SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 6-K

Report of Foreign Private Issuer
Pursuant to Rule 13a-16 or 15d-16 of the
Securities Exchange Act of 1934

PENGROWTH ENERGY TRUST

2900, 240 — 4^th Avenue S.W.
Calgary, Alberta T2P 4H4 Canada
(address of principal executive offices)

     [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 First Quarter 2006 Results.

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.

NEWS RELEASE

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

PENGROWTH ENERGY TRUST ANNOUNCES FIRST QUARTER 2006 RESULTS

(Calgary, May 1, 2006) /CCNMatthews/ — Pengrowth Corporation (“Pengrowth”), administrator of Pengrowth Energy Trust, announced the interim unaudited operating and financial results for the three month period ended March 31, 2006.

•

During the first quarter of 2006, Pengrowth generated distributable cash of $144
million versus $128 million in the first quarter of 2005, an increase of approximately 13
percent. Actual cash distributions to unitholders in the first quarter of 2006 totaled $120
million or $0.75 per trust unit reflecting a payout ratio of 85 percent of funds generated
from operations compared to 91 percent for the same period in 2005.

•

Capital expenditures for the first quarter of 2006 totaled $75 million and focused on
increasing production and improving reserve recovery through infill drilling. Capital
expenditures were fully funded through a combination of undistributed cash from
operations, proceeds from property dispositions, cash provided by distribution
reinvestment plans and the exercise of rights and options.

•

Based on quarter end market capitalization, Pengrowth was capitalized with 12 percent
net debt (long term debt plus working capital deficit) representing a net debt to
annualized cash flow from operations of 0.7 times.

•

Total production in the first quarter of 2006 was relatively unchanged from the same
period of 2005 with additions from the Swan Hills Unit No.1 and Crispin Energy Inc.
acquisitions, which closed on February 28, 2005 and April 29, 2005, respectively, and
development activities offsetting natural production declines and divestitures.

•

The Board of Directors considers it appropriate to examine whether the Class A and Class B
trust unit structure continues to be in the best interests of Pengrowth Energy Trust and
its unitholders and the extent to which the structure may be hindering Pengrowth’s
execution of its business plan. To facilitate this initiative, a special committee was
formed to make recommendations to the Board of Directors.

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

- 2 - PENGROWTH ENERGY TRUST

Summary of Financial and Operating Results

		Three months ended
		March 31								%
(thousands, except per unit amounts)		2006				2005				Change
INCOME STATEMENT
Oil and gas sales		$	291,896			$	239,913				22	%
Net income		$	66,335			$	56,314				18	%
Net income per trust unit		$	0.41			$	0.37				11	%
CASH FLOW
Funds generated from operations*		$	141,260			$	126,407				12	%
Funds generated from operations per trust unit*		$	0.88			$	0.82				7	%
Distributable cash *		$	144,177			$	127,804				13	%
Distributable cash per trust unit *		$	0.90			$	0.83				8	%
Distributions paid or declared		$	120,302			$	115,022				5	%
Distributions paid or declared per trust unit		$	0.75			$	0.69				9	%
Payout Ratio*			85	%			91	%			-6	%
Development capital		$	75,078			$	45,736				64	%
Weighted average number of trust units outstanding			160,149				153,388				4	%
BALANCE SHEET
Working capital		$	(139,121	)		$	(97,897	)			42	%
Property, plant and equipment and other assets		$	2,098,385			$	2,061,105				2	%
Long term debt		$	421,095			$	441,920				-5	%
Unitholders’ equity		$	1,432,824			$	1,414,203				1	%
Unitholders’ equity per trust unit		$	8.93			$	9.21				-3	%
Number of trust units outstanding at period end			160,383				153,621				4	%
DAILY PRODUCTION
Crude oil (barrels)			21,262				20,443				4	%
Heavy oil (barrels)			5,018				6,046				-17	%
Natural gas (mcf)			157,876				157,491				0	%
Natural gas liquids (barrels)			6,252				6,345				-1	%
Total production (boe)			58,845				59,082				0	%
TOTAL PRODUCTION (mboe)			5,296				5,317				0	%
PRODUCTION PROFILE
Crude oil			36	%			35	%
Heavy oil			8	%			10	%
Natural gas			45	%			44	%
Natural gas liquids			11	%			11	%
AVERAGE REALIZED PRICES (after hedging)
Crude oil (per barrel)		$	63.31			$	54.42				16	%
Heavy oil (per barrel)		$	29.18			$	24.39				20	%
Natural gas (per mcf)		$	8.76			$	6.84				28	%
Natural gas liquids (per barrel)		$	58.23			$	50.48				15	%
Average realized price per boe		$	55.04			$	44.97				22	%

* See the section entitled “Non-GAAP Financial Measures”

PENGROWTH ENERGY TRUST - 3 -

Summary of Trust Unit Trading Data

		Three months ended
		March 31
(thousands, except per trust unit amounts)		2006				2005
TRUST UNIT TRADING (Class A)
PGH (NYSE)
High		$	25.15 US			$	22.94 US
Low		$	21.82 US			$	18.11 US
Close		$	23.10 US			$	20.00 US
Value		$	316,218 US			$	515,131 US
Volume (thousands of trust units)			13,421				24,621
PGF.A (TSX)
High		$	28.96			$	28.29
Low		$	24.96			$	22.15
Close		$	26.88			$	24.03
Value		$	33,841			$	53,267
Volume (thousands of trust units)			1,244				2,049
TRUST UNIT TRADING (Class B)
PGF.B (TSX)
High		$	24.50			$	19.90
Low		$	20.71			$	16.10
Close		$	23.32			$	17.05
Value		$	420,062			$	543,701
Volume (thousands of trust units)			18,338				29,219

- 4 - PENGROWTH ENERGY TRUST

The following discussion and analysis of financial results should be read in conjunction with the audited consolidated financial statements for the year ended December 31, 2005 and the interim unaudited consolidated financial statements for the three month’s ended March 31, 2006 and is based on information available to May 1, 2006.

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 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 thousand barrels of oil equivalent, “mcf” refers to thousand cubic feet, “gj” refers to gigajoule and “mmbtu” refers to million British thermal units.

Advisory Regarding Forward-Looking Statements

This discussion 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 discussion 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 expenses for 2006, 2006 operating expenses per boe, capital expenditures for 2006 and the breakdown of such capital expenditures for drilling, facilities and maintenance, land and seismic acquisition and recompletions, work-overs and CO₂ pilots. 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 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 “Risk Factors” in Pengrowth’s most recent Annual Information Form, its most recent consolidated financial statements, management’s discussion and analysis, management’s information circular, quarterly reports, 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 discussion are made as of the date of this discussion 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 discussion are expressly qualified by this cautionary statement.

PENGROWTH ENERGY TRUST - 5 -

Critical Accounting Estimates

As discussed in Note 1 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 discussion and analysis 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, 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 for the first quarter of 2006 decreased by four percent from the fourth quarter of 2005. This decrease is attributable primarily to operational downtime at the Sable Offshore Energy Project (SOEP) and the divestment of properties producing approximately 1,000 boe per day to Monterey Exploration Ltd. (Monterey) effective January 12, 2006. Production for the first quarter of 2006 was relatively unchanged from the same period of 2005 with additions 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, and development activities offsetting natural production declines and divestitures.

At this time, Pengrowth is increasing its forecast for average 2006 production to the range of 55,500 to 57,500 boe per day from our previous guidance of 54,000 to 56,000 boe per day. This estimate incorporates anticipated production additions from planned 2006 development activities and the Dunvegan area acquisition which closed on March 30, 2006. Offsetting these additions are previously disclosed divestitures of approximately 1,300 boe per day impacting the first quarter of 2006 which have been excluded from the above estimate, including the Monterey divestment and expected production declines from normal operations. The above estimate excludes the potential impact of any other future acquisitions or divestitures.

Daily Production

		Three months ended
		Mar 31, 2006				Dec 31, 2005				Mar 31, 2005
Light crude oil (bbls)			21,262				21,179				20,443
Heavy oil (bbls)			5,018				5,410				6,046
Natural gas (mcf)			157,876				168,862				157,491
Natural gas liquids (bbls)			6,252				6,710				6,345
Total boe per day			58,845				61,442				59,082

Light crude oil production volumes for the first quarter of 2006 remained relatively flat compared to the fourth quarter of 2005. Improved miscible flood response at Judy Creek offset the natural production decline. Production for the first quarter of 2006 compared to the first quarter of 2005 increased four percent mainly due to the positive impact of production related to the Swan

- 6 - PENGROWTH ENERGY TRUST

Hills acquisition.

Heavy oil production decreased seven percent in the first quarter of 2006 over the fourth quarter of 2005 due to natural production declines. The 17 percent decrease in production for the first quarter of 2006 compared to the first quarter of 2005 is attributable to natural production declines.

Natural gas production for the first quarter of 2006 decreased almost seven percent from the fourth quarter of 2005. This decrease is primarily due to the Monterey divestment, operational curtailments at SOEP and natural production declines. Production for the first quarter of 2006 compared to the first quarter of 2005 remained relatively level. Additional production volumes from ongoing development activities, particularly the Prespatou and Princess drilling programs completed in the second half of 2005, increased gas sales at Judy Creek due to lower residue gas solvent demand and the Crispin acquisition, combined to more than offset the Monterey divestment, the Sable operational difficulties and natural production declines.

Natural gas liquids (NGLs) production for the first quarter of 2006 decreased by seven percent from the fourth quarter of 2005 due to natural production decline. In comparing to the first quarter of 2005, production decreased just over one percent.

Pricing and Commodity Price Hedging

The increase in U.S. based prices for North American crude oil was partially offset by the negative impact of the rising Canadian dollar. These factors combined with lower hedging losses resulted in a higher overall crude oil price compared to both the first quarter and the fourth quarter of 2005. Natural gas prices in North America declined significantly in the first quarter of 2006 from the fourth quarter of 2005, but remained higher than in the first quarter of 2005.

Average Realized Prices

		Three months ended
(Cdn$)		Mar 31, 2006				Dec 31, 2005				Mar 31, 2005
Light crude oil (per bbl)			65.06				67.00				58.03
after hedging			63.31				59.40				54.42
Heavy oil (per bbl)			29.18				31.77				24.39
Natural gas (per mcf)			8.74				12.80				6.85
after hedging			8.76				11.97				6.84
Natural gas liquids (per bbl)			58.23				58.46				50.48
Total per boe			55.62				67.43				46.25
after hedging			55.04				62.55				44.97
Benchmark prices
WTI oil (U.S. $  per bbl)			63.48				60.05				50.03
AECO spot gas (Cdn $  per gj)			8.79				11.08				6.34
NYMEX gas (U.S. $  per mmbtu)			8.98				12.97				6.27
Currency (U.S. $/Cdn $)			0.87				0.85				0.82

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 ENERGY TRUST - 7 -

Hedging Losses (Gains)

		Three months ended
		Mar 31, 2006				Dec 31, 2005				Mar 31, 2005
Light crude oil ($ million)			3.3				14.8				6.6
Light crude oil ($ per bbl)			1.75				7.60				3.61
Natural gas ($ million)			(0.3	)			12.9				0.1
Natural gas ($ per mcf)			(0.02	)			0.83				0.01
Combined ($ million)			3.0				27.7				6.7
Combined ($ per boe)			0.58				4.88				1.28

Commodity price hedges in place at March 31, 2006 are provided in Note 10 to the Financial Statements. At March 31, 2006, the mark-to-market value of the fixed price financial sales contracts represented a potential loss of $17.3 million.

In conjunction with the Murphy acquisition, which closed in 2004, 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 March 31, 2006 of $16.9 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. At March 31, 2006, the mark-to-market value of the fixed price physical sales contract represented a potential loss of $26.9 million.

Oil and Gas Sales — Contribution Analysis

($ millions)		Three months ended
						% of								% of								% of
Sales Revenue		Mar 31, 2006				total				Dec 31, 2005				total				Mar 31, 2005				total
Natural gas			124.4				43	%			186.0				53	%			96.9				40	%
Light crude oil			121.1				41	%			115.7				33	%			100.1				42	%
Natural gas liquids			32.8				11	%			36.1				10	%			28.8				12	%
Heavy oil			13.2				5	%			15.8				4	%			13.3				6	%
Brokered sales/sulphur			0.4				—				0.3				—				0.8				—
Total oil and gas sales			291.9								353.9								239.9

Oil and Gas Sales — Price and Volume 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 for the first quarter of 2006 compared to the fourth quarter of 2005.

($ millions)		Natural gas				Light oil				NGL				Heavy oil				Other				Total
Quarter ended December 31, 2005			186.0				115.7				36.1				15.8				0.3				353.9
Effect of change in product prices			(57.7	)			(3.7	)			(0.1	)			(1.2	)			—				(62.7	)
Effect of change in sales volumes			(17.0	)			(2.3	)			(3.2	)			(1.4	)			—				(23.9	)
Effect of change in hedging losses			13.1				11.4				—				—				—				24.5
Other			—				—				—				—				0.1				0.1
Quarter ended March 31, 2006			124.4				121.1				32.8				13.2				0.4				291.9

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 for the first quarter of 2006 compared to the same period of 2005.

- 8 - PENGROWTH ENERGY TRUST

($ millions)		Natural gas				Light oil				NGL				Heavy oil				Other				Total
Quarter ended March 31, 2005			96.9				100.1				28.8				13.3				0.8				239.9
Effect of change in product prices			26.9				13.4				4.4				2.2				—				46.9
Effect of change in sales volumes			0.2				4.3				(0.4	)			(2.3	)			—				1.8
Effect of change in hedging losses			0.4				3.3				—				—				—				3.7
Other			—				—				—				—				(0.4	)			(0.4	)
Quarter ended March 31, 2006			124.4				121.1				32.8				13.2				0.4				291.9

Processing, Interest and Other Income

		Three months ended
($ millions)		Mar 31, 2006				Dec 31, 2005				Mar 31, 2005
Processing, interest & other income			3.8				4.0				4.2
$  per boe			0.71				0.71				0.79

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
($ millions)		Mar 31, 2006				Dec 31, 2005				Mar 31, 2005
Royalty expense			65.3				68.0				40.6
$  per boe			12.34				12.03				7.63
Royalties as a percent of sales			22.4	%			19.2	%			16.9	%

Royalties include crown, freehold and overriding royalties as well as mineral taxes. The royalty rate for the first quarter of 2006 compared to both the fourth quarter and the first quarter of 2005 increased primarily due to a higher royalty rate and a $1.8 million prior period adjustment at SOEP recorded in the first quarter of 2006. 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. This was recognized in March 2006 when the annual royalty submission was filed. Based on Pengrowth’s forecast, the royalty obligation is now in Tier IV which is 30 percent of net revenue (gross revenue less the costs associated with getting the gas and liquids to the project boundary) commencing with February 2006 production.

Operating Expenses

		Three months ended
($ millions)		Mar 31, 2006				Dec 31, 2005				Mar 31, 2005
Operating expenses			54.0				61.2				49.1
$  per boe			10.20				10.83				9.23

Operating expenses decreased in the first quarter of 2006 in comparison to the fourth quarter of 2005 primarily due to a reduction in utility costs and lower maintenance activity at Judy Creek. Increased utility costs were the most significant reason for the increase in expenses in comparing the first quarter of 2006 versus the first quarter of 2005. Operating expenses include costs incurred to earn processing and other income reported separately.

PENGROWTH ENERGY TRUST - 9 -

Transportation Costs

		Three months ended
($ millions)		Mar 31, 2006				Dec 31, 2005				Mar 31, 2005
Light oil transportation			0.5				0.5				0.5
$  per bbl			0.27				0.27				0.30
Natural gas transportation			1.3				1.8				1.3
$  per mcf			0.09				0.12				0.09

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 the 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 March 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
($ millions)		Mar 31, 2006				Dec 31, 2005				Mar 31, 2005
Purchased and capitalized			10.6				14.5				7.6
Amortization			8.0				7.1				5.4

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 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 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. During the first quarter of 2006, the balance of unamortized injectant costs increased by $2.6 million to $37.9 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. Purchased injectants increased almost forty percent in the first quarter of 2006 compared to the same quarter of 2005 due to the increased ownership in Swan Hills and increased injection volumes. There was a 27 percent decrease in the first quarter of 2006 from the fourth quarter of 2005 due to the reduction in the price of injectants. Pengrowth currently anticipates similar injection volumes for Judy Creek and increased injection volumes for Swan Hills for the remainder of 2006. This combined with higher forecast prices for natural gas and ethane is anticipated to result in increased total injectant costs for 2006.

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 $31.44 per boe (after hedging) in the first quarter of 2006 compared to $27.70 (after hedging) for the same period in 2005, mainly due to higher average commodity prices in 2006 partially offset by higher operating expenses and royalties. The $7.37 per boe decrease in operating netbacks from the fourth quarter of 2005 is primarily due to the decrease in average commodity prices, particularly natural gas.

- 10 - PENGROWTH ENERGY TRUST

Combined Netbacks ($ per boe)		Three months ended
		Mar 31, 2006				Dec 31, 2005				Mar 31, 2005
Sales price		$	55.04			$	62.55			$	44.97
Other production income			0.07				0.06				0.15
			55.11				62.61				45.12
Processing, interest and other income			0.71				0.71				0.79
Royalties			(12.34	)			(12.02	)			(7.63	)
Operating expenses			(10.20	)			(10.83	)			(9.23	)
Transportation costs			(0.33	)			(0.41	)			(0.34	)
Amortization of injectants			(1.51	)			(1.25	)			(1.01	)
Operating netback		$	31.44			$	38.81			$	27.70

Light Crude Netbacks ($ per bbl)		Three months ended
		Mar 31, 2006				Dec 31, 2005				Mar 31, 2005
Sales price		$	63.31			$	59.40			$	54.42
Other production income			0.06				0.17				0.42
			63.37				59.57				54.84
Processing, interest and other income			0.59				0.34				0.38
Royalties			(7.23	)			(6.47	)			(7.11	)
Operating expenses			(10.90	)			(14.32	)			(10.74	)
Transportation costs			(0.27	)			(0.27	)			(0.30	)
Amortization of injectants			(4.17	)			(3.63	)			(2.93	)
Operating netback		$	41.39			$	35.22			$	34.14

Heavy Oil Netbacks ($ per bbl)		Three months ended
		Mar 31, 2006				Dec 31, 2005				Mar 31, 2005
Sales price		$	29.18			$	31.77			$	24.39
Processing, interest and other income			0.38				0.74				0.99
Royalties			(1.55	)			(2.98	)			(2.58	)
Operating expenses			(14.16	)			(11.60	)			(18.56	)
Operating netback		$	13.85			$	17.93			$	4.24

Natural Gas Netbacks ($ per mcf)		Three months ended
		Mar 31, 2006				Dec 31, 2005				Mar 31, 2005
Sales price		$	8.76			$	11.97			$	6.84
Other production income			0.02				—				—
			8.78				11.97				6.84
Processing, interest and other income			0.18				0.19				0.21
Royalties			(2.54	)			(2.62	)			(1.27	)
Operating expenses			(1.54	)			(1.38	)			(1.08	)
Transportation costs			(0.09	)			(0.12	)			(0.09	)
Operating netback		$	4.79			$	20.01			$	11.45

PENGROWTH ENERGY TRUST - 11 -

NGLs Netbacks ($ per bbl)		Three months ended
		Mar 31, 2006				Dec 31, 2005				Mar 31, 2005
Sales price		$	58.23			$	58.46			$	50.48
Royalties			(26.10	)			(21.29	)			(14.07	)
Operating expenses			(8.65	)			(10.05	)			(6.88	)
Operating netback		$	23.48			$	27.12			$	29.53

Interest

Interest expense increased seven percent to $5.8 million for the first quarter of 2006 from $5.4 million in the same period of 2005 primarily due to an increase in the average interest rate. Interest expense increased by $0.9 million in the first quarter of 2006 compared to the fourth quarter of 2005 due to higher average interest rates and increased long term debt.

General and Administrative (G&A)

		Three months ended
($ millions)		Mar 31, 2006				Dec 31, 2005				Mar 31, 2005
Cash G&A expense			7.5				7.7				6.3
$  per boe			1.41				1.36				1.18
Non-cash G&A expense			1.3				0.8				0.8
$  per boe			0.26				0.14				0.15
Total G&A ($ million)			8.8				8.5				7.1
Total G&A ($  per boe)			1.67				1.50				1.33

The cash component of G&A for the first quarter of 2006 compared to the first quarter of 2005 increased largely due to higher salaries and a general increase in financial reporting and legal costs related to increasing regulatory requirements including preparing for compliance with the Sarbanes-Oxley Act’s requirement to report on internal controls. The non-cash G&A expense is related to the value of trust unit options and rights (see Note 5 to the financial statements for details). The increase in non-cash G&A expense for the first quarter of 2006 relative to the fourth quarter of 2005 is due to the increased cost of incentive programs to attract and retain high quality employees.

Management Fees

		Three months ended
($ millions)		Mar 31, 2006				Dec 31, 2005				Mar 31, 2005
Management Fee			3.2				2.2				3.1
Performance Fee			1.0				2.2				0.6
Total ($ million)			4.2				4.4				3.7
Total ($  per boe)			0.80				0.77				0.70

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, including the performance fee, is limited to 80 percent of the fees that would otherwise have been payable under the previous management agreement. The Board of Directors elected to not exercise an option to terminate the agreement and hence the agreement has been extended for a second term expiring on July 1, 2009 without a further right of renewal. Starting July 1, 2006, the maximum fees payable will be reduced to 60 percent of the fees otherwise payable under the previous management agreement.

- 12 - PENGROWTH ENERGY TRUST

Depletion, Depreciation and Accretion

		Three months ended
($ millions)		Mar 31, 2006				Dec 31, 2005				Mar 31, 2005
Depletion and Depreciation			71.1				71.4				69.1
$  per boe			13.42				12.63				13.00
Accretion			3.3				3.6				3.4
$  per boe			0.63				0.64				0.64

Depletion and depreciation of property, plant and equipment and other assets is provided on the unit of production method based on total proved reserves.

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 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 Expenditures

During the first quarter of 2006, Pengrowth spent $75.1 million on development and optimization activities. The largest expenditures were in Judy Creek ($11.2 million), Quirk Creek ($9.5 million) and SOEP ($6.3 million). Pengrowth engages in limited exploration activities and in the first quarter of 2006 most of the capital spent on development was directed towards increasing production and improving reserve recovery through infill drilling.

		Three months ended
($ millions)		Mar 31, 2006				Dec 31, 2005				Mar 31, 2005
Geological and geophysical			1.2				—				0.6
Drilling and completions			57.8				41.1				34.3
Plant and facilities			13.4				10.2				10.6
Land purchases			2.7				8.8				0.2
Development capital			75.1				60.1				45.7
Acquisitions			49.8				—				89.8
Total capital expenditures and acquisitions			124.9				60.1				135.5

Pengrowth’s planned capital expenditures for maintenance and development opportunities at existing properties are approximately $236 million for 2006 which comprises 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 medium and longer term plays or projects in coalbed methane, heavy oil and enhanced oil recovery which will not necessarily result in production additions in 2006.

PENGROWTH ENERGY TRUST - 13 -

Acquisitions and Dispositions

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

On January 12, 2006, Pengrowth divested oil and gas properties for $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. 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. Pengrowth’s reported production does not include volume from the equity ownership.

Financial Resources and Liquidity

Pengrowth’s long term debt at March 31, 2006 was $421.1 million, compared to $368.1 million at December 31, 2005 and $441.9 million at March 31, 2005. The $53 million increase in long term debt is primarily due to capital expenditures and acquisitions exceeding cash withholdings and proceeds from the Monterey transaction.

At March 31, 2006, Pengrowth maintained $370 million in committed credit facilities which were reduced by drawings of $86 million and by $17 million in letters of credit outstanding at period 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 March 31, 2006, Pengrowth had $291 million available to draw from its credit facilities.

Long term debt at March 31, 2006 included fixed rate term debt denominated in U.S. dollars which translated to Cdn $233.6 million. Due to the appreciation of the Canadian dollar relative to the U.S. dollar, an unrealized gain of Cdn $56.6 million has been recorded since the U.S. dollar denominated debt was issued in April of 2003. Long term debt at March 31, 2006 also included fixed rate term debt of £50 million which translated to Cdn $101.5 million. Through a series of hedging transactions, Pengrowth fixed the foreign exchange rate for all future interest payments and repayment at maturity on the U.K. pound sterling debt.

Pengrowth anticipates funding its 2006 capital expenditures through a combination of undistributed cash from operations, unused credit facilities, any proceeds from property dispositions and cash provided by distribution reinvestment plans and exercise of rights and options.

At the end of the first quarter of 2006, Pengrowth was capitalized with 12 percent net debt (long term debt plus working capital deficit) and 88 percent equity, as compared with 15 percent debt and 85 percent equity at the end of the first quarter of 2005 (based on quarter-end market capitalization). The Trust’s net debt to annualized cash flow from operations was approximately 0.7 times at the end of the first quarter of 2006, as compared to 1.1 times at the end of the first quarter of 2005.

Distributable Cash, Distributions and Taxability of Distributions

Pengrowth generated $144.2 million ($0.90 per average trust unit outstanding) of distributable cash from first quarter 2006 operations, compared to $127.8 million ($0.83 per average trust unit outstanding) in the first quarter of 2005. Distributions paid or declared were $120.3 million for first quarter 2006 (2005 — $115.0 million) and as a percentage of funds generated from operations (payout ratio) represent approximately 85 percent (2005 — 91 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 nonresidents, 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 unitholder’s 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. Pengrowth paid $0.75 per trust unit as cash distributions during the first quarter of 2006.

There is no standardized measure of distributable cash, funds generated from operations and payout ratio and therefore these

- 14 - PENGROWTH ENERGY TRUST

financial measures, as reported by Pengrowth, may not be comparable to similar measures presented by other trusts. The following table provides a reconciliation of distributable cash:

($ thousands, except per trust unit amounts)		Three months ended
		Mar 31, 2006				Dec 31, 2005				Mar 31, 2005
Cash generated from operations			191,599				196,588				136,420
Change in non-cash operating working capital			(50,339	)			(7,993	)			(10,013	)
Funds generated from operations			141,260				188,595				126,407
Change in deferred injectants			2,643				7,411				2,179
Change in remediation trust funds			(391	)			784				(263	)
Change in deferred charges			788				(793	)			(395	)
Other			(123	)			(118	)			(124	)
Distributable cash			144,177				195,879				127,804
Allocation of Distributable cash
Cash withheld			23,875				76,021				12,782
Distributions paid or declared			120,302				119,858				115,022
Distributable cash			144,177				195,879				127,804
Distributable cash per trust unit			0.90				1.23				0.83
Distributions paid or declared per trust unit			0.75				0.75				0.69
Payout ratio (1)			85	%			64	%			91	%

⁽¹⁾ Payout ratio is calculated as distributions paid or declared divided by funds generated from operations

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.

Class A and Class B Trust Unit Structure

Maintaining its status as a mutual fund trust under the Income Tax Act (Canada) is of fundamental importance to Pengrowth Energy 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, either: (1) the trust must not be established or maintained primarily for the benefit of non-residents of Canada (i.e. a majority of its trust units must be owned by residents of Canada) (the “Benefit Test”) or (2) all or substantially all of the property of the trust must consist of property other than taxable Canadian property (the “Property Exception”).

As a result of uncertainty as to whether or not Pengrowth satisfied the Property Exception, it was necessary for Pengrowth to rely upon the Benefit Test and, as a result, on July 27, 2004 Pengrowth implemented the Class A and Class B trust unit structure to ensure that, after the implementation period, residents of Canada, through the ownership of Class B trust units, would own a majority of the outstanding trust units.

On November 26, 2004, Pengrowth Energy Trust received a customary form of comfort letter from the Department of Finance (Canada) (the “November Finance Letter”) stating that the Department of Finance would recommend to the Minister of Finance that an amendment be made to the Income Tax Act that would clarify Pengrowth Energy Trust’s ability to rely upon the Property Exception.

However, various announcements by the Federal Government relating to the residency requirements for mutual fund trusts during 2004 and 2005 resulted in considerable uncertainty regarding Pengrowth’s long term ability to rely upon the Property Exception and Pengrowth considered it prudent to maintain the Class A and Class B trust unit structure.

Pengrowth received a letter dated March 23, 2006 from the Department of Finance stating that it remains the intention of the Department of Finance to recommend to the Minister of Finance the changes to the Income Tax Act outlined in the November Finance Letter. Thereafter, counsel to Pengrowth advised that as a result of a number of factors, including receipt by the Corporation of confirmations from the Canada Revenue Agency and the Department of Finance, it is no longer necessary to monitor or regulate the level of ownership of trust units by persons who are not Canadian residents in order to preserve Pengrowth’s status as a mutual fund trust.

PENGROWTH ENERGY TRUST - 15 -

Within the last several months, the spread between the trading values of the Class A and Class B trust units has narrowed to the lowest level since shortly after implementing the structure in July, 2004. The Class A and Class B trust units have identical rights to voting, distributions and assets of Pengrowth Energy Trust upon windup.

In light of these developments, the Board of Directors of Pengrowth Corporation considered it appropriate to examine whether the Class A and Class B trust unit structure continues to be in the best interests of Pengrowth Energy Trust and its unitholders and the extent to which the structure may be hindering the execution by Pengrowth of its business plan. To facilitate this initiative, a special committee of the Board of Directors was formed to make recommendations to the Board of Directors. The special committee consists of A. Terence Poole, Thomas A. Cumming, Kirby L. Hedrick and Michael S. Parrett, all of whom are independent directors. The special committee has retained BMO Nesbitt Burns and Merrill Lynch as its financial advisors and Burnett Duckworth and Palmer LLP as its legal advisor.

The Board of Directors has requested that the Special Committee examine alternatives to the Class A and Class B trust unit structure, including amending the Trust Indenture with respect to the removal of the ownership restriction from the Class B trust units, the merger of the Class A trust units and the Class B trust units into a single class of trust units or any other alternatives the committee considers appropriate, together with the impact of any course of action on Pengrowth and both the Class A unitholders and Class B unitholders and the methods of implementation thereof.

To facilitate the process of the Special Committee, the date of Pengrowth’s annual general meeting has been delayed until Friday, June 23, 2006, with a record date of May 5, 2006. The Trust Indenture provides that the Class A and Class B trust units vote together and have one vote per unit. An extraordinary resolution to amend the Trust Indenture requires the affirmative votes of the holders of not less than 66 2/3 percent of the votes attaching to the trust units represented at the meeting and voted on a poll on the resolution.

There can be no assurance regarding any changes the special committee will recommend to the Board of Directors, the likelihood of the implementation of any such recommendations, the consequences of such implementation, including the potential effect on the market price or value of the Class A trust units or Class B trust units, which effect may be significantly different as between the Class A trust units and Class B trust units, or the terms or timing thereof.

Summary of Quarterly Results

The following table is a summary of quarterly results for 2006, 2005 and 2004. As this table illustrates, production and distributable cash were impacted positively by the Murphy acquisition in the second quarter of 2004.

This table also shows the relatively high commodity prices sustained throughout all quarter results, which have had a positive impact on net income and distributable cash.

2006		Q1
Oil and gas sales ($000’s)			291,896
Net income ($000’s)			66,335
Net income per trust unit ($)			0.41
Net income per trust unit — diluted ($)			0.41
Distributable cash ($000’s)			144,177
Actual distributions paid or declared per trust unit ($)			0.75
Daily production (boe)			58,845
Total production (mboe)			5,296
Average realized price ($  per boe)			55.04
Operating netback ($  per boe)			31.44

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 ($000’s)			127,804				134,047				162,009				195,879
Actual distributions paid or declared per trust unit ($)			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

- 16 - PENGROWTH ENERGY TRUST

2004		Q1				Q2				Q3				Q4
Oil and gas sales ($000’s)			168,771				197,284				226,514				223,183
Net income ($000’s)			38,652				32,684				51,271				31,138
Net income per trust unit ($)			0.31				0.24				0.38				0.23
Net income per trust unit — diluted ($)			0.31				0.24				0.38				0.23
Distributable cash ($000’s)			92,895				99,021				104,304				104,958
Actual distributions paid or declared per trust unit ($)			0.63				0.64				0.67				0.69
Daily production (boe)			45,668				51,451				60,151				57,425
Total production (mboe)			4,156				4,682				5,534				5,283
Average realized price ($  per boe)			40.37				41.83				40.90				42.08
Operating netback ($  per boe)			25.71				25.71				22.77				24.31

Outlook

Based on first quarter 2006 production results, Pengrowth expects daily average production of approximately 55,500 to 57,500 boe per day for the full year 2006, reflecting a positive revision of 1,500 boe per day compared to our year end production guidance. The revised estimate incorporates production additions from the Dunvegan area acquisition and Pengrowth’s 2006 development program, offset by the disposition of properties to Monterey and the impact of normal production declines.

In line with Pengrowth’s previous guidance total operating expenses for 2006 are expected to remain at approximately $220 million. Should natural gas prices remain at today’s levels, it is expected that full year operating expenses may be slightly below this forecast. Assuming Pengrowth’s average production results for 2006 are as forecast above, Pengrowth now estimates 2006 operating expenses per boe of between $10.50 and $10.85.

Pengrowth continues to anticipate capital expenditures for maintenance and development of approximately $236 million for 2006. During the quarter Pengrowth achieved positive results from its enhanced development program, with significant new potential production in the Fort St. John area of British Columbia and the Edson and Quirk Creek areas of Alberta, which overall could total an additional 2,000 to 3,000 boe per day. In addition, ongoing infill drilling and enhanced oil recovery programs at Judy Creek and Weyburn have more than offset declines at these properties.

On the coalbed methane front, some 11 wells were successfully drilled in the Horseshoe Canyon properties during the first quarter and in light of the favourable results achieved, the CBM program may well be accelerated this year. Infill drilling of Pengrowth’s shallow gas program will also continue.

Looking forward, a team is currently being formed to analyze the potential of Pengrowth’s Lindbergh, Alberta area holdings, estimated to contain 1.3 billion barrels of heavy oil-in-place. A study will be conducted to ascertain whether economic recovery of this heavy oil is technically and economically feasible.

Preparations for the compressor installation at SOEP continued at the Thebaud facilities during the first quarter and Pengrowth currently anticipates that production at SOEP will be somewhat reduced during the second quarter due to downtime required for installation.

In addition to the $75 million of maintenance and development expenditures in the first quarter, an additional $48 million was invested to complete the acquisition of an additional 2.3 percent interest in the Dunvegan Gas Unit, bringing our total interest in this quality gas field to 10.2 percent. While the acquisition market remains challenging with generally fewer quality assets available in the marketplace, Pengrowth believes selected acquisition opportunities remain available and we continue to analyze opportunities in domestic and international markets for potential further acquisitions.

PENGROWTH ENERGY TRUST - 17 -

- 18 - PENGROWTH ENERGY TRUST

Operations Review

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

NORTHEAST BRITISH COLUMBIA

•		Two gas wells were drilled and cased at Rigel. An operated gas cap producer tested 2 mmcf per day (gross) and a non-operated gas well is yet to be completed. The target zone (Bluesky) was found to be present and an initial production rate of 450 mcf per day is anticipated.
•		A successful oil well was drilled in the Oak C Pool capable of 70 bbls per day.
•		Two standing operated gas wells at Gutah were tied-into a third party gathering system.
•		Seven non-operated gas wells were drilled in the Gutah area, five of which were tied in before spring breakup and two which are still standing.
•		Five gas wells were drilled and cased at Prespatou. Four have been tied-in to the existing facility which is currently being expanded from 4 mmcf per day to 12 mmcf per day. Expansion is anticipated to be completed during the second quarter.
•		Four Notikewin gas wells were drilled at Bulrush with two successes and two abandonments. One successful recompletion was conducted and two recompletions did not yield economic quantities of gas. One standing well was tied-in.
•		A gas well recompletion from the Gething formation at Wildmint will be on stream in the second quarter with an anticipated initial production rate of 450 mcf per day.
•		A reactivation and recompletion of a North Pine waterflood producer at Squirrel were concluded with an initial production rate of 90 bbls per day.
•		A gas well recompletion at Weasel tested 162 mcf per day of incremental production.
•		A Bluesky gas well recompletion at Beatton will yield 200 mcf per day for the remainder of the year.
•		A new gathering line was installed from West Weasel to the Duke system that will facilitate three gas wells to produce at capability. Compression will be installed in the second quarter to bring this system on line.
•		Drilling operations of a non-operated gas well at Karr were suspended at intermediate casing. Drilling will restart again in December 2006.

CENTRAL

Judy Creek

•

A new miscible flood pattern was initiated in the Judy Creek A Pool with two new injectors and one oil well which tested at 160 bbl per day during the first quarter.

Weyburn

•

As part of a 40 well program, 11 wells are currently on stream. Initial rates net to Pengrowth are approximately 100 barrels per day.

Swan Hills Unit

•

One oil well was drilled and a second oil well will spudded in the second quarter.

West Pembina Area

•

Three successful gas wells were drilled with two completed during the first quarter. The third well is standing and awaiting completion operations in the third quarter.

SOUTHERN

Quirk Creek

•

One non-operated well was drilled, cased and tied-in to the Quirk Creek gas plant. Completion and production testing of the well are expected in June 2006.

Twining

•		Eleven Coal Bed Methane (CBM) wells were drilled, cased and logged. Completion operations will commence in the second quarter.
•		A Belly River well was drilled and is currently awaiting tie in.

PENGROWTH ENERGY TRUST - 19 -

Mikwan

•

Three new drills from fourth quarter 2005 were recompleted in the first quarter of 2006 along with three recompletions yielding positive results from the Belly River and Lower Mannville Ellerslie formations with an initial cumulative production rate of 1.2 mmcf per day. Only one of these six wells remains to be tied in during the second quarter of 2006.

Miscellaneous

•

At Elnora there is one standing Ellerslie gas well and at Huxley there is one well completed and awaiting tie in.

HEAVY OIL

•		One well and one recompletion were successful at Provost in the first quarter.
•		A 3D seismic program was completed at Bodo and will lead to future locations.
•		Polymer skid construction is completed and is forecast to start up at Bodo in the second quarter.

SABLE OFFSHORE ENERGY PROJECT

Production

	•		First quarter gross raw gas production from the five SOEP fields, Thebaud, Venture, North Triumph, Alma and South Venture averaged 379 mmcf per day (32 mmcf per day net).
	•		Monthly raw production for January, February and March was 398 mmcf per day (33 mmcf per day net); 387 mmcf per day (32 mmcf per day net); and 352 mmcf per day (30 mmcf per day net), respectively.
	•		Pengrowth shipped approximately 114,000 bbls of condensate in the first quarter.
	•		The Venture 7 (V7) development well spudded on August 5, 2005 started production on December 28, 2005. V7 initial production was approximately 50 mmcf per day gross (4.2 mmcf per day net to Pengrowth).
	•		In early January, the Alma mono ethylene glycol (MEG) line experienced a leak. A temporary facility was installed and a permanent repair was completed in March.
	•		The drilling rig Galaxy II spudded the Alma 3 well on February 9, 2006. By March 31, 2006 Alma 3 was perforated and being tied-in for production.

Tier II Status as of March 31, 2006

	•		Fabrication of the compression topsides, jacket and piles was approximately 99 percent complete.
	•		Cut-in work in preparation for the compressor installation continued at the Thebaud facilities.
	•		In-service for the compressor is scheduled for late 2006.

- 20 - PENGROWTH ENERGY TRUST

Consolidated Balance Sheets

(Stated in thousands of dollars)
(unaudited)

		As at				As at
		March 31				December 31
		2006				2005
ASSETS
CURRENT ASSETS
Accounts receivable		$	94,672			$	127,394
REMEDIATION TRUST FUNDS			8,720				8,329
DEFERRED CHARGES (Note 7)			6,680				4,886
EQUITY INVESTMENT (Note 3)			7,000				—
GOODWILL			182,835				182,835
PROPERTY, PLANT AND EQUIPMENT AND OTHER ASSETS			2,098,385				2,067,988
		$	2,398,292			$	2,391,432
LIABILITIES AND UNITHOLDERS’ EQUITY
CURRENT LIABILITIES
Bank indebtedness		$	6,341			$	14,567
Accounts payable and accrued liabilities			114,479				111,493
Distributions payable to unitholders			80,240				79,983
Due to Pengrowth Management Limited			7,689				8,277
Note payable			20,000				20,000
Current portion of contract liabilities			5,044				5,279
			233,793				239,599
CONTRACT LIABILITIES			11,852				12,937
LONG TERM DEBT (Note 2)			421,095				368,089
ASSET RETIREMENT OBLIGATIONS (Note 6)			186,069				184,699
FUTURE INCOME TAXES			112,659				110,112
TRUST UNITHOLDERS’ EQUITY
Trust Unitholders’ capital (Note 4)			2,524,862				2,514,997
Contributed surplus (Note 4)			4,576				3,646
Deficit (Note 4)			(1,096,614	)			(1,042,647	)
			1,432,824				1,475,996
		$	2,398,292			$	2,391,432

See accompanying notes to the consolidated financial statements.

PENGROWTH ENERGY TRUST - 21 -

Consolidated Statements of Income and Deficit

(Stated in thousands of dollars)
(unaudited)

		Three months ended
		March 31
		2006				2005
REVENUES
Oil and gas sales		$	291,896			$	239,913
Processing and other income			3,219				4,118
Royalties, net of incentives			(65,335	)			(40,565	)
			229,780				203,466
Interest and other income			565				112
NET REVENUE			230,345				203,578
EXPENSES
Operating			54,018				49,079
Transportation			1,758				1,807
Amortization of injectants for miscible floods			7,972				5,392
Interest			5,778				5,433
General and administrative			8,820				7,081
Management fee			4,241				3,708
Foreign exchange loss (Note 8)			1,239				1,360
Depletion and depreciation			71,056				69,149
Accretion (Note 6)			3,328				3,403
			158,210				146,412
NET INCOME BEFORE TAXES			72,135				57,166
INCOME TAX EXPENSE (REDUCTION)
Capital			1,480				1,297
Future			4,320				(445	)
			5,800				852
NET INCOME		$	66,335			$	56,314
Deficit, beginning of period			(1,042,647	)			(922,996	)
Distributions paid or declared			(120,302	)			(105,998	)
DEFICIT, END OF PERIOD		$	(1,096,614	)		$	(972,680	)
NET INCOME PER TRUST UNIT (Note 4)       Basic		$	0.41			$	0.37
Diluted		$	0.41			$	0.37

See accompanying notes to the consolidated financial statements.

- 22 - PENGROWTH ENERGY TRUST

Consolidated Statements of Cash Flow

(Stated in thousands of dollars)
(unaudited)

		Three months ended
		March 31
		2006				2005
CASH PROVIDED BY (USED FOR):
OPERATING
Net income		$	66,335			$	56,314
Depletion, depreciation and accretion			74,384				72,552
Future income taxes			4,320				(445	)
Contract liability amortization			(1,320	)			(1,449	)
Amortization of injectants			7,972				5,392
Purchase of injectants			(10,615	)			(7,571	)
Expenditures on remediation			(1,380	)			(1,118	)
Unrealized foreign exchange loss (Note 8)			1,000				1,520
Trust unit based compensation (Note 5)			1,352				817
Deferred charges			(2,364	)			—
Amortization of deferred charges			1,576				395
Changes in non-cash operating working capital (Note 9)			50,339				10,013
			191,599				136,420
FINANCING
Distributions			(120,045	)			(105,757	)
Change in long term debt, net			51,000				95,000
Proceeds from issue of trust units			9,443				9,883
			(59,602	)			(874	)
INVESTING
Expenditures on property acquisitions			(49,785	)			(89,950	)
Expenditures on property, plant and equipment			(75,078	)			(45,535	)
Proceeds on property dispositions			16,702				—
Change in remediation trust fund			(391	)			(263	)
Change in non-cash investing working capital (Note 9)			(15,219	)			(3,192	)
			(123,771	)			(138,940	)
CHANGE IN CASH AND TERM DEPOSITS			8,226				(3,394	)
BANK INDEBTEDNESS AT BEGINNING OF PERIOD			(14,567	)			(4,214	)
BANK INDEBTEDNESS AT END OF PERIOD		$	(6,341	)		$	(7,608	)

See accompanying notes to the consolidated financial statements.

PENGROWTH ENERGY TRUST - 23 -

Notes To Consolidated Financial Statements

(Unaudited)
March 31, 2006

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

1.		SIGNIFICANT ACCOUNTING POLICIES
		The interim consolidated financial statements of Pengrowth Energy Trust include the accounts of Pengrowth Energy Trust (the “Trust”), Pengrowth Corporation (the “Corporation”) and its subsidiaries (collectively referred to as “Pengrowth”). The financial statements do not contain the accounts of Pengrowth Management Limited (the “Manager”).
		The financial statements have been prepared by management in accordance with accounting principles generally accepted in Canada. The interim consolidated financial statements have been prepared following the same accounting policies and methods of computation as the consolidated financial statements for the fiscal year ended December 31, 2005. The disclosures provided below are incremental to those included with the annual consolidated financial statements. The interim consolidated financial statements should be read in conjunction with the consolidated financial statements and the notes thereto in Pengrowth’s annual report for the year ended December 31, 2005.
2.		LONG TERM DEBT

		As at				As at
		March 31,				December 31,
		2006				2005
U.S. dollar denominated debt:
U.S. $150 million senior unsecured notes at 4.93 percent due April 2010		$	175,200			$	174,450
U.S. $50 million senior unsecured notes at 5.47 percent due April 2013			58,400				58,150
			233,600				232,600
Pounds sterling denominated £50 million unsecured notes at 5.46 percent due December 2015			101,495				100,489
Canadian dollar revolving credit borrowings			86,000				35,000
		$	421,095			$	368,089

		Pengrowth has a $370 million revolving unsecured credit facility syndicated among eight financial institutions with an extendible 364 day revolving period and a three year amortization term period. The facilities were reduced by drawings of $86 million and by outstanding letters of credit in the amount of approximately $17 million at March 31, 2006. In addition, Pengrowth has a $35 million demand operating line of credit. Interest payable on amounts drawn is at the prevailing bankers’ acceptance rates plus stamping fees, lenders’ prime lending rates, or U.S. LIBOR rates plus applicable margins, depending on the form of borrowing by Pengrowth. The margins and stamping fees vary from zero percent to 1.4 percent depending on financial statement ratios and the form of borrowing.
		The revolving credit facility will revolve until June 16, 2006, whereupon it may be renewed for a further 364 days, subject to satisfactory review by the lenders, or converted into a term facility. If converted to a term facility, one third of the amount outstanding would be repaid in equal quarterly instalments in each of the first two years with the final one third to be repaid upon maturity of the term period. Pengrowth can post, at its option, security suitable to the banks in lieu of the first year’s payments. In such an instance, no principal payment would be made to the banks for one year following the date of non-renewal.

- 24 - PENGROWTH ENERGY TRUST

3.		EQUITY INVESTMENT
		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 March 31, 2006 Pengrowth holds 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.
4.		TRUST UNITHOLDERS’ EQUITY
		Trust Unitholders’ Capital
		The total authorized capital of Pengrowth is 500,000,000 trust units.
		Total Trust Units:

		Three months ended								Year ended
		March 31, 2006								December 31, 2005
		Number								Number
Trust units issued		of trust units				Amount				of 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 cash on exercise of trust unit options and rights			235,244				5,058				1,512,211				21,818
Issued for cash under Distribution Reinvestment Plan (DRIP)			284,076				4,385				1,154,004				20,726
Trust unit rights incentive plan (non-cash exercised)			—				422				—				1,209
Balance, end of year			160,383,403			$	2,524,862				159,864,083			$	2,514,997

Class A Trust Units:

		Three months ended								Year ended
		March 31, 2006								December 31, 2005
		Number								Number
Trust units issued		of trust units				Amount				of 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			200				3				45,182				692
Balance, end of period			77,524,873			$	1,196,124				77,524,673			$	1,196,121

PENGROWTH ENERGY TRUST - 25 -

Class B Trust Units:

		Three months ended								Year ended
		March 31, 2006								December 31, 2005
		Number								Number
Trust units issued		of trust units				Amount				of trust units				Amount
Balance, beginning of period			82,301,443			$	1,318,294				76,106,471			$	1,205,734
Trust units converted			3,655				58				(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			235,244				5,058				1,512,211				21,818
Issued for cash under Distribution Reinvestment Plan (DRIP)			284,076				4,385				1,154,004				20,726
Trust unit rights incentive plan (non-cash exercised)			—				422				—				1,209
Balance, end of period			82,824,418			$	1,328,217				82,301,443			$	1,318,294

Unclassified Trust Units:

		Three months ended								Year ended
		March 31, 2006								December 31, 2005
		Number								Number
Trust Units Issued		of units				Amount				of units				Amount
Balance, beginning of period			37,967			$	582				73,325			$	1,123
Converted to Class A or Class B trust units			(3,855	)			(61	)			(35,358	)			(541	)
Balance, end of period			34,112			$	521				37,967			$	582