for the same period last year. Included in the third quarter of 2005 G&A is $0.6 million of non-cash compensation costs related to trust unit rights and deferred entitlement trust units (see note 1 to consolidated financial statements) compared to $0.6 million for the third quarter of 2004. The year-to-date non-cash component is $2.1 million compared to $1.9 million for the first nine months of 2004. Excluding the non-cash component of G&A, 2005 year-to-date G&A has increased over 2004 levels by $4.1 million mainly due to the addition of personnel and office space required to manage the Murphy assets as well as the expense associated with the trust unit award plan.

Management Fees

Management fees were $3.5 million ($0.65 per boe) for the third quarter of 2005 compared to $2.5 million ($0.45 per boe) for the third quarter of 2004. For the first nine months of 2005, management fees were $11.6 million ($0.72 per boe) for 2005 compared to $10.3 million ($0.72 per boe) for the same period in 2004.

Management fees recorded in the third quarter of 2005 include an accrual for estimated performance fees of $1.9 million. Under the current management agreement, which came into effect July 1, 2003, the manager will earn a performance fee if Pengrowth trust unit total returns exceed eight percent per annum on a three year rolling average basis. The maximum fees payable, including the performance fee, is limited to 80 percent of the fees that would otherwise have been payable under the previous management agreement for the first three years and 60 percent for the subsequent three years. Management fees have increased from 2004 mainly due to higher commodity prices that have increased cash generated from operations.

Interest

Interest expense decreased to $5.6 million in the third quarter of 2005 compared to $8.7 million for the third quarter of 2004 primarily due to reduced debt level. For the first nine months of 2005, interest expense was $16.8 million compared to $20.6 million for the same period of 2004. Interest expense includes $1.2 million of fees on a year-to-date basis related to the amortization of U.S. debt issue costs and imputed interest on the note payable to Emera Offshore Incorporated.

Depletion and Depreciation

Depletion and depreciation costs increased to $73.5 million in the third quarter of 2005 compared to $69.3 million in the third quarter of 2004. For the first nine months of 2005, depletion and depreciation costs were $213.6 million compared to $177.9 million in the first nine months of 2004. On a per boe basis, depletion and depreciation costs have increased to $13.57 per boe in the third quarter of 2005 compared to $12.53 per boe in the third quarter of 2004, and $13.34 per boe on a year-to-date basis, compared to $12.38 per boe in the first nine months of 2004. The increase is mainly attributable to recent purchases, including the Murphy acquisition in May 2004. With the sustained strength in commodity prices in recent years, the higher cost of acquiring oil and gas properties has increased the depletion rate per boe produced.

Distributions and Taxability of Distributions

Pengrowth generated $162.0 million ($1.02 per average trust unit outstanding) of distributable cash related to third quarter 2005 operations, compared to $104.3 million ($0.77 per average trust unit outstanding) in the third quarter of 2004. For the first nine months of 2005, Pengrowth generated $423.9 million distributable cash compared to $296.2 million in the first nine months of 2004. Distributions were $326.1 million for 2005 (2004 - $266.6 million) and as a percentage of cash generated from operations (payout ratio) represent approximately 77 percent (2004 - 86 percent). Pengrowth's previous practice had been to withhold approximately 10 percent of cash available for distribution to repay debt and/or contribute to capital spending. For the third quarter of 2005, the Board of Directors resolved to maintain the existing level of distributions at $0.23 per trust unit. Given the level of current commodity prices, this action has resulted in an increase in cash available to help fund Pengrowth's capital expenditures. Pengrowth is pleased to announce an increase in monthly distributions to $0.25 per trust unit for the fourth quarter of 2005 beginning with the December 15, 2005 distribution.

Cash distributions are paid to unitholders on the 15th day of the second month following the month of production. Pengrowth paid $0.69 per trust unit as cash distributions during the third quarter of 2005.

There is no standardized measure of distributable cash and therefore distributable cash, as reported by Pengrowth, may not be comparable to similar measures presented by other trusts. In conjunction with the change to Pengrowth's withholding practice, distributable cash as presented below may not be comparable to previous disclosures. The following table provides a reconciliation of distributable cash for the three and nine month periods ended September 30, 2005 and 2004.



($thousands, except Three months Nine months
per unit amounts) ended Sept 30 ended Sept 30
------------------------------------------------------------------------
2005 2004 2005 2004
------------------------------------------------------------------------
Cash generated from
operations 158,976 116,258 421,482 310,880
Change in non-cash operating
working capital (789) (9,857) (1,840) (9,749)
Change in deferred injectants 892 (1,663) 2,854 (2,482)
Change in remediation trust funds (272) (276) (803) (949)
Change in deferred charges 2,818 (473) 2,028 (1,420)
Other 384 315 139 (60)
------------------------------------------------------------------------
Distributable cash 162,009 104,304 423,860 296,220
------------------------------------------------------------------------

------------------------------------------------------------------------
Allocation of Distributable Cash
Cash withheld 52,156 10,434 97,741 29,625
Distributions paid or
declared 109,853 93,870 326,119 266,595
------------------------------------------------------------------------
Distributable cash 162,009 104,304 423,860 296,220
------------------------------------------------------------------------
Distributable cash per unit 1.02 0.77 2.71 2.24
Distributions paid or
declared per unit 0.69 0.67 2.07 1.94
Payout ratio 69% 81% 77% 86%
------------------------------------------------------------------------
------------------------------------------------------------------------


At this time, Pengrowth anticipates that approximately 75 to 80 percent of 2005 distributions will be taxable for Canadian residents; 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.

Liquidity and Capital Resources

Pengrowth's long-term debt at September 30, 2005 was $422.2 million, compared to $345.4 million at December 31, 2004 and $355.3 million at September 30, 2004. During the third quarter, Pengrowth received $18.6 million of proceeds from the sale of non-operated oil and natural gas properties. Year-to-date capital expenditures, excluding acquisitions, of $114.5 million were financed through the combination of cash withheld of $97.7 million and of $32.0 million proceeds from the exercise of trust unit rights and options.

Approximately $295 million of a $470 million revolving credit facility and a $35 million demand operating line of credit remain unutilized at September 30, 2005. The remainder of Pengrowth's debt outstanding at the end of the third quarter 2005 is U.S. dollar denominated fixed rate term debt, details of which are provided in Note 2 to the financial statements. Due to the change in the value of the U.S. dollar relative to the Canadian dollar, an unrealized gain of $12.9 million has been recorded in the quarter ended September 30, 2005 ($8.2 million year-to-date) on the U.S. dollar denominated debt. Since the U.S. $200 million denominated debt was issued in April 2003, the Canadian dollar has strengthened significantly, resulting in a cumulative unrealized gain of $58.0 million.

At the end of the third quarter of 2005, Pengrowth was capitalized with 12 percent net debt (long-term debt less working capital) and 88 percent equity, as compared with 20 percent debt and 80 percent equity at the end of the third quarter of 2004 (based on quarter-end market capitalization). The Trust's net debt to annualized cash flow from operations was approximately 0.8 times at the end of the third quarter of 2005, as compared to 1.7 times at the end of the third quarter of 2004.



As of November 2, 2005, the number of trust units outstanding was
approximately:

(000's)
---------------------------------------------------
Class A trust units 77,524
Class B trust units 81,817
Undeclared trust units 43
---------------------------------------------------
Total 159,384


As of November 2, 2005, the number of trust unit options, rights and
deferred entitlement trust units was approximately:

(000's)
---------------------------------------------------
Trust unit options 357
Rights incentive options 1,554
Deferred entitlement trust units 150
---------------------------------------------------


Acquisitions and Dispositions

During the third quarter of 2005, Pengrowth received approximately $19 million of proceeds from the sale of non-core oil and natural gas properties with associated production of approximately 200 boe per day. Due to the timing of the sales, production from these properties is included in the third quarter of 2005 results.

Prior to the third quarter, Pengrowth successfully completed the acquisition of an additional 11.89 percent working interest in the Swan Hills Unit No. 1 property for $87 million which was funded through additional debt. Pengrowth also closed the acquisition of all of the issued and outstanding shares of Crispin Energy Inc. on April 29, 2005 by issuing approximately 677,000 Class A trust units and approximately 3,552,000 Class B trust units, valued at $88 million, and assuming debt of approximately $20 million.

Capital Spending

Capital expenditures for the nine months ending September 30, 2005 totaled $114.5 million including $24.6 million at Judy Creek, $18.5 million at SOEP, $7.8 million at Buick, $5.5 million at Swan Hills Unit No. 1, $4.9 million at Weyburn, and $4.5 million at Squirrel.

Pengrowth currently expects to spend a total of approximately $70 million on development activities in the remaining quarter of 2005 for a total revised capital program of approximately $185 million for full year 2005. The revised capital plan represents a decrease of $30 million or 14 percent from the previous guidance of $215 million. The reduction in the 2005 capital program reflects the impact of limited rig availability and weather related delays in planned development activities which have resulted in deferral of related expenditures to the 2006 capital year. This includes development activity planned at Pengrowth's operated Judy Creek and in Northeast British Columbia properties, as well as additional development drilling and facilities at the non-operated SOEP, Swan Hills Unit No. 1, Quirk Creek and Weyburn properties. Capital expenditures year-to-date have been fully funded from retained cash and proceeds from trust unit rights and options exercised.

Summary of Quarterly Results

The following table is a summary of quarterly results for 2003, 2004 and the first three quarters of 2005. Net income and net income per trust unit for the third quarter of 2005 increased over the second quarter of 2005, mainly due to a 19 percent increase in average per boe price realized as well as a $16 million change in unrealized foreign exchange gain partly offset by increased utility costs and the expense associated with the trust unit award plan.



2005
---------------------------------------------------------------------
Q1 Q2 Q3
---------------------------------------------------------------------
Oil and gas sales ($000's) 239,913 253,189 304,484
Net income ($000's) 56,314 53,106 100,243
Net income per unit ($) 0.37 0.34 0.63
Net income per unit - diluted ($) 0.37 0.34 0.63
Distributable cash ($000's) 127,804 134,047 162,009
Actual distributions paid or
declared per unit ($) 0.69 0.69 0.69
Daily production (boe) 59,082 57,988 58,894
Total production (mboe) 5,317 5,277 5,418
Average realized price per boe
($ per boe) 44.97 47.79 56.07
Operating netback per boe ($ per boe) 27.70 29.26 33.94



2004
---------------------------------------------------------------------
Q1 Q2 Q3 Q4
---------------------------------------------------------------------
Oil and gas sales ($000's) 168,771 197,284 226,514 223,183
Net income ($000's) 38,652 32,684 51,271 31,138
Net income per unit ($) 0.31 0.24 0.38 0.23
Net income per unit - diluted ($) 0.31 0.24 0.38 0.23
Distributable cash ($000's) 92,895 99,021 104,304 104,598
Actual distributions paid or
declared per unit ($) 0.63 0.64 0.67 0.69
Daily production (boe) 45,668 51,451 60,151 57,425
Total production (mboe) 4,156 4,682 5,534 5,283
Average realized price per boe
($ per boe) 40.37 41.83 40.90 42.08
Operating netback per boe
($ per boe) 25.71 25.71 22.77 24.31


2003
---------------------------------------------------------------------
Q1 Q2 Q3 Q4
---------------------------------------------------------------------
Oil and gas sales ($000's) 207,891 171,836 165,601 157,404
Net income ($000's) 62,920 54,214 34,808 37,355
Net income per unit ($) 0.57 0.49 0.29 0.31
Net income per unit - diluted ($) 0.57 0.48 0.29 0.30
Distributable cash ($000's) 108,025 79,695 81,057 77,122
Actual distributions paid or
declared per unit ($) 0.75 0.67 0.63 0.63
Daily production (boe) 50,827 48,839 48,850 47,653
Total production (mboe) 4,574 4,444 4,494 4,384
Average realized price per boe
($ per boe) 45.21 38.60 36.65 35.78
Operating netback per boe
($ per boe) 26.50 21.11 20.54 20.43


Management Appointments

During the third quarter, Pengrowth made several senior management appointments bringing additional operation expertise to the Pengrowth team reflecting Pengrowth's commitment to operational excellence, effective strategic planning and creation of value through further development of Pengrowth's reserves. In each case, the new members of senior management have strong technical backgrounds with leading companies in the oil and gas industry. In the current environment of above average oil and gas prices, Pengrowth's strategic objectives include focused attention on Pengrowth's existing properties and appropriate application of new technology.

- Mr. Larry B. Strong has been appointed Vice President, Geosciences and an Officer of Pengrowth Corporation. He will focus on exploitation and exploration opportunities on Pengrowth's existing land base and will add value in conjunction with new acquisitions. Mr. Strong is a highly qualified geologist with both solid management and business experience. Mr. Strong brings over 20 years experience in Earth Sciences beginning his career as a Petroleum Geologist/Geophysicist with Chevron Canada Resources. Prior to joining Pengrowth, Mr. Strong served in senior geosciences roles at NCE Resources Group and Waterous & Co. and most recently served as an Officer and Vice President of Geosciences at Petrofund Corporation. Mr. Strong holds a Bachelor of Science (Specialist) in Geology and a Minor in Computer Science from Brandon University.

- Mr. William Christensen who is presently consulting to Pengrowth will become Vice President, Strategic Planning and Reservoir Exploitation and an Officer of Pengrowth Corporation upon Canadian immigration approval. Mr. Christensen's responsibilities will include a comprehensive review of past acquisitions and the effectiveness of Pengrowth's exploitation and development programs as a basis for planning effective future initiatives to enhance unitholder value. Mr. Christensen has over 25 years in the energy sector including broad international experience, both in operations and the completion of transactions. Prior to a recent relocation to Houston, Mr. Christensen served as Vice President Planning with Northrock Resources. Before joining Northrock, Mr. Christensen served in several capacities during a long and varied career with Unocal Corporation. Mr. Christensen holds a Masters in Business Administration from UCLA and a Bachelor of Science in Mechanical Engineering from Oregon State University.

- Mr. James Causgrove has been appointed Vice President, Production and Operations and an Officer of Pengrowth Corporation. He will have broad responsibilities for the operating activities of Pengrowth Corporation and Pengrowth's ongoing development and growth. Mr. Causgrove has over 25 years of experience with Chevron, where he most recently held the position of Manager, New Growth Opportunities Group and Senior Vice President and Chief Operating Officer of Central Alberta Midstream. Mr. Causgrove has a broad operational background in drilling, production engineering and midstream areas across the Western Canadian Sedimentary Basin as well as significant experience in the property divestiture market and the analysis of potential corporate and acquisitions and divestitures, including the recent sale of Central Alberta Midstream. Mr. Causgrove holds a Bachelor of Science in Chemical Engineering and is a registered professional engineer.

Outlook

Based on third quarter 2005 production results, Pengrowth expects daily average production of approximately 57,500 to 58,500 boe per day for the full year 2005. This estimate incorporates production additions from the Swan Hills Unit No. 1 and Crispin acquisitions, Pengrowth's 2005 development program and two condensate shipments from SOEP in the fourth quarter of 2005, offset by normal production declines and non-core property divestitures.

Total operating costs for 2005 are expected to increase to approximately $210 to $220 million including a full year of costs from the Murphy acquisition and those associated with the Swan Hills Unit No. 1 and Crispin acquisitions. Assuming Pengrowth's average production results for 2005 are as forecast above, Pengrowth now estimates 2005 operating costs per boe of between $9.80 and $10.45 and combined G&A and management fees of approximately $2.05 to $2.15 per boe.

Pengrowth currently anticipates capital expenditures for maintenance and development of approximately $185 million for 2005.

Pengrowth is pleased to announce an increase in monthly distributions during the fourth quarter to $0.25 per trust unit beginning with the December 15, 2005 distribution which is expected to result in a payout ratio of 73 to 76 percent for the full year 2005.

Pengrowth is continually evaluating its portfolio for optimization opportunities. In addition to the property sales which closed in the third quarter of 2005, purchase and sale agreements have been executed with several parties to acquire from Pengrowth non-core properties with associated production of approximately 400 boe per day for gross proceeds of approximately $20 million, before adjustments. These divestments were previously disclosed in the second quarter of 2005 and are now expected to close in the fourth quarter.

Pengrowth has sought and achieved compliance with the applicable legal and regulatory provisions. On July 27, 2004, Pengrowth Trust implemented a Class A and Class B trust unit structure to manage the level of non-resident ownership of the Fund. Subsequent to implementation of the structure, and prior to June 1, 2005, Pengrowth achieved foreign ownership below a threshold of 49.75% in accordance with an advance tax ruling by Canada Revenue Agency essentially confirming the status of Pengrowth Trust as a Mutual Fund Trust under the Income Tax Act (Canada).

To the extent that Class A trust units in the future represent less than the ownership threshold of 49.75 percent, conversion of Class B trust units to Class A trust units is permissible under the Trust Indenture. Pengrowth proposed a new form of reservation system that was approved in principle by unitholders at the Annual & Special Unitholder Meeting on April 26, 2005 in order to provide all unitholders with an equal and orderly opportunity to convert Class B trust units into Class A trust units. Pengrowth is currently working with Computershare Trust Company of Canada to design an appropriate system and proposes to make a press release in respect to the implementation of the system during the fourth quarter.

In connection with statements made in the 2005 Federal Budget, the Department of Finance released a consultation paper (the "Consultation Paper") on September 8, 2005 titled Tax and Other Issues Related to Publicly Listed Flow-Through Entities. The Consultation Paper launched a process of discussion and third-party input on the impact of publicly listed income trusts and other flow-through entities (FTEs) on federal tax revenues and the Canadian economy. Although not specifically referred to, FTEs could include royalty trusts such as Pengrowth Energy Trust. The consultation process will seek input on a number of questions, including:

- Does the tax advantage of FTEs relative to public corporations have a significant impact on how businesses are organized in Canada?
- Have FTEs had a significant impact on tax revenues? Is there potential for revenue losses to grow in the years to come?
- What impacts are FTEs having on investment decision and the allocation of capital in Canada? Is the overall impact on the economy positive or negative?
- Given the important role that tax-exempt investors play in Canadian capital markets, and could play in the FTE market, what impact could this have on government revenues and economic efficiency?
- Overall, are there public policy concerns about FTEs and how the tax system influences their existence and, if so, what actions would be considered to address these concerns?

This process will not include separate consultations announced by the Department of Finance on December 6, 2004 regarding the 2004 Federal Budget proposals with respect to mutual funds maintained primarily for the benefit of non-residents. The Department of Finance has invited submissions until December 31, 2005. Subsequent to the consultation process, the Minister of Finance announced there would be a moratorium on the issuance of tax ruling to FTEs.

Pengrowth has complied with the applicable legal and regulatory provisions. On July 27, 2004, Pengrowth Trust implemented a Class A and Class B trust unit structure to manage the level of non-resident ownership of the Fund. Subsequent to implementation of the structure, and prior to June 1, 2005, Pengrowth achieved foreign ownership below a threshold of 49.75% in accordance with an advance tax ruling by Canada Revenue Agency essentially confirming the status of Pengrowth Trust as a Mutual Fund Trust under the Income Tax Act (Canada).

The royalty trust industry has become an important element of Canada's capital markets and a significant contributor to the capital resources available to the petroleum industry and the efficiency of its operations. Throughout its 17 year history Pengrowth has fostered a culture of innovation, operational excellence and environmental stewardship acquiring and effectively managing legacy oil and natural gas properties in Canada. During that period Pengrowth has completed more than 50 acquisitions in accordance with a series of tax rulings and policy pronouncements by CRA and the Department of Finance while fostering relationships with all levels of government defined by consultation, cooperation and compliance.

Pengrowth will continue its approach of consultation and intends to make specific submissions to the Department of Finance in both consultation processes on the benefits of achieving certainty and maintaining the tax and regulatory regime governing royalty trusts that has enhanced the value and efficiency of the petroleum industry and enabled Canadians across the country to participate in that process.


CONFERENCE CALL AND CONTACT INFORMATION

Pengrowth will hold a conference call beginning at 11:00 A.M. Eastern Time (9:00 A.M. Mountain Time) on Friday, November 4, 2005 during which Management will review Pengrowth's 2005 third quarter financial and operating results and respond to inquiries from the investment community. To participate callers may dial (866) 898-9626 or Toronto local (416) 340-2216. To ensure timely participation in the teleconference callers are encouraged to dial in 10 to 15 minutes prior to commencement of the call to register. A live audio webcast will be accessible through the Webcast and Multimedia Centre section of Pengrowth's website at www.pengrowth.com. The webcast will be archived through November 4, 2006. A telephone replay will be available through to midnight Eastern Time on Friday, November 11, 2005 by dialing (800) 408-3053 or Toronto local (416) 695-5800 and entering passcode number 3165707. For further information about Pengrowth, please visit our website www.pengrowth.com or contact:

Investor Relations, E-mail: investorrelations@pengrowth.com

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

Investor Relations, Toronto, Toll Free: 1-888-744-1111 Facsimile: (416) 362-8191

Operations Review

REVIEW OF DEVELOPMENT ACTIVITIES (All volumes stated below are net to Pengrowth unless otherwise stated)

NORTHEAST BRITISH COLUMBIA

- Successfully drilled one oil well at Oak Baldonnel (100 percent working interest) and testing is currently underway.

- Completed Reservoir Simulation on Oak Cecil C Pool. Identified an infill drilling opportunity for the fourth quarter.

- Delineated Notikewin play over Bulrush area for first quarter 2006 activity.

- Sirius/Prespatou Gas Facility was brought online in July (90 percent working interest) with 4.0 mmcf per day gross throughput.

- Two non-operated recompletions (33.33 percent working interest) yielded 1.0 mmcf per day at Bonanza and will be tied-in during the fourth quarter.

- Two parcels were purchased at Crown land sales for prospects to be drilled in 2006.

SOUTHERN

- A 100 percent working interest well in the West Pembina area came on production at 1.0 mmcf per day.

- A non-operated gas well (20 percent working interest) was tested in the Notikewin formation at 320 mcf per day.

- Pengrowth increased its undeveloped land position at West Pembina during the quarter.

- During the third quarter, 44 wells of a 52 well program for the Milk River and Medicine Hat formations at Princess, Alberta were drilled, completed, fracture stimulated and tied-in (mainly in the third quarter). These wells should come on production November 1, 2005. The drilling of the remaining eight wells was deferred to 2006.

- Wells which came on during the third quarter include two Belly River (284 mcf and 250 mcf per day), one Ellerslie (460 mcf per day) and one additional well was drilled and is awaiting completion.

- Imperial Oil Resources served notice of their intent to commence the drilling of a gas well at Quirk Creek. Pengrowth is participating in this well with a working interest of 68 percent.

CENTRAL

Judy Creek

- A new miscible pattern is beginning to see response with incremental oil production of 283 barrels of oil per day.

- One producer reactivation at 25 barrels of oil per day.

- Pengrowth acquired 4,000 acres at Crown land sales on parcels directly offsetting the Judy Creek A & B pools.

- Two farm-in wells were drilled by industry partners.

- The Judy Creek Plant Acid Gas Injection project is underway with the testing of a prospective injection well. The acid gas compressor is on order and Alberta Environment has granted an extension to the current plant license to July, 2006 to allow time for the implementation of this project.

McLeod

- One well drilled at a Gething location was dry and abandoned.

Weyburn Unit

- Fourteen oil wells were drilled in the third quarter. These were a combination of horizontals and vertical re-entries for horizontal production. Production response to the drilling and CO2 injection programs has been favourable.

Hanlan

- At the Hanlan Unit and Hanlan Robb Gas Plant one gas well was drilled and expected onstream in September, 2005. The initial in-line flow test (3.3 mmcf per day gross) is now being analyzed by the operator and is slated to come onstream in February 2006.

South Swan Hills Unit

- Two wells were rig released from drilling in the third quarter. Plans are in place to test these multi-legged horizontal oil wells in the east platform area. The operator has not yet reported results.

Swan Hills Unit No. 1

- The final three oil producers in a seven well drilling program came onstream in the third quarter. The last two of a four oil well reactivation program came onstream in July.

HEAVY OIL

- Three development wells were drilled in East Bodo, one of which is a horizontal well. These wells were drilled to change the waterflood pattern from an inverted nine spot to a line drive. Pengrowth expects initial primary production for up to a year before conversion to a line drive.

- A non-operated development well was drilled and cased at South Bodo (35 percent working interest).

- One development well in Cosine and one development well in Plover are expected to be completed as gas wells with the potential for up to four development infill opportunities. All are expected to be tied-in in the fourth quarter of 2005.

- The polymer skid for the East Bodo polymer pilot has been ordered. It is now under construction with delivery, installation and polymer injection to start in 2006.

- A large 3-D seismic program in the East Bodo area has been initiated for development potential and possible surveillance of the East Bodo waterflood and polymer pilot.

SABLE OFFSHORE ENERGY PROJECT

Production

- Third quarter gross raw gas production from the five SOEP fields, Thebaud, Venture, North Triumph, Alma and South Venture averaged 432 mmcf per day gross ( 36.3 mmcf per day net).

- Monthly raw production for July, August, and September was 414 mmcf per day gross (36.3 mmcf per day net), 446 mmcf per day gross (37.5 mmcf per day net) and 435 mmcf per day gross (36.5 mmcf per day net), respectively.

- Pengrowth also had a 65,000 bbl condensate sale in August.

- The Venture 7 (V7) development well was spudded on August 5, 2005. As of September 30, 2005 the V7 well was at a drilled depth of 5,666 meters with a projected total depth of 6,444 meters. The V7 well is expected to start production by year-end.

Tier II Status

- Fabrication of the compression topsides, jacket and piles is approximately 40 percent complete.

- Cut-in work in preparation for the compressor installation is in progress at the Thebaud facilities.

- In-service date for the compressor is scheduled for late 2006.



Consolidated Balance Sheets
As at As at
September 30 December 31
(Stated in thousands of dollars) 2005 2004
---------------------------------------------------------------------
ASSETS (unaudited)
CURRENT ASSETS
Cash $ 997 $ -
Accounts receivable 127,392 104,228
Inventory - 439
---------------------------------------------------------------------
128,389 104,667

REMEDIATION TRUST FUND 9,113 8,309

DEFERRED CHARGES (Note 6) 5,679 3,651

GOODWILL (Note 3) 183,385 170,619

PROPERTY, PLANT AND EQUIPMENT
AND OTHER ASSETS 2,090,399 1,989,288
---------------------------------------------------------------------

$ 2,416,965 $ 2,276,534
---------------------------------------------------------------------
---------------------------------------------------------------------

LIABILITIES AND UNITHOLDERS' EQUITY
CURRENT LIABILITIES
Bank indebtedness $ - $ 4,214
Accounts payable and accrued liabilities 107,089 80,423
Distributions payable to unitholders 73,323 70,456
Due to Pengrowth Management Limited 5,096 7,325
Note payable 15,000 15,000
Current portion of contract liabilities 5,409 5,795
---------------------------------------------------------------------
205,917 183,213

NOTE PAYABLE 20,000 20,000

CONTRACT LIABILITIES 14,256 18,216

LONG-TERM DEBT (Note 2) 422,220 345,400

ASSET RETIREMENT OBLIGATIONS (Note 5) 183,452 171,866

FUTURE INCOME TAXES 103,261 75,628

TRUST UNITHOLDERS' EQUITY
Trust Unitholders' capital (Note 4) 2,504,125 2,383,284
Contributed surplus (Note 4) 3,186 1,923
Accumulated earnings 936,720 727,057
Accumulated distributions paid or declared (1,976,172) (1,650,053)
---------------------------------------------------------------------
1,467,859 1,462,211
---------------------------------------------------------------------

SUBSEQUENT EVENT (Note 10)
$ 2,416,965 $ 2,276,534
---------------------------------------------------------------------
---------------------------------------------------------------------

See accompanying notes to the consolidated financial statements.


Consolidated Statements of Income and Accumulated Earnings

(Stated in thousands Three months ended Nine months ended
of dollars) September 30 September 30
(Unaudited) 2005 2004 2005 2004
---------------------------------------------------------------------

REVENUES
Oil and gas sales $ 304,484 $ 226,514 $ 797,587 $ 592,569
Processing and
other income 2,039 2,871 11,771 8,495
Royalties, net
of incentives (57,414) (49,207) (145,879) (111,274)
---------------------------------------------------------------------
249,109 180,178 663,479 489,790
Interest and other income 74 78 1,916 1,204
---------------------------------------------------------------------
NET REVENUE 249,183 180,256 665,395 490,994

EXPENSES
Operating 57,371 47,163 156,885 117,149
Transportation 1,969 2,423 5,584 5,797
Amortization of injectants
for miscible floods 5,969 4,694 17,322 14,721
Interest 5,644 8,650 16,786 20,582
General and administrative 7,559 6,142 21,765 17,538
Management fee 3,537 2,493 11,588 10,317
Foreign exchange
gain (Note 7) (12,255) (13,688) (8,470) (6,651)
Depletion and depreciation 73,541 69,323 213,594 177,923
Accretion (Note 5) 3,578 3,093 10,531 7,465
---------------------------------------------------------------------
146,913 130,293 445,585 364,841
---------------------------------------------------------------------

NET INCOME BEFORE TAXES 102,270 49,963 219,810 126,153

INCOME TAX EXPENSE (RECOVERY)
Capital 2,116 1,474 4,722 2,849
Future (89) (2,782) 5,425 697
---------------------------------------------------------------------
2,027 (1,308) 10,147 3,546

NET INCOME $ 100,243 $ 51,271 $ 209,663 $ 122,607
---------------------------------------------------------------------
---------------------------------------------------------------------

Accumulated earnings,
beginning of period 836,477 644,648 727,057 573,312
---------------------------------------------------------------------

ACCUMULATED EARNINGS,
END OF PERIOD $ 936,720 $ 695,919 $ 936,720 $ 695,919
---------------------------------------------------------------------
---------------------------------------------------------------------

NET INCOME
PER UNIT (Note 4)
Basic $ 0.631 $ 0.377 $ 1.341 $ 0.927

Diluted $ 0.629 $ 0.376 $ 1.337 $ 0.923
---------------------------------------------------------------------
---------------------------------------------------------------------

See accompanying notes to the consolidated financial statements.


Consolidated Statements of Cash Flow

(Stated in thousands Three months ended Nine months ended
of dollars) September 30 September 30
(Unaudited) 2005 2004 2005 2004
---------------------------------------------------------------------

CASH PROVIDED BY (USED FOR):

OPERATING
Net income $ 100,243 $ 51,271 $ 209,663 $ 122,607
Depletion, depreciation
and accretion 77,119 72,416 224,125 185,388
Future income taxes (89) (2,782) 5,425 697
Contract liability
amortization (1,448) (1,555) (4,346) (2,379)
Amortization of injectants 5,969 4,694 17,322 14,721
Purchase of injectants (6,861) (3,031) (20,176) (12,239)
Expenditures on remediation (1,676) (1,199) (4,300) (4,029)
Unrealized foreign
exchange gain (Note 7) (12,860) (14,440) (8,180) (6,980)
Trust unit
based compensation 608 554 2,137 1,925
Deferred charges (4,283) - (4,283) -
Amortization of
deferred charges 1,465 473 2,255 1,420
Changes in non-cash
operating working
capital (Note 8) 789 9,857 1,840 9,749
---------------------------------------------------------------------
158,976 116,258 421,482 310,880
---------------------------------------------------------------------

FINANCING
Distributions (109,455) (88,293) (323,252) (251,822)
Change in long-term
debt, net (26,428) 14,680 64,541 339,680
Proceeds from issue of
trust units 15,477 13,036 32,007 218,205
---------------------------------------------------------------------
(120,406) (60,577) (226,704) 306,063
---------------------------------------------------------------------

INVESTING
Expenditures on
property acquisitions (2,861) (20,852) (94,427) (574,045)
Expenditures on property,
plant and equipment (40,050) (43,455) (114,486) (107,020)
Proceeds on property
dispositions 18,623 - 18,623 -
Change in remediation
trust fund (272) (276) (804) (949)
Purchase of marketable
securities - (2,680) - (2,680)
Change in non-cash investing
working capital (Note 8) 1,527 1,385 1,527 (959)
---------------------------------------------------------------------
(23,033) (65,878) (189,567) (685,653)
---------------------------------------------------------------------

CHANGE IN CASH
AND TERM DEPOSITS 15,537 (10,197) 5,211 (68,710)

CASH AND TERM DEPOSITS
(BANK INDEBTEDNESS)
AT BEGINNING OF PERIOD (14,540) 5,641 (4,214) 64,154
---------------------------------------------------------------------

CASH AND TERM DEPOSITS
(BANK INDEBTEDNESS)
AT END OF PERIOD $ 997 $ (4,556) $ 997 $ (4,556)
---------------------------------------------------------------------
---------------------------------------------------------------------

See accompanying notes to the consolidated financial statements.


Notes To Consolidated Financial Statements

(Unaudited)

September 30, 2005

(Tabular dollar amounts are stated in thousands of dollars except per trust unit amounts)

1. SIGNIFICANT ACCOUNTING POLICIES

The interim consolidated financial statements of Pengrowth Energy Trust include the accounts of Pengrowth Energy Trust, Pengrowth Corporation and its subsidiaries (collectively referred to as "Pengrowth"). The financial statements do not contain the accounts of Pengrowth Management Limited (the "Manager"). The financial statements have been prepared by management in accordance with accounting principles generally accepted in Canada. The interim consolidated financial statements have been prepared following the same accounting policies and methods of computation as the consolidated financial statements for the fiscal year ended December 31, 2004. The disclosures provided below are incremental to those included with the annual consolidated financial statements. The interim consolidated financial statements should be read in conjunction with the consolidated financial statements and the notes thereto in Pengrowth's annual report for the year ended December 31, 2004.

TRUST UNIT AWARD PLAN

Effective July 13, 2005, Pengrowth established a new incentive plan to reward and retain employees whereby Class B trust units and cash to offset the estimated taxable benefit will be awarded to eligible employees. Employees will receive one half of the trust units and cash on January 1, 2006 and one half of the trust units and cash on July 1, 2006. Any appreciation or depreciation in the Class B trust units over the vesting period accrues to the eligible employees.

Pengrowth acquired the Class B trust units to be awarded under the plan on the open market for $4.3 million and placed them in a trust account established for the benefit of the eligible employees. The cost to acquire the trust units has been recorded as deferred compensation expense and is being charged to net income on a straight line basis over one year. In addition, the cash portion of the incentive plan of approximately $1.5 million is being accrued on a straight line basis over one year. Any unvested trust units will be sold on the open market. During the three months ended September 30, 2005 $1.4 million has been charged to net income.

TRUST UNIT BASED COMPENSATION PLANS

Pengrowth has trust unit based compensation plans under which directors, officers, employees and special consultants of Pengrowth and the Manager are eligible to receive trust unit options and rights. Pengrowth records compensation expense and a corresponding decrease to contributed surplus in respect of rights incentive options granted on or after January 1, 2003. The amount of compensation expense is reduced and a corresponding increase to contributed surplus recorded for rights incentive options which are subsequently cancelled prior to vesting.

Compensation expense is based on a fair value method. The fair value of rights incentive options granted during the nine months ended September 30, 2005 was estimated at 15 percent of the exercise price at the date of grant using a modified Black-Scholes option pricing model with the following assumptions: risk-free rate of 3.9 percent, volatility of 22 percent, expected life of five years and adjustments for the estimated distributions and reductions in the exercise price over the life of the right incentive option. For the three months ended September 30, 2005, compensation expense of $250,000 (September 30, 2004 - $312,000) and for the nine months ended September 30, 2005 compensation expense of $1,308,000 (September 30, 2004 - $938,000) related to the rights incentive options was recorded.

LONG TERM INCENTIVE PLAN

Effective January 1, 2005, the Board of Directors approved a Long Term Incentive Plan. Under the Long Term Incentive Plan for permanent employees of Pengrowth and other designated participants, deferred entitlement trust units are granted based on a grant value as a percentage of an individual's base salary and an established weighting of deferred entitlement trust units and/or rights incentive options that is dependent on an individual's position within the organization. The deferred entitlement trust units fully vest and are converted to Pengrowth Energy Trust Class B trust units ("Class B trust units") on the third anniversary year from the date of grant and will receive distributions prior to the vesting date in the form of additional deferred entitlement trust units. However, the number of deferred entitlement trust units actually issued to each participant at the end of the three year vesting period will be subject to a relative performance test which compares Pengrowth's three year average total return to the three year average total return of a peer group of other energy trusts such that upon vesting, the number of Class B trust units issued from treasury may range from zero to one and one-half times the number of deferred entitlement trust units granted plus accrued deferred entitlement trust units through the deemed re-investment of distributions.

Compensation expense related to deferred entitlement trust units is based on the fair value of the deferred entitlement trust units at the date of grant. The number of Class B trust units awarded at the end of the vesting period is subject to certain performance conditions. Compensation expense incorporates the estimated fair value of the deferred entitlement trust units at the date of grant and an estimate of the relative performance multiplier. Fluctuations in compensation expense may occur due to changes in estimating the outcome of the performance conditions. An estimate of forfeiture has not been made; rather compensation expense is reduced for actual forfeitures as they occur. Compensation expense is recognized in income over the vesting period with a corresponding increase or decrease to Contributed Surplus. Upon issuance of the Class B trust units at the end of the vesting period, trust unit holders' capital is increased and contributed surplus is reduced. For the three months ended and nine months ended September 30, 2005, Pengrowth recorded compensation expense of $358,000 and $795,000, respectively associated with the deferred entitlement trust units. Compensation expense associated with the deferred entitlement trust units was based on the weighted average estimated fair value of $18.69 per deferred entitlement trust unit.



2. LONG TERM DEBT

As at As at
September 30, December 31,
2005 2004
---------------------------------------------------------------------
U.S. dollar denominated debt:
U.S. $150 million senior unsecured
notes at 4.93% due April 2010 $ 174,165 $ 180,300
U.S. $50 million senior unsecured
notes at 5.47% due April 2013 58,055 60,100
---------------------------------------------------------------------
232,220 240,400
Canadian dollar revolving credit
borrowings 190,000 105,000
---------------------------------------------------------------------
$ 422,220 $ 345,400
---------------------------------------------------------------------
---------------------------------------------------------------------


On September 30, 2005 Pengrowth had a $470 million revolving unsecured credit facility syndicated among eight financial institutions of which approximately $295 million remained unutilized. The facilities are currently reduced by outstanding letters of credit in the amount of approximately $21 million. The credit facility is an extendible 364 day revolving facility with a three year amortization period. The credit facility will revolve until June 16, 2006 and is extendible at that time at the lenders' option. In the event the facility is not renewed, any amount outstanding would be repaid in equal quarterly instalments over the three year period. Pengrowth can post, at its option, security suitable to the banks in lieu of the first year's payments. In such an instance, no principal payment would be made to the banks for the one year following the date of non-renewal. Pengrowth also has a $35 million demand operating line of credit. Interest payable on amounts drawn is at the prevailing bankers' acceptance rates plus stamping fees, lenders' prime lending rates, or U.S. LIBOR rates plus applicable margins, depending on the form of borrowing by Pengrowth. The margin and stamping fees vary from 0.25 percent to 1.40 percent on the new revolving credit facility depending on financial statement ratios and the form of borrowing.

3. CORPORATE ACQUISITION

On April 29, 2005, Pengrowth acquired all of the issued and outstanding shares of Crispin Energy Inc. (Crispin) which held interests in oil and natural gas assets mainly in Alberta. The shares were acquired on the basis of exchanging 0.0725 Class B trust units of Pengrowth Energy Trust for each share held by Canadian resident shareholders of Crispin and 0.0512 Class A trust units of Pengrowth Energy Trust for each share held by non-Canadian resident shareholders of Crispin. The average value assigned to each trust unit issued was $20.80 based on the weighted average trading price of the Class A and Class B trust units for a period before and after the acquisition was announced. Pengrowth Energy Trust issued 3,538,581 Class B trust units and 686,732 Class A trust units valued at $88 million. The transaction was accounted for using the purchase method of accounting with the allocation of the purchase price and consideration as follows:



Allocation of purchase price:
---------------------------------------------------------------------
Working capital $ 1,655

Property, plant, and equipment 121,729

Goodwill 12,766

Long-term debt (20,459)

Asset retirement obligations (4,038)

Future income taxes (22,208)

---------------------------------------------------------------------
$ 89,445
---------------------------------------------------------------------
Cost of acquisition:
Trust units issued $ 87,960

Acquisition costs 1,485
---------------------------------------------------------------------
$ 89,445
---------------------------------------------------------------------
---------------------------------------------------------------------


Property, plant and equipment of $122 million represents the estimated fair value of the assets acquired determined in part by an independent reserve evaluation. Goodwill of $13 million, which is not deductible for tax purposes, was determined based on the excess of the total cost of the acquisition less the value assigned to the identifiable assets and liabilities including the future income tax liability.

The future income tax liability was determined based on an enacted income tax rate of approximately 34 percent as at April 29, 2005. Results from operations of the acquired assets of Crispin subsequent to April 29, 2005 are included in the consolidated financial statements. Final determination of the cost of the acquisition and the allocation thereof to the fair values of Crispin's net assets is still pending.



4. TRUST UNITS

The total authorized capital of Pengrowth is 500,000,000 trust units.

Undeclared Trust Units:

9 Months Ended 12 Months Ended
September 30, 2005 December 31, 2004
---------------------------------------------------------------------
Number Number
Trust units issued of units Amount of units Amount
---------------------------------------------------------------------
Balance, beginning
of period 73,325 $ 1,123 123,873,651 $1,872,924

Issued for cash - - 10,900,000 200,560
Less: issue expenses - - - (10,710)
Issued for cash on
exercise of trust
units options and
rights - - 547,974 8,735
Issued for cash under
Distribution
Reinvestment Plan
(DRIP) - - 543,888 9,636
Trust unit rights
incentive plan
(non-cash exercised) - - - 259
Royalty units exchanged
for trust units - - 700 -
---------------------------------------------------------------------
Balance, prior to
conversion - - 135,866,213 $2,081,404
Converted to Class A
or Class B trust units (25,556) (392)(135,792,888) (2,080,281)
---------------------------------------------------------------------
Balance, end of
period 47,769 $ 731 73,325 $ 1,123
---------------------------------------------------------------------
---------------------------------------------------------------------


Class A Trust Units:

For the period from
9 Months Ended July 27, 2004 to
September 30, 2005 Dec 31, 2004
---------------------------------------------------------------------
Number Number
Trust units issued of units Amount of units Amount
---------------------------------------------------------------------
Balance, beginning
of period 76,792,759 $1,176,427 - $ -
Issued for the
Crispin acquisition
(non-cash) (Note 3) 686,732 19,002 - -
Trust units converted 45,082 691 76,792,759 1,176,427
---------------------------------------------------------------------
Balance, end of
period 77,524,573 $1,196,120 76,792,759 $1,176,427
---------------------------------------------------------------------
---------------------------------------------------------------------

Class B Trust Units:

For the period from
9 Months Ended July 27, 2004 to
September 30, 2005 Dec 31, 2004
---------------------------------------------------------------------
Number Number
Trust units issued of units Amount of units Amount
---------------------------------------------------------------------
Balance, beginning
of period 76,106,471 $1,205,734 - $ -
Trust units
converted (19,526) (299) 59,000,129 903,854
Issued for cash - - 15,985,000 298,920
Less: issue expenses - - - (15,577)
Issued for the
Crispin acquisition
(non-cash) (Note 3) 3,538,581 68,958 - -
Issued for cash on
exercise of trust
units options and
rights 1,235,557 17,449 746,864 11,516
Issued for cash
under Distribution
Reinvestment Plan
(DRIP) 829,918 14,558 374,478 6,750
Trust unit rights
incentive plan
(non-cash exercised) - 874 - 271
---------------------------------------------------------------------
Balance, end of
period 81,691,001 $1,307,274 76,106,471 $1,205,734
---------------------------------------------------------------------
---------------------------------------------------------------------


As at September 30, 2005 Pengrowth had 159,263,343 trust units (December 31, 2004 - 152,972,555 trust units) outstanding.

Per Trust Unit Amounts

The per trust unit amounts of net income are based on the following weighted average trust units outstanding for the period. The weighted average trust units outstanding for the three months ended September 30, 2005 were 158,789,481 trust units (September 30, 2004 - 135,906,487 trust units) and for the nine months ended September 30, 2005 were 156,318,245 trust units (September 30, 2004 - 132,213,280 trust units). In computing diluted net income per trust unit, 507,494 trust units were added to the weighted average number of trust units outstanding during the three months ended September 30, 2005 (September 30, 2004 - 633,751 trust units) and 502,233 trust units were added for the nine months ended September 30, 2005 (September 30, 2004 - 623,464 trust units) for the dilutive effect of trust unit options, rights and deferred entitlement trust units. For the three months ended September 30, 2005, 10,140 options and rights (September 30, 2004 - 958,292 options and rights) and for the nine months ended September 30, 2005, 549,284 options and rights (September 30, 2004 - 781,161 options and rights) were excluded from the diluted net income per trust unit calculation as their effect is anti-dilutive.



Contributed Surplus

9 Months Ended 12 Months Ended
September 30, 2005 December 31, 2004
---------------------------------------------------------------------
Balance, beginning of period $ 1,923 $ 189
Trust unit rights incentive plan
(non-cash expensed) 1,308 2,264
Deferred entitlement trust units
(non-cash expensed) 829 -
Trust unit rights incentive plan
(non-cash exercised) (874) (530)
---------------------------------------------------------------------
Balance, end of period $ 3,186 $ 1,923
---------------------------------------------------------------------
---------------------------------------------------------------------


Trust Unit Option Plan

As at September 30, 2005, options to purchase 365,200 Class B trust units were outstanding (December 31, 2004 - options to purchase 845,374 Class B trust units) that expire at various dates to June 28, 2009.



9 Months Ended 12 Months Ended
September 30, 2005 December 31, 2004
---------------------------------------------------------------------
Weighted Weighted
Trust unit options Average Average
Number Exercise Number Exercise
Of options price of options price
---------------------------------------------------------------------
Outstanding at
beginning of period 845,374 $16.97 2,014,903 $17.47
Exercised (452,424) $16.37 (838,789) $16.82
Expired (2,400) $15.25 (325,200) $20.44
Cancelled (25,350) $18.98 (5,540) $16.53
---------------------------------------------------------------------
Outstanding and
exercisable at
period-end 365,200 $17.57 845,374 $16.97
---------------------------------------------------------------------
---------------------------------------------------------------------


Rights Incentive Plan

As at September 30, 2005, rights to purchase 1,553,576 Class B trust
units were outstanding (December 31, 2004 - rights to purchase
2,011,451 Class B trust units) that expire at various dates to
July 7, 2010.


9 Months Ended 12 Months Ended
September 30, 2005 December 31, 2004
---------------------------------------------------------------------
Weighted Weighted
Rights incentive options Average Average
Number Exercise Number Exercise
Of options price of options price
---------------------------------------------------------------------
Outstanding at
beginning of period 2,011,451 $14.23 1,112,140 $12.20
Granted (1) 521,312 $18.18 1,409,856 $17.35
Exercised (783,133) $12.82 (456,049) $13.47
Cancelled (196,054) $17.12 (54,496) $14.19
---------------------------------------------------------------------
Outstanding
at period-end 1,553,576 $14.88 2,011,451 $14.23
---------------------------------------------------------------------
Exercisable
at period-end 720,191 $13.13 1,037,078 $12.48
---------------------------------------------------------------------
---------------------------------------------------------------------

(1) Weighted average exercise price of rights granted are based on
the exercise price at the date of grant


Long Term Incentive Program

As at September 30, 2005, 150,529 deferred entitlement trust units were outstanding, including accrued distributions re-invested to September 15, 2005. The deferred entitlement trust units vest on various dates to July, 2008.



Number of deferred
entitlement trust
units
---------------------------------------------------------------------
Outstanding, beginning of period -
Granted 170,983
Cancelled (20,454)
---------------------------------------------------------------------
Outstanding, end of period 150,529
---------------------------------------------------------------------
---------------------------------------------------------------------

Compensation expense associated with the deferred entitlement trust
units was based on the weighted average estimated fair value of
$18.69 per deferred entitlement trust unit.

5. ASSET RETIREMENT OBLIGATIONS

For the nine For the
months ended year ended
September 30, December 31,
2005 2004
---------------------------------------------------------------------
Asset retirement obligations,
beginning of period $ 171,866 $ 102,528
Increase (decrease) in liabilities
related to:
Acquisitions 6,347 44,368
Additions 1,302 2,681
Disposals (2,294) -
Revisions - 16,087
Accretion expense 10,531 10,642
Liabilities settled during the period (4,300) (4,440)
---------------------------------------------------------------------
Asset retirement obligations,
end of period $ 183,452 $ 171,866
---------------------------------------------------------------------
---------------------------------------------------------------------

6. DEFERRED CHARGES

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

Imputed interest on note payable (net of
accumulated amortization of $2,543) $ 1,065 $ 2,020
U.S. debt issue costs (net of
accumulated amortization of $739) 1,402 1,631
Deferred compensation expense (net of
accumulated amortization of $1,071) 3,212 -
---------------------------------------------------------------------
$ 5,679 $ 3,651
---------------------------------------------------------------------
---------------------------------------------------------------------

7. FOREIGN EXCHANGE

Three months ended Nine months ended
September 30, September 30,
2005 2004 2005 2004
---------------------------------------------------------------------
Unrealized foreign exchange
gain on translation of U.S.
dollar denominated debt $ 12,860 $ 14,440 $ 8,180 $ 6,980
Realized foreign exchange
gain (loss) (605) (752) 290 (329)
---------------------------------------------------------------------
$ 12,255 $ 13,688 $ 8,470 $ 6,651
---------------------------------------------------------------------
---------------------------------------------------------------------

The U.S. dollar denominated debt is translated into Canadian dollars
at the exchange rate in effect at the balance sheet date. Foreign
exchange gains and losses are included in income.

8. OTHER CASH FLOW DISCLOSURES

Change in Non-Cash Operating Working Capital
Cash provided by (used for):

Three months ended Nine months ended
September 30, September 30,
2005 2004 2005 2004
---------------------------------------------------------------------
Accounts receivable $(24,052) $(11,157) $(21,508) $(34,713)
Inventory - (113) 439 170
Accounts payable and
accrued liabilities 23,884 19,701 25,138 39,128
Due to Pengrowth Management
Limited 957 1,426 (2,229) 5,164
---------------------------------------------------------------------
$ 789 $ 9,857 $ 1,840 $ 9,749
---------------------------------------------------------------------
---------------------------------------------------------------------

Change in Non-Cash Investing Working Capital
Cash provided by (used for):

Three months ended Nine months ended
September 30, September 30,
2005 2004 2005 2004
---------------------------------------------------------------------
Accounts payable for
capital accruals $ 1,527 $ 1,385 $ 1,527 $ (959)
---------------------------------------------------------------------
---------------------------------------------------------------------

Cash Payments

Three months ended Nine months ended
September 30, September 30,
2005 2004 2005 2004
---------------------------------------------------------------------
Cash payments made
for taxes $ 1,787 $ 1,730 $ 4,363 $ 2,885
Cash payments made
for interest $ 2,763 $ 5,145 $ 12,952 $ 15,733
---------------------------------------------------------------------
---------------------------------------------------------------------


9. FINANCIAL INSTRUMENTS

Pengrowth has a price risk management program whereby the commodity price associated with a portion of its future production is fixed. Pengrowth sells forward a portion of its future production through a combination of fixed price sales contracts with customers and commodity swap agreements with financial counterparties. The forward and futures contracts are subject to market risk from fluctuating commodity prices and exchange rates.

As at September 30, 2005, Pengrowth had fixed the price applicable to future production as follows:



Crude Oil:

Volume Reference Price
Remaining Term (bbl/day) Point per bbl
---------------------------------------------------------------------

2005
Financial:
Oct 1, 2005 - Dec 31, 2005 10,000 WTI (1) $54.39 Cdn

2006
Financial:
Jan 1, 2006 - Dec 31, 2006 4,000 WTI (1) $64.08 Cdn
---------------------------------------------------------------------
---------------------------------------------------------------------


Natural Gas:

Volume Reference Price
Remaining Term (mmbtu/day) Point per mmbtu
---------------------------------------------------------------------

2005
Financial:
Oct 1, 2005 - Dec 31, 2005 11,000 Tetco M3 (1) $ 9.27 Cdn
Oct 1, 2005 - Dec 31, 2005 5,000 Transco Z6 (1) $10.11 Cdn
Oct 1, 2005 - Dec 31, 2005 2,500 NGI Chicago (1) $ 9.41 Cdn
Oct 1, 2005 - Dec 31, 2005 2,500 NYMEX (1) $14.07 Cdn
Oct 1, 2005 - Dec 31, 2005 2,370 AECO $ 8.35 Cdn

2006
Financial:
Jan 1, 2006 - Dec 31, 2006 2,500 Transco Z6 (1) $10.63 Cdn
Jan 1, 2006 - Dec 31, 2006 2,370 AECO $ 8.03 Cdn
Jan 1, 2006 - Mar 31, 2006 2,500 NYMEX (1) $14.56 Cdn
---------------------------------------------------------------------
---------------------------------------------------------------------

(1) Associated Cdn$ / U.S. $ foreign exchange rate has been fixed.


The estimated fair value of the financial crude oil and natural gas contracts has been determined based on the amounts Pengrowth would receive or pay to terminate the contracts at period-end. At September 30, 2005, the amount Pengrowth would pay to terminate the financial crude oil and natural gas contracts would be $39,198,000 and $25,036,000, respectively.



Natural Gas Fixed Price Sales Contract:

Pengrowth also has a natural gas fixed price physical sales contract
outstanding, the details of which are provided below:

Volume Price
Remaining Term (mmbtu/day) per mmbtu (2)
---------------------------------------------------------------------

2005 to 2009
July 1, 2005 - Oct 31, 2005 3,886 $2.18 Cdn
Nov 1, 2005 - Oct 31, 2006 3,886 $2.23 Cdn
Nov 1, 2006 - Oct 31, 2007 3,886 $2.29 Cdn
Nov 1, 2007 - Oct 31, 2008 3,886 $2.34 Cdn
Nov 1, 2008 - Apr 30, 2009 3,886 $2.40 Cdn
---------------------------------------------------------------------
---------------------------------------------------------------------

(2) Reference price based on AECO


As at September 30, 2005, the fair value amount Pengrowth would pay to terminate the natural gas fixed price sales contract would be $37,822,000 (December 31, 2004 - $22,282,000).

Fair Value of Financial Instruments

The carrying value of financial instruments included in the balance sheet, other than long-term debt, the note payable and remediation trust funds approximate their fair value due to their short maturity. The fair value of the remediation trust funds at September 30, 2005 was approximately $9,207,000 (December 31, 2004 - $8,366,000). The fair value of the U.S. dollar denominated debt at September 30, 2005 was approximately $225,850,000 (December 31, 2004 - $238,726,000) based on the changes in the fair value of the underlying seven and ten year U.S. Treasury Bill that was originally used as the basis for determining the coupon rate for each of Pengrowth Corporation's notes. The fair value of the note payable at September 30, 2005, approximates its carrying value net of the imputed interest included in deferred charges.

10. SUBSEQUENT EVENT

Purchase and sale agreements have been executed with several parties to acquire from Pengrowth non-core properties with associated production of approximately 400 boe per day for gross proceeds of approximately $20 million. These divestments were previously disclosed in the second quarter of 2005 and are now expected to close in the fourth quarter.


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