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

For the period November 3, 2006 to November 10, 2006

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.		Third Quarter Report for the period ended September 30, 2006
2.		Certification of Interim Filings — CEO
3.		Certificate of Interim Filings — CFO

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.

 

T H I R D   Q U A R T E R   R E S U L T S
S E P T E M B E R 3 0 , 2 0 0 6

H I G H L I G H T S

 •

Average daily production increased four percent to 58,344 boe per day in the third quarter of 2006 from 56,325 boe per day in the second quarter of 2006 and remained relatively stable when compared to the third quarter of 2005. The increase is mainly attributable to improved volumes at the Sable Offshore Energy Project after second quarter operational curtailments and new production from the Prespatou and heavy oil areas. Pengrowth has increased its full year production outlook to 62,500 to 63,500 boe per day which incorporates production additions from the Dunvegan and Carson Creek area acquisitions, the Esprit Energy Trust business combination and anticipated production additions from planned 2006 development activities, excluding the impact from other future acquisitions or divestitures.

 •

During the quarter, Pengrowth generated $143.3 million ($0.89 per average trust unit outstanding) of distributable cash from operations and distributions to unitholders totaled $0.75 per trust unit.

 •

Pengrowth’s average realized price after hedging decreased two percent to $53.67 per boe in the third quarter of 2006 when compared to $54.91 per boe recorded in the second quarter of 2006 and four percent when compared to the same period in 2005 when $56.07 was recorded. The decrease is due mainly to the continuing decline in natural gas prices and the negative impact of the strong Canadian dollar on relatively robust crude oil prices.

 •

During the third quarter, Pengrowth successfully completed an acquisition from Exxon Mobil Canada Energy of the shares of a wholly owned subsidiary company that owned and controlled assets in the Carson Creek area in central Alberta for a total purchase price of $475 million prior to adjustments. The Carson Creek assets provide Pengrowth with ownership in one of the larger conventional original oil-in-place reservoirs in the Western Canadian Sedimentary Basin, are in close proximity to Pengrowth’s existing Judy Creek and Swan Hills properties, and add approximately 19 million boe of proved plus probable reserves and approximately 5,100 boe per day of mainly high-quality, light crude oil production.

 •

Subsequent to quarter-end, Pengrowth also successfully completed the business combination with Esprit Energy Trust, which closed on October 2, 2006. This combination capitalized on the opportunity to acquire long life natural gas assets in an environment of lower natural gas prices. As a result of the combination, Pengrowth acquired 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.

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												Nine Months ended
		September 30								%				September 30								%
(thousands, except per unit amounts)		2006				2005				Change				2006				2005				Change
INCOME STATEMENT
Oil and gas sales		$	287,757			$	304,484				-5	%		$	863,185			$	797,587				8	%
Net income		$	82,542			$	100,243				-18	%		$	258,993			$	209,663				24	%
Net income per trust unit		$	0.51			$	0.63				-19	%		$	1.61			$	1.34				20	%
CASH FLOW
Cash flows from operating activities		$	174,294			$	158,976				10	%		$	484,219			$	421,482				15	%
Cash flows from operating activities per trust unit		$	1.08			$	1.00				8	%		$	3.01			$	2.70				11	%
Distributable cash *		$	143,347			$	162,009				-12	%		$	436,604			$	423,860				3	%
Distributable cash per trust unit *		$	0.89			$	1.02				-13	%		$	2.72			$	2.71				0	%
Distributions paid or declared		$	132,513			$	109,853				21	%		$	373,412			$	326,119				15	%
Distributions paid or declared per trust unit		$	0.75			$	0.69				9	%		$	2.25			$	2.07				9	%
Payout ratio*			92	%			68	%			24	%			86	%			77	%			9	%
Development capital		$	56,774			$	40,848				39	%		$	179,028			$	115,600				55	%
Development capital per trust unit		$	0.35			$	0.26				35	%		$	1.11			$	0.74				50	%
Weighted average number of trust units outstanding			161,502				158,789				2	%			160,753				156,318				3	%
BALANCE SHEET
Working capital														$	(139,799	)		$	(77,528	)			80	%
Property, plant and equipment														$	2,556,802			$	2,090,399				22	%
Long term debt														$	459,910			$	422,220				9	%
Unitholders’ equity														$	1,888,365			$	1,467,859				29	%
Unitholders’ equity per trust unit														$	10.24			$	9.22				11	%
Number of trust units outstanding at period end															184,459				159,263				16	%
DAILY PRODUCTION
Crude oil (barrels)			20,651				20,660				0	%			20,750				20,670				0	%
Heavy oil (barrels)			5,272				5,405				-2	%			5,054				5,695				-11	%
Natural gas (mcf)			158,757				164,288				-3	%			155,873				158,426				-2	%
Natural gas liquids (barrels)			5,961				5,448				9	%			6,054				5,885				3	%
Total production (boe)			58,344				58,894				-1	%			57,836				58,654				-1	%
TOTAL PRODUCTION (mboe)			5,368				5,418				-1	%			15,789				16,013				-1	%
PRODUCTION PROFILE
Crude oil			36	%			35	%							36	%			35	%
Heavy oil			9	%			9	%							9	%			10	%
Natural gas			45	%			47	%							45	%			45	%
Natural gas liquids			10	%			9	%							10	%			10	%
AVERAGE REALIZED PRICES (after hedging)
Crude oil (per barrel)		$	72.61			$	63.95				14	%		$	69.49			$	58.31				19	%
Heavy oil (per barrel)		$	51.47			$	47.74				8	%		$	43.72			$	33.82				29	%
Natural gas (per mcf)		$	6.29			$	8.57				-27	%		$	7.26			$	7.61				-5	%
Natural gas liquids (per barrel)		$	60.76			$	57.75				5	%		$	59.30			$	52.59				13	%
Average realized price per boe		$	53.67			$	56.07				-4	%		$	54.53			$	49.66				10	%

*

See the section entitled “Non-GAAP Financial Measures”

PENGROWTH ENERGY TRUST - 3 -

Summary of Trust Unit Trading Data

			Three Months ended										Nine Months ended
			September 30										September 30
(thousands, except per trust unit amounts)		2006					2005					2006					2005
TRUST UNIT TRADING
PGH (NYSE)
High		$	24.95		U.S.		$	25.75		U.S.		$	25.15		U.S.		$	25.75		U.S.
Low		$	18.90		U.S.		$	21.55		U.S.		$	18.90		U.S.		$	18.11		U.S.
Close		$	19.62		U.S.		$	25.42		U.S.		$	19.62		U.S.		$	25.42		U.S.
Value		$	603,978		U.S.		$	340,318		U.S.		$	1,257,186		U.S.		$	1,190,435		U.S.
Volume			27,359					14,502					55,057					55,276
PGF.A (TSX) *
High		$	28.25				$	30.10				$	28.96				$	30.10
Low		$	24.95				$	26.30				$	24.20				$	22.15
Close		$	25.30				$	29.50				$	25.30				$	29.50
Value		$	110,607				$	58,000				$	192,056				$	157,672
Volume			4,297					2,047					7,351					5,894
PGF.B (TSX) *
High		$	27.25				$	21.26				$	27.25				$	21.26
Low		$	24.84				$	18.25				$	20.71				$	16.10
Close		$	25.31				$	20.58				$	25.31				$	20.58
Value		$	363,983				$	441,039				$	1,243,673				$	1,327,210
Volume			14,226					22,738					51,547					71,326
PGF.UN (TSX) *
High		$	26.11									$	26.11
Low		$	21.02									$	21.02
Close		$	21.94									$	21.94
Value		$	707,966									$	707,966
Volume			29,262										29,262

- 4 - PENGROWTH ENERGY TRUST

President’s Message

To our valued unitholders,

I am pleased to announce the unaudited quarterly results for the three months and nine months ended September 30, 2006. The third quarter of 2006 was characterized by Pengrowth’s commitment to providing stable distributions to unitholders while executing its business plan for continued growth and success in both its operational activities and financial results.

In my annual letter dated February 27, 2006, I stated that Pengrowth’s objectives for the year ahead would be focused upon:

	1.		continuing to seek out high-quality acquisitions which target areas in which we already hold significant interests including large oil-in-place reservoirs, shallow gas properties with additional development potential and areas with coalbed methane prospects; and
	2.		to capitalize on organic growth opportunities including an increased concentration on exploiting our existing asset base, aggressively pursuing improved reserve recovery potential and enhancing operational efficiencies.

I am pleased to report that Pengrowth achieved success in both areas.

At the end of the third quarter, Pengrowth successfully completed an acquisition from Exxon Mobil Canada Energy of the shares of a wholly owned subsidiary company which owned and controlled assets in the Carson Creek area in central Alberta for a total purchase price of $475 million prior to adjustments. The Carson Creek acquisition was in line with our strategic direction and further strengthened Pengrowth’s high-quality asset base.

The Carson Creek assets provide Pengrowth with ownership in one of the larger conventional original oil-in-place reservoirs in the Western Canadian Sedimentary Basin and they are in close proximity to Pengrowth’s existing Judy Creek and Swan Hills properties. The acquisition expands our strategic focus area in light crude oil; provides anticipated field operating synergies; further development potential; and is expected to improve overall efficiencies for both the Judy Creek and Carson Creek facilities. The acquisition adds approximately 19 million barrels of oil equivalent (boe) of proved plus probable reserves and approximately 5,100 boe per day of mainly high-quality, light crude oil production.

In conjunction with the Carson Creek acquisition, Pengrowth completed a bought deal equity offering in which 23,310,000 trust units were issued at $22.60 per trust unit for gross proceeds of $526,806,000. The majority of the net proceeds from the offering were used to fund the acquisition, with the remaining net proceeds being applied against Pengrowth’s revolving credit facility or for general corporate purposes.

Subsequent to quarter-end, Pengrowth also successfully completed the business combination with Esprit Energy Trust, which closed on October 2, 2006. This combination illustrated our commitment to capitalize on counter-cyclical acquisitions as evidenced by acquiring these long life natural gas assets in the current environment of lower natural gas prices. As a result of the combination, Pengrowth acquired 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.

The Esprit assets are highly concentrated with seven properties making up over 70 percent of the corporate total and are of a high quality with a proved plus probable reserve life index of 10.5 years. Esprit’s net undeveloped acreage position adds approximately 60 percent to Pengrowth’s existing undeveloped land base to total approximately 660,000 net acres. This large land base is expected to provide significant upside to the trust based on the growth and development opportunities associated with it.

PENGROWTH ENERGY TRUST - 5 -

The combination of these acquisitions is accretive to unitholders on all significant metrics including distributable cash, production and reserves per trust unit. Pengrowth also expects to realize additional value through infill development drilling opportunities, drilling on undeveloped lands and enhanced oil recovery potential. Pengrowth’s anticipated fourth quarter production is now approximately 79,000 boe per day which represents a slight decrease relative to our previous 81,000 boe per day estimate due to a combination of temporary third-party facility restrictions at Willesden Green and Three Hills; on-going well remediation and optimization work in Carson Creek; and weather-related delays in drilling and tie-ins across most areas. The trust retains an above sector average reserve life index of 10.6 years and the production mix will remain balanced at approximately 51 percent natural gas with the remainder in oil and natural gas liquids. The combination of our operations teams provides additional resources and technical expertise to take advantage of our expanded inventory of organic growth opportunities.

In the third quarter of 2006, Pengrowth continued to focus on enhancing its business through internal development opportunities including the further exploitation of our asset base and the active pursuit of improved reserve recovery. This was apparent in third quarter average daily production which increased four percent quarter over quarter. The increase is attributable to not only improved volumes at the Sable Offshore Energy Project but also our internal development program with new production additions from the Prespatou and the heavy oil areas.

We have raised our forecast for full year production to 62,500 to 63,500 boe per day which not only reflects the production associated with the Esprit and Carson Creek area acquisitions but also includes anticipated production additions from planned 2006 development activities. Pengrowth has spent approximately $179 million in the first three quarters of the year on its maintenance and development program with the majority of its development program directed at increasing production and improving reserve recovery through infill drilling. The 2006 capital program has been increased to $280 million, mainly reflecting additional capital related to the addition of the Esprit business combination.

During the third quarter, development capital totaled $56.8 million with approximately 75 percent directed towards drilling and completions. Pengrowth’s development program provided strong results during the quarter which included drilling 93 gross wells (43.7 net) with a 94 percent success rate.

Production testing of the new Quirk Creek gas well, in which Pengrowth holds a 68 percent working interest, was completed and has commenced production in October at a restricted rate of approximately 5 mmcf per day (3.4 mmcf per day net). We have also had some good success in our two-phase coalbed methane project in the Twining area of southern Alberta. In Phase 1, 11 wells were completed and five of these wells were tied in and are expected to begin production in the fourth quarter. The second phase consists of a 50 well program and during the third quarter Pengrowth drilled ten wells with an average working interest of 61 percent. Partners in the area drilled an additional 17 wells of which 15 are expected to be completed for production and the remaining two to come on stream in the fourth quarter. In addition, we have had reasonable success in the development of the new miscible flood pattern at Judy Creek which has continued to provide positive returns.

Pengrowth’s high quality, long-life assets have provided the trust with a stable production profile that is reflected in the steady distribution provided to unitholders. Distributable cash generated from operations remained relatively flat in the third quarter at $143 million ($0.89 per average trust unit outstanding) compared with $149 million ($0.93 per trust unit) in the second quarter of 2006. Distributions to unitholders during the quarter totaled $0.75 per trust unit.

The Honourable Jim Flaherty, Canadian Minister of Finance, made an announcement yesterday outlining proposed changes to the taxation of income trusts. In his announcement, Mr. Flaherty included a proposed tax on distributions paid on publicly traded income trusts and limited partnerships. As Pengrowth is an existing, publicly traded income trust these proposed changes would not affect Pengrowth until 2011. At this stage, this remains a proposal and would need to be approved by the Canadian government before becoming legislation. Pengrowth will continue to pay close attention to the government’s stance on taxing distributions from income trusts and any potential impact this may have on Pengrowth and its stakeholders.

- 6 - PENGROWTH ENERGY TRUST

The past quarter has been a period of significant growth and change for the trust with considerable challenges and opportunities evident ahead. Our skilled and experienced team of employees has increased substantially and along with our talented leadership team and Board of Directors, we remain dedicated to meeting these challenges head on and exploiting opportunities fully with innovative strategies focused on long term growth. I would like to offer my sincere appreciation to our team for their efforts thus far in 2006 and I look forward to continuing to work with them in striving towards providing unitholders with continued solid returns and superior value.

James S. Kinnear
Chairman, President and Chief Executive Officer
November 1, 2006

For further information about Pengrowth, please visit our website www.pengrowth.com or contact:
Investor Relations, Calgary Telephone: (403) 233-0224 Toll Free: 1-800-223-4122 Facsimile: (403) 294-0051
Investor Relations, Toronto Telephone: (416) 362-1748 Toll Free: 1-888-744-1111 Facsimile: (416) 362-8191

PENGROWTH ENERGY TRUST - 7 -

Management’s Discussion and Analysis

The following Management’s 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 nine months ended September 30, 2006 and is based on information available to November 1, 2006.

Frequently Recurring Terms

For the purposes of this Management’s Discussion and Analysis, 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 Management’s Discussion and Analysis: “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 Management’s Discussion and Analysis 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 Management’s 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

- 8 - PENGROWTH ENERGY TRUST

consider the foregoing factors and other uncertainties and potential events. Furthermore, the forward-looking statements contained in this Management’s Discussion and Analysis are made as of the date of this Management’s Discussion and Analysis 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 Management’s Discussion and Analysis 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 Management’s 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

This Management’s Discussion and Analysis contains no material amounts relating to the September 28, 2006 completed acquisition of assets in the Carson Creek area of Alberta, or the Esprit Energy Trust (Esprit) business combination completed on October 2, 2006.

Production

Average daily production for the third quarter of 2006 increased four percent from the second quarter of 2006. This increase is attributable primarily to improved volumes after the operational curtailments at the Sable Offshore Energy Project (SOEP) during the second quarter and new production from the Prespatou and heavy oil areas. Production for both the third quarter and first nine months of 2006 decreased marginally from the same periods in 2005 as additions from Judy Creek improved gas sales, the Dunvegan area acquisition and new production from development activities were not able to offset the Monterey Exploration Ltd. (Monterey) and other minor previously disclosed divestitures, the operational downtime at SOEP and natural production declines.

At this time, Pengrowth anticipates full year production of 62,500 to 63,500 boe per day, up from its previous production guidance of 56,000 to 57,500 boe per day. This estimate incorporates production additions from the Dunvegan and Carson Creek area acquisitions, the Esprit business combination and anticipated production additions from planned 2006 development activities. The above estimate excludes the impact from other future acquisitions or divestitures.

PENGROWTH ENERGY TRUST - 9 -

Daily Production

		Three months ended												Nine months ended
		Sept 30, 2006				Jun 30, 2006				Sept 30, 2005				Sept 30, 2006				Sept 30, 2005
Light crude oil (bbls)			20,651				20,342				20,660				20,750				20,670
Heavy oil (bbls)			5,272				4,869				5,405				5,054				5,695
Natural gas (mcf)			158,757				150,976				164,288				155,873				158,426
Natural gas liquids (bbls)			5,961				5,952				5,448				6,054				5,885
Total boe per day			58,344				56,325				58,894				57,836				58,654

Light crude oil production volumes for the third quarter of 2006 increased two percent from the second quarter of 2006, while in comparison to the third quarter of 2005, the production volumes were flat. For the first nine 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 increased eight percent in the third quarter of 2006 from the second quarter of 2006 as new production from drilling at Bodo and Cactus Lake came on stream. The two percent decrease in production for the third quarter of 2006 compared to the same quarter of 2005 is attributable to natural production declines. For the first nine months, production decreased 11 percent due to natural production declines.

Natural gas production for the third quarter of 2006 increased five percent from the second quarter of 2006. This increase is primarily due to new production from wells drilled in the Prespatou area and improved volumes after the operational curtailments at SOEP and the Hanlan turnaround during the second quarter. Production for the third quarter of 2006 compared to the same quarter of 2005 decreased three percent. Additions from the Dunvegan area and Carson Creek acquisitions and new production from the Prespatou and Princess areas were more than offset by natural production declines and the Monterey and other minor previously disclosed divestments. For the first nine months of 2006 compared to the same period in 2005, production decreased by almost two percent. Additional production volumes from increased gas sales at Judy Creek due to lower residue gas solvent utilization, ongoing development activities, particularly the Prespatou and Princess drilling programs completed in the second half of 2005, and the Dunvegan area and Crispin acquisitions, were more than offset by SOEP operational downtime, the Monterey and other divestments, and natural production declines.

Natural gas liquids (NGLs) production for the third quarter of 2006 remained flat from the second quarter of 2006. In comparing the third quarter of 2006 to the same quarter of 2005, production increased nine percent primarily from acquisition activity. Production for the first nine months of 2006 increased three percent in comparison to the same period of 2005 due to the increased ownership in Swan Hills.

Pricing and Commodity Price Hedging

U.S. based prices for North American crude oil remained strong in the third quarter of 2006, but continued to be partially offset by the negative impact of the strong Canadian dollar. Natural gas prices in North America continued to decline in the third quarter of 2006 from the second quarter of 2006.

- 10 - PENGROWTH ENERGY TRUST

Average Realized Prices

		Three months ended												Nine months ended
(Cdn$)		Sept 30, 2006				Jun 30, 2006				Sept 30, 2005				Sept 30, 2006				Sept 30, 2005
Light crude oil (per bbl)			75.53				75.67				74.37				72.04				64.94
after hedging			72.61				72.67				63.95				69.49				58.31
Heavy oil (per bbl)			51.47				50.07				47.74				43.72				33.82
Natural gas (per mcf)			6.22				6.69				8.69				7.21				7.63
after hedging			6.29				6.76				8.57				7.26				7.61
Natural gas liquids (per bbl)			60.76				58.92				57.75				59.30				52.59
Total per boe			54.51				55.80				60.06				55.30				52.04
after hedging			53.67				54.91				56.07				54.53				49.66
Benchmark prices
WTI oil (U.S.$  per bbl)			70.54				70.72				63.31				68.21				55.60
AECO spot gas (Cdn$  per gj)			5.72				5.95				7.75				6.82				7.03
NYMEX gas (U.S.$  per mmbtu)			6.66				6.76				8.49				7.47				7.16
Currency (U.S.$/Cdn$)			0.89				0.89				0.83				0.88				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.

WTI Oil Price ($ U.S./bbl)		AECO Gas Price ($ Cdn/mcf)		Exchange Rate ($ Cdn/U.S.)

Hedging Losses (Gains)

		Three months ended												Nine months ended
Realized		Sept 30, 2006				Jun 30, 2006				Sept 30, 2005				Sept 30, 2006				Sept 30, 2005
Light crude oil ($ millions)			5.5				5.6				19.8				14.4				37.4
Light crude oil ($  per bbl)			2.92				3.00				10.42				2.55				6.63
Natural gas ($ millions)			(1.0	)			(1.0	)			1.8				(2.3	)			0.7
Natural gas ($  per mcf)			(0.07	)			(0.07	)			0.12				(0.05	)			0.02
Combined ($ millions)			4.5				4.6				21.6				12.1				38.1
Combined ($  per boe)			0.84				0.89				3.99				0.77				2.38

Starting in the second quarter of 2006, Pengrowth no longer adopted hedge accounting for any new hedges entered into. Pengrowth will recognize any changes to the fair value of commodity hedges entered into after the first quarter in the income statement.

Commodity price hedges in place at September 30, 2006 are provided in Note 11 to the Financial Statements. At September 30, 2006, the mark-to-market value of the fixed price financial sales contracts represented a potential gain of $15.0 million, which includes a $16.6 million gain year to date that has been recognized on the income statement. At September 30, 2005, the mark-to-market value of the fixed price financial sales contracts represented a potential loss of $64.2 million, none of which was recognized on the income statement.

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. 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-

PENGROWTH ENERGY TRUST - 11 -

market value at May 31, 2004. The liability at September 30, 2006 of $14.3 million for the contracts will continue to be drawn down and recognized in income as the contracts are settled. As this is a non-cash component of income, it is not included in the calculation of distributable cash. As at September 30, 2006, Pengrowth would be required to pay $17.8 million to terminate the fixed price physical sales contract. This amount is not included above in hedging losses (gains).

Oil and Gas Sales — Contribution Analysis

($ millions)										Three months ended																Nine months ended
		Sept 30,				% of				Jun 30,				% of				Sept 30,				% of				Sept 30,				% of				Sept 30,				% of
Sales Revenue		2006				total				2006				total				2005				total				2006				total				2005				total
Light crude oil			137.9				48				134.6				47				121.6				40				393.6				46				329.1				41
Natural gas			91.9				32				92.8				33				129.5				43				309.1				36				329.0				41
Natural gas liquids			33.3				11				31.9				11				29.0				9				98.0				11				84.5				11
Heavy oil			24.9				9				22.2				8				23.8				8				60.3				7				52.6				7
Brokered sales/sulphur			(0.2	)			0				2.0				1				0.6				0				2.2				0				2.4				0
Total oil and gas sales			287.8								283.5								304.5								863.2								797.6

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

($ millions)		Light oil				Natural gas				NGL				Heavy oil				Other				Total
Quarter ended June 30, 2006			134.6				92.8				31.9				22.2				2.0				283.5
Effect of change in product prices			(0.3	)			(6.9	)			1.0				0.7				—				(5.5	)
Effect of change in sales volumes			3.7				5.8				0.4				2.1				—				12.0
Effect of change in hedging losses			0.1				—				—				—				—				0.1
Other			(0.2	)			0.2				—				(0.1	)			(2.2	)			(2.3	)
Quarter ended September 30, 2006			137.9				91.9				33.3				24.9				(0.2	)			287.8

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

($ millions)		Light oil				Natural gas				NGL				Heavy oil				Other				Total
Year to date September 30, 2005			329.1				329.0				84.5				52.6				2.4				797.6
Effect of change in product prices			40.2				(17.7	)			11.1				13.7				—				47.3
Effect of change in sales volumes			1.4				(5.3	)			2.4				(5.9	)			—				(7.4	)
Effect of change in hedging losses			23.0				3.0				—				—				—				26.0
Other			(0.1	)			0.1				—				(0.1	)			(0.2	)			(0.3	)
Year to date September 30, 2006			393.6				309.1				98.0				60.3				2.2				863.2

Processing, Interest and Other Income

		Three months ended												Nine months ended
($ millions)		Sept 30, 2006				Jun 30, 2006				Sept 30, 2005				Sept 30, 2006				Sept 30, 2005
Processing, interest & other income			4.7				4.1				2.1				12.6				13.7
$ per boe			0.88				0.80				0.39				0.80				0.86

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.

- 12 - PENGROWTH ENERGY TRUST

Royalties

		Three months ended												Nine months ended
($ millions)		Sept 30, 2006				Jun 30, 2006				Sept 30, 2005				Sept 30, 2006				Sept 30, 2005
Royalty expense			57.8				45.3				57.4				168.4				145.9
$  per boe			10.77				8.84				10.60				10.67				9.11
Royalties as a percent of sales			20.1	%			16.0	%			18.9	%			19.5	%			18.3	%

Royalties include crown, freehold and overriding royalties as well as mineral taxes. The royalty rate for the third quarter of 2006 compared to the second quarter of 2006 increased by 4.1 percent. This was primarily due to a favorable adjustment of $5.0 million recorded in the second 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 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 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												Nine months ended
($ millions)		Sept 30, 2006				Jun 30, 2006				Sept 30, 2005				Sept 30, 2006				Sept 30, 2005
Operating expenses			58.8				58.0				57.4				170.8				156.9
$ per boe			10.94				11.32				10.59				10.82				9.80

Operating expenses increased minimally in the third quarter of 2006 in comparison to the second quarter of 2006; while the expense per boe decreased as production volumes improved from the second quarter’s maintenance/turnaround activity. Increased utility costs and higher maintenance were the most significant reasons for the increase in expenses in comparing the first nine months 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												Nine months ended
($ millions)		Sept 30, 2006				Jun 30, 2006				Sept 30, 2005				Sept 30, 2006				Sept 30, 2005
Light oil transportation			0.5				0.5				0.6				1.5				1.7
$ per bbl			0.26				0.27				0.29				0.26				0.30
Natural gas transportation			1.3				1.2				1.4				3.8				3.9
$ 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 September 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												Nine months ended
($ millions)		Sept 30, 2006				Jun 30, 2006				Sept 30, 2005				Sept 30, 2006				Sept 30, 2005
Purchased and capitalized			7.9				6.7				6.9				25.2				20.2
Amortization			8.8				8.5				6.0				25.3				17.3

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

PENGROWTH ENERTY TRUST - 13 -

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 third quarter of 2006, the balance of unamortized injectant costs decreased by $0.9 million to $35.2 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 increased 18 percent in the third quarter of 2006 from the second quarter of 2006 primarily due to the increase in volume of injectants. The 14 percent increase in the third quarter of 2006 compared to the same quarter of 2005 is due to increased injection volumes. On a year to date basis, the 25 percent increase in purchased injectants is due to increased injection volumes and the price of injectants.

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 $30.82 per boe (after hedging) in the third quarter of 2006 compared to $33.94 per boe (after hedging) for the same period in 2005, mainly due to lower average commodity prices, higher operating expenses and royalty expenses.

Combined Netbacks ($ per boe)		Three months ended												Nine months ended
		Sept 30, 2006				Jun 30, 2006				Sept 30, 2005				Sept 30, 2006				Sept 30, 2005
Sales price		$	53.67			$	54.91			$	56.07			$	54.53			$	49.66
Other production income			(0.06	)			0.41				0.13				0.13				0.15
			53.61				55.32				56.20				54.66				49.81
Processing, interest and other income			0.88				0.80				0.39				0.80				0.86
Royalties			(10.77	)			(8.84	)			(10.60	)			(10.67	)			(9.11	)
Operating expenses			(10.94	)			(11.32	)			(10.59	)			(10.82	)			(9.80	)
Transportation costs			(0.33	)			(0.35	)			(0.36	)			(0.34	)			(0.35	)
Amortization of injectants			(1.63	)			(1.67	)			(1.10	)			(1.60	)			(1.08	)
Operating netback		$	30.82			$	33.94			$	33.94			$	32.03			$	30.33

Light Crude Netbacks ($ per bbl)		Three months ended												Nine months ended
		Sept 30, 2006				Jun 30, 2006				Sept 30, 2005				Sept 30, 2006				Sept 30, 2005
Sales price		$	72.61			$	72.67			$	63.95			$	69.49			$	58.31
Other production income			(0.19	)			1.07				0.37				0.31				0.44
			72.42				73.74				64.32				69.80				58.75
Processing, interest and other income			0.60				0.50				0.64				0.56				0.51
Royalties			(12.19	)			(11.27	)			(11.03	)			(10.21	)			(9.39	)
Operating expenses			(13.20	)			(12.17	)			(12.85	)			(12.09	)			(11.58	)
Transportation costs			(0.26	)			(0.27	)			(0.29	)			(0.26	)			(0.30	)
Amortization of injectants			(4.61	)			(4.61	)			(3.14	)			(4.46	)			(3.07	)
Operating netback		$	42.76			$	45.92			$	37.65			$	43.34			$	34.92

Heavy Oil Netbacks ($ per bbl)		Three months ended												Nine months ended
		Sept 30, 2006				Jun 30, 2006				Sept 30, 2005				Sept 30, 2006				Sept 30, 2005
Sales price		$	51.47			$	50.07			$	47.74			$	43.72			$	33.82
Processing, interest and other income			0.38				0.16				(0.83	)			0.31				0.24
Royalties			(6.27	)			(4.75	)			(8.00	)			(4.24	)			(5.03	)
Operating expenses			(16.28	)			(16.03	)			(16.30	)			(15.51	)			(16.95	)
Operating netback		$	29.30			$	29.45			$	22.61			$	24.28			$	12.08

- 14 - PENGROWTH ENERGY TRUST

Natural Gas Netbacks ($ per mcf)		Three months ended												Nine months ended
		Sept 30, 2006				Jun 30, 2006				Sept 30, 2005				Sept 30, 2006				Sept 30, 2005
Sales price		$	6.29			$	6.76			$	8.57			$	7.26			$	7.61
Other production income			—				0.01				—				0.01				—
			6.29				6.77				8.57				7.27				7.61
Processing, interest and other income			0.23				0.23				0.09				0.21				0.24
Royalties			(1.34	)			(0.93	)			(1.47	)			(1.61	)			(1.36	)
Operating expenses			(1.38	)			(1.66	)			(1.31	)			(1.52	)			(1.19	)
Transportation costs			(0.09	)			(0.09	)			(0.09	)			(0.09	)			(0.09	)
Operating netback		$	3.71			$	4.32			$	5.79			$	4.26			$	5.21

NGLs Netbacks ($ per bbl)		Three months ended												Nine months ended
		Sept 30, 2006				Jun 30, 2006				Sept 30, 2005				Sept 30, 2006				Sept 30, 2005
Sales price		$	60.76			$	58.92			$	57.75			$	59.30			$	52.59
Royalties			(21.84	)			(17.67	)			(20.57	)			(21.93	)			(16.27	)
Operating expenses			(10.26	)			(10.20	)			(10.13	)			(9.69	)			(8.65	)
Operating netback		$	28.66			$	31.05			$	27.05			$	27.68			$	27.67

Other production income consists of sulphur sales and brokered sales and purchases. A prior period adjustment for brokered sales is included in the second quarter of 2006 while both the second and third quarter of 2006 include adjustments for brokered purchases.

Interest

Interest expense increased eight percent to $7.1 million for the third quarter of 2006 from $6.5 million in the second quarter of 2006 primarily due to an increase in the average interest rate. Interest expense increased by $1.4 million in the third quarter of 2006 compared to the same period in 2005 due to higher average interest rates.

General and Administrative (G&A)

		Three months ended												Nine months ended
($ millions)		Sept 30, 2006				Jun 30, 2006				Sept 30, 2005				Sept 30, 2006				Sept 30, 2005
Cash G&A expense			6.8				8.1				7.0				22.4				19.7
$  per boe			1.27				1.59				1.29				1.42				1.23
Non-cash G&A expense			0.9				0.6				0.6				2.8				2.1
$  per boe			0.17				0.11				0.11				0.18				0.13
Total G&A ($ millions)			7.7				8.7				7.6				25.2				21.8
Total G&A ($  per boe)			1.44				1.70				1.40				1.60				1.36

The cash component of G&A for the third quarter of 2006 compared to the second quarter of 2006 decreased in part due to the timing of compensation expenses for retention programs. Retention programs were the main reason for the $3.4 million increase in the first nine months of 2006 versus the same period in 2005.

Management Fees

		Three months ended												Nine months ended
($ millions)		Sept 30, 2006				Jun 30, 2006				Sept 30, 2005				Sept 30, 2006				Sept 30, 2005
Management Fee			0.8				2.1				1.6				6.1				6.8
Performance Fee			2.2				1.3				1.9				4.5				4.8
Total ($ millions)			3.0				3.4				3.5				10.6				11.6
Total ($  per boe)			0.56				0.65				0.65				0.67				0.72

PENGROWTH ENERGY TRUST - 15 -

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

Depletion, Depreciation and Accretion

		Three months ended												Nine months ended
($ millions)		Sept 30, 2006				Jun 30, 2006				Sept 30, 2005				Sept 30, 2006				Sept 30, 2005
Depletion and Depreciation			83.5				67.8				73.5				222.4				213.6
$ per boe			15.56				13.23				13.57				14.09				13.34
Accretion			4.5				3.9				3.5				11.7				10.5
$ per boe			0.84				0.76				0.66				0.74				0.66

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

Other Expenses

Other expenses, on a year to date basis, consist of costs related to the consolidation of Class A and Class B trust units ($2.7 million) and 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.

On October 31, 2006, the Federal Government announced it intends to remove certain deductions currently available to the Trust when calculating taxable income. While no specific legislation has been proposed making it difficult to fully assess the impact of the announcement, the intent of the proposal is to change Pengrowth’s taxability starting in 2011.

Capital Expenditures

During the first nine months of 2006, Pengrowth spent $179.0 million on development and optimization activities. The largest expenditures were at Judy Creek ($29.4 million), SOEP ($17.7 million), Quirk Creek ($11.0 million), West Pembina ($9.7 million), Bodo ($8.4 million), Weyburn ($8.2 million), Three Hills Creek ($7.1 million) and Prespatou ($6.6 million). Pengrowth engages in limited exploration activities and in the first nine months of 2006 most of the capital spent on development was directed towards increasing production and improving reserve recovery through infill drilling. An additional $528 million was incurred to complete the Carson Creek area, Dunvegan area and other acquisitions.

		Three months ended												Nine months ended
($ millions)		Sept 30, 2006				Jun 30, 2006				Sept 30, 2005				Sept 30, 2006				Sept 30, 2005
Geological and geophysical			0.5				1.1				0.2				2.8				1.4
Drilling and completions			42.2				33.5				29.8				133.5				89.2
Plant and facilities			9.4				7.5				10.0				30.3				23.9
Land purchases			4.7				5.0				0.8				12.4				1.1
Development capital			56.8				47.1				40.8				179.0				115.6
Acquisitions			473.8				4.4				2.1				528.0				93.3
Total capital expenditures and acquisitions			530.6				51.5				42.9				707.0				208.9

Pengrowth currently anticipates capital expenditures for maintenance and development of approximately $280 million for 2006, up from our previous guidance of $261 million. The increase from our previous guidance includes post acquisition capital expenditures primarily related to the Esprit business combination.

- 16 - PENGROWTH ENERGY TRUST

Acquisitions and Dispositions

On September 28, 2006, Pengrowth acquired all of the issued and outstanding shares of a company which had interests in oil and natural gas assets in the Carson Creek area of Alberta and the adjacent Carson Creek Gas Plant for $475 million prior to adjustments. Goodwill of $133 million was determined based on the excess of the total consideration paid less the value assigned to the identifiable assets and liabilities including the future tax liability.

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 capital structure is as follows:

		As at				As at				As at
		September 30				December 31				September 30
($ thousands)		2006				2005				2005
Revolving credit facilities			132,000				35,000				190,000
Senior unsecured notes			327,910				333,089				232,220
Working capital deficit			119,234				77,639				63,524
Note payable			20,000				20,000				35,000
Cash balance			(928	)			—				(997	)
Net Debt			598,216				465,728				519,747
Unitholders’ equity			1,888,365				1,475,996				1,467,859
Net debt as a percentage of total book capitalization			24.1	%			24.0	%			26.1	%
Trailing 12 months cash flow *			680,811				618,070				514,766
Net debt to trailing 12 months cash flow*			0.9				0.8				1.0

The $97 million increase in the revolving credit facilities from December 31, 2005 is primarily due to capital expenditures, acquisitions, and the purchase of portfolio investments exceeding cash withholdings, proceeds from the Monterey transaction and net proceeds from the equity offering that closed September 28, 2006.

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

At September 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 $132 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 September 30, 2006, Pengrowth had $387 million available to draw from its credit facilities. On October 2, 2006, concurrent with the closing of the business combination with Esprit, Pengrowth increased its term credit facility to $950 million. A total of $315 million was used to repay and cancel Esprit’s credit facility. On October 2, 2006, Pengrowth had over $500 million available to draw from its credit facilities after the increase to its credit facility and repayment of Esprit’s facility.

Pengrowth does not have any off balance sheet financing arrangements.

PENGROWTH ENERGY TRUST - 17 -

Pengrowth’s U.S. $200 million senior unsecured notes, Pound sterling denominated £50 million senior unsecured notes, and the revolving credit facilities have certain financial covenants which may restrict the total amount of Pengrowth’s borrowings. The financial covenants are different between the revolving credit facilities and the senior unsecured notes and some of the covenants are summarized below:

	1.		Total senior debt should not be greater than three times Earnings Before Income Taxes Depreciation and Amortization (EBITDA) for the last four fiscal quarters
	2.		Total debt should not be greater than 3.5 times EBITDA for the last four fiscal quarters
	3.		Total senior debt should be less than 50% of total book capitalization
	4.		EBITDA should not be less than four times interest expense

In the event that Pengrowth enters into a significant acquisition, certain credit facility financial covenants are relaxed for two fiscal quarters after the close of the acquisition.

The actual loan documents are filed on SEDAR as Other Material Contracts. As at September 30, 2006, Pengrowth was in compliance with all its financial covenants. In the event that Pengrowth was not in compliance with any of the financial covenants in its credit facility or senior unsecured notes, Pengrowth would be in default of that specific debt and would have to repay the debt, refinance the debt or negotiate new terms with the debt holders and may have to suspend distributions to unitholders.

On November 1, 2006, Pengrowth announced its offer to purchase all of the outstanding 6.5 percent convertible extendible unsecured subordinated debentures (the “Debentures”). Approximately $95.8 million of Debentures remained outstanding at September 30, 2006. Following the completion of the business combination with Esprit on October 2, 2006, Pengrowth assumed all the covenants and obligations of Esprit under its Debenture Indenture providing for the issuance of the Debentures. Pursuant to the change of control provisions in the Debenture Indenture, Pengrowth is required within 30 days of such change of control, to make an offer to purchase all the outstanding Debentures at a price equal to 101 percent of the principal amount of the outstanding Debentures, plus any accrued but unpaid interest.

Distributable Cash and Distributions

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

		Three months ended												Nine months ended
($ thousands, except per trust unit amounts)		Sept 30, 2006				Jun 30, 2006				Sept 30, 2005				Sept 30, 2006				Sept 30, 2005
Cash flows from operating activities			174,294				118,326				158,976				484,219				421,482
Change in non-cash operating working capital			(31,351	)			34,219				(789	)			(47,471	)			(1,840	)
Funds generated from operations			142,943				152,545				158,187				436,748				419,642
Change in deferred injectants			(870	)			(1,853	)			892				(80	)			2,854
Change in remediation trust funds			(599	)			(279	)			(272	)			(1,269	)			(804	)
Change in deferred charges			1,997				(1,716	)			2,818				1,069				2,028
Other			(124	)			383				384				136				140
Distributable cash			143,347				149,080				162,009				436,604				423,860
Allocation of Distributable cash
Cash withheld			10,834				28,483				52,156				63,192				97,741
Distributions paid or declared			132,513				120,597				109,853				373,412				326,119
Distributable cash			143,347				149,080				162,009				436,604				423,860
Distributable cash per trust unit			0.89				0.93				1.02				2.72				2.71
Distributions paid or declared per trust unit			0.75				0.75				0.69				2.25				2.07
Payout ratio (1)			92	%			81	%			68	%			86	%			77	%

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

Distributable cash is derived from producing and selling oil, natural gas and related products. As such, distributable cash is highly dependent on commodity prices. From time to time, Pengrowth enters into forward commodity contracts to fix the commodity price and mitigate price volatility. Details of commodity contracts are contained in Note 11 to the September 30, 2006 Financial Statements.

The Board of Directors and Management regularly monitor forecasted distributable cash and payout ratio. The Board considers a number of factors, including expectations of future commodity prices, capital expenditure requirements,

- 18 - PENGROWTH ENERGY TRUST

and the availability of debt and equity capital. Pursuant to the Royalty Indenture, the Board can establish a reserve for certain items including up to 20 percent of Gross Revenue to fund various costs including future capital expenditures, royalty income in any future period and future abandonment costs.

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 third quarter of 2006.

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

Ex-Distribution				Distribution		Distribution Amount				US $
Date *		Record Date		Payment Date		per Trust Unit				Amount**
December 28, 2005		December 30, 2005		January 15, 2006		$	0.25			$	0.21
January 30, 2006		February 1, 2006		February 15, 2006		$	0.25			$	0.22
February 27, 2006		March 1, 2006		March 15, 2006		$	0.25			$	0.22
March 29, 2006		March 31, 2006		April 15, 2006		$	0.25			$	0.22
April 27, 2006		May 1, 2006		May 15, 2006		$	0.25			$	0.22
May 30, 2006		June 1, 2006		June 15, 2006		$	0.25			$	0.22
June 28, 2006		June 30, 2006		July 15, 2006		$	0.25			$	0.22
July 28, 2006		July 31, 2006		August 15, 2006		$	0.25			$	0.22
August 29, 2006		August 31, 2006		September 15, 2006		$	0.25			$	0.22
September 27, 2006		September 29, 2006		October 15, 2006		$	0.25			$	0.22
October 30, 2006		November 1, 2006		November 15, 2006		$	0.25			$	0.22
November 29, 2006		December 1, 2006		December 15, 2006

Taxability of Distributions

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.

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.

PENGROWTH ENERGY TRUST - 19 -

Summary of Quarterly Results

The following table is a summary of quarterly results for 2006, 2005 and 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				Q3
Oil and gas sales ($000’s)							291,896				283,532				287,757
Net income ($000’s)							66,335				110,116				82,542
Net income per trust unit ($)							0.41				0.69				0.51
Net income per trust unit — diluted($)							0.41				0.68				0.51
Distributable cash ($000’s)							144,177				149,080				143,347
Actual distributions paid or declared per trust unit($)							0.75				0.75				0.75
Daily production (boe)							58,845				56,325				58,344
Total production (mboe)							5,296				5,126				5,368
Average realized price ($  per boe)							55.04				54.91				53.67
Operating netback ($  per boe)							31.44				33.94				30.82