Pengrowth Energy Trust
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Pengrowth Energy Trust
Pengrowth Corporation

Pengrowth Corporation

February 28, 2005 10:53 ET

Pengrowth Energy Trust Announces Unaudited Financial, Operating and Reserve Results for Year Ended December 31, 2004

CALGARY, ALBERTA--(CCNMatthews - Feb. 28, 2005) - Pengrowth Corporation
("Pengrowth"), administrator of Pengrowth Energy Trust (the "Trust"), is
pleased to report operating and financial results for the fourth quarter
and year ended December 31, 2004 as well as selected information from
Pengrowth's independent engineering reserve report effective December 31,
2004.

2004 KEY ACHIEVEMENTS

- Fourth quarter oil and gas sales increased 42% to $218.8 million in
2004 from $154.1 million in 2003 resulting in full year 2004 oil and
gas sales of $801.2 million, up 16% from $691.0 million in 2003.

- On May 31, 2004 Pengrowth acquired oil and natural gas assets
in Alberta and Saskatchewan from a subsidiary of Murphy Oil
Corporation (the "Murphy Assets") for $550.8 million. These properties
increased Pengrowth's proved plus probable reserves by 46.1 million
barrels of oil equivalent (boe) and increased daily production by
approximately 14,600 barrels of oil equivalent per day (boepd),
representing an increase of 25% from Pengrowth's opening reserve base
and a contribution of approximately 31% to average daily production
during the fourth quarter 2004.

- On July 27, 2004 Pengrowth trust units were reclassified as Class A
and Class B trust units. The reclassification was initiated in
response to restrictions on foreign ownership in mutual
fund trusts. On December 6, 2004, subsequent to the reclassification,
the Minister of Finance announced his intention to defer
implementation of legislation proposed in the March 23, 2004 Federal
Budget that would have further restricted foreign ownership to allow
further consultation with industry participants. The reclassification
positions Pengrowth to actively manage the level of foreign ownership
in the Trust to comply with existing and possible future legislative
requirements, thereby ensuring the Trust's continued status as a
mutual fund trust.

- Pengrowth ended the year with proved plus probable reserves of
218.6 mmboe compared to 184.4 mmboe at year-end 2003. This represents
an increase of 34 mmboe or over 18% resulting from acquisitions of
48 mmboe, largely attributable to the Murphy Assets, and 6 mmboe of
positive reserve revisions and additions, offset by 20 mmboe of
production.

- Pengrowth raised a total of $509.8 million in new equity during 2004,
including a public offering of 10.9 million trust units on March 23,
2004 for gross proceeds of $200.6 million ($189.9 million net
proceeds) and a public offering of 16.0 million Class B trust units
for gross proceeds of $298.9 million ($283.3 million net proceeds) on
December 30, 2004. An additional $36.6 million in proceeds was
raised under the Distribution Reinvestment Plan("DRIP")and the
employee trust unit option and rights plans.

- With the closing of the Class B trust unit offering at the end of
2004, Pengrowth's financial position remained strong with a long-term
debt to debt-plus-equity ratio at a conservative 19% of total
consolidated capitalization at book, providing Pengrowth with
sufficient borrowing capacity to fully fund its 2005 capital
requirements.

The following table and discussion includes non-GAAP financial measures.
Certain non-GAAP financial measures are used to facilitate the evaluation of
underlying trends that can be compared with prior periods and may not be
comparable to results presented by other companies (see Non-GAAP Financial
Measures).

<<

Financial and Operating Highlights

(thousands, except Three Months ended
per unit amounts) December 31 %
2004 2003 Change
Income Statement
Oil and gas sales $ 218,835 $ 154,139(*) 42
Net income $ 31,138 $ 37,355 (17)
Net income per unit $ 0.23 $ 0.31 (26)
Distributable cash $ 96,466 $ 71,469 35
Actual distributions paid or
declared per unit $ 0.69 $ 0.63 10
Weighted average number of trust
units outstanding 136,916 122,326 12

Balance Sheet
Working capital
Property, plant and equipment
and other assets
Long-term debt
Unitholders' equity
Unitholders' equity per unit
Number of units outstanding at
year end

Daily Production
Crude oil (barrels) 20,118 22,193 (9)
Heavy oil (barrels) 5,819 0
Natural gas (thousands of
cubic feet) 156,621 117,315 34
Natural gas liquids (barrels) 5,385 5,907 (9)
Total production (BOE) 6:1 57,425 47,653 21

Total production (mboe) 6:1 5,283 4,384 21

Change in production (year
over year) (%) 21% (9%)

Production Profile
Crude oil 35% 47%
Heavy oil 10% 0%
Natural gas 46% 41%
Natural gas liquids 9% 12%

Average Prices
Crude oil (per barrel) $ 44.76 $ 38.29(*) 17
Heavy oil (per barrel) $ 26.99 $ -
Natural gas (per mcf) $ 7.02 $ 5.50(*) 28
Natural gas liquids (per barrel) $ 48.04 $ 35.52(*) 35
Average price per BOE 6:1 $ 41.42 $ 35.16(*) 18

Proved Plus Probable Reserves
Crude oil (mbbls)
Heavy oil (mbbls)
Natural gas (bcf)
Natural gas liquids (mbbls)
Total oil equivalent (mboe)


(thousands, except Twelve Months ended
per unit amounts) December 31 %
2004 2003 Change
Income Statement
Oil and gas sales $ 801,200 $ 691,020(*) 16
Net income $ 153,745 $ 189,297 (19)
Net income per unit $ 1.15 $ 1.63 (29)
Distributable cash $ 363,061 $ 313,415 16
Actual distributions paid or
declared per unit $ 2.63 $ 2.68 (2)
Weighted average number of trust
units outstanding 133,395 115,912 15

Balance Sheet
Working capital $ (78,546) $ 12,966 (706)
Property, plant and equipment
and other assets $ 1,989,288 $ 1,530,359 30
Long-term debt $ 345,400 $ 259,300 33
Unitholders' equity $ 1,462,211 $ 1,159,433 26
Unitholders' equity per unit $ 9.56 $ 9.36 2
Number of units outstanding at
year end 152,973 123,874 23

Daily Production
Crude oil (barrels) 20,817 23,337 (11)
Heavy oil (barrels) 3,558 0
Natural gas (thousands of
cubic feet) 144,277 119,842 20
Natural gas liquids (barrels) 5,281 5,722 (8)
Total production (BOE) 6:1 53,702 49,033 10

Total production (mboe) 6:1 19,655 17,897 10

Change in production (year
over year) (%) 10% 12%

Production Profile
Crude oil 39% 47%
Heavy oil 6% 0%
Natural gas 45% 41%
Natural gas liquids 10% 12%

Average Prices
Crude oil (per barrel) $ 43.21 $ 40.85(*) 6
Heavy oil (per barrel) $ 32.45 $ -
Natural gas (per mcf) $ 6.80 $ 6.35(*) 7
Natural gas liquids (per barrel) $ 42.21 $ 35.54(*) 19
Average price per BOE 6:1 $ 40.76 $ 38.61(*) 6

Proved Plus Probable Reserves
Crude oil (mbbls) 94,066 97,360 (3)
Heavy oil (mbbls) 18,245 -
Natural gas (bcf) 521 413 26
Natural gas liquids (mbbls) 19,395 18,250 6
Total oil equivalent (mboe) 218,613 184,416 19

(*) Restated to conform to presentation adopted in the current year

Note Regarding Forward-Looking Statements
The following discussion and analysis contains forward-looking
statements. These statements relate to future events or our future
performance. In some cases, you can identify forward-looking statements by
terminology such as "may", "will", "should", "expect", "plan", "anticipate",
"believe", "estimate", "predict", "potential", "continue", or the negative of
these terms or other comparable terminology. These statements are only
predictions. A number of factors may cause actual results to vary materially
from these estimates. Actual events or results may differ materially. In
addition, this discussion contains forward-looking statements attributed to
third party industry sources. Readers should not place undue reliance on these
forward- looking statements.
The amounts recorded for depletion, depreciation, amortization of
injectants and the provision for asset retirement obligations are based on
estimates. The ceiling test calculation is based on estimates of proved
reserves, production rates, oil and natural gas prices, future costs and other
relevant assumptions. As required by National Instrument 51-101 ("NI 51-101"),
Pengrowth uses independent qualified reserve evaluators in the preparation of
reserve evaluations. By their nature, these estimates are subject to
measurement uncertainty and changes in these estimates may impact the
consolidated financial statements of future periods.

Non-GAAP Financial Measures

This press release refers to certain financial measures that are not
determined in accordance with Canadian Generally Accepted Accounting
Principles ("GAAP") in Canada or the United States. These measures do not have
standardized meanings and may not be comparable to similar measures presented
by other trusts or corporations. Although such measures as Distributable cash,
Distributable cash before withholding and Operating netbacks do not have
standardized meanings prescribed by GAAP. Distributable cash is determined by
reference to the Distributions and Taxability of Distributions section of this
release while the remaining measures are determined by reference to our
financial statements. We discuss these measures, which have been applied on a
consistent basis, because we believe that they facilitate the understanding of
the results of our operations and financial position.

Conversion and currency

When converting natural gas to equivalent barrels of oil within this
discussion, Pengrowth has adopted the international standard of 6 thousand
cubic feet (mcf) to one barrel of oil equivalent (boe). Barrels of oil
equivalent may be misleading, particularly if used in isolation; a conversion
ratio of 6 mcf of natural gas to one boe is based on an energy equivalency
conversion method primarily applicable at the burner tip and does not
represent a value equivalency at the wellhead. All amounts are stated in
Canadian dollars unless otherwise specified.

2004 YEAR OVERVIEW

Robust commodity prices and seven months of incremental production from
the Murphy Assets combined for another solid year of cash flow generation for
Pengrowth. Funds generated from operations were up 13% from 2003 leading to an
increase of 16% in the level of Distributable cash for the year ended December
31, 2004 compared to 2003. Financial hedging losses of $69.1 million on crude
oil and natural gas offset some of the positive impact of the high benchmark
prices for the year as did the 7% depreciation of the U.S. dollar relative to
the Canadian dollar.
Pengrowth also achieved strong results from its 2004 capital expenditure
program. During the year Pengrowth spent a combined total of $161.1 million on
maintenance and development projects with approximately $112.1 million of that
amount directed specifically towards development activities which resulted in
the addition of new proved plus probable reserves of 1.4 mmboe and the
reclassification of 6.6 mmboe of reserves from the proved undeveloped to the
proved developed category. Approximately 46% of expenditures were funded
through a combination of the 10% holdback from distributions and equity
proceeds received from the DRIP and the employee trust unit option and rights
incentive plans.
Distributable cash to unitholders increased to $363 million in 2004 from
$313 million in 2003. Actual distributions paid or declared in respect of the
2004 production year were $2.63 per trust unit, a marginal decrease of 1.9%
from $2.68 per trust unit in 2003.
Net income decreased to $154 million in 2004 ($31.1 million in the fourth
quarter) from $189 million in 2003 ($37.4 million in the fourth quarter). The
reduction in income resulted largely from lower unrealized foreign exchange
gains on U.S. dollar debt (2004 - $18.9 million; 2003 - $30.9 million) and a
higher per boe depletion rate in 2004 versus 2003 (2004 - $12.58 per boe; 2003
- $10.35 per boe). The 22% increase in the depletion rate per boe is
reflective of the relatively higher cost of 2004 reserve additions compared to
the lower cost of older reserves. In 2004, Pengrowth recognized a future
income tax liability on the acquisition of the Murphy Assets. Net income in
2004 includes a $15.6 million future income tax expense which represents an
increase in the future income tax liability subsequent to the acquisition.
During 2004 Pengrowth realized an average commodity price of $40.76 per
boe, an increase of 6% versus the average realized commodity price of $38.61
in 2003. In the fourth quarter the average realized commodity price was
$41.42, an increase of 18% versus the fourth quarter of 2003.

2004 OPERATIONAL REVIEW

Production

Pengrowth exited the year with fourth quarter production of 2004 of
57,425 boepd, an increase of 21% over the same period of 2003. Full year
average production increased 10% to 53,702 boepd in 2004 compared to 49,033
boepd in 2003. This increase is attributable mainly to the mid-year
acquisition of the Murphy Assets which added approximately 14,600 boepd
commencing in June, comprised mainly of heavy oil and natural gas.

Daily Production Volume 2004 2003 % Change
-------------------------------------------------------------------------
Light crude oil (bbl) 20,817 23,337 (11)
Heavy oil (bbl) 3,558 -
Natural gas (mcf) 144,277 119,842 20
Natural gas liquids (bbl) 5,281 5,722 (8)
Total production (boe) 53,702 49,033 10


Pricing and Commodity Price Hedging

The increase in U.S. dollar based prices for North American crude oil and
natural gas were partially offset by the negative impact of the rising
Canadian dollar relative to the U.S. dollar and hedging losses.

Benchmark Pricing 2004 2003 % Change
-------------------------------------------------------------------------
WTI crude oil ($U.S./bbl) $ 37.35 $ 30.99 21
AECO (monthly) natural gas ($/mcf) $ 6.58 $ 6.70 (2)
NYMEX (Henry Hub close) natural
gas ($U.S./MMbtu) $ 6.26 $ 5.39 16
Currency ($U.S./$Cdn) $ 0.77 $ 0.71 (7)


Pengrowth's Average Realized Prices
-------------------------------------------------------------------------
(Adjusted for Hedging)
2004 2003 % Change
-------------------------------------------------------------------------
Crude oil ($/bbl) $ 43.21 $ 40.85 6
Heavy oil ($/bbl) $ 32.45 -
Natural gas ($/mcf) $ 6.80 $ 6.35 7
Natural gas liquids ($/bbl) $ 42.21 $ 35.54 19
Average price ($/boe) 6:1 $ 40.76 $ 38.61 6


Oil and Gas Sales

($ millions)
-------------------------------------------------------------------------

2004 2003 % Change
-------------------------------------------------------------------------
Crude oil $ 329.2 $ 348.0 (5)
Heavy oil 42.3 -
Natural gas 359.3 277.8 29
Natural gas liquids 81.6 74.2 10
Less: gross overriding royalties (14.6) (11.7) 24
Gas marketing, brokering income
and sulphur 3.4 2.7 27
-------------------------------------------------------------------------
Total oil and gas sales $ 801.2 $ 691.0 16
-------------------------------------------------------------------------

The following table illustrates in detail the effect of changes in prices
and volumes on the components of oil and gas sales including the impact of
hedges which expired during the period.

Oil and Gas Sales - Price and volume analysis

(millions Light Heavy Natural
of dollars) Oil Oil Gas NGL GORR Other Total
-------------------------------------------------------------------------
Year ended
December 31,
2003 $348.0 - $277.8 $ 74.2 ($11.7) $2.7 $691.0
Effect of changes
in sales volumes (36.8) 42.3 57.6 (5.5) - - 57.6
Effect of increase
in product prices 18.0 - 23.9 12.9 - - 54.8
Other - - - - (2.9) 0.7 (2.2)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Year end
December 31,
2004 $329.2 $ 42.3 $359.3 $ 81.6 ($14.6) $ 3.4 $801.2
-------------------------------------------------------------------------

Royalties

Crown royalties (net of incentives), freehold royalties and mineral taxes
increased to $145.8 million in 2004 from $114.9 million in 2003. Royalties as
a percentage of oil and gas sales increased to 18.2% in 2004 from 16.6% in
2003 as a result of higher commodity prices. Also affecting royalties was an
adjustment to the Enhanced Oil Recovery relief as a result of solvent
injection costs being $6.5 million lower at Judy Creek due to shutdowns and
changes in injection strategy.

Operating Expenses

Operating expenses increased to $159.7 million in 2004 compared to
$149.0 million in 2003. The increase is due mainly to the purchase of the
Murphy Assets offset in part by a decrease in operating costs at the Sable
Offshore Energy Project ("SOEP") due to the elimination of processing fees as
a result of the purchase of the processing facilities in May and December of
2003.
Operating costs per boe decreased to $8.13 per boe in 2004 from
$8.33 per boe in 2003. The decrease was due mainly to the elimination of SOEP
processing fees, offset in part by the impact of production declines at a
number of Pengrowth's properties and general cost increases in the industry.

Amortization of Injectants for Miscible Floods

The cost of injectants (primarily ethane and methane) purchased for
injection in miscible flood programs is amortized over the period of expected
future economic benefit. Prior to 2005, the expected future economic benefit
from injection was estimated at 30 months, based on the results of previous
flood patterns. Commencing in 2005, the response period for additional new
patterns being developed is expected to be somewhat shorter relative to the
historical miscible patterns in the project. Accordingly, the cost of
injectants purchased in 2005 will be amortized over a 24 month period while
costs incurred for the purchase of injectants in prior periods will continue
to be amortized over 30 months. The total cost of purchased injectants
decreased to $20.4 million in 2004 from $23.0 million in 2003. In 2004,
$19.7 million was amortized and deducted from Distributable cash (2003 -
$32.5 million). As at December 31, 2004, Pengrowth had deferred injectant
costs of $25.0 million, which will be amortized and charged against
Distributable cash of future periods.
The value of Pengrowth's proprietary injectants is not recorded until
reproduced from the flood and sold, although the cost of producing these
injectants is included in operating costs. Pengrowth currently anticipates
lower injection volumes through 2005, however this is expected to be offset
somewhat by higher forecast prices for natural gas and ethane and the increase
in Pengrowth's working interest in Swan Hills resulting in anticipated total
injectant costs for 2005 relatively unchanged from those incurred in 2004. The
amount of injectants amortized against net income is expected to increase in
2005 as a result of a shorter amortization period and the acquisition of the
additional interest in Swan Hills Unit No.1.

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, heavy oil, natural gas and
natural gas liquids production.
Pengrowth recorded an operating netback of $24.51 per boe in 2004
($24.31 in the fourth quarter) compared to $22.17 in 2003 ($20.43 in the
fourth quarter), mainly due to higher average commodity prices in 2004.

Three Months Ended Twelve Months Ended
Dec 31, Dec 31, Dec 31, Dec 31,
2004 2003 2004 2003
-------------------------------------------------------------------------
Light Crude Netbacks
($ per Bbl)

Sales Price $ 44.76 $ 38.29 $ 43.21 $ 40.85
Other production
income 0.48 0.25 0.45 0.31
GORR Royalties (0.90) (0.54) (0.76) (0.54)
-------------------------------------------------------------------------
44.34 38.00 42.90 40.62
Other income 0.51 0.43 0.46 0.35
Crown and Freehold
Royalties (8.75) (2.77) (6.86) (4.94)
Operating costs (9.17) (9.65) (9.31) (8.60)
Transportation Costs (0.23) (0.21) (0.23) (0.21)
Amortization of
injectants (2.67) (2.96) (2.58) (3.82)
-------------------------------------------------------------------------
Operating Netback $ 24.03 $ 22.84 $ 24.38 $ 23.40
-------------------------------------------------------------------------



Three Months Ended Twelve Months Ended
Dec 31, Dec 31, Dec 31, Dec 31,
2004 2003 2004 2003
-------------------------------------------------------------------------
Heavy Oil Netbacks
($ per Bbl)
-------------------------------------------------------------------------

Sales Price $ 26.99 $ - $ 32.45 $ -
GORR Royalties (0.27) - (0.21) -
-------------------------------------------------------------------------
26.72 - 32.24 -
Crown and Freehold
Royalties (3.92) - (4.66) -
Operating costs (9.44) - (9.85) -
-------------------------------------------------------------------------
Operating Netback $ 13.36 $ - $ 17.73 -
-------------------------------------------------------------------------

Natural Gas Netbacks
($ per Mcf)
-------------------------------------------------------------------------
Sales Price $ 7.02 $ 5.50 $ 6.80 $ 6.35
GORR Royalties (0.14) (0.15) (0.13) (0.12)
-------------------------------------------------------------------------
6.88 5.35 6.67 6.23
Other income 0.24 0.17 0.20 0.17
Crown and Freehold
Royalties (1.20) (0.87) (1.13) (1.06)
Operating costs (1.16) (1.32) (1.15) (1.31)
Transportation Costs (0.14) (0.15) (0.12) (0.14)
-------------------------------------------------------------------------
Operating Netback $ 4.62 $ 3.18 $ 4.47 $ 3.89
-------------------------------------------------------------------------

NGL Netbacks ($ per Bbl)
-------------------------------------------------------------------------
Sales Price $ 48.04 $ 35.52 $ 42.21 $ 35.54
GORR Royalties (1.02) (0.92) (0.92) (0.87)
-------------------------------------------------------------------------
47.02 34.60 41.29 34.67
Crown and Freehold
Royalties (18.35) (9.38) (14.51) (12.56)
Operating costs (7.87) (9.46) (7.94) (8.94)
Transportation Costs (0.10) (0.07) (0.10) (0.08)
-------------------------------------------------------------------------
Operating Netback $ 20.70 $ 15.69 $ 18.74 $ 13.09
-------------------------------------------------------------------------

Combined Netbacks
($ per Bbl)
-------------------------------------------------------------------------
Sales Price $ 42.08 $ 35.78 $ 41.33 $ 39.11
Other production
income 0.17 0.12 0.17 0.15
GORR Royalties (0.83) (0.74) (0.74) (0.65)
-------------------------------------------------------------------------
41.42 35.16 40.76 38.61
Other income 0.83 0.63 0.72 0.59
Crown and Freehold
Royalties (8.47) (4.60) (7.42) (6.42)
Operating costs (8.06) (8.91) (8.13) (8.33)
Transportation Costs (0.47) (0.47) (0.42) (0.46)
Amortization of
injectants (0.94) (1.38) (1.00) (1.82)
-------------------------------------------------------------------------
Operating Netback $ 24.31 $ 20.43 $ 24.51 $ 22.17
-------------------------------------------------------------------------

Reserves (Development and Acquisition)

Based on an independent engineering evaluation conducted by Gilbert
Laustsen Jung Associates Ltd. (GLJ) effective December 31, 2004 and prepared
in accordance with NI 51-101, Pengrowth had proved plus probable reserves of
218.6 mmboe compared to 184.4 mmboe at year end 2003. This represents an
increase of 34 mmboe resulting from acquisitions of 48 mmboe, largely
attributable to the Murphy Assets, and 6 mmboe of positive reserve revisions
and additions, offset by 20 mmboe of production.
Proved producing reserves are estimated at 142 mmboe and represent 65% of
proved plus probable reserves and total proved reserves of 175 mmboe account
for 80% of proved plus probable reserves. These percentages compare to 64% and
81% for 2003, respectively.
Using a 10% discount factor and GLJ January 1, 2005 forecast pricing, the
proved producing reserves account for 71% of the proved plus probable value
while the total proved reserves account for 84% of the proved plus probable
value. Using a 6:1 boe conversion rate for natural gas, approximately 43% of
Pengrowth's reserves are light/medium crude oil, 8% are heavy oil (acquired
from Murphy), 40% are natural gas and 9% are Natural Gas Liquids (NGLs).
Pengrowth remains a geographically diversified energy trust with
properties located across Canada in the provinces of British Columbia,
Alberta, Saskatchewan and offshore Nova Scotia. On a proved plus probable
reserve basis, the Alberta, Saskatchewan, British Columbia and offshore Nova
Scotia holdings account for 68%, 14%, 10%, and 8% of reserves reported by GLJ,
respectively.

Reserves Summary 2004

Company Interest (Working Interest plus Royalty Interest before the
deduction of Royalty Burdens Payable)

Oil Oil
Light and Equi- Equi-
Medium Heavy Natural valent valent
Crude Oil Oil NGLs Gas 2004 2003
mbbl mbbl mbbl bcf mboe mboe
-------------------------------------------------------------------------
Proved
Producing 57,654 12,592 12,841 355.6 142,353 117,937
Proved
Developed
Non-Producing 548 72 376 23.0 4,825 2,680
Proved
Undeveloped 15,973 1,958 2,271 48.7 28,324 28,442
-------------------------------------------------------------------------
Total Proved 74,175 14,622 15,488 427.3 175,502 149,060
-------------------------------------------------------------------------
Proved plus
Probable 94,066 18,245 19,395 521.4 218,613 184,416
-------------------------------------------------------------------------

Net Interest (Working Interest less Royalties Payable)

Oil Oil
Light and Equi- Equi-
Medium Heavy Natural valent valent
Crude Oil Oil NGLs Gas 2004 2003
mbbl mbbl mbbl bcf mboe mboe
-------------------------------------------------------------------------
Proved
Producing 49,212 11,037 9,037 285.1 116,798 95,760
Proved
Developed
Non-Producing 465 62 292 17.6 3,757 2,120
Proved
Undeveloped 13,894 1,633 1,644 38.7 23,616 24,478
-------------------------------------------------------------------------
Total Proved 63,572 12,733 10,974 341.4 144,171 122,357
-------------------------------------------------------------------------
Proved plus
Probable 80,443 15,798 13,819 415.4 179,298 151,060
-------------------------------------------------------------------------

Reserve Reconciliation

Pengrowth added 54 mmboe of proved plus probable reserves during 2004,
replacing 2004 production by 270%. The acquisition of the Murphy Assets, which
included heavy oil along the Alberta-Saskatchewan border and light oil and
natural gas in southern and west central Alberta, accounted for approximately
85% of the reserve increase. The balance was due to drilling additions, mainly
in Southeast Alberta shallow gas, and performance related positive revisions,
mainly in the Weyburn Unit CO2 miscible flood and the SOEP Alma field.

Company Interest Volumes (before deduction of Royalty Burdens Payable)

Light and
Medium Natural Oil
Crude Oil Heavy Oil NGLs Gas Equivalent
mbbl mbbl mbbl bcf mboe
-------------------------------------------------------------------------
Total Proved
December 31,
2003 78,038 - 14,638 338.3 149,060
Exploration
and Development 93 - 11 2.3 487
Improved
Recovery 473 - 36 10.8 2,309
Revisions 1,168 - 771 7.1 3,124
Acquisitions 2,022 15,924 1,965 121.6 40,177
Dispositions - - - - -
Production (7,619) (1,302) (1,933) (52.8) (19,655)
-------------------------------------------------------------------------
December 31,
2004 74,175 14,622 15,488 427.3 175,501
-------------------------------------------------------------------------
Proved plus
Probable
December 31,
2003 97,360 - 18,250 412.8 184,416
Exploration
and Development 173 - 17 3.2 724
Improved
Recovery 367 - 37 12.0 2,404
Revisions 1,442 - 762 3.8 2,838
Acquisitions 2,343 19,547 2,262 142.4 47,886
Dispositions - - - - -
Production (7,619) (1,302) (1,933) (52.8) (19,655)
-------------------------------------------------------------------------
December 31,
2004 94,066 18,245 19,395 521.4 218,613
-------------------------------------------------------------------------


Net After Royalty Volumes

Light and
Medium Natural Oil
Crude Oil Heavy Oil NGLs Gas Equivalent
mbbl mbbl mbbl bcf mboe
-------------------------------------------------------------------------
Total Proved
December 31,
2003 66,667 - 10,509 271.1 122,357
Exploration
and Development 79 - 8 1.8 394
Improved
Recovery 405 - 25 8.6 1,869
Revisions 791 - 590 5.4 2,278
Acquisitions 1,733 13,863 1,392 97.1 33,179
Dispositions - - - - -
Production (6,104) (1,130) (1,550) (42.7) (15,907)
-------------------------------------------------------------------------
December 31,
2004 63,572 12,733 10,974 341.4 144,171
-------------------------------------------------------------------------
Proved plus
Probable
December 31,
2003 83,173 - 13,138 328.5 151,060
Exploration
and Development 148 - 12 2.5 586
Improved
Recovery 314 - 26 9.6 1,933
Revisions 908 - 581 4.1 2,173
Acquisitions 2,004 16,928 1,612 113.4 39,452
Dispositions - - - - -
Production (6,104) (1,130) (1,550) (42.7) (15,907)
-------------------------------------------------------------------------
December 31,
2003 80,443 15,798 13,819 415.4 179,298
-------------------------------------------------------------------------


Net Present Value (NPV) Summary 2004
------------------------------------

At GLJ January 1, 2005 forecast prices and costs(*)

Undiscounted Discounted Discounted Discounted Discounted
$M at 8%, $M at 10%, $M at 12%, $M at 15%, $M
-------------------------------------------------------------------------
Proved
Producing 2,364,561 1,650,513 1,544,553 1,454,228 1,340,922
Proved
Developed
Non-Producing 109,632 66,740 60,905 56,019 49,999
Proved
Undeveloped 458,079 240,947 208,768 181,768 148,767
-------------------------------------------------------------------------
Total Proved 2,932,271 1,958,199 1,814,226 1,692,016 1,539,687
-------------------------------------------------------------------------
Proved plus
Probable 3,836,540 2,364,797 2,167,082 2,002,558 1,801,428
-------------------------------------------------------------------------
(*) Prior to provision for income taxes, interest, debt service charges
and general and administrative expenses.

Constant Prices at December 31, 2004(*)

Undiscounted Discounted Discounted Discounted Discounted
$M at 8%, $M at 10%, $M at 12%, $M at 15%, $M
-------------------------------------------------------------------------
Proved
Producing 2,720,359 1,805,738 1,674,719 1,564,163 1,427,068
Proved
Developed
Non-Producing 120,672 74,590 68,077 62,587 55,785
Proved
Undeveloped 534,033 286,803 249,589 218,250 179,808
-------------------------------------------------------------------------
Total Proved 3,375,064 2,167,130 1,992,385 1,845,000 1,662,661
-------------------------------------------------------------------------
Proved plus
Probable 4,345,327 2,613,047 2,379,906 2,186,164 1,949,936
-------------------------------------------------------------------------
(*) Prior to provision for income taxes, interest, debt service charges
and general and administrative expenses.


GLJ's price forecast is shown below:

Edmonton
WTI Light Natural
Crude Oil Crude Oil Gas at AECO
Year ($U.S./bbl) ($Cdn/bbl) ($Cdn/mmbtu)
-------------------------------------------------------------------------
2005 42.00 50.25 6.60
2006 40.00 47.25 6.35
2007 38.00 45.50 6.15
2008 36.00 43.25 6.00
2009 34.00 40.75 6.00
2010 33.00 39.50 6.00
2011 33.00 39.50 6.00
2012 33.00 39.50 6.00
2013 33.50 40.00 6.10
2014 34.00 40.75 6.20
2015 34.50 41.25 6.30
Escalate thereafter 2.0% per year 2.0% per year 2.0% per year


Constant Prices at December 31, 2004:

Edmonton
WTI Light Natural
Crude Oil Crude Oil Gas at AECO
($U.S./bbl) ($Cdn/bbl) ($Cdn/mmbtu)
-------------------------------------------
43.45 46.54 6.79


Net Asset Value (NAV) at December 31, 2004

In the following table, Pengrowth's net asset value is measured with
reference to the present value of future net cash flows from reserves, as
estimated by GLJ. The calculation is shown using both the GLJ forecast prices
and constant (year-end 2004) prices.
NAV at December 31, 2004

GLJ GLJ
Forecast Constant
$Thousands, except per unit amounts Prices Prices
-------------------------------------------------------------------------

Value of Proved plus Probable Reserves
discounted at 10% $ 2,167,082 $ 2,379,906
Undeveloped Lands(1) 35,326 35,326
Working Capital Deficit(2) (8,090) (8,090)
Reclamation Fund 8,309 8,309
Long-term debt(3) (383,616) (383,616)
Asset Retirement Obligation(4) (110,999) (89,725)
-------------------------------------------------------------------------
Net Asset Value $ 1,708,012 $ 1,942,110
Units Outstanding (000's) 152,973 152,973
NAV/Unit $ 11.17 $ 12.70
-------------------------------------------------------------------------

(1) Pengrowth's internal estimate
(2) Working capital excludes distributions payable
(3) Long-term debt plus long-term portion of note payable and contract
liabilities
(4) The Asset Retirement Obligation (ARO) is based on the same
methodology used to calculate the ARO on Pengrowth's year-end
financial statements, except that the future expected ARO costs were
inflated at 2% and discounted at 10% and well abandonment costs
included in the GLJ report were deducted.


Reserve Life Index (RLI)

Pengrowth's proved RLI decreased from 8.9 years to 8.6 years and the
proved plus probable RLI decreased to 10.4 years from 10.6 years in 2003.

Reserve Life Index 2004 2003 2002
-------------------------------------------------------------------------
Total Proved 8.6 8.9 10.0
Proved plus Probable
(Established reserves prior to 2003) 10.4 10.6 11.6


Development Activity

During 2004, Pengrowth spent $161.1 million on development and
optimization activities. The largest expenditures were in Judy Creek
($38.3 million), SOEP ($31.9 million), Monogram ($17.7 million), Weyburn
($5.4 million) and Squirrel ($5.3 million). Pengrowth does not typically
participate in exploration activities and in 2004 most of the capital spent on
development was directed towards arresting production declines and improving
recovery by infill drilling, rather than finding new reserves.
The following table provides further detail regarding Pengrowth's capital
expenditures by major property for 2004. Capital expenditures for 2003 are
also provided for purposes of comparison.

Capital Expenditures
Year Ended December 31 2004 2003
-------------------------------------------------------------------------
Total Total
($ millions) Development Capital Capital
Property Drilling Facilities Expenditures Expenditures
-------------------------------------------------------------------------
Judy Creek 35.2 3.1 38.3 21.5
SOEP 8.1 23.8 31.9 15.0
Monogram 12.4 5.3 17.7 0.1
Weyburn 3.5 1.9 5.4 8.7
Squirrel 4.8 0.5 5.3 0.4
Princess 4.2 0.3 4.5 -
Dunvegan 3.3 0.7 4.0 1.5
McLeod River 4.4 0.1 4.5 6.0
Swan Hills 2.9 1.0 3.9 1.1
Bodo 3.3 - 3.3 -
Oak 2.0 1.2 3.2 6.1
Weasel 2.6 0.3 2.9 0.2
Tilley 2.2 0.4 2.6 0.9
Laprise 2.4 0.1 2.5 1.3
Countess 0.2 2.2 2.4 -
Tangleflags 1.9 0.5 2.4 -
House Mountain 2.2 - 2.2 2.8
Tupper 1.1 0.9 2.0 1.8
Elm 1.5 0.1 1.6 2.4
Redeye 0.6 0.1 0.7 1.3
Cessford 0.1 0.2 0.3 7.2
Other 13.2 6.3 19.5 7.4
-------------------------------------------------------------------------
112.1 49.0 161.1 85.7
-------------------------------------------------------------------------

In Judy Creek, development activity in 2004 was largely focused within
the "A" Pool and included five horizontal solvent injection wells and five oil
producers. Drilling and related activities such as well workovers and
conversions resulted in the development of nine new solvent patterns and three
new waterflood patterns in 2004. Six of the new solvent patterns were
receiving solvent by year end with response expected during the first quarter
of 2005. The remaining patterns are scheduled to begin injection by mid 2005
with response expected one to three months later. These and earlier such
initiatives resulted in reclassifying 1.3 mmboe to proved producing reserves.
During 2004, significant upgrades were also completed on the produced water
injection system and the control systems of five compressor installations.
These proactive upgrades improve the integrity and operating efficiency of the
facilities and are expected to reduce maintenance costs and fuel consumption.
Most of the 2004 SOEP capital expenditures were directed towards the
development of the South Venture field and Thebaud compression. The South
Venture platform and topsides were successfully installed in late 2004 with
production from the first South Venture well (SV1) starting to flow to Thebaud
on December 7, 2004. A second South Venture well (SV2) was spudded in 2004 but
drilling was temporarily suspended during installation of the production
platform. The SV2 well reached total depth in early 2005. Significant capital
was also spent on the engineering and design of the compression facilities
that will be installed at Thebaud in 2006. In addition to the engineering and
design, purchase orders were placed for the 30,000 hp compression unit and the
materials needed for the fabrication of the platform and topsides. These items
are routinely ordered early to ensure they are available when required at the
fabrication yard in Korea.
In Monogram, a shallow gas infill drilling program was completed in 2004.
In total 154 wells were drilled with 149 wells on stream by year-end. The
infill program more than doubled Pengrowth's existing production of
approximately 7.5 mmcf per day and resulted in 11.2 bcf of reserves being
reclassified as proved producing.
In Weyburn, the majority of the capital was directed towards expansion
and optimization of the CO2 miscible flood. Twelve new miscible flood patterns
were developed in 2004, adding to the 32 from previous years. In addition,
there was ongoing development and optimization in existing enhanced oil
recovery and waterflood areas where a total of 24 horizontal infill/re- entry
wells were drilled. The success of the miscible flood and infill drilling
program resulted in average production of 23,400 barrels of oil per day (bopd)
during 2004 and an exit rate of 25,800 bopd, both exceeding budget
expectations.
In Squirrel capital spending was largely focused on optimizing the North
Pine waterflood project to maximize oil recovery. During 2004, five wells were
drilled into the pool and another was converted to injection. In addition, new
reserves encountered in uphole secondary zones are being exploited.

Acquisitions

In 2004, Pengrowth made a major acquisition in Western Canada, purchasing
oil and natural gas assets from a subsidiary of Murphy Oil Corporation. The
acquisition added almost 14,600 boepd of production for a purchase price of
$550.8 million and closed on May 31, 2004. The high quality, mostly operated
properties offer numerous development opportunities and complement Pengrowth's
existing property portfolio.
Pengrowth also acquired an additional 34.35% working interest in the
Pengrowth operated Kaybob Notikewin Gas Unit adding 1.8 mmboe of proved plus
probable reserves. The acquisition closed on August 12, 2004 and brought
Pengrowth's ownership in the Unit to 98.88%. The acquisition price was $20.0
million, before adjustments.

Total Future Net Revenue (Undiscounted)

GLJ January 1, 2005 forecast pricing:

Royalties Operating
Revenue $M $M Costs, $M
-------------------------------------------------------------------------
Proved Producing 5,525,488 976,057 1,897,231
Proved Developed Non-Producing 184,689 37,581 28,417
Proved Undeveloped 1,252,211 185,301 409,293
-------------------------------------------------------------------------
Total Proved 6,962,388 1,198,939 2,334,942
-------------------------------------------------------------------------
Total Probable 1,836,049 329,329 535,287
-------------------------------------------------------------------------
Proved plus Probable 8,798,437 1,528,268 2,870,229
-------------------------------------------------------------------------

Future Net
Revenue
Capital Abandon- Before
Development ment(*) Income
Costs, $M Costs, $M Tax, $M
-------------------------------------------------------------------------
Proved Producing 172,616 115,024 2,364,561
Proved Developed Non-Producing 6,603 2,455 109,632
Proved Undeveloped 193,240 6,299 458,079
-------------------------------------------------------------------------
Total Proved 372,458 123,778 2,932,271
-------------------------------------------------------------------------
Total Probable 55,590 11,574 904,268
-------------------------------------------------------------------------
Proved plus Probable 428,049 135,352 3,836,540
-------------------------------------------------------------------------

Constant Price at December 31, 2004:

Royalties Operating
Revenue $M $M Costs, $M
-------------------------------------------------------------------------
Proved Producing 5,572,368 1,002,442 1,599,656
Proved Developed Non-Producing 192,926 40,514 23,440
Proved Undeveloped 1,286,956 211,288 355,910
-------------------------------------------------------------------------
Total Proved 7,052,250 1,254,243 1,979,007
------------------------------------------------------------------------
Total Probable 1,717,629 329,584 363,928
------------------------------------------------------------------------
Proved plus Probable 8,769,879 1,583,828 2,342,934
------------------------------------------------------------------------

Future Net
Revenue
Capital Abandon- Before
Development ment(*) Income
Costs, $M Costs, $M Tax, $M
-------------------------------------------------------------------------
Proved Producing 162,543 87,368 2,720,359
Proved Developed Non-Producing 6,311 1,988 120,672
Proved Undeveloped 182,348 3,377 534,033
------------------------------------------------------------------------
Total Proved 351,202 92,733 3,375,064
------------------------------------------------------------------------
Total Probable 51,386 2,469 970,262
------------------------------------------------------------------------
Proved plus Probable 402,588 95,202 4,345,327
------------------------------------------------------------------------
(*) Downhole abandonment costs

The foregoing tables represent GLJ's estimates of future net revenue and
do not represent fair market value.

FINANCIAL UPDATE

In 2004, Pengrowth continued its policy of issuing new equity when
appropriate while maintaining a high distribution pay-out ratio to
unitholders. During the year, Pengrowth raised a total of $509.8 million in
new equity proceeds on a net basis, issuing a total of 29.1 million additional
trust units. On March 23, 2004 Pengrowth completed a public offering of
10.9 million trust units at $18.40 per unit to raise total gross proceeds of
$200.6 million, and net proceeds of $189.9 million and on December 30, 2004
Pengrowth completed a public offering of 16.0 million Class B trust units at
$18.70 per trust unit to raise total gross proceeds of $298.9 million, and net
proceeds of $283.3 million. During 2004, 0.9 million Class B trust units were
issued under the DRIP at an average price of $17.84 per trust unit, raising
additional equity of $16.4 million, and 1.3 million Class B trust units were
issued under the employee trust unit option and rights plans, at an average
price of $15.64 per trust unit, to raise an additional $20.3 million in new
equity. As a result non-Canadian resident ownership of Pengrowth was reduced
to 50.2% by year-end 2004.

Financial Resources and Liquidity

At year-end 2004, Pengrowth had a long-term debt-to-debt plus equity at
book value ratio of 0.2 and maintained $375 million in committed credit
facilities which were reduced by drawings of $106 million and by $23 million
in letters of credit outstanding at year-end. In addition, Pengrowth maintains
a $35 million demand operating line of credit. Pengrowth remains well
positioned to fund its 2005 development program and to take advantage of
acquisition opportunities as they arise.
Long-term debt at December 31, 2004 included fixed rate term debt
denominated in U.S. dollars and translated to Cdn $240.4 million. Due to the
improvement in the Canadian to U.S. dollar exchange rate, an unrealized gain
of Cdn $49.8 million has been recorded since the U.S. dollar denominated debt
was issued in April of 2003.
Pengrowth's long-term debt increased by $86.1 million in fiscal 2004 to
$345.4 million at the end of 2004. At December 31, 2004 Pengrowth also had a
$35 million non-interest bearing note payable to Emera Offshore Incorporated
("Emera") related to the purchase of the SOEP offshore facilities from Emera
on December 31, 2003. The terms of this note are provided in Note 8 to the
financial statements.
During the year Pengrowth incurred $325 million of new debt to fund the
acquisition of the Murphy Assets. Of this amount, $220 million was comprised
of an acquisition bridge facility with a one year term ending May 31, 2005
with the remaining $105 million drawn from a revolving credit facility with a
renewal date of May 30, 2005. A portion of the proceeds from the December 30,
2004 Class B trust unit offering was used to fully repay the drawing on the
bridge facility.

Financial Leverage and Coverage

2004 2003
-------------------------------------------------------------------------
Distributable cash to interest expense (times) 12 17
Long-term debt to Distributable cash (times) 1.0 0.8
Long-term debt-to-debt plus equity 19% 18%


Interest

Pengrowth's average long-term debt balances increased by approximately
58% in 2004 compared to 2003. As a result, interest expense increased by 65%
to $29.9 million in 2004 ($9.3 million in the fourth quarter) from
$18.2 million in 2003 ($3.8 million in the fourth quarter), reflecting a
higher average debt level and higher standby fees and debt amortization costs.
Standby fees related to the set-up of bridge financing utilized for the Murphy
acquisition amounted to $3.9 million (2003 - nil). Interest expense also
includes $0.3 million of fees related to the amortization of U.S. debt issue
costs (2003 - $0.2 million). Imputed interest on the note payable to Emera was
also recorded in the amount of $1.6 million (2003 - nil).
The average interest rate on Pengrowth's long-term debt outstanding at
December 31, 2004 is 4.59%. Approximately 70% of Pengrowth's outstanding debt
at December 31, 2004 incurs interest expense payable in U.S. dollars and
therefore remains subject to fluctuations in the exchange rate. The Note
Payable is non-interest bearing.

Foreign Currency Gains and Losses

Pengrowth recorded a net foreign exchange gain of $17.3 million in 2004,
compared to a net foreign exchange gain of $29.9 million in 2003. Included in
the 2004 net gain of $17.3 million is an $18.9 million unrealized foreign
exchange gain related to the U.S. dollar denominated debt. This gain arises as
a result of the increase in the Canadian to U.S. dollar exchange rate in 2004
from a rate of approximately $0.77 at December 31, 2003 to a rate of
approximately $0.83 at December 31, 2004. The balance, a foreign exchange loss
of $1.6 million relates mainly to U.S. dollar denominated natural gas sales
from SOEP. Pengrowth has hedged the exchange rate on a portion of these U.S.
dollar denominated gas sales. Revenues are recorded at the average exchange
rate for the production month in which they accrue, with payment being
received on or about the 25th of the following month. As a result of the
increase in the Canadian dollar relative to the U.S. dollar over the course of
the year, a foreign exchange loss was recorded to the extent that there was a
difference between the average exchange rate for the month of production and
the exchange rate at the date the payments were received on that portion of
production sales that remained unhedged. Pengrowth has arranged a significant
portion of its long-term debt in U.S. dollars as a natural hedge against a
stronger Canadian dollar, as the negative impact on oil and gas sales is
somewhat offset by a reduction in the U.S. dollar denominated interest cost.

Price Risk Management

Pengrowth uses forward and futures contracts to manage its exposure to
commodity price fluctuations. Commodity price hedges in place at December 31,
2004 are detailed in Note 17 to the Financial Statements. Pengrowth has not
entered into any additional contracts subsequent to year end.

General and Administrative

General and administrative expenses ("G&A") increased to $24.4 million
($1.24 per boe) from $16.0 million ($0.89 per boe) in 2003, including
$6.9 million in the fourth quarter of 2004 compared to $4.1 million in the
same quarter of 2003. Included in 2004 G&A is $2.3 million (2003 -
$0.2 million) in non-cash compensation expense related to trust unit options
and rights (see Note 2 and Note 10 to the Financial Statements for details).
Also included in 2004 G&A is $0.8 million for estimated reimbursement of G&A
expenses incurred by the Manager, pursuant to the Management Agreement.
Excluding the non-cash component of G&A, and the reimbursement of Manager
expenses, 2004 year to date G&A increased by $5.5 million over 2003 levels.
G&A costs increased due to a number of factors including the addition of
personnel and office space in conjunction with the purchase of the Murphy
Assets and costs incurred in conjunction with the restructuring of the Class A
and Class B trust units. Other ongoing factors contributing to a general
increase in G&A costs include increasing financial reporting, legal and
regulatory costs from the growth in our unitholder base, and increasing
regulatory requirements including preparing for compliance with Section 404 of
the Sarbanes Oxley Act when it becomes applicable.

Management Fees

Management fees paid to Pengrowth Management Limited ("the Manager")
increased to $12.9 million in 2004 from $10.2 million in 2003. The base fees
paid to the manager totaled $6.8 million and are calculated as a fixed
percentage of "net operating income" (oil and gas sales and other income, less
royalties, operating costs, solvent amortization and reclamation funding).
Although the fixed percentage rates at which base fees are calculated
decreased by 46.5% from an average rate of 2.66% to 1.42% under the new
Management Agreement effective July 1, 2003, there was an increase in total
management fees due to the higher level of net operating income in 2004.
Management fees for 2004 also include a performance fee of $6.1 million,
which combined with the base fee for the period is equivalent to the cap of
80% of total fees that would have been earned by the Manager for that period
pursuant to the old Management Agreement. The Manager earned the maximum
performance fee by meeting or exceeding the performance criteria for a rolling
three year average total return in excess of 8.0%. The Manager achieved a
three year average return exceeding 25% as at the end of 2004.

Related Party Transactions

Details of related party transactions incurred in 2004 and 2003 are
provided in Note 15 to the financial statements. These transactions include
the Management fees paid to the Manager, as discussed in the preceding
paragraphs. The Manager is controlled by James S. Kinnear, the Chairman,
President and Chief Executive Officer of Pengrowth Corporation. As discussed
above, the Management fees paid to the Manager are pursuant to a Management
Agreement which has been approved by the trust unitholders. Mr. Kinnear is not
entitled to receive any salary or bonus in his capacity as a director and
officer of Pengrowth Corporation.
Related party transactions in 2004 also include $841,457 (2003 -
$675,692) paid to a firm controlled by the Corporate Secretary of Pengrowth
Corporation, Charles V. Selby. These fees are paid in respect of legal and
advisory services provided by the Corporate Secretary.

Taxes

In determining its taxable income, Pengrowth Corporation deducts royalty
payments to unitholders, and historically, this has been sufficient to reduce
taxable income to nil. As a result of Pengrowth's distribution approach,
whereby approximately 10% of funds available for distribution are withheld to
repay debt or fund future capital expenditures, the Corporation could become
subject to taxation on a portion of its income within the Corporation at some
point in the future. However the Corporation believes there are sufficient tax
pools available in the Corporation at present to offset the expected level of
income to be retained.
Capital taxes of $4.6 million in 2004 (2003 - $1.8 million) include
Federal Large Corporations Tax (LCT) of $1.3 million (2003 - $0.6 million) and
Saskatchewan Capital Tax and Resource Surcharge of $3.2 million (2003 -
$1.2 million).

Distributions and Taxability of Distributions

Pengrowth generated $363.1 million of Distributable cash related to 2004
cash flow, compared to $313.4 million in 2003. This equates to 90% of funds
generated from operations, compared to 88% in 2003.
Pengrowth currently withholds approximately 10% of cash available for
distribution to repay debt and/or contribute to capital spending in the
future. The Board of Directors may decide to increase (or decrease) the amount
withheld in the future, depending on a number of factors, including future
commodity prices, capital expenditure requirements, and the availability of
debt and equity capital. Board discretion with respect to withholding is
subject to a maximum withholding amount of 20% of gross revenues, as approved
by unitholders at the 2003 Annual General Meeting.
Cash distributions are paid to unitholders on the 15th day of the second
month following the month of production. Pengrowth paid $2.59 per trust unit
as cash distributions during the 2004 calendar year. For Canadian tax purposes
55.32% of these distributions or $1.4328 per trust unit is taxable income to
unitholders for the 2004 tax year. The remaining 44.68% or $1.1572 per trust
unit is a tax deferred return of capital which will reduce the unitholder's
cost base of the trust unit for purposes of calculating a capital gain or loss
upon ultimate disposition of the trust units.
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. The following table provides a
reconciliation of Distributable cash for fiscal years 2004 and 2003.

2004 2003
-------------------------------------------------------------------------
Funds generated from operations $ 402,994 $ 356,414
Change in deferred injectants 746 (9,504)
Change in Remediation Trust Funds (917) (713)
Amortization of deferred charges (1,893) (204)
Gain (loss) on sale of marketable securities 248 (94)
-------------------------------------------------------------------------
Distributable cash before withholding 401,178 345,899
Cash withheld (38,117) (32,484)
-------------------------------------------------------------------------
Distributable cash 363,061 313,415
Less: Actual distributions paid or declared (363,001) (313,381)
-------------------------------------------------------------------------
Balance to be distributed $ 60 $ 34
-------------------------------------------------------------------------
Actual distributions paid or declared per unit $ 2.630 $ 2.680


At December 31, 2004, the trust had unused tax deductions of $7.66 per
trust unit (2003 - $10.27 per unit). At this time, Pengrowth anticipates that
approximately 70 - 75% 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.

Depletion and Depreciation

Depletion and depreciation of property, plant and equipment and other
assets is provided on the unit of production method based on total proved
reserves. The provision for depletion and depreciation increased 33% in 2004
to $247.3 million from $185.3 million in 2003 due to a larger depletable asset
base and a higher depletion rate (production as a percentage of total proved
reserves). On a unit of production basis, depletion increased 22% to $12.58
per boe in 2004 from $10.35 per boe in 2003. The increase in the per boe
depletion amount in 2004 reflects the acquisition of the Murphy properties.

Ceiling Test

Under Canadian GAAP, a ceiling test is applied to the carrying value of
the property, plant and equipment and other assets. The carrying value is
assessed to be recoverable when the sum of the undiscounted cash flows
expected from the production of proved reserves, the lower of cost and market
of unproved properties and the cost of major development projects exceeds the
carrying value. When the carrying value is not assessed to be recoverable, an
impairment loss is recognized to the extent that the carrying value of assets
exceeds the sum of the discounted cash flows expected from the production of
proved and probable reserves, the lower of cost and market of unproved
properties and the cost of major development projects. The cash flows are
estimated using expected future product prices and costs and are discounted
using a risk-free interest rate. There was a significant surplus in the
ceiling test at year end 2004.

Asset Retirement Obligations

In 2003, the CICA issued Section 3110, "Asset Retirement Obligations"
(ARO) which harmonizes Canadian GAAP requirements with the corresponding U.S.
GAAP requirements under SFAS 143. Under these standards, the fair value of a
liability for ARO must be recognized in the period in which it is incurred,
and a corresponding asset retirement cost is to be added to the carrying
amount of the related asset. The capitalized amount is depleted on the unit-
of-production method based on proved reserves. The liability amount is
increased each reporting period due to the passage of time and the amount of
accretion is expensed to income in the period. Actual costs incurred upon the
settlement of the ARO are charged against the ARO. The new Canadian standard
was effective for fiscal years beginning on or after January 1, 2004 with
earlier adoption encouraged. Pengrowth elected to adopt this standard in 2003.
The total future ARO were estimated by management based on Pengrowth's
working interest in wells and facilities, estimated costs to remediate,
reclaim and abandon the wells and facilities and the estimated timing of the
costs to be incurred in future periods. Pengrowth has estimated the net
present value of its total ARO to be $172 million as at December 31, 2004
(2003 - $103 million), based on a total future liability of $551 million (2003
- $352 million). These costs are expected to be incurred over 50 years with
the majority of the costs incurred between 2014 and 2037. Pengrowth's credit
adjusted risk free rate of eight percent and an inflation rate of 1.5 percent
were used to calculate the net present value of the ARO.

Remediation Trust Funds and Remediation and Abandonment Expenses

During 2004, Pengrowth contributed $1.5 million into trust funds
established to fund certain abandonment and reclamation costs associated with
Judy Creek, Swan Hills and SOEP. The balance in these remediation trust funds
was $8.3 million at December 31, 2004.
Pengrowth takes a proactive approach to managing our well abandonment and
site restoration obligations. We have an on-going program to abandon wells and
reclaim well and facility sites on the properties we operate. In 2004,
Pengrowth spent $ 4.4 million on abandonment and reclamation (2003 -
$3.2 million). Pengrowth expects to spend approximately $8.2 million per year,
prior to inflation, over the next ten years on remediation and abandonment
expenses at operated properties.

Future Tax Liability

As required by Canadian GAAP, Pengrowth recorded a future tax liability
upon acquisition of the Murphy Assets. The tax liability arises due to the
deficiency in tax pools of the Murphy Assets acquired offset in part by excess
tax pools (compared to book value) from past acquisitions. The future tax
liability represents the income taxes that would arise, based on the enacted
income tax rates, if the operating company's assets and liabilities were
disposed of or settled at book value. Because of the tax structure of the
Trust, Pengrowth does not expect to pay cash income taxes in the operating
companies in the foreseeable future.

Goodwill

In accordance with Canadian GAAP, Pengrowth was also required to record
goodwill of $170.6 million upon acquisition of the Murphy Assets. The goodwill
value was determined based on the excess of total consideration paid less the
net value assigned to other identifiable assets and liabilities, including the
future income tax liability. Details of the acquisition are provided in Note 5
of the financial statements.

Commitments and Contractual Obligations

2004 Contractual Obligations
($ thousands)
-------------------------------------------------------------------------
2005 2006 2007 2008
-------------------------------------------------------------------------

Long-Term Debt(1) - - - -

Interest Payments on
Long-Term Debt(2) 12,176 12,176 12,176 12,176

Note Payable 15,000 20,000 - -

Operating Leases
Office Rent 1,235 469 - -
Vehicle Leases 745 700 567 342
-------------------------------------------------------------------------
1,980 1,169 567 342

Purchase Obligations
Pipeline
transportation 41,475 41,281 40,192 33,420
Capital expenditures 36,900 34,800 6,600 -
CO2 purchases 5,976 5,236 4,418 4,254
-------------------------------------------------------------------------
84,351 81,317 51,210 37,674

Remediation trust
fund payments 250 250 250 250
-------------------------------------------------------------------------
113,757 114,912 64,203 50,442
-------------------------------------------------------------------------


($ thousands)
2009 thereafter Total
------------------------------------------------------------
Long-Term Debt(1) - 345,400 345,400

Interest Payments on
Long-Term Debt(2) 12,176 13,632 74,512

Note Payable - - 35,000

Operating Leases
Office Rent - - 1,704
Vehicle Leases 95 - 2,449
------------------------------------------------------------
95 - 4,153

Purchase Obligations
Pipeline
transportation 29,728 63,894 249,990
Capital expenditures - - 78,300
CO2 purchases 4,289 23,512 47,686
------------------------------------------------------------
34,017 87,407 375,976

Remediation trust
fund payments 250 - 1,250
------------------------------------------------------------
46,538 446,439 836,292
------------------------------------------------------------

(1) U.S. dollar denominated debt due as follows $150M on April 2010 &
$50M on April 2013, translated at the Dec 31, 2004 foreign exchange
rate of 1.2020 Cdn/U.S.

(2) Interest Payments on U.S. denominated debt, calculated based on
Dec 31, 2004 foreign exchange rate.

SUBSEQUENT EVENTS

On January 21, 2005, Pengrowth announced it had entered into an agreement
to purchase an additional 12.5% working interest in Swan Hills Unit No. 1 for
a purchase price of $90 million, before adjustments. The transaction, which is
subject to Rights of First Refusal, is effective October 1, 2004 and is
anticipated to close on February 28, 2005. The acquisition would increase
Pengrowth's working interest in the Swan Hills Unit No. 1 to 22.7%.
On February 17, 2005, Pengrowth announced an Arrangement Agreement (the
"Arrangement") with Crispin Energy Inc. ("Crispin") under which Pengrowth will
acquire all of the issued and outstanding shares of Crispin on the basis of
0.0725 Class B trust units of the Trust for each share held by Canadian
resident shareholders of Crispin and 0.0512 Class A trust units of the Trust
for each share held by non-Canadian resident shareholders of Crispin. The
Arrangement will require the approval of 66 2/3 percent of the votes cast by
shareholders and optionholders of Crispin voting as a single class, the
approval of the majority of shareholders excluding certain management
personnel and the approval of the Court of Queen's Bench of Alberta and
certain regulatory agencies. Completion of the Arrangement is expected to
close prior to the end of April 2005.

OUTLOOK

Unitholders of Pengrowth Energy Trust saw Pengrowth complete one of its
largest acquisitions with the purchase of the Murphy Assets in May 2004. The
Murphy Assets were funded through two equity issues allowing Pengrowth to
continue to maintain a prudent and flexible financial structure.
Pengrowth will strive to provide attractive long-term returns for
unitholders. Our business objectives include:

- Maintaining a balanced portfolio of oil and gas properties in our key
focus areas;
- Growing production and reserves through accretive acquisitions and low
risk development drilling;
- Farming out undeveloped land with higher risk exploration potential;
- Continuing to optimize costs and maximize netbacks;
- The selective disposition of oil and gas properties that do not meet
our return objectives;
- Operating our properties in a safe and prudent manner in order to
protect our employees, the public, the environment and our investment;
- Continuing to maintain a stable distribution policy while withholding
a portion of Distributable cash to fund future capital programs.

At this time, Pengrowth is forecasting average 2005 production of 55,000
to 57,000 boepd from our existing properties. This estimate incorporates
anticipated production additions from the Swan Hills acquisition, scheduled to
close on February 28, 2005, as well as our 2005 development program, offset by
the impact of expected production declines from normal operations. The above
estimate excludes the potential impact of any future acquisitions or
divestitures, including the acquisition of Crispin.
Total operating costs for 2005 are expected to increase to approximately
$200 million. This increase is due to the addition of a full-year of operating
expenses associated with the Murphy Assets, Pengrowth's increased working
interest in Swan Hills Unit No. 1 and the prospective addition of operating
expenses associated with the recently announced acquisition of Crispin.
Assuming Pengrowth's average production at the end of 2005 results largely as
forecast above, Pengrowth currently estimates 2005 per boe operating costs
between $9.61 and $9.96 per boe and combined G&A and Management fees of
approximately $1.81 per boe.
Budgeted capital expenditures for 2005 total approximately $171.0 million
for maintenance and development opportunities at existing properties.
Approximately one half of the expected 2005 expenditures are planned for the
SOEP and Judy Creek properties. The above estimate does not take into account
any incremental expenditures which may be incurred in association with the
recently announced acquisitions of Swan Hills and Crispin. Pengrowth currently
anticipates a successful completion of the acquisition on or before April 30,
2005.

------------------------------------------------------------------------
------------------------------------------------------------------------
CONFERENCE CALL

Pengrowth will hold a conference call beginning at 11:00 A.M. Eastern
Time (9:00 A.M. Mountain Time) on Tuesday, March 1, 2005 during which
Management will review Pengrowth's 2004 fourth quarter and full year
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 10-15 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 May 30, 2005. A telephone replay will be available through to
midnight Eastern Time on Thursday, March 3, 2005 by dialing
(877) 289-8525 or Toronto local (416) 640-1917 and entering passcode
number 21108177 followed by the pound key.
------------------------------------------------------------------------
------------------------------------------------------------------------


PENGROWTH CORPORATION
James S. Kinnear, President



SUPPLEMENTAL INFORMATION

Summary of Quarterly Results
----------------------------
The following table is a summary of Quarterly results for 2004 and 2003.
As this table illustrates, production and Distributable cash were impacted
positively by the acquisition of the Murphy Assets in the second quarter of
2004.
This table also shows the relatively high commodity prices sustained
throughout 2003 and 2004, which have had a positive impact on net income and
Distributable cash.
Production declines were offset by the acquisition of the Murphy Assets
in the second quarter of 2004, positively impacting net income. However, in
the fourth quarter of 2004, net income was negatively impacted by the
recognition of $15.6 million of future income tax expense representing an
increase in the future tax liability subsequent to the acquisition of the
Murphy Assets.

Summary of Quarterly Results
2004
($ thousands) Q1 Q2 Q3 Q4 Total
Oil and gas
sales $ 165,880 $ 193,637 $ 222,848 $ 218,835 $ 801,200
Net income $ 38,652 $ 32,684 $ 51,271 $ 31,138 $ 153,745
Net income
per unit $0.31 $0.24 $0.38 $0.23 $1.15
Net income
per unit -
diluted $0.31 $0.24 $0.38 $0.23 $1.15
Distributable
cash $ 83,606 $ 89,119 $ 93,870 $ 96,466 $ 363,061
Actual
distributions
paid or
declared
per unit $0.63 $0.64 $0.67 $0.69 $2.63
Daily production
(boe) 45,668 51,451 60,151 57,425 53,702
Total production
mboe (6:1) 4,156 4,682 5,534 5,283 19,655
Average price
per boe $ 39.91 $ 41.36 $ 40.27 $ 41.42 $ 40.76
Operating
netback
per boe $ 25.71 $ 25.71 $ 22.77 $ 24.31 $ 24.51


2003
Q1 Q2 Q3 Q4 Total
Oil and gas
sales $ 204,824 $ 169,238 $ 162,819 $ 154,139 $ 691,020
Net income $ 62,920 $ 54,214 $ 34,808 $ 37,355 $ 189,297
Net income
per unit $0.57 $0.49 $0.29 $0.31 $1.63
Net income
per unit -
diluted $0.57 $0.48 $0.29 $0.30 $1.63
Distributable
cash $ 97,221 $ 71,774 $ 72,951 $ 71,469 $ 313,415
Actual
distributions
paid or
declared
per unit $0.75 $0.67 $0.63 $0.63 $2.68
Daily production
(boe) 50,827 48,839 48,850 47,653 49,033
Total production
mboe (6:1) 4,574 4,444 4,494 4,384 17,896
Average price
per boe $ 44.78 $ 38.08 $ 36.22 $ 35.16 $ 38.61
Operating
netback
per boe $ 26.50 $ 21.11 $ 20.54 $ 20.43 $ 22.17


Selected Annual Information
Financial Results
($thousands)
2004 2003 2002
Oil and gas sales $ 801,200 $ 691,020 $ 482,301
Net income $ 153,745 $ 189,297 $ 56,955
Net income per unit $1.15 $1.63 $0.63
Distributable cash $ 363,061 $ 313,415 $ 194,458
Actual distributions paid or
declared per unit $2.63 $2.68 $2.07
Total assets $ 2,276,534 $ 1,673,718 $ 1,552,651
Long-term financial
liabilities(*) $ 383,616 $ 294,300 $ 316,501
Unitholders' equity $ 1,462,211 $ 1,159,433 $ 1,073,164
Number of units outstanding at
year-end (thousands) 152,973 123,874 110,562

(*) Long-term debt plus long-term portion of note payable and contract
liabilities.


Class A and Class B Trust Unit Reclassification

Generally speaking, the Income Tax Act (Canada) provides that a trust
will permanently lose its mutual fund trust status if it is established or
maintained primarily for the benefit of non-residents of Canada (which is
generally interpreted to mean that the majority of unitholders must not be non-
residents of Canada) (the "Benefit Test"), unless at all times after February
21, 1990, "all or substantially all" of the Trust's property consisted of
property other than taxable Canadian property (the "TCP Exception").
The Federal Budget tabled by the Minister of Finance on March 23, 2004
proposed several changes to Subsection 132(7) of the Tax Act to the effect
that the TCP Exception would generally no longer be available to royalty
trusts after December 31, 2004.
On April 22, 2004, Pengrowth Energy Trust sought and obtained the
approval of its unitholders for the reclassification of its trust units as
Class A trust units and Class B trust units (the "A/B Structure"). The purpose
of the A/B Structure was to enable Pengrowth Energy Trust to satisfy the
Benefit Test by providing a mechanism to ensure that the majority of trust
units, distributions, votes and entitlements to the capital of Pengrowth
Energy Trust would be held by residents of Canada. The A/B Structure was
implemented by Pengrowth Energy Trust on July 27, 2004, but the ownership
threshold has not yet been achieved. As of December 31, 2004, the outstanding
Class A trust units of Pengrowth Energy Trust represented approximately 50.20%
of the total outstanding trust units. The Trust Indenture of Pengrowth Energy
Trust currently stipulates that an ownership threshold of a maximum of 49.75%
represented by Class A trust units must be achieved by June 1, 2005. It is
anticipated that the ownership threshold will be achieved prior to June 1,
2005 due to the issuance of Class B trust units under the Arrangement with
Crispin and through the issuance of Class B trust units through the DRIP and
employee trust unit option and rights incentive plans.

2004 2003
--------------------
Class A trust units 50.20% 0.00%
Class B trust units 49.75% 0.00%
Trust units prior to reclassification 0.056% 100.00%

On November 26, 2004, Pengrowth Energy Trust received a customary form of
comfort letter from the Department of Finance (Canada) (the "November Finance
Letter") stating that the Department of Finance will recommend to the Minister
of Finance that an amendment be made to the TCP Exception that would clarify
Pengrowth Energy Trust's ability to rely upon that exception and would
effectively remove any significant risk regarding the status of Pengrowth
Energy Trust as a Mutual Fund Trust. The November Finance Letter is subject to
acceptance of the recommendations therein by the Minister of Finance and
Parliament, which Pengrowth Energy Trust believes is reasonable to assume will
occur.
On December 6, 2004, the Minister of Finance tabled a Notice of Ways and
Means Motion in the House of Commons to implement measures proposed in the
March 23, 2004 Federal Budget. However, the changes to the Mutual Fund Trust
provisions proposed in the March 23, 2004 Federal Budget to remove the TCP
Exception were not included. The Minister of Finance indicated that further
discussions would be pursued with the private sector concerning the
appropriate tax treatment of non-residents investing in resource property
through mutual funds. Therefore, uncertainty remains as to whether or not the
TCP Exception will be available to royalty trusts such as Pengrowth Energy
Trust indefinitely.
To the extent that Class A trust units in the future represent less than
the ownership threshold of 49.75%, conversions of Class B trust units to Class
A trust units will be permissible under the Trust Indenture. Pengrowth intends
to implement a new form of reservation system in order to provide all
unitholders with an equal and orderly opportunity to convert Class B trust
units into Class A trust units. All registered and beneficial unitholders will
have the opportunity to participate in the reservation system by providing an
appropriate form to Computershare Trust Company of Canada ("Computershare").
Computershare will, at a specified time, select unitholders from within the
reservation system using a random selection process that essentially provides
an equal opportunity to all unitholders within the system. Each selection will
entitle a unitholder to convert up to 1,000 Class B trust units into Class A
trust units on a one for one basis. Unitholders will remain in the reservation
system until they receive reservation numbers in respect of all of their Class
B trust units within the system or until the reservation expires in accordance
with its terms. It is anticipated that selections will occur monthly, but they
may occur more or less frequently as determined by the Board of Directors of
Pengrowth. At each periodic selection, the number of unitholders that will be
selected will be determined by the number of Class B trust units that may be
converted into Class A trust units without exceeding the ownership threshold.
Further details regarding the reservation system, including certain income tax
consequences of exercising the conversion option, will be provided
sufficiently in advance of the first selection process so that all interested
unitholders will have an equal opportunity to participate.

Trust Unit Information

Trust Unit Trading -
after re-class(*) Volume Value ($
High Low Close (000s) millions)
TSX - PGF.A (Cdn$)
2004 1st quarter
2nd quarter
3rd quarter $ 24.19 $ 19.10 $ 22.67 1,672 $ 35.5
4th quarter $ 26.33 $ 20.03 $ 24.93 2,607 $ 58.9
Year $ 26.33 $ 19.10 $ 24.93 4,279 $ 94.4
TSX - PGF.B (Cdn$)
2004 1st quarter
2nd quarter
3rd quarter $ 20.00 $ 18.03 $ 18.87 5,588 $ 105.6
4th quarter $ 20.04 $ 17.51 $ 18.50 16,007 $ 301.8
Year $ 20.04 $ 17.51 $ 18.50 21,595 $ 407.4
NYSE - PGH (U.S.$)
2004 1st quarter
2nd quarter
3rd quarter $ 18.94 $ 14.40 $ 17.93 21,200 $ 350.4
4th quarter $ 21.24 $ 15.85 $ 20.82 31,174 $ 574.7
Year $ 21.24 $ 14.40 $ 20.82 52,374 $ 925.1


Trust Unit Trading -
after re-class(*) Volume Value ($
High Low Close (000s) millions)
TSX -PGF.UN (Cdn$)
2004 1st quarter $ 21.25 $ 15.55 $ 17.98 30,620 $ 567.8
2nd quarter $ 19.15 $ 16.15 $ 18.67 18,145 $ 328.5
3rd quarter $ 19.75 $ 18.52 $ 19.42 3,554 $ 68.5
4th quarter
Year $ 21.25 $ 15.55 $ 19.42 52,319 $ 964.8

2003 1st quarter $ 15.90 $ 13.39 $ 14.25 20,122 $ 297.6
2nd quarter $ 18.22 $ 13.95 $ 17.25 32,575 $ 519.0
3rd quarter $ 17.87 $ 16.20 $ 17.25 20,476 $ 349.5
4th quarter $ 22.22 $ 16.75 $ 21.25 24,220 $ 451.6
Year $ 22.22 $ 13.39 $ 21.25 97,393 $1,617.7
NYSE - PGH (U.S.$)
2004 1st quarter $ 16.60 $ 12.10 $ 13.70 36,899 $ 525.6
2nd quarter $ 14.24 $ 11.62 $ 13.98 22,194 $ 295.9
3rd quarter $ 14.95 $ 13.84 $ 14.64 5,797 $ 84.5
4th quarter
Year $ 14.95 $ 11.62 $ 14.64 64,890 $ 906.0

2003 1st quarter $ 10.67 $ 9.07 $ 9.71 8,168 $ 80.8
2nd quarter 13.80 9.40 12.83 22,500 271.1
3rd quarter 13.13 11.55 12.81 18,614 230.2
4th quarter 17.00 12.50 16.40 24,721 340.8
Year $ 17.00 $ 9.07 $ 16.40 74,003 $ 922.9

(*) July 27, 2004, trust units were re-classified as Class A
or Class B units.

Class A trust units trade on the New York Stock Exchange (NYSE under PGH
and on the Toronto Stock Exchange (TSX) under PGF.A. Class B trust units trade
only on the TSX under PGF.B.



PENGROWTH ENERGY TRUST

UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2004



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


2004 2003
------------ ------------
(unaudited) (audited)
ASSETS
CURRENT ASSETS
Cash and term deposits $ - $ 64,154
Accounts receivable 104,228 65,570
Inventory 439 699
------------ ------------
104,667 130,423

REMEDIATION TRUST FUNDS (Note 4) 8,309 7,392

DEFERRED CHARGES (Note 11) 3,651 5,544

GOODWILL (Note 5) 170,619 -

PROPERTY, PLANT AND EQUIPMENT
AND OTHER ASSETS (Note 6) 1,989,288 1,530,359
------------ ------------

$ 2,276,534 $ 1,673,718
------------ ------------
------------ ------------

LIABILITIES AND UNITHOLDERS' EQUITY
CURRENT LIABILITIES
Bank indebtedness $ 4,214 $ -
Accounts payable and accrued liabilities 80,423 54,196
Distributions payable to unitholders 70,456 52,139
Due to Pengrowth Management Limited 7,325 1,122
Note payable (Note 8) 15,000 10,000
Current portion of contract liabilities
(Note 5) 5,795 -
------------ ------------
183,213 117,457

NOTE PAYABLE (Note 8) 20,000 35,000

CONTRACT LIABILITIES (Note 5) 18,216 -

LONG-TERM DEBT (Note 9) 345,400 259,300

ASSET RETIREMENT OBLIGATIONS (Note 7) 171,866 102,528

FUTURE INCOME TAXES (Note 14) 75,628 -

TRUST UNITHOLDERS' EQUITY
Trust Unitholders' capital (Note 10) 2,383,284 1,872,924
Contributed surplus (Note 10) 1,923 189
Accumulated earnings 727,057 573,312
Accumulated distributable cash (1,650,053) (1,286,992)
------------ ------------
1,462,211 1,159,433
------------ ------------

COMMITMENTS (Note 18)
SUBSEQUENT EVENTS (Note 19)
$ 2,276,534 $ 1,673,718
------------ ------------
------------ ------------

See accompanying notes to the unaudited consolidated financial
statements.



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

2004 2003
------------ ------------
(unaudited) (audited)
REVENUES
Oil and gas sales $ 801,200 $ 691,020
Processing and other income 12,390 9,726
Crown royalties, net of incentives (133,952) (108,325)
Freehold royalties and mineral taxes (11,848) (6,580)
------------ ------------
667,790 585,841
Interest and other income 1,770 840
------------ ------------
NET REVENUE 669,560 586,681

EXPENSES
Operating 159,742 149,032
Transportation 8,274 8,225
Amortization of injectants for miscible
floods 19,669 32,541
Interest 29,924 18,153
General and administrative 24,448 15,997
Management fee 12,874 10,181
Foreign exchange gain (Note 12) (17,300) (29,911)
Depletion and depreciation 247,332 185,270
Accretion (Note 7) 10,642 6,039
------------ ------------
495,605 395,527
------------ ------------

NET INCOME BEFORE TAXES 173,955 191,154

Income tax expense (Note 14)
Capital 4,594 1,857
Future 15,616 -
------------ ------------
20,210 1,857

NET INCOME $ 153,745 $ 189,297

Accumulated earnings, beginning of year 573,312 384,015
------------ ------------

ACCUMULATED EARNINGS, END OF PERIOD $ 727,057 $ 573,312
------------ ------------
------------ ------------

NET INCOME PER UNIT (Note 16) Basic $1.153 $1.633
------------ ------------
------------ ------------

Diluted $1.147 $1.625
------------ ------------
------------ ------------

See accompanying notes to the unaudited consolidated financial
statements.



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

2004 2003
------------ ------------
(unaudited) (audited)
CASH PROVIDED BY (USED FOR):

OPERATING
Net income $ 153,745 $ 189,297
Depletion, depreciation and accretion 257,974 191,309
Future income taxes 15,616 -
Contract liability amortization (4,164) -
Amortization of injectants 19,669 32,541
Purchase of injectants (20,415) (23,037)
Expenditures on remediation (4,440) (3,243)
Unrealized foreign exchange gain (Note 12) (18,900) (30,940)
Trust unit based compensation (Note 10) 2,264 189
Amortization of deferred charges (Note 11) 1,893 204
(Gain) loss on sale of marketable securities (248) 94
------------ ------------
Funds generated from operations 402,994 356,414

Changes in non-cash operating working
capital (Note 13) 1,173 (9,863)
------------ ------------
404,167 346,551
------------ ------------

FINANCING
Distributions (344,744) (306,591)
Change in long-term debt 105,000 (26,261)
Note payable (Note 8) (10,000) 41,393
Proceeds from issue of trust units 509,830 210,198
------------ ------------
260,086 (81,261)
------------ ------------

INVESTING
Expenditures on property acquisitions (572,980) (122,964)
Expenditures on property, plant and
equipment (161,141) (85,718)
Proceeds on property dispositions - 2,835
Deferred Charges - (2,141)
Change in Remediation Trust Fund (917) (713)
Purchase of marketable securities (2,680) -
Proceeds from sale of marketable securities 2,928 1,812
Change in non-cash investing working capital
(Note 13) 2,169 (2,539)
------------ ------------
(732,621) (209,428)
------------ ------------

INCREASE (DECREASE) IN CASH AND TERM DEPOSITS (68,368) 55,862

CASH AND TERM DEPOSITS AT BEGINNING OF YEAR 64,154 8,292

CASH AND TERM DEPOSITS
(BANK INDEBTEDNESS) AT END OF YEAR $ (4,214) $ 64,154
------------ ------------
------------ ------------

See accompanying notes to the unaudited consolidated financial
statements.



PENGROWTH ENERGY TRUST
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2004 AND 2003
(Tabular amounts are stated in thousands of dollars except
per unit amounts.)

1. STRUCTURE OF THE TRUST

Pengrowth Energy Trust ("EnergyTrust") is a closed-end investment
trust created under the laws of the Province of Alberta pursuant to a
Trust Indenture dated December 2, 1988 (as amended) between Pengrowth
Corporation ("Corporation") and Computershare Investor Services Inc.
("Computershare"). Operations commenced on December 30, 1988. The
beneficiaries of EnergyTrust are the holders of trust units (the
"unitholders").

EnergyTrust acquires and holds royalty units and notes issued by the
Corporation, which entitles EnergyTrust to the net income generated
by the Corporation and its subsidiaries' petroleum and natural gas
properties less certain charges, as defined in the Royalty Indenture.
In addition, unitholders are entitled to receive the net income from
other investments that are held directly by EnergyTrust. EnergyTrust
owns approximately 99.9 percent of the royalty units issued by the
Corporation.

Pengrowth Management Limited (the "Manager") is responsible for the
management of the business affairs of the Corporation and the
administration of EnergyTrust. The Manager owns 9 percent of the
common shares of Corporation, and the Manager is controlled by an
officer and a director of the Corporation. The remaining 91 percent
of the common shares of the Corporation are owned by EnergyTrust.

Under the terms of the Royalty Indenture, the Corporation is entitled
to retain a 1 percent share of royalty income and all miscellaneous
income (the "Residual Interest") to the extent this amount exceeds
the aggregate of debt service charges, general and administrative
expenses, and management fees. In 2004 and 2003, this Residual
Interest, as computed, did not result in any income retained by
Pengrowth Corporation.

2. SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation
EnergyTrust's consolidated financial statements have been prepared in
accordance with Generally Accepted Accounting Principles ("GAAP")in
Canada and they include the accounts of EnergyTrust, the Corporation
and its subsidiaries (collectively referred to as "Pengrowth"). All
inter-entity transactions have been eliminated. These financial
statements do not contain the accounts of the Manager.

EnergyTrust owns 91 percent of the shares of Corporation and, through
the royalty, obtains substantially all the economic benefits of
Corporation. In addition, the unitholders of EnergyTrust have the
right to elect the majority of the board of directors of Corporation.

Joint Interest Operations
A significant proportion of Pengrowth's petroleum and natural gas
development and production activities are conducted with others and
accordingly the accounts reflect only Pengrowth's proportionate
interest in such activities.

Property Plant and Equipment
Pengrowth follows the full cost method of accounting for oil and gas
properties and facilities whereby all costs of developing
and acquiring oil and gas properties are capitalized and depleted on
the unit of production method based on proved reserves before
royalties as estimated by independent engineers. The fair value of
future estimated asset retirement obligations associated with
properties and facilities are also capitalized and depleted on the
unit of production method. The associated asset retirement
obligations on future development capital costs are also included in
the cost base subject to depletion. Natural gas production and
reserves are converted to equivalent units of crude oil using their
relative energy content.

General and administrative costs are not capitalized other than to
the extent they are directly related to a successful acquisition, or
to the extent of Pengrowth's working interest in capital expenditure
programs to which overhead fees can be recovered from partners.
Overhead fees are not charged on 100 percent owned projects.

Proceeds from disposals of oil and gas properties and equipment are
credited against capitalized costs unless the disposal would alter
the rate of depletion and depreciation by more than 20 percent, in
which case a gain or loss on disposal is recorded.

Pengrowth places a limit on the carrying value of property, plant and
equipment and other assets, which may be depleted against revenues of
future periods (the "ceiling test"). The carrying value is assessed
to be recoverable when the sum of the undiscounted cash flows
expected from the production of proved reserves, the lower of cost
and market of unproved properties and the cost of major development
projects exceeds the carrying value. When the carrying value is not
assessed to be recoverable, an impairment loss is recognized to the
extent that the carrying value of assets exceeds the sum of the
discounted cash flows expected from the production of proved and
probable reserves, the lower of cost and market of unproved
properties and the cost of major development projects. The cash flows
are estimated using expected future product prices and costs and are
discounted using a risk-free interest rate. The carrying value of
property, plant and equipment and other assets subject to the ceiling
test includes asset retirement costs.

Repairs and maintenance costs are expensed as incurred.

Goodwill
Goodwill, which represents the excess of the total purchase price
over the estimated fair value of the net identifiable assets and
liabilities acquired, is not amortized but instead is assessed for
impairment annually or as events occur that could result in
impairment. Impairment is assessed by determining the fair value of
the reporting entity (consolidated EnergyTrust) and comparing this
fair value to the book value of the reporting entity. If the fair
value of the reporting entity is less than the book value, impairment
is measured by allocating the fair value of the reporting entity to
the identifiable assets and liabilities of the reporting entity as if
the reporting entity had been acquired in a business combination for
a purchase price equal to its fair value. The excess of the fair
value of the reporting entity over the assigned values of the
identifiable assets and liabilities is the fair value of the
goodwill. Any excess of the book value of goodwill over this implied
fair value is the impairment amount. Impairment is charged to
earnings in the period in which it occurs.

Goodwill is stated at cost less impairment.

Injectant Costs
Injectants (mostly ethane and methane) are used in miscible flood
programs to stimulate incremental oil recovery. The cost of
injectants purchased from third parties for miscible flood projects
is deferred and amortized over the period of expected future economic
benefit which is estimated as 24 to 30 months.

Inventory
Inventories of crude oil, natural gas and natural gas liquids are
stated at the lower of average cost and net realizable value.

Asset Retirement Obligations
Pengrowth recognizes the fair value of an Asset Retirement Obligation
("ARO") in the period in which it is incurred when a reasonable
estimate of the fair value can be made. The fair value of the
estimated ARO is recorded as a liability, with a corresponding
increase in the carrying amount of the related asset. The capitalized
amount is depleted on the unit of production method based on proved
reserves. The liability amount is increased each reporting period due
to the passage of time and the amount of accretion is expensed to
income in the period. Actual costs incurred upon the settlement of
the ARO are charged against the ARO.

Pengrowth has placed cash in segregated remediation trust accounts to
fund certain ARO for the Judy Creek and Swan Hills properties, and
the Sable Offshore Energy Project ("SOEP"). Contributions to these
remediation trust accounts and expenditures on ARO not funded by the
trust accounts are charged against actual cash distributions in the
period incurred.

Income Taxes
EnergyTrust is a taxable trust under the Canadian Income Tax Act. As
income taxes are the responsibility of the individual unitholders and
EnergyTrust distributes all of its taxable income to its unitholders,
no provision has been made for income taxes by EnergyTrust in these
financial statements.

The Corporation follows the tax liability method of accounting for
income taxes. Under this method, income tax liabilities and assets
are recognized for the estimated tax consequences attributable to
differences between the amounts reported in the financial statements
of the Corporation and its subsidiaries and their respective tax
bases, using enacted income tax rates. The effect of a change in
income tax rates on future income tax liabilities and assets is
recognized in income in the period that the change occurs.

Trust Unit Compensation Plans
Pengrowth has unit based compensation plans, which are described in
Note 10. Compensation expense associated with unit based compensation
plans is recognized in income over the vesting period of the plan
with a corresponding increase in contributed surplus. The amount of
compensation expense and contributed surplus is reduced for options
and rights that are cancelled prior to vesting. Any consideration
received upon the exercise of the unit based compensation together
with the amount of non-cash compensation expense recognized in
contributed surplus is recorded as an increase in trust unitholders'
capital. Compensation expense is based on the fair value of the unit
based compensation at the date of grant using a modified Black-
Scholes option pricing model.

Pengrowth does not have any outstanding unit compensation plans that
call for settlement in cash or other assets. Grants of such items, if
any, will be recorded as expenses and liabilities based on the
intrinsic value.

Risk Management
Financial instruments are utilized by Pengrowth to manage its
exposure to commodity price fluctuations, foreign currency and
interest rate exposures. Pengrowth's practice is not to utilize
financial instruments for trading or speculative purposes.

Pengrowth formally documents relationships between hedging
instruments and hedged items, as well as its risk management
objective and strategy for undertaking various hedge transactions.
This process includes linking derivatives to specific assets and
liabilities on the balance sheet or to specific firm commitments or
forecasted transactions. Pengrowth also formally assesses, both at
the hedge's inception and on an ongoing basis, whether the
derivatives that are used in hedging transactions are highly
effective in offsetting changes in fair value or cash flows of hedged
items.

Pengrowth uses forward, futures and swap contracts to manage its
exposure to commodity price fluctuations. The net receipts or
payments arising from these contracts are recognized in income as a
component of oil and gas sales during the same period as the
corresponding hedged position.

Foreign exchange gains and losses on foreign currency exchange swaps
used to hedge U.S. dollar denominated gas sales are recognized in
income as a component of natural gas sales during the same period as
the corresponding hedged position.

Interest rate swap agreements are used as part of Pengrowth's program
to manage the fixed and floating interest rate mix of Pengrowth's
total debt portfolio and related overall cost of borrowing. The
interest rate swap agreements involve the periodic exchange of
payments without the exchange of the notional principal amount upon
which the payments are based, and are recorded as an adjustment of
interest expense on the hedged debt instrument.

Measurement Uncertainty
The preparation of financial statements in conformity with Canadian
GAAP requires management to make estimates and assumptions that
affect the reported amounts of assets and liabilities at the date of
the financial statements and revenues and expenses for the period
then ended.

The amounts recorded for depletion, depreciation, amortization of
injectants and the ARO are based on estimates. The ceiling test
calculation is based on estimates of proved reserves, production
rates, oil and natural gas prices, future costs and other relevant
assumptions. By their nature, these estimates are subject to
measurement uncertainty and may impact the consolidated financial
statements of future periods.

Earnings per unit
In calculating diluted net income per unit, Pengrowth follows the
treasury stock method to determine the dilutive effect of trust unit
options and other dilutive instruments. Under the treasury stock
method, only "in the money" dilutive instruments impact the diluted
calculations.

Cash and term deposits
Pengrowth considers term deposits with an original maturity of three
months or less to be cash equivalents.

Revenue recognition
Revenue from the sale of oil and natural gas is recognized when the
product is delivered. Revenue from processing and other miscellaneous
sources is recognized upon completion of the relevant service.

Comparative figures
Certain comparative figures have been reclassified to conform to the
presentation adopted in the current year.

3. CHANGES IN ACCOUNTING POLICIES

Full Cost Accounting Guideline
Effective January 1, 2003, Pengrowth adopted a new Canadian
accounting standard relating to full cost accounting for oil and gas
entities, as outlined in Note 2. Prior to adopting the new standard,
the limit on the aggregate carrying value of the property, plant and
equipment and other assets that may be carried forward for depletion
against future revenues was based on the sum of the undiscounted cash
flows expected from the production of proved reserves, the lower of
cost or market of unproved reserves and the cost of major development
projects less the estimated future costs for administration,
financing, ARO and income taxes.

Asset Retirement Obligations
Effective January 1, 2002, Pengrowth retroactively adopted, with
restatement of prior periods, a new accounting standard relating to
ARO, as outlined in Note 2. Prior to adopting the standard, Pengrowth
recognized a provision for future site restoration costs over the
life of the oil and gas properties and facilities using a unit of
production method.

Trust Unit Based Compensation Plan
Effective January 1, 2003, Pengrowth prospectively adopted amendments
to a Canadian accounting standard relating to recognizing the
compensation expense associated with unit based compensation plans,
as outlined in Note 2. Under the amended standards, Pengrowth must
recognize compensation expense based on the fair value of the trust
unit options and rights granted under Pengrowth's unit based
compensation plans. Pengrowth uses a modified Black-Scholes option
pricing model to determine the fair value of trust unit based
compensation plans at the date of grant. For trust unit options and
rights granted in 2002, Pengrowth elected not to recognize
compensation expense but provide pro forma disclosure as if the
amended accounting standards were adopted retroactively.

4. REMEDIATION TRUST FUNDS

Pengrowth is required to make contributions to a remediation trust
fund that is used to cover certain ARO of the Judy Creek properties.
Pengrowth makes monthly contributions to the fund of $0.10 per boe of
production from the Judy Creek properties and an annual lump sum
contribution of $250,000.

Every five years Pengrowth must evaluate the assets in the trust fund
and the outstanding ARO, and make recommendations to the former owner
of the Judy Creek properties as to whether contribution levels should
be changed. In 2004 an evaluation was completed with the results of
the evaluation determining that current funding levels would remain
unchanged until the next evaluation in 2007. Pengrowth may be
required to increase contributions to the Judy Creek remediation
trust fund based on future evaluations of the fund.

Pengrowth is required, pursuant to various agreements with the SOEP
partners, to make contributions to a remediation trust fund that will
be used to fund the ARO of the SOEP properties and facilities.
Pengrowth makes monthly contributions to the fund of $0.04 per mcf of
natural gas production and $0.08 per boe of natural gas liquids
production from SOEP.

The following summarizes Pengrowth's trust fund contributions for
2004 and 2003 and Pengrowth's expenditures on ARO not covered by the
trust funds:

2004 2003
---------------------------------------------------------------------
Contributions to Judy Creek Remediation
Trust Fund $ 906 $ 910
Contributions to Sable Environmental
Restoration Fund 548 181
Expenditures related to Judy Creek
Remediation Trust Fund (537) (378)
---------------------------------------------------------------------
917 713
---------------------------------------------------------------------

Expenditures on ARO not covered by the
trust funds 3,903 2,865
Expenditures on ARO covered by the trust
funds 537 378
---------------------------------------------------------------------
4,440 3,243
---------------------------------------------------------------------

Total trust fund contributions and ARO
expenditures not covered by the trust funds $ 5,357 $ 3,956
---------------------------------------------------------------------
---------------------------------------------------------------------

5. ACQUISITIONS

Corporate Acquisition
On May 31, 2004, Pengrowth acquired all of the issued and outstanding
shares of a company which had interests in oil and natural gas assets
in Alberta and Saskatchewan (the "Murphy Assets"). The transaction
was accounted for using the purchase method of accounting with the
allocation of the purchase price and consideration paid as follows:

Allocation of purchase price:
Working capital $ 9,310
Property, plant, and equipment 502,924
Goodwill (with no tax base) 170,619
Asset retirement obligations (43,876)
Future income taxes (60,012)
Contract liabilities (28,175)
--------------------------------------------------------------------
$ 550,790
--------------------------------------------------------------------
--------------------------------------------------------------------
Cost of acquisition:
Cash and term deposits $ 224,700
Acquisition facility 325,000
Acquisition costs 1,090
--------------------------------------------------------------------
$ 550,790
--------------------------------------------------------------------
--------------------------------------------------------------------

Property, plant and equipment of $503 million represents the fair
value of the assets acquired determined in part by an independent
reserve evaluation, net of purchase price adjustments. Goodwill of
$171 million was determined based on the excess of the total
consideration paid 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 the enacted
income tax rate of approximately 34 percent as at May 31, 2004.

Contract liabilities include a natural gas fixed price sales contract
(see Note 17) and firm pipeline demand charge contracts. The fair
value of these liabilities has been determined on the date of
acquisition and a liability of $21,824,000 has been recorded for the
natural gas fixed price sales contract and $6,351,000 has been
recorded for the firm pipeline demand charge contracts. The
liabilities will be reduced as the contracts are settled.

Results from operations of the acquired Murphy Assets subsequent
to May 31, 2004 are included in the consolidated financial
statements.

The following unaudited pro forma information provides an indication
of what Pengrowth's results of operations might have been had the
acquisition of the Murphy Assets taken place on January 1 of each of
the following years:

2004 2003
(unaudited) (unaudited)
---------------------------------------------------------------------
Oil and gas sales $ 882,846 $ 899,770
Net income $ 180,101 $ 236,500
Net income per unit:
Basic $ 1.206 $ 1.793
Diluted $ 1.201 $ 1.785

Property Acquisitions
In August 2004, Pengrowth acquired an additional 34.35 percent
working interest in Kaybob Notikewin Unit No.1 for a purchase price
of $20.0 million before adjustments. The acquisition increased
Pengrowth's working interest in the Kaybob Notikewin Unit No.1 to
approximately 99 percent.

In December 2003, Pengrowth acquired an 8.4 percent working interest
in the SOEP offshore production platforms and associated sub-sea
field gathering lines from Emera Offshore Incorporated ("Emera") for
$65 million. The consideration for this acquisition included cash of
$20 million and a $45 million note payable over three years (see
Note 8).

In conjunction with the December 2003 acquisition, Pengrowth
exchanged its royalty interest in SOEP for a direct working interest
in SOEP.

In May 2003, Pengrowth acquired an 8.4 percent working interest in
the SOEP processing facilities, downstream of the Thebaud central
processing platform, for approximately $57 million.

In June 2003, Pengrowth acquired interests in eleven significant
discovery licenses from Nova Scotia Resources (Ventures) Limited
("NSRVL") for $4.5 million plus a ten percent Net Profits Interest to
NSRVL.

6. PROPERTY, PLANT AND EQUIPMENT AND OTHER ASSETS

2004 2003
---------------------------------------------------------------------
Property, Plant and Equipment
Property, Plant and Equipment, at cost $ 2,986,681 $ 2,281,166
Accumulated depletion and depreciation (1,022,435) (775,103)
---------------------------------------------------------------------
Net book value of property, plant and
equipment 1,964,246 1,506,063
Other Assets
Deferred injectant costs 25,042 24,296
---------------------------------------------------------------------
Net book value of property, plant and
equipment and other assets $ 1,989,288 $ 1,530,359
---------------------------------------------------------------------
---------------------------------------------------------------------

Property, plant and equipment includes $81.1 million
(2003 - $69.5 million) related to ARO, net of accumulated depletion.

Pengrowth performed a ceiling test calculation at December 31, 2004
to assess the recoverable value of the property, plant and equipment
and other assets. The oil and gas future prices are based on the
January 1, 2005 commodity price forecast of our independent reserve
evaluators. These prices have been adjusted for commodity price
differentials specific to Pengrowth. The following table summarizes
the benchmark prices used in the ceiling test calculation. Based on
these assumptions, the undiscounted value of future net revenues from
Pengrowth's proved reserves exceeded the carrying value of property,
plant and equipment and other assets at December 31, 2004.


Foreign Edmonton Light
WTI Oil Exchange Crude Oil AECO Gas
Year ($U.S./bbl) Rate ($Cdn/bbl) ($Cdn/mmbtu)
--------------------------------------------------------------------
2005 42.00 0.82 50.25 6.60
2006 40.00 0.82 47.75 6.35
2007 38.00 0.82 45.50 6.15
2008 36.00 0.82 43.25 6.00
2009 34.00 0.82 40.75 6.00
2010-2015 33.50 0.82 40.08 6.10
---------------------------------------------------------------------
Escalate 2.0% 2.0% 2.0%
thereafter per year per year per year

7. ASSET RETIREMENT OBLIGATIONS

The total future ARO were estimated by management based on
Pengrowth's working interest in wells and facilities, estimated costs
to remediate, reclaim and abandon the wells and facilities and the
estimated timing of the costs to be incurred in future periods.
Pengrowth has estimated the net present value of its total ARO to be
$172 million as at December 31, 2004 (2003 - $103 million), based on
a total future liability of $551 million (2003 - $352 million). These
costs are expected to be made over 50 years with the majority of the
costs incurred between 2014 and 2037. Pengrowth's credit adjusted
risk free rate of 8 percent (2003 - 8 percent) and an inflation rate
of 1.5 percent (2003 - 1.5 percent) were used to calculate the net
present value of the ARO.

The following reconciles Pengrowth's ARO:

2004 2003
---------------------------------------------------------------------
Asset retirement obligations, beginning
of year $ 102,528 $ 73,493
Increase in liabilities during the year
related to:
Acquisitions 44,368 9,865
Additions 2,681 1,221
Revisions 16,087 15,153
Accretion expense 10,642 6,039
Liabilities settled during the year (4,440) (3,243)
---------------------------------------------------------------------
Asset retirement obligations, end of year $ 171,866 $ 102,528
---------------------------------------------------------------------
---------------------------------------------------------------------

8. NOTE PAYABLE

The note payable is due to Emera, in respect of the acquisition of
the SOEP facility (Note 5). The note payable is secured by
Pengrowth's working interest in SOEP. The note payable is
non-interest bearing with payments due as follows: $15 million on
December 29, 2005, and $20 million on December 31, 2006.

At December 31, 2004, $2.0 million has been recorded as a deferred
charge representing the imputed interest on the non-interest bearing
note. This amount will be recognized as interest expense over the
period outstanding for each individual instalment.

9. LONG-TERM DEBT

2004 2003
---------------------------------------------------------------------
U.S. dollar denominated debt:
U.S. $150 million senior unsecured notes
at 4.93 percent due April 2010 $ 180,300 $ 194,475
U.S. $50 million senior unsecured notes
at 5.47 percent due April 2013 60,100 64,825
---------------------------------------------------------------------
240,400 259,300
Canadian dollar revolving credit borrowings 105,000 -
---------------------------------------------------------------------
$ 345,400 $ 259,300
---------------------------------------------------------------------
---------------------------------------------------------------------

On April 23, 2003, Pengrowth closed a U.S. $200 million private
placement of senior unsecured notes to a group of U.S. investors. The
notes were offered in two tranches of U.S. $150 million at
4.93 percent due April 2010 and U.S. $50 million at 5.47 percent due
in April 2013. The notes contain certain financial maintenance
covenants and interest is paid semi-annually. Costs incurred in
connection with issuing the notes, in the amount of $2,141,000, are
being amortized straight line over the term of the notes (see
Note 11).

The Corporation has 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 $23 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 will revolve until May 30, 2005,
whereupon it may be renewed for a further 364 days, subject to
satisfactory review by the lenders, or converted into a term
facility. One third of the amount outstanding would be repaid in
equal quarterly instalments in each of the first two years with the
final one third to be repaid upon maturity of the term 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 one year following
the date of non-renewal.

10. TRUST UNITS

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

2004 2003
---------------------------------------------------------------------
Number Number
Trust Units Issued of units Amount of units Amount
---------------------------------------------------------------------
Balance, beginning
of year 123,873,651 $ 1,872,924 110,562,327 $ 1,662,726

Issued for cash 10,900,000 200,560 8,500,000 144,075

Less: issue
expenses - (10,710) - (7,820)

Issued for cash on
exercise of trust
units options and
rights 547,974 8,735 3,358,442 51,701

Issued for cash
under Distribution
Reinvestment Plan
("DRIP") 543,888 9,636 1,452,882 22,242

Trust unit rights
incentive plan
(non-cash exercised) - 259 - -

Royalty units
exchanged for trust
units 700 - - -
---------------------------------------------------------------------
Balance, prior
to conversion 135,866,213 $ 2,081,404 123,873,651 $ 1,872,924

Converted to
Class A or
Class B trust
units (135,792,888) (2,080,281) - -
---------------------------------------------------------------------
Balance, end of
year 73,325 $ 1,123 123,873,651 $ 1,872,924
---------------------------------------------------------------------



Class A Trust Units Class B Trust Units
---------------------------------------------------------------------
For the period from
July 27, 2004 to
December 31, 2004
---------------------------------------------------------------------
Number Number
Trust Units Issued of units Amount of units Amount
---------------------------------------------------------------------
Balance, beginning
of period - $ - - $ -

Trust units
converted 76,792,759 1,176,427 59,000,129 903,854

Issued for cash - - 15,985,000 298,920

Less: issue
expenses - - - (15,577)

Issued for cash on
exercise of trust
units options and
rights - - 746,864 11,516

Issued for cash
under Distribution
Reinvestment Plan
("DRIP") - - 374,478 6,750

Trust unit rights
incentive plan
(non-cash exercised) - - - 271
---------------------------------------------------------------------
Balance, end of
period 76,792,759 $ 1,176,427 76,106,471 $ 1,205,734
---------------------------------------------------------------------

On July 27, 2004 Pengrowth implemented a reclassification of its
trust units whereby the existing outstanding trust units were
reclassified into Class A or Class B trust units depending on the
residency of the unitholder. Of the original trust units, 73,325 are
undeclared trust units that have not been classified as Class A or
Class B trust units as the unitholders of these trust units have not
submitted a declaration of residency certificate.

The Class A trust units and the Class B trust units have the same
rights to vote, obtain distributions upon wind-up or dissolution of
EnergyTrust. The most significant distinction between the two classes
of units is in respect of residency of the persons entitled to hold
and trade the Class A trust units and Class B trust units.

Class A trust units are not subject to any residency restriction but
are subject to a restriction on the number to be issued such that the
total number of issued and outstanding Class A trust units will not
exceed 99 percent of the number of issued and outstanding Class B
trustunits after an initial implementation period (the "Ownership
Threshold"). Class A trust units may be converted by a holder at any
time into Class B trust units provided that the holder is a resident
of Canada and provides a suitable residency declaration. Class A
trust units trade on both the Toronto Stock Exchange ("TSX") and the
New York Stock Exchange ("NYSE").

Class B trust units may not be held by non-residents of Canada and
trade only on the TSX. Class B trust units may be converted by a
holder into Class A trust units, provided that the Ownership
Threshold will not be exceeded.

If the number of issued and outstanding Class A trust units exceeds
the Ownership Threshold, EnergyTrust may make a public announcement
of the contravention and enforce one or several available options to
reduce the number of Class A trust units to the Ownership Threshold,
as outlined in the Trust Indenture.

If it appears from the securities registers, or if the Board of
Directors of Corporation determines that, a person that is a
non-resident of Canada holds or beneficially owns any Class B trust
units, Pengrowth shall send a notice to the registered holder(s) of
the Class B trust units requiring such holder(s) to dispose of the
Class B trust units and pending such disposition may suspend all
rights of ownership attached to such units, including the rights to
receive distributions.

Following the reclassification, the number of outstanding Class A
trust units exceeded the Ownership Threshold. The Trust Indenture
provides that the provisions of the Ownership Threshold will not
apply until December 31, 2004 or such later date by which Pengrowth
must comply with the Ownership Threshold as may be specified in the
Advance Tax Ruling; however, if the Board of Directors of Pengrowth
Corporation determines that the number of outstanding Class A trust
units on or after that date is likely to exceed the Ownership
Threshold, Pengrowth Corporation may enforce any or all of the
available provisions. On December 1, 2004, Pengrowth received a
letter from the Canada Revenue Agency that amended the Advance Tax
Ruling to extend the date by which Pengrowth must comply with the
Ownership Threshold in order to be able to rely on the ruling from
December 31, 2004 to June 1, 2005. The number of Class A trust units
exceeded the Ownership Threshold by 0.45 percent on
December 31, 2004.

Certain provisions exist that could prevent exclusionary offers being
made for only one class of trust units in existence at the time of
the original offer. In the event that an offer is made for only one
class of trust units, in certain circumstances, the Ownership
Threshold would temporarily cease to apply.

Pursuant to the terms of the Royalty Indenture and the Trust
Indenture, there is attached to each royalty unit granted by the
Corporation, to royalty unitholders other than EnergyTrust, the right
to exchange such royalty units for an equivalent number of trust
units. Accordingly Computershare, as Trustee, has reserved 18,240
trust units for such future conversion.

Distribution Reinvestment Plan
Class B unitholders are eligible to participate in the DRIP. DRIP
entitles the unitholder to reinvest cash distributions in additional
units of EnergyTrust. The trust units under the plan are issued from
treasury at a 5 percent discount to the weighted average closing
price of all Class B trust units traded on the TSX for the 20 trading
days preceding a distribution payment date. Class A unitholders are
not eligible to participate in DRIP. Trust units issued on the
exercise of options and rights under Pengrowth's unit based
compensation plans are Class B trust units.

Contributed Surplus

2004 2003
---------------------------------------------------------------------
Balance, beginning of year $ 189 $ -

Trust unit rights incentive plan
(non-cash expensed) 2,264 189

Trust unit rights incentive plan
(non-cash exercised) (530) -
---------------------------------------------------------------------
Balance, end of year $ 1,923 $ 189
---------------------------------------------------------------------
---------------------------------------------------------------------

Trust Unit Option Plan
Pengrowth has a trust unit option plan under which directors,
officers, employees and special consultants of the Corporation and
the Manager are eligible to receive options to purchase Class B trust
units. Under the terms of the plan, up to 10 percent of the issued
and outstanding trust units to a maximum of 10 million trust units
may be reserved for option and right grants. The options expire seven
years from the date of grant. One third of the options vest on the
grant date, one third on the first anniversary of the date of grant,
and the remaining third on the second anniversary.

As at December 31, 2004, options to purchase 845,374 Class B trust
units were outstanding (2003 - 2,014,903) that expire at various
dates to June 28, 2009.

2004 2003

Trust Unit Options Number Weighted Number Weighted
of options Average of options Average
Exercise Exercise
price price
---------------------------------------------------------------------
Outstanding at
beginning of year 2,014,903 $17.47 4,451,131 $16.78

Exercised (838,789) $16.82 (2,374,182) $16.19

Expired (325,200) $20.44 - $ -

Cancelled (5,540) $16.53 (62,046) $17.17
---------------------------------------------------------------------
Outstanding at
year-end 845,374 $16.97 2,014,903 $17.47

Exercisable at
year-end 845,374 $16.97 1,999,436 $17.48
---------------------------------------------------------------------


The following table summarizes information about trust unit options
outstanding and exercisable at December 31, 2004:

Options Outstanding and Exercisable
--------------------------------------------------------------------
Number Weighted-
Outstanding Average Weighted-
Range of and Remaining Average
Exercise Exercisable Contractual Exercise
Prices at Life(years) Price
--------------------------------------------------------------------
$12.00 to $14.99 150,105 3.6 $13.05
$15.00 to $16.99 130,244 3.7 $15.04
$17.00 to $17.99 207,782 3.5 $17.48
$18.00 to $20.50 357,243 2.9 $19.02
---------------------------------------------------------------------
$12.00 to $20.50 845,374 3.3 $16.97


Employee Trust Unit Rights Incentive Plan
Pengrowth has an Employee Trust Unit Rights Incentive Plan ("Rights
Incentive Plan"), pursuant to which rights to acquire Class B trust
units may be granted to the directors, officers, employees, and
special consultants of the Corporation and the Manager. Under the
Rights Incentive Plan, distributions per trust unit to trust
unitholders in a calendar quarter which represent a return of more
than 2.5 percent of the net book value of property, plant and
equipment at the beginning of such calendar quarter result in a
reduction in the exercise price. Total price reductions calculated
for 2004 were $1.30 per trust unit right (2003 - $1.47 per trust unit
right). One third of the rights granted under the Rights Incentive
Plan vest on the grant date, one third on the first anniversary date
of the grant and the remaining on the second anniversary. The rights
have an expiry date of five years from the date of grant.

As at December 31, 2004, rights to purchase 2,011,451 Class B trust
units were outstanding (2003 - 1,112,140) that expire at various
dates to October 28, 2009.

2004 2003

Rights Incentive Number Weighted Number Weighted
Options of rights Average of rights Average
Exercise Exercise
price price
---------------------------------------------------------------------
Outstanding at
beginning of year 1,112,140 $12.20 1,964,100 $13.29

Granted(1) 1,409,856 $17.35 165,000 $16.35

Exercised (456,049) $13.47 (984,260) $13.49

Cancelled (54,496) $14.19 (32,700) $12.75
---------------------------------------------------------------------
Outstanding at
year-end 2,011,451 $14.23 1,112,140 $12.20

Exercisable at
year-end 1,037,078 $12.48 359,740 $11.92
---------------------------------------------------------------------
(1) Weighted average exercise price of rights granted are based on
the exercise price at the date of grant.

The following table summarizes information about rights incentive
options outstanding and exercisable at December 31, 2004:

Rights
Outstanding Rights Exercisable
-----------------------------------------------------
Number Weighted- Weighted- Number Weighted-
Outstanding Average Average Exercisable Average
Range of At Remaining Exercise At Exercise
Exercise 12/31/04 Contractual Price 12/31/04 Price
Prices Life(years)
-----------------------------------------------------
$10.00 to $11.99 685,500 2.9 $10.46 685,500 $10.46
$12.00 to $13.99 32,900 3.3 $13.08 2,867 $12.73
$14.00 to $15.99 994,773 4.1 $15.50 249,285 $15.51
$17.00 to $18.99 298,278 4.6 $18.78 99,426 $18.78
---------------------------------------------------------------------
$10.00 to $18.99 2,011,451 3.7 $14.23 1,037,078 $12.48


Fair Value of Unit Based Compensation
Pengrowth records compensation expense on rights incentive options
granted on or after January 1, 2003. For trust unit options and
rights granted in 2002, Pengrowth has elected to disclose the pro
forma effect on net income had compensation expense been recorded
using the fair value method. The following is the pro forma effect on
net income:

2004 2003
---------------------------------------------------------------------

Net income $ 153,745 $ 189,297
Compensation expense related to trust unit
options granted in 2002 - (367)
Compensation expense related to rights
incentive options granted in 2002 (1,067) (1,279)
---------------------------------------------------------------------
Pro forma net income $ 152,678 $ 187,651
---------------------------------------------------------------------
---------------------------------------------------------------------

Pro forma net income per unit:
Basic $ 1.145 $ 1.619
---------------------------------------------------------------------
---------------------------------------------------------------------
Diluted $ 1.139 $ 1.611
---------------------------------------------------------------------
---------------------------------------------------------------------

The fair value of rights incentive options granted in 2004 and 2003
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 rights incentive option.

Long-Term Incentive Program
On November 29, 2004, the Board of Directors approved a new Long-Term
Incentive Program effective, January 1, 2005. Under the new Long-Term
Incentive Program, Restricted Share Units ("Phantom trust units")
will be allocated to employees, officers, directors and certain
consultants of the Corporation and the Manager. The number of Phantom
trust units granted will be based on a grant value as a percentage of
an individual's base salary and an established weighting of Phantom
trust units and/or rights incentive options that is dependent on an
individual's position. The Phantom trust units will fully vest on the
third anniversary year from the date of grant. The Phantom trust
units will receive distributions in the form of additional Phantom
trust units. The number of Phantom trust units, including any
additional units from re-invested distributions 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 on
the Phantom trust units to the three-year average total return of a
peer group of other Energy Trusts. Upon vesting, the number of trust
units issued from treasury may range from zero to one and one-half
times the number of Phantom trust units granted.

Employee Savings Plans
Pengrowth has a trust unit savings plan whereby qualifying employees
may contribute from one to ten percent of their basic annual salary.
Employee contributions are invested in trust units purchased on the
open market. Pengrowth matches the employees' contribution, investing
in additional trust units purchased on the open market. Pengrowth's
share of contributions is recorded as an expense and amounted to
$1,301,314 in 2004 (2003 - $1,037,063).

In addition, Pengrowth has a plan whereby it will match zero to
five percent of an employee's contribution to their Group Registered
Retirement Savings Plan. Pengrowth's share of contributions under
this plan is recorded as an expense and amounted to $425,371 in 2004
(2003 - $358,245). Pengrowth's total matching contributions under
both Employee Savings Plans cannot exceed ten percent of their basic
annual salary.

Trust Unit Margin Purchase Plan
Pengrowth has a plan whereby the employees and certain consultants of
Corporation and the Manager can purchase trust units and finance up
to 75 percent of the purchase price through an investment dealer,
subject to certain participation limits and restrictions. Certain
officers and directors hold trust units under the Trust Unit Margin
Purchase Plan; however, they are prohibited from increasing the
number of trust units they can hold under the plan. Participants
maintain personal margin accounts with the investment dealer and are
responsible for all interest costs and obligations with respect to
their margin loans.

The Corporation has provided a $5 million letter of credit to the
investment dealer to guarantee amounts owing with respect to the
plan. The amount of the letter of credit may fluctuate depending on
the amounts financed pursuant to the plan. At December 31, 2004,
848,022 trust units were deposited under the plan (2003 - 2,471,120)
with a market value of $15.7 million (2003 - $52.5 million) and a
corresponding margin loan of $3.1 million (2003 - $4.8 million).

The investment dealer has limited the total margin loan available
under the plan to the lesser of $15 million or 35 percent of the
market value of the units held under the plan. If the market value of
the trust units under the plan declines, the Corporation may be
required to make payments or post additional letters of credit to the
investment dealer. Any payments to be made by the Corporation are to
be reduced by proceeds of liquidating the individual's trust units
held under the plan. The maximum amount of the guarantee at
December 31, 2004 was $3.1 million (2003 - $4.8 million), the fair
value of which is estimated to be a nominal amount.

Redemption Rights
Trust units are redeemable at the request of a unitholder. The
redemption right permits unitholders in the aggregate to redeem a
maximum of $25,000 of trust units in a month.

11. DEFERRED CHARGES
2004 2003
---------------------------------------------------------------------
Imputed interest on note payable (net of
accumulated amortization of $1,587,
(2003 - nil) $ 2,020 $ 3,607
U.S. debt issue costs (net of accumulated
amortization of $510, (2003 - $204) 1,631 1,937
---------------------------------------------------------------------
$ 3,651 $ 5,544
---------------------------------------------------------------------
---------------------------------------------------------------------

12. FOREIGN EXCHANGE LOSS (GAIN)
2004 2003
---------------------------------------------------------------------
Unrealized foreign exchange gain on
translation of U.S. dollar denominated
debt $ (18,900) $ (30,940)
Realized foreign exchange losses 1,600 1,029
---------------------------------------------------------------------
$ (17,300) $ (29,911)
---------------------------------------------------------------------
---------------------------------------------------------------------

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.

13. OTHER CASH FLOW DISCLOSURES

Change in Non-Cash Operating Working Capital
2004 2003
---------------------------------------------------------------------
Accounts receivable $ (22,515) $ (24,144)
Inventory 260 602
Accounts payable and accrued liabilities 17,225 13,643
Due to Pengrowth Management Limited 6,203 36
---------------------------------------------------------------------
$ 1,173 $ (9,863)
---------------------------------------------------------------------
---------------------------------------------------------------------

Change in Non-Cash Investing Working Capital
2004 2003
---------------------------------------------------------------------
Accounts payable for capital accruals $ 2,169 $ (2,539)
---------------------------------------------------------------------
---------------------------------------------------------------------

Cash payments
2004 2003
---------------------------------------------------------------------
Cash payments made for taxes $ 4,729 $ 1,834
Cash payments made for interest $ 28,119 $ 16,657


14. INCOME TAXES

The provision for income taxes in the financial statements differs
from the result which would have been obtained by applying the
combined federal and provincial tax rate to Pengrowth's income
before taxes.

2004 2003
---------------------------------------------------------------------
Net Income before taxes $ 173,955 $ 191,154
Combined federal and provincial tax rate 38.6% 40.6%
---------------------------------------------------------------------
Expected income tax 67,147 77,609
Income allocated to trust unitholders (59,346) (78,893)
Resource allowance (8,807) (462)
Non-deductible crown charges 16,476 413
Unrealized foreign exchange gain (3,648) (6,281)
Attributed Canadian royalty income (3,113) (1,073)
Effect of proposed tax changes 3,850 -
Rate reductions - 14,089
Change in valuation allowance 3,035 (4,947)
Other 22 (455)
---------------------------------------------------------------------
Future income taxes 15,616 -
Capital taxes 4,594 1,857
---------------------------------------------------------------------
$ 20,210 $ 1,857
---------------------------------------------------------------------
---------------------------------------------------------------------

The net future income tax liability is comprised of:

2004 2003
---------------------------------------------------------------------
Future income tax liabilities:
Property, plant, equipment and other
assets $ 79,774 $ -
Unrealized foreign exchange gain 8,378 5,356
Other (34) 27
---------------------------------------------------------------------
88,118 5,383
Future income tax assets:
Property, plant, equipment and other assets - (60,628)
Attributed Canadian royalty income (4,418) -
Contract liabilities (8,072) -
---------------------------------------------------------------------
75,628 (55,245)
Valuation allowance - 55,245
---------------------------------------------------------------------
$ 75,628 $ -
---------------------------------------------------------------------
---------------------------------------------------------------------


Non-Resident Ownership and Mutual Fund Trust Status
The Federal budget tabled on March 23, 2004 proposed several changes
to subsection 132(7) of the Income Tax Act (Canada) (the "Act"), that
would have affected the mutual fund status of royalty trusts.

On December 5, 2004, the Minister of Finance tabled a Notice of Ways
and Means Motion in the House of Commons to implement the measures
proposed in the March 23, 2004 Federal budget. However, the changes
to the mutual fund trust provisions proposed in both the March 23,
2004 Federal budget and in the draft legislation published on
September 16, 2004 were not included. The Minister of Finance
indicated that further discussions would be pursued with the private
sector concerning the appropriate Canadian tax treatment of
non-residents investing in resource property through mutual fund
trusts. Therefore, the uncertainty remains as to whether or not the
taxable Canadian property exception will be available to royalty
trusts, such as Pengrowth Energy Trust, indefinitely.

15. RELATED PARTY TRANSACTIONS

Pengrowth Management Limited provides certain services pursuant to a
Management Agreement for which Pengrowth was charged $6,135,000
(2003 - $520,000) for performance fees and $6,739,000
(2003 - $9,660,749) for a management fee. In 2003, Pengrowth was
charged $695,000 for acquisition fees. In 2004, no acquisition fee
was charged. In addition, Pengrowth was charged $800,000 for
estimated reimbursement of general and administrative expenses
incurred by the Manager pursuant to the Management Agreement. The law
firm controlled by the corporate secretary charged $841,457
(2003 - $675,692) for legal and advisory services provided to
Pengrowth by the corporate secretary. The transactions have been
recorded at the exchange amount.

16. AMOUNTS PER UNIT

The per unit amounts for net income are based on the weighted average
units outstanding for the year. The weighted average units
outstanding for 2004 were 133,395,485 units (2003 - 115,912,374
units). In computing diluted net income per unit, 611,086 units were
added to the weighted average number of units outstanding during the
year ended December 31, 2004 (2003 - 567,335) for the dilutive effect
of trust unit options and rights. In 2004, 624,723 (2003 - 14,820)
trust unit options and rights were excluded from the diluted net
income per unit calculation as their effect is anti-dilutive.

17. FINANCIAL INSTRUMENTS

Interest Rate Risk
On April 23, 2003, Pengrowth completed a U.S. $200 million private
placement of fixed rate seven and ten year term notes. The interest
and principal payments on the term notes are payable in U.S. dollars.
Pengrowth had previously fixed the interest rates on $125 million of
Canadian bank debt using interest rate swaps. In 2003, Pengrowth
terminated these interest rate swaps at a total cost including
accrued interest of approximately $2,229,000. There were no interest
rate swaps outstanding in 2004.

Foreign Currency Exchange Risk
Pengrowth is exposed to foreign currency fluctuations as crude oil
and natural gas prices received are referenced to U.S. dollar
denominated prices. Pengrowth has mitigated some of this exchange
risk by entering into fixed Canadian dollar crude oil and natural gas
price swaps as outlined in the forward and futures contracts section
below.

Pengrowth entered into a foreign exchange swap which fixed the
Canadian to U.S. dollar exchange rate at Cdn $1.55 per U.S. $1.00 on
U.S. $750,000 per month effective 2003 and 2004. At December 31,
2004, there were no foreign exchange swaps outstanding.

Credit Risk
Pengrowth sells a significant portion of its oil and gas to commodity
marketers, and the accounts receivable are subject to normal industry
credit risks. The use of financial swap agreements involves a degree
of credit risk that Pengrowth manages through its credit policies
which are designed to limit eligible counterparties to those with "A"
credit ratings or better.

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 December 31, 2004, Pengrowth had fixed the price applicable to
future production as follows:

Crude Oil:

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

Financial:
----------
Jan 1, 2005 - Dec 31, 2005 8,000 WTI(1) $ 51.66 Cdn
---------------------------------------------------------------------


Natural Gas:

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

Financial:
----------
Jan 1, 2005 - Mar 31, 2005 2,500 Transco Z6(1) $ 12.62 Cdn
Jan 1, 2005 - Dec 31, 2005 11,000 Tetco M3(1) $ 9.27 Cdn
Jan 1, 2005 - Dec 31, 2005 2,500 Transco Z6(1) $ 10.01 Cdn
Jan 1, 2005 - Dec 31, 2005 2,500 NGI Chicago(1) $ 9.41 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 year end. At
December 31, 2004, the amount Pengrowth would receive to terminate
the financial crude oil and natural gas contracts would be $1,360,000
and $5,957,000 respectively.

Natural Gas Fixed Price Sales Contract:

Pengrowth assumed a natural gas fixed price sales contract in
conjunction with the acquisition of the Murphy Assets. The fair value
of the liability associated with the natural gas contract at the date
of acquisition was estimated to be $21,824,000 in respect thereof.
The liability will be reduced as the contract is settled. Details of
the physical fixed price sales contract are provided below:

Volume Price
Remaining Term (mcf/d) per mcf(1)
---------------------------------------------------------------------

2005 to 2009
------------
Jan 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
---------------------------------------------------------------------
(1) Reference price based on AECO


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 December 31, 2004,
was $8,366,000 (2003 - $7,479,000). The fair value of the U.S. dollar
denominated debt at December 31, 2004 was approximately $238,726,000
based on changes in the fair value of the underlying U.S. Treasury
Bill that was originally used as the basis for determining the coupon
rate for each of the Corporation's notes. The fair value of the
U.S. dollar denominated debt approximated its fair value at
December 31, 2003, as the rate on the debt did not vary significantly
from market rates. The fair value of the note payable at December 31,
2004 and 2003 approximated its carrying value net of the imputed
interest included in deferred charges.

18. COMMITMENTS

Pengrowth has future commitments under various agreements for oil and
natural gas pipeline transportation, the purchase of carbon dioxide
and operating leases. The commitment to purchase carbon dioxide
arises as a result of Pengrowth's working interest in the Weyburn CO2
miscible flood project(1).

There-
2005 2006 2007 2008 2009 after Total
---------------------------------------------------------------------
Pipeline
transport-
ation $41,475 $41,281 $40,192 $33,420 $29,728 $63,894 $249,990

Capital
expendi-
tures 36,900 34,800 6,600 - - - 78,300

CO2
purchases 5,976 5,236 4,418 4,254 4,289 23,513 47,686

Other
commitments 1,980 1,169 567 342 95 - 4,153
---------------------------------------------------------------------
$86,331 $82,486 $51,777 $38,016 $34,112 $87,407 $380,129
---------------------------------------------------------------------

(1) Contract prices for CO2 are denominated in U.S. dollars and have
been translated at the year end foreign exchange rate.

19. SUBSEQUENT EVENTS

On January 21, 2005, Pengrowth announced it had entered into an
agreement to purchase an additional 12.5 percent working interest in
Swan Hills Unit No. 1 for a purchase price of $90 million, before
adjustments. The transaction, which is subject to Rights of First
Refusal, is effective October 1, 2004 and is anticipated to close
on February 28, 2005. The acquisition would increase
Pengrowth's working interest in Swan Hills Unit No. 1 to
22.7 percent.

On February 17, 2005, Pengrowth announced an Arrangement Agreement
(the "Arrangement") with Crispin Energy Inc. ("Crispin") under which
Pengrowth will acquire all of the issued and outstanding shares of
Crispin on the basis of 0.0725 Class B trust units of EnergyTrust for
each share held by Canadian resident shareholders of Crispin and
0.0512 Class A trust units of EnergyTrust for each share held by
non-Canadian resident shareholders of Crispin. The Board of Directors
of Crispin will call a Special Meeting of Shareholders in mid to late
April 2005 for approval of the Arrangement. The Arrangement will
require the approval of 66 2/3 percent of the votes cast by
shareholders and optionholders of Crispin voting as a single class,
the approval of the majority of shareholders excluding certain
management personnel and the approval of the Court of Queen's Bench
of Alberta and certain regulatory agencies. Completion of the
Arrangement is expected to close prior to the end of April 2005.

Contact Information