Edgar Filing: PENGROWTH ENERGY TRUST

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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 March 28, 2006 to March 30, 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:

2005 Annual Report.

SIGNATURES

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


	PENGROWTH ENERGY TRUST by its administrator PENGROWTH CORPORATION
March 30, 2006	By:	/s/ Gordon M. Anderson
		Name:	Gordon M. Anderson
		Title:	Vice President

High-Quality Assets

Pengrowth’s property portfolio is one of the strongest in the energy trust sector with a proved plus probable reserve life index of 10.5 years and a reserve base of 219.4 million boe. Our assets are characterized by low decline rates and high development potential allowing us to achieve stable production.

See page 16

Organic Growth

Pengrowth is committed to maintaining an optimal portfolio of low-risk development and aggressive organic growth opportunities. A large inventory of opportunities, including EOR, CBM and shallow gas has been identified to augment our conventional exploitation opportunities.

See page 24

Operational Excellence

Pengrowth is focused on continuous improvements in our safety, environmental and facility maintenance programs. Key operational categories are continuously reviewed to identify opportunities to increase productivity and improve well performance and facility reliability.

See page 44

Cover: Randy Steele, Manager, NEBC and W6M Alberta, Production Operations

Annual General Meeting

The annual general meeting of the unitholders of Pengrowth Energy Trust will be held on Tuesday, May 2, 2006 at 3:00 p.m. MST, in the McMurray Room, Calgary Petroleum Club, 319-5 Ave S.W., Calgary, Alberta. Unitholders who are unable to attend are urged to complete, sign and mail their proxies to ensure their units will be voted at the meeting.

Financial Flexibility

Pengrowth’s prudent approach to the trust’s capital structure has been instrumental in our continuing financial flexibility and strength. A keen focus is placed on managing operating and administrative costs to maximize returns and position Pengrowth for future growth.

See page 52

Corporate Governance

Pengrowth is diligent in its pursuit of the highest standards of corporate governance. We believe that good corporate governance is essential to effective and efficient operations and seek to not only meet but exceed all applicable securities and regulatory guidelines where feasible.

See page 46

Inside

02		Financial Highlights

04		Operating Highlights

06		President’s Message

18		High-Quality Assets

26		Organic Growth

37		Operations Statistical Review

46		Operational Excellence

48		Corporate Governance

54		Management’s Discussion and Analysis

81		Management’s Report to Unitholders

82		Auditors’ Report

83		Consolidated Financial Statements

86		Notes to the Consolidated Financial Statements

IBC Corporate Information

2005 ANNUAL REPORT

Financial Highlights


(thousands, except per unit amounts)	2005			2004			% Change

INCOME STATEMENT
Oil and gas sales	$	1,151,510		$	815,751	⁽⁴⁾		41
Net income	$	326,326		$	153,745			112
Net income per trust unit	$	2.08		$	1.15			81
Cash generated from operations	$	618,070		$	404,167			53
Cash generated from operations per trust unit	$	3.93		$	3.03			30
Distributable cash ⁽¹⁾	$	619,739		$	401,178	⁽⁴⁾		54
Distributable cash per trust unit ⁽¹⁾	$	3.94		$	3.01			31
Distributions paid or declared	$	445,977		$	363,061			23
Distributions paid or declared per trust unit	$	2.82		$	2.63			7
Payout Ratio ⁽¹⁾		72	%		90	%		(20	)
Weighted average number of trust units outstanding		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	)
Long term debt plus equity, at book	$	1,844,085		$	1,807,611			2
Number of trust units outstanding at year end	$	159,864		$	152,973			5
Equity Market Capitalization ⁽²⁾	$	3,989,939		$	3,323,770			20
Enterprise Value ⁽³⁾	$	4,358,028		$	3,669,170			19
Net Asset Value @ 10%	$	2,834,663		$	1,708,012			66
Net Asset Value per trust unit @ 10%	$	17.73		$	11.17			59
Long term debt as a ratio of:
Cash generated from operations		0.6	x		0.9	x
Total Capitalization:
Long term debt plus equity at book value		20	%		19	%
Long term debt plus equity at market value		8	%		9	%


⁽¹⁾		See the section of the report entitled “Non-GAAP Financial Measures”, page 56

⁽²⁾		Equity Market Capitalization equals the number of Class A trust units outstanding at period end multiplied by the PGF.A TSX closing price plus the number of Class B trust units and undeclared trust units outstanding at period end multiplied by the PGF.B TSX closing price

⁽³⁾		Enterprise Value equals equity market capitalization plus long term debt

⁽⁴⁾		Restated to conform to presentation adopted in the current year

PENGROWTH ENERGY TRUST

Oil and Gas Sales ($ millions)

Distributable Cash ($ millions)

Distributions ($ per trust unit)

2005 ANNUAL REPORT

Operating Highlights


	2005			2004			% Change

DAILY PRODUCTION
Crude oil (barrels)		20,799			20,817			—
Heavy oil (barrels)		5,623			3,558			58
Natural gas (mcf)		161,056			144,277			12
Natural gas liquids (barrels)		6,093			5,281			15
Total production (boe)		59,357			53,702			10
TOTAL PRODUCTION (mboe)		21,665			19,655			10
PRODUCTION PROFILE
Crude oil		35	%		39	%
Heavy oil		10	%		6	%
Natural gas		45	%		45	%
Natural gas liquids		10	%		10	%
AVERAGE REALIZED PRICES (after hedging)
Crude oil (per barrel)	$	58.59		$	43.21			36
Heavy oil (per barrel)	$	33.32		$	32.45			3
Natural gas (per mcf)	$	8.76		$	6.80			29
Natural gas liquids (per barrel)	$	54.22		$	42.21			28
Average realized price per boe	$	53.02		$	41.33	⁽¹⁾		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			—
OPERATING EXPENSES (2)
Millions	$	218.1		$	159.7			37
Per boe	$	10.07		$	8.13			24
GENERAL AND ADMINISTRATIVE COSTS
Millions	$	30.3		$	24.4			24
Per boe	$	1.40		$	1.24			13
MANAGEMENT FEES
Millions	$	16.0		$	12.9			24
Per boe	$	0.74		$	0.66			12
ACQUISITION COSTS
Millions	$	175.1		$	569.7	⁽¹⁾		(69	)
Mmboe acquired		16.7			47.9			(65	)
Per boe	$	10.49		$	11.89	⁽¹⁾		(12	)


⁽¹⁾		Restated to conform to presentation adopted in the current year

⁽²⁾		Operating expenses incurred to earn processing and other income are included

PENGROWTH ENERGY TRUST

Operating Costs ($ per boe)

Production (mboe per day)

Production Volumes (boe per trust unit)

2005 ANNUAL REPORT

President’s Message

James S. Kinnear Chairman, President and Chief Executive Officer

The year 2005 was exceptional for Pengrowth Energy Trust with new records achieved in several aspects of our business. Certainly, the higher prices for oil and natural gas were significant contributors to our positive financial results. However, the year also represented a time of markedly enhanced development internally for Pengrowth.

First of all, to review the bellwether operating and financial results achieved by the trust during the year 2005:

•

Pengrowth’s average production of crude oil and natural gas increased by over ten percent reaching a new record level of 59,357 boe per day up from an average 53,702 boe per day in 2004. During the fourth quarter of 2005, a new quarterly production record was achieved at 61,442 boe per day, seven percent above the fourth quarter 2004 level. Production per weighted average trust unit outstanding declined only moderately from 0.147 boe per trust unit in 2004 to 0.138 boe per trust unit in 2005.

•

Oil and natural gas sales exceeded $1 billion for the first time in Pengrowth’s history increasing by 41 percent to $1.15 billion as compared with $816 million in the previous year.

•

Distributable cash reached a new high in 2005 at $620 million, an increase of 54 percent over $401 million in 2004. On a per trust unit basis, distributable cash was $3.94 in 2005 an increase of 31 percent compared to $3.01 per trust unit in 2004.

PENGROWTH ENERGY TRUST

•

Distributions paid or declared to unitholders increased 23 percent to $446 million or $2.82 per trust unit in 2005 as compared to $363 million or $2.63 per trust unit in 2004.

•

Pengrowth’s monthly distribution per trust unit was raised in December 2005 from $0.23 to $0.25 or $3.00 annually, an increase of nine percent.

•

The trust’s payout ratio for the full year 2005 was 72 percent as compared with 90 percent in 2004. During the fourth quarter of 2005 the payout ratio reached a new low of 61 percent.

•

As a result of the higher level of withholdings, Pengrowth retained $174 million during the year which essentially fully funded our $176 million development and capital expenditure program during the year. This was the first time in Pengrowth’s history that this has occurred.

•

Net income reached a new record of $326 million or $2.08 per trust unit in 2005 as compared to $154 million or $1.15 per trust unit in 2004.

The marked increase in commodity prices driven by strong global demand for energy and continued geopolitical unrest during the year was a significant contributor to Pengrowth’s enhanced results in 2005. West Texas Intermediate (WTI) crude oil prices rose by almost 37 percent from an average of U.S. $41.47 per barrel in 2004 to U.S. $56.70 per barrel in 2005. Natural gas prices on the New York Mercantile Exchange (NYMEX) rose by approximately 40 percent from an average of U.S. $6.16 per mmbtu in 2004 to U.S. $8.62 per mmbtu in 2005. As a result, Pengrowth’s average realized commodity prices, after hedging, increased 28 percent to $53.02 per boe in 2005 from $41.33 in 2004.

Crude Oil Price History

WTI Oil (U.S. $ per bbl)

2005 ANNUAL REPORT

Natural Gas Price History
AECO (Cdn $ per gj)

Proved plus Probable* Reserves
(mmboe) * Prior to 2004 Established

Proved plus Probable* Reserves
(boe per trust unit) * Prior to 2004 Established

Reserves and Development Activities

During 2005, Pengrowth shifted our focus toward organic growth potential to capitalize on opportunities available from its existing asset base. The cost of reserve additions from the trust’s internal development program may be less than the cost of reserve additions through acquisitions.

•

During the year, Pengrowth spent a combined total of $176 million on maintenance and development projects in order to enhance reserves from our existing assets.

•

Pengrowth incurred finding and development costs for proved reserves of $10.63 per boe in 2005 including the change in future development capital in accordance with National Instrument 51-101.

•

The year end GLJ Petroleum Consultants Ltd. (GLJ) reserve appraisal indicated proved plus probable reserves of 219.4 million boe as compared with 218.6 million boe at the end of 2004. Acquisitions added 16.7 million boe during the year while drilling additions, improved recoveries and technical revisions totaled 8.6 million boe. The new additions were offset by production of 21.7 million boe and divestitures of 2.8 million boe. Proved plus probable reserves per trust units outstanding at year end declined modestly from 1.43 boe per trust unit to 1.37 boe per trust unit at year end 2005.

•

The reserve life index (RLI) for proved plus probable reserves at 10.5 years was essentially unchanged at year end 2005 from the 10.4 year RLI for year end 2004. This compares favourably with the trust sector average.

PENGROWTH ENERGY TRUST

Acquisitions Activity

The general environment of rising oil and natural gas prices resulted in a difficult period for making acquisitions of oil and gas producing assets on terms favorable to unitholders. Pengrowth’s challenge is to grow its business in an environment of higher asset prices and reduced availability of high-quality assets.

Despite the enhanced competitive environment, reduced availability of product and lessened asset quality Pengrowth successfully concluded two acquisitions in 2005 that replaced a significant portion of 2005 production.

On February 28, 2005, Pengrowth acquired an additional 11.89 percent working interest in Swan Hills Unit No.1 for an adjusted purchase price of $87 million bringing our total working interest to 22.34 percent. The transaction was funded through existing credit facilities. The acquisition added production of approximately 1,390 boe per day and reserves of approximately 9.7 million boe proved and 11.0 million boe proved plus probable based on an independent appraisal by GLJ. More importantly, the acquisition doubled Pengrowth’s working interest in one of Western Canada’s few remaining large oil-in-place reservoirs. This is a core component of Pengrowth’s enhanced oil recovery (EOR) strategy for future growth.

On April 29, 2005, Pengrowth completed its first acquisition of a public corporation with the closing of the Arrangement Agreement with Crispin Energy Inc. The acquisition was accretive to unitholders on a production and distributable cash per trust unit basis and added proved plus probable reserves of 5.2 million boe.

The acquisition included producing properties located primarily in the Three Hills area of central Alberta, one of Pengrowth’s focus areas. It also provided 39,000 net acres of undeveloped land, including approximately 25,000 net acres in the Horseshoe Canyon coalbed methane (CBM) prospect areas of Twining and Mikwan which are a new growth area for Pengrowth.

Pengrowth’s strategy includes the divestiture of non-core assets, allowing us to high-grade our property portfolio and maintain our focus on core areas. We have sought out new and innovative ways to enhance value for our unitholders. Several divestitures were completed in 2005 while the most significant was completed in early 2006.

Industry Average Production Acquisition Price ($ per boe)

Industry Average Reserve Acquisition Price ($ per boe)

2005 ANNUAL REPORT

On January 12, 2006, Pengrowth entered into an agreement with Monterey Exploration Ltd. (Monterey) that enabled Pengrowth to realize value for non-core producing properties while accelerating exploration and development of Pengrowth’s acreage position in northeast BC. The concept was to capitalize on the ability of new oil and gas companies to raise equity capital in the current buoyant energy market environment and the premium asset value accorded to these entities in the market place. Pengrowth sold assets producing approximately 1,000 boe per day to Monterey for $22 million and eight million shares representing approximately 34 percent equity ownership of the company.

In a related transaction, Pengrowth farmed out undeveloped acreage in northeast BC based on Monterey’s commitment to drill a minimum of 20 exploration wells over the next two years with an option for Pengrowth to retain up to a 25 percent working interest. Pengrowth also remains active in this region with significant operations while realizing proceeds for non-core assets and reducing risk by accessing outside capital to fund an enhanced exploration program.

The engine for growth for our business has been producing property acquisitions. At the same time an active development program seeks to generally offset declines in existing properties.

As a result of recent industry trends, Pengrowth has developed the following strategy:

•

Continue to seek quality producing property acquisitions in a focused way by concentrating on areas in which we already hold significant interests. Focus areas for Pengrowth include large oil-in-place crude oil reservoirs, shallow gas with the potential for further development and CBM opportunities.

•

Augment Pengrowth’s technical expertise to provide further opportunities for organic growth and enhanced development of existing properties. There may be more economic options within Pengrowth’s own suite of assets as the prices for acquisitions continue to increase.

•

Continue to rationalize the existing property portfolio and dispose of smaller interests to re-invest and re-focus our portfolio on our major asset holdings.

•

Monitor our reserves and production with the goal of growing reserves and production on a per trust unit basis over time.

PENGROWTH ENERGY TRUST

Capitalizing on Organic Growth Opportunities

As a result of the increasingly competitive and challenging acquisition environment it has become more vital for Pengrowth to enhance its business through other measures. These measures include improved operational efficiencies, the continued exploitation of our existing asset base, the aggressive pursuit of improved reserve recovery potential and opportunities in new focus areas including CBM and shallow gas.

The enhanced organic growth development program is already beginning to show success. For example, our Judy Creek team drilled a significant oil well late in 2005. The average rate for the well was 300 bbls per day over the first month of production. This is one of the best wells drilled to date in the field since Pengrowth purchased the asset in 1997.

Our northeast BC team has been very active this winter drilling five wells (3.3 net) in the Fort St. John area. Preliminary estimates show initial rates of 368 boe per day net from these wells with additional follow up locations and expansion of our gas gathering infrastructure planned for 2006.

The South Edson team has been actively exploring Cretaceous targets on lands initially acquired from Murphy Oil Corporation. Four wells have been drilled into the trend with 100 percent success at this time. Average well capability is in excess of 150 boe per day in multi-zone completions. Pengrowth is actively growing its land position in this area to generate more opportunities for future capital expenditures.

Operating Netback ($ per boe)

Leadership Team

From left to right Back row: Charles Selby Chris Webster Larry Strong Doug Bowles Bill Christensen Jim MacDonald Merle Spence
Seated: Gordon Anderson Jim Kinnear Jim Causgrove

2005 ANNUAL REPORT

Capital Expenditures
($ millions)

Capital Expenditures as a Percent of Cash Generated from Operations

Enhanced Technical Expertise

Significant technical expertise has been added through the appointment of three new members to Pengrowth’s leadership team.

•

James Causgrove was appointed Vice President, Production and Operations and an Officer of Pengrowth Corporation. Mr. Causgrove has broad responsibilities for the operating activities of Pengrowth Corporation and Pengrowth’s ongoing development and growth. Mr. Causgrove has more than 25 years of experience and a broad operational background in drilling, production engineering and midstream areas across the WCSB as well as significant experience in the property divestiture market and the analysis of potential acquisitions and divestitures;

•

William Christensen was appointed Vice President, Strategic Planning and Reservoir Exploitation and an Officer of Pengrowth Corporation. Mr. Christensen’s responsibilities include a comprehensive review of past acquisitions and the effectiveness of Pengrowth’s exploitation and development programs as a basis for planning effective initiatives to enhance unitholder value. Mr. Christensen has more than 25 years of experience in the energy sector, including broad international experience, both in operations and transactions; and

•

Larry B. Strong, was appointed Vice President, Geosciences and an Officer of Pengrowth Corporation. Mr. Strong will focus on exploitation and exploration opportunities on Pengrowth’s existing land base and will identify opportunities to add value in conjunction with new acquisitions. Mr. Strong is a geologist with solid management and business experience bringing more than 20 years of experience in earth sciences.

•

In addition, Jim MacDonald was promoted to Director of East Coast Operations from his previous role as General Manager. This reflects Mr. MacDonald’s increasing responsibilities in the east coast and his expanding role in respect to Pengrowth’s general business activities. Mr. MacDonald joined Pengrowth in 2002 following a 28-year engineering and management career.

Capital Program 2005 and 2006

In 2005, Pengrowth completed its most ambitious capital program to date spending $176 million. Of this amount approximately $135 million was directed to development activities to add proved plus probable reserves. Pengrowth’s 2005 development expenditures were essentially fully funded through withholdings from distributable cash.

PENGROWTH ENERGY TRUST

Pengrowth will continue to aggressively seek new development opportunities. At $236 million, our planned capital expenditures program for 2006 is the largest in our history. Pengrowth has undertaken a rigorous budgeting process to rank opportunities that can add reserves and production. In the current competitive acquisition environment some of the best investment opportunities lie on Pengrowth’s lands. Pengrowth’s program will aggressively pursue opportunities on our core assets, coupled with further development of mid and longer term projects in CBM, heavy oil and enhanced oil recovery while allocating sufficient capital to maintain a high quality operation.

Operational Excellence

During 2006, Pengrowth will continue to strive for operational excellence by further improvements in safety, environmental, operating and maintenance systems and execution. In the area of safety, Pengrowth plans to build on employee involvement in proactive safety interventions as well as our ongoing work with contractors regarding good communication and safe work. In its environmental programs, Pengrowth will progress with proactive pipeline replacement in operated areas and continue to fund ongoing well and facility abandonment and reclamation as appropriate. Pengrowth will review key operating cost categories to determine and pursue areas for additional cost savings as well as the improvement of well and facility reliability to increase overall productivity.

Financial Flexibility

An essential factor influencing Pengrowth’s growth is access to capital markets and its cost of capital. Therefore a further component of our success is the ability to enhance financial flexibility, maintain a strong balance sheet and manage operating and administrative costs effectively.

We strive to maintain a relatively low cost of capital as well as diversify our capital sources. For example, on December 1, 2005, Pengrowth completed a private placement issuance of £50 million in Senior Unsecured Term Notes maturing December 1, 2015. The notes were purchased by institutional investors in the United Kingdom. This continues Pengrowth’s strategy of issuing long term debt notes on occasion to ensure that the maturity of Pengrowth’s loan obligations is staggered over time. The offering provides longer term, relatively low-cost financing and extends the maturity profile of Pengrowth’s outstanding debt. Proceeds from the private placement were used to repay a portion of Pengrowth’s revolving credit facility.

Average Cost of Debt Capital
(%)

Long Term Debt/ Cash Generated from Operations
(times)

2005 ANNUAL REPORT

Debt as a Percent of
Total Capitalization
Based on Market Value

(BAR CHART)

At year end, Pengrowth’s long term debt to debt-plus-equity ratio was at 20 percent of total consolidated capital at book. Our debt-to-cash flow ratio stood at 0.6 times with the trust effectively situated to fund the upcoming capital program as well as to capitalize on favourable acquisition opportunities that may become available.

Debt as a Percent of Total Capitalization

(BAR CHART)

Debt as a Percent of
Total Capitalization
Based on Market Value

(BAR CHART)

Monthly Distribution History

Since late 2002 Pengrowth has been striving to reduce the volatility of monthly distributions. The strong commodity prices have provided an opportunity to increase distributions over time while funding internal capital obligations.

Monthly cash distributions are subject to variations depending on overall production, crude oil and natural gas prices and the amount of budgeted development and maintenance capital expenditures. The rate of monthly cash distributions is established by the Board of Directors on a regular basis and at a minimum is reviewed quarterly.

Further Enhancements to the Leadership Team

As outlined earlier, Pengrowth has been exceptionally fortunate in establishing a strong leadership team. In addition to the new operational Vice Presidents, we strengthened our financial management team with the following additions in 2005 and early 2006:

•

Christopher G. Webster, CGA, CFA, was appointed Chief Financial Officer of Pengrowth Corporation. Mr. Webster previously held the position of Vice President, Treasurer for Pengrowth;

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PENGROWTH ENERGY TRUST

•

Charles V. Selby, P.Eng., LLB, was appointed Vice President and Corporate Secretary. Mr. Selby is a lawyer and professional engineer with broad involvement in the business and affairs of Pengrowth Corporation and has served as Corporate Secretary since 1993;

•

Douglas C. Bowles, CA, was appointed Controller of Pengrowth Corporation bringing with him more than 18 years of accounting experience; and

•

Peter Cheung, CA, succeeded Mr. Webster as Treasurer of Pengrowth Corporation bringing with him over eight years in accounting and financial experience including most recently a term as Vice President, Energy Group, RBC Capital Markets.

Corporate Governance

Our active and committed Board of Directors complements Pengrowth’s strong management team. Corporate governance is an integral component of Pengrowth’s continued success. The Board ensures that a high standard of corporate governance is adopted for the Corporation and the Trust.

Pengrowth is committed to the highest standards and best practices. With consistent improvement, our corporate governance practices ensure that we not only comply with all the applicable securities and regulatory guidelines but that we exceed them wherever possible. We continuously review and adapt our program and I invite you to review additional details of our corporate governance practices which appear further in this report.

We were pleased to welcome two new members to Pengrowth’s Board of Directors in 2005 increasing our depth of financial and technical expertise and business experience in Canada and internationally.

•

A. Terence Poole, CA, has a B.Comm. Degree from Dalhousie University and brings extensive senior financial management, accounting, capital and debt market experience to Pengrowth. Mr. Poole currently holds the position of Executive Vice President, Corporate Strategy and Development of Nova Chemicals Corporation (Nova). Prior to assuming his present position in 2000, Mr. Poole held various senior management positions with Nova and other companies.

•

Kirby L. Hedrick received a B.Sc. and Mech.Eng. Degree from the University of Evansville, Indiana in 1975. Mr. Hedrick completed the Stanford Executive Program in 1997 and the Stanford Corporate Governance Program in 2003. Mr. Hedrick has extensive engineering and senior management experience in the United States and internationally retiring in 2000 as Executive Vice President, Upstream of Phillips Petroleum.

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2005 ANNUAL REPORT

One Year Annual
Compound Rate
of Return
(%)

Five Year Average
Annual Compound
Rate of Return
(%)

10 Year Average
Annual Compound
Rate of Return
(%)

Note: Assumes reinvestment of distributions in the trust at month end.

* Weighted average of Class A trust units and Class B trust units.

Management Agreement

Under the terms of the new management agreement that became effective on July 1, 2003 for two three-year terms, the Board of Directors of Pengrowth Corporation has an exclusive option to terminate the agreement and to make a payment to the Manager of approximately two thirds of the previous three years’ management fees.

Current Outlook

While the acquisitions market for producing property acquisitions remains challenging, Pengrowth will continue to seek quality asset purchases that are accretive to the trust and its unitholders.

Pengrowth has substantially augmented its technical expertise throughout the organization with significant potential for value enhancing development of our existing asset base.

The near term outlook is obviously dependent upon crude oil and natural gas prices. Current oil prices remain above U.S. $60.00 per barrel while natural gas prices have recently declined to the U.S. $7.00 per mmbtu range due in part to the warmest January weather recorded in North America in the past 100 years.

The current year forward prices for crude are presently over U.S. $65.00 while forward natural gas prices for the 2006 year are approximately U.S. $8.00 per mmbtu.

3 Year Average Annual Compound Rate of Return
(%)

Note: Assumes reinvestment of distributions in the trust at month end.

*Weighted average of Class A trust units and Class B trust units.

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PENGROWTH ENERGY TRUST

The decision of the Board of Directors to increase the monthly distribution rate was based upon the distributable cash outlook for the fourth quarter of 2005 and the full year 2006, including the enhanced capital development budget for the current year.

Our target is to continue to provide unitholders with above average results going forward. Our distributions have grown at a compound growth rate of 13 percent per annum since inception and our total returns, including a cash-on-cash yield and capital growth, have exceeded 20 percent per annum. Pengrowth will strive to provide attractive long term returns for unitholders and sustainable growth through acquisitions and development.

Compound Average Annual Rates of Return (%)

(Weighted Average of A and B Trust Units)

I would like to extend my thanks to Pengrowth’s more than 300 team members for their exceptional efforts in 2005 in creating value for our unitholders. I am extremely proud of the innovation, expertise and commitment that I observe on a daily basis. The past year was marked by significant changes and renewed vigor — it was truly a period of transformation for the trust. I am excited by the changing face of Pengrowth and eager to continue capitalizing on a multitude of new opportunities in 2006.

Respectfully submitted on behalf of the Board of Directors,

(signed)

James S. Kinnear
Chairman, President and Chief Executive Officer
February 27, 2006

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2005 ANNUAL REPORT

High-Quality Assets

Pengrowth’s assets are characterized by stable production and high-quality reserves. Pengrowth has pursued long-reserve life, large reserves and low-decline rate acquisitions and has been generally successful in this regard. Pengrowth’s assets have a Reserve Life Index (RLI) of 10.5 years based on GLJ’s year end proved plus probable reserves. These long-life reserves encompass working interests in five of the largest oil pools in the Western Canadian Sedimentary Basin (WCSB). Each of these pools originally averaged more than one billion barrels of oil-in-place.

Since inception, Pengrowth has acquired over $2 billion of oil and natural gas properties at prices per boe for proved plus probable reserves which on average were below industry prices over the same period. Using these high-quality assets as a basis from which to grow, our operations team is focused on developing these reserves to maximize economic recovery. Pengrowth operations are divided into five business units.

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PENGROWTH ENERGY TRUST

19
2005 ANNUAL REPORT

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2005 ANNUAL REPORT

Summary of Property Interests


	Pengrowth				Remaining		Reserve		Value⁽³⁾ of				2005 Oil				2005
	P+P		Percent		Reserve		Life		10%		Percent		& NGLs		2005 Gas		Total		Percent		2005
	Reserves⁽²⁾		of Total		Life		Index		Discount		of Total		Production		Production		Production⁽²⁾		of Total		Capex
	(mboe)		Reserves		(Years)		(Years)		($000’s)		Assets		(bbl per day)		(mmcf per day)		(boe per day)		Production		($MM)

Judy Creek BHL Unit		36,820		16.8		50		11.9		538.1		16.8		8,703		0.9		8,847		14.9		34.2
Swan Hills Unit No. 1		19,903		9.1		50		21.1		196.5		6.1		2,283		1.2		2,481		4.2		7.2
Weyburn Unit		19,253		8.8		50		18.6		186.1		5.8		2,638		0.1		2,649		4.5		8.8
SOEP		15,241		6.9		11		5.7		346.1		10.8		1,722		32.1		7,075		11.9		27.2
Judy Creek West BHL Unit		9,160		4.2		50		23.1		81.1		2.5		1,203		1.3		1,415		2.4		2.5
Monogram Gas Unit		6,265		2.9		36		8.7		120.6		3.8		0		15.1		2,517		4.2		1.9
McLeod River		5,480		2.5		50		7.3		92.5		2.9		439		11.3		2,321		3.9		2.2
East Bodo		5,252		2.4		50		28.3		31.5		1.0		516		0.2		542		0.9		3.4
Dunvegan Gas Unit		5,154		2.3		39		9.3		72.6		2.3		387		6.3		1,442		2.4		5.6
Twining		4,390		2.0		45		10.3		63.9		2.0		487		5.2		1,360		2.3		2.2
Kaybob Notikewin Unit		4,366		2.0		40		12.8		53.6		1.7		44		6.0		1,048		1.8		0.0
Tangleflags North		4,344		2.0		18		6.8		22.8		0.7		1,805		0.0		1,806		3.0		0.7
Oak		4,030		1.8		50		10.9		70.4		2.2		752		1.6		1,014		1.7		3.2
Quirk Creek		3,574		1.6		35		11.9		42.7		1.3		174		3.8		807		1.4		0.5
Princess		3,556		1.6		50		9.0		65.1		2.0		0		4.8		796		1.3		11.1
Enchant		3,270		1.5		50		15.3		37.1		1.2		637		0.3		684		1.2		0.1
Rigel		3,150		1.4		21		6.7		73.4		2.3		1,550		0.4		1,625		2.7		1.3
Other⁽¹⁾		66,188		30.2		50		8.9		1,110.4		34.6		9,175		70.5		20,928		35.3		63.6

Total		219,396		100.0		50		10.5		3,204.5		100.0		32,515		161.1		59,357		100.0		175.7

		Notes:

⁽¹⁾		“Other” includes Pengrowth’s working or royalty interests in approximately 100 other properties.

⁽²⁾		Natural gas has been converted to barrels of oil equivalent on the basis of six mcf of natural gas being equivalent to one boe.

⁽³⁾		At forecast prices and costs.

2005 Production (% of total)

2005 Reserves (% of total)

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2005 ANNUAL REPORT

Northeastern British Columbia — West of 6 Alberta (NEBC-W6M AB)

Production from Pengrowth’s NEBC—W6M AB area in 2005 averaged approximately 10,000 boe per day with 55 percent of production comprised of sweet natural gas and 45 percent of light crude oil and natural gas liquids (NGLs). Pengrowth’s average working interest is approximately 60 percent.

The NEBC–W6M AB area consists of: 1) primary and secondary recovery light oil production at the Rigel, Oak, and Squirrel fields near Fort St. John; 2) natural gas production north of Fort St. John, including the operated fields of Bulrush, Weasel, Prespatou and Beatton; and 3) primarily natural gas production in northwestern Alberta including the Dunvegan, Karr and Montney fields.

Central Alberta

The Central Alberta area averaged approximately 24,000 boe per day in 2005 with 75 percent of production comprised of light oil and NGLs and 25 percent comprised of natural gas. Pengrowth’s average working interest is approximately 44 percent. The area is made up of large oil-in-place fields including Judy Creek, Swan Hills, South Swan Hills, House Mountain and Deer Mountain. Hydrocarbon miscible flood projects are in place at the Judy Creek field and Swan Hills Unit Unit No. 1 (Swan Hills).

The Weyburn Unit in southeast Saskatchewan is also included in this business unit as there is a strong, functional focus on large oil-in-place reservoirs and enhanced oil recovery (EOR) opportunities, including CO₂ flood potential.

The Central Alberta operating area also includes a number of operated and partner-operated properties at Kaybob, McLeod, Niton, Edson and West Pembina which are primarily natural gas-producing pools.

Southern Alberta

In 2005, production from the Southern Alberta area averaged approximately 11,500 boe per day with 80 percent of production coming from natural gas and 20 percent coming from light oil and NGLs. Pengrowth’s average working interest is approximately 70 percent. This business unit consists of: 1) shallow gas fields in the Brooks area; 2) shallow gas, oil and CBM fields in the Three Hills area; and 3) deep, sour natural gas production from the Alberta Foothills region at the Quirk Creek field west of Turner Valley.

The Brooks area shallow gas production includes the operated Princess field as well as partner-operated fields at Monogram, Tilley, Patricia/Dinosaur and Cessford.

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PENGROWTH ENERGY TRUST

The Three Hills area produces oil and natural gas from the Belly River and Ellerslie formations as well as CBM from the shallow Horseshoe Canyon coals. The Quirk Creek field is a 500 bcf original-gas-in-place sour gas pool with an associated plant located approximately 25 kilometres southwest of Calgary.

Heavy Oil

Pengrowth became a participant in heavy oil production with the Murphy acquisition in 2004. The heavy oil areas of eastern Alberta and western Saskatchewan averaged approximately 7,000 boe per day in 2005 with 85 percent of production comprised of heavy oil and 15 percent comprised of natural gas. Pengrowth’s average working interest is approximately 62 percent.

The heavy oil business unit consists of primary and secondary recovery fields in the Bodo, Cactus and Plover areas operated by Pengrowth and the enhanced recovery steam assisted gravity drainage (SAGD) operation in the Tangleflags field operated by Canadian Natural Resources Limited.

Sable Offshore Energy Project (SOEP)

SOEP involves the development of several natural gas fields located approximately 225 kilometres off the east coast of Nova Scotia. Raw gas from SOEP is delivered to the onshore gas plant facility at Goldboro where the

2005 ANNUAL REPORT

liquids are extracted and sent to the fractionation plant in Point Tupper for processing. Sales gas is transported to market via the Maritimes and Northeast Pipeline. Propane and butane are shipped by both truck and rail while condensate is transported by ship. The project produced approximately 7,000 boe per day in 2005 representing 12 percent of Pengrowth’s total production with a corresponding operating cash flow contribution exceeding 20 percent. Production is comprised of approximately 75 percent natural gas and 25 percent NGLs. Pengrowth’s working interest is 8.4 percent.

Organic Growth Opportunities

Pengrowth is aggressively pursuing organic growth opportunities including infill and extension drilling, enhanced oil recovery in both light and heavy oil reservoirs, and shallow gas and CBM fields.

Pengrowth remains focused on maintaining an optimal portfolio. With a significant amount of undeveloped land our strategy includes maintaining approximately 400,000 acres. We will continue to purchase land for future development as well as identify properties that do not fit within the current asset base for potential disposition. This upgrading of Pengrowth’s portfolio is expected to continue throughout 2006.

2005

Pengrowth’s success in 2005 was exemplified by record levels of production and our largest capital expenditure program to date. Average daily production for the year totaled 59,357 boe per day, an increase of over ten percent when compared with the 2004 average of 53,702 boe per day.

The capital expenditure program totaled approximately $176 million and Pengrowth participated in the drilling of 286 gross wells, with a 99 percent success rate. Pengrowth operates approximately 47 percent of its overall production. This provides the trust with the opportunity to control a significant portion of development and maximize capital efficiencies through the strategic scheduling of projects, workovers and facility upgrades.

2006

Pengrowth will continue to be an active developer with capital expenditures expected to total $236 million.

Pengrowth’s 2006 drilling program, estimated at $131 million, will include approximately 280 gross (132 net) wells. The program consists of approximately 60 net wells planned for Pengrowth’s shallow gas-prone Southern Alberta business unit (11 of which are planned for CBM development), 44 net wells planned for the further development of the Heavy Oil business unit and 17 net wells planned in the Central Alberta business unit, largely in the Judy Creek area.

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PENGROWTH ENERGY TRUST

There are planned expenditures of approximately $12 million for major workovers and the recompletion and reactivation of over 40 gross (25 net) wells.

Pengrowth has also allocated approximately $64 million for facilities and maintenance as well as $21 million for land and seismic expenditures in anticipation of opportunities to add incrementally to our existing land position in core areas and to improve our knowledge of new and existing pools through the use of enhanced 3-D seismic technologies.

At this time, Pengrowth is forecasting average 2006 production of 54,000 to 56,000 boe per day from our existing properties, including 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.

Looking forward we have identified four core focus areas which are expected to drive our 2006 capital expenditures program. These include: 1) Enhanced Oil Recovery — Light Crude Oil and Heavy Oil; 2) Shallow Gas; 3) Coalbed Methane; and 4) Conventional Resource Development.

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2005 ANNUAL REPORT

Organic Growth
Enhanced Oil Recovery

Light Crude Oil

Production

(boe per day)

Light Crude Oil Average
Realized Prices
($ per bbl)

Light Crude Oil
Overview

The WCSB is a mature basin with conventional light oil production demonstrating long term declines. In order to maximize recovery and offset declines, industry focus has shifted to the exploration and development of smaller pools as well as revisiting large established pools through infill drilling on reduced spacing units and the use of various EOR technologies. These EOR techniques include secondary recovery methods such as waterflood and tertiary methods such as miscible floods which include the use of CO². Because these large established pools had vast original-oil-in-place, a large percentage of which is unrecovered to date, there remains significant volume available to be targeted by these tertiary techniques.

Strategy

Pengrowth has been a leader in applying EOR technologies. Our experience began subsequent to the operatorship of the Judy Creek field acquired in 1997 where we have achieved significant success with the miscible flood program. Pengrowth plans to continue employing and improving EOR techniques to develop its reservoirs. EOR programs are normally preceded by field simulations and pilot-scale test projects to reduce risks, determine technical feasibility and safeguard unitholders’ capital. Our strong EOR technical teams provide a competitive advantage in fully developing large-oil-in-place reservoirs.

Focus Areas
Judy Creek

Judy Creek is Pengrowth’s largest producing asset and is comprised of two oil reservoirs, the “A” and “B”

Judy Creek Oil Production
(boe per day)

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PENGROWTH ENERGY TRUST

pools, in which we have a full 100 percent working interest. Pengrowth maintains a hydrocarbon miscible flood program and has expanded the flood area to optimize and stabilize production.

The 2005 drilling program consisted of three oil wells and two injectors, including one horizontal injector. Of particular note is an infill well drilled in the northern central section of the “A” Pool in December 2005 that had initial stabilized production of 400 bbls per day of oil. Gross production for the year averaged approximately 10,000 boe per day.

During the year, the Judy Creek Plant Acid Gas Injection project was initiated with project scoping and design as well as the testing of a prospective disposal well. The intent of this project is to dispose of non-saleable gas (mainly CO²) that has been separated from the raw gas production at the Judy Creek Gas Conservation Plant. Pengrowth will begin acid gas disposal in 2006 when the appropriate regulatory approvals are received.

Judy Creek Hydrocarbon Miscible Flood

27
2005 ANNUAL REPORT

New development has continued with Pengrowth drilling one producer and two injectors during the first quarter of 2006. In total, we expect drilling activity to consist of six new vertical wells and one horizontal producer. Plans include the development of four new miscible patterns at Judy Creek. In addition, Pengrowth acquired 4,000 acres at Crown land sales on parcels directly offsetting the Judy Creek “A” and “B” pools, where five potential shallow gas drilling locations have been identified. Production at Judy Creek is estimated to average approximately 9,600 boe per day in 2006.

Pengrowth also expects to commence a CO² pilot project in an existing miscible flood pattern. The objective of the pilot program is to test the feasibility of injecting CO² into the Judy Creek reservoir. If the program is successful, there may be an additional recovery of one to three percent of the original-oil-in-place in the various patterns, as well as the recovery of previously injected hydrocarbon solvent. As the field’s
original-oil-in-place is estimated at 815 million bbls, the added recoverable reserves could be significant. This pilot program will begin at the conclusion of the injection phase of the CO² pilot program in the neighbouring Swan Hills property.

Swan Hills Unit No.1

Pengrowth acquired an additional 11.89 percent working interest on February 28, 2005, bringing our total working interest to 22.34 percent.

Development activity in 2005 included the successful drilling and completion of seven wells. These wells added gross production of 600 boe per day beginning in the third quarter. In addition, two miscible flood patterns were added in 2005. Gross production from Swan Hills averaged approximately 12,000 boe per day, including 10,000 bbls per day of oil.

Capital expenditures planned for 2006 include funding for drilling four new oil wells and one new injector as well as activating two new miscible flood patterns.

A CO² pilot project was implemented at Swan Hills in late 2004 to evaluate hydrocarbon recovery in a previously

Weyburn Unit Oil Production Forecast
(bbl per day)

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PENGROWTH ENERGY TRUST

flooded miscible pattern. This single-pattern pilot has produced a moderate oil response and production of CO₂ is now evident but additional time is necessary to determine the final results.

Weyburn

Pengrowth holds a 9.75 percent working interest in the Weyburn Unit. Development and optimization activities have been ongoing and production response to drilling and CO₂ injection programs has continued to show positive results.

The 2005 capital program was active with more than 40 wells drilled. This resulted in December production exceeding 30,000 boe per day gross, an increase of 4,700 boe per day over the December 2004 rate

The 2006 drilling program is expected to include a similar number of wells, four additional CO₂ patterns and an expansion of the water injection patterns. There are still significant opportunities to implement further CO₂ patterns and the outlook remains extremely favourable for incremental recovery.

CO₂ Injection

29
2005 ANNUAL REPORT

Heavy Oil
Production
(boe per day)

Heavy Oil Average
Realized Prices
($ per bbl)

(BAR CHART)

Heavy Oil
Overview

Conventional heavy oil is another area in which EOR technology is playing an increasingly important role. Increased productivity from horizontal wells coupled with a strong pricing environment have made heavy oil more economic to produce. Conventional heavy oil production in the WCSB is considered to be at or approaching peak levels, with overall basin-wide decline expected to set in over the near term.

Techniques to enhance productivity and maximize resource recovery mirror those applicable to light crude oil, including the development of smaller pools and the application of various EOR technologies. However, the exact methodologies differ. In heavy oil, EOR methods include waterfloods, application of thermal energy such as cyclic steam stimulation, steam assisted gravity drainage and new techniques such as polymer and solvent flooding. As with light crude oil, advanced EOR technology will provide the opportunity to improve recovery and generate yet to be tapped production.

Strategy

Pengrowth is planning to exploit existing heavy oil producing properties through the application of current and new technologies. In 2006, Pengrowth will focus on improving recovery in our existing assets through 3-D seismic, horizontal wells and waterflooding for pressure maintenance. In addition, leading edge EOR schemes will be evaluated.

Development activities in 2005 included drilling eight net wells, which added more than 0.5 mmboe of reserves. Pengrowth’s overall heavy oil production remained virtually flat which demonstrates success in offsetting normal annual production declines. Development activities planned for 2006 include a conventional horizontal well program at Bodo, which follows up a large

East Bodo Polymer Pilot Project Oil Recoveries
(boe per day)

30
PENGROWTH ENERGY TRUST

3-D seismic survey completed in 2005 that has allowed Pengrowth to better understand the entire Bodo field.

Focus Areas
East Bodo

Pengrowth initiated a polymer pilot project at East Bodo in late 2005 with project start-up anticipated for the second quarter of 2006. This innovative EOR method involves adding polymer to injected water to increase the effective sweep of the injected fluids. The pilot will test this technique in a vertical well injector pattern. The addition of polymer is expected to improve recovery in the pattern by up to 50 percent. If successful, this recovery technique could be further enhanced by utilizing horizontal injectors and producers, with the potential to add 16 million bbls of incremental recovery in our heavy oil area.

Lindbergh

In 2006 Pengrowth will initiate scoping work for a potential EOR pilot at the Lindbergh field. This field is currently shut-in and contains over one billion barrels of resource-in-place. Lindbergh contains bitumen that cannot be recovered using conventional heavy oil recovery techniques. Several geological and engineering challenges will need to be overcome to facilitate economic recovery of Lindbergh’s huge resource. It is anticipated that scoping work will continue through 2006 with the potential for a pilot project to begin in 2007.

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2005 ANNUAL REPORT

Shallow Gas

Natural Gas
Production
(mcf per day)

Natural Gas Average
Realized Prices
($ per mcf)

Overview

Canada is a major producer of natural gas, with almost 98 percent of Canadian production coming from the WCSB. Overall conventional natural gas production is expected to decline slightly even with a high number of wells drilled. The favourable price environment for natural gas has made it economically viable for additional drilling and for the development of formations and pools that were uneconomic in the past.

Strategy

A major core area for Pengrowth is Southern Alberta where approximately 80 percent of production is shallow natural gas. Shallow gas is important within Pengrowth’s producing portfolio because it provides generally long-life, low-risk and low-operating cost production. Pengrowth has several years of drilling inventory to keep facilities at capacity. Pengrowth continually seeks out acquisitions in shallow gas areas that have infill drilling and facility optimization potential.

Focus Areas

Pengrowth holds a variety of working interests in a number of properties that produce from multiple stacked sands in the Medicine Hat/Milk River and Second White Specks intervals. There is significant potential present in the Belly River and Edmonton sands as well as potential for CBM production.

Princess

In 2005 Pengrowth drilled 44 wells in the Princess area with 100 percent success. These wells began production in November 2005, generating initial incremental production of approximately 4 mmcf per day increasing Pengrowth’s production to 11 mmcf per day in December 2005.

The Princess production undergoes dehydration and compression at Pengrowth’s 100 percent owned facilities. Pengrowth expects to drill an

Shallow Gas Production Growth
(mmcf per day)

32
PENGROWTH ENERGY TRUST

additional 20 wells in 2006 to keep these facilities running at full capacity for the next few years.

Monogram

In 2006, the operator intends to carry out a 20-well stimulation program to increase production at Monogram. The intent is to keep the gas processing facilities fully-loaded at approximately 15 mmcf per day net to Pengrowth’s 53.8 percent working interest. A program to perforate and test new zones for bypassed gas is planned and the overall size of this program will depend on initial results.

Colin Muir, Reservoir/Production Engineer

Coalbed Methane

Overview

Non-conventional natural gas sources are becoming strategically important to help maintain and possibly grow overall Canadian natural gas production. One of the most promising non-conventional sources for natural gas in the WCSB is CBM.

In geological time the coalification process, whereby plant material is progressively converted to coal, generates large quantities of methane-rich gas. Development of what is estimated to be vast CBM potential in Canada remains at a relatively early stage, with commercial production coming onstream in 2002. Despite the high initial costs of CBM development, the increased gas pricing environment has made CBM more economical to produce. CBM drilling and production growth in the WCSB have exceeded the expectations of major authorities. Reserve bookings of CBM have reached meaningful levels and are expected to grow significantly.

Strategy

Pengrowth has approximately 50,000 net undeveloped acres of land in southern Alberta with a multitude of coals that are estimated to be capable of yielding production of 40 to 400 mcf per day per well. These lands lie within the Horseshoe Canyon productive trend. Several thousand wells have been drilled by other companies for this play type with favorable results. The Horseshoe Canyon coals are shallow at less than 1,000 metres depth and primarily produce water-free gas. Infrastructure must be efficiently designed to handle this low-pressure gas and keep capital and operating expenses down.

In autumn 2005 Pengrowth’s Board of Directors unanimously supported a strategy to develop our CBM resources internally. A CBM team was assembled with technical expertise in geologic mapping, drilling, completion, and overall project management skills. Pengrowth’s land negotiators enhanced the asset base by executing several acreage poolings with industry partners to facilitate a drilling program in 2006. Pengrowth’s existing lands provide opportunities for several years of development.

Focus Areas
Twining Horseshoe Canyon

Pengrowth has a non-convertible royalty from the Twining Horseshoe Canyon producing property. Production commenced in July 2005 with peak production reaching 7 mmcf per day from 50 producing wells. Results from this pool have provided Pengrowth with the additional confidence needed to initiate development on offsetting working interest lands.

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PENGROWTH ENERGY TRUST

An initial 18-well program (11 wells net) will commence drilling in the first quarter of 2006 and first sales are expected to occur by the third quarter of 2006. Up to 40 additional gross wells could be drilled in 2006 based upon drilling success and land agreements.

Mannville

In 2005, the emerging Mannville CBM play became increasingly important as the next potential source of non-conventional production. Commercial production was established in central Alberta at Corbett Creek, which lies approximately 40 kilometres east of Pengrowth’s Judy Creek field. One of the companies involved in Corbett Creek farmed in on Pengrowth’s Mannville CBM acreage in 2004, drilling six wells to date. A seventh well is slated for 2006 to satisfy the farmin agreement. Pengrowth retains an overriding royalty until project payout, at which time Pengrowth can become a working interest partner in the project.

Pengrowth is well-positioned for the Mannville CBM play through our land position of approximately 95,000 acres in the southern and central areas of Alberta. We will closely follow industry activity by CBM early entrants to further our understanding of the technical complexities of this enormous resource as it is developed.

35
2005 ANNUAL REPORT

Conventional Resource Development

Overview

Pengrowth has an enviable suite of geographically diversified assets ranging from liquids-rich natural gas offshore Nova Scotia to light sweet crude oil in the Fort St. John region of NEBC. In 2005 Pengrowth’s management made a commitment to its Board of Directors to place increasing emphasis on internal development.

Strategy

Acquisitions of undeveloped land in and near our core areas became an integral component of the trust’s organic growth strategy. These undeveloped lands, combined with our producing acreage, provide the fuel for future production growth.

The year 2005 was the most active year in the trust’s history for Crown and freehold land acquisitions. We purchased in excess of 20,000 acres in various areas where Pengrowth has existing operations. This synergy of producing operations, facilities, technical expertise and drilling opportunities raised the exploitation and development budget to record levels in 2006. Capital investment in drilling has yielded favorable financial results in this strong commodity price environment.

Pengrowth manages production related risks by maintaining a portfolio of opportunities diversified by geography, commodity and play type.

Focus Areas
SOEP

SOEP drilling activity in 2005 involved the addition of three new wells. The South Venture 2 well was drilled in 2004 and completed in 2005. Initial production of 50 mmcf per day (4.2 mmcf per day net) was attained in 2005. The South Venture 3 and Venture 7 wells were both drilled and completed in 2005.

The main construction activity at Sable is the compression project which involves the fabrication of an additional platform and topsides that will be installed beside the Thebaud platform and connected to Thebaud by a bridge. Installation of the platform and topsides will occur in mid 2006 with start-up scheduled for late 2006. Compression will allow the SOEP fields to be drawn down to much lower pressures allowing for a higher recovery of gas at higher production rates.

Quirk Creek

Pengrowth agreed to participate in a development well at Quirk Creek in Southern Alberta in which we have a 68 percent working interest. This well spudded in the first quarter of 2006.

Other Conventional Activity

Successful drilling results at West Pembina and Fort St. John in 2005 have fueled additional development drilling opportunities in 2006. Pengrowth will be actively acquiring additional acreage on these productive trends for additional growth.

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PENGROWTH ENERGY TRUST

Operations Statistical Review

Reserves Overview

Based on an independent engineering evaluation conducted by GLJ Petroleum Consultants Ltd. (GLJ) effective December 31, 2005 and prepared in accordance with National Instrument 51-101, Pengrowth had proved plus probable reserves of 219.4 mmboe. This represents 100 percent reserve replacement mainly through acquisitions of 16.7 mmboe and additions from development activity (drilling and improved recovery) of 8.2 mmboe. Positive changes were offset by 21.7 mmboe of production and dispositions of 2.8 mmboe.

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

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

Pengrowth is a geographically diversified energy trust with properties located across Canada in the provinces of British Columbia, Alberta, Saskatchewan and offshore Nova Scotia. On a proved plus probable reserve basis, the Alberta, Saskatchewan, British Columbia and offshore Nova Scotia holdings account for 69 percent, 14 percent, 10 percent and 7 percent, respectively, of reserves reported by GLJ.

Reserves Summary 2005

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


	Light and								Oil		Oil
	Medium		Heavy				Natural		Equivalent		Equivalent
	Crude Oil		Oil		NGLs		Gas		2005		2004
	(mbbls)		(mbbls)		(mbbls)		(bcf)		(mboe)		(mboe)

Proved Producing		58,219		10,924		13,566		366.2		143,741		142,353
Proved Developed Non-producing		365		62		637		24.3		5,113		4,825
Proved Undeveloped		18,768		1,699		1,139		30.8		26,745		28,324

Total Proved		77,351		12,684		15,342		421.3		175,599		175,502

Proved plus Probable		98,684		15,790		18,985		515.6		219,396		218,613


* as defined in the Canadian Oil and Gas Evaluation Handbook (COGEH), Volume 2, Section 5.2, November 1, 2005

Totals may not add due to rounding

37
2005 ANNUAL REPORT

Company Net Interest (Company Net Interest* which is the Company Interest Reserves less Royalties Payable)


	Light and								Oil		Oil
	Medium		Heavy				Natural		Equivalent		Equivalent
	Crude Oil		Oil		NGLs		Gas		2005		2004
	(mbbls)		(mbbls)		(mbbls)		(bcf)		(mboe)		(mboe)

Proved Producing		49,693		9,621		9,334		289.4		116,877		116,798
Proved Developed Non-producing		308		57		460		18.4		3,893		3,757
Proved Undeveloped		15,991		1,420		805		23.9		22,200		23,616

Total Proved		65,992		11,098		10,600		331.7		142,970		144,171

Proved plus Probable		83,929		13,714		13,218		404.3		178,246		179,298


* as defined in the Canadian Oil and Gas Evaluation Handbook (COGEH), Volume 2, Section 5.2, November 1, 2005

Totals may not add due to rounding

Reserves

Overall, the 2005 capital program including acquisitions replaced all of Pengrowth’s reserves depleted through production. The development activity, including revisions, replaced more than 50 percent of the proved reserves and approximately 40 percent of the proved plus probable reserves. In addition to adding new proved reserves, approximately 4.3 million boe of undeveloped reserves were reclassified as proved producing reserves as a result of development activity. If these promoted reserves were treated as new proved additions the proved finding, development and acquisition (FD&A) cost (excluding future development capital (FDC)) would be $13.47 per boe.

The intent of including the change in FDC is to recognize the impact of the capital used in promoting undeveloped reserves. The proved FD&A (including FDC) of $14.42 per boe compares closely to the $13.47 per boe.

The table below illustrates the overall results of the 2005 program in terms of reserve volumes as well as the capital efficiencies of the program:

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


	Total			Total Proved
	Proved			plus Probable
	(mmboe)			(mmboe)

Technical Revisions		4,072			344
Drilling Additions and Improved Recovery		7,289			8,240
Acquisitions		12,699			16,697
Dispositions		(2,296	)		(2,831	)
FD&A, $ per boe (including revisions, excluding change in future development capital)	$	16.12		$	15.62
FD&A, $ per boe (including revisions, including change in future development capital)	$	14.42		$	14.46


^* as defined in the Canadian Oil and Gas Evaluation Handbook (COGEH), Volume 2, Section 5.2, November 1, 2005

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PENGROWTH ENERGY TRUST

Reserves Reconciliation

Pengrowth added 25.3 mmboe of proved plus probable reserves during 2005, replacing production by 117 percent. The acquisition of Crispin and an additional interest in Swan Hills accounted for approximately 66 percent of the reserve additions. The balance of additions resulted mainly from drilling and improved recovery. Most significant were drilling extensions at West Pembina and infill drilling and increased CO₂ miscible flood recovery in the Weyburn Unit. The disposition of various non-core assets resulted in a decrease of 2.8 mmboe.

Reserves Reconciliation 2005

Company Interest Volumes(before deduction of Royalty Burdens Payable)


	Light and
	Medium			Heavy						Natural			Oil
	Crude Oil			Oil			NGLs			Gas			Equivalent
	(mbbls)			(mbbls)			(mbbls)			(bcf)			(mboe)

Total Proved
December 31, 2004		74,175			14,622			15,488			427.3			175,502
Exploration and development		—			81			715			19.8			4,096
Improved recovery		2,328			134			448			1.7			3,193
Revisions		709			(101	)		642			16.9			4,072
Acquisitions		9,106			—			376			19.3			12,699
Dispositions		(1,376	)		—			(103	)		(4.9	)		(2,296	)
Production		(7,591	)		(2,052	)		(2,224	)		(58.8	)		(21,667	)

December 31, 2005		77,351			12,684			15,342			421.3			175,599

Proved plus Probable
December 31, 2004		94,066			18,245			19,395			521.4			218,613
Exploration and development		—			92			823			23.9			4,898
Improved recovery		2,599			149			277			1.9			3,342
Revisions		(435	)		(644	)		343			6.5			344
Acquisitions		11,702			—			478			27.1			16,697
Dispositions		(1,657	)		—			(107	)		(6.4	)		(2,831	)
Production		(7,591	)		(2,052	)		(2,224	)		(58.8	)		(21,667	)

December 31, 2005		98,684			15,790			18,985			515.6			219,396


Totals may not add due to rounding

39
2005 ANNUAL REPORT

Net After Royalty Volumes


	Light and
	Medium			Heavy						Natural			Oil
	Crude Oil			Oil			NGLs			Gas			Equivalent
	(mbbls)			(mbbls)			(mbbls)			(bcf)			(mboe)

Total Proved
December 31, 2004		63,572			12,733			10,974			341.4			144,171
Exploration and development		—			71			494			15.6			3,163
Improved recovery		1,986			117			309			1.3			2,635
Revisions		(354	)		59			591			10.6			2,074
Acquisitions		7,769			—			260			15.2			10,561
Dispositions		(1,174	)		—			(71	)		(3.9	)		(1,888	)
Production		(5,807	)		(1,882	)		(1,957	)		(48.6	)		(17,746	)

December 31, 2005		65,992			11,098			10,600			331.7			142,970

Proved plus Probable
December 31, 2004		80,443			15,798			13,819			415.4			179,298
Exploration and development		—			80			573			18.7			3,776
Improved recovery		2,211			129			193			1.5			2,781
Revisions		(1,461	)		(412	)		332			1.0			(1,370	)
Acquisitions		9,952			—			333			21.3			13,827
Dispositions		(1,409	)		—			(75	)		(5.0	)		(2,320	)
Production		(5,807	)		(1,882	)		(1,957	)		(48.6	)		(17,746	)

December 31, 2005		83,929			13,714			13,218			404.3			178,246

Totals may not add due to rounding

Net Present Value Summary 2005

At GLJ January 1, 2006 escalated prices and costs*


			Discounted		Discounted		Discounted		Discounted
($ thousands)	Undiscounted		at 8%		at 10%		at 12%		at 15%

Proved Producing		3,676,741		2,563,707		2,401,037		2,262,789		2,089,851
Proved Developed Non-producing		148,744		94,965		87,578		81,363		73,662
Proved Undeveloped		559,904		269,672		229,572		196,476		156,685

Total Proved		4,385,388		2,928,344		2,718,187		2,540,628		2,320,198

Proved plus Probable		5,693,559		3,490,944		3,204,481		2,967,685		2,679,919


* Prior to provision for income taxes, interest, debt service charges and general and administrative expenses.

Totals may not add due to rounding

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PENGROWTH ENERGY TRUST

Constant Prices at December 31, 2005*


			Discounted			Discounted		Discounted		Discounted
($ thousands)	Undiscounted		at 8%		at 10%				at 12%	at 15%

Proved Producing		4,745,097		3,127,174			2,895,985		2,701,198		2,460,128
Proved Developed Non-producing		183,180		115,627			105,969		97,813		87,701
Proved Undeveloped		770,444		396,166			342,540		297,883		243,694

Total Proved		5,698,721		3,638,966			3,344,494		3,096,895		2,791,524

Proved plus Probable		7,286,322		4,342,199			3,953,173		3,631,474		3,241,128


* Prior to provision for income taxes, interest, debt service charges and general and administrative expenses.

Totals may not add due to rounding

GLJ’s January 1, 2006 price forecast is below:


	WTI Crude Oil		Edmonton Light		Natural Gas at
Year	(U.S. $ per bbl)		Crude Oil (Cdn $ per bbl)		AECO (Cdn $ per mmbtu)

2006		57.00		66.25		10.60
2007		55.00		64.00		9.25
2008		51.00		59.25		8.00
2009		48.00		55.75		7.50
2010		46.50		54.00		7.20
2011		45.00		52.25		6.90
2012		45.00		52.25		6.90
2013		46.00		53.25		7.05
2014		46.75		54.25		7.20
2015		47.75		55.50		7.40
2016		48.75		56.50		7.55
Escalate thereafter	2.0% per year		2.0% per year		2.0% per year

Constant Prices at December 31, 2005

WTI Crude Oil

Edmonton Light

Natural Gas at

Year

(U.S. $ per bbl)

Crude Oil (Cdn $ per bbl)

AECO (Cdn $ per mmbtu)

2006

61.04

68.27

9.71

41
2005 ANNUAL REPORT

Net Asset Value at December 31, 2005

In the following table, Pengrowth’s net asset value is measured with reference to the present value of future net cash flows from reserves, as estimated by GLJ. The calculation is shown using both the GLJ escalated price forecast and constant (year end 2005) prices.


	GLJ 2006-01			Constant
($ thousands, except per trust unit amount)	Price Forecast			Price Forecast

Value of Proved plus Probable Reserves discounted at 10 percent		3,204,481			3,953,173
Undeveloped lands ⁽¹⁾		145,344			145,344
Working capital ⁽²⁾		(32,222	)		(32,222	)
Remediation trust fund		8,329			8,329
Long term debt and Note Payable		(381,026	)		(381,026	)
Asset Retirement Obligation⁽³⁾		(110,243	)		(118,243	)

Net Asset Value	$	2,834,663		$	3,575,355
Trust units outstanding at year end (000’s)		159,864			159,864

Net Asset Value per trust unit	$	17.73		$	22.36


⁽¹⁾	Pengrowth’s internal estimate

⁽²⁾	Working capital excludes distributions payable

⁽³⁾	ARO is based on the same methodology used to calculate the ARO on Pengrowth’s year end financial statements, except that the future expected ARO costs were inflated at two percent and discounted at ten percent and well abandonment costs included in the GLJ report were deducted.

Reserve Life Index

Pengrowth’s proved RLI remained the same at 8.6 years and the proved plus probable RLI of 10.5 years can be compared to last year’s value of 10.4 years.


Reserve Life Index	2005		2004		2003

Total Proved		8.6		8.6		8.9
Proved plus Probable		10.5		10.4		10.6

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PENGROWTH ENERGY TRUST

Finding, Development and Acquisition Costs

Finding and Development Costs

During 2005, Pengrowth spent $175.7 million on development and optimization activities, which added 11.4 mmboe of proved and 8.6 mmboe of proved plus probable reserves including revisions. The largest additions were from infill drilling and enhanced recovery development in the Weyburn Unit CO₂ miscible flood project and drilling extensions for gas in West Pembina.

In total, Pengrowth participated in drilling 286 gross wells (94 net wells) during 2005 with a 99 percent success rate.

Pengrowth continues to develop shallow gas in southeast Alberta, drilling 44 infill wells at Princess and participating in 108 wells at Tilley. Pengrowth was also active in drilling for gas in northern Alberta, participating in 35 infill wells in the Dunvegan Gas Unit.

At Judy Creek, ongoing development of the hydrocarbon miscible flood project continues to be a focus for Pengrowth. Infill drilling and miscible flood pattern development and optimization contribute to arresting declines and improving recovery.

During 2005, significant capital expenditures were made at SOEP to further exploit gas reserves. Two successful wells, South Venture 3 and Venture 7, were drilled and brought onstream. The massive compression project at Thebaud is progressing with completion anticipated in late 2006 or early 2007.

In the southeast Saskatchewan Weyburn Unit, expansion and optimization of the partner operated CO₂ miscible flood enhanced oil recovery project is progressing as planned. Forty-seven infill wells, both new and re-entry, were drilled and facilities are being expanded to accommodate higher CO₂ injection rates.

Acquisitions and Divestitures

During 2005 Pengrowth was again active in making strategic acquisitions. Pengrowth spent $175.1 million adding 10.4 mmboe of proved and 13.9 mmboe of proved plus probable reserves, net of some minor dispositions of scattered non-core properties.

In February 2005, Pengrowth acquired 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. The acquisition added 11.0 mmboe of proved plus probable reserves.

In April of 2005, Pengrowth completed the acquisition of Crispin adding almost 1,900 boe per day of production and 5.2 mmboe of proved plus probable reserves. The acquisition 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.

In the latter half of 2005, Pengrowth concluded a disposition program selling non-core oil and natural gas properties with associated production of approximately 600 boe per day and 2.6 mmboe of proved plus probable reserves. Total disposition proceeds were $37.6 million.

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2005 ANNUAL REPORT

Future Development Capital

If a company chooses to disclose finding and development costs, National Instrument 51-101 requires that the calculation include changes in forecasted future development costs relating to the reserves. Future development costs reflect the amount of capital estimated by the independent evaluator that will be required to bring non-producing, undeveloped or probable reserves on stream. These forecasts of future development costs will change with time due to ongoing development activity, inflationary changes in capital costs and the acquisition or disposition of assets. Pengrowth provides the calculation of finding and development costs both with and without change in future development capital.

FD&A Costs — Company Interest reserves


				Proved plus
	Proved			Probable

FD&A Costs Excluding Future Development Capital
Exploration and Development Capital Expenditures ($000’s)	$	175,700		$	175,700
Exploration and Development Reserve Additions including Revisions (mboe)		11,361			8,591

Finding and Development Cost ($ per boe)	$	15.47		$	20.45

Net Acquisition Capital ($000’s)	$	175,100		$	175,100
Net Acquisition Reserve Additions (mboe)		10,403			13,866

Net Acquisition Cost ($ per boe)	$	16.83		$	12.63

Total Capital Expenditures including Net Acquisitions ($000’s)	$	350,800		$	350,800
Reserve Additions including Net Acquisitions (mboe)		21,764			22,457

Finding Development and Acquisition Cost ($ per boe)	$	16.12		$	15.62


FD&A Costs Including Future Development Capital
Exploration and Development Capital Expenditures ($000’s)	$	175,700		$	175,700
Exploration and Development Change in FDC ($000’s)	$	(54,931	)	$	(50,749	)
Exploration and Development Capital including Change in FDC ($000’s)	$	120,769		$	124,951
Exploration and Development Reserve Additions including Revisions (mboe)		11,361			8,591

Finding and Development Cost ($ per boe)	$	10.63		$	14.54

Net Acquisition Capital ($000’s)	$	175,100		$	175,100
Net Acquisition FDC ($000’s)	$	17,900		$	24,700
Net Acquisition Capital including FDC ($000’s)	$	193,000		$	199,800
Net Acquisition Reserve Additions (mboe)		10,403			13,866

Net Acquisition Cost ($ per boe)	$	18.55		$	14.41

Total Capital Expenditures including Net Acquisitions ($000’s)	$	350,800		$	350,800
Total Change in FDC ($000’s)	$	(37,031	)	$	(26,049	)
Total Capital including Change in FDC ($000’s)	$	313,769		$	324,751
Reserve Additions including Net Acquisitions (mboe)		21,764			22,457

Finding Development and Acquisition Cost including FDC ($ per boe)	$	14.42		$	14.46

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PENGROWTH ENERGY TRUST

Total Future Net Revenue (Undiscounted)

GLJ January 1, 2006 escalated pricing:


											Future Net
							Capital				Revenue
					Operating		Development		Abandonment		Before
($ thousands)	Revenue		Royalties		Costs		Costs		Costs*		Income Tax

Proved Producing		7,508,321		1,415,040		2,161,122		129,826		125,593		3,676,741
Proved Developed Non-producing		253,600		56,850		38,331		7,933		1,743		148,744
Proved Undeveloped		1,540,086		240,315		535,055		197,668		7,145		559,904

Total Proved		9,302,007		1,712,204		2,734,507		335,427		134,481		4,385,388

Total Probable		2,516,295		473,676		655,671		66,363		12,413		1,308,171

Proved plus Probable		11,818,302		2,185,881		3,390,179		401,790		146,894		5,693,559

Totals may not add due to rounding

Constant Prices at December 31, 2005:


											Future Net
							Capital				Revenue
					Operating		Development		Abandonment		Before
($ thousands)	Revenue		Royalties		Costs		Costs		Costs*		Income Tax

Proved Producing		8,409,412		1,606,510		1,842,164		121,923		93,718		4,745,097
Proved Developed Non-producing		293,753		67,811		33,775		7,642		1,345		183,180
Proved Undeveloped		1,749,618		314,087		471,885		188,804		4,398		770,444

Total Proved		10,452,783		1,988,409		2,347,823		318,370		99,460		5,698,721

Total Probable		2,628,744		534,619		443,673		60,868		1,983		1,587,601

Proved plus Probable		13,081,527		2,523,028		2,791,497		379,237		101,444		7,286,322


*		Downhole abandonment costs

Totals may not add due to rounding

45
2005 ANNUAL REPORT

Operational Excellence

Pengrowth is focused on building excellence within all its programs including health and safety, environment, and operations and projects and as such we are committed to continuous improvements within these areas.

Health and Safety

Pengrowth remains strongly committed to the ongoing health and safety of its employees and contractors as well as the communities in which we operate. We continue to meet all the necessary requirements and continuous improvement components for the successful maintenance of our Certificate of Recognition in Alberta and British Columbia. Pengrowth has operating facilities in Alberta, British Columbia and Saskatchewan which can be challenging. We focus a great deal of effort on maintaining programs that ensure compliance with the various occupational health and safety legislation and concentrate on best practices across our operations.

Contractor safety is a major concern due to the increased work activities and less experienced personnel available in all our operating areas. To help manage higher-risk work, Pengrowth holds training sessions ensuring our work supervisors are current with Pengrowth practices and occupational health and safety requirements.

Our incident and near miss/hazard identification reporting system is also of importance and is employed in all areas and work groups within Pengrowth. Tracking information allows for detailed analysis to prevent incident reoccurrence and opportunities to identify potentially threatening trends, thereby preventing future incidents.

Pengrowth strives to improve the skills of all employees in regulatory and skill enhancement training thus ensuring the protection and well-being of all worksite personnel as well as local residents.

Environment

Pengrowth is committed to corporate and industry excellence in environmental performance. We remain dedicated to responsible operatorship, minimization of environmental impacts and compliance with all provincial and federal legislation and regulations or other requirements within the jurisdictions in which we operate.

We are active participants in the Environment, Health, Safety and Social (EHS&S) Stewardship Program initiated by the Canadian Association of Petroleum Producers (CAPP) and in 2005 Pengrowth received CAPP’s platinum level recognition in support of its achievements. To attain this achievement Pengrowth successfully passed an independent, certified external audit of both our EHS&S management systems and results.

Pengrowth is continuing with proactive pipeline replacement at Judy Creek where exposure to and impact of spills are deemed to be unacceptably high. In 2005 Pengrowth spent over $3 million on this program and in 2006 we plan to spend an additional $6 million. During 2005 Pengrowth had three reportable pipeline spills in our

46
PENGROWTH ENERGY TRUST

BC operations and remediation efforts were promptly undertaken. For 2006, Pengrowth will expand our pipeline integrity review to additional operating areas and address any findings appropriately.

Pengrowth is committed to meeting the reporting requirements, including the National Pollutant Release Inventory, Federal Greenhouse Gas Reporting Program, Alberta Specified Gas Reporting program and the CAPP Benzene Emissions Report. As a result we continue to monitor and track emissions at our facilities.

During 2005 Alberta Environment and the Alberta Energy and Utilities Board (AEUB) conducted compliance and approval renewal audits and inspections at the Judy Creek Gas Plant. The audit resulted in a few minor items for Pengrowth to address which were completed prior to year end.

Pengrowth employees are essential to the execution of our environmental mandate. Key operations and consulting staff participated in waste management training. Facility inspections were conducted throughout the year to improve overall environmental awareness, reduce flared and vented volumes and reduce environmental incidents at operated facilities.

During 2005, Pengrowth maintained an active well abandonment and site restoration program under which the trust continued to assess and remediate sites impacted by historical operations. The primary focus for reclamation and remediation was on removing flare pits and drill sumps. During the year Pengrowth spent approximately $7 million on remediation and reclamation activities. For 2006 Pengrowth will continue an active well abandonment program to ensure our ability to meet upcoming changes in suspended/abandoned well regulations.

Operations and Projects

Pengrowth continues to focus on operational reliability and costs. In 2005 production achieved new records due in part to the efforts of our team members in ongoing improvements in reliability through facility optimization efforts, timely repairs along with preventative and predictive maintenance activities. For 2006 we will continue to work on improving facility reliability to enhance both production and operating cost results.

Operating expenses were above original 2005 targets due to increases in utility costs and the significant rise in the cost of labor, services and materials across the industry. Despite the current industry pricing pressures, reduction in operating expenses remains a strategic focus. Pengrowth participated in a third party benchmarking study to facilitate additional ideas and targets in this area. This study identified operating cost advantages that could be built upon and operating cost gaps which will require additional review to determine further improvements. This study was received near year end and will be used to formulate additional plans for operating cost savings in 2006.

Project execution is also important to operational excellence and our drilling, production and surface facilities project team members were very successful in delivering our 2005 capital program. The 2006 capital budget of $236 million is the largest to date and we will look to continue our focus on improved project planning and execution which should result in ongoing improvement in the timeliness and cost effectiveness of our projects.

47
2005 ANNUAL REPORT

Corporate Governance

Board of Directors

  From left to right
              Back row:
    Michael Parrett
          Terry Poole
      Kirby Hedrick

                  Seated:
           Stan Wong
     John Zaozirny
        Jim Kinnear
     Tom Cumming

Board Of Directors

Thomas A. Cumming, B.A.Sc., P.Eng.

Tom Cumming joined Pengrowth Corporation’s Board of Directors in April 2000. He held the position of President and Chief Executive Officer of the Alberta Stock Exchange from 1988 to 1999. His career also includes 25 years with a major Canadian bank both nationally and internationally. He is currently Chairman of Alberta’s Electricity Balancing Pool and serves as a Director of the Canadian Investor Protection Fund, the Alberta Capital Market Foundation and Western Lakota Energy Services Inc. He is also a past president of the Calgary Chamber of Commerce.

Kirby L. Hedrick, B.Sc, P.Eng.

Kirby Hedrick joined Pengrowth Corporation’s Board of Directors in April 2005. Mr. Hedrick received a Bachelor of Science and Mechanical Engineering degree from the University of Evansville, Indiana in 1975. He completed the Stanford Executive Program in 1997 and the Stanford Corporate Governance Program in 2003. Mr. Hedrick has extensive engineering and senior management experience in the United States and internationally, retiring in 2000 as Executive Vice President, Upstream of Phillips Petroleum. Mr. Hedrick also serves on the board of Noble Energy Inc.

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PENGROWTH ENERGY TRUST

James S. Kinnear, B.Sc., CFA, Chairman, President and Chief Executive Officer,

Mr. Kinnear graduated from the University of Toronto in 1969 with a Bachelor of Science degree and received a Chartered Financial Analyst designation in 1979. In 1982 he founded Pengrowth Management Limited and in 1988 created Pengrowth Energy Trust. Prior to 1982, he worked in the securities sector in Montreal, Toronto and London, England. Mr. Kinnear is currently a Director of the Calgary Chamber of Commerce and a Director of the National Arts Centre Foundation Board. Mr. Kinnear is Chairman of the Pengrowth Rockyview General Hospital Invitational Golf Tournament, a member of the Calgary Health Trust Development Council and a member of the Canadian Council of Chief Executives.

Michael S. Parrett, B.A. Econ., CA

Michael Parrett, appointed to the Board of Directors of Pengrowth Corporation in April 2004, is currently an independent consultant providing advisory service to various public companies in Canada and the United States. Mr. Parrett is a member of the board of Fording Inc. and is serving as a Trustee for Fording Canadian Coal Trust as well as Chairman of Gabriel Resources Limited. He was formerly President of Rio Algom Limited and prior to that Chief Financial Officer of Rio Algom and Falconbridge Limited. He has participated as an instructor, panel member and guest speaker at various mining conferences, as well as the Law Society of Upper Canada, the Insurance Institute of Ontario and the Canadian School of Management.

A. Terence Poole, B.Comm., CA

Terry Poole joined Pengrowth Corporation’s Board of Directors in April 2005. Mr. Poole received a Bachelor of Commerce degree from Dalhousie University and holds a Chartered Accountant designation. Mr. Poole brings extensive senior financial management, accounting, capital and debt market experience to Pengrowth. Mr. Poole currently holds the position of Executive Vice President, Corporate Strategy and Development of Nova Chemicals Corporation. Prior to assuming his present position in 2000, Mr. Poole held various senior management positions with Nova and other companies.

Stanley H. Wong, B.Sc., P.Eng.

Stan Wong is President of Carbine Resources Ltd., a private oil and gas producing and engineering consulting company. He is also a Director of Adamant Energy Inc. a private oil and gas exploration and producing company. Mr. Wong was a senior engineer with Hudson’s Bay Oil & Gas for ten years and was employed by Total Petroleum for 15 years where he was Chief Engineer and later became Manager of Special Projects.

John B. Zaozirny, Q.C., B.Comm., LL.B., LL.M., Lead Director

John Zaozirny is Counsel to McCarthy Tetrault and Vice Chairman of Canaccord Capital Corporation. He was Minister of Energy and Natural Resources for the Province of Alberta from 1982 to 1986. Mr. Zaozirny currently serves on the board of numerous Canadian and international corporations. He is also a Governor of the Business Council of British Columbia.

49
2005 ANNUAL REPORT

Corporate Governance

The Board of Directors, the Manager and senior management consider good corporate governance to be central to the effective and efficient operation of Pengrowth Energy Trust and the Corporation. The Board of Directors has general authority over the business and affairs of the Corporation and derives its authority in respect to Pengrowth Energy Trust by virtue of the delegation of powers by the Trustee to the Corporation as “Administrator” in accordance with the Trust Indenture. In accordance with the Royalty Indenture, Trust Indenture and Unanimous Shareholder Agreement, the Trust unitholders and Royalty unitholders also empowered the Trustee and the Corporation to delegate authority to the Manager. The Manager derives its authority from the Management Agreement with both the Corporation and Pengrowth Energy Trust. In practice, the Manager defers to the Board of Directors on all matters material to the Corporation and Pengrowth Energy Trust.

The Board of Directors of the Corporation currently has the following standing committees:

1. Audit Committee

2. Corporate Governance Committee

3. Compensation Committee

4. Reserves Committee

Each committee has a Terms of Reference or Charter which sets out the duties and responsibilities of the committee. These duties and responsibilities are reviewed annually and any changes are submitted to the Board of Directors for approval. At the organizational meeting following Pengrowth’s Annual General Meeting, committee members are appointed or re-appointed based on the particular skills of each director. Each committee makes regular reports to the entire Board of Directors. The Board of Directors is responsible for nominating any new directors on the recommendation of the corporate governance committee and invitations to join the board are made by the Lead Director.

Audit Committee

The audit committee is comprised of four members of the board: Tom Cumming (Chairman), Michael Parrett, Kirby Hedrick and Terry Poole. All members are considered independent and financially literate for the purpose of the Sarbanes-Oxley Act of 2002 (SOX) rules governing the composition of the audit committee. The committee includes at least one person that would be considered an audit committee financial expert within the meaning of the SOX rules. The primary purposes of this committee are to review with management and the external auditors the Corporation’s and Pengrowth Energy Trust’s annual audited and interim unaudited financial statements prior to filing or distribution and to monitor the integrity of the company’s financial reporting process and systems of internal controls regarding financial, accounting and legal compliance. The committee also monitors the independence and performance of the the Trust’s and the Corporation’s

50
PENGROWTH ENERGY TRUST

auditors and provides an avenue of communication among the external auditors, management and the board. The committee’s charter is reviewed annually and any changes are then submitted to the Board of Directors for approval. A Whistle Blower Policy is also in place which sets out the procedures for submitting complaints or concerns to the audit committee regarding financial statement disclosures, accounting, internal accounting controls or auditing matters. Members of the committee meet with the auditor independently from members of management. The committee also has a session at the end of each meeting where management and the auditors are excluded.

Corporate Governance Committee

The corporate governance committee is comprised of four members of the board: John Zaozirny (Chairman), Michael Parrett, Tom Cumming and Terry Poole. Each member of this committee is considered to be independent. The primary function of this committee is to assist the board in carrying out its responsibilities by reviewing corporate governance and nomination issues and making recommendations to the board as appropriate. The corporate governance committee acknowledges the formal guidelines relating to corporate governance in Canada as provided for by National Policy 58-101 Disclosure of Corporate Governance Practices and National Policy 58-201 Corporate Governance Guidelines and the overriding objective of promoting appropriate behaviour with respect to all aspects of Pengrowth’s business. The committee also provides oversight review of the Corporation’s systems for achieving compliance with legal and regulatory requirements. Duties of the committee include such items as bringing to the Board of Directors issues that are necessary for the proper governance of Pengrowth and developing the approach of the Corporation in matters of corporate governance. The committee also assesses and makes recommendations to the Board of Directors on the size of the board, identifying candidates for membership to the board based on a review of qualifications. The committee considers the mandates of committees of the board, selection and rotation of committee members and the chair and makes recommendations to the board. The committee oversees the evaluation of the performance of the board and reports on the results. The directors complete an annual board effectiveness survey on topics such as board responsibility, operations and effectiveness. The committee also monitors the appropriate sharing of duties between Pengrowth Management Limited, the Corporation and Pengrowth Energy Trust and establishes structures and procedures to permit the board to function independently of management and the Manager relying in part upon a Lead Director. In consultation with the Manager, the committee develops a succession plan for officers, other senior management and key employees of the Corporation. Director compensation is also a responsibility of this committee and any changes are recommended to the Board of Directors. The Committee’s Terms of Reference are reviewed annually and any changes are recommended to the Board of Directors for approval. The committee reviews

51
2005 ANNUAL REPORT

policies such as the Corporate Disclosure Policy, the policy in respect to Insider Trading and Self-Dealing, the Code of Business Ethics and the Privacy Policy on an annual basis and recommends to the board any necessary changes. A session where management is excluded is held at the end of each meeting.

Compensation Committee

The compensation committee is comprised of three members of the board: Michael Parrett (Chairman), Tom Cumming and John Zaozirny. Each member of this committee is considered to be independent. The committee’s responsibilities include compensation in the annual budget, annual bonus payments, incentive payments and programs. The compensation committee is also responsible for matters pertaining to the Manager. These include reviewing discussions with the Manager with respect to the strategy and objectives for the Corporation and Pengrowth Energy Trust and the performance of the Manager in accordance with the Management Agreement, KPMG Reports on the Manager’s compensation, consideration of Assumed Expenses under the Management Agreement and consideration of extension or termination of the Management Agreement. In consultation with the Manager, the committee recommends for approval by the Board of Directors specific compensation guidelines for senior employees, officers and consultants of the Corporation in the form of stock options, cash compensation and bonuses. The committee reviews disclosure of compensation matters in Pengrowth’s public disclosure materials. The committee’s Terms of Reference sets out its duties and responsibilities and is reviewed on an annual basis with any changes approved by the board. The committee holds a session where management is excluded as part of its meetings.

Reserves Committee

The reserves committee is comprised of two members of the board: Kirby Hedrick (Chairman) and Stan Wong. The committee’s responsibilities include reviewing the Corporation’s procedures relating to the disclosure of information with respect to oil and gas activities. The committee meets with management and the independent evaluator to review reserves data and the report of the independent evaluator. The committee then presents a report to the Board of Directors and makes a recommendation regarding approval of the reserves data. The Mandate and Terms of Reference of the committee are reviewed annually and changes are brought to the Board of Directors for approval. As part of its mandate, the committee will review any individual change in a property that is over one million boe of total proved reserves and all properties that individually constitute more than five percent of the total reserves.

52
PENGROWTH ENERGY TRUST

Board of Directors

The Board of Directors is comprised of seven members and five of those are considered independent. Two members are considered related to the Corporation and/or Pengrowth Energy Trust by virtue of their appointment by the Manager and other factors. The Corporation has appointed a Lead Director who is considered to be independent. A meeting of only the directors, chaired by the Lead Director, is held at the end of each board meeting. The Board of Directors of the Corporation has adopted a Corporate Governance Policy to formalize guidelines pursuant to which the board will fulfill its obligations to the Corporation. The board has adopted a strategic planning process and has approved a strategic plan that will be reviewed and updated on an annual basis. It will also review and approve the annual budget for the Corporation. On recommendations from the compensation committee, the Board of Directors is responsible for making recommendations to the unitholders on the appointment of the Manager or any amendments to the Management Agreement. The board reviews the Corporation’s policies on the recommendation of the corporate governance committee such as the Corporate Disclosure Policy as well as other relevant policies such as the policy on authority levels. The Corporation’s Code of Business Conduct and Ethics has also been recently updated and all directors, officers and employees are required to sign an acknowledgement confirming they have read and understand the contents.

The Manager

Under the Management Agreement, the Manager is empowered to act as agent for Pengrowth Energy Trust in respect to various matters, to execute documents on behalf of the Trust and to make executive decisions which conform to general policies and general principles previously established by the Trust. The Manager is empowered to undertake on behalf of the Corporation and Pengrowth Energy Trust, subject to the Royalty Indenture, all matters pertaining to the operations of the Corporation. These matters include a requirement to keep the Corporation fully informed with respect to the acquisition, development, operation and disposition of, and other dealings with, the properties held by the Corporation, a review of opportunities to acquire properties, the conduct of negotiations for the acquisition of properties and the operating, administration and retention of consultants, legal and accounting advisors in respect to the foregoing. The Manager is also given broad responsibility for unitholder services in relation to Pengrowth Energy Trust.

The Manager derives its authority from the Management Agreement with both the Corporation and Pengrowth Energy Trust. In practice, the Manager defers to the Board of Directors on all matters material to the Corporation and Pengrowth Energy Trust. The result is the Board and Pengrowth operate in a manner consistent with corporations and trusts that do not have a management agreement.

53
2005 ANNUAL REPORT

Management’s Discussion and Analysis

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).

54
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.

60
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

61
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.

74
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

77
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.

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PENGROWTH ENERGY TRUST

Management’s Report to Unitholders

Management’s Responsibility to the Unitholders

The financial statements are the responsibility of the management of Pengrowth Energy Trust. They have been prepared in accordance with generally accepted accounting principles, using management’s best estimates and judgements, where appropriate.

Management is responsible for the reliability and integrity of the financial statements, the notes to the financial statements, and other financial information contained in this report. In the preparation of these statements, estimates are sometimes necessary because a precise determination of certain assets and liabilities is dependent on future events. Management believes such estimates have been based on careful judgements and have been properly reflected in the accompanying financial statements.

Management is also responsible for ensuring that management fulfills its responsibilities for financial reporting and internal control. The Board is assisted in exercising its responsibilities through the Audit Committee of the Board, which is composed of four non-management directors. The Committee meets periodically with management and the auditors to satisfy itself that management’s responsibilities are properly discharged, to review the financial statements and to recommend approval of the financial statements to the Board.

KPMG LLP, the independent auditors appointed by the unitholders, have audited Pengrowth Energy Trust’s consolidated financial statements in accordance with generally accepted auditing standards and provided an independent professional opinion. The auditors have full and unrestricted access to the Audit Committee to discuss their audit and their related findings as to the integrity of the financial reporting process.


(signed)		(signed)

James S. Kinnear		Christopher G. Webster
Chairman, President and		Chief Financial Officer
Chief Executive Officer

February 27, 2006

81
2005 ANNUAL REPORT

Auditors’ Report

TO THE UNITHOLDERS OF PENGROWTH ENERGY TRUST

We have audited the consolidated balance sheets of Pengrowth Energy Trust as at December 31, 2005 and 2004 and the consolidated statements of income and deficit and cash flow for the years then ended. These financial statements are the responsibility of the Trust’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with Canadian generally accepted auditing standards. Those standards require that we plan and perform an audit to obtain reasonable assurance whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.

In our opinion, these consolidated financial statements present fairly, in all material respects, the financial position of the Trust as at December 31, 2005 and 2004 and the results of its operations and its cash flow for the years then ended in accordance with Canadian generally accepted accounting principles.

(signed)

Chartered Accountants
Calgary, Canada

February 27, 2006

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PENGROWTH ENERGY TRUST

Consolidated Balance Sheets


(Stated in thousands of dollars)
As at December 31	2005			2004

ASSETS
Current Assets
Accounts receivable	$	127,394		$	104,228
Inventory		—			439

		127,394			104,667
Remediation Trust Funds (Note 3)		8,329			8,309
Deferred Charges (Note 11)		4,886			3,651
Goodwill (Note 4)		182,835			170,619
Property, Plant And Equipment and Other Assets (Note 5)		2,067,988			1,989,288

	$	2,391,432		$	2,276,534


LIABILITIES AND UNITHOLDERS’ EQUITY
Current Liabilities
Bank indebtedness	$	14,567		$	4,214
Accounts payable and accrued liabilities		111,493			80,423
Distributions payable to unitholders		79,983			70,456
Due to Pengrowth Management Limited		8,277			7,325
Note payable (Note 7)		20,000			15,000
Current portion of contract liabilities (Note 4)		5,279			5,795

		239,599			183,213
Note Payable (Note 7)		—			20,000
Contract Liabilities (Note 4)		12,937			18,216
Long Term Debt (Note 8)		368,089			345,400
Asset Retirement Obligations (Note 6)		184,699			171,866
Future Income Taxes (Note 14)		110,112			75,628

Trust Unitholders’ Equity
Trust Unitholders’ capital (Note 10)		2,514,997			2,383,284
Contributed surplus (Note 10)		3,646			1,923
Deficit (Note 9)		(1,042,647	)		(922,996	)

		1,475,996			1,462,211

Commitments (Note 18)
Subsequent Event (Note 19)
	$	2,391,432		$	2,276,534

See accompanying notes to the consolidated financial statements.

Approved on Behalf of Pengrowth Energy Trust by Pengrowth Corporation, as Administrator


(signed)		(signed)

Director		Director

83
2005 ANNUAL REPORT

Consolidated Statements of Income and Deficit


(Stated in thousands of dollars)
Years ended December 31	2005			2004

REVENUES
Oil and gas sales	$	1,151,510		$	815,751
Processing and other income		15,091			12,390
Royalties, net of incentives		(213,863	)		(160,351	)

		952,738			667,790
Interest and other income		2,596			1,770

Net Revenue		955,334			669,560

EXPENSES
Operating		218,115			159,742
Transportation		7,891			8,274
Amortization of injectants for miscible floods		24,393			19,669
Interest		21,642			29,924
General and administrative		30,272			24,448
Management fee (Note 15)		15,961			12,874
Foreign exchange gain (Note 12)		(6,966	)		(17,300	)
Depletion and depreciation		284,989			247,332
Accretion (Note 6)		14,162			10,642

		610,459			495,605

Income Before Taxes		344,875			173,955
Income Tax Expense (Note 14)
Capital		6,273			4,594
Future		12,276			15,616

		18,549			20,210

NET INCOME	$	326,326		$	153,745
Deficit, beginning of year		(922,996	)		(713,680	)
Distributions paid or declared		(445,977	)		(363,061	)

Deficit, End of Year	$	(1,042,647	)	$	(922,996	)

Net Income Per Trust Unit (Note 16)
Basic	$	2.077		$	1.153
Diluted	$	2.066		$	1.147

See accompanying notes to the consolidated financial statements.

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PENGROWTH ENERGY TRUST

Consolidated Statements of Cash Flow


(Stated in thousands of dollars)
Years ended December 31	2005			2004

CASH PROVIDED BY (USED FOR):
Operating
Net income	$	326,326		$	153,745
Depletion, depreciation and accretion		299,151			257,974
Future income taxes		12,276			15,616
Contract liability amortization		(5,795	)		(4,164	)
Amortization of injectants		24,393			19,669
Purchase of injectants		(34,658	)		(20,415	)
Expenditures on remediation		(7,353	)		(4,440	)
Unrealized foreign exchange gain (Note 12)		(7,800	)		(18,900	)
Trust unit based compensation (Note 10)		2,932			2,264
Deferred charges (Note 11)		(4,961	)		—
Amortization of deferred charges (Note 11)		3,726			1,893
Gain on sale of marketable securities		—			(248	)
Changes in non-cash operating working capital (Note 13)		9,833			1,173

		618,070			404,167

Financing
Distributions		(436,450	)		(344,744	)
Change in long term debt, net		10,030			105,000
Note payable (Note 7)		(15,000	)		(10,000	)
Proceeds from issue of trust units		42,544			509,830

		(398,876	)		260,086

Investing
Expenditures on property acquisitions		(92,568	)		(572,980	)
Expenditures on property, plant and equipment		(175,693	)		(161,141	)
Proceeds on property dispositions		37,617			—
Change in remediation trust fund		(20	)		(917	)
Purchase of marketable securities		—			(2,680	)
Proceeds from sale of marketable securities		—			2,928
Change in non-cash investing working capital (Note 13)		1,117			2,169

		(229,547	)		(732,621	)

Change in Cash and Term Deposits		(10,353	)		(68,368	)
Cash and Term Deposits (Bank Indebtedness) at Beginning of Year		(4,214	)		64,154

Cash and Term Deposits (Bank Indebtedness) at End of Year	$	(14,567	)	$	(4,214	)

See accompanying notes to the consolidated financial statements.

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2005 ANNUAL REPORT

Notes to Consolidated

Financial Statements

YEARS ENDED DECEMBER 31, 2005 AND 2004

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

1. Structure of the Trust

Pengrowth Energy Trust (the “Trust”) is a closed-end investment trust created under the laws of the Province of Alberta pursuant to a Trust Indenture dated December 2, 1988 (as amended) between Pengrowth Corporation (Corporation) and Computershare Trust Company of Canada (Computershare). Operations commenced on December 30, 1988. The beneficiaries of the Trust are the holders of trust units (the “unitholders”).

The purpose of the Trust is to directly and indirectly explore for, develop and hold interests in petroleum and natural gas properties, through investments in securities, royalty units, and notes issued by the Corporation. The activities of Corporation and its subsidiaries are financed by issuance of royalty units and interest bearing notes to the Trust and third party debt. The Trust owns approximately 99.99 percent of the royalty units and 91 percent of the common shares of Corporation. The Trust, through the royalty ownership, obtains substantially all the economic benefits of Corporation. Under the terms of the Royalty Indenture, the Corporation is entitled to retain a one percent share of royalty income and all miscellaneous income (the “Residual Interest”) to the extent this amount exceeds the aggregate of debt service charges, general and administrative expenses, and management fees. In 2005 and 2004, this Residual Interest, as computed, did not result in any income retained by Corporation.

The royalty units and notes of Corporation held by the Trust entitle it to the net income generated by the Corporation and its subsidiaries’ petroleum and natural gas properties less amounts withheld in accordance with prudent business practices to provide for future Operating Expenses and Reclamation Obligations, as defined in the Royalty Indenture. In addition, unitholders are entitled to receive the net income from other investments that are held directly by the Trust. Pursuant to the Royalty Indenture, the Board of Directors of Corporation 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.

Pursuant to the Trust Indenture, Trust unitholders are entitled to monthly distributions from interest income on the notes, royalty income under the Royalty Indenture and from other investments held directly by the Trust, less any reserves and certain expenses of the Trust including General and Administrative costs as defined in the Trust Indenture.

The Board of Directors has general authority over the business and affairs of the Corporation and derives its authority in respect to the Trust by virtue of the delegation of powers by the trustee to the Corporation as Administrator in accordance with the Trust Indenture.

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PENGROWTH ENERGY TRUST

Pengrowth Management Limited (the “Manager”) has responsibility for the management of the business affairs of the Corporation and the administration of the Trust and defers to the Board of Directors on all matters material to the Corporation and the Trust. Corporate Governance practices are consistent with corporations and trusts that do not have a management agreement. The Manager owns nine percent of the common shares of Corporation, and the Manager is controlled by an officer and a director of the Corporation.

2. Significant Accounting Policies

Basis of Presentation

The Trust’s consolidated financial statements have been prepared in accordance with Generally Accepted Accounting Principles (GAAP) in Canada and they include the accounts of the Trust, the Corporation and its subsidiaries (collectively referred to as “Pengrowth”). All inter-entity transactions have been eliminated. These financial statements do not contain the accounts of the Manager.

The Trust owns 91 percent of the shares of Corporation and, through the royalty and notes, obtains substantially all the economic benefits of Corporation. In addition, the unitholders of the Trust have the right to elect the majority of the Board of Directors of Corporation.

Joint Interest Operations

A significant proportion of Pengrowth’s petroleum and natural gas development and production activities are conducted with others and accordingly the accounts reflect only Pengrowth’s proportionate interest in such activities.

Property, Plant and Equipment

Pengrowth follows the full cost method of accounting for oil and gas properties and facilities whereby all costs of developing and acquiring oil and gas properties are capitalized and depleted on the unit of production method based on proved reserves before royalties as estimated by independent engineers. The fair value of future estimated asset retirement obligations associated with properties and facilities are also capitalized and depleted on the unit of production method. The associated asset retirement obligations on future development capital costs are also included in the cost base subject to depletion. Natural gas production and reserves are converted to equivalent units of crude oil using their relative energy content.

General and administrative costs are not capitalized other than to the extent they are directly related to a successful acquisition, or to the extent of Pengrowth’s working interest in capital expenditure programs to which overhead fees can be recovered from partners. Overhead fees are not charged on 100 percent owned projects.

Proceeds from disposals of oil and gas properties and equipment are credited against capitalized costs unless the disposal would alter the rate of depletion and depreciation by more than 20 percent, in which case a gain or loss on disposal is recorded.

Pengrowth places a limit on the carrying value of property, plant and equipment and other assets, which may be depleted against revenues of future periods (the “ceiling test”). 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

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2005 ANNUAL REPORT

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. The carrying value of property, plant and equipment and other assets subject to the ceiling test includes asset retirement costs.

Repairs and maintenance costs are expensed as incurred.

Goodwill

Goodwill, which represents the excess of the total purchase price over the estimated fair value of the net identifiable assets and liabilities acquired, is not amortized but instead is assessed for impairment annually or as events occur that could result in impairment. Impairment is assessed by determining the fair value of the reporting entity and comparing this fair value to the book value of the reporting entity. If the fair value of the reporting entity is less than the book value, impairment is measured by allocating the fair value of the reporting entity to the identifiable assets and liabilities of the reporting entity as if the reporting entity had been acquired in a business combination for a purchase price equal to its fair value. The excess of the fair value of the reporting entity over the assigned values of the identifiable assets and liabilities is the fair value of the goodwill. Any excess of the book value of goodwill over this implied fair value is the impairment amount. Impairment is charged to earnings in the period in which it occurs.

Goodwill is stated at cost less impairment.

Injectant Costs

Injectants (mostly natural gas and ethane) are used in miscible flood programs to stimulate incremental oil recovery. The cost of hydrocarbon injectants purchased from third parties for miscible flood projects is deferred and amortized over the period of expected future economic benefit which is estimated as 24 to 30 months.

Inventory

Inventories of crude oil, natural gas and natural gas liquids are stated at the lower of average cost and net realizable value.

Asset Retirement Obligations

Pengrowth recognizes the fair value of an Asset Retirement Obligation (ARO) in the period in which it is incurred when a reasonable estimate of the fair value can be made. The fair value of the estimated ARO is recorded as a liability, with a corresponding increase in the carrying amount of the related asset. The capitalized amount is depleted on the unit of production method based on proved reserves. The liability amount is increased each reporting period due to the passage of time and the amount of accretion is expensed to income in the period. Actual costs incurred upon the settlement of the ARO are charged against the ARO.

Pengrowth has placed cash in segregated remediation trust accounts to fund certain ARO for the Judy Creek properties, and the Sable Offshore Energy Project (SOEP). Contributions to these remediation trust accounts and expenditures on ARO not funded by the trust accounts are charged against actual cash distributions in the period incurred.

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PENGROWTH ENERGY TRUST

Income Taxes

The Trust is a taxable trust under the Canadian Income Tax Act. As income taxes are the responsibility of the individual unitholders and the Trust distributes all of its taxable income to its unitholders, no provision has been made for income taxes by the Trust in these financial statements.

The Corporation and its subsidiaries follow the tax liability method of accounting for income taxes. Under this method, income tax liabilities and assets are recognized for the estimated tax consequences attributable to differences between the amounts reported in the financial statements of the Corporation and its subsidiaries and their respective tax bases, using enacted income tax rates. The effect of a change in income tax rates on future income tax liabilities and assets is recognized in income in the period that the change occurs.

Trust Unit Compensation Plans

Pengrowth has trust unit based compensation plans, which are described in Note 10. Compensation expense associated with trust unit based compensation plans is recognized in income over the vesting period of the plan with a corresponding increase in contributed surplus. The amount of compensation expense and contributed surplus is reduced for options, rights and deferred entitlement trust units (DEU’s) that are cancelled prior to vesting. Any consideration received upon the exercise of trust unit based compensation together with the amount of non-cash compensation expense recognized in contributed surplus is recorded as an increase in trust unitholders’ capital. Compensation expense is based on the estimated fair value of the trust unit based compensation at the date of grant, as further described in Note 10.

Pengrowth does not have any outstanding trust unit compensation plans that call for settlement in cash or other assets. Grants of such items, if any, will be recorded as expenses and liabilities based on the intrinsic value.

Risk Management

Financial instruments are utilized by Pengrowth to manage its exposure to commodity price fluctuations, foreign currency and interest rate exposures. Pengrowth’s practice is not to utilize financial instruments for trading or speculative purposes.

Pengrowth formally documents relationships between hedging instruments and hedged items, as well as its risk management objective and strategy for undertaking various hedge transactions. This process includes linking derivatives to specific assets and liabilities on the balance sheet or to specific firm commitments or forecasted transactions. Pengrowth also formally assesses, both at the hedge’s inception and on an ongoing basis, whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in fair value or cash flows of hedged items.

Pengrowth uses forward, futures and swap contracts to manage its exposure to commodity price fluctuations. The net receipts or payments arising from these contracts are recognized in income as a component of oil and gas sales during the same period as the corresponding hedged position.

Foreign exchange gains and losses on foreign currency exchange swaps used to hedge U.S. dollar denominated sales are recognized in income as a component of natural gas sales during the same period as the corresponding hedged position.

Foreign exchange swaps were used to fix the foreign exchange rate on the interest and principal of the £50 million ten year senior unsecured notes (see Note 17). Unrealized foreign exchange gains and losses on the debt and related hedge are recorded as the exchange rate changes.

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2005 ANNUAL REPORT

Measurement Uncertainty

The preparation of financial statements in conformity with Canadian GAAP requires management 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, amortization of injectants, goodwill and ARO 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. By their nature, these estimates are subject to measurement uncertainty and may impact the consolidated financial statements of future periods.

Earnings per unit

In calculating diluted net income per trust unit, Pengrowth follows the treasury stock method to determine the dilutive effect of trust unit based compensation plans and other dilutive instruments. Under the treasury stock method, only “in the money” dilutive instruments impact the diluted calculations.

Cash and term deposits

Pengrowth considers term deposits with an original maturity of three months or less to be cash equivalents.

Revenue recognition

Revenue from the sale of oil and natural gas is recognized when the product is delivered. Revenue from processing and other miscellaneous sources is recognized upon completion of the relevant service.

Comparative figures

Certain comparative figures have been reclassified to conform to the presentation adopted in the current year.

3. Remediation Trust Funds

Pengrowth is required to make contributions to a remediation trust fund that is used to cover certain ARO of the Judy Creek properties. Pengrowth makes monthly contributions to the fund of $0.10 per boe of production from the Judy Creek properties and an annual lump sum contribution of $250,000.

Every five years Pengrowth must evaluate the assets in the trust fund and the outstanding ARO, and make recommendations to the former owner of the Judy Creek properties as to whether contribution levels should be changed. In 2004 an evaluation was completed with the results of the evaluation determining that current funding levels would remain unchanged until the next evaluation in 2007. Contributions to the Judy Creek remediation trust fund may change based on future evaluations of the fund.

Pengrowth is required, pursuant to various agreements with the SOEP partners, to make contributions to a remediation trust fund that will be used to fund the ARO of the SOEP properties and facilities. Pengrowth makes monthly contributions to the fund of $0.04 per mcf of natural gas production and $0.08 per boe of natural gas liquids production from SOEP.

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PENGROWTH ENERGY TRUST

The following summarizes Pengrowth’s trust fund contributions for 2005 and 2004 and Pengrowth’s expenditures on ARO not covered by the trust funds:


	2005			2004

Contributions to Judy Creek Remediation Trust Fund	$	778		$	906
Contributions to SOEP Environmental Restoration Fund		556			548
Expenditures related to Judy Creek Remediation Trust Fund		(1,314	)		(537	)

		20			917

Expenditures on ARO not covered by the trust funds		6,039			3,903
Expenditures on ARO covered by the trust funds		1,314			537

		7,353			4,440

Total trust fund contributions and ARO expenditures not covered by the trust funds	$	7,373		$	5,357

4. Acquisitions

Corporate Acquisitions

On April 29, 2005, Pengrowth acquired all of the issued and outstanding shares of Crispin Energy Inc. (Crispin) which held interests in oil and natural gas assets mainly in Alberta. The shares were acquired on the basis of exchanging 0.0725 Class B trust units of the Trust for each share held by Canadian resident shareholders of Crispin and 0.0512 Class A trust units of the Trust for each share held by non-Canadian resident shareholders of Crispin. The average value assigned to each trust unit issued was $20.80 based on the weighted average trading price of the Class A and Class B trust units for a period before and after the acquisition was announced. The Trust issued 3,538,581 Class B trust units and 686,732 Class A trust units valued at $88 million. The transaction was accounted for using the purchase method of accounting with the allocation of the purchase price and consideration as follows:


Allocation of purchase price:
Working capital	$	1,655
Property, plant, and equipment		121,729
Goodwill		12,216
Bank debt		(20,459	)
Asset retirement obligations		(4,038	)
Future income taxes		(22,208	)

	$	88,895

Cost of acquisition:
Trust units issued	$	87,960
Acquisition costs		935

	$	88,895

Property, plant and equipment of $122 million represents the estimated fair value of the assets acquired determined in part by an independent reserve evaluation. Goodwill of $12 million, which is not deductible for tax purposes, was determined based on the excess of the total cost of the acquisition less the value assigned to the identifiable assets and liabilities, including the future income tax liability.

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2005 ANNUAL REPORT

The future income tax liability was determined based on an enacted income tax rate of approximately 34 percent as at April 29, 2005. Results from operations of the acquired assets of Crispin subsequent to April 29, 2005 are included in the consolidated financial statements.

On May 31, 2004, Pengrowth acquired all of the issued and outstanding shares of a company which had interests in oil and natural gas assets in Alberta and Saskatchewan (the “Murphy acquisition”). The transaction was accounted for using the purchase method of accounting with the allocation of the purchase price and consideration paid as follows:


Allocation of purchase price:
Working capital	$	9,310
Property, plant, and equipment		502,924
Goodwill		170,619
Asset retirement obligations		(43,876	)
Future income taxes		(60,012	)
Contract liabilities		(28,175	)

	$	550,790

Cost of acquisition:
Cash and term deposits	$	224,700
Acquisition facility		325,000
Acquisition costs		1,090

	$	550,790

Property, plant and equipment of $503 million represents the fair value of the assets acquired determined in part by an independent reserve evaluation, net of purchase price adjustments. Goodwill of $171 million, which is not deductible for tax purposes, was determined based on the excess of the total consideration paid less the value assigned to the identifiable assets and liabilities including the future income tax liability.

The future income tax liability was determined based on the enacted income tax rate of approximately 34 percent as at May 31, 2004.

Contract liabilities include a natural gas fixed price sales contract (see Note 17) and firm pipeline demand charge contracts. The fair value of these liabilities was determined on the date of acquisition and is being reduced as the contracts are settled. As at December 31, 2005 a net liability of $12.3 million (2004 — $17.9 million) has been recorded for the natural gas fixed price sales contract and $5.9 million (2004 — $6.1 million) has been recorded for the firm pipeline demand charge contracts.

Results of operations from the Murphy Acquisition subsequent to May 31, 2004 are included in the consolidated financial statements.

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PENGROWTH ENERGY TRUST

The following unaudited pro forma information provides an indication of what Pengrowth’s results of operations might have been had the Murphy Acquisition taken place on January 1 of 2004:


	2004 Proforma		2004 Actual
	(unaudited)		(audited)

Oil and gas sales	$	897,397	$	815,751
Net income	$	180,101	$	153,745
Net income per unit:
Basic	$	1.206	$	1.153
Diluted	$	1.201	$	1.147

Property Acquisitions

In February 2005, Pengrowth acquired an additional 11.89 percent working interest in Swan Hills for a purchase price of $87 million before adjustments. The acquisition increased Pengrowth’s working interest in Swan Hills to 22.34 percent.

In August 2004, Pengrowth acquired an additional 34.35 percent working interest in Kaybob Notikewin Unit No.1 for a purchase price of $20 million before adjustments. The acquisition increased Pengrowth’s working interest in the Kaybob Notikewin Unit No.1 to approximately 99 percent.

5. Property, Plant and Equipment and Other Assets


	2005			2004

Property, Plant and Equipment
Property, Plant and Equipment, at cost	$	3,340,106		$	2,986,681
Accumulated depletion and depreciation		(1,307,424	)		(1,022,435	)

Net book value of property, plant and equipment		2,032,682			1,964,246
Other Assets
Deferred injectant costs		35,306			25,042

Net book value of property, plant and equipment and other assets	$	2,067,988		$	1,989,288

Property, plant and equipment includes $77.3 million (2004 – $81.1 million) related to ARO, net of accumulated depletion.

Pengrowth performed a ceiling test calculation at December 31, 2005 to assess the recoverable value of the property, plant and equipment and other assets. The oil and gas future prices are based on the January 1, 2006 commodity price forecast of our independent reserve evaluators. These prices have been adjusted for commodity price differentials specific to Pengrowth. The following table summarizes the benchmark prices used in the ceiling test calculation. Based on these assumptions, the undiscounted value of future net revenues from Pengrowth’s proved reserves exceeded the carrying value of property, plant and equipment and other assets at December 31, 2005.

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2005 ANNUAL REPORT


			Foreign		Edmonton Light
	WTI Oil		Exchange Rate		Crude Oil		AECO Gas
Year	(U.S.$/bbl)		(U.S.$/Cdn)		(Cdn$/bbl)		(Cdn$/mmbtu)

2006		57.00		0.85		66.25		10.60
2007		55.00		0.85		64.00		9.25
2008		51.00		0.85		59.25		8.00
2009		48.00		0.85		55.75		7.50
2010		46.50		0.85		54.00		7.20
2011		45.00		0.85		52.25		6.90
2012		45.00		0.85		52.25		6.90
2013		46.00		0.85		53.25		7.05
2014		46.75		0.85		54.25		7.20
2015		47.75		0.85		55.50		7.40
2016		48.75		0.85		56.50		7.55
Escalate thereafter	2.0% per year				2.0% per year		2.0% per year

6. Asset Retirement Obligations

The total future ARO were estimated by management based on Pengrowth’s working interest in wells and facilities, estimated costs to remediate, reclaim and abandon the wells and facilities and the estimated timing of the costs to be incurred in future periods. Pengrowth has estimated the net present value of its 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). These costs are expected to be made 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.

The following reconciles Pengrowth’s ARO:


	2005			2004

Asset retirement obligations, beginning of year	$	171,866		$	102,528
Increase (decrease) in liabilities during the year related to:
Acquisitions		6,347			44,368
Disposals		(3,844	)		—
Additions		1,972			2,681
Revisions		1,549			16,087
Accretion expense		14,162			10,642
Liabilities settled during the year		(7,353	)		(4,440	)

Asset retirement obligations, end of year	$	184,699		$	171,866

7. Note Payable

The note payable is due to Emera Offshore Incorporated, in respect of the acquisition of the SOEP facility in 2003. The note payable is secured by Pengrowth’s working interest in SOEP. The note payable is non-interest bearing with the final payment of $20 million due on December 31, 2006.

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PENGROWTH ENERGY TRUST

At December 31, 2005, $0.7 million (2004 — $2.0 million) has been recorded as a deferred charge representing the imputed interest on the non-interest bearing note. This amount will be recognized as interest expense over the term of the note.

8. Long Term Debt


	2005		2004

U.S. dollar denominated debt:
U.S. $150 million senior unsecured notes at 4.93 percent due April 2010	$	174,450	$	180,300
U.S. $50 million senior unsecured notes at 5.47 percent due April 2013		58,150		60,100

		232,600		240,400
Pound sterling denominated £50 million unsecured notes at 5.46 percent due December 2015		100,489		—
Canadian dollar revolving credit borrowings		35,000		105,000

	$	368,089	$	345,400

On April 23, 2003, Pengrowth closed a U.S. $200 million private placement of senior unsecured notes. The notes were offered in two tranches of U.S. $150 million at 4.93 percent due April 2010 and U.S. $50 million at 5.47 percent due in April 2013. The notes contain certain financial maintenance covenants and interest is paid semi-annually. Costs incurred in connection with issuing the notes, in the amount of $2.1 million are being amortized over the term of the notes (see Note 11).

On December 1, 2005 Pengrowth closed a £50 million private placement of senior unsecured notes. In a series of related hedging transactions, Pengrowth fixed the pound sterling to Canadian dollar exchange rate for all the semi-annual interest payments and the principal repayments at maturity. The notes have an effective rate of 5.49 percent after the hedging transactions. The notes contain the same financial maintenance covenants as the U.S. dollar denominated notes. Costs incurred in connection with issuing the notes, in the amount of $0.7 million are being amortized over the term on the notes (see Note 11).

The Corporation has a $370 million revolving unsecured credit facility syndicated among eight financial institutions with an extendible 364 day revolving period and a three year amortization term period. The facilities are currently reduced by outstanding letters of credit in the amount of approximately $17 million. In addition, it has a $35 million demand operating line of credit. Interest payable on amounts drawn is at the prevailing bankers’ acceptance rates plus stamping fees, lenders’ prime lending rates, or U.S. LIBOR rates plus applicable margins, depending on the form of borrowing by the Corporation. The margins and stamping fees vary from zero percent to 1.4 percent depending on financial statement ratios and the form of borrowing.

The revolving credit facility will revolve until June 16, 2006, whereupon it may be renewed for a further 364 days, subject to satisfactory review by the lenders, or converted into a term facility. If converted to a term facility, one third of the amount outstanding would be repaid in equal quarterly instalments in each of the first two years with the final one third to be repaid upon maturity of the term period. The Corporation can post, at its option, security suitable to the banks in lieu of the first year’s payments. In such an instance, no principal payment would be made to the banks for one year following the date of non-renewal.

The five year schedule of long term debt repayment based on maturity is as follows: 2006 — nil, 2007 — nil, 2008 — nil, 2009 — nil, 2010 — $174.5 million.

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2005 ANNUAL REPORT

9. Deficit


	2005			2004

Accumulated earnings	$	1,053,383		$	727,057
Accumulated distributions paid or declared		(2,096,030	)		(1,650,053	)

	$	(1,042,647	)	$	(922,996	)

Pengrowth is obligated by virtue of its Royalty and Trust Indentures to distribute to unitholders a significant portion of its cash flow from operations. Cash flow from operations typically exceeds net income as a result of non cash expenses such as depletion, depreciation and accretion. These non cash expenses result in a deficit being recorded despite Pengrowth distributing less than its cash flow from operations.

10. Trust Units

The total authorized capital of Pengrowth is 500,000,000 trust units.

Total Trust Units:


	Year Ended				Year Ended
	December 31, 2005				December 31, 2004

	Number of				Number of
Trust Units Issued	Trust Units		Amount		Trust Units		Amount

Balance, beginning of period		152,972,555	$	2,383,284		123,873,651	$	1,872,924
Issued for cash		—		—		26,885,000		499,480
Less: issue expenses		—		—		—		(26,287	)
Issued for the Crispin acquisition (non-cash) (Note 4)		4,225,313		87,960		—		—
Issued for cash on exercise of trust unit options and rights		1,512,211		21,818		1,294,838		20,251
Issued for cash under Distribution Reinvestment Plan (DRIP)		1,154,004		20,726		918,366		16,386
Trust unit rights incentive plan (non-cash exercised)		—		1,209		—		530
Royalty units exchanged for trust units		—		—		700		—

Balance, end of period		159,864,083	$	2,514,997		152,972,555	$	2,383,284

Class A Trust Units:

Year Ended

For the period from July 27, 2004

December 31, 2005

to December 31, 2004

Number of

Number of

Trust Units Issued

Trust Units

Amount

Trust Units

Amount

Balance, beginning of period

76,792,759

1,176,427

—

Issued for the Crispin acquisition (non-cash) (Note 4)

686,732

19,002

—

Trust units converted

45,182

692

76,792,759

1,176,427

Balance, end of period

77,524,673

1,196,121

76,792,759

1,176,427

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PENGROWTH ENERGY TRUST

Class B Trust Units:


	Year Ended						For the period from July 27, 2004
	December 31, 2005						to December 31, 2004

	Number of						Number of
Trust Units Issued	Trust Units			Amount			Trust Units		Amount

Balance, beginning of period		76,106,471		$	1,205,734			—	$	—
Trust units converted		(9,824	)		(151	)		59,000,129		903,854
Issued for cash		—			—			15,985,000		298,920
Less: issue expenses		—			—			—		(15,577	)
Issued for the Crispin acquisition (non-cash) (Note 4)		3,538,581			68,958			—		—
Issued for cash on exercise of trust unit options and rights		1,512,211			21,818			746,864		11,516
Issued for cash under Distribution Reinvestment Plan (DRIP)		1,154,004			20,726			374,478		6,750
Trust unit rights incentive plan (non-cash exercised)		—			1,209			—		271

Balance, end of period		82,301,443		$	1,318,294			76,106,471	$	1,205,734

Unclassified Trust Units:


	Year Ended						Year Ended
	December 31, 2005						December 31, 2004

	Number of						Number of
Trust Units Issued	Trust Units			Amount			Trust Units			Amount

Balance, beginning of year		73,325		$	1,123			123,873,651		$	1,872,924
Issued for cash		—			—			10,900,000			200,560
Less: issue expenses		—			—			—			(10,710	)
Issued for cash on exercise of trust unit options and rights		—			—			547,974			8,735
Issued for cash under Distribution Reinvestment Plan (DRIP)		—			—			543,888			9,636
Trust unit rights incentive plan (non-cash exercised)		—			—			—			259
Royalty units exchanged for trust units		—			—			700			—

Balance, prior to conversion		—			—			135,866,213			2,081,404
Converted to Class A or Class B trust units		(35,358	)		(541	)		(135,792,888	)		(2,080,281	)

Balance, end of year		37,967		$	582			73,325		$	1,123

On July 27, 2004 Pengrowth implemented a reclassification of its trust units whereby the existing outstanding trust units were reclassified into Class A or Class B trust units depending on the residency of the unitholder. Of the original trust units, 37,967 are undeclared trust units that have not been classified as Class A or Class B trust units as the unitholders of these trust units have not submitted a declaration of residency certificate.

The Class A trust units and the Class B trust units have the same rights to vote and obtain distributions upon wind-up or dissolution of the Trust. The most significant distinction between the two classes of units is in respect of residency of the persons entitled to hold and trade the Class A trust units and Class B trust units.

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2005 ANNUAL REPORT

Class A trust units are not subject to any residency restriction but are subject to a restriction on the number to be issued such that the total number of issued and outstanding Class A trust units will not exceed 99 percent of the number issued and outstanding Class B trust units after an initial implementation period (the “Ownership Threshold”). Class A trust units may be converted by a holder at any time into Class B trust units provided that the holder is a resident of Canada and provides a suitable residency declaration. Class A trust units trade on both the Toronto Stock Exchange (TSX) and the New York Stock Exchange (NYSE).

Class B trust units may not be held by non-residents of Canada and trade only on the TSX. Class B trust units may be converted by a holder into Class A trust units, provided that the Ownership Threshold will not be exceeded.

If the number of issued and outstanding Class A trust units exceeds the Ownership Threshold, the Trust may make a public announcement of the contravention and enforce one or several available options to reduce the number of Class A trust units to the Ownership Threshold, as outlined in the Trust Indenture.

If it appears from the securities registers, or if the Board of Directors of Corporation determines, that a person that is a non-resident of Canada holds or beneficially owns any Class B trust units, Pengrowth shall send a notice to the registered holder(s) of the Class B trust units requiring such holder(s) to dispose of the Class B trust units and pending such disposition may suspend all rights of ownership attached to such units, including the rights to receive distributions.

Following the reclassification, the number of outstanding Class A trust units exceeded the Ownership Threshold. On December 1, 2004, Pengrowth received a letter from the Canada Revenue Agency that extended the date by which Pengrowth must comply with the Ownership Threshold to June 1, 2005. Pengrowth complied with the Ownership Threshold on April 29, 2005 and continued to comply with the Ownership Threshold as of February 27, 2006.

Certain provisions exist that could prevent exclusionary offers being made for only one class of trust units in existence at the time of the original offer. In the event that an offer is made for only one class of trust units; in certain circumstances the Ownership Threshold would temporarily cease to apply.

Pursuant to the terms of the Royalty Indenture and the Trust Indenture, there is attached to each royalty unit granted by the Corporation to royalty unitholders other than the Trust the right to exchange such royalty unit for an equivalent number of trust units. Accordingly, Computershare as Trustee has reserved 18,240 trust units for such future conversion.

Distribution Reinvestment Plan

Class B unitholders are eligible to participate in the Distribution Reinvestment Plan (DRIP). DRIP entitles the unitholder to reinvest cash distributions in additional units of the Trust. The trust units under the plan are issued from treasury at a five percent discount to the weighted average closing price of all Class B trust units traded on the TSX for the 20 trading days preceding a distribution payment date. Class A unitholders are not eligible to participate in DRIP. Trust units issued on the exercise of options and rights under Pengrowth’s unit based compensation plans are Class B trust units.

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PENGROWTH ENERGY TRUST

Contributed Surplus


	2005			2004

Balance, beginning of year	$	1,923		$	189
Trust unit rights incentive plan (non-cash expensed)		1,740			2,264
Deferred entitlement trust units		1,192			—
Trust unit rights incentive plan (non-cash exercised)		(1,209	)		(530	)

Balance, end of year	$	3,646		$	1,923

Trust Unit Option Plan

Pengrowth has a trust unit option plan under which directors, officers, employees and special consultants of the Corporation and the Manager are eligible to receive options to purchase Class B trust units. No new grants have been issued under the plan since November 2002. Under the terms of the plan, up to ten percent of the issued and outstanding trust units, to a maximum of ten million trust units, may be reserved for option and right grants. The options expire seven years from the date of grant. One third of the options vest on the grant date, one third on the first anniversary of the date of grant, and the remaining third on the second anniversary.

As at December 31, 2005, options to purchase 259,317 Class B trust units were outstanding (2004 – 845,374) that expire at various dates to June 28, 2009.

Trust Unit Options


	2005					2004
				Weighted					Weighted
	Number			Average		Number of			Average
	of Options			Exercise Price		Options			Exercise Price

Outstanding at beginning of year		845,374		$	16.97		2,014,903		$	17.47
Exercised		(558,307	)	$	16.74		(838,789	)	$	16.82
Expired		(27,750	)	$	18.63		(325,200	)	$	20.44
Cancelled		—			—		(5,540	)	$	16.53

Outstanding at year end		259,317		$	17.28		845,374		$	16.97
Exercisable at year end		259,317		$	17.28		845,374		$	16.97

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2005 ANNUAL REPORT

The following table summarizes information about trust unit options outstanding and exercisable at December 31, 2005:

Options Outstanding and Exercisable


			Weighted Average
	Number Outstanding		Remaining Contractual		Weighted Average
Range of Exercise Prices	and Exercisable		Life (years)		Exercise Price

$12.00 to $14.99		30,193		2.9	$	13.08
$15.00 to $16.99		38,139		2.7	$	15.05
$17.00 to $17.99		82,772		2.4	$	17.47
$18.00 to $20.50		108,213		1.9	$	19.09

$12.00 to $20.50		259,317		2.3	$	17.28

Trust Unit Rights Incentive Plan

Pengrowth has a Trust Unit Rights Incentive Plan (Rights Incentive Plan), pursuant to which rights to acquire Class B trust units may be granted to the directors, officers, employees, and special consultants of the Corporation and the Manager. Under the Rights Incentive Plan, distributions per trust unit to unitholders in a calendar quarter which represent a return of more than 2.5 percent of the net book value of property, plant and equipment at the beginning of such calendar quarter result, at the discretion of the holder, in a reduction in the exercise price. Total price reductions calculated for 2005 were $1.49 per trust unit right (2004 – $1.30 per trust unit right). One third of the rights granted under the Rights Incentive Plan vest on the grant date, one third on the first anniversary date of the grant and the remaining on the second anniversary. The rights have an expiry date of five years from the date of grant.

As at December 31, 2005, rights to purchase 1,441,737 Class B trust units were outstanding (2004 – 2,011,451) that expire at various dates to November 21, 2010.

Trust Unit Rights


	2005					2004
				Weighted					Weighted
	Number of			Average		Number of			Average
	Rights			Exercise Price		Rights			Exercise Price

Outstanding at beginning of year		2,011,451		$	14.23		1,112,140		$	12.20
Granted⁽¹⁾		606,575		$	18.34		1,409,856		$	17.35
Exercised		(953,904	)	$	12.81		(456,049	)	$	13.47
Cancelled		(222,385	)	$	16.19		(54,496	)	$	14.19

Outstanding at year end		1,441,737		$	14.85		2,011,451		$	14.23
Exercisable at year end		668,473		$	13.73		1,037,078		$	12.48


⁽¹⁾		Weighted average exercise price of rights granted are based on the exercise price at the date of grant.

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PENGROWTH ENERGY TRUST

The following table summarizes information about trust unit rights outstanding and exercisable at December 31, 2005:


	Rights Outstanding						Rights Exercisable
			Weighted
			Average		Weighted				Weighted
			Remaining		Average				Average
	Number		Contractual		Exercise		Number		Exercise
Range of Exercise Prices	Outstanding		Life (years)		Price		Exercisable		Price

$8.97 to $13.99		199,280		1.9	$	9.03		199,280	$	9.03
$14.00 to $15.99		549,620		3.1	$	14.01		223,339	$	14.01
$16.00 to $17.99		571,505		3.9	$	16.89		206,942	$	17.04
$18.00 to $20.99		121,332		4.8	$	18.65		38,912	$	18.68

$8.97 to $20.99		1,441,737		3.1	$	14.85		668,473	$	13.73

Fair Value of Unit Based Compensation

Pengrowth records compensation expense on trust unit rights granted on or after January 1, 2003. For trust unit options and rights granted in 2002, Pengrowth has elected to disclose the pro forma effect on net income had compensation expense been recorded using the fair value method. All of the trust unit options and rights issued in 2002 were fully vested prior to 2005, therefore there is no pro forma effect on net income for 2005. The following is the pro forma effect on net income in 2004:


	2004

Net income	$	153,745
Compensation expense related to rights incentive options granted in 2002		(1,067	)

Pro forma net income	$	152,678
Pro forma net income per unit:
Basic	$	1.145
Diluted	$	1.139

The fair value of trust unit rights granted in 2005 and 2004 was estimated at 15 percent of the exercise price at the date of grant using a modified Black-Scholes option pricing model with the following assumptions: risk-free rate of 3.9 percent, volatility of 19 percent (2004 – 22 percent), expected life of five years and adjustments for the estimated distributions and reductions in the exercise price over the life of the trust unit rights.

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2005 ANNUAL REPORT

Long Term Incentive Program

Effective January 1, 2005, the Board of Directors approved a Long Term Incentive Plan. The DEU’s issued under the plan fully vest and are converted to Class B trust units on the third anniversary year from the date of grant and will receive deemed distributions prior to the vesting date in the form of additional DEU’s. However, the number of DEU’s actually issued to each participant at the end of the three year vesting period will be subject to a relative performance test which compares Pengrowth’s three year average total return to the three year average total return of a peer group of other energy trusts such that upon vesting, the number of Class B trust units issued from treasury may range from zero to one and one-half times the number of DEU’s granted plus accrued DEU’s through the deemed reinvestment of distributions.

Compensation expense related to DEU’s is based on the fair value of the DEU’s at the date of grant. The number of Class B trust units awarded at the end of the vesting period is subject to certain performance conditions. Compensation expense incorporates the estimated fair value of the DEU’s at the date of grant and an estimate of the relative performance multiplier. Fluctuations in compensation expense may occur due to changes in estimating the outcome of the performance conditions. An estimate of forfeiture has not been made; rather compensation expense is reduced for actual forfeitures as they occur. Compensation expense is recognized in income over the vesting period with a corresponding increase or decrease to Contributed Surplus. Upon issuance of the Class B trust units at the end of the vesting period, trust unitholders’ capital is increased and contributed surplus is reduced. For the 12 months ended December 31, 2005, Pengrowth recorded compensation expense of $1.2 million associated with the DEU’s. Compensation expense associated with the DEU’s was based on the weighted average estimated fair value of $18.32 per DEU.


	Number of DEU’s

Outstanding, beginning of period		—
Granted		194,229
Cancelled		(26,258	)
Deemed DRIP		17,620

Outstanding, end of period		185,591

Trust Unit Award Plan

Effective July 13, 2005, Pengrowth established an incentive plan to reward and retain employees whereby Class B trust units and cash were awarded to eligible employees. Employees received one half of the trust units and cash on or about January 1, 2006 and will receive one half of the trust units and cash on or about July 1, 2006. Any change in the market value of the Class B trust units and reinvested distributions over the vesting period accrues to the eligible employees.

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PENGROWTH ENERGY TRUST

Pengrowth acquired the Class B trust units to be awarded under the plan on the open market for $4.3 million and placed them in a trust account established for the benefit of the eligible employees. The cost to acquire the trust units has been recorded as deferred compensation expense and is being charged to net income on a straight line basis over one year. In addition, the cash portion of the incentive plan of approximately $1.5 million is being accrued on a straight line basis over one year. Any unvested trust units will be sold on the open market. During the six months ended December 31, 2005 $2.9 million has been charged to net income.

Employee Savings Plans

Pengrowth has savings plans whereby Pengrowth will match contributions by qualifying employees of zero to ten percent of their annual basic salary, less any of Pengrowth’s contributions to the Group Registered Retirement Savings Plan (Group RRSP), to purchase trust units in the open market. Participants in the Group RRSP can make contributions from one to 13 percent and Pengrowth will match contributions to a maximum of five percent of their annual basic salary. Pengrowth’s share of contributions to the Trust Unit Purchase Plan and Group RRSP were $1.5 million in 2005 (2004 – $1.3 million) and $0.5 million in 2005 (2004 – $0.4 million), respectively.

Trust Unit Margin Purchase Plan

Pengrowth has a plan whereby the employees and certain consultants of Pengrowth and the Manager can purchase trust units and finance up to 75 percent of the purchase price through an investment dealer, subject to certain participation limits and restrictions. Certain officers and directors hold trust units under the Trust Unit Margin Purchase Plan; however, they are prohibited from increasing the number of trust units they can hold under the plan. Participants maintain personal margin accounts with the investment dealer and are responsible for all interest costs and obligations with respect to their margin loans.

Pengrowth has provided a $1 million letter of credit (2004 – $5 million) to the investment dealer to guarantee amounts owing with respect to the plan. The amount of the letter of credit may fluctuate depending on the amounts financed pursuant to the plan. At December 31, 2005, 721,334 Class B trust units were deposited under the plan (2004 – 848,022) with a market value of $16.3 million (2004 – $15.7 million) and a corresponding margin loan of $2.7 million (2004 – $3.1 million).

The investment dealer has limited the total margin loan available under the plan to the lesser of $15 million or 35 percent of the market value of the units held under the plan. If the market value of the trust units under the plan declines, Pengrowth may be required to make payments or post additional letters of credit to the investment dealer. Any payments to be made by Pengrowth are to be reduced by proceeds of liquidating the individual’s trust units held under the plan. The maximum amount Pengrowth may be required to pay at December 31, 2005 was $2.7 million (2004 – $3.1 million), the fair value of which is estimated to be a nominal amount.

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2005 ANNUAL REPORT

Redemption Rights

Trust units are redeemable at the option of the holder. The redemption price is equal to the lesser of 95 percent of the market trading price of the Class B trust units traded on the TSX for the ten trading days after the trust units have been surrendered for redemption and the closing market price of the Class B trust units quoted on the TSX on the date the trust units have been surrendered for redemption. Trust units can be redeemed for cash to a maximum of $25,000 per month. Redemptions in excess of the cash limit must be satisfied by way of a distribution in specie of a pro-rata share of royalty units and other assets, excluding facilities, pipelines or other assets associated with oil and natural gas production, which are held by the Trust at the time the trust units are to be redeemed.

11. Deferred Charges


	2005		2004

Imputed interest on note payable (net of accumulated amortization of $2,859, 2004 — $1,587)	$	748	$	2,020
U.S. debt issue costs (net of accumulated amortization of $816, 2004 — $510)		1,325		1,631
Deferred compensation expense (net of accumulated amortization of $2,143, 2004 — nil)		2,141		—
U.K. debt issue costs (net of accumulated amortization of $5)		672		—

	$	4,886	$	3,651

12. Foreign Exchange Loss (Gain)


	2005			2004

Unrealized foreign exchange gain on translation of U.S. dollar denominated debt	$	(7,800	)	$	(18,900	)
Realized foreign exchange losses		834			1,600

	$	(6,966	)	$	(17,300	)

The U.S. dollar denominated debt is translated into Canadian dollars at the exchange rate in effect at the balance sheet date. Foreign exchange gains and losses are included in income.

13. Other Cash Flow Disclosures

Change in Non-Cash Operating Working Capital


Cash provided by (used for):	2005			2004

Accounts receivable	$	(21,511	)	$	(22,515	)
Inventory		439			260
Accounts payable and accrued liabilities		29,953			17,225
Due to Pengrowth Management Limited		952			6,203

	$	9,833		$	1,173

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PENGROWTH ENERGY TRUST

Change in Non-Cash Investing Working Capital


Cash provided by:	2005		2004

Accounts payable for capital accruals	$	1,117	$	2,169

Cash payments


	2005		2004

Cash payments made for taxes⁽¹⁾	$	6,424	$	4,729
Cash payments made for interest	$	21,779	$	28,119


⁽¹⁾		Capital and resource taxes

14. Income Taxes

In 2003, the federal government implemented a reduction in federal corporate income tax rates that is being phased in over a period of five years commencing 2003. The applicable tax rate on resource income will be reduced from 28 percent to 21 percent. Additionally, crown royalties will be an allowable deduction and the resource allowance will be eliminated.

As a result of the changes to the income tax rates, Pengrowth’s future tax rate applied to the temporary differences is approximately 34 percent in 2005 (34 percent in 2004) compared to the federal and provincial statutory rate of approximately 38 percent for the 2005 income tax year. The provision for income taxes in the financial statements differs from the result which would have been obtained by applying the combined federal and provincial tax rate to Pengrowth’s income before taxes.


	2005			2004

Income before taxes	$	344,875		$	173,955
Combined federal and provincial tax rate		37.6	%		38.6	%

Expected income tax		129,673			67,147
Net income of the Trust		(122,698	)		(59,346	)
Resource allowance		(10,985	)		(8,807	)
Non-deductible crown charges		22,756			16,476
Unrealized foreign exchange gain		(1,623	)		(3,648	)
Attributed Canadian royalty income		(3,541	)		(3,113	)
Effect of proposed tax changes		—			3,850
Future tax rate difference		(1,402	)		(1,585	)
Change in valuation allowance		—			3,035
Other		96			1,607

Future income taxes		12,276			15,616
Capital taxes		6,273			4,594

	$	18,549		$	20,210

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2005 ANNUAL REPORT

The net future income tax liability is comprised of:


	2005			2004

Future income tax liabilities:
Property, plant, equipment and other assets	$	114,256		$	79,774
Unrealized foreign exchange gain		9,689			8,378
Other		110			—

		124,055			88,152
Future income tax assets:
Attributed Canadian royalty income		(7,819	)		(4,418	)
Contract liabilities		(6,124	)		(8,072	)
Other		—			(34	)

	$	110,112		$	75,628

At December 31, 2005, the petroleum and natural gas properties and facilities owned by the corporate subsidiaries of Pengrowth have an approximate tax basis of $634 million (2004 – $607 million) available for future use as deductions from taxable income.

15. Related Party Transactions

The Manager provides certain services pursuant to a management agreement for which Pengrowth was charged $6.9 million (2004 – $6.1 million) for performance fees and $9.1 million (2004 – $6.8 million) for a management fee. In addition, Pengrowth was charged $0.9 million (2004 – $0.8 million) for reimbursement of general and administrative expenses incurred by the Manager pursuant to the management agreement. The law firm controlled by the Vice President and Corporate Secretary charged $0.7 million (2004 – $0.8 million) for legal and advisory services provided to Pengrowth. The transactions have been recorded at the exchange amount. Amounts payable to the related parties are unsecured, non-interest bearing and have no set terms of repayment.

16. Amounts Per Trust Unit

The per trust unit amounts for net income are based on the weighted average trust units outstanding for the year. The weighted average trust units outstanding for 2005 were 157,127,181 trust units (2004 – 133,395,485 trust units). In computing diluted net income per trust unit, 786,577 trust units were added to the weighted average number of trust units outstanding during the year ended December 31, 2005 (2004 – 611,086) for the dilutive effect of trust unit options, trust unit rights and DEU’s. In 2005, 409,557 (2004 – 741,838) trust unit options and rights were excluded from the diluted net income per unit calculation as their effect is anti-dilutive.

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PENGROWTH ENERGY TRUST

17. Financial Instruments

Interest Rate Risk

Pengrowth has minimal exposure to interest rate changes as approximately 90 percent of Pengrowth’s long term debt at December 31, 2005 has fixed interest rates (Note 8).

At December 31, 2005 and 2004, there were no interest rate swaps outstanding.

Foreign Currency Exchange Risk

Pengrowth is exposed to foreign currency fluctuations as crude oil and natural gas prices received are referenced to U.S. dollar denominated prices. Pengrowth has mitigated some of this exchange risk by entering into fixed Canadian dollar crude oil and natural gas price swaps as outlined in the forward and futures contracts section below. Pengrowth is exposed to foreign currency fluctuation on the U.S. denominated notes for both interest and principal payments.

Pengrowth entered into a foreign exchange swap in conjunction with issuing £50 million of ten year term notes (Note 8) which fixed the Cdn$ to £ exchange rate on the interest and principal of the £ denominated debt at approximately £0.4976 per Canadian dollar. The estimated fair value of the foreign exchange swap has been determined based on the amount Pengrowth would receive or pay to terminate the contract at year end. At December 31, 2005, the amount Pengrowth would pay to terminate the foreign exchange swap would be approximately $2.2 million.

At December 31, 2004, there were no foreign currency exchange swaps outstanding.

Credit Risk

Pengrowth sells a significant portion of its oil and gas to commodity marketers, and the accounts receivable are subject to normal industry credit risks. The use of financial swap agreements involves a degree of credit risk that Pengrowth manages through its credit policies which are designed to limit eligible counterparties to those with “A” credit ratings or better.

Forward and Futures Contracts

Pengrowth has a price risk management program whereby the commodity price associated with a portion of its future production is fixed. Pengrowth sells forward a portion of its future production through a combination of fixed price sales contracts with customers and commodity swap agreements with financial counterparties. The forward and futures contracts are subject to market risk from fluctuating commodity prices and exchange rates.

As at December 31, 2005, Pengrowth had fixed the price applicable to future production as follows:

Crude Oil:

Remaining Term

Volume(bbl per day)

Reference Point

Price per bbl

Financial:

Jan 1, 2006 – Dec 31, 2006

4,000

WTI (1)

$64.08 Cdn

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2005 ANNUAL REPORT

Natural Gas:

Remaining Term

Volume (mmbtu per day)

Reference Point

Price per mmbtu

Financial:

Jan 1, 2006 – Mar 31, 2006

2,500

NYMEX (1)

$14.56 Cdn

Jan 1, 2006 – Dec 31, 2006

2,500

Transco Z6⁽¹⁾

$10.63 Cdn

Jan 1, 2006 – Dec 31, 2006

2,370

AECO

$8.03 Cdn


⁽¹⁾		Associated Cdn$ / U.S.$ foreign exchange rate has been fixed.

The estimated fair value of the financial crude oil and natural gas contracts has been determined based on the amounts Pengrowth would receive or pay to terminate the contracts at year end. At December 31, 2005, the amount Pengrowth would pay to terminate the financial crude oil and natural gas contracts would be $13.0 million and $5.4 million, respectively.

Natural Gas Fixed Price Sales Contract:

Pengrowth assumed a natural gas fixed price sales contract in conjunction with the Murphy acquisition. At December 31, 2005, the amount Pengrowth would pay to terminate the fixed price sales contract would be $35.3 million. Details of the physical fixed price sales contract are provided below:


Remaining Term	Volume (mmbtu per day)		Price per mmbtu (1)

2006 to 2009
Jan 1, 2006 – Oct 31, 2006		3,886	$2.23 Cdn
Nov 1, 2006 – Oct 31, 2007		3,886	$2.29 Cdn
Nov 1, 2007 – Oct 31, 2008		3,886	$2.34 Cdn
Nov 1, 2008 – April 30, 2009		3,886	$2.40 Cdn


⁽¹⁾		Reference price based on AECO

Fair value of financial instruments

The carrying value of financial instruments included in the balance sheet, other than long term debt, the note payable and remediation trust funds approximate their fair value due to their short maturity. The fair value of the note payable at December 31, 2005 and 2004 approximated its carrying value net of the imputed interest included in deferred charges. The fair value of the other financial instruments are as follows:

As at December 31, 2005

As at December 31, 2004

Net

Net

Fair Value

Book Value

Fair Value

Book Value

Remediation Funds

9,071

8,329

8,366

8,309

U.S. dollar denominated debt

220,187

232,600

238,726

240,400

£ denominated debt

101,257

100,489

—

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PENGROWTH ENERGY TRUST

18. Commitments

Pengrowth has future commitments under various agreements for oil and natural gas pipeline transportation, the purchase of carbon dioxide and operating leases. The commitment to purchase carbon dioxide arises as a result of Pengrowth’s working interest in the Weyburn CO₂ miscible flood project ⁽¹⁾. Capital expenditures arise from authorized expenditures at SOEP.


	2006		2007		2008		2009		2010		Thereafter		Total

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
Other commitments		3,132		3,096		3,950		3,610		3,377		32,779		49,944

	$	85,413	$	52,748	$	43,423	$	37,665	$	19,392	$	105,032	$	343,663


⁽¹⁾		Contract prices for CO₂ are denominated in U.S. dollars and have been translated at the year end foreign exchange rate.

19. Subsequent Event

20. Reconciliation of Financial Statements to United States Generally Accepted Accounting Principles

The significant differences between Canadian Generally Accepted Accounting Principles (Canadian GAAP) which, in most respects, conforms to generally accepted accounting principles in the United States (U.S. GAAP), as they apply to Pengrowth, are as follows:

(a)		As required annually under U.S. GAAP, the carrying value of petroleum and natural gas properties and related facilities, net of future or deferred income taxes, is limited to the present value of after tax future net revenue from proven reserves, discounted at ten percent (based on prices and costs at the balance sheet date), plus the lower of cost and fair value of unproven properties. At December 31, 1998 and 1997 the application of the full cost ceiling test under U.S. GAAP resulted in a write-down of capitalized costs of $328.6 million and $49.8 million, respectively. At December 31, 2005 and 2004, the application of the full cost ceiling test under U.S. GAAP did not result in a write-down of capitalized costs.

		Where the amount of a ceiling test write-down under Canadian GAAP differs from the amount of the write-down under U.S. GAAP, the charge for depletion will differ in subsequent years.

(b)		Under U.S. GAAP, interest and other income would not be included as a component of Net Revenue.

(c)		Effective January 1, 2003, Pengrowth prospectively adopted U.S. standards relating to recognizing the compensation expense associated with trust unit based compensation plans. Under U.S. GAAP Pengrowth adopted the following:

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2005 ANNUAL REPORT

(i) For trust unit options granted on or after January 1, 2003, the estimated fair value of the options is recognized as an expense over the vesting period. The compensation expense associated with trust unit options granted prior to January 1, 2003 is disclosed on a pro forma basis. As of January 1, 2005 all trust unit options were fully vested, thus there is no pro forma expense disclosed for 2005.

(ii) For trust unit rights granted on or after January 1, 2003, the estimated fair value of the rights, determined using a modified Black-Scholes option pricing model, is recognized as an expense over the vesting period. The compensation expense associated with the rights granted prior to January 1, 2003 is disclosed on a pro forma basis. As of January 1, 2005 all trust unit rights issued before January 1, 2003 are fully vested, thus there is no pro forma expense disclosed for 2005.

The following is the pro forma effect of trust unit options and rights granted prior to January 1, 2003, had the fair value method of accounting been used:


Year ended December 31,	2004

Net income (loss) — U.S. GAAP, as reported	$	180,045
Compensation expense related to rights incentive options granted prior to January 1, 2003		(1,067	)

Pro forma net income — U.S. GAAP	$	178,978

Pro forma net income — U.S. GAAP per unit:
Basic	$	1.34
Diluted	$	1.34

(d)		Statement of Financial Accounting Standards (SFAS) 130 requires the reporting of comprehensive income in addition to net income. Comprehensive income includes net income plus other comprehensive income; specifically, all changes in equity of a company during a period arising from non-owner sources.

(e)		SFAS 133, “Accounting for Derivative Instruments and Hedging Activities” establishes accounting and reporting standards for derivative instruments and for hedging activities. This statement requires an entity to establish, at the inception of a hedge, the method it will use for assessing the effectiveness of the hedging derivative and the measurement approach for determining the ineffective aspect of the hedge. Those methods must be consistent with the entity’s approach to managing risk.

		At December 31, 2005, $18.4 million has been recorded as a current liability in respect of the fair value of financial crude oil and natural gas hedges outstanding at year end with a corresponding change in accumulated other comprehensive income. At December 31, 2004, $7.3 million has been recorded as a current asset in respect of the fair value of the financial crude oil and natural gas hedges outstanding at year end with a corresponding change in accumulated other comprehensive income. These amounts will be recognized against crude oil and natural gas sales over the remaining terms of the related hedges.

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PENGROWTH ENERGY TRUST



		At December 31, 2005, $0.3 million has been recorded as a current liability with respect to the ineffective portion of crude oil and natural gas hedges outstanding at year end, with a corresponding change in net income. At December 31, 2004, the ineffective portion of crude oil and natural gas hedges outstanding at year end was not significant.

		At December 31, 2005, Pengrowth recorded a loss of $2.2 million relating to the foreign currency swap associated with the issuance of the £ denominated debt. As of February 14, 2006, Pengrowth had adequate documentation in place to account for the foreign currency contract as a hedge under U.S. GAAP.

		At December 31, 2004, there were no foreign exchange swaps outstanding.

(f)		Under U.S. GAAP the Trust’s equity is classified as redeemable equity as the Trust units are redeemable at the option of the holder. The redemption price is equal to the lesser of 95 percent of the market trading price of the Class B trust units traded on the TSX for the 10 trading days after the trust units have been surrendered for redemption and the closing market price of the Class B trust units quoted on the TSX on the date the trust units have been surrendered for redemption. Prior to the reclassification of trust units into Class A or Class B trust units, the trust units were redeemable as described above except the redemption price was based on the market trading price of the original trust units. Trust units can be redeemed for cash to a maximum of $25,000 per month. Redemptions in excess of the cash limit must be satisfied by way of a distribution in Specie of a pro-rata share of royalty units and other assets, excluding facilities, pipelines or other assets associated with oil and natural gas production, which are held by the Trust at the time the trust units are to be redeemed.

(g)		Under U.S. standards, an entity that is subject to income tax in multiple jurisdictions is required to disclose income tax expense at each jurisdiction. Pengrowth is subject to tax at the federal and provincial level. The portion of income tax expense taxed at the federal level is $12.9 million (2004 – $14.8 million). The portion of income tax expense taxed at the provincial level is $5.7 million (2004 – $5.4 million).

(h)		In December 2004, the FASB issued SFAS 153 which deals with the accounting for the exchanges of non-monetary assets. SFAS 153 is an amendment of APB Opinion 29. APB Opinion 29 requires that exchanges of non-monetary assets should be measured based on the fair value of the assets exchanged. SFAS 153 amends APB Opinion 29 to eliminate the exception from using fair market value for non-monetary exchanges of similar productive assets and introduce a broader exception for exchanges of non-monetary assets that do not have commercial substance. SFAS 153 is effective for non-monetary asset exchanges occurring in fiscal periods beginning after June 15, 2005. Adopting the provisions of SFAS 153 is not expected to impact the U.S. GAAP financial statements.

		In December 2004, the FASB issued SFAS 123R which deals with the accounting for transactions in which an entity exchanges its equity instruments for goods or services. SFAS 123R also addresses transactions in which an entity incurs liabilities in exchange for goods or services that are based on the fair value of the entity’s equity instruments or that may be settled by the issuance of those equity instruments. SFAS 123R focuses primarily on accounting for transactions in which an entity obtains employee services in share-based payment transactions. SFAS 123R is a revision of SFAS 123. SFAS 123R

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2005 ANNUAL REPORT

requires a public entity to measure the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award (with limited exceptions). That cost will be recognized over the period during which an employee is required to provide service in exchange for the award—the requisite service period (usually the vesting period). Since January 1, 2004 Pengrowth has recognized the costs of equity instruments issued in exchange for employee services based on the grant-date fair value of the award (Note 2), in accordance with Canadian GAAP. The methodology for determining fair value of equity instruments issued in exchange for employee services prescribed by SFAS 123R differs from that prescribed by Canadian GAAP. SFAS 123R is effective for exchanges in equity instruments in exchanges for goods or services occurring in fiscal years beginning after June 15, 2005. Adopting the provisions of SFAS 123R is not expected to have a material impact on the U.S. GAAP financial statements.

In May 2005 FASB issued SFAS 154 which deals with the accounting for all voluntary changes in accounting principles as well as changes required by accounting pronouncements that do not include specific transition provisions. SFAS 154 requires retrospective application to prior periods’ financial statements of changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. This Statement defines retrospective application as the application of a different accounting principle to prior accounting periods as if that principle had always been used or as the adjustment of previously issued financial statements to reflect a change in the reporting entity. This Statement also redefines restatement as the revising of previously issued financial statements to reflect the correction of an error. SFAS 123R is effective for changes in accounting pronouncements effective in fiscal years beginning after December 15, 2005. Adopting SFAS 154 is not expected to have a material impact on the U.S. GAAP financial statements.

Consolidated Statements of Income
The application of U.S. GAAP would have the following effect on net income as reported:


Stated in thousands of Canadian Dollars, except per unit amounts
Years ended December 31,	2005			2004

Net income for the year, as reported	$	326,326		$	153,745
Adjustments:
Depletion and depreciation (a)		24,723			26,000
Unrealized gain (loss) on ineffective portion of oil and natural gas hedges (e)		(255	)		300
Realized loss on foreign exchange contract (e)		(2,204	)		—

Net income — U.S. GAAP	$	348,590		$	180,045
Other comprehensive income:
Realized gain on foreign exchange swap (d)(e)		—			(2,169	)
Unrealized hedging gains (loss) (d)(e)		(25,470	)		21,186

Comprehensive income — U.S. GAAP	$	323,120		$	199,062

Net income — U.S. GAAP
Basic	$	2.22		$	1.35
Diluted	$	2.21		$	1.34

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PENGROWTH ENERGY TRUST

Consolidated Balance Sheets

The application of U.S. GAAP would have the following effect on the Balance Sheets as reported:

Stated in thousands of Canadian Dollars

Increase

December 31, 2005

Reported

(Decrease)

U.S. GAAP

Assets:

Capital assets (a)

2,067,988

(192,219

)

1,875,769

(192,219

)

Liabilities

Accounts payable (e)

111,493

255

111,748

Current portion of unrealized hedging loss (e)

—

18,153

Current portion of unrealized foreign currency contract (e)

—

2,204

Unitholders’ equity (f):

Accumulated other comprehensive income (d)(e)

—

(18,153

)

(18,153

)

Trust unitholders’ equity (a)

1,475,996

(194,678

)

1,281,318

(192,219

)


Stated in thousands of Canadian Dollars	As		Increase
December 31, 2004	Reported		(Decrease)			U.S. GAAP

Assets:
Current portion of unrealized hedging gain (e)	$	—	$	7,317		$	7,317
Capital assets (a)		1,989,288		(216,942	)		1,772,346

			$	(209,625	)

Unitholders’ equity (f):
Accumulated other comprehensive income (d)(e)	$	—	$	7,317		$	7,317
Trust unitholders’ equity (a)		1,462,211		(216,942	)		1,245,269

			$	(209,625	)

Additional disclosures required under U.S. GAAP

The components of accounts receivable are as follows:


As at December 31,	2005		2004

Trade	$	103,619	$	77,778
Prepaids		20,230		15,378
Other		3,545		11,072

	$	127,394	$	104,228

The components of accounts payable and accrued liabilities are as follows:


As at December 31,	2005		2004

Accounts payable	$	50,756	$	37,588
Accrued liabilities		60,737		42,835

	$	111,493	$	80,423

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2005 ANNUAL REPORT

Historical Distributions and Unit Price

Distribution Date


	2005		2004		2003		2002		2001		2000		1999		1998		1997		1996		1995		1994		1993		1992

January 15	$	0.23		0.21		0.20		0.13		0.34		0.25		0.11		0.14		0.15		0.08		0.07		0.06		0.19		–
February 15		0.23		0.21		0.20		0.13		0.40		0.26		0.13		0.22		0.31		0.13		0.18		0.10		0.14		0.12
March 15		0.23		0.21		0.25		0.13		0.43		0.30		0.13		0.11		0.15		0.08		0.07		0.06		0.05		–
April 15		0.23		0.21		0.25		0.13		0.38		0.29		0.15		0.11		0.22		0.09		0.07		0.06		0.05		–
May 15		0.23		0.21		0.25		0.15		0.33		0.32		0.22		0.24		0.24		0.23		0.22		0.16		0.18		0.26
June 15		0.23		0.21		0.25		0.21		0.29		0.24		0.16		0.11		0.21		0.20		0.16		0.13		0.05		0.04
July 15		0.23		0.21		0.21		0.17		0.26		0.26		0.19		0.11		0.15		0.20		0.08		0.06		0.05		0.04
August 15		0.23		0.22		0.21		0.16		0.28		0.30		0.22		0.11		0.15		0.16		0.08		0.07		0.05		0.04
September 15		0.23		0.22		0.21		0.15		0.21		0.28		0.21		0.11		0.17		0.10		0.08		0.07		0.24		0.04
October 15		0.23		0.22		0.21		0.17		0.21		0.30		0.22		0.11		0.11		0.16		0.14		0.13		0.06		0.04
November 15		0.23		0.23		0.21		0.20		0.21		0.38		0.25		0.11		0.11		0.10		0.08		0.07		0.06		0.05
December 15		0.25		0.23		0.21		0.20		0.15		0.37		0.23		0.17		0.14		0.14		0.12		0.15		0.06		0.05

Total	$	2.78		2.59		2.66		1.93		3.49		3.55		2.22		1.65		2.11		1.67		1.35		1.12		1.18		0.68

Cumulative total	$	31.03		28.25		25.66		23.00		21.07		17.58		14.03		11.81		10.16		8.05		6.38		5.03		3.91		2.73

Unit Price and Cash Distribution (Monthly)

114
PENGROWTH ENERGY TRUST

Five Year Review

Consolidated Balance Sheets


(Stated in thousands of dollars)
As at December 31	2005		2004		2003		2002		2001

ASSETS
Current assets
Cash and term deposits	—		—		64,154		8,292		3,797
Other current assets	127,394		104,667		66,269		44,633		30,546

	127,394		104,667		130,423		52,925		34,343
Goodwill	182,835		170,619		—		—		—
Property, plant and equipment	2,067,988		1,989,288		1,530,359		1,493,047		1,229,395
Other long term assets	13,215		11,960		12,936		6,679		6,470

	2,391,432		2,276,534		1,673,718		1,552,651		1,270,208


LIABILITIES AND UNITHOLDERS’ EQUITY

Current liabilities
Bank indebtedness	14,567		4,214		—		—		—
Other current liabilities	225,032		178,999		117,457		89,493		54,089

	239,599		183,213		117,457		89,493		54,089
Long term debt	368,089		345,400		259,300		316,501		345,456
Other long term liabilities	307,748		285,710		137,528		73,493		42,123


Trust unitholders’ equity
Trust unitholders’ capital	2,514,997		2,383,284		1,872,924		1,662,726		1,280,599
Contributed surplus	3,646		1,923		189		—		—
Deficit	(1 ,042,647	)	(922,996	)	(713,680	)	(589,562	)	(452,059	)

	1,475,996		1,462,211		1,159,433		1,073,164		828,540

	2,391,432		2,276,534		1,673,718		1,552,651		1,270,208

115
2005 ANNUAL REPORT

Five Year Review

Consolidated Statements of Income and Deficit


(Stated in thousands of dollars)
Years ended December 31	2005			2004			2003			2002			2001

REVENUES
Oil and gas sales ⁽¹⁾		1,151,510			815,751			702,732			490,472			479,845
Processing and other income		15,091			12,390			9,726			6,936			7,071
Royalties, net of incentives ⁽¹⁾		(213,863	)		(160,351	)		(126,617	)		(88,777	)		(81,876	)

		952,738			667,790			585,841			408,631			405,040
Interest and other income		2,596			1,770			840			274			1,348

Net revenues		955,334			669,560			586,681			408,905			406,388

EXPENSES
Operating		218,115			159,742			149,032			129,802			104,943
Transportation		7,891			8,274			8,225			–			–
Amortization of injectants for miscible floods		24,393			19,669			32,541			44,330			47,448
Interest		21,642			29,924			18,153			15,213			18,806
General and administrative		30,272			24,448			15,997			10,992			7,467
Management fee		15,961			12,874			10,181			6,567			7,120
Foreign exchange loss (gain)		(6,966	)		(17,300	)		(29,911	)		182			0
Depletion and depreciation		284,989			247,332			185,270			140,775			126,409
Accretion		14,162			10,642			6,039			3,566			3,293

		610,459			495,605			395,527			351,427			315,486


Income before taxes		344,875			173,955			191,154			57,478			90,902

Income tax expense
Capital		6,273			4,594			1,857			523			2,717
Future		12,276			15,616			–			–			–

		18,549			20,210			1,857			523			2,717

NET INCOME		326,326			153,745			189,297			56,955			88,185
Deficit, beginning of year		(922,996	)		(713,680	)		(589,562	)		(452,059	)		(324,457	)
Distributions paid or declared		(445,977	)		(363,061	)		(313,415	)		(194,458	)		(215,787	)

Deficit, end of year		( 1,042,647	)		(922,996	)		(713,680	)		(589,562	)		(452,059	)


Net income per trust unit
Basic		2.08			1.15			1.63			0.63			1.24
Diluted		2.07			1.15			1.63			0.63			1.24


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

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PENGROWTH ENERGY TRUST

Five Year Review

Consolidated Statements of Cash Flow


(Stated in thousands of dollars)
Years ended December 31	2005			2004			2003			2002			2001

CASH PROVIDED BY (USED FOR):
Operating
Net income		326,326			153,745			189,297			56,955			88,185
Depletion and depreciation		284,989			247,332			185,270			140,775			126,409
Accretion		14,162			10,642			6,039			3,566			3,293
Future income taxes		12,276			15,616			—			—			—
Amortization of injectants		24,393			19,669			32,541			44,330			47,448
Purchase of injectants		(34,658	)		(20,415	)		(23,037	)		(15,107	)		(56,352	)
Other non-cash items		(19,251	)		(23,595	)		(33,696	)		(1,783	)		(1,223	)
Changes in non-cash operating working capital		9,833			1,173			(9,863	)		120			(2,919	)

		618,070			404,167			346,551			228,856			204,841
Financing
Distributions		(436,450	)		(344,744	)		(306,591	)		(171,350	)		(241,590	)
Changes in long term debt and note payable		(4,970	)		95,000			15,132			(28,955	)		58,080
Proceeds from issue of trust units		42,544			509,830			210,198			382,127			305,875

		(398,876	)		260,086			(81,261	)		181,822			122,365
Investing
Expenditures on property acquisitions		(92,568	)		(572,980	)		(122,964	)		(391,761	)		(280,058	)
Expenditures on property, plant and equipment		(175,693	)		(161,141	)		(85,718	)		(55,631	)		(74,026	)
Other items		38,714			1,500			(746	)		41,209			26,142

		(229,547	)		(732,621	)		(209,428	)		(406,183	)		(327,942	)
Change in cash and term deposits		(10,353	)		(68,368	)		55,862			4,495			(736	)
Cash and term deposits (bank indebtedness) at beginning of year		(4,214	)		64,154			8,292			3,797			4,533

Cash and term deposits (bank indebtedness) at year end		(14,567	)		(4,214	)		64,154			8,292			3,797

117
2005 ANNUAL REPORT

Five Year Review

Operating Measures


Years ended December 31	2005		2004		2003		2002		2001

PRODUCTION
Crude Oil (bbl per day)		20,799		20,817		23,337		19,914		19,726
Heavy Oil (bbl per day)		5,623		3,558		—		—		—
Natural Gas (mcf per day)		161,056		144,277		119,842		111,713		91,764
Natural gas liquids (bbl per day)		6,093		5,281		5,722		5,252		5,258
Total (boe per day)		59,357		53,702		49,033		43,785		40,320
Annual (mmboe)		21.7		19.7		17.9		16.0		14.7
% natural gas		45		45		41		43		38

Production per weighted average trust unit outstanding (boe)		0.14		0.15		0.15		0.18		0.21

BENCHMARK PRICES
WTI (U.S. $ per bbl)	$	56.70	$	41.47	$	30.99	$	26.08	$	25.90
NYMEX (U.S. $ per mmbtu)	$	8.62	$	6.16	$	5.39	$	3.22	$	4.27
AECO (Cdn $ per mcf)	$	8.48	$	6.79	$	6.70	$	4.07	$	6.30
Currency (U.S. $ per Cdn $)	$	0.83	$	0.77	$	0.71	$	0.64	$	0.65

AVERAGE REALIZED PRICES
Oil ($ per bbl)	$	58.59	$	43.21	$	40.85	$	38.06	$	37.26
Heavy Oil ($ per bbl)	$	33.32	$	32.45		n/a		n/a		n/a
Natural Gas ( $ per mcf)	$	8.76	$	6.80	$	6.35	$	3.85	$	4.48
Natural gas liquids ($ per bbl)	$	54.22	$	42.21	$	35.54	$	28.11	$	30.68
Average price per boe ⁽¹⁾	$	53.02	$	41.33	$	39.12	$	30.50	$	32.47

AVERAGE NETBACK
Light oil netback ( $ per bbl)	$	35.01	$	24.38	$	23.40		n/a		n/a
Heavy oil netback ($ per bbl)	$	13.50	$	17.73		n/a		n/a		n/a
Natural gas netback ( $ per mcf)	$	5.95	$	4.47	$	3.89		n/a		n/a
NGL netback ( $ per bbl)	$	27.52	$	18.74	$	13.09		n/a		n/a
Operating netback ($ per boe)	$	32.54	$	24.51	$	22.17	$	14.70	$	17.25

Property acquisitions ($ millions)	$	175.1	$	569.7	$	126.5	$	389.3	$	277.1
Capital expenditures ($ millions)	$	175.7	$	161.1	$	85.7	$	55.6	$	74.0

Reserves (proved plus probable)
Reserves acquired in the year (mmboe)		16.7		47.9		n/a		37.7		48.4
Reserves at year end (mmboe)		219.4		218.6		184.4		214.8		210.5
Acquisition cost per boe ⁽¹⁾	$	10.49	$	11.89		n/a	$	10.33	$	5.72

Reserves per year end trust units outstanding		1.37		1.43		1.49		1.94		2.56

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

118
PENGROWTH ENERGY TRUST

Five Year Review

Financial Measures


(Stated in thousands of dollars, except per trust unit amounts)
Years ended December 31	2005		2004		2003		2002		2001

Expenses (per boe)
Royalties	$	9.87	$	8.16	$	7.07	$	5.56	$	5.56
Operating	$	10.07	$	8.13	$	8.33	$	8.12	$	7.13
Transportation	$	0.36	$	0.42	$	0.46	$	—	$	—
Amortization of injectants for miscible floods	$	1.13	$	1.00	$	1.82	$	2.77	$	3.22
Interest	$	1.00	$	1.52	$	1.01	$	0.95	$	1.28
General and administrative	$	1.40	$	1.24	$	0.89	$	0.69	$	0.51
Management fee	$	0.74	$	0.66	$	0.57	$	0.41	$	0.48
Depletion and depreciation	$	13.15	$	12.58	$	10.35	$	8.81	$	8.59
Accretion	$	0.65	$	0.54	$	0.34	$	0.22	$	0.22
Net income	$	326,326	$	153,745	$	189,297	$	56,955	$	88,185
Net income per trust unit	$	2.08	$	1.15	$	1.63	$	0.63	$	1.24
Distributable Cash
Cash Generated from Operations	$	618,070	$	404,167	$	346,551	$	228,856	$	204,841
Cash Generated from Operations per trust unit	$	3.93	$	3.03	$	2.99	$	2.55	$	2.89
Distributable cash ⁽¹⁾	$	619,739	$	401,178	$	345,911	$	199,480	$	215,787
Distributable cash per trust unit ⁽¹⁾	$	3.94	$	3.01	$	2.98	$	2.22	$	3.04
Actual distributions paid or declared	$	445,977	$	363,061	$	313,415	$	194,458	$	215,787
Actual distributions paid or declared per trust unit	$	2.82	$	2.63	$	2.68	$	2.07	$	3.01
Payout Ratio (%)		72		90		90		85		105
Number of trust units outstanding
Weighted average		157,127		133,395		115,912		89,923		70,911
Total at year end		159,864		152,973		123,874		110,562		82,240

Total assets	$	2,391,432	$	2,276,534	$	1,673,718	$	1,552,651	$	1,270,208
Total assets per trust unit	$	14.96	$	14.88	$	13.51	$	14.04	$	15.45
Long term debt	$	368,089	$	345,400	$	259,300	$	316,501	$	345,456
Long term debt per trust unit	$	2.30	$	2.26	$	2.09	$	2.86	$	4.20
Unitholders’ equity	$	1,475,996	$	1,462,211	$	1,159,433	$	1,073,164	$	828,540
Unitholders’ equity per trust unit	$	9.23	$	9.56	$	9.36	$	9.71	$	10.07
Net asset value at 10%	$	2,834,663	$	1,708,012	$	1,124,433	$	1,239,322	$	914,970
Net asset value per trust unit	$	17.73	$	11.17	$	9.08	$	11.21	$	11.13
Capitalization highlights
Net debt (net of working capital)	$	480,294	$	443,946	$	281,334	$	353,069	$	365,202
Unitholders’ equity	$	1,475,996	$	1,462,211	$	1,159,433	$	1,073,164	$	828,540
Total book capitalization	$	1,956,290	$	1,906,157	$	1,440,767	$	1,426,233	$	1,193,742
Equity Market capitalization	$	3,989,939	$	3,323,770	$	2,632,315	$	1,628,583	$	1,169,454
Enterprise value	$	4,358,028	$	3,669,170	$	2,891,615	$	1,945,084	$	1,514,910

Return on average equity (%)		22.2		11.7		17.0		6.0		11.9
Cash flow return on average equity (%)		30.3		27.7		28.1		20.5		29.2
Average cost of debt capital (%)⁽¹⁾		4.6		5.1		5.1		4.6		5.2


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

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2005 ANNUAL REPORT

Pengrowth Team Members

Bodo
Gerard Doetzel
Gary Magnusson

Cactus
Vicki Ostrowski
Dennis Reschny

Calgary
Elizabeth Allan
Gordon Anderson
Ross Andrews
Gail Anson
Wayne Arnold
Tony Avdicos
Richard Bader
Richard Ballantine
Leah Barevich
Lorraine Bedet
Andrew Beingessner
Mo Berglund
Sue-Ann Bibby
Pamela Bilodeau
Allan Birce
Micheline Bird
Douglas Bowles
Shane Bradley
Susan Bradley
Lynne Brinkworth
Debora Brisson
Vania Burton
Eyon Butterworth
Neil Cameron
James Causgrove
Jennifer Charlesworth
Peter Cheung
Erik Chico
Daniel Christal
William Christensen
Matthew Clark
Allen Connick
Karen Cote-Balmer
Glori Cowan
Stuart Crichton
Amanda Crozier
Kim Cuthbertson
Jeffrey Dashkin
Anne Davison
Clare De Jersey-Lowney
Polly DeWulf
Terry Dey
Cate Dicken
Linda Dickenson
Jade Diep
Stephen Dunsmore
Christopher Dutchak
Larry Dziuba
Jim Edgar
Kevin Eike
Nadine Epp
Kathy Fidyk
Terry Fong
Todd Frankel
Leanne Fraser
Steve Freeman
Philip Fung
John Gemmel
Sandra-Lynne Gerlitz
Dawna Gibb
Phillip Goldsney
Kiterri Goulder
Emma Gowers
Rebecca Greenan
Brenda Gregoire
Cherie Griffett-Bloodworth
Jamie Grolla
Kevin Gunning
Kristy Halat
John Hanko
Amanda Hartman
Carla Hennessey
Grant Henschel
Beverly Hill
Wayne Ho
Shanda Hoar
Stephen Hu
Jocelyn Hunt
Justine Hunter
Donald Ind
Abiodun Jaiyeola
Ron Janz
Kevin Jensen
Tania Kaschl
Nadia Kassianoff
Justin Kereluk
Faryal Khawaja
Tracy Knibbs
Rebecca Kondrat
Kathy Konrad
Kirsten Kulyk
Lorrie Lancaster
Dick Lane
Kate Langejans
David Lankester
Karen Laustsen
Renee Lee
Darlene Loeffel
Lisa MacKinnon
Glenn Malcolm
Bruce Malcolm
Betty Maloney
Allison Martin
Terry Martin
Leslie McCawley
Carol McDonald
Sharon McFetridge
John Mclnnes
Mark McLenahan
Cyndy Mercier
Vesna Milicevic
Heather Mitchell
Valerie Mitchell
Rob Moriyama
Dean Morrison
Chris Mortl
Darlene Nelson
Wayne Nibogie
Emily Nickle
Wendy Noonan
Carol O’Grady
Janet Page
Linda Parsons
Lise Pitt
Terry Pocza
Christopher Popoff
Henry Postma
Nancy Pow
Doreen Prichard
Bonnie Procter
Clay Radu
Gordon Ross
Lori Rounce
Jayne Ruttan
Jacki Sampson
Juan Sarmiento-Barraza
Lawrence Schafers
Ken Segouin
Mike Seleznev
Andrew Seto
Ron Shannon
Steve Simonds
Connie Skimmings
Stephen Smith
Heather Sommers
Merle Spence
Karen Spencer
Lorraine Steele
Randy Steele
Anna Steininger
Larry Strong
Mario Struik
Ira Sujadi
Isabel Szeto
Tina Taing
Celine Tan
Daisy Tao
Douglas Taylor
Kayla Thai
Linda Thain
Evelyn Thorburn
Hoang Tran
Dale Trenerry
Jennifer Turner
Nikki Tuveson
Scott Urquhart
Myra Valencerina
Ashley van der Borgh
Rudy van der Borgh
Patrick Van Mil
Neil Walliser
Jim Walters
Jennifer Wardell
Arnold Weatherdon
Christopher Webster
Carol Weis

Davette Weston
Olwen Wirth
Theressa Wong
Rosaline Wood
Debra Woolhouse
Graham Wright
Dwayne Yanitski
Brandie Yarmie

Fort St. John
Wes Andres
Kathreen Badiou
Garry Beamish
Rick Brown
Wyatt Dressler
Cody Goddard
Randall Howe
Kelly Hunter
Curt Jansen
Robert Lewis
Mark McDermott
Laurie Olson
Bernard O’Neill
Nolan Steinwand
Garry Tremain
Lee Wizniuk
Ken Workman

Halifax
James MacDonald

Judy Creek
Robert Azim
Dale Babiak
Norman Bachand
Dane Baker
Rohan Balkaran
David Beeson
Keith Black
Dave Bradley
Warren Bready
Duane Carlson
Nigel Cook
Kevin Cote
Dean Cotton
Darcy Craft
Donald Craig
Robin Cramer
Debra Danyluk
Leonard Danyluk
Alan Doucette
Geoff Duff
Tasha Erickson
Greg Ewasiuk
Jean Feckley
Garry Fisher
Brian Fuglerud
Randy Fuglerud
Patrick Gaultier
Bernie Gaumont
Dianna Gaumont
Roy Gertz
Garry Givens
Elaine Grant
Richard Grant
Jim Greer
Jeff Harasym
John Hestermann
Douglas Hiemstra
Paul Hiemstra
Grant Huber
Khai Huynh
Craig Johnson
Dale Johnson
Dan Jones
Erika Jones
Donald Kallis
Pat Kletzel
Francis Kripal
Sam Kuric
Gregory Lawrence
Randy Lawrie
Martin Littke
Rod Machula
Randal Marriott
David McConnell
Robbie McKinnon
Pete Mierau
Keith Miller
Colin Muir
Peter Neudorf
Joseph Oleksow
Robert Paterson
Lonnie Patten
David Peachman
Roger Pechanec
Raymond Pollock
Eric Pratt
Kevin Prodaniuk
Gordon Rau
Brian Read
Laura Rock
Robert Rock
Terry Romaniuk
Anne Schlauch
Sheldon Scyrup
Wesley Semler
Phil Semmler
Stuart Slager
Dean Soucy
Darren Tetlock
Jay Thebeau
Carolyn Thomas
Joyce Tonsi
Randy Trofimuk
Travis Visitew
Arlene Volden
Doug Wakaruk
Donna Walker
James Whaley
Jeffrey Whatmore
Beverly Whitaker-Jackman
Jeremy Wilhelm
Levi Willis

McLeod
MacKenzie Hehn
Marc Morin

Niton
Damon Jager
Trent Vanthuyne

Plover
Tim Gallinger
Dwaine Long

Princess
Terry Cameron
Arthur Creasser
Ray Erker
Lyndon Johnson
Kenton Osadczuk

Three Hills
Richard Evans
Catherine Prohl
Gary Rose
Michael Sept
David Ward

Toronto
Kerry Breeze
Sally Elliott

120
PENGROWTH ENERGY TRUST

121
2005 ANNUAL REPORT

A Note to U.S. Unitholders

This note is of a general nature only and is not intended to be legal or tax advice to any particular unitholder. Consequently, existing or prospective unitholders should consult their own tax advisors with respect to their particular circumstances.

Background

Pengrowth Energy Trust has elected under applicable U.S. Treasury Regulations to be treated as a partnership for U.S. tax purposes. A U.S. resident unitholder is a partner for U.S. tax purposes and is required to take into account his/her share of partnership income, gain, loss and deduction in computing his/her federal income tax liability.

Pengrowth has made available to U.S. unitholders a substitute schedule K-1 containing the applicable income, gains and deductions for the 2005 tax year. Pengrowth will continue to provide K-1 schedules within 75 days of each calendar year.

A detailed U.S. Tax Reporting Package is available by calling Pengrowth Investor Relations at (888) 744-1111 or on Pengrowth’s website at www.pengrowth.com.

122
PENGROWTH ENERGY TRUST

Distribution Reinvestment and Trust Unit Plan

Pengrowth’s Distribution Reinvestment and Trust Unit Purchase Plan, was developed as a convenient way for unitholders ⁽¹⁾ to maximize their investment in Pengrowth — at a discount to current market prices and free of brokerage commissions and other fees.

Under the Plan, participating unitholders automatically reinvest their monthly cash distributions in new trust units and can purchase, at their option, up to $1,000 worth of additional new trust units per month.

The price of units purchased under the Plan is 5 percent off the weighted average stock market trading price of Pengrowth’s trust units for the 20 days leading up to the most recent cash distribution. Enrolment, reinvestment and optional purchases are completely free of charge for self-registered unitholders. Those enrolling in the Plan through a broker, trust company, bank or other nominee may be subject to fees charged by the nominee. Plan participants receive a statement of account mailed monthly.

For further information on the Plan and to receive an enrolment form, please visit the Trust’s website at www.pengrowth.com or contact Pengrowth’s Investor Relations department at (888) 744-1111 to request the forms by mail or fax; or contact Pengrowth’s Trustee, Computershare Trust Company of Canada, at (800) 564-6253

⁽¹⁾ available to Class B trust unitholders only.


Pengrowth Energy Trust
Suite 2900		Distribution Reinvestment and Trust Unit Purchase Plan
240-4^thAvenue S.W.		Request for Information
Calgary, Alberta T2P 4H4


o		Distribution Reinvestment
		I am a Class B trust unitholder and wish to participate in the Distribtution Reinvestment and Trust Unit Purchase Plan of Pengrowth Energy Trust. Please send the required authorization form to me.

o		Request for Information
		Please send detailed information concerning the Distribution Reinvestment and Trust Unit Purchase Plan of Pengrowth Energy Plan to me.


Name(s):


Signature(s):


Address:




Telephone: Home:								Bus:


Date:

Place
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Pengrowth Energy Trust
Suite 2900
240-4^thAvenue S.W.
Calgary, Alberta, Canada
T2P 4H4

PENGROWTH ENERGY TRUST

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Corporate Information

Directors of Pengrowth Corporation

Thomas A. Cumming
Business Consultant

Kirby L. Hedrick
Business Consultant

James S. Kinnear; Chairman
President, Pengrowth Management Limited

Michael S. Parrett
Business Consultant

A. Terence Poole
Executive Vice President, Corporate
Strategy and Development,
Nova Chemicals Corporation

Stanley H. Wong
President, Carbine Resources Ltd.

John B. Zaozirny; Lead Director
Counsel, McCarthy Tetrault

Directors Emeritus

Thomas S. Dobson
President, T.S. Dobson Consultant Ltd.

Francis G. Vetsch
President, Vetsch Resource Management Ltd.

Officers of Pengrowth Corporation

James S. Kinnear
Chairman, President and Chief Executive Officer

Christopher G. Webster
Chief Financial Officer

Gordon M. Anderson
Vice President, Finance

Douglas C. Bowles*
Vice President, Controller

James Causgrove
Vice President, Production and Operations

Peter Cheung*
Treasurer

William Christensen Vice President, Strategic Planning and Reservoir Exploitation

Charles V. Selby
Vice President and Corporate Secretary

Larry B. Strong
Vice President, Geosciences

Trustee

Computershare Trust Company of Canada

Bankers

Bank Syndicate Agent:
Royal Bank of Canada

Auditors

KPMG LLP

Engineering Consultants

GLJ Petroleum Consultants Ltd.

Abbreviations


bbl		barrel
bcf boe*		billions of cubic feet barrels of oil equivalent
gj		gigajoule
mbbls		thousand barrels
mmbbls		million barrels
mboe*		thousand barrels of oil equivalent
mmboe*		million barrels of oil equivalent
mmbtu		million British thermal units
mcf		thousand cubic feet


*6 mcf of gas = 1 barrel of oil

Pengrowth and a Strong Community

Pengrowth believes in enhancing the community where our employees live and work. Pengrowth and Pengrowth Management Limited support causes and institutions both financially and through volunteer efforts and are proud of these associations and partnerships with many community-building non-profit organizations. Pengrowth has a substantial investment in our community though many of the costs are attributed to Pengrowth Management, Pengrowth Energy Trust unitholders benefit through the visibility associated with these vital partnerships.

Stock Exchange Listings

The Toronto Stock Exchange:
Symbol: PGF.A / PGF.B

The New York Stock Exchange:
Symbol: PGH

Pengrowth Energy Trust

Head Office

Suite 2900, 240 – 4^th Avenue S.W.
Calgary, Alberta T2P 4H4 Canada
Telephone: (403) 233-0224
Toll-Free: (800) 223-4122
Facsimile: (403) 265-6251
Email: investorrelations@pengrowth.com
Website: http://www.pengrowth.com

Toronto Office

Scotia Plaza, 40 King Street West
Suite 3006 – Box 106
Toronto, Ontario M5H 3Y2 Canada
Telephone: (416) 362-1748
Toll-Free: (888) 744-1111
Facsimile: (416) 362-8191

Halifax Office

Purdy’s Tower 1 — Suite 1700
1959 Upper Water Street
Halifax, Nova Scotia B3J 2N2 Canada
Telephone: (902) 425-8778
Facsimile: (902) 425-7887

London Office

33 St. James Square
London, England SW1 Y4JS
Telephone: 011 (44) 207-661-9591
Facsimile: 011 (44) 207-661-9592

Investor Relations

For investor relations enquiries,
please contact:
Investor Relations,
Telephone: (403) 233-0224
Toll-Free: (888) 744-1111
Facsimile: (403) 294-0051
Email: investorrelations@pengrowth.com

Photography

Head Office Photography: Marnie Burkhart,
Jazhart Studios, Calgary, AB
Field Photography:
Neil King, King Photography, Calgary, AB


*		Effective March 1, 2006

IBC
2005 ANNUAL REPORT