Edgar Filing: PENGROWTH ENERGY TRUST

e40vfza

U.S. SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 40-F/A

AMENDMENT NO. 2

	o		REGISTRATION STATEMENT PURSUANT TO SECTION 12 OF THE SECURITIES EXCHANGE ACT OF 1934.

	þ		ANNUAL REPORT PURSUANT TO SECTION 13(a) OF THE SECURITIES EXCHANGE ACT OF 1934



For the fiscal year ended: December 31, 2005		Commission File Number: 1-31253

PENGROWTH ENERGY TRUST

(Exact name of Registrant as specified in its charter)

Alberta, Canada
(Province or other jurisdiction of incorporation or organization)


1311		None
(Primary Standard Industrial		(I.R.S. Employer
Classification Code Number)		Identification Number)

Suite 2900, 240 – 4^th Avenue S.W.
Calgary, Alberta Canada T2P 4H4
(403) 233-0224
(Address and telephone number of Registrant’s principal executive offices)

Vinson & Elkins L.L.P.
2300 First City Tower, 1001 Fannin
Houston, Texas 77002-6760
(713) 758-2222
(Name, address (including zip code) and telephone number (including area code)
of agent for service in the United States)

Securities registered or to be registered pursuant to Section 12(b) of the Act.


Title of each class		Name of each exchange on which registered
Trust Units		New York Stock Exchange

Securities registered or to be registered pursuant to Section 12(g) of the Act.

None

(Title of Class)

Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act.

None

(Title of Class)

For Annual Reports indicate by check mark the information filed with this Form:


þ Annual information form		þ Audited annual financial statements

Indicate the number of outstanding shares of each of the issuer’s classes of capital or common stock as of the close of the period covered by the annual report:

Indicate by check mark whether the Registrant filing the information contained in this Form is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934 (the “Exchange Act”). If “Yes” is marked, please indicate the filing number assigned to the Registrant in connection with such Rule.


Yes o		No þ

Indicate by check mark whether the Registrant (1) has filed all reports to be filed by Section 13 or 15(d) of the Exchange Act during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports) and (2) has been subject to filing requirements for the past 90 days.


Yes þ		No o

EXPLANATORY NOTE

This Amendment No. 2 (this “Amendment”) to the Annual Report on Form 40-F filed on March 31, 2006 (the “Original Filing”) of Pengrowth Energy Trust (“Pengrowth”) for the fiscal year ended December 31, 2005, is being filed for the purpose of amending Pengrowth’s Management’s Discussion and Analysis to include the Disclosure Controls and Procedures section, which was inadvertently omitted from the Original Filing. In addition, we are including as exhibits certain currently dated certifications of our Chief Executive Officer and Chief Financial Officer.

Other than as expressly set forth above, this Form 40-F/A does not, and does not purport to, update or restate the information in any Item of the Original Filing or reflect any events that have occurred after the Original Filing was filed. The filing of this Amendment shall not be deemed an admission that the Original Filing, when made, included any known, untrue statement of material fact or knowingly omitted to state a material fact necessary to make a statement not misleading.

DOCUMENTS FILED AS PART OF THIS ANNUAL REPORT

The following documents have been filed as part of this Amendment on Form 40-F:


Appendix		Documents

A*		Pengrowth Energy Trust Annual Information Form for the year ended December 31, 2005.


B		Management’s Discussion and Analysis (Revised) (included on pages 54 through 80 of the Pengrowth Energy Trust 2005 Annual Report).


C*		Consolidated Financial Statements of Pengrowth Energy Trust, including note 20 thereof which includes a reconciliation of the Consolidated Financial Statements to United States generally accepted accounting principles.

D*		Five Year Review — Pengrowth Energy Trust Consolidated Financial Results (included on pages 115 through 119 of the Pengrowth Energy Trust 2005 Annual Report).

E*		Corporate Governance (included on pages 48 through 53 of the Pengrowth Energy Trust 2005 Annual Report).

F*		Oil and Gas Producing Activities Prepared in Accordance with SFAS No. 69 — “Disclosures about Oil and Gas Producing Activities”.

G*		Auditors’ Report.

* Previously filed.

- 2 -

EXHIBIT LIST


1.*		Consent of KPMG LLP

2.*		Consent of Gilbert Laustsen Jung Associates Ltd.

3.		Certification pursuant to Section 906

4.		Certificate of CEO

5.		Certificate of CFO


*		Previously filed.

- 3 -

SIGNATURES

Pursuant to the requirements of the Exchange Act, the Registrant certifies that it meets all of the requirements for filing this Amendment on Form 40-F and has duly caused this Annual Report to be signed on its behalf by the undersigned, thereunto duly authorized.


Date: September 15, 2006	PENGROWTH ENERGY TRUST by its Administrator PENGROWTH CORPORATION
	By:	/s/ James S. Kinnear
		James S. Kinnear
		Chairman, President and Chief Executive Officer

MANAGEMENT’S DISCUSSION AND ANALYSIS (REVISED)
(INCLUDED ON PAGES 54 THROUGH 80 OF THE PENGROWTH ENERGY TRUST 2005 ANNUAL REPORT)

Management’s Discussion and Analysis (Revised)

The following discussion and analysis of financial results should be read in conjunction with the audited consolidated financial statements for the year ended December 31, 2005 and is based on information available to February 27, 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.

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

Historical Annual Compound Returns by Year
(%)
Note: Assumes reinvestment of distributions in the trust at month end.

* Weighted average of Class A trust units
(NYSE) and Class B trust units (TSX).

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PENGROWTH ENERGY TRUST

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 “Business Risks” herein and under “Risk Factors” in Pengrowth’s Annual Information Form which will be available on SEDAR at www.sedar.com on or before March 31, 2006.

Pengrowth cautions that the foregoing list of factors that may affect future results is not exhaustive. When relying on our forward-looking statements to make decisions with respect to Pengrowth, investors and others should carefully consider the foregoing factors and other uncertainties and potential events. Furthermore, the forward-looking statements contained in this Management’s Discussion and Analysis are

55
2005 ANNUAL REPORT

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

Critical Accounting Estimates

As discussed in Note 2 to the financial statements, the financial statements are prepared in accordance with Canadian Generally Accepted Accounting Principles (GAAP). Management is required to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and revenues and expenses for the period then ended.

The amounts recorded for depletion, depreciation and amortization of injectants and the provision for asset retirement obligations are based on estimates. The ceiling test calculation is based on estimates of proved reserves, production rates, oil and natural gas prices, future costs and other relevant assumptions. As required by National Instrument 51-101 (NI 51-101), Pengrowth uses independent qualified reserve evaluators in the preparation of reserve evaluations. By their nature, these estimates are subject to measurement uncertainty and changes in these estimates may impact the consolidated financial statements of future periods.

Non-GAAP Financial Measures

This 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 distributable cash, distributable cash per trust unit, payout ratio and operating netbacks do not have standardized meanings prescribed by GAAP. During the second quarter of 2005, Pengrowth’s withholding practice and presentation of distributable cash changed. The impact of the new practice is discussed in the Distributable Cash, Distributions and Taxability of Distributions section of this report on pages 69 to 70, while the remaining non-GAAP measures are determined by reference to our financial statements. We discuss these measures because we believe that they facilitate the understanding of the results of our operations and financial position.

Conversion and Currency

When converting natural gas to equivalent barrels of oil within this discussion, Pengrowth uses the international standard of six thousand cubic feet (mcf) to one barrel of oil equivalent. Barrels of oil equivalent may be misleading, particularly if used in isolation; a conversion ratio of six mcf of natural gas to one boe is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Production volumes, revenues and reserves are reported on a company interest gross basis (before royalties) in accordance with Canadian practice. All amounts are stated in Canadian dollars unless otherwise specified.

Year 2005 Overview

Pengrowth achieved record net income and cash generated from operations for 2005.

Robust commodity prices, a full year of production from the 2004 Murphy acquisition and additional production from the Swan Hills Unit No.1 (Swan Hills) and Crispin Energy Inc. (Crispin) acquisitions, which closed on February 28, 2005 and April 29, 2005, respectively, combined to have a favorable impact on 2005 financial and operating results relative to 2004. Financial hedging losses of $65.8 million on crude oil and natural gas offset some of the positive impact of the high commodity prices during the year as did the three percent depreciation of the U.S. dollar relative to the Canadian dollar.

56
PENGROWTH ENERGY TRUST

Highlights

•

Oil and gas sales increased 41 percent to $1.15 billion in 2005 resulting in record net income of $326 million, an increase of 112 percent over 2004.

•

Production for 2005 averaged 59,357 barrels of oil equivalent (boe) per day, an increase of more than ten percent versus 2004. Fourth quarter production averaged 61,442 boe per day, an increase of four percent over the previous quarter and seven percent over the comparable period in 2004.

•

Distributable cash reached a new high in 2005 at $620 million, an increase of 54 percent over 2004. Fourth quarter distributable cash increased 87 percent versus 2004 to $196 million, the highest level of distributable cash generated in any quarter in Pengrowth’s history.

•

Distributions paid or declared to unitholders increased 23 percent to $446 million or $2.82 per trust unit in 2005 from $363 million or $2.63 per trust unit in 2004. Pengrowth’s monthly distribution was increased in December 2005 to an annualized rate of $3.00 per trust unit.

•

Pengrowth’s payout ratio to unitholders for the full year and fourth quarter of 2005 reached record lows of 72 percent and 61 percent of cash generated from operations, respectively.

•

Pengrowth’s 2005 development expenditures were essentially fully funded through withholdings from distributable cash.

•

During the year Pengrowth spent a combined total of $176 million on maintenance and development projects ending the year with proved plus probable (P50) reserves of 219.4 million barrels of oil equivalent (mmboe) compared to 218.6 mmboe at year end 2004. Pengrowth’s P50 reserves were replaced through the addition of 16.7 mmboe related to acquisitions and 8.6 mmboe resulting from drilling activity, improved recoveries and technical revisions. Additions were offset by production of 21.7 mmboe and divestitures of 2.8 mmboe.

•

Pengrowth’s average realized commodity price (after hedging) increased 28 percent to $53.02 per boe in 2005, from $41.33 in 2004.

•

Operating netbacks increased 33 percent to $32.54 per boe (after hedging) versus $24.51 per boe in 2004. Combined hedging losses totaled $3.04 per boe in 2005 versus $3.52 per boe in 2004.

•

On February 28, 2005, Pengrowth acquired an additional 11.89 percent working interest in the Swan Hills property for $87 million. This acquisition increased Pengrowth’s total interest in the property to 22.34 percent.

•

On April 29, 2005, Pengrowth successfully completed the acquisition of all of the issued and outstanding shares of Crispin adding approximately 1,900 boe per day of production to our portfolio.

•

On December 1, 2005, Pengrowth completed a £50 million private placement of senior unsecured ten year notes.

•

As at December 31, 2005, Pengrowth had generated a combined three-year weighted average compound total return of 36 percent per annum for Class A and Class B unitholders.

57
2005 ANNUAL REPORT

Summary of Financial and Operating Results


	Three months ended December 31									Twelve months ended December 31
(thousands, except per unit amounts)	2005			2004			% Change			2005			2004			% Change

INCOME STATEMENT
Oil and gas sales	$	353,923		$	223,183	⁽²⁾		59		$	1,151,510		$	815,751	⁽²⁾		41
Net income	$	116,663		$	31,138			275		$	326,326		$	153,745			112
Net income per trust unit	$	0.73		$	0.23			217		$	2.08		$	1.15			81
Cash generated from operations	$	196,588		$	93,287			111		$	618,070		$	404,167			53
Cash generated from operations per trust unit	$	1.23		$	0.68			81		$	3.93		$	3.03			30
Distributable cash ⁽¹⁾	$	195,879		$	104,958	⁽²⁾		87		$	619,739		$	401,178	⁽²⁾		54
Distributable cash per trust unit ⁽¹⁾	$	1.23		$	0.77			60		$	3.94		$	3.01			31
Distributions paid or declared	$	119,858		$	96,466			24		$	445,977		$	363,061			23
Distributions paid or declared per trust unit	$	0.75		$	0.69			9		$	2.82		$	2.63			7
Weighted average number of trust units outstanding		159,528			136,916			17			157,127			133,395			18

BALANCE SHEET
Working capital										$	(112,205	)	$	(78,546	)		43
Property, plant and equipment and other assets										$	2,067,988		$	1,989,288			4
Long term debt										$	368,089		$	345,400			7
Unitholders’ equity										$	1,475,996		$	1,462,211			1
Unitholders’ equity per trust unit										$	9.23		$	9.56			(3	)
Number of trust units outstanding at year end											159,864			152,973			5

DAILY PRODUCTION
Crude oil (barrels)		21,179			20,118			5			20,799			20,817			0
Heavy oil (barrels)		5,410			5,819			(7	)		5,623			3,558			58
Natural gas (mcf)		168,862			156,621			8			161,056			144,277			12
Natural gas liquids (barrels)		6,710			5,385			25			6,093			5,281			15
Total production (boe)		61,442			57,425			7			59,357			53,702			10
Total production (mboe)		5,653			5,283			7			21,665			19,655			10

PRODUCTION PROFILE
Crude oil		34	%		35	%					35	%		39	%
Heavy oil		9	%		10	%					10	%		6	%
Natural gas		46	%		46	%					45	%		45	%
Natural gas liquids		11	%		9	%					10	%		10	%

AVERAGE REALIZED PRICES
(AFTER HEDGING)
Crude oil (per barrel)	$	59.40		$	44.76			33		$	58.59		$	43.21			36
Heavy oil (per barrel)	$	31.77		$	26.99			18		$	33.32		$	32.45			3
Natural gas (per mcf)	$	11.97		$	7.02			71		$	8.76		$	6.80			29
Natural gas liquids (per barrel)	$	58.46		$	48.04			22		$	54.22		$	42.21			28
Average realized price per boe	$	62.55		$	42.08	⁽²⁾		49		$	53.02		$	41.33	⁽²⁾		28

PROVED PLUS PROBABLE RESERVES
Crude oil (mbbls)											98,684			94,066			5
Heavy oil (mbbls)											15,790			18,245			(13	)
Natural gas (bcf)											516			521			(1	)
Natural gas liquids (mbbls)											18,985			19,395			(2	)
Total oil equivalent (mboe)											219,396			218,613			0


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

⁽²⁾Restated to conform to presentation adopted in the current year

58
PENGROWTH ENERGY TRUST

Results of Operations

Production

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

Daily Production


	Three months ended						Twelve months ended
	Dec. 31, 2005		Sep. 30, 2005		Dec. 31, 2004		Dec. 31, 2005		Dec. 31, 2004

Light crude oil (bbls) ⁽¹⁾		21,179		20,660		20,118		20,799		20,817
Heavy oil (bbls) ⁽¹⁾		5,410		5,405		5,819		5,623		3,558
Natural gas (mcf)		168,862		164,288		156,621		161,056		144,277
Natural gas liquids (bbls) ⁽¹⁾		6,710		5,448		5,385		6,093		5,281

Total boe per day		61,442		58,894		57,425		59,357		53,702


⁽¹⁾bbls refers to barrels

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

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

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

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

59
2005 ANNUAL REPORT

Pricing and Commodity Price Hedging

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

Average Realized Prices


(Cdn$)	Three months ended							Twelve months ended
	Dec. 31, 2005		Sep. 30, 2005		Dec. 31, 2004			Dec. 31, 2005		Dec. 31, 2004

Light crude oil (per bbl)		67.00		74.37		55.24			65.47		50.72
after hedging		59.40		63.95		44.76			58.59		43.21
Heavy oil (per bbl)		31.77		47.74		26.99			33.32		32.45
Natural gas (per mcf)		12.80		8.69		7.25			8.99		7.03
after hedging		11.97		8.57		7.02			8.76		6.80
Natural gas liquids (per bbl)		58.46		57.75		48.04			54.22		42.21

Total per boe		67.43		60.06		46.38	⁽³⁾		56.06		44.85	⁽³⁾
after hedging		62.55		56.07		42.08	⁽³⁾		53.02		41.33	⁽³⁾

Benchmark Prices
WTI oil (U.S. $ per bbl)		60.05		63.31		48.27			56.70		41.47
AECO spot gas (Cdn $ per gj) ⁽¹⁾		11.08		7.75		6.72			8.04		6.44
NYMEX gas (U.S. $ per mmbtu)⁽²⁾		12.97		8.49		7.11			8.62		6.16
Currency (U.S. $/Cdn $)		0.85		0.83		0.82			0.83		0.77


⁽¹⁾ gj refers to gigajoules

⁽²⁾ mmbtu refers to millions of British thermal units

⁽³⁾ Prior years restated to conform to presentation adopted in current year

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


	Three months ended						Twelve months ended
	Dec. 31, 2005		Sep. 30, 2005		Dec. 31, 2004		Dec. 31, 2005		Dec. 31, 2004
Light crude oil ($ million)		14.8		19.8		19.4		52.2		57.2
Light crude oil ($ per bbl)		7.60		10.42		10.48		6.88		7.51
Natural gas ($ million)		12.9		1.8		3.3		13.6		11.9
Natural gas ($ per mcf)		0.83		0.12		0.23		0.23		0.23

Combined ($ million)		27.7		21.6		22.7		65.8		69.1
Combined ($ per boe)		4.88		3.99		4.30		3.04		3.52

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

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PENGROWTH ENERGY TRUST

In conjunction with the Murphy acquisition, Pengrowth assumed certain fixed price natural gas sales contracts and firm pipeline demand charge contracts associated with the Murphy reserves. Under these contracts, Pengrowth is obligated to sell 3,886 mmbtu per day, until April 30, 2009 at an average remaining contract price of Cdn $2.31 per mmbtu. As required by GAAP, the fair value of the natural gas sales contract was recognized as a liability based on the mark-to-market value at May 31, 2004. The liability at December 31, 2005 of $18.2 million for the contracts will continue to be drawn down and recognized in income as the contracts are settled. As this is a non-cash component of income, it is not included in the calculation of distributable cash. At December 31, 2005, the mark-to-market value of the fixed price physical sales contract represented a potential loss of $35.3 million.

Oil and Gas Sales — Contribution Analysis


($ millions)	Three months ended												Twelve months ended
	Dec. 31,		% of		Sep. 30,		% of		Dec. 31,		% of		Dec. 31,		% of		Dec. 31,		% of
Sales Revenue	2005		total		2005		total		2004		total		2005		total		2004		total

Natural gas		186.0		53		129.5		43		101.2		45		514.9		45		359.3		44

Light crude oil		115.7		33		121.6		40		82.8		37		444.8		39		329.2		40

Natural gas liquids		36.1		10		28.9		9		23.8		11		120.6		10		81.6		10

Heavy oil		15.8		4		23.7		8		14.5		7		68.4		6		42.3		5

Brokered sales/sulphur		0.3		—		0.8		—		0.9		—		2.8		—		3.4		1

Total oil and gas sales		353.9		—		304.5		—		223.2		—		1,151.5		—		815.8		—

Oil and Gas Sales — Price and Volumes Analysis

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


($ millions)	Natural gas			Light oil			NGLs		Heavy oil		Other			Total

Year ended December 31, 2004		359.3			329.2			81.6		42.3		3.4			815.8

Effect of change in product prices		115.3			112.0			26.7		1.8		—			255.8

Effect of change in sales volumes		42.0			(1.4	)		12.3		24.3		—			77.2

Effect of hedging losses		(1.7	)		5.0			—		—		—			3.3

Other		—			—			—		—		(0.6	)		(0.6	)

Year ended December 31, 2005		514.9			444.8			120.6		68.4		2.8			1,151.5

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2005 ANNUAL REPORT

Transportation Costs

($ millions)

Three months ended

Twelve months ended

Dec. 31, 2005

Sep. 30, 2005

Dec. 31, 2004

Dec. 31, 2005

Dec. 31, 2004

Light oil transportation

0.5

0.6

0.4

2.2

1.8

$ per bbl

0.27

0.29

0.23

0.29

0.23

Natural gas transportation

1.8

1.4

2.0

5.7

6.3

$ per mcf

0.12

0.09

0.14

0.10

0.12

Pengrowth incurs transportation costs for its product once the product enters a feeder or main pipeline to the title transfer point. The transportation cost is dependant upon industry rates and distance the product flows on the pipeline prior to changing ownership or custody. Pengrowth has the option to sell some of its natural gas directly to premium markets outside of Alberta by incurring additional transportation costs. In 2005, Pengrowth sold most of its natural gas without incurring significant additional transportation costs. Similarly, Pengrowth has elected to sell approximately 75 percent of its crude oil at market points beyond the wellhead, but at the first major trading point, requiring minimal transportation costs.

Royalties


($ millions)	Three months ended									Twelve months ended
	Dec. 31, 2005			Sep. 30, 2005			Dec. 31, 2004			Dec. 31, 2005			Dec. 31, 2004

Royalty expense		68.0			57.4			49.1			213.9			160.4
$ per boe		12.03			10.60			9.29			9.87			8.16

Royalties as a percent of sales		19.2	%		18.9	%		22.0	%		18.6	%		19.7	%

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

Processing, Interest and Other Income

($ millions)

Three months ended

Twelve months ended

Dec. 31, 2005

Sep. 30, 2005

Dec. 31, 2004

Dec. 31, 2005

Dec. 31, 2004

Processing, interest & other income

4.0

2.1

4.5

17.7

14.2

$ per boe

0.71

0.39

0.83

0.82

0.72

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 included below in Operating Expenses.

62
PENGROWTH ENERGY TRUST

Operating Expenses

($ millions)

Three months ended

Twelve months ended

Dec. 31, 2005

Sep. 30, 2005

Dec. 31, 2004

Dec. 31, 2005

Dec. 31, 2004

Operating expenses

61.2

57.4

42.6

218.1

159.7

$ per boe

10.83

10.59

8.06

10.07

8.13

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

Amortization of Injectants for Miscible Floods

($ millions)

Three months ended

Twelve months ended

Dec. 31, 2005

Sep. 30, 2005

Dec. 31, 2004

Dec. 31, 2005

Dec. 31, 2004

Purchased and capitalized

14.5

6.9

8.2

34.7

20.4

Amortization

7.1

6.0

4.9

24.4

19.7

The cost of injectants (primarily natural gas and ethane) purchased for injection in miscible flood programs is amortized over the period of expected future economic benefit. Prior to 2005, the expected future economic benefit from injection was estimated at 30 months, based on the results of previous flood patterns. Commencing in 2005, the response period for additional new patterns being developed is expected to be somewhat shorter relative to the historical miscible patterns in the project. Accordingly, the cost of injectants purchased in 2005 will be amortized over a 24 month period while costs incurred for the purchase of injectants in prior periods will continue to be amortized over 30 months. As of December 31, 2005, the balance of unamortized injectant costs was $35.3 million.

The value of Pengrowth’s proprietary injectants is not recorded until reproduced from the flood and sold, although the cost of producing these injectants is included in operating expenses. Pengrowth currently anticipates similar injection volumes for Judy Creek and increased injection volumes for Swan Hills during 2006. This combined with higher forecast prices for natural gas and ethane is anticipated to result in increased total injectant costs for 2006.

Interest

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

63
2005 ANNUAL REPORT

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

Foreign Currency Gains and Losses

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

General and Administrative


($ millions)	Three months ended						Twelve months ended
	Dec. 31, 2005		Sep. 30, 2005		Dec. 31, 2004		Dec. 31, 2005		Dec. 31, 2004

Cash G&A expense		7.7		7.0		6.5		27.4		22.1

$ per boe		1.36		1.29		1.23		1.27		1.12

Non-cash G&A expense		0.8		0.6		0.4		2.9		2.3

$ per boe		0.14		0.11		0.08		0.13		0.12

Total G&A ($ million)		8.5		7.6		6.9		30.3		24.4

Total G&A ($ per boe)		1.50		1.40		1.31		1.40		1.24

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

64
PENGROWTH ENERGY TRUST

Management Fees

($ million)

Three months ended

Twelve months ended

Dec. 31, 2005

Sep. 30, 2005

Dec. 31, 2004

Dec. 31, 2005

Dec. 31, 2004

Management Fee

2.2

1.6

1.4

9.1

6.8

Performance Fee

2.2

1.9

1.2

6.9

6.1

Total ($ million)

4.4

3.5

2.6

16.0

12.9

Total ($ per boe)

0.77

0.65

0.48

0.74

0.66

Under the current management agreement, which came into effect July 1, 2003 for two three-year terms ending June 30, 2009, the Manager will earn a performance fee if the Trust’s total returns exceed eight percent per annum on a three year rolling average basis. At the end of the first term a review process will determine whether to extend the agreement for the second term. The maximum fees payable, including the performance fee, is limited to 80 percent of the fees that would otherwise have been payable under the previous management agreement for the first three years and 60 percent for the subsequent three years.

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

Related Party Transactions

Details of related party transactions incurred in 2005 and 2004 are provided in Note 15 to the financial statements. These transactions include the management fees paid to the Manager. The Manager is controlled by James S. Kinnear, the Chairman, President and Chief Executive Officer of the Corporation. The management fees paid to the Manager are pursuant to a management agreement which has been approved by the trust unitholders. Mr. Kinnear does not receive any salary or bonus in his capacity as a director and officer of the Corporation and has not received any new trust unit options or rights since November 2002.

Related party transactions in 2005 also include $0.7 million (2004 — $0.8 million) paid to a law firm controlled by the Vice President and Corporate Secretary of Pengrowth Corporation, Charles V. Selby. These fees are paid in respect of legal and advisory services provided by the Vice President and Corporate Secretary. Mr. Selby does not receive any salary or bonus in his capacity as Vice President and Corporate Secretary of the Corporation. Mr. Selby has from time to time been granted trust unit rights and options.

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

65
2005 ANNUAL REPORT

The corporate acquisition of Crispin in 2005 resulted in Pengrowth recording an additional future tax liability of $22.2 million. A $75.6 million future tax liability was initially recorded in 2004 as a result of the Murphy acquisition. The future tax liability represents the difference between the tax basis and the fair values assigned to the acquired assets. A comparison of the fair value and tax basis at the end of the year increased the future tax liability by $12.3 million to $110.1 million.

Depletion, Depreciation and Accretion

($ millions)

Three months ended

Twelve months ended

Dec. 31, 2005

Sep. 30, 2005

Dec. 31, 2004

Dec. 31, 2005

Dec. 31, 2004

Depletion and Depreciation

71.4

73.5

69.4

285.0

247.3

$ per boe

12.63

13.57

13.14

13.15

12.58

Accretion

3.6

3.6

3.2

14.2

10.6

$ per boe

0.64

0.66

0.60

0.65

0.54

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

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

Ceiling Test

Under Canadian GAAP, a ceiling test is applied to the carrying value of the property, plant and equipment and other assets. The carrying value is assessed to be recoverable when the sum of the undiscounted cash flows expected from the production of proved reserves, the lower of cost and market of unproved properties and the cost of major development projects exceeds the carrying value. When the carrying value is not assessed to be recoverable, an impairment loss is recognized to the extent that the carrying value of assets exceeds the sum of the discounted cash flows expected from the production of proved and probable reserves, the lower of cost and market of unproved properties and the cost of major development projects. The cash flows are estimated using expected future product prices and costs and are discounted using a risk-free interest rate. There was a significant surplus in the ceiling test at year end 2005.

Asset Retirement Obligations

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

66
PENGROWTH ENERGY TRUST

Remediation Trust Funds & Remediation and Abandonment Expenses

During 2005, Pengrowth contributed $1.3 million into trust funds established to fund certain abandonment and reclamation costs associated with Judy Creek and SOEP. The balance in these remediation trust funds was $8.3 million at December 31, 2005.

Pengrowth takes a proactive approach to managing its well abandonment and site restoration obligations. There is an on-going program to abandon wells and reclaim well and facility sites. In 2005, Pengrowth spent $7.4 million on abandonment and reclamation (2004 — $4.4 million). Pengrowth expects to spend approximately $11 million per year, prior to inflation, over the next ten years on remediation and abandonment.

Goodwill

In accordance with Canadian GAAP, Pengrowth recorded goodwill of $12.2 million upon the Crispin acquisition in 2005 and $170.6 million upon the Murphy acquisition in 2004. The goodwill value was determined based on the excess of total consideration paid less the net value assigned to other identifiable assets and liabilities, including the future income tax liability. Details of the acquisitions are provided in Note 4 to the financial statements.

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, processing, interest and other income and royalty injection credits between light crude oil, heavy oil, natural gas and NGL production. Pengrowth recorded an operating netback of $32.54 per boe (after hedging) in 2005 compared to $24.51 (after hedging) in 2004, mainly due to higher average commodity prices in 2005 partially offset by higher operating expenses and royalties.

Combined Netbacks


($ per boe)	Three months ended									Twelve months ended
	Dec. 31, 2005			Sep. 30, 2005			Dec. 31, 2004			Dec. 31, 2005			Dec. 31, 2004

Sales price		62.55			56.07			42.08			53.02			41.33

Other production income		0.06			0.13			0.17			0.13			0.17

		62.61			56.20			42.25			53.15			41.50

Processing, interest and other income		0.71			0.39			0.83			0.82			0.72

Royalties		(12.02	)		(10.60	)		(9.29	)		(9.87	)		(8.16	)

Operating expenses		(10.83	)		(10.59	)		(8.07	)		(10.07	)		(8.13	)

Transportation costs		(0.41	)		(0.36	)		(0.47	)		(0.36	)		(0.42	)

Amortization of injectants		(1.25	)		(1.10	)		(0.94	)		(1.13	)		(1.00	)

Operating netback		38.81			33.94			24.31			32.54			24.51

67
2005 ANNUAL REPORT

Light Crude Netbacks


($ per bbl)	Three months ended									Twelve months ended
	Dec. 31, 2005			Sep. 30, 2005			Dec. 31, 2004			Dec. 31, 2005			Dec. 31, 2004

Sales price		59.40			63.95			44.76			58.59			43.21

Other production income		0.17			0.37			0.48			0.37			0.45

		59.57			64.32			45.24			58.96			43.66

Processing, interest and other income		0.34			0.64			0.51			0.47			0.46

Royalties		(6.47	)		(11.03	)		(9.65	)		(8.64	)		(7.62	)

Operating expenses		(14.32	)		(12.85	)		(9.17	)		(12.28	)		(9.31	)

Transportation costs		(0.27	)		(0.29	)		(0.23	)		(0.29	)		(0.23	)

Amortization of injectants		(3.63	)		(3.14	)		(2.67	)		(3.21	)		(2.58	)

Operating netback		35.22			37.65			24.03			35.01			24.38

Heavy Oil Netbacks


($ per bbl)	Three months ended									Twelve months ended
	Dec. 31, 2005			Sep. 30, 2005			Dec. 31, 2004			Dec. 31, 2005			Dec. 31, 2004

Sales price		31.77			47.74			26.99			33.32			32.45

Processing, interest and other income		0.74			(0.83	)		—			0.36			—

Royalties		(2.98	)		(8.00	)		(4.19	)		(4.53	)		(4.87	)

Operating expenses		(11.60	)		(16.30	)		(9.44	)		(15.65	)		(9.85	)

Operating netback		17.93			22.61			13.36			13.50			17.73

Natural Gas Netbacks


($ per mcf)	Three months ended									Twelve months ended
	Dec. 31, 2005			Sep. 30, 2005			Dec. 31, 2004			Dec. 31, 2005			Dec. 31, 2004

Sales price		11.97			8.57			7.02			8.76			6.80

Processing, interest and other income		0.19			0.09			0.24			0.23			0.20

Royalties		(2.62	)		(1.47	)		(1.34	)		(1.70	)		(1.26	)

Operating expenses		(1.38	)		(1.31	)		(1.16	)		(1.24	)		(1.15	)

Transportation costs		(0.12	)		(0.09	)		(0.14	)		(0.10	)		(0.12	)

Operating netback		8.04			5.79			4.62			5.95			4.47

68
PENGROWTH ENERGY TRUST

NGLs Netbacks


($ per bbl)	Three months ended									Twelve months ended
	Dec. 31, 2005			Sep. 30, 2005			Dec. 31, 2004			Dec. 31, 2005			Dec. 31, 2004

Sales price		58.46			57.75			48.04			54.22			42.21
Royalties		(21.29	)		(20.57	)		(19.37	)		(17.66	)		(15.43	)
Operating expenses		(10.05	)		(10.13	)		(7.87	)		(9.04	)		(7.94	)
Transportation costs		—			—			(0.10	)		—			(0.10	)

Operating netback		27.12			27.05			20.70			27.52			18.74

Distributable Cash, Distributions and Taxability of Distributions

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

The Board of Directors may change the amount withheld in the future, depending on a number of factors, including future commodity prices, capital expenditure requirements, and the availability of debt and equity capital. Pursuant to the Royalty Indenture, the Board of Directors can establish a reserve for certain items including up to 20 percent of Gross Revenue to fund future capital expenditures or for the payment of royalty income in any future period.

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

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

69
2005 ANNUAL REPORT


($ thousands, except per trust unit amounts)	Three months ended									Twelve months ended
	Dec. 31, 2005			Sep. 30, 2005			Dec. 31, 2004			Dec. 31, 2005			Dec. 31, 2004

Cash generated from operations		196,588			158,976			93,287			618,070			404,167
Change in non-cash operating working capital		(7,993	)		(789	)		8,576			(9,833	)		(1,173	)
Change in deferred injectants		7,411			892			3,228			10,265			746
Change in remediation trust funds		784			(272	)		32			(20	)		(917	)
Change in deferred charges		(793	)		2,818			(473	)		1,235			(1,893	)
Other		(118	)		384			308			22			248

Distributable cash		195,879			162,009			104,958			619,739			401,178

Allocation of Distributable Cash
Cash withheld		76,021			52,156			8,492			173,762			38,117
Distributions paid or declared		119,858			109,853			96,466			445,977			363,061

Distributable cash		195,879			162,009			104,958			619,739			401,178

Distributable cash per trust unit		1.23			1.02			0.77			3.94			3.01
Distributions paid or declared per trust unit		0.75			0.69			0.69			2.82			2.63

Payout ratio⁽¹⁾		61	%		69	%		103	%		72	%		90	%


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

At this time, Pengrowth anticipates that approximately 75 to 80 percent of 2006 distributions will be taxable to Canadian residents. This estimate is subject to change depending on a number of factors including, but not limited to, the level of commodity prices, acquisitions, dispositions, and new equity offerings.

Acquisitions and Dispositions

On February 28, 2005, Pengrowth closed the acquisition of an additional 11.89 percent working interest in Swan Hills increasing Pengrowth’s total working interest in the unit to 22.34 percent. The purchase price was $87 million, after adjustments from the October 1, 2004 effective date to the closing date.

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

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

70
PENGROWTH ENERGY TRUST

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

On August 12, 2004, Pengrowth acquired an additional 34.35 percent interest in Kaybob Notikewin Unit No. 1 for a purchase price of $20 million, bringing Pengrowth’s total working interest in this unit to just below 99 percent.

Capital Expenditures

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


($ millions)	Three months ended						Twelve months ended
	Dec. 31, 2005		Sep. 30, 2005		Dec. 31, 2004		Dec. 31, 2005		Dec. 31, 2004

Geological and geophysical		—		0.2		0.2		1.4		0.6
Drilling and completions		41.1		29.8		36.2		130.3		111.5
Plant and facilities		10.2		10.0		17.7		34.1		49.0
Land purchases		8.8		0.8		—		9.9		—

Development capital		60.1		40.8		54.1		175.7		161.1

Acquisitions		—		—		—		175.1		573.0

Total capital expenditures and acquisitions		60.1		40.8		54.1		350.8		734.1

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

Reserves

Pengrowth reported year end Proved plus Probable reserves of 219.4 mmboe compared to 218.6 mmboe at year end 2004. Further details of Pengrowth’s 2005 year end reserves are provided on pages 37 to 45 of the annual report.

71
2005 ANNUAL REPORT

Working Capital

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

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

Financial Resources and Liquidity

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

Long term debt at December 31, 2005 included fixed rate term debt denominated in U.S. dollars which translated to Cdn $232.6 million. Due to the improvement in the Canadian to U.S. dollar exchange rate, an unrealized gain of Cdn $57.6 million has been recorded since the U.S. dollar denominated debt was issued in April of 2003. Long term debt at December 31, 2005 also included fixed rate term debt of £50 million which translated to Cdn$100.5 million. Through a series of hedging transactions, Pengrowth fixed the exchange rate in Canadian dollars for all future interest payments and repayment at maturity.

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

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

Pengrowth anticipates funding its 2006 capital expenditures through a combination of undistributed cash from operations, unused credit facilities and any proceeds from property dispositions.

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PENGROWTH ENERGY TRUST

Financial Leverage and Coverage


	Twelve months ended December 31
	2005		2004

Cash generated from operations to interest expense (times)		29		13
Long term debt to cash generated from operations (times)		0.6		0.9
Long term debt to debt plus book equity (%)		20		19

Class A and Class B Trust Unit Structure

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

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

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

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

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2005 ANNUAL REPORT

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

The Board of Directors may determine, based upon market circumstances as they exist at that time or other factors, that it is in the best interests of all unitholders to: (a) remove the requirement to comply with the ownership threshold that restricts the Class A trust units to 49.75 percent of the outstanding trust units; (b) remove the residency restrictions pertaining to the holding of Class B trust units; (c) permit a free conversion of Class B trust units to Class A trust units; (d) permit the consolidation of the trust unit capital of the Trust; (e) allow a controlled conversion of Class B trust units to Class A trust units over time to preserve an orderly market; (f) maintain the Class A and Class B trust unit structure until market circumstances become more favorable to both classes of unitholders; or (g) take such other action as the Board of Directors may consider appropriate.

Commitments and Contractual Obligations


($ thousands)	2006		2007		2008		2009		2010		Thereafter		Total

Long term debt ⁽¹⁾		—		—		—		—		174,450		193,639		368,089
Interest payments on long term debt ⁽²⁾		17,298		17,298		17,298		17,298		11,564		34,546		115,302
Note payable		20,000		—		—		—		—		—		20,000
Operating leases
Office rent		2,030		2,070		3,096		3,055		3,036		21,529		34,816
Vehicle leases		852		776		604		306		91		—		2,629

		2,882		2,846		3,700		3,361		3,127		21,529		37,445

Purchase obligations
Pipeline transportation		43,839		38,197		34,981		29,813		11,748		53,525		212,103
Capital expenditures		33,323		7,098		294		—		—		—		40,715
CO₂ purchases		5,119		4,357		4,198		4,232		4,267		18,728		40,901

		82,281		49,652		39,473		34,045		16,015		72,253		293,719

Remediation trust fund payments		250		250		250		250		250		11,250		12,500

		122,711		70,046		60,721		54,954		205,406		333,217		847,055


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

⁽²⁾		Interest payments on foreign denominated debt, calculated based on Dec 31, 2005 foreign exchange rate.

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PENGROWTH ENERGY TRUST

Trust Unit Information

Trust Unit Trading — after re-class⁽¹⁾

High

Low

Volume (000’s)

Value ($ millions)

TSX — PGF.A ($ Cdn)

2005 1st quarter

28.29

22.15

24.03

2,049

53.3

2nd quarter

27.90

23.95

27.20

1,798

46.4

3rd quarter

30.10

26.30

29.50

2,047

58.0

4th quarter

29.80

23.64

27.41

1,324

35.2

Year

30.10

22.15

27.41

7,218

192.9

2004 1st quarter

2nd quarter

3rd quarter

24.19

19.10

22.67

1,672

35.5

4th quarter

26.33

20.03

24.93

2,607

58.9

Year

26.33

19.10

24.93

4,279

94.4

TSX — PGF.B ($ Cdn)

2005 1st quarter

19.90

16.10

17.05

29,219

543.7

2nd quarter

19.01

16.37

18.40

19,370

342.5

3rd quarter

21.26

18.25

20.58

22,738

441.0

4th quarter

23.38

17.27

22.65

19,747

411.0

Year

23.38

16.10

22.65

91,074

1,738.2

2004 1st quarter

2nd quarter

3rd quarter

20.00

18.03

18.87

5,588

105.6

4th quarter

20.04

17.51

18.50

16,007

301.8

Year

20.04

17.51

18.50

21,595

407.4

NYSE — PGH ($ U.S.)

2005 1st quarter

22.94

18.11

20.00

24,621

515.1

2nd quarter

22.74

19.05

22.25

16,153

335.0

3rd quarter

25.75

21.55

25.42

14,502

340.3

4th quarter

25.56

20.00

23.53

17,808

399.7

Year

25.75

18.11

23.53

73,084

1,590.1

2004 1st quarter

2nd quarter

3rd quarter

18.94

14.40

17.93

21,200

350.4

4th quarter

21.24

15.85

20.82

31,174

574.7

Year

21.24

14.40

20.82

52,374

925.1


⁽¹⁾		July 27, 2004, trust units were re-classified as Class A or Class B trust units. Class A trust units trade on the New York Stock Exchange (NYSE) under PGH and on the Toronto Stock Exchange (TSX) under PGF.A. Class B trust units trade only on the TSX under PGF.B.

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2005 ANNUAL REPORT

Trust Unit Trading — before re-class⁽¹⁾


	High		Low		Close		Volume (000’s) Value ($ millions)

TSX — PGF.UN ( $ Cdn)
2004 1st quarter		21.25		15.55		17.98		30,620	567.8
2nd quarter		19.15		16.15		18.67		18,145	328.5
3rd quarter		19.75		18.52		19.42		3,554	68.5
4th quarter
Year		21.25		15.55		19.42		52,319	964.8

NYSE — PGH ($ U.S.)		16.60		12.10		13.70		36,899	525.6
2004 1st quarter
2nd quarter		14.24		11.62		13.98		22,194	295.9
3rd quarter		14.95		13.84		14.64		5,797	84.5
4th quarter
Year		14.95		11.62		14.64		64,890	906.0


⁽¹⁾		July 27, 2004, trust units were re-classified as Class A or Class B trust units. Class A trust units trade on the New York Stock Exchange (NYSE) under PGH and on the Toronto Stock Exchange (TSX) under PGF.A. Class B trust units trade only on the TSX under PGF.B.

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

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

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PENGROWTH ENERGY TRUST

Summary of Quarterly Results

The following table is a summary of quarterly results for 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 2004 and 2005, which have had a positive impact on net income and distributable cash.

2005

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

0.75

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

Oil and gas sales ($000’s) ⁽¹⁾

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) ⁽¹⁾

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) ⁽¹⁾

40.37

41.83

40.90

42.08

Operating netback ($ per boe)

25.71

22.77

24.31

Selected Annual Information Financial Results



	Twelve months ended December 31
($ thousands)	2005		2004		2003

Oil and gas sales ⁽¹⁾		1,151,510		815,751		702,732
Net income		326,326		153,745		189,297
Net income per trust unit		2.08		1.15		1.63
Distributable cash ⁽¹⁾		619,739		401,178		345,911
Actual distributions paid or declared per trust unit		2.82		2.63		2.68
Total assets		2,391,432		2,276,534		1,673,718
Long term financial liabilities ⁽²⁾		381,026		383,616		294,300
Unitholders’ equity		1,475,996		1,462,211		1,159,433
Number of units outstanding at year end (thousands)		159,864		152,973		123,874


⁽¹⁾		Prior years restated to conform to presentation adopted in the current year

⁽²⁾		Long term debt plus long term portion of note payable and contract liabilities

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2005 ANNUAL REPORT

Business Risks

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

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

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

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

•		Government royalties, income taxes, commodity taxes, and other taxes, levies and fees have a significant economic impact on Pengrowth’s financial results. Changes to federal and provincial legislation governing such royalties, taxes and fees could have a material impact on Pengrowth’s financial results and the value of Pengrowth trust units.

•		Environmental laws and regulatory initiatives impact Pengrowth financially and operationally. We may incur substantial capital and operating expenses to comply with increasingly complex laws and regulations covering the protection of the environment and human health and safety. In particular, we may be required to incur significant costs to comply with the 1997 Kyoto Protocol to the United Nations Framework Convention on Climate Change.

•		Pengrowth’s oil and gas reserves will be depleted over time and our level of distributable cash and the value of our trust units could be reduced if reserves and production are not replaced. The ability to replace production depends on Pengrowth’s success in developing existing reserves, acquiring new reserves and financing this development and acquisition activity within the context of the capital markets.

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

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

•		Increased activity within the oil and gas sector can increase the cost of goods and services and make it more difficult to hire and retain professional staff.

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

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

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PENGROWTH ENERGY TRUST

•		The value of Class A trust units and Class B trust units, relative to one another, may be influenced by the different markets in which the trust units trade, the restrictions in entitlement of the Class B trust units to Canadian residents and the limitation in the number of Class A trust units beneath an ownership threshold of 49.75 percent of all trust units outstanding.

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

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

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

Pengrowth mitigates some of these risks by:

•		Fixing the price on a portion of its future crude oil and natural gas production.

•		Fixing the Canadian / U.S. exchange rate through financial hedging contracts or by fixing commodity prices in Canadian dollars.

•		Offering competitive incentive-based compensation packages to attract and retain highly qualified and motivated professional staff.

•		Adhering to strict investment criteria for acquisitions.

•		Acquiring mature production with long life reserves and proven production.

•		Performing extensive geological, geophysical, engineering and environmental analysis before committing to capital development projects.

•		Geographically diversifying its portfolio.

•		Controlling costs to maximize profitability.

•		Developing and adhering to policies and practices that protect the environment and meet or exceed the regulations imposed by the government.

•		Developing and adhering to safety policies and practices that meet or exceed regulatory standards.

•		Ensuring strong third party operators for non-operated properties.

•		Carrying insurance to cover physical losses and business interruption.

These factors should not be considered to be exhaustive. Additional risks are outlined in the Annual Information Form (AIF) of the Trust available on SEDAR at www.sedar.com on or before March 31, 2006.

Subsequent Event

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

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2005 ANNUAL REPORT

Outlook

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

•		Operating our properties in a safe and prudent manner in order to protect our employees, the public, the environment and our investment;

•		Maintaining a balanced portfolio of oil and gas properties in our key focus areas;

•		Growing production and reserves through accretive acquisitions and low risk development drilling;

•		Increasing our undeveloped land position;

•		Continuing to optimize costs and maximize netbacks;

•		The selective disposition of oil and gas properties that do not meet our return objectives;

•		Continuing to maintain a stable distribution policy while withholding a portion of distributable cash to fund future capital programs.

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

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

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

Disclosure Controls and Procedures

As a Canadian reporting issuer with securities listed on both the TSX and the NYSE, Pengrowth is required to comply with Multilateral Instrument 52-109 “Certification of Disclosure in Issuers’ Annual and Interim Filings”, as well as the Sarbanes Oxley Act (SOX) enacted in the United States. Both the Canadian regulations and the U.S. certification rules include similar requirements where both the Chief Executive Officer and the Chief Financial Officer must assess and certify as to the effectiveness of the internal controls over the disclosure of annual filings, interim filings, reports and other releases of material information.

The Chief Executive Officer, James Kinnear, and the Chief Financial Officer, Christopher Webster, evaluated the effectiveness of Pengrowth’s disclosure controls and procedures for the period ending December 31st, 2005. This evaluation considered the functions performed by its Disclosure Committee, the review and oversight of all executive officers and the board, as well as the process and systems in place for filing regulatory and public information. Pengrowth’s established review process and disclosure controls are designed to ensure that all required information, reports and filings required under provincial securities legislation and United States securities laws are properly submitted and recorded in a timely fashion. Pengrowth’s disclosure controls and procedures were certified as being effective for that period on Form 52-109F1 but Pengrowth omitted reference to this evaluation in its Management’s Discussion and Analysis for the period filed under Canadian securities laws. Pengrowth did disclose this evaluation in its filings for the period under U.S. securities laws. Pengrowth continues to believe that the processes, practices and administration procedures it has in place provide effective disclosure controls.

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PENGROWTH ENERGY TRUST