Pengrowth Energy Trust
NYSE : PGH
TSX : PGF.UN

Pengrowth Energy Trust

August 06, 2009 21:21 ET

Pengrowth Energy Trust Announces Second Quarter 2009 Results

CALGARY, ALBERTA--(Marketwire - Aug. 6, 2009) - Pengrowth Corporation, administrator of Pengrowth Energy Trust (collectively "Pengrowth") (TSX:PGF.UN) (NYSE:PGH), is pleased to announce the interim unaudited operating and financial results for the three month period ended June 30, 2009.

Cash flow from operating activities before working capital changes was approximately $160.1 million ($0.62 per trust unit) in the second quarter of 2009 as compared to $130.4 million ($0.51 per trust unit) in the first quarter and $272.7 million ($1.10 per trust unit) in the same period last year. The decrease in cash flow from operations from the same period last year is largely due to lower commodity prices, partly offset by higher production volumes and lower royalty expenses.

Pengrowth recorded net income of $10.3 million ($0.04 per trust unit) for the second quarter of 2009 compared to a loss of $118.7 million ($0.48 per trust unit) in the same period last year. For both years, non-cash items, specifically unrealized losses on mark-to-market risk management contracts had a negative impact on net income, yet did not impact cash flow from operating activities.

Distributions declared in the second quarter totalled $77.5 million versus $77.2 million during the first quarter and $168.2 million in the second quarter last year. Pengrowth reduced its distributions in the first quarter of 2009 to $0.10 per trust unit per month, to align with the global decline in commodity prices since the second quarter of 2008. During the second quarter, Pengrowth declared distributions of $0.30 per trust unit to its unitholders, which is 48 percent of cash flow from operating activities before working capital changes. Pengrowth's distributions have remained stable at $0.10 per trust unit per month for the past six months, up to and including the most recently announced August 17, 2009 distribution.

Daily production was 82,171 boe per day, an increase of two percent when compared to both the first quarter's production of 80,284 boe per day and the second quarter of 2008's production of 80,895 boe per day. The increase was partially due to prior period adjustments, arising through the final stage of the integration process for assets previously acquired. In addition, volumes brought on stream from the development program together with a scheduled condensate lift at Sable Offshore Energy Project (SOEP) and minimal weather related issues throughout the quarter all aided in boosting production during the second quarter. At this time, Pengrowth is raising its guidance for annual production from 76,000 - 78,000 boe per day to 78,000 - 79,500 boe per day, excluding any impact from potential future acquisitions or dispositions.

Development capital for the second quarter of 2009 totalled $40.1 million, with approximately 63 percent spent on drilling and completions. Pengrowth participated in drilling 10 gross wells (5.4 net) throughout the quarter, all of which were cased for production.

Note regarding currency: all figures contained within this report are quoted in Canadian dollars unless otherwise indicated.

Chairman's Message

To our valued unitholders,

I am pleased to present the unaudited quarterly operating and financial results for the three months ended June 30, 2009. Although positive sentiment has begun to be reflected in the global marketplace, lower commodity prices through the first half of 2009 compared to the same period of 2008 continued to have the most significant impact on earnings and operating cash flow throughout the second quarter. The second quarter results reflected a stabilization in crude oil prices in the U.S. $50 to $60 per barrel range, recovering from the lows in the U.S. $32 to $35 range reached during the first quarter. Natural gas price weakness continued during the quarter averaging U.S. $ 3.50 per mcf as compared with U.S. $4.89 per mcf in the first quarter of 2009. Pengrowth was able to offset the weak crude oil and natural gas prices somewhat through our price risk management program and solid daily production averaging 82,171 boe per day during the quarter.

To summarize Pengrowth's second quarter results:

Operating cash flow before working capital changes was $160.1 million (or $0.62 per trust unit), a 23 percent increase over the first quarter's operating cash flow of $130.4 million (or $0.51 per trust unit) and a 41 percent decrease when compared to $272.7 million (or $1.10 per trust unit) in the second quarter of 2008.

Daily production increased two percent to 82,171 boe per day during the second quarter from the first quarter's level of 80,284 boe per day and also increased two percent from 2008's second quarter level of 80,895 boe per day. At this time, Pengrowth is raising its guidance for annual production from 76,000 - 78,000 boe per day to 78,000 - 79,500 boe per day.

The increase in production of almost 2,000 boe per day is partially attributable to prior period adjustments, arising through the final stage of the integration process for assets previously aquired. In addition, volumes brought on stream from the development program together with a scheduled condensate lift at Sable Offshore Energy Project (SOEP) and minimal weather related issues throughout the quarter all aided in boosting production during the second quarter.

Distributions declared remained stable during the second quarter totalling $77.5 million or $0.30 per trust unit as compared with $77.2 million or $0.30 per trust unit during the first quarter. When compared to the same period last year, distributions declared have declined by 54 percent from $168.2 million or $0.68 per trust unit declared during the second quarter of 2008.

The reduction in distributions year-over-year is reflective of Pengrowth's conservative approach toward both distributions and capital spending based on our continued commitment to preserve our financial flexibility. Pengrowth's payout ratio (ratio of distributions declared over cash flow from operating activities before working capital changes) for the second quarter of 2009 was 48 percent and our total payout ratio when including capital expenditures totalled 76 percent during the quarter. This represents an operating surplus and the outlook is positive for the balance of the year. Fully funding our capital program and distributions from cash flow from operating activities continues to place Pengrowth in a position of considerable flexibility to pursue new acquisition and consolidation activities should the right opportunities present themselves.

Beginning with the March 15, 2009 payment, Pengrowth has maintained our Cdn $0.10 per trust unit distribution level for six consecutive months up to and including the recently declared August 17, 2009 distribution. Pengrowth's board of directors will continue to prudently examine distributions on a monthly basis while considering overall oil and gas market conditions and capital spending requirements.

While our planned capital spending may be lower in 2009 than 2008, the projects have been selected to provide the greatest economic value for the capital spent. Capital development expenditures were $40.1 million for the second quarter of 2009 as compared with $68.0 million during the first quarter. Pengrowth's development program has continued to deliver as expected with 63 percent of our capital development expenditures being spent on the drilling of 10 gross wells (5.4 net) throughout the quarter, all of which were cased for production and $0.6 million was spent on land acquisitions, adding 5,560 net acres.

During the second quarter, we continued to selectively reallocate capital to high-grade projects where immediate cash flow and value creation could be realized. Capital reallocation of $23 million budgeted for other projects ($7 million from Lindbergh oil sands pilot project) was reallocated to our Carson Creek property, an area in which we have had considerable development success in recent months. Pengrowth acquired additional 3D seismic in the first quarter and plans to follow up with six horizontal wells during the remainder of the year. This area in the Carson pool had no production at the time of acquisition in 2006, yet following a drilling campaign of five vertical wells and one horizontal well production peaked at 1,500 boe per day. We plan to ramp up production for the remainder of the year and into the first quarter of 2010 pending success of the horizontal well drilling program which commenced in the second quarter. The Lindbergh oil sands property also continues to provide significant long term potential for Pengrowth and the progress being made on the pilot project remains important as commercial development is ready to move forward once commodity prices improve.

In May, the Government of Alberta, through Alberta Energy's Innovative Energy Technologies Program (IETP) announced it would commit $3.54 million towards Pengrowth's carbon dioxide enhanced oil recovery pilot at our Judy Creek facility in central Alberta. This project is very helpful in evaluating and confirming the economic viability of recovering additional reserves from Pengrowth's proven long-life conventional oil pools.

Over the quarter, Pengrowth continued to benefit from the stabilization in operating cash flow provided by our risk management strategy, especially as we continue to be challenged by depressed North American gas prices. In total, realized gains from our hedging strategy were $47.1 million in the quarter. Pengrowth realized a price of Cdn $73.26 per bbl on its light oil contracts during the second quarter as compared to the benchmark WTI (West Texas Intermediate) translated to Cdn $69.71 per bbl and realized a price of Cdn $4.78 per mcf(i) of natural gas, in comparison to the AECO spot benchmark of Cdn $3.47 per gj(i) and the NYMEX gas equivalent translated to Cdn $4.06 per mmbtu(i).

For the remainder of the year, Pengrowth has hedged approximately 64 percent of our net liquids production at a price of Cdn $82.45 per bbl and 44 percent of our net natural gas production at an average price of Cdn $8.00 per mmbtu. In addition, for 2010, Pengrowth has approximately 12,500 bbl per day of crude oil production hedged at Cdn $82.09 per bbl and 16,600 mmbtu per day of natural gas production hedged at Cdn $8.64 per mmbtu.

As the majority of our revenue is derived in U.S. dollars, the strengthening of the Canadian dollar in relation to the U.S. dollar has negatively impacted Pengrowth's revenue in Canadian dollar terms. The Canadian dollar/U.S. dollar exchange rate averaged 0.86 for the second quarter, closed at 0.86 on June 30, 2009 and has recently risen to the 0.92 U.S. level.

The average price realized for Pengrowth's oil and gas sales of $44.74 per boe, after commodity risk management contracts, remained stable when compared to the first quarter's average realized price of $44.57 per boe, after risk management contracts. When compared to the second quarter of 2008's average realized price of $73.21, 2009's second quarter average realized price decreased 39 percent. The stabilization between the first two quarters of the year is reflective of Pengrowth's active risk management program, whereas the decrease from the second quarter of last year to the second quarter of this year can be attributed to the lower commodity price environment in 2009 versus 2008.

Operating expenses in the second quarter of $11.84 per boe decreased 20 percent from $14.87 per boe in the first quarter as reductions in Alberta Power Pool prices resulted in lower operating expenses in the second quarter. Reductions in Alberta Power Pool prices resulted in a $7.8 million decrease in utility expenses over the quarter. At this time, due primarily to the lower utility pricing expected for the remainder of the year as well increased production guidance and ongoing cost reduction activities, Pengrowth is lowering our full year 2009 operating cost guidance from $14.45 per boe to $14.00 per boe. Cost savings will continue to be an important focus for Pengrowth given the current economic climate and depressed commodity prices.

Pengrowth's operating netback increased to $26.28 per boe in the second quarter of 2009 compared with $23.87 in the first quarter and $42.15 in the same period last year. The decrease in operating costs during the second quarter was the primary contributor to the higher netback quarter-over-quarter. The decrease in netback year-over-year can mainly be attributed to the decline in global commodity prices offset slightly by lower utility pricing.

Recent weeks have seen considerable positive sentiment in the financial markets as consumer confidence continues to rise, credit markets soften and global fiscal and monetary stimulus plans take hold. Pertinent to our industry, the fundamentals for crude oil also continue to strengthen with increasingly positive economic news. Since the first quarter, we have seen the leveling of crude prices from their lows in the mid $30 range to their current levels around the $70 mark.

Although there is continued concern over depressed North American natural gas prices these too seem to have found a stabilized trading range between U.S. $3.25 to $4.00 per mcf and we see a number of positive signs moving forward. Rig activity has declined dramatically in North America over the last year and production decline will likely cut into storage volumes as the economy recovers.

The Bank of Canada recently announced their belief that the Canadian economy will in fact grow through the next quarter and that Canada (and the rest of the world) are on the track toward economic recovery. Regardless of the differing beliefs on how swift a recovery may be, the popular opinion contends that we have found bottom and a definite revival of the financial markets is in the works. It is my belief that it is only a matter of time before a visible and firm recovery takes shape.

At Pengrowth, we are poised and ready to embark on the emerging road to recovery and we remain focused toward the growth and value opportunities that lie ahead for the Trust and our unitholders. Thank you for your continued support and dedication through the first half of this year and I look forward to the potential continued recovery that is ahead of us for the remainder of 2009.

Best regards,

James S. Kinnear, Chairman and Chief Executive Officer

August 6, 2009



Summary of Financial and Operating Results

Three Months ended June 30
(thousands, except per unit amounts) 2009 2008 % Change
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STATEMENT OF INCOME (LOSS)
Oil and gas sales $ 335,634 $ 550,623 (39)
Net income (loss) $ 10,272 $ (118,650) 109
Net income (loss) per trust unit $ 0.04 $ (0.48) 108
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CASH FLOWS
Cash flows from operating activities $ 144,116 $ 267,874 (46)
Cash flows from operating activities
per trust unit $ 0.56 $ 1.08 (48)

Distributions declared $ 77,526 $ 168,159 (54)
Distributions declared per trust unit $ 0.30 $ 0.675 (56)

Ratio of distributions declared over
cash flows from operating activities 54% 63% (14)

Capital expenditures $ 44,129 $ 83,060 (47)
Capital expenditures per trust unit $ 0.17 $ 0.33 (48)
Weighted average number of trust
units outstanding 257,971 248,489 4
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BALANCE SHEET
Working capital deficiency
Property, plant and equipment
Long term debt
Trust unitholders' equity
Trust unitholders' equity per
trust unit

Currency (U.S.$/Cdn$) (closing
rate at period end)

Number of trust units outstanding
at period end
----------------------------------------------------------------------------
AVERAGE DAILY PRODUCTION
Crude oil (barrels) 23,078 25,052 (8)
Heavy oil (barrels) 7,822 8,242 (5)
Natural gas (mcf) 247,604 234,028 6
Natural gas liquids (barrels) 10,004 8,596 16
Total production (boe) 82,171 80,895 2

TOTAL PRODUCTION (mboe) 7,478 7,361 2
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PRODUCTION PROFILE
Crude oil 28% 31%
Heavy oil 10% 10%
Natural gas 50% 48%
Natural gas liquids 12% 11%
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AVERAGE REALIZED PRICES
(after commodity risk management)
Crude oil (per barrel) $ 73.26 $ 83.88 (13)
Heavy oil (per barrel) $ 55.47 $ 100.34 (45)
Natural gas (per mcf) $ 4.78 $ 9.40 (49)
Natural gas liquids (per barrel) $ 36.68 $ 92.25 (60)
Average realized price per boe $ 44.74 $ 73.21 (39)
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Six Months ended June 30
(thousands, except per unit amounts) 2009 2008 % Change
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STATEMENT OF INCOME (LOSS)
Oil and gas sales $ 658,607 $ 1,008,229 (35)
Net income (loss) $ (43,960) $ (175,233) 75
Net income (loss) per trust unit $ (0.17) $ (0.71) 76
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CASH FLOWS
Cash flows from operating activities $ 238,502 $ 484,112 (51)
Cash flows from operating activities
per trust unit $ 0.93 $ 1.95 (52)

Distributions declared $ 154,738 $ 335,393 (54)
Distributions declared per trust unit $ 0.60 $ 1.350 (56)

Ratio of distributions declared over
cash flows from operating activities 65% 69% (6)

Capital expenditures $ 117,189 $ 176,594 (34)
Capital expenditures per trust unit $ 0.46 $ 0.71 (35)
Weighted average number of trust
units outstanding 257,352 247,873 4
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BALANCE SHEET
Working capital deficiency $(191,223)(1) $ (460,191) (58)
Property, plant and equipment $4,068,356 $ 4,199,258 (3)
Long term debt $1,388,158 $ 1,243,674 12
Trust unitholders' equity $2,487,501 $ 2,284,095 9
Trust unitholders' equity per
trust unit $ 9.63 $ 9.17 5

Currency (U.S.$/Cdn$) (closing
rate at period end) 0.8598 0.9990

Number of trust units outstanding
at period end 258,419 248,993 4
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AVERAGE DAILY PRODUCTION
Crude oil (barrels) 23,250 25,077 (7)
Heavy oil (barrels) 7,748 7,991 (3)
Natural gas (mcf) 241,949 237,618 2
Natural gas liquids (barrels) 9,910 9,131 9
Total production (boe) 81,233 81,803 (1)

TOTAL PRODUCTION (mboe) 14,703 14,888 (1)
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PRODUCTION PROFILE
Crude oil 29% 31%
Heavy oil 10% 10%
Natural gas 50% 48%
Natural gas liquids 11% 11%
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AVERAGE REALIZED PRICES
(after commodity risk management)
Crude oil (per barrel) $ 69.68 $ 81.63 (15)
Heavy oil (per barrel) $ 45.05 $ 82.13 (45)
Natural gas (per mcf) $ 5.37 $ 8.55 (37)
Natural gas liquids (per barrel) $ 36.16 $ 78.86 (54)
Average realized price per boe $ 44.66 $ 66.68 (33)
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(1) Includes $174.1 million current portion of long term debt.



Trust Unit Trading Information

Three Months ended Six Months ended
(thousands, except per June 30 June 30
trust unit amounts) 2009 2008 2009 2008

TRUST UNIT TRADING
PGH (NYSE)
High $ 9.00 U.S. $ 21.90 U.S. $ 10.11 U.S. $ 21.90 U.S.
Low $ 5.30 U.S. $ 18.86 U.S. $ 4.51 U.S. $ 13.67 U.S.
Close $ 7.90 U.S. $ 20.11 U.S. $ 7.90 U.S. $ 20.11 U.S.
Value $205,813 U.S. $392,743 U.S. $401,655 U.S. $650,299 U.S.
Volume 27,305 19,425 55,843 33,718

PGF.UN (TSX)
High $ 9.81 $ 21.56 $ 12.33 $ 21.56
Low $ 6.71 $ 19.17 $ 5.84 $ 14.16
Close $ 9.18 $ 20.50 $ 9.18 $ 20.50
Value $233,826 $569,706 $486,439 $1,127,595
Volume 26,934 28,004 57,499 58,759


The following discussion of financial results should be read in conjunction with the unaudited consolidated Financial Statements for six months ended June 30, 2009 of Pengrowth Energy Trust and is based on information available to August 6, 2009.

Frequently Recurring Terms

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

Pengrowth uses the following frequently recurring industry terms in this discussion: "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 contains forward-looking statements within the meaning of securities laws, including the "safe harbour" provisions of Canadian securities legislation and the United States Private Securities Litigation Reform Act of 1995. Forward-looking information is often, but not always, identified by the use of words such as "anticipate", "believe", "expect", "plan", "intend", "forecast", "target", "project", "guidance" "may", "will", "should", "could", "estimate", "predict" or similar words suggesting future outcomes or language suggesting an outlook. Forward-looking statements in this discussion include, but are not limited to, statements with respect to: reserves, 2009 production, production additions from Pengrowth's 2009 development program, royalty obligations, 2009 operating expenses, future income taxes, goodwill, asset retirement obligations, taxability of distributions, remediation and abandonment expenses, capital expenditures, general and administration expenses, and proceeds from the disposal of properties. Statements relating to "reserves" are forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions that the reserves described exist in the quantities predicted or estimated and can profitably be produced in the future.

Forward-looking statements and information are based on Pengrowth's current beliefs as well as assumptions made by, and information currently available to, Pengrowth concerning anticipated financial performance, business prospects, strategies, regulatory developments, future oil and natural gas commodity prices and differentials between light, medium and heavy oil prices, future oil and natural gas production levels, future exchange rates, the proceeds of anticipated divestitures, the amount of future cash distributions paid by Pengrowth, the cost of expanding our property holdings, our ability to obtain equipment in a timely manner to carry out development activities, our ability to market our oil and natural gas successfully to current and new customers, the impact of increasing competition, our ability to obtain financing on acceptable terms and our ability to add production and reserves through our development and exploitation activities. Although management considers these assumptions to be reasonable based on information currently available to it, they may prove to be incorrect.

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 and royalty laws; the failure to qualify as a mutual fund trust; and Pengrowth's ability to access external sources of debt and equity capital. Further information regarding these factors may be found under the heading "Business Risks" herein and under "Risk Factors" in Pengrowth's most recent Annual Information Form (AIF), and in Pengrowth's most recent consolidated financial statements, management information circular, quarterly reports, material change reports and news releases. Copies of the Trust's Canadian public filings are available on SEDAR at www.sedar.com. The Trust's U.S. public filings, including the Trust's most recent annual report form 40-F as supplemented by its filings on form 6-K, are available at www.sec.gov.

Pengrowth cautions that the foregoing list of factors that may affect future results is not exhaustive. When relying on our forward-looking statements to make decisions with respect to Pengrowth, investors and others should carefully consider the foregoing factors and other uncertainties and potential events. Furthermore, the forward-looking statements contained in this discussion are made as of the date of this discussion and Pengrowth does not undertake any obligation to update publicly or to revise any of the included forward-looking statements, except as required by law. The forward-looking statements in this document are provided for the limited purpose of enabling current and potential investors to evaluate an investment in Pengrowth. Readers are cautioned that such statements may not be appropriate, and should not be used for other purposes.

The forward-looking statements contained in this discussion are expressly qualified by this cautionary statement.

Critical Accounting Estimates

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 ended.

The amounts recorded for depletion, depreciation and amortization of injectants, the provision for asset retirement obligations, unit based compensation, goodwill and future taxes 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. The amounts recorded for the fair value of risk management contracts and the unrealized gains or losses on the change in fair value are based on estimates. These estimates can change significantly from period to period. As required by National Instrument 51-101 (NI 51-101) Standards of Disclosure for Oil and Gas Activities, Pengrowth uses independent qualified reserve evaluators in the preparation of the annual 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.

The preparation of financial statements in conformity with Canadian GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and revenues and expenses for the period then ended. Certain of these estimates may change from period to period resulting in a material impact on Pengrowth's results of operations, financial position, and change in financial position.

Non-GAAP Financial Measures

This discussion refers to certain financial measures that are not determined in accordance with GAAP in Canada or the United States. These measures do not have standardized meanings and may not be comparable to similar measures presented by other trusts or corporations. Measures such as operating netbacks do not have standardized meanings prescribed by GAAP.

Distributions can be compared to cash flow from operating activities in order to determine the amount, if any, of distributions financed through debt or short term borrowing. The current level of capital expenditures funded through retained cash, as compared to debt or equity, can also be determined when it is compared to the difference in cash flow from operating activities and distributions paid in the financing section of the Statement of Cash Flows.

Management monitors Pengrowth's capital structure using non-GAAP financial metrics. The two metrics are Total Debt to the trailing twelve months Earnings Before Interest, Taxes, Depletion, Depreciation, Amortization, Accretion, and other non-cash items (EBITDA) and Total Debt to Total Capitalization. Total Debt is the sum of working capital, long term debt and convertible debentures as shown on the balance sheet, and Total Capitalization is the sum of Total Debt and Unitholder's equity. Management believes that targeting prudent ratios of these measures are reasonable given the size of Pengrowth, its capital management objectives, growth strategy, uncertainty of oil and gas commodity prices and additional margin required from the debt covenants.

If the ratio of Total Debt to trailing EBITDA reaches or exceeds certain levels, management would consider steps to reduce the ratio of Total Debt to trailing EBITDA. If the ratio of Total Debt to Total Capitalization reaches or exceeds certain levels, Pengrowth management would consider steps to improve the ratio while considering our debt financial covenant limits.

Non-GAAP Operational Measures

The reserves and production in this discussion refer to Company Interest reserves or production that is Pengrowth's working interest share of production or reserves prior to the deduction of royalties plus the interest in production or reserves at the wellhead. Company interest is more fully described in Pengrowth's AIF.

When converting natural gas to equivalent barrels of oil within this discussion, Pengrowth uses the industry 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 primarily 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.

Currency

All amounts are stated in Canadian dollars unless otherwise specified.

OVERVIEW

Pengrowth generated cash flow from operating activities of $144.1 million during the second quarter of 2009, a 53 percent increase from the first quarter of 2009. Contributing to the increase were higher production volumes, higher realized prices for oil and natural gas liquids (NGL), lower operating expenses and a reduction in non-cash operating working capital. Lower commodity prices in the current year was the major contributor to a 51 percent decrease in operating cash flow and a 33 percent decrease in the operating netback comparing the first half of 2009 to the same period of 2008. Similarly, the 46 percent decrease in operating cash flows from the second quarter of 2008 to the second quarter of 2009 was primarily due to commodity prices retreating from 2008's record high oil prices and very strong natural gas prices.



Three months ended Six months ended
----------------------------------------------------------------------------
----------------------------------------------------------------------------
June 30, Mar 31, June 30, June 30, June 30,
2009 2009 2008 2009 2008
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Production (boe/d) 82,171 80,284 80,895 81,233 81,803
Netback ($/boe)(1) 26.28 23.87 42.15 25.10 37.84
Cash flows from operating
activities ($000's) 144,116 94,386 267,874 238,502 484,112
Net income (loss) ($000's) 10,272 (54,232)(118,650) (43,960)(175,233)
Included in net income:
Unrealized loss on commodity
risk management ($000's) (115,400) (12,616)(352,628)(128,016)(518,355)
Unrealized foreign exchange
gain (loss) on foreign
denominated debt ($000's) 79,835 (39,160) 4,735 40,675 (20,420)
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----------------------------------------------------------------------------
(1) Prior period restated to conform to presentation in the current period.


Comparing second quarter 2009 to the first quarter of 2009, Pengrowth recorded net income of $10.3 million compared to a net loss of $54.2 million in the first quarter of 2009 and a net loss of $118.7 million in the second quarter of 2008. Included in the net income (loss) are unrealized losses on mark-to-market commodity risk management contracts which result from the change in fair value of the contracts between periods. In the second quarter of 2009, an unrealized loss of $115.4 million before taxes ($82.5 million after tax) was recorded compared to an unrealized loss of $12.6 million before tax ($9.0 million after tax) in the first quarter of 2009 and an unrealized loss of $352.6 million before tax ($247.3 million after tax) in the second quarter of 2008. While the strengthening of the Canadian dollar relative to the U.S. dollar during the quarter had a negative impact on cash flow as lower revenue was received, the stronger dollar resulted in unrealized foreign exchange gains on foreign denominated debt of $79.8 million before tax ($79.8 million after tax) in the second quarter of 2009 compared to a loss of $39.2 million before tax ($39.2 million after tax) in the first quarter of 2009 and a gain of $4.7 million before tax ($4.1 million after tax) for the second quarter of 2008. During the first half of 2009, the net loss was approximately $44 million, a decrease of 75 percent compared to the first half of 2008.This decrease is primarily due to reduced unrealized commodity risk management losses in the current year, partly offset by lower price-driven revenue as discussed above.

The commodity risk management activities, which are utilized to partially secure returns from significant acquisitions and provide a level of stability to the Trust's cash flow from operating activities, has from time to time limited the Trust's ability to fully realize higher commodity prices. The commodity risk management activity did offset a portion of the Trust's exposure to the reduced natural gas prices through the second quarter and first half of 2009.

RESULTS OF OPERATIONS

This discussion contains the results of Pengrowth Energy Trust and its subsidiaries.

Production

Average daily production increased approximately two percent in the second quarter of 2009 compared to the first quarter of 2009. Second quarter 2009 production volumes benefited from prior period volumes which are mainly from prior year acquisitions, reduced solvent injection at Judy Creek, two minor acquisitions in the first quarter and results from development activity. Offsetting the production increases were scheduled and unscheduled maintenance shutdowns at Dunvegan and SOEP, respectively. In comparison to the second quarter of 2008, average daily production increased two percent as a result of the items noted above and the Accrete Energy Inc ("Accrete") acquisition completed September 30, 2008, partly offset by operational issues at SOEP. Daily production in the first half of 2009 decreased slightly compared to the same period of 2008 mainly due to the previously mentioned operational issues at SOEP, weather related issues experienced early in 2009 and natural decline, partly offset by the favorable items noted above.

At this time, Pengrowth is raising its 2009 full year average production guidance from 76,000 and 78,000 boe per day to between 78,000 and 79,500 boe per day. This estimate excludes the impact from any potential future acquisitions and dispositions.



Daily Production

Three months ended
----------------------------------------------------------------------------
June 30, % of Mar 31, % of June 30, % of
2009 total 2009 total 2008 total
----------------------------------------------------------------------------
Light crude oil(bbls) 23,078 28 23,424 29 25,052 31
Heavy oil(bbls) 7,822 10 7,672 10 8,242 10
Natural gas(mcfs) 247,604 50 236,232 49 234,028 48
Natural gas liquids(bbls) 10,004 12 9,815 12 8,596 11
----------------------------------------------------------------------------
Total boe per day 82,171 80,284 80,895
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Six months ended
----------------------------------------------------------------------------
June 30, % of June 30, % of
2009 total 2008 total
----------------------------------------------------------------------------
Light crude oil(bbls) 23,250 29 25,077 31
Heavy oil(bbls) 7,748 10 7,991 10
Natural gas(mcfs) 241,949 50 237,618 48
Natural gas liquids(bbls) 9,910 11 9,131 11
----------------------------------------------------------------------------
Total boe per day 81,233 81,803
----------------------------------------------------------------------------


Light crude oil production volumes decreased approximately one percent in the second quarter of 2009 compared to the first quarter of 2009 primarily a result of turnaround activity at Nipisi and natural declines. Production volumes decreased approximately eight percent comparing the second quarter of 2009 to the same period of 2008 and approximately seven percent for the first half of 2009 compared to the same period of 2008. The decreases are primarily attributable to the previously mentioned turnaround work, first quarter operational issues at Judy Creek and natural declines.

Heavy oil production increased approximately two percent compared to the first quarter of 2009. The increase in the second quarter was a result of the completion of downhole repair work at Tangleflags. The decrease in production comparing the second quarter of 2009 and first half of 2009 to the same periods of 2008 is attributable to maintenance activities at Tangleflags and natural declines offset by strong performance of the East Bodo polymer flood pilot.

Natural gas production increased five percent from the first quarter of 2009. The increase in the second quarter is attributable to prior period volumes from previous acquisitions (approximately 1,000 boe per day) being recorded in the current quarter. Other factors contributing to the increase in the second quarter include improved uptime at Quirk Creek, additional volumes as a result of the gas development program and the production from properties purchased in the first quarter. Partially offsetting the increases were operational issues at SOEP, turnaround activities at Dunvegan and natural declines. Production volumes increased six percent comparing the second quarter of 2009 to the same period of 2008 and approximately two percent for the first half of 2009 compared to the same period of 2008. These increases are a result of the prior period volumes recorded in the current quarter, additional volumes from the gas development program, particularly at Carson Creek and Monogram, volumes from the minor acquisitions in the first quarter, the Accrete acquisition and uptime at Olds in the current period as the maintenance shutdown in 2008 was not repeated in the current year. These increases to production were partially offset by the previously mentioned operational issues at SOEP, current year turnaround activity and natural declines.

NGL production increased two percent in the second quarter of 2009 compared to the first quarter of 2009 primarily due to the condensate lift at SOEP compared to the absence of a condensate lift in the first quarter of 2009 and prior period volumes being booked at Harmattan for ethane recoveries (approximately 500 bbls per day average for the second quarter). Second quarter 2009 production increased approximately 16 percent compared to second quarter 2008 and nine percent in the first six months of 2009 compared to the same period of 2008. These increases are attributable to the prior period ethane recoveries at Harmattan and higher sales at Judy Creek as a result of lower solvent injection in the second quarter of 2009, partially offset by decreased number of condensate lifts at SOEP in the current period and natural decline.

Pricing and Commodity Risk Management

Pengrowth's realizations are influenced by the benchmark prices; realized gains from commodity risk management activities have partially muted the effects of lower natural gas prices.

As part of its risk management strategy, Pengrowth uses forward price swaps 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. As of June 30, 2009, Pengrowth has crude oil contracts for the remainder of 2009, 2010 and 2011 for 15,500 bbls per day, 12,500 bbls per day and 500 bbls per day respectively. Also as of June 30, 2009, Pengrowth has natural gas contracts for the remainder of 2009 and 2010 for approximately 75,000 mcf per day and approximately 16,600 mcf per day, respectively. Each Cdn $1 per barrel change in future oil prices would result in approximately Cdn $7.6 million pre-tax change in the value of the crude contracts. Similarly, each Cdn $0.25 per mcf change in future natural gas prices would result in approximately Cdn $4.9 million pre-tax change in the value of the natural gas contracts. The changes in the fair value of the forward contracts directly affects reported net income as the unrealized amounts recorded in the income statement during the period. The effect on cash flows will be recognized separately only upon realization of the contracts, which could vary significantly from the unrealized amount recorded due to timing and prices when each contract is settled. However, if each contract were to settle at the contract price in effect at June 30, 2009, future revenue and cash flow would be increased by the $36.7 million unrealized commodity risk management asset that has been recorded to June 30, 2009. The $36.7 million asset is composed of an asset of $46.3 million relating to contracts expiring in 2009 and a liability of $9.6 million relating to contracts expiring in 2010 and 2011. Pengrowth has fixed the Canadian dollar exchange rate at the same time that it swaps any U.S. dollar denominated commodity in order to protect against changes in the foreign exchange rate.

Pengrowth has not designated any outstanding commodity contracts as hedges for accounting purposes and therefore records these contracts on the balance sheet at their fair value and recognize changes in fair value on the income statement as unrealized commodity risk management gains or losses. There will continue to be volatility in earnings to the extent that the fair value of commodity contracts fluctuate however, these non-cash amounts do not impact Pengrowth's operating cash flows. Realized commodity risk management gains or losses are recorded in oil and gas sales on the income statement and impacts cash flows at that time.



Average Realized Prices

Three months ended Six months ended
----------------------------------------------------------------------------
----------------------------------------------------------------------------
June 30, Mar 31, June 30, June 30, June 30,
(Cdn$) 2009 2009 2008 2009 2008
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Light crude oil (per bbl) 64.50 48.06 119.96 56.25 106.84
after realized commodity
risk management 73.26 66.12 83.88 69.68 81.63
Heavy oil (per bbl) 55.47 34.31 100.34 45.05 82.13
Natural gas (per mcf) 3.51 5.31 10.05 4.38 8.77
after realized commodity
risk management 4.78 6.00 9.40 5.37 8.55
Natural gas liquids (per bbl) 36.68 35.62 92.25 36.16 78.86
----------------------------------------------------------------------------
Total per boe 38.44 37.27 86.26 37.87 75.04
after realized commodity
risk management 44.74 44.57 73.21 44.66 66.68
----------------------------------------------------------------------------
Benchmark prices
WTI oil (U.S.$ per bbl) 59.62 43.08 123.98 51.35 110.94
AECO spot gas (Cdn$ per gj) 3.47 5.34 8.86 4.40 7.81
NYMEX gas (U.S.$ per mmbtu) 3.50 4.89 10.93 4.19 9.48
Currency (U.S.$/Cdn$) 0.86 0.80 0.99 0.83 0.99
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Lower commodity prices through the first half of 2009 compared to the same period of 2008 had the most significant impact to earnings and operating cash flow.



Commodity Risk Management Gains (Losses)

Three months ended Six months ended
----------------------------------------------------------------------------
June 30, Mar 31, June 30, June 30, June 30,
(Realized) 2009 2009 2008 2009 2008
----------------------------------------------------------------------------

Light crude oil ($ millions) 18.4 38.1 (82.2) 56.5 (115.0)
Light crude oil ($ per bbl) 8.76 18.06 (36.08) 13.43 (25.21)

Natural gas ($ millions) 28.7 14.7 (13.8) 43.4 (9.4)
Natural gas ($ per mcf) 1.27 0.69 (0.65) 0.99 (0.22)
----------------------------------------------------------------------------
Combined ($ millions) 47.1 52.8 (96.0) 99.9 (124.4)
Combined ($ per boe) 6.30 7.30 (13.06) 6.79 (8.36)
----------------------------------------------------------------------------

----------------------------------------------------------------------------
Unrealized
----------------------------------------------------------------------------
Total unrealized risk
management assets (liabilities)
at period end ($ millions) 36.7 152.1 (603.6) 36.7 (603.6)
Less: Unrealized risk management
assets (liabilities)
at beginning of period
($ millions) 152.1 164.7 (250.9) 164.7 (85.2)
----------------------------------------------------------------------------
Unrealized (loss) gain on risk
management contracts (115.4) (12.6) (352.6) (128.0) (518.4)
----------------------------------------------------------------------------


During the first and second quarters of 2009, natural gas prices continued to decline while oil prices increased, however both commodity prices remained lower than prices established in the commodity risk management contracts resulting in realized commodity risk management gains. These gains are included in oil and gas sales in the income statement.

As the commodity risk management contracts settle, the effect on cash flows will vary due to timing, prices and the volume under contract. This variance is evidenced by comparing the commodity risk management gains positively impacting cash flow in the second quarter of $47 million and through the first half of 2009 of $100 million, while the second quarter and first half of 2008 experienced losses of $96 million and $124 million respectively, which negatively impacted cash flow.



Oil and Gas Sales - Contribution Analysis

The following table includes the impact of realized commodity risk
management activity.

($ millions) Three months ended
----------------------------------------------------------------------------
June 30, % of Mar 31, % of June 30, % of
Sales Revenue 2009 total 2009 total 2008 total
----------------------------------------------------------------------------
Light crude oil 153.8 46 139.4 43 191.2 35
Natural gas 107.8 32 127.5 40 200.3 36
Natural gas liquids 33.4 10 31.5 10 72.2 13
Heavy oil 39.5 12 23.7 7 75.3 14
Brokered sales/sulphur 1.1 - 0.9 - 11.6 2
----------------------------------------------------------------------------
Total oil and gas sales 335.6 323.0 550.6
----------------------------------------------------------------------------



($ millions) Six months ended
----------------------------------------------------------------------------
June 30, % of June 30, % of
Sales Revenue 2009 total 2008 total
----------------------------------------------------------------------------
Light crude oil 293.2 45 372.6 37
Natural gas 235.3 36 369.7 37
Natural gas liquids 64.9 10 131.1 13
Heavy oil 63.2 9 119.5 12
Brokered sales/sulphur 2.0 - 15.3 1
----------------------------------------------------------------------------
Total oil and gas sales 658.6 1,008.2
----------------------------------------------------------------------------


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 realized
commodity risk management activity, for the second quarter of 2009 compared
to the first quarter of 2009.



----------------------------------------------------------------------------
Light Natural Heavy Other
($ millions) oil gas NGLs oil (1) Total
----------------------------------------------------------------------------
Quarter ended Mar 31,
2009 139.4 127.5 31.5 23.7 0.9 323.0
Effect of change in
product prices 34.5 (40.5) 1.0 15.1 - 10.1
Effect of change in
sales volumes (0.4) 6.7 1.0 0.7 - 8.0
Effect of change in
realized commodity
risk management
activities (19.7) 14.0 - - - (5.7)
Other - 0.1 (0.1) - 0.2 0.2
----------------------------------------------------------------------------
Quarter ended June 30,
2009 153.8 107.8 33.4 39.5 1.1 335.6
----------------------------------------------------------------------------
(1) Primarily sulphur sales


The following table illustrates the effect of changes in prices and volumes on the components of oil and gas sales including the impact of realized commodity risk management activity, for the first six months of 2009 compared to the same period of 2008.



----------------------------------------------------------------------------
Light Natural Heavy Other
($ millions) oil gas NGLs oil (1) Total
----------------------------------------------------------------------------
Period ended June 30,
2008 372.6 369.7 131.1 119.5 15.3 1,008.2
Effect of change in
product prices (212.9) (192.2) (76.6) (52.0) - (533.7)
Effect of change in
sales volumes (38.0) 4.8 10.4 (4.3) - (27.1)
Effect of change in
realized commodity
risk management
activities 171.6 52.8 - - - 224.4
Other (0.1) 0.2 - - (13.3) (13.2)
----------------------------------------------------------------------------
Period ended June 30,
2009 293.2 235.3 64.9 63.2 2.0 658.6
----------------------------------------------------------------------------
(1) Primarily sulphur sales



Processing and Other Income

Three months ended Six months ended
----------------------------------------------------------------------------
June 30, Mar 31, June 30, June 30, June 30,
($ millions) 2009 2009 2008 2009 2008
----------------------------------------------------------------------------
Processing & other income(1) 4.8 4.8 3.8 9.6 8.0
$ per boe 0.64 0.67 0.51 0.65 0.54
----------------------------------------------------------------------------
(1) Prior period restated to conform to presentation adopted in the current
period.


Processing and other income is primarily derived from fees charged for processing and gathering third party gas, road use, oil and water processing. Income is higher in the second quarter 2009 and for the first half of 2009 compared to the same time periods of 2008 primarily a result of additional income from road use fees and oil processing included in the current period.

This income primarily represents the partial recovery of operating expenses reported separately.



Royalty Expense

Three months ended Six months ended
----------------------------------------------------------------------------
June 30, Mar 31, June 30, June 30, June 30,
($ millions) 2009 2009 2008 2009 2008
----------------------------------------------------------------------------

Royalty expense 47.0 39.9 125.6 86.9 223.8
$ per boe 6.29 5.52 17.05 5.91 15.03
----------------------------------------------------------------------------
Royalties as a percent of sales 14.0% 12.3% 22.8% 13.2% 22.2%
Royalties as a percent of sales
excluding realized risk
management contracts 16.3% 14.6% 19.4% 15.6% 19.8%
----------------------------------------------------------------------------


Royalties include Crown, freehold and overriding royalties as well as mineral taxes. The increase in the royalty rate in the second quarter 2009 compared to the first quarter is a result of recording unfavorable Enhanced Oil Recovery (EOR) adjustments at partner operated properties related to prior periods of $5.4 million which was offset by favorable 13 month adjustments for 2008 gas cost allowance of $6.6 million. Also contributing to the second quarter increase is a prior period adjustment recorded in the first quarter for estimate to actual adjustments for mineral taxes of $8.0 million. The lower royalty rate in the current period comparing second quarter and the first half of 2009 to the same time periods of 2008 is reflective of lower commodity prices and the implementation of The New Royalty Framework in Alberta which became effective January 1, 2009. Royalty payments are based on revenue prior to commodity risk management activities. Gains or losses from realized commodity risk management activities are reported as part of sales and therefore affect royalty rates as a percentage of sales.

Pengrowth is forecasting royalty expense to average approximately 18 percent of sales excluding the impact of risk management contracts.



Operating Expenses

Three months ended Six months ended
----------------------------------------------------------------------------
June 30, Mar 31, June 30, June 30, June 30,
($ millions) 2009 2009 2008 2009 2008
----------------------------------------------------------------------------

Operating expenses 88.6 107.5 109.7 196.0 209.2
$ per boe 11.84 14.87 14.89 13.33 14.05
----------------------------------------------------------------------------


Operating expenses decreased approximately 18 percent from the first quarter of 2009 or 20 percent on a boe basis. This decrease is mainly attributable to a 41 percent decrease in Alberta Power Pool prices which resulted in a $7.8 million decrease in utility expenses. Other decreases in the current quarter were a result of lower activity for subsurface and surface facility maintenance (approximately $5.0 million) at Goose River, Judy Creek and Jenner; lower chemical purchases in the current quarter ($2.0 million); and the deferral of some maintenance projects. Second quarter 2009 operating expenses decreased $21.1 million compared to the second quarter of 2008. In addition to the previously mentioned lower utility prices, lower maintenance activities and deferral of maintenance projects in the current quarter, second quarter 2008 included $4.5 million of expenses related to the Olds turnaround not repeated in the current year. Operating expenses for the first half of 2009 compared to the first half of 2008 decreased by $13.2 million mainly attributable to a 44 percent decrease in power pool prices, the absence of turnaround expenses at Olds and the deferral of maintenance activities.

At this time, primarily due to lower utility pricing as well as increased production guidance; Pengrowth is lowering its anticipated total operating expenses for 2009 from approximately $14.45 per boe to approximately $14.00 per boe.



Net Operating Expenses

Three months ended Six months ended
----------------------------------------------------------------------------
June 30, Mar 31, June 30, June 30, June 30,
($ millions) 2009 2009 2008 2009 2008
----------------------------------------------------------------------------

Net operating expenses(1) 83.8 102.7 105.9 186.5 201.2
$ per boe 11.20 14.20 14.38 12.68 13.51
----------------------------------------------------------------------------
(1) Prior period restated to conform to presentation adopted in the current
period.


Included in the table above are operating expenses net of processing and other income.



Transportation Costs

Three months ended Six months ended
----------------------------------------------------------------------------
June 30, Mar 31, June 30, June 30, June 30,
($ millions) 2009 2009 2008 2009 2008
----------------------------------------------------------------------------

Light oil transportation 1.1 0.8 1.1 1.9 2.3
$ per bbl 0.50 0.38 0.50 0.44 0.50
Natural gas transportation 1.9 1.8 2.1 3.7 4.2
$ per mcf 0.09 0.09 0.10 0.09 0.10
----------------------------------------------------------------------------


Pengrowth incurs transportation costs for its natural gas production once the product enters pipeline at a title transfer point. Pengrowth also incurs transportation costs on its oil production that includes clean oil trucking charges and pipeline costs once the product enters a feeder or main pipeline. The transportation cost is dependant upon third party rates and distance the product travels 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. Pengrowth sells 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 Six months ended
----------------------------------------------------------------------------
June 30, Mar 31, June 30, June 30, June 30,
($ millions) 2009 2009 2008 2009 2008
----------------------------------------------------------------------------

Purchased and capitalized 4.1 2.6 7.0 6.7 10.8
Amortization 5.4 5.3 5.7 10.7 13.5
----------------------------------------------------------------------------


The cost of injectants (primarily natural gas and ethane) purchased for injection in the miscible flood program at Judy Creek and Swan Hills is amortized equally over the period of expected future economic benefit. The costs of injectants purchased are amortized over a 24 month period. As of June 30, 2009, the balance of unamortized injectant costs was $18.4 million.

The amount of injectants purchased and capitalized in the second quarter 2009 was higher than the first quarter of 2009 as Pengrowth relied more heavily on third party volumes for injectant requirements rather than on proprietary volumes. The value of Pengrowth's proprietary injectants is not recorded as an asset or a sale; the cost of producing these injectants is included in operating expenses.

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 NGL production.

Pengrowth recorded an average operating netback of $26.28 per boe in the second quarter of 2009 compared to $23.87 per boe in the first quarter of 2009 and $42.15 per boe for the second quarter of 2008. The increase in the netback in the second quarter of 2009 compared to the first quarter of 2009 is primarily attributable to lower operating expenses. The decrease in operating netback in the first half of 2009 compared to the first half of 2008 was primarily a result of lower combined commodity price realizations and partly offset by lower royalty expenses.

The sales price used in the calculation of operating netbacks is after realized commodity risk management gains or losses.



---------------------------------------------
Three months ended Six months ended
June 30, Mar 31, June 30, June 30, June 30,
Combined Netbacks ($ per boe) 2009 2009 2008 2009 2008
---------------------------------------------
---------------------------------------------
Sales price (after commodity
risk management) 44.74 44.57 73.21 44.66 66.68
Other production income(1) 0.15 0.12 1.59 0.14 1.04
---------------------------------------------
44.89 44.69 74.80 44.80 67.72
Processing and other income(2) 0.64 0.67 0.51 0.65 0.54
Royalties (6.29) (5.52) (17.05) (5.91) (15.03)
Operating expenses (11.84) (14.87) (14.89) (13.33) (14.05)
Transportation costs (0.40) (0.36) (0.45) (0.38) (0.44)
Amortization of injectants (0.72) (0.74) (0.77) (0.73) (0.90)
---------------------------------------------
Operating netback 26.28 23.87 42.15 25.10 37.84
---------------------------------------------

---------------------------------------------
---------------------------------------------
Three months ended Six months ended
Light Crude Netbacks June 30, Mar 31, June 30, June 30, June 30,
($ per bbl) 2009 2009 2008 2009 2008
---------------------------------------------
---------------------------------------------

Sales price (after commodity
risk management) 73.26 66.12 83.88 69.68 81.63
Other production income(1) 0.66 (0.03) 0.76 0.32 0.38
---------------------------------------------
73.92 66.09 84.64 70.00 82.01
Processing and other income(2) 0.84 1.19 0.34 1.01 0.50
Royalties (12.18) (9.28) (17.52) (10.73) (16.48)
Operating expenses (19.81) (15.05) (16.39) (17.42) (15.96)
Transportation costs (0.50) (0.38) (0.50) (0.44) (0.50)
Amortization of injectants (2.56) (2.53) (2.50) (2.55) (2.95)
---------------------------------------------
Operating netback 39.71 40.04 48.07 39.87 46.62
---------------------------------------------

---------------------------------------------
---------------------------------------------
Three months ended Six months ended
Heavy Oil Netbacks June 30, Mar 31, June 30, June 30, June 30,
($ per bbl) 2009 2009 2008 2009 2008
---------------------------------------------
---------------------------------------------
Sales price 55.47 34.31 100.34 45.05 82.13
Processing and other income 1.43 0.41 0.70 0.93 0.49
Royalties(3) (12.05) (4.08) (15.07) (8.12) (12.22)
Operating expenses (4) (5.97) (15.73) (11.60) (10.78) (11.96)
---------------------------------------------
Operating netback 38.88 14.91 74.37 27.08 58.44
---------------------------------------------

---------------------------------------------
---------------------------------------------
Three months ended Six months ended
Natural Gas Netbacks June 30, Mar 31, June 30, June 30, June 30,
($ per mcf) 2009 2009 2008 2009 2008
---------------------------------------------
---------------------------------------------

Sales price (after commodity
risk management) 4.78 6.00 9.40 5.37 8.55
Other production income(1) (0.01) 0.04 0.47 0.02 0.32
---------------------------------------------
4.77 6.04 9.87 5.39 8.87
Processing and other income(2) 0.09 0.10 0.12 0.09 0.12
Royalties(5) (0.11) (0.45) (2.06) (0.27) (1.85)
Operating expenses (1.55) (2.45) (2.39) (1.98) (2.21)
Transportation costs (0.09) (0.09) (0.10) (0.09) (0.10)
---------------------------------------------
Operating netback 3.11 3.15 5.44 3.14 4.83
---------------------------------------------

---------------------------------------------
---------------------------------------------
Three months ended Six months ended
June 30, Mar 31, June 30, June 30, June 30,
NGLs Netbacks ($ per bbl) 2009 2009 2008 2009 2008
---------------------------------------------
---------------------------------------------

Sales price 36.68 35.62 92.25 36.16 78.86
Royalties (11.40) (9.11) (38.77) (10.27) (30.66)
Operating expenses (8.68) (14.48) (16.36) (11.54) (14.20)
---------------------------------------------
Operating netback 16.60 12.03 37.12 14.35 34.00
---------------------------------------------
---------------------------------------------

(1) Other production income includes sulphur revenue and brokered sales.
(2) Prior period restated to conform to presentation in the current period
(3) Heavy oil royalties in the second quarter of 2009 includes unfavorable
EOR adjustments related to 2005 - 2008.
(4) Heavy oil operating expenses lower in the second quarter as a result of
lower sub-surface maintenance activity and utility costs.
(5) Natural gas royalties in the first quarter of 2009 includes accounting
adjustments to Freehold Mineral Tax for prior periods.



Interest Expense

Three months ended Six months ended
----------------------------------------------------------------------------
June 30, Mar 31, June 30, June 30, June 30,
($ millions) 2009 2009 2008 2009 2008
----------------------------------------------------------------------------

Interest Expense(1) 20.6 22.0 18.6 42.6 34.6
----------------------------------------------------------------------------
(1) Prior Period restated to conform to presentation adopted in the current
period.


At June 30, 2009, Pengrowth had $1,562.3 million of debt outstanding composed of $1,388.2 million in long term debt and $174.1 million of current debt. Of this approximately 71 percent is fixed at a weighted average interest rate of 6.2 percent with the remaining 29 percent subject to floating rates. The majority of the fixed rate debt incurs interest in U.S dollars and is therefore subject to fluctuations in the U.S. dollar exchange rates.

During the third quarter of 2008 Pengrowth closed the issuance of two series of private placement senior unsecured notes at an average rate of 6.96 percent, replacing debt from the lower rate term credit facility. As a result of both this issuance and the higher overall debt level Pengrowth's interest expense during the first half of 2009 increased relative to the first half of 2008. (See Note 3 of the consolidated financial statements for further details on debt outstanding.)



General and Administrative Expenses

Three months ended Six months ended
----------------------------------------------------------------------------
June 30, Mar 31, June 30, June 30, June 30,
($ millions) 2009 2009 2008 2009 2008
----------------------------------------------------------------------------

Cash G&A expense 14.0 14.2 11.2 28.2 23.9
$ per boe 1.87 1.97 1.52 1.92 1.61
Non-cash G&A expense 3.0 3.2 2.0 6.2 4.6
$ per boe 0.40 0.44 0.27 0.42 0.31
----------------------------------------------------------------------------
Total G&A 17.0 17.4 13.2 34.4 28.5
$ per boe 2.27 2.41 1.79 2.34 1.91
----------------------------------------------------------------------------


The cash component of general and administrative (G&A) expenses was relatively consistent comparing the first and second quarters of 2009. Cash G&A increased $2.8 million in the second quarter of 2009 compared to the second quarter of 2008 primarily due to the estimated reimbursement of G&A incurred by the Manager, pursuant to the management agreement, of $1.5 million and the absence of a favourable recovery of $0.9 million related to the 2007 dispositions which was booked in the second quarter 2008 and not repeated in the current period. In the first half of 2009, cash G&A increased $4.3 million compared to the first half of 2008. This increase is primarily due to the previously mentioned reimbursement of expenses to the Manager and the absence of the favourable adjustment completed in 2008 as well as additional professional fees and software licensing of $1.5 million.

The non-cash component of G&A represents the compensation expense associated with Pengrowth's Long Term Incentive Programs (LTIP) including trust unit rights and deferred entitlement units. The increase comparing the first half of 2009 to the first half of 2008 is due to increased employee base resulting from the 2006 and 2007 acquisitions.

On a per boe basis, G&A is anticipated to be approximately $2.37 per boe for full year 2009, which includes non-cash G&A and anticipated management fees of approximately $0.10 per boe.



Management Fees

Three months ended Six months ended
----------------------------------------------------------------------------
June 30, Mar 31, June 30, June 30, June 30,
($ millions) 2009 2009 2008 2009 2008
----------------------------------------------------------------------------

Management Fee (0.2) 3.0 2.6 2.8 6.0
$ per boe (0.03) 0.42 0.35 0.19 0.40
----------------------------------------------------------------------------


The management agreement expired on June 30, 2009.

Management fees were $2.8 million for the first six months of 2009, which will result in a 2009 full year average of $0.10 per boe, as no further management fees will be incurred in 2009.

Management fees for the second quarter are much lower than the first quarter due to adjusting the first quarter accrual to the actual amount payable for the final 6 month period of the contract.

Taxes

In determining its taxable income, the Corporation deducts payments made to the Trust, effectively transferring the income tax liability to unitholders thus reducing the Corporation's taxable income to nil. Under the Corporation's current distribution policy, at the discretion of the board, funds can be withheld to fund future capital expenditures, repay debt or used for other corporate purposes. If withholdings increased sufficiently or the Corporation's tax pool balances were reduced sufficiently, the Corporation could become subject to taxation on a portion of its income in the future. This can be mitigated through various options including the issuance of additional trust units, increased tax pools from additional capital spending, modifications to the distribution policy or potential changes to the corporate structure.

Bill C-52 Budget Implementation Act 2007

Bill C-52 modifies the taxation of certain flow-through entities including mutual fund trusts referred to as "specified investment flow-through" entities or "SIFTS" and the taxation of distributions from such entities (the "SIFT Legislation"). Bill C-52 applies a tax at the trust level on distributions of certain income from such a SIFT trust at a rate of tax comparable to the combined federal and provincial corporate tax rate. These distributions will be treated as dividends to the trust unitholders.

Pengrowth believes that it is characterized as a SIFT trust and, as a result, will be subject to Bill C-52 commencing on January 1, 2011 subject to the qualification below regarding the possible loss of the four year grandfathering period in the case of "undue expansion". Pengrowth may lose the benefit of the grandfathering period, which ends December 31, 2010, if Pengrowth exceeds the limits on the issuance of new trust units and convertible debt that constitute normal growth during the grandfathering period (subject to certain exceptions). The normal growth limits are calculated as a percentage of Pengrowth's market capitalization of approximately $4.8 billion on October 31, 2006. The normal growth guidelines have been revised to accelerate the safe harbour amount for each of 2009 and 2010. As of June 30, 2009 Pengrowth may issue $4.2 billion of equity in total for 2009 and 2010 under the safe harbour provision. The normal growth restriction on trust unit issuance is monitored by management as part of the overall capital management objectives. Pengrowth is in compliance with the normal growth restrictions.

Based on existing tax legislation, the tax rate in 2011 is expected to be 26.5 percent and 25 percent in 2012 and subsequent years. The payment of this tax will reduce the amount of cash available for distribution to unitholders.

On July 14, 2008, Finance released for comment proposed amendments to the Income Tax Act (Canada) to facilitate the conversion of existing income trusts and other public flow through entities into corporations on a tax deferred basis. On January 27, 2009, Finance introduced a notice of ways and mean motion in Parliament to implement the conversion rules which was subsequently enacted on March 12, 2009. The conversion rules would provide an existing income trust with tax efficient structuring options to convert to a corporate form. The conversion rules would be available to Pengrowth if Pengrowth determines to convert to a corporation. The transition provisions are only available to trusts that convert prior to 2013. Pengrowth can continue to have the benefit of its tax structure through December 31, 2010. Should Pengrowth remain a trust for any period after January 1, 2011, Pengrowth would be subject to the SIFT tax and would utilize existing tax pools to mitigate a portion of the SIFT tax. Bill C-10, which received Royal Assent on March 12, 2009, contained legislation implementing the conversion rules.

Pursuant to the SIFT Legislation, the distribution tax will only apply in respect of distributions of income and will not apply to returns of capital. Pengrowth currently has available tax pool balances of approximately $2.8 billion, which will be considered in identifying the alternatives and timing of our response to the enactment of the SIFT Legislation.

Future Income Taxes

Future income tax is a non-cash item relating to temporary differences between the accounting and tax basis of Pengrowth's assets and liabilities and has no immediate impact on Pengrowth's cash flows. During the second quarter of 2009, Pengrowth recorded a future tax recovery of $39.6 million to reflect temporary differences primarily relating to unrealized risk management losses and a true-up of tax pool balances from the 2007 divestiture program. These losses are partially offset by a reduction in the future provincial SIFT tax rate from 13 percent to approximately 10.5 percent.



Depletion, Depreciation and Accretion

Three months ended Six months ended
----------------------------------------------------------------------------
June 30, Mar 31, June 30, June 30, June 30,
($ millions) 2009 2009 2008 2009 2008
----------------------------------------------------------------------------

Depletion and depreciation 152.7 147.2 148.4 299.9 300.2
$ per boe 20.42 20.37 20.16 20.40 20.16
Accretion 6.8 6.7 6.9 13.6 13.7
$ per boe 0.92 0.93 0.94 0.92 0.92
----------------------------------------------------------------------------


Depletion and depreciation of property, plant and equipment is calculated using the unit of production method based on total proved reserves. The increase in the depletion rate is due to higher production volumes realized in the current quarter.

Pengrowth's Asset Retirement Obligations (ARO) liability changes from net acquisitions and by the amount of accretion, which is a charge to net income over the lifetime of the producing oil and gas assets.

Asset Retirement Obligations

The total future ARO is based on management's estimate of costs to remediate, reclaim and abandon wells and facilities having regard for Pengrowth's working interest and the estimated timing of the costs to be incurred in future periods. Pengrowth has developed an internal process to calculate these estimates which considers applicable regulations, actual and anticipated costs, type and size of well or facility and the geographic location. Pengrowth has estimated the net present value of its total ARO to be $352 million as at June 30, 2009 (December 31, 2008 - $344 million), based on a total escalated future liability of $2,296 million (December 31, 2008 - $2,283 million). These costs are expected to be incurred over 50 years with the majority of the costs incurred between 2040 and 2054. A credit adjusted risk free rate of eight percent and an inflation rate of two percent per annum were used to calculate the net present value of the ARO.

Pengrowth takes a proactive approach to managing its well abandonment and site restoration obligations. There is an on-going program to abandon wells and reclaim well and facility sites. Through June 30, 2009, Pengrowth spent $7.2 million on abandonment and reclamation (June 30, 2008 - $10.4 million). Pengrowth expects to spend approximately $22 million in 2009 on reclamation and abandonment, excluding contributions to remediation trust funds and orphan well levies.



Capital Expenditures

Three months ended Six months ended
----------------------------------------------------------------------------
June 30, Mar 31, June 30, June 30, June 30,
($ millions) 2009 2009 2008 2009 2008
----------------------------------------------------------------------------

Seismic acquisitions(1) 0.2 4.0 1.3 4.2 5.1
Drilling, completions and
facilities 25.4 49.8 57.4 75.2 129.7
Maintenance capital 13.9 12.6 10.6 26.5 18.3
Land purchases 0.6 1.6 5.4 2.2 6.5
----------------------------------------------------------------------------
Development capital 40.1 68.0 74.7 108.1 159.6
Lindbergh Project 3.4 3.9 3.4 7.3 6.6
Other capital 0.7 1.1 5.0 1.8 10.4
----------------------------------------------------------------------------
Total capital expenditures 44.2 73.0 83.1 117.2 176.6
----------------------------------------------------------------------------
Business acquisitions - - 0.3 - 0.2
Property acquisitions 1.8 8.7 16.9 10.5 17.6
Proceeds on property
dispositions - (8.1) 4.7 (8.1) 3.0
----------------------------------------------------------------------------
Net capital expenditures
and acquisitions 46.0 73.6 105.0 119.6 197.4
----------------------------------------------------------------------------
(1) Seismic acquisitions are net of seismic sales revenue.


Through the first half of 2009, Pengrowth spent $108.1 million on development and optimization activities. The largest expenditures were at Carson Creek ($15.8 million), Heavy Oil Properties ($9.2 million), Judy Creek ($8.9 million), Harmattan and Olds ($8.7 million), Swan Hills ($6.6 million), Fenn Big Valley ($5.7 million), Horn River ($4.6 million), and Red Earth ($3.1 million). In addition to development activities, $7.3 million was spent on the Lindbergh project and $1.8 million was spent on corporate items. Capital expenditures do not include the Drilling Royalty Credits (DRC) announced by the Alberta government as part of the Energy Incentive Program.

Pengrowth currently anticipates the 2009 capital program to be $215 million, less anticipated DRC of approximately $8 million, for net expenditures of $207 million. Included in the capital program are planned expenditures of $13 million for the oil sands pilot project at Lindbergh. In deciding which projects to fund, Pengrowth reviewed its extensive portfolio and identified those projects that created the greatest economic value. Subsequent to year end, $7 million has been redirected from the Lindbergh project to other projects that are preferentially identified in the budget. Pengrowth anticipates spending approximately $6 million on corporate items.

Acquisitions and Dispositions

In the second quarter of 2009, Pengrowth completed an acquisition in the Carson Creek area for approximately $1.8 million net of adjustments.

During the first quarter of 2009, Pengrowth completed the disposition of non-core properties in the Dawson area in British Columbia. Proceeds of the disposition were approximately $6.4 million net of adjustments.

In addition, during the first quarter of 2009, Pengrowth completed the acquisition of additional working interest in the Carson Creek area for approximately $8.9 million net of adjustments.

Working Capital

The working capital deficiency increased at June 30, 2009 by $121.1 million compared to December 31, 2008. The change in working capital is attributable to $174.1 million of long term debt reclassified to a current liability and the change in the fair value of commodity risk management contracts, offset by lower accounts payable and distributions payable.

Pengrowth generally operates with a working capital deficiency, as distributions for the two previous production months are payable to unitholders at the end of any month, but cash flow from one month of production is still receivable. For example, at the end of June, distributions related to May and June production months being payable on July 15 and August 15, respectively. May's production revenue, received on June 25, is temporarily applied against Pengrowth's term credit facility until the distribution payment on July 15.



Financial Resources and Liquidity
Pengrowth's capital structure is as follows:

($ thousands) June 30, Dec 31, June 30,
As at: 2009 2008 2008
----------------------------------------------------------------------------

Term credit facilities $ 450,000 $ 372,000 $ 534,000
Senior unsecured notes(1) 938,158 1,152,503 709,674
----------------------------------------------------------------------------
Total long term debt 1,388,158 1,524,503 1,243,674

Working capital deficit 17,085 70,159 460,191
Current portion of long term debt 174,138 - -
----------------------------------------------------------------------------
Working capital deficiency 191,223 70,159 460,191
----------------------------------------------------------------------------

Total debt excluding
convertible debentures $ 1,579,381 $ 1,594,662 $ 1,703,865

Convertible debentures 74,871 74,915 74,973
----------------------------------------------------------------------------
Total debt including
convertible debentures $ 1,654,252 $ 1,669,577 $ 1,778,838
----------------------------------------------------------------------------


June 30, Dec 31, June 30,
Trailing twelve months ended 2009 2008 2008
----------------------------------------------------------------------------
Net income (loss) $ 527,123 $ 395,850 $ (17,406)
Add:
Interest expense (2) $ 84,260 $ 76,304 $ 73,922
Future tax reduction $ 63,229 $ (71,925) $ (321,908)
Depletion, depreciation,
amortization and accretion $ 636,953 $ 637,377 $ 640,104
Other non-cash (income)
expenses $ (506,391) $ (26,864) $ 649,550
----------------------------------------------------------------------------

EBITDA $ 805,174 $ 1,010,742 $ 1,024,262

----------------------------------------------------------------------------
Total debt excluding
convertible debentures to
EBITDA 2.0 1.6 1.7
Total debt including
convertible debentures to
EBITDA 2.1 1.7 1.7
----------------------------------------------------------------------------

Total Capitalization excluding
convertible debentures(3) $ 3,875,659 $ 4,188,308 $ 3,527,769
Total Capitalization including
convertible debentures $ 3,950,530 $ 4,263,223 $ 3,602,742
----------------------------------------------------------------------------
Total debt excluding
convertible debentures as a
percentage of total
capitalization 40.8% 38.1% 48.3%
Total debt including
convertible debentures as a
percentage of total
capitalization 41.9% 39.2% 49.4%
----------------------------------------------------------------------------
(1) Non-current portion of long term debt.

(2) Prior period restated to conform to presentation in the current period.

(3) Total capitalization includes total debt plus Unitholders Equity.(Total
debt excludes working capital deficit)


The $15.3 million decrease in total debt excluding convertible debentures from December 31, 2008 was primarily driven by changes in Pengrowth's working capital over the period. The total debt excluding convertible debentures to EBITDA ratio at the end of the quarter was higher relative to both June 30, 2008 and December 31, 2008. The change in the ratio can be attributed to both an increase in the total debt outstanding and a decrease in EBITDA as a result of lower commodity prices.

It is Pengrowth's current intention to replace maturing term debt with new term debt. If the private placement debt market is not favourable at a particular debt maturity, Pengrowth may utilize its revolving credit facility to repay the term debt until conditions improve, or issue equity and use the proceeds to repay the term debt.

Capital spending and acquisitions may be funded by the excess of cash flows from operating activities over distributions declared, through additional debt or the issuance of equity and property dispositions. The credit facilities 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 affect our access to bank credit facilities and our ability to fund operations, maintain distributions and pursue profitable growth opportunities.

If the ratio of Total Debt to trailing EBITDA reaches or exceeds certain levels, management would consider steps to reduce the ratio of Total Debt to trailing EBITDA. If the ratio of Total Debt to Total Capitalization reaches or exceeds certain levels, Pengrowth management would consider steps to improve the ratio while considering our debt financial covenant limits. Those steps could include, but are not limited to, raising equity, selling assets, reducing capital expenditures or reducing distributions. Details of these measures are included in Note 12 to the consolidated financial statements. In the event of a significant acquisition, Pengrowth may prepare pro forma financial statements for debt covenant purposes and has additional flexibility under its debt covenants for a set period of time.

Pengrowth has implemented an Equity Distribution Program which permits the distribution of up to 25,000,000 trust units from time to time at prevailing market prices until January of 2010 through the New York Stock Exchange (NYSE) or the Toronto Stock Exchange (TSX). Both the shelf prospectus and the Equity Distribution Agreement enabling the at-the-market distribution had expired but were reinstated on May 6, 2009 and July 13, 2009 respectively. No trust units were issued under the Equity Distribution Program during the period ended June 30, 2009. Subsequent to quarter end Pengrowth sold 350,000 Trust Units over two trading days at an average price of US$7.49 for net proceeds of approximately US$2.6 million on the NYSE under the Equity Distribution Program.

Pengrowth maintains a committed $1.2 billion term credit facility with a syndicate of seven Canadian banks and four foreign banks which expires June 15, 2011, and a $50 million demand operating line of credit with one Canadian bank. As of June 30, 2009 the term credit facility was reduced by drawings of $450 million and outstanding letters of credit of approximately $11 million while the operating facility, which is accounted for under Bank Indebtedness on the Balance Sheet, was reduced by drawings of $3 million.

Pengrowth expects to be able to fund its 2009 development program and to take advantage of acquisition opportunities as they arise. At June 30, 2009, Pengrowth had approximately $784 million available to draw from its credit facilities.

Unitholders are eligible to participate in the Distribution Reinvestment Plan (DRIP). DRIP entitles the unitholder to reinvest cash distributions in additional units of the Trust. The trust units under the plan are issued from treasury at a five percent discount to the weighted average closing price of all trust units traded on the TSX for the 20 trading days preceding a distribution payment date. For the six month period ended June 30, 2009, 1.8 million trust units were issued for cash proceeds of $15.1 million under the DRIP compared to 1.7 million trust units for cash proceeds of $30.0 million at June 30, 2008.

Pengrowth does not have any off balance sheet financing arrangements.

There have been no significant changes to the number of trust units outstanding since June 30, 2009.

Pengrowth's U.S. $865 million, Cdn $15 million and, U.K. Pound Sterling denominated Pounds Sterling 50 million senior unsecured notes and the credit facilities have certain financial covenants, which may restrict the total amount of Pengrowth's borrowings. The calculation for each financial covenant is based on specific definitions, is not in accordance with GAAP and cannot be readily replicated by referring to Pengrowth's financial statements. The financial covenants are different between the 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 EBITDA for the
last four fiscal quarters
2. Total debt should not be greater than 3.5 times EBITDA for the last four
fiscal quarters
3. Total senior debt should be less than 50 percent of total book
capitalization
4. EBITDA should not be less than four times interest expense


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

The actual loan documents are filed on SEDAR as "Other" or "Material document". As at June 30, 2009, Pengrowth was in compliance with all its financial covenants. Failing a financial covenant may result in one or more of Pengrowth's loans being in default. In certain circumstances, being in default of one loan will, absent a cure, result in other loans to also be in default. In the event that Pengrowth was not in compliance with any one of the financial covenants in its credit facility or senior unsecured notes, Pengrowth would be in default of one or more of its loans and would have to repay the debt, refinance the debt or negotiate new terms with the debt holders and may have to suspend distributions to unitholders.

As a result of the October 2, 2006 business combination with Esprit Trust, Pengrowth assumed all of Esprit Trust's 6.5 percent convertible unsecured subordinated debentures (the "debentures"). The debentures mature on December 31, 2010. Pengrowth can elect to redeem all or a portion of the outstanding debentures at a price of $1,050 per debenture or $1,025 per debenture after December 31, 2009. As at June 30, 2009, the principal amount of debentures outstanding was $74.7 million.

Financial Instruments

Financial instruments are utilized by Pengrowth to manage its exposure to commodity price fluctuations, foreign currency and interest rate exposures. Pengrowth's policy is not to utilize financial instruments for trading or speculative purposes. Please see Note 2 of the December 31, 2008 audited financial statements for a description of the accounting policies for financial instruments and Note 20 for information regarding market risk, credit risk and liquidity risk. For information regarding the fair value of Pengrowth's financial instruments at June 30, 2009 please see Note 13 to the June 30, 2009 financial statements.

Cash Flows and Distributions

The following table provides cash flows from operating activities, net income (loss) and distributions declared with the excess (shortfall) over distributions and the ratio of distributions declared over cash flows from operating activities:



($ thousands, except per
trust unit amounts) Three months ended Six months ended
----------------------------------------------------------------------------
June 30, Mar 31, June 30, June 30, June 30,
2009 2009 2008 2009 2008
----------------------------------------------------------------------------
Cash flows from
operating activities 144,116 94,386 267,874 238,502 484,112

Net income (loss) 10,272 (54,232) (118,650) (43,960) (175,233)

Distributions declared 77,526 77,212 168,159 154,738 335,393
Distributions declared
per trust unit 0.30 0.30 0.675 0.60 1.35

Excess of cash flows from
operating activities over
distributions declared 66,590 17,174 99,715 83,764 148,719
Per trust unit 0.26 0.07 0.40 0.33 0.60

Shortfall of net income
(loss) over distributions
declared (67,254) (131,444) (286,809) (198,698) (510,626)
Per trust unit (0.26) (0.51) (1.15) (0.77) (2.06)

Ratio of distributions
declared over cash flows
from operating activities 54% 82% 63% 65% 69%
----------------------------------------------------------------------------


Distributions typically exceed net income as a result of non-cash expenses which may include unrealized losses on commodity risk; depletion, depreciation, and amortization; future income tax expense; trust unit based compensation; and accretion. These non-cash expenses result in a reduction to net income, with no impact to cash flow from operating activities. Pengrowth's goal over longer periods of time is to maximize returns to the unitholders through cash distributions on a per Trust Unit basis and enhancing the value of the Trust Units. Accordingly, we expect that distributions will exceed net income in most periods. In most periods, we would not expect distributions to exceed cash flows from operating activities. In the event distributions exceed cash flows from operating activities, the shortfall would be funded by available bank facilities. The most likely circumstance for this to occur would be where there is a significant negative impact to working capital during the reporting period.

As a result of the depleting nature of Pengrowth's oil and gas assets, capital expenditures are required to offset production declines while other capital is required to maintain facilities, acquire prospective lands and prepare future projects. Capital spending and acquisitions may be funded by the excess of cash flows from operating activities over distributions declared, through additional debt or the issuance of equity. Pengrowth does not deduct capital expenditures when calculating cash flows from operating activities. However, Pengrowth does deduct costs associated with environmental activities when calculating cash flows from operating activities.

Notwithstanding the fact that cash flow from operating activities normally exceeds distributions, the difference is not sufficient to fund the capital spending required to fully replace production. That difference is funded by equity or a combination of equity and debt. Accordingly, Pengrowth believes our distributions include a return of capital.

Forecasted capital spending in 2009 of $207 million will not be sufficient to fully replace the oil and gas reserves Pengrowth expects to produce during the year. If the produced reserves are not offset in the future by additional capital or acquisitions, future distributions could be impacted. Pengrowth has historically paid distributions at a level that includes a portion which is a return of capital to its investors. From time to time Pengrowth may issue additional trust units to fund capital programs and acquisitions. Investors can elect to participate in the distribution re-investment program.

Cash flows from operating activities are derived from producing and selling oil, natural gas and related products. As such, cash flow from operating activities is highly dependent on commodity prices. Pengrowth entered into forward commodity contracts to mitigate price volatility and to provide a measure of stability to monthly cash flows. Details of commodity contracts are contained in Note 13 to the financial statements.

The board of directors and management regularly review the level of distributions. 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 the Corporation's gross revenue to fund various costs including future capital expenditures, royalty income in any future period and future abandonment costs. As a result of the volatility in commodity prices, changes in production levels and capital expenditure requirements, there can be no certainty that Pengrowth will be able to maintain current levels of distributions and distributions can and may fluctuate in the future. To maintain its financial flexibility, Pengrowth reduced monthly distributions twice between March 31, 2008 and March 31, 2009 from 22.5 cents per trust unit to 17 cents per trust unit to 10 cents per trust unit. In the current production and price environment, the possibility of suspending distributions in the near future is unlikely, but the amount may vary. Pengrowth has no restrictions on the payment of its distributions other than maintaining its financial covenants in its borrowings.

Cash distributions are generally paid to unitholders on or about the 15th day of the second month following the month of production. Pengrowth paid $0.30 per trust unit as cash distributions during the second quarter of 2009.

Taxability of Distributions

At this time, 100 percent of Pengrowth's 2009 distributions are anticipated to be taxable to Canadian residents.

Pengrowth amended its U.S. tax entity election to be classified as a corporation for U.S. federal income tax purposes effective July 1, 2009. Distributions paid to U.S. residents for the first six months of 2009 will be treated as partnership distributions for U.S. federal tax purposes and will be treated as dividends starting with the July 15th distribution. Distributions to U.S. residents are currently subject to a 15 percent Canadian withholding tax. On September 21, 2007, Canada and the United States signed the fifth protocol of the Canada-United States Tax Convention (the "Protocol") which increases the amount of Canadian withholding tax from 15 percent to 25 percent on distributions of income from a partnership. The increase will become effective on and after January 1, 2010, which was one of the reasons prompting Pengrowth to change its election on July 1, 2009, and have its distributions taxed as dividends for U.S. investors. As a result the increase does not apply to corporate dividends and the withholding tax will remain at 15 percent on Pengrowth's distributions. Residents of the U.S. should consult their individual tax advisors on the impact of this change. The Canadian withholding tax rate on distributions paid to unitholders in other countries varies based on individual tax treaties.



Summary of Quarterly Results
The following table is a summary of quarterly information for 2009, 2008
and 2007.

----------------------------------------------------------------------------
2009 Q1 Q2
----------------------------------------------------------------------------
Oil and gas sales ($000's) 322,973 335,634
Net income/(loss) ($000's) (54,232) 10,272
Net income/(loss) per trust unit ($) (0.21) 0.04
Net income/(loss) per trust unit - diluted ($) (0.21) 0.04
Cash flow from operating activities ($000's) 94,386 144,116
Distributions declared ($000's) 77,212 77,526
Distributions declared per trust unit ($) 0.30 0.30
Daily production (boe) 80,284 82,171
Total production (mboe) 7,226 7,478
Average realized price ($ per boe) 44.57 44.74
Operating netback ($ per boe) (1) 23.87 26.28


----------------------------------------------------------------------------
2008 Q1 Q2 Q3 Q4
----------------------------------------------------------------------------
Oil and gas sales ($000's) 457,606 550,623 518,662 392,158
Net income/(loss) ($000's) (56,583) (118,650) 422,395 148,688
Net income/(loss) per trust unit ($) (0.23) (0.48) 1.69 0.58
Net income/(loss) per trust unit
- diluted ($) (0.23) (0.48) 1.69 0.58
Cash flow from operating activities
($000's) 216,238 267,874 273,597 154,807
Distributions declared ($000's) 167,234 168,159 170,959 144,663
Distributions declared per trust
unit ($) 0.675 0.675 0.675 0.565
Daily production (boe) 82,711 80,895 80,981 83,373
Total production (mboe) 7,527 7,361 7,450 7,670
Average realized price ($ per boe) 60.30 73.21 67.71 50.34
Operating netback ($ per boe) (1) 33.62 42.15 37.48 26.23


----------------------------------------------------------------------------
2007 Q1 Q2 Q3 Q4
----------------------------------------------------------------------------
Oil and gas sales ($000's) 432,108 443,977 420,704 425,249
Net income/(loss) ($000's) (69,834) 271,659 161,492 (3,665)
Net income/(loss) per trust unit ($) (0.29) 1.11 0.66 (0.01)
Net income/(loss) per trust unit
- diluted ($) (0.29) 1.10 0.66 (0.01)
Cash flow from operating activities
($000's) 136,429 249,960 217,630 196,325
Distributions declared ($000's) 183,534 184,327 172,109 166,631
Distributions declared per trust
unit ($) 0.75 0.75 0.70 0.675
Daily production (boe) 90,068 89,633 85,654 84,331
Total production (mboe) 8,106 8,157 7,880 7,758
Average realized price ($ per boe) 53.30 54.39 53.34 54.58
Operating netback ($ per boe) 29.87 29.56 32.66 29.56

(1) Restated to conform to presentation adopted in the current period.


Production changes over these quarters was a result of property dispositions completed by Pengrowth throughout 2007, production limitations due to plant turnarounds and unscheduled maintenance in the second, third and fourth quarters of 2008 and a property acquisition in the fourth quarter of 2008. Changes in commodity prices have affected oil and gas sales, which have been partially muted by risk management activity to mitigate price volatility and to provide a measure of stability to monthly cash flows. Net income (loss) in 2007, 2008 and 2009 has been impacted by non-cash charges, in particular depletion, depreciation and accretion, unrealized mark-to-market gains and losses, unrealized foreign exchange gains and losses, and future taxes. Cash flow has not been impacted by the non-cash charges, however, reflects the impact of higher operating and general and administrative costs.

Business Risks

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

- Capital markets may restrict Pengrowth's access to capital and raise its borrowing costs. To the extent that external sources of capital become limited or cost prohibitive, Pengrowth's ability to fund future development and acquisition opportunities may be impaired.

- Pengrowth is exposed to third party credit risk through it's oil and gas sales, financial hedging transactions and joint venture activities. The failure of any of these counterparties to meet their contractual obligations could adversely impact Pengrowth. In response, Pengrowth has established a credit policy designed to mitigate this risk and monitors its counterparties on a regular basis.

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

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

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

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

- Pengrowth could lose its grandfathered status under the SIFT Legislation and become subject to the old SIFT tax prior to January 1, 2011 if it exceeds the normal growth guidelines.

- Oil and gas operations carry the risk of damaging the local environment in the event of equipment or operational failure. The cost to remediate any environmental damage could be significant.

- Environmental laws and regulatory initiatives impact Pengrowth financially and operationally. We may incur substantial capital and operating expenses to comply with increasingly complex laws and regulations covering the protection of the environment and human health and safety. In particular, we may be required to incur significant costs to comply with future regulations to reduce greenhouse gas and other emissions.

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

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

- Timing of oil and gas operations is dependent on gaining timely access to lands. Consultations, that are mandated by governing authorities, with all stakeholders (including surface owners, First Nations and all interested parties) are becoming increasingly time consuming and complex, and are having a direct impact on cycle times.

- A significant portion of Pengrowth's properties are operated by third parties whereby Pengrowth has less control over the pace of capital and operating expenditures. If these operators fail to perform their duties properly, or become insolvent, we may experience interruptions in production and revenues from these properties or incur additional liabilities and expenses as a result of the default of these third party operators.

- During periods of increased activity within the oil and gas sector, the cost of goods and services may increase and it may be more difficult to hire and retain professional staff.

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

- Failing a financial covenant may result in one or more of Pengrowth's loans being in default. In certain circumstances, being in default of one loan will result in other loans to also be in default.

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

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

- Canadian / U.S. exchange rates influence revenues and, to a lesser extent, operating and capital costs. Pengrowth is also exposed to foreign currency fluctuations on the U.S. dollar denominated notes for both interest and principal payments.

- The value of Pengrowth trust units is impacted directly by the related tax treatment of the trust units and the trust unit distributions, and indirectly by the tax treatment of alternative equity investments. Changes in Canadian or U.S. tax legislation could adversely affect the value of our trust units. As 2011 approaches, the expectation of taxability of distributions may negatively impact the value of trust units.

- Attacks by individuals against facilities and the threat of such attacks may have an adverse impact on Pengrowth and the implementation of security measures as a precaution against possible attacks would result in increased cost to Pengrowth's business.

- Substantial and sustained reductions in commodity prices or equity markets, including Pengrowth's unit price, in some circumstances could result in Pengrowth reducing the recorded book value of some of its assets.

- Delays in business operations could adversely affect Pengrowth's distributions to unitholders and the market price of the trust units.

These factors should not be considered exhaustive. Additional risks are outlined in the AIF of the Trust available on SEDAR at www.sedar.com.

Outlook

At this time, Pengrowth is raising its 2009 full year average production guidance from between 76,000 and 78,000 boe per day to between 78,000 to 79,500 boe per day. This estimate excludes the impact from any potential future acquisitions and dispositions.

The boe values which follow assume an average of 78,750 boe per day, which is the midpoint of our guidance.

At this time, primarily due to lower utility pricing well as increased production guidance; Pengrowth is lowering its anticipated total operating expenses for 2009 from approximately $14.45 per boe to approximately $14.00 per boe.

Royalty expense is forecasted to be approximately 18 percent of Pengrowth's sales, excluding the impact of risk management contracts, for 2009.

On a per boe basis, G&A is anticipated to be approximately $2.37 for the full year of 2009, including non-cash G&A and anticipated management fees of approximately $0.10 per boe.

The 2009 capital program is forecasted to be $215 million less DRC's of approximately $8 million for net capital expenditures of $207 million.

Pengrowth expects to spend approximately $22 million for 2009 on remediation and abandonment, excluding contributions to remediation trust funds.

Current Global Economic Conditions

Towards the end of 2008, the global economic environment deteriorated rapidly and resulted in a very challenging time for commodity prices, the capital markets and equity values. This deterioration could negatively affect Pengrowth as continued uncertainty in the credit markets may restrict the availability and/or increase the cost of borrowing required for future development and acquisitions. The dramatic decreases in commodity prices since highs reached in the summer of 2008 negatively impacts operating cash flow and future borrowing capacity. This uncertainty may also impair Pengrowth's normal business counterparties to meet their obligations to Pengrowth. Additional credit risk could exist where little or none previously existed.

Pengrowth's guidance on the capital expenditure program for 2009 is focused on reducing risk and repositioning the Trust to adjust to current market conditions. Pengrowth continues to maintain a strong mix of both conventional and non-conventional assets and a solid overall financial structure. Management and the Board of Directors will continue to evaluate both capital expenditures and distribution levels within the context of economic and commodity price outlooks.

International Financial Reporting Standards (IFRS)

On February 13, 2008, the Canadian Accounting Standards Board confirmed that publicly accountable enterprises will be required to adopt International Financial Reporting Standards ("IFRS") in place of Canadian GAAP for interim and annual periods beginning on or after January 1, 2011. At this time, the impact on Pengrowth's future financial position and results of operations is not reasonably determinable or estimable.

Pengrowth commenced its IFRS conversion project in 2008 and has established a formal governance structure. This structure includes a full time IFRS Project Coordinator, a steering committee consisting of senior members of the finance team on an ongoing basis and also includes information technology, treasury and operations personnel. Pengrowth has also engaged an external expert advisory firm.

Regular IFRS project reporting is provided to senior management and to the Audit Committee of the Board of Directors. During the quarter ended June 30, 2009, accounting policy analysis has been documented and presented to the board for business combinations, in addition to the previously completed documentation for the three most critical issues - accounting for exploration and development activities including classification of exploration and evaluation expenditures, depletion and impairment of capital assets. In addition, regular updates on the IFRS project are presented to the Audit Committee of the Board of Directors on a quarterly basis.

Pengrowth's project consists of four phases: diagnostic; design and planning; solution development; and implementation. Pengrowth completed the diagnostic phase in 2008, which involved a high level review of the major differences between Canadian GAAP and IFRS, and identification of potential information systems and process changes. Pengrowth has begun detailed analysis of the next most significant issues - asset retirement obligations, stock based compensation, financial instruments and initial adoption of IFRS. The impact on disclosure controls and internal controls over financial reporting will also be determined.

Pengrowth is currently engaged in the design and planning and solution development phases of our project, working with issue-specific teams to focus on generating options and making recommendations in the identified areas. Pengrowth's IFRS team has determined accounting policies for property, plant and equipment and business combinations under IFRS. These IFRS accounting policies require calculation of depletion and testing for possible impairment of assets at a more detailed level than under current accounting policies and Pengrowth is currently planning information technology solutions to address these new calculations. Business combinations would require different valuation of share based consideration paid and require all transaction costs to be expensed as incurred, increasing general and administrative costs in the periods where acquisitions occur. We are also currently planning solutions to allow Pengrowth to account for transactions in Canadian GAAP and IFRS financial statements in 2010.

During the design and planning phase, Pengrowth has initiated training for key personnel. The IFRS steering committee has presented the IFRS property, plant and equipment accounting policy choices to key finance, investor relations and information technology personnel. Future training for key operational personnel and senior management are in the planning phase.

On July 23, 2009, the International Accounting Standards Board issued an amendment to IFRS 1 in respect of property plant and equipment as at the date of initial transition to IFRS. This amendment permits issuers currently using the full cost method of accounting to allocate the balance of property plant and equipment (as determined under Canadian GAAP) to the IFRS categories of exploration and evaluation assets and development and producing properties without significant adjustment arising from the retroactive adoption of IFRS. Pengrowth currently intends to use the exemption provided therein.

The Canadian Association of Petroleum Producers (CAPP) has released a guidance document in March 2009 to assist upstream oil and gas producers with IFRS implementation. Members of Pengrowth's IFRS Steering Committee have been involved in the development of this guidance since its inception. Pengrowth's IFRS Project Coordinator was one of the presenters in the roll-out of the CAPP guidance and has been named chairman of CAPP's accounting policy committee.

Pengrowth continues to monitor the IFRS adoption efforts of many of its peers and will participate in any related processes, as appropriate. Pengrowth is currently involved in an IFRS working group comprised of intermediate to large oil and gas producers and an IFRS and Financial Reporting group consisting of our peer income trusts.

Recent Accounting Pronouncements

New Canadian accounting standards related to business combinations have been issued which will require changes to the way business combinations are accounted. The new standards broaden the scope of business combinations and require transaction costs to be expensed as incurred as well as require valuing all assets and liabilities and measuring consideration paid at the closing date. The new Canadian standards are required for all business combinations occurring on or after January 1, 2011 although early adoption is allowed. Pengrowth has not yet determined the impact on the financial position, results of operations or cash flows. Pengrowth has not determined if it will adopt this standard earlier than the required date.

New Canadian accounting recommendations related to goodwill and intangible assets were adopted on January 1, 2009. There was no impact on the financial position or results of operations as a result of adopting this standard.

Disclosure Controls and Procedures and Internal Controls Over Financial Reporting

As a Canadian reporting issuer with securities listed on both the TSX and the NYSE, Pengrowth is required to comply with Multilateral Instrument 52-109 - Certification of Disclosure in Issuers' Annual and Interim Filings, as well as the Sarbanes Oxley Act enacted in the United States.

At the end of the interim period ended June 30, 2009, Pengrowth did not have any material weakness relating to design of its internal control over financial reporting. Pengrowth has not limited the scope of its design of disclosure controls and procedures and internal control over financial reporting to exclude controls, policies and procedures of (i) a proportionately consolidated entity in which Pengrowth has an interest; (ii) a variable interest entity in which Pengrowth has an interest; or (iii) a business that Pengrowth acquired not more than 365 days before June 30, 2009, and summary financial information about these items has been proportionately consolidated or consolidated in Pengrowth's financial statements. During the interim period ended June 30, 2009, no change occurred to Pengrowth's internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, Pengrowth's internal control over financial reporting.

CONFERENCE CALL AND CONTACT INFORMATION

Pengrowth will hold a conference call beginning at 9:00 A.M. Mountain Time on Friday, August 7, 2009 during which management will review Pengrowth's 2009 second quarter financial and operating results and respond to inquiries from the investment community. To participate callers may dial (800) 594-3615 or Toronto local (416) 644-3423. 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. The conference call will also be accessible by webcast at http://events.onlinebroadcasting.com/pengrowth/080609/index.php. A live audio webcast will be accessible through the Presentations and Webcasts 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 Friday, August 14, 2009 by dialing (877) 289-8525 or Toronto local (416) 640-1917 and entering passcode number 21310526#.

For further information about Pengrowth, please visit our website www.pengrowth.com.

Operations Review

REVIEW OF DEVELOPMENT ACTIVITIES

(All volumes and amounts stated below are net to Pengrowth unless otherwise stated)

In the second quarter of 2009, Pengrowth's daily production averaged 82,171 barrels of oil equivalent (boe) per day. This was a two percent increase from the first quarter mainly due to prior period adjustments (from prior year acquisitions), reduced solvent injection at Judy Creek, two minor acquisitions in the first quarter and current results from our develop program. Pengrowth's full year production guidance has increased to 78,000 to 79,500 boe per day excluding any future acquisitions and dispositions.

Development capital expenditures totaled $40 million, with approximately 63 percent spent on drilling, completions and facilities. Included in the development capital expenditures are land acquisition costs of $0.6 million. In addition to the Development Capital, $3.3 million was spent at Lindbergh.

Pengrowth participated in the drilling of 10 gross and 5.4 net wells in the quarter, all of which were cased for production.

During the quarter, Pengrowth added to its undeveloped land position through the acquisition of 5,560 net acres at Crown land sales in Alberta.

Pengrowth assesses our asset portfolio by aggregating production from properties into the following categories: light oil; heavy oil; conventional gas; shallow gas and coalbed methane; offshore gas; and oil sands. Because all the production from the properties are aggregated into one of these groups, as opposed to the actual commodities, the production by commodity reported elsewhere will be different than those reported below.

Light Oil:

Pengrowth's asset base includes interests in a number of large original-oil-in-place reservoirs in the Western Canadian Sedimentary Basin (WCSB). These properties mainly produce light, sweet oil and are candidates for enhanced oil recovery (EOR) techniques. Major light oil properties in our portfolio include Judy Creek, Weyburn, Swan Hills, Carson Creek North and Fenn Big Valley. Production from the light oil properties averaged 26,554 boe per day including natural gas and natural gas liquids.

Approval for a water injection scheme was received for a key well in the Goose River Swan Hills Unit. Injection began on June 1, 2009.

In Three Hills Creek a well was recompleted as a Viking oil well, adding an initial incremental 60 boe per day. The well is being monitored and may result in additional drilling opportunities.

At Judy Creek, CO2 injection was completed in the second quarter and pattern response monitoring will continue through 2010.

At House Mountain Unit No. 1 two horizontal wells (0.25 net) drilled in the first quarter, were put on production in April 2009 at a cumulative initial production rate of approximately 73 boe per day.

Pengrowth participated in the drilling of four partner-operated (0.96 net) new wells in Swan Hills Unit No. 1. Three (0.72 net) of these wells will be on stream in the third quarter of 2009. They are expected to produce a combined of 47 boe per day.

Heavy Oil:

Pengrowth's heavy oil properties consist mainly of operated primary and secondary recovery fields in southeastern Alberta and southwestern Saskatchewan plus a non-operated EOR steam assisted gravity drainage (SAGD) operation. Major properties include Jenner, Bodo, Cactus and Tangleflags. Production from the heavy oil properties averaged 9,778 boe per day during the first quarter.

In the second quarter, Pengrowth tied-in a horizontal producer at East Bodo that was drilled in the first quarter, adding approximately 100 boe per day. This well's performance has been enhanced due to the polymer flood in the area.

Additional production of approximately 125 boe per day was added through waterflood optimization at East Bodo.

At Jenner, a gas recompletion was brought on production at an initial rate of 700 mcf per day (117 boe per day) to coincide with the new royalty incentives. Pengrowth also successfully conducted one oil well recompletion adding 30 boe per day.

Conventional Gas:

Conventional gas provides a stable source of base production for Pengrowth. Major properties include Olds, Carson Creek Gas Unit, Harmattan, Dunvegan, Quirk Creek and Kaybob. Production during the quarter from the conventional gas properties averaged 25,759 boe per day including liquids.

The first horizontal well drilled for Swan Hills gas in the Carson Creek Gas Unit was tied in during the second quarter. Pengrowth has a 95 percent working interest in this unit. This well was put on production in April 2009. A three month average initial rate of 570 boe per day (gas and condensate) has been obtained from this well. Phase one of the follow-up multi-well drilling program was initiated in the second quarter with the "batch drilling" of one vertical and two horizontal wells from one pad. The first vertical pilot hole was cored, and logged in June 2009. The build sections for the first two horizontal wells have been drilled and cased. The two horizontal legs will be drilled back to back starting in July 2009.

At Olds, one (0.5 net) new drill in the Harmattan area was brought on stream in April, adding initial production of approximately 35 boe per day. This well was drilled in a property acquired in late 2008. An Olds unit Wabamun new drill was spud in the quarter and, pending success, will be completed in the third quarter.

Pengrowth participated in one (0.5 net) Dunvegan gas well in the Puskwa area in the first quarter of 2008. This well was put on production in April at a rate of 355 mcf per day (60 boe per day).

A partner-operated well (0.5 net) was drilled in the Lanfine area of Southern Alberta and tested at approximately 900 mcf per day (150 boe per day). The well is expected to be on production early in the third quarter.

In the McLeod area, Pengrowth operated two Wilrich re-completions. Both wells were put on production in early April 2009 at a cumulative rate of 200 mcf per day (33 boe per day). Although these are low rate wells, the re-completions have proven potential for Wilrich gas production in the McLeod area.

In April, Pengrowth received approval for waterflooding in the Stoddart North Pine G Pool. Pengrowth subsequently drilled a successful Dunvegan water source well and expects the water flood scheme to be fully implemented in the third quarter.

At Pine Creek one (0.5 net) non-operated gas well was pooled for gas production and came on stream in mid April. The well came on stream at 63 mcf per day (10 boe per day) at no capital cost to Pengrowth.

Shallow Gas and Coalbed Methane (CBM):

Shallow gas has been a significant part of Pengrowth's portfolio for some time and CBM production has been an important addition to this strategic focus. Shallow gas is an attractive resource as it is generally low-risk, low decline with relatively low capital requirements. CBM has similar risk and capital characteristics to conventional shallow gas and provides Pengrowth with a new, unconventional source of gas as conventional shallow gas production in the WCSB declines. Principle shallow gas and CBM properties include Three Hills/Twining, Monogram, Tilley, Jenner and Lethbridge. Production from the shallow gas and CBM properties averaged 14,261 boe per day including liquids during the second quarter.

In response to commodity prices, focus continues on recompletions. In the Jenner, Fenn Big Valley and Twining areas six recompletions resulted in approximately 180 boe per day being brought onstream in the quarter, the bulk starting April 1 to coincide with the new royalty incentives.

At Monogram 79 of the 80 (43 net) first quarter gas wells were on production at the end of the quarter adding approximately 2,309 mcf per day (385 boe per day) of production.

At Tilley, four gas wells (0.39 net) were drilled and cased in the first quarter and two of these wells were placed on production in the second quarter.

A 100 percent working interest Horseshoe Canyon/Belly River well was drilled and cased in the Three Hills Creek area.

Pengrowth brought on its fourth Mannville CBM well in the Fenn Big Valley area to coincide with the new royalty incentives. The initial production rate was 148 boe per day.

Sable Offshore Energy Project:

The Sable Offshore Energy Project (SOEP) encompasses the fields of North Triumph, Venture, Thebaud, South Venture and Alma located off the east coast of Nova Scotia. SOEP provides geographic diversification within our property portfolio and provides Pengrowth with direct exposure to the premium northeastern U.S. gas markets.

Production in the second quarter of 2009 averaged 266 mmcf per day of natural gas and 1,384 bbl per day of natural gas liquids. Pengrowth's share of the production averaged 5,818 boe per day for the quarter.

Pengrowth has an 8.4 percent working interest in the Alma 4 well currently being drilled offshore Sable Island. The primary target is the Mississauga 'A' Gas Sand at a total depth of 4,282 metres. The well will be at total depth in August and completion will follow shortly thereafter.



Consolidated Balance Sheets
(Stated in thousands of dollars)
(unaudited)

As at As at
June 30 December 31
2009 2008
----------------------------------------------------------------------------
----------------------------------------------------------------------------

ASSETS
CURRENT ASSETS
Accounts receivable $ 178,940 $ 197,131
Due from Pengrowth Management Limited 441 623
Fair value of risk management
contracts (Note 13) 52,909 122,841
----------------------------------------------------------------------------
----------------------------------------------------------------------------
232,290 320,595

FAIR VALUE OF RISK MANAGEMENT
CONTRACTS (Note 13) 4,467 41,851

OTHER ASSETS (Note 2) 45,049 42,618

PROPERTY, PLANT AND EQUIPMENT 4,068,356 4,251,381

GOODWILL 660,896 660,896
----------------------------------------------------------------------------
----------------------------------------------------------------------------

$ 5,011,058 $ 5,317,341
----------------------------------------------------------------------------
----------------------------------------------------------------------------

LIABILITIES AND UNITHOLDERS' EQUITY
CURRENT LIABILITIES
Bank indebtedness $ 4,608 $ 2,631
Accounts payable and accrued liabilities 169,430 260,828
Distributions payable to unitholders 51,710 87,142
Fair value of risk management contracts
(Note 13) 9,004 2,706
Future income taxes (Note 5) 12,517 34,964
Contract liabilities 2,106 2,483
Current portion of long-term debt (Note 3) 174,138 -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
423,513 390,754

FAIR VALUE OF RISK MANAGEMENT CONTRACTS
(Note 13) 20,524 16,021

CONTRACT LIABILITIES 8,816 9,680

CONVERTIBLE DEBENTURES 74,871 74,915

LONG TERM DEBT (Note 3) 1,388,158 1,524,503

ASSET RETIREMENT OBLIGATIONS (Note 4) 351,994 344,345

FUTURE INCOME TAXES (Note 5) 255,681 293,318

TRUST UNITHOLDERS' EQUITY
Trust unitholders' capital (Note 6) 4,610,393 4,588,587
Equity portion of convertible debentures 160 160
Contributed surplus (Note 6) 17,167 16,579
Deficit (Note 8) (2,140,219) (1,941,521)
----------------------------------------------------------------------------
2,487,501 2,663,805
----------------------------------------------------------------------------


$ 5,011,058 $ 5,317,341
----------------------------------------------------------------------------
----------------------------------------------------------------------------

See accompanying notes to the consolidated financial statements.



Consolidated Statements of Income (Loss) and Deficit
(Stated in thousands of dollars)
(unaudited)

Three months ended Six months ended
June 30 June 30
2009 2008 2009 2008
----------------------------------------------------------------------------
----------------------------------------------------------------------------

REVENUES
Oil and gas sales $ 335,634 $ 550,623 $ 658,607 $ 1,008,229
Unrealized loss on
commodity risk
management (Note 13) (115,400) (352,628) (128,016) (518,355)
Processing and other
income 4,762 3,782 9,581 7,992
Royalties, net of
incentives (47,036) (125,525) (86,937) (223,774)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
NET REVENUE 177,960 76,252 453,235 274,092

EXPENSES
Operating 88,567 109,645 196,036 209,166
Transportation 2,992 3,243 5,629 6,531
Amortization of
injectants for
miscible floods 5,382 5,704 10,718 13,469
Interest on long term
debt 20,612 18,573 42,599 34,643
General and
administrative 16,965 13,195 34,402 28,498
Management fee (207) 2,600 2,793 6,000
Foreign exchange (gain)
loss (Note 9) (88,194) (1,080) (50,139) 34,744
Depletion, depreciation
and amortization 152,718 148,375 299,900 300,157
Accretion (Note 4) 6,845 6,934 13,574 13,741
Other expenses (income) 1,601 (1,555) 1,767 (2,386)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
207,281 305,634 557,279 644,563
----------------------------------------------------------------------------
----------------------------------------------------------------------------

LOSS BEFORE TAXES (29,321) (229,382) (104,044) (370,471)

Future income tax
reduction (Note 5) (39,593) (110,732) (60,084) (195,238)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

NET INCOME (LOSS) AND
COMPREHENSIVE
INCOME (LOSS) $ 10,272 $ (118,650) $ (43,960) $ (175,233)

Deficit, beginning of
period (2,072,965) (1,910,173) (1,941,521) (1,686,356)

Distributions declared (77,526) (168,159) (154,738) (335,393)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

DEFICIT, END OF PERIOD $(2,140,219) $(2,196,982) $(2,140,219) $(2,196,982)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

NET INCOME (LOSS) PER
TRUST UNIT (Note 11)
Basic $ 0.04 $ (0.48) (0.17) (0.71)
Diluted $ 0.04 $ (0.48) (0.17) (0.71)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

See accompanying notes to the consolidated financial statements.


Consolidated Statements of Cash Flow
(Stated in thousands of dollars)
(unaudited)

Three months ended Six months ended
June 30 June 30
2009 2008 2009 2008
----------------------------------------------------------------------------
----------------------------------------------------------------------------

CASH PROVIDED BY (USED FOR):

OPERATING
Net income (loss) and
comprehensive income (loss) $ 10,272 $(118,650) $ (43,960) $(175,233)
Depletion, depreciation and
accretion 159,563 155,309 313,474 313,898
Future income tax reduction (39,593) (110,732) (60,084) (195,238)
Contract liability amortization (621) (1,210) (1,243) (2,332)
Amortization of injectants 5,382 5,704 10,718 13,469
Purchase of injectants (4,042) (6,949) (6,680) (10,795)
Expenditures on remediation
(Note 4) (1,467) (3,924) (7,224) (10,380)
Unrealized foreign exchange
(gain) loss (Note 9) (89,362) (709) (50,574) 35,863
Unrealized loss on commodity
risk management (Note 13) 115,400 352,628 128,016 518,355
Trust unit based compensation
(Note 7) 2,950 1,913 6,185 4,561
Other items 1,613 (672) 1,823 (835)
Changes in non-cash operating
working capital (Note 10) (15,979) (4,834) (51,949) (7,221)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
144,116 267,874 238,502 484,112
----------------------------------------------------------------------------
----------------------------------------------------------------------------

FINANCING
Distributions paid (Note 8) (77,347) (167,614) (190,170) (334,396)
Bank indebtedness 1,961 1,274 1,976 6,507
Change in long term debt, net (16,000) (1,955) 78,000 19,765
Proceeds from issue of trust
units 6,898 19,478 16,209 33,941
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(84,488) (148,817) (93,985) (274,183)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

INVESTING
Business acquisition - (232) - (176)
Expenditures on property, plant
and equipment (44,129) (83,060) (117,189) (176,594)
Other property acquisitions (1,811) (16,905) (10,513) (17,572)
Proceeds on property
dispositions (17) (4,695) 8,086 (2,973)
Change in remediation trust
funds (1,986) (2,514) (3,825) (4,652)
Change in non-cash investing
working capital (Note 10) (11,685) (11,651) (21,076) (9,979)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(59,628) (119,057) (144,517) (211,946)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

CHANGE IN CASH AND TERM DEPOSITS - - - (2,017)

CASH AND TERM DEPOSITS AT
BEGINNING OF PERIOD - - - 2,017

CASH AND TERM DEPOSITS AT END OF
PERIOD $ - $ - $ - $ -
----------------------------------------------------------------------------
----------------------------------------------------------------------------

See accompanying notes to the consolidated financial statements.


Notes To Consolidated Financial Statements
(Unaudited)
June 30, 2009

(Tabular amounts are stated in thousands of dollars except per trust unit
amounts and as otherwise stated)


1. SIGNIFICANT ACCOUNTING POLICIES

The interim consolidated financial statements of Pengrowth Energy Trust include the accounts of Pengrowth Energy Trust (the "Trust") and all of its subsidiaries (collectively referred to as "Pengrowth"), including Pengrowth Corporation (the "Corporation"). The financial statements do not contain the accounts of Pengrowth Management Limited (the "Manager"). The management agreement with the Manager expired on June 30, 2009. As of June 30, 2009, the Trust owns 100 percent of the royalty units and 91 percent of the common shares of the Corporation. The Trust, through the royalty ownership, obtains substantially all the economic benefits of the Corporation.

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, 2008 except as noted 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, 2008.

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

Change in Accounting Policies

New Canadian accounting recommendations related to goodwill and intangible assets which established revised standards for the recognition, measurement, presentation and disclosure of goodwill and intangible assets, were adopted on January 1, 2009. There was no impact on the financial position or results of operations as a result of adopting this standard.



2. OTHER ASSETS

As at As at
June 30, 2009 December 31, 2008
----------------------------------------------------------------------------
Remediation trust funds $ 31,010 $ 27,122
Equity investment in Monterey Exploration
Ltd. 8,665 9,872
Other investments 5,374 5,624
----------------------------------------------------------------------------
$ 45,049 $ 42,618
----------------------------------------------------------------------------


The Sable Offshore Energy Project (SOEP) remediation trust fund as at June 30, 2009 was $22.2 million (December 31, 2008 - $18.4 million). The investments in the fund have been designated as held for trading and are recorded at fair value each period end. For the six months ended June 30, 2009, the amount of unrealized gain related to the SOEP remediation trust fund was $0.1 million (June 30, 2008 - loss of $0.1 million), which was included in other expenses (income). As at June 30, 2009, the $8.8 million (December 31, 2008 - $8.7 million) in the Judy Creek remediation trust fund is classified as held to maturity and interest income is recognized when earned and included in other expenses (income).



3. LONG TERM DEBT

As at As at
June 30, 2009 December 31, 2008
----------------------------------------------------------------------------
U.S. dollar denominated senior unsecured
notes:
150 million at 4.93 percent due
April 2010 $ 174,138 $ 182,180
50 million at 5.47 percent due April 2013 57,997 60,727
400 million at 6.35 percent due July 2017 463,205 485,080
265 million at 6.98 percent due
August 2018 306,737 321,231
----------------------------------------------------------------------------
$ 1,002,077 $ 1,049,218
U.K. Pound Sterling denominated 50 million
unsecured notes at 5.46 percent due
December 2015 95,219 88,285
Canadian dollar 15 million senior
unsecured notes at 6.61 percent due
August 2018 15,000 15,000
Canadian dollar revolving credit facility
borrowings 450,000 372,000
----------------------------------------------------------------------------
Total long term debt $ 1,562,296 $ 1,524,503
Current portion of long term debt due
April 2010 (174,138) -
----------------------------------------------------------------------------
Non-current portion of long term debt $ 1,388,158 $ 1,524,503
----------------------------------------------------------------------------


Pengrowth has a committed $1.2 billion syndicated extendible revolving term credit facility. The facility is unsecured, covenant based with a June 15, 2011 maturity date. Pengrowth has the option to extend the facility annually, subject to the approval of the lenders, or repay the entire balance upon maturity. 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 0.60 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. The revolving facility was reduced by drawings of $450 million and by outstanding letters of credit in the amount of approximately $11 million at June 30, 2009. In addition, Pengrowth has a $50 million demand operating facility line of credit, which was reduced by drawings of $3 million as of June 30, 2009, and is included in bank indebtedness.

As of June 30, 2009, an unrealized cumulative foreign exchange loss of $19.3 million (December 31, 2008 - $66.9 million) has been recognized on the U.S. dollar term notes since the date of issuance. As of June 30, 2009, an unrealized cumulative foreign exchange gain of $18.5 million (December 31, 2008 - $25.4 million) has been recognized on the U.K. Pound Sterling denominated term notes since Pengrowth ceased to designate existing foreign exchange swaps as a hedge on January 1, 2007.



4. ASSET RETIREMENT OBLIGATIONS (ARO)

Six months ended Year Ended
June 30, 2009 December 31, 2008
----------------------------------------------------------------------------
ARO, beginning of period $ 344,345 $ 352,171
Increase (decrease) in liabilities
during the period related to:
Acquisitions 185 3,414
Dispositions (47) (5,663)
Additions 1,161 3,618
Revisions - (4,555)
Accretion expense 13,574 28,051
Liabilities settled in the period (7,224) (32,691)
----------------------------------------------------------------------------
ARO, end of period $ 351,994 $ 344,345
----------------------------------------------------------------------------


5. INCOME TAXES

Future income tax is a non-cash item relating to temporary differences between the accounting and tax basis of Pengrowth's assets and liabilities and has no immediate impact on Pengrowth's cash flows. During the six months ended June 30, 2009, Pengrowth recorded a future tax reduction of $60 million to reflect the change in temporary differences primarily relating to the unrealized risk management losses. These losses are partially offset by a reduction in the future provincial SIFT tax rate from 13 percent to approximately 10.5 percent in the six months ended June 30, 2009.



6. TRUST UNITS
Pengrowth is authorized to issue an unlimited number of trust units.

Total Trust Units:

Six months ended Year Ended
June 30, 2009 December 31, 2008
----------------------------------------------------------------------------
Number of Number of
Trust Units Issued Trust Units Amount Trust Units Amount
----------------------------------------------------------------------------
Balance, beginning of period 256,075,997 $4,588,587 246,846,420 $4,432,737
Issued on redemption of
Deferred Entitlement Units
(DEUs) (non-cash) 380,164 5,389 238,633 2,484
Issued for cash on exercise
of trust unit options and
rights 168,007 1,111 290,363 4,274
Issued for cash under
Distribution Reinvestment
Plan (DRIP) 1,794,790 15,098 3,727,256 59,423
Issued for the Accrete
business combination - - 4,973,325 89,253
Trust unit rights incentive
plan (non-cash exercised) - 208 - 614
Issue costs - - - (198)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Balance, end of period 258,418,958 $4,610,393 256,075,997 $4,588,587
----------------------------------------------------------------------------


During the six months ended June 30, 2009, 1,000 Class A trust units were converted to "consolidated" trust units. As at June 30, 2009, 888 Class A trust units remain outstanding. All other trust units outstanding are "consolidated" trust units.



Contributed Surplus

Six months ended Year Ended
June 30, 2009 December 31, 2008
----------------------------------------------------------------------------
Balance, beginning of period $ 16,579 $ 9,679
Trust unit rights incentive plan
(non-cash expensed) 1,750 2,348
Deferred entitlement trust units
(non-cash expensed) 4,435 7,650
Trust unit rights incentive plan
(non-cash exercised) (208) (614)
Deferred entitlement trust units
(non-cash exercised) (5,389) (2,484)
----------------------------------------------------------------------------
Balance, end of period $ 17,167 $ 16,579
----------------------------------------------------------------------------


7. TRUST UNIT BASED COMPENSATION PLANS

Up to ten percent of the issued and outstanding trust units, to a maximum of 24 million trust units, may be reserved for DEUs, rights and option grants, in aggregate, subject to a maximum of 5.5 million DEUs available for issuance pursuant to the long term incentive program.

Long Term Incentive Program

Pengrowth recorded compensation expense of $4.4 million in the six months ended June 30, 2009 (June 30, 2008 - $3.0 million) related to the DEUs based on the weighted average grant date fair value of $6.31 per DEU (June 30, 2008 - $18.40 per DEU). For the six months ended June 30, 2009, 380,164 trust units were issued (June 30, 2008 - 218,737) on redemption of vested DEUs.



Six months ended Year Ended
June 30, 2009 December 31, 2008
----------------------------------------------------------------------------
Weighted Weighted
Number average Number average
DEUs of DEUs price of DEUs price
----------------------------------------------------------------------------
Outstanding, beginning of period 1,270,750 $ 19.38 868,042 $ 20.13
Granted 1,086,098 $ 6.31 578,833 $ 17.88
Forfeited (51,870) $ 13.79 (158,532) $ 19.54
Exercised (261,301) $ 22.03 (202,020) $ 18.51
Deemed DRIP (1) 136,955 $ 15.60 184,427 $ 19.70
----------------------------------------------------------------------------
Outstanding, end of period 2,180,632 $ 12.44 1,270,750 $ 19.38
----------------------------------------------------------------------------
(1) Weighted average deemed DRIP price is based on the average of the
original grant prices.


Trust Unit Rights Incentive Plan

As at June 30, 2009, rights to purchase 5,542,105 trust units were outstanding (December 31, 2008 - 3,292,622) that expire at various dates to June 18, 2014.



Six months ended Year Ended
June 30, 2009 December 31, 2008
----------------------------------------------------------------------------
Weighted Weighted
Number average Number average
Trust Unit Rights of rights price of rights price
----------------------------------------------------------------------------
Outstanding, beginning of period 3,292,622 $ 16.78 2,250,056 $ 17.39
Granted (1) 2,670,021 $ 6.33 1,703,892 $ 17.96
Forfeited (252,531) $ 12.44 (397,469) $ 17.49
Exercised (168,007) $ 6.62 (263,857) $ 14.55
----------------------------------------------------------------------------
Outstanding, end of period 5,542,105 $ 12.22 3,292,622 $ 16.78
----------------------------------------------------------------------------
Exercisable, end of period 3,213,489 $ 14.69 1,950,375 $ 16.52
----------------------------------------------------------------------------
(1) Weighted average exercise price of rights granted are based on the
exercise price at the date of grant.


Compensation expense associated with the trust unit rights granted in the six months ended June 30, 2009 was based on the estimated fair value of $1.08 per trust unit right (June 30, 2008 - $1.70). The fair value of trust unit rights granted in the period was estimated at 17 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 1.7 percent, volatility of 43 percent, expected distribution yield of 20 percent per trust unit and reductions in the exercise price over the life of the trust unit rights. The amount of compensation expense is reduced by the estimated forfeitures at the date of grant which has been estimated at five percent for directors and officers and ten percent for employees. Compensation expense related to the trust unit rights for the six months ended June 30, 2009 was $1.8 million (June 30, 2008 - $1.5 million).

Trust Unit Option Plan

During the six months ended June 30, 2009, no trust unit options were exercised (June 30, 2008 - 26,506 at a weighted average exercise price of $16.43) and 1,700 trust unit options were forfeited (June 30, 2008 - 5,070) at a weighted average exercise price of $14.95 (June 30, 2008 - $17.48). As at June 30, 2009, no options to purchase trust units were outstanding (June 30, 2008 - 34,742 were outstanding with a weighted average exercise price of $14.01).



8. DEFICIT

As at As at
June 30, 2009 December 31, 2008
----------------------------------------------------------------------------
Accumulated earnings $ 2,027,228 $ 2,071,188
Accumulated distributions declared (4,167,447) (4,012,709)
----------------------------------------------------------------------------
$ (2,140,219) $ (1,941,521)
----------------------------------------------------------------------------


Pengrowth is obligated by virtue of its Royalty and Trust Indentures and NPI agreement to distribute to unitholders a significant portion of its cash flow from operations. Cash flow from operations typically exceeds net income or loss as a result of non-cash expenses such as unrealized gains (losses) on commodity contracts, unrealized foreign exchange gains (losses), depletion, depreciation and accretion. These non-cash expenses result in a deficit being recorded despite Pengrowth distributing less than its cash flow from operations.

Distributions paid

Actual cash distributions paid for the six months ended June 30, 2009 were $190 million (June 30, 2008 - $334 million). Distributions declared have been determined in accordance with the Trust Indenture. Distributions are declared payable in the following month after the distributions were earned. The amount of cash not distributed to unitholders is at the discretion of the Board of Directors.



9. FOREIGN EXCHANGE LOSS (GAIN)

Three months ended Six months ended
June 30, June 30, June 30, June 30,
2009 2008 2009 2008
----------------------------------------------------------------------------
Unrealized foreign exchange (gain)
loss on translation of U.S. dollar
denominated debt $(85,030) $ (4,080) $(47,575) $ 17,040
Unrealized foreign exchange loss
(gain) on translation of U.K.
pound sterling denominated debt 5,195 (655) 6,900 3,380
----------------------------------------------------------------------------
(79,835) (4,735) (40,675) 20,420
Unrealized (gain) loss on foreign
exchange risk management contracts (9,527) 4,026 (9,899) 15,443
----------------------------------------------------------------------------
(89,362) (709) (50,574) 35,863
Realized foreign exchange loss
(gain) 1,168 (371) 435 (1,119)
----------------------------------------------------------------------------
$(88,194) $ (1,080) $(50,139) $ 34,744
----------------------------------------------------------------------------


10. OTHER CASH FLOW DISCLOSURES

Change in Non-Cash Operating Working Capital

Three months ended Six months ended
June 30, June 30, June 30, June 30,
Cash provided by (used for): 2009 2008 2009 2008
----------------------------------------------------------------------------
Accounts receivable $ 9,670 $(50,970) $ 18,191 $(59,567)
Accounts payable and accrued
liabilities (24,970) 46,470 (70,322) 50,130
Due from Pengrowth Management
Limited (679) (334) 182 2,216
----------------------------------------------------------------------------
$ (15,979) $ (4,834) $(51,949) $ (7,221)
----------------------------------------------------------------------------


Change in Non-Cash Investing Working Capital

Three months ended Six months ended
June 30, June 30, June 30, June 30,
Cash used for: 2009 2008 2009 2008
----------------------------------------------------------------------------
Accounts payable and capital
accruals $ (11,685) $(11,651) $(21,076) $ (9,979)
----------------------------------------------------------------------------


Cash Interest Payments

Three months ended Six months ended
June 30, June 30, June 30, June 30,
2009 2008 2009 2008
----------------------------------------------------------------------------
Interest on long-term debt $ 13,915 $ 17,851 $ 46,256 $ 37,347
----------------------------------------------------------------------------


11. AMOUNTS PER TRUST UNIT

The following reconciles the weighted average number of trust units used in
the basic and diluted net income (loss) per unit calculations:

Three months ended Six months ended
June 30, 2009 June 30, 2008 June 30, 2009 June 30, 2008
----------------------------------------------------------------------------
Weighted average
number of trust
units - basic 257,970,863 248,488,936 257,352,129 247,873,071
Dilutive effect of
trust unit options,
trust unit rights
and DEUs 1,569,054 - - -
----------------------------------------------------------------------------
Weighted average
number of trust
units - diluted 259,539,917 248,488,936 257,352,129 247,873,071
----------------------------------------------------------------------------


For the three months ended June 30, 2009, 6.2 million trust units from trust unit options, rights, DEUs and the convertible debentures were excluded from the diluted net income (loss) per unit calculation as their effect is anti-dilutive. For the three months ended June 30, 2008 and for the six months ended June 30, 2008 and 2009, all trust units from trust unit options, rights, DEUs and the convertible debentures were excluded from the diluted net income (loss) per unit calculation as their effect is anti-dilutive.

12. CAPITAL DISCLOSURES

Pengrowth defines its capital as trust unitholders' equity, long term debt, bank indebtedness, convertible debentures and working capital.

Pengrowth's goal over longer periods of time is to maximize returns to the unitholders through cash distributions on a per trust unit basis and enhancing the value of the trust units. Pengrowth's aim is to maintain sufficient financial flexibility in its capital structure to allow it to finance its capital expenditures to replace produced reserves through operating cash flows and within Pengrowth's debt capacity while maintaining distributions at a level that provides a reasonable return to unitholders. Pengrowth seeks to retain sufficient flexibility with its capital to take advantage of acquisition opportunities that may arise.

Pengrowth must comply with certain financial debt covenants. Compliance with these financial covenants is closely monitored by management as part of Pengrowth's overall capital management objectives. The covenants are based on specific definitions prescribed in the debt agreements and are different between the credit facility and the term notes. Throughout the period, Pengrowth was in compliance with all financial covenants.

Pengrowth's ability to issue trust units and convertible debt is subject to external restrictions as a result of the Specified Investment Flow-Through Entities Legislation (the SIFT tax). As of June 30, 2009 Pengrowth may issue an additional $4.2 billion of equity in total for 2009 and 2010 under the safe harbour provisions.

Management monitors capital using non-GAAP financial metrics, primarily total debt to the trailing twelve months earnings before interest, taxes, depletion, depreciation, amortization, accretion, and other non-cash items (EBITDA) and Total Debt to Total Capitalization. Pengrowth seeks to manage the ratio of total debt to trailing EBITDA and Total Debt to Total Capitalization ratio with the objective of being able to finance its growth strategy while maintaining sufficient flexibility under the debt covenants.

In order to maintain its financial condition or adjust its capital structure, Pengrowth may issue new debt, refinance existing debt, issue additional equity, adjust the level of distributions paid to unitholders, adjust the level of capital spending or dispose of non-core assets to reduce debt levels. To maintain its financial flexibility, Pengrowth reduced distributions twice between March 31, 2008 and March 31, 2009 from 22.5 cents per trust unit to 17 cents per trust unit to 10 cents per trust unit. However, there may be instances where it would be acceptable for total debt to trailing EBITDA to temporarily fall outside of the normal targets set by management such as in financing an acquisition to take advantage of growth opportunities. This would be a strategic decision made by management and approved by the Board of Directors with steps taken in the subsequent period to restore Pengrowth's capital structure based on its capital management objectives.

Pengrowth's objectives, policies and processes for managing capital have remained substantially consistent from the prior year. Management believes that current total debt to trailing EBITDA is within reasonable limits.

The following is a summary of Pengrowth's capital structure, excluding unitholders' equity:



As at As at
June 30, 2009 December 31, 2008
----------------------------------------------------------------------------
Term credit facilities $ 450,000 $ 372,000
Senior unsecured notes(1) 938,158 1,152,503
Working capital deficiency 191,223 70,159
Convertible debentures 74,871 74,915
----------------------------------------------------------------------------
Total debt including convertible debentures $ 1,654,252 $ 1,669,577
----------------------------------------------------------------------------
(1) Non-current portion of long-term debt


13. FINANCIAL INSTRUMENTS

MARKET RISK

Market risk is the risk that the fair value, or future cash flows of financial assets and liabilities, will fluctuate due to movements in market prices. Market risk is composed of commodity price risk, foreign currency risk, interest rate risk and equity price risk.



Commodity Price Risk
As at June 30, 2009, Pengrowth had fixed the price applicable to future
production as follows:

Crude Oil:
----------------------------------------------------------------------------
Remaining term Volume (bbl/d) Reference Point Price per bbl
----------------------------------------------------------------------------
Financial:
Jul 1, 2009 - Dec 31, 2009 15,500 WTI (1) $ 82.45 Cdn
Jan 1, 2010 - Dec 31, 2010 12,500 WTI (1) $ 82.09 Cdn
Jan 1, 2011 - Dec 31, 2011 500 WTI (1) $ 82.44 Cdn
----------------------------------------------------------------------------
(1) Associated Cdn $/U.S. $ foreign exchange rate has been fixed


Natural Gas:
----------------------------------------------------------------------------
Price per
Remaining term Volume (mmbtu/d) Reference Point mmbtu
----------------------------------------------------------------------------
Financial:
Jul 1, 2009 - Dec 31, 2009 10,000 NYMEX (1) $ 8.50 Cdn
Jul 1, 2009 - Dec 31, 2009 49,760 AECO $ 7.76 Cdn
Jul 1, 2009 - Dec 31, 2009 15,000 Chicago MI (1) $ 8.45 Cdn
Jan 1, 2010 - Dec 31, 2010 16,587 AECO $ 8.64 Cdn
----------------------------------------------------------------------------
(1) Associated Cdn $/U.S. $ foreign exchange rate has been fixed


Pengrowth has designated the above commodity risk management contracts as held for trading and recorded the contracts on the balance sheet at fair value.

The fair value of the commodity risk management contracts are allocated to current and non-current assets and liabilities on a contract by contract basis. The change in the fair value of the commodity risk management contracts during the period is recognized as an unrealized gain or loss on the statement of income (loss) as follows:



As at As at
Commodity Risk Management Contracts June 30, 2009 June 30, 2008
----------------------------------------------------------------------------
Current portion of unrealized risk
management assets $ 52,909 $ -
Non-current portion of unrealized risk
management assets 4,467 -
Current portion of unrealized risk
management liabilities (7,630) (459,937)
Non-current portion of unrealized risk
management liabilities (13,070) (143,625)
----------------------------------------------------------------------------
Total unrealized risk management assets
(liabilities) at period end $ 36,676 $ (603,562)
----------------------------------------------------------------------------


Three months ended Three months ended
June 30, 2009 June 30, 2008
----------------------------------------------------------------------------
Total unrealized risk management
assets (liabilities) at period end $ 36,676 $ (603,562)
Less: Unrealized risk management
assets (liabilities) at beginning of
period 152,076 (250,934)
----------------------------------------------------------------------------
Unrealized loss on risk management
contracts for the period $ (115,400) $ (352,628)
----------------------------------------------------------------------------


Six months ended Six months ended
June 30, 2009 June 30, 2008
----------------------------------------------------------------------------
Total unrealized risk management
assets (liabilities) at period end $ 36,676 $ (603,562)
Less: Unrealized risk management
assets (liabilities) at beginning of
period 164,692 (85,207)
----------------------------------------------------------------------------
Unrealized loss on risk management
contracts for the period $ (128,016) $ (518,355)
----------------------------------------------------------------------------


Commodity Price Sensitivity

Each Cdn $1 per barrel change in future oil prices would result in approximately Cdn $7.6 million pre-tax change in the unrealized gain (loss) on commodity risk management contracts. Similarly, each Cdn $0.25 per mcf change in future natural gas prices would result in approximately Cdn $4.9 million pre-tax change in the unrealized gain (loss) on commodity risk management contracts.

As of close June 30, 2009, the AECO spot price gas price was approximately $3.01/GJ and the WTI prompt month price was U.S. $69.89 per barrel.

Foreign Exchange Risk

Pengrowth entered into foreign exchange risk management contracts in conjunction with issuing U.K. Pounds Sterling 50 million ten year term notes which fixed the Canadian dollar to U.K. Pound Sterling exchange rate on the interest and principal of the U.K. Pound Sterling denominated debt at approximately 0.4976 U.K. Pounds Sterling per Canadian dollar. The estimated fair value of the foreign exchange risk management contracts have been determined based on the amount Pengrowth would receive or pay to terminate the contracts at period end. At June 30, 2009, the amount Pengrowth would pay to terminate the foreign exchange risk management contracts would be approximately $8.8 million.

Pengrowth has designated the foreign exchange risk management contracts as held for trading and are recorded on the balance sheet at fair value. The fair value of the foreign exchange risk management contracts are allocated to current and non-current assets and liabilities on a contract by contract basis. The change in the fair value of the foreign exchange risk management contracts during the period is recognized as an unrealized gain or loss on the statement of income (loss) as follows:



As at As at
Foreign Exchange Risk Management Contracts June 30, 2009 June 30, 2008
----------------------------------------------------------------------------
Current portion of unrealized risk
management liabilities $ (1,374) $ (1,298)
Non-current portion of unrealized risk
management liabilities (7,454) (8,339)
----------------------------------------------------------------------------
Total unrealized risk management
liabilities at period end $ (8,828) $ (9,637)
----------------------------------------------------------------------------

Three months ended Three months ended
June 30, 2009 June 30, 2008
----------------------------------------------------------------------------
Total unrealized risk management
liabilities at period end $ (8,828) $ (9,637)
Less: Unrealized risk management
liabilities at beginning of period (18,355) (5,611)
----------------------------------------------------------------------------
Unrealized gain (loss) on risk
management contracts for the period $ 9,527 $ (4,026)
----------------------------------------------------------------------------


Six months ended Six months ended
June 30, 2009 June 30, 2008
----------------------------------------------------------------------------
Total unrealized risk management
liabilities at period end $ (8,828) $ (9,637)
Less: Unrealized risk management
(liabilities) assets at beginning of
period (18,727) 5,806
----------------------------------------------------------------------------
Unrealized gain (loss) on risk
management contracts for the period $ 9,899 $ (15,443)
----------------------------------------------------------------------------


Foreign Exchange Rate Sensitivity

The following summarizes the sensitivity on a pre-tax basis of a change in the foreign exchange rate on unrealized foreign exchange gains (losses) related to the translation of the foreign denominated term debt and on unrealized gains (losses) related to the change in the fair value of the foreign exchange risk management contracts, holding all other variables constant:



Cdn $0.01 Exchange Rate Change
Foreign Exchange Sensitivity Cdn - U.S. Cdn - U.K.
----------------------------------------------------------------------------
Unrealized foreign exchange gain or loss $ 8,650 $ 500
Unrealized foreign exchange risk management
gain or loss - 574
----------------------------------------------------------------------------


Interest Rate Risk

Pengrowth is exposed to interest rate risk on the Canadian dollar revolving credit facility as the interest is based on floating interest rates. Pengrowth has mitigated some of its exposure to interest rate risk by issuing fixed rate term notes.

Interest Rate Sensitivity

As at June 30, 2009, Pengrowth has approximately $1.6 billion of long term debt of which $450 million is based on floating interest rates. A one percent increase in interest rates would increase pre-tax interest expense by approximately $2.3 million for the six months ended June 30, 2009.

Equity Price Risk

Pengrowth has exposure to equity price risk on investments in an exchange traded bond fund related to a portion of the remediation trust fund and on its investment in Result, a publicly traded entity. Pengrowth's exposure to equity price risk is not significant.



FAIR VALUE
The fair value of financial instruments that differ from their carrying
value are as follows:

June 30, 2009 December 31, 2008
Carrying Carrying
As at Amount Fair Value Amount Fair Value
----------------------------------------------------------------------------
Financial Assets
Remediation Trust Funds $ 31,010 $ 30,806 $ 27,122 $ 26,948
Financial Liabilities
U.S. dollar denominated senior
unsecured notes $1,002,077 $1,077,337 $1,049,218 $1,213,723
Cdn dollar senior unsecured
notes $ 15,000 $ 15,453 $ 15,000 $ 16,075
U.K. Pound Sterling
denominated unsecured notes $ 95,219 $ 102,452 $ 88,285 $ 95,495
Convertible debentures $ 74,871 $ 74,741 $ 74,915 $ 68,014
----------------------------------------------------------------------------


CREDIT RISK

Pengrowth considers amounts over 90 days as past due. As at June 30, 2009, the amount of accounts receivable that were past due was not significant. Pengrowth has not recorded a significant allowance for doubtful accounts as no significant impairment issues exist at June 30, 2009. Pengrowth's objectives, processes and policies for managing credit risk have not changed from the previous year.



LIQUIDITY RISK
All of Pengrowth's financial liabilities are current and due within one
year, except as follows:

More
Carrying Contractual within 1-2 2-5 than 5
As at June 30, 2009 Amount Cash Flows 1 year years years years
----------------------------------------------------------------------------
Cdn dollar revolving
credit facility(1) $450,000 $ 458,727 $ 4,455 $454,272 $ - $ -
Cdn dollar senior
unsecured notes(1) 15,000 24,071 992 992 2,977 19,110
U.S. dollar
denominated senior
unsecured notes(1) 827,939 1,279,064 54,233 54,233 217,225 953,373
U.K. Pound Sterling
denominated
unsecured notes(1) 95,219 129,230 5,224 5,224 15,684 103,098
Convertible
debentures (1) 74,871 82,048 4,858 77,190 - -
Remediation trust
fund payments - 12,500 250 250 750 11,250
Commodity risk
management contracts 20,700 21,001 7,699 12,517 785 -
Foreign exchange
risk management
contracts 8,828 195 30 30 90 45
----------------------------------------------------------------------------
(1) Contractual cash flows include future interest payments calculated at
period end exchange rates and interest rates.


Contact Information