SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 6-K

PENGROWTH ENERGY TRUST

     [Indicate by check mark whether the registrant files or will file annual reports under cover Form 20-F or Form 40-F.]

Form 20-F o                               Form 40-F þ

     [Indicate by check mark whether the registrant by furnishing the information contained in this Form is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2(b) under the Security Exchange Act of 1934.

Yes o                              No þ

     [If “Yes” is marked, indicate below the file number assigned to the registrant in connection with Rule 12g3-2(b):                    ]

 

 

DOCUMENTS FURNISHED HEREUNDER:

1.

Press Release announcing unaudited financial, operating and reserve results for year ended December 31, 2005.

SIGNATURES

     Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

		PENGROWTH ENERGY TRUST by its administrator PENGROWTH CORPORATION
February 28, 2006		By:		/s/ Gordon M. Anderson   Name: Gordon M. Anderson
				Title: Vice President

NEWS RELEASE

Attention: Financial Editors		Stock Symbol:		(PGF.A / PGF.B) — TSX;
				(PGH) — NYSE

PENGROWTH ENERGY TRUST ANNOUNCES UNAUDITED FINANCIAL, OPERATING AND
RESERVE RESULTS FOR YEAR ENDED DECEMBER 31, 2005

(Calgary February 27, 2006) /CCN Matthews/ — Pengrowth Corporation, administrator of Pengrowth Energy Trust, is pleased to report operating and financial results for the fourth quarter and year ended December 31, 2005 as well as selected information from Pengrowth’s independent engineering reserve report effective December 31, 2005.

YEAR 2005 OVERVIEW

Robust commodity prices, a full year of production from the 2004 Murphy acquisition and additional production from the Swan Hills Unit No.1 (Swan Hills) and Crispin Energy Inc. (Crispin) acquisitions, which closed on February 28, 2005 and April 29, 2005, respectively, combined to have a favorable impact on 2005 financial and operating results relative to 2004.

2005 KEY ACHIEVEMENTS AND MILESTONES

	v		Oil and gas sales increased 41 percent to $1.15 billion in 2005 resulting in record net income of $326 million, an increase of 112 percent over 2004.
	v		Production for 2005 averaged 59,357 barrels of oil equivalent (boe) per day, an increase of ten percent versus 2004. Fourth quarter production averaged 61,442 boe per day, an increase of four percent over the previous quarter and seven percent over the comparable period in 2004.
	v		Distributable cash reached a new high in 2005 at $620 million, an increase of 54 percent over 2004. Fourth quarter distributable cash increased 87 percent versus 2004 to $196 million, the highest level of distributable cash generated in any quarter in Pengrowth’s history.
	v		Distributions paid or declared to unitholders increased 23 percent to $446 million or $2.82 per trust unit in 2005 from $363 million or $2.63 per trust unit in 2004. Pengrowth’s monthly distribution was increased in December 2005 to an annualized rate of $3.00 per trust unit.
	v		Pengrowth’s payout ratio to unitholders for the full year and fourth quarter of 2005 reached record lows of 72 percent and 61 percent of cash generated from operations, respectively.
	v		Pengrowth’s 2005 development expenditures were essentially fully funded through the withholdings from distributable cash.
	v		During the year Pengrowth spent a combined total of $176 million on maintenance and development projects ending the year with proved plus probable reserves of 219.4 million barrels of oil equivalent (mmboe) compared to 218.6 mmboe at year-end 2004. Pengrowth’s proved plus probable reserves were replaced through the addition of 16.7 mmboe related to acquisitions and 8.6 mmboe resulting from drilling activity, improved recoveries and technical revisions. Additions were offset by production of 21.7 mmboe and divestures of 2.8 mmboe.

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	v		During 2005, Pengrowth incurred Finding and Development (F&D) costs for proved reserves of $10.63 per boe, including the change in future development capital, in accordance with NI 51-101. Excluding the downward revision to future development capital of approximately $37 million, Pengrowth’s F&D costs for proved reserves totaled $15.47 per boe during 2005. Overall finding, development and acquisition (FD&A) costs, with and without the change in future development capital, were $14.42 per boe and $16.12 per boe, respectively.
	v		Pengrowth’s average realized commodity price (after hedging) increased 28 percent to $53.02 per boe in 2005, from $41.33 in 2004.
	v		Operating netbacks increased 33 percent to $32.54 per boe (after hedging) versus $24.51 per boe in 2004. Combined hedging losses totaled $3.04 per boe in 2005 versus $3.52 per boe in 2004.
	v		On February 28, 2005, Pengrowth acquired an additional 11.9 percent working interest in the Swan Hills property for $87 million. This acquisition increased Pengrowth’s total interest in the property to 22.3 percent.
	v		On April 29, 2005, Pengrowth successfully completed the acquisition of all of the issued and outstanding shares of Crispin, adding approximately 1,900 boe per day of production to our portfolio.
	v		On December 1, 2005, Pengrowth completed a £50 million private placement of senior unsecured ten year notes.
	v		As at December 31, 2005, Pengrowth had $337 million of funds available under its $370 million in committed credit facilities.
	v		As at December 31, 2005, Pengrowth had generated a combined three-year weighted average compound total return of 36 percent per annum for Class A and Class B unitholders.

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

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Summary of Financial and Operating Results
		Three Months ended												Twelve Months ended
		December 31								%				December 31								%
(thousands, except per unit amounts)		2005				2004				Change				2005				2004				Change
INCOME STATEMENT
Oil and gas sales		$	353,923			$	223,183	**			59	%		$	1,151,510			$	815,751	**			41	%
Net income		$	116,663			$	31,138				275	%		$	326,326			$	153,745				112	%
Net income per trust unit		$	0.73			$	0.23				217	%		$	2.08			$	1.15				81	%
Cash generated from operations		$	196,588			$	93,287				111	%		$	618,070			$	404,167				53	%
Cash generated from operations per trust unit		$	1.23			$	0.68				81	%		$	3.93			$	3.03				30	%
Distributable cash *		$	195,879			$	104,958	**			87	%		$	619,739			$	401,178	**			54	%
Distributable cash per trust unit *		$	1.23			$	0.77				60	%		$	3.94			$	3.01				31	%
Distributions paid or declared		$	119,858			$	96,466				24	%		$	445,977			$	363,061				23	%
Distributions paid or declared per unit		$	0.75			$	0.69				9	%		$	2.82			$	2.63				7	%
Weighted average number of trust units outstanding			159,528				136,916				17	%			157,127				133,395				18	%
BALANCE SHEET
Working capital														$	(112,205	)		$	(78,546	)			43	%
Property, plant and equipment and other assets														$	2,067,988			$	1,989,288				4	%
Long term debt														$	368,089			$	345,400				7	%
Unitholders’ equity														$	1,475,996			$	1,462,211				1	%
Unitholders’ equity per trust unit														$	9.23			$	9.56				-3	%
Number of trust units outstanding at year-end															159,864				152,973				5	%
Daily Production
Crude oil (barrels)			21,179				20,118				5	%			20,799				20,817				0	%
Heavy oil (barrels)			5,410				5,819				-7	%			5,623				3,558				58	%
Natural gas (mcf)			168,862				156,621				8	%			161,056				144,277				12	%
Natural gas liquids (barrels)			6,710				5,385				25	%			6,093				5,281				15	%
Total production (boe)			61,442				57,425				7	%			59,357				53,702				10	%
Total Production (mboe)			5,653				5,283				7	%			21,665				19,655				10	%
Production Profile
Crude oil			34	%			35	%							35	%			39	%
Heavy oil			9	%			10	%							10	%			6	%
Natural gas			46	%			46	%							45	%			45	%
Natural gas liquids			11	%			9	%							10	%			10	%
Average Realized Prices (after hedging)
Crude oil (per barrel)		$	59.40			$	44.76				33	%		$	58.59			$	43.21				36	%
Heavy oil (per barrel)		$	31.77			$	26.99				18	%		$	33.32			$	32.45				3	%
Natural gas (per mcf)		$	11.97			$	7.02				71	%		$	8.76			$	6.80				29	%
Natural gas liquids (per barrel)		$	58.46			$	48.04				22	%		$	54.22			$	42.21				28	%
Average realized price per boe		$	62.55			$	42.08	**			49	%		$	53.02			$	41.33	**			28	%
Proved Plus Probable (P50) Reserves
Crude oil (mbbls)															98,684				94,066				5	%
Heavy oil (mbbls)															15,790				18,245				-13	%
Natural gas (bcf)															516				521				-1	%
Natural gas liquids (mbbls)															18,985				19,395				-2	%
Total oil equivalent (mboe)															219,396				218,613				0	%

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Frequently Recurring Terms

For the purposes of this release, 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 the Corporation on a consolidated basis and the “Manager” refers to Pengrowth Management Limited.

Advisory Regarding Forward-Looking Statements

This release contains forward-looking statements within the meaning of securities laws, including the “safe harbour” provisions of the Ontario Securities Act 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”, “may”, “will”, “should”, “could”, “estimate”, “predict” or similar words suggesting future outcomes or language suggesting an outlook. Forward-looking statements in this release include, but are not limited to, statements with respect to: reserves, average 2006 production, production additions from Pengrowth’s 2006 development program, the impact on production of divestitures in 2006, total operating cost for 2006, 2006 operating costs per boe, capital expenditures for 2006 and the breakdown of such capital expenditures for drilling, facilities and maintenance, land and seismic acquisition and re-completions, workovers and CO₂ pilot. 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 and regulatory developments. 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 predications, 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 in the Supplemental Information section under the heading “Business Risks” herein and under “Risk Factors” in Pengrowth’s Annual Information Form which will be available on SEDAR at www.sedar.com on or before March 31, 2006.

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 release are made as of the date of the release and Pengrowth does not undertake any obligation to up-date publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise. The forward-looking statements contained in this release are expressly qualified by this cautionary statement.

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Critical Accounting Estimates

As discussed in Note 2 to the 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 period then 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), 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 release 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 distributable cash, distributable cash per trust unit, payout ratio and operating netbacks do not have standardized meanings prescribed by GAAP. During the second quarter of 2005, Pengrowth’s withholding practice and presentation of distributable cash changed. The impact of the new practice is discussed in the Distributable Cash, Distributions and Taxability of Distributions section of this release, while the remaining non-GAAP measures are determined by reference to our financial statements. We discuss these measures because we believe that they facilitate the understanding of the results of our operations and financial position.

Conversion and Currency

When converting natural gas to equivalent barrels of oil within this release, Pengrowth uses the international standard of six thousand cubic feet (mcf) 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 over ten percent in 2005 compared to 2004. The increase is attributable primarily to the Murphy, Swan Hills and Crispin acquisitions and contributions from ongoing development activities. At this time, Pengrowth is forecasting average 2006 production of 54,000 to 56,000 boe per day from existing assets. This estimate incorporates anticipated production additions from planned 2006 development activities. Offsetting these additions are previously disclosed divestitures of approximately 1,300 boe per day in the first quarter of 2006 which have been excluded from the above estimate, including the divestment of approximately 1,000 boe per day related to the Monterey Exploration Ltd. (Monterey) transaction announced on January 12, 2006 and expected production declines from normal operations. The above estimate specifically excludes the potential impact of any other future acquisitions or divestitures.

		Three months ended													Twelve months ended
Daily Production		Dec 31, 2005				Sept 30, 2005				Dec 31, 2004					Dec 31, 2005				Dec 31, 2004
Light crude oil (bbls) (1)			21,179				20,660				20,118					20,799				20,817
Heavy oil (bbls) (1)			5,410				5,405				5,819					5,623				3,558
Natural gas (mcf)			168,862				164,288				156,621					161,056				144,277
Natural gas liquids (bbls) (1)			6,710				5,448				5,385					6,093				5,281
Total boe per day			61,442				58,894				57,425					59,357				53,702

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Light crude oil production volumes remained relatively flat year-over-year due to the positive impact of production related to the Swan Hills and Crispin acquisitions which largely offset natural production declines. Improved miscible flood response at Judy Creek contributed to most of the three percent increase in production in fourth quarter 2005 versus the third quarter of 2005.

Heavy oil production increased 58 percent year-over-year due to the inclusion of a full 12 months of production volumes from properties acquired in the Murphy acquisition which closed on May 31, 2004. The seven percent decrease in production for the fourth quarter of 2005 compared to the fourth quarter of 2004 is attributable to natural production declines.

Natural gas production increased 12 percent year-over-year. Additional production volumes from the Murphy and Crispin acquisitions and ongoing development activities, particularly the Monogram infill drilling program completed in the fourth quarter of 2004, combined to more than offset natural production declines. The three percent increase in volumes in the fourth quarter of 2005 compared to the third quarter of 2005 is due largely to a 44 well drilling program at Princess which was completed during the fourth quarter. Fourth quarter 2005 volumes were eight percent higher than fourth quarter 2004 volumes primarily due to the Crispin acquisition, new wells at Princess and Sable Offshore Energy Project (SOEP) and lower residue gas solvent demand at Judy Creek allowing for increased sales.

Natural gas liquids (NGL) production increased 15 percent year-over-year primarily due to the timing and size of condensate sales from SOEP. Pengrowth received six shipments from SOEP in 2005 (two shipments in the fourth quarter) compared to four shipments in the previous year.

Pricing and Commodity Price Hedging

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

		Three months ended													Twelve months ended
		Dec 31, 2005				Sept 30, 2005				Dec 31, 2004					Dec 31, 2005				Dec 31, 2004
Average realized prices (Cdn$)
Light crude oil (per bbl)			67.00				74.37				55.24					65.47				50.72
after hedging			59.40				63.95				44.76					58.59				43.21
Heavy oil (per bbl)			31.77				47.74				26.99					33.32				32.45
Natural gas (per mcf)			12.80				8.69				7.25					8.99				7.03
after hedging			11.97				8.57				7.02					8.76				6.80
Natural gas liquids (per bbl)			58.46				57.75				48.04					54.22				42.21
Total per boe			67.43				60.06				46.38					56.06				44.85
after hedging			62.55				56.07				42.08					53.02				41.33
Benchmark prices
WTI oil (U.S.$  per bbl)			60.05				63.31				48.27					56.70				41.47
AECO spot gas (Cdn$ per gj) (1)			11.08				7.75				6.72					8.04				6.44
NYMEX gas (U.S. $ per mmbtu) (2)			12.97				8.49				7.11					8.62				6.16
Currency (U.S.$/Cdn $)			0.85				0.83				0.82					0.83				0.77

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.

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		Three months ended													Twelve months ended
Hedging Losses		Dec 31, 2005				Sept 30, 2005				Dec 31, 2004					Dec 31, 2005				Dec 31, 2004
Light crude oil ($ million)			14.8				19.8				19.4					52.2				57.2
Light crude oil ($  per bbl)			7.60				10.42				10.48					6.88				7.51
Natural gas ($ million)			12.9				1.8				3.3					13.6				11.9
Natural gas ($  per mcf)			0.83				0.12				0.23					0.23				0.23
Combined ($ million)			27.7				21.6				22.7					65.8				69.1
Combined ($  per boe)			4.88				3.99				4.30					3.04				3.52

Commodity price hedges in place at December 31, 2005 are provided in Note 17 to the financial statements. Pengrowth has not entered into any additional contracts subsequent to year-end as of February 27, 2006.

In conjunction with the Murphy acquisition, Pengrowth assumed certain fixed price natural gas sales contracts and firm pipeline demand charge contracts associated with the Murphy reserves. Under these contracts, Pengrowth is obligated to sell 3,886 mmbtu per day, until April 30, 2009 at an average remaining contract price of Cdn $2.31 per mmbtu. As required by 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, 2005 of $18.2 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. At December 31, 2005, the mark-to-market value of the fixed price physical sales contract represented a potential loss of $35.3 million.

Oil and Gas Sales — Contribution Analysis

												Three months ended																						Twelve months ended
			Dec 31,					% of				Sept 30,					% of				Dec 31,					% of				Dec 31,					% of				Dec 31,					% of
Sales Revenue ($ million)			2005					total				2005					total				2004					total				2005					total				2004					total
Natural gas				186.0				53	%				129.5				43	%				101.2				45	%				514.9				45	%				359.3				44	%
Light crude oil				115.7				33	%				121.6				40	%				82.8				37	%				444.8				39	%				329.2				40	%
Natural gas liquids				36.1				10	%				28.9				9	%				23.8				11	%				120.6				10	%				81.6				10	%
Heavy oil				15.8				4	%				23.7				8	%				14.5				7	%				68.4				6	%				42.3				5	%
Brokered sales/sulphur				0.3				0	%				0.8				0	%				0.9				0	%				2.8				0	%				3.4				1	%
Total oil and gas sales				353.9									304.5									223.2									1,151.5									815.8

Oil and Gas Sales — Price and Volumes Analysis

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

($ million)		Natural gas				Light oil				NGL				Heavy oil				Other				Total
Year ended December 31, 2004			359.3				329.2				81.6				42.3				3.4				815.8
Effect of change in product prices			115.3				112.0				26.7				1.8				—				255.8
Effect of change in sales volumes			42.0				(1.4	)			12.3				24.3				—				77.2
Effect of hedging losses			(1.7	)			5.0				—				—				—				3.3
Other			—				—				—				—				(0.6	)			(0.6	)
Year ended December 31, 2005			514.9				444.8				120.6				68.4				2.8				1,151.5

Processing, Interest and Other Income

		Three months ended													Twelve months ended
($ million)		Dec 31, 2005				Sept 30, 2005				Dec 31, 2004					Dec 31, 2005				Dec 31, 2004
Processing, interest & other income			4.0				2.1				4.5					17.7				14.2
$  per boe			0.71				0.39				0.83					0.82				0.72

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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 costs included below in Operating Expenses.

Royalties

		Three months ended													Twelve months ended
($ million)		Dec 31, 2005				Sept 30, 2005				Dec 31, 2004					Dec 31, 2005				Dec 31, 2004
Royalty expense			68.0				57.4				49.1					213.9				160.4
$  per boe			12.03				10.60				9.29					9.87				8.16
Royalties as a percent of sales			19.2	%			18.9	%			22.0	%				18.6	%			19.7	%

Royalties include crown, freehold and overriding royalties as well as mineral taxes. A lesser credit for enhanced oil recovery relief at Judy Creek had an unfavorable impact to royalties in the fourth quarter of 2004 as solvent injection costs were lower than anticipated.

Operating Expenses

		Three months ended													Twelve months ended
($ million)		Dec 31, 2005				Sept 30, 2005				Dec 31, 2004					Dec 31, 2005				Dec 31, 2004
Operating expenses			61.2				57.4				42.6					218.1				159.7
$  per boe			10.83				10.59				8.06					10.07				8.13

Operating expenses increased year-over-year as a result of timing of acquisitions partway through 2004 and in 2005 which impacted costs by approximately $30 million. Additionally, there was general upward pressure on the cost of goods and services in the oil and gas industry during 2005, with year-over-year increases of more than ten percent within most of these areas. Utility costs also increased approximately $10 million year-over-year. Operating expenses include costs incurred to earn processing and other income included above in Processing, Interest and Other Income.

Transportation Costs

		Three months ended													Twelve months ended
($ million)		Dec 31, 2005				Sept 30, 2005				Dec 31, 2004					Dec 31, 2005				Dec 31, 2004
Light oil transportation			0.5				0.6				0.4					2.2				1.8
$  per bbl			0.27				0.29				0.23					0.29				0.23
Natural gas transportation			1.8				1.4				2.0					5.7				6.3
$  per mcf			0.12				0.09				0.14					0.10				0.12

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. In 2005, 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
($ million)		Dec 31, 2005				Sept 30, 2005				Dec 31, 2004					Dec 31, 2005				Dec 31, 2004
Purchased and capitalized			14.5				6.9				8.2					34.7				20.4
Amortization			7.1				6.0				4.9					24.4				19.7

The cost of injectants (primarily natural gas and ethane) purchased for injection in miscible flood programs is amortized over the period of expected future economic benefit. Prior to 2005, the expected future economic benefit from injection was estimated at 30 months, based on the results of previous flood patterns. Commencing in 2005 the response period for additional new patterns being

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developed is expected to be somewhat shorter relative to the historical miscible patterns in the project. Accordingly, the cost of injectants purchased in 2005 will be amortized over a 24 month period while costs incurred for the purchase of injectants in prior periods will continue to be amortized over 30 months. As of December 31, 2005, 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 costs. Pengrowth currently anticipates similar injection volumes for Judy Creek and increased injection volumes for Swan Hills during 2006. This combined with higher forecast prices for natural gas and ethane is anticipated to result in increased total injectant costs for 2006.

Netbacks

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

Pengrowth recorded an operating netback of $32.54 per boe (after hedging) in 2005 compared to $24.51 (after hedging) in 2004, mainly due to higher average commodity prices in 2005 partially offset by higher operating costs and royalties.

		Three months ended												Twelve months ended
Combined Netbacks ($ per boe)		Dec 31, 2005				Sept 30, 2005				Dec 31, 2004				Dec 31, 2005				Dec 31, 2004
Sales price		$	62.55			$	56.07			$	42.08			$	53.02			$	41.33
Other production income			0.06				0.13				0.17				0.13				0.17
			62.61				56.20				42.25				53.15				41.50
Processing, interest and other income			0.71				0.39				0.83				0.82				0.72
Royalties			(12.02	)			(10.60	)			(9.29	)			(9.87	)			(8.16	)
Operating costs			(10.83	)			(10.59	)			(8.07	)			(10.07	)			(8.13	)
Transportation costs			(0.41	)			(0.36	)			(0.47	)			(0.36	)			(0.42	)
Amortization of injectants			(1.25	)			(1.10	)			(0.94	)			(1.13	)			(1.00	)
Operating netback		$	38.81			$	33.94			$	24.31			$	32.54			$	24.51

		Three months ended												Twelve months ended
Light Crude Netbacks ($ per bbl)		Dec 31, 2005				Sept 30, 2005				Dec 31, 2004				Dec 31, 2005				Dec 31, 2004
Sales price		$	59.40			$	63.95			$	44.76			$	58.59			$	43.21
Other production income			0.17				0.37				0.48				0.37				0.45
			59.57				64.32				45.24				58.96				43.66
Processing, interest and other income			0.34				0.64				0.51				0.47				0.46
Royalties			(6.47	)			(11.03	)			(9.65	)			(8.64	)			(7.62	)
Operating costs			(14.32	)			(12.85	)			(9.17	)			(12.28	)			(9.31	)
Transportation costs			(0.27	)			(0.29	)			(0.23	)			(0.29	)			(0.23	)
Amortization of injectants			(3.63	)			(3.14	)			(2.67	)			(3.21	)			(2.58	)
Operating netback		$	35.22			$	37.65			$	24.03			$	35.01			$	24.38

		Three months ended												Twelve months ended
Heavy Oil Netbacks ($ per bbl)		Dec 31, 2005				Sept 30, 2005				Dec 31, 2004				Dec 31, 2005				Dec 31, 2004
Sales price		$	31.77			$	47.74			$	26.99			$	33.32			$	32.45
Processing, interest and other income			0.74				(0.83	)			—				0.36				—
Royalties			(2.98	)			(8.00	)			(4.19	)			(4.53	)			(4.87	)
Operating costs			(11.60	)			(16.30	)			(9.44	)			(15.65	)			(9.85	)
Operating netback		$	17.93			$	22.61			$	13.36			$	13.50			$	17.73

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		Three months ended												Twelve months ended
Natural Gas Netbacks ($ per mcf)		Dec 31, 2005				Sept 30, 2005				Dec 31, 2004				Dec 31, 2005				Dec 31, 2004
Sales price		$	11.97			$	8.57			$	7.02			$	8.76			$	6.80
Processing, interest and other income			0.19				0.09				0.24				0.23				0.20
Royalties			(2.62	)			(1.47	)			(1.34	)			(1.70	)			(1.26	)
Operating costs			(1.38	)			(1.31	)			(1.16	)			(1.24	)			(1.15	)
Transportation costs			(0.12	)			(0.09	)			(0.14	)			(0.10	)			(0.12	)
Operating netback		$	8.04			$	5.79			$	4.62			$	5.95			$	4.47

		Three months ended												Twelve months ended
NGL Netbacks ($ per bbl)		Dec 31, 2005				Sept 30, 2005				Dec 31, 2004				Dec 31, 2005				Dec 31, 2004
Sales price		$	58.46			$	57.75			$	48.04			$	54.22			$	42.21
Royalties			(21.29	)			(20.57	)			(19.37	)			(17.66	)			(15.43	)
Operating costs			(10.05	)			(10.13	)			(7.87	)			(9.04	)			(7.94	)
Transportation costs			—				—				(0.10	)			—				(0.10	)
Operating netback		$	27.12			$	27.05			$	20.70			$	27.52			$	18.74

Interest

Interest expense decreased by 28 percent to $21.6 million in 2005 from $29.9 million in 2004, reflecting a lower average debt level, the impact of the appreciation of the Canadian dollar on U.S. dollar denominated interest and lower standby fees. Standby fees in 2004 of $3.9 million were related to the set-up of bridge financing utilized for the 2004 Murphy acquisition. Imputed interest on the note payable to Emera Offshore Incorporated (Emera) was also recorded in the amount of $1.3 million (2004 — $1.6 million).

The average interest rate on Pengrowth’s long term debt outstanding at December 31, 2005 is 5.1 percent. Approximately 63 percent of Pengrowth’s outstanding debt as at December 31, 2005 incurs interest expense payable in U.S. dollars and therefore remains subject to fluctuations in the U.S. dollar exchange rate. The note payable is non-interest bearing.

General and Administrative

		Three months ended													Twelve months ended
($ million)		Dec 31, 2005				Sept 30, 2005				Dec 31, 2004					Dec 31, 2005				Dec 31, 2004
Cash G&A expense			7.7				7.0				6.5					27.4				22.1
$  per boe			1.36				1.29				1.23					1.27				1.12
Non-cash G&A expense			0.8				0.6				0.4					2.9				2.3
$  per boe			0.14				0.11				0.08					0.13				0.12
Total G&A ($ million)			8.5				7.6				6.9					30.3				24.4
Total G&A ($  per boe)			1.50				1.40				1.31					1.40				1.24

The cash component of General and Administrative (G&A) increased due to a number of factors including the addition of personnel and office space in conjunction with the Murphy acquisition as well as a general increase in financial reporting, legal and regulatory costs related to the growth in our unitholder base and increasing regulatory requirements including preparing for compliance with the Sarbanes-Oxley Act and the related requirement to report on internal controls. The non-cash compensation is expense related to the value of trust unit options and rights (see Note 2 and Note 10 to the financial statements for details). Also included in 2005 G&A is $0.9 million (2004 — $0.8 million) for estimated reimbursement of G&A expenses incurred by the Manager, pursuant to the management agreement.

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Management Fees

		Three months ended													Twelve months ended
($ million)		Dec 31, 2005				Sept 30, 2005				Dec 31, 2004					Dec 31, 2005				Dec 31, 2004
Management Fee			2.2				1.6				1.4					9.1				6.8
Performance Fee			2.2				1.9				1.2					6.9				6.1
Total ($ million)			4.4				3.5				2.6					16.0				12.9
Total ($  per boe)			0.77				0.65				0.48					0.74				0.66

Under the current management agreement, which came into effect July 1, 2003 for two three-year terms ending June 30, 2009, 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. At the end of the first term, a review process will determine whether to extend the agreement for the second term. The maximum fees payable, including the performance fee, is limited to 80 percent of the fees that would otherwise have been payable under the previous management agreement for the first three years and 60 percent for the subsequent three years.

The Trust achieved a three-year average total return of 36 percent per annum at the end of 2005; as a result the Manager earned the maximum fee payable under the new management agreement.

Foreign Currency Gains and Losses

Pengrowth recorded a net foreign exchange gain of $7.0 million in 2005, compared to a foreign exchange gain of $17.3 million in 2004. Included in the 2005 gain is a $7.8 million unrealized foreign exchange gain related to the U.S. dollar denominated debt. This gain arises as a result of the increase in the Canadian to U.S. dollar exchange rate in 2005 from a rate of approximately $0.83 at December 31, 2004 to a rate of approximately $0.86 at December 31, 2005. Offsetting this gain is a realized foreign exchange loss of $0.8 million related mainly to U.S. dollar denominated receivables. Revenues are recorded at the average exchange rate for the production month in which they accrue, with payment being received on or about the 25^th of the following month. As a result of the increase in the Canadian dollar relative to the U.S. dollar over the course of the year, a foreign exchange loss was recorded to the extent that there was a difference between the average exchange rate for the month of production and the exchange rate at the date the payments were received on that portion of production sales that are received in U.S. dollars. Pengrowth has arranged a significant portion of its long term debt in U.S. dollars as a natural hedge against a stronger Canadian dollar, as the negative impact on oil and gas sales is somewhat offset by a reduction in the U.S. dollar denominated interest cost (See Note 12 to the financial statements for further detail).

Depletion, Depreciation and Accretion

		Three months ended													Twelve months ended
($ million)		Dec 31, 2005				Sept 30, 2005				Dec 31, 2004					Dec 31, 2005				Dec 31, 2004
Depletion and Depreciation			71.4				73.5				69.4					285.0				247.3
$ per boe			12.63				13.57				13.14					13.15				12.58
Accretion			3.6				3.6				3.2					14.2				10.6
$ per boe			0.64				0.66				0.60					0.65				0.54

Depletion and depreciation of property, plant and equipment and other assets is provided on the unit of production method based on total proved reserves. The provision for depletion and depreciation increased 15 percent in 2005 due to a larger depletable asset base and a higher depletion rate (production as a percentage of total proved reserves).

Accretion increased 34 percent year-over-year due to a larger Asset Retirement Obligation (ARO).

Taxes

In determining its taxable income, the Corporation deducts payments made to the Trust, effectively transferring the income tax liability to unitholders thus reducing taxable income to nil. Under the Corporation’s current distribution policy, funds are withheld from distributable cash to fund future

- 12 -

capital expenditures and repay debt. As a result of increased amounts being withheld to fund capital spending, 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 changes to the corporate structure. As a result, the Corporation does not anticipate the payment of any cash income taxes in the foreseeable future.

Capital taxes paid or payable by the Corporation, based on debt and equity levels at the end of the year, amounted to $6.2 million in 2005 (2004 — $4.6 million). This amount is comprised of Federal Large Corporations Tax of $2.2 million (2004 — $1.3 million) and Saskatchewan Capital Tax and Resource Surcharge of $4.0 million (2004 — $3.2 million). The increase in 2005 capital taxes is due to a higher taxable capital base from the Crispin acquisition and increased capital expenditures relative to 2004.

The corporate acquisition of Crispin in 2005 resulted in Pengrowth recording an additional future tax liability of $22.2 million. A $75.6 million future tax liability was initially recorded in 2004 as a result of the Murphy acquisition. The future tax liability represents 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 increased the future tax liability by $12.3 million to $110.1 million.

Capital Expenditures

During 2005, Pengrowth spent $175.7 million on development and optimization activities. The largest expenditures were in Judy Creek ($36.7 million), SOEP ($27.2 million), Princess ($11.1 million), Weyburn ($8.8 million), Prespatou ($7.5 million) and Swan Hills ($7.2 million). Pengrowth does not typically participate in high risk exploration activities and in 2005 most of the capital spent on development was directed towards increasing production, arresting production declines and improving recovery through infill drilling.

		Three months ended													Twelve months ended
($ million)		Dec 31, 2005				Sept 30, 2005				Dec 31, 2004					Dec 31, 2005				Dec 31, 2004
Geological and geophysical			0.7				0.2				0.2					2.1				0.6
Drilling and completions			40.4				29.8				36.1					129.6				111.3
Plant and facilities			10.2				10.0				17.7					34.1				49.1
Land purchases			8.8				0.8				0.2					9.9				2.3
Development capital			60.1				40.8				54.2					175.7				163.3
Acquisitions																175.1				569.7
Total capital expenditures and acqusit			60.1				40.8				54.2					350.8				733.0

Pengrowth’s planned capital expenditures for maintenance and development opportunities at existing properties are approximately $236 million for 2006 which is the largest capital program in Pengrowth’s history. Approximately half of the 2006 spending will be on a 280 gross well (132 net well) drilling program. The remainder of the budget will be spent on recompletions and reactivations, development of coalbed methane resources, production enhancements and ongoing maintenance. Pengrowth’s 2006 capital program targets the furtherance of Pengrowth’s short, medium and long term objectives, reflecting Pengrowth’s focus on pursuing a balanced approach to the development of its key assets. While the most significant portion of Pengrowth’s 2006 capital program will involve the continued development and maintenance of existing production and properties, a key element of the 2006 program will be further development of mid and longer term plays or projects in coalbed methane, heavy oil and enhanced oil recovery. Pengrowth anticipates funding its 2006 capital expenditures through a combination of undistributed cash from operations, unused credit facilities and any proceeds from property dispositions.

Acquisitions and Dispositions

On February 28, 2005, Pengrowth closed the acquisition of an additional 11.9 percent working interest in Swan Hills increasing Pengrowth’s total working interest in the unit to 22.3 percent. The

- 13 -

purchase price was $87 million, after adjustments from the October 1, 2004 effective date to the closing date.

On April 29, 2005, Pengrowth completed the acquisition of Crispin which held interests in oil and natural gas assets mainly in Alberta. This represented Pengrowth’s first acquisition of a publicly traded corporation and was funded through the issuance of Class A and Class B trust units valued at approximately $88 million. Pengrowth also assumed debt of approximately $20 million as part of the acquisition.

During the second half of 2005, Pengrowth received approximately $38 million of proceeds from the sale of non-core oil and natural gas properties with associated production of approximately 600 boe per day.

On May 31, 2004, Pengrowth acquired oil and natural gas assets in Alberta and Saskatchewan from a subsidiary of Murphy Oil Corporation for a purchase price of $550 million prior to adjustments.

On August 12, 2004, Pengrowth acquired an additional 34.4 percent interest in Kaybob Notikewin Unit No. 1 for a purchase price of $20 million, bringing Pengrowth’s total working interest in this unit to just below 99 percent.

Goodwill

In accordance with Canadian GAAP, Pengrowth recorded goodwill of $12.2 million upon the Crispin acquisition in 2005 and $170.6 million upon the Murphy acquisition in 2004. 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 4 to the financial statements.

Working Capital

Working capital declined by $33.7 million from a working capital deficiency of $78.5 million in 2004 to a working capital deficiency of $112.2 million as at December 31, 2005. Most of the working capital decline is attributable to an increase in bank indebtedness, accounts payable and accrued liabilities, distributions payable to unitholders and the current portion of the note payable, offset by an increase in accounts receivable as at December 31, 2005.

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. 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 revolving credit facility until the distribution payment on January 15.

Financial Resources and Liquidity

At year-end 2005, Pengrowth had a long term debt to debt-plus-equity at book value ratio of 0.2 and maintained $370 million in committed credit facilities which were reduced by drawings of $35 million and by $17 million in letters of credit outstanding at year-end. In addition, Pengrowth maintains a $35 million demand operating line of credit. Pengrowth remains well positioned to fund its 2006 development program and to take advantage of acquisition opportunities as they arise. At December 31, 2005, Pengrowth had $337 million available to draw from its credit facilities.

Long term debt at December 31, 2005 included fixed rate term debt denominated in U.S. dollars which translated to Cdn $232.6 million. Due to the appreciation of the Canadian dollar relative to the U.S. dollar, an unrealized gain of Cdn $57.6 million has been recorded since the U.S. dollar denominated debt was issued in April of 2003. Long term debt at December 31, 2005 also included fixed rate term debt denominated in U.K. £50 million which translated to Cdn $100.5 million.

- 14 -

Through a series of hedging transactions, Pengrowth fixed the exchange rate in Canadian dollars for all future interest payments and repayment at maturity.

Pengrowth’s long term debt increased by $22.7 million in fiscal 2005 to $368.1 million at December 31, 2005. At the end of 2005 Pengrowth also had a $20 million non-interest bearing note payable to Emera related to the purchase of the SOEP offshore facilities from Emera on December 31, 2003. The terms of this note are provided in Note 7 to the financial statements.

During the year Pengrowth incurred $87 million of new debt to fund the acquisition of an additional interest in Swan Hills and assumed $20 million of bank debt from the acquisition of Crispin. Pengrowth was able to fund this new debt from its existing credit facilities.

Financial Leverage and Coverage

		Twelve months ended
		Dec 31, 2005					Dec 31, 2004
Distributable cash to interest expense (times)			29					13
Long term debt to distributable cash (times)			0.6					0.9
Long term debt to debt plus book equity (%)			20					19

Commitments and Contractual Obligations

($ thousands)		2006				2007				2008				2009				2010				Thereafter				Total
Long term debt (1)			—				—				—				—				174,450				193,639				368,089
Interest payments on long term debt (2)			17,298				17,298				17,298				17,298				11,564				34,546				115,302
Note payable			20,000				—				—				—				—				—				20,000
Operating leases
Office rent			2,030				2,070				3,096				3,055				3,036				21,529				34,816
Vehicle leases			852				776				604				306				91				—				2,629
			2,882				2,846				3,700				3,361				3,127				21,529				37,445
Purchase obligations
Pipeline transportation			43,839				38,197				34,981				29,813				11,748				53,525				212,103
Capital expenditures			33,323				7,098				294				—				—				—				40,715
CO2 purchases			5,119				4,357				4,198				4,232				4,267				18,728				40,901
			82,281				49,652				39,473				34,045				16,015				72,253				293,719
Remediation trust fund payments			250				250				250				250				250				11,250				12,500
			122,711				70,046				60,721				54,954				205,406				333,217				847,055

(1)		Foreign dollar denominated debt due as follows U.S. $150 million, in April 2010, U.S. $50 million, in April 2013 and £50 million in December 2015, translated at the Dec 31, 2005 exchange rate.
(2)		Interest payments on foreign denominated debt, calculated based on Dec 31, 2005 foreign exchange rate.

Related Party Transactions

Details of related party transactions incurred in 2005 and 2004 are provided in Note 15 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 2005 also include $0.7 million (2004 — $0.8 million) paid to a law firm controlled by the Vice President and Corporate Secretary of Pengrowth Corporation, Charles V. Selby. These fees are paid in respect of legal and advisory services provided by the Vice President

- 15 -

and Corporate Secretary. Mr. Selby does not receive any salary or bonus in his capacity as Vice President and Corporate Secretary of the Corporation. Mr. Selby has from time to time been granted trust unit rights and options.

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 2005.

Asset Retirement Obligations

The total future ARO were 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 $185 million as at December 31, 2005 (2004 — $172 million), based on a total escalated future liability of $1,041 million (2004 — $551 million). The significant change in the estimated future liability is due to increasing regulatory requirements, changing the assumptions of economic life to agree with GLJ Petroleum Consultants Ltd. (GLJ) economic life and increasing the future inflation rate. These costs are expected to be incurred over 50 years with the majority of the costs incurred between 2032 and 2054. Pengrowth’s credit adjusted risk free rate of eight percent (2004 — eight percent) and an inflation rate of 2.0 percent (2004 — 1.5 percent) were used to calculate the net present value of the ARO.

Remediation Trust Funds & Remediation and Abandonment Expenses

During 2005, Pengrowth contributed $1.3 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 $8.3 million at December 31, 2005.

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 2005, Pengrowth spent $7.4 million on abandonment and reclamation (2004 — $4.4 million). Pengrowth expects to spend approximately $11 million per year, prior to inflation, over the next ten years on remediation and abandonment.

Distributable Cash, Distributions and Taxability of Distributions

Pengrowth generated $619.7 million ($3.94 per average trust unit outstanding) of distributable cash from 2005 operations, compared to $401.2 million ($3.01 per unit) in 2004. Distributions paid or declared were $446.0 million for 2005 (2004 — $363.1 million) and as a percentage of cash generated from operations (payout ratio) represent approximately 72 percent (2004 — 90 percent).

The Board of Directors may change the amount withheld in the future, depending on a number of factors, including future commodity prices, capital expenditure requirements, and the availability of debt and equity capital. Pursuant to the Royalty Indenture, the Board of Directors 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.

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

- 16 -

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.

Cash distributions are paid to unitholders on the 15^th day of the second month following the month of production. Cash distributions paid in the 2005 calendar year totaled $2.78 per trust unit and are 80 percent return on capital (taxable) or $2.22 per trust unit and 20 percent return of capital (tax deferred) or $0.56 per trust unit. Changes in the estimated taxable and deferred portion of the cash distributions are announced quarterly.

2005 Distribution Taxability Information

		Taxable				Tax deferred
		Amount				Amount				Total
Payment Date		(Other Income)				(Return of Capital)				Distribution
January 15, 2005		$	0.1840			$	0.0460			$	0.2300
February 15, 2005		$	0.1840			$	0.0460			$	0.2300
March 15, 2005		$	0.1840			$	0.0460			$	0.2300
April 15, 2005		$	0.1840			$	0.0460			$	0.2300
May 15, 2005		$	0.1840			$	0.0460			$	0.2300
June 15, 2005		$	0.1840			$	0.0460			$	0.2300
July 15, 2005		$	0.1840			$	0.0460			$	0.2300
August 15, 2005		$	0.1840			$	0.0460			$	0.2300
September 15, 2005		$	0.1840			$	0.0460			$	0.2300
October 15, 2005		$	0.1840			$	0.0460			$	0.2300
November 15, 2005		$	0.1840			$	0.0460			$	0.2300
December 15, 2005		$	0.2000			$	0.0500			$	0.2500
		$	2.2240			$	0.5560			$	2.7800

There is no standardized measure of distributable cash and therefore distributable cash, as reported by Pengrowth, may not be comparable to similar measures presented by other trusts. In conjunction with the change to Pengrowth’s withholding practice, distributable cash as presented below may not be comparable to previous disclosures. The following table provides a reconciliation of distributable cash.

($ thousands, except per unit amounts)		Three months ended													Twelve months ended
		Dec 31, 2005				Sept 30, 2005				Dec 31, 2004					Dec 31, 2005				Dec 31, 2004
Cash generated from operations			196,588				158,976				93,287					618,070				404,167
Change in non-cash operating working capital			(7,993	)			(789	)			8,576					(9,833	)			(1,173	)
Change in deferred injectants			7,411				892				3,228					10,265				746
Change in remediation trust funds			784				(272	)			32					(20	)			(917	)
Change in deferred charges			(793	)			2,818				(473	)				1,235				(1,893	)
Other			(118	)			384				308					22				248
Distributable cash			195,879				162,009				104,958					619,739				401,178
Allocation of Distributable cash
Cash withheld			76,021				52,156				8,492					173,762				38,117
Distributions paid or declared			119,858				109,853				96,466					445,977				363,061
Distributable cash			195,879				162,009				104,958					619,739				401,178
Distributable cash per unit			1.23				1.02				0.77					3.94				3.01
Distributions paid or declared per unit			0.75				0.69				0.69					2.82				2.63
Payout ratio			61	%			69	%			103	%				72	%			90	%

At this time, Pengrowth anticipates that approximately 75 to 80 percent of 2006 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.

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Trust Unit Information

Pengrowth had 159,864,083 trust units outstanding at December 31, 2005, compared to 152,972,555 trust units at December 31, 2004. The weighted average number of trust units during the year was 157,127,181 (2004 — 133,935,485).

On April 29, 2005, Pengrowth issued 4.2 million trust units to complete the Crispin acquisition (see Note 4 to the financial statements for further detail).

Class A and Class B Trust Unit Structure

Maintaining its status as a mutual fund trust under Income Tax Act (Canada) is of fundamental importance to the Trust. Generally speaking, in addition to several other requirements, in order for a trust such as Pengrowth to be a mutual fund trust under the Income Tax Act it must satisfy one of two tests. The first test is a benefit test that requires that the trust must not be established or maintained primarily for the benefit of non-residents of Canada (which is generally interpreted to mean that the majority of unitholders must be residents of Canada) (the “Benefit Test”). The second test is a property test that requires that, at all times after February 21, 1990, “all or substantially all” of the trust’s property consist of property other than taxable Canadian property (the “Property Exception”). Pengrowth is aware that many other oil and gas income trusts have significantly greater than 50 percent non-resident ownership and are relying on the Property Exception to maintain their mutual fund trust status.

For reasons that may be unique to the Trust, it was not clear that the Trust could rely upon the Property Exception, as a sale and leaseback transaction entered into with the Corporation in 1998 regarding certain facilities at Judy Creek may have resulted in the Trust’s taxable Canadian property exceeding the threshold required by the Property Exception. On November 26, 2004, the Trust received a customary form of comfort letter from the Department of Finance (Canada) stating that the Department of Finance will recommend to the Minister of Finance that an amendment be made to the Property Exception that would clarify the Trust’s ability to rely upon the Property Exception.

As a result of this uncertainty, the Trust adopted the Class A and Class B trust unit structure, which requires that the Class A trust units constitute not more than 49.75 percent of the outstanding trust units of the Trust and that all of the Class B trust units be held by residents of Canada, to ensure that the Trust would satisfy the Benefit Test. The Trust received an advance tax ruling from the Canada Revenue Agency on July 26, 2004 and an amended ruling on December 1, 2004 that confirmed that the Trust would continue to be a mutual fund trust if the Class A trust units constituted less than the ownership threshold of 49.75 percent by June 1, 2005 and the Trust was a mutual fund trust prior to that date.

As at December 31, 2004, the Class A trust units represented 50.2 percent of the outstanding trust units of the Trust. As a result of a public offering of Class B trust units in December of 2004, the issuance of a majority of Class B trust units in connection with Pengrowth’s acquisition of Crispin in 2005 and the issuance of Class B trust units in accordance with the Distribution Reinvestment Program and other Pengrowth incentive plans, the ownership threshold of 49.75 percent for the Class A trust units was achieved prior to June 1, 2005 in accordance with the advance income tax ruling. On December 6, 2004, the Minister of Finance indicated that further discussions and consultations concerning the appropriate tax treatment of non-residents owning resource properties through mutual fund trusts would take place.

At present, Pengrowth is maintaining the Class A and Class B trust unit structure in compliance with the advance income tax ruling. The Board of Directors considers it prudent at this time to continue the Class A and Class B trust unit structure.

The Board of Directors may determine, based upon market circumstances as they exist at that time or other factors, that it is in the best interests of all unitholders to: (a) remove the requirement to comply with the ownership threshold that restricts the Class A trust units to 49.75 percent of the outstanding

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trust units; (b) remove the residency restrictions pertaining to the holding of Class B trust units; (c) permit a free conversion of Class B trust units to Class A trust units; (d) permit the consolidation of the trust unit capital of the Trust; (e) allow a controlled conversion of Class B trust units to Class A trust units over time to preserve an orderly market; (f) maintain the Class A and Class B trust unit structure until market circumstances become more favorable to both classes of unitholders; or (g) take such other action as the Board of Directors may consider appropriate.

Subsequent Event

On January 12, 2006, Pengrowth announced certain transactions with Monterey under which Pengrowth has sold oil and gas properties for $22 million of cash and eight million shares in Monterey. As at February 27, 2006 Pengrowth holds approximately 34 per percent of the common shares of Monterey.

Outlook

Pengrowth will seek to provide attractive long term returns for unitholders. Our business objectives include:

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

At this time, Pengrowth is forecasting average 2006 production of 54,000 to 56,000 boe per day from our existing properties. This estimate incorporates anticipated production additions from our 2006 development program, offset by the impact of divestitures of approximately 1,300 boe per day and expected production declines from normal operations. The above estimate excludes the potential impact of any future acquisitions or divestitures.

Total operating costs for 2006 are expected to increase to approximately $220 million. This increase is due to the addition of a full-year of operating expenses associated with Pengrowth’s increased working interest in Swan Hills and the acquisition of Crispin. Assuming Pengrowth’s average production for 2006 as forecast above, Pengrowth currently estimates 2006 per boe operating costs of approximately $11.00 per boe.

Budgeted capital expenditures for 2006 total approximately $236 million. Approximately half of the budgeted 2006 expenditures is for a 280 gross wells (132 net wells) drilling program, 27 percent are for facilities and maintenance, nine percent are for land and seismic acquisitions, and eight percent for recompletions, workovers, CO₂ pilot and other. Pengrowth’s 2006 capital program targets the furtherance of Pengrowth’s short, medium and long term objectives, reflecting Pengrowth’s focus on pursuing a balanced approach to the development of its key assets. While the most significant portion of Pengrowth’s 2006 capital program will involve the continued development and maintenance of existing production and properties, a key element of the 2006 program will be further development of mid and longer term plays or projects in coalbed methane, heavy oil and enhanced oil recovery. Pengrowth anticipates funding its 2006 capital expenditures through a combination of undistributed cash from operations, unused credit facilities and any proceeds from property dispositions.

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PENGROWTH CORPORATION
James S. Kinnear, President

For further information about Pengrowth, please visit our website www.pengrowth.com or contact:
Investor Relations, E-mail: investorrelations@pengrowth.com
Telephone: (403) 233-0224 Toll Free:
1-800-223-4122 Facsimile: (403) 294-0051
Investor Relations, Toronto, Toll Free: 1-888-744-1111
Facsimile: (416) 362-8191

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SUPPLEMENTAL INFORMATION

Based on an independent engineering evaluation conducted by GLJ effective December 31, 2005 and prepared in accordance with NI 51-101, Pengrowth had proved plus probable reserves of 219.4 mmboe. This represents 100 percent replacement of proved plus probable reserves through the acquisition of 16.7 mmboe and additions of 8.6 mmboe resulting from drilling activity, improved recoveries and technical revisions. Additions were offset by 21.7 mmboe of production and dispositions amounting to 2.8 mmboe.

Proved producing reserves are estimated at 143.7 mmboe; these reserves represent 82 percent of the total proved reserves of 175.6 mmboe and 66 percent of proved plus probable reserves. The total proved reserves account for 80 percent of proved plus probable reserves. These percentages are virtually unchanged from 2004.

Using a ten percent discount factor and GLJ January 1, 2006 pricing, the proved producing reserves account for 75 percent of the proved plus probable value while the total proved reserves account for 85 percent of the proved plus probable value. Using a 6:1 boe conversion rate for natural gas, approximately 45 percent of Pengrowth’s reserves are light/medium crude oil, 39 percent are natural gas, 9 percent are NGLs and 7 percent are heavy oil.

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, Saskatchewan, British Columbia and offshore Nova Scotia holdings account for 71 percent, 14 percent, 10 percent, and 5 percent, respectively of reserves reported by GLJ.

Reserves Summary 2005

Company Interest (Company Gross Interest* plus Royalty Interest Reserves)

		Light and																Oil				Oil
		Medium Crude				Heavy								Natural				Equivalent				Equivalent
		Oil				Oil				NGLs				Gas				2005				2004
		mbbl				mbbl				mbbl				bcf				mboe				mboe
Proved Producing			58,219				10,924				13,566				366.2				143,741				142,353
Proved Developed
Non Producing			365				62				637				24.3				5,113				4,825
Proved Undeveloped			18,768				1,699				1,139				30.8				26,745				28,324
Total Proved			77,351				12,684				15,342				421.3				175,599				175,502
Proved plus Probable			98,684				15,790				18,985				515.6				219,396				218,613