Pengrowth Energy Trust
NYSE : PGH
TSX : PGF.UN

Pengrowth Energy Trust
Pengrowth Corporation

Pengrowth Corporation

February 27, 2007 02:31 ET

Pengrowth Announces Unaudited Financial, Operating and Reserve Results for Year Ended December 31, 2006

CALGARY, ALBERTA--(CCNMatthews - Feb. 27, 2007) - Pengrowth Corporation, administrator of Pengrowth Energy Trust (TSX:PGF.UN) (NYSE:PGH), is pleased to report operating and financial results for the fourth quarter and year ended December 31, 2006 as well as selected information from Pengrowth's independent engineering reserve report effective December 31, 2006.

YEAR 2006 Overview

2006 was a very strong year for Pengrowth. During the year, Pengrowth enjoyed success on two fronts. Firstly, our internal drilling and development activities replaced the reserves depleted through production in the year, a significant achievement for Pengrowth. Secondly, Pengrowth completed two significant value-adding acquisitions, including the business combination with Esprit Energy Trust (Esprit Trust) and the acquisition of oil and natural gas assets in the Carson Creek area of Alberta (Carson Creek). A $103.8 million deposit was made late in 2006 on the acquisition of Canadian oil and natural gas producing properties from four subsidiaries of Burlington Resources Limited, a subsidiary of ConocoPhillips (the CP Properties).

At the close of the year, Pengrowth had a balanced portfolio of high-quality oil and natural gas properties with a large inventory of development opportunities.

2006 and Fourth Quarter Highlights

Financial

- Oil and gas sales increased five percent to $1.2 billion dollars in 2006 reflecting higher volumes produced during the year, partially offset by lower average realized prices. In the fourth quarter, oil and gas sales were $351 million, an increase of 22 percent from the third quarter and virtually unchanged from the same quarter in 2005.

- Distributable cash totaled $576 million in 2006 and $140 million in the fourth quarter. This represents a decrease of five percent from 2005 and one percent from the previous quarter. The decreases are mainly as a result of higher operating, royalty, administrative and interest costs incurred. The 26 percent decrease in the fourth quarter of 2006 from the fourth quarter in 2005 is primarily due to lower commodity prices, higher operating, royalty, administrative and interest costs incurred, partly offset by higher production volumes.

- Distributions remained stable during the fourth quarter and for the full year in 2006, at $0.25 per unit per month, or $3.00 per unit for 2006. For the full year, distributions of $ $559 million were paid or declared to unitholders, an increase of 25 percent from the previous year.

- In 2006, Pengrowth paid out or declared 97 percent of its distributable cash as distributions to unitholders and 132 percent in the fourth quarter. The payout ratio in the fourth quarter reflects distributions paid out or declared on trust units issued for the acquisition of Esprit Trust and for the acquisition the CP Properties. However, due to the usual delays in receiving cash flow from production as well as the early 2007 closing of the CP Properties acquisition, the corresponding cash flow is not reflected in operating results.

- Net income decreased almost 20 percent for 2006 from 2005 as a result of higher operating expenses, royalties and depletion and depreciation. Net income decreased approximately 97 percent in the fourth quarter of 2006 compared to the fourth quarter of 2005 primarily due to higher depletion and depreciation expenses, lower commodity prices, higher operating, royalty, administrative and interest costs incurred, partly offset by higher production volumes.

- During the year, Pengrowth's average realized price was $52.88 per boe (after hedging) compared to an average price of $53.02 per boe in 2005. A decrease in natural gas prices during the year was largely offset by a combination of higher oil and natural gas liquids prices and lower hedging losses. For the fourth quarter, average realized prices were $49.24 per boe (after hedging) down eight percent from the third quarter and 21 percent from the same quarter last year. These decreases reflect a lower commodity price environment for oil and natural gas in the fourth quarter of 2006.

- Operating netbacks (after hedging) decreased nine percent in 2006 to $29.59 per boe, largely driven by higher operating and royalty costs. For the fourth quarter, operating netbacks were $24.17 per boe down from the previous quarter and fourth quarter of 2005 by 22 percent and 38 percent, respectively. The fourth quarter netbacks were lower largely due to lower realized prices and higher operating costs.

Operational

- Production for 2006 averaged 62,821 barrels of oil equivalent (boe) per day, a six percent increase over 2005. Fourth quarter production averaged 77,614 boe per day, up 33 percent from the third quarter and 26 percent from the fourth quarter in 2005. The higher production levels reflect volumes added through the Carson Creek and Esprit Trust acquisitions and through ongoing development activities.

- Pengrowth's development capital in 2006 totaled $301 million, an increase of 71 percent from the previous year. This year's capital program was one of Pengrowth's most successful and resulted in reserve replacement of 99 percent on a proved plus probable basis. Development capital for the fourth quarter was $122 million compared to $57 million in the third quarter and $60 million in the fourth quarter of 2005. During the year, Pengrowth participated in 298 gross (162.9 net) wells with a 96 percent success rate.

- At December 31, 2006, proved reserves were 225.9 million barrels of oil equivalent (mmboe) and proved plus probable reserves were 297.8 mmboe, an increase of 29 percent and 36 percent, respectively from the reserves at the end of 2005. During 2006, on a proved plus probable basis, Pengrowth added 22.7 mmboe through drilling, improved recoveries and technical revisions and 81.5 mmboe through acquisitions. Additions were partially offset by 22.9 mmboe of production and 2.8 mmboe of divestitures.

- On a pro forma basis, including the CP Properties, Pengrowth's reserves total 277.0 mmboe on a proved basis and 362.9 mmboe on a proved plus probable basis at December 31, 2006. The pro forma reserves represent a reserve life index of approximately 10 years on a proved plus probable basis.

- Finding and development costs (excluding the change in future development costs) were $21.25 per boe on a proved basis and $13.25 per boe on a proved plus probable basis. Finding and development costs (including the change in future development costs) were $21.67 per boe on a proved basis and $17.35 per boe on a proved plus probable basis. Overall finding, development and acquisitions excluding and including the change in future development costs were $29.24 per boe and $30.71per boe respectively on a proved basis and $21.13 per boe and $23.62 per boe respectively on a proved plus probable basis.


Strategic

- During 2006, Pengrowth issued $1.9 billion in financing to fund strategic acquisitions announced in 2006. This included the acquisition of the Carson Creek assets, the business combination with Esprit Trust and most recently, the acquisition of the CP Properties where $461 million in equity was raised at the end of 2006 and the acquisition was completed in early 2007.

- On July 27, 2006 Pengrowth consolidated its Class A trust units and Class B trust units into one class of trust units. The Class A trust units were delisted from the Toronto Stock Exchange and converted into Class B trust units (with the exception of Class A trust units held by residents of Canada who elected to retain their Class A trust units), the Class B trust units were renamed as "trust units" and their trading symbol was changed from PGF.B to PGF.UN.

- On March 30, 2006, Pengrowth closed the acquisition of an additional working interest in the Dunvegan Unit as well as some minor oil and gas properties in central Alberta for approximately $48 million.

- On January 12, 2006, Pengrowth divested non-core oil and gas properties for consideration of $22 million of cash, prior to adjustments, and approximately eight million shares in Monterey Exploration Ltd. (Monterey). Pengrowth holds approximately 34 percent of the common shares of Monterey.

The following discussion of financial results should be read in conjunction with the unaudited consolidated Financial Statements for the year ended December 31, 2006 of Pengrowth Energy Trust and is based on information available to February 26, 2007.



Summary of Financial and Operating Results

Three Months ended
December 31 %
(thousands, except per unit amounts) 2006 2005 Change
---------------------------------------------------------------------------
INCOME STATEMENT
Oil and gas sales $ 350,908 $ 353,923 (1)
Net income $ 3,310 $ 116,663 (97)
Net income per trust unit $ 0.01 $ 0.73 (99)
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CASH FLOW
Cash flows from operating activities $ 91,237 $ 196,588 (54)
Cash flows from operating activities
per trust unit $ 0.41 $ 1.23 (67)

Distributable cash (1) $ 140,405 $ 189,379 (26)
Distributable cash per trust unit (1) $ 0.64 $ 1.19 (46)
Distributions paid or declared $ 185,651 $ 119,858 55
Distributions paid or declared
per trust unit $ 0.75 $ 0.75 0
Payout ratio (1) 132% 63% 69

Capital expenditures $ 121,781 $ 60,093 103
Capital expenditures per trust unit $ 0.55 $ 0.38 45

Weighted average number of trust units
outstanding 220,734 159,528 38
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BALANCE SHEET
Working capital
Property, plant and equipment
Long term debt
Unitholders' equity
Unitholders' equity per trust unit

Number of trust units outstanding at
period end
---------------------------------------------------------------------------
DAILY PRODUCTION
Crude oil (bbls) 25,000 21,179 18
Heavy oil (bbls) 4,695 5,410 (13)
Natural gas (mcf) 234,050 168,862 39
Natural gas liquids (bbls) 8,910 6,710 33
Total production (boe) 77,614 61,442 26

TOTAL PRODUCTION (mboe) 7,141 5,653 26
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PRODUCTION PROFILE
Crude oil 32% 34%
Heavy oil 6% 9%
Natural gas 50% 46%
Natural gas liquids 12% 11%
---------------------------------------------------------------------------
AVERAGE REALIZED PRICES (after hedging)
Crude oil (per bbl) $ 60.35 $ 59.40 2
Heavy oil (per bbl) $ 37.61 $ 31.77 18
Natural gas (per mcf) $ 7.12 $ 11.97 (41)
Natural gas liquids (per bbl) $ 52.69 $ 58.46 (10)
Average realized price per boe $ 49.24 $ 62.55 (21)
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PROVED PLUS PROBABLE RESERVES
Crude oil (mbbls)
Heavy oil (mbbls)
Natural gas (bcf)
Natural gas liquids (mbbls)
Total oil equivalent (mboe)

Twelve Months ended
December 31 %
(thousands, except per unit amounts) 2006 2005 Change
---------------------------------------------------------------------------
INCOME STATEMENT
Oil and gas sales $1,214,093 $1,151,510 5
Net income $ 262,303 $ 326,326 (20)
Net income per trust unit $ 1.49 $ 2.08 (28)
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CASH FLOW
Cash flows from operating activities $ 554,368 $ 618,070 (10)
Cash flows from operating activities per
trust unit $ 3.15 $ 3.93 (20)

Distributable cash (1) $ 575,884 $ 608,217 (5)
Distributable cash per trust unit (1) $ 3.27 $ 3.87 (16)
Distributions paid or declared $ 559,063 $ 445,977 25
Distributions paid or declared per trust
unit $ 3.00 $ 2.82 6
Payout ratio (1) 97% 73% 24

Capital expenditures $ 300,809 $ 175,693 71
Capital expenditures per trust unit $ 1.71 $ 1.12 53

Weighted average number of trust units
outstanding 175,871 157,127 12
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BALANCE SHEET
Working capital $ (149,937)$ (112,205) 34
Property, plant and equipment $3,741,602 $2,067,988 81
Long term debt $ 604,200 $ 368,089 64
Unitholders' equity $3,049,677 $1,475,996 107
Unitholders' equity per trust unit $ 12.50 $ 9.23 35

Number of trust units outstanding at period
end 244,017 159,864 53
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DAILY PRODUCTION
Crude oil (bbls) 21,821 20,799 5
Heavy oil (bbls) 4,964 5,623 (12)
Natural gas (mcf) 175,578 161,056 9
Natural gas liquids (bbls) 6,774 6,093 11
Total production (boe) 62,821 59,357 6

TOTAL PRODUCTION (mboe) 22,930 21,665 6
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PRODUCTION PROFILE
Crude oil 35% 35%
Heavy oil 8% 10%
Natural gas 46% 45%
Natural gas liquids 11% 10%
---------------------------------------------------------------------------
AVERAGE REALIZED PRICES (after hedging)
Crude oil (per bbl) $ 66.85 $ 58.59 14
Heavy oil (per bbl) $ 42.26 $ 33.32 27
Natural gas (per mcf) $ 7.22 $ 8.76 (18)
Natural gas liquids (per bbl) $ 57.11 $ 54.22 5
Average realized price per boe $ 52.88 $ 53.02 0
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PROVED PLUS PROBABLE RESERVES
Crude oil (mbbls) 112,388 98,684 14
Heavy oil (mbbls) 18,336 15,790 16
Natural gas (bcf) 827 516 60
Natural gas liquids (mbbls) 29,142 18,985 54
Total oil equivalent (mboe) 297,774 219,396 36

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


Summary of Trust Unit Trading Data

Volume Value
High Low Close (000's) $ millions)
TSX - PGF.A ($ Cdn)
2006 1st quarter 28.96 24.96 26.88 1,244 33.8
2nd quarter 28.50 24.20 26.70 1,810 47.6
3rd quarter (2) 28.25 24.95 25.30 4,297 110.6
4th quarter - - - - -
Year 28.96 24.20 25.30 7,351 192.0
2005 1st quarter 28.29 22.15 24.03 2,049 53.3
2nd quarter 27.90 23.95 27.20 1,798 46.4
3rd quarter 30.10 26.30 29.50 2,047 58.0
4th quarter 29.80 23.64 27.41 1,324 35.2
Year 30.10 22.15 27.41 7,218 192.9

TSX - PGF.B ($ Cdn)
2006 1st quarter 24.50 20.71 23.32 18,338 420.1
2nd quarter 26.05 22.41 26.05 18,982 459.6
3rd quarter (2) 27.25 24.84 25.31 14,226 364.0
4th quarter - - - - -
Year 27.25 20.71 25.31 51,546 1,243.7
2005 1st quarter 19.90 16.10 17.05 29,219 543.7
2nd quarter 19.01 16.37 18.40 19,370 342.5
3rd quarter 21.26 18.25 20.58 22,738 441.0
4th quarter 23.38 17.27 22.65 19,747 411.0
Year 23.38 16.10 22.65 91,074 1,738.2

TSX - PGF.UN ($ Cdn)
2006 1st quarter - - - - -
2nd quarter - - - - -
3rd quarter (2) 26.11 21.02 21.94 29,262 708.0
4th quarter 22.69 16.81 19.94 75,576 1,505.0
Year 26.11 16.81 19.94 104,838 2,213.0

NYSE - PGH ($ U.S.)
2006 1st quarter 25.15 21.50 23.10 13,421 316.2
2nd quarter 25.00 21.85 24.09 14,277 337.0
3rd quarter 24.95 18.90 19.62 27,359 604.0
4th quarter 20.25 14.78 17.21 55,108 955.6
Year 25.15 14.78 17.21 110,165 2,212.8
2005 1st quarter 22.94 18.11 20.00 24,621 515.1
2nd quarter 22.74 19.05 22.25 16,153 335.0
3rd quarter 25.75 21.55 25.42 14,502 340.3
4th quarter 25.56 20.00 23.53 17,808 399.7
Year 25.75 18.11 23.53 73,084 1,590.1

(2) On July 27, 2006, Pengrowth's Class A trust units and Class B trust
units were consolidated into a single class of trust units pursuant to
which the Class A trust units were delisted from the Toronto Stock
Exchange, Class A trust units were converted into Class B trust units
(with the exception of Class A trust units held by residents of Canada
who elected to retain their Class A trust units) and the Class B trust
units were renamed as trust units and their trading symbol changed to
PGF.UN.


Frequently Recurring Terms

For the purposes of this discussion, we use certain frequently recurring terms as follows: the "Trust" refers to Pengrowth Energy Trust, the "Corporation" refers to Pengrowth Corporation, "Pengrowth" refers to the Trust and its subsidiaries and the Corporation on a consolidated basis and the "Manager" refers to Pengrowth Management Limited.

Pengrowth uses the following frequently recurring industry terms in this discussion: "bbls" refers to barrels, "boe" refers to barrels of oil equivalent, "mboe" refers to a thousand barrels of oil equivalent, "mcf" refers to thousand cubic feet, "gj" refers to gigajoule and "mmbtu" refers to million British thermal units.

Critical Accounting Estimates

As discussed in Note 2 to the unaudited financial statements, the financial statements are prepared in accordance with Canadian Generally Accepted Accounting Principles (GAAP). Management is required 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 year ended.

The amounts recorded for depletion, depreciation and 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) Disclosure for Oil and Gas Activities, 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 discussion refers to certain financial measures that are not determined in accordance with 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. Measures such as funds generated from operations, funds generated from operations per trust unit, distributable cash, distributable cash per trust unit, payout ratio and operating netbacks do not have standardized meanings prescribed by GAAP. We discuss these measures 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 uses the international standard of six thousand cubic feet to one barrel of oil equivalent. Barrels of oil equivalent may be misleading, particularly if used in isolation; a conversion ratio of six 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. Production volumes, revenues and reserves are reported on a company interest gross basis (before royalties) in accordance with Canadian practice. All amounts are stated in Canadian dollars unless otherwise specified.

RESULTS OF OPERATIONS

Production

Average daily production increased six percent in 2006, compared to 2005 and 33 percent in the fourth quarter of 2006 from the third quarter of 2006. This increase is attributable primarily to the Carson Creek and Esprit Trust acquisitions which were completed late in the third quarter and in the fourth quarter of 2006, respectively and contributions from ongoing development activities.

At this time, Pengrowth anticipates 2007 full year production of 83,000 to 87,500 boe per day. This estimate incorporates production from the CP Properties acquisition disclosed in the Subsequent Event section of the discussion. It also includes expected divestitures during the first half of 2007 of approximately 7,700 boe per day of current production. The above estimate excludes the impact from any future acquisitions, if they were to occur.



Daily Production

Three months ended Twelve months ended
---------------------------------------------------------------------------
Dec 31, Sept 30, Dec 31, Dec 31, Dec 31,
2006 2006 2005 2006 2005
---------------------------------------------------------------------------
Light crude oil (bbls) 25,000 20,651 21,179 21,821 20,799
Heavy oil (bbls) 4,695 5,272 5,410 4,964 5,623
Natural gas (mcf) 234,050 158,757 168,862 175,578 161,056
Natural gas liquids (bbls) 8,910 5,961 6,710 6,774 6,093
---------------------------------------------------------------------------
Total boe per day 77,614 58,344 61,442 62,821 59,357
---------------------------------------------------------------------------


Light crude oil production volumes increased five percent year-over-year, 21 percent in the fourth quarter of 2006 compared to the third quarter and 18 percent when compared to the fourth quarter of 2005. The additional volumes from the Esprit Trust and Carson Creek acquisitions had a positive impact on production that more than offset natural production declines.

Heavy oil production decreased 12 percent year-over-year and 13 percent when comparing the fourth quarter of 2006 to the same quarter of 2005 due to natural production declines. Production was temporarily shut-in during the fourth quarter of 2006 at Tangleflags to facilitate a new drilling program and natural production declines were responsible for the 11 percent decrease in the fourth quarter of 2006 compared to the third quarter of 2006.

Natural gas production increased nine percent year-over-year. Additional production volumes from acquisitions, development activities, particularly at Prespatou, Princess and Cutbank/Tupper and increased gas sales at Judy Creek due to lower gas solvent utilization, combined to more than offset the Monterey divestiture and the operational downtime at the Sable Offshore Energy Project (SOEP) during the second and fourth quarters of 2006. The 47 percent increase in volumes in the fourth quarter of 2006 compared to the third quarter of 2006 is due to acquisitions and the drilling results from the Cutbank/Tupper area which more than offset the downtime at SOEP for the compression program. The 39 percent increase in production volumes for the fourth quarter of 2006 compared to the same period of 2005 was due to acquisitions, drilling results from the Cutbank/Tupper area which more than offset the downtime at SOEP in 2006, the Monterey divestiture and natural production declines.

Natural gas liquids (NGLs) production increased 11 percent year-over-year primarily due to acquisitions. Production volumes nearly doubled in the fourth quarter of 2006 in comparison to the third quarter of 2006 due to acquisitions and additional condensate at SOEP partially offset by natural production declines. The 33 percent increase in production volumes for the fourth quarter of 2006 compared to the same period of 2005 was due to acquisitions, which more than offset the Monterey divestiture and natural production declines.

Pricing and Commodity Price Hedging

On a year-over-year basis, the nearly 17 percent increase in U.S. based prices for North American crude oil and improved differentials for heavy oil during 2006 were partially offset by the negative impact of lower gas prices.



Average Realized Prices

Three months ended Twelve months ended
---------------------------------------------------------------------------
Dec 31, Sept 30, Dec 31, Dec 31, Dec 31,
(Cdn$) 2006 2006 2005 2006 2005
---------------------------------------------------------------------------

Light crude oil (per bbl) 60.94 75.53 67.00 68.83 65.47
after hedging 60.35 72.61 59.40 66.85 58.59
Heavy oil (per bbl) 37.61 51.47 31.77 42.26 33.32
Natural gas (per mcf) 6.82 6.22 12.80 7.08 8.99
after hedging 7.12 6.29 11.97 7.22 8.76
Natural gas liquids (per bbl) 52.69 60.76 58.46 57.11 54.22
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Total per boe 48.52 54.51 67.43 53.18 56.06
after hedging 49.24 53.67 62.55 52.88 53.02
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Benchmark prices
WTI oil (U.S.$ per bbl) 60.17 70.54 60.05 66.25 56.70
AECO spot gas (Cdn$ per gj) 6.36 5.72 11.08 6.70 8.04
NYMEX gas (U.S.$ per mmbtu) 6.56 6.66 12.97 7.24 8.62
Currency (U.S.$/Cdn$) 0.88 0.89 0.85 0.88 0.83
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As part of our financial management strategy, Pengrowth uses forward price swap and option contracts to manage its exposure to commodity price fluctuations, to provide a measure of stability to monthly cash distributions and to partially secure returns on significant new acquisitions. Pengrowth has committed approximately 40 percent of its gross production to commodity price contracts in 2007.



Hedging Losses (Gains)

Three months ended Twelve months ended
---------------------------------------------------------------------------
Dec 31, Sept 30, Dec 31, Dec 31, Dec 31,
Realized 2006 2006 2005 2006 2005
---------------------------------------------------------------------------

Light crude oil ($ millions) 1.4 5.5 14.8 15.8 52.2
Light crude oil ($ per bbl) 0.59 2.92 7.60 1.98 6.88

Natural gas ($ millions) (6.5) (1.0) 12.9 (8.8) 13.6
Natural gas ($ per mcf) (0.30) (0.07) 0.83 (0.14) 0.23
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Combined ($ millions) (5.1) 4.5 27.7 7.0 65.8
Combined ($ per boe) (0.72) 0.84 4.88 0.30 3.04
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Effective May 1, 2006, Pengrowth no longer designates new commodity price contracts as hedges. Pengrowth has recognized any changes to the fair value of commodity contracts entered into after May 1, 2006 in the income statement.

Commodity price contracts in place at December 31, 2006 are detailed in Note 20 to the financial statements. At December 31, 2006, the mark-to-market value of the outstanding commodity contracts represented an unrealized potential gain of $37.1 million, which includes a $26.5 million gain year to date that has been recognized on the income statement. The $26.5 million unrealized gain is a non-cash item and is not reflected in oil and gas sales. The balance of the gain of $10.6 million was capitalized as part of the purchase price allocation for Esprit Trust. Compared to December 31, 2005, the mark-to-market value of the commodity contracts represented a potential loss of $18.4 million, none of which was recognized on the income statement at that time.

In conjunction with an acquisition, which closed in 2004, Pengrowth assumed certain fixed price natural gas sales contracts and firm pipeline demand charge contracts. Under these contracts, Pengrowth is obligated to sell 3,886 mmbtu per day until April 30, 2009 at an average remaining contract price of Cdn $2.34 per mmbtu. As required by Canadian GAAP, the fair value of the natural gas sales contract was recognized as a liability based on the mark-to-market value at May 31, 2004. The liability at December 31, 2006 of $12.9 million for the contracts will continue to be drawn down and recognized in income as the contracts are settled. As this is a non-cash component of income, it is not included in the calculation of distributable cash. As at December 31, 2006, Pengrowth would be required to pay $17.0 million to terminate the fixed price physical sales contract. This amount is not included above in hedging losses (gains).



Oil and Gas Sales - Contribution Analysis

($ millions) Three months ended
---------------------------------------------------------------------------
Dec 31, % of Sept 30, % of Dec 31, % of
Sales Revenue 2006 total 2006 total 2005 total
---------------------------------------------------------------------------
Light crude oil 138.8 40 137.9 48 115.7 33
Natural gas 153.3 44 91.9 32 186.0 53
Natural gas liquids 43.2 12 33.3 11 36.1 10
Heavy oil 16.3 4 24.9 9 15.8 4
Brokered sales/sulphur (0.7) - (0.2) - 0.3 -
---------------------------------------------------------------------------
Total oil and gas sales 350.9 287.8 353.9
---------------------------------------------------------------------------

($ millions) Twelve months ended
---------------------------------------------------------------------------
Dec 31, % of Dec 31, % of
Sales Revenue 2006 total 2005 total
---------------------------------------------------------------------------
Light crude oil 532.4 44 444.8 39
Natural gas 462.4 38 514.9 45
Natural gas liquids 141.2 12 120.6 10
Heavy oil 76.6 6 68.4 6
Brokered sales/sulphur 1.5 - 2.8 -
---------------------------------------------------------------------------
Total oil and gas sales 1,214.1 1,151.5
---------------------------------------------------------------------------


Oil and Gas Sales - Price and Volume Analysis

The following table illustrates the effect of changes in prices and
volumes, on a year-over-year basis, on the components of oil and gas sales,
including the impact of hedging.

---------------------------------------------------------------------------
($ millions) Light Natural NGL Heavy Other Total
oil gas oil
---------------------------------------------------------------------------

Year ended December 31, 2005 444.8 514.9 120.6 68.4 2.8 1,151.5
Effect of change in product prices 26.8 (122.5) 7.1 16.2 - (72.4)
Effect of change in sales volumes 24.4 47.6 13.5 (8.0) - 77.5
Effect of change in hedging
losses/gains 36.4 22.4 - - - 58.8
Other - - - - (1.3) (1.3)
---------------------------------------------------------------------------
Year ended December 31, 2006 532.4 462.4 141.2 76.6 1.5 1,214.1
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Processing, Interest and Other Income

Three months ended Twelve months ended
---------------------------------------------------------------------------
Dec 31, Sept 30, Dec 31, Dec 31, Dec 31,
($ millions) 2006 2006 2005 2006 2005
---------------------------------------------------------------------------

Processing, interest
& other income 6.2 4.7 4.0 18.8 17.7
$ per boe 0.86 0.88 0.71 0.82 0.82
---------------------------------------------------------------------------


Processing, interest and other income is primarily derived from fees charged for processing and gathering third party gas, road use and oil and water processing. This income represents the partial recovery of operating expenses reported separately.



Royalties

Three months ended Twelve months ended
---------------------------------------------------------------------------
Dec 31, Sept 30, Dec 31, Dec 31, Dec 31,
($ millions) 2006 2006 2005 2006 2005
---------------------------------------------------------------------------

Royalty expense 73.1 57.8 68.0 241.5 213.9
$ per boe 10.23 10.77 12.03 10.53 9.87
---------------------------------------------------------------------------
Royalties as a percent
of sales 20.8% 20.1% 19.2% 19.9% 18.6%


Royalties include Crown, freehold and overriding royalties as well as mineral taxes. The increase in the royalty rate for 2006 is primarily due to the change in royalties at SOEP. SOEP has a five tier royalty regime based on gross revenue for the first three tiers and net revenue for the final two tiers. During 2005, the royalty obligation at SOEP was approximately two percent of gross revenue (Tier II) but progressed to five percent of gross revenue (Tier III) starting with October 2005 production. The increase to five percent was recognized in March 2006 when the 2005 royalty submission was filed. Commencing with March 2006 production, Pengrowth forecasted, the royalty obligation to be in Tier IV which is 30 percent of net revenue (gross revenue less certain capital and other specified costs associated with producing the gas and natural gas liquids).

The outlook for 2007 is approximately 21 percent royalty as a percentage of Pengrowth's sales.



Operating Expenses

Three months ended Twelve months ended
---------------------------------------------------------------------------
Dec 31, Sept 30, Dec 31, Dec 31, Dec 31,
($ millions) 2006 2006 2005 2006 2005
---------------------------------------------------------------------------

Operating expenses 99.7 58.8 61.2 270.5 218.1
$ per boe 13.97 10.94 10.83 11.80 10.07
---------------------------------------------------------------------------


Operating expenses increased $41 million or $3.03 per boe in the fourth quarter of 2006 in comparison to the third quarter of 2006. Increased utility costs and higher maintenance ($12 million), the Esprit Trust ($18 million or $10.96 per boe) and Carson Creek acquisitions ($6 million or $16.54 per boe) were the most significant reasons for the increase in expenses. Carson Creek has operating costs per boe that are generally higher than Pengrowth's average due to its high utility requirements, but are expected to improve as utility costs decline and operating synergies are captured. Operating expenses increased almost $39 million in the fourth quarter of 2006 in comparison to the fourth quarter of 2005. Increased utility costs and higher maintenance ($9 million), the Esprit Trust ($18 million) and Carson Creek acquisitions ($7 million) were the most significant reasons for the increase in operating expense. In comparing year-over-year, operating expenses increased $53 million. Increased utility costs and higher maintenance ($17 million), the Esprit Trust ($18 million) and Carson Creek acquisitions ($7 million) and higher salaries and employee retention programs were the primary reasons for the increase.

Operating expenses include costs incurred to earn processing and other income which are reported separately.

Pengrowth expects total operating expenses for 2007 to increase when compared to 2006 and are anticipated to total approximately $405 million or $13.00 per boe. Pengrowth expects to spend approximately $14.5 million per year, prior to inflation, excluding contributions to remediation trust funds, over the next ten years on remediation and abandonment.



Transportation Costs

Three months ended Twelve months ended
---------------------------------------------------------------------------
Dec 31, Sept 30, Dec 31, Dec 31, Dec 31,
($ millions) 2006 2006 2005 2006 2005
---------------------------------------------------------------------------

Light oil transportation 0.5 0.5 0.5 2.0 2.2
$ per bbl 0.21 0.26 0.27 0.25 0.29
Natural gas transportation 1.8 1.3 1.8 5.6 5.7
$ per mcf 0.09 0.09 0.12 0.09 0.10
---------------------------------------------------------------------------


Pengrowth incurs transportation costs for its product once the product enters a feeder or main pipeline to the title transfer point. The transportation cost is dependant upon industry rates and distance the product flows on the pipeline prior to changing ownership or custody. Pengrowth has the option to sell some of its natural gas directly to premium markets outside of Alberta by incurring additional transportation costs. Prior to December 31, 2006, Pengrowth sold most of its natural gas without incurring significant additional transportation costs. Similarly, Pengrowth has elected to sell approximately 75 percent of its crude oil at market points beyond the wellhead, but at the first major trading point, requiring minimal transportation costs.



Amortization of Injectants for Miscible Floods

Three months ended Twelve months ended
---------------------------------------------------------------------------
Dec 31, Sept 30, Dec 31, Dec 31, Dec 31,
($ millions) 2006 2006 2005 2006 2005
---------------------------------------------------------------------------

Purchased and capitalized 9.4 7.9 14.5 34.6 34.7
Amortization 9.3 8.8 7.1 34.6 24.4
---------------------------------------------------------------------------


The cost of injectants (primarily natural gas and ethane) purchased for injection in miscible flood programs is amortized equally 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 and 2006 is amortized over a 24 month period while costs incurred for the purchase of injectants in prior periods is amortized over 30 months. As of December 31, 2006, the balance of unamortized injectant costs was $35.3 million.

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 expenses. The cost of purchased injectants decreased minimally year-over year as the increased injectant volume of natural gas liquids offset the lower price paid for gas volumes injected.

Operating Netbacks

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

Pengrowth recorded an operating netback of $29.59 per boe (after hedging) in 2006 compared to $32.54 per boe (after hedging) in 2005, mainly due to higher operating and royalty expenses.



Three months ended Twelve months ended
------------------------------------------------
Combined Netbacks Dec 31, Sept 30, Dec 31, Dec 31, Dec 31,
($ per boe) 2006 2006 2005 2006 2005
------------------------------------------------

Sales price 49.24 53.67 62.55 52.88 53.02
Other production income (0.09) (0.06) 0.06 0.06 0.13
------------------------------------------------
49.15 53.61 62.61 52.94 53.15
Processing, interest
and other income 0.86 0.88 0.71 0.82 0.82
Royalties (10.23) (10.77) (12.02) (10.53) (9.87)
Operating expenses (13.97) (10.94) (10.83) (11.80) (10.07)
Transportation costs (0.33) (0.33) (0.41) (0.33) (0.36)
Amortization of injectants (1.31) (1.63) (1.25) (1.51) (1.13)
------------------------------------------------
Operating netback 24.17 30.82 38.81 29.59 32.54
------------------------------------------------


Three months ended Twelve months ended
------------------------------------------------
Light Crude Netbacks Dec 31, Sept 30, Dec 31, Dec 31, Dec 31,
($ per bbl) 2006 2006 2005 2006 2005
------------------------------------------------

Sales price 60.35 72.61 59.40 66.85 58.59
Other production income (0.31) (0.19) 0.17 0.13 0.37
------------------------------------------------
60.04 72.42 59.57 66.98 58.96
Processing, interest
and other income 0.64 0.60 0.34 0.58 0.47
Royalties (11.65) (12.19) (6.47) (10.63) (8.64)
Operating expenses (17.95) (13.20) (14.32) (13.78) (12.28)
Transportation costs (0.21) (0.26) (0.27) (0.25) (0.29)
Amortization of injectants (4.08) (4.61) (3.63) (4.35) (3.21)
------------------------------------------------
Operating netback 26.79 42.76 35.22 38.55 35.01
------------------------------------------------


Three months ended Twelve months ended
------------------------------------------------
Heavy Oil Netbacks Dec 31, Sept 30, Dec 31, Dec 31, Dec 31,
($ per bbl) 2006 2006 2005 2006 2005
------------------------------------------------

Sales price 37.61 51.47 31.77 42.26 33.32
Processing, interest
and other income 0.80 0.38 0.74 0.43 0.36
Royalties (5.44) (6.27) (2.98) (4.53) (4.53)
Operating expenses (14.06) (16.28) (11.60) (15.16) (15.65)
------------------------------------------------
Operating netback 18.91 29.30 17.93 23.00 13.50
------------------------------------------------


Three months ended Twelve months ended
------------------------------------------------
Natural Gas Netbacks Dec 31, Sept 30, Dec 31, Dec 31, Dec 31,
($ per mcf) 2006 2006 2005 2006 2005
------------------------------------------------

Sales price 7.12 6.29 11.97 7.22 8.76
Other production income - - - 0.01 -
------------------------------------------------
7.12 6.29 11.97 7.23 8.76
Processing, interest
and other income 0.20 0.23 0.19 0.21 0.23
Royalties (1.41) (1.34) (2.62) (1.54) (1.70)
Operating expenses (1.90) (1.38) (1.38) (1.65) (1.24)
Transportation costs (0.09) (0.09) (0.12) (0.09) (0.10)
------------------------------------------------
Operating netback 3.92 3.71 8.04 4.16 5.95
------------------------------------------------


Three months ended Twelve months ended
------------------------------------------------
NGLs Netbacks Dec 31, Sept 30, Dec 31, Dec 31, Dec 31,
($ per bbl) 2006 2006 2005 2006 2005
------------------------------------------------

Sales price 52.69 60.76 58.46 57.11 54.22
Royalties (16.61) (21.84) (21.29) (20.17) (17.66)
Operating expenses (14.00) (10.26) (10.05) (11.12) (9.04)
------------------------------------------------
Operating netback 22.08 28.66 27.12 25.82 27.52
------------------------------------------------


Interest

Interest expense increased approximately 49 percent to $32.1 million in 2006 from $21.6 million in 2005, reflecting a higher average debt level combined with higher interest rates and higher standby fees in 2006. Approximately 39 percent of Pengrowth's outstanding long term debt as at December 31, 2006 incurs interest expense payable in U.S. dollars and therefore remains subject to fluctuations in the U.S. dollar exchange rate.



General and Administrative (G&A)

Three months ended Twelve months ended
---------------------------------------------------------------------------
Dec 31, Sept 30, Dec 31, Dec 31, Dec 31,
($ millions) 2006 2006 2005 2006 2005
---------------------------------------------------------------------------

Cash G&A expense 11.7 6.8 7.7 34.1 27.4
$ per boe 1.63 1.27 1.36 1.49 1.27
Non-cash G&A expense (0.3) 0.9 0.8 2.5 2.9
$ per boe (0.04) 0.17 0.14 0.11 0.13
---------------------------------------------------------------------------
Total G&A 11.4 7.7 8.5 36.6 30.3
Total G&A ($ per boe) 1.59 1.44 1.50 1.60 1.40


The cash component of G&A for the fourth quarter of 2006 compared to the third quarter of 2006 increased $4.9 million due to the increase in salaries resulting from the Esprit Trust business combination and employee retention programs ($1.8 million), increased office rent ($0.7 million), year-end reserves report ($0.6 million) and $1.0 million for estimated reimbursement of G&A expenses incurred by the Manager, pursuant to the management agreement. Employee retention programs and additional expenses relating to the Esprit Trust business combination were the main reasons for the $6.7 million increase year-over-year.



Management Fees

Three months ended Twelve months ended
---------------------------------------------------------------------------
Dec 31, Sept 30, Dec 31, Dec 31, Dec 31,
($ millions) 2006 2006 2005 2006 2005
---------------------------------------------------------------------------

Management Fee 0.9 0.8 2.2 7.0 9.1
Performance Fee (1.6) 2.2 2.2 2.9 6.9
---------------------------------------------------------------------------
Total (0.7) 3.0 4.4 9.9 16.0
Total ($ per boe) (0.09) 0.56 0.77 0.43 0.74
---------------------------------------------------------------------------


Under the current management agreement, which came into effect July 1, 2003, the Manager will earn a performance fee if the Trust's total returns exceed eight percent per annum on a three year rolling average basis. The maximum fees payable until June 30, 2006, including the performance fee, were limited to 80 percent of the fees plus expenses that would otherwise have been payable under the original management agreement that was effective prior to July 1, 2003. Commencing July 1, 2006, for the remaining three year term, the maximum fees payable are limited to 60 percent of the fees that would have been payable under the original agreement or $12 million, whichever is lower. The current agreement expires on June 30, 2009 and does not contain a further right of renewal.

Related Party Transactions

Details of related party transactions incurred in 2006 and 2005 are provided in Note 18 to the financial statements. These transactions include the management fees paid to the Manager. The Manager is controlled by James S. Kinnear, the Chairman, President and Chief Executive Officer of the Corporation. The management fees paid to the Manager are pursuant to a management agreement which has been approved by the trust unitholders. Mr. Kinnear does not receive any salary or bonus in his capacity as a director and officer of the Corporation and has not received any new trust unit options or rights since November 2002.

Related party transactions in 2006 also include $1.0 million (2005 - $0.7 million) paid to a law firm controlled by the Vice President and Corporate Secretary of the Corporation, Charles V. Selby. These fees are paid in respect of legal and advisory services provided by the Vice President and Corporate Secretary of the Corporation. Mr. Selby has from time to time been granted trust unit rights and options.

On January 12, 2006, Pengrowth divested non-core oil and gas properties for consideration of $22 million of cash, prior to adjustments, and approximately eight million shares in Monterey. Pengrowth holds approximately 34 percent of the common shares of Monterey. In December 2006, two senior officers of the Corporation directly and indirectly purchased a total of 30,000 shares of Monterey for a total consideration of $150,000 in a new share offering marketed by an independent broker.

Taxes

In determining its taxable income, the Corporation deducts payments made to the Trust, effectively transferring the income tax liability to unitholders thus reducing the Corporation's taxable income to nil. Under the Corporation's current distribution policy, at the discretion of the Board, funds can be withheld from distributable cash to fund future capital expenditures, repay debt or other corporate purposes. In the event withholdings increased sufficiently, the Corporation could become subject to taxation on a portion of its income in the future. This can be mitigated through various options including the issuance of additional trust units, increased tax pools from additional capital spending, modifications to the distribution policy or potential changes to the corporate structure. As a result, none of the Trust's subsidiaries anticipate the payment of any cash income taxes in the foreseeable future.

Effective January 1, 2006, the federal government eliminated the Large Corporations tax. Large Corporations tax payable in 2005 amounted to $2.2 million.

The acquisition of Esprit Trust resulted in Pengrowth recording an additional future tax liability of $110.6 million. Additionally, the acquisition of Carson Creek resulted in an additional future tax liability of $121.4 million. In 2005, the acquisition of Crispin Energy Inc. (Crispin) resulted in Pengrowth recording an additional tax liability of $22.2 million. The future tax liabilities represent the difference between the tax basis and the fair values assigned to the acquired assets. A comparison of the fair value and tax basis at the end of the year reduced the future tax liability by $14.3 million to $327.8 million.

On October 31, 2006, the Minister of Finance (Canada) announced tax proposals which, if enacted, would modify the taxation of certain flow-through entities including mutual fund trusts and their unitholders (the "October 31 Proposals"). The October 31 Proposals will apply to a specified investment flow-through (SIFT) trust and will apply a tax at the trust level on distributions of certain income from such a SIFT trust at a rate of tax comparable to the combined federal and provincial corporate tax rate. These distributions will be treated as dividends to the trust unitholders.

On December 21, 2006, the Department of Finance (Canada) released draft legislation to implement the October 31 Proposals discussed above. The draft legislation appears to be generally consistent with details included in the October 31 announcement.

It is expected that Pengrowth will be characterized as a SIFT trust and as a result would be subject to the October 31 Proposals. The October 31 Proposals are to apply commencing January 1, 2007 for all SIFT trusts that begin to be publicly traded after October 31, 2006 and commencing January 1, 2011 for all SIFT trusts that were publicly traded on or before October 31, 2006. Subject to the qualification below regarding the possible loss of the four year grandfathering period in the case of undue expansion, it is expected that Pengrowth will not be subject to the October 31 Proposals until January 1, 2011.

Under the existing provisions of the Tax Act, Pengrowth can generally deduct in computing its income for a taxation year any amount of income that it distributes to unitholders in the year and, on that basis, Pengrowth is generally not liable for any material amount of tax.

Pursuant to the October 31 Proposals, commencing January 1, 2011, (subject to the qualification below regarding the possible loss of the four year grandfathering period in the case of undue expansion), Pengrowth will not be able to deduct certain of its distributed income (referred to as specified income). Pengrowth will become subject to a distribution tax on this specified income at a special rate estimated to be 31.5 percent.

Pengrowth may lose the benefit of the four year grandfathering period if Pengrowth exceeds the limits on the issuance of new trust units and convertible debt that constitute normal growth during the grandfathering period (subject to certain exceptions). The normal growth limits are calculated as a percentage of Pengrowth's market capitalization of approximately $4.8 billion on October 31, 2006 as follows: 40 percent for the period November 1, 2006 to December 31, 2007, 20 percent for each of 2008, 2009 and 2010. Unused portions may be carried forward until December 31, 2010. It is anticipated that the issuance of 21,100,000 trust units on December 8, 2006 for proceeds of $461 million will constitute a portion of the 40 percent normal growth limit for the period ending on December 31, 2007.

Pursuant to the draft legislation, the distribution tax will only apply in respect of distributions of income and will not apply to returns of capital.

If the October 31 Proposals are implemented, the Trust would be required to recognize, on a prospective basis, future income taxes on temporary differences in the Trust.

Foreign Currency Gains and Losses

Pengrowth recorded an immaterial net foreign exchange loss in 2006, compared to a foreign exchange gain of $7.0 million in 2005. Included in the 2006 loss is a $0.5 million unrealized foreign exchange loss compared to a $7.8 million unrealized foreign exchange gain related to the U.S. dollar denominated debt and the closing exchange rate at the end of each year. 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 changes in the Canadian dollar relative to the U.S. dollar over the course of the year, a foreign exchange gain 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 are received in U.S. dollars. Pengrowth has arranged a portion of its long term debt in U.S. dollars as a natural hedge against changes in the 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. (See note 16 to the financial statements for further detail).

Pengrowth has mitigated the foreign exchange risk on the interest and principal payments related to the U.K. denominated notes (see Note 10 of the financial statements) by using foreign exchange swaps. As a result of applying hedge accounting to this transaction, an unrealized foreign exchange loss of $13.9 million has been included in Other Assets as at December 31, 2006.



Depletion, Depreciation and Accretion

Three months ended Twelve months ended
---------------------------------------------------------------------------
Dec 31, Sept 30, Dec 31, Dec 31, Dec 31,
($ millions) 2006 2006 2005 2006 2005
---------------------------------------------------------------------------

Depletion and Depreciation 129.2 83.5 71.4 351.6 285.0
$ per boe 18.09 15.56 12.63 15.33 13.15
Accretion 4.9 4.5 3.6 16.6 14.2
$ per boe 0.68 0.84 0.64 0.72 0.65
---------------------------------------------------------------------------


Depletion and depreciation of property, plant and equipment is provided on the unit of production method based on total proved reserves. The increase in 2006 rates for both depletion and depreciation and accretion is due to the inclusion of the property, plant and equipment from the Carson Creek and Esprit Trust acquisitions.

Pengrowth's Asset Retirement Obligations (ARO) liability increases by the amount of accretion, which is a charge to net income as a result of the passage of time. The accretion expense is based on a credit adjusted risk-free rate of eight percent per year.

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 2006.

Asset Retirement Obligations

The total future ARO is estimated by management based on estimated costs to remediate, reclaim and abandon wells and facilities based on Pengrowth's working interest 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 $255 million as at December 31, 2006 (2005 - $185 million), based on a total escalated future liability of $1,530 million (2005 - $1,041 million). These costs are expected to be incurred over 50 years with the majority of the costs incurred between 2035 and 2054. Pengrowth's credit adjusted risk free rate of eight percent (2005 - eight percent) and an inflation rate of two percent (2005 - two percent) were used to calculate the net present value of the ARO.

Remediation Trust Funds & Remediation and Abandonment Expenses

During 2006, Pengrowth contributed $3.2 million into trust funds established to fund certain abandonment and reclamation costs associated with Judy Creek and SOEP. The balance in these remediation trust funds was $11.1 million at December 31, 2006.

Pengrowth takes a proactive approach to managing its well abandonment and site restoration obligations. There is an on-going program to abandon wells and reclaim well and facility sites. In 2006, Pengrowth spent $9.1 million on abandonment and reclamation (2005 - $7.4 million). Pengrowth expects to spend approximately $14.5 million per year, prior to inflation, excluding contributions to remediation trust funds, over the next ten years on remediation and abandonment.

Other Expenses

On a year-over-year basis, other expenses increased $6.2 million primarily due to costs related to the consolidation of Class A and Class B trust units ($2.7 million) completed in July 2006 and one time legal fees from a predecessor company ($2.7 million).

Goodwill

As at December 31, 2006, Pengrowth recorded goodwill of $598.3 million, an increase of $415.5 million from December 31, 2005. In accordance with Canadian GAAP, Pengrowth recorded goodwill of $129.7 million and $285.7 million upon the Carson Creek area acquisition and the Esprit Trust business combination, respectively, in 2006. 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 acquisitions are provided in Note 3 of the financial statements. Management has assessed goodwill for impairment and determined there is no impairment at December 31, 2006.

Capital Expenditures

During 2006, Pengrowth spent $300.8 million on development and optimization activities. This year's capital program was one of Pengrowth's most successful to date and resulted in the replacement of approximately 99 percent of production through internal development. The largest expenditures were at Judy Creek ($42.5 million), SOEP ($22.4 million), Weyburn ($20.2 million), Twining ($18.2 million), Bodo ($14.2 million), Three Hills Creek ($13.8 million), Quirk Creek ($13.0 million), West Pembina ($9.7 million), Olds ($8.5 million) and Prespatou ($6.6 million). Pengrowth engages in limited exploration activities and in 2006 most of the capital spent on development was directed towards increasing production and improving reserve recovery through infill drilling. An additional $1,449.3 million was incurred in 2006 to complete the Esprit Trust, Carson Creek, Dunvegan Unit and other acquisitions compared to $180.5 million to complete the Crispin and Swan Hills acquisitions in 2005.



Three months ended Twelve months ended
---------------------------------------------------------------------------
Dec 31, Sept 30, Dec 31, Dec 31, Dec 31,
($ millions) 2006 2006 2005 2006 2005
---------------------------------------------------------------------------

Geological and geophysical 6.1 0.5 - 8.9 1.4
Drilling and completions 83.6 42.2 41.1 217.1 130.3
Plant and facilities 26.6 9.4 10.2 56.9 34.1
Land purchases 5.5 4.7 8.8 17.9 9.9
---------------------------------------------------------------------------
Development capital 121.8 56.8 60.1 300.8 175.7
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Cash costs for business
acquisitions 4.8 475.6 (0.6) 500.5 0.9
Cash costs for property
acquisitions 0.5 (1.7) (1.3) 52.9 91.6
Value of trust units issued
for acquisitions 895.9 - - 895.9 88.0
---------------------------------------------------------------------------
Total value of cash & trust
units issued for
acquisitions 901.2 473.9 (1.9) 1,449.3 180.5
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Total capital expenditures
and acquisitions 1,023.0 530.7 58.2 1,750.1 356.2
---------------------------------------------------------------------------


Pengrowth currently anticipates capital expenditures for maintenance and development opportunities at existing properties of approximately $275 million for 2007. Two thirds of the 2007 capital program is expected to be spent on the drilling program and the remainder of the budget is expected to be spent on facility maintenance and optimization and land and seismic purchases.

In addition to the 2007 capital development program, Pengrowth expects to invest $25 million to prepare its new head office building.

Reserves

Pengrowth reported year-end proved reserves of 225.9 mmboe and proved plus probable reserves of 297.8 mmboe compared to 175.6 mmboe and 219.4 mmboe at year end 2005. Further details of Pengrowth's 2006 year-end reserves are provided in this release, the annual report and AIF.

Acquisitions and Dispositions

On October 2, 2006 Pengrowth and Esprit Trust completed the business combination of Pengrowth and Esprit Trust (the "Combination"). Under the terms of the Combination agreement, each Esprit Trust unit was exchanged for 0.53 of a Pengrowth trust unit. As a result of the Combination, approximately 34,725,157 Pengrowth trust units were issued to Esprit Trust unitholders. (See Note 3 of the financial statements.)

On September 28, 2006, Pengrowth acquired from ExxonMobil Canada all of the issued and outstanding shares of a company which had interests in oil and natural gas assets in the Carson Creek area of Alberta and the adjacent Carson Creek Gas Plant for $475 million prior to adjustments.

On March 30, 2006, Pengrowth closed the acquisition of an additional working interest in the Dunvegan Unit as well as some minor oil and gas properties in central Alberta for approximately $48 million.

On January 12, 2006, Pengrowth divested non-core oil and gas properties for consideration of $22 million of cash, prior to adjustments, and approximately eight million shares in Monterey. Pengrowth holds approximately 34 percent of the common shares of Monterey.

Working Capital

Working capital declined $37.7 million from a working capital deficiency of $112.2 million at December 31, 2005 to a working capital deficiency of $149.9 million as at December 31, 2006. Most of the increased working capital deficiency is attributable to an increase in accounts payable and accrued liabilities and distributions payable to unitholders, offset by an increase in accounts receivable as at December 31, 2006.

Pengrowth frequently operates with a working capital deficiency as a result of the fact that distributions related to two production months of operating income are payable to unitholders at the end of any month, but only one month of production is still receivable. For example, at the end of December, distributions related to November and December production months were payable on January 15 and February 15, respectively. November's production revenue, received on December 25, is temporarily applied against Pengrowth's term credit facility until the distribution payment on January 15.



Financial Resources and Liquidity
Pengrowth's capital structure is as follows:

As at As at
December 31 December 31
($ thousands) 2006 2005
---------------------------------------------------------------------------

Term credit facilities 257,000 35,000
Senior unsecured notes 347,200 333,089
Working capital deficit 140,563 77,638
Note payable - 20,000
Bank indebtedness 9,374 14,567
---------------------------------------------------------------------------
Net debt excluding convertible debentures 754,137 480,294
---------------------------------------------------------------------------

Convertible debentures 75,127 -
---------------------------------------------------------------------------
Net debt including convertible debentures 829,264 480,294
---------------------------------------------------------------------------

Unitholders' equity 3,049,677 1,475,996

Net debt excluding convertible debentures as a
percentage of total book capitalization 19.8% 24.6%
Net debt including convertible debentures as a
percentage of total book capitalization 21.4% 24.6%
---------------------------------------------------------------------------
Cash flow from operating activities 554,368 618,070

Net debt excluding convertible debentures to cash
flow from operating activities 1.4 0.8
Net debt including convertible debentures to cash
flow from operating activities 1.5 0.8
---------------------------------------------------------------------------


The $222 million increase in the term credit facilities as at December 31, 2006 from December 31, 2005 is primarily due to capital expenditures, acquisitions including assumed debt, deposit on the CP Properties acquisition, repayment of the SOEP note payable and redemption of convertible debentures all of which exceeds cash withheld, proceeds from the Monterey transaction and net proceeds from the equity offerings that closed September 28, 2006 and December 8, 2006.

Pengrowth funds its capital expenditures through a combination of cash withholdings, available credit from its bank credit facilities and proceeds from exercise of trust unit rights and the distribution reinvestment plan. The credit facility and other sources of cash are expected to be sufficient to meet Pengrowth's near term capital requirements and provide the flexibility to pursue profitable growth opportunities. A significant decline in oil and natural gas prices could impact our access to bank credit facilities and our ability to fund operations and maintain distributions.

At December 31, 2006, Pengrowth maintained a $950 million term credit facility and a $35 million demand operating line of credit. These facilities were reduced by drawings of $257 million and by $18 million in letters of credit outstanding at year end. Pengrowth remains well positioned to fund its 2007 development program and to take advantage of acquisition opportunities as they arise. At December 31, 2006, Pengrowth had approximately $700 million available to draw from its credit facilities.

Pengrowth does not have any off balance sheet financing arrangements.

Pengrowth's U.S. $200 million senior unsecured notes, Pound sterling denominated 50 million senior unsecured notes, and the term credit facilities have certain financial covenants which may restrict the total amount of Pengrowth's borrowings. The calculation for each ratio is based on specific definitions, is not in accordance with GAAP and cannot be readily replicated by referring to Pengrowth's financial statements. The financial covenants are different between the term credit facilities and the senior unsecured notes and some of the covenants are summarized below:

1. Total senior debt should not be greater than three times Earnings Before Income Taxes Depreciation and Amortization (EBITDA) for the last four fiscal quarters.

2. Total debt should not be greater than 3.5 times EBITDA for the last four fiscal quarters.

3. Total senior debt should be less than 50 percent of total book capitalization.

4. EBITDA should not be less than four times interest expense.

In the event that Pengrowth enters into a significant acquisition, certain credit facility financial covenants are relaxed for two fiscal quarters after the close of the acquisition. Pengrowth may also make certain pro forma adjustments in calculating the financial covenant ratios.

The actual loan documents are filed on SEDAR as Other Material Contracts. As at December 31, 2006, Pengrowth was in compliance with all its financial covenants. Failing a financial covenant may result in one or more of Pengrowth's loans being in default. In certain circumstances, being in default of one loan may result in other loans to also be in default. In the event that Pengrowth was not in compliance with any of the financial covenants in its credit facility or senior unsecured notes, Pengrowth would be in default of one or more of its loans and would have to repay the debt, refinance the debt or negotiate new terms with the debt holders and may have to suspend distributions to unitholders.

As a result of the October 2, 2006 business combination with Esprit Trust, Pengrowth assumed all of Esprit Trust's 6.5 percent convertible unsecured subordinated debentures (the "debentures"). The debentures were originally issued on July 28, 2005 for a $100 million principal amount with interest paid semi-annually in arrears on June 30 and December 31 of each year. At October 2, 2006, $95.8 million principal amount of debentures was outstanding. Each $1,000 principal amount of debentures is convertible at the option of the holder at any time into fully paid Pengrowth trust units at a conversion price of $25.54 per trust unit. The debentures mature on December 31, 2010. After December 31, 2008, Pengrowth may elect to redeem all or a portion of the outstanding debentures at a price of $1,050 per debenture or $1,025 per debenture after December 31, 2009. Pursuant to a change of control provision in the Debenture Indenture, Pengrowth was required to make an offer to purchase all of the outstanding debentures at a price equal to 101 percent of the principal amount, plus any accrued and unpaid interest. The amount of accrued interest paid on the redemption was $0.6 million. On December 12, 2006, Pengrowth redeemed the tendered debentures for cash proceeds of $21.8 million (including accrued interest and offer premium). As at December 31, 2006, the principal amount of debentures outstanding was $74.7 million.

Distributable Cash and Distributions

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 and payout ratio:



($ thousands, except per trust unit amounts)

Three months ended Twelve months ended
---------------------------------------------------------------------------
Dec 31, Sept 30, Dec 31, Dec 31, Dec 31,
2006 2006 2005 2006 2005
---------------------------------------------------------------------------
Cash flows from operating
activities 91,237 179,971 196,588 554,368 618,070
Change in non-cash
operating working capital 50,714 (37,028) (7,993) 24,331 (9,833)
---------------------------------------------------------------------------
Funds generated from
operations 141,951 142,943 188,595 578,699 608,237
Change in remediation
trust funds (1,546) (599) 784 (2,815) (20)
---------------------------------------------------------------------------
Distributable cash 140,405 142,344 189,379 575,884 608,217
---------------------------------------------------------------------------

Distributions paid or
declared 185,651 132,513 119,858 559,063 445,977
Distributable cash per
trust unit 0.64 0.88 1.19 3.27 3.87
Distributions paid or
declared per trust unit 0.75 0.75 0.75 3.00 2.82
Payout ratio (1) 132% 93% 63% 97% 73%
---------------------------------------------------------------------------

(1) Payout ratio is calculated as distributions paid or declared divided by
distributable cash


Pengrowth does not deduct capital expenditures when calculating distributable cash (2006 - $300.8 million, 2005 - $175.7 million). As a result of the depleting nature of Pengrowth's oil and natural gas assets, some level of capital expenditures is required to minimize production declines while other capital is required to optimize facilities. While Pengrowth does deduct actual expenditures on ARO and contributions to remediation trust funds, no deduction is made for future remediation commitments or accretion expense charged to the ARO reported on the balance sheet as those obligations will be funded out of cash flow generated in the future. Pengrowth's calculation of distributable cash also adds back changes in operating working capital. In times of commodity price volatility, including working capital changes results in cash flows from operations which may be inconsistent with actual results. Pengrowth calculates and presents distributable cash to provide investors with a measure of the changes in cash available to be distributed to unitholders. As a result of the volatility in commodity prices and changes in production levels, Pengrowth may not report the same amount of distributable cash in each period and may temporarily borrow funds to maintain distributions.

Distributable cash is derived from producing and selling oil, natural gas and related products. As such, distributable cash is highly dependent on commodity prices. Pengrowth enters into forward commodity contracts to fix the commodity price and mitigate price volatility on a portion of its 2007 and 2008 sales volumes. Details of commodity contracts are contained in Note 20 to the financial statements.

The Board of Directors and Management regularly monitor forecasted distributable cash and payout ratio. The Board considers a number of factors, including expectations of future commodity prices, capital expenditure requirements, and the availability of debt and equity capital. Pursuant to the Royalty Indenture, the Board can establish a reserve for certain items including up to 20 percent of the Corporation's gross revenue to fund various costs including future capital expenditures, royalty income in any future period and future abandonment costs.

In 2006, Pengrowth paid out or declared 97 percent of its distributable cash as distributions to unitholders and 132 percent in the fourth quarter. The payout ratio in the fourth quarter reflects distributions paid out or declared on units issued for the acquisition of Esprit Trust and for the acquisition of the CP Properties. However, due to the usual delays in receiving cash flow from production as well as the early 2007 closing of the CP Properties acquisition, the corresponding cash flow is not reflected in operating results.
Cash distributions are paid to unitholders on the 15th day of the second month following the month of production. Pengrowth paid $0.75 per trust unit as cash distributions during the fourth quarter of 2006 and $3.00 for the full year of 2006.



The following is a summary of recent monthly distributions and future key
dates:

Distribution
Amount
Ex-Distribution Distribution per Trust US $
Date (1) Record Date Payment Date Unit Amount(2)
---------------------------------------------------------------------------
December 27, 2006 December 29, 2006 January 15, 2007 $0.25 $0.21
January 30, 2007 February 1, 2007 February 15, 2007 $0.25 $0.21
February 27, 2007 March 1, 2007 March 15, 2007 $0.25 $0.21
March 28, 2007 March 30, 2007 April 15, 2007
April 27, 2007 May 1, 2007 May 15, 2007
May 30, 2007 June 1, 2007 June 15, 2007
June 27, 2007 June 29, 2007 July 15, 2007
July 27, 2007 July 31, 2007 August 15, 2007
August 29, 2007 August 31, 2007 September 15, 2007
September 26, 2007 September 28, 2007 October 15, 2007
October 30, 2007 November 1, 2007 November 15, 2007
November 29, 2007 December 3, 2007 December 15, 2007

(1) To benefit from the monthly cash distribution, unitholders must
purchase or hold trust units prior to the ex-distribution date.
(2) Before applicable withholding taxes.


Taxability of Distributions

The following discussion relates to the taxation of Canadian unitholders only. For detailed tax information relating to non-residents, please refer to our website www.pengrowth.com. Cash distributions are comprised of a return of capital portion, which is tax deferred, and return on capital portion which is taxable income. The return of capital portion reduces the cost base of a unitholders trust units for purposes of calculating a capital gain or loss upon ultimate disposition.

At this time, Pengrowth anticipates that approximately 90 to 95 percent of 2007 distributions will be taxable to Canadian residents. This estimate is subject to change depending on a number of factors including, but not limited to, the level of commodity prices, acquisitions, dispositions, and new equity offerings.




Commitments and Contractual Obligations

---------------------------------------------------------------------------
($ thousands) 2007 2008 2009 2010 2011 thereafter Total
---------------------------------------------------------------------------
Long term debt (1) - - 257,000 174,810 - 158,759 590,569
Interest payments
on long term
debt (2) 30,172 30,172 23,202 11,585 8,704 25,538 129,373
Convertible
debentures (3) - - - 74,741 - - 74,741
Interest payments
on convertible
debentures (4) 4,858 4,858 4,858 4,858 - - 19,432
Other (5) 7,350 7,387 6,494 6,019 5,790 35,923 68,963
---------------------------------------------------------------------------
42,380 42,417 291,554 272,013 14,494 220,220 883,078
Purchase
obligations
Pipeline
transportation 47,959 42,215 33,317 18,758 18,207 59,589 220,045
CO2 purchases
(6) 7,651 5,845 4,232 4,267 3,772 14,876 40,643
---------------------------------------------------------------------------
55,610 48,060 37,549 23,025 21,979 74,465 260,688
Remediation trust
fund payments 250 250 250 250 250 11,750 13,000
---------------------------------------------------------------------------
98,240 90,727 329,353 295,288 36,723 306,435 1,156,766
---------------------------------------------------------------------------
---------------------------------------------------------------------------

(1) The debt repayment includes the principal owing at maturity on
foreign denominated fixed rate debt. (see Note 9 of the financial
statements).
(2) Interest payments relate to the interest payable on foreign denominated
fixed rate debt using the year end exchange rate.
(3) Includes repayment of convertible debentures on maturity (see Note 9
of the financial statements), and assumes no conversion of
convertible debentures to trust units.
(4) Includes annual interest on convertible debentures outstanding at
Year end and assumes no conversion of convertible debentures prior to
maturity.
(5) Includes office rent and other vehicle leases.
(6) For the Weyburn CO2 (project, prices are denominated in U.S. dollars
and have been translated at the year end) exchange rate. (For the Judy
Creek CO2 (pilot project, prices are denominated in Canadian dollars.)


Summary of Quarterly Results
The following table is a summary of quarterly results for 2006 and 2005.

---------------------------------------------------------------------------
2006 Q1 Q2 Q3 Q4
---------------------------------------------------------------------------
Oil and gas sales ($000's) 291,896 283,532 287,757 350,908
Net income ($000's) 66,335 110,116 82,542 3,310
Net income per trust unit ($) 0.41 0.69 0.51 0.01
Net income per trust unit - diluted ($) 0.41 0.68 0.51 0.01
Distributable cash ($000's) 140,869 152,266 142,344 140,405
Actual distributions paid or declared
per trust unit ($) 0.75 0.75 0.75 0.75
Daily production (boe) 58,845 56,325 58,344 77,614
Total production (mboe) 5,296 5,126 5,368 7,141
Average realized price ($ per boe) 55.04 54.91 53.67 49.24
Operating netback ($ per boe) 31.44 33.94 30.82 24.17

---------------------------------------------------------------------------
2005 Q1 Q2 Q3 Q4
---------------------------------------------------------------------------
Oil and gas sales ($000's) 239,913 253,189 304,484 353,923
Net income ($000's) 56,314 53,106 100,243 116,663
Net income per trust unit ($) 0.37 0.34 0.63 0.73
Net income per trust unit - diluted ($) 0.37 0.34 0.63 0.73
Distributable cash ($000's) 126,144 134,779 157,195 189,379
Actual distributions paid or declared
per trust unit ($) 0.69 0.69 0.69 0.75
Daily production (boe) 59,082 57,988 58,894 61,442
Total production (mboe) 5,317 5,277 5,418 5,653
Average realized price ($ per boe) 44.97 47.79 56.07 62.55
Operating netback ($ per boe) 27.70 29.26 33.94 38.81
---------------------------------------------------------------------------


Selected Annual Information Financial Results


Twelve months ended December 31
---------------------------------------------------------------------------
($ thousands) 2006 2005 2004
---------------------------------------------------------------------------
Oil and gas sales (1) 1,214,093 1,151,510 815,751
Net income 262,303 326,326 153,745
Net income per trust unit 1.49 2.08 1.15
Net income per trust unit - diluted 1.49 2.07 1.15
Distributable cash (2) 575,886 608,217 402,077
Actual distributions paid or declared
per trust unit 3.00 2.82 2.63
Total assets 4,669,972 2,391,432 2,276,534
Long term debt (3) 679,327 368,089 365,400
Unitholders' equity 3,049,677 1,475,996 1,462,211

Number of trust units outstanding
at year end (thousands) 244,017 159,864 152,973

(1) 2004 restated as a result of a change in 2005 presentation.
(2) Prior years restated to conform to presentation adopted in the current
Year.
(3) Includes long term debt, long term portion of note payable and
convertible debentures.


Business Risks

The amount of distributable cash available to unitholders and the value of Pengrowth trust units are subject to numerous risk factors. As the trust units allow investors to participate in the net cash flow from Pengrowth's portfolio of producing oil and natural gas properties, the principal risk factors that are associated with the oil and gas business include, but are not limited to, the following influences:

- The prices of Pengrowth's products (crude oil, natural gas, and NGLs) fluctuate due to many factors including local and global market supply and demand, weather patterns, pipeline transportation and political stability.

- The marketability of our production depends in part upon the availability, proximity and capacity of gathering systems, pipelines and processing facilities. Operational or economic factors may result in the inability to deliver our products to market.

- Geological and operational risks affect the quantity and quality of reserves and the costs of recovering those reserves. Our actual results will vary from our reserve estimates and those variations could be material.

- Government royalties, income taxes, commodity taxes and other taxes, levies and fees have a significant economic impact on Pengrowth's financial results. Changes to federal and provincial legislation including implementation of the October 31 Proposals governing such royalties, taxes and fees could have a material impact on Pengrowth's financial results and the value of Pengrowth trust units.

- Oil and natural gas operations carry the risk of damaging the local environment in the event of equipment or operational failure. The cost to remediate any environmental damage could be significant.

- Environmental laws and regulatory initiatives impact Pengrowth financially and operationally. We may incur substantial capital and operating expenses to comply with increasingly complex laws and regulations covering the protection of the environment and human health and safety. In particular, we may be required to incur significant costs to comply with future regulations to reduce greenhouse gas and other emissions.

- Pengrowth's oil and gas reserves will be depleted over time and our level of distributable cash and the value of our trust units could be reduced if reserves and production are not replaced. The ability to replace production depends on Pengrowth's success in developing existing reserves, acquiring new reserves and financing this development and acquisition activity within the context of the capital markets. Additional uncertainty with new legislation may limit access to capital or increase the cost of raising capital.

- Increased competition for properties will drive the cost of acquisitions up and expected returns from the properties down.

- A significant portion of our properties are operated by third parties. If these operators fail to perform their duties properly, or become insolvent, we may experience interruptions in production and revenues from these properties or incur additional liabilities and expenses as a result of the default of these third party operators.

- Increased activity within the oil and gas sector has increased the cost of goods and services and makes it more difficult to hire and retain professional staff.

- Changing interest rates influence borrowing costs and the availability of capital.

- Investors' interest in the oil and gas sector may change over time which would affect the availability of capital and the value of Pengrowth trust units.

- Inflation may result in escalating costs which could impact unitholder distributions and the value of Pengrowth trust units.

- Canadian / U.S. exchange rates influence revenues and, to a lesser extent, operating and capital costs.

- The value of Pengrowth trust units is impacted directly by the related tax treatment of the trust units and the trust unit distributions, and indirectly by the tax treatment of alternative equity investments. Changes in Canadian or U.S. tax legislation could adversely affect the value of our trust units.

These factors should not be considered to be exhaustive. Additional risks are outlined in the AIF of the Trust available on SEDAR at www.sedar.com on or before March 31, 2007.

Subsequent Events

On January 22, 2007 Pengrowth closed the acquisition of four subsidiaries of Burlington Resources Canada Ltd., a subsidiary of ConocoPhillips, holding Canadian oil and natural gas producing properties and undeveloped lands (the "CP Properties") for a purchase price of $1.0375 billion, prior to adjustments. The acquisition of the CP Properties was funded in part by the December 8, 2006 equity offering of approximately $461 million with the remainder supported by a $600 million bank credit facility maturing January 22, 2008.

Subsequent to December 31, 2006, Pengrowth has entered into a series of fixed price commodity sales contracts with third parties that are detailed in Note 22 to the financial statements.

Outlook

At this time, Pengrowth is forecasting average 2007 production of 83,000 to 87,500 boe per day from our existing properties. This estimate incorporates production from the acquisition disclosed in the subsequent event section of this discussion. This estimate takes into account the expected divestiture during 2007 of approximately 7,700 boe per day of current production. The above estimate excludes the impact from other future acquisitions or divestitures.

Pengrowth's total operating expenses for 2007 are expected to increase when compared to 2006 and are anticipated to total approximately $405 million or $13.00 per boe.

General and administrative expenses per boe are expected to decrease in 2007 when compared to 2006. This per boe decrease is mainly attributable to a higher production base and lower management fees. On a per boe basis, G&A is anticipated to be approximately $1.95, which includes management fees of approximately $0.40 per boe.

The Board of Directors and Management regularly monitor forecasted distributable cash and payout ratio. The Board considers a number of factors, including expectations of future commodity prices, capital expenditure requirements and the availability of debt and equity capital. Pursuant to the Royalty Indenture, the Board can establish a reserve for certain items including up to 20 percent of the Corporation's gross revenue to fund various costs including future capital expenditures, royalty income in any future period and future abandonment costs.

Pengrowth currently anticipates capital expenditures for maintenance and development opportunities at existing properties of approximately $275 million for 2007. Two thirds of the 2007 capital program is expected to be spent on the drilling program and the remainder of the budget is expected to be spent on facility maintenance and optimization and land and seismic purchases. In addition to the 2007 capital development program, Pengrowth expects to invest $25 million to prepare its new head office building.

Recent Accounting Pronouncement

Effective January 1, 2007, Pengrowth will be required to adopt several new and revised standards issued by the Canadian Institute of Chartered Accountants in January 2005 related to Financial Instruments. Under the new standards, a Statement of Comprehensive Income has been introduced that will provide for certain gains and losses and other amounts arising from changes in fair value to be temporarily recorded outside the income statement. In addition, all financial instruments including derivatives are to be included on the balance sheet and measured at fair values in most instances. The requirements for hedge accounting have also been further clarified under the revised standards. Pengrowth is currently evaluating the impact of the new standards. Management does not anticipate the new and revised standards to have a material impact on its consolidated financial statements as Pengrowth currently uses fair value accounting for derivative instruments that do not qualify or are not designated as hedges.

Disclosure Controls and Procedures

As a Canadian reporting issuer with securities listed on both the TSX and the NYSE, Pengrowth is required to comply with Multilateral Instrument 52-109 - Certification of Disclosure in Issuers' Annual and Interim Filings, as well as the Sarbanes Oxley Act (SOX) enacted in the United States. Both the Canadian and U.S. certification rules include similar requirements where both the Chief Executive Officer and the Chief Financial Officer must assess and certify as to the effectiveness of the disclosure controls and procedures as defined in Canada by Multilateral Instrument 52-109 Certification of Disclosure in Issuers' Annual and Interim Filings and in the United States by Rules 13a-15(e) and 15d-15(e) under the Securites Exchange Act of 1934, as amended.

The Chief Executive Officer, James S. Kinnear, and the Chief Financial Officer, Christopher Webster, evaluated the effectiveness of Pengrowth's disclosure controls and procedures for the period ending December 31, 2006. This evaluation considered the functions performed by its Disclosure Committee, the review and oversight of all executive officers and the board, as well as the process and systems in place for filing regulatory and public information. Pengrowth's established review process and disclosure controls are designed to ensure that all required information, reports and filings required under Canadian securities legislation and United States securities laws are properly submitted and recorded in accordance with those requirements.

Based on that evaluation, the CEO and CFO concluded that the design and operation of our disclosure controls and procedures were effective as at December 31, 2006 to ensure that information required to be disclosed by us in reports that we file under Canadian and U.S. securities laws is gathered, recorded, processed, summarized and reported within the time periods specified under Canadian and U.S. securities laws and is accumulated and communicated to the management of Pengrowth Corporation, including the CEO and CFO, to allow timely decisions regarding required disclosure as required under Canadian and U.S. securities laws.

CONFERENCE CALL INFORMATION

Pengrowth will hold a conference call beginning at 9:00 A.M. Mountain Time on Tuesday, February 27, 2007 during which management will review Pengrowth's financial, operating and reserve results for the year ended December 31, 2006 and respond to inquiries from the investment community.

To participate callers may dial (800) 732-0232 or Toronto local (416) 644-3425. To ensure timely participation in the teleconference, callers are encouraged to dial in 10 to 15 minutes prior to commencement of the call to register. A live audio webcast will be accessible through the Webcast and Multimedia Centre section of Pengrowth's website at www.pengrowth.com. The webcast will be archived on the Pengrowth website. A telephone replay will be available through to midnight Eastern Time on Tuesday, March 6, 2007 by dialling (877) 289-8525 or Toronto local (416) 640-1917 and entering passcode number 21217144#.



Consolidated Balance Sheet

(Stated in thousands of dollars)
As at As at
December 31 December 31
2006 2005
---------------------------------------------------------------------------
(unaudited) (audited)

ASSETS
CURRENT ASSETS
Accounts receivable $ 151,719 $ 127,394
Fair value of commodity contracts (Note 20) 37,972 -
---------------------------------------------------------------------------
---------------------------------------------------------------------------
189,691 127,394

FAIR VALUE OF COMMODITY CONTRACTS (Note 20) 495 -

DEPOSIT ON ACQUISITION (Note 22) 103,750 -

OTHER ASSETS (Note 4) 29,097 13,215

EQUITY INVESTMENT (Note 5) 7,035 -

PROPERTY, PLANT AND EQUIPMENT (Note 6) 3,741,602 2,067,988

GOODWILL (Note 3) 598,302 182,835
---------------------------------------------------------------------------
---------------------------------------------------------------------------

$ 4,669,972 $ 2,391,432
---------------------------------------------------------------------------
---------------------------------------------------------------------------

LIABILITIES AND UNITHOLDERS' EQUITY
CURRENT LIABILITIES
Bank indebtedness $ 9,374 $ 14,567
Accounts payable and accrued liabilities 201,056 111,493
Distributions payable to unitholders 122,080 79,983
Due to Pengrowth Management Limited 2,101 8,277
Other liabilities (Notes 7 and 8) 5,017 25,279
---------------------------------------------------------------------------
---------------------------------------------------------------------------
339,628 239,599

FAIR VALUE OF COMMODITY CONTRACTS (Note 20) 1,367 -

CONTRACT LIABILITIES (Note 8) 16,825 12,937

CONVERTIBLE DEBENTURES (Note 9) 75,127 -

LONG TERM DEBT (Note 10) 604,200 368,089

ASSET RETIREMENT OBLIGATIONS (Note 11) 255,331 184,699

FUTURE INCOME TAXES (Note 12) 327,817 110,112

TRUST UNITHOLDERS' EQUITY (Note 13)
Trust unitholders' capital 4,383,993 2,514,997
Equity portion of convertible debentures 160 -
Contributed surplus 4,931 3,646
Deficit (Note 15) (1,339,407) (1,042,647)
---------------------------------------------------------------------------
---------------------------------------------------------------------------
3,049,677 1,475,996
---------------------------------------------------------------------------
---------------------------------------------------------------------------

COMMITMENTS (Note 21)
SUBSEQUENT EVENTS (Note 22)
$ 4,669,972 $ 2,391,432
---------------------------------------------------------------------------

See accompanying notes to the consolidated financial statements.


Consolidated Statements of Income and Deficit

(Stated in thousands of dollars)
Years ended
December 31
2006 2005
---------------------------------------------------------------------------
---------------------------------------------------------------------------
(unaudited) (audited)

REVENUES
Oil and gas sales $ 1,214,093 $ 1,151,510
Processing and other income 15,639 15,091
Royalties, net of incentives (241,494) (213,863)
---------------------------------------------------------------------------
---------------------------------------------------------------------------
988,238 952,738
Interest and other income 3,129 2,596
---------------------------------------------------------------------------
---------------------------------------------------------------------------
NET REVENUE 991,367 955,334

EXPENSES
Operating 270,519 218,115
Transportation 7,621 7,891
Amortization of injectants for miscible floods 34,644 24,393
Interest 32,109 21,642
General and administrative 36,613 30,272
Management fee 9,941 15,961
Foreign exchange (gain) loss (Note 16) 22 (6,966)
Depletion and depreciation 351,575 284,989
Accretion (Note 11) 16,591 14,162
Unrealized gain on commodity contracts
(Note 20) (26,499) -
Other expenses 10,183 4,029
---------------------------------------------------------------------------
---------------------------------------------------------------------------
743,319 614,488
---------------------------------------------------------------------------
---------------------------------------------------------------------------

INCOME BEFORE TAXES 248,048 340,846

INCOME TAX EXPENSE (REDUCTION) (Note 12)
Capital 14 2,244
Future (14,269) 12,276
---------------------------------------------------------------------------
(14,255) 14,520
---------------------------------------------------------------------------

NET INCOME $ 262,303 $ 326,326
---------------------------------------------------------------------------
---------------------------------------------------------------------------

Deficit, beginning of year (1,042,647) (922,996)

Distributions paid or declared (559,063) (445,977)
---------------------------------------------------------------------------
---------------------------------------------------------------------------

DEFICIT, END OF YEAR $ (1,339,407) $ (1,042,647)
---------------------------------------------------------------------------

NET INCOME PER TRUST UNIT (Note 19) Basic $ 1.49 $ 2.08

Diluted $ 1.49 $ 2.07
---------------------------------------------------------------------------

See accompanying notes to the consolidated financial statements.


Consolidated Statements of Cash Flow

(Stated in thousands of dollars)
Years ended
December 31
2006 2005
---------------------------------------------------------------------------
---------------------------------------------------------------------------
(unaudited) (audited)

CASH PROVIDED BY (USED FOR):

OPERATING
Net income $ 262,303 $ 326,326
Depletion, depreciation and accretion 368,166 299,151
Future income taxes (reduction) (14,269) 12,276
Contract liability amortization (5,447) (5,795)
Amortization of injectants 34,644 24,393
Purchase of injectants (34,630) (34,658)
Expenditures on remediation (9,093) (7,353)
Other non-cash items (66) -
Unrealized foreign exchange (gain) loss
(Note 16) 480 (7,800)
Unrealized gain on fair value of commodity
contracts (Note 20) (26,499) -
Trust unit based compensation (Note 14) 2,546 2,932
Deferred charges (5,081) (4,961)
Amortization of deferred charges 5,645 3,726
Changes in non-cash operating working capital
(Note 17) (24,331) 9,833
---------------------------------------------------------------------------
---------------------------------------------------------------------------
554,368 618,070
---------------------------------------------------------------------------
---------------------------------------------------------------------------

FINANCING
Distributions paid (516,966) (436,450)
Bank indebtedness 9,374 -
Change in long term debt, net (54,870) 10,030
Redemption of convertible debentures (Note 9) (21,184) -
Repayment of note payable (Note 7) (20,000) (15,000)
Proceeds from issue of trust units 971,791 42,544
---------------------------------------------------------------------------
---------------------------------------------------------------------------
368,145 (398,876)
---------------------------------------------------------------------------
---------------------------------------------------------------------------

INVESTING
Business acquisitions (Note 3) (500,451) (935)
Property acquisitions (52,880) (91,633)
Expenditures on property, plant and equipment (300,809) (175,693)
Proceeds on property dispositions 15,230 37,617
Deposit on acquisition (Note 22) (103,750) -
Change in remediation trust fund (Note 11) (2,815) (20)
Change in non-cash investing working capital
(Note 17) 37,529 1,117
---------------------------------------------------------------------------
---------------------------------------------------------------------------
(907,946) (229,547)
---------------------------------------------------------------------------
---------------------------------------------------------------------------

CHANGE IN CASH (BANK INDEBTEDNESS) 14,567 (10,353)

CASH (BANK INDEBTEDNESS) AT BEGINNING OF YEAR (14,567) (4,214)
---------------------------------------------------------------------------
---------------------------------------------------------------------------

CASH (BANK INDEBTEDNESS) AT END OF YEAR $ - $ (14,567)
---------------------------------------------------------------------------
---------------------------------------------------------------------------

See accompanying notes to the consolidated financial statements.

PENGROWTH ENERGY TRUST

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2006 AND 2005
(Tabular amounts are stated in thousands of dollars except per trust unit
amounts)

(Unaudited)


1. STRUCTURE OF THE TRUST

Pengrowth Energy Trust (the "Trust") 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 Trust Company of Canada (Computershare). Operations commenced on December 30, 1988. The beneficiaries of the Trust are the holders of trust units (the "unitholders").

The purpose of the Trust is to directly and indirectly explore for, develop and hold interests in petroleum and natural gas properties, through investments in securities, royalty units, net profits interests and notes issued by subsidiaries of the Trust. The activities of the Corporation and its subsidiaries are financed by issuance of royalty units and interest bearing notes to the Trust and third party debt. The Trust owns approximately 99.99 percent of the royalty units and 91 percent of the common shares of the Corporation. The Trust, through the royalty ownership, obtains substantially all the economic benefits of the Corporation. Under the terms of the Royalty Indenture, the Corporation is entitled to retain a one 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 2006 and 2005, this Residual Interest, as computed, did not result in any income retained by the Corporation.

The royalty units and notes of the Corporation held by the Trust entitle it to the net income generated by the Corporation and its subsidiaries' petroleum and natural gas properties less amounts withheld in accordance with prudent business practices to provide for future operating costs and asset retirement obligations, as defined in the Royalty Indenture. In addition, unitholders are entitled to receive the net income from other investments that are held directly by the Trust. Pursuant to the Royalty Indenture, the Board of Directors of the Corporation can establish a reserve for certain items including up to 20 percent of gross revenue to fund future capital expenditures or for the payment of royalty income in any future period.

Pursuant to the Trust Indenture, trust unitholders are entitled to monthly distributions from interest income on the notes, royalty income under the Royalty Indenture and from other investments held directly by the Trust, less any reserves and certain expenses of the Trust including general and administrative costs as defined in the Trust Indenture.

The Board of Directors has general authority over the business and affairs of the Corporation and derives its authority in respect to the Trust by virtue of the delegation of powers by the trustee to the Corporation as Administrator in accordance with the Trust Indenture.

The Trust acquired notes receivable and a Net Profits Interest (the "NPI agreement") in Esprit Exploration Ltd. (Esprit) as a result of a business combination with Esprit Energy Trust (Esprit Trust). The NPI agreement entitles the Trust to monthly distributions from Esprit, a wholly owned subsidiary of the Trust. The monthly distribution is equal to the amount by which 99 percent of the gross revenue exceeds 99 percent of certain deductible expenditures as defined in the NPI agreement.

Pengrowth Management Limited (the "Manager") has certain responsibilities for the business affairs of the Corporation, Esprit and the administration of the Trust under the terms of the management agreement and defers to the Board of Directors on all matters material to the Corporation and the Trust. Corporate governance practices are consistent with corporations and trusts that do not have a management agreement. The management agreement terminates on July 1, 2009. The Manager owns nine percent of the common shares of Corporation, and the Manager is controlled by an officer and a director of the Corporation and Esprit.

2. SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

The Trust's consolidated financial statements have been prepared in accordance with Generally Accepted Accounting Principles (GAAP) in Canada. The consolidated financial statements include the accounts of the Trust, the Corporation and its subsidiaries and as of October 2, 2006, the accounts of Esprit Trust, Esprit 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.

The Trust owns 91 percent of the shares of Corporation and, through the royalty and notes, obtains substantially all the economic benefits of Corporation. The Trust owns all the shares of Esprit and, through the net profits interest and notes, obtains substantially all the economic benefits of Esprit. In addition, the unitholders of the Trust 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 cost of unproven properties are included in the calculation of depletion. 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.

There is 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 suggest an impairment exists. Impairment is assessed by determining the fair value of the reporting entity 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 natural gas and ethane) are used in miscible flood programs to stimulate incremental oil recovery. The cost of hydrocarbon 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.

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 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

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

During 2006, the taxation authorities have released for comment draft legislation which would result in a tax structure for the Trust similar to that of corporate entities. If the proposed legislation is implemented, the Trust would be required to recognize, on a prospective basis, future income taxes on temporary differences in the Trust.

The Corporation, Esprit and their subsidiaries follow 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 and their respective tax bases, using substantively 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 trust unit based compensation plans, which are described in Note 14. Compensation expense associated with trust unit based compensation plans is recognized in income over the vesting period of the plan with a corresponding increase in contributed surplus. For grants after January 1, 2006, Pengrowth estimates the forfeiture rate of trust unit rights and deferred entitlement trust units (DEUs) at the date of grant. For grants prior to December 31, 2005, Pengrowth did not estimate the forfeiture rate of trust unit rights and DEUs, forfeitures were accounted for as they occur. Any consideration received upon the exercise of trust 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 estimated fair value of the trust unit based compensation at the date of grant, as further described in Note 14.

Pengrowth does not have any outstanding trust unit compensation plans that call for settlement in cash or other assets. Grants of such items, if any, will be recorded as liabilities, with changes in the liabilities charged to net income, 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 policy is not to utilize financial instruments for trading or speculative purposes.

Effective May 1, 2006, Pengrowth discontinued designating new commodity contracts as hedges. Prior to May 1, 2006, any commodity contracts previously designated as hedges continued to be designated as hedges and Pengrowth formally documented the relationships between hedging instruments and the hedged items, as well as its risk management objective and strategy for undertaking various hedge transactions. This process included linking derivatives to specific assets and liabilities on the balance sheet or to specific firm commitments or forecasted transactions. Pengrowth also formally assessed, both at the hedge's inception and on an ongoing basis, whether the derivatives that were used in hedging transactions were 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 sales are recognized.

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 commodity price swaps whereby the Canadian dollar price in the swap is fixed. Foreign exchange gains and losses realized on the settlement of the commodity price swaps are recognized in income as a component of oil and gas sales during the same period as the corresponding sales are recognized.

Foreign exchange swaps were used to fix the foreign exchange rate on the interest and principal of the Pounds Sterling 50 million ten year senior unsecured notes (see Note 20). Pengrowth has formally documented this relationship as a hedge as well as the risk management objective and strategy for undertaking the hedge. As a result of applying hedge accounting to this transaction, any unrealized foreign exchange gains (losses) on the translation on the debt are deferred and recorded in other assets (other liabilities).

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, goodwill and 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.

Net Income Per Trust Unit

Basic net income per unit amounts are calculated using the weighted average number of units outstanding for the year. Diluted net income per unit amounts include the dilutive effect of trust unit options, trust unit rights and DEUs using the treasury stock method. The treasury stock method assumes that any proceeds obtained on the exercise of in-the-money trust unit options and trust unit rights would be used to purchase trust units at the average price during the period. Diluted net income per unit amounts also includes the dilutive effect of convertible debentures using the "if-converted" method which assumes that the convertible debentures were converted at the beginning of the period.

Revenue Recognition

Revenue from the sale of oil and natural gas is recognized when the product is delivered and collection is reasonably assured. 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. ACQUISITIONS

2006 Acquisitions
Carson Esprit
Creek Energy
Properties Trust Total
---------------------------------------------------------------------------
Allocation of Purchase Price:

Property, plant and equipment $ 495,806 $ 1,207,121 $ 1,702,927
Goodwill 129,745 285,722 415,467
Fair value of commodity contracts - 10,601 10,601
Bank debt - (276,870) (276,870)
Convertible debentures (Note 9) - (96,500) (96,500)
Contract liabilities (Note 8) (9,073) - (9,073)
Asset retirement obligation (20,668) (51,651) (72,319)
Future income taxes (121,384) (110,590) (231,974)
Working capital deficiency - (45,864) (45,864)
---------------------------------------------------------------------------
$ 474,426 $ 921,969 $ 1,396,395
---------------------------------------------------------------------------

Consideration:
Cash $ 474,089 $ 19,990 $ 494,079
Pengrowth trust units issued - 895,944 895,944
Acquisition costs 337 6,035 6,372
---------------------------------------------------------------------------
$ 474,426 $ 921,969 $ 1,396,395
---------------------------------------------------------------------------


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

The future income tax liability was determined based on the enacted income tax rate of approximately 29 percent. The asset retirement obligations were determined using Pengrowth's estimated costs to remediate, reclaim and abandon the wells and facilities, the estimated timing of the costs to be incurred in future periods, an inflation rate of two percent, and a discount rate of eight percent.

Carson Creek Properties

On September 28, 2006, Pengrowth acquired all of the issued and outstanding shares of a company which has interests in oil and natural gas assets in the Carson Creek area of Alberta (the "Carson Creek" acquisition). The transaction was accounted for using the purchase method of accounting.

Pengrowth assumed a firm pipeline transportation contract liability. The fair value of the contract was determined at the date of acquisition. Results of operations from the Carson Creek acquisition subsequent to the acquisition date are included in the consolidated financial statements. Final determination of the cost of the acquisition and the allocation thereof to the fair values of the Carson Creek assets is still pending.

Esprit Energy Trust

On October 2, 2006, Pengrowth and Esprit Trust completed a business combination (the "Combination"). Under the terms of the Combination agreement, each Esprit trust unit was exchanged for 0.53 of a Pengrowth trust unit and a one time special distribution of $0.30 per Esprit trust unit that was paid to Esprit unitholders prior to the closing date of the Combination.

As a result of the Combination, 34,725,157 Pengrowth trust units were issued to Esprit unitholders. The value assigned to each Pengrowth trust unit issued was approximately $25.80 per unit based on the weighted average market price of the trust units on the five days surrounding the announcement of the Combination. The Combination was accounted for as an acquisition of Esprit Trust by Pengrowth using the purchase method of accounting.

The consolidated financial statements include the results of operations and cash flows of Esprit Trust and Esprit subsequent to October 2, 2006. Final determination of the cost of the acquisition and the allocation thereof to the fair values of the Esprit Trust and Esprit assets is still pending.



2005 Acquisitions
Crispin
Energy Swan Hills
Inc Properties Total
---------------------------------------------------------------------------
Allocation of purchase price:
Working capital $ 1,655 $ - $ 1,655
Property, plant and equipment 121,729 87,170 208,899
Goodwill 12,216 - 12,216
Bank debt (20,459) - (20,459)
Asset retirement obligations (4,038) - (4,038)
Future income taxes (22,208) - (22,208)
---------------------------------------------------------------------------
$ 88,895 $ 87,170 $ 176,065
---------------------------------------------------------------------------

Consideration:
Cash $ - $ 87,170 $ 87,170
Pengrowth trust units issued 87,960 - 87,960
Acquisition costs 935 - 935
---------------------------------------------------------------------------
$ 88,895 $ 87,170 $ 176,065
---------------------------------------------------------------------------


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

The future income tax liability was determined based on the enacted income tax rate of approximately 34 percent. The asset retirement obligations were determined using Pengrowth's estimated costs to remediate, reclaim and abandon the wells and facilities, the estimated timing of the costs to be incurred in future periods, an inflation rate of one and one half percent, and a discount rate of eight percent.

Crispin Energy Inc.

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

Results from operations of the acquired assets of Crispin subsequent to April 29, 2005 are included in the consolidated financial statements.

Swan Hills Properties

In February 2005, Pengrowth acquired an additional 11.9 percent working interest in Swan Hills for a purchase price of $87 million before adjustments. The acquisition increased Pengrowth's working interest in the Swan Hills Unit No. 1 to approximately 22 percent.



4. OTHER ASSETS

2006 2005
---------------------------------------------------------------------------
Deferred compensation expense (net of accumulated
amortization of $2,381, 2005 - $2,143) $ 2,696 $ 2,141
Debt issue costs (net of accumulated
amortization of $1,192, 2005 - $821) 1,626 1,997
Imputed interest on note payable (net of
accumulated amortization of $3,607, 2005 - $2,859) - 748
---------------------------------------------------------------------------
4,322 4,886
Deferred foreign exchange loss on translation of
U.K. debt 13,631 -
Remediation trust funds (Note 11) 11,144 8,329
---------------------------------------------------------------------------
$ 29,097 $ 13,215
---------------------------------------------------------------------------


5. EQUITY INVESTMENT

2006 2005
---------------------------------------------------------------------------
Investment in Monterey $ 7,035 -
---------------------------------------------------------------------------


On January 12, 2006 Pengrowth closed certain transactions with Monterey Exploration Ltd. (Monterey) under which Pengrowth has sold certain oil and gas properties for $22 million in cash, less closing adjustments, and 8,048,132 common shares of Monterey. As of December 31, 2006, Pengrowth held approximately 34 percent of the common shares of Monterey.

Pengrowth utilizes the equity method of accounting for the investment in Monterey. The investment is initially recorded at cost and adjusted thereafter to include Pengrowth's pro rata share of post-acquisition earnings of Monterey. Any dividends received or receivable from Monterey would reduce the carrying value of the investment.



6. PROPERTY, PLANT AND EQUIPMENT

2006 2005
---------------------------------------------------------------------------

Property, plant and equipment, at cost $ 5,365,309 $ 3,340,106
Accumulated depletion and depreciation (1,659,000) (1,307,424)
---------------------------------------------------------------------------
Net book value of property, plant and equipment 3,706,309 2,032,682
Net book value of deferred injectant costs 35,293 35,306
---------------------------------------------------------------------------
Net book value of property, plant and equipment
and deferred injectants $ 3,741,602 $ 2,067,988
---------------------------------------------------------------------------


Property, plant and equipment includes $56.0 million (2005 - $77.3 million) related to ARO, net of accumulated depletion.

Pengrowth performed a ceiling test calculation at December 31, 2006 to assess the recoverable value of the property, plant and equipment. The oil and gas future prices are based on the January 1, 2007 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 at December 31, 2006.




Foreign Edmonton
Exchange Light
WTI Oil Rate Crude Oil AECO Gas
Year (U.S.$/bbl) (U.S.$/Cdn$) (Cdn$/bbl) (Cdn$/mmbtu)
---------------------------------------------------------------------------
2007 $ 62.00 0.870 $ 70.25 $ 7.20
2008 $ 60.00 0.870 $ 68.00 $ 7.45
2009 $ 58.00 0.870 $ 65.75 $ 7.75
2010 $ 57.00 0.870 $ 64.50 $ 7.80
2011 $ 57.00 0.870 $ 64.50 $ 7.85
2012 $ 57.50 0.870 $ 65.00 $ 8.15
2013 $ 58.50 0.870 $ 66.25 $ 8.30
2014 $ 59.75 0.870 $ 67.75 $ 8.50
2015 $ 61.00 0.870 $ 69.00 $ 8.70
2016 $ 62.25 0.870 $ 70.50 $ 8.90
2017 $ 63.50 0.870 $ 71.75 $ 9.10
Escalate + 2.0 + 2.0 + 2.0
thereafter percent/yr percent/yr percent/yr
---------------------------------------------------------------------------


7. OTHER LIABILITIES

2006 2005
---------------------------------------------------------------------------
Current portion of contract liabilities $ 5,017 $ 5,279
Note payable - 20,000
---------------------------------------------------------------------------
$ 5,017 $ 25,279
---------------------------------------------------------------------------

The note payable was secured by Pengrowth's working interest in SOEP,
non-interest bearing and was paid on December 31, 2006.

8. CONTRACT LIABILITIES

Contract liabilities are comprised of the following amounts:

2006 2005
---------------------------------------------------------------------------
Fixed price commodity contract $ 7,800 $ 12,318
Firm transportation contracts 14,042 5,898
---------------------------------------------------------------------------
21,842 18,216
Less current portion (5,017) (5,279)
---------------------------------------------------------------------------
$ 16,825 $ 12,937
---------------------------------------------------------------------------


Pengrowth assumed a natural gas fixed price sales contract and firm transportation commitments in conjunction with certain acquisitions. The fair values of the contracts was estimated on the date of acquisition and the amount recorded is reduced as the contracts settle.

9. CONVERTIBLE DEBENTURES

As a result of the Combination (see Note 3), Pengrowth assumed all of Esprit Trust's 6.5 percent convertible unsecured subordinated debentures (the "Debentures"). The Debentures were originally issued by Esprit Trust on July 28, 2005 for a $100 million principal amount with interest paid semi-annually in arrears on June 30 and December 31 of each year. At October 2, 2006, $95.8 million principal amount of Debentures was outstanding. Each $1,000 principal amount of Debentures is convertible at the option of the holder at any time into Pengrowth trust units at a conversion price of $25.54 per unit. The Debentures mature on December 31, 2010. After December 31, 2008, Pengrowth may elect to redeem all or a portion of the outstanding Debentures at a price of $1,050 per debenture or $1,025 per debenture after December 31, 2009.

Pursuant to a change of control provision in the Debenture Indenture, Pengrowth was required to make an offer to purchase all of the outstanding Debentures at a price equal to 101 percent of the principal amount, plus any accrued and unpaid interest. On December 12, 2006 Pengrowth redeemed a portion of the Debentures, pursuant to the change of control provision, for cash proceeds of $21.8 million (including accrued interest of $0.6 million and offer premium of $0.2 million).

The Debentures were recorded on the consolidated financial statements at the estimated fair value on October 2, 2006, the date of the Combination. The estimated fair value of the Debentures was higher than the book (or "recorded") value based on the market trading price of the Debentures on the date of the Combination. The Debentures have been classified as debt, net of the fair value of the conversion feature at the date of the Combination, which has been classified as part of Trust Unitholders' Equity. The fair value of the conversion feature was calculated using an option pricing model. The debt premium will be amortized over the term of the Debentures. The amortization of the debt premium and the interest paid are recorded as interest. If the Debentures are converted into trust units, the portion of the value of the conversion feature within Trust Unitholders' Equity will be reclassified to trust units along with the principal amount converted. As of December 31, 2006, Debentures with a face value of $74.7 million remain outstanding.



The following is a reconciliation of the Debentures balance from October 2,
2006:

Debt Equity Total
---------------------------------------------------------------------------
Fair value on October 2, 2006
(Note 3) $ 96,295 $ 205 $ 96,500
Amortization of debt premium (29) - (29)
Redeemed for cash (21,139) (45) (21,184)
---------------------------------------------------------------------------
Balance, December 31, 2006 $ 75,127 $ 160 $ 75,287
---------------------------------------------------------------------------


10. LONG TERM DEBT

2006 2005
---------------------------------------------------------------------------
U.S. dollar denominated debt:
U.S. dollar 150 million senior unsecured notes
at 4.93 percent due April 2010 $ 174,810 $ 174,450
U.S. dollar 50 million senior unsecured notes
at 5.47 percent due April 2013 58,270 58,150
---------------------------------------------------------------------------
233,080 232,600
Pound sterling denominated 50 million unsecured
notes at 5.46 percent due December 2015 114,120 100,489
Canadian dollar revolving credit borrowings 257,000 35,000
---------------------------------------------------------------------------
$ 604,200 $ 368,089
---------------------------------------------------------------------------


On April 23, 2003, Corporation closed a U.S. $200 million private placement of senior unsecured notes. 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 $2.1 million are being amortized over the term of the notes (see Note 4).

On December 1, 2005, Corporation closed a Pounds Sterling 50 million private placement of senior unsecured notes. In a series of related hedging transactions, Pengrowth fixed the Pound Sterling to Canadian dollar exchange rate for all the semi-annual interest payments and the principal repayments at maturity. The notes have an effective rate of 5.49 percent after the hedging transactions. The notes contain the same financial maintenance covenants as the U.S. dollar denominated notes. Costs incurred in connection with issuing the notes, in the amount of $0.7 million are being amortized over the term on the notes (see Note 4).

Pengrowth has a $950 million extendible revolving term credit facility syndicated among ten financial institutions. The facility is unsecured, covenant based and has a three year term maturing June 16, 2009. Pengrowth has the option to extend the facility each year, subject to the approval of the lenders, or repay the entire balance at the end of the three year term. Various borrowing options are available under the facility including prime rate based advances and bankers' acceptance loans. This facility carries floating interest rates that are expected to range between 0.65 percent and 1.15 percent over bankers' acceptance rates depending on Pengrowth's consolidated ratio of senior debt to earnings before interest, taxes and non-cash items. In addition, Pengrowth has a $35 million demand operating line of credit. The facilities were reduced by drawings of $257 million and by outstanding letters of credit in the amount of approximately $17.6 million at December 31, 2006.

The five year schedule of long term debt repayment based on maturity is as follows: 2007 - nil; 2008 - nil; 2009 - $257.0 million; 2010 - $174.8 million; and 2011 - nil.

11. ASSET RETIREMENT OBLIGATIONS

The 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, considering various information including the annual reserves assessment and evaluation of Pengrowth's propertiesfrom the independent reserves evaluators. Pengrowth has estimated the net present value of its ARO to be $255 million as at December 31, 2006 (2005 - $185 million), based on a total escalated future liability of $1,530 million (2005 - $1,041 million). These costs are expected to be made over 50 years with the majority of the costs incurred between 2035 and 2054. Pengrowth's credit adjusted risk free rate of eight percent (2005 - eight percent) and an inflation rate of two percent (2005 - two percent) were used to calculate the net present value of the ARO.



The following reconciles Pengrowth's ARO:

2006 2005
---------------------------------------------------------------------------
Asset retirement obligations, beginning of year $ 184,699 $ 171,866
Increase (decrease) in liabilities during the year
related to:
Acquisitions 72,680 6,347
Disposals (1,500) (3,844)
Additions 1,649 1,972
Revisions (9,695) 1,549
Accretion expense 16,591 14,162

Liabilities settled during the year (9,093) (7,353)
---------------------------------------------------------------------------
Asset retirement obligations, end of year $ 255,331 $ 184,699
---------------------------------------------------------------------------


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. The next evaluation is anticipated to occur in 2007. Contributions to the Judy Creek remediation trust fund may change based on future evaluations of the fund.

Pengrowth is required to make contributions to a remediation trust fund that will be used to fund the ARO of the SOEP properties and facilities. Pengrowth currently makes a monthly contribution to the fund of $0.42 per mcf of natural gas production and $0.84 per bbl of natural gas liquids production from SOEP.

The following summarizes Pengrowth's trust fund contributions for 2006 and 2005 and Pengrowth's expenditures on ARO not covered by the trust funds:



Remediation Trust Funds 2006 2005
---------------------------------------------------------------------------
Opening balance $ 8,329 $ 8,309

Contributions to Judy Creek Remediation Trust Fund 1,036 778
Contributions to SOEP Environmental Restoration Fund 2,153 556
Remediation funded by Judy Creek Remediation Trust
Fund (374) (1,314)
---------------------------------------------------------------------------
2,815 20
---------------------------------------------------------------------------
Closing balance $ 11,144 $ 8,329
---------------------------------------------------------------------------

Expenditures on ARO 2006 2005
---------------------------------------------------------------------------
Expenditures on ARO not covered by the trust funds $ 8,719 $ 6,039
Expenditures on ARO covered by the trust funds 374 1,314
---------------------------------------------------------------------------
$ 9,093 $ 7,353
---------------------------------------------------------------------------


12. 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.



2006 2005
---------------------------------------------------------------------------
Income before taxes $ 248,048 $ 340,846
Combined federal and provincial tax rate 34.1% 37.6%
---------------------------------------------------------------------------
Expected income tax 84,584 128,158
Net income of the Trust (85,989) (122,698)
Resource allowance (8,618) (10,985)
Non-deductible crown charges 17,586 24,271
Unrealized foreign exchange gain 1 (1,623)
Attributed Canadian royalty income (6,616) (3,541)
Effect of proposed tax changes (19,886) -
Future tax rate difference 2,491 (1,402)
Other including stock based compensation 2,178 96
---------------------------------------------------------------------------
Future income taxes (14,269) 12,276
Capital taxes 14 2,244
---------------------------------------------------------------------------
$ (14,255) $ 14,520
---------------------------------------------------------------------------


As identified above, changes to the income tax rates have changed Pengrowth's future tax rate to approximately 29 percent in 2006 (34 percent in 2005) applied to the temporary differences compared to the federal and provincial statutory rate of approximately 34 percent for the 2006 income tax year (38 percent in 2005).



The net future income tax liability is comprised of:

2006 2005
---------------------------------------------------------------------------
Future income tax liabilities:
Property, plant, equipment and other assets $ 339,660 $ 114,256
Unrealized foreign exchange gain 8,288 9,689
Other 150 110
---------------------------------------------------------------------------
348,098 124,055
Future income tax assets:
Attributed Canadian royalty income (13,947) (7,819)
Contract liabilities (6,334) (6,124)
---------------------------------------------------------------------------
$ 327,817 $ 110,112
---------------------------------------------------------------------------


The Trust maintains an income tax status that permits it to deduct distributions to unitholders in addition to other items. Accordingly, no future income tax provision or recovery was made for temporary differences in the Trust. As at December 31, 2006, the tax basis of the Trust's assets and liabilities exceed their net book value amount by $92 million (2005 - $241 million).



13. TRUST UNITS

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

Total Trust Units:
Year ended Year ended
December 31, 2006 December 31, 2005
---------------------------------------------------------------------------
Number of Number of
Trust units issued trust units Amount trust units Amount
---------------------------------------------------------------------------
Balance, beginning
of period 159,864,083 $ 2,514,997 152,972,555 $ 2,383,284
Issued for the
Crispin acquisition
(non cash) - - 4,225,313 87,960
Issued for the
Esprit Trust
business
combination
(non-cash) 34,725,157 895,944 - -
Issued for cash 47,575,000 987,841 - -
Issue costs - (51,575) - -
Issued on
redemption of
Deferred
Entitlement Trust
Units (DEUs) 14,523 233 - -
Issued for cash on
exercise of trust unit
options and rights 607,766 9,476 1,512,211 21,818
Issued for cash
under Distribution
Reinvestment Plan
(DRIP) 1,226,806 26,049 1,154,004 20,726
Issued on
redemption of
Royalty Units
(non-cash) 3,288 - - -
Trust unit rights
incentive plan
(non-cash
exercised) - 1,028 - 1,209
---------------------------------------------------------------------------
Balance, end of
period 244,016,623 $ 4,383,993 159,864,083 $ 2,514,997
---------------------------------------------------------------------------

"Consolidated" Trust Units:

Year ended Year ended
December 31, 2006 December 31, 2005
---------------------------------------------------------------------------
Number of Number of
Trust units issued trust units Amount trust units Amount
---------------------------------------------------------------------------
Balance, beginning
of period - $ - - $ -
Issued in trust
unit consolidation 160,921,001 2,535,949 - -
Issued on conversion
of Class A trust
units 3,450 57 - -
Issued for the
Esprit Trust
business
combination
(non-cash) 34,725,157 895,944 - -
Issued for cash 47,575,000 987,841 - -
Issue costs - (51,575) - -
Issued on redemption
of DEUs 14,523 233 - -
Issued for cash on
exercise of trust
unit options and rights 99,228 1,579 - -
Issued for cash
under DRIP 663,458 13,415 - -
Issued on redemption
of Royalty Units
(non-cash) 3,288 - - -
Trust unit rights
incentive plan
(non-cash
exercised) - 376 - -
---------------------------------------------------------------------------
Balance, end of
period 244,005,105 $ 4,383,819 - $ -
---------------------------------------------------------------------------

Class A Trust Units:

Year ended Year ended
December 31, 2006 December 31, 2005
---------------------------------------------------------------------------
Number of Number of
Trust units issued trust units Amount trust units Amount
---------------------------------------------------------------------------
Balance, beginning
of period 77,524,673 $ 1,196,121 76,792,759 $ 1,176,427
Issued for the
Crispin acquisition
(non-cash) - - 686,732 19,002
Trust units converted to
Class A trust units 2,760 43 45,182 692
Trust units converted to
"consolidated"
trust units (77,515,915) (1,195,990) - -
---------------------------------------------------------------------------
Balance, end of
period 11,518 $ 174 77,524,673 $ 1,196,121
---------------------------------------------------------------------------

Class B Trust Units:

Year ended Year ended
December 31, 2006 December 31, 2005
---------------------------------------------------------------------------
Number of Number of
Trust units issued trust units Amount trust units Amount
---------------------------------------------------------------------------
Balance, beginning
of period 82,301,443 $ 1,318,294 76,106,471 $ 1,205,734
Trust units converted to
(from) Class B trust
units 1,095 17 (9,824) (151)
Issued for the
Crispin acquisition
(non-cash) - - 3,538,581 68,958
Issued for cash on
exercise of trust
unit options and rights 508,538 7,897 1,512,211 21,818
Issued for cash
under DRIP 563,348 12,634 1,154,004 20,726
Trust unit rights
incentive plan
(non-cash exercised) - 652 - 1,209
Trust units renamed
to become "consolidated"
trust units (83,374,424) (1,339,494) - -
---------------------------------------------------------------------------
Balance, end of period - $ - 82,301,443 $ 1,318,294
---------------------------------------------------------------------------

Unclassified Trust Units:

Year ended Year ended
December 31, 2006 December 31, 2005
---------------------------------------------------------------------------
Number of Number of
Trust units issued trust units Amount trust units Amount
---------------------------------------------------------------------------
Balance, beginning
of period 37,967 $ 582 73,325 $ 1,123
Converted to Class A or
Class B trust units (3,855) (60) (35,358) (541)
Trust units converted to
"consolidated" trust
units (34,112) (522) - -
---------------------------------------------------------------------------
Balance, end of period - $ - 37,967 $ 582
---------------------------------------------------------------------------


Class A Trust Unit and Class B Trust Unit Consolidation

On June 23, 2006 the Pengrowth unitholders voted to consolidate the Class A trust units and Class B trust units into one class of trust units ("consolidated" trust units). As a result:

- Effective as of 5:00 pm Mountain Time on June 27, 2006, the restrictions on the Class B trust units that provided that the Class B trust units may only be held by residents of Canada was eliminated.

- Effective as of 5:00 p.m. Mountain Time on July 27, 2006;

-- the Class A trust units were delisted from the Toronto Stock Exchange (TSX) (effective as of the close of markets);

-- the Class B trust units were renamed as trust units to become the "consolidated" trust units and the trading symbol of the "consolidated" trust units was changed from PGF.B to PGF.UN;

-- all of the issued and outstanding Class A trust units were converted into "consolidated" trust units on the basis of one "consolidated" trust unit for each whole Class A trust unit previously held (with the exception of Class A trust units held by residents of Canada who provided a residency declaration to the Trustee);

-- the "consolidated" trust units were substitutionally listed in place of the Class A trust units on the New York Stock Exchange under the symbol PGH; and

-- the unclassified trust units were converted into consolidated trust units on the basis of one consolidated trust unit for each unclassified trust unit held.

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 the Trust, the right to exchange such royalty unit for an equivalent number of trust units. Accordingly, Computershare as Trustee has reserved 14,952 trust units for such future conversion.

Redemption Rights

Trust units are redeemable at the option of the holder. The redemption price is equal to the lesser of 95 percent of the market trading price of the trust units traded on the TSX for the ten trading days after the trust units have been surrendered for redemption and the closing market price of the trust units quoted on the TSX on the date the trust units have been surrendered for redemption. Trust units can be redeemed for cash to a maximum of $25,000 per month. Redemptions in excess of the cash limit must be satisfied by way of a distribution in specie of a pro-rata share of royalty units and other assets, excluding facilities, pipelines or other assets associated with oil and natural gas production, which are held by the Trust at the time the trust units are to be redeemed.

Distribution Reinvestment Plan

Canadian resident trust unitholders are eligible to participate in the Distribution Reinvestment Plan (DRIP). DRIP entitles the unitholder to reinvest cash distributions in additional units of the Trust. The trust units under the plan are issued from treasury at a five percent discount to the weighted average closing price of all trust units traded on the TSX for the 20 trading days preceding a distribution payment date. Non-resident unitholders are not eligible to participate in DRIP.



Contributed Surplus
2006 2005
---------------------------------------------------------------------------
Balance, beginning of year $ 3,646 $ 1,923
Trust unit rights incentive plan (non-cash expensed) 1,298 1,740
Deferred entitlement trust units (non-cash expensed) 1,248 1,192
Trust unit rights incentive plan (non-cash exercised) (1,028) (1,209)
Deferred entitlement trust units (non-cash exercised) (233) -
---------------------------------------------------------------------------
Balance, end of year $ 4,931 $ 3,646
---------------------------------------------------------------------------


14. TRUST UNIT BASED COMPENSATION PLANS

Up to ten percent of the issued and outstanding trust units, to a maximum of 18 million trust units, may be reserved for DEUs, rights and option grants, in aggregate.

Long Term Incentive Program

Effective January 1, 2005, the Board of Directors approved a Long Term Incentive Plan. The DEUs issued under the plan vest and are converted to trust units on the third anniversary from the date of grant and will receive deemed distributions prior to the vesting date in the form of additional DEUs. However, the number of DEUs actually issued to each participant at the end of the three year vesting period will be subject to an absolute performance test and a relative performance test which compares Pengrowth's three year average total return to the three year average total return of a peer group of other energy trusts such that upon vesting, the number of trust units issued from treasury may range from zero to one and one-half times the number of DEUs granted plus accrued DEUs through the deemed reinvestment of distributions.

Compensation expense related to DEUs is based on the fair value of the DEUs at the date of grant. The number of trust units awarded at the end of the vesting period is subject to certain performance conditions. Compensation expense incorporates the estimated fair value of the DEUs at the date of grant and an estimate of the relative performance multiplier. Fluctuations in compensation expense may occur due to changes in estimating the outcome of the performance conditions. Compensation expense is recognized in income over the vesting period with a corresponding increase or decrease to contributed surplus. Upon issuance of the trust units at the end of the vesting period, trust unitholders' capital is increased and contributed surplus is reduced. For the twelve months ended December 31, 2006, Pengrowth recorded compensation expense of $1.3 million (2005 - $1.2 million) associated with the DEUs. Compensation expense associated with the DEUs was based on the weighted average grant date fair value of $20.65 per DEU (2005 - $18.31 per DEU). The fair value of the DEUs is determined based on the closing price of the date of grant, forfeiture rate of 25 percent prior to vesting and an estimated performance multiplier of 125 percent based on the performance of Pengrowth's total return compared to its peers. As of December 31, 2006, the unrecognized compensation costs to be amortized over the remaining vesting period is $4.4 million (2005 - $3.7 million) at a weighted average of $12.60 (2005 - $13.87) per DEU. The trust units are issued from treasury upon redemption.




2006 2005
---------------------------------------------------------------------------
Weighted Weighted
Number of average Number of average
DEUs fair DEUs fair
value value
--------------------------------------------------------------------------
Outstanding, beginning of
period 185,591 $ 18.32 - $ -
Granted 222,088 $ 22.28 194,229 $ 18.31
Forfeited (33,981) $ 20.13 (26,258) $ 18.16
Exercised (14,207) $ 20.43 - $ -
Deemed DRIP 40,077 $ 19.14 17,620 $ 18.19
---------------------------------------------------------------------------
Outstanding, end of period 399,568 $ 20.55 185,591 $ 18.32
---------------------------------------------------------------------------


Trust Unit Rights Incentive Plan

Pengrowth has a Trust Unit Rights Incentive Plan, pursuant to which rights to acquire 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 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 may result, at the discretion of the holder, in a reduction in the exercise price. Total price reductions calculated for 2006 were $1.79 per trust unit right (2005 - $1.49 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, 2006, rights to purchase 1,534,241 trust units were outstanding (2005 - 1,441,737) that expire at various dates to December 2, 2011.



2006 2005
---------------------------------------------------------------------------
Weighted Weighted
average average
Number exercise Number exercise
Trust Unit Rights of rights price of rights price
---------------------------------------------------------------------------
Outstanding at beginning
of year 1,441,737 $ 14.85 2,011,451 $ 14.23
Granted (1) 617,409 $ 22.39 606,575 $ 18.34
Exercised (452,468) $ 14.75 (953,904) $ 12.81
Forfeited (72,437) $ 17.47 (222,385) $ 16.19
---------------------------------------------------------------------------
Outstanding at year end 1,534,241 $ 16.06 1,441,737 $ 14.85
---------------------------------------------------------------------------
Exercisable at year end 969,402 $ 14.22 668,473 $ 13.73
---------------------------------------------------------------------------
(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 trust unit rights
outstanding and exercisable at December 31, 2006:

Rights Outstanding Rights Exercisable
---------------------------------------------------------------------------
Weighted
average
remaining Weighted Weighted
contractual average average
Range of Number life exercise Number exercise
exercise prices outstanding (years) price exercisable price
---------------------------------------------------------------------------
$ 7.00 to $8.99 130,250 0.9 $ 7.18 130,250 $ 7.18
$ 9.00 to $10.99 2,100 1.4 $ 10.48 2,100 $ 10.48
$11.00 to $12.99 345,820 2.1 $ 12.22 345,820 $ 12.22
$14.00 to $15.99 378,075 3.0 $ 15.05 246,317 $ 15.16
$16.00 to $18.99 241,349 4.4 $ 17.93 109,059 $ 17.70
$19.00 to $24.99 436,647 4.2 $ 21.62 135,856 $ 21.64
---------------------------------------------------------------------------
$ 7.00 to $24.99 1,534,241 2.7 $ 16.06 969,402 $ 14.22
---------------------------------------------------------------------------


Compensation expense associated with the trust unit rights granted during 2006 was based on the estimated fair value of $1.79 per trust unit right (2005 - $2.75). The fair value of trust unit rights granted in 2006 was estimated at eight percent of the exercise price at the date of grant using a binomial lattice option pricing model with the following assumptions: risk-free rate of 4.1 percent, volatility of 19 percent and reductions in the exercise price over the life of the trust unit rights. An estimate of forfeitures was made at the date of grant and reduces the amount of compensation expense recorded. A forfeiture rate of five percent was used for directors and officers and ten percent for employees. Compensation expense related to the trust unit rights in 2006 was $1.3 million (2005 - $1.7 million).

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 trust units. No new grants have been issued under the plan since November 2002. 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, 2006, options to purchase 98,619 trust units were outstanding (2005 - 259,317) that expire at various dates to June 28, 2009.




2006 2005
---------------------------------------------------------------------------
Weighted Weighted
average average
Number exercise Number exercise
Trust Unit Options of options price of options price
---------------------------------------------------------------------------
Outstanding at beginning
of year 259,317 $ 17.28 845,374 $ 16.97
Exercised (155,298) $ 18.03 (558,307) $ 16.74
Expired (5,400) $ 16.96 (27,750) $ 18.63
---------------------------------------------------------------------------
Outstanding and exercisable
at year end 98,619 $ 16.12 259,317 $ 17.28
---------------------------------------------------------------------------

The following table summarizes information about trust unit options
outstanding and exercisable at December 31, 2006:

Options Outstanding and Exercisable
---------------------------------------------------------------------------
Weighted average
remaining
Range of Number outstanding contractual Weighted average
exercise prices and exercisable life (years) exercise price
---------------------------------------------------------------------------
$ 12.00 to $14.99 24,793 2.0 $ 13.12
$ 15.00 to $16.99 22,799 1.8 $ 15.00
$ 17.00 to $17.99 29,316 1.3 $ 17.47
$ 18.00 to $20.50 21,711 0.9 $ 18.90
---------------------------------------------------------------------------
$ 12.00 to $20.50 98,619 1.5 $ 16.12
---------------------------------------------------------------------------


Trust Unit Award Plan

Effective July 13, 2005, Pengrowth established an incentive plan to reward and retain employees whereby trust units and cash were awarded to eligible employees. Pengrowth acquires the trust units to be awarded under the plan on the open market and places them in a trust account established for the benefit of the eligible employees. The cost to acquire the trust units has been recorded as deferred compensation expense and is being charged to net income on a straight-line basis over one year. In addition, the cash portion of the incentive plan is being accrued on a straight-line basis over one year. Any unvested trust units will be sold on the open market. Any change in the market value of the trust units and re-invested distributions over the vesting period accrues to the eligible employees. In 2006, the amount charged to net income related to the July 13, 2005 trust unit award plan including the cash portion of the award, net of any unvested trust units that were sold on the open market was $2.7 million (2005 - $2.9 million).

Effective February 27, 2006, Pengrowth awarded trust units and in some cases trust units and cash to eligible employees under the Trust Unit Award Plan. Eligible employees will receive the trust units and cash on or about July 1, 2007. Pengrowth acquired the trust units to be awarded under the plan on the open market for $5.1 million and placed them in a trust account established for the benefit of the eligible employees. The cost to acquire the trust units has been recorded as deferred compensation expense and is being charged to net income on a straight-line basis over the vesting period. In addition, the cash portion of the incentive plan of approximately $1.1 million is being accrued on a straight-line basis over the vesting period. Any unvested trust units will be sold on the open market. In 2006, the amount charged to net income related to the February 27, 2006 trust unit award plan including the cash portion of the award was $3.0 million.

Employee Savings Plans

Pengrowth has savings plans whereby Pengrowth will match contributions by qualifying employees of zero to 11 percent (2005 - zero to ten percent) of their annual basic salary, less any of Pengrowth's contributions to the Group Registered Retirement Savings Plan (Group RRSP), to purchase trust units in the open market. Participants in the Group RRSP can make contributions from one to 13 percent and Pengrowth will match contributions to a maximum of five percent of their annual basic salary. Pengrowth's share of contributions to the Trust Unit Purchase Plan and Group RRSP were $2.1 million in 2006 (2005 - $1.5 million) and $0.6 million in 2006 (2005 - $0.5 million), respectively.

Trust Unit Margin Purchase Plan

Pengrowth has a plan whereby the employees and certain consultants of Pengrowth 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.

Pengrowth has provided a $1 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, 2006, 527,482 trust units were deposited under the plan (2005 - 721,334) with a market value of $10.5 million (2005 - $16.3 million) and a corresponding margin loan of $5.8 million (2005 - $2.7 million).

The investment dealer has limited the total margin loan available under the plan to the lesser of $20 million or 75 percent of the market value of the units held under the plan. If the market value of the trust units under the plan declines, Pengrowth may be required to make payments or post additional letters of credit to the investment dealer. Any payments to be made by Pengrowth are to be reduced by proceeds of liquidating the individual's trust units held under the plan. The maximum amount Pengrowth may be required to pay at December 31, 2006 was $5.8 million (2005 - $2.7 million), however, the individual plan members are primarily responsible for any margin loans and Pengrowth would only be responsible for any unpaid amounts.



15. DEFICIT

2006 2005
---------------------------------------------------------------------------
Accumulated earnings $ 1,315,686 $ 1,053,383
Accumulated distributions paid or declared (2,655,093) (2,096,030)
---------------------------------------------------------------------------
$ (1,339,407) $ (1,042,647)
---------------------------------------------------------------------------


Pengrowth is obligated by virtue of its Royalty and Trust Indentures and NPI agreement to distribute to unitholders a significant portion of its cash flow from operations. Cash flow from operations typically exceeds net income as a result of non-cash expenses such as unrecognized gain (losses) on commodity contracts, depletion, depreciation and accretion. These non-cash expenses result in a deficit being recorded despite Pengrowth distributing less than its cash flow from operations.



16. FOREIGN EXCHANGE LOSS (GAIN)

2006 2005
---------------------------------------------------------------------------
Unrealized foreign exchange loss (gain) on translation
of U.S. dollar denominated debt $ 480 $ (7,800)
Realized foreign exchange (gain) loss (458) 834
---------------------------------------------------------------------------
$ 22 $ (6,966)
---------------------------------------------------------------------------


The U.S. dollar and U.K. Pound Sterling denominated debt are translated into Canadian dollars at the Bank of Canada exchange rate in effect at the close of business on the balance sheet date. Foreign exchange gains and losses on the U.S. dollar denominated debt are included in income. Foreign exchange gains and losses on translating the U.K. Pound Sterling denominated debt are deferred and included in other assets.



17. OTHER CASH FLOW DISCLOSURES

Change in Non-Cash Operating Working Capital
Cash provided by (used for): 2006 2005
---------------------------------------------------------------------------
Accounts receivable $ 12,819 $ (21,072)
Accounts payable and accrued liabilities (30,974) 29,953
Due to Pengrowth Management Limited (6,176) 952
---------------------------------------------------------------------------
$ (24,331) $ 9,833
---------------------------------------------------------------------------


Change in Non-Cash Investing Working Capital
Cash provided by: 2006 2005
---------------------------------------------------------------------------
Accounts payable for capital accruals $ 37,529 $ 1,117

Cash payments
2006 2005
---------------------------------------------------------------------------
Taxes $ 14 $ 2,123
Interest $ 32,183 $ 21,779
---------------------------------------------------------------------------


18. RELATED PARTY TRANSACTIONS

The Manager provides certain services pursuant to a management agreement for which Pengrowth was charged $2.9 million (2005 - $6.9 million) for performance fees and $7.0 million (2005 - $9.1 million) for management fees. In addition, Pengrowth was charged $1.0 million (2005 - $0.9 million) for reimbursement of general and administrative expenses incurred by the Manager pursuant to the management agreement. The law firm controlled by the Vice President and Corporate Secretary of the Corporation charged $1.0 million (2005 - $0.7 million) for legal and advisory services provided to Pengrowth. The transactions have been recorded at the exchange amount. Amounts payable to the related parties are unsecured, non-interest bearing and have no set terms of repayment.

A senior officer of the Corporation is a member of the Board of Directors of Monterey, a company that Pengrowth owns approximately 34 percent of the outstanding common shares. In December 2006, two senior officers of the Corporation directly and indirectly purchased a total of 30,000 shares of Monterey for a total consideration of $150,000 in a new share offering marketed by an independent broker.



19. AMOUNTS PER TRUST UNIT

The following reconciles the weighted average number of trust units used in
the basic and diluted net income per unit calculations:

2006 2005
---------------------------------------------------------------------------
Weighted average number of trust units - basic 175,871 157,127
Dilutive effect of trust unit options, trust unit
rights and DEUs 583 787
---------------------------------------------------------------------------
Weighted average number of trust units - diluted 176,454 157,914
---------------------------------------------------------------------------


In 2006, 0.7 million (2005 - 0.4 million) trust units from trust unit options, rights and convertible debentures were excluded from the diluted net income per unit calculation as their effect is anti-dilutive.

20. FINANCIAL INSTRUMENTS

Interest Rate Risk

Pengrowth has mitigated some exposure to interest rate risk by entering into fixed rate term notes (Note 10). Pengrowth is exposed to interest rate risk on the Canadian revolving credit facility as the interest charged on the amount borrowed is based on a floating interest rate.

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 is exposed to foreign currency fluctuation on the U.S. dollar denominated notes for both interest and principal payments.

Pengrowth entered into a foreign exchange swap in conjunction with issuing Pounds Sterling 50 million of ten year term notes (Note 10) which fixed the Canadian dollar to Pound Sterling exchange rate on the interest and principal of the Pound Sterling denominated debt at approximately Pounds Sterling 0.4976 per Canadian dollar. The estimated fair value of the foreign exchange swap has been determined based on the amount Pengrowth would receive or pay to terminate the contract at year end. At December 31, 2006, the amount Pengrowth would receive (pay) to terminate the foreign exchange swap would be approximately $13.9 million (December 31, 2005 - ($2.2) million).

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, 2006, 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, 2007 - Dec 31, 2007 13,000 WTI (1) $ 76.58 Cdn
Jan 1, 2008 - Oct 31, 2008 1,000 WTI (1) $ 74.25 Cdn
Jan 1, 2008 - Dec 31, 2008 1,000 WTI (1) $ 78.88 Cdn

---------------------------------------------------------------------------

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

Financial:
Jan 1, 2007 - Oct 31, 2007 5,000 Transco Z6 (1) $ 11.62 Cdn
Jan 1, 2007 - Mar 31, 2007 11,848 AECO $ 9.63 Cdn
Apr 1, 2007 - Oct 31, 2007 9,478 AECO $ 8.28 Cdn
Jan 1, 2007 - Dec 31, 2007 42,652 AECO $ 7.97 Cdn
Jan 1, 2007 - Oct 31, 2007 5,000 Chicago MI (1) $ 9.69 Cdn
Jan 1, 2007 - Dec 31, 2007 10,500 Chicago MI (1) $ 8.89 Cdn
Jan 1, 2007 - Oct 31, 2007 4,739 AECO $ 7.39 - 9.07 Cdn(2)
Jan 1, 2007 - Mar 31, 2007 4,739 AECO $7.91 - 10.81 Cdn(2)
---------------------------------------------------------------------------
(1) Associated Cdn$ / U.S.$ foreign exchange rate has been fixed.
(2) Costless collars


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, 2006, the amount Pengrowth would receive to terminate the financial crude oil and natural gas contracts would be $5 million and $32 million, respectively.

Natural Gas Fixed Price Sales Contract:

Corporation assumed a natural gas fixed price physical sales contract in conjunction with an acquisition. At December 31, 2006, the amount Corporation would pay to terminate the fixed price sales contract would be $17 million. Details of the physical fixed price sales contract are provided below:



Price
Volume per mmbtu
Remaining Term (mmbtu/d) (1)
---------------------------------------------------------------------------
2007 to 2009
Jan 1, 2007 -- 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


In accordance with GAAP, the fair value of the commodity contracts are allocated to current and non-current assets and liabilities on a contract by contract basis. A summary of the gains (losses) on the fair value of the commodity contracts are provided below:



2006
---------------------------------------------------------------------------
Current gain on the fair value of commodity contracts $ 37,972
Non-current gain on the fair value of commodity contracts 495
Non-current loss on the fair value of commodity contracts (1,367)
---------------------------------------------------------------------------
37,100
Fair value of commodity contracts recognized as part of
Esprit Trust acquisition (10,601)
---------------------------------------------------------------------------
Unrealized gain on fair value of commodity contracts $ 26,499
---------------------------------------------------------------------------


Fair value of financial instruments

The carrying value of financial instruments included in the balance sheet, other than U.S. and U.K. debt, the debentures and remediation trust funds approximate their fair value due to their short maturity. The fair value of the other financial instruments is as follows:



As at As at
December 31, 2006 December 31, 2005
---------------------------------------------------------------------------
Net book Net book
Fair value value Fair value value
---------------------------------------------------------------------------
Remediation funds $ 11,162 $ 11,144 $ 9,071 $ 8,329
U.S. dollar denominated debt 224,624 233,080 220,187 232,600
Pound Sterling denominated debt 109,692 114,120 101,257 100,489
Convertible debentures 75,488 75,127 - -
---------------------------------------------------------------------------


21. COMMITMENTS

2007 2008 2009 2010 2011 Thereafter Total
---------------------------------------------------------------------------
Operating
leases (1) $ 7,350 $ 7,387 $ 6,494 $ 6,019 $ 5,790 $35,923 $68,963
---------------------------------------------------------------------------
(1) Operating leases commitments include office rent and other vehicle
leases.


Pengrowth is involved in litigation and claims arising in the normal course of operations, none of which could reasonably be expected to materially affect Pengrowth's financial position or reported results of operations.

22. SUBSEQUENT EVENTS

On January 22, 2007, Pengrowth acquired four subsidiaries of Burlington Resources Canada Ltd., a subsidiary of ConocoPhillips, which hold Canadian oil and natural gas producing properties and undeveloped lands (the "CP Properties") for a purchase price of $1.0375 billion, prior to adjustments. The acquisition of the CP Properties was funded in part by the December 1, 2006 equity offering of approximately $461 million with the balance funded by a new credit facility. A deposit of $103.8 million was paid on the acquisition prior to year end.

In conjunction with acquiring the CP Properties, Pengrowth entered into a new $600 million credit facility syndicated among ten financial institutions. The facility is unsecured, covenant based and has a one year term. Various borrowing options are available under the facility including prime rate based advances and bankers' acceptance loans. The facility carries floating interest rates that are expected to range between 0.65 percent and 1.15 percent over bankers' acceptance rates, depending on Pengrowth's consolidated ratio of senior debt to earnings before interest, taxes and non-cash items. Certain net proceeds from any future asset dispositions, equity offerings or debt issuances are required to repay the amount borrowed under this credit facility.

Subsequent to December 31, 2006, Pengrowth has entered into a series of fixed price commodity sales contracts with third parties as follows:



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

Financial:
Mar 1, 2007 - Dec 31, 2007 2,000 WTI (1) $73.36 Cdn
Jan 1, 2008 - Dec 31, 2008 6,000 WTI (1) $74.73 Cdn
---------------------------------------------------------------------------


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

Financial:
Feb 1, 2007 - Dec 31, 2007 7,500 TETCO M3 (1) $9.00 Cdn
Mar 1, 2007 - Dec 31, 2007 5,000 TETCO M3 (1) $9.08 Cdn
Feb 1, 2007 - Dec 31, 2007 7,500 NYMEX(1) $8.94 Cdn
Jan 1, 2008 - Dec 31, 2008 5,000 Transco Z6 (1) $10.90 Cdn
Mar 1, 2007 - Dec 31, 2007 4,740 AECO $8.48 Cdn
Apr 1, 2007 - Dec 31, 2007 2,370 AECO $7.02 Cdn
Nov 1, 2007 - Dec 31, 2007 2,370 AECO $8.44 Cdn
Jan 1, 2008 - Mar 31, 2008 2,370 AECO $8.44 Cdn
Jan 1, 2008 - Dec 31, 2008 42,653 AECO $8.33 Cdn
Mar 1, 2007 - Dec 31, 2007 2,500 Chicago MI (1) $8.21 Cdn
Jan 1, 2008 - Dec 31, 2008 5,000 Chicago MI (1) $9.20 Cdn
---------------------------------------------------------------------------
(1) Associated Cdn$ / U.S.$ foreign exchange rate has been fixed.


23. RECONCILIATION OF FINANCIAL STATEMENTS TO UNITED STATES GENERALLY
ACCEPTED ACCOUNTING PRINCIPLES

The significant differences between Canadian generally accepted accounting principles (Canadian GAAP) which, in most respects, conforms to United States generally accepted accounting principles (U.S. GAAP), as they apply to Pengrowth, are as follows:

(a) As required annually under U.S. GAAP, the carrying value of petroleum and natural gas properties and related facilities, net of future or deferred income taxes, is limited to the present value of after tax future net revenue from proven reserves, discounted at ten percent (based on prices and costs at the balance sheet date), plus the lower of cost and fair value of unproven properties. At December 31, 2006, the application of the full cost ceiling test under U.S. GAAP resulted in a write-down of capitalized costs of $114 million. The ceiling test did not include the CP Properties discussed in Note 22. The application of the full cost ceiling test under U.S. GAAP did not result in a write-down of capitalized costs at December 31, 2005.

Where the amount of a ceiling test write-down under Canadian GAAP differs from the amount of the write-down under U.S. GAAP, the charge for depletion will differ in subsequent years. Pengrowth had write-downs of capitalized costs in 1998 and 1997 of $328.6 million and $49.8 million respectively. In addition, under U.S. GAAP depletion is calculated based on constant dollar reserves as opposed to escalated dollar reserves required under Canadian GAAP. As such, the depletion rate under U.S. GAAP differs from Canadian GAAP. The effect of ceiling test impairments and a different depletion rate under U.S. GAAP has reduced the 2006 depletion charge by $24.0 million (2005 - $24.7 million).

(b) Under U.S. GAAP, interest and other income would not be included as a component of Net Revenue.

(c) Statement of Financial Accounting Standards (SFAS) 130, "Reporting Comprehensive Income" requires the reporting of comprehensive income in addition to net income. Comprehensive income includes net income plus other comprehensive income; specifically, all changes in equity of a company during a period arising from non-owner sources.

(d) SFAS 133, "Accounting for Derivative Instruments and Hedging Activities" establishes accounting and reporting standards for derivative instruments and for hedging activities. This statement requires an entity to establish, at the inception of a hedge, the method it will use for assessing the effectiveness of the hedging derivative and the measurement approach for determining the ineffective aspect of the hedge. Those methods must be consistent with the entity's approach to managing risk.

Effective May 1, 2006, Pengrowth discontinued designating new commodity contracts as hedges. As at December 31, 2006, there were no financial crude oil and natural gas contracts outstanding for which hedge accounting was applied. The estimated fair value of the financial crude oil and natural gas contracts outstanding at year end have been recorded on the balance sheet with the change in fair value of these contracts from May 1, 2006 to December 31, 2006 recorded in net income. The accounting treatment for financial commodity contracts entered into after May 1, 2006 and where hedge accounting was no longer applied by Pengrowth is consistent with the accounting standards for these contracts under U.S. GAAP.

At December 31, 2005, $18.4 million was recorded as a current liability in respect of the fair value of financial crude oil and natural gas hedges outstanding at year end with a corresponding change in accumulated other comprehensive income. These amounts were recognized against crude oil and natural gas sales over the terms of the related hedges.

At December 31, 2005, $0.3 million was recorded as a current liability with respect to the ineffective portion of crude oil and natural gas hedges outstanding at year end, with a corresponding change in net income.

At December 31, 2005, Pengrowth's foreign currency swap was not designated as a hedge resulting in the estimated fair value of $2.2 million being recorded as a liability with a corresponding charge to net income. Subsequent to December 31, 2005, Pengrowth designated the foreign currency swap as a cash flow hedge on its U.K. pound denominated debt. Changes in the fair value of the foreign currency swap subsequent to designation as a hedge are charged to other comprehensive income and reclassified to earnings to the extent the amount offsets unrealized gains and losses on the translation of the U.K. denominated debt. Under Canadian GAAP, for the year ended December 31, 2006, a $13.6 million exchange loss on the translation of the U.K. pound denominated debt was deferred and included in other assets on the balance sheet. This deferred exchange loss has been expensed under U.S. GAAP and has been offset by the reclassification of $13.6 million of the unrealized gain on the foreign currency swap from other comprehensive income.

(e) Under U.S. GAAP the Trust's equity is classified as redeemable equity as the Trust units are redeemable at the option of the holder. The redemption price is equal to the lesser of 95 percent of the market trading price of the "consolidated" trust units traded on the TSX for the ten trading days after the trust units have been surrendered for redemption and the closing market price of the "consolidated" trust units quoted on the TSX on the date the trust units have been surrendered for redemption. The total amount of trust units that can be redeemed for cash is limited to a maximum of $25,000 per month. Redemptions in excess of the cash limit must be satisfied by way of a distribution in Specie of a pro-rata share of royalty units and other assets, excluding facilities, pipelines or other assets associated with oil and natural gas production, which are held by the Trust at the time the trust units are to be redeemed.

(f) Under U.S. GAAP, an entity that is subject to income tax in multiple jurisdictions is required to disclose income tax expense in each jurisdiction. Pengrowth is subject to tax at the federal and provincial level. The portion of income tax expense (reduction) taxed at the federal level for the year ended December 31, 2006 is ($9.4 million) (2005 - $12.9 million). The portion of income tax expense (reduction) taxed at the provincial level is ($4.9 million) (2005 - $1.6 million).

(g) SFAS 123 (revised 2004) ("SFAS 123®"), "Share-Based Payment" deals with accounting for transactions in which an entity exchanges its equity instruments for goods or services. SFAS 123® also addresses transactions in which an entity incurs liabilities in exchange for goods or services that are based on the fair value of the entity's equity instruments or that may be settled by the issuance of those equity instruments. SFAS 123® requires a public entity to measure the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award (with limited exceptions). That cost will be recognized over the period during which an employee is required to provide service in exchange for the award -the requisite service period. Since January 1, 2003, Pengrowth has recognized the costs of equity instruments issued in exchange for employee services based on the grant-date fair value of the award, in accordance with Canadian GAAP. The methodology for determining fair value of equity instruments issued in exchange for employee services prescribed by SFAS 123® differs from that prescribed by Canadian GAAP, primarily as Canadian GAAP permits accounting for forfeitures of share-based payments as they occur while U.S. standards require an estimate of forfeitures to be made at the date of grant and thereafter until the requisite service period has been completed or the awards are cancelled.

Pengrowth adopted SFAS 123® for U.S. reporting purposes on January 1, 2006 using the modified prospective approach. Under the modified prospective approach, the valuation provisions of SFAS 123® apply to new awards and to awards that are outstanding on the effective date and subsequently modified or cancelled. Under the modified prospective application, prior periods are not restated for comparative purposes. Upon adoption of SFAS 123®, Pengrowth began using a binomial lattice model for estimating the fair value of trust unit rights for both Canadian and U.S. GAAP purposes. The impact of the change to a binomial lattice model for estimating fair value of trust unit rights was not material. The required adjustment under U.S. GAAP to account for estimated forfeitures was not significant for all periods presented.

(h) Under U.S. GAAP, the unrealized gain on crude oil and natural gas derivative contracts of $26.5 million for the year ended December 31, 2006 would be combined with realized gains or losses on crude oil and natural gas derivative contracts and recorded in oil and gas sales.

(i) Under Canadian GAAP, the Trust's convertible debentures are classified as debt with a portion, representing the estimated fair value of the conversion feature at the date of issue, being allocated to equity. In addition, under Canadian GAAP a non-cash interest expense or income representing the effective yield of the debt component is recorded in the consolidated statements of income with a corresponding credit or debit to the convertible debenture liability balance to accrete or amortize the balance to the principal due on maturity.

Under U.S. GAAP, the convertible debentures, in their entirety, are classified as debt. The non-cash interest expense recorded under Canadian GAAP would not be recorded under U.S. GAAP.

(j) Under SFAS 141, "Business Combinations", supplemental pro forma disclosure is required for significant business combinations occurring during the year. On October 2, 2006, Pengrowth and Esprit Trust completed a business combination. The consolidated financial statements include the results of operations and cash flows of Esprit Trust and Esprit subsequent to October 2, 2006.

The following unaudited pro forma information provides an indication of what Pengrowth's results of operations might have been under U.S. GAAP, had the business combination taken place on January 1 of each of the following years:



2006 Pro Forma 2005 Pro forma
(unaudited) (unaudited)
---------------------------------------------------------------------------
Oil and gas sales $ 1,458,370 $ 1,441,793
Net income $ 182,661 $ 355,573
Net income per trust unit:
---------------------------------------------------------------------------
Basic $ 0.90 $ 1.85
---------------------------------------------------------------------------
Diluted $ 0.89 $ 1.85
---------------------------------------------------------------------------


(k) Under U.S. GAAP, the amount shown as bank indebtedness of $14.6 million for the year ended December 31, 2005 on the consolidated statement of cash flows would be shown as cash generated from financing activities.

(l) New Accounting Pronouncements

In July 2006, the Financial Accounting Standards Board ("FASB") issued FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes - an Interpretation of FASB Statement No. 109 ("FIN 48"). FIN 48 provides guidance for recognizing and measuring uncertain tax positions, as defined in SFAS 109, Accounting for Taxes. FIN 48 prescribes a threshold condition that a tax position must meet for any of the benefit of the uncertain tax position to be recognized in the financial statements. Guidance is also provided regarding de-recognition, classification and disclosure of these uncertain tax positions. FIN 48 is effective for fiscal years beginning after December 15, 2006. Pengrowth has not yet determined the impact on the financial position, results of operations or cash flows from FIN 48.

In February 2006, the FASB issued SFAS No. 155, 'Accounting for Certain Hybrid Financial Instruments - an amendment of FASB Statements No. 133 and 140' ("SFAS 155"). SFAS 155 simplifies the accounting for certain hybrid financial instruments under SFAS 133 by permitting fair value remeasurement for financial instruments containing an embedded derivative that otherwise would require separation of the derivative from the financial instrument. SFAS 155 is effective for all financial instruments acquired, issued or subject to a remeasurement event occurring in fiscal years beginning after September 15, 2006. Pengrowth does not expect that SFAS 155 will have a material impact on the financial position, results of operations or cash flows.

In September 2006, the FASB issued SFAS No. 157, 'Fair Value Measurements' ("SFAS 157"). SFAS 157 defines fair value, establishes a framework for measuring fair value under GAAP and to expand disclosures about fair value measurements. The statement is effective for fair value measures already required or permitted by other standards for financial statements issued for fiscal years beginning after November 15, 2007 and interim periods within those fiscal years. Pengrowth has not yet determined the impact on the financial position, results of operations or cash flows from SFAS 157.



Consolidated Statements of Income

The application of U.S. GAAP would have the following effect on net income
as reported:

(Stated in thousands of Canadian Dollars, except per trust unit amounts)

---------------------------------------------------------------------------
Years ended December 31, 2006 2005

---------------------------------------------------------------------------

Net income, as reported $ 262,303 $ 326,326

Adjustments:
Depletion and depreciation (a) 23,997 24,723
Ceiling test write down under US GAAP (a) (114,212) -
Unrealized gain (loss) on ineffective portion
of oil and natural gas hedges (d) 255 (255)
Unrealized loss on foreign exchange contract (d) - (2,204)
Reclassification of hedging losses on foreign
exchange swap from other comprehensive income (d) - 13,631
Deferred foreign exchange loss (d) (13,631) -
Non-cash interest on convertible debentures (i) (29) -
---------------------------------------------------------------------------
Net income - U.S. GAAP $ 172,314 $ 348,590
Other comprehensive income (c):
Unrealized gain on foreign exchange swap (d) 16,077 -
Unrealized hedging gain (loss) (d) 18,153 (25,470)
Reclassification to net income (d) (13,631) -
---------------------------------------------------------------------------
Comprehensive income - U.S. GAAP $ 192,913 $ 323,120
---------------------------------------------------------------------------
---------------------------------------------------------------------------

Net income - U.S. GAAP
Basic $ 0.98 $ 2.22
Diluted $ 0.98 $ 2.21

---------------------------------------------------------------------------
---------------------------------------------------------------------------


Consolidated Balance Sheets

The application of U.S. GAAP would have the following effect on the Balance
Sheets as reported:

(Stated in thousands of Canadian Dollars)

---------------------------------------------------------------------------
---------------------------------------------------------------------------
As Increase
December 31, 2006 Reported (Decrease) U.S. GAAP
---------------------------------------------------------------------------

Assets:
Current portion of unrealized foreign
exchange gain (d) $ - $ 1,559 $ 1,559
Other assets (d) 29,097 (1,317) 27,780
Capital assets (a) 3,741,602 (282,434) 3,459,168
---------------------------------------------------------------------------
$(282,192)
---------------------------------------------------------------------------
---------------------------------------------------------------------------

Liabilities
Convertible debentures (i) $ 75,127 $ 189 $ 75,316

Unitholders' equity (e):
Accumulated other comprehensive income
(c)(d) $ - $ 2,446 $ 2,446
Trust unitholders' Equity (a) 3,049,677 (284,827) 2,764,850
---------------------------------------------------------------------------
$(282,192)
---------------------------------------------------------------------------
---------------------------------------------------------------------------

As Increase
December 31, 2005 Reported (Decrease) U.S. GAAP
---------------------------------------------------------------------------

Assets:
Capital assets (a) $ 2,067,988 $ (192,219) $ 1,875,769
---------------------------------------------------------------------------
$ (192,219)
---------------------------------------------------------------------------
---------------------------------------------------------------------------

Liabilities
Accounts payable (d) $ 111,493 $ 255 $ 111,748
Current portion of unrealized
hedging loss (d) - 18,153 18,153
Current portion of unrealized
foreign currency contract (d) - 2,204 2,204

Unitholders' equity (e):
Accumulated other comprehensive
income (c)(d) $ - $ (18,153) $ (18,153)
Trust unitholders' Equity (a) 1,475,996 (194,678) 1,281,318
---------------------------------------------------------------------------
$ (192,219)
---------------------------------------------------------------------------
---------------------------------------------------------------------------


Additional disclosures required under U.S. GAAP

The components of accounts receivable are as follows:

---------------------------------------------------------------------------
---------------------------------------------------------------------------
As at December 31,
2006 2005
---------------------------------------------------------------------------

Trade $ 125,522 $ 103,619
Prepaids 23,972 20,230
Other 2,225 3,545
---------------------------------------------------------------------------
$ 151,719 $ 127,394
---------------------------------------------------------------------------
---------------------------------------------------------------------------


The components of accounts payable and accrued liabilities are as follows:

---------------------------------------------------------------------------
---------------------------------------------------------------------------
As at December 31,
2006 2005
---------------------------------------------------------------------------

Accounts payable $ 73,631 $ 50,756
Accrued liabilities 127,425 60,737
---------------------------------------------------------------------------
$ 201,056 $ 111,493
---------------------------------------------------------------------------
---------------------------------------------------------------------------



SUPPLEMENTAL INFORMATION

Reserves

Based on an independent engineering evaluation conducted by GLJ Petroleum Consultants (GLJ) effective December 31, 2006 and prepared in accordance with National Instrument 51-101 (NI 51-101), Pengrowth had proved plus probable reserves of 297.8 mmboe. This represents 442 percent replacement of proved plus probable reserves through the acquisition of 78.6 mmboe, net of dispositions, and additions of 22.7 mmboe resulting from drilling activity, improved recoveries and technical revisions, offset by 22.9 mmboe of production.

Proved producing reserves are estimated at 189.0 mmboe. These reserves represent approximately 84 percent of the total proven reserves of 225.9 mmboe. The total proved reserves account for 76 percent of the proved plus probable reserves. These percentages compare to 82 percent and 80 percent, respectively for 2005.

Using a ten percent discount factor and GLJ January 1, 2007 pricing, the proved producing reserves account for 70 percent of the proved plus probable value while the total proved reserves account for 81 percent of the proved plus probable value. Using a 6:1 boe conversion rate for natural gas, approximately 38 percent of Pengrowth's proved plus probable reserves are light/medium crude oil, six percent are heavy oil, ten percent are NGLs and 46 percent are natural gas.

Pengrowth is 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, British Columbia, Saskatchewan and offshore Nova Scotia holdings account for 78 percent, six percent, 12 percent and four percent, respectively of reserves reported by GLJ.



Reserves Summary 2006

Company Interest (Company Gross Interest(a) plus Royalty Interest Reserves,
escalated pricing)

Light and Oil Oil
Medium Heavy Natural Equivalent Equivalent
Crude Oil Oil NGLs Gas 2006 2005
(mbbl) (mbbl) (mbbl) (bcf) (mboe) (mboe)
---------------------------------------------------------------------------
Proved
Producing 67,070 11,364 20,380 540.9 188,961 143,741
Proved
Developed
Non Producing 436 990 631 36.8 8,187 5,113
Proved
Undeveloped 17,363 1,891 1,439 48.2 28,726 26,745
---------------------------------------------------------------------------
Total Proved 84,870 14,244 22,450 625.9 225,875 175,599
---------------------------------------------------------------------------
Total Proved
plus Probable 112,388 18,336 29,142 827.5 297,774 219,396
---------------------------------------------------------------------------

(a) Company Gross Interest and Company Net Interest as defined in the
Canadian Oil and Gas Evaluation Handbook (COGEH), Volume 2, Section
5.2, November 1, 2005.
Totals may not add due to rounding.


Net Interest (Company Net Interest(b) which is the Company Interest
Reserves less Royalties Payable, escalated pricing)

Light and Oil Oil
Medium Heavy Natural Equivalent Equivalent
Crude Oil Oil NGLs Gas 2006 2005
(mbbl) (mbbl) (mbbl) (bcf) (mboe) (mboe)
---------------------------------------------------------------------------
Proved
Producing 57,753 9,973 14,569 427.8 153,592 116,877
Proved
Developed
Non Producing 348 836 452 27.9 6,291 3,893
Proved
Undeveloped 14,781 1,634 1,075 38.4 23,895 22,200
---------------------------------------------------------------------------
Total Proved 72,882 12,443 16,096 494.1 183,777 142,970
---------------------------------------------------------------------------
Total Proved
plus Probable 96,333 15,911 20,958 651.4 241,763 178,246
---------------------------------------------------------------------------

(b)Company Gross Interest and Company Net Interest as defined in the
Canadian Oil and Gas Evaluation Handbook (COGEH), Volume 2, Section
5.2, November 1, 2005.
Totals may not add due to rounding.


Reserve Reconciliation

Pengrowth added 101.3 mmboe of proved plus probable reserves during 2006, replacing production by 442 percent. Acquisitions accounted for approximately 80 percent of the reserve increase, primarily from the Esprit Trust business combination and purchase of the Carson Creek assets. The balance of additions resulted mainly from drilling and improved recovery. Most significant were infill drilling and drilling extensions for Horseshoe Canyon coalbed methane (CBM), infill drilling and increased CO2 miscible flood recovery in the Weyburn Unit, an exploration discovery at Quirk Creek and infill drilling at Tangleflags and Monogram. Disposition of various non-core assets resulted in a decrease of 2.8 mmboe.



Reserves Reconciliation 2006
Company Interest Volumes (before deduction of Royalty Burdens Payable)

Light and
Medium Heavy Natural Oil
Crude Oil Oil NGL's Gas Equivalent
(mbbl) (mbbl) (mbbl) (bcf) (mboe)
---------------------------------------------------------------------------
Total Proved
December 31, 2005 77,352 12,684 15,342 421.3 175,599
Exploration and development 997 1,811 550 40.2 10,062
Improved recovery 1,142 - 27 0.8 1,306
Revisions 900 935 422 3.2 2,786
Acquisitions 12,693 626 8,809 234.5 61,215
Dispositions (248) - (228) (10.1) (2,163)
Production (7,965) (1,812) (2,473) (64.1) (22,930)
---------------------------------------------------------------------------
December 31, 2006 84,870 14,244 22,450 625.9 225,875
---------------------------------------------------------------------------
Proved plus Probable
December 31, 2005 98,684 15,790 18,985 515.6 219,396
Exploration and development 1,662 2,597 1,037 70.3 17,020
Improved recovery 3,139 - 29 1.1 3,353
Revisions 973 886 209 1.6 2,335
Acquisitions 16,303 875 11,651 315.7 81,451
Dispositions (408) - (296) (12.9) (2,849)
Production (7,965) (1,812) (2,473) (64.1) (22,930)
---------------------------------------------------------------------------
December 31, 2006 112,388 18,336 29,142 827.4 297,774
---------------------------------------------------------------------------
Totals may not add due to rounding.


Reserves Reconciliation 2006
Net After Royalty Volumes

Light and
Medium Heavy Natural Oil
Crude Oil Oil NGLs Gas Equivalent
(mbbl) (mbbl) (mbbl) (bcf) (mboe)
---------------------------------------------------------------------------
Total Proved
December 31, 2005 65,993 11,098 10,600 331.7 142,970
Exploration and development 960 1,564 389 32.1 8,256
Improved recovery 1,099 - 12 0.6 1,214
Revisions 505 956 553 4.8 2,819
Acquisitions 10,865 528 6,789 184.7 48,962
Dispositions (222) - (180) (8.0) (1,728)
Production (6,318) (1,703) (2,067) (51.8) (18,715)
---------------------------------------------------------------------------
December 31, 2006 72,882 12,443 16,096 494.1 183,777
---------------------------------------------------------------------------
Proved plus Probable
December 31, 2005 83,929 13,714 13,218 404.3 178,246
Exploration and development 1,541 2,251 772 55.8 13,859
Improved recovery 2,992 - 56 0.8 3,188
Revisions 691 911 296 3.6 2,490
Acquisitions 13,864 737 8,918 248.8 64,980
Dispositions (366) - (234) (10.1) (2,285)
Production (6,318) (1,703) (2,067) (51.8) (18,715)
---------------------------------------------------------------------------
December 31, 2006 96,333 15,911 20,958 651.4 241,763
---------------------------------------------------------------------------
Totals may not add due to rounding.


Net Present Value Summary 2006

At GLJ January 1, 2007 escalated prices and costs(a)

Undiscounted Discounted Discounted Discounted Discounted
($ thousands) at 5% at 10% at 15% at 20%
---------------------------------------------------------------------------
Proved
Producing 5,165,355 3,858,392 3,121,677 2,649,816 2,320,338
Proved
Developed
Non Producing 203,284 155,497 125,347 104,745 89,829
Proved
Undeveloped 794,510 499,220 336,179 236,242 170,314
---------------------------------------------------------------------------
Total Proved 6,163,149 4,513,109 3,583,204 2,990,803 2,580,482
---------------------------------------------------------------------------
Proved plus
Probable 8,581,907 5,830,077 4,433,372 3,598,399 3,043,285
---------------------------------------------------------------------------
(a) Prior to provision for income taxes, interest, debt service charges and
general and administrative expenses.
Totals may not add due to rounding.


At Constant Prices at December 31, 2006(b)

Undiscounted Discounted Discounted Discounted Discounted
($ thousands) at 5% at 10% at 15% at 20%
---------------------------------------------------------------------------
Proved
Producing 4,417,128 3,363,280 2,746,285 2,341,479 2,054,496
Proved
Developed
Non Producing 152,894 119,299 97,279 81,843 70,464
Proved
Undeveloped 746,181 474,225 321,943 227,274 164,146
---------------------------------------------------------------------------
Total Proved 5,316,203 3,956,804 3,165,507 2,650,596 2,289,106
---------------------------------------------------------------------------
Proved plus
Probable 7,188,158 5,027,440 3,875,088 3,164,429 2,682,877
---------------------------------------------------------------------------
(b) Prior to provision for income taxes, interest, debt service charges and
general and administrative expenses.
Totals may not add due to rounding.


GLJ's price forecast is shown below:

Edmonton Light Natural Gas
WTI Crude Oil Crude Oil at AECO
Year ($U.S./bbl) ($Cdn/bbl) ($Cdn/mmbtu)
---------------------------------------------------------------------------
2007 62.00 70.25 7.20
2008 60.00 68.00 7.45
2009 58.00 65.75 7.75
2010 57.00 64.50 7.80
2011 57.00 64.50 7.85
2012 57.50 65.00 8.15
2013 58.50 66.25 8.30
2014 59.75 67.75 8.50
2015 61.00 69.00 8.70
2016 62.25 70.50 8.90
2017 63.50 71.75 9.10
escalate thereafter +2.0% per year +2.0% per year +2.0% per year


Constant Prices at December 31, 2006

Edmonton Light Natural Gas
WTI Crude Oil Crude Oil at AECO
Year ($U.S./bbl) ($Cdn/bbl) ($Cdn/mmbtu)
---------------------------------------------------------------------------
2007 60.85 67.58 6.07


Net Asset Value at December 31, 2006

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 escalated price forecast, and constant (year end 2006) prices.



GLJ 2007-01 Constant
($thousands, except per unit amount) Price Forecast Price Forecast
---------------------------------------------------------------------------
Value of Proved plus Probable Reserves
discounted at 10% 4,433,372 3,875,088
Undeveloped lands (1) 220,125 220,125
Working capital (2) (65,829) (65,829)
Remediation trust fund 11,144 11,144
Long term debt and note payable (3) (621,025) (621,025)
Convertible debentures (75,127) (75,127)
Asset retirement obligation (4) (139,932) (104,795)
---------------------------------------------------------------------------
Net asset value 3,762,728 3,239,581
Units outstanding (000's) 244,017 244,017
---------------------------------------------------------------------------
Net asset value per unit $15.42 $13.28
---------------------------------------------------------------------------
(1) Pengrowth's internal estimate
(2) Working capital excludes distributions payable
(3) Long term debt plus note payable less current portion plus contract
liabilities discounted at appropriate rate
(4) The asset retirement obligation is based on Pengrowth's estimate of
future site restoration and abandonment liabilities less that portion
of these costs that are included in the value of proved plus probable
reserves.


Reserve Life Index (RLI)

Pengrowth's proved RLI decreased to 8.0 years from 8.6 years last year. The proved plus probable RLI of 10.1 years can be compared to last year's value of 10.5 years. The decrease is mainly due to the shorter life reserves acquired in 2006 and Pengrowth's efforts to maximize production and present value.



Reserve Life Index 2006 2005 2004
---------------------------------------------------------------------------

Total Proved 8.0 8.6 8.6

Proved plus Probable 10.1 10.5 10.4


FINDING, DEVELOPMENT AND ACQUISITION COSTS

Finding and Development Costs
During 2006, Pengrowth spent $300.8 million on development and optimization activities, which added 14.2 mmboe of proved and 22.7 mmboe of proved plus probable reserves including revisions and essentially replacing production during the year. The largest additions were from infill drilling and drilling extensions for Horseshoe Canyon CBM, infill drilling and increased CO2 miscible flood recovery in the Weyburn Unit, an exploration discovery at Quirk Creek and infill drilling at Tangleflags and Monogram.

In total, Pengrowth participated in drilling 298 gross wells (162.9 net wells) during 2006 with a 96 percent success rate.

At Judy Creek, infill drilling and ongoing development of the hydrocarbon miscible flood projects continue to be a focus for Pengrowth along with routine maintenance capital expenditures for facility upgrades. Similar infill drilling and miscible flood development occurred in the Swan Hills Unit No. 1.

In 2006, Pengrowth participated in numerous CBM wells in the Twining area of southern Alberta. This included a 61 well program operated by Pengrowth, with many of the wells coming onstream in February 2007.

Significant capital expenditure was made during 2006 off the east coast of Canada at SOEP. One additional well was drilled at Alma and the central compression facility was completed and brought onstream in October.

Further development and optimization occurred in the Weyburn field in southeast Saskatchewan. A large infill drilling program was carried out in 2006 along with new pattern development in the CO2 miscible flood project area.

In 2006, Pengrowth participated at a 68 percent working interest in a deep foothills development well which encountered new pool reserves.

Various multi-well infill drilling programs were conducted during 2006 to increase production and maximize recoveries. In the heavy oil area, ten horizontal infill wells were drilled at Bodo and 13 vertical infills were drilled in the Tangleflags steam assisted gravity drainage project. Ongoing shallow gas development occurred with multi-well infill programs at Princess, Monogram, Tilley and Patricia. In the Dunvegan Gas Unit, another 12 infill wells were drilled.

Acquisitions and Divestitures

Pengrowth experienced its most active year ever in 2006 making significant strategic asset and corporate acquisitions. Pengrowth spent $1,839.9 million adding 59.1 mmboe of proved and 78.6 mmboe of proved plus probable reserves, net of some minor dispositions of scattered non-core properties.

In March 2006, Pengrowth acquired the Alberta assets of Tundra Oil & Gas, adding approximately 1.8 mmboe of proved plus probable reserves. Most significant of the assets acquired in this transaction was an additional 2.3991 percent working interest in the Dunvegan Gas Unit No. 1. This increased Pengrowth's ownership in the unit, which is the company's oldest original asset, to 10.3737 percent.

In September 2006, Pengrowth closed a transaction acquiring the Carson Creek assets which consisted of an 87.5 percent working interest in the Carson Creek North Unit No. 1 and a 95.1 percent working interest in both the Carson Creek Unit No. 1 and Carson Creek Gas Plant. The Carson Creek assets are in close proximity to Pengrowth's Judy Creek and Swan Hills focus area. The acquisition added 18.9 mmboe of proved plus probable reserves.

The strategic business combination between Pengrowth and Esprit Energy Trust closed in October 2006 providing for a combined trust with a well diversified set of quality assets with many positive attributes. The business combination added 60.7 mmboe of proved plus probable reserves.

In January 2006, Pengrowth divested some non-core assets, primarily in northeast British Columbia, to Monterey for cash and equity ownership. The sale resulted in a decrease of 2.8 mmboe of proved plus probable reserves.

Future Development Capital

If a company chooses to disclose finding and development costs, NI 51-101 requires that the calculation include changes in forecasted future development costs (FDC) relating to the reserves. Future development costs reflect the amount of capital estimated by the independent evaluator that will be required to bring non-producing, undeveloped or probable reserves on stream. These forecasts of future development costs will change with time due to ongoing development activity, inflationary changes in capital costs and acquisition or disposition of assets. Pengrowth provides the calculation of finding and development costs both with and without change in future development costs.



Proved Probable
---------------------------------------------------------------------------

Finding, Development & Acquisition Costs Excluding
FDC
Exploration and Development Capital Expenditures
-$thousands $ 300,800 $ 300,800
Exploration and Development Reserve Additions
including Revisions - mboe 14,155 22,706
---------------------------------------------------------------------------
Finding and Development Cost - $/boe $ 21.25 $ 13.25
---------------------------------------------------------------------------

Net Acquisition Capital - $thousands $1,839,900 $1,839,900
Net Acquisition Reserve Additions - mboe 59,051 78,602
---------------------------------------------------------------------------
Net Acquisition Cost - $/boe $ 31.16 $ 23.41
---------------------------------------------------------------------------

Total Capital Expenditures including Net
Acquisitions - $thousands $2,140,700 $2,140,700
Reserve Additions including Net Acquisitions - mboe 73,206 101,307
---------------------------------------------------------------------------
Finding Development and Acquisition Cost - $/boe $ 29.24 $ 21.13
---------------------------------------------------------------------------

Finding, Development & Acquisition Costs Including
FDC
Exploration and Development Capital Expenditures
-$thousands $ 300,800 $ 300,800
Exploration and Development Change in FDC
-$thousands $ 6,000 $ 93,100
Exploration and Development Capital including
Change in FDC - $thousands $ 306,800 $ 393,900
Exploration and Development Reserve Additions
including Revisions - mboe 14,155 22,706
---------------------------------------------------------------------------
Finding and Development Cost - $/boe $ 21.67 $ 17.35
---------------------------------------------------------------------------

Net Acquisition Capital - $thousands $1,839,900 $1,839,900
Net Acquisition FDC - $thousands $ 101,600 $ 158,900
Net Acquisition Capital including FDC - $thousands $1,941,500 $1,998,800
Net Acquisition Reserve Additions - mboe 59,051 78,602
---------------------------------------------------------------------------
Net Acquisition Cost - $/boe $ 32.88 $ 25.43
---------------------------------------------------------------------------

Total Capital Expenditures including Net
Acquisitions - $thousands $2,140,700 $2,140,700
Total Change in FDC - $thousands $ 107,600 $ 252,000
Total Capital including Change in FDC - $thousands $2,248,300 $2,392,700
Reserve Additions including Net Acquisitions - mboe 73,206 101,307
---------------------------------------------------------------------------
Finding Development and Acquisition Cost including
FDC - $/boe $ 30.71 $ 23.62
---------------------------------------------------------------------------


Total Future Net Revenue (Undiscounted)
GLJ January 1, 2007 escalated pricing:

Operating
($ thousands) Revenue Royalties costs
---------------------------------------------------------------------------
Proved Producing 10,898,910 1,954,030 3,462,128
Proved Developed Non Producing 404,027 85,212 89,141
Proved Undeveloped 1,954,012 297,673 592,827
---------------------------------------------------------------------------
Total Proved 13,256,949 2,336,915 4,144,096
---------------------------------------------------------------------------
Total Probable 4,792,511 875,266 1,266,118
---------------------------------------------------------------------------
Proved plus Probable 18,049,460 3,212,181 5,410,213
---------------------------------------------------------------------------


Revenue
Development Abandonment before
($ thousands) costs costs(a) income tax
---------------------------------------------------------------------------
Proved Producing 162,320 155,078 5,165,355
Proved Developed Non Producing 21,920 4,470 203,284
Proved Undeveloped 258,977 10,025 794,510
---------------------------------------------------------------------------
Total Proved 443,216 169,574 6,163,149
---------------------------------------------------------------------------
Total Probable 210,793 21,576 2,418,758
---------------------------------------------------------------------------
Proved plus Probable 654,009 191,150 8,581,907
---------------------------------------------------------------------------


Constant Price at December 31, 2006:

Operating
($ thousands) Revenue Royalties costs
---------------------------------------------------------------------------
Proved Producing 9,183,921 1,643,607 2,860,330
Proved Developed Non Producing 324,716 67,222 79,441
Proved Undeveloped 1,826,149 280,122 545,328
---------------------------------------------------------------------------
Total Proved 11,334,786 1,990,951 3,485,099
---------------------------------------------------------------------------
Total Probable 3,544,535 673,554 797,936
---------------------------------------------------------------------------
Proved plus Probable 14,879,321 2,664,505 4,283,035
---------------------------------------------------------------------------


Revenue
Development Abandonment before
($ thousands) costs costs(a) income tax
---------------------------------------------------------------------------
Proved Producing 145,573 117,283 4,417,128
Proved Developed Non Producing 21,610 3,549 152,894
Proved Undeveloped 248,067 6,451 746,181
---------------------------------------------------------------------------
Total Proved 415,250 127,283 5,316,203
---------------------------------------------------------------------------
Total Probable 195,706 5,384 1,871,955
---------------------------------------------------------------------------
Proved plus Probable 610,956 132,667 7,188,158
---------------------------------------------------------------------------
(a) Downhole abandonment costs
Totals may not add due to rounding.


Pro Forma Reserves Summary 2006

On January 22, 2007, Pengrowth closed the acquisition of four subsidiaries of Burlington Resources Ltd., a subsidiary of ConocoPhillips, holding Canadian oil and natural gas producing properties and undeveloped lands (the "CP Properties"). (See note 22 of the financial statements). As part of an ongoing focus of high-grading its portfolio, Pengrowth has selected non-core assets from legacy Pengrowth and the Esprit Trust and CP Properties acquisitions for disposition in 2007. These properties are expected to total approximately 25 mmboe in proved plus probable reserves (on a company interest, before royalties basis). The disposition of these assets is expected to occur in the first half of 2007. Based on an independent engineering evaluation conducted by GLJ effective December 31, 2006 and prepared in accordance with NI 51-101, pro forma reserves at December 31, 2006 including this acquisition and excluding anticipated dispositions are summarized below:



Company Interest (Company Gross Interest(a) plus Royalty Interest Reserves,
escalated pricing)

Light and Oil Oil
Medium Heavy Natural Equivalent Equivalent
Crude Oil Oil NGLs Gas 2006 2005
(mbbl) (mbbl) (mbbl) (bcf) (mboe) (mboe)
---------------------------------------------------------------------------
Proved
Producing 79,647 17,037 23,314 683.0 233,839 143,741
Proved
Developed
Non Producing 696 990 685 39.1 8,881 5,113
Proved
Undeveloped 18,819 2,232 1,569 70.2 34,326 26,745
---------------------------------------------------------------------------
Total Proved 99,162 20,258 25,569 792.3 277,046 175,599
---------------------------------------------------------------------------
Total Proved
plus Probable 131,518 25,892 32,991 1,035.1 362,915 219,396
---------------------------------------------------------------------------

(a) Company Gross Interest and Company Net Interest as defined in the
Canadian Oil and Gas Evaluation Handbook (COGEH), Volume 2, Section
5.2, November 1, 2005.
Totals may not add due to rounding.


Pro Forma Reserve Life Index

Including the reserves acquired with the CP properties, Pengrowth's
pro-forma RLI is 9.9 years on proved plus probable basis and 7.9 years on a
proved basis.

Reserve Life Index 2006 2005 2004
---------------------------------------------------------------------------

Total Proved 7.9 8.6 8.6

Proved plus Probable 9.9 10.5 10.4


Tax Pools

On a combined basis, Pengrowth's tax pools total approximately $2 billion. The table below provides an estimate of tax pools at both the trust and the operating entity level as at December 31, 2006. These estimates are based upon forecasts prepared internally and have not been verified by any provincial or federal taxing authority. They have been included for information purposes only.


($ millions)
---------------------------------------------------------------------------
Trust Tax Pools $ 1,177

Operating Entity Tax Pools
COGPE 68
CDE 334
UCC 665
CEE 34
Other (Injectants, etc.) 168
---------------------------------------------------------------------------
Total Tax Pools $ 2,446
---------------------------------------------------------------------------


PENGROWTH CORPORATION

James S. Kinnear, Chairman, President and CEO

All amounts are stated in Canadian dollars unless otherwise specified.

Advisory Regarding Forward-Looking Statements

This press release contains forward-looking statements within the meaning of securities laws, including the "safe harbour" provisions of Canadian securities legislation and the United States Private Securities Litigation Reform Act of 1995. Forward-looking information is often, but not always, identified by the use of words such as "anticipate", "believe", "expect", "plan", "intend", "forecast", "target", "project", "guidance" "may", "will", "should", "could", "estimate", "predict" or similar words suggesting future outcomes or language suggesting an outlook. Forward-looking statements in this press release include, but are not limited to, statements with respect to: reserves, 2007 production, production additions from Pengrowth's 2007 development program, the impact on production of divestitures in 2007, royalty obligations, 2007 operating expenses, future income taxes, asset retirement obligations, taxability of distributions, remediation and abandonment expenses, capital expenditures, new head office expenses, general and administration expenses and the impact of the proposed changes to the Canadian tax legislation. Statements relating to "reserves" are deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions that the reserves described exist in the quantities predicted or estimated and can profitably be produced in the future.

Forward-looking statements and information are based on Pengrowth's current beliefs as well as assumptions made by and information currently available to Pengrowth concerning anticipated financial performance, business prospects, strategies, regulatory developments future oil and natural gas commodity prices and differentials between light, medium and heavy oil prices, future oil and natural gas production levels, future exchange rates, the proceeds of anticipated divestitures, the amount of future cash distributions paid by Pengrowth, the cost of expanding our property holdings, our ability to obtain equipment in a timely manner to carry out development activities, our ability to market our oil and natural gas successfully to current and new customers, the impact of increasing competition, our ability to obtain financing on acceptable terms, and our ability to add production and reserves through our development and exploitation activities. Although management considers these assumptions to be reasonable based on information currently available to it, they may prove to be incorrect.

By their very nature, forward-looking statements involve inherent risks and uncertainties, both general and specific, and risks that predictions, forecasts, projections and other forward-looking statements will not be achieved. We caution readers not to place undue reliance on these statements as a number of important factors could cause the actual results to differ materially from the beliefs, plans, objectives, expectations and anticipations, estimates and intentions expressed in such forward-looking statements. These factors include, but are not limited to: the volatility of oil and gas prices; production and development costs and capital expenditures; the imprecision of reserve estimates and estimates of recoverable quantities of oil, natural gas and liquids; Pengrowth's ability to replace and expand oil and gas reserves; environmental claims and liabilities; incorrect assessments of value when making acquisitions; increases in debt service charges; the loss of key personnel; the marketability of production; defaults by third party operators; unforeseen title defects; fluctuations in foreign currency and exchange rates; inadequate insurance coverage; compliance with environmental laws and regulations; changes in tax laws; the failure to qualify as a mutual fund trust; and Pengrowth's ability to access external sources of debt and equity capital. Further information regarding these factors may be found under the heading "Business Risks" herein and under "Risk Factors" in Pengrowth's most recent Annual Information Form (AIF) and in Pengrowth's most recent consolidated financial statements, management information circular, quarterly reports, MD&A, material change reports and news releases. Copies of the Trust's Canadian public filings are available on SEDAR at www.sedar.com . The Trust's U.S. public filings, including the Trust's most recent annual report form 40-F as supplemented by its filings on form 6-K, are available at www.sec.gov.

Pengrowth cautions that the foregoing list of factors that may affect future results is not exhaustive. When relying on our forward-looking statements to make decisions with respect to Pengrowth, investors and others should carefully consider the foregoing factors and other uncertainties and potential events. Furthermore, the forward-looking statements contained in this press release are made as of the date of this press release and Pengrowth does not undertake any obligation to update publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise, except as required by law. The forward-looking statements contained in this press release are expressly qualified by this cautionary statement.

Caution Regarding Engineering Terms:

When used herein, the term "boe" means barrels of oil equivalent on the basis of one boe being equal to one barrel of oil or NGLs or 6,000 cubic feet of natural gas (6 mcf: 1 bbl). Barrels of oil equivalent may be misleading, particularly if used in isolation. A conversion ratio of six 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. As used herein, the term mmboe is defined as millions of barrels of oil equivalent. All production figures stated are based on company interest before the deduction of royalties.

The U.S. Securities and Exchange Commission (SEC) permits United States oil and natural gas companies, in their filings therewith, to disclose only proved reserves net of royalties and interests of others that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Canadian securities laws permit oil and natural gas companies, in their filings with Canadian securities regulators, to disclose reserves prior to the deduction of royalties and interests of others, and to disclose probable reserves. Probable reserves are of a higher risk and are generally believed to be less likely to be recovered than proved reserves. Certain reserve information used herein to describe our reserves, such as "probable" reserve information, is prohibited in filings with the SEC by U.S. oil and natural gas companies.

Contact Information