SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 6-K

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

PENGROWTH ENERGY TRUST

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

          [Indicate by check mark whether the registrant files or will file annual reports under cover Form 20-F or Form 40-F.]

Form 20-F     o		Form 40-F     þ

          [Indicate by check mark whether the registrant by furnishing the information contained in this Form is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2(b) under the Security Exchange Act of 1934.]

Yes     o		No     þ

          [If “Yes” is marked, indicate below the file number assigned to the registrant in connection with Rule 12g3-2(b):                    ]

 

 

DOCUMENTS FURNISHED HEREUNDER:

1.

Management’s Discussion and Analysis for Pengrowth Energy Trust for year ended December 31, 2006.

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.

Management’s Discussion
and Analysis

The following Management’s Discussion and Analysis (MD&A) of financial results should be read in conjunction with the audited consolidated Financial Statements for the year ended December 31, 2006 of Pengrowth Energy Trust and is based on information available to February 26, 2007.

FREQUENTLY RECURRING TERMS

For the purposes of this MD&A, 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 its subsidiaries and the Corporation on a consolidated basis and the “Manager” refers to Pengrowth Management Limited.

Pengrowth uses the following frequently recurring industry terms in this MD&A: “bbls” refers to barrels, “boe” refers to barrels of oil equivalent, “mboe” refers to a thousand barrels of oil equivalent, “mcf” refers to thousand cubic feet, “gj” refers to gigajoule and “mmbtu” refers to million British thermal units.

ADVISORY REGARDING FORWARD-LOOKING STATEMENTS

This MD&A contains forward-looking statements within the meaning of securities laws, including the “safe harbour” provisions of Canadian securities legislation 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”, “guidance” “may”, “will”, “should”, “could”, “estimate”, “predict” or similar words suggesting future outcomes or language suggesting an outlook. Forward-looking statements in this MD&A include, but are not limited to, statements with respect to: reserves, 2007 production, production additions from Pengrowth’s 2007 development program, the impact on production of divestitures in 2007, royalty obligations, 2007 operating expenses, future income taxes, asset retirement obligations, taxability of distributions, remediation and abandonment expenses, capital expenditures, new head office expenses, general and administration expenses and the impact of the proposed changes to the Canadian tax legislation. 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, regulatory developments future oil and natural gas commodity prices and differentials between light, medium and heavy oil prices, future oil and natural gas production levels, future exchange rates, the proceeds of anticipated divestitures, the amount of future cash distributions paid by Pengrowth, the cost of expanding our property holdings, our ability to obtain equipment in a timely manner to carry out development activities, our ability to market our oil and natural gas successfully to current and new customers, the impact of increasing competition, our ability to obtain

PENGROWTH 2006 | 61

Management’s Discussion
and Analysis

financing on acceptable terms, and our ability to add production and reserves through our development and exploitation activities. Although management considers these assumptions to be reasonable based on information currently available to it, they may prove to be incorrect.

HISTORICAL AVERAGE ANNUAL TOTAL COMPOUND RETURNS BY YEAR(%)

TSX trading

Note: Assumes reinvestment of distributions.

TRUST UNIT CLOSING PRICE AND HISTORICAL CASH DISTRIBUTIONS

TSX trading

Note: Pengrowth consolidated the Class A and Class B trust units into a single class of trust units on July 27, 2006 which now trade on the TSX under the symbol PGF.UN and on the NYSE under the symbol PGH.

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 most recent Annual Information Form (AIF), and in Pengrowth’s most recent consolidated financial statements, management information circular, quarterly reports, material change reports and news releases. Copies of the Trust’s Canadian public filings are available on SEDAR at www.sedar.com. The Trust’s U.S. public filings, including the Trust’s most recent annual report Form 40-F as supplemented by its filings on Form 6-K, are available at www.sec.gov.

Pengrowth cautions that the foregoing list of factors that may affect future results is not exhaustive. When relying on our forward-looking statements to make decisions with respect to Pengrowth, investors and others should carefully consider the foregoing factors and other uncertainties and potential events. Furthermore, the forward-looking statements contained in this press release are made as of the date of this MD&A and Pengrowth

62 | PENGROWTH 2006

Management’s Discussion
and Analysis

does not undertake any obligation to update publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise, except as required by law. The forward-looking statements contained in this MD&A 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 year 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) Disclosure for Oil and Gas Activities, Pengrowth uses independent qualified reserve evaluators in the preparation of reserve evaluations. By their nature, these estimates are subject to measurement uncertainty and changes in these estimates may impact the consolidated financial statements of future periods.

NON-GAAP FINANCIAL MEASURES

This discussion refers to certain financial measures that are not determined in accordance with GAAP in Canada or the United States. These measures do not have standardized meanings and may not be comparable to similar measures presented by other trusts or corporations. Measures such as funds generated from operations, distributable cash, distributable cash per trust unit, payout ratio and operating netbacks do not have standardized meanings prescribed by GAAP. We discuss these measures because we believe that they facilitate the understanding of the results of our operations and financial position.

CONVERSION AND CURRENCY

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

PENGROWTH 2006 | 63

Management’s Discussion
and Analysis

YEAR 2006 OVERVIEW

2006 was a very strong year for Pengrowth. During the year, Pengrowth enjoyed success on two fronts. Firstly, our internal drilling and development activities replaced the reserves depleted through production in the year, a significant achievement for Pengrowth. Secondly, Pengrowth completed two significant value-adding acquisitions, including the business combination with Esprit Energy Trust (Esprit Trust) and the acquisition of oil and natural gas assets in the Carson Creek area of Alberta (Carson Creek). A $103.8 million deposit was made late in 2006 on the acquisition of Canadian oil and natural gas producing properties from four subsidiaries of Burlington Resources Limited, a subsidiary of ConocoPhillips (the CP Properties).

At the close of the year, Pengrowth had a balanced portfolio of high-quality oil and natural gas properties with a large inventory of development opportunities.

HIGHLIGHTS

•		Oil and gas sales increased five percent to $1.2 billion dollars in 2006 reflecting higher volumes produced during the year, partially offset by lower average realized prices. In the fourth quarter, oil and gas sales were $351 million, an increase of 22 percent from the third quarter and virtually unchanged from the same quarter in 2005.
•		Production for 2006 averaged 62,821 barrels of oil equivalent (boe) per day, a six percent increase over 2005. Fourth quarter production averaged 77,614 boe per day, up 33 percent from the third quarter and 26 percent from the fourth quarter in 2005. The higher production levels reflect volumes added through the Carson Creek and Esprit Trust acquisitions and through ongoing development activities.
•		Distributable cash totaled $576 million in 2006 and $140 million in the fourth quarter. This represents a decrease of five percent from 2005 and one percent from the previous quarter. The decreases are mainly as a result of higher operating, royalty, administrative and interest costs incurred. The 26 percent decrease in the fourth quarter of 2006 from the fourth quarter in 2005 is primarily due to higher production volumes which were largely offset by lower commodity prices, higher operating, royalty, administrative and interest costs incurred.
•		Distributions remained stable during the fourth quarter and for the full year of 2006, at $0.25 per unit per month. For the full year, distributions of $3.00 per unit or $559 million were paid or declared to unitholders, an increase of 25 percent from the previous year.
•		In 2006, Pengrowth paid out or declared 97 percent of its distributable cash as distributions to unitholders and 132 percent in the fourth quarter. The payout ratio in the fourth quarter reflects distributions paid out or declared on units issued for the acquisition of Esprit Trust and for the acquisition of the CP Properties. However, due to the usual delays in receiving cash flow from production as well as the early 2007 closing of the CP Properties acquisition, the corresponding cash flow is not reflected in operating results.
•		During 2006, Pengrowth issued $1.9 billion in equity to fund strategic acquisitions announced in 2006. This included the acquisition of the Carson Creek assets, the business combination with Esprit Trust and most recently, the acquisition of the CP Properties where $461 million in equity was raised at the end of 2006 and the acquisition was completed in early 2007.

64 | PENGROWTH 2006

Management’s Discussion
and Analysis

•		Net income decreased almost 20 percent for 2006 from 2005 as a result of higher operating expenses, royalties and depletion and depreciation. Net income decreased approximately 97 percent in the fourth quarter of 2006 compared to the fourth quarter of 2005 primarily due to higher depletion and depreciation expenses, lower commodity prices, higher operating, royalty, administrative and interest costs incurred, partly offset by higher production volumes.
•		During the year, Pengrowth’s average realized price was $52.88 per boe (after hedging) compared to an average price of $53.02 per boe in 2005. A decrease in natural gas prices during the year was largely offset by a combination of higher oil and natural gas liquids prices and lower hedging losses. For the fourth quarter, average realized prices were $49.24 per boe (after hedging) down eight percent from the third quarter and 21 percent from the same quarter last year. These decreases reflect a lower commodity price environment for oil and natural gas in the fourth quarter of 2006.
•		Operating netbacks (after hedging) decreased nine percent in 2006 to $29.59 per boe, largely driven by higher operating and royalty costs. For the fourth quarter, operating netbacks were $24.17 per boe down from the previous quarter and fourth quarter of 2005 by 22 percent and 38 percent, respectively. The fourth quarter netbacks were lower largely due to lower realized prices and higher operating costs.
•		Pengrowth’s development capital in 2006 totaled $301 million, an increase of 71 percent from the previous year. This year’s capital program was one of Pengrowth’s most successful and resulted in reserve replacement of 99 percent on a proved plus probable basis. Development capital for the fourth quarter was $122 million compared to $57 million in the third quarter and $60 million in the fourth quarter of 2005. During the year, Pengrowth participated in 298 gross (162.9 net) wells with a 96 percent success rate.
•		On July 27, 2006 Pengrowth consolidated its Class A trust units and Class B trust units into one class of trust units. The Class A trust units were delisted from the Toronto Stock Exchange and converted into Class B trust units (with the exception of Class A trust units held by residents of Canada who elected to retain their Class A trust units), the Class B trust units were renamed as “trust units” and their trading symbol was changed from PGF.B to PGF.UN.
•		On March 30, 2006, Pengrowth closed the acquisition of an additional working interest in the Dunvegan Unit as well as some minor oil and gas properties in central Alberta for approximately $48 million.
•		On January 12, 2006, Pengrowth divested non-core oil and gas properties for consideration of $22 million of cash, prior to adjustments, and approximately eight million shares in Monterey Exploration Ltd. (Monterey). Pengrowth holds approximately 34 percent of the common shares of Monterey.

PENGROWTH 2006 | 65

SUMMARY OF FINANCIAL AND OPERATING RESULTS

			Three Months ended December 31														Twelve Months ended December 31
(thousands, except per unit amounts)			2006					2005				% Change					2006					2005				% Change
INCOME STATEMENT
Oil and gas sales			$	350,908				$	353,923				(1	)			$	1,214,093				$	1,151,510				5
Net income			$	3,310				$	116,663				(97	)			$	262,303				$	326,326				(20	)
Net income per trust unit			$	0.01				$	0.73				(99	)			$	1.49				$	2.08				(28	)
CASH FLOW
Cash flows from operating activities			$	91,237				$	196,588				(54	)			$	554,368				$	618,070				(10	)
Cash flows from operating activities per trust unit			$	0.41				$	1.23				(67	)			$	3.15				$	3.93				(20	)
Distributable cash*			$	140,405				$	189,379				(26	)			$	575,884				$	608,217				(5	)
Distributable cash per trust unit*			$	0.64				$	1.19				(46	)			$	3.27				$	3.87				(16	)
Distributions paid or declared			$	185,651				$	119,858				55				$	559,063				$	445,977				25
Distributions paid or declared per trust unit			$	0.75				$	0.75				—				$	3.00				$	2.82				6
Payout ratio*				132	%				63	%								97	%				73	%
Capital expenditures			$	121,781				$	60,093				103				$	300,809				$	175,693				71
Capital expenditures per trust unit			$	0.55				$	0.38				45				$	1.71				$	1.12				53
Weighted average number of trust units outstanding				220,734					159,528				38					175,871					157,127				12
BALANCE SHEET
Working capital																	$	(149,937	)			$	(112,205	)			34
Property, plant and equipment																	$	3,741,602				$	2,067,988				81
Long term debt																	$	604,200				$	368,089				64
Trust unitholders’ equity																	$	3,049,677				$	1,475,996				107
Trust unitholders’ equity per trust unit																	$	12.50				$	9.23				35
Number of trust units outstanding at year end																		244,017					159,864				53
DAILY PRODUCTION
Crude oil (bbls)				25,000					21,179				18					21,821					20,799				5
Heavy oil (bbls)				4,695					5,410				(13	)				4,964					5,623				(12	)
Natural gas (mcf)				234,050					168,862				39					175,578					161,056				9
Natural gas liquids (bbls)				8,910					6,710				33					6,774					6,093				11
Total production (boe)				77,614					61,442				26					62,821					59,357				6
TOTAL PRODUCTION (mboe)				7,141					5,653				26					22,930					21,665				6
PRODUCTION PROFILE
Crude oil				32	%				34	%								35	%				35	%
Heavy oil				6	%				9	%								8	%				10	%
Natural gas				50	%				46	%								46	%				45	%
Natural gas liquids				12	%				11	%								11	%				10	%
AVERAGE REALIZED PRICES
(after hedging)
Crude oil (per bbl)			$	60.35				$	59.40				2				$	66.85				$	58.59				14
Heavy oil (per bbl)			$	37.61				$	31.77				18				$	42.26				$	33.32				27
Natural gas (per mcf)			$	7.12				$	11.97				(41	)			$	7.22				$	8.76				(18	)
Natural gas liquids (per bbl)			$	52.69				$	58.46				(10	)			$	57.11				$	54.22				5
Average realized price per boe			$	49.24				$	62.55				(21	)			$	52.88				$	53.02				—
PROVED PLUS PROBABLE RESERVES
Crude oil (mbbls)																		112,388					98,684				14
Heavy oil (mbbls)																		18,336					15,790				16
Natural gas (bcf)																		827					516				60
Natural gas liquids (mbbls)																		29,142					18,985				54
Total oil equivalent (mboe)																		297,774					219,396				36

*		See the section entitled “Non-GAAP Financial Measures”. Prior year restated to conform to presentation adopted in current year.

66 | PENGROWTH 2006

Management’s Discussion
and Analysis

RESULTS OF OPERATIONS

PRODUCTION

Average daily production increased six percent in 2006, compared to 2005 and 33 percent in the fourth quarter of 2006 from the third quarter of 2006. This increase is attributable primarily to the Carson Creek and Esprit Trust acquisitions which were completed late in the third quarter and in the fourth quarter of 2006, respectively and contributions from ongoing development activities.

At this time, Pengrowth anticipates 2007 full year production of 83,000 to 87,500 boe per day. This estimate incorporates production from the CP properties acquisition disclosed in the Subsequent Events section of the MD&A. It also includes expected divestitures during the first half of 2007 of approximately 7,700 boe per day of current production. The above estimate excludes the impact from any future acquisitions, if they were to occur.

Daily Production

			Three months ended														Twelve months ended
			Dec 31, 2006					Sept 30, 2006				Dec 31, 2005					Dec 31, 2006					Dec 31, 2005
Light crude oil (bbls)				25,000					20,651				21,179					21,821					20,799
Heavy oil (bbls)				4,695					5,272				5,410					4,964					5,623
Natural gas (mcf)				234,050					158,757				168,862					175,578					161,056
Natural gas liquids (bbls)				8,910					5,961				6,710					6,774					6,093
Total boe per day				77,614					58,344				61,442					62,821					59,357

Light crude oil production volumes increased five percent year-over-year, 21 percent in the fourth quarter of 2006 compared to the third quarter and 18 percent when compared to the fourth quarter of 2005. The additional volumes from the Esprit Trust and Carson Creek acquisitions had a positive impact on production that more than offset natural production declines.

Heavy oil production decreased 12 percent year-over-year and 13 percent when comparing the fourth quarter of 2006 to the same quarter of 2005 due to natural production declines. Production was temporarily shut-in during the fourth quarter of 2006 at Tangleflags to facilitate a new drilling program and natural production declines were responsible for the 11 percent decrease in the fourth quarter of 2006 compared to the third quarter of 2006.

Natural gas production increased nine percent year-over-year. Additional production volumes from acquisitions, development activities, particularly at Prespatou, Princess and Cutbank/Tupper and increased gas sales at Judy Creek due to lower gas solvent utilization, combined to more than offset the Monterey divestiture and the operational downtime at the Sable Offshore Energy Project (SOEP) during the second and fourth quarters of 2006. The 47 percent increase in volumes in the fourth quarter of 2006 compared to the third quarter of 2006 is due to acquisitions and the drilling results from the Cutbank/Tupper area which more than offset the downtime at SOEP for the compression program. The 39 percent increase in production volumes for the fourth quarter of 2006 compared to the same period of 2005 was due to acquisitions, drilling results from the Cutbank/Tupper area which more than offset the downtime at SOEP in 2006, the Monterey divestiture and natural production declines.

PENGROWTH 2006 | 67

Management’s Discussion
and Analysis

Natural gas liquids (NGLs) production increased 11 percent year-over-year primarily due to acquisitions. Production volumes nearly doubled in the fourth quarter of 2006 in comparison to the third quarter of 2006 due to acquisitions and additional condensate at SOEP partially offset by natural production declines. The 33 percent increase in production volumes for the fourth quarter of 2006 compared to the same period of 2005 was due to acquisitions, which more than offset the Monterey divestiture and natural production declines.

PRICING AND COMMODITY PRICE HEDGING

On a year-over-year basis, the nearly 17 percent increase in U.S. based prices for North American crude oil and improved differentials for heavy oil during 2006 were partially offset by the negative impact of lower gas prices.

AVERAGE REALIZED PRICES

			Three months ended														Twelve months ended
(Cdn$)			Dec 31, 2006					Sept 30, 2006				Dec 31, 2005					Dec 31, 2006					Dec 31, 2005
Light crude oil (per bbl)				60.94					75.53				67.00					68.83					65.47
after hedging				60.35					72.61				59.40					66.85					58.59
Heavy oil (per bbl)				37.61					51.47				31.77					42.26					33.32
Natural gas (per mcf)				6.82					6.22				12.80					7.08					8.99
after hedging				7.12					6.29				11.97					7.22					8.76
Natural gas liquids (per bbl)				52.69					60.76				58.46					57.11					54.22
Total per boe				48.52					54.51				67.43					53.18					56.06
after hedging				49.24					53.67				62.55					52.88					53.02
Benchmark prices
WTI oil (U.S. $ per bbl)				60.17					70.54				60.05					66.25					56.70
AECO spot gas (Cdn $ per gj)				6.36					5.72				11.08					6.70					8.04
NYMEX gas (U.S. $ per mmbtu)				6.56					6.66				12.97					7.24					8.62
Currency (U.S. $ per Cdn $)				0.88					0.89				0.85					0.88					0.83

As part of our financial management strategy, Pengrowth uses forward price swap and option contracts to manage its exposure to commodity price fluctuations, to provide a measure of stability to monthly cash distributions and to partially secure returns on significant new acquisitions. Pengrowth has committed approximately 40 percent of its production to commodity price contracts in 2007.

HEDGING LOSSES (GAINS)

($ millions)			Three months ended														Twelve months ended
Realized			Dec 31, 2006					Sept 30, 2006				Dec 31, 2005					Dec 31, 2006					Dec 31, 2005
Light crude oil				1.4					5.5				14.8					15.8					52.2
Light crude oil ($ per bbl)				0.59					2.92				7.60					1.98					6.88
Natural gas				(6.5	)				(1.0	)			12.9					(8.8	)				13.6
Natural gas ($ per mcf)				(0.30	)				(0.07	)			0.83					(0.14	)				0.23
Combined				(5.1	)				4.5				27.7					7.0					65.8
Combined ($ per boe)				(0.72	)				0.84				4.88					0.30					3.04

68 | PENGROWTH 2006

Management’s Discussion
and Analysis

Effective May 1, 2006, Pengrowth no longer designates new commodity price contracts as hedges. Pengrowth has recognized any changes to the fair value of commodity contracts entered into after May 1, 2006 on the income statement.

Commodity price contracts in place at December 31, 2006 are detailed in Note 20 to the financial statements. At December 31, 2006, the mark-to-market value of the outstanding commodity contracts represented an unrealized potential gain of $37.1 million, which includes a $26.5 million gain on a year to date basis that has been recognized on the income statement. The $26.5 million unrealized gain is a non-cash item and is not reflected in oil and gas sales. The balance of the gain of $10.6 million was capitalized as part of the purchase price allocation for Esprit Trust. Compared to December 31, 2005, the mark-to-market value of the commodity contracts represented a potential loss of $18.4 million, none of which was recognized on the income statement at that time.

In conjunction with an acquisition, which closed in 2004, Pengrowth assumed certain fixed price natural gas sales contracts and firm pipeline demand charge contracts. Under the fixed price natural gas sales contracts, Pengrowth is obligated to sell 3,886 mmbtu per day until April 30, 2009 at an average remaining contract price of Cdn $2.34 per mmbtu. As required by Canadian 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, 2006 of $12.9 million for the contracts will continue to be drawn down and recognized in income as the contracts are settled. As this is a non-cash component of income, it is not included in the calculation of distributable cash. As at December 31, 2006, Pengrowth would be required to pay $17.0 million to terminate the fixed price physical sales contract. This amount is not included above in hedging losses (gains).

OIL AND GAS SALES — CONTRIBUTION ANALYSIS

($ millions)			Three months ended																										Twelve months ended
			Dec. 31,				% of					Sept. 30,				% of				Dec. 31,				% of					Dec 31,				% of					Dec. 31,				% of
Sales Revenue			2006				total					2006				total				2005				total					2006				total					2005				total
Light crude oil				138.8				40					137.9				48				115.7				33					532.4				44					444.8				39
Natural gas				153.3				44					91.9				32				186.0				53					462.4				38					514.9				45
Natural gas liquids				43.2				12					33.3				11				36.1				10					141.2				12					120.6				10
Heavy oil				16.3				4					24.9				9				15.8				4					76.6				6					68.4				6
Brokered sales/sulphur				(0.7	)			—					(0.2	)			—				0.3				—					1.5				—					2.8				—
Total oil and gas sales				350.9									287.8								353.9									1,214.1									1,151.5

OIL AND GAS SALES — PRICE AND VOLUME ANALYSIS

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

($ millions)			Light oil				Natural gas				NGL				Heavy oil				Other				Total
Year ended December 31, 2005				444.8				514.9				120.6				68.4				2.8				1,151.5
Effect of change in product prices				26.8				(122.5	)			7.1				16.2				—				(72.4	)
Effect of change in sales volumes				24.4				47.6				13.5				(8.0	)			—				77.5
Effect of change in hedging losses/gains				36.4				22.4				—				—				—				58.8
Other				—				—				—				—				(1.3	)			(1.3	)
Year ended December 31, 2006				532.4				462.4				141.2				76.6				1.5				1,214.1

PENGROWTH 2006 | 69

Management’s Discussion
and Analysis

PROCESSING, INTEREST AND OTHER INCOME

			Three months ended														Twelve months ended
($ millions)			Dec 31, 2006					Sept 30, 2006				Dec 31, 2005					Dec 31, 2006					Dec 31, 2005
Processing, interest & other income				6.2					4.7				4.0					18.8					17.7
$  per boe				0.86					0.88				0.71					0.82					0.82

Processing, interest and other income is primarily derived from fees charged for processing and gathering third party gas, road use and oil and water processing. This income represents the partial recovery of operating expenses reported separately.

ROYALTIES

			Three months ended														Twelve months ended
($ millions)			Dec 31, 2006					Sept 30, 2006				Dec 31, 2005					Dec 31, 2006					Dec 31, 2005
Royalty expense				73.1					57.8				68.0					241.5					213.9
$  per boe				10.23					10.77				12.03					10.53					9.87
Royalties as a percent of sales				20.8	%				20.1	%			19.2	%				19.9	%				18.6	%

Royalties include Crown, freehold and overriding royalties as well as mineral taxes. The increase in the royalty rate for 2006 is primarily due to the change in royalties at SOEP. SOEP has a five tier royalty regime based on gross revenue for the first three tiers and net revenue for the final two tiers. During 2005, the royalty obligation at SOEP was approximately two percent of gross revenue (Tier II) but progressed to five percent of gross revenue (Tier III) starting with October 2005 production. The increase to five percent was recognized in March 2006 when the 2005 royalty submission was filed. Commencing with March 2006 production, Pengrowth forecasted, the royalty obligation to be in Tier IV which is 30 percent of net revenue (gross revenue less certain capital and other specified costs associated with producing the gas and natural gas liquids).

The outlook for 2007 is approximately 21 percent royalty as a percentage of Pengrowth’s sales.

OPERATING EXPENSES

			Three months ended														Twelve months ended
($ millions)			Dec 31, 2006					Sept 30, 2006				Dec 31, 2005					Dec 31, 2006					Dec 31, 2005
Operating expenses				99.7					58.8				61.2					270.5					218.1
$  per boe				13.97					10.94				10.83					11.80					10.07

Operating expenses increased $41 million or $3.03 per boe in the fourth quarter of 2006 in comparison to the third quarter of 2006. Increased utility costs and higher maintenance ($12 million), the Esprit Trust ($18 million or $10.96 per boe) and Carson Creek ($6 million or $16.54 per boe) acquisitions were the most significant reasons for the increase in expenses. Carson Creek has operating costs per boe that are generally higher than Pengrowth’s average due to its high utility requirements, but are expected to improve as utility costs decline and operating synergies are captured. Operating expenses increased almost $39 million in the fourth quarter of 2006 in comparison to the fourth quarter of 2005. Increased utility costs and higher maintenance ($9 million), the Esprit Trust ($18 million) and Carson Creek ($7 million) acquisitions were the most significant reasons for the increase in operating expenses. In

70 | PENGROWTH 2006

Management’s Discussion
and Analysis

comparing year-over-year, operating expenses increased by approximately $53 million. Increased utility costs and higher maintenance ($17 million), the Esprit Trust ($18 million) and Carson Creek ($7 million) acquisitions and higher salaries and employee retention programs were the primary reasons for the increase.

Operating expenses include costs incurred to earn processing and other income which are reported separately.

Pengrowth expects total operating expenses for 2007 to increase when compared to 2006 and are anticipated to total approximately $405 million or $13.00 per boe. Pengrowth expects to spend approximately $14.5 million per year, prior to inflation, excluding contributions to remediation trust funds, over the next ten years on remediation and abandonment.

TRANSPORTATION COSTS

			Three months ended														Twelve months ended
($ millions)			Dec 31, 2006					Sept 30, 2006				Dec 31, 2005					Dec 31, 2006					Dec 31, 2005
Light oil transportation				0.5					0.5				0.5					2.0					2.2
$  per bbl				0.21					0.26				0.27					0.25					0.29
Natural gas transportation				1.8					1.3				1.8					5.6					5.7
$  per mcf				0.09					0.09				0.12					0.09					0.10

Pengrowth incurs transportation costs for its product once the product enters a feeder or main pipeline to the title transfer point. The transportation cost is dependant upon industry rates and distance the product flows on the pipeline prior to changing ownership or custody. Pengrowth has the option to sell some of its natural gas directly to premium markets outside of Alberta by incurring additional transportation costs. Prior to December 31, 2006, Pengrowth sold most of its natural gas without incurring significant additional transportation costs. Similarly, Pengrowth has elected to sell approximately 75 percent of its crude oil at market points beyond the wellhead, but at the first major trading point, requiring minimal transportation costs.

AMORTIZATION OF INJECTANTS FOR MISCIBLE FLOODS

			Three months ended														Twelve months ended
($ millions)			Dec 31, 2006					Sept 30, 2006				Dec 31, 2005					Dec 31, 2006					Dec 31, 2005
Purchased and capitalized				9.4					7.9				14.5					34.6					34.7
Amortization				9.3					8.8				7.1					34.6					24.4

The cost of injectants (primarily natural gas and ethane) purchased for injection in miscible flood programs is amortized equally over the period of expected future economic benefit. Prior to 2005, the expected future economic benefit from injection was estimated at 30 months, based on the results of previous flood patterns. Commencing in 2005, the response period for additional new patterns being developed is expected to be somewhat shorter relative to the historical miscible patterns in the project. Accordingly, the cost of injectants purchased in 2005 and 2006 is amortized over a 24 month period while costs incurred for the purchase of injectants in prior periods is amortized over 30 months. As of December 31, 2006, 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. The cost of purchased injectants decreased minimally year-over year as the increased injectant volume of natural gas liquids offset the lower price paid for gas volumes injected.

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Management’s Discussion
and Analysis

OPERATING NET BACKS

There is no standardized measure of operating netbacks and therefore operating netbacks, as presented below may not be comparable to similar measures presented by other companies. Certain assumptions have been made in allocating operating expenses, other production income, other income and royalty injection credits between light crude, heavy oil, natural gas and natural gas liquids production.

Pengrowth recorded an operating netback of $29.59 per boe (after hedging) in 2006 compared to $32.54 per boe (after hedging) in 2005, mainly due to higher operating and royalty expenses.

			Three months ended														Twelve months ended
Combined Netbacks ($ per boe)			Dec 31, 2006					Sept 30, 2006				Dec 31, 2005					Dec 31, 2006					Dec 31, 2005
Sales price				49.24					53.67				62.55					52.88					53.02
Other production income				(0.09	)				(0.06	)			0.06					0.06					0.13
				49.15					53.61				62.61					52.94					53.15
Processing, interest and other income				0.86					0.88				0.71					0.82					0.82
Royalties				(10.23	)				(10.77	)			(12.02	)				(10.53	)				(9.87	)
Operating expenses				(13.97	)				(10.94	)			(10.83	)				(11.80	)				(10.07	)
Transportation costs				(0.33	)				(0.33	)			(0.41	)				(0.33	)				(0.36	)
Amortization of injectants				(1.31	)				(1.63	)			(1.25	)				(1.51	)				(1.13	)
Operating netback				24.17					30.82				38.81					29.59					32.54

			Three months ended														Twelve months ended
Light Crude Netbacks ($ per bbl)			Dec 31, 2006					Sept 30, 2006				Dec 31, 2005					Dec 31, 2006					Dec 31, 2005
Sales price				60.35					72.61				59.40					66.85					58.59
Other production income				(0.31	)				(0.19	)			0.17					0.13					0.37
				60.04					72.42				59.57					66.98					58.96
Processing, interest and other income				0.64					0.60				0.34					0.58					0.47
Royalties				(11.65	)				(12.19	)			(6.47	)				(10.63	)				(8.64	)
Operating expenses				(17.95	)				(13.20	)			(14.32	)				(13.78	)				(12.28	)
Transportation costs				(0.21	)				(0.26	)			(0.27	)				(0.25	)				(0.29	)
Amortization of injectants				(4.08	)				(4.61	)			(3.63	)				(4.35	)				(3.21	)
Operating netback				26.79					42.76				35.22					38.55					35.01

			Three months ended														Twelve months ended
Heavy Oil Netbacks ($ per bbl)			Dec 31, 2006					Sept 30, 2006				Dec 31, 2005					Dec 31, 2006					Dec 31, 2005
Sales price				37.61					51.47				31.77					42.26					33.32
Processing, interest and other income				0.80					0.38				0.74					0.43					0.36
Royalties				(5.44	)				(6.27	)			(2.98	)				(4.53	)				(4.53	)
Operating expenses				(14.06	)				(16.28	)			(11.60	)				(15.16	)				(15.65	)
Operating netback				18.91					29.30				17.93					23.00					13.50

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			Three months ended														Twelve months ended
Natural Gas Netbacks ($ per mcf)			Dec 31, 2006					Sept 30, 2006				Dec 31, 2005					Dec 31, 2006					Dec 31, 2005
Sales price				7.12					6.29				11.97					7.22					8.76
Other production income				—					—				—					0.01					—
				7.12					6.29				11.97					7.23					8.76
Processing, interest and other income				0.20					0.23				0.19					0.21					0.23
Royalties				(1.41	)				(1.34	)			(2.62	)				(1.54	)				(1.70	)
Operating expenses				(1.90	)				(1.38	)			(1.38	)				(1.65	)				(1.24	)
Transportation costs				(0.09	)				(0.09	)			(0.12	)				(0.09	)				(0.10	)
Operating netback				3.92					3.71				8.04					4.16					5.95

			Three months ended														Twelve months ended
NGLs Netbacks ($ per bbl)			Dec 31, 2006					Sept 30, 2006				Dec 31, 2005					Dec 31, 2006					Dec 31, 2005
Sales price				52.69					60.76				58.46					57.11					54.22
Royalties				(16.61	)				(21.84	)			(21.29	)				(20.17	)				(17.66	)
Operating expenses				(14.00	)				(10.26	)			(10.05	)				(11.12	)				(9.04	)
Operating netback				22.08					28.66				27.12					25.82					27.52

INTEREST

Interest expense increased approximately 49 percent to $32.1 million in 2006 from $21.6 million in 2005, reflecting a higher average debt level combined with higher interest rates and higher standby fees in 2006. Approximately 39 percent of Pengrowth’s outstanding long term debt as at December 31, 2006 incurs interest expense payable in U.S. dollars and therefore remains subject to fluctuations in the U.S. dollar exchange rate.

GENERAL AND ADMINISTRATIVE (G&A)

			Three months ended														Twelve months ended
($ millions)			Dec 31, 2006					Sept 30, 2006				Dec 31, 2005					Dec 31, 2006					Dec 31, 2005
Cash G&A expense				11.7					6.8				7.7					34.1					27.4
$  per boe				1.63					1.27				1.36					1.49					1.27
Non-cash G&A expense				(0.3	)				0.9				0.8					2.5					2.9
$  per boe				(0.04	)				0.17				0.14					0.11					0.13
Total G&A				11.4					7.7				8.5					36.6					30.3
Total G&A ($  per boe)				1.59					1.44				1.50					1.60					1.40

The cash component of G&A for the fourth quarter of 2006 compared to the third quarter of 2006 increased $4.9 million due to the increase in salaries resulting from the Esprit Trust business combination and employee retention programs ($1.8 million), increased office rent ($0.7 million), year-end reserves report ($0.6 million) and $1.0 million for estimated reimbursement of G&A expenses incurred by the Manager, pursuant to the management agreement. Employee retention programs and additional expenses relating to the Esprit Trust business combination were the main reasons for the $6.3 million increase year-over-year.

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Management’s Discussion
and Analysis

MANAGEMENT FEES

			Three months ended														Twelve months ended
($ millions)			Dec 31, 2006					Sept 30, 2006				Dec 31, 2005					Dec 31, 2006					Dec 31, 2005
Management Fee				0.9					0.8				2.2					7.0					9.1
Performance Fee				(1.6	)				2.2				2.2					2.9					6.9
Total				(0.7	)				3.0				4.4					9.9					16.0
Total ($  per boe)				(0.09	)				0.56				0.77					0.43					0.74

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

RELATED PARTY TRANSACTIONS

Details of related party transactions incurred in 2006 and 2005 are provided in Note 18 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 2006 also include $1.0 million (2005 — $0.7 million) paid to a law firm controlled by the Vice President and Corporate Secretary of the Corporation, Charles V. Selby. These fees are paid in respect of legal and advisory services provided by the Vice President and Corporate Secretary of the Corporation. Mr. Selby has been granted 12,507 trust unit rights and 2,085 deferred entitlement units in 2006.

On January 12, 2006, Pengrowth divested non-core oil and gas properties for consideration of $22 million of cash, prior to adjustments, and approximately eight million shares in Monterey. Pengrowth holds approximately 34 percent of the common shares of Monterey. In December 2006, two senior officers of the Corporation directly and indirectly purchased a total of 30,000 shares of Monterey for a total consideration of $150,000 in a new share offering marketed by an independent broker.

TAXES

In determining its taxable income, the Corporation deducts payments made to the Trust, effectively transferring the income tax liability to unitholders thus reducing the Corporation’s taxable income to nil. Under the Corporation’s current distribution policy, at the discretion of the Board, funds can be withheld from distributable cash to fund future capital expenditures, repay debt or other corporate purposes. In the event withholdings increased sufficiently, 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 potential changes to the corporate structure. As a result, none of the Trust’s subsidiaries anticipate the payment of any cash income taxes in the foreseeable future.

74 | PENGROWTH 2006

Management’s Discussion
and Analysis

Effective January 1, 2006, the federal government eliminated the Large Corporations tax. Large Corporations tax in 2005 amounted to $2.2 million.

The acquisition of Esprit Trust resulted in Pengrowth recording an additional future tax liability of $110.6 million. Additionally, the acquisition of Carson Creek resulted in an additional future tax liability of $121.4 million. In 2005, the acquisition of Crispin Energy Inc. (Crispin) resulted in Pengrowth recording an additional tax liability of $22.2 million. The future tax liabilities represent 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 reduced the future tax liability by $14.3 million to $327.8 million.

On October 31, 2006, the Minister of Finance (Canada) announced tax proposals which, if enacted, would modify the taxation of certain flow-through entities including mutual fund trusts and their unitholders (the “October 31 Proposals”). The October 31 Proposals will apply to a specified investment flow-through (SIFT) trust and will apply a tax at the trust level on distributions of certain income from such a SIFT trust at a rate of tax comparable to the combined federal and provincial corporate tax rate. These distributions will be treated as dividends to the trust unitholders.

On December 21, 2006, the Department of Finance (Canada) released draft legislation to implement the October 31 Proposals discussed above. The draft legislation appears to be generally consistent with details included in the October 31 announcement.

It is expected that Pengrowth will be characterized as a SIFT trust and as a result would be subject to the October 31 Proposals. The October 31 Proposals are to apply commencing January 1, 2007 for all SIFT trusts that begin to be publicly traded after October 31, 2006 and commencing January 1, 2011 for all SIFT trusts that were publicly traded on or before October 31, 2006. Subject to the qualification below regarding the possible loss of the four year grandfathering period in the case of undue expansion, it is expected that Pengrowth will not be subject to the October 31 Proposals until January 1, 2011.

Under the existing provisions of the Tax Act, Pengrowth can generally deduct in computing its income for a taxation year any amount of income that it distributes to unitholders in the year and, on that basis, Pengrowth is generally not liable for any material amount of tax.

Pursuant to the October 31 Proposals, commencing January 1, 2011, (subject to the qualification below regarding the possible loss of the four year grandfathering period in the case of undue expansion), Pengrowth will not be able to deduct certain portions of its distributed income (referred to as specified income). Pengrowth will become subject to a distribution tax on this specified income at a special rate estimated to be 31.5 percent.

Pengrowth may lose the benefit of the four year grandfathering period if Pengrowth exceeds the limits on the issuance of new trust units and convertible debt that constitute normal growth during the grandfathering period (subject to certain exceptions). The normal growth limits are calculated as a percentage of Pengrowth’s market capitalization of approximately $4.8 billion on October 31, 2006 as follows: 40 percent for the period November 1, 2006 to December 31, 2007, 20 percent for each of 2008, 2009 and 2010. Unused portions may be carried forward until December 31, 2010. It is anticipated that the issuance of 24,265,000 trust units on December 8, 2006 for gross proceeds of $461 million will constitute a portion of the 40 percent normal growth limit for the period ending on December 31, 2007.

PENGROWTH 2006 | 75

Management’s Discussion
and Analysis

Pursuant to the draft legislation, the distribution tax will only apply in respect of distributions of income and will not apply to returns of capital. If the October 31 Proposals are implemented, the trust would be required to recognize, on a prospective basis, future income taxes on temporary differences in Trust.

If the October 31 Proposals are implemented, it is expected that the imposition of tax at the Pengrowth trust level under the October 31 Proposals will materially reduce the amount of cash available for distributions to unitholders.

FOREIGN CURRENCY GAINS AND LOSSES

Pengrowth recorded an immaterial net foreign exchange loss in 2006, compared to a foreign exchange gain of $7.0 million in 2005. Included in the 2006 loss is a $0.5 million unrealized foreign exchange loss compared to a $7.8 million unrealized foreign exchange gain related to the translation of the U.S. dollar denominated debt using the closing exchange rate at the end of each year. 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 changes in the Canadian dollar relative to the U.S. dollar over the course of the year, a foreign exchange gain 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 portion of its long term debt in U.S. dollars as a natural hedge against changes in the 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 16 to the financial statements for further detail).

Pengrowth has mitigated the foreign exchange risk on the interest and principal payments related to the U.K. denominated notes (see Note 10 of the financial statements) by using foreign exchange swaps. As a result of applying hedge accounting to this transaction, an unrealized foreign exchange loss of $13.6 million has been included in Other Assets as at December 31, 2006.

DEPLETION, DEPRECIATION AND ACCRETION

			Three months ended									Twelve months ended
($ millions)			Dec 31, 2006					Sept 30, 2006				Dec 31, 2005					Dec 31, 2006					Dec 31, 2005
Depletion and Depreciation				129.2					83.5				71.4					351.6					285.0
$  per boe				18.09					15.56				12.63					15.33					13.15
Accretion				4.9					4.5				3.6					16.6					14.2
$  per boe				0.68					0.84				0.64					0.72					0.65

Depletion and depreciation of property, plant and equipment is provided on the unit of production method based on total proved reserves. The increase in 2006 rates for both depletion and depreciation and accretion is due to the inclusion of the property, plant and equipment from the Carson Creek and Esprit Trust acquisitions.

Pengrowth’s Asset Retirement Obligations (ARO) liability increases by the amount of accretion, which is a charge to net income as a result of the passage of time. The accretion expense is based on a credit adjusted risk-free rate of eight percent per year.

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

76 | PENGROWTH 2006

Management’s Discussion
and Analysis

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 2006.

ASSET RETIREMENT OBLIGATIONS

The total future ARO is 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 $255 million as at December 31, 2006 (2005 — $185 million), based on a total escalated future liability of $1,530 million (2005 — $1,041 million). These costs are expected to be incurred over 50 years with the majority of the costs incurred between 2035 and 2054. Pengrowth’s credit adjusted risk free rate of eight percent (2005 — eight percent) and an inflation rate of two percent (2005 — two percent) were used to calculate the net present value of the ARO.

REMEDIATION TRUST FUNDS & REMEDIATION AND ABANDONMENT EXPENSES

During 2006, Pengrowth contributed $3.2 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 $11.1 million at December 31, 2006.

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 2006, Pengrowth spent $9.1 million on abandonment and reclamation (2005 — $7.4 million). Pengrowth expects to spend approximately $14.5 million per year, prior to inflation, excluding contributions to remediation trust funds, over the next ten years on remediation and abandonment.

OTHER EXPENSES

On a year-over-year basis, other expenses increased $6.2 million primarily due to costs related to the consolidation of Class A and Class B trust units ($2.7 million) completed in July 2006 and one time legal fees from a predecessor company ($2.7 million).

GOODWILL

As at December 31, 2006, Pengrowth recorded goodwill of $598.3 million, an increase of $415.5 million from December 31, 2005. In accordance with Canadian GAAP, Pengrowth recorded goodwill of $129.7 million and $285.7 million upon the Carson Creek area acquisition and the Esprit Trust business combination, respectively, in 2006. 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 3 of the financial statements. Management has assessed goodwill for impairment and determined there is no impairment at December 31, 2006.

CAPITAL EXPENDITURES

During 2006, Pengrowth spent $300.8 million on development and optimization activities. This year’s capital program was one of Pengrowth’s most successful to date and resulted in the replacement of approximately 99 percent of production through internal development. The largest expenditures were at Judy Creek ($42.5 million), SOEP ($22.4 million), Weyburn ($20.2 million), Twining ($18.2 million), Bodo ($14.2 million), Three Hills Creek ($13.8 million), Quirk Creek ($13.0 million), West Pembina ($9.7 million), Olds ($8.5 million) and Prespatou ($6.6 million). Pengrowth engages in limited exploration activities and in 2006 most of the capital spent on development was directed towards increasing production and improving reserve recovery through infill drilling. An additional $1,449.3 million was incurred in 2006 to complete the Esprit Trust, Carson Creek, Dunvegan Unit and other acquisitions compared to $180.5 million to complete the Crispin and Swan Hills acquisitions in 2005.

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Management’s Discussion
and Analysis

WORKING CAPITAL

Working capital declined $37.7 million from a working capital deficiency of $112.2 million at December 31, 2005 to a working capital deficiency of $149.9 million as at December 31, 2006. Most of the increased working capital deficiency is attributable to an increase in accounts payable and accrued liabilities and distributions payable to unitholders, offset by an increase in accounts receivable as at December 31, 2006.

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 term credit facility until the distribution payment on January 15.

FINANCIAL RESOURCES AND LIQUIDITY

Pengrowth’s capitalization is as follows:

As at December 31
($ thousands)			2006					2005
Term credit facilities				257,000					35,000
Senior unsecured notes				347,200					333,089
Working capital deficit				140,563					77,638
Note payable				—					20,000
Bank indebtedness				9,374					14,567
Net debt excluding convertible debentures				754,137					480,294
Convertible debentures				75,127					—
Net debt including convertible debentures				829,264					480,294
Trust unitholders’ equity				3,049,677					1,475,996
Net debt excluding convertible debentures as a percentage of total book capitalization				19.8	%				24.6	%
Net debt including convertible debentures as a percentage of total book capitalization				21.4	%				24.6	%
Cash flow from operating activities				554,368					618,070
Net debt excluding convertible debentures to cash flow from operating activities				1.4					0.8
Net debt including convertible debentures to cash flow from operating activities				1.5					0.8

The $222 million increase in the term credit facilities as at December 31, 2006 from December 31, 2005 is primarily due to capital expenditures, acquisitions including assumed debt, deposit on the CP Properties acquisition, repayment of the SOEP note payable and redemption of convertible debentures all of which exceeds cash withheld, proceeds from the Monterey transaction and net proceeds from the equity offerings that closed September 28, 2006 and December 8, 2006.

PENGROWTH 2006 | 79

Management’s Discussion
and Analysis

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

At December 31, 2006, Pengrowth maintained a $950 million term credit facility and a $35 million demand operating line of credit. These facilities were reduced by drawings of $257 million and by $18 million in letters of credit outstanding at year end. Pengrowth remains well positioned to fund its 2007 development program and to take advantage of acquisition opportunities as they arise. At December 31, 2006, Pengrowth had approximately $700 million available to draw from its credit facilities.

Pengrowth does not have any off balance sheet financing arrangements.

Pengrowth’s U.S. $200 million senior unsecured notes, Pound sterling denominated 50 million senior unsecured notes, and the term credit facilities have certain financial covenants which may restrict the total amount of Pengrowth’s borrowings. The calculation for each ratio is based on specific definitions, is not in accordance with GAAP and cannot be readily replicated by referring to Pengrowth’s financial statements. The financial covenants are different between the term credit facilities and the senior unsecured notes and some of the covenants are summarized below:

1.

Total senior debt should not be greater than three times Earnings Before Income Taxes Depreciation and Amortization (EBITDA) for the last four fiscal quarters.

2.

Total debt should not be greater than 3.5 times EBITDA for the last four fiscal quarters.

3.

Total senior debt should be less than 50 percent of total book capitalization.

4.

EBITDA should not be less than four times interest expense.

In the event that Pengrowth enters into a significant acquisition, certain credit facility financial covenants are relaxed for two fiscal quarters after the close of the acquisition. Pengrowth may also make certain pro forma adjustments in calculating the financial covenant ratios.

The actual loan documents are filed on SEDAR as Other Material Contracts. As at December 31, 2006, Pengrowth was in compliance with all its financial covenants. Failing a financial covenant may result in one or more of Pengrowth’s loans being in default. In certain circumstances, being in default of one loan may result in other loans to also be in default. In the event that Pengrowth was not in compliance with any of the financial covenants in its credit facility or senior unsecured notes, Pengrowth would be in default of one or more of its loans and would have to repay the debt, refinance the debt or negotiate new terms with the debt holders and may have to suspend distributions to unitholders.

As a result of the October 2, 2006 business combination with Esprit Trust, Pengrowth assumed all of Esprit Trust’s 6.5 percent convertible unsecured subordinated debentures (the “debentures”). The debentures were originally issued on July 28, 2005 for a $100 million principal amount with interest paid semi-annually in arrears on June 30 and December 31 of each year. At October 2, 2006, $95.8 million principal amount of debentures was outstanding. Each $1,000 principal amount of debentures is convertible at the option of the holder at any time into fully paid Pengrowth trust units at a conversion price of $25.54 per trust unit. The debentures

80 | PENGROWTH 2006

Management’s Discussion
and Analysis

mature on December 31, 2010. After December 31, 2008, Pengrowth may elect to redeem all or a portion of the outstanding debentures at a price of $1,050 per debenture or $1,025 per debenture after December 31, 2009. Pursuant to a change of control provision in the Debenture Indenture, Pengrowth was required to make an offer to purchase all of the outstanding debentures at a price equal to 101 percent of the principal amount, plus any accrued and unpaid interest. The amount of accrued interest paid on the redemption was $0.6 million. On December 12, 2006, Pengrowth redeemed the tendered debentures for cash proceeds of $21.8 million (including accrued interest and offer premium). As at December 31, 2006, the principal amount of debentures outstanding was $74.7 million.

DISTRIBUTABLE CASH AND DISTRIBUTIONS

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

			Three months ended									Twelve months ended
($ thousands, except per trust unit amounts)			Dec 31, 2006					Sept 30, 2006				Dec 31, 2005					Dec 31, 2006					Dec 31, 2005
Cash flows from operating activities				91,237					179,971				196,588					554,368					618,070
Change in non-cash operating working capital				50,714					(37,028	)			(7,993	)				24,331					(9,833	)
Funds generated from operations				141,951					142,943				188,595					578,699					608,237
Change in remediation trust funds				(1,546	)				(599	)			784					(2,815	)				(20	)
Distributable cash (2)				140,405					142,344				189,379					575,884					608,217
Distributions paid or declared				185,651					132,513				119,858					559,063					445,977
Distributable cash per trust unit (2)				0.64					0.88				1.19					3.27					3.87
Distributions paid or declared per trust unit				0.75					0.75				0.75					3.00					2.82
Payout ratio (1) (2)				132	%				93	%			63	%				97	%				73	%