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 Second 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.

		PENGROWTH ENERGY TRUST by its administrator PENGROWTH CORPORATION
August 3, 2006		By:		/s/ Gordon M. Anderson
				Name: Gordon M. Anderson
				Title: Vice President

Attention:		Financial Editors		Stock Symbol:		(PGF.UN) — TSX;
						(PGH) – NYSE

PENGROWTH ENERGY TRUST ANNOUNCES SOLID
SECOND QUARTER 2006 RESULTS

(Calgary, August 2, 2006) /CCNMatthews/ — Pengrowth Corporation, administrator of Pengrowth Energy Trust (collectively “Pengrowth”), is pleased to announce the interim unaudited operating and financial results for the three and six month periods ended June 30, 2006.

“The second quarter marked further progress in Pengrowth’s continued transformation,” said
Jim Kinnear, Chairman, President and CEO of Pengrowth Energy Trust, “Our enhanced focus on
organic development as part of the largest capital program in Pengrowth’s history is
showing benefits. We continued to see positive results from our drilling and development
activities during the second quarter and remain well positioned for a generally favourable
second half of 2006.”

Second Quarter and Year-to-Date Highlights

•

Pengrowth spent approximately $122 million on its capital expenditure program
during the first six months of 2006 with efforts directed towards increasing production and
additional reserve recovery through infill drilling. The 2006 capital expenditure program
has been expanded through the second quarter to recognize additional development
opportunities and is now expected to total approximately $261 million for the full year.

•

Pengrowth generated $149 million ($0.93 per average trust unit outstanding) of
distributable cash from second quarter 2006 operations, compared to $134 million ($0.86 per
trust unit) in the second quarter of 2005. Distributions paid or declared were $121 million
for second quarter 2006 (2005 — $110 million). Distributions to unitholders during the
quarter totaled $0.75 per trust unit resulting in a payout ratio of approximately 81
percent.

•

Despite the decline in natural gas prices during the quarter, Pengrowth’s oil and gas
sales decreased only three percent quarter over quarter to $284 million as a result of
Pengrowth’s balanced production which benefited from the offsetting strength in pricing for
crude oil and liquids.

•

Pengrowth’s second quarter average realized price after hedging remained relatively
flat at $54.91 per boe compared to $55.04 per boe in the previous quarter. The approximate
23 percent decrease in the realized price for natural gas was largely offset by respective
increases of 15 percent, 72 percent and 1 percent in the prices realized for light oil,
heavy oil and natural gas liquids.

•

Pengrowth’s operating netback increased 8 percent to $33.94 for the second quarter
compared to $31.44 for the previous quarter and 16 percent versus the second quarter of
2005.

•

Operational downtime and production curtailments required for the installation of
compression facilities at the Sable Offshore Energy Project (SOEP) had an unfavourable
impact on second quarter production volumes. Planned maintenance activities, wet weather
and natural production declines also contributed to an approximate four percent decline in
second quarter production to 56,325 boe per day from 58,845 boe per day
in the first quarter of 2006. The full year production outlook remains positive and
Pengrowth is increasing its forecast for average 2006 production to 56,000 to 57,500
boe per day, excluding the impact of future acquisitions or dispositions and the recently
announced combination with Esprit Energy Trust.

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

Subsequent Events

The second and final phase of Pengrowth’s Class A and Class B trust unit consolidation was completed on July 27, 2006 resulting in a single consolidated trust unit that trades on the Toronto Stock Exchange under the symbol PGF.UN and on the New York Stock Exchange under the symbol PGH. The consolidation has created a simpler, more competitive capital structure which should enable Pengrowth to compete more effectively in a tight acquisition environment.

On July 24, 2006 Pengrowth and Esprit Energy Trust (Esprit) announced that they had entered into an agreement to combine Pengrowth and Esprit (the “Combination”). As a result of the Combination, Pengrowth will acquire approximately 18,350 boe per day of current production, 71.7 million boe of proved plus probable oil and natural gas reserves and 250,000 net acres of undeveloped land, including shallow gas and coalbed methane potential, at a cost of approximately $72,450 per boe per day and $18.50 per boe of proved plus probable reserves, favourable metrics in today’s competitive acquisition environment. The Combination is expected to be accretive to Pengrowth Unitholders on all pertinent financial and operational measures, including reserves, production and distributable cash flow per trust unit.

President’s Message

Pengrowth continued to perform well during the second quarter. Oil and gas sales remained strong benefiting from Pengrowth’s balanced production profile and the strength in crude prices which helped to offset the decline in natural gas pricing which began in the first quarter. As a result, distributable cash increased three percent quarter over quarter to $149 million resulting in a payout ratio of approximately 81 percent and withholdings of $28 million to help fund Pengrowth’s development activities.

Pengrowth remained focused on its development opportunities during the quarter and continued to achieve encouraging results. Following a mid-year review of Pengrowth’s development program a determination was made to increase the full year program from our original budget of $236 million to $261 million in recognition of incremental development opportunities available including an additional 140 Milk River well drilling program at Tilley as well as an expanded coalbed methane drilling program.

Pengrowth also made significant progress on several other fronts. On May 16, 2006, Pengrowth’s Board of Directors announced its unanimous recommendation to remove Pengrowth’s dual class structure. Pengrowth’s Board of Directors elected to bring the consolidation proposal forward to unitholders for a vote having determined that the dual class structure was a significant impediment to the execution of Pengrowth’s business plan. In making its determination, Pengrowth’s Board of Directors considered the advice of its financial advisors including BMO Nesbitt Burns, Merrill Lynch and RBC Capital Markets whose findings concluded that the dual class structure resulted in:

	•		an inability to effectively raise capital at the lowest possible cost;
	•		a significant impediment to completing mergers or acquisitions using trust units as consideration;
	•		significantly reduced liquidity in the trading of Pengrowth’s trust units;
	•		an inability to complete efficient equity financings; and
	•		a diversion of management’s time.

On June 23, 2006, Pengrowth unitholders voted in excess of 98 percent in favour of consolidating the Class A and Class B trust units into a single class of units at the special and annual meetings.

The trust units were consolidated through a two-phase process with the final consolidation becoming effective following the close of markets on July 27, 2006. On July 28, 2006, Pengrowth trust units began trading as a consolidated trust unit on the Toronto Stock Exchange under the symbol PGF.UN and on the New York Stock Exchange under the symbol PGH.

The benefits of the consolidation have already begun to be realized and Management’s commitment to enhancing unitholder value was further evidenced by the strategic business combination (the “Combination”) with Esprit Energy Trust which was announced subsequent to the quarter end on Monday, July 24, 2006. The combination remains subject to regulatory approval and the approval to two-thirds of Esprit unitholders and is expected to close on or about September 28, 2006.

Highlights of the Combination between Pengrowth and Esprit

	•		Under the agreement, each Esprit unit will be exchanged for 0.53 of a Pengrowth unit.
	•		In addition, Esprit’s Board of Directors expects to pay a $0.30 per unit special distribution. This special distribution is expected to be paid immediately prior to the closing of the transaction. If and when declared, this is intended to effectively maintain the equivalent cash distribution to Esprit unitholders for 17 months.
	•		Including the special distribution, the total consideration to be received by Esprit unitholders represents a 26 percent premium based on the closing prices on July 21, 2006 for each of the Esprit and Pengrowth units. This represents a substantial premium for Esprit Unitholders, almost ten times the average of all previous trust mergers. It also reflects an excellent opportunity for Pengrowth to acquire high quality, long life, natural gas weighted reserves through corporate acquisition at a cost of approximately $72,450 per boe per day and $18.50 per boe of proved plus probable reserves. These are favourable metrics in today’s competitive acquisition environment.
	•		The Combination is expected to be accretive to Pengrowth unitholders on all pertinent financial and operational measures, including reserves, production and distributable cash flow per trust unit.
	•		The combination will provide Pengrowth with approximately 18,350 barrels of oil equivalent (boe) per day of current production, 71.7 million boe of proved plus probable oil and natural gas reserves, 250,000 net acres of undeveloped land and includes shallow gas and coalbed methane potential.
	•		Esprit unitholders will be able to participate in a larger pool of development and growth opportunities, including Pengrowth’s enhanced oil recovery programs, coalbed methane initiatives, oil sands assets and conventional development.
	•		The transaction significantly reduces portfolio risk by creating a combined trust that will have a more diversified asset base and more balanced production mix than either entity on a stand-alone basis.
	•		The combined trust will continue to hold Pengrowth’s interests in five of the largest oil pools in western Canada which are expected to continue to deliver incremental reserves through technological advances in enhanced recovery.
	•		The combined trust will have increased financial strength with a more competitive cost of capital which is critical in the tight acquisition market.

The Combination furthers Pengrowth’s long term strategy of acquiring long life assets and provides a significant strategic fit in terms of assets, people and ongoing business philosophies. Following completion of the Combination, the combined trust will have total production of approximately 75,000 boe per day, weighted 52 percent to natural gas and 48 percent to oil and liquids, proved plus probable reserves of approximately 291 million boe and a reserve life index of 10.6 years.

The coming months promise to be both exciting and challenging. I am eager to capitalize on the opportunities ahead and look forward to welcoming new employees from Esprit to the Pengrowth team, including Esprit’s Chairman of the Board Mr. Michael Stewart. I also would like to thank both Pengrowth’s Board of Directors and our more than 300 team members for their exceptional efforts thus far in creating value for our unitholders and their continuing efforts going forward.

Summary of Financial and Operating Results

		Three Months ended												Six Months ended
		June 30								%				June 30								%
(thousands, except per unit amounts)		2006				2005				Change				2006				2005				Change
INCOME STATEMENT
Oil and gas sales		$	283,532			$	253,189				12	%		$	575,428			$	493,103				17	%
Net income		$	110,116			$	53,106				107	%		$	176,451			$	109,420				61	%
Net income per trust unit		$	0.69			$	0.34				103	%		$	1.10			$	0.71				55	%
CASH FLOW
Cash generated from operations		$	118,326			$	126,086				-6	%		$	309,925			$	262,506				18	%
Cash generated from operations per trust unit		$	0.74			$	0.80				-8	%		$	1.93			$	1.69				14	%
Distributable cash *		$	149,080			$	134,047				11	%		$	293,257			$	261,851				12	%
Distributable cash per trust unit *		$	0.93			$	0.86				8	%		$	1.83			$	1.69				8	%
Distributions paid or declared		$	120,597			$	110,268				9	%		$	240,899			$	216,266				11	%
Distributions paid or declared per trust unit		$	0.75			$	0.69				9	%		$	1.50			$	1.38				9	%
Payout ratio*			81	%			82	%			-1	%			82	%			83	%			-1	%
Development capital		$	47,176			$	29,016				63	%		$	122,254			$	74,752				64	%
Weighted average number of trust units outstanding			160,592				156,718				2	%			160,372				155,062				3	%
BALANCE SHEET
Working capital														$	(97,150	)		$	(90,479	)			7	%
Property, plant and equipment and other assets														$	2,081,403			$	2,141,769				-3	%
Long term debt														$	488,310			$	461,508				6	%
Unitholders’ equity														$	1,430,850			$	1,461,384				-2	%
Unitholders’ equity per trust unit														$	8.90			$	9.23				-4	%
Number of trust units outstanding at period end															160,777				158,283				2	%
DAILY PRODUCTION
Crude oil (barrels)			20,342				20,906				-3	%			20,800				20,676				1	%
Heavy oil (barrels)			4,869				5,641				-14	%			4,943				5,842				-15	%
Natural gas (mcf)			150,976				153,423				-2	%			154,407				155,446				-1	%
Natural gas liquids (barrels)			5,952				5,870				1	%			6,101				6,106				0	%
Total production (boe)			56,325				57,988				-3	%			57,578				58,532				-2	%
TOTAL PRODUCTION (mboe)			5,126				5,277				-3	%			10,422				10,594				-2	%
PRODUCTION PROFILE
Crude oil			36	%			36	%							36	%			35	%
Heavy oil			9	%			10	%							8	%			10	%
Natural gas			45	%			44	%							45	%			44	%
Natural gas liquids			10	%			10	%							11	%			11	%
AVERAGE REALIZED PRICES (after hedging)
Crude oil (per barrel)		$	72.67			$	56.44				29	%		$	67.91			$	55.45				22	%
Heavy oil (per barrel)		$	50.07			$	30.32				65	%		$	39.52			$	27.27				45	%
Natural gas (per mcf)		$	6.76			$	7.34				-8	%		$	7.77			$	7.09				10	%
Natural gas liquids (per barrel)		$	58.92			$	50.03				18	%		$	58.57			$	50.26				17	%
Average realized price per boe		$	54.91			$	47.79				15	%		$	54.98			$	46.38				19	%

Summary of Trust Unit Trading Data

		Three Months ended								Six Months ended
		June 30								June 30
(thousands, except per trust unit amounts)		2006				2005				2006				2005
TRUST UNIT TRADING (Class A)
PGH (NYSE)
High		$	25.00	U.S.		$	22.74	U.S.		$	25.15	U.S.		$	22.94	U.S.
Low		$	21.85	U.S.		$	19.05	U.S.		$	21.50	U.S.		$	18.11	U.S.
Close		$	24.09	U.S.		$	22.25	U.S.		$	24.09	U.S.		$	22.25	U.S.
Value		$	336,990	U.S.		$	334,986	U.S.		$	653,208	U.S.		$	850,117	U.S.
Volume (thousands of trust units)			14,277				16,153				27,698				40,774
PGF.A (TSX)
High		$	28.50			$	27.90			$	28.96			$	28.29
Low		$	24.20			$	23.95			$	24.20			$	22.15
Close		$	26.70			$	27.20			$	26.70			$	27.20
Value		$	47,608			$	46,405			$	81,449			$	99,672
Volume (thousands of trust units)			1,810				1,798				3,054				3,847
TRUST UNIT TRADING (Class B)
PGF.B (TSX)
High		$	26.05			$	19.01			$	26.05			$	19.90
Low		$	22.41			$	16.37			$	20.71			$	16.10
Close		$	26.05			$	18.40			$	26.05			$	18.40
Value		$	459,628			$	342,470			$	879,690			$	886,171
Volume (thousands of trust units)			18,982				19,370				37,321				48,589

The following discussion 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 six months ended June 30, 2006 and is based on information available to August 2, 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 a 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 and analysis 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
re-completions, work-overs, 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 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.

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 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 second quarter of 2006 decreased four percent from the first quarter of 2006. This decrease is attributable primarily to operational curtailments at the Sable Offshore Energy Project (SOEP) partially offset by the additional production from the Dunvegan area acquisition which closed on March 30, 2006. Production for both the second quarter and first half of 2006 decreased from the same periods in 2005 as additions from Judy Creek improved gas sales and the Dunvegan area acquisition were not able to offset the operational downtime at SOEP and natural production declines.

At this time, Pengrowth is increasing the lower end of its forecast range to 56,000 from 55,500 boe per day resulting in revised full year production guidance of 56,000 to 57,500 boe per day. This estimate incorporates anticipated production additions from planned 2006 development activities. Offsetting these additions are the Monterey and other minor previously disclosed divestitures of approximately 1,300 boe per day and expected production declines from normal operations. The above estimate excludes the impact from the Esprit business combination announced on July 24, 2006 and any potential impact from other acquisitions or divestitures.

Daily Production

		Three months ended												Six months ended
		Jun 30, 2006				Mar 31, 2006				Jun 30, 2005				Jun 30, 2006				Jun 30, 2005
Light crude oil (bbls)			20,342				21,262				20,906				20,800				20,676
Heavy oil (bbls)			4,869				5,018				5,641				4,943				5,842
Natural gas (mcf)			150,976				157,876				153,423				154,407				155,446
Natural gas liquids (bbls)			5,952				6,252				5,870				6,101				6,106
Total boe per day			56,325				58,845				57,988				57,578				58,532

Light crude oil production volumes for the second quarter of 2006 decreased four percent from the first quarter of 2006 and three percent from the second quarter of 2005 due to natural production declines. For the first six months of 2006 versus the same period in 2005, production increased minimally as improvements at Weyburn, Judy Creek and Swan Hills offset natural production declines.

Heavy oil production decreased three percent in the second quarter of 2006 from the first quarter of 2006 due to natural production declines. The 14 percent decrease in production for the second quarter of 2006 compared to the second quarter of 2005 is attributable to natural production declines particularly at partner operated properties. On a year-to-date basis, production decreased 15 percent due to natural production declines.

Natural gas production for the second quarter of 2006 decreased four percent from the first quarter of 2006. This decrease is primarily due to the curtailed production at SOEP, partially offset by the Dunvegan area acquisition. Operational downtime and a compressor installation at SOEP during the second quarter decreased gas volumes by 3,700 mcf per day with a return to full production expected in the third quarter. The production for the second quarter of 2006 compared to the second quarter of 2005 decreased two percent. Additions from increased gas sales at Judy Creek due to lower residue gas solvent demand

and the Dunvegan area acquisition were more than offset by SOEP operational curtailments, natural production decline and the Monterey divestment which closed on January 12, 2006. For the first six months of 2006 compared to the same period in 2005, production decreased by one percent. Additional production volumes from increased gas sales at Judy Creek due to lower residue gas solvent demand, ongoing development activities, particularly the Prespatou and Princess drilling programs completed in the second half of 2005, and the Crispin acquisition, were more than offset by SOEP operational downtime, the Monterey divestment and natural production declines.

Natural gas liquids (NGLs) production for the second quarter of 2006 decreased five percent from the first quarter of 2006 primarily due to production curtailments at SOEP. In comparing the second quarter of 2006 to the second quarter of 2005, production increased just over one percent. Production for the first half of 2006 remained flat in comparison to the first half of 2005.

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. Natural gas prices in North America continued to decline in the second quarter of 2006 from the first quarter of 2006.

Average Realized Prices

		Three months ended												Six months ended
(Cdn$)		Jun 30, 2006				Mar 31, 2006				Jun 30, 2005				Jun 30, 2006				Jun 30, 2005
Light crude oil (per bbl)			75.67				65.06				62.22				70.27				60.16
after hedging			72.67				63.31				56.44				67.91				55.45
Heavy oil (per bbl)			50.07				29.18				30.32				39.52				27.27
Natural gas (per mcf)			6.69				8.74				7.25				7.72				7.05
after hedging			6.76				8.76				7.34				7.77				7.09
Natural gas liquids (per bbl)			58.92				58.23				50.03				58.57				50.26
Total per boe			55.80				55.62				49.65				55.71				47.94
after hedging			54.91				55.04				47.79				54.98				46.38
Benchmark prices
WTI oil (U.S.$  per bbl)			70.72				63.48				53.22				67.13				51.66
AECO spot gas (Cdn$ per gj)			5.95				8.79				6.99				7.37				6.67
NYMEX gas (U.S.$  per mmbtu)			6.76				8.98				6.73				7.87				6.50
Currency (U.S. $/Cdn$)			0.89				0.87				0.80				0.88				0.81

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.

Hedging Losses (Gains)

		Three months ended												Six months ended
		Jun 30, 2006				Mar 31, 2006				Jun 30, 2005				Jun 30, 2006				Jun 30, 2005
Light crude oil ($ millions)			5.6				3.3				11.0				8.9				17.6
Light crude oil ($  per bbl)			3.00				1.75				5.78				2.36				4.71
Natural gas ($ millions)			(1.0	)			(0.3	)			(1.2	)			(1.3	)			(1.1	)
Natural gas ($  per mcf)			(0.07	)			(0.02	)			(0.09	)			(0.05	)			(0.04	)
Combined ($ millions)			4.6				3.0				9.8				7.6				16.5
Combined ($  per boe)			0.89				0.58				1.86				0.73				1.56

Commodity price hedges in place at June 30, 2006 are provided in Note 10 to the Financial Statements. At June 30, 2006, the mark-to-market value of the fixed price financial sales contracts represented a potential loss of $16.5 million, which includes $3.4 million that has been recognized on the income statement in the second quarter.

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 June 30, 2006 of $15.6 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 June 30, 2006, the mark-to-market value of the fixed price physical sales contract represented a potential loss of $22.5 million.

Oil and Gas Sales – Contribution Analysis

($ millions)	Three months ended																Six months ended
		Jun 30,				% of				Mar 31,				% of				Jun 30,				% of				Jun 30,				% of				Jun 30,				% of
Sales Revenue		2006				total				2006				total				2005				total				2006				total				2005				total
Light crude oil			134.6				47				121.1				41				107.4				42				255.7				45				207.5				42
Natural gas			92.8				33				124.4				43				102.6				41				217.2				38				199.5				41
Natural gas liquids			31.9				11				32.8				11				26.7				11				64.7				11				55.5				11
Heavy oil			22.2				8				13.2				5				15.5				6				35.4				6				28.8				6
Brokered sales/sulphur			2.0				1				0.4				—				1.0				—				2.4				—				1.8				—
Total oil and gas sales			283.5								291.9								253.2								575.4								493.1

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 second quarter of 2006 compared to the first quarter of 2006.

($ millions)		Light oil				Natural gas				NGL				Heavy oil				Other				Total
Quarter ended March 31, 2006			121.1				124.4				32.8				13.2				0.4				291.9
Effect of change in product prices			19.6				(28.2	)			0.4				9.2				—				1.0
Effect of change in sales volumes			(4.1	)			(4.1	)			(1.2	)			(0.2	)			—				(9.6	)
Effect of change in hedging losses (gains)			(2.3	)			0.7				—				—				—				(1.6	)
Other			0.3				—				(0.1	)			—				1.6				1.8
Quarter ended June 30, 2006			134.6				92.8				31.9				22.2				2.0				283.5

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 six months of 2006 compared to the same period of 2005.

($ millions)		Light oil				Natural gas				NGL				Heavy oil				Other				Total
Year to date June 30, 2005			207.5				199.5				55.5				28.8				1.8				493.1
Effect of change in product prices			38.1				18.7				9.2				11.0				—				77.0
Effect of change in sales volumes			1.3				(1.3	)			—				(4.4	)			—				(4.4	)
Effect of change in hedging losses			8.7				0.2				—				—				—				8.9
Other			0.1				0.1				—				—				0.6				0.8
Year to date June 30, 2006			255.7				217.2				64.7				35.4				2.4				575.4

Processing, Interest and Other Income

		Three months ended												Six months ended
($ millions)		Jun 30, 2006				Mar 31, 2006				Jun 30, 2005				Jun 30, 2006				Jun 30, 2005
Processing, interest & other income			4.1				3.8				7.4				7.9				11.6
$  per boe			0.80				0.71				1.39				0.76				1.09

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												Six months ended
($ millions)		Jun 30, 2006				Mar 31, 2006				Jun 30, 2005				Jun 30, 2006				Jun 30, 2005
Royalty expense			45.3				65.3				47.9				110.6				88.5
$  per boe			8.84				12.34				9.08				10.61				8.35
Royalties as a percent of sales			16.0	%			22.4	%			18.9	%			19.2	%			17.9	%

Royalties include crown, freehold and overriding royalties as well as mineral taxes. The royalty rate for the second quarter of 2006 compared to the first quarter of 2006 decreased by 6.4 percent. This was primarily due to a favorable adjustment of $5.0 million recorded in the second quarter for SOEP and a $1.8 million unfavorable prior period adjustment recorded in the first quarter for SOEP. SOEP has a five tier royalty regime based on gross revenue for the first three tiers and net revenue for the final two tiers. During 2005, the royalty obligation at SOEP was approximately two percent of gross revenue (Tier 2) but progressed to five percent of gross revenue (Tier 3) 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 the fourth tier which is 30 percent of net revenue (gross revenue less certain capital and other costs associated with getting the gas and natural gas liquids to the project boundary) commencing with March 2006 production, which is later than previously

estimated in the first quarter.

Operating Expenses

		Three months ended												Six months ended
($ millions)		Jun 30, 2006				Mar 31, 2006				Jun 30, 2005				Jun 30, 2006				Jun 30, 2005
Operating expenses			58.0				54.0				50.4				112.0				99.5
$  per boe			11.32				10.20				9.56				10.75				9.39

Operating expenses increased in the second quarter of 2006 in comparison to the first quarter of 2006 primarily due to $3.3 million of higher maintenance activity at SOEP, Judy Creek and Hanlan. Increased utility costs and higher maintenance were the most significant reasons for the increase in expenses in comparing the first half of 2006 versus the same period in 2005. Operating expenses include costs incurred to earn processing and other income reported separately.

Transportation Costs

		Three months ended												Six months ended
($ millions)		Jun 30, 2006				Mar 31, 2006				Jun 30, 2005				Jun 30, 2006				Jun 30, 2005
Light oil transportation			0.5				0.5				0.6				1.0				1.1
$  per bbl			0.27				0.27				0.30				0.27				0.30
Natural gas transportation			1.2				1.3				1.2				2.5				2.5
$  per mcf			0.09				0.09				0.09				0.09				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 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 June 30, 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												Six months ended
($ millions)		Jun 30, 2006				Mar 31, 2006				Jun 30, 2005				Jun 30, 2006				Jun 30, 2005
Purchased and capitalized			6.7				10.6				5.7				17.3				13.3
Amortization			8.5				8.0				6.0				16.5				11.4

The cost of injectants (primarily natural gas and ethane) purchased for injection in miscible flood programs is amortized equally over the period of expected future economic benefit. Prior to 2005, the expected future economic benefit from injection was estimated at 30 months, based on the results of previous flood patterns. Commencing in 2005 the response period for additional new patterns being developed is expected to be somewhat shorter relative to the historical miscible patterns in the project. Accordingly, the cost of injectants purchased in 2005 and 2006 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 second quarter of 2006, the balance of unamortized injectant costs decreased by $1.8 million to $36.1 million.

The value of Pengrowth’s proprietary injectants is not recorded until reproduced from the flood and sold, although the cost of producing these injectants is included in operating expenses. The cost of purchased injectants decreased 37 percent in the second quarter of 2006 from the first quarter of 2006 primarily due to the reduction in the price of injectants. The 18 percent increase in the second quarter of 2006 compared to the same quarter of 2005 is due to the increased ownership in Swan Hills and increased injection volumes. On a year-to-date basis, the 30 percent increase in purchased injectants is due primarily to increased price of injectants and the increased ownership in Swan Hills.

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 $33.94 per boe (after hedging) in the second quarter of 2006 compared to $29.26 per boe (after hedging) for the same period in 2005, mainly due to higher average commodity prices in 2006 partially offset by higher operating expenses.

Combined Netbacks ($ per boe)		Three months ended												Six months ended
		Jun 30, 2006				Mar 31, 2006				Jun 30, 2005				Jun 30, 2006				Jun 30, 2005
Sales price		$	54.91			$	55.04			$	47.79			$	54.98			$	46.38
Other production income			0.41				0.07				0.19				0.24				0.17
			55.32				55.11				47.98				55.22				46.55
Processing, interest and other income			0.80				0.71				1.39				0.76				1.09
Royalties			(8.84	)			(12.34	)			(9.08	)			(10.61	)			(8.35	)
Operating expenses			(11.32	)			(10.20	)			(9.56	)			(10.75	)			(9.39	)
Transportation costs			(0.35	)			(0.33	)			(0.34	)			(0.34	)			(0.34	)
Amortization of injectants			(1.67	)			(1.51	)			(1.13	)			(1.58	)			(1.07	)
Operating netback		$	33.94			$	31.44			$	29.26			$	32.70			$	28.49

Light Crude Netbacks ($ per bbl)		Three months ended												Six months ended
		Jun 30, 2006				Mar 31, 2006				Jun 30, 2005				Jun 30, 2006				Jun 30, 2005
Sales price		$	72.67			$	63.31			$	56.44			$	67.91			$	55.45
Other production income			1.07				0.06				0.52				0.56				0.47
			73.74				63.37				56.96				68.47				55.92
Processing, interest and other income			0.50				0.59				0.51				0.54				0.44
Royalties			(11.27	)			(7.23	)			(9.96	)			(9.22	)			(8.56	)
Operating expenses			(12.17	)			(10.90	)			(11.14	)			(11.53	)			(10.94	)
Transportation costs			(0.27	)			(0.27	)			(0.30	)			(0.27	)			(0.30	)
Amortization of injectants			(4.61	)			(4.17	)			(3.13	)			(4.38	)			(3.03	)
Operating netback		$	45.92			$	41.39			$	32.94			$	43.61			$	33.53

Heavy Oil Netbacks ($ per bbl)		Three months ended												Six months ended
		Jun 30, 2006				Mar 31, 2006				Jun 30, 2005				Jun 30, 2006				Jun 30, 2005
Sales price		$	50.07			$	29.18			$	30.32			$	39.52			$	27.27
Processing, interest and other income			0.16				0.38				0.49				0.27				0.75
Royalties			(4.75	)			(1.55	)			(4.75	)			(3.14	)			(3.64	)
Operating expenses			(16.03	)			(14.16	)			(15.88	)			(15.09	)			(17.26	)
Operating netback		$	29.45			$	13.85			$	10.18			$	21.56			$	7.12

Natural Gas Netbacks ($ per mcf)		Three months ended												Six months ended
		Jun 30, 2006				Mar 31, 2006				Jun 30, 2005				Jun 30, 2006				Jun 30, 2005
Sales price		$	6.76			$	8.76			$	7.34			$	7.77			$	7.09
Other production income			0.01				0.02				—				0.01				—
			6.77				8.78				7.34				7.78				7.09
Processing, interest and other income			0.23				0.18				0.44				0.20				0.32
Royalties			(0.93	)			(2.54	)			(1.34	)			(1.75	)			(1.30	)
Operating expenses			(1.66	)			(1.54	)			(1.16	)			(1.60	)			(1.12	)
Transportation costs			(0.09	)			(0.09	)			(0.09	)			(0.09	)			(0.09	)
Operating netback		$	4.32			$	4.79			$	5.19			$	4.54			$	4.90

NGLs Netbacks ($ per bbl)		Three months ended												Six months ended
		Jun 30, 2006				Mar 31, 2006				Jun 30, 2005				Jun 30, 2006				Jun 30, 2005
Sales price		$	58.92			$	58.23			$	50.03			$	58.57			$	50.26
Royalties			(17.67	)			(26.10	)			(14.59	)			(21.97	)			(14.32	)
Operating expenses			(10.20	)			(8.65	)			(9.15	)			(9.41	)			(7.98	)
Operating netback		$	31.05			$	23.48			$	26.29			$	27.19			$	27.96

Interest

Interest expense increased thirteen percent to $6.5 million for the second quarter of 2006 from $5.8 million in the first quarter of 2006 primarily due to fees related to renewing credit facilities and an increase in the average interest rate. Interest expense increased by $0.8 million in the second quarter of 2006 compared to the same period in 2005 due to higher average interest rates and increased long term debt.

General and Administrative (G&A)

		Three months ended												Six months ended
($ millions)		Jun 30, 2006				Mar 31, 2006				Jun 30, 2005				Jun 30, 2006				Jun 30, 2005
Cash G&A expense			8.1				7.5				6.4				15.6				12.7
$  per boe			1.59				1.41				1.22				1.50				1.20
Non-cash G&A expense			0.6				1.3				0.7				1.9				1.5
$  per boe			0.11				0.26				0.13				0.18				0.14
Total G&A ($ millions)			8.7				8.8				7.1				17.5				14.2
Total G&A ($  per boe)			1.70				1.67				1.35				1.68				1.34

The cash component of G&A for the second quarter of 2006 compared to both the first quarter of 2006 and the second quarter of 2005 increased primarily due to higher salaries. The decrease in non-cash G&A expense for the second quarter of 2006 relative to the first quarter of 2006 is due to the recognition of incentive programs recorded in the first quarter to attract and retain employees in a highly competitive labour market.

Management Fees

		Three months ended												Six months ended
($ millions)		Jun 30, 2006				Mar 31, 2006				Jun 30, 2005				Jun 30, 2006				Jun 30, 2005
Management Fee			2.1				3.2				2.0				5.3				5.2
Performance Fee			1.3				1.0				2.3				2.3				2.9
Total ($ millions)			3.4				4.2				4.3				7.6				8.1
Total ($  per boe)			0.65				0.80				0.82				0.73				0.76

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 plus expenses that would otherwise have been payable under the original management agreement that was effective prior to July 1, 2003. Commencing July 1, 2006, for the remaining three year term, the maximum fees payable is limited to 60 percent of the fees that would have been payable under the original agreement or $12 million plus expenses, whichever is lower. The current agreement expires on June 30, 2009 and does not contain a further right of renewal.

Depletion, Depreciation and Accretion

		Three months ended												Six months ended
($ millions)		Jun 30, 2006				Mar 31, 2006				Jun 30, 2005				Jun 30, 2006				Jun 30, 2005
Depletion and Depreciation			67.8				71.1				70.9				138.9				140.1
$  per boe			13.23				13.42				13.44				13.33				13.22
Accretion			3.9				3.3				3.6				7.2				7.0
$  per boe			0.76				0.63				0.67				0.69				0.66

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

Other Expenses

Other expenses consist of costs related to the consolidation of Class A and Class B trust units ($2.5 million) for the second quarter, while the remainder relates to the Saskatchewan Resource Surcharge.

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 six months of 2006, Pengrowth spent $122.2 million on development and optimization activities. The largest expenditures were at Judy Creek ($18.6 million), SOEP ($13.2 million), Bodo ($10.1 million), Quirk Creek ($8.6 million), Prespatou ($7.1 million) and Weyburn ($4.9 million). Pengrowth engages in limited exploration activities and in the first six months of 2006 most of the capital spent on development was directed towards increasing production and improving reserve recovery through infill drilling.

		Three months ended												Six months ended
($ millions)		Jun 30, 2006				Mar 31, 2006				Jun 30, 2005				Jun 30, 2006				Jun 30, 2005
Geological and geophysical			1.1				1.2				0.6				2.3				1.2
Drilling and completions			33.5				57.8				25.1				91.3				59.4
Plant and facilities			7.5				13.4				3.3				20.9				13.9
Land purchases			5.0				2.7				0.1				7.7				0.3
Development capital			47.1				75.1				29.1				122.2				74.8
Acquisitions			4.4				49.8				1.4				54.2				91.2
Total capital expenditures and acquisitions			51.5				124.9				30.5				176.4				166.0

Pengrowth currently anticipates capital expenditures for maintenance and development of approximately $261 million for 2006, up from our previous guidance of $236 million. The $25 million increase from our previous guidance includes an additional 140 Milk River well drilling program at the Tilley field as well as an accelerated CBM drilling program. An additional $54 million was incurred to complete the Dunvegan area and other acquisitions.

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.

Financial Resources and Liquidity

Pengrowth’s long term debt at June 30, 2006 was $488.3 million, compared to $368.1 million at December 31, 2005 and $461.5 million at June 30, 2005. The $120 million increase in long term debt from December 31, 2005 is primarily due to capital expenditures, acquisitions, and the purchase of portfolio investments exceeding cash withholdings and proceeds from the Monterey transaction.

At June 30, 2006, Pengrowth maintained a $500 million term credit facility and a $35 million demand operating line of credit. These facilities were reduced by drawings of $162 million and by $17 million in letters of credit outstanding at period end. Pengrowth remains well positioned to fund its 2006 development program and to take advantage of acquisition opportunities as they arise. At June 30, 2006, Pengrowth had $357 million available to draw from its credit facilities.

Long term debt at June 30, 2006 included fixed rate term debt denominated in U.S. dollars which translated to Cdn $223.2 million. Due to the appreciation of the Canadian dollar relative to the U.S. dollar, an unrealized gain of Cdn $67.0 million has been recorded since the U.S. dollar denominated debt was issued in April of 2003. Long term debt at June 30, 2006 also included fixed rate term debt of £50 million which translated to $103.1 million Canadian. 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 cash withholdings, unused credit facilities, proceeds from exercise of trust unit rights and the distribution reinvestment plan and any proceeds from property dispositions.

At the end of the second quarter of 2006, Pengrowth was capitalized with 12 percent net debt (long term debt less working capital) and 88 percent equity, as compared with 14 percent debt and 86 percent equity at the end of the second quarter of 2005 (based on quarter-end market capitalization). The Trust’s net debt to trailing 12 months cash generated from operations was approximately 0.9 times at the end of the second quarter of 2006, as compared to 1.2 times at the end of the second quarter of 2005.

Distributable Cash, Distributions and Taxability of Distributions

Pengrowth generated $149.1 million ($0.93 per average trust unit outstanding) of distributable cash from second quarter 2006 operations, compared to $134.0 million ($0.86 per trust unit) in the second quarter of 2005. Distributions paid or declared were $120.6 million for second quarter 2006 (2005 — $110.3 million) and as a percentage of distributable cash (payout ratio) represents approximately 81 percent (2005 — 82 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 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. Pengrowth paid $0.75 per trust unit as cash distributions during the second quarter of 2006.

There is no standardized measure of distributable cash and therefore distributable cash, as reported by Pengrowth, may not be comparable to similar measures presented by other trusts. The following table provides a reconciliation of distributable cash:

($ thousands, except per trust unit amounts)		Three months ended												Six months ended
		Jun 30, 2006				Mar 31, 2006				Jun 30, 2005				Jun 30, 2006				Jun 30, 2005
Cash generated from operations			118,326				191,599				126,086				309,925				262,506
Change in non-cash operating working capital			34,219				(50,339	)			8,962				(16,120	)			(1,051	)
Funds generated from operations			152,545				141,260				135,048				293,805				261,455
Change in deferred injectants			(1,853	)			2,643				(217	)			790				1,962
Change in remediation trust funds			(279	)			(391	)			(269	)			(670	)			(532	)
Change in deferred charges			(1,716	)			788				(395	)			(928	)			(790	)
Other			383				(123	)			(120	)			260				(244	)
Distributable cash			149,080				144,177				134,047				293,257				261,851
Allocation of Distributable cash
Cash withheld			28,483				23,875				23,779				52,358				45,585
Distributions paid or declared			120,597				120,302				110,268				240,899				216,266
Distributable cash			149,080				144,177				134,047				293,257				261,851
Distributable cash per trust unit			0.93				0.90				0.86				1.83				1.69
Distributions paid or declared per trust unit			0.75				0.75				0.69				1.50				1.38
Payout ratio (1)			81	%			83	%			82	%			82	%			83	%

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.

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				Q2
Oil and gas sales ($000’s)			291,896				283,532
Net income ($000’s)			66,335				110,116
Net income per trust unit ($)			0.41				0.69
Net income per trust unit — diluted ($)			0.41				0.68
Distributable cash ($000’s)			144,177				149,080
Actual distributions paid or declared per trust unit ($)			0.75				0.75
Daily production (boe)			58,845				56,325
Total production (mboe)			5,296				5,126
Average realized price ($  per boe)			55.04				54.91
Operating netback ($  per boe)			31.44				33.94

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

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

Subsequent Events

On July 24, 2006 Pengrowth and Esprit Energy Trust (Esprit) announced that they have entered into an agreement providing for the combination of Pengrowth and Esprit (the “Combination”). Under the terms of the agreement, each Esprit trust unit will be exchanged for 0.53 of a Pengrowth trust unit (the new trust units from the consolidation of Pengrowth’s Class A and Class B trust units effective on July 27, 2006). Upon completion of the Combination, existing Pengrowth and Esprit unitholders will own approximately 82 percent and 18 percent, respectively, of the combined trust. The transaction is subject to regulatory and Esprit unitholder approval and is anticipated to close in the third quarter.

On June 23, 2006, the unitholders of Pengrowth voted to consolidate the Class A trust units and Class B trust units into one class of trust units. On June 27, 2006, the restriction on the Class B trust units that they may only be held by residents of Canada was eliminated. As of July 27, 2006, the Class A trust units were delisted from the Toronto Stock Exchange and the Class B trust units were renamed as Trust Units and their trading symbol on the Toronto Stock Exchange was changed to PGF.UN.

Also on July 27, 2006, all of the issued and outstanding Class A trust units were converted into Trust Units on the basis of one trust unit for each whole Class A trust unit held (with the exception of Class A trust units held by Canadian residents who provided a residency declaration to Computershare Trust Company of Canada) and the Trust Units were substitutionally listed in place of the Class A trust units on the New York Stock Exchange under the symbol PGH.

Outlook

At this time, Pengrowth is increasing the lower end of its forecast range to 56,000 from 55,500 boe per day resulting in revised full year production guidance of 56,000 to 57,500 boe per day. This 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 $220.0 million. 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 $10.75 and combined G&A and management fees of approximately $2.30 to $2.40 per boe.

Pengrowth currently anticipates capital expenditures for maintenance and development of approximately $261 million for 2006, up from our previous guidance of $236 million. An additional $54 million was incurred to complete the Dunvegan area and other acquisitions. The $25 million increase from our previous guidance includes an additional 140 Milk River well drilling program at the Tilley field as well as an additional CBM drilling program. Currently our budgeted expenditures include a 400 gross well full year drilling program with 100 wells drilled during the first six months of 2006. Forty one gross (17.6 net) wells were drilled in the second quarter of 2006.

Assuming the continuity of current market conditions, subject to Board approval, Pengrowth expects monthly distributions during the third quarter to be maintained at $0.25 per trust unit up to and including the November 15, 2006 distribution.

Operations Review

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

NORTH EAST BRITISH COLUMBIA (NEBC)

	•		At Gutah five of seven wells from the first quarter drilling program are on production. In addition, three of four previously drilled high interest wells have also come on production. The three remaining wells are to be tied-in during the first quarter of 2007.
	•		The Prespatou compression facility expansion to 12 mmcf per day (gross) was completed.
	•		At Rigel, an operated gas-cap producer was tied-in and is producing at 1 mmcf per day (gross).
	•		A recompletion at Wildmint was tied-in and is on production.
	•		At West Weasel a compression installation project was completed.
	•		Two new wells were successfully recompleted at Beatton River.
	•		There were no new wells drilled in NEBC during the second quarter and the summer drilling program is scheduled to commence in the third quarter.

CENTRAL

	•		Seven additional Weyburn wells were drilled and are on production. Wells drilled in 2006 now total 17 wells. This year’s drilling program has been expanded from 40 to 51 wells.
	•		At Swan Hills, two additional wells were drilled in the second quarter. The fourth well of the 2006 program will be completed in the third quarter.
	•		Tie-in work on three new West Pembina wells was underway at the end of the second quarter and they are scheduled to come on production during the third quarter.
	•		A well drilled in the first quarter at Judy Creek began production at the end of the second quarter at a rate of 250 bbls of oil per day.
	•		One new Judy Creek well was drilled and will be tied-in during the third quarter.
	•		Production in the Central area was negatively impacted by approximately 200 boe per day due to well and facilities being temporarily shut-in for major planned maintenance. The maintenance outages occurred at the Hanlan, McLeod and Kaybob fields.

SOUTHERN

	•		Completions on the 11 wells of phase one of the Coalbed Methane (CBM) program began at the end of the second quarter. Tie-ins are anticipated in the third quarter.
	•		A 50 well CBM program (Phase 2) was approved and will begin drilling in the third quarter.
	•		Three wells of the 11 well Princess drilling program were completed. The remainder of this program will be concluded in the third quarter.
	•		Nine wells were drilled in the Three Hills area (six operated and three non-operated). Eight of the wells were cased and one was drilled and abandoned. Additional drilling will continue throughout the third quarter.
	•		At Monogram, a 14 well re-frac program was completed with encouraging results. A larger 50 well re-frac program is planned for the third quarter.
	•		Completion of the new Quirk Creek well has been delayed to the third quarter due to requirements for additional regulatory approvals.
	•		Planned maintenance at Princess and generally wet weather conditions in Southern Alberta during spring break-up resulted in approximately 20 boe per day on average for the quarter being temporarily shut-in.

HEAVY OIL

	•		The polymer injection pilot began at East Bodo. The pilot is currently operating as anticipated with detailed monitoring to continue throughout 2006.
	•		At East Bodo, three horizontal wells were drilled and cased. Tie-ins are expected early in the third quarter and additional horizontal drilling is planned.
	•		An extremely wet spring break-up resulted in approximately 40 boe per day on average for the quarter being temporarily shut-in.

SABLE OFFSHORE ENERGY PROJECT (SOEP)

Production

	•		Second quarter gross raw gas production from the five SOEP fields, Thebaud, Venture, North Triumph, Alma and South Venture, averaged 330 mmcf per day (28 mmcf per day net).
	•		Monthly raw production for April, May and June was 333 mmcf per day (28 mmcf per day net); 321 mmcf per day (27 mmcf per day net); and 337 mmcf per day (28 mmcf per day net), respectively.
	•		Production was reduced in the second quarter due to ten days of shutdown time required to install the compression jacket and topsides.
	•		Pengrowth shipped approximately 68,000 bbls of condensate in the second quarter.
	•		Alma 3 was perforated on March 31, 2006 and started production on April 7, 2006.

Tier II Status as of June 30, 2006

	•		The compression jacket arrived at the SOEP site on May 13, 2006 and was set in place on May 16, 2006 with pile driving completed on May 21, 2006.
	•		The compression topsides arrived on location on May 22, 2006 and were placed on the jacket on May 28, 2006.
	•		The drilling rig Galaxy II was moved to Thebaud to act as an accommodation vessel to support the compressor installation.
	•		Cut-in work continued at the Thebaud facilities in preparation for the start-up of the compressor.
	•		In-service for the compressor is scheduled for late 2006.