Pengrowth Energy Trust
NYSE : PGH
TSX : PGF.UN

Pengrowth Energy Trust
Pengrowth Corporation

Pengrowth Corporation

November 02, 2006 01:07 ET

Pengrowth Energy Trust Announces Third Quarter 2006 Results

CALGARY, ALBERTA--(CCNMatthews - Nov. 2, 2006) - Pengrowth Corporation, administrator of Pengrowth Energy Trust (TSX:PGF.UN) (NYSE:PGH) (collectively "Pengrowth"), is pleased to announce the interim unaudited operating and financial results for the three and nine month periods ended September 30, 2006.

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

During the quarter, Pengrowth generated $143.3 million ($0.89 per average trust unit outstanding) of distributable cash from operations and distributions to unitholders totaled $0.75 per trust unit. Pengrowth is committed to providing unitholders with stable distributions and expects to maintain the monthly distribution for the fourth quarter of 2006 up to and including the February 15, 2007 distribution at $0.25 per trust unit per month subject to Board approval and assuming the continuity of current market conditions.

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

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

Subsequent to quarter-end, Pengrowth also successfully completed the strategic business combination with Esprit Energy Trust, which closed on October 2, 2006. This combination capitalized on the opportunity to acquire long life natural gas assets in an environment of lower natural gas prices. As a result of the combination, Pengrowth acquired approximately 18,350 boe per day of current production, 71.7 million boe of proved plus probable oil and natural gas reserves and 250,000 net acres of undeveloped land, including shallow gas and coalbed methane potential.

President's Message

To our valued unitholders,

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

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

1. continuing to seek out high-quality acquisitions which target areas in which we already hold significant interests including large oil-in-place reservoirs, shallow gas properties with additional development potential and areas with coalbed methane prospects; and

2. to capitalize on organic growth opportunities including an increased concentration on exploiting our existing asset base, aggressively pursuing improved reserve recovery potential and enhancing operational efficiencies.

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

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

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

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

Subsequent to quarter-end, Pengrowth also successfully completed the strategic business combination with Esprit Energy Trust, which closed on October 2, 2006. This combination illustrated our commitment to capitalize on counter-cyclical acquisitions as evidenced by acquiring these long life natural gas assets in the current environment of lower natural gas prices. As a result of the combination, Pengrowth acquired approximately 18,350 boe per day of current production, 71.7 million boe of proved plus probable oil and natural gas reserves and 250,000 net acres of undeveloped land, including shallow gas and coalbed methane potential.

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

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

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

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

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

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

Pengrowth's high quality, long-life assets have provided the trust with a stable production profile that is reflected in the steady distribution provided to unitholders. Distributable cash generated from operations remained relatively flat in the third quarter at $143 million ($0.89 per average trust unit outstanding) compared with $149 million ($0.93 per trust unit) in the second quarter of 2006. Distributions to unitholders during the quarter totaled $0.75 per trust unit and we expect to maintain the monthly distribution for the fourth quarter of 2006 up to and including the February 15, 2007 distribution at $0.25 per trust unit per month subject to Board approval and assuming the continuity of current market conditions.

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

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

James S. Kinnear, Chairman, President and Chief Executive Officer

November 1, 2006



Summary of Financial and Operating Results

Three Months ended
September 30 %
(thousands, except per unit amounts) 2006 2005 Change
---------------------------------------------------------------------------
INCOME STATEMENT
Oil and gas sales $ 287,757 $ 304,484 -5%
Net income $ 82,542 $ 100,243 -16%
Net income per trust unit $ 0.51 $ 0.63 -17%
---------------------------------------------------------------------------
CASH FLOW
Cash flows from operating activities $ 174,294 $ 158,976 10%
Cash flows from operating activities
per trust unit $ 1.08 $ 1.00 8%

Distributable cash (1) $ 143,347 $ 162,009 -12%
Distributable cash per trust unit (1) $ 0.89 $ 1.02 -13%
Distributions paid or declared $ 132,513 $ 109,853 21%
Distributions paid or declared per
trust unit $ 0.75 $ 0.69 9%
Payout ratio (1) 92% 68% 24%

Development capital $ 56,774 $ 40,848 39%
Development capital per trust unit $ 0.35 $ 0.26 35%

Weighted average number of trust units
outstanding 161,502 158,789 2%
---------------------------------------------------------------------------
BALANCE SHEET
Working capital
Property, plant and equipment
Long term debt
Unitholders' equity
Unitholders' equity per trust unit

Number of trust units outstanding at
period end
---------------------------------------------------------------------------
DAILY PRODUCTION
Crude oil (barrels) 20,651 20,660 0%
Heavy oil (barrels) 5,272 5,405 -2%
Natural gas (mcf) 158,757 164,288 -3%
Natural gas liquids (barrels) 5,961 5,448 9%
Total production (boe) 58,344 58,894 -1%

TOTAL PRODUCTION (mboe) 5,368 5,418 -1%
---------------------------------------------------------------------------
PRODUCTION PROFILE
Crude oil 36% 35%
Heavy oil 9% 9%
Natural gas 45% 47%
Natural gas liquids 10% 9%
---------------------------------------------------------------------------
AVERAGE REALIZED PRICES (after hedging)
Crude oil (per barrel) $ 72.61 $ 63.95 14%
Heavy oil (per barrel) $ 51.47 $ 47.74 8%
Natural gas (per mcf) $ 6.29 $ 8.57 -27%
Natural gas liquids (per barrel) $ 60.76 $ 57.75 5%
Average realized price per boe $ 53.67 $ 56.07 -4%


Nine Months ended
September 30 %
(thousands, except per unit amounts) 2006 2005 Change
---------------------------------------------------------------------------
INCOME STATEMENT
Oil and gas sales $ 863,185 $ 797,587 8%
Net income $ 258,993 $ 209,663 24%
Net income per trust unit $ 1.61 $ 1.34 20%
---------------------------------------------------------------------------
CASH FLOW
Cash flows from operating activities $ 484,219 $ 421,482 15%
Cash flows from operating activities
per trust unit $ 3.01 $ 2.70 11%

Distributable cash (1) $ 436,604 $ 423,860 3%
Distributable cash per trust unit (1) $ 2.72 $ 2.71 0%
Distributions paid or declared $ 373,412 $ 326,119 15%
Distributions paid or declared per
trust unit $ 2.25 $ 2.07 9%
Payout ratio (1) 86% 77% 9%

Development capital $ 179,028 $ 115,600 55%
Development capital per trust unit $ 1.11 $ 0.74 50%

Weighted average number of trust units
outstanding 160,753 156,318 3%
---------------------------------------------------------------------------
BALANCE SHEET
Working capital $ (139,799) $ (77,528) 80%
Property, plant and equipment $ 2,556,802 $ 2,090,399 22%
Long term debt $ 459,910 $ 422,220 9%
Unitholders' equity $ 1,888,365 $ 1,467,859 29%
Unitholders' equity per trust unit $ 10.24 $ 9.22 11%

Number of trust units outstanding at
period end 184,459 159,263 16%
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DAILY PRODUCTION
Crude oil (barrels) 20,750 20,670 0%
Heavy oil (barrels) 5,054 5,695 -11%
Natural gas (mcf) 155,873 158,426 -2%
Natural gas liquids (barrels) 6,054 5,885 3%
Total production (boe) 57,836 58,654 -1%

TOTAL PRODUCTION (mboe) 15,789 16,013 -1%
---------------------------------------------------------------------------
PRODUCTION PROFILE
Crude oil 36% 35%
Heavy oil 9% 10%
Natural gas 45% 45%
Natural gas liquids 10% 10%
---------------------------------------------------------------------------
AVERAGE REALIZED PRICES (after hedging)
Crude oil (per barrel) $ 69.49 $ 58.31 19%
Heavy oil (per barrel) $ 43.72 $ 33.82 29%
Natural gas (per mcf) $ 7.26 $ 7.61 -5%
Natural gas liquids (per barrel) $ 59.30 $ 52.59 13%
Average realized price per boe $ 54.53 $ 49.66 10%

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


Summary of Trust Unit Trading Data

Three Months ended
September 30
(thousands, except per trust unit amounts) 2006 2005

TRUST UNIT TRADING
PGH (NYSE)
High $ 24.95 U.S. $ 25.75 U.S.
Low $ 18.90 U.S. $ 21.55 U.S.
Close $ 19.62 U.S. $ 25.42 U.S.
Value $ 603,978 U.S. $ 340,318 U.S.
Volume 27,359 14,502

PGF.A (TSX) (1)
High $ 28.25 $ 30.10
Low $ 24.95 $ 26.30
Close $ 25.30 $ 29.50
Value $ 110,607 $ 58,000
Volume 4,297 2,047

TRUST UNIT TRADING (Class B)
PGF.B (TSX) (1)
High $ 27.25 $ 21.26
Low $ 24.84 $ 18.25
Close $ 25.31 $ 20.58
Value $ 363,983 $ 441,039
Volume 14,226 22,738

PGF.UN (TSX) (1)
High $ 26.11
Low $ 21.02
Close $ 21.94
Value $ 707,966
Volume 29,262


Nine Months ended
September 30
(thousands, except per trust unit amounts) 2006 2005

TRUST UNIT TRADING (Class A)
PGH (NYSE)
High $ 25.15 U.S. $ 25.75 U.S.
Low $ 18.90 U.S. $ 18.11 U.S.
Close $ 19.62 U.S. $ 25.42 U.S.
Value $ 1,257,186 U.S. $ 1,190,435 U.S.
Volume 55,057 55,276

PGF.A (TSX) (1)
High $ 28.96 $ 30.10
Low $ 24.20 $ 22.15
Close $ 25.30 $ 29.50
Value $ 192,056 $ 157,672
Volume 7,351 5,894

TRUST UNIT TRADING (Class B)
PGF.B (TSX) (1)
High $ 27.25 $ 21.26
Low $ 20.71 $ 16.10
Close $ 25.31 $ 20.58
Value $ 1,243,673 $ 1,327,210
Volume 51,547 71,326

PGF.UN (TSX) (1)
High $ 26.11
Low $ 21.02
Close $ 21.94
Value $ 707,966
Volume 29,262

(1) July 27, 2006, Pengrowth's Class A trust units and Class B trust units
were consolidated into a single class of trust units whereas the Class
A trust units were delisted from the Toronto Stock Exchange and the
Class B trust units were renamed as Trust units and their trading
symbol changed to PGF.UN.


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 the interim unaudited consolidated financial statements for the nine months ended September 30, 2006 and is based on information available to November 1, 2006.

Frequently Recurring Terms

For the purposes of this discussion and analysis, we use certain frequently recurring terms as follows: the "Trust" refers to Pengrowth Energy Trust, the "Corporation" refers to Pengrowth Corporation, "Pengrowth" refers to the Trust and the Corporation on a consolidated basis and the "Manager" refers to Pengrowth Management Limited.

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

Advisory Regarding Forward-Looking Statements

This 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 discussion and analysis include, but are not limited to, statements with respect to: reserves, average 2006 production, production additions from Pengrowth's 2006 development program, the impact on production of divestitures in 2006, total operating expenses for 2006, 2006 operating expenses per boe, capital expenditures for 2006 and the breakdown of such capital expenditures for drilling, facilities and maintenance, land and seismic acquisition and re-completions, work-overs, and CO2 pilot. Statements relating to "reserves" are deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions that the reserves described exist in the quantities predicted or estimated and can profitably be produced in the future.

Forward-looking statements and information are based on Pengrowth's current beliefs as well as assumptions made by and information currently available to Pengrowth concerning anticipated financial performance, business prospects, strategies and regulatory developments. Although management considers these assumptions to be reasonable based on information currently available to it, they may prove to be incorrect.

By their very nature, forward-looking statements involve inherent risks and uncertainties, both general and specific, and risks that predictions, forecasts, projections and other forward-looking statements will not be achieved. We caution readers not to place undue reliance on these statements as a number of important factors could cause the actual results to differ materially from the beliefs, plans, objectives, expectations and anticipations, estimates and intentions expressed in such forward-looking statements. These factors include, but are not limited to: the volatility of oil and gas prices; production and development costs and capital expenditures; the imprecision of reserve estimates and estimates of recoverable quantities of oil, natural gas and liquids; Pengrowth's ability to replace and expand oil and gas reserves; environmental claims and liabilities; incorrect assessments of value when making acquisitions; increases in debt service charges; the loss of key personnel; the marketability of production; defaults by third party operators; unforeseen title defects; fluctuations in foreign currency and exchange rates; inadequate insurance coverage; compliance with environmental laws and regulations; changes in tax laws; the failure to qualify as a mutual fund trust; and Pengrowth's ability to access external sources of debt and equity capital. Further information regarding these factors may be found under the heading "Risk Factors" in Pengrowth's most recent Annual Information Form, its most recent consolidated financial statements, discussion and analysis, management's information circular, quarterly reports, material change reports and news releases. Copies of the Trust's Canadian public filings are available on SEDAR at www.sedar.com . The Trust's U.S. public filings, including the Trust's most recent annual report form 40-F as supplemented by its filings on form 6-K, are available at www.sec.gov.

Pengrowth cautions that the foregoing list of factors that may affect future results is not exhaustive. When relying on our forward-looking statements to make decisions with respect to Pengrowth, investors and others should carefully consider the foregoing factors and other uncertainties and potential events. Furthermore, the forward-looking statements contained in this discussion and analysis are made as of the date of this discussion and analysis and Pengrowth does not undertake any obligation to update publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise, except as required by law. The forward-looking statements contained in this discussion and analysis are expressly qualified by this cautionary statement.

Critical Accounting Estimates

As discussed in Note 1 to the financial statements, the financial statements are prepared in accordance with Canadian Generally Accepted Accounting Principles (GAAP). Management is required to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and revenues and expenses for the period then ended.

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

Non-GAAP Financial Measures

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

Conversion and Currency

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

RESULTS OF OPERATIONS

The third quarter results in the press release contain no material amounts relating to the September 28, 2006 completed acquisition of assets in the Carson Creek area of Alberta, or the Esprit Energy Trust (Esprit) business combination completed on October 2, 2006.

Production

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

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



Daily Production

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


Light crude oil production volumes for the third quarter of 2006 increased two percent from the second quarter of 2006, while in comparison to the third quarter of 2005, the production volumes were flat. For the first nine months of 2006 versus the same period in 2005, production increased minimally as improvements at Weyburn, Judy Creek and Swan Hills offset natural production declines.

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

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

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

Pricing and Commodity Price Hedging

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



Average Realized Prices

Three months ended Nine months ended
---------------------------------------------------------------------------
Sept 30, Jun 30, Sept 30, Sept 30, Sept 30,
(cdn$) 2006 2006 2005 2006 2005
---------------------------------------------------------------------------

Light crude oil (per bbl) 75.53 75.67 74.37 72.04 64.94
after hedging 72.61 72.67 63.95 69.49 58.31
Heavy oil (per bbl) 51.47 50.07 47.74 43.72 33.82
Natural gas (per mcf) 6.22 6.69 8.69 7.21 7.63
after hedging 6.29 6.76 8.57 7.26 7.61
Natural gas liquids (per
bbl) 60.76 58.92 57.75 59.30 52.59
---------------------------------------------------------------------------
Total per boe 54.51 55.80 60.06 55.30 52.04
after hedging 53.67 54.91 56.07 54.53 49.66
---------------------------------------------------------------------------
Benchmark prices
WTI oil (U.S.$ per bbl) 70.54 70.72 63.31 68.21 55.60
AECO spot gas (Cdn$ per gj) 5.72 5.95 7.75 6.82 7.03
NYMEX gas (U.S.$ per mmbtu) 6.66 6.76 8.49 7.47 7.16
Currency (U.S.$/Cdn$) 0.89 0.89 0.83 0.88 0.82
---------------------------------------------------------------------------


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



Hedging Losses (Gains)

Three months ended Nine months ended
---------------------------------------------------------------------------
Realized Sept 30, Jun 30, Sept 30, Sept 30, Sept 30,
2006 2006 2005 2006 2005
---------------------------------------------------------------------------

Light crude oil ($ millions) 5.5 5.6 19.8 14.4 37.4
Light crude oil ($ per bbl) 2.92 3.00 10.42 2.55 6.63

Natural gas ($ millions) (1.0) (1.0) 1.8 (2.3) 0.7
Natural gas ($ per mcf) (0.07) (0.07) 0.12 (0.05) 0.02
---------------------------------------------------------------------------
Combined ($ millions) 4.5 4.6 21.6 12.1 38.1
Combined ($ per boe) 0.84 0.89 3.99 0.77 2.38
---------------------------------------------------------------------------


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

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

In conjunction with the Murphy acquisition, which closed in 2004, Pengrowth assumed certain fixed price natural gas sales contracts and firm pipeline demand charge contracts. Under these contracts, Pengrowth is obligated to sell 3,886 mmbtu per day, until April 30, 2009 at an average remaining contract price of Cdn $2.31 per mmbtu. As required by GAAP, the fair value of the natural gas sales contract was recognized as a liability based on the mark-to-market value at May 31, 2004. The liability at September 30, 2006 of $14.3 million for the contracts will continue to be drawn down and recognized in income as the contracts are settled. As this is a non-cash component of income, it is not included in the calculation of distributable cash. As at September 30, 2006, Pengrowth would be required to pay $17.8 million to terminate the fixed price physical sales contract. This amount is not included above in the hedging losses (gains).

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



Oil and Gas Sales - Contribution Analysis

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


Oil and Gas Sales - Price and Volume Analysis

The following table illustrates the effect of changes in prices and volumes on the components of oil and gas sales, including the impact of hedging, for the third quarter of 2006 compared to the second quarter of 2006.



---------------------------------------------------------------------------
($ millions) Light oil Natural gas NGL Heavy oil Other Total
---------------------------------------------------------------------------

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


The following table illustrates the effect of changes in prices and volumes on the components of oil and gas sales, including the impact of hedging, for the first nine months of 2006 compared to the same period of 2005.



---------------------------------------------------------------------------
($ millions) Light oil Natural gas NGL Heavy oil Other Total
---------------------------------------------------------------------------

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


Processing, Interest and Other Income

Three months ended Nine months ended
---------------------------------------------------------------------------
($ millions) Sept 30, Jun 30, Sept 30, Sept 30, Sept 30,
2006 2006 2005 2006 2005
---------------------------------------------------------------------------

Processing, interest &
other income 4.7 4.1 2.1 12.6 13.7
$ per boe 0.88 0.80 0.39 0.80 0.86
---------------------------------------------------------------------------


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



Royalties

Three months ended Nine months ended
---------------------------------------------------------------------------
($ millions) Sept 30, Jun 30, Sept 30, Sept 30, Sept 30,
2006 2006 2005 2006 2005
---------------------------------------------------------------------------

Royalty expense 57.8 45.3 57.4 168.4 145.9
$ per boe 10.77 8.84 10.60 10.67 9.11
---------------------------------------------------------------------------
Royalties as a percent
of sales 20.1% 16.0% 18.9% 19.5% 18.3%


Royalties include crown, freehold and overriding royalties as well as mineral taxes. The royalty rate for the third quarter of 2006 compared to the second quarter of 2006 increased by 4.1 percent. This was primarily due to a favorable adjustment of $5.0 million recorded in the second quarter for SOEP. SOEP has a five tier royalty regime based on gross revenue for the first three tiers and net revenue for the final two tiers. During 2005, the royalty obligation at SOEP was approximately two percent of gross revenue (Tier II) but progressed to five percent of gross revenue (Tier III) starting with October 2005 production. This was recognized in March 2006 when the annual royalty submission was filed. Based on Pengrowth's forecast the royalty obligation is now in the fourth tier which is 30 percent of net revenue (gross revenue less certain capital and other costs associated with getting the gas and natural gas liquids to the project boundary) commencing with March 2006 production, which is later than previously estimated in the first quarter.



Operating Expenses

Three months ended Nine months ended
---------------------------------------------------------------------------
($ millions) Sept 30, Jun 30, Sept 30, Sept 30, Sept 30,
2006 2006 2005 2006 2005
---------------------------------------------------------------------------

Operating expenses 58.8 58.0 57.4 170.8 156.9
$ per boe 10.94 11.32 10.59 10.82 9.80
---------------------------------------------------------------------------


Operating expenses increased minimally in the third quarter of 2006 in comparison to the second quarter of 2006; while the expense per boe decreased as production volumes improved from the second quarter's maintenance/turnaround activity. Increased utility costs and higher maintenance were the most significant reasons for the increase in expenses in comparing the first nine months of 2006 versus the same period in 2005. Operating expenses include costs incurred to earn processing and other income reported separately.



Transportation Costs

Three months ended Nine months ended
---------------------------------------------------------------------------
($ millions) Sept 30, Jun 30, Sept 30, Sept 30, Sept 30,
2006 2006 2005 2006 2005
---------------------------------------------------------------------------

Light oil transportation 0.5 0.5 0.6 1.5 1.7
$ per bbl 0.26 0.27 0.29 0.26 0.30
Natural gas transportation 1.3 1.2 1.4 3.8 3.9
$ per mcf 0.09 0.09 0.09 0.09 0.09
---------------------------------------------------------------------------


Pengrowth incurs transportation costs for its product once the product enters a feeder or main pipeline to the title transfer point. The transportation cost is dependant upon industry rates and distance the product flows on the pipeline prior to changing ownership or custody. Pengrowth has the option to sell some of its natural gas directly to premium markets outside of Alberta by incurring additional transportation costs. Prior to September 30, 2006, Pengrowth sold most of its natural gas without incurring significant additional transportation costs. Similarly, Pengrowth has elected to sell approximately 75 percent of its crude oil at market points beyond the wellhead, but at the first major trading point, requiring minimal transportation costs.



Amortization of Injectants for Miscible Floods

Three months ended Nine months ended
---------------------------------------------------------------------------
($ millions) Sept 30, Jun 30, Sept 30, Sept 30, Sept 30,
2006 2006 2005 2006 2005
---------------------------------------------------------------------------

Purchased and capitalized 7.9 6.7 6.9 25.2 20.2
Amortization 8.8 8.5 6.0 25.3 17.3
---------------------------------------------------------------------------


The cost of injectants (primarily natural gas and ethane) purchased for injection in miscible flood programs is amortized equally over the period of expected future economic benefit. Prior to 2005, the expected future economic benefit from injection was estimated at 30 months, based on the results of previous flood patterns. Commencing in 2005 the response period for additional new patterns being developed is expected to be somewhat shorter relative to the historical miscible patterns in the project. Accordingly, the cost of injectants purchased in 2005 and 2006 will be amortized over a 24 month period while costs incurred for the purchase of injectants in prior periods will continue to be amortized over 30 months. During the third quarter of 2006, the balance of unamortized injectant costs decreased by $0.9 million to $35.2 million.

The value of Pengrowth's proprietary injectants is not recorded until reproduced from the flood and sold, although the cost of producing these injectants is included in operating expenses. The cost of purchased injectants increased 18 percent in the third quarter of 2006 from the second quarter of 2006 primarily due to the increase in volume of injectants. The 14 percent increase in the third quarter of 2006 compared to the same quarter of 2005 is due to increased injection volumes. On a year to date basis, the 25 percent increase in purchased injectants is due to increased injection volumes and the price of injectants.

Operating Netbacks

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

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



Combined Netbacks ($ per boe)

Three months ended Nine months ended
----------------------------- -------------------
Sept 30, Jun 30, Sept 30, Sept 30, Sept 30,
2006 2006 2005 2006 2005
----------------------------- -------------------

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


Light Crude Netbacks ($ per bbl)

Three months ended Nine months ended
----------------------------- -------------------
Sept 30, Jun 30, Sept 30, Sept 30, Sept 30,
2006 2006 2005 2006 2005
----------------------------- -------------------

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


Heavy Oil Netbacks ($ per bbl)

Three months ended Nine months ended
----------------------------- -------------------
Sept 30, Jun 30, Sept 30, Sept 30, Sept 30,
2006 2006 2005 2006 2005
----------------------------- -------------------

Sales price $ 51.47 $ 50.07 $ 47.74 $ 43.72 $ 33.82

Processing, interest
and other income 0.38 0.16 (0.83) 0.31 0.24
Royalties (6.27) (4.75) (8.00) (4.24) (5.03)
Operating expenses (16.28) (16.03) (16.30) (15.51) (16.95)
----------------------------- -------------------
Operating netback $ 29.30 $ 29.45 $ 22.61 $ 24.28 $ 12.08
----------------------------- -------------------


Natural Gas Netbacks ($ per mcf)

Three months ended Nine months ended
----------------------------- -------------------
Sept 30, Jun 30, Sept 30, Sept 30, Sept 30,
2006 2006 2005 2006 2005
----------------------------- -------------------

Sales price $ 6.29 $ 6.76 $ 8.57 $ 7.26 $ 7.61
Other production income - 0.01 - 0.01 -
----------------------------- -------------------
6.29 6.77 8.57 7.27 7.61

Processing, interest
and other income 0.23 0.23 0.09 0.21 0.24
Royalties (1.34) (0.93) (1.47) (1.61) (1.36)
Operating expenses (1.38) (1.66) (1.31) (1.52) (1.19)
Transportation costs (0.09) (0.09) (0.09) (0.09) (0.09)
----------------------------- -------------------
Operating netback $ 3.71 $ 4.32 $ 5.79 $ 4.26 $ 5.21
----------------------------- -------------------


NGLs Netbacks ($ per bbl)

Three months ended Nine months ended
----------------------------- -------------------
Sept 30, Jun 30, Sept 30, Sept 30, Sept 30,
2006 2006 2005 2006 2005
----------------------------- -------------------

Sales price $ 60.76 $ 58.92 $ 57.75 $ 59.30 $ 52.59

Royalties (21.84) (17.67) (20.57) (21.93) (16.27)
Operating expenses (10.26) (10.20) (10.13) (9.69) (8.65)
----------------------------- -------------------
Operating netback $ 28.66 $ 31.05 $ 27.05 $ 27.68 $ 27.67
----------------------------- -------------------


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

Interest

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



General and Administrative (G&A)

Three months ended Nine months ended
---------------------------------------------------------------------------
($ millions) Sept 30, Jun 30, Sept 30, Sept 30, Sept 30,
2006 2006 2005 2006 2005
---------------------------------------------------------------------------

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


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



Management Fees

Three months ended Nine months ended
---------------------------------------------------------------------------
($ millions) Sept 30, Jun 30, Sept 30, Sept 30, Sept 30,
2006 2006 2005 2006 2005
---------------------------------------------------------------------------

Management Fee 0.8 2.1 1.6 6.1 6.8
Performance Fee 2.2 1.3 1.9 4.5 4.8
---------------------------------------------------------------------------
Total ($ millions) 3.0 3.4 3.5 10.6 11.6
Total ($ per boe) 0.56 0.65 0.65 0.67 0.72
---------------------------------------------------------------------------


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



Depletion, Depreciation and Accretion

Three months ended Nine months ended
---------------------------------------------------------------------------
($ millions) Sept 30, Jun 30, Sept 30, Sept 30, Sept 30,
2006 2006 2005 2006 2005
---------------------------------------------------------------------------

Depletion and Depreciation 83.5 67.8 73.5 222.4 213.6
$ per boe 15.56 13.23 13.57 14.09 13.34
Accretion 4.5 3.9 3.5 11.7 10.5
$ per boe 0.84 0.76 0.66 0.74 0.66
---------------------------------------------------------------------------


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

Other Expenses

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

Taxes

In determining its taxable income, the Corporation deducts payments made to the Trust, effectively transferring the income tax liability to unitholders thus reducing taxable income to nil. Under the Corporation's current distribution policy, funds are withheld from distributable cash to fund future capital expenditures and repay debt.

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


Capital Expenditures

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



Three months ended Nine months ended
---------------------------------------------------------------------------
($ millions) Sept 30, Jun 30, Sept 30, Sept 30, Sept 30,
2006 2006 2005 2006 2005
---------------------------------------------------------------------------

Geological and geophysical 0.5 1.1 0.2 2.8 1.4
Drilling and completions 42.2 33.5 29.8 133.5 89.2
Plant and facilities 9.4 7.5 10.0 30.3 23.9
Land purchases 4.7 5.0 0.8 12.4 1.1
---------------------------------------------------------------------------
Development capital 56.8 47.1 40.8 179.0 115.6
---------------------------------------------------------------------------
Acquisitions 473.8 4.4 2.1 528.0 93.3
---------------------------------------------------------------------------
Total capital expenditures
and acquisitions 530.6 51.5 42.9 707.0 208.9
---------------------------------------------------------------------------


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

Acquisitions and Dispositions

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

On March 30, 2006, Pengrowth closed the acquisition of an additional working interest in the Dunvegan area as well as some minor oil and gas properties in central Alberta for approximately $48 million.

On January 12, 2006, Pengrowth divested oil and gas properties for $22 million of cash, prior to adjustments, and approximately eight million shares in Monterey. Pengrowth holds approximately 34 percent of the common shares of Monterey.

Financial Resources and Liquidity

Pengrowth's capital structure is as follows:



As at As at As at
September 30 December 31 September 30
($ thousands) 2006 2005 2005
----------------------------------------------

Revolving credit facilities 132,000 35,000 190,000
Senior unsecured notes 327,910 333,089 232,220
Working capital deficit 119,234 77,639 63,524
Note payable 20,000 20,000 35,000
Cash balance (928) - (997)
----------------------------------------------
Net Debt 598,216 465,728 519,747
----------------------------------------------

Unitholders' equity 1,888,365 1,475,996 1,467,859

Net debt as a percentage of
total book capitalization 24.1% 24.0% 26.1%

Trailing 12 months cash flow(1) 680,811 618,070 514,766

Net debt to trailing 12 months
cash flow(1) 0.9 0.8 1.0

(1) Cash flow in this table is defined as cash flow from operating
activities after working capital changes


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

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

At September 30, 2006, Pengrowth maintained a $500 million term credit facility and a $35 million demand operating line of credit. These facilities were reduced by drawings of $132 million and by $17 million in letters of credit outstanding at period end. Pengrowth remains well positioned to fund its 2006 development program and to take advantage of acquisition opportunities as they arise. At September 30, 2006, Pengrowth had $387 million available to draw from its credit facilities. On October 2, 2006, concurrent with the closing of the strategic business combination with Esprit, Pengrowth increased its term credit facility to $950 million. A portion of the increase was used to repay and cancel Esprit's credit facility. On October 2, 2006, Pengrowth had over $500 million available to draw from its credit facilities after the increase to its credit facility and repayment of Esprit's facility.

Pengrowth does not have any off balance sheet financing arrangements.

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

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

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

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

4. EBITDA should not be less than four times interest expense

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

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

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


Distributable Cash and Distributions

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



($ thousands, except
per trust unit amounts) Three months ended Nine months ended
---------------------------------------------------------------------------
Sept 30, Jun 30, Sept 30, Sept 30, Sept 30,
2006 2006 2005 2006 2005
---------------------------------------------------------------------------

Cash flows from
operating activities 174,294 118,326 158,976 484,219 421,482
Change in non-cash
operating working capital (31,351) 34,219 (789) (47,471) (1,840)
---------------------------------------------------------------------------
Funds generated from
operations 142,943 152,545 158,187 436,748 419,642
---------------------------------------------------------------------------
Change in deferred
injectants (870) (1,853) 892 (80) 2,854
Change in remediation
trust funds (599) (279) (272) (1,269) (804)
Change in deferred charges 1,997 (1,716) 2,818 1,069 2,028
Other (124) 383 384 136 140
---------------------------------------------------------------------------
Distributable cash 143,347 149,080 162,009 436,604 423,860
---------------------------------------------------------------------------

---------------------------------------------------------------------------
Allocation of
Distributable cash
Cash withheld 10,834 28,483 52,156 63,192 97,741
Distributions paid or
declared 132,513 120,597 109,853 373,412 326,119
---------------------------------------------------------------------------
Distributable cash 143,347 149,080 162,009 436,604 423,860
---------------------------------------------------------------------------
Distributable cash per
trust unit 0.89 0.93 1.02 2.72 2.71
Distributions paid or
declared per trust unit 0.75 0.75 0.69 2.25 2.07
Payout ratio (1) 92% 81% 68% 86% 77%
---------------------------------------------------------------------------

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


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

The Board of Directors and Management regularly monitor forecasted distributable cash and payout ratio. The Board meets formally at least quarterly to set the distributions for the next quarter. The Board considers a number of factors, including expectations of future commodity prices, capital expenditure requirements, and the availability of debt and equity capital. Pursuant to the Royalty Indenture, the Board can establish a reserve for certain items including up to 20 percent of Gross Revenue to fund various costs including future capital expenditures, royalty income in any future period and future abandonment costs.


Cash distributions are paid to unitholders on the 15th day of the second month following the month of production. Pengrowth paid $0.75 per trust unit as cash distributions during the third quarter of 2006.

Taxability of Distributions

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

The following discussion relates to the taxation of Canadian unitholders only. For detailed tax information relating to non-residents, please refer to our website www.pengrowth.com. Cash distributions are comprised of a return of capital portion, which is tax deferred, and return on capital portion which is taxable income. The return of capital portion reduces the cost base of a unitholders trust units for purposes of calculating a capital gain or loss upon ultimate disposition.



Summary of Quarterly Results

The following table is a summary of quarterly results for 2006,
2005 and 2004.

This table also shows the relatively high commodity prices
sustained throughout all quarter results, which have had a
positive impact on net income and distributable cash.

-----------------------
2006 Q1 Q2 Q3
------------------------------------------------------------------
Oil and gas sales ($000's) 291,896 283,532 287,757
Net income ($000's) 66,335 110,116 82,542
Net income per trust unit ($) 0.41 0.69 0.51
Net income per trust unit - diluted($) 0.41 0.68 0.51
Distributable cash ($000's) 144,177 149,080 143,347
Actual distributions paid or declared
per trust unit ($) 0.75 0.75 0.75
Daily production (boe) 58,845 56,325 58,344
Total production (mboe) 5,296 5,126 5,368
Average realized price ($ per boe) 55.04 54.91 53.67
Operating netback ($ per boe) 31.44 33.94 30.82


---------------------------------------------------------------------------
2005 Q1 Q2 Q3 Q4
---------------------------------------------------------------------------
Oil and gas sales ($000's) 239,913 253,189 304,484 353,923
Net income ($000's) 56,314 53,106 100,243 116,663
Net income per trust unit ($) 0.37 0.34 0.63 0.73
Net income per trust unit - diluted($) 0.37 0.34 0.63 0.73
Distributable cash ($000's) 127,804 134,047 162,009 195,879
Actual distributions paid or declared
per trust unit ($) 0.69 0.69 0.69 0.75
Daily production (boe) 59,082 57,988 58,894 61,442
Total production (mboe) 5,317 5,277 5,418 5,653
Average realized price ($ per boe) 44.97 47.79 56.07 62.55
Operating netback ($ per boe) 27.70 29.26 33.94 38.81


---------------------------------------------------------------------------
---------------------------------------------------------------------------
2004 Q1 Q2 Q3 Q4
---------------------------------------------------------------------------
Oil and gas sales ($000's) 168,771 197,284 226,514 223,183
Net income ($000's) 38,652 32,684 51,271 31,138
Net income per trust unit ($) 0.31 0.24 0.38 0.23
Net income per trust unit - diluted($) 0.31 0.24 0.38 0.23
Distributable cash ($000's) 92,895 99,021 104,304 104,958
Actual distributions paid or declared
per trust unit ($) 0.63 0.64 0.67 0.69
Daily production (boe) 45,668 51,451 60,151 57,425
Total production (mboe) 4,156 4,682 5,534 5,283
Average realized price ($ per boe) 40.37 41.83 40.90 42.08
Operating netback ($ per boe) 25.71 25.71 22.77 24.31


Subsequent Events

On October 2, 2006 Pengrowth and Esprit completed the previously announced business combination of Pengrowth and Esprit (the "Combination"). Under the terms of the agreement, each Esprit trust unit was exchanged for 0.53 of a Pengrowth trust unit (the new trust units from the consolidation of Pengrowth's Class A and Class B trust units effective on July 27, 2006). The Combination was approved by in excess of 99 percent of the votes cast at the Esprit unitholder meeting held on September 26, 2006. As a result of the Combination, approximately 35,514,327 Pengrowth trust units were issued to Esprit unitholders, including 789,170 Pengrowth trust units issued to the Corporation which were exchanged with and immediately cancelled by Pengrowth.

On October 27, 2006 Pengrowth entered into an exclusivity agreement with a third party with respect to a possible significant asset acquisition. Under the terms of the agreement, Pengrowth has made a $30 million payment as an exclusivity fee. If Pengrowth chooses not to proceed, the $30 million is not refundable. If the vendor chooses not to proceed, the $30 million is refundable. Pengrowth is now in the process of determining whether it will proceed in light of a variety of considerations, including the recent Federal Government announcement on taxability of Trusts. Pengrowth has no information as to whether the vendor will proceed.

Subsequent to September 30, 2006, Pengrowth has entered into a series of fixed price commodity sales contracts with third parties. The effect of these contracts is to fix the price received in 2007 for approximately 16,250 boe per day. Including contracts entered into prior to the third quarter, the total volumes subject to fixed price commodity sales contracts is approximately 21,920 boe per day for the majority of 2007.

Outlook

At this time, Pengrowth anticipates full year production of 62,500 to 63,500 boe per day, up from its previous production guidance of 56,000 to 57,500 boe per day. The increase in estimated production is mainly as a result of the Carson Creek area and the Esprit acquisitions. The fourth quarter production is estimated at 79,000 boe per day. This two percent decrease relative to our previous 81,000 boe per day estimate at acquisition is due to a combination of temporary third-party facility restrictions at Willesden Green and Three Hills; on-going well remediation and optimization work in Carson Creek; and weather-related delays in drilling and tie-ins across most areas. Offsetting the additions from acquisitions and planned 2006 development activities are the Monterey and other minor previously disclosed divestitures and expected production declines from normal operations. The above estimate excludes the impact from other future acquisitions or divestitures.

Pengrowth expects to increase its total operating expenses for 2006 to approximately $245 million, up from its previous guidance of $220 million as a result of the Esprit strategic business combination and the Carson Creek area acquisition. Assuming Pengrowth's average production results for 2006 are as forecast above, Pengrowth now estimates 2006 operating expenses per boe of between $10.55 and $10.75 and combined G&A and management fees of approximately $2.30 to $2.40 per boe.

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


Disclosure Controls and Procedures

The Chief Executive Office, James Kinnear, and the Chief Financial Officer, Christopher Webster, have evaluated Pengrowth's disclosure controls and procedures for the period ending September 30, 2006. Based on that evaluation, there has not been any change in the company's disclosure controls and procedures and internal controls over financial reporting during the last fiscal quarter that has materially affected, or is reasonably likely to materially affect, Pengrowth's internal controls over financial reporting.

CONFERENCE CALL AND CONTACT INFORMATION

Pengrowth will hold a conference call beginning at 9:00 A.M. Mountain Time on Thursday, November 2, 2006 during which management will review Pengrowth's 2006 third quarter financial and operating results and respond to inquiries from the investment community. To participate callers may dial (800) 814-4853 or Toronto local (416) 644-3422. To ensure timely participation in the teleconference, callers are encouraged to dial in 10 to 15 minutes prior to commencement of the call to register. A live audio webcast will be accessible through the Webcast and Multimedia Centre section of Pengrowth's website at www.pengrowth.com. The webcast will be archived on the Pengrowth website. A telephone replay will be available through to midnight Eastern Time on Thursday, November 9, 2006 by dialing (877) 289-8525 or Toronto local (416) 640-1917 and entering passcode number 21206447#.

Operations Review

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

In addition to the acquisitions announced in the third quarter, Pengrowth remained focused on developing internal opportunities. Development capital in the quarter totaled $56.8 million with approximately 75 percent directed towards drilling and completions. During the quarter, Pengrowth drilled 93 gross (43.7 net) wells with a 94 percent success rate.

NORTHEAST BRITISH COLUMBIA (NEBC) / NORTHWEST ALBERTA

- A farmout well was drilled at Grand Prairie and is currently undergoing production testing.

- At Cutbank, three non-operated wells were drilled and are on production at a combined initial rate of 5.1 mmcf per day. Four additional wells are planned for the fourth quarter of 2006.

- Two successful oil wells were drilled at Rigel adding 210 bbls per day.

- Devon, the operator of the Dunvegan Gas Unit, drilled five successful gas wells that are expected to be tied in during the fourth quarter.

- Monterey drilled eight wells in the quarter with Pengrowth participating in seven of those wells. This resulted in four gas wells, one suspended well and two dry holes. Tie in of the gas wells is expected during the fourth quarter of this year.

CENTRAL

- During the quarter, 13 wells were drilled at the Weyburn Unit bringing the total number of wells drilled at the property in 2006 to 38. An additional 13 to 17 wells are expected to be drilled before year end. The 2006 drilling program has been very successful adding 9,397 bbls per day (917 bbls per day net) of incremental production.

- At Swan Hills, the last well in a four well program was drilled during the third quarter. Three of the four wells averaged 510 bbls per day (114 bbls per day net) of production. The fourth well of the 2006 program is expected to commence production in the fourth quarter of 2006. Work is underway on the development of two new miscible patterns including the drilling of a new injection well to support solvent injection which will also commence in the upcoming quarter.

- Tie in work on three new West Pembina wells was completed and incremental production of 2.6 mmcf per day was realized. One non-operated well (50 percent working interest) was drilled and cased in the quarter at West Pembina.

- An infill oil producer at Judy Creek which was rig released in the second quarter of 2006 was brought on production in the third quarter and has a current oil rate of 95 bbls per day.

- Power interruptions due to severe lightning storms in August resulted in electrical operational problems and 13 days of reduced production at Judy Creek of approximately 400 bbls of oil per day.

SOUTHERN

- In the Twining area, completions on the 11 wells of phase one of the coalbed methane (CBM) program were completed in the third quarter. Five of the 11 wells were tied in and began production during the quarter.

- A 50 well CBM program (Phase 2) commenced with the drilling of 10 wells (average working interest of 61 percent) in the third quarter.

- Partners drilled 17 wells of which 15 are expected to be completed for CBM production. The remaining two wells are anticpicated to be on stream in the fourth quarter of 2006.

- Pengrowth drilled, completed and tied in 16 wells (100 percent working interest) at Princess in the third quarter targeting shallow gas.

- Two wells (100 percent working interest) were drilled and cased at Elnora and Trochu. Testing is expected to commence in the fourth quarter of 2006.

- A Pekisko gas well in the Twining Unit (88 percent working interest) was successfully tested at 0.71 mmcf per day.

- At Monogram, a 70 well re-frac program was completed adding 1.75 mmcf per day (0.94 mmcf per day net) of incremental production.

- Production testing of the new Quirk Creek gas well (68 percent working interest) was completed in the third quarter. It commenced production in October at a restricted rate of approximately 5 mmcf per day (3.4 mmcf per day net).

- At Mikwan/Three Hills, four Belly River and Mannville conventional wells were drilled and completed and all tested gas.

HEAVY OIL

- During the quarter, three horizontal wells at East Bodo came on stream at 150 bbls of oil per day.

SABLE OFFSHORE ENERGY PROJECT (SOEP)

Production

- Third quarter gross raw gas production from the five SOEP fields Thebaud, Venture, North Triumph, Alma and South Venture averaged 416 mmcf per day (35 mmcf per day net).

- Monthly raw gas production for July, August and September was 433 mmcf per day (36.4 mmcf per day net); 427 mmcf per day (35.9 mmcf per day net); and 387 mmcf per day (32.5 mmcf per day net), respectively.

- Production was reduced in the third quarter due to a required September shutdown in order to test the compression control systems and complete final tie ins.

- Pengrowth shipped approximately 67,000 bbls of condensate in the third quarter.

- A condensate cargo expected for late September was moved to early October.

Tier II Status as of September 30, 2006

- Shutdown to test compression computer and instrumentation systems started on September 20, 2006.

- Modifications to the Goldboro gas plant were also made during the shutdown.

- In-service for the compressor is scheduled for late 2006.



Consolidated Balance Sheet

(Stated in thousands of dollars)
As at As at
September 30 December 31
2006 2005
---------------------------------------------------------------------------
---------------------------------------------------------------------------
(unaudited) (audited)

ASSETS
CURRENT ASSETS
Cash $ 928 $ -
Accounts receivable 105,116 127,394
---------------------------------------------------------------------------
---------------------------------------------------------------------------
106,044 127,394
UNREALIZED MARK-TO-MARKET GAIN ON
COMMODITY CONTRACTS 16,637 -

OTHER ASSETS (Note 8) 19,434 13,215

LONG TERM INVESTMENTS (Note 4) 26,990 -

GOODWILL (Note 3) 315,666 182,835

PROPERTY, PLANT AND EQUIPMENT (Note 3) 2,556,802 2,067,988
---------------------------------------------------------------------------
---------------------------------------------------------------------------
$ 3,041,573 $ 2,391,432
---------------------------------------------------------------------------
---------------------------------------------------------------------------

LIABILITIES AND UNITHOLDERS' EQUITY
CURRENT LIABILITIES
Bank indebtedness $ - $ 14,567
Accounts payable and
accrued liabilities 124,600 111,493
Distributions payable to unitholders 92,252 79,983
Due to Pengrowth Management Limited 4,418 8,277
Other liabilities (Note 12) 24,573 25,279
---------------------------------------------------------------------------
---------------------------------------------------------------------------
245,843 239,599

CONTRACT LIABILITIES 9,683 12,937

LONG TERM DEBT (Note 2) 459,910 368,089

ASSET RETIREMENT
OBLIGATIONS (Notes 3 and 7) 229,793 184,699

FUTURE INCOME TAXES (Note 3) 207,979 110,112

TRUST UNITHOLDERS' EQUITY (Note 5)
Trust Unitholders' capital 3,040,038 2,514,997
Contributed surplus 5,393 3,646
Deficit (1,157,066) (1,042,647)
---------------------------------------------------------------------------
---------------------------------------------------------------------------
1,888,365 1,475,996
---------------------------------------------------------------------------
---------------------------------------------------------------------------

SUBSEQUENT EVENTS (Note 13)
$ 3,041,573 $ 2,391,432

See accompanying notes to the consolidated financial statements.


Consolidated Statements of Income and Deficit

(Stated in thousands of dollars)
(unaudited)

Three months ended Nine months ended
September 30 September 30
2006 2005 2006 2005
---------------------------------------------------------------------------
---------------------------------------------------------------------------

REVENUES
Oil and gas sales $ 287,757 $ 304,484 $ 863,185 $ 797,587
Processing and other
income 3,319 2,039 10,524 11,771
Royalties, net of
incentives (57,810) (57,414) (168,435) (145,879)
---------------------------------------------------------------------------
---------------------------------------------------------------------------
233,266 249,109 705,274 663,479
Interest and other
income 1,389 74 2,085 1,916
---------------------------------------------------------------------------
---------------------------------------------------------------------------
NET REVENUE 234,655 249,183 707,359 665,395

EXPENSES
Operating 58,748 57,371 170,768 156,885
Transportation 1,760 1,969 5,299 5,584
Amortization of
injectants for
miscible floods 8,756 5,969 25,263 17,322
Interest 7,051 5,644 19,340 16,786
General and
administrative 7,729 7,559 25,246 21,765
Management fee 2,999 3,537 10,557 11,588
Foreign exchange(gain)
loss (Note 9) 123 (12,255) (8,997) (8,470)
Depletion and
depreciation 83,513 73,541 222,396 213,594
Accretion (Note 7) 4,490 3,578 11,721 10,531
Unrealized gain (loss)
on commodity contracts
(Notes 1 and 11) (20,026) - (16,637) -
Other expenses 1,365 1,511 6,142 3,225
---------------------------------------------------------------------------
---------------------------------------------------------------------------
156,508 148,424 471,098 448,810
---------------------------------------------------------------------------
---------------------------------------------------------------------------

NET INCOME BEFORE TAXES 78,147 100,759 236,261 216,585

INCOME TAX EXPENSE
Capital - 605 11 1,497
Future (REDUCTION) (4,395) (89) (22,743) 5,425
---------------------------------------------------------------------------
---------------------------------------------------------------------------
(4,395) 516 (22,732) 6,922
---------------------------------------------------------------------------
---------------------------------------------------------------------------

NET INCOME $ 82,542 $ 100,243 $ 258,993 $ 209,663
---------------------------------------------------------------------------
---------------------------------------------------------------------------

Deficit, beginning of
period (1,107,095) (1,029,842) (1,042,647) (922,996)

Distributions declared (132,513) (109,853) (373,412) (326,119)
---------------------------------------------------------------------------
---------------------------------------------------------------------------

DEFICIT, END OF PERIOD $(1,157,066) $(1,039,452) $(1,157,066) (1,039,452)
---------------------------------------------------------------------------
---------------------------------------------------------------------------

NET INCOME
PER TRUST
UNIT (Note 5) Basic $ 0.51 $ 0.63 $ 1.61 $ 1.34
Diluted $ 0.51 $ 0.63 $ 1.60 $ 1.34
---------------------------------------------------------------------------
---------------------------------------------------------------------------

See accompanying notes to the consolidated financial statements.


Consolidated Statements of Cash Flow

(Stated in thousands of dollars)
(unaudited)

Three months ended Nine months ended
September 30 September 30
2006 2005 2006 2005
---------------------------------------------------------------------------
---------------------------------------------------------------------------

CASH PROVIDED BY (USED FOR):

OPERATING
Net income $ 82,542 $ 100,243 $ 258,993 $ 209,663
Depletion,
depreciation and
accretion 88,003 77,119 234,117 224,125
Future income taxes (4,395) (89) (22,743) 5,425
Contract liability
amortization (1,320) (1,448) (3,960) (4,346)
Amortization of
injectants 8,756 5,969 25,263 17,322
Purchase of injectants (7,886) (6,861) (25,183) (20,176)
Expenditures on
remediation (1,970) (1,676) (5,820) (4,300)
Unrealized foreign
exchange (gain) loss
(Note 9) 300 (12,860) (9,060) (8,180)
Unrealized gain on
commodity contracts
(Notes 1 and 11) (20,026) - (16,637) -
Trust unit based
compensation (Note 6) 936 608 2,847 2,137
Deferred charges (2,721) (4,283) (5,085) (4,283)
Amortization of deferred
charges 724 1,465 4,016 2,255
Changes in non-cash
operating working
capital (Note 10) 31,351 789 47,471 1,840
--------------------------------------------------------------------------
--------------------------------------------------------------------------
174,294 158,976 484,219 421,482
---------------------------------------------------------------------------
---------------------------------------------------------------------------

FINANCING
Distributions (120,698) (109,455) (361,143) (323,252)
Change in long term
debt, net (30,000) (26,428) 97,000 64,541
Proceeds from issue of
trust units 506,550 15,477 523,941 32,007
---------------------------------------------------------------------------
---------------------------------------------------------------------------
355,852 (120,406) 259,798 (226,704)
---------------------------------------------------------------------------
---------------------------------------------------------------------------

INVESTING
Expenditures on property
acquisitions (473,883) (2,861) (528,045) (94,427)
Expenditures on property,
plant and equipment (56,774) (40,050) (179,028) (114,486)
Proceeds on property
dispositions (1,998) 18,623 15,755 18,623
Change in remediation
trust fund (599) (272) (1,269) (804)
Purchase of long term
investments - - (19,990) -
Change in non-cash
investing working
capital (Note 10) 2,839 1,527 (15,945) 1,527
---------------------------------------------------------------------------
---------------------------------------------------------------------------
(530,415) (23,033) (728,522) (189,567)
---------------------------------------------------------------------------
---------------------------------------------------------------------------

CHANGE IN CASH AND BANK
INDEBTEDNESS (269) 15,537 15,495 5,211

CASH (BANK INDEBTEDNESS)
AT BEGINNING OF PERIOD 1,197 (14,540) (14,567) (4,214)
---------------------------------------------------------------------------
---------------------------------------------------------------------------

CASH AT END OF PERIOD $ 928 $ 997 $ 928 $ 997
---------------------------------------------------------------------------
---------------------------------------------------------------------------

See accompanying notes to the consolidated financial statements.


Notes To Consolidated Financial Statements
(Unaudited)
September 30, 2006

(Tabular dollar amounts are stated in thousands of dollars except per trust
unit amounts)
---------------------------------------------------------------------------


1. SIGNIFICANT ACCOUNTING POLICIES

The interim consolidated financial statements of Pengrowth Energy Trust include the accounts of Pengrowth Energy Trust (the "Trust"), Pengrowth Corporation (the "Corporation") and its subsidiaries (collectively referred to as "Pengrowth"). The financial statements do not contain the accounts of Pengrowth Management Limited (the "Manager").

The financial statements have been prepared by management in accordance with generally accepted accounting principles in Canada. The interim consolidated financial statements have been prepared following the same accounting policies and methods of computation as the consolidated financial statements for the fiscal year ended December 31, 2005, except as discussed below. The disclosures provided below are incremental to those included with the annual consolidated financial statements. The interim consolidated financial statements should be read in conjunction with the consolidated financial statements and the notes thereto in Pengrowth's annual report for the year ended December 31, 2005.

FINANCIAL INSTRUMENTS

Effective May 1, 2006, Pengrowth no longer designates new commodity contracts as hedges. Commodity contracts that do not qualify as hedges, or are not designated as hedges, are recorded using the fair value method of accounting whereby instruments are recorded in the consolidated balance sheet as either an asset or liability with changes in fair value recognized in net earnings. Realized gains or losses from financial derivatives related to commodity prices are recognized in natural gas and crude oil revenues as the related sales occur. Unrealized gains and losses are recognized in expenses at the end of each respective reporting period. The fair value of derivative instruments is based on quoted market prices or, in its absence, estimated using third party market indications and forecasts.

Commodity contracts are used by Pengrowth to manage economic exposure to market risks relating to commodity prices. Pengrowth's policy is not to utilize derivative financial instruments for speculative purposes.

Financial derivative contracts previously designated as hedges continue to be designated as hedges and are accounted for as disclosed in the annual financial statements.



2. LONG TERM DEBT
As at As at
September 30, December 31,
2006 2005
---------------------------------------------------------------------------
U.S. dollar denominated debt:
U.S. $150 million senior unsecured notes at
4.93 percent due April 2010 $ 167,655 $ 174,450
U.S. $50 million senior unsecured notes at
5.47 percent due April 2013 55,885 58,150
---------------------------------------------------------------------------
223,540 232,600
Pound sterling denominated 50 million
unsecured notes at 5.46 percent due
December 2015 104,370 100,489
Canadian dollar revolving credit facility 132,000 35,000
---------------------------------------------------------------------------
$ 459,910 $ 368,089
---------------------------------------------------------------------------


On June 16, 2006, Pengrowth entered into a new $500 million extendible revolving term credit facility syndicated among eight financial institutions. The facility is unsecured, covenant based and has a three year term. Pengrowth has the option to extend the facility each year, subject to the approval of the lenders, or repay the entire balance at the end of the three year term. Various borrowing options are available under the facility including prime rate based advances and bankers' acceptance loans. This facility carries floating interest rates that are expected to range between 0.65 percent and 1.15 percent over bankers' acceptance rates, depending on Pengrowth's consolidated ratio of senior debt to earnings before interest, taxes and non-cash items. In addition, Pengrowth has a $35 million demand operating line of credit for working capital purposes. The facilities were reduced by drawings of $132 million and by outstanding letters of credit in the amount of approximately $17 million at September 30, 2006.

On October 2, 2006, concurrent with the closing of the business combination with Esprit Energy Trust (Esprit), Pengrowth increased its extendible revolving credit facility to $950,000,000 and the addition of two new financial institutions into the syndicate. No other material changes were made to the credit facility. $315 million of the increase was used to repay and cancel Esprit's credit facility, leaving over $500 million available to draw from the credit facility.

3. CORPORATE ACQUISITION

On September 28, 2006, Pengrowth acquired all of the issued and outstanding shares of a company which has interests in oil and natural gas assets in the Carson Creek area of Alberta (the "Carson Creek" 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:
Property, plant and equipment $ 502,270
Goodwill 132,831
Asset retirement obligations (38,874)
Future income taxes (120,610)
--------------------------------------------------------------------------
$ 475,617
--------------------------------------------------------------------------
--------------------------------------------------------------------------

Cost of Acquisition:
Cash $ 475,558
Acquisition costs 59
--------------------------------------------------------------------------
$ 475,617
--------------------------------------------------------------------------
--------------------------------------------------------------------------


Property, plant and equipment of $502 million represents the fair value of the assets acquired determined in part by an independent reserve evaluation. Goodwill of $133 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 tax liability.

The future income tax liability was determined based on the enacted income tax rate of approximately 29 percent. The asset retirement obligations were determined using Pengrowth's estimated costs to remediate, reclaim and abandon the wells and facilities, the estimated timing of the costs to be incurred in future periods, an inflation rate of two percent, and a discount rate of eight percent.

Results of operations from the Carson Creek acquisition subsequent to the acquisition date are included in the consolidated financial statements. Final determination of the cost of the acquisition and the allocation thereof to the fair values of the Carson Creek assets is still pending.



4. LONG TERM INVESTMENTS

September 30, 2006 December 31, 2005
---------------------------------------------------------------------------
Investment in Esprit Energy Trust $19,990 -

Equity investments 7,000 -
---------------------------------------------------------------------------
$26,990 -
---------------------------------------------------------------------------


INVESTMENT IN ESPRIT ENERGY TRUST

On July 24, 2006, Pengrowth announced an agreement providing for the combination of Pengrowth and Esprit (See Note 13). As at September 30, 2006, Pengrowth held 1,489,000 Esprit trust units with a market value of approximately $17.3 million. The investment is accounted for at cost. Distributions earned on the Esprit trust units of $1.4 million are recorded in other income, as received. On October 2, 2006, in connection with the business combination with Esprit, the Corporation received 789,170 Pengrowth trust units which were exchanged with and immediately cancelled by Pengrowth.

EQUITY INVESTMENTS

On January 12, 2006 Pengrowth closed certain transactions with Monterey Exploration Ltd. (Monterey) under which Pengrowth has sold certain oil and gas properties for $22 million in cash, less closing adjustments, and 8,048,132 common shares of Monterey. As of September 30, 2006, Pengrowth held approximately 34 percent of the common shares of Monterey.

Pengrowth utilizes the equity method of accounting for the investment in Monterey. The investment is initially recorded at cost and adjusted thereafter to include Pengrowth's pro rata share of post-acquisition earnings of Monterey. Any dividends received or receivable from Monterey would reduce the carrying value of the investment.

5. TRUST UNITHOLDERS' EQUITY

Trust Unitholders' Capital

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



Total Trust Units:

Nine months ended Year ended
September 30, 2006 December 31, 2005
---------------------------------------------------------------------------
Number Number
of trust of trust
Trust units issued units Amount units Amount
---------------------------------------------------------------------------
Balance, beginning of
period 159,864,083 $ 2,514,997 152,972,555 $ 2,383,284

Issued for the Crispin
acquisition (non cash) - - 4,225,313 87,960

Issued for cash 23,310,000 526,806 - -

Issue costs - (27,886) - -

Issued on redemption of
Deferred Entitlement
Trust Units (DEU's) 12,106 193 - -
Issued for cash on
exercise of trust unit
options and rights 553,270 8,613 1,512,211 21,818
Issued for cash under
Distribution Reinvestment
Plan (DRIP) 719,780 16,408 1,154,004 20,726
Trust unit rights
incentive plan (non-
cash exercised) - 907 - 1,209
---------------------------------------------------------------------------
Balance, end of period 184,459,239 $ 3,040,038 159,864,083 $ 2,514,997
---------------------------------------------------------------------------


"Consolidated" Trust Units:

Nine months ended Year ended
September 30, 2006 December 31, 2005
---------------------------------------------------------------------------
Number Number
of trust of trust
Trust units issued units Amount units Amount
---------------------------------------------------------------------------
Balance, beginning of
period - $ - - $ -

Issued in trust unit
consolidation 160,921,001 2,535,949 - -

Issued for cash 23,310,000 526,806 - -

Issue costs - (27,886) - -

Issued on redemption
of DEU's 12,106 193 - -

Issued for cash on
exercise of trust unit
options and rights 44,732 716 - -
Issued for cash under
DRIP 156,432 3,774 - -
Trust unit rights
incentive plan (non-
cash exercised) - 255 - -
---------------------------------------------------------------------------
Balance, end of period 184,444,271 $ 3,039,807 - $ -
---------------------------------------------------------------------------


Class A Trust Units:

Nine months ended Year ended
September 30, 2006 December 31, 2005
---------------------------------------------------------------------------
Number Number
of trust of trust
Trust units issued units Amount units Amount
---------------------------------------------------------------------------
Balance, beginning
of period 77,524,673 $ 1,196,121 76,792,759 $ 1,176,427

Issued for the Crispin
acquisition (non-cash) - - 686,732 19,002

Trust units converted to
(from) Class A trust
units 2,760 43 45,182 692
Trust Units converted to
"consolidated" trust
units (77,512,465) (1,195,933) - -
---------------------------------------------------------------------------
Balance, end of period 14,968 $ 231 77,524,673 $ 1,196,121
---------------------------------------------------------------------------


Class B Trust Units:

Nine months ended Year ended
September 30, 2006 December 31, 2005
---------------------------------------------------------------------------
Number Number
of trust of trust
Trust units issued units Amount units Amount
---------------------------------------------------------------------------
Balance, beginning
of period 82,301,443 $ 1,318,294 76,106,471 $ 1,205,734

Trust units converted
to (from) Class B 1,095 17 (9,824) (151)
trust units
Issued for the
Crispin acquisition
(non-cash) - - 3,538,581 68,958
---------------------------------------------------------------------------
Issued for cash on
exercise of trust unit
options and rights 508,538 7,897 1,512,211 21,818
Issued for cash under
DRIP 563,348 12,634 1,154,004 20,726
Trust unit rights
incentive plan (non-
cash exercised) - 652 - 1,209

Trust units converted
to "consolidated"
trust units (83,374,424) (1,339,494) - -
---------------------------------------------------------------------------
Balance, end of period - $ - 82,301,443 $ 1,318,294
---------------------------------------------------------------------------


Unclassified Trust Units:

Nine months ended Year ended
September 30, 2006 December 31, 2005
---------------------------------------------------------------------------
Number Number
of trust of trust
Trust units issued units Amount units Amount
---------------------------------------------------------------------------
Balance, beginning
of period 37,967 $ 582 73,325 $ 1,123
Converted to Class A or
Class B trust units (3,855) (60) (35,358) (541)

Trust Units converted to
"consolidated" trust units (34,112) (522) - -
---------------------------------------------------------------------------
Balance, end of period - $ - 37,967 $ 582
---------------------------------------------------------------------------


Class A Trust Unit and Class B Trust Unit Consolidation

On June 23, 2006 the Pengrowth unitholders voted to consolidate the Class A trust units and Class B trust units into one class of trust units ("consolidated" trust units). As a result:

- Effective as of 5:00 p.m. (MDT) on June 27, 2006, the restrictions on the Class B trust units that provided that the Class B trust units may only be held by residents of Canada was eliminated.

- Effective as of 5:00 p.m. (MDT) on July 27, 2006;

- the Class A trust units were delisted from the Toronto Stock Exchange (effective as of the close of markets);

- the Class B trust units were renamed consolidated trust units and the trading symbol of the consolidated trust units was changed from PGF.B to PGF.UN;

- all of the issued and outstanding Class A trust units were converted into consolidated trust units on the basis of one consolidated trust unit for each whole Class A trust unit previously held (with the exception of Class A trust units held by residents of Canada who have provided a residency declaration to the Trustee);

- the consolidated trust units were substitutionally listed in place of the Class A trust units on the New York Stock Exchange under the symbol PGH; and

- the unclassified trust units were converted into consolidated trust units on the basis of one consolidated trust unit for each unclassified trust unit held.

Per Trust Unit Amounts

The per trust unit amounts of net income are based on the following weighted average trust units outstanding for the period. The weighted average trust units outstanding for the three months ended September 30, 2006 were 161,502,209 trust units (September 30, 2005 - 158,789,481 trust units) and for the nine months ended September 30, 2006 were 160,752,712 trust units (September 30, 2005 - 156,318,245). In computing diluted net income per trust unit, 670,218 trust units were added to the weighted average number of trust units outstanding during the three months ended September 30, 2006 (September 30, 2005 - 507,494 trust units) and 647,654 trust units were added to the weighted average number of trust units outstanding during the nine months ended September 30, 2006 (September 30, 2005 - 502,233) for the dilutive effect of trust unit options, rights and deferred entitlement trust units (DEU's). For the three months ended September 30, 2006, no anti-dilutive options, rights or DEU's (September 30, 2005 - 10,140) and for the nine months ended September 30, 2006 no anti-dilutive options, rights or DEU's (September 30, 2005 - 549,284), were excluded from the diluted net income per trust unit calculation as their effect is anti-dilutive.



Contributed Surplus


Nine months ended Year ended
September 30, December 31,
2006 2005
---------------------------------------------------------------------------
Balance, beginning of period $ 3,646 $ 1,923
Trust unit rights incentive plan (non-cash
expensed) 1,056 1,740
DEU's(non-cash expensed) 1,791 1,192
Trust unit rights incentive plan (non-cash
exercised) (907) (1,209)
Redemption of DEU's (non-cash exercised) (193) -
---------------------------------------------------------------------------
Balance, end of period $ 5,393 $ 3,646
---------------------------------------------------------------------------


Deficit
As at As at
September 30, 2006 December 31, 2005
---------------------------------------------------------------------------
Accumulated earnings $ 1,312,376 $ 1,053,383
Accumulated distributions paid
or declared (2,469,442) (2,096,030)
---------------------------------------------------------------------------
$ (1,157,066) $ (1,042,647)
---------------------------------------------------------------------------


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.

6. TRUST UNIT BASED COMPENSATION PLANS

Trust Unit Option Plan

As at September 30, 2006, options to purchase 109,323 trust units were outstanding (December 31, 2005 - 259,317 Class B trust units) that expire at various dates to June 28, 2009. All outstanding trust unit options were fully expensed by December 31, 2004.



Nine months ended Year ended
September 30, 2006 December 31, 2005
---------------------------------------------------------------------------
Weighted Weighted
average average
Number exercise Number exercise
Trust unit options of options price of options price
---------------------------------------------------------------------------
Outstanding at beginning
of period 259,317 $ 17.28 845,374 $ 16.97

Exercised (144,594) $ 18.09 (558,307) $ 16.74

Expired or cancelled (5,400) $ 16.96 (27,750) $ 18.63

---------------------------------------------------------------------------
Outstanding and exercisable
at period-end 109,323 $ 16.23 259,317 $ 17.28
---------------------------------------------------------------------------


Trust Unit Rights Incentive Plan

As at September 30, 2006, rights to purchase 1,456,806 trust units were outstanding (December 31, 2005 - 1,441,737 Class B trust units) that expire at various dates to August 2, 2011.

Compensation expense associated with the trust unit rights granted during 2006 was based on the estimated fair value of $1.87 per trust unit right. The fair value of trust unit rights granted during the nine months ended September 30, 2006 was estimated at eight percent of the exercise price at the date of grant using a binomial lattice option pricing model with the following assumptions: risk-free rate of 4.1 percent, volatility of 19 percent and reductions in the exercise price over the life of the trust unit rights. For the nine months ended September 30, 2006, compensation expense of $1,056,000 (September 30, 2005 - $1,308,000) related to the trust unit rights was recorded.



Nine months ended Year ended
September 30, 2006 December 31, 2005
---------------------------------------------------------------------------
Weighted Weighted
average average
Number exercise Number exercise
Trust unit rights of rights price of rights price
---------------------------------------------------------------------------
Outstanding at beginning
of period 1,441,737 $ 14.85 2,011,451 $ 14.23
Granted (1) 477,366 $ 23.34 606,575 $ 18.34
Exercised (408,676) $ 14.68 (953,904) $ 12.81
Cancelled (53,621) $ 16.89 (222,385) $ 16.19
---------------------------------------------------------------------------
Outstanding at period-end 1,456,806 $ 16.33 1,441,737 $ 14.85
---------------------------------------------------------------------------
Exercisable at period-end 717,272 $ 14.11 668,473 $ 13.73
---------------------------------------------------------------------------

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


Long Term Incentive Program

As at September 30, 2006, 338,221 DEU's were outstanding (December 31, 2005 - 185,591), including accrued distributions re-invested to September 30, 2006. The DEU's vest on various dates to February 27, 2009. For the nine months ended September 30, 2006, Pengrowth recorded compensation expense of $1,791,000 (September 30, 2005 - $829,000) associated with the DEU's based on the weighted average estimated fair value of $20.74 (2005 - $18.18) per DEU. For the nine months ended September 30, 2006, 12,106 "consolidated" trust units were issued on redemption of DEU's by retired employees.



Nine months ended Year ended
Number of DEU's September 30, 2006 December 31, 2005
---------------------------------------------------------------------------
Outstanding, beginning of period 185,591 -

Granted 165,419 194,229

Cancelled (25,647) (26,258)
Redeemed (12,106) -
Deemed DRIP 24,964 17,620
---------------------------------------------------------------------------
Outstanding, end of period 338,221 185,591
---------------------------------------------------------------------------


Trust Unit Award Plans

Pengrowth has an incentive plan to reward and retain employees whereby trust units and, in some cases trust units and cash, are awarded to eligible employees. Employees will receive the trust units and cash on or about July 1, 2007. Pengrowth acquired the trust units to be awarded on the open market for $5.1 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 monthly to net income on a straight line basis. The cash portion of the incentive plan of approximately $1.1 million is being accrued monthly.

During the three months ended September 30, 2006, $0.7 million has been charged to net income and during the nine months ended September 30, 2006, $4.2 million has been charged to net income.



7. ASSET RETIREMENT OBLIGATIONS

Nine months ended Year ended
September 30, 2006 December 31, 2005
---------------------------------------------------------------------------
Asset retirement obligations,
beginning of period $ 184,699 $ 171,866
Increase (decrease) in liabilities
related to:

Acquisitions 39,237 6,347

Additions 1,455 1,972

Disposals (1,500) (3,844)

Revisions - 1,549

Accretion expense 11,721 14,162

Liabilities settled during the period (5,819) (7,353)
---------------------------------------------------------------------------

Asset retirement obligations,
end of period $ 229,793 $ 184,699
---------------------------------------------------------------------------


8. OTHER ASSETS

As at As at
September 30, 2006 December 31,2005
---------------------------------------------------------------------------
Imputed interest on note
payable - net of accumulated
amortization of $3,420 (2005 -
$ 2,859) $ 187 $ 748
Debt issue costs - net of
accumulated amortization of
$1,098 (2005 - $821) 1,720 1,997
Deferred compensation expense - net
of accumulated amortization of
$5,316 (2005 - $ 2,143) 4,048 2,141
---------------------------------------------------------------------------
5,955 4,886
Deferred foreign exchange gain on
revaluation of U.K. debt hedge 3,881 -
Remediation trust funds 9,598 8,329
---------------------------------------------------------------------------
$ 19,434 $ 13,215
---------------------------------------------------------------------------


9. FOREIGN EXCHANGE (GAIN) LOSS

Three months ended Nine months ended
September 30, September 30,
2006 2005 2006 2005
---------------------------------------------------------------------------
Unrealized foreign exchange on
(gain) loss on translation of U.S.
dollar denominated debt $ 300 $ (12,860) $ (9,060) $ (8,180)

Realized foreign exchange
(gain) loss (177) 605 63 (290)
---------------------------------------------------------------------------
$ 123 $ (12,255) $ (8,997) $ (8,470)
---------------------------------------------------------------------------


The U.S. dollar and U.K. pound sterling denominated debt are translated into Canadian dollars at the Bank of Canada exchange rate in effect at the close of business on the balance sheet date. Foreign exchange gains and losses on the U.S. dollar denominated debt are included in income. Foreign exchange gains and losses on translating the U.K pound sterling denominated debt and the associated gains and losses on the U.K. pound sterling denominated exchange swap are deferred and included in deferred charges.



10. OTHER CASH FLOW DISCLOSURES

Change in Non-Cash Operating Working Capital
Cash provided by (used for):

Three months ended Nine months ended
September 30, September 30,
2006 2005 2006 2005
---------------------------------------------------------------------------
Accounts receivable $ 12,462 $ (24,052) $ 22,278 $ (21,508)
Inventory - - - 439
Accounts payable and accrued
liabilities 17,895 23,884 29,052 25,138
Due to Pengrowth Management
Limited 994 957 (3,859) (2,229)
---------------------------------------------------------------------------
$ 31,351 $ 789 $ 47,471 $ 1,840
---------------------------------------------------------------------------

Change in Non-Cash Investing Working Capital
Cash provided by (used for):

Three months ended Nine months ended
September 30, September 30,
2006 2005 2006 2005
---------------------------------------------------------------------------
Accounts payable for
capital accruals $ 2,839 $ 1,527 $ (15,945) $ 1,527
---------------------------------------------------------------------------

Cash Payments

Three months ended Nine months ended
September 30, September 30,
2006 2005 2006 2005
---------------------------------------------------------------------------
Cash payments made (refund
received) for taxes $ 189 $ 626 $ 23 $ (266)
Cash payments made for
interest $ 2,272 $ 2,763 $ 14,715 $ 12,952


11. FINANCIAL INSTRUMENTS

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 September 30, 2006, Pengrowth had fixed the price and applied hedge accounting to future production as follows:



Crude Oil

Volume Reference Price
Remaining Term (bbl per day) Point per bbl
---------------------------------------------------------------------------
Financial:
Oct 1, 2006 - Dec 31, 2006 4,000 WTI (1) $ 64.08 Cdn
---------------------------------------------------------------------------

Natural Gas:
Volume Reference Price
Remaining Term (mmbtu per day) Point per mmbtu
---------------------------------------------------------------------------
Financial:
Oct 1, 2006 - Dec 31, 2006 2,500 Transco Z6 (1) $ 10.63 Cdn
Oct 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 period-end. At September 30, 2006, the amount Pengrowth would receive (pay) to terminate the financial crude oil and natural gas contracts would be $(2.8) million and $1.2 million, respectively.

As at September 30, 2006, Pengrowth had fixed the price and recognized the mark-to-market loss on future production as follows:



Crude Oil:
Volume Reference Price
Remaining Term (bbl per day) Point per bbl
---------------------------------------------------------------------------
Financial:
Jan 1, 2007 - Dec 31, 2007 2,000 WTI (1) $ 79.50 Cdn
Jan 1, 2007 - Dec 31, 2007 1,000 WTI (1) $ 86.15 Cdn
Jan 1, 2007 - Dec 31, 2007 1,000 WTI (1) $ 86.20 Cdn
---------------------------------------------------------------------------

Natural Gas:
Volume
Remaining Term (mmbtu per Reference Price
day) Point per mmbtu
---------------------------------------------------------------------------
Financial:
Nov 1, 2006 - Oct 1, 2007 5,000 Transco Z6 (1) $ 11.62 Cdn
Nov 1, 2006 - Oct 1, 2007 5,000 Chicago MI (1) $ 9.69 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 period-end. At September 30, 2006, the amount Pengrowth would receive to terminate the financial crude oil and natural gas contracts would be $10.4 million and $6.2 million, respectively.

Natural Gas Fixed Price Sales Contract:

Pengrowth also has a natural gas fixed price physical sales contract outstanding which was assumed in the 2004 Murphy acquisition, the details of which are provided below:



Volume Price
Remaining Term (mmbtu per day) per mmbtu (2)
---------------------------------------------------------------------------
2006 to 2009
Oct 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 - Apr 30, 2009 3,886 $2.40 Cdn
---------------------------------------------------------------------------

(2) Reference price based on AECO


As at September 30, 2006, the amount Pengrowth would pay to terminate the natural gas fixed price sales contract would be $17.8 million.

Fair Value of Financial Instruments

The carrying value of financial instruments included in the balance sheet, other than long term debt, the note payable, long term investments and remediation trust funds approximate their fair value due to their short maturity. The fair value of the other financial instruments is as follows:



As at September 30, As at December 31,
2006 2005
---------------------------------------------------------------------------

Fair Net Book Fair Net Book
Value Value Value Value
---------------------------------------------------------------------------
Remediation Funds $ 9,980 $ 9,598 $ 9,071 $ 8,329
U.S. dollar denominated debt 215,779 223,540 220,187 232,600
U.K. Pounds Sterling denominated
debt 101,874 104,370 101,257 100,489
---------------------------------------------------------------------------


12. OTHER LIABILITIES
As at September 30, As at December 31,
2006 2005
---------------------------------------------------------------------------
Current portion of contract
liabilities $ 4,573 $ 5,279
Note Payable 20,000 20,000
---------------------------------------------------------------------------
$ 24,573 $ 25,279
---------------------------------------------------------------------------


13. SUBSEQUENT EVENTS

On October 2, 2006 Pengrowth and Esprit announced the completion of the previously announced business combination. The combination was approved by in excess of 99 percent of the votes cast at the Esprit unitholder meeting held on September 26, 2006. As a result of the combination, approximately 35,514,327 Pengrowth trust units were issued to Esprit unitholders, including 789,170 Pengrowth trust units issued to the Corporation which were exchanged with and immediately cancelled by Pengrowth.

On October 2, 2006, concurrent with the closing of the business combination with Esprit, Pengrowth increased its extendible revolving credit facility to $950,000,000 and the addition of two new financial institutions into the syndicate. No other material changes were made to the credit facility. $315 million of the increase was used to repay and cancel Esprit's credit facility leaving over $500 million available to draw from the credit facility.

On October 27, 2006, Pengrowth entered into an exclusivity agreement with a third party with respect to a possible significant asset acquisition. Under the terms of the agreement, Pengrowth has made a $30 million payment as an exclusivity fee. If Pengrowth chooses not to proceed, the $30 million is not refundable. If the vendor chooses not to proceed, the $30 million is refundable. Pengrowth is now in the process of determining whether it will proceed in light of a variety of considerations, including the recent Federal Government announcement on taxability of Trusts. Pengrowth has no information as to whether the vendor will proceed.

Subsequent to September 30, 2006, Pengrowth has entered into a series of fixed price commodity sales contracts with third parties. The effect of theses contracts is to fix the price received in 2007 for a volume equivalent to approximately 25 percent of Pengrowth's total production for the nine months ended September 30, 2006. The forward and futures contracts are subject to market risk from fluctuating commodity prices and exchange rates.

Pengrowth had fixed the price and will recognize the mark-to-market loss on future production in future periods as follows:



Crude Oil:
Volume Reference Price
Remaining Term (bbl per day) Point per bbl
---------------------------------------------------------------------------
Financial:
Jan 1, 2007 - Dec 31, 2007 7,000 WTI (1) $ 73.49 Cdn
---------------------------------------------------------------------------

Natural Gas:
Volume
Remaining Term (mmbtu per Reference Price
day) Point per mmbtu
---------------------------------------------------------------------------
Financial:
Jan 1, 2007 - Dec 31, 2007 45,020 AECO $ 7.98 Cdn
Jan 1, 2007 - Dec 31, 2007 10,500 Chicago MI (1) $ 8.89 Cdn
---------------------------------------------------------------------------

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



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