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

Pengrowth Energy Trust
Pengrowth Corporation

Pengrowth Corporation

August 04, 2005 02:01 ET

Pengrowth Energy Trust Announces Second Quarter 2005 Results

CALGARY, ALBERTA--(CCNMatthews - Aug. 4, 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 six month periods ended June 30, 2005.

-During the second quarter of 2005, Pengrowth generated record distributable cash at $134 million versus $99 million in the second quarter of 2004, an increase of more than 35 percent. Combined with Pengrowth's prior record of $128 million, achieved in the first quarter of this year, distributable cash for the first half of 2005 was $262 million, up 36% from $192 million in the comparable period of 2004 representing the highest level of distributable cash generated over any six month period in Pengrowth's history.

-Distributions to unitholders were maintained at $0.23 per trust unit per month resulting in a year-to-date payout ratio of approximately 83 percent of funds generated from operations.

-On April 29, 2005, Pengrowth completed the acquisition of Crispin Energy Inc. which held interests in oil and natural gas assets mainly in Alberta. This represented Pengrowth's first acquisition of a publicly traded corporation and was funded through the issuance of Class A and Class B trust units valued at approximately $88 million. The Crispin acquisition is accretive in terms of both production and distributable cash per trust unit and adds estimated reserves of 5.2 million barrels of oil equivalent on a proved plus probable basis.

-Production volumes increased 13 percent over second quarter 2004 averaging approximately 58,000 barrels of oil equivalent per day.

-Capital expenditures for the second quarter of $28.9 million were fully funded with cash withheld from distributable cash and proceeds from the exercise of trust unit rights and options.

-During the second quarter, Pengrowth lowered its foreign ownership in the fund to less than 49.75 percent of combined Class A and Class B trust units issued and outstanding. In doing so, Pengrowth complied with its advance tax ruling from the Canada Revenue Agency regarding Pengrowth's status as a mutual fund trust.

-Subsequent to quarter end, Pengrowth executed purchase and sale agreements with several parties for the sale of certain non-core Pengrowth properties with associated production estimated at 600 barrels of oil equivalent per day for gross proceeds of approximately $37 million.

-The trust's net debt to annualized second quarter 2005 cash flow from operations was approximately 1.1 times at the end of the second quarter of 2005 as compared to 1.7 times at the end of the second quarter of 2004. Net debt to total capitalization was 13.7 percent versus 21.2 percent year over year.

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
June 30 %
($thousands, except per unit amounts) 2005 2004 Change

INCOME STATEMENT
Oil and gas sales $ 247,903 $ 193,637 28%

Net income $ 53,106 $ 32,684 62%
Net income per unit $ 0.34 $ 0.24 42%

Funds generated from operations $ 135,048 $ 102,932 31%
Funds generated from operations
per unit $ 0.86 $ 0.76 13%

Distributable cash(x) $ 134,047 $ 99,021 35%
Distributable cash per unit(x) $ 0.86 $ 0.73 18%
Distributions $ 101,237 $ 89,119 14%
Distributions paid or declared
per unit $ 0.69 $ 0.64 8%

Weighted average number of
units outstanding 156,718 135,473 16%

BALANCE SHEET
Working capital $ (90,479) $ (270,681) (67)%
Property, plant and equipment
and other assets $2,141,769 $1,990,977 8%
Long-term debt $ 461,508 $ 371,760 24%
Unitholders' equity $1,461,384 $1,264,586 16%
Unitholders' equity per unit $ 9.23 $ 9.32 (1)%

Number of units outstanding
at period end 158,283 135,677 17%

DAILY PRODUCTION
Crude oil (barrels) 20,906 20,906 -
Heavy oil (barrels) 5,641 1,848 205%
Natural gas (thousands of cubic feet) 153,423 136,142 13%
Natural gas liquids (barrels) 5,870 6,007 (2)%
Total production (BOE) 6:1 57,988 51,451 13%

TOTAL PRODUCTION (MBOE) 6:1 5,277 4,682 13%

PRODUCTION PROFILE (6:1 conversion)
Crude oil 36% 41%
Heavy oil 10% 3%
Natural gas 44% 44%
Natural gas liquids 10% 12%

AVERAGE PRICES
Crude oil (per barrel) $ 56.44 $ 42.46 33%
Heavy oil (per barrel) $ 30.32 $ 30.19 -
Natural gas (per mcf) $ 7.34 $ 7.08 4%
Natural gas liquids (per barrel) $ 50.03 $ 40.75 23%
Average price per BOE 6:1 $ 46.98 $ 41.36 14%


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

INCOME STATEMENT
Oil and gas sales $ 484,671 $ 359,517 35%

Net income $ 109,420 $ 71,336 53%
Net income per unit $ 0.71 $ 0.55 29%

Funds generated from operations $ 261,455 $ 194,730 34%
Funds generated from operations
per unit $ 1.69 $ 1.49 13%

Distributable cash(x) $ 261,851 $ 191,917 36%
Distributable cash per unit(x) $ 1.69 $ 1.47 15%
Distributions $ 216,259 $ 172,723 25%
Distributions paid or declared
per unit $ 1.38 $ 1.27 9%

Weighted average number of
units outstanding 155,062 130,346 19%

BALANCE SHEET
Working capital $ (90,479) $ (270,681) (67)%
Property, plant and equipment
and other assets $2,141,769 $1,990,977 8%
Long-term debt $ 461,508 $ 371,760 24%
Unitholders' equity $1,461,384 $1,264,586 16%
Unitholders' equity per unit $ 9.23 $ 9.32 (1)%

Number of units outstanding
at period end 158,283 135,677 17%

DAILY PRODUCTION
Crude oil (barrels) 20,676 21,211 (3)%
Heavy oil (barrels) 5,842 924 532%
Natural gas (thousands of cubic feet) 155,446 126,745 23%
Natural gas liquids (barrels) 6,106 5,300 15%
Total production (BOE) 6:1 58,532 48,560 20%

TOTAL PRODUCTION (MBOE) 6:1 10,594 8,838 20%

PRODUCTION PROFILE (6:1 conversion)
Crude oil 35% 44%
Heavy oil 10% 2%
Natural gas 44% 43%
Natural gas liquids 11% 11%

AVERAGE PRICES
Crude oil (per barrel) $ 55.45 $ 41.50 34%
Heavy oil (per barrel) $ 27.27 $ 30.19 (10)%
Natural gas (per mcf) $ 7.09 $ 6.96 2%
Natural gas liquids (per barrel) $ 50.26 $ 39.16 28%
Average price per BOE 6:1 $ 45.75 $ 40.68 12%

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



Summary of Trust Unit Trading Data

Three Months ended Six Months ended
(thousands, except June 30 June 30
per unit amounts) 2005 2004 2005 2004

TRUST UNIT TRADING (Class A)
PGH (NYSE) after unit re-class(xx)
High $ 22.74 US $ 22.94 US
Low $ 19.05 US $ 18.11 US
Close $ 22.25 US $ 22.25 US
Value $334,986 US $850,117 US
Volume (thousands
of units) 16,153 40,774
PGF.A (TSX) (xx)
High $ 27.90 $ 28.29
Low $ 23.95 $ 22.15
Close $ 27.20 $ 27.20
Value $ 46,405 $ 99,672
Volume (thousands
of units) 1,798 3,847

TRUST UNIT TRADING (Class B)
PGF.B (TSX) (xx)
High $ 19.01 $ 19.90
Low $ 16.37 $ 16.10
Close $ 18.40 $ 18.40
Value $342,470 $886,171
Volume (thousands
of units) 19,370 48,589

TRUST UNIT TRADING (before unit re-class)
PGH (NYSE) before unit re-class(xx)
High $ 14.24 US $ 16.60 US
Low $ 11.62 US $ 11.62 US
Close $ 13.98 US $ 13.98 US
Value $295,835 US $821,444 US
Volume (thousands of units) 22,194 59,093
PGF.UN (TSX) (xx)
High $ 19.15 $ 21.25
Low $ 16.15 $ 15.55
Close $ 18.67 $ 18.67
Value $328,450 $896,235
Volume (thousands of units) 18,145 48,765

(xx)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 crown and freehold 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 unit and operating netbacks do not have standardized meanings prescribed by GAAP. During the second quarter, Pengrowth's withholding practice and presentation of distributable cash has 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

During the second quarter, Pengrowth successfully completed the previously disclosed acquisition of all of the issued and outstanding shares of Crispin Energy Inc. The acquisition added estimated proved plus probable reserves of approximately 5.2 million boe estimated by Gilbert Laustsen Jung Associates Ltd. as at January 1, 2005.

Continued strength in commodity prices and production added through the Murphy, Swan Hills Unit No. 1 and Crispin Energy Inc. acquisitions, which closed on May 31, 2004, February 28, 2005 and April 29, 2005, respectively, had a favourable impact on 2005 second quarter results relative to the second quarter of 2004.

Net Income

Net income for the second quarter of 2005 was $53.1 million ($0.34 per trust unit) compared to $32.7 million ($0.24 per trust unit) for the previous year. For the first six months of 2005 Pengrowth recorded net income of $109.4 million ($0.71 per trust unit), compared to $71.3 million ($0.55 per trust unit) for the previous year. The increase in net income for the second quarter of 2005 compared to the same period last year is due mainly to a 13 percent increase in production volumes and a 14 percent increase in average commodity prices.

Production

Production for the second quarter of 2005 increased 13 percent to just below 58,000 boe per day compared to approximately 51,500 boe per day for the second quarter of 2004, due to a full quarter of production in 2005 from the Murphy acquisition and the increased working interest in Swan Hills Unit No. 1 as well as two months of production from the Crispin acquisition. Partially offsetting the production increase was the timing of Sable Offshore Energy Project (SOEP) condensate shipments and natural production declines. On a year to date basis, production for the six months ended June 30, 2005 was 20 percent higher than the same period last year.



Daily Three months ended June 30 Six months ended June 30
Production 2005 2004 % Change 2005 2004 % Change
---------------------------------------------------------------------
Light crude
oil (bbls) 20,906 20,906 - 20,676 21,211 (3)%
Heavy oil (bbls) 5,641 1,848 205% 5,842 924 532%
Natural gas
(mcf) 153,423 136,142 13% 155,446 126,745 23%
Natural gas
liquids (bbls) 5,870 6,007 (2)% 6,106 5,300 15%
---------------------------------------------------------------------
Total boe/d 57,988 51,451 13% 58,532 48,560 20%
---------------------------------------------------------------------
---------------------------------------------------------------------


Light oil production volumes were unchanged in the second quarter compared to the second quarter of 2004. The Murphy, Swan Hills and Crispin acquisitions, in addition to development activities over the past year, combined to offset natural production declines.

Heavy oil production was derived from the May 31, 2004 Murphy acquisition, including working interests in Tangleflags and Bodo.

Natural gas production increased 17 mmcf/day (13 percent) in the second quarter of 2005 compared to the second quarter of 2004. Additional gas volumes from the Murphy and Crispin acquisitions, as well as incremental volumes from development activities, including the Monogram area, more than offset the impact of natural production declines.

Natural gas liquids (NGL) production decreased by two percent in the second quarter of 2005 over the same quarter of 2004. The fluctuation in NGL sales from quarter to quarter is due in part to the timing of condensate sales from SOEP. One condensate shipment was made in the second quarter of 2005, compared to two shipments in the same period last year. Pengrowth anticipates five to six shipments for 2005.

Total production for the second quarter of 2005 is down approximately 1,100 boe per day compared to the first quarter of 2005. The main reason for this decrease is one less SOEP condensate shipment which reduced quarterly production by 740 boe per day and third party gas plant maintenance in British Columbia.

Prices

Pengrowth's average commodity price per boe for the second quarter of 2005, after the impact of hedging, was 14 percent higher than the second quarter of 2004.



Average realized
prices Cdn$
(after the
impact Three months ended June 30 Six months ended June 30
of hedging) 2005 2004 % Change 2005 2004 % Change
---------------------------------------------------------------------
Light crude
oil (per bbl) $56.44 $42.46 33% $55.45 $41.50 34%
Heavy oil
(per bbl) 30.32 30.19 - 27.27 30.19 (10)%
Natural gas
(per mcf) 7.34 7.08 4% 7.09 6.96 2%
Natural gas
liquids
(per bbl) 50.03 40.75 23% 50.26 39.16 28%
---------------------------------------------------------------------
Total per boe $46.98 $41.36 14% $45.75 $40.68 12%
---------------------------------------------------------------------
---------------------------------------------------------------------


Pengrowth's average light oil price increased 33 percent in the second quarter of 2005 and 34 percent for the first half compared to the same periods of 2004. Although the West Texas Intermediate (WTI) benchmark price increased 39 percent in the second quarter of 2005 compared to the same period last year, it was partially offset by a nine percent depreciation in the value of the U.S. dollar relative to the Canadian dollar and a small downward adjustment in Pengrowth's average field quality differentials relative to benchmark pricing.

Pengrowth's heavy oil price showed a marginal increase in the second quarter of 2005, while the first half of 2005 compared to 2004 shows a decrease of 10% largely due to the light/heavy price differential.

Pengrowth's average natural gas price for the second quarter of 2005 increased to $7.34 per mcf compared to $7.08 per mcf over the same period last year. Pengrowth's average natural gas prices remained relatively stable year over year reflective of the small increase (five percent) in the AECO Index price. NYMEX last day average price increased by 12 percent but this was partially offset by a weaker U.S. dollar relative to the Canadian dollar. Pengrowth did not experience the full effect of increased market prices as certain fixed price gas contracts which were part of the Murphy acquisition 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 lock in early year returns of new acquisitions. On a combined basis, oil and gas hedging losses were $9.8 million ($1.86 per boe) for the second quarter and $16.5 million ($1.56 per boe) for the first half of 2005 compared to $15.6 million ($3.33 per boe) and $27.4 million ($3.10 per boe) for the respective periods of 2004.

In the second quarter of 2005, Pengrowth realized a net hedging gain of $1.2 million ($0.09 per mcf) related to natural gas financial swap contracts, compared to a net hedging loss of $2.8 million ($0.23 per mcf) for the same period last year. On a year to date basis, Pengrowth has realized a net hedging gain of $1.1 million ($0.04 per mcf) in the first six months of 2005 related to natural gas financial swap contracts, compared to a net hedging loss of $7.5 million ($0.33 per mcf) for the same period of last year.

With the continued strength in crude oil prices in the second quarter, Pengrowth realized a net hedging loss of $11 million ($5.78 per bbl) on light crude oil price swap transactions, compared to a loss of $12.8 million ($6.72 per bbl) in the second quarter of 2004. On a year to date basis, Pengrowth has realized a net hedging loss of $17.6 million ($4.71 per bbl) for the first six months of 2005 on light crude oil price swap transactions, compared to a net hedging loss of $19.9 million ($5.15 per bbl) for the first half of 2004.

In conjunction with the purchase of 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 June 30, 2005 of $21.1 million will continue to be drawn down and recognized in income as the contract is settled. At June 30, 2005, the mark-to-market value of Pengrowth's fixed price physical sales contract represented a potential loss of $29.9 million. As this is a non-cash component of income, it is not included in the calculation of distributable cash.

Pengrowth currently has 10,000 barrels per day of crude oil hedged for the remainder of 2005 at an average price of Cdn $54.39 per barrel and a further 4,000 barrels per day is hedged for 2006 at Cdn $64.08 per barrel. Western gas production of 2,370 MMBTU per day is hedged at an average price of Cdn $8.35 per MMBTU for the period of May 1 to December 31, 2005 and a further 2,370 MMBTU per day is hedged at Cdn $8.03 per MMBTU for 2006. Eastern gas production of 16,000 MMBTU per day is hedged at an average delivered price of Cdn $9.53 per MMBTU for the remainder of 2005 and 2,500 MMBTU per day is hedged at Cdn $10.63 for 2006. For the remainder of 2005, Pengrowth has a Mid-Continent (Chicago) hedge of 2,500 MMBTU per day at Cdn $9.41 per MMBTU. The details of Pengrowth's commodity hedges are provided in Note 9 to the financial statements.

At June 30, 2005, the mark-to-market value of Pengrowth's commodity hedges represented a potential loss of $43.6 million consisting of a loss of $2.1 million on natural gas contracts and $41.5 million for crude oil contracts.

Royalties

Royalties, including crown and freehold royalties, were 17 percent of oil and gas sales in the second quarter of 2005, compared to 16 percent in the second quarter of 2004 due to the higher effective rates applicable at higher commodity prices. For the six month period, royalties were 17 percent and 15 percent in 2005 and 2004, respectively.

Operating Costs

Operating costs were $50.4 million ($9.56 per boe) for the second quarter of 2005, compared to $38.8 million ($8.29 per boe) for the second quarter of 2004. For the six months ended June 30, 2005, operating costs were $99.5 million ($9.39 per boe) compared to $70 million ($7.92 per boe) for the first half of 2004. Higher operating costs associated with the Murphy Assets and Swan Hills acquisitions contributed to higher operating costs on a per boe basis compared to the second quarter of 2004.

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

Injectants for Miscible Floods

During the second quarter of 2005, Pengrowth purchased $5.7 million of injectants and amortized a related $6 million against second quarter net income and distributable cash, compared to $1.9 million and $4.8 million, respectively, in second quarter of 2004. On a year-to-date basis, Pengrowth has purchased $13.3 million of injectants and amortized $11.4 million, compared to $9.2 million and $10 million 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. The majority of ethane and natural gas volumes injected at Judy Creek are proprietary volumes produced from Judy Creek and Swan Hills and then re-injected. Revenue is not recorded for volumes that are produced and subsequently re-injected.

At June 30, 2005, the balance of unamortized injectant costs was $27 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 14 percent reflecting the overall increase in oil and gas prices, net of hedging, offset partially by the increase in operating costs per boe.



Combined Netbacks ($ per Bbl)

---------------------- ------------------------
Three months ended Six months ended
June 30, June 30, June 30, June 30,
2005 2004 2005 2004
---------------------- ------------------------
Sales Price $ 47.79 $ 41.83 $ 46.38 $ 41.15
Other production
income 0.19 0.30 0.17 0.27
GORR Royalties (1.00) (0.77) (0.80) (0.74)
---------------------- ------------------------
46.98 41.36 45.75 40.68
Other income 1.39 0.71 1.09 0.76
Crown and Freehold
Royalties (8.08) (6.64) (7.55) (6.28)
Operating costs (9.56) (8.29) (9.39) (7.92)
Transportation Costs (0.34) (0.40) (0.34) (0.38)
Amortization of
injectants (1.13) (1.03) (1.07) (1.13)
---------------------- ------------------------
Operating Netback $ 29.26 $ 25.71 $ 28.49 $ 25.73
---------------------- ------------------------
---------------------- ------------------------


Light Crude Netbacks ($ per Bbl)
---------------------- ------------------------
Three months ended Six months ended
June 30, June 30, June 30, June 30,
2005 2004 2005 2004
---------------------- ------------------------
Sales Price $ 56.44 $ 42.46 $ 55.45 $ 41.50
Other production
income 0.52 0.74 0.47 0.62
GORR Royalties (1.15) (0.67) (0.90) (0.66)
---------------------- ------------------------
55.81 42.53 55.02 41.46
Other income 0.51 0.63 0.44 0.54
Crown and Freehold
Royalties (8.81) (5.91) (7.66) (4.65)
Operating costs (11.14) (8.35) (10.94) (7.92)
Transportation Costs (0.30) (0.23) (0.30) (0.23)
Amortization of
injectants (3.13) (2.54) (3.03) (2.60)
---------------------- ------------------------
Operating Netback $ 32.94 $ 26.13 $ 33.53 $ 26.60
---------------------- ------------------------


Heavy Oil Netbacks ($ per Bbl)
---------------------- ------------------------
Three months ended Six months ended
June 30, June 30, June 30, June 30,
2005 2004 2005 2004
---------------------- ------------------------
Sales Price $ 30.32 $ 30.19 $ 27.27 $ 30.19
GORR Royalties (0.14) (0.27) (0.10) (0.27)
---------------------- ------------------------
30.18 29.92 27.17 29.92
Other income 0.49 - 0.75 -
Crown and Freehold
Royalties (4.61) (4.38) (3.54) (4.38)
Operating costs (15.88) (7.92) (17.26) (7.92)
---------------------- ------------------------
Operating Netback 10.18 17.62 7.12 17.62
---------------------- ------------------------


Natural Gas Netbacks ($ per Mcf)
---------------------- ------------------------
Three months ended Six months ended
June 30, June 30, June 30, June 30,
2005 2004 2005 2004
---------------------- ------------------------
Sales Price $ 7.34 $ 7.08 $ 7.09 $ 6.96
GORR Royalties (0.18) (0.15) (0.14) (0.14)
---------------------- ------------------------
7.16 6.93 6.95 6.82
Other income 0.44 0.17 0.32 0.20
Crown and Freehold
Royalties (1.16) (1.05) (1.16) (1.05)
Operating costs (1.16) (1.38) (1.12) (1.32)
Transportation Costs (0.09) (0.11) (0.09) (0.10)
---------------------- ------------------------
Operating Netback $ 5.19 $ 4.56 $ 4.90 $ 4.55
---------------------- ------------------------


NGL Netbacks ($ per Bbl)
---------------------- ------------------------
Three months ended Six months ended
June 30, June 30, June 30, June 30,
2005 2004 2005 2004
---------------------- ------------------------
Sales Price $ 50.03 $ 40.75 $ 50.26 $ 39.16
GORR Royalties (1.02) (0.77) (0.84) (0.82)
---------------------- ------------------------
49.01 39.98 49.42 38.34
Crown and Freehold
Royalties (13.57) (11.13) (13.48) (13.19)
Operating costs (9.15) (8.24) (7.98) (7.92)
Transportation Costs - (0.09) - (0.09)
---------------------- ------------------------
Operating Netback $ 26.29 $ 20.52 $ 27.96 $ 17.14
---------------------- ------------------------


General and Administrative

General and administrative expenses (G&A) were $7.1 million ($1.35 per boe) in the second quarter of 2005 compared to $5 million ($1.07 per boe) for the second quarter of 2004. For the six months ended June 30, 2005, G&A expenses were $14.2 million ($1.34 per boe) compared to $10.8 million ($1.23 per boe) for the same period last year. Included in 2005 second quarter G&A is $0.7 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 $0.3 million for the second quarter of 2004. The year to date non-cash component is $1.5 million compared to $1.4 million for the first six months of 2004. Excluding the non-cash component of G&A, 2005 year-to-date G&A has increased over 2004 levels by $3.2 million mainly due to the addition of personnel and office space required to manage the Murphy acquisition.

Management Fees

Management fees were $4.3 million ($0.82 per boe) for the second quarter of 2005 compared to $5.6 million ($1.20 per boe) for the second quarter of 2004. For the six month period, management fees were $8.1 million ($0.76 per boe) for 2005 compared to $8.4 million ($0.95 per boe) in 2004.

Management fees recorded in the second quarter of 2005 include an accrual for estimated performance fees of $2.3 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. However, the maximum fees payable, including the performance fee, is limited to 80 percent of the fees that would otherwise have been payable under the old management agreement for the first three years and 60 percent for the subsequent three years. Management fees have decreased from 2004 due mainly to the 80 percent maximum fee calculation being lower in 2005.

Interest

Interest expense decreased to $5.7 million in the second quarter of 2005 compared to $7.8 million for the second quarter of 2004 due to the absence of bank fees of $2.3 million incurred to establish the bridge facility used to finance the Murphy acquisition. For the first six months of 2005, interest expense was $11.1 million compared to $11.9 million for the same period of 2004. Interest expense includes $0.8 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 increased to $70.9 million in the second quarter of 2005 compared to $58.1 million in the second quarter of 2004. For the six month period, depletion and depreciation was $140.1 million compared to $108.6 million in the first half of 2004. On a per boe basis, depletion and depreciation has increased to $13.44 per boe in the second quarter of 2005 compared to $12.41 per boe in the second quarter of 2004, and $13.22 per boe on a year to date basis, compared to $12.29 in the first six months of 2004. The increase is mainly attributable to the purchase of properties over the past year, including the Murphy Assets 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 $134 million ($0.86 per average trust unit outstanding) of distributable cash related to second quarter 2005 operations, compared to $99 million ($0.73 per average trust unit outstanding) in 2004. For the first six months of 2005, Pengrowth recorded $261.9 million of distributable cash compared to $191.9 million in the first six months of 2004. Distributions were $216.3 million for 2005 (2004 - $172.7 million) and as a percentage of funds generated from operations ("payout ratio") represent approximately 83 percent (2004 - 89 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 second 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 commodity prices during the quarter, this action resulted in an increase in cash available to help fund Pengrowth's capital expenditures. Pengrowth currently expects monthly distributions to remain at $0.23 per trust unit for the third quarter of 2005 up to and including the November 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 second 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 six month periods ended June 30, 2005 and 2004.



($thousands, except per unit amounts)
Three months ended Six months ended
June 30 June 30
---------------------------------------------------------------------
2005 2004 2005 2004
---------------------------------------------------------------------
Funds generated from operations 135,048 102,932 261,455 194,730
Change in deferred injectants (217) (2,874) 1,962 (819)
Change in remediation trust funds (269) (375) (532) (673)
Amortization of deferred charges (395) (473) (790) (947)
Other (120) (189) (244) (374)
---------------------------------------------------------------------
Distributable cash 134,047 99,021 261,851 191,917
---------------------------------------------------------------------
Cash withheld for capital
expenditures 32,810 9,902 45,592 19,194
Distributions 101,237 89,119 216,259 172,723
---------------------------------------------------------------------
134,047 99,021 261,851 191,917
---------------------------------------------------------------------
Distributable cash per unit 0.86 0.73 1.69 1.47
Distributions paid or declared
per unit 0.69 0.64 1.38 1.27
Payout ratio 75% 87% 83% 89%
---------------------------------------------------------------------


At this time, Pengrowth anticipates that approximately 75 to 80 percent of 2005 distributions will be taxable; this estimate is subject to change depending on a number of factors including, but not limited to, the level of commodity prices, acquisitions, dispositions and new equity offerings.

Liquidity and Capital Resources

Pengrowth's long-term debt at June 30, 2005 was $461.5 million, compared to $345.4 million at December 31, 2004 and $371.8 million at June 30, 2004. During the second quarter, Pengrowth assumed approximately $20 million of new debt associated with the Crispin acquisition. Year-to-date capital expenditures, excluding acquisitions, of $74.4 million were financed through the combination of $45.6 million of cash withheld for capital expenditures, proceeds of $16.5 million from the exercise of trust unit rights and options, and positive working capital changes of $12.3 million.

Approximately $130 million of a $375 million revolving credit facility remains unutilized at June 30, 2005. In addition, Pengrowth has a $35 million demand operating line of credit. The revolving credit facility was replaced on July 26, 2005 with a $470 million revolving credit facility which will revolve until June 16, 2006. Details of the new facility are disclosed in Note 2 to the financial statements. The remainder of Pengrowth's debt outstanding at the end of the second 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 increase in the value of the U.S. dollar relative to the Canadian dollar, an unrealized loss of $3.2 million has been recorded in the quarter ended June 30, 2005 on the U.S. dollar denominated debt with a total unrealized gain of $45.2 million recorded since the debt issuance in April 2003.

At the end of the second quarter of 2005, Pengrowth was capitalized with 14 percent net debt (long-term debt less working capital) and 86 percent equity, as compared with 21 percent debt and 79 percent equity at the end of the second quarter of 2004 (based on quarter-end market capitalization). The Trust's net debt to annualized second quarter 2005 cash flow from operations was approximately 1.1 times as compared to 1.7 times at the end of the second quarter of 2004 when additional debt in the form of a bridge facility existed as a result of the Murphy acquisition.

As of August 3, 2005, the number of trust units outstanding was approximately:



(000's)
------------------------------------------------
Class A trust units 77,511
Class B trust units 81,079
Undeclared trust units 48
------------------------------------------------
Total 158,638
------------------------------------------------

As of August 3, 2005, the number of trust units options, rights and
Deferred Entitlement trust units was approximately:

(000's)
------------------------------------------------
Trust unit options 623
Rights incentive options 1,778
Deferred Entitlement trust units 163
------------------------------------------------


Acquisitions

On April 29, 2005, Pengrowth closed the acquisition of all of the issued and outstanding shares of Crispin Energy Inc. The acquisition added estimated proved plus probable reserves of about 5.2 million boe. The acquisition was funded by issuing approximately 677,000 Class A trust units and approximately 3,552,000 Class B trust units valued at $88 million.

Also during 2005, 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.

Capital Spending

Capital expenditures for the six months ending June 30, 2005 totaled $74.4 million including $18.3 million at Judy Creek, $9.5 million at SOEP, $6.3 million at Buick, $4.1 million at Squirrel, $3.6 million at Weyburn and $3 million at Swan Hills.

Pengrowth expects to spend a total of approximately $140 million on maintenance and development activities in the remaining two quarters of 2005 for a total revised capital program of approximately $215 million for full year 2005. This represents an increase of $10 million from Pengrowth's previous guidance of $205 million provided in the first quarter report and reflects an increase in development activity planned at Pengrowth's Weyburn and Princess properties as well as additional development drilling and facilities in Northeast British Columbia. Approximately 83 percent of the first six month's capital expenditures have been funded from withheld 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 two quarters of 2005. Net income and net income per unit decreased quarter over quarter by approximately six percent and eight percent, respectively. The decrease is attributable to a two percent decrease in production volume, particularly the decrease in SOEP condensate shipments as well as the absence of a favorable first quarter prior period future tax expense adjustment, partly offset by a five percent increase in average per boe price realized.



2005 2004
---------------------------------------------------------------------
Q1 Q2 Q1 Q2 Q3 Q4
---------------------------------------------------------------------
Oil and gas
sales ($000's) 236,768 247,903 165,880 193,637 222,848 218,835
Net income ($000's) 56,314 53,106 38,652 32,684 51,271 31,138
Net income per
unit ($) 0.37 0.34 0.31 0.24 0.38 0.23
Net income per
unit - diluted ($) 0.37 0.34 0.31 0.24 0.38 0.23
Distributable
Cash ($000's) 127,804 134,047 92,895 99,021 104,304 104,598
Actual distributions
paid or declared
per unit ($) 0.69 0.69 0.63 0.64 0.67 0.69
Daily production
(boe) 59,082 57,988 45,668 51,451 60,151 57,425
Total Production mboe 5,317 5,277 4,156 4,682 5,534 5,283
Average realized
price per boe
($ per boe) 44.53 46.98 39.91 41.36 40.27 41.42
Operating netback per
boe ($ per boe) 27.70 28.45 25.71 25.71 22.77 24.31
---------------------------------------------------------------------


2003
---------------------------------------------------------------------
Q1 Q2 Q3 Q4
---------------------------------------------------------------------
Oil and gas sales ($000's) 204,824 169,238 162,819 154,140
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 (6:1) 4,574 4,444 4,494 4,384
Average realized price per
boe ($per boe) 44.78 38.08 36.22 35.16
Operating netback per boe ($per boe) 26.50 21.11 20.54 20.43
---------------------------------------------------------------------


Outlook

Based on second quarter 2005 production results, Pengrowth expects daily average production of approximately 56,500 to 58,500 boe per day for the full year 2005. This estimate incorporates production additions from the Swan Hills and Crispin acquisitions as well as Pengrowth's 2005 development program, offset by normal production declines.

Total operating costs for 2005 are expected to increase to approximately $200 million including a full year of costs from the Murphy Assets and those associated with the Swan Hills 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 $9.40 and $9.70 and combined G&A and management fees of approximately $1.91 to $1.97 per boe.

Pengrowth currently anticipates capital expenditures for maintenance and development of approximately $215 million for 2005. In addition, another $175 million was invested to complete the Swan Hills and Crispin acquisitions of which $87 million was paid in cash and the balance was paid through the issuance of Class A trust units and Class B trust units.

Assuming that current levels of commodity prices continue, subject to Board approval, Pengrowth expects monthly distributions during the third quarter will be maintained at $0.23 per trust unit which is expected to represent a 73 percent to 77 percent payout of funds from operations.

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 Unitholders 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. In addition, Pengrowth is considering all alternatives with respect to the Class A and Class B trust units in conjunction with discussions with the Department of Finance.

Pengrowth is continually evaluating its portfolio for optimization opportunities. Subsequent to the quarter end, purchase and sale agreements have been executed with several parties to acquire from Pengrowth approximately 600 boe per day of non-core properties for gross proceeds of approximately $37 million. The divestments are expected to close by August 31, 2005 and have an effective date of June 1, 2005. Pengrowth anticipates further non-core asset divestitures may be possible prior to year end 2005.

CONFERENCE CALL

Pengrowth will hold a conference call beginning at 11:00 A.M. Eastern Time (9:00 A.M. Mountain Time) on Thursday, August 4, 2005 during which Management will review Pengrowth's 2005 second quarter financial and operating results and respond to inquiries from the investment community. To participate callers may dial (800) 814-4941 or Toronto local (416) 640-4127. 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 2, 2005. A telephone replay will be available through to midnight Eastern Time on Saturday, August 6, 2005 by dialing (877) 289-8525 or Toronto local (416) 640-1917 and entering passcode number 21131197 followed by the pound key.


Operations Review

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

Judy Creek (100% working interest)

- Tied in a previously abandoned oil producer that was reactivated and acid fracture stimulated in the first quarter. The initial oil rate is 160 bpd.

- Commenced water injection at a horizontal injector pattern scheduled for solvent injection in the third quarter. Current oil response to this water injection is 250 bopd.

- Solvent injection began at two new miscible patterns, replacing three patterns that completed injection during the second quarter. Oil response will be seen from these new patterns beginning in the third quarter.

Swan Hills Unit (22.34% working interest)

- Four additional hillslide wells were drilled in the hillslide area for a total of seven wells this year. Two of the wells have been completed and are on stream at rates averaging 100 bopd per well and the other five are undergoing either completion or testing operations. These five wells are anticipated to be on stream during the third quarter of 2005.

- The CO2 pilot commenced in October 2004 and the CO2 injection rate has increased from 60 mcf per day to 177 mcf per day. CO2 response is predicted to occur between six to twelve months after the start of injection.

Weyburn Unit (9.75% working interest)

- A total of 22 new horizontal or vertical re-entries were drilled and additional legs were added to two existing horizontal wells at the end of the second quarter. Twenty of the new wells and the two horizontal wells with additional legs are on production. The average unit production rate for the second quarter was 25,925 bopd (2,528 bopd net).

Sable Offshore Energy Project (SOEP) (8.4% working interest)

Production

- Second quarter gross raw gas production from the five SOEP fields, Thebaud, Venture, North Triumph, Alma and South Venture averaged 392 mmcf per day (32.9 mmcf per day net).

- Monthly raw production for April, May and June was 406 mmcf per day (34.1 mmcf per day net), 371 mmcf per day (31.2 mmcf per day net), 401 mmcf per day (33.7 mmcf per day net), respectively.

- South Venture 2 was recompleted in an up hole zone with production starting on May 9, 2005.

- South Venture was completed in June with production starting on June 23, 2005.

- Pengrowth also had a 68,000 bbl condensate lifting in June.

Tier 2 Status

- Fabrication of the compression topsides, jacket and piles is approximately 15 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.

Buick/Prespatou (100% working interest)

- Construction of compressor station and sales pipeline commenced during the second quarter. Upon completion in the third quarter, the new facilities will support production from two wells drilled in the first quarter, for net initial production of 2.5 mmcf per day. The new facilities will also provide for production from additional wells which will be drilled later this year.

Oak B (58.4 % working interest)

- Artificial lift upsize at one oil producer resulted in a net gain of 75 bopd.

McLeod River (75% working interest)

- One gas well drilled. Completion and tie-in will proceed in the third quarter with expected initial production of just over 1 mmcf per day (gross).

Three Hills Creek (65% working interest)

- One gas well was drilled and completed. The associated tie in is expected to proceed in the third quarter with initial production expected to be 800 mcf per day (gross).

Princess (100% working interest)

- 52 well shallow gas drilling program commenced late in the second quarter. Drilling, completion and tie-in operations will continue through the third quarter.

Cactus (100% working interest)

- Installed a new booster compressor to increase gas throughput by 2 mmcf per day.



CONSOLIDATED BALANCE SHEETS

As at As at
June 30 December 31
(Stated in thousands of dollars) 2005 2004
---------------------------------------------------------------------
ASSETS (unaudited) (audited)
CURRENT ASSETS
Accounts receivable $ 104,033 $ 104,228
Inventory - 439
---------------------------------------------------------------------
104,033 104,667

REMEDIATION TRUST FUNDS 8,841 8,309

DEFERRED CHARGES (Note 6) 2,861 3,651

GOODWILL (Note 3) 182,524 170,619

PROPERTY, PLANT AND EQUIPMENT
AND OTHER ASSETS 2,141,769 1,989,288
---------------------------------------------------------------------
$2,440,028 $2,276,534
---------------------------------------------------------------------
---------------------------------------------------------------------

LIABILITIES AND UNITHOLDERS' EQUITY
CURRENT LIABILITIES
Bank indebtedness $ 14,540 $ 4,214
Accounts payable and accrued liabilities 82,371 80,423
Distributions payable to unitholders 72,925 70,456
Due to Pengrowth Management Limited 4,139 7,325
Note payable 15,000 15,000
Current portion of contract liabilities 5,537 5,795
---------------------------------------------------------------------
194,512 183,213

NOTE PAYABLE 20,000 20,000

CONTRACT LIABILITIES 15,576 18,216

LONG-TERM DEBT (Note 2) 461,508 345,400

ASSET RETIREMENT OBLIGATIONS (Note 5) 183,698 171,866

FUTURE INCOME TAXES 103,350 75,628

TRUST UNITHOLDERS' EQUITY
Trust Unitholders' capital (Note 4) 2,488,220 2,383,284
Contributed surplus (Note 4) 3,006 1,923
Accumulated earnings 836,477 727,057
Accumulated distributions paid or declared (1,866,319) (1,650,053)
---------------------------------------------------------------------
1,461,384 1,462,211
---------------------------------------------------------------------

SUBSEQUENT EVENT (Note 10)
$2,440,028 $2,276,534
---------------------------------------------------------------------
---------------------------------------------------------------------

See accompanying notes to the consolidated financial statements.



CONSOLIDATED STATEMENTS OF INCOME AND ACCUMULATED EARNINGS
(Stated in thousands of dollars)
(Unaudited)

Three months ended Six months ended
June 30 June 30
2005 2004 2005 2004
---------------------------------------------------------------------

REVENUES
Oil and gas sales $247,903 $193,637 $484,671 $359,517
Processing and other income 5,614 2,639 9,732 5,624
Crown royalties, net
of incentives (38,361) (27,762) (72,324) (50,783)
Freehold royalties and
mineral taxes (4,252) (3,251) (7,709) (4,746)
---------------------------------------------------------------------
210,904 165,263 414,370 309,612
Interest and other income 1,730 701 1,842 1,126
---------------------------------------------------------------------
NET REVENUE 212,634 165,964 416,212 310,738

EXPENSES
Operating 50,435 38,826 99,514 69,986
Transportation 1,808 1,817 3,615 3,374
Amortization of injectants
for miscible floods 5,961 4,823 11,353 10,027
Interest 5,709 7,755 11,142 11,932
General and administrative 7,125 5,003 14,206 10,849
Management fee 4,343 5,617 8,051 8,371
Foreign exchange loss (Note 7) 2,425 4,666 3,785 7,037
Depletion and depreciation 70,904 58,088 140,053 108,600
Accretion (Note 5) 3,550 2,373 6,953 4,372
---------------------------------------------------------------------
152,260 128,968 298,672 234,548
---------------------------------------------------------------------

NET INCOME BEFORE TAXES 60,374 36,996 117,540 76,190

INCOME TAXES
Capital 1,309 833 2,606 1,375
Future 5,959 3,479 5,514 3,479
---------------------------------------------------------------------
7,268 4,312 8,120 4,854

NET INCOME $ 53,106 $ 32,684 $109,420 $ 71,336
---------------------------------------------------------------------
---------------------------------------------------------------------

Accumulated earnings,
beginning of period 783,371 611,964 727,057 573,312
---------------------------------------------------------------------

ACCUMULATED EARNINGS,
END OF PERIOD $836,477 $644,648 $836,477 $644,648
---------------------------------------------------------------------
---------------------------------------------------------------------

NET INCOME PER UNIT (Note 4)
Basic $ 0.339 $ 0.241 $ 0.706 $ 0.547

Diluted $ 0.338 $ 0.240 $ 0.703 $ 0.545
---------------------------------------------------------------------

See accompanying notes to the consolidated financial statements.



CONSOLIDATED STATEMENTS OF CASH FLOW
(Stated in thousands of dollars)
(Unaudited)

Three months ended Six months ended
June 30 June 30
2005 2004 2005 2004
---------------------------------------------------------------------

CASH PROVIDED BY (USED FOR):

OPERATING
Net income $ 53,106 $ 32,684 $109,420 $ 71,336
Depletion, depreciation
and accretion 74,454 60,461 147,006 112,972
Future income taxes 5,959 3,479 5,514 3,479
Contract liability
amortization (1,449) (824) (2,898) (824)
Amortization of injectants 5,961 4,823 11,353 10,027
Purchase of injectants (5,744) (1,949) (13,315) (9,208)
Expenditures on remediation (1,506) (979) (2,624) (2,830)
Unrealized foreign exchange
loss (Note 7) 3,160 4,500 4,680 7,460
Trust unit based compensation 712 264 1,529 1,371
Amortization of deferred
charges 395 473 790 947
---------------------------------------------------------------------
Funds generated from
operations 135,048 102,932 261,455 194,730

Changes in non-cash operating
working capital (Note 8) (8,962) 4,768 1,051 (108)
---------------------------------------------------------------------
126,086 107,700 262,506 194,622
---------------------------------------------------------------------

FINANCING
Distributions (108,040) (85,310) (213,797) (163,529)
Change in long-term
debt, net (4,031) 325,000 90,969 325,000
Proceeds from issue of
trust units 6,647 5,730 16,530 205,169
---------------------------------------------------------------------
(105,424) 245,420 (106,298) 366,640
---------------------------------------------------------------------

INVESTING
Expenditures on property
acquisitions (1,616) (552,406) (91,566) (553,193)
Expenditures on property,
plant and equipment (28,901) (38,703) (74,436) (63,565)
Change in remediation
trust fund (269) (375) (532) (673)
Change in non-cash investing
working capital (Note 8) 3,192 (7,072) - (2,344)
---------------------------------------------------------------------
(27,594) (598,556) (166,534) (619,775)
---------------------------------------------------------------------

DECREASE IN CASH AND
TERM DEPOSITS (6,932) (245,436) (10,326) (58,513)

CASH AND TERM DEPOSITS
(BANK INDEBTEDNESS) AT
BEGINNING OF PERIOD (7,608) 251,077 (4,214) 64,154
---------------------------------------------------------------------

CASH AND TERM DEPOSITS
(BANK INDEBTEDNESS) AT
END OF PERIOD $(14,540) $ 5,641 $(14,540) $ 5,641
---------------------------------------------------------------------
---------------------------------------------------------------------

See accompanying notes to the consolidated financial statements.



Notes To Consolidated Financial Statements
(Unaudited)
June 30, 2005

(Tabular dollar amounts are stated in thousands of dollars except per 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 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.

LONG-TERM INCENTIVE PLAN

Effective January 1, 2005, Pengrowth established a new long term incentive plan whereby rights incentive options and restricted share units ("Deferred Entitlement trust units") are granted under the plan. The terms of the rights incentive options are consistent with the existing Trust Units Rights Incentive Plan. Compensation expense related to rights incentive options is based on a fair value method using a modified Black Scholes model described in Note 10 of the consolidated financial statements for the fiscal year-ended December 31, 2004.

The terms of the Deferred Entitlement trust units are described in Note 4. 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 condition. 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 unitholders' capital is increased and contributed surplus is reduced.



2. LONG-TERM DEBT
As at As at
June 30, December 31,
2005 2004
---------------------------------------------------------------------
U.S. dollar denominated debt:
U.S. $150 million senior
unsecured notes at 4.93% due April 2010 $ 183,810 $ 180,300
U.S. $50 million senior unsecured
notes at 5.47% due April 2013 61,270 60,100
---------------------------------------------------------------------
245,080 240,400
Canadian dollar revolving credit borrowings 216,428 105,000
---------------------------------------------------------------------
$ 461,508 $ 345,400
---------------------------------------------------------------------


On June 30, 2005 Pengrowth had a $375 million revolving unsecured credit facility syndicated among eight financial institutions with an extendible 364 day revolving period and a two year amortization term period. The facilities are currently reduced by outstanding letters of credit in the amount of approximately $22 million. In addition, it 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 the Corporation. The margins and stamping fees vary from 0.25 percent to 1.50 percent depending on financial statement ratios and the form of borrowing.

The revolving credit facility was replaced on July 26, 2005 with a $470 million revolving unsecured credit facility syndicated among eight financial institutions. The new credit facility is an extendible 364 day revolving facility with a three year amortization period. The new credit facility will revolve until June 16, 2006 and is extendible at that time at the lenders' option. 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. In the event the facility is not renewed, any amount outstanding would be repaid in equal quarterly instalments over the three year period. The Corporation 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.

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 3,552,457 Class B trust units and 676,934 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 11,905

Long-term debt (20,459)

Asset retirement obligations (4,038)

Future income taxes (22,208)
---------------------------------------------------------------------
$ 88,584
---------------------------------------------------------------------
Cost of acquisition:

Trust units issued $ 87,960

Acquisition costs 624
---------------------------------------------------------------------
$ 88,584
---------------------------------------------------------------------


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 $12 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.

June 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
July 27, 2004 to
June 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) 676,934 18,731 - -
Trust units converted 41,591 637 76,792,759 1,176,427
---------------------------------------------------------------------
Balance,
end of period 77,511,284 $ 1,195,795 76,792,759 $ 1,176,427
---------------------------------------------------------------------

Class B Trust Units:

For the period from
July 27, 2004 to
June 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 (16,035) (245) 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) 3,552,457 69,229 - -
Issued for cash on
exercise of trust
units options and
rights 572,770 7,787 746,864 11,516
Issued for cash under
Distribution
Reinvestment
Plan ("DRIP") 508,317 8,743 374,478 6,750
Trust unit rights
incentive plan
(non-cash exercised) - 446 - 271
---------------------------------------------------------------------
Balance,
end of period 80,723,980 $ 1,291,694 76,106,471 $ 1,205,734
---------------------------------------------------------------------


The total number of trust units outstanding as at June 30, 2005 was 158,283,033 trust units (December 31, 2004 - 152,972,555).

Per Unit Amounts

The per unit amounts of net income are based on the following weighted average units outstanding for the period. The weighted average units outstanding for the three months ended June 30, 2005 were 156,718,379 units (June 30, 2004 - 135,472,925 units) and for the six months ended June 30, 2005 were 155,062,147 units (June 30, 2004 - 130,346,384 units). In computing diluted net income per unit, 425,749 units were added to the weighted average number of units outstanding during the three months ended June 30, 2005 (June 30, 2004 - 588,294 units) and 499,559 units were added for the six months ended June 30, 2005 (June 30, 2004 - 618,264 units) for the dilutive effect of trust unit options, rights and Deferred Entitlement trust units. For the three months ended June 30, 2005, 333,583 (June 30, 2004 - 691,622) and for the six months ended June 30, 2005, 823,325 (June 30, 2004 - 691,622) trust unit options and rights were excluded from the diluted net income per unit calculation as their effect is anti-dilutive.



Contributed Surplus
June 30, 2005 December 31, 2004
---------------------------------------------------------------------
Balance, beginning of period $ 1,923 $ 189
Trust unit rights incentive plan
(non-cash expensed) 1,058 2,264
Deferred Entitlement trust units
(non-cash expensed) 471 -
Trust unit rights incentive plan
(non-cash exercised) (446) (530)
---------------------------------------------------------------------
Balance, end of period $ 3,006 $ 1,923
---------------------------------------------------------------------


Trust Unit Option Plan

As at June 30, 2005, options to purchase 632,182 Class B trust units were outstanding (December 31, 2004 - 845,374) that expire at various dates to June 28, 2009.



June 30, 2005 December 31, 2004
---------------------------------------------------------------------
Weighted Weighted
Average Average
Number Exercise Number Exercise
Trust Unit Options 0f options price of options price
---------------------------------------------------------------------
Outstanding at
beginning of period 845,374 $16.97 2,014,903 $17.47
Exercised (195,972) $14.25 (838,789) $16.82
Expired (2,400) $15.25 (325,200) $20.44
Cancelled (14,820) $18.98 (5,540) $16.53
---------------------------------------------------------------------
Outstanding and
exercisable at
period-end 632,182 $17.77 845,374 $16.97
---------------------------------------------------------------------


Rights Incentive Plan

As at June 30, 2005, rights to purchase 2,029,743 Class B trust units were outstanding (December 31, 2004 - 2,011,451) that expire at various dates to March 3, 2010.



June 30, 2005 December 31, 2004
---------------------------------------------------------------------
Weighted Weighted
Average Average
Rights Number Exercise Number Exercise
Incentive Options of rights price of rights price
---------------------------------------------------------------------
Outstanding at
beginning of period 2,011,451 $14.23 1,112,140 $12.20
Granted (1) 482,945 $18.14 1,409,856 $17.35
Exercised (376,798) $13.25 (456,049) $13.47
Cancelled (87,855) $16.47 (54,496) $14.19
---------------------------------------------------------------------
Outstanding at
period-end 2,029,743 $14.59 2,011,451 $14.23
---------------------------------------------------------------------
Exercisable at
period-end 1,165,058 $13.23 1,037,078 $12.48
---------------------------------------------------------------------
(1) Weighted average exercise price of rights granted are based on
the exercise price at the date of grant


The fair value of rights incentive options granted during the six months ended June 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.

Long-Term Incentive Program

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 Corporation 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 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.

As at June 30, 2005, 150,832 Deferred Entitlement trust units were outstanding, including accrued distributions re-invested to June 15, 2005. The Deferred Entitlement trust units vest on March 2, 2008.



Number of Phantom
trust units
---------------------------------------------------------------------
Outstanding, beginning of period -
Granted 160,888
Accrued distributions re-invested 6,108
Cancelled (16,164)
---------------------------------------------------------------------
Outstanding, end of period 150,832
---------------------------------------------------------------------


Compensation expense associated with the Deferred Entitlement trust units was based on the estimated fair value of $18.14 per Deferred Entitlement trust unit.



5. ASSET RETIREMENT OBLIGATIONS

For the six For the year
months ended ended
June 30, December 31,
2005 2004
---------------------------------------------------------------------
Asset retirement obligations,
beginning of period $ 171,866 $ 102,528
Increase in liabilities related to:
Acquisitions 6,347 44,368
Additions 1,156 2,681
Revisions - 16,087
Accretion expense 6,953 10,642
Liabilities settled during the period (2,624) (4,440)
---------------------------------------------------------------------
Asset retirement obligations, end of period $ 183,698 $ 171,866
---------------------------------------------------------------------


6. DEFERRED CHARGES
As at As at
June 30, December 31,
2005 2004
---------------------------------------------------------------------

Imputed interest on note payable
(net of accumulated amortization of $2,224) $ 1,383 $ 2,020
U.S. debt issue costs
(net of accumulated amortization of $663) 1,478 1,631
---------------------------------------------------------------------
$ 2,861 $ 3,651
---------------------------------------------------------------------


7. FOREIGN EXCHANGE LOSS

Three months ended Six months ended
June 30, June 30, June 30, June 30,
2005 2004 2005 2004
---------------------------------------------------------------------
Unrealized foreign
exchange loss on
translation of US
dollar denominated
debt $ 3,160 $ 4,500 $ 4,680 $ 7,460
Realized foreign
exchange loss (gain) (735) 166 (895) (423)
---------------------------------------------------------------------
$ 2,425 $ 4,666 $ 3,785 $ 7,037
---------------------------------------------------------------------


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 Six months ended
June 30, June 30, June 30, June 30,
2005 2004 2005 2004
---------------------------------------------------------------------
Accounts receivable $ 3,636 $ (23,757) $ 2,544 $ (23,556)
Inventory - 641 439 283
Accounts payable and
accrued liabilities (11,311) 24,279 1,254 19,427
Due to Pengrowth
Management Limited (1,287) 3,605 (3,186) 3,738
---------------------------------------------------------------------
$ (8,962) $ 4,768 $ 1,051 $ (108)
---------------------------------------------------------------------



Change in Non-Cash Investing Working Capital

Cash provided by (used for):

Three months ended Six months ended
June 30, June 30, June 30, June 30,
2005 2004 2005 2004
---------------------------------------------------------------------
Accounts payable for
capital accruals $ 3,192 $(7,072) $ - $(2,344)
---------------------------------------------------------------------



Cash Payments

Three months ended Six months ended
June 30, June 30, June 30, June 30,
2005 2004 2005 2004
---------------------------------------------------------------------
Cash payments made
for taxes $ 1,329 $ 632 $ 2,576 $ 1,155
Cash payments made
for interest $ 8,314 $ 10,244 $ 10,189 $ 10,588



9. FINANCIAL INSTRUMENTS

Forward and Futures Contracts

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 June 30, 2005, Pengrowth had fixed the price applicable to future production as follows:



Crude Oil:

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

2005
Financial:
----------
July 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/d) Point per mmbtu
---------------------------------------------------------------------


2005
Financial:
----------
July 1, 2005 - Dec 31, 2005 11,000 Tetco M3 (1) $ 9.27 Cdn
July 1, 2005 - Dec 31, 2005 5,000 Transco Z6 (1) $10.11 Cdn
July 1, 2005 - Dec 31, 2005 2,500 NGI Chicago (1) $ 9.41 Cdn
July 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

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


The estimated fair value of the financial crude oil and natural gas contracts have been determined based on the amounts Pengrowth would receive or pay to terminate the contracts at period-end. At June 30, 2005, the amount Pengrowth would pay to terminate the financial crude oil and natural gas contracts would be $41,505,000 and $2,132,000, 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:



Price
Volume per
Remaining Term (mmbtu/d) 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 - April 30, 2009 3,886 $2.40 Cdn
---------------------------------------------------------------------
(2) Reference price based on AECO


As at June 30, 2005, the fair value amount Pengrowth would pay to terminate the natural gas fixed price sales contract would be $29,910,000 (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 June 30, 2005 was approximately $8,928,000 (December 31, 2004 - $8,366,000). The fair value of the U.S. dollar denominated debt at June 30, 2005 was approximately $243,858,000 (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 June 30, 2005, approximates its carrying value net of the imputed interest included in deferred charges.

10. SUBSEQUENT EVENT

Subsequent to quarter end, purchase and sale agreements have been executed with several parties who will acquire certain non-core properties of Pengrowth for proceeds of approximately $37 million, before adjustments. The divestments have an effective date of June 1, 2005 and are expected to close by August 31, 2005.

Contact Information