Pengrowth Q1 2012

PENGROWTH ENERGY CORPORATION

First Quarter 2012 Results

SUMMARY OF FINANCIAL & OPERATING RESULTS

(monetary amounts in millions, except per share and per boe amounts or as otherwise stated)Three months ended

Mar 31, 2012 Dec 31, 2011 % Change Mar 31, 2011 % Change

CASH FLOW

Funds flow from operations (1) $ 113.6 $ 171.1 (34) $ 146.8 (23)Funds flow from operations per share $ 0.31 $ 0.50 (38) $ 0.45 (31)

Oil and gas sales (2) (3) $ 328.5 $ 389.2 (16) $ 340.9 (4)Oil and gas sales per boe $ 47.73 $ 55.17 (13) $ 51.45 (7)

Operating expense $ 95.5 $ 99.7 (4) $ 91.5 4Operating expense per boe $ 13.88 $ 14.13 (2) $ 13.81 1

Royalty expense $ 77.9 $ 72.3 8 $ 60.4 29Royalty expense per boe $ 11.32 $ 10.25 10 $ 9.11 24Royalty expense as a percent of sales 24% 19% 18%

Cash G&A expense $ 16.4 $ 16.3 1 $ 17.7 (7)Cash G&A expense per boe $ 2.39 $ 2.31 3 $ 2.67 (10)

Capital expenditures $ 153.7 $ 142.1 8 $ 140.7 9Capital expenditures per share $ 0.42 $ 0.41 2 $ 0.43 (2)

Capital expenditures including net acquisitions $ 178.8 $ 132.6 35 $ 142.1 26Capital expenditures including net acquisitions per share $ 0.49 $ 0.38 30 $ 0.44 11

Dividends paid $ 75.8 $ 71.4 6 $ 68.2 11Dividends paid per share $ 0.21 $ 0.21 – $ 0.21 –

Number of shares outstanding at period end (000’s) 364,471 360,282 1 327,070 11Weighted average number of shares outstanding (000’s) 361,966 345,163 5 326,373 11STATEMENT OF INCOME (LOSS)

Adjusted Net (Loss) Income (4) $ (5.4) $ 22.3 (124) $ 35.9 (115)Net income (loss) $ 0.7 $ (9.0) 108 $ 5.4 (87)Net income (loss) per share – $ (0.03) 100 $ 0.02 (100)LONG TERM DEBT (5)

Long term debt $ 1,044.0 $ 1,007.7 4 $ 1,109.2 (6)PRODUCTION

Average daily production (boe) 75,618 76,691 (1) 73,634 3CONTRIBUTION BASED ON OPERATING NETBACKS (4)

Light oil 61% 54% 49%Heavy oil 16% 14% 12%Natural gas liquids 21% 20% 19%Natural gas 2% 12% 20%

(1) See definition under section “Additional GAAP Measures”.(2) Prior periods restated to conform to presentation in the current period.(3) Includes the impact of realized commodity risk management contracts.(4) See definition under section “Non-GAAP Financial Measures”.(5) As at period end.

Note regarding currency: all figures contained within this report are quoted in Canadian dollars unless otherwise indicated. Noteregarding oil production: references to light oil contained within this report include light and medium oil.

Note: On March 23, 2012, Pengrowth announced that it has entered into an arrangement agreement (“the ArrangementAgreement”) for the strategic business combination of Pengrowth and NAL Energy Corporation (“NAL”) by way of a Court

approved plan of arrangement (“the Proposed Arrangement”). The Proposed Arrangement is expected to close on May 31, 2012(see Proposed Transaction section for additional information). Actual results for the first quarter and the prior quarters do not

include any impact of the Proposed Arrangement.

PENGROWTH First Quarter 2012 Summary of Financial & Operating Results 1

SUMMARY OF TRADING DATA

Three months ended March 31(thousands, except per share amounts) 2012 2011

SHARE TRADING

PGH (NYSE)

High U.S.$ 11.17 U.S.$ 14.14

Low U.S.$ 9.40 U.S.$ 12.09

Close U.S.$ 9.40 U.S.$ 13.83

Value U.S.$200,560 U.S.$284,752

Volume 19,845 21,853

PGF (TSX)

High $ 11.36 $ 13.80

Low $ 9.35 $ 11.98

Close $ 9.35 $ 13.41

Value $530,389 $795,747

Volume 52,533 61,957

2 PENGROWTH First Quarter 2012 Summary of Trading Data

MANAGEMENT’S DISCUSSION & ANALYSIS

The following Management’s Discussion and Analysis (“MD&A”) of financial results should be read in conjunction with theunaudited financial statements for the three months ended March 31, 2012 of Pengrowth Energy Corporation. The MD&A is basedon information available to May 2, 2012.

STRUCTURE OF THE CORPORATIONPengrowth Energy Corporation (the “Corporation”) is a Canadian resource company that is engaged in the production, development,exploration and acquisition of oil and natural gas assets.

FREQUENTLY RECURRING TERMSPengrowth uses the following frequently recurring industry terms in this MD&A: “bbls” refers to barrels, “Mbbls” refers tothousands of barrels, “boe” refers to barrels of oil equivalent, “Mboe” refers to a thousand boe, “MMboe” refers to million boe,“Mcf” refers to thousand cubic feet, “MMcf’ refers to million cubic feet, “Bcf” refers to billion cubic feet, , “MMBtu” refers to millionBritish thermal units and “MW” refers to megawatt. Disclosure provided herein in respect of a boe may be misleading, particularly ifused in isolation. A boe conversion ratio of six Mcf of natural gas to one barrel of crude oil equivalent is based on an energyequivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

ADVISORY REGARDING FORWARD-LOOKING STATEMENTSThis MD&A contains forward-looking statements within the meaning of securities laws, including the “safe harbour” provisions ofCanadian securities legislation and the United States Private Securities Litigation Reform Act of 1995. Forward-looking information isoften, 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 orlanguage suggesting an outlook. Forward-looking statements in this MD&A include, but are not limited to, statements with respectto: reserves, 2012 production, the proportion of 2012 production of each product type, production additions from Pengrowth’s 2012development program, royalty expenses, 2012 operating expenses, deferred income taxes, goodwill, asset retirement obligations,taxability of dividends, remediation, reclamation and abandonment expenses, capital expenditures, development activities, generaland administration expenses, and proceeds from the disposal of properties. Statements relating to “reserves” are forward-lookingstatements, as they involve the implied assessment, based on certain estimates and assumptions that the reserves described existin 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, andinformation currently available to, Pengrowth concerning general economic and financial market conditions, anticipated financialperformance, business prospects, strategies, regulatory developments, including in respect of taxation, royalty rates andenvironmental protection, future capital expenditures and the timing thereof, future oil and natural gas commodity prices anddifferentials between light, medium and heavy oil prices, future oil and natural gas production levels, future exchange rates andinterest rates, the proceeds of anticipated divestitures, the amount of future cash dividends paid by Pengrowth, the cost ofexpanding our property holdings, our ability to obtain labour and 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, ourability to obtain financing on acceptable terms, our ability to add production and reserves through our development, exploitation andexploration activities. Although management considers these assumptions to be reasonable based on information currentlyavailable 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 thatpredictions, forecasts, projections and other forward-looking statements will not be achieved. We caution readers not to placeundue reliance on these statements as a number of important factors could cause the actual results to differ materially from thebeliefs, 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 capitalexpenditures; 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, ability to produce those reserves; production may be impacted byunforeseen events such as equipment failures and weather related issues; environmental claims and liabilities; incorrectassessments of value when making acquisitions; increases in debt service charges; the loss of key personnel; the marketability ofproduction; defaults by third party operators; unforeseen title defects; fluctuations in foreign currency and exchange rates;inadequate insurance coverage; counterparty risk; compliance with environmental laws and regulations; changes in tax and royaltylaws; Pengrowth’s ability to access external sources of debt and equity capital; the implementation of International FinancialReporting Standards; and the implementation of greenhouse gas emissions legislation. Further information regarding these factors

PENGROWTH First Quarter 2012 Management’s Discussion & Analysis 3

may be found under the heading “Business Risks” herein and under “Risk Factors” in Pengrowth’s most recent Annual InformationForm (AIF), and in Pengrowth’s most recent consolidated financial statements, management information circular, quarterly reports,material change reports and news releases. Copies of Pengrowth’s Canadian public filings are available on SEDAR atwww.sedar.com. Pengrowth’s U.S. public filings, including the most recent annual report form 40-F as supplemented by its filingson 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 foregoingfactors and other uncertainties and potential events. Furthermore, the forward-looking statements contained in this MD&A aremade as of the date of this MD&A and Pengrowth does not undertake any obligation to update publicly or to revise any of theincluded forward-looking statements, except as required by law. The forward-looking statements in this document are provided forthe limited purpose of enabling current and potential investors to evaluate an investment in Pengrowth. Readers are cautioned thatsuch statements may not be appropriate, and should not be used for other purposes.

The forward-looking statements contained in this MD&A are expressly qualified by this cautionary statement.

CRITICAL ACCOUNTING ESTIMATESThe financial statements are prepared in accordance with IFRS. Management is required to make estimates and assumptions thataffect the reported amounts of assets and liabilities at the date of the financial statements and revenues and expenses for theperiod ended. Certain of these estimates may change from period to period resulting in a material impact on Pengrowth’s results ofoperations, financial position, and change in financial position.

The following describes Pengrowth’s significant critical accounting estimates.

Estimating oil and gas reserves

Pengrowth engages a qualified, independent oil and gas reserves evaluator to perform an estimation of the Corporation’s oil andgas reserves at least annually. Reserves form the basis for the calculation of depletion charges and assessment of impairment ofoil and gas assets. Reserves are estimated using the reserve definitions and guidelines prescribed by National Instrument 51-101(NI 51-101) and the Canadian Oil and Gas Evaluation Handbook (COGEH).

Proved plus probable reserves are defined as the “best estimate” of quantities of oil, natural gas and related substances estimatedto be commercially recoverable from known accumulations, from a given date forward, based on drilling, geological, geophysicaland engineering data, the use of established technology and specified economic conditions. It is equally likely that the actualremaining quantities recovered will be greater than or less than the sum of the estimated proved plus probable reserves. Theestimates are made using all available geological and reservoir data as well as historical production data. Estimates are reviewedand revised as appropriate. Revisions occur as a result of changes in prices, costs, fiscal regimes and reservoir performance or achange in Pengrowth’s plans with respect to future development or operating practices.

Determination of Cash Generating Units (“CGUs”)

CGUs are the smallest group of assets that generate cash inflows largely independent from other assets or group of assets.Determination of what constitutes a CGU is subject to management’s judgement. The asset composition of a CGU can directlyimpact the recoverability of the assets included therein. The recoverability of development and production asset carrying values areassessed at the CGU level. In assessing the recoverability of oil and gas properties, each CGU’s carrying value is compared to itsrecoverable amount, defined as the greater of fair value less costs to sell and value in use.

Asset Retirement Obligation

Pengrowth estimates obligations under environmental regulations in respect of decommissioning and site restoration. Theseobligations are determined based on the expected present value of expenses required in the process of plugging and abandoningwells, dismantling of wellheads, production and transportation facilities and restoration of producing areas in accordance withrelevant legislation, discounted from the date when expenses are expected to be incurred. Most of the abandonment of Pengrowth’swells is estimated to take place far in the future. Therefore, changes in estimated timing of future expenses, estimated logistics ofperforming abandonment work and the discount rate used to present value future expenses could have a significant effect on thecarrying amount of the decommissioning provision.

Impairment testing

Impairment testing of property, plant and equipment is completed for each of Pengrowth’s CGUs. Impairment testing is based onestimates of proved plus probable reserves, production rates, oil and natural gas prices, future costs, discount rates and otherrelevant assumptions. The impairment assessment of goodwill is based on the estimated fair value of Pengrowth’s CGUs. By theirnature, these estimates are subject to measurement uncertainty and may impact the financial statements of future periods.

4 PENGROWTH First Quarter 2012 Management’s Discussion & Analysis

Valuation of trade and other receivables, and prepayments to suppliers

Management estimates the likelihood of the collection of trade and other receivables and recovery of prepayments based on ananalysis of individual accounts. Factors taken into consideration include the aging of receivables in comparison with the creditterms allowed to customers and the financial position and collection history with the customer. Should actual collections be lessthan estimates, Pengrowth would be required to record an additional expense.

ADDITIONAL GAAP MEASURE

Funds Flow from Operations

Pengrowth uses Funds Flow from Operations, a Generally Accepted Accounting Principles (“GAAP”) measure that is not definedunder IFRS. Management believes that in addition to cash provided by operations, Funds Flow from Operations, as reported in theConsolidated Statements of Cash Flow is a useful supplemental measure as it provides an indication of the funds generated byPengrowth’s principal business activities prior to consideration of changes in working capital and remediation expenditures.Pengrowth considers this to be a key measure of performance as it demonstrates its ability to generate cash flow necessary to funddividends and capital investments.

NON-GAAP FINANCIAL MEASURES

This MD&A refers to certain financial measures that are not determined in accordance with IFRS. These measures do not havestandardized meanings and may not be comparable to similar measures presented by other oil and gas companies. Measures suchas operating netbacks do not have standardized meanings prescribed by GAAP. See the section of this MD&A entitled OperatingNetbacks for a discussion of the calculation.

The current level of capital expenditures funded through retained cash flow, as compared to debt or equity, can be determined whenit is compared to the difference in Funds Flow from Operations and dividends paid as shown on the Statement of Cash Flow.

Management monitors Pengrowth’s capital structure using non-GAAP financial metrics. The two metrics are Total Debt to thetrailing 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 deficit and long term debt as shown onthe Balance Sheet, and Total Capitalization is the sum of Total Debt and Shareholders’ Equity.

Payout Ratio is a term used to evaluate financial flexibility and the capacity to fund dividends. Payout Ratio is defined on apercentage basis as dividends declared divided by Funds Flow from Operations.

Adjusted Net Income

Management believes that, in addition to net income, Adjusted Net Income is a useful supplemental measure as it reflects theunderlying performance of Pengrowth’s business activities by excluding the after tax effect of non-cash commodity mark to marketgains and losses, non-cash gains on investments and unrealized foreign exchange gains and losses that may significantly impactnet income from period to period based on movements in future commodity prices and foreign exchange rates.

OPERATIONAL MEASURES

The reserves and production in this MD&A refer to company-interest reserves or production that is Pengrowth’s working interestshare of production or reserves prior to the deduction of Crown and other royalties plus any Pengrowth-owned royalty interest inproduction or reserves at the wellhead. Company-interest is more fully described in the AIF.

When converting natural gas to equivalent barrels of oil within this MD&A, Pengrowth uses the industry standard of six Mcf to oneboe. Barrels of oil equivalent may be misleading, particularly if used in isolation; a conversion ratio of six Mcf of natural gas to oneboe is based on an energy equivalency conversion 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.

Pengrowth’s first quarter results for 2012 are contained within this MD&A.


2012 GUIDANCE AND FIRST QUARTER 2012 FINANCIAL HIGHLIGHTSOn March 23, 2012, Pengrowth announced that it has entered into an arrangement agreement (“the Arrangement Agreement”) forthe strategic business combination of Pengrowth and NAL Energy Corporation (“NAL”) by way of a Court approved plan ofarrangement (“the Proposed Arrangement”). The Proposed Arrangement is subject to various approvals, including Court approvaland the approval of Pengrowth and NAL shareholders at separate special meetings to be held on May 23, 2012. The ProposedArrangement is expected to close on May 31, 2012. The 2012 Guidance and actual results contained within this MD&A exclude theimpact of the Proposed Arrangement.

The following table provides a summary of the 2012 Guidance and actual results for the first three months of 2012.

Q1 2012 2012Actual Guidance (1)

Production (boe/d) 75,618 74,500 - 76,500 (2)

Exit Production (boe/d) – 78,000 (2)

Royalty Expense (% of Sales) (3) 22.8 20.0

Operating Expense ($/boe) 13.88 13.89 (4)

G&A Expense (cash & non-cash) ($/boe) 2.88 2.68 (4)

Capital expenditures ($ millions) 153.7 625.0

(1) This guidance does not reflect the Proposed Arrangement with NAL which is expected to close on May 31, 2012.(2) Based on production guidance levels provided on January 24, 2012 and excludes Lindbergh volumes.(3) Royalty expense as a % of sales excludes the impact of commodity risk management contracts.(4) Operating and G&A expense ($/boe) assume the midpoint of production guidance.

First quarter production was at the midpoint of guidance.

Royalty expense in the first quarter exceeded guidance as it was increased by one time prior period adjustments.

2012 operating expenses and general and administrative (“G&A”) costs are anticipated to be within current guidance.

Pengrowth includes production revenue and costs associated with the Lindbergh Steam Assisted Gravity Drainage (“SAGD”) projectin capital expenditures until commerciality is declared, pursuant to Pengrowth’s Exploration and Evaluation Assets (“E&E Assets”)accounting policy (see Note 3 to the financial statements for additional information). When commerciality is declared, Pengrowthwill record revenue, operating and other expenses in its results.

FINANCIAL HIGHLIGHTS

Three months ended(monetary amounts in millions, exceptper boe amounts or as otherwise stated)

Mar 31,2012

Dec 31,2011

Mar 31,2011

Production (boe/d) 75,618 76,691 73,634

Capital expenditures $ 153.7 $ 142.1 $ 140.7

Funds flow from operations (1) $ 113.6 $ 171.1 $ 146.8

Operating netback ($/boe) (2) $ 21.69 $ 29.99 $ 27.64

Adjusted Net (Loss) Income (3) $ (5.4) $ 22.3 $ 35.9

Net income (loss) $ 0.7 $ (9.0) $ 5.4

Included in net income (loss):

Realized (loss) gain on commodity risk management (4) $ (12.7) $ 2.7 $ 3.1

Unrealized loss on commodity risk management (4) $ (14.1) $ (102.9) $ (68.3)

Unrealized foreign exchange gain (4) $ 19.1 $ 29.2 $ 23.5

Non-cash gain on investments (4) $ – $ 23.0 $ –

Deferred tax reduction $ 2.6 $ 13.7 $ 11.2

(1) Prior periods restated to conform to presentation in the current period.(2) Includes the impact of realized commodity risk management contracts.(3) See definition under section “Non-GAAP Financial Measures”.(4) Pre-tax amount.


Funds Flow from Operations

($ millions) 2011 Q4 % Change 2011 Q1 % Change

Funds Flow from Operations 171.1 146.8

Change due to:

Volume (6.4) (4) 23.4 16

Price (36.6) (21) (22.2) (15)

Realized gains or losses on risk management contracts (15.5) (9) (15.8) (11)

Other Income (2.2) (1) 2.0 1

Royalty expense (5.6) (3) (17.5) (12)

Expenses:

Operating 4.2 2 (4.0) (3)

Transportation (0.2) – – –

Cash G&A (0.1) – 1.3 1

Interest & Financing 4.0 2 (0.4) (1)

Realized foreign exchange (0.5) – – –

Other Expenses 1.3 1 0.1 –

2012 Q1 Funds Flow from Operations 113.6 (33) 113.6 (23)

Funds Flow from Operations decreased 33 percent in the first quarter of 2012 compared to the fourth quarter of 2011. The decreasewas due to lower prices for all commodities, lower realized gains on commodity risk management contracts, and higher royaltiesdue to prior period and one-time adjustments of $4.1 million. Realized crude oil prices in the first quarter 2012 compared to theprevious quarter was negatively impacted by a higher discount for Canadian crude oil to the WTI benchmark as a result of pipelinecapacity issues into major refining hubs in the United States which resulted in funds flow from operations being approximately$20 million lower in the current quarter. Partially offsetting these decreases were lower operating expenses and decreased interestand financing charges.

Funds Flow from Operations decreased 23 percent in the first quarter of 2012 compared to the same period in 2011. The decreasewas primarily driven by lower commodity prices for natural gas, lower realized gains on risk management contracts and higherroyalties from prior period and one-time adjustments totaling $5.1 million. Partially offsetting these decreases were increasedrevenues from higher production and realized crude prices in the first quarter of 2012 compared to the same period last year.Although oil sales were higher year over year, the impact of the higher discount for Canadian crude to the WTI benchmark price inthe first quarter 2012 negatively impacted funds flow from operations by approximately $20 million.

Price Sensitivity

The following table illustrates the sensitivity of Funds Flow from Operations to changes in commodity prices.

Estimated Commodity Price Environment (1) Assumption Change

Estimated Impact on12 month Funds Flowfrom Operations(2)(3)

($ millions)

Edmonton Par Oil Price Cdn$/bbl $94.16 $1.00

Light Oil Production 6.9

Heavy Oil Production 1.9

NGL Production 2.9

11.7

AECO Natural Gas Price

Natural Gas Production Cdn$/Mcf $2.07 $0.10 6.0

(1) Calculations are performed independently and are not indicative of actual results when multiple variables change at the same time.(2) Commodity price is based on an estimation of the 12 month forward price curve at April 15, 2012 and a fixed light to heavy oil differential of

approximately $18/bbl and does not include the impact of risk management contracts.(3) The calculated impact on revenue/cash flow is only applicable within a limited range of the change indicated and is based on production

guidance levels contained herein.


Net Income or Loss and Adjusted Net Income or Loss

The following table provides a reconciliation of Net Income to Adjusted Net Income:

Three months ended

(monetary amounts in millions)Mar 31,

2012Dec 31,

2011Mar 31,

2011

Net income (loss) $ 0.7 $ (9.0) $ 5.4

Non-cash items included in net income (loss):

Unrealized loss on commodity risk management (14.1) (102.9) (68.3)

Unrealized foreign exchange gain 19.1 29.2 23.5

Non-cash gain on investments – 23.0 –

Tax effect on non-cash items above 1.1 19.4 14.3

Adjusted Net (Loss) Income $ (5.4) $ 22.3 $ 35.9

An Adjusted Net Loss of $5.4 million was recorded in the first quarter of 2012 as compared to Adjusted Net Income of $22.3 millionand $35.9 million in the fourth quarter of 2011 and the first quarter of 2011, respectively. The changes are summarized below, butare mainly attributable to price-driven reductions in Funds Flow from Operations.

Three Months Ended($ millions) 2011 Q4 2011 Q1

Adjusted Net Income 22.3 35.9

Funds Flow from Operations decrease (57.5) (33.2)

DD&A Expense decrease (increase) 4.4 (8.8)

2011 Q4 Impairment write-off 27.4 –

Decrease in gain on property dispositions (8.0) –

Other (3.2) (1.7)

(36.9) (43.7)

Estimated tax reduction on above 9.2 10.9

Tax rate reduction in prior year – (8.5)

2012 Q1 Adjusted Net Loss (5.4) (5.4)

For the first quarter of 2012, Pengrowth recorded net income of $0.7 million, compared to a net loss of $9.0 million in the fourthquarter of 2011, representing an increase of $9.7 million. The increase in the first quarter of 2012 is primarily due to a lowerunrealized commodity risk management loss as noted in the table above, which more than offset the decrease in Funds Flow fromOperations of $57.5 million and other items noted above.

Net income decreased by $4.7 million from net income of $5.4 million in the first quarter of 2011 to net income of $0.7 million in thefirst quarter of 2012. The change is primarily due to a lower unrealized commodity risk management loss as noted in the tableabove, partly offset by a decrease in Funds Flow from Operations of $33.2 million and other items noted above.


RESULTS OF OPERATIONS

(All volumes, wells and spending amounts stated below reflect Pengrowth’s net working interest unless otherwise stated.)

CAPITAL EXPENDITURES

For the first quarter of 2012, Pengrowth spent $153.7 million on capital expenditures excluding property acquisitions anddispositions. Approximately 80 percent of the capital expenditures were spent on drilling, completions and facilities, with theremaining 20 percent spent on land, seismic and maintenance capital.

Three months ended

($ millions)Mar 31,

2012Dec 31,

2011Mar 31,

2011

Drilling, completions and facilities (1) $ 122.7 $ 124.6 $ 121.3

Land & Seismic acquisitions (2) 12.8 6.9 1.4

Maintenance capital 18.1 12.2 17.3

Development capital 153.6 143.7 140.0

Other capital (1) (3) 0.1 (0.8) 0.7

Drilling Royalty Credits – (0.8) –

Capital expenditures 153.7 142.1 140.7

Property acquisitions 27.1 – 1.5

Proceeds on property dispositions (2.0) (9.5) (0.1)

Capital expenditures including net acquisitions $ 178.8 $ 132.6 $ 142.1

(1) Prior periods restated to conform to presentation in the current period.(2) Seismic acquisitions are net of seismic sales revenue.(3) Other capital includes equipment inventory and material transfers.

DRILLING ACTIVITY

Pengrowth participated in the drilling of 68 wells (37.5 net) in the first quarter of 2012.

Q1 2012Gross Net

Focus Areas (1)

Swan Hills 15 8.2

Lindbergh 18 18.0

Olds 4 2.6

Other Areas (1) 31 8.7

Total wells drilled 68 37.5

(1) Drilling activity reflects both operated and partner operated properties.


DEVELOPMENT CAPITAL ACTIVITIESPengrowth’s capital spending breakdown by area is as follows:

($ millions) Q1 2012 Full Year 2011

Focus Areas (1)

Swan Hills $ 63.2 $282.1

Lindbergh 19.4 61.4

Olds 17.3 49.8

Bodo Polymer Project 7.2 29.3

Groundbirch – 70.6

107.1 493.2

Other Areas 15.6 40.3

Drilling, completions & facilities 122.7 533.5

Maintenance 18.1 51.7

Land & Seismic Acquisitions 12.8 20.6

Other 0.1 5.7

Drilling Royalty Credits – (2.4)

Net capital expenditures $153.7 $609.1

(1) Spending amounts reflect the activity for both operated and partner operated properties.

Focus Areas

(Pengrowth references average well test results for certain properties. These results are not necessarily representative of long-term well performance or ultimate recoveries.)

Swan Hills TrendWith a net estimated 2.3 billion barrels of 42° API original oil in place in the Beaverhill Lake formation (Energy ResourcesConservation Board estimate), the Swan Hills Trend is the most significant conventional oil resource across Pengrowth’s land base.This extensive carbonate oil reservoir provides Pengrowth with significant opportunities to put its expertise in horizontal drilling andmulti-stage acid fracturing of carbonate reservoirs to work on its operated interests in Judy Creek, Carson Creek, House Mountain,Deer Mountain and Virginia Hills.

During the first quarter, Pengrowth drilled 7 operated wells (6.8 net) in the Swan Hills area. Five of the wells were completed andtested with average five day initial production (“IP”) rates of over 580 boe per day per well and were tied-in during the quarter.Activity during the first quarter also included bringing on stream eight operated wells (7.9 net) previously drilled and completed inthe third and fourth quarters of 2011 with average five day IP rates in excess of 640 boe per day per well.

During the first quarter, Pengrowth had up to 3 rigs drilling in the Swan Hills area and anticipates that a multi-rig drilling programwill continue through the remainder of 2012. Pengrowth had 2 wells awaiting completion and tie-in and 2 wells awaiting tie-in atquarter end.

Lindbergh Steam Assisted Gravity Drainage (“SAGD”) ProjectThe Lindbergh property, located in the Cold Lake area of Alberta, is 100 percent owned and operated by Pengrowth. AtDecember 31, 2011, the Lindbergh lease had Best Estimate Contingent Resources as described in the 2011 AIF, of 296 millionbarrels of bitumen in the Lloydminster formation. This oil has favorable viscosity characteristics and is in a clean, continuous, highpermeability reservoir. Subject to pilot performance and a declaration of commerciality, Lindbergh is expected to providePengrowth with the potential to develop a first commercial stage project of 12,500 barrels of oil per day (bopd) and a final projectwith up to 30,000 bopd. This is expected to be low cost, low decline, stable oil production, with a 25 year reserve life.

During the quarter, Pengrowth completed construction of the central processing facility, well-pad and surface pipelines at the pilotfacility on time and on budget. Expenditures on the pilot facility and the 2 pilot well-pairs were incurred to assess the viability of acommercial project.

During the quarter, Pengrowth began injecting steam consistently into the 2 pilot well-pairs during the circulation phase of SAGDoperations. This phase entails creating and expanding a steam chamber between injector and producer wells. Plant operations havebeen steady during the circulation phase to date and the warm-up phase has been progressing as anticipated.


The reservoir is responding to steam injection and production performance so far indicates good oil mobility, straightforwardtreating and minimal solids production, all of which are encouraging at this early phase.

Performance will be better understood once both well-pairs are converted over to full SAGD operations, with artificial lift (pumps) inplace down-hole, which is planned for the second quarter of 2012.

Engineering and design work continued on the planned first commercial stage.

Olds/GarringtonIn the first quarter Pengrowth drilled 1 (1.0 net) successful liquids rich Mannville well, which was tied-in and had a five-day IP ratein excess of 560 boe per day. Pengrowth also participated in a successful Mannville oil well (net 0.4) which tested on swabbing inexcess of 400 boe per day.

Pengrowth continued with the liquids-rich gas program in the Elkton formation, drilling 2 wells (1.3 net). Completion, evaluation andtie-ins were underway late in the quarter. A third well (1.0 net) was drilling at the end of the quarter which is expected to becompleted and tied-in early in the second quarter.

East Bodo and CactusThe East Bodo and Cactus heavy oil properties which straddle the Alberta-Saskatchewan border produce primarily from theMcLaren and Lloydminster formations. These properties produce heavy oil through a combination of water flooding with enhancedoil recovery through the injection of polymer.

In East Bodo, the construction of the first commercial Polymer project injection facility was completed and successfullycommissioned. This facility will utilize produced water thus minimizing environmental impact (no fresh water consumption). Thetarget for this facility is an incremental recovery of 10 to 15% of the 65 MM bbls of OOIP in the Lloydminster formation at East Bodo.

At Cactus Lake, monitoring is ongoing for the polymer pilot which is testing this enhanced recovery method on the McLarenformation. If successful, this would open up the potential for a 10 to 15% incremental recovery from the 600 MM bbls of OOIP in theMcLaren formation in the Bodo/Cactus area.

PRODUCTION

Three months ended

Daily productionMar 31,

2012% oftotal

Dec 31,2011

% oftotal

Mar 31,2011

% oftotal

Light oil (bbls) 22,431 30 22,935 30 21,066 29

Heavy oil (bbls) 6,576 9 6,448 8 6,639 9

Natural gas liquids (bbls) 11,004 14 10,478 14 9,176 12

Natural gas (Mcf) 213,639 47 220,977 48 220,517 50

Total boe per day 75,618 76,691 73,634

A decrease of approximately 1 percent in the first quarter 2012 average daily production compared to the fourth quarter of 2011 isconsistent with production and spending profiles when comparing the two quarters. The decrease is mainly attributable to naturaldecline partially offset by increased volumes from minor property acquisitions.

Total equivalent production increased 3 percent in the first quarter 2012 compared to the first quarter 2011 mainly due toproduction from new wells in the Swan Hills area and production recoveries after the pipeline failure on the Swan Hills gasgathering line early in 2011 which more than offset natural declines particularly in natural gas production.

Light OilFirst quarter 2012 light oil production decreased 2 percent from the fourth quarter of 2011. This decrease is mainly attributable tonatural decline and sub-surface maintenance work at Carson Creek partially offset by new wells on production in Judy Creek.

Light oil production increased 6 percent in the first quarter of 2012 compared to the same quarter last year due to production fromnew wells in the Swan Hills area and production recoveries after the pipeline failure on the Swan Hills gas gathering line early inthe first quarter of 2011.


Heavy OilHeavy oil production increased 2 percent in the first quarter of 2012 compared to the fourth quarter of 2011 due to increasedproduction at East Bodo, partially offset by reductions at Tangleflags due to surface and sub-surface maintenance work.

The 1 percent decrease between the first quarters of 2012 and 2011 is attributable to reductions at Tangleflags as a result of thepreviously mentioned surface and sub-surface maintenance work mostly offset by production gains in East Bodo.

NGLsNGL production increased 5 percent in the first quarter of 2012 compared to the fourth quarter of 2011 due to additional volumesfrom minor acquisitions, a larger condensate shipment at the Sable Offshore Energy Project (“SOEP”) and new wells on productionin Judy Creek.

Volumes increased 20 percent in the first quarter of 2012 versus the same period last year due to production recovering after thepipeline failure on the Swan Hills gas gathering line early in the first quarter of 2011. In addition to the previously mentioned minoracquisitions, new production in Judy Creek also contributed to higher NGL volumes this quarter.

Natural GasFirst quarter natural gas production decreased 3 percent compared to both fourth and first quarters of 2011 due to natural declinesin Groundbirch and other areas partially offset by minor acquisitions.

Natural declines in gas production are not anticipated to be offset with new production due to current low natural gas commodityprices and Pengrowth’s focus on oil and liquids rich projects.

COMMODITY PRICES

Average Realized Prices

Three months ended(Cdn$ unless otherwise indicated) Mar 31, 2012 Dec 31, 2011 Mar 31, 2011

Light oil (per bbl) (1) 90.24 94.77 85.56

after realized commodity risk management (1) 82.79 91.16 82.70

Heavy oil (per bbl) (1) 71.37 77.60 61.65

Natural gas liquids (per bbl) 67.31 70.54 71.40

Natural gas (per Mcf) 2.20 3.26 3.92

after realized commodity risk management 2.33 3.77 4.35

Average realized price per boe 48.99 53.88 50.68

after realized commodity risk management 47.14 54.28 51.15

Other production income (1) 0.59 0.89 0.30

Total oil and gas sales per boe (1) 47.73 55.17 51.45

Average Benchmark prices

Edmonton par light oil (Cdn$ per bbl) 93.24 97.78 88.60

WTI oil (U.S.$ per bbl) 103.03 94.06 94.60

AECO spot gas (Cdn$ per MMBtu) 2.12 3.19 3.77

NYMEX gas (U.S.$ per MMBtu) 2.50 3.48 4.20

Currency exchange rate ($1 Cdn = $ U.S.) 1.00 0.98 1.01

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

During the first quarter of 2012, WTI benchmark crude oil prices averaged U.S.$103.03 per bbl, an increase of 10 percent from thefourth quarter 2011 and an increase of 9 percent from the first quarter 2011. Canadian benchmark Edmonton par light oil pricesaveraged Cdn$93.24 per bbl during the first quarter, a decline of 5 percent compared to fourth quarter 2011 average price ofCdn$97.78 per bbl and a 5 percent increase compared to first quarter 2011 average price of Cdn$88.60 per bbl. Pipeline capacityissues into major refining hubs in the United States led to a decrease in demand for Canadian crude oil and resulted in a


discounting of Canadian crude oil prices compared to the WTI benchmark price. The discount between the Edmonton-based lightsweet crude and the WTI benchmark averaged Cdn$9.91 per barrel during the quarter, with March experiencing a Cdn$17.68 perbbl discount.

Pengrowth’s average realized price for light oil, after risk management activities, averaged Cdn$82.79 per bbl in the first quarter,which was a decline of 9 percent compared to the fourth quarter 2011 realized price of Cdn$91.16 per bbl and remained essentiallyunchanged when compared to Cdn$82.70 per bbl in the first quarter of 2011. Contributing to the lower realized price versus thefourth quarter was the discounting of Canadian crude oil versus the benchmark WTI crude mentioned earlier coupled with realizedcommodity risk management losses.

Natural gas prices continued to be under pressure during the first quarter, with NYMEX gas declining 28 percent and 40 percentcompared to the fourth quarter and first quarter 2011 average prices of U.S.$3.48 per MMBtu and U.S.$4.20 per MMBtu,respectively. A mild winter across much of North America coupled with an abundant supply of natural gas largely attributable toincreased production from shale gas plays has resulted in record storage volumes of natural gas.

AECO spot prices continued to trade at a discount to the NYMEX benchmark, with prices declining by 34 percent to Cdn$2.12 perMMBtu in the first quarter 2012, compared to Cdn$3.48 per MMBtu in the fourth quarter of 2011 and the decline was 44 percentfrom Cdn$3.77 per MMBtu during the first quarter 2011.

Pengrowth’s average realized natural gas price after risk management activities was Cdn$2.33 per Mcf during the first quarter2012, a 38 percent decline compared to the fourth quarter 2011 average realized price of Cdn$3.77 per Mcf and a decline of 46percent compared to the first quarter 2011 average realized price of Cdn$4.35 per Mcf. The lower realized prices in the first quarterof 2012 were attributable to a lower benchmark price for natural gas and a lower contribution from realized gas commodity riskmanagement activities compared to 2011.

Pengrowth’s total average realized price, after risk management activities during the first quarter was Cdn$47.14 per boe, a 13percent decrease over the fourth quarter 2011 average price of Cdn$54.28 per boe and an 8 percent decrease over the first quarter2011 average price of Cdn$51.15 per boe. The decrease in realized prices is primarily a result of the substantial discounting ofCanadian crude oil versus the WTI benchmark prices, lower natural gas prices and realized commodity risk management losses onoil sales in the first quarter of 2012.

Commodity Risk Management Gains (Losses)

Three months endedMar 31, 2012 Dec 31, 2011 Mar 31, 2011

Realized

Light oil ($ millions) (15.2) (7.6) (5.4)

Light oil ($ per bbl) (7.45) (3.61) (2.86)

Natural gas ($ millions) 2.5 10.4 8.5

Natural gas ($ per Mcf) 0.13 0.51 0.43

Combined ($ millions) (12.7) 2.8 3.1

Combined ($ per boe) (1.85) 0.40 0.47

Unrealized

Total unrealized risk management (liabilities) assets at period end ($ millions) (56.1) (42.0) (70.3)

Less: Unrealized risk management assets (liabilities) at beginning of period($ millions) (42.0) 60.8 (2.1)

Unrealized (loss) gain on risk management contracts (14.1) (102.8) (68.2)

As part of Pengrowth’s risk management strategy, forward price swaps are used to manage exposure to commodity pricefluctuations and provide a measure of stability to cash flow.

Pengrowth incurred a $15.2 million realized risk management loss in the first quarter of 2012 from crude oil risk managementactivities, compared to a $7.6 million loss in the fourth quarter of 2011 and a $5.4 million loss in the first quarter of 2011.Benchmark oil prices used in commodity risk management contracts increased to a level above the average price achieved throughour commodity risk management activities.


Realized gains from natural gas commodity risk management activities decreased to a gain of $2.5 million in the first quarter of2012, compared to gains of $10.4 million and $8.5 million in fourth and first quarters of 2011, respectively. The primary reason forthe lower realized hedging gain was decreased hedged volumes in 2012.

The change in fair value of the forward contracts between periods affects net income through the unrealized amounts recordedduring the period. The fair value of forward contracts is determined by comparing the contracted fixed price to the forward pricecurve at each period end.

Pengrowth experienced a $14.1 million unrealized loss in the first quarter of 2012, compared to a $102.8 million unrealized loss inthe fourth quarter of 2011, and a $68.2 million unrealized loss in the first quarter of 2011. These unrealized losses result when theforward price curve moves higher, and the magnitude of the loss is proportional to the movement in the forward price curve. In thefourth and first quarters of 2011 the forward price curve moved up more than it did in the first quarter of 2012, resulting in largerunrealized losses in those periods.

As of March 31, 2012, the following commodity risk management contracts were in place:

Crude Oil:

Reference Point Volume (bbl/d) Term Price per bbl

Financial:

WTI (1) 17,000 April 1, 2012 - Dec 31, 2012 $93.23 Cdn

WTI (1) 6,000 Jan 1, 2013 - Dec 31, 2013 $98.45 Cdn(1) Associated Cdn $/U.S. $ foreign exchange rate has been fixed.

Natural Gas:

Reference Point Volume (MMBtu/d) Term Price per MMbtu

Financial:

AECO 14,217 April 1, 2012 - Dec 31, 2012 $ 4.45 Cdn

Power:

Reference Point Volume (MW) Term Price per MW

Financial:

AESO 15 April 1, 2012 - Dec 31, 2012 $72.83 Cdn

AESO 5 Jan 1, 2013 - Dec 31, 2013 $74.50 Cdn

Based on the mid-point of our 2012 production guidance, the above contracts represent approximately 46 percent of estimated totalliquids volumes at an average price of $93.23 per bbl and approximately 6 percent of estimated natural gas volumes at $4.45 perMMBtu. The power contracts represent approximately 15 percent of estimated 2012 consumption.

Each Cdn$1 per barrel change in future WTI oil prices results in approximately $6.9 million pre-tax change in the value of the crudecontracts, while each Cdn$0.25 per MMBtu change in future natural gas prices results in approximately $1.0 million pre-tax changein the value of the natural gas contracts. The changes in the fair value of the forward contracts directly affect reported net incomethrough the unrealized amounts recorded in the Statement of Income during the period. The effect on cash flow will be recognizedseparately only upon settlement of the contracts, which could vary significantly from the unrealized amount recorded due to timingand prices when each contract is settled.

If each commodity risk management contract were to settle at the contract price in effect at March 31, 2012, future revenue andcash flow would be $56.1 million lower than if the contracts were not in place based on the estimated fair value of the riskmanagement liability at period end. The $56.1 million liability is composed of a net liability of $47.2 million relating to contractsexpiring within 1 year and a net liability of $8.9 million relating to contracts expiring beyond 1 year. Pengrowth currently fixes theCanadian dollar exchange rate at the same time it swaps U.S. dollar denominated commodity but may change this practice in thefuture.

Each Cdn$1 per MW change in future power prices would result in approximately $0.1 million pre-tax change in the fair value of therisk management contracts.


Pengrowth has not designated any outstanding commodity contracts as hedges for accounting purposes and therefore recordsthese contracts on the Balance Sheet at their fair value and recognizes changes in fair value on the Statement of Income asunrealized commodity risk management gains or losses. There will continue to be volatility in Net Income to the extent that the fairvalue of commodity contracts fluctuate, however these non-cash amounts do not impact Pengrowth’s operating cash flow. Realizedcommodity risk management gains or losses are recorded in oil and gas sales on the Statement of Income and impacts cash flow atthat time.

In accordance with policies approved by the Board of Directors, Pengrowth may sell forward its production by product volume orpower consumption as follows:

Percent of Monthly Company Interest Production or estimated Power Consumption Forward Period

Up to 65% 1 - 12 Months



Each commodity risk management transaction for natural gas or crude oil shall not exceed 20,000 MMBtu per day or 2,500 bbls perday, respectively. Each power consumption risk management transaction shall not exceed 25 MW.

OIL AND GAS SALES

Contribution Analysis

The following table shows the contribution of each product category to the overall sales revenue inclusive of realized commodityrisk management activities:

($ millions except percentages)Sales Revenue

Three months ended

Mar 31,2012

% oftotal

Dec 31,2011

% oftotal

Mar 31,2011

% oftotal

Light oil (1) 169.0 51 192.4 49 156.8 46

Heavy oil (1) 42.7 13 46.0 12 36.8 11

Natural gas liquids 67.4 21 68.0 17 59.0 17

Natural gas 45.3 14 76.5 20 86.3 25

Brokered sales/sulphur (1) 4.1 1 6.3 2 2.0 1

Total oil and gas sales (1) 328.5 389.2 340.9

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

Price and Volume Analysis

The following table illustrates the effect of changes in prices and volumes on the components of oil and gas sales revenue includingthe impact of realized commodity risk management activities, for the first quarter of 2012 compared to the fourth quarter of 2011.The decreased realized natural gas prices and the effect of the higher discount in crude oil prices to WTI combined with lowerrealized gains on commodity risk management contracts are the primary reasons for lower oil and gas sales. The impact of thehigher discount in the Canadian crude oil price to the WTI benchmark in the first quarter 2012 was approximately $20 million.

($ millions) Light oil (1) Natural gas NGLs Heavy oil (1) Other (2) Total (1)

Quarter ended December 31, 2011 192.4 76.5 68.0 46.0 6.3 389.2

Effect of change in product prices and differentials (9.2) (20.5) (3.2) (3.7) – (36.6)

Effect of change in realized commodity risk managementactivities (7.6) (7.9) – – – (15.5)

Effect of change in sales volumes (6.5) (2.9) 2.6 0.4 – (6.4)

Other (0.1) 0.1 – – (2.2) (2.2)

Quarter ended March 31, 2012 169.0 45.3 67.4 42.7 4.1 328.5

(1) Prior period restated to conform to presentation in the current period.(2) Primarily sulphur sales


The following table illustrates the effect of changes in prices and volumes on the components of oil and gas sales including theimpact of realized commodity risk management activity, for the first quarter of 2012 compared to the same period in 2011. Thedecrease in natural gas prices and reduced gains from risk management activities are the primary reasons for lower oil and gassales in the first quarter 2012. Although oil sales increased in the first quarter compared to the same quarter last year, they werenegatively impacted by the higher discount in the Canadian crude oil price to the WTI benchmark by approximately $20 million.Partially offsetting these price decreases were higher revenues due to increased production in 2012.

($ millions) Light oil (1) Natural gas NGLs Heavy oil (1) Other (1) (2) Total (1)


Effect of change in product prices and differentials 9.6 (33.5) (4.1) 5.8 – (22.2)

Effect of change in realized commodity risk managementactivities (9.8) (6.0) – – – (15.8)

Effect of change in sales volumes 12.4 (1.6) 12.5 0.1 – 23.4

Other – 0.1 – – 2.1 2.2


(1) Prior period restated to conform to presentation in the current period.(2) Primarily sulphur sales

ROYALTY EXPENSE

Three months ended

($ millions except per boe amounts)Mar 31,

2012Dec 31,

2011Mar 31,

2011

Royalty expense 77.9 72.3 60.4

$ per boe 11.32 10.25 9.11

Royalties as a percent of sales 23.7% 18.6% 17.7%

Royalties as a percent of sales excluding realized risk management contracts 22.8% 18.7% 17.9%

Royalties include Crown, freehold, overriding royalties and mineral taxes. Royalty payments are based on revenue beforecommodity risk management activities; however gains or losses from realized commodity risk management activities are reportedas part of revenue and therefore affect royalty rates as a percentage of sales. First quarter 2012 royalty rates increased comparedto the both the fourth and first quarters of 2011 due to prior period and one-time royalty adjustments including a $1.5 million SOEPannual royalty true-up, and a $1.2 million gross overriding royalty adjustment at Olds. First quarter gas cost allowance credits were$1.4 million lower when compared to the fourth quarter of 2011 due to favourable adjustments not repeated in the first quarter.

The higher royalty rate in the first quarter of 2012 compared to previous quarters is due to the increasing percentage of salesrevenues from light oil and natural gas liquids which attract a higher royalty rate than natural gas. In addition royalty expense wasapproximately $5.1 million higher in the first quarter of 2012 due to prior period and one-time adjustments.

Royalty expense for 2012 is forecasted to be approximately 20 percent of Pengrowth’s sales excluding the impact of riskmanagement contracts and excluding any impact from the Proposed Arrangement with NAL.

OPERATING EXPENSE

Three months ended

($ millions except per boe amounts)Mar 31,

2012Dec 31,

2011Mar 31,

2011

Operating expense (1) 95.5 99.7 91.5

$ per boe 13.88 14.13 13.81


Operating expenses in the first quarter of 2012 decreased $4.2 million or 2 percent on a per boe basis, compared to the fourthquarter of 2011. Reduced facility maintenance and repair costs coupled with an increase in third party fee income more than offsetthe impact of the increased subsurface activity in the first quarter of 2012.


Comparing the first quarters of 2012 and 2011, operating expenses increased 4 percent. Increased operating expenses wereprimarily attributable to subsurface maintenance and optimization which were partially offset by increased third party fee income.

2012 operating expenses are forecast to be $384 million or $13.89 per boe excluding any impact from the Proposed Arrangementwith NAL.

TRANSPORTATION COSTS

Three months ended

($ millions except per bbl and per Mcf amounts)Mar 31,

2012Dec 31,

2011Mar 31,

2011

Light oil transportation (1) 3.3 2.8 3.1

$ per bbl 1.59 1.34 1.62

Heavy oil transportation (1) 0.7 0.9 0.8

$ per bbl 1.17 1.46 1.63

NGL transportation 0.1 0.2 –

$ per bbl 0.13 0.19 –

Natural gas transportation 1.7 1.7 1.8

$ per Mcf 0.09 0.09 0.09

Total 5.8 5.6 5.7

$ per boe 0.84 0.80 0.88


Overall transportation costs increased 4 percent in the first quarter of 2012 compared to the fourth quarter of 2011 as higher cleanproduct trucking costs were partially offset by reduced heavy oil transportation. Light oil transportation increased approximately 18percent in the first quarter of 2012 compared to the fourth quarter of 2011 primarily due to an increase in Pengrowth’s cleanproduct trucking costs in the non-operated House Mountain area as a section of the Pembina pipeline was shut down in thesummer of 2011 and remains shut down.

Pengrowth incurs transportation costs for its natural gas production once the product enters a pipeline at a title transfer point.Pengrowth has the option to sell some of its natural gas directly to markets outside of Alberta by incurring additional transportationcosts. Pengrowth sells most of its natural gas without incurring significant additional transportation costs. Pengrowth also incurstransportation costs on its oil and NGL production that includes clean oil trucking charges and pipeline costs up to the custodytransfer point. Pengrowth has elected to sell approximately 75 percent of its crude oil at market points beyond the wellheadincurring transportation costs to the first major trading point. The transportation cost is dependent upon third party rates and thedistance the product travels on the pipeline prior to changing ownership or custody.

OPERATING NETBACKS

Pengrowth’s operating netbacks have been calculated by taking balances directly from the Statement of Income and dividing byproduction. Certain assumptions have been made in allocating operating expenses, other income and royalty injection creditsbetween light oil, heavy oil, natural gas and NGL production. Operating netbacks as presented below may not be comparable tosimilar measures presented by other companies, as there are no standardized measures.

Pengrowth realized an average operating netback of $21.69 per boe in the first quarter of 2012 compared to $29.99 per boe in thefourth quarter of 2011 and $27.64 per boe for the first quarter of 2011. The decrease in the netback in the first quarter of 2012compared to the fourth and first quarters of 2011 is primarily due to lower realized commodity prices and prior period royaltyadjustments.

The operating net back for natural gas declined significantly in the first quarter 2012 to $0.13 per mcf compared to $1.32 per mcfand $1.81 per mcf in the fourth and first quarters of 2011, respectively. The primary reasons are related to a 38 percent and 44percent decline in the realized average price from the fourth and first quarter last year, respectively.


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

Three months endedCombined Netbacks ($ per boe) Mar 31, 2012 Dec 31, 2011 Mar 31, 2011

Oil & gas sales (1) 47.73 55.17 51.44

Royalties (11.32) (10.25) (9.11)

Operating expenses (1) (13.88) (14.13) (13.81)

Transportation costs (1) (0.84) (0.80) (0.88)

Operating netback (1) 21.69 29.99 27.64

Three months endedLight Oil Netbacks ($ per bbl) Mar 31, 2012 Dec 31, 2011 Mar 31, 2011

Sales (1) 83.42 92.07 83.29

Royalties (20.70) (21.29) (17.82)



Operating netback (1) 44.53 54.04 47.56

Three months endedHeavy Oil Netbacks ($ per bbl) Mar 31, 2012 Dec 31, 2011 Mar 31, 2011

Sales (1) 71.37 77.60 61.65

Royalties (14.82) (13.65) (9.07)



Operating netback 39.40 48.57 38.22

Three months endedNGLs Netbacks ($ per bbl) Mar 31, 2012 Dec 31, 2011 Mar 31, 2011

Sales 67.31 70.54 71.40

Royalties (22.10) (14.51) (15.87)

Operating expenses (12.95) (12.34) (13.43)

Transportation costs (0.13) (0.20) –


Three months endedNatural Gas Netbacks ($ per Mcf) Mar 31, 2012 Dec 31, 2011 Mar 31, 2011

Sales (1) 2.47 3.98 4.39

Royalties (0.24) (0.26) (0.41)


Transportation costs (0.09) (0.09) (0.09)




GENERAL AND ADMINISTRATIVE EXPENSES

Three months ended($ millions except per boe amounts) Mar 31, 2012 Dec 31, 2011 Mar 31, 2011

Cash G&A expense 16.4 16.3 17.7

$ per boe 2.39 2.31 2.67

Non-cash G&A expense 3.4 2.0 3.1

$ per boe 0.49 0.28 0.47

Total G&A 19.8 18.3 20.8

$ per boe 2.88 2.60 3.14

First quarter cash G&A expenses were essentially unchanged from the fourth quarter of last year. Cash G&A costs for the firstquarter of 2012 compared to the same period last year decreased mainly due to a performance bonus estimate adjustment in 2011and other nonrecurring items.

The non-cash component of G&A represents the compensation expense associated with Pengrowth’s Long Term Incentive Plans(LTIP) (see Note 8 to the financial statements). The compensation costs associated with these plans are expensed over theapplicable vesting period. The $1.4 million decrease in the fourth quarter of 2011 compared to the first quarter of 2012 is primarilydue to a lower performance multiplier used in that period for the Deferred Entitlement Share Units (DESU) as a result of marketperformance below target relative to our peer group. The performance multipliers applicable for the first quarters of 2012 and 2011are both at the target level.

Excluding any impact from the Proposed Arrangement with NAL, total 2012 G&A costs are expected to be $2.68 per boe, whichincludes non-cash G&A costs of approximately $0.49 per boe.

DEPLETION, DEPRECIATION, AMORTIZATION AND ACCRETION

Three months ended($ millions except per boe amounts) Mar 31, 2012 Dec 31, 2011 Mar 31, 2011

Depletion, depreciation and amortization 113.2 117.6 104.4

$ per boe 16.45 16.67 15.75

Accretion 4.2 4.0 3.9

$ per boe 0.61 0.57 0.59

Depletion and depreciation of property, plant and equipment is calculated using the unit of production method, based on provedplus probable reserves and the dollar value of the property, plant and equipment asset base.

The decrease in depletion expense in the first quarter of 2012 compared to the fourth quarter of 2011 is mainly due to lowerproduction volumes. Depletion expense in the first quarter 2012 compared to the same period last year was higher as the depletionrate this quarter reflects the impact of Pengrowth’s increased capital program, and higher production volumes when compared tolast year.

Accretion is a charge to earnings that increases the Asset Retirement Obligations (ARO) liability for the passage of time (unwindingof the discount). Accretion is charged to net income over the lifetime of the producing oil and gas assets.

INTEREST AND FINANCING CHARGES

Three months ended($ millions) Mar 31, 2012 Dec 31, 2011 Mar 31, 2011

Interest and Financing charges 17.1 21.1 16.7

At March 31, 2012, Pengrowth had approximately $1 billion in long term debt. The majority of long term debt consists of U.S. dollardenominated fixed rate notes at a weighted average interest rate of 6.3 percent. Long term debt also consists of drawings fromPengrowth’s syndicated bank facility which is subject to prevailing market rates. At March 31, 2012, Pengrowth’s floating rate costof funds was approximately 3 percent.


Interest and financing charges were $4.0 million lower in the first quarter of 2012 than the fourth quarter of 2011, as Pengrowthrenewed its syndicated credit facility in the fourth quarter of 2011 resulting in $2.0 million of unamortized costs on the previous2010 bank renewal being expensed in the quarter. The slight increase in interest expense in the first quarter of 2012 compared tothe same quarter of 2011 reflects the higher debt levels outstanding this year as compared to the first quarter of 2011.

TAXES

Deferred income tax is a non-cash item relating to temporary differences between the accounting and tax basis of Pengrowth’sassets and liabilities and has no immediate impact on Pengrowth’s cash flows. During the period ended March 31, 2012, Pengrowthrecorded a deferred tax reduction of $2.6 million (March 31, 2011 – $11.2 million reduction). No current income taxes were paid byPengrowth in the first quarter of 2012. See Note 6 to the financial statements for additional information.

FOREIGN CURRENCY GAINS & LOSSES

Three months ended($ millions) Mar 31, 2012 Dec 31, 2011 Mar 31, 2011

Unrealized foreign exchange gain (loss) on U.S. dollar denominated debt 17.6 28.8 22.6

Unrealized foreign exchange (loss) gain on U.K. pound sterling denominated debt (0.8) 2.8 (0.3)

16.8 31.6 22.3

Unrealized gain (loss) on foreign exchange risk management contract on U.K.pound sterling denominated debt 2.2 (2.4) 1.2

Total Unrealized foreign exchange gain (loss) 19.0 29.2 23.5

Realized foreign exchange (loss) gain (0.1) (0.6) (0.1)

Pengrowth’s unrealized foreign exchange gains and losses are attributable to the translation of the foreign denominated long termdebt and are included in net income.

The gains or losses are calculated by comparing the translated Canadian dollar balance of foreign denominated long term debtfrom one period to another. The total unrealized foreign exchange gain in the first quarter of 2012 was $16.8 million, compared togains of $31.6 million and $22.3 million in the fourth and first quarters of 2011, respectively. The decrease in the unrealized foreignexchange gain this quarter compared to the fourth quarter was the result of a smaller change in the opening and closing exchangerates between the Canadian dollar and U.S. dollar. Similarly, a smaller change in the foreign exchange rates reduced the unrealizedgain when comparing the first quarter of 2012 to the same quarter of last year.

As some realized commodity prices are derived from U.S. denominated benchmarks, a weaker U.S. dollar reduces oil and gasrevenues. To mitigate this, Pengrowth elects to hold a portion of its long term debt in U.S. dollars as a natural hedge. Therefore, adecline in revenues as a result of foreign exchange fluctuations will be partially offset by a reduction in U.S. dollar interest expense.

ASSET RETIREMENT OBLIGATIONS (ARO)

The total future ARO is based on management’s estimate of costs to remediate, reclaim and abandon wells and facilities havingregard for Pengrowth’s working interest and the estimated timing of the costs to be incurred in future periods. Pengrowth hasdeveloped 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.

For the three months ended March 31, 2012, Pengrowth’s ARO liability increased by $22.3 million. The increase is mainly due to theadditional ARO liabilities resulting from the acquisition of several properties during the first quarter of 2012.

Pengrowth has estimated the net present value of its total ARO to be $683.2 million as at March 31, 2012 (December 31, 2011 –$660.9 million), based on a total escalated future liability of $1.9 billion (December 31, 2011 – $1.8 billion). These costs are expectedto be incurred over 65 years with the majority of the costs incurred between 2036 and 2077. A risk free discount rate of 2.5 percentper annum and an inflation rate of 1.5 percent per annum were used to calculate the net present value of the ARO.

ACQUISITIONS AND DISPOSITIONS

During the first quarter of 2012, Pengrowth exercised rights of first refusal in the Quirk Creek field and the Weyburn Unit,increasing its working interests in each. The purchase prices were $13.5 million and $12.3 million net of adjustments, respectively.


WORKING CAPITALThe working capital deficiency at March 31, 2012 was $211.0 million, compared to $137.3 million at December 31, 2011.

FINANCIAL RESOURCES AND LIQUIDITY

As at: Mar 31, 2012 Dec 31, 2011 Mar 31, 2011

($ millions)Term credit facilities $ 53.0 – $ 146.0

Senior unsecured notes 991.0 1,007.7 963.2

Long term debt 1,044.0 1,007.7 1,109.2

Working capital deficiency 211.0 137.3 111.4

Total debt $1,255.0 $1,145.0 $1,220.6

Twelve months trailing: Mar 31, 2012 Dec 31, 2011 Mar 31, 2011

Net income $ 79.8 $ 84.5 $ 16.2

Add:

Interest and financing charges 76.4 75.9 69.0

Deferred tax expense 30.9 22.3 150.5

Depletion, depreciation, amortization and accretion 462.7 453.5 445.8

Impairment of assets 27.4 27.4 –

Other non-cash expenses (income) (12.0) 34.8 0.1

EBITDA $ 665.2 $ 698.4 $ 681.6

Total debt to EBITDA 1.9 1.6 1.8

Total Capitalization (1) $4,562.1 $4,492.3 $4,240.6

Total debt as a percentage of total capitalization 27.5% 25.5% 28.8%

(1) Total capitalization includes total outstanding debt plus Shareholders’ Equity. Total outstanding debt includes working capital deficit (excess).

As at March 31, 2012, long term debt increased by $36.3 million from December 31, 2011 and decreased by $65.2 from March 31,2011. In November 2011, Pengrowth completed an equity offering for net proceeds of $288.1 million which were used primarily topay down amounts owing on the revolving credit facility as a result of an increased capital program in 2011. Borrowings of $53million on the revolving credit facility relating to normal operations were then incurred in the first quarter of 2012. The increase indebt resulted in a trailing 12 month Total Debt to EBITDA ratio at March 31, 2012 of 1.9x, which is within corporate targets.

Term Credit Facilities

Pengrowth maintains a $1.0 billion revolving credit facility which was drawn by $53 million in borrowings and approximately $24million in outstanding letters of credit at March 31, 2012. The credit facility includes an expansion feature of $250 million providingPengrowth with up to $1.25 billion of credit capacity from a syndicate of seven Canadian and three foreign banks. The revolvingcredit facility matures on November 29, 2015 and can be extended at Pengrowth’s discretion any time prior to maturity subject tosyndicate approval.

Pengrowth also maintains a $50 million demand operating facility with one Canadian bank which is reduced by borrowings of$28 million and approximately $1 million of outstanding letters of credit at March 31, 2012. This facility appears on the BalanceSheet as a current liability in Bank indebtedness together with the amount of outstanding cheques.

Together, these two facilities provided Pengrowth with approximately $943 million of available credit capacity at March 31, 2012,with the ability to expand the facilities by an additional $250 million.

Financial Covenants

Pengrowth’s senior unsecured notes and credit facilities are subject to a number of covenants, all of which were met at all timesduring the preceding twelve months, and at March 31, 2012. All loan agreements can be found on SEDAR (www.sedar.com) filedunder “Other” or “Material Document”.

The calculation for each financial covenant is based on specific definitions, is not in accordance with GAAP and cannot be readilyreplicated by referring to Pengrowth’s financial statements. The financial covenants are substantially similar between the creditfacilities and the senior unsecured notes.


Key financial covenants are summarized below:

1. Total senior debt must not exceed 3.0 times EBITDA for the last four fiscal quarters;

2. Total debt must not exceed 3.5 times EBITDA for the last four fiscal quarters;

3. Total senior debt (excluding working capital) must be less than 50 percent of total book capitalization; and

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

There may be instances, such as financing an acquisition, where it would be acceptable for total debt to trailing EBITDA to betemporarily offside. In the event of a significant acquisition, certain credit facility financial covenants are relaxed for two fiscalquarters after the close of the acquisition. Pengrowth may prepare pro forma financial statements for debt covenant purposes andhas additional flexibility under its debt covenants for a set period of time. This would be a strategic decision recommended bymanagement and approved by the Board of Directors with steps taken in the subsequent period to restore Pengrowth’s capitalstructure based on its capital management objectives.

Breaching a financial covenant may result in one or more of Pengrowth’s loans being in default. In certain circumstances, being indefault of one loan will, absent a cure, result in other loans also being in default. In the event that non-compliance continued,Pengrowth would have to repay, refinance or re-negotiate the terms and conditions of the debt and may have to suspend dividendsto shareholders.

If certain financial ratios reach or exceed certain levels, management may consider steps to improve these ratios. These steps mayinclude, but are not limited to, raising equity, property dispositions, reducing capital expenditures or dividends. Details of thesemeasures are included in Note 17 to the December 31, 2011, audited financial statements.

Dividend Reinvestment Plan

Pengrowth’s Dividend Reinvestment Plan (“DRIP”) entitles shareholders to reinvest cash dividends in additional shares of theCorporation. Under the DRIP, the shares are issued from treasury at a 5 percent discount to the weighted average closing price asdetermined by the plan.

During the three months ended March 31, 2012, 2.0 million shares were issued for cash proceeds of $19.5 million under the DRIPcompared to 0.7 million shares for cash proceeds of $7.9 million for the same period last year.

On January 3, 2012, Pengrowth announced that it has introduced a Premium Dividend™ program in addition to the DRIP, effectiveFebruary 2012. Under the Premium DividendTM program, 1.3 million shares have been issued for cash proceeds of $11.9 million inFebruary and March 2012.

Pengrowth does not have any off balance sheet financing arrangements.

FINANCIAL INSTRUMENTS

Pengrowth uses financial instruments to manage its exposure to commodity price fluctuations, foreign currency and interest rateexposures. Pengrowth’s policy is not to utilize financial instruments for trading or speculative purposes. Please see Note 2 to theaudited December 31, 2011 year-end financial statements for a description of the accounting policies for financial instruments andNote 11 to the unaudited March 31, 2012 financial statements for additional information regarding market risk, credit risk, liquidityrisk and fair value of Pengrowth’s financial instruments.


FUNDS FLOW FROM OPERATIONS AND DIVIDENDS

The following table provides Funds Flow from Operations, net income and dividends declared with the excess (shortfall) overdividends and Payout Ratio:

Three months ended($ millions, except per share amounts) Mar 31, 2012 Dec 31, 2011 Mar 31, 2011

Funds flow from operations 113.6 171.1 146.8

Net income (loss) 0.7 (9.0) 5.4

Dividends declared 76.1 73.5 68.6

Per share 0.21 0.21 0.21

Excess of funds flow from operations less dividends declared 37.5 97.6 78.2

Per Share 0.10 0.28 0.24

Shortfall of net income (loss) less dividends declared (75.4) (82.5) (63.2)

Per Share (0.21) (0.24) (0.19)

Payout Ratio (1) 67% 43% 47%

(1) Payout Ratio is calculated as dividends declared divided by funds flow from operations.

As a result of the depleting nature of Pengrowth’s oil and gas assets, capital expenditures are required to offset production declineswhile other capital is required to maintain facilities, acquire prospective lands and prepare future projects. Capital spending andacquisitions may be funded by the excess of Funds Flow from Operations less dividends declared, through additional debt or theissuance of equity. Pengrowth does not deduct capital expenditures when calculating Funds Flow from Operations.

Funds Flow from Operations is derived from producing and selling oil, natural gas and related products and is therefore highlydependent on commodity prices. Pengrowth enters into forward commodity contracts to mitigate price volatility and to provide ameasure of stability to monthly cash flow. Details of commodity contracts are contained in Note 11 to the unaudited financialstatements.

As part of Pengrowth’s financial management structure, a Dividend Reinvestment Plan (“DRIP”) and a Premium DividendTM

program have been implemented. The following table provides the net payout ratio when the proceeds of these plans are accountedfor to reflect Pengrowth’s net cash outlay.

Three months ended($ millions, except per share amounts) Mar 31, 2012 Dec 31, 2011 Mar 31, 2011

Proceeds from Dividend Reinvestment and Premium DividendTM Plans 31.7 18.1 9.1

Per Share 0.09 0.05 0.03

Net Payout Ratio (1) 39% 32% 41%

(1) Net Payout Ratio is calculated as dividends declared net of proceeds from Dividend Reinvestment and Premium DividendTM plans divided byfunds flow from operations.

DIVIDENDS

The board of directors regularly reviews the level of dividends. The board considers a number of factors, including expectations offuture commodity prices, capital expenditure requirements, and the availability of debt and equity capital. As a result of the volatilityin commodity prices, changes in production levels and capital expenditure requirements, there can be no certainty that Pengrowthwill be able to maintain current levels of dividends and dividends can and may fluctuate in the future. Pengrowth has no restrictionson the payment of its dividends other than maintaining its financial covenants in its borrowings.

Dividends are generally paid to shareholders on or about the 15th day of the month. Pengrowth paid $0.07 per share in each monthof January, February, and March 2012, for an aggregate cash dividend of $0.21 per share. Aggregate cash dividends for both thefourth and first quarters of 2011 were $0.21 per share.


SUMMARY OF QUARTERLY RESULTS

The following table is a summary of quarterly information for 2012, 2011 and 2010.

2012 Q1

Oil and gas sales ($ millions) 328.5

Net income (loss) ($ millions) 0.7

Net income (loss) per share ($) –

Net income (loss) per share - diluted ($) –

Funds flow from operations ($ millions) 113.6

Dividends declared ($ millions) 76.1

Dividends declared per share ($) 0.21

Daily production (boe) 75,618

Total production (Mboe) 6,881

Average realized price ($ per boe) 47.14

Operating netback ($ per boe) 21.69

2011 Q1 Q2 Q3 Q4

Oil and gas sales ($ millions) 340.9 356.7 366.9 389.2

Net income (loss) ($ millions) 5.4 88.5 (0.5) (9.0)

Net income (loss) per share ($) 0.02 0.27 – (0.03)

Net income (loss) per share - diluted ($) 0.02 0.27 – (0.03)

Funds flow from operations ($ millions) 146.8 151.7 150.4 171.1

Dividends declared ($ millions) 68.6 68.9 69.2 73.5

Dividends declared per share ($) 0.21 0.21 0.21 0.21

Daily production (boe) 73,634 70,958 74,568 76,691

Total production (Mboe) 6,627 6,457 6,860 7,056

Average realized price ($ per boe) 51.15 54.41 52.68 54.28

Operating netback ($ per boe) 27.64 28.97 27.15 29.99

2010 Q1 Q2 Q3 Q4

Oil and gas sales ($ millions) 362.7 340.8 320.3 344.9

Net income (loss) ($ millions) 139.0 18.2 144.6 (152.0)

Net income (loss) per share ($) 0.48 0.06 0.49 (0.47)

Net income (loss) per share - diluted ($) 0.48 0.06 0.48 (0.47)

Funds flow from operations ($ millions) 161.5 175.5 149.3 139.9

Dividends declared ($ millions) 61.0 61.2 65.3 45.1(1)

Dividends declared per share ($) 0.21 0.21 0.21 0.14(1)

Daily production (boe) 75,627 75,517 72,704 74,953

Total production (Mboe) 6,806 6,872 6,689 6,896

Average realized price ($ per boe) 52.79 49.17 47.39 49.34

Operating netback ($ per boe) 28.24 27.75 26.64 25.02

(1) Reflects one month less of distribution declared as a result of the corporate conversion.

In addition to natural decline, production changes over these quarters was a result of production limitations due to first quarter2011 unscheduled pipeline outage, second quarter 2011 scheduled maintenance shutdowns and restrictions due to flooding andforest fires and unscheduled maintenance in the third quarter of 2010 partly offset by the Monterey acquisition in the third quarterof 2010. Changes in commodity prices have affected oil and gas sales, which have been partially muted by risk management activityto mitigate price volatility and to provide a measure of stability to monthly cash flow. Quarterly net income (loss) has also been


affected by non-cash charges, in particular depletion, depreciation and amortization, impairment charges, unrealized gains oninvestments, accretion of ARO, unrealized mark-to-market gains and losses, unrealized foreign exchange gains and losses, andfuture taxes. Funds flow was also impacted by changes in royalty expense, operating and general and administrative costs.

BUSINESS RISKS

The amount of dividends available to shareholders and the value of Pengrowth common shares are subject to numerous riskfactors. Pengrowth’s principle source of net cash flow is from Pengrowth’s portfolio of producing oil and natural gas properties, theprincipal risk factors that are associated with the oil and gas business include, but are not limited to, the following influences:

Risks associated with Commodity Prices• 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, discount for Western Canadian light andheavy oil and natural gas, and political and economic stability.

• Production could be shut-in at specific wells or fields in low commodity prices, particularly at natural gas fields withminimal liquids content as natural gas prices continue to decline.

• Substantial and sustained reductions in commodity prices or equity markets, including Pengrowth’s share price, in somecircumstances could result in Pengrowth recording an impairment loss, as well as affecting the ability to maintain thecurrent dividends, spend capital and meet obligations.

Risks associated with Liquidity• 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 acquisitionopportunities may be impaired.

• Pengrowth is exposed to third party credit risk through its oil and gas sales, financial hedging transactions and jointventure activities. The failure of any of these counterparties to meet their contractual obligations could adversely impactPengrowth.

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

• Breaching 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 also being in default. In the event that non-compliance continued,Pengrowth would have to repay the debt, refinance the debt or negotiate new terms with the debt holders and may have tosuspend dividends to shareholders.

• Pengrowth’s indebtedness may limit the amount of dividends that we are able to pay our shareholders, and if we default onour debts, the net proceeds of any foreclosure sale would be allocated to the repayment of our lenders, note holders andother creditors and only the remainder, if any, would be available for dividend to our shareholders.

• Uncertainty in international financial markets could lead to constrained capital markets, increased cost of capital andnegative impact on economic activity and commodity prices.

Risks associated with Legislation and Regulatory Changes• 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 feescould have a material impact on Pengrowth’s financial results and the value of Pengrowth’s common shares.

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

• Regulations surrounding the fracture stimulation of wells, including increasing disclosure and restrictions, differ anddepend on the area of operation. Pengrowth may have to adjust operational practice, increase compliance and incuradditional cost as a result.

• Changes to accounting policies may result in significant adjustments to our financial results, which could negativelyimpact our business, including increasing the risk of failing a financial covenant contained within our credit facility.


Risks associated with Operations• The marketability of our production depends in part upon the availability, proximity and capacity of gathering systems,

pipelines, storage capacity and processing facilities. Operational or economic factors may result in the inability to deliverour products to market.

• Increased competition for properties could drive the cost of acquisitions up and expected returns from the propertiesdown.

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

• Availability of specialized equipment and goods and services, during periods of increased activity within the oil and gassector, may adversely impact timing of operations.

• Oil and gas operations can be negatively impacted by equipment failures and certain weather conditions, including floods,spring breakup, forest fires and other natural events, which may restrict production and/or delay drilling activities.

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

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

• 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.

• Delays in business operations could adversely affect Pengrowth’s dividends to shareholders and the market price of thecommon shares.

• During periods of increased activity within the oil and gas sector, the cost of goods and services may increase.

• During times of increased activity it may be more difficult to hire and retain staff and the cost for certain skills mayincrease.

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

• Actual production and reserves will vary from estimates. Those variations could be material and may negatively affect themarket price of the common shares and dividends to our shareholders.

• Delays or failure to secure regulatory approvals for Steam Assisted Gravity Drainage (“SAGD”) projects may result incapital being spent with reduced economics, reduced or no further reserves being booked, and reduced or no associatedfuture production and cash flow.

• The performance and results of a SAGD project such as Lindbergh are dependent on the ability of the steam to access thereservoir and efficiently move additional heavy oil that would otherwise remain trapped within the reservoir rock. Theamount and cost of steam required, the additional oil recovered, the quality of the oil produced, the ability to recycleproduced water into steam and the ability to manage costs will determine the economic viability for a SAGD project.

Risks associated with Strategy• Capital re-investment on our existing assets may not yield the expected benefits and related value creation. Drilling

opportunities may prove to be more costly or less productive than anticipated. In addition, the dedication of a largerpercentage of our cash flow to such opportunities may reduce the funds available for dividend payment to shareholders. Insuch an event, the market value of the common shares may be adversely affected.

• Pengrowth’s oil and gas reserves will be depleted over time and our level of cash flow from operations and the value of ourcommon shares could be reduced if reserves and production are not replaced. The ability to replace production dependson the amount of capital invested and success in developing existing reserves, acquiring new reserves and financing thisdevelopment and acquisition activity within the context of the capital markets.

• Incorrect assessments of value at the time of acquisitions could adversely affect the value of our common shares anddividends to our shareholders.


• Our dividends and the market price of the common shares could be adversely affected by unforeseen title defects, whichcould reduce dividends to our shareholders.

General Business Risks• Investors’ interest in the oil and gas sector may change over time which would affect the availability of capital and the

value of Pengrowth common shares.

• Inflation may result in escalating costs, which could impact dividends and the value of Pengrowth common shares.

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

• The ability of investors resident in the United States to enforce civil remedies may be negatively affected for a number ofreasons.

• As the unit of measure is smaller under IFRS, it may lead to more frequent impairments at the individual CGU level as asurplus from one asset will no longer shelter a deficit in another.

• Failure to receive regulatory approval or the expiry of the rights to explore for E&E assets could lead to the impairment ofE&E assets.

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

PROPOSED TRANSACTION

On March 23, 2012, Pengrowth announced that it has entered into an arrangement agreement (“the Arrangement Agreement”) forthe strategic business combination of Pengrowth and NAL Energy Corporation (“NAL”) by way of a Court approved plan ofarrangement (“the Proposed Arrangement”). The Proposed Arrangement is subject to various approvals, including Court approvaland the approval of Pengrowth and NAL shareholders at separate special meetings to be held on May 23, 2012. The ProposedArrangement is expected to close on May 31, 2012.

OUTLOOK

The following outlook parameters exclude the impact of the Proposed Arrangement with NAL.

Pengrowth currently anticipates a 2012 capital program, excluding acquisitions, of $625 million, focused on development of oil andliquids rich gas plays in Swan Hills, Olds/Garrington and at the Lindbergh SAGD project.

Execution of Pengrowth’s 2012 capital program is expected to generate full year average production of between 74,500 and 76,500boe per day. Exit production is expected to be 78,000 boe per day.

Forecasted operating expenses for 2012 are $384 million or $13.89 per boe.

Total G&A costs for 2012 are expected to be $2.68 per boe. Included in Pengrowth’s 2012 G&A forecast are non-cash G&A costs ofapproximately $0.49 per boe.

FUTURE CHANGES IN ACCOUNTING POLICIES

There were no significant changes during the first quarter 2012 to the future accounting policies that were described in theDecember 31, 2011 annual audited financial statements (refer to Note 3 in the 2011 annual financial statements for information onfuture accounting pronouncements).

DISCLOSURE AND INTERNAL CONTROLS

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

At the end of the interim period ended March 31, 2012, Pengrowth did not have any material weakness relating to design of itsinternal control over financial reporting. Pengrowth has not limited the scope of its design of disclosure controls and proceduresand 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 thatPengrowth acquired not more than 365 days before March 31, 2012 and summary financial information about these items has beenproportionately consolidated or consolidated in Pengrowth’s financial statements. During the interim period ended March 31, 2012,no change occurred to Pengrowth’s internal control over financial reporting that has materially affected, or is reasonably likely tomaterially affect, Pengrowth’s internal control over financial reporting.

It should be noted that while Pengrowth’s CEO and CFO believe that Pengrowth’s disclosure controls and procedures provide areasonable level of assurance that they are effective, they do not expect that Pengrowth’s disclosure controls and procedures orinternal control over financial reporting will prevent all errors and fraud. A control system, no matter how well conceived oroperated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met.


PENGROWTH ENERGY CORPORATIONBALANCE SHEETS

(Stated in thousands of dollars)(unaudited)

NoteAs at

March 31, 2012As at

December 31, 2011

ASSETS

Current Assets

Cash and cash equivalents $ – $ 36,722

Accounts receivable 162,037 183,814

Fair value of risk management contracts – 643

162,037 221,179

Other assets 85,738 84,712

Property, plant and equipment 2 4,136,862 4,074,434

Exploration and evaluation assets 3 592,981 563,751

Goodwill 700,652 700,652

TOTAL ASSETS $ 5,678,270 $ 5,644,728

LIABILITIES AND SHAREHOLDERS’ EQUITY

Current Liabilities

Bank indebtedness 4 $ 29,356 $ –

Accounts payable 248,999 273,344

Dividends payable 25,513 25,220

Fair value of risk management contracts 11 49,026 39,753

Current portion of provisions 5 20,116 20,149

373,010 358,466

Fair value of risk management contracts 11 29,947 26,487

Long term debt 4 1,044,043 1,007,686

Provisions 5 668,952 646,998

Deferred income taxes 6 255,233 257,838

2,371,185 2,297,475

Shareholders’ Equity

Shareholders’ capital 7 3,564,027 3,525,222

Contributed surplus 14,142 17,697

Deficit (271,084) (195,666)

3,307,085 3,347,253

TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY $ 5,678,270 $ 5,644,728

See accompanying notes to the financial statements.

PENGROWTH First Quarter 2012 Financial Results 29

PENGROWTH ENERGY CORPORATIONSTATEMENTS OF INCOME

(Stated in thousands of dollars, except per share amounts)(unaudited)

Three months ended March 31Note 2012 2011

REVENUES

Oil and gas sales $ 328,454 $ 340,921

Royalties, net of incentives (77,902) (60,368)

250,552 280,553

Unrealized loss on commodity risk management 11 (14,127) (68,255)

236,425 212,298

EXPENSES

Operating 95,505 91,542

Transportation 5,805 5,840

General and administrative 19,786 20,809

Depletion, depreciation and amortization 2 113,222 104,367

234,318 222,558

OPERATING INCOME (LOSS) 2,107 (10,260)

Other (income) expense items

Gain on disposition of properties (1,687) –

Unrealized foreign exchange gain 12 (19,059) (23,501)

Realized foreign exchange loss 12 99 75

Interest and financing charges 17,138 16,693

Accretion 5 4,237 3,881

Other expense (income) 3,264 (1,642)

LOSS BEFORE TAXES (1,885) (5,766)

Deferred income tax reduction 6 (2,605) (11,193)

NET INCOME AND COMPREHENSIVE INCOME $ 720 $ 5,427

NET INCOME PER SHARE 10

Basic $ – $ 0.02

Diluted $ – $ 0.02


30 PENGROWTH First Quarter 2012 Financial Results

PENGROWTH ENERGY CORPORATIONSTATEMENTS OF CASH FLOW



CASH PROVIDED BY (USED FOR):

OPERATING

Net income and comprehensive income $ 720 $ 5,427

Depletion, depreciation and accretion 117,459 108,248

Deferred income tax reduction (2,605) (11,653)

Contract liability amortization (413) (419)

Unrealized foreign exchange gain 12 (19,059) (23,501)

Unrealized loss on commodity risk management 11 14,127 68,255

Share based compensation 8 3,361 3,129

Gain on disposition of properties (1,687) –

Other items 1,697 (2,661)

Funds flow from operations 113,600 146,825

Interest and financing charges 17,138 16,693

Expenditures on remediation (5,275) (8,723)

Changes in non-cash operating working capital 9 1,029 (15,952)

126,492 138,843

FINANCING

Dividends paid (75,845) (68,221)

Bank indebtedness (repayment) 29,356 (17,333)

Long term debt 4 53,000 107,000

Interest paid (24,610) (24,250)

Proceeds from equity issues 31,740 9,068

13,641 6,264

INVESTING

Capital expenditures (153,740) (140,686)

Other property acquisitions (27,082) (1,452)

Proceeds on property dispositions 1,984 109

Purchase of injectants (833) (261)

Contributions to remediation trust funds (1,096) (1,306)

Change in non-cash investing working capital 9 3,912 (4,360)

(176,855) (147,956)

CHANGE IN CASH AND CASH EQUIVALENTS (36,722) (2,849)

CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 36,722 2,849

CASH AND CASH EQUIVALENTS AT END OF PERIOD $ – $ –



PENGROWTH ENERGY CORPORATIONSTATEMENTS OF SHAREHOLDERS’ EQUITY



SHAREHOLDERS’ CAPITAL 7

Balance, beginning of period $ 3,525,222 $ 3,171,719

Share based compensation 7,408 3,791

Issued under Dividend Reinvestment Plan 19,504 7,943

Issued for cash under Premium Dividend Plan™ 11,893 –

Balance, end of period 3,564,027 3,183,453

CONTRIBUTED SURPLUS

Balance, beginning of period 17,697 10,626

Share based compensation 8 3,510 3,129

Exercise of share based compensation awards (7,065) (2,666)

Balance, end of period 14,142 11,089

DEFICIT

Balance, beginning of period (195,666) –

Net income 720 5,427

Dividends declared (76,138) (68,602)

Balance, end of period (271,084) (63,175)

TOTAL SHAREHOLDERS’ EQUITY $ 3,307,085 $ 3,131,367



PENGROWTH ENERGY CORPORATIONNOTES TO FINANCIAL STATEMENTS

AS OF AND FOR THE PERIOD ENDED MARCH 31, 2012

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

1. CORPORATE STRUCTURE

Pengrowth Energy Corporation (the “Corporation” or “Pengrowth”) is a Canadian resource company that is engaged in theproduction, development, exploration and acquisition of oil and natural gas assets.

These interim financial statements for the three months ended March 31, 2012 are unaudited and have been prepared inaccordance with IAS 34 ‘Interim Financial Reporting’ (“IAS 34”) using accounting policies consistent with the International FinancialReporting Standards (“IFRS”) issued by the International Accounting Standards Board (“IASB”) and International FinancialReporting Interpretations Committee (“IFRIC”). The disclosures provided below are incremental to those included with the annualfinancial statements. These interim financial statements should be read in conjunction with the audited financial statements andthe notes thereto in Pengrowth’s annual report for the year ended December 31, 2011.

The financial statements were authorized for release by the Audit and Risk Committee of the Board of Directors on May 2, 2012.

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

2. PROPERTY, PLANT AND EQUIPMENT

Cost or Deemed CostOil and natural

gas assetsOther

equipment Total

Balance, January 1, 2011 $ 4,138,502 $ 64,686 $ 4,203,188

Expenditures on property, plant and equipment 534,297 5,152 539,449

Property acquisitions 10,623 – 10,623

Transfers from exploration and evaluation assets 26,313 – 26,313

Change in asset retirement obligations 215,360 – 215,360

Divestitures (7,340) – (7,340)

Balance, December 31, 2011 $ 4,917,755 $ 69,838 $ 4,987,593

Expenditures on property, plant and equipment 124,988 505 125,493

Property acquisitions 27,082 – 27,082

Change in asset retirement obligations 23,372 – 23,372

Divestitures (414) – (414)

Balance, March 31, 2012 $ 5,092,783 $ 70,343 $ 5,163,126

Accumulated depletion, amortization and impairment lossesOil and natural

gas assetsOther

equipment Total

Balance, January 1, 2011 $ 423,661 $ 41,511 $ 465,172

Depletion and amortization for the period 430,053 7,870 437,923

Impairment loss 11,121 – 11,121

Disposals (1,057) – (1,057)

Balance, December 31, 2011 $ 863,778 $ 49,381 $ 913,159

Depletion and amortization for the period 111,450 1,772 113,222

Disposals (117) – (117)

Balance, March 31, 2012 $ 975,111 $ 51,153 $ 1,026,264


Carrying AmountOil and natural

gas assetsOther

equipment Total

December 31, 2011 4,053,977 20,457 4,074,434

March 31, 2012 4,117,672 19,190 4,136,862

During the three months ended March 31, 2012, approximately $3.0 million (March 31, 2011 – $4.3 million) of directly attributablegeneral and administrative costs were capitalized to property plant and equipment.

3. EXPLORATION AND EVALUATION ASSETS

Cost or Deemed Cost

Balance, January 1, 2011 $ 511,569

Additions 78,495

Transfers to property, plant and equipment (26,313)

Balance, December 31, 2011 $ 563,751

Additions 29,230

Balance, March 31, 2012 $ 592,981

Production revenue and costs related to the Lindbergh pilot project are capitalized to exploration and evaluation assets until suchtime as the project is considered to be technically feasible and commercially viable. During the three months ended March 31, 2012,$2.0 million (March 31, 2011 – nil) of production costs, net of production revenue, were capitalized as exploration and evaluationassets.

During the three months ended March 31, 2012 approximately $0.6 million (March 31, 2011 – $0.4 million) of directly attributablegeneral and administrative costs related to exploration and evaluation activities were capitalized.

4. LONG TERM DEBT

As atMarch 31, 2012 December 31, 2011

U.S. dollar denominated senior unsecured notes:

50 million at 5.47 percent due April 2013 $ 49,834 $ 50,799

71.5 million at 4.67 percent due May 2015 71,051 72,423

400 million at 6.35 percent due July 2017 397,691 405,429

265 million at 6.98 percent due August 2018 263,325 268,452

115.5 million at 5.98 percent due May 2020 114,632 116,865

$ 896,533 $ 913,968

U.K. Pound Sterling denominated 50 million unsecured notes at 5.46 percent dueDecember 2015 79,510 78,718

Canadian dollar 15 million senior unsecured notes at 6.61 percent due August 2018 15,000 15,000

Canadian dollar revolving credit facility borrowings 53,000 –

Total long term debt $ 1,044,043 $ 1,007,686


Pengrowth’s unsecured covenant based revolving credit facility includes a committed value of $1.0 billion and a $250 millionexpansion feature providing $1.25 billion of credit capacity subject to the syndicate’s participation. The facility matures onNovember 29, 2015 and can be renewed at Pengrowth’s discretion any time prior to its maturity, subject to syndicate approval. Inthe event that the lenders do not agree to a renewal, the outstanding balance is due upon maturity.

This facility carries floating interest rates that are expected to range between 2.00 percent and 3.25 percent over bankers’acceptance rates, depending on Pengrowth’s ratio of senior debt to earnings before interest, taxes and non-cash items. As atMarch 31, 2012, the available facility was reduced by drawings of $53 million (December 31, 2011 – nil) and letters of credit in theamount of approximately $24 million (December 31, 2011 – $24 million) were outstanding.

Pengrowth also maintains a $50 million demand operating facility with one Canadian bank. As at March 31, 2012, this facility wasreduced by borrowings of $28 million (December 31, 2011 – nil) and letters of credit of approximately $1.0 million (December 31,2011 – $1.5 million). Borrowings under this facility are included in bank indebtedness on the balance sheet.

5. PROVISIONS

Provisions are comprised of Asset Retirement Obligations (ARO) and contract liabilities. The following provides a continuity of theARO and contract liabilities for the following periods:

Asset retirementobligations Contract Liabilities Total

Balance, January 1, 2011 $ 447,068 $ 7,952 $ 455,020

Provisions made during the period 7,789 – 7,789

Provisions on dispositions (1,151) – (1,151)

Provisions settled (21,939) – (21,939)

Revisions due to discount rate changes 206,554 – 206,554

Other revisions 6,932 – 6,932

Accretion (amortization) 15,618 (1,676) 13,942

Balance, December 31, 2011 $ 660,871 $ 6,276 $ 667,147

Provisions made during the period 1,658 – 1,658

Provisions on acquisitons 22,111 – 22,111

Provisions on dispositions (397) – (397)

Provisions settled (5,275) – (5,275)

Accretion (amortization) 4,237 (413) 3,824

Balance, March 31, 2012 $ 683,205 $ 5,863 $ 689,068

As of March 31, 2012

Current $ 18,500 $ 1,616 $ 20,116

Non-current 664,705 4,247 668,952

$ 683,205 $ 5,863 $ 689,068

As of December 31, 2011

Current $ 18,500 $ 1,649 $ 20,149

Non-current 642,371 4,627 646,998

$ 660,871 $ 6,276 $ 667,147


The following assumptions were used to estimate the ARO liability:

As atMarch 31, 2012 December 31, 2011

Total escalated future costs ($ millions) $ 1,905 $ 1,845

Discount rate, per annum 2.5% 2.5%

Inflation rate, per annum 1.5% 1.5%

6. INCOME TAXES

A reconciliation of tax expense calculated based on the income before taxes at the statutory tax rate to the actual provision forincome taxes is as follows:

Three months endedMarch 31, 2012 March 31, 2011

Loss before taxes $ (1,885) $ (5,766)

Combined federal and provincial tax rate 25.32% 26.86%

Expected income tax reduction (477) (1,549)

Foreign exchange gain (1) (2,135) (3,026)

Effect of change in corporate tax rate (549) (8,591)

Other including stock based compensation 556 1,973

Deferred income tax reduction $ (2,605) $ (11,193)

(1) Reflects the 50% non-taxable portion of unrealized foreign exchange gains.

7. SHAREHOLDERS’ CAPITAL

Pengrowth is authorized to issue an unlimited number of common shares and up to 10 million preferred shares. No preferredshares have been issued.

Three months endedMarch 31, 2012

Year endedDecember 31, 2011

Common SharesNumber of

Common Shares AmountNumber of

Common Shares Amount

Balance, beginning of period 360,282,162 $ 3,525,222 326,024,040 $ 3,171,719

Share based compensation (cash exercised) 54,380 343 542,083 3,540

Share based compensation (non-cash exercised) 861,313 7,065 368,994 4,546

Issued for cash under Dividend Reinvestment Plan (DRIP) 2,011,586 19,504 5,037,045 54,698

Issued for cash under Premium Dividend Plan™ 1,261,100 11,893 – –

Issued for cash on equity issue – – 28,310,000 300,086

Issue costs net of tax of $3,184 – – – (9,367)

Balance, end of period 364,470,541 $ 3,564,027 360,282,162 $ 3,525,222

8. SHARE BASED COMPENSATION PLANS

A rolling maximum of four and one half percent of the issued and outstanding common shares in aggregate may be reserved forissuance under the share based compensation plans as approved by shareholders. Currently, the number of shares issuable underthe share based compensation plans in aggregate is within the limit.


Share based compensation expense is comprised of the following:


Long Term Incentive Plan $ 3,158 $ 1,151

Previous Long Term Incentive Plan (1)

Deferred Entitlement Share Unit Plan 352 1,798

Common Share Rights Incentive Plan – 180

Total Share based compensation 3,510 3,129

Less: Amounts capitalized in the period (149) –

Share based compensation expense included in earnings $ 3,361 $ 3,129

(1) These compensation plans were used while Pengrowth was a trust. Effective January 1, 2011, no further grants were made under these plans.

LONG TERM INCENTIVE PLAN (“LTIP”)

The following provides a continuity of the LTIP:

Three months ended March 31, 2012

PSUs RSUs DSUs

Numberof share

units

Weightedaverage

price

Numberof share

units

Weightedaverage

price

Numberof share

units

Weightedaverage

price

Outstanding, beginning of period 573,274 $ 12.42 686,134 $ 12.45 50,159 $ 12.64

Granted 787,055 10.09 1,061,609 10.09 59,468 10.09

Forfeited (37,701) 11.56 (36,869) 11.55 – –

Exercised – – (274,438) 11.80 – –

Deemed DRIP (1) 11,753 12.41 14,095 12.44 1,033 12.64

Outstanding, end of period 1,334,381 $ 11.07 1,450,531 $ 10.87 110,660 $ 11.27

(1) Weighted average deemed DRIP price is based on the average of the original grant prices.

Year ended December 31, 2011

PSUs RSUs DSUs

Numberof share

units

Weightedaverage

price

Numberof share

units

Weightedaverage

price

Numberof share

units

Weightedaverage

price

Outstanding, beginning of year – $ – – $ – – $ –

Granted 637,000 12.44 882,267 12.49 47,468 12.64

Forfeited (94,249) 12.57 (117,527) 12.58 – –

Exercised – – (119,487) 12.64 – –

Deemed DRIP (1) 30,523 12.56 40,881 12.58 2,691 12.64

Outstanding, end of year 573,274 $ 12.42 686,134 $ 12.45 50,159 $ 12.64

(1) Weighted average deemed DRIP price is based on the average of the original grant prices.


PREVIOUS LONG TERM INCENTIVE PLAN

(a) Deferred Entitlement Share Units (“DESU”) Plan

The following provides a continuity of the DESUs:



DESUsNumber of

DESUsWeighted

average priceNumber

of DESUsWeighted

average price

Outstanding, beginning of period 2,024,142 $ 9.78 2,948,588 $ 10.95

Forfeited (55,062) 10.20 (363,889) 9.34

Exercised (586,875) 8.16 (249,504) 11.14

Vested, no shares issued (1) (395,252) 6.63 (472,308) 16.81

Deemed DRIP (2) 35,680 10.27 161,255 9.99

Outstanding, end of period 1,022,633 $11.93 2,024,142 $ 9.78

Comprised of:

Performance related DESUs 501,304 $11.22 1,307,474 $ 8.44

Non-Performance related DESUs 521,329 12.61 716,668 12.21

Outstanding, end of period 1,022,633 $11.93 2,024,142 $ 9.78

(1) 2009 DEU grant vested in March 2012 with a performance multiplier of fifty percent.(2) Weighted average deemed DRIP price is based on the average of the original grant prices.

(b) Common Share Rights Incentive Plan

The following provides a continuity of the Common Share Rights:



Numberoutstanding

Weightedaverage price

Numberoutstanding

Weightedaverage price

Outstanding, beginning of period 2,217,274 $12.96 3,583,766 $12.70

Expired (487,863) 17.78 (319,174) 19.40

Forfeited (21,051) 13.02 (505,235) 14.27

Exercised (54,380) 6.31 (542,083) 6.53

Outstanding, end of period 1,653,980 $11.77 2,217,274 $12.96

Comprised of:

Share Unit Options 878,614 $ 7.05 932,994 $ 6.98

Share Unit Rights 775,366 17.11 1,284,280 17.30

Outstanding, end of period 1,653,980 $11.77 2,217,274 $12.96

9. OTHER CASH FLOW DISCLOSURES

CHANGE IN NON-CASH OPERATING WORKING CAPITAL

Three months endedCash provided by (used for): March 31, 2012 March 31, 2011

Accounts receivable $ 18,594 $ 10,491

Accounts payable (17,565) (26,443)

$ 1,029 $ (15,952)


CHANGE IN NON-CASH INVESTING WORKING CAPITALThree months ended

Cash provided by (used for): March 31, 2012 March 31, 2011

Accounts receivable $ 3,183 $ –

Accounts payable, including capital accruals 729 (4,360)

$ 3,912 $ (4,360)

10. AMOUNTS PER SHARE

The following reconciles the weighted average number of shares used in the basic and diluted net income per share calculations:


Weighted average number of shares – basic 361,966,365 326,372,900

Dilutive effect of share based compensation plans 1,494,445 2,159,484

Weighted average number of shares – diluted 363,460,810 328,532,384

For the three months ended March 31, 2012, 0.9 million shares (March 31, 2011 – 1.7 million shares) that are issuable on exercise ofthe share based compensation plans were excluded from the diluted net income per share calculation as their effect is anti-dilutive.

11. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

Commodity Price ContractsAs at March 31, 2012, Pengrowth had fixed the price applicable to future production as follows:

Crude Oil:

Reference Point Volume (bbl/d) Term Price per bbl

Financial:

WTI (1) 17,000 April 1, 2012 - Dec 31, 2012 $ 93.23 Cdn

WTI (1) 6,000 Jan 1, 2013 - Dec 31, 2013 98.45 Cdn

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

Natural Gas:

Reference Point Volume (MMbtu/d) Term Price per MMbtu

Financial:

AECO 14,217 April 1, 2012 - Dec 31, 2012 $ 4.45 Cdn

Commodity Price Sensitivity

Each Cdn $1 per barrel change in future oil prices would result in approximately Cdn $6.9 million pre-tax change in the unrealizedgain (loss) on commodity risk management contracts as at March 31, 2012 (March 31, 2011 – $8.1 million). Similarly, each Cdn$0.25 per MMbtu change in future natural gas prices would result in approximately Cdn $1.0 million pre-tax change in theunrealized gain (loss) on commodity risk management contracts (March 31, 2011 – $3.9 million).

As of close March 31, 2012, the AECO spot price gas price was approximately $1.62 per MMbtu (March 31, 2011 – $3.76 per MMbtu),the WTI prompt month price was U.S. $103.02 per barrel (March 31, 2011 – U.S. $106.72 per barrel).

Power Price ContractsAs at March 31, 2012, Pengrowth had fixed the price applicable to future power costs as follows:

Power:

Reference Point Volume (MW) Term Price per MWh

Financial:

AESO 15 April 1, 2012 - Dec 31, 2012 $72.83 Cdn

AESO 5 Jan 1, 2013 - Dec 31, 2013 $74.50 Cdn


As of close March 31, 2012, the Alberta average power pool spot price was approximately $22.26/MWh (March 31, 2011 –$26.95/MWh). The average Alberta power pool price was $60.12/MWh for the three months ended March 31, 2012 (March 31, 2011 –$82.05/MWh).

Power Price Sensitivity

Each Cdn $1 per MWh change in future power prices would result in approximately Cdn $0.1 million pre-tax change in theunrealized gain (loss) on power risk management contracts as at March 31, 2012 (March 31, 2011 – $0.2 million).

Foreign Exchange Contract

Pengrowth entered into foreign exchange risk management contracts in conjunction with issuing U.K. Pounds Sterling 50 millionten 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.

Foreign Exchange Rate Sensitivity

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

Cdn $0.01 Exchange RateChange

Foreign Exchange Sensitivity as at March 31, 2012 Cdn - U.S. Cdn - U.K.

Unrealized foreign exchange gain or loss on foreign denominated debt $ 9,020 $ 500

Unrealized foreign exchange risk management gain or loss – 594

Cdn $0.01 Exchange RateChange

Foreign Exchange Sensitivity as at March 31, 2011 Cdn - U.S. Cdn - U.K.

Unrealized foreign exchange gain or loss on foreign denominated debt $ 9,020 $ 500

Unrealized foreign exchange risk management gain or loss – 577

Interest Rate Risk

Pengrowth is exposed to interest rate risk on the Canadian dollar revolving credit facility as the interest is based on floating interestrates.

Interest Rate Sensitivity

As at March 31, 2012, Pengrowth has approximately $1.0 billion of long term debt outstanding (December 31, 2011 – $1.0 billion) ofwhich $53 million is based on floating interest rates (December 31, 2011 – nil). A one percent increase in interest rates wouldincrease pre-tax interest expense by approximately $0.1 million for the three months ended March 31, 2012 (three months endedMarch 31, 2011 – $0.4 million).


Summary of Gains and Losses on Risk Management Contracts

The following tables provide details of the fair value of risk management contracts and the unrealized and realized gains and losseson risk management recorded in the Statement of Income:

As at and for the period ended March 31, 2012

Commodity riskmanagement

contracts (1)

Power riskmanagement

contracts (2)

Foreign exchangerisk management

contracts (3) Total

Current portion of risk management liabilities $ (47,249) $ (630) $ (1,147) $ (49,026)

Non-current portion of risk management liabilities (8,914) (291) (20,742) (29,947)

Risk management liabilities, end of period (56,163) (921) (21,889) (78,973)

Less: Risk management (liabilities) assets at beginning of period (42,036) 536 (24,097) (65,597)

Unrealized (loss) gain on risk management contracts for theperiod (14,127) (1,457) 2,208 (13,376)

Realized loss on risk management contracts for the period (12,710) (416) (611) (13,737)

Total unrealized and realized (loss) gain on risk managementcontracts for the period $ (26,837) $ (1,873) $ 1,597 $ (27,113)

As at and for the period ended March 31, 2011

Commodity riskmanagement

contracts (1)

Power riskmanagement

contracts (2)

Foreign exchangerisk management

contracts (3) Total

Current portion of risk management assets $ 1,427 $ 3,761 $ – $ 5,188

Current portion of risk management liabilities (47,845) – (1,257) (49,102)

Non-current portion of risk management liabilities (23,922) – (23,505) (47,427)

Risk management (liabilities) assets, end of period (70,340) 3,761 (24,762) (91,341)

Less: Risk management (liabilities) assets at beginning of period (2,085) 870 (25,929) (27,144)

Unrealized (loss) gain on risk management contracts for theperiod (68,255) 2,891 1,167 (64,197)

Realized gain (loss) on risk management contracts for the period 3,122 1,928 (601) 4,449

Total unrealized and realized (loss) gain on risk managementcontracts for the period $ (65,133) $ 4,819 $ 566 $ (59,748)

(1) Unrealized gains and losses are presented as a separate caption in revenue. Realized gains and losses are included in oil and gas sales.(2) Unrealized gains and losses are included in other expenses (income). Realized gains and losses are included in operating expenses.(3) Unrealized gains and losses are presented as a separate caption in expenses. Realized gains and losses are included in interest expense.

12. FOREIGN EXCHANGE (GAIN) LOSS


Unrealized foreign exchange gain on U.S. dollar denominated debt $ (17,641) $ (22,550)

Unrealized foreign exchange loss on U.K. pound sterling denominated debt 790 216

$ (16,851) $ (22,334)

Unrealized gain on foreign exchange risk management contracts (2,208) (1,167)

Unrealized foreign exchange gain $ (19,059) $ (23,501)

Realized foreign exchange loss $ 99 $ 75

13. PROPOSED TRANSACTION

On March 23, 2012, Pengrowth announced that it has entered into an arrangement agreement (“the Arrangement Agreement”) forthe strategic business combination of Pengrowth and NAL Energy Corporation (“NAL”) by way of a Court approved plan ofarrangement (“the Proposed Arrangement”). The Proposed Arrangement is subject to various approvals, including Court approvaland the approval of Pengrowth and NAL shareholders at separate special meetings to be held on May 23, 2012. The ProposedArrangement is expected to close on May 31, 2012.


Pengrowth Energy CorporationCorporate ProfileDIRECTORS

John B. ZaozirnyChairman; Vice ChairmanCanaccord Genuity Corp.

Thomas A. Cumming,Business Consultant

Derek EvansPresident and CEOPengrowth Energy Corporation

Wayne K. FooPresident & CEO,Parax Resources Inc.

James D. McFarlandPresident and CEO,Valeura Energy Inc.

Michael S. ParrettBusiness Consultant

A. Terence PooleBusiness Consultant

D. Michael G. StewartCorporate Director

OFFICERS

Derek W. EvansPresident and Chief Executive Officer

David AllenVice President, Exploration

Gillian BasfordVice President, Human Resources

Douglas C. BowlesVice President and Controller

James E.A. CausgroveSr. Vice President, Operations andEngineering

Steve J. De MaioVice President, In-Situ Development& Operations

David Dean EvansTreasurer

Andrew D. GrasbySr. Vice President, General Counsel andCorporate Secretary

Frederic D. KerrVice President, Investor Relations

Marlon McDougallChief Operating Officer

Robert W. RosineExecutive Vice President,Business Development

Christopher G. WebsterChief Financial Officer

TRUSTEE

Olympia Trust Company

BANKERS

Bank Syndicate Agent:Royal Bank of Canada

AUDITORS

KPMG LLP

ENGINEERING

CONSULTANTS

GLJ Petroleum Consultants Ltd.

ABBREVIATIONS

bbl . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . barrelBcf . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .billion cubic feetboe* . . . . . . . . . . . . . . . . . . . . . . . . . . . . .barrels of oil equivalentGJ . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .gigajouleMbbls . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .thousand barrelsMMbbls . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .million barrelsMboe* . . . . . . . . . . . . . . . . . . .thousand barrels of oil equivalentMMboe* . . . . . . . . . . . . . . . . . . . .million barrels of oil equivalent

MMBtu . . . . . . . . . . . . . . . . . . . . . . .million British thermal unitsMcf . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .thousand cubic feetMMcf . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .million cubic feetTcf . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .trillion cubic feetMW . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .mega watt* 6 mcf of gas = 1 barrel of oil equivalent

Pengrowth Energy Corporation

Head Office: 2100, 222 Third Avenue SW, Calgary, Alberta, Canada T2P 0B4

Phone: 403.233.0224 | Toll free: 800.223.4122Fax: 403.265.6251www.pengrowth.com

For investor relations enquiries, please contact:

Investor Relations

Phone: 403.233.0224 | Toll free: 888.744.1111Email: [email protected]

Stock Exchange Listings

Toronto Stock Exchange: PGFNew York Stock Exchange: PGH

Documents

Pengrowth Q1 2012