Pengrowth Energy (PGH) 40-F 2013 FY Annual report (Canada)

EXHIBIT 99.2

MANAGEMENT’S DISCUSSION & ANALYSIS

The following Management’s Discussion and Analysis ("MD&A") of financial results should be read in conjunction with the audited Financial Statements for the year ended December 31, 2013 of Pengrowth Energy Corporation ("Pengrowth" or the "Corporation"). This MD&A is based on information available to February 28, 2014.

Pengrowth’s fourth quarter and annual results for 2013 are contained within this MD&A.

BUSINESS OF THE CORPORATION

Pengrowth is a Canadian resource company that is engaged in the production, development, exploration and acquisition of oil and natural gas assets. The financial and operating results from property dispositions are included in Pengrowth’s results up to the time of closing for each disposition. Prior year figures include seven months of results from NAL Energy Corporation ("NAL") which was acquired by Pengrowth on May 31, 2012 ("NAL Acquisition") and was amalgamated with Pengrowth on January 1, 2013.

FREQUENTLY RECURRING TERMS

Pengrowth uses the following frequently recurring industry terms in this MD&A: "bbls" refers to barrels, "bbl/d" refers to barrels per day, "Mbbls" refers to thousands of barrels, "boe" refers to barrels of oil equivalent, "boe/d" refers to barrels of oil equivalent per day, "Mboe"refers to thousand boe, "MMboe" refers to million boe, "Mcf" refers to thousand cubic feet, "Mcf/d" refers to thousand cubic feet per day, "MMcf" refers to million cubic feet, "Bcf" refers to billion cubic feet, "MMBtu" refers to million British thermal units, "MMBtu/d" refers to million British thermal units per day, "MW" refers to megawatt and "MWh" refers to megawatt hour, "WTI" refers to West Texas Intermediate crude oil price, "WCS" refers to Western Canadian Select crude oil price, "AECO" refers to Alberta natural gas price point, "AESO" refers to Alberta power price point, "NYMEX" refers to New York Mercantile Exchange, "NGI Chicago" refers to Chicago natural gas price point. Bitumen is reported as heavy oil throughout this document. Disclosure provided herein in respect of a boe may be misleading, particularly if used in isolation. A boe conversion ratio of six Mcf of natural gas to one barrel of crude oil equivalent is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

ADVISORY REGARDING FORWARD-LOOKING STATEMENTS

This MD&A contains forward-looking statements within the meaning of securities laws, including the "safe harbour" provisions of Canadian securities legislation and the United States Private Securities Litigation Reform Act of 1995. Forward-looking information is often, but not always, identified by the use of words such as "anticipate", "believe", "expect", "plan", "intend", "forecast", "target", "project", "guidance", "may", "will", "should", "could", "estimate", "predict" or similar words suggesting future outcomes or language suggesting an outlook. Forward-looking statements in this MD&A include, but are not limited to, statements with respect to: reserves, production, the proportion of production of each product type, production additions from Pengrowth's development program, royalty expenses, operating expenses, tax horizon, deferred income taxes, goodwill, Asset Retirement Obligations ("ARO"), taxability of dividends, remediation, reclamation and abandonment expenses, capital expenditures, development activities, General and Administrative Expenses ("G&A"), and proceeds from the disposal of properties. Statements relating to "reserves" are forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions that the reserves described exist in the quantities predicted or estimated and can profitably be produced in the future.

Forward-looking statements and information are based on Pengrowth's current beliefs as well as assumptions made by, and information currently available to, Pengrowth concerning general economic and financial market conditions, anticipated financial performance, business prospects, strategies, regulatory developments, including in respect of taxation, royalty rates and environmental protection, future capital expenditures and the timing thereof, future oil and natural gas commodity prices and differentials between light, medium and heavy oil prices, future oil and natural gas production levels, future exchange rates and interest rates, the proceeds of anticipated divestitures, the amount of future cash dividends paid by Pengrowth, the cost of expanding 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 including transportation availability, the impact of increasing competition, our ability to obtain financing on acceptable terms, our ability to add production and reserves through our development, exploitation and exploration activities, our ability to complete divestments to generate cash to repay debt and fund capital projects. Although management considers these assumptions to be reasonable based on information currently available to it, they may prove to be incorrect.

PENGROWTH 2013 Management's Discussion and Analysis 1

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By their very nature, forward-looking statements involve inherent risks and uncertainties, both general and specific, and risks that predictions, forecasts, projections and other forward-looking statements will not be achieved. We caution readers not to place undue reliance on these statements as a number of important factors could cause the actual results to differ materially from the beliefs, plans, objectives, expectations and anticipations, estimates and intentions expressed in such forward-looking statements. These factors include, but are not limited to: the volatility of oil and gas prices; Canadian light and heavy oil differentials; production and development costs and capital expenditures; the imprecision of reserve estimates and estimates of recoverable quantities of oil, natural gas and liquids; Pengrowth's ability to replace and expand oil and gas reserves, ability to produce those reserves; production may be impacted by unforeseen events such as equipment and transportation failures and weather related issues; environmental claims and liabilities; incorrect assessments of value when making acquisitions; increases in debt service charges; the loss of key personnel; the marketability of production; defaults by third party operators; unforeseen title defects; fluctuations in foreign currency and exchange rates; inadequate insurance coverage; counterparty risk; compliance with environmental laws and regulations; changes in tax and royalty laws; Pengrowth's ability to access external sources of debt and equity capital; the implementation of new International Financial Reporting Standards ("IFRS"); and the implementation of greenhouse gas emissions legislation. Further information regarding these factors may be found under the heading "Business Risks" herein and under "Risk Factors" in Pengrowth's most recent Annual Information Form ("AIF"), and in Pengrowth’s most recent audited Financial Statements, management information circular, quarterly reports, material change reports and news releases. Copies of Pengrowth’s Canadian public filings are available on SEDAR at www.sedar.com. Pengrowth’s U.S. public filings, including the most recent annual report form 40-F as supplemented by its filings on form 6-K, are available at www.sec.gov.

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

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

CRITICAL ACCOUNTING ESTIMATES

The audited Financial Statements are prepared in accordance with IFRS. Management is required to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the audited Financial Statements and revenues and expenses for the period ended. Certain of these estimates may change from period to period resulting in a material impact on Pengrowth’s results of operations, financial position, and change in financial position.

Estimating oil and gas reserves

Pengrowth engages a qualified, independent oil and gas reserves evaluator to perform an estimation of the Corporation’s oil and gas reserves at least annually. Reserves form the basis for the calculation of depletion charges and assessment of impairment of oil 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 estimated to be commercially recoverable from known accumulations, from a given date forward, based on drilling, geological, geophysical and engineering data, the use of established technology and specified economic conditions. It is equally likely that the actual remaining quantities recovered will be greater than or less than the sum of the estimated proved plus probable reserves. The estimates are made using all available geological and reservoir data as well as historical production data. Estimates are reviewed and revised as appropriate. Revisions occur as a result of changes in prices, costs, fiscal regimes and reservoir performance or a change 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 judgment. The asset composition of a CGU can directly impact the recoverability of the assets included therein. The recoverability of development and production asset carrying values are assessed at the CGU level. In assessing the recoverability of oil and gas properties,

PENGROWTH 2013 Management's Discussion and Analysis 2

each CGU’s carrying value is compared to its recoverable 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. These obligations are determined based on the expected present value of expenses required in the process of plugging and abandoning wells, dismantling of wellheads, production and transportation facilities and restoration of producing areas in accordance with relevant legislation, discounted from the date when expenses are expected to be incurred. Most of the abandonment of Pengrowth's wells is estimated to take place far in the future. Therefore, changes in estimated timing of future expenses, estimated logistics of performing abandonment work, the inflation assumption, and the discount rate used to present value future expenses could have a significant effect on the carrying amount of the decommissioning provision. During 2013, Pengrowth’s ARO risk free discount rate changed from 2.5 percent to 3.25 percent due to an increase in the 30 year Canadian Government long term bond rate which drives Pengrowth’s estimate of the ARO discount rate.

Impairment testing

CGUs that have associated goodwill are tested for impairment at least annually and CGUs with or without associated goodwill are tested when there is an indication of impairment. Impairment testing is based primarily on estimates of proved plus probable reserves, production rates, oil and natural gas prices, future costs, discount rates and other relevant assumptions including undeveloped land, contingent resources and infrastructure. The impairment assessment of goodwill is based on the estimated recoverable amount of the related CGUs. By their nature, these estimates are subject to measurement uncertainty and may impact the financial statements of future periods.

Valuation of trade, other receivables and prepayments to suppliers

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

NAL Acquisition

In connection with the NAL Acquisition completed on May 31, 2012, fair values assigned to the various assets and liabilities of NAL were based on internal and third party estimates.

COMPARATIVE FIGURES

As of January 1, 2013, certain technical support costs, previously included in operating expenses, are included in G&A expenses. Comparative figures for G&A and operating expenses including the netback calculations have been adjusted accordingly with no impact on net income (loss). Management believes that these presentation changes better reflect Pengrowth’s operating results. As required under IFRS, changes in the accounting for the NAL Acquisition completed on May 31, 2012 , that arose in the fourth quarter of 2012 were adjusted retrospectively to the second quarter of 2012. Net income and basic and diluted earnings per share comparative figures for the second quarter of 2012 have been adjusted accordingly.

ADDITIONAL GAAP MEASURE

Funds Flow from Operations

Pengrowth uses funds flow from operations, a Generally Accepted Accounting Principles ("GAAP") measure that is not defined under IFRS. Management believes that in addition to cash provided by operations, funds flow from operations, as reported in the Statements of Cash Flow is a useful supplemental measure as it provides an indication of the funds generated by Pengrowth’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 fund dividends and capital investments.

The current level of capital expenditures funded through retained cash flow, as compared to debt or equity, can be determined when it is compared to the difference in funds flow from operations and dividends paid as shown on the Statements of Cash Flow.

NON-GAAP FINANCIAL MEASURES

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

Management monitors Pengrowth’s capital structure using non-GAAP financial metrics. The two metrics are total debt to the trailing twelve months Earnings Before Interest, Taxes, Depletion, Depreciation, Amortization, Accretion, and other non-cash items ("Adjusted EBITDA") and total debt to total capitalization. Total debt is the sum of working capital and long term debt including convertible debentures as shown on the Balance Sheets, and total capitalization is the sum of total debt and shareholders’ equity.

Payout ratio and net payout ratio are terms used to evaluate financial flexibility and the capacity to fund dividends. Payout ratio is defined on a percentage basis as dividends declared divided by funds flow from operations. Net payout ratio is calculated as dividends declared net of proceeds from the Dividend Reinvestment Plan ("DRIP") divided by funds flow from operations. Management believes that, in addition to net income (loss), adjusted net income (loss) is a useful supplemental measure as it reflects the underlying performance of Pengrowth’s business activities by excluding the after tax effect of non-cash commodity and power mark to market gains and losses, non-cash mark to market gains and losses on investments, unrealized foreign exchange gains and losses and gains on acquisitions that may significantly impact net income (loss) from period to period. Management believes that segregating G&A expenses into cash and non-cash expenses is useful to the reader, as non-cash expenses only affect net income (loss) but not funds flow from operations.

Pengrowth has an active risk management program which primarily uses forward price swaps to manage the exposure to commodity and power price fluctuations and provide a measure of stability to cash flow in order to maintain its dividend and ensure all capital expenditures are funded. Although commodity risk management gains and losses are presented separately on the Statements of Income (Loss), oil and gas sales are presented throughout this MD&A including realized commodity risk management gains and losses. Management believes that this is a useful supplemental measure that enables readers to analyze product sales in conjunction with commodity risk management efforts pertaining to them.

OPERATIONAL MEASURES

The reserves and production in this MD&A refer to company-interest reserves or production that is Pengrowth’s working interest share of production or reserves prior to the deduction of Crown and other royalties plus any Pengrowth-owned royalty interest in production or reserves at the wellhead, in accordance with Canadian industry practice. 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 one boe. Barrels of oil equivalent may be misleading, particularly if used in isolation; a conversion ratio of six Mcf of natural gas to one boe is based on an energy equivalency conversion and does not represent a value equivalency at the wellhead.

Pengrowth’s ability to grow both reserves and production can be measured with the following metrics: reserves per share, reserves per debt adjusted share, production per share and production per debt adjusted share. Reserves per share and reserves per debt adjusted share are measured using year end proved plus probable reserves and the number of common shares outstanding at year end. The reserves per debt adjusted share is debt-adjusted by assuming additional shares are issued at the year end share prices to replace year end long term debt outstanding.

Production per share and production per debt adjusted share are measured in respect of the average production for the year and the weighted average number of common shares outstanding during the year. The production per debt adjusted share is debt-adjusted by assuming additional shares are issued at year end share prices to replace year end long term debt outstanding.

Recycle ratio is a measure of value creation for each dollar spent. This measure is calculated as operating netback per boe divided by Finding and Development ("F&D") cost per boe and can also be calculated using Finding, Development & Acquisition ("FD&A") cost per boe. Recycle ratio can be calculated including or excluding Future Development Costs ("FDC").

CURRENCY

All amounts are stated in Canadian dollars unless otherwise specified.

PENGROWTH 2013 Management's Discussion and Analysis 3

2013 AND 2014 GUIDANCE AND 2013 FINANCIAL HIGHLIGHTS

Pengrowth has taken several measures to safeguard its dividend, maintain its financial and balance sheet strength and provide additional flexibility to develop the Lindbergh thermal project. These measures include selling non-core properties, expanding commodity and power risk management activities and managing interest costs through term debt markets.

The following table provides a summary of the 2013 Guidance and actual results for the twelve months ended December 31, 2013. Commencing January 1, 2013, financial and operating results from the Lindbergh thermal pilot are reflected in Pengrowth’s operating results. Prior to 2013, Lindbergh thermal pilot results were capitalized. The financial and operating results from property dispositions are included in Pengrowth’s results up to the time of closing for each disposition.

	2013 Actual	2013 Guidance	2013 Variance
Production (boe/d)	84,527	82,000 - 84,000	527
Capital expenditures ($ millions)	695.8	770	(74.2	)
Royalty expense (% of sales)	17.3	17.0	0.3
Operating expense ($/boe)	15.64	15.70	(0.06	)
G&A expense (cash & non-cash) ($/boe)	3.33	3.50	(0.17	)
EBITDA ($ millions) (1)	625.4	650.0	(24.6	)

⁽¹⁾ Guidance EBITDA calculated as funds flow from operations plus interest and financing charges less expenditures on remediation.

2013 production exceeded Guidance largely due to better than expected performance and timing of new Cardium development wells in addition to better performance from operated base production. This was offset by lower than expected volumes from Sable Island due to a longer than anticipated outage at the Venture and South Venture platforms, and by lower growth volumes in areas where capital spending was reduced. Fourth quarter of 2013 average production of 77,371 boe/d was at the high end of the fourth quarter production Guidance of 75,000 to 77,000 boe/d.

2013 capital expenditures amounted to $695.8 million, including $306.4 million invested at Lindbergh. Spending was below the $770 million Guidance, as discretionary spending on non-thermal projects was reduced to $389.4 million.

2013 royalty expense as a percentage of sales was in line with 2013 Guidance.

2013 operating expense was in line with 2013 Guidance.

2013 G&A expense of $3.33/boe was lower than Guidance mainly due to lower staff costs in the latter part of 2013 as well as strong production results.

2013 EBITDA was approximately $25 million lower than Guidance primarily due to a $21 million impact from higher crude differentials in the fourth quarter than forecast.

The following table provides Pengrowth's 2014 Guidance:

	2014 Guidance
Production (boe/d)	71,000 - 73,000
Capital expenditures ($ millions)	700 - 730
Royalty expense (% of sales)	16 - 18
Operating expense ($/boe) (1)	15.20 - 15.80
Cash G&A expense ($/boe) (1)	2.70 - 2.90

⁽¹⁾ Per boe estimates based on high and low ends of production Guidance.

PENGROWTH 2013 Management's Discussion and Analysis 4

FINANCIAL HIGHLIGHTS

	Three months ended						Twelve months ended
($ millions except per boe amounts)	Dec 31, 2013		Sept 30, 2013		Dec 31, 2012		Dec 31, 2013		Dec 31, 2012
Production (boe/d)	77,371		83,275		94,039		84,527		85,748
Capital expenditures	239.7		176.2		93.9		695.8		467.4
Funds flow from operations	105.9		161.5		189.7		560.9		538.8
Operating netback ($/boe)(1) (2)	20.82		27.10		27.87		24.35		23.67
Adjusted net income (loss)	(37.3	)	(108.2	)	24.1		(183.8	)	(89.7	)
Net income (loss)	(91.1	)	(107.3	)	(1.0	)	(316.9	)	12.7

⁽¹⁾  Includes realized commodity risk management gains and losses.

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

Funds Flow from Operations

($ millions)	Q3/13 vs. Q4/13			% Change		Q4/12 vs. Q4/13			% Change		2012 vs. 2013			% Change
Funds flow from operations for comparative period	Q3/13	161.5				Q4/12	189.7				2012	538.8
Change due to:
Volume		(45.5	)	(28	)		(78.2	)	(41	)		(3.1	)	(1	)
Price including differentials		(47.3	)	(29	)		10.0		5			139.3		26
Realized commodity risk management gains (losses)		9.7		6			(33.3	)	(18	)		(77.1	)	(14	)
Other income including sulphur		(3.1	)	(2	)		(2.1	)	(1	)		(1.0	)	—
Royalty expense		9.8		6			6.7		4			2.4		—
Expenses:
Operating		16.4		10			5.3		3			(47.4	)	(9	)
Cash G&A		(1.7	)	(1	)		3.4		2			2.3		—
Interest & financing		2.4		2			4.4		2			(7.7	)	(1	)
Other expenses including transportation and NAL acquisition costs		3.7		2			—		—			14.4		3
Net change		(55.6	)	(34	)		(83.8	)	(44	)		22.1		4
Funds flow from operations	Q4/13	105.9				Q4/13	105.9				2013	560.9

Funds flow from operations decreased 34 percent in the fourth quarter of 2013 compared to the third quarter of 2013 due to the approximately $40 million impact from the widening of light and heavy oil differentials experienced in November and December of 2013. A decrease in volumes resulting from the 2013 dispositions was another prominent factor behind the fourth quarter of 2013 decrease. The negative impact of decreases in prices and volumes, however, was partly offset by lower operating costs mainly resulting from lower power costs in the fourth quarter of 2013 and the absence of expenses from sold properties.

The 44 percent decrease in funds flow from operations, when comparing the fourth quarter of 2013 to the same period last year, was largely due to an 18 percent decrease in production volumes as a result of the 2013 dispositions. The fourth quarter of 2013 funds flow from operations was approximately $39 million lower than the same period in 2012 due to the widening of light and heavy oil differentials.

2013 funds flow from operations increased 4 percent compared to 2012, mostly as a result of a 31 percent increase in realized natural gas prices partially offset by higher realized losses on commodity risk management. This positive impact was also partly negated by higher operating costs, the most significant of which was power costs. 2013 funds flow from operations was approximately $14 million lower due to widening of heavy oil differentials compared to 2012.

Net Income (Loss)

Pengrowth recorded a net loss of $91.1 million in the fourth quarter of 2013 compared to a $107.3 million net loss in the third quarter of 2013. The third quarter of 2013 included approximately $115 million (after tax) loss from the disposal of properties. The fourth quarter of 2013 was negatively affected, compared to the third quarter, by a reduction in funds flow from operations driven by the lower volumes and lower average realized price after realized commodity risk management. When comparing the fourth quarter of 2013 to the same period last year, the net loss increased $90.1 million mainly as a result of lower funds flow from operations.

PENGROWTH 2013 Management's Discussion and Analysis 5

For the full year 2013, Pengrowth recorded a net loss of $316.9 million, compared to net income of $12.7 million in 2012. The change was primarily due to various non-cash items including approximately $138 million (after tax) of losses on dispositions of properties, higher unrealized foreign exchange and commodity risk management losses, and the absence of a one time $73.5 million gain on the NAL Acquisition recorded in 2012.

Adjusted Net Income (Loss)

Pengrowth reports adjusted net income (loss) to remove the effect of unrealized gains and losses and the impact of the one time acquisition gain as noted below in the adjusted net income (loss) table. One time after-tax non-cash losses on dispositions of properties of approximately $138 million recorded in 2013 are however included in the adjusted net loss. The following table provides a reconciliation of net income (loss) to adjusted net income (loss):

	Three months ended						Twelve months ended
($ millions)	Dec 31, 2013		Sept 30, 2013		Dec 31, 2012		Dec 31, 2013		Dec 31, 2012
Net income (loss)	(91.1	)	(107.3	)	(1.0	)	(316.9	)	12.7
Exclude non-cash items in net income (loss):
Unrealized gain (loss) on commodity risk management	(39.1	)	(17.9	)	(0.5	)	(87.0	)	30.6
Unrealized foreign exchange gain (loss)(1)	(28.2	)	16.4		(13.3	)	(63.0	)	21.9
Unrealized loss on investments	—		—		(15.0	)	(15.0	)	(15.0	)
Gain on acquisition	—		—		—		—		73.5
Tax effect on non-cash items above	13.5		2.4		3.7		31.9		(8.6	)
Total excluded	(53.8	)	0.9		(25.1	)	(133.1	)	102.4
Adjusted net income (loss)	(37.3	)	(108.2	)	24.1		(183.8	)	(89.7	)

⁽¹⁾  Net of associated foreign exchange risk management contracts.

The following table represents a continuity of adjusted net income (loss):
($ millions)	Q3/13 vs. Q4/13			Q4/12 vs. Q4/13			2012 vs. 2013
Adjusted net income (loss) for comparative period	Q3/13	(108.2	)	Q4/12	24.1		2012	(89.7	)
Funds flow from operations increase (decrease)		(55.6	)		(83.8	)		22.1
DD&A and accretion expense (increase) decrease		5.0			35.2			(7.4	)
Other		(0.5	)		(5.3	)		(8.0	)
Impairment charges decrease		—			—			78.3
Loss on disposition (increase) decrease		146.0			(8.0	)		(185.7	)
Estimated tax reduction (increase) on above		(24.0	)		14.0			20.1
Tax adjustments		—			(13.5	)		(13.5	)
Net change		70.9			(61.4	)		(94.1	)
Adjusted net loss	Q4/13	(37.3	)	Q4/13	(37.3	)	2013	(183.8	)

The adjusted net loss in the fourth quarter of 2013 decreased $70.9 million compared to the third quarter of 2013. The significant reduction in losses on property dispositions were only partly offset by lower funds flow from operations.

The adjusted net loss of $37.3 million in the fourth quarter of 2013 was $61.4 million lower than the fourth quarter of 2012. The primary driver for the decrease was the $83.8 million decrease in funds flow from operations, partly offset by lower DD&A resulting from property dispositions.

Year over year adjusted net loss increased $94.1 million between 2012 and 2013. The $22.1 million funds flow from operations increase in 2013 is more reflective of the underlying business performance in 2013, but was more than offset by non-cash losses on the significant 2013 disposition program, partly offset by the absence of 2012 impairment charges.

PENGROWTH 2013 Management's Discussion and Analysis 6

Price Sensitivity

The following table illustrates the sensitivity of funds flow from operations to changes in commodity prices after taking into account Pengrowth’s risk management contracts and outlook on oil differentials:

						Estimated Impact on 12 Month Funds Flow
COMMODITY PRICE ENVIRONMENT (1)		Assumption		Change		($ millions)
West Texas Intermediate Oil (2) (3)	U.S.$/bbl	$	95.00	$	1.00
Light oil (4)						6.5
Heavy oil (4)						2.6
Oil risk management (5)						(9.4	)
NGLs						2.5
Net impact of $1/bbl change in WTI						2.2
Oil differentials
Light oil	U.S.$/bbl	$	7.60	$	1.00	6.5
Heavy oil	U.S.$/bbl	$	25.65	$	1.00	2.6
Net impact of $1/bbl change in differentials						9.1
AECO Natural Gas (2) (3)	Cdn$/Mcf	$	4.30	$	0.10
Natural gas						6.1
Natural gas risk management (5)						(4.0	)
Net impact of $0.10/Mcf change in AECO						2.1

⁽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 January 31, 2014 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.

⁽⁴⁾  Includes an average Cdn$ WTI to Edmonton light oil differential of 8 percent of Cdn$ WTI and a heavy oil differential of 27 percent of Cdn$ WTI.

⁽⁵⁾  Includes risk management contracts as at February 4, 2014.

PENGROWTH 2013 Management's Discussion and Analysis 7

RESULTS OF OPERATIONS

All volumes, wells and spending amounts stated below reflect Pengrowth’s net working interest for both operated and non-operated properties unless otherwise stated.

CAPITAL EXPENDITURES

	Three months ended				Twelve months ended
($ millions)	Dec 31, 2013	Sept 30, 2013		Dec 31, 2012	Dec 31, 2013	Dec 31, 2012
Drilling, completions and facilities
Lindbergh (1)	136.0	93.9		9.7	306.4	35.5
Non-thermal	72.8	62.7		61.3	299.8	332.4
Total drilling, completions and facilities	208.8	156.6		71.0	606.2	367.9
Land & seismic acquisitions (2)	1.1	(0.1	)	1.5	2.9	18.2
Maintenance capital	26.6	19.6		18.8	81.9	74.4
Development capital	236.5	176.1		91.3	691.0	460.5
Other capital	3.2	0.1		2.6	4.8	6.9
Capital expenditures	239.7	176.2		93.9	695.8	467.4

⁽¹⁾  2012 capital expenditures include production revenue and costs associated with the Lindbergh pilot.

⁽²⁾  Seismic acquisitions are net of seismic sales revenue.

Fourth quarter capital expenditures were $239.7 million following the strategy of selecting and executing projects that maximize cash flow and provide the highest rates of return while continuing to invest in the first commercial phase of the Lindbergh thermal project. Approximately 87 percent of the fourth quarter capital expenditures were invested in drilling, completions and facilities, with the remaining 13 percent spent on maintenance, land, seismic and other capital. Pengrowth invested 57 percent of total fourth quarter capital expenditures in the Lindbergh commercial project including the drilling of 7 horizontal producers and 3 delineation/core hole wells. Pengrowth also participated in the drilling of 14 (8.3 net) non-thermal wells, all of which were successful.

Full year 2013 capital spending amounted to $695.8 million with approximately 87 percent of capital expenditures invested in drilling, completions and facilities and the remaining 13 percent spent on maintenance, land, seismic, and other capital. Pengrowth invested 44 percent of total 2013 capital expenditures at Lindbergh which included the drilling of 36 wells (7 horizontal producers, 19 delineation/core hole, 9 observation and 1 water disposal). In addition to the Lindbergh wells drilled, Pengrowth participated in the drilling of 139 (79.4 net) non-thermal wells during 2013.

Focus Areas

Lindbergh

Pengrowth’s 100 percent owned and operated Lindbergh thermal project is located in the Cold Lake area of Alberta and encompasses 42.5 sections of land. Cost advantages of the Lindbergh resource include enhanced bitumen quality and flow characteristics which result in higher netbacks compared to typical thermal projects. Based on positive pilot results during 2012, the 12,500 bbl/d first commercial phase of Lindbergh was sanctioned by Pengrowth’s Board of Directors in January 2013 and Alberta Environmental Protection and Enhancement Act approval was received for the first commercial phase in July 2013.

Lindbergh is expected to provide Pengrowth with the potential to develop production of up to 50,000 bbl/d of bitumen over the next five years. This is expected to be strong netback production with low decline rates and long reserve life together with low sustaining capital requirements resulting in a sustainable total return model that supports growth in cash flow per share and the ability to fund an attractive dividend.

During 2013, $306.4 million was invested at Lindbergh including $136.0 million in the fourth quarter.

Civil and mechanical field construction as well as shop fabrication of major and minor equipment continued for the first 12,500 bbl/d commercial phase, during the fourth quarter of 2013. Tank and major equipment foundation construction is progressing as planned, and shop fabricated modular equipment continues to be shipped to the site and set into place. Drilling of the first well-pad continued, with 7 horizontal producers drilled in the fourth quarter and completed at the end of January 2014. The project remains on budget and on schedule with first steam from the commercial project expected in the fourth quarter of 2014 with first oil production in early 2015.

PENGROWTH 2013 Management's Discussion and Analysis 8

                                                         ��      

Operations at the pilot project continued to show strong results during the fourth quarter with combined field production from the two well pairs averaging approximately 1,700 bbl/d of bitumen. The average Instantaneous Steam Oil Ratio ("ISOR") for the quarter was 2.1. Since steaming commenced in February 2012, cumulative production from the two well pairs exceeded 1,000,000 bbls of bitumen by December 31, 2013. Significantly higher than expected production rates and level of reserves recovered to date, coupled with engineering analysis would suggest that the production rates from the pilot well pairs are expected to commence their natural decline in 2014 and, as expected, the ISOR will start to increase in the first quarter of 2014.

The Environmental Impact Assessment ("EIA") application for the Lindbergh expansion to 30,000 bbl/d was submitted to the regulators in December 2013. Approval is expected in the first quarter of 2016.

Non-Thermal Oil and Gas

Pengrowth’s significant non-thermal oil and gas portfolio includes a large contiguous land base in the Greater Olds/Garrington area encompassing over 500 gross (250 net) sections of land with stacked opportunities in the Cardium, Viking and Mannville sands as well as in the Mississippian carbonate section. An extensive gathering and processing infrastructure provides an efficient platform for continued development in this area. Pengrowth also controls large oil and gas accumulations in the Swan Hills area providing ongoing development projects with low decline production and strong cash flow.

During the fourth quarter, Pengrowth continued to achieve strong drilling and completion results with 14 (8.3 net) wells being drilled in the Cardium formation with 100 percent success. Based on initial test data and early production results, the Cardium wells appear to be meeting or exceeding type curve expectations.

2014 Capital Program

Pengrowth's expected 2014 capital program of $715 million represents a 3 percent increase from 2013 capital expenditures of $695.8 million. The program includes a $350 million non-thermal capital plan focused on Cardium development in the Olds/Garrington area, miscible flood development in Swan Hills and developing heavy oil production in the Greater Jenner area. Thermal capital of $365 million is focused on the Lindbergh 12,500 bbl/d project and in support of the next phase of development.

RESERVES AND PERFORMANCE MEASURES

Reserves - Company Interest at Forecast Prices

Reserves Summary (MMboe except as noted)	2013		2012		2011
Proved Reserves
Additions + revisions for the year	83.4		21.0		41.0
Net acquisitions (dispositions) for the year	(45.6	)	75.9		(0.2	)
Total proved reserves at period end	307.0		300.1		234.9
Proved reserve replacement ratio excluding net acquisitions (dispositions)	270%		66	%	152	%
Proved reserve replacement ratio including net acquisitions (dispositions)	122%		306	%	151	%
Proved plus Probable Reserves (P+P)
Additions + revisions for the year	65.3		103.8		39.3
Net acquisitions (dispositions) for the year	(69.0	)	109.4		(0.3	)
Total proved plus probable reserves at period end	477.4		512.0		330.5
Total production (MMboe) (1)	30.9		31.7		27.0
P+P Reserve replacement ratio excluding net acquisitions (dispositions)	211%		327	%	146	%
P+P Reserve replacement ratio including net acquisitions (dispositions) (2)	(12	)%	672	%	145	%

⁽¹⁾  Includes production from Lindbergh pilot project.

⁽²⁾  2013 negative replacement ratio was a result of net dispositions in the year.

Pengrowth reported 2013 year end total proved reserves of 307.0 MMboe and total proved plus probable reserves of 477.4 MMboe, representing an increase of 2 percent and a decrease of 7 percent, respectively, from year end 2012. During 2013, Pengrowth’s development and optimization activities in the non-thermal properties as well as regulatory approval for commercial development and ongoing delineation of the Lindbergh thermal project resulted in the addition of 83.4 MMboe of proved reserves and 65.3 MMboe of total proved plus probable reserves including revisions. With respect to net acquisitions (dispositions), a significant asset disposition program in 2013, offset by minor acquisitions, resulted in a decrease of 45.6 MMboe in proved reserves and 69.0 MMboe in total proved plus probable reserves.

PENGROWTH 2013 Management's Discussion and Analysis 9

The reserve changes in 2013 resulted in an organic reserve replacement ratio of 211 percent for total proved plus probable reserves excluding net acquisitions (dispositions), and a negative 12 percent including net acquisitions (dispositions), based on production of 30.9 MMboe during the year.

Further details of Pengrowth’s 2013 year end reserves, F&D and FD&A calculations are provided in the AIF which is filed on SEDAR (www.sedar.com) or the 40-F filed on Edgar (www.sec.gov).

Performance Measures

Finding & Development Costs & Recycle Ratio	2013		2012		2011		3 year weighted average
Excluding Net Acquisitions (Dispositions) (F&D)
Excluding changes in FDC
F&D costs per boe - (P+P)	$	10.61	$	4.44	$	15.34	$	8.43
Recycle ratio (1) (2)	2.3		5.3		1.9		3.0
Including changes in FDC
F&D costs per boe - (P+P)	$	21.96	$	16.85	$	20.12	$	19.07
Recycle ratio (1)	1.1		1.4		1.4		1.3

⁽¹⁾  Calculated as operating netback per boe divided by F&D costs per boe based on proved plus probable reserves.

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

The 2013 total proved plus probable F&D cost, including changes in FDC, was $21.96/boe, a 30 percent increase from the 2012 F&D cost. The increase from 2012 is primarily due to the addition of reserves at higher future development costs both for the Lindbergh thermal project and non-thermal properties.

Recycle ratio is an important performance measure in assessing investment profitability and provides a comparison to our competitors. Pengrowth’s operating results and capital program in 2013 yielded a recycle ratio, excluding net acquisitions (dispositions) and including changes in FDC, of 1.1 on a proved plus probable basis, slightly below the three year average of 1.3. The recycle ratio decreased from 2012 due to the higher F&D cost and the depressed netback resulting from the continuing low price environment for natural gas and higher operating costs in the current year.

Other Performance Measures	2013	2012	2011
Production per share (boe/share)	0.06	0.07	0.08
Production per debt adjusted share (boe/share) (1)	0.04	0.04	0.06
Reserves per share - (P+P) (boe/share)	0.91	1.00	0.92
Reserves per debt adjusted share - (P+P) (boe/share) (1)	0.62	0.60	0.73

⁽¹⁾  Debt adjusted shares equals the shares outstanding plus the number of shares needed to retire all of the debt at the year end share price.

Pengrowth’s goal over the longer term is to modestly grow production and reserves per debt adjusted share, while continuing to pay a prudent dividend. On a debt adjusted basis, production and total proved plus probable reserves per share were virtually unchanged from 2012, primarily due to the increase in Pengrowth’s share price used to value the debt at December 31, 2013, offsetting the 1 percent production decrease and 7 percent reserves decrease due to significant 2013 asset dispositions.

PRODUCTION

	Three months ended						Twelve months ended
Daily production	Dec 31, 2013	% of total	Sept 30, 2013	% of total	Dec 31, 2012	% of total	Dec 31, 2013	% of total	Dec 31, 2012	% of total
Light oil (bbls)	22,488	29	27,102	32	31,898	34	27,061	32	28,005	33
Heavy oil (bbls)	8,369	11	8,812	11	6,532	7	8,355	10	6,514	8
Natural gas liquids (bbls)	10,476	13	9,847	12	11,611	12	10,476	12	10,731	12
Natural gas (Mcf)	216,231	47	225,081	45	263,983	47	231,812	46	242,992	47
Total boe per day	77,371		83,275		94,039		84,527		85,748

The fourth quarter average daily production decreased 7 percent compared to the third quarter mainly due to property dispositions. Comparing the fourth quarter to the same period last year, production decreased 18 percent due to property dispositions and natural gas production declines, partly offset by production additions from the Cardium development program and the inclusion of Lindbergh thermal pilot production in 2013 operating results.

PENGROWTH 2013 Management's Discussion and Analysis 10

2013 average daily production decreased 1 percent compared to last year. This decrease was primarily due to the 2013 divestitures which combined with declines in natural gas production offset the full year of gains from May 31, 2012 NAL Acquisition and inclusion of Lindbergh production in 2013.

Light Oil

Fourth quarter light oil production decreased 17 percent compared to the third quarter mainly due to the southeast Saskatchewan light oil disposition. The 30 percent decline in the fourth quarter light oil production compared to the same period last year was due to the Weyburn and southeast Saskatchewan dispositions partly offset by the Cardium development program.

2013 light oil production decreased 3 percent compared to 2012 also due to property dispositions partly offset by positive results from the Cardium development program and a full year of production in 2013 from the NAL Acquisition.

Heavy Oil

Fourth quarter heavy oil production decreased 5 percent compared to the third quarter due to power and weather related issues at Jenner and downhole pump maintenance performed at Lindbergh.

Fourth quarter and full year 2013 heavy oil production increased 28 percent compared to the same periods last year due to the inclusion of the Lindbergh thermal pilot production in the 2013 operating results.

NGLs

NGL production increased 6 percent in the fourth quarter compared to the third quarter as a condensate shipment at Sable Island occurred in November of 2013. The 10 percent decline in fourth quarter NGL production compared to the same period last year was mainly caused by 2013 property dispositions and natural declines partly offset by the 2013 development program.

2013 NGL production decreased 2 percent compared to 2012 due to the property dispositions and one fewer Sable Island condensate shipment partly offset by positive results from the 2013 development program and production gains from the NAL Acquisition.

Natural Gas

Fourth quarter natural gas production decreased 4 and 18 percent, respectively, compared to the third quarter and the same period last year due to the 2013 property dispositions and natural declines as capital investment was directed to oil and liquids rich programs.

2013 natural gas production decreased 5 percent compared to 2012 also due to the 2013 property dispositions and natural declines which were partly offset by a full year of production from the NAL Acquisition.

COMMODITY PRICES

Oil and Liquids Prices

	Three months ended						Twelve months ended
(Cdn$/bbl)	Dec 31, 2013		Sept 30, 2013		Dec 31, 2012		Dec 31, 2013		Dec 31, 2012
Average Benchmark Prices
WTI oil	102.75		107.97		87.36		101.07		94.15
Edmonton par light oil	87.07		104.89		84.59		93.47		86.29
WCS heavy oil	69.07		92.01		69.43		75.14		72.69
Average Differentials to WTI
Edmonton par	(15.68	)	(3.08	)	(2.77	)	(7.60	)	(7.86	)
WCS heavy oil	(33.68	)	(15.96	)	(17.93	)	(25.93	)	(21.46	)
Average Realized Prices
Light oil	83.23		101.10		80.42		89.69		82.60
after realized commodity risk management	74.77		88.55		85.80		83.56		83.57
Heavy oil	61.43		88.19		63.73		67.98		65.94
Natural gas liquids	60.49		57.18		56.64		55.81		57.92

The WTI benchmark prices were volatile during 2013 driven by fundamental factors including geopolitical concerns, U.S. domestic oil supply growth, the global economy expanding relatively slowly and pipeline issues reflecting

PENGROWTH 2013 Management's Discussion and Analysis 11

transportation constraints within North America. Although the fourth quarter of 2013 WTI crude oil price decreased 5 percent compared to the third quarter, it increased 18 percent compared to the same period last year. Full year 2013 average WTI price increased 7 percent in comparison to 2012.

Pengrowth's Canadian crude oil was subject to widening location and quality differentials in 2013 as transportation bottlenecks resulted in oil-on-oil competition in various markets due to growing U.S. crude oil production. These pipeline bottlenecks resulted in Canadian crude oil producers receiving a discounted oil price relative to WTI particularly in early and late 2013. As a result light and heavy oil differentials widened significantly in the fourth quarter of 2013 pushing the full year average differentials to the levels seen in 2012. When differentials widen significantly, Pengrowth takes proactive steps to improve realizations, including utilizing rail.

Fourth quarter realized light oil price decreased 18 percent compared to the third quarter due to the impact of wider differentials. Fourth quarter and full year 2013 realized light oil price increased 3 percent and 9 percent, respectively, compared to the same periods in 2012 as a result of an increase in benchmark oil prices.

Fourth quarter heavy oil realized prices decreased 30 percent and 4 percent, respectively, compared to the third quarter of 2013 and the fourth quarter last year due to wider heavy oil differentials. Full year 2013 heavy oil realized price increased 3 percent in line with the increase in benchmark oil prices.

Fourth quarter NGL realized prices increased 6 percent compared to the third quarter as a result of the Sable Island condensate shipment in November attracting a higher price relative to the other NGLs. The 7 percent increase in realized NGL price when comparing the fourth quarter of 2013 to the same period last year was in line with strengthening oil benchmarks. Full year 2013 NGL price decreased 4 percent compared to 2012 largely influenced by capacity constraints in the local Alberta market resulting in higher fractionation and transportation costs.

Natural Gas Prices

	Three months ended						Twelve months ended
(Cdn$)	Dec 31, 2013		Sept 30, 2013		Dec 31, 2012		Dec 31, 2013		Dec 31, 2012
Average Benchmark Prices
NYMEX gas (per MMBtu)	4.05		3.63		3.50		3.82		2.83
AECO monthly gas (per MMBtu)	3.15		2.82		3.06		3.16		2.40
Average Differential to NYMEX
AECO differential	(0.90	)	(0.81	)	(0.44	)	(0.66	)	(0.43	)
Average Realized Prices
Natural gas (per Mcf) (1)	3.18		2.83		3.07		3.19		2.35
after realized commodity risk management	3.27		3.11		3.14		3.26		2.49

⁽¹⁾  Average realized prices are recorded in Mcf to reflect the volumetric reporting standard for Pengrowth's natural gas.

Overall 2013 was a much stronger year for natural gas prices than 2012, however prices remained lower than those in years prior to 2012. The significant reduction in North American natural gas prices has resulted from the emergence of unconventional natural gas production. Colder weather influenced Henry Hub prices to both start and end 2013 on a strong note. Natural gas prices recovered through the first quarter of 2013, reaching mid-year highs in April before falling off during the summer season. Fourth quarter recovery in demand pushed the full year 2013 NYMEX average price to Cdn$3.82/MMBtu, an increase of 35 percent over 2012.

Much like crude oil, growing production in the U.S. resulted in location differentials widening over the course of the year. As such, a wider basis spread between Henry Hub and AECO prices resulted in 2013 compared to 2012. The fourth quarter 2013 AECO differential increased 11 percent compared to the third quarter and the differential remained at significantly higher levels during the fourth quarter and full year 2013 compared to same periods in 2012.

Fourth quarter of 2013 realized natural gas price increased 12 percent and 4 percent, respectively, compared to the third quarter of 2013 and the fourth quarter of 2012 due to the increase in the AECO price. Following the same trend, full year 2013 natural gas realized price improved 36 percent compared to 2012.

PENGROWTH 2013 Management's Discussion and Analysis 12

Total Average Realized Prices

	Three months ended			Twelve months ended
($/boe)	Dec 31, 2013	Sept 30, 2013	Dec 31, 2012	Dec 31, 2013	Dec 31, 2012
Average realized price	47.92	56.64	47.31	51.10	45.90
after realized commodity risk management	45.71	53.32	49.34	49.32	46.60
Other production income including sulphur	0.37	0.74	0.54	0.54	0.57
Total oil and gas sales after realized commodity risk management	46.08	54.06	49.88	49.86	47.17

Fourth quarter average realized price decreased 15 percent compared to the third quarter in line with decreases in realized light and heavy oil prices partly offset by higher natural gas and NGL realized prices. Fourth quarter average realized price remained relatively unchanged compared to the same period last year, while the full year 2013 average realized price increased 11 percent over 2012 influenced by higher light and heavy oil prices and a significant recovery in the realized natural gas price.

Commodity Risk Management Gains (Losses)

	Three months ended						Twelve months ended
	Dec 31, 2013		Sept 30, 2013		Dec 31, 2012		Dec 31, 2013		Dec 31, 2012
Realized
Light oil ($ millions)	(17.5	)	(31.3	)	15.8		(60.5	)	9.9
Light oil ($/bbl)	(8.46	)	(12.55	)	5.38		(6.13	)	0.97
Natural gas ($ millions)	1.8		5.9		1.8		5.5		12.2
Natural gas ($/Mcf)	0.09		0.28		0.07		0.07		0.14
Combined ($ millions)	(15.7	)	(25.4	)	17.6		(55.0	)	22.1
Combined ($/boe)	(2.21	)	(3.32	)	2.03		(1.78	)	0.70
Unrealized
Unrealized commodity risk management assets (liabilities) at period end ($ millions)	(80.0	)	(40.9	)	7.0		(80.0	)	7.0
Less: Unrealized commodity risk management assets (liabilities) at beginning of period ($ millions)	(40.9	)	(23.0	)	7.5		7.0		(42.0	)
	(39.1	)	(17.9	)	(0.5	)	(87.0	)	49.0
Less: Commodity risk management assets, acquired with NAL - May 31, 2012 ($ millions)	—		—		—		—		18.4
Unrealized gain (loss) on commodity risk management contracts for the period ($ millions)	(39.1	)	(17.9	)	(0.5	)	(87.0	)	30.6

Pengrowth has an active risk management program which primarily uses forward price swaps to manage the exposure to commodity price fluctuations and provide a measure of stability to cash flow in order to maintain its dividend and ensure capital expenditures are funded, including Lindbergh.

Realized gains (losses) vary from period to period and are a function of the volumes under risk management contracts, the fixed prices of those risk management contracts and the benchmarkpricing for the commodities under risk management contract. Realized losses result when the average fixed risk management contracted price is lower than the benchmarks, while realized gains are recorded when the average fixed risk management contracted price is higher than the benchmarks at settlement. Realized gains and losses are settled monthly.

Fourth quarter and full year 2013 light oil realized commodity risk management losses were higher compared to the respective periods in 2012 in response to the WTI oil price increasing relative to Pengrowth's average contracted price. The decrease in natural gas realized commodity risk management gains in the fourth quarter of 2013 and full year 2013 compared the third quarter of 2013 and full year 2012, respectively, were also due to an increase in the benchmark pricing relative to Pengrowth's average contracted price in place.

Unrealized gains (losses) also vary period to period and are a function of the volumes under risk management contract, the fixed prices of those risk management contracts and the forward curvepricing for the commodities under risk management contract at the end of the period. Unrealized losses result when the forward price curve moves higher

PENGROWTH 2013 Management's Discussion and Analysis 13

than the fixed price, with the magnitude of the loss being proportional to the movement in the forward price curve while unrealized gains result when the forward price curve moves lower than the fixed price, with the magnitude of the gain being proportional to the movement in the forward price curve.

Forward Contracts

The following table provides a summary of the fixed prices of the commodity and power risk management contracts in place at December 31, 2013 (see Note 18 to the audited Financial Statements for more information on Pengrowth's risk management contracts):

Crude Oil (1)
Reference point	Yearly average volume (bbl/d)	Year	% of 2014 total oil production Guidance (2) (3)	Price/bbl ($Cdn)
WTI	23,000	2014	77%	94.51
WTI	23,232	2015	78%	93.64
WTI	124	2016	—	92.00
Natural Gas (1)
Reference point	Yearly average volume (MMBtu/d)	Year	% of 2014 total natural gas production Guidance	Price/MMBtu ($Cdn)
AECO & NGI Chicago Index	121,075	2014	61%	3.81
AECO & NGI Chicago Index	59,953	2015	30%	3.79
Power
Reference point	Yearly average volume (MW)	Year	% of 2014 estimated power consumption	Price/MWh ($)
AESO	45	2014	45%	56.50
AESO	20	2015	20%	49.69

⁽¹⁾  U.S. denominated contracts have been converted to Canadian dollars at the December 31, 2013 closing exchange rate.

⁽²⁾  Includes light and heavy crude oil. After the successful 2013 divestment program, oil risk management contracts represent over 65 percent of 2014 production Guidance. Pengrowth's Board of Directors has approved the retention of the risk management contracts already in place.

⁽³⁾  Excludes NGL production. Including NGL production would result in 60 percent for both 2014 and 2015.

At December 31, 2013, each Cdn$1/bbl change in future WTI oil prices results in approximately $16.7 million pre-tax change in the value of the crude risk management contracts, while each Cdn$0.25/MMBtu change in future natural gas prices results in approximately $16.4 million pre-tax change in the value of the natural gas risk management contracts. The changes in fair value of the forward risk management contracts directly affect reported net income (loss) through the unrealized amounts recorded in the Statements of Income (Loss) during the period. The effect on cash flow will be recognized separately only upon settlement of the risk management contracts, which could vary significantly from the unrealized amount recorded due to timing and prices when each contract is settled.

If each commodity risk management contract were to have settled at December 31, 2013, revenue and cash flow would have been $80.0 million lower than if the risk management contracts were not in place based on the estimated fair value of the risk management contracts at period end. The $80.0 million is composed of liabilities of $68.1 million relating to risk management contracts expiring within one year and liabilities of $11.9 million relating to risk management contracts expiring beyond one year.

Each Cdn$1/MWh change in future power prices would result in approximately $0.6 million pre-tax change in the fair value of the risk management contracts.

Pengrowth has not designated any outstanding commodity risk management contracts as hedges for accounting purposes and therefore records these risk management contracts on the Balance Sheets at their fair value and recognizes changes in fair value on the Statements of Income (Loss) as unrealized commodity risk management gains (losses). The volatility in net income (loss) will continue to the extent that the fair value of the commodity risk management contracts fluctuates. However, these non-cash amounts do not affect Pengrowth’s cash flow until realized.

Realized commodity risk management gains (losses) on crude oil and natural gas contracts are recorded separately on the Statements of Income (Loss) and impact cash flow at that time. Realized risk management gains (losses) on power contracts are recorded in operating expenses and the unrealized amounts are recorded in other expense.

PENGROWTH 2013 Management's Discussion and Analysis 14

In accordance with policies approved by its Board of Directors, Pengrowth may sell forward its production and purchase risk management contracts by product volume or power consumption as follows:

Forward Period	Percent of Estimated Production	Percent of Estimated Power Consumption
1 - 24 Months	Up to 65%	Up to 80%
25 - 36 Months	Up to 30%	Up to 50%
37 - 60 Months	Up to 25%	Up to 25%

In addition to the above table, Pengrowth's Board of Directors approved a one time risk management policy enhancement in order to stabilize cash flows throughout 2015 and 2016. Under this one time policy change, notwithstanding the 25-36 month forward period, Pengrowth can enter into risk management contracts up to 50 percent of its production until the end of 2016. After the successful 2013 divestment program, oil risk management contracts represent over 65 percent of 2014 production Guidance. Pengrowth's Board of Directors has approved the retention of the risk management contracts already in place.

OIL AND GAS SALES INCLUDING REALIZED COMMODITY RISK MANAGEMENT

Contribution Analysis

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

	Three months ended						Twelve months ended
($ millions except percentages)	Dec 31, 2013	% of total	Sept 30, 2013	% of total	Dec 31, 2012	% of total	Dec 31, 2013	% of total	Dec 31, 2012	% of total
Light oil	154.7	47	220.8	53	251.8	58	825.3	54	856.6	58
Heavy oil	47.3	14	71.5	17	38.3	9	207.3	13	157.2	11
Natural gas liquids	58.3	18	51.8	13	60.5	14	213.4	14	227.5	15
Natural gas	65.1	20	64.4	16	76.3	18	275.5	18	221.1	15
Other income including sulphur	2.6	1	5.7	1	4.7	1	16.9	1	17.9	1
Total oil and gas sales	328.0		414.2		431.6		1,538.4		1,480.3

Price and Volume Analysis

Quarter ended December 31, 2013 versus Quarter ended September 30, 2013

The following table illustrates the effect of changes in prices and volumes on the components of oil and gas sales including the impact of realized commodity risk management activities:

($ millions)	Light oil		Heavy oil		NGLs	Natural gas		Other (1)		Total
Quarter ended September 30, 2013	220.8		71.5		51.8	64.4		5.7		414.2
Effect of change in product prices and differentials	(37.0	)	(20.6	)	3.2	7.1		—		(47.3	)
Effect of change in realized commodity risk management activities	13.8		—		—	(4.1	)	—		9.7
Effect of change in sales volumes	(42.9	)	(3.6	)	3.3	(2.3	)	—		(45.5	)
Other	—		—		—	—		(3.1	)	(3.1	)
Quarter ended December 31, 2013	154.7		47.3		58.3	65.1		2.6		328.0

⁽¹⁾  Primarily sulphur sales.

Light oil sales decreased 30 percent in the fourth quarter of 2013 compared to the third quarter resulting from a wider Edmonton light oil differential in addition to lower sales volumes due to property dispositions. Heavy oil sales decreased 34 percent also driven by wider differentials in the quarter. NGL sales increased 13 percent due to an improvement in realized pricing and an increase in sales volumes from the Sable Island condensate shipment in November. Natural gas sales increased 1 percent due to shrinking of the AECO differential partly offset by lower risk management gains and lower sales volumes driven by property dispositions and natural declines.

PENGROWTH 2013 Management's Discussion and Analysis 15

Quarter ended December 31, 2013 versus Quarter ended December 31, 2012

The following table illustrates the effect of changes in prices and volumes on the components of oil and gas sales including the impact of realized commodity risk management activities:

($ millions)	Light oil		Heavy oil		NGLs		Natural gas		Other (1)		Total
Quarter ended December 31, 2012	251.8		38.3		60.5		76.3		4.7		431.6
Effect of change in product prices and differentials	5.8		(1.8	)	3.7		2.3		—		10.0
Effect of change in realized commodity risk management activities	(33.3	)	—		—		—		—		(33.3	)
Effect of change in sales volumes	(69.6	)	10.8		(5.9	)	(13.5	)	—		(78.2	)
Other	—		—		—		—		(2.1	)	(2.1	)
Quarter ended December 31, 2013	154.7		47.3		58.3		65.1		2.6		328.0

⁽¹⁾  Primarily sulphur sales.

Light oil sales decreased 39 percent in the fourth quarter of 2013 compared to the same period in 2012. The decrease was mainly due to lower sales volumes from the 2013 disposition program and increased realized losses on oil risk management, which resulted from an increase in WTI. Heavy oil sales posted a 23 percent increase due to the inclusion of Lindbergh thermal pilot production in 2013 results. NGL sales decreased 4 percent due to lower sales volumes caused by natural declines while natural gas sales decreased 15 percent mainly as a result of a decrease in sales volumes from property dispositions and natural declines.

Twelve months endedDecember 31, 2013 versus Twelve months endedDecember 31, 2012

The following table illustrates the effect of changes in prices and volumes on the components of oil and gas sales including the impact of realized commodity risk management activities:

($ millions)	Light oil		Heavy oil	NGLs		Natural gas		Other (1)		Total
Twelve months ended December 31, 2012	856.6		157.2	227.5		221.1		17.9		1,480.3
Effect of change in product prices and differentials	69.9		6.2	(8.1	)	71.3		—		139.3
Effect of change in realized commodity risk management activities	(70.4	)	—	—		(6.7	)	—		(77.1	)
Effect of change in sales volumes	(30.8	)	43.9	(6.0	)	(10.2	)	—		(3.1	)
Other	—		—	—		—		(1.0	)	(1.0	)
Twelve months ended December 31, 2013	825.3		207.3	213.4		275.5		16.9		1,538.4

⁽¹⁾  Primarily sulphur sales.

Light oil sales decreased 4 percent in 2013 compared to 2012 as a result of lower sales volumes. Heavy oil sales were 32 percent higher due to the addition of the Lindbergh thermal pilot production volumes in 2013 as well as higher realized prices. NGL sales decreased 6 percent driven by both lower realized prices and volumes, while natural gas sales increased 25 percent due to a significant recovery in realized prices partly offset by lower sales volumes from 2013 dispositions and decreased realized gains on risk management.

ROYALTY EXPENSE

($ millions except per boe amounts and percentages)	Three months ended			Twelve months ended
	Dec 31, 2013	Sept 30, 2013	Dec 31, 2012	Dec 31, 2013	Dec 31, 2012
Royalty expense	62.8	72.6	69.5	275.1	277.5
$/boe	8.82	9.47	8.03	8.92	8.84
Royalties as a percent of sales (%)	18.3	16.5	16.8	17.3	19.0

Royalties include Crown, freehold, overriding royalties and mineral taxes.

Royalty rates as a percentage of sales increased from 16.5 percent in the third quarter of 2013 to 18.3 percent in the fourth quarter mainly due to the absence of favourable freehold mineral tax adjustments recorded in the third quarter, in addition to the absence of royalties pertaining to the southeast Saskatchewan assets sold in the third quarter which were generally lower compared to the overall royalty rate. Partly offsetting these factors was a favourable gas and

PENGROWTH 2013 Management's Discussion and Analysis 16

sulphur royalty adjustment relating to prior years which resulted in the negative natural gas royalty expense for the fourth quarter of 2013.

Royalty rates as a percentage of sales increased from 16.8 percent in the fourth quarter 2012 to 18.3 percent in the fourth quarter of 2013 due to the southeast Saskatchewan disposition, as mentioned above.

Royalty rates decreased from 19.0 percent in 2012 to 17.3 percent in 2013 due to higher Gas Cost Allowance ("GCA") in 2013 and favourable prior year freehold mineral tax adjustment recorded in the third quarter of 2013 in addition to the sulphur and gas royalty adjustments recorded in the fourth quarter of 2013.

OPERATING EXPENSES

($ millions except per boe amounts)	Three months ended			Twelve months ended
	Dec 31, 2013	Sept 30, 2013	Dec 31, 2012	Dec 31, 2013	Dec 31, 2012
Operating expenses (1)	109.2	125.6	114.5	482.5	435.1
$/boe	15.34	16.39	13.23	15.64	13.87

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

Fourth quarter of 2013 operating expenses decreased $16.4 million or 13 percent compared to the third quarter mainly due to a decrease in electrical power costs, the absence of operating costs on disposed properties, as well as lower subsurface costs in non-thermal operations. On a per boe basis, fourth quarter operating costs decreased $1.05/boe compared to the third quarter as a result of lower power and subsurface costs as indicated above, partly offset by lower production volumes.

Fourth quarter of 2013 operating expenses decreased $5.3 million or 5 percent compared to the same period last year as a result of lower power and subsurface costs partly offset by higher processing and gathering fees. The inclusion of Lindbergh thermal pilot costs in 2013 was offset by the absence of operating costs from the disposed properties. On a per boe basis, operating costs increased $2.11/boe compared to the same quarter last year due to production declines in natural gas properties resulting from the focus of the capital program on oil and liquids, combined with increased processing fees and inclusion of the Lindbergh thermal pilot expenses in 2013. 2013 dispositions resulted in a drop in both production and costs over the periods, but had a minor impact on a per boe basis.

2013 operating expenses increased $47.4 million or 11 percent largely due to significantly higher power costs, the inclusion of the Lindbergh thermal pilot expenses in 2013 results, and higher processing and gathering fees. On a per boe basis, 2013 operating costs increased $1.77/boe compared to 2012 due to the higher costs noted above.

TRANSPORTATION COSTS

($ millions except per boe amounts)	Three months ended			Twelve months ended
	Dec 31, 2013	Sept 30, 2013	Dec 31, 2012	Dec 31, 2013	Dec 31, 2012
Transportation costs	7.8	8.4	6.5	29.4	24.8
$/boe	1.10	1.10	0.75	0.95	0.79

Transportation costs were essentially unchanged in the fourth quarter of 2013 compared to the third quarter. Fourth quarter transportation costs increased $1.3 million or 20 percent compared to the same period last year due to additional sales product trucking charges at Lochend and the inclusion of Lindbergh transportation costs in 2013 results.

2013 transportation costs increased $4.6 million or 19 percent compared to 2012 driven by the inclusion of Lindbergh transportation costs and higher sales product trucking costs at Lochend. On a per boe basis, 2013 transportation costs increased 20 percent due to the impact of increased trucking costs.

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 transportation costs. Pengrowth sells most of its natural gas without incurring significant additional transportation costs. Pengrowth also incurs transportation costs on its oil and NGL production including sales product trucking charges and pipeline costs up to the custody transfer point. Pengrowth has elected to sell approximately 65 percent of its crude oil at market points beyond the wellhead incurring transportation costs to the first major trading point. The transportation cost is dependent upon third party rates and distance the product travels prior to changing ownership or custody.

PENGROWTH 2013 Management's Discussion and Analysis 17

OPERATING NETBACKS

Pengrowth’s operating netbacks have been calculated by taking balances directly from the Statements of Income (Loss) and dividing by production, except for oil and gas sales which is the sum of oil and gas sales and realized gains and losses from commodity risk management. Certain assumptions have been made in allocating operating expenses, other income and royalty injection credits between light oil, heavy oil, natural gas and NGL production. Operating netbacks as presented below may not be comparable to similar measures presented by other companies, as there are no standardized measures.

	Three months ended						Twelve months ended
Combined Netback ($/boe)	Dec 31, 2013		Sept 30, 2013		Dec 31, 2012		Dec 31, 2013		Dec 31, 2012
Oil & gas sales (1)	46.08		54.06		49.88		49.86		47.17
Royalties	(8.82	)	(9.47	)	(8.03	)	(8.92	)	(8.84	)
Operating expenses (2)	(15.34	)	(16.39	)	(13.23	)	(15.64	)	(13.87	)
Transportation costs	(1.10	)	(1.10	)	(0.75	)	(0.95	)	(0.79	)
Operating netback (2)	20.82		27.10		27.87		24.35		23.67
Light Oil Netback ($/bbl)
Sales (includes other income) (1)	75.25		88.89		86.17		83.95		84.07
Royalties	(19.84	)	(20.76	)	(16.24	)	(18.71	)	(17.52	)
Operating expenses (2)	(16.57	)	(17.38	)	(15.03	)	(17.04	)	(15.93	)
Transportation costs	(2.22	)	(1.93	)	(1.24	)	(1.65	)	(1.32	)
Operating netback (2)	36.62		48.82		53.66		46.55		49.30
Heavy Oil Netback ($/bbl)
Sales (1)	61.43		88.19		63.73		67.98		65.94
Royalties	(9.90	)	(12.79	)	(9.19	)	(9.79	)	(12.03	)
Operating expenses (2)	(17.36	)	(19.91	)	(15.07	)	(18.97	)	(16.35	)
Transportation costs	(1.36	)	(1.93	)	(0.91	)	(1.62	)	(1.01	)
Operating netback (2)	32.81		53.56		38.56		37.60		36.55
NGLs Netback ($/bbl)
Sales (1)	60.49		57.18		56.64		55.81		57.92
Royalties	(15.47	)	(15.43	)	(14.63	)	(15.33	)	(16.40	)
Operating expenses (2)	(14.30	)	(15.79	)	(12.68	)	(15.03	)	(12.79	)
Transportation costs	(0.01	)	(0.04	)	(0.22	)	(0.05	)	(0.20	)
Operating netback (2)	30.71		25.92		29.11		25.40		28.53
Natural Gas Netback ($/Mcf)
Sales (includes other income) (1)	3.35		3.34		3.29		3.41		2.63
Royalties (3)	0.04		0.17		(0.03	)	(0.02	)	(0.05	)
Operating expenses (2)	(2.39	)	(2.51	)	(1.96	)	(2.35	)	(2.05	)
Transportation costs	(0.11	)	(0.09	)	(0.09	)	(0.09	)	(0.09	)
Operating netback ($/Mcf) (2)	0.89		0.91		1.21		0.95		0.44
Operating netback ($/boe) (2)	5.34		5.46		7.26		5.70		2.64
CONTRIBUTION BASED ON OPERATING NETBACKS (2)
Light oil (1)	51	%	59	%	65	%	61	%	68	%
Heavy oil	17	%	21	%	10	%	15	%	12	%
Natural gas liquids	20	%	11	%	13	%	13	%	15	%
Natural gas (1)	12	%	9	%	12	%	11	%	5	%

⁽¹⁾  Includes realized commodity risk management gains and losses.

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

⁽³⁾  Positive amounts pertain to favourable prior period adjustments where applicable.

PENGROWTH 2013 Management's Discussion and Analysis 18

Pengrowth realized a weighted average operating netback of $20.82/boe in the fourth quarter of 2013, down 23 percent when compared to the third quarter due to a decrease in realized oil prices resulting from widening differentials at the end of 2013. The netback decreased 25 percent when comparing the fourth quarter to the same period last year also due to decreased realized prices and higher costs. Full year 2013 operating netback, however, increased 3 percent compared to last year resulting from a significant recovery in natural gas prices year over year.

The fourth quarter light oil netback decreased 25 percent and 32 percent when compared to the third quarter and the same quarter last year, respectively, as a result of wider differentials experienced in the latter part of 2013.

The heavy oil netback decreased 39 percent in the fourth quarter of 2013 compared to the third quarter following the trend of significantly wider differentials experienced in the fourth quarter of 2013.

In contrast, the NGL netback improved 18 percent in the fourth quarter compared to the third quarter of 2013 mainly resulting from the condensate shipment at Sable Island in November as condensate attracts a higher price compared to other NGLs.

The natural gas netback more than doubled in 2013 compared to 2012 as a result of the previously noted natural gas price recovery in 2013.

GENERAL AND ADMINISTRATIVE EXPENSES

	Three months ended			Twelve months ended
($ millions except per boe amounts)	Dec 31, 2013	Sept 30, 2013	Dec 31, 2012	Dec 31, 2013	Dec 31, 2012
Cash G&A expense (1)	21.7	20.0	25.1	87.8	90.1
$/boe	3.05	2.61	2.90	2.85	2.87
Non-cash G&A expense	2.5	4.4	1.3	15.0	12.2
$/boe	0.35	0.57	0.15	0.48	0.39
Total G&A (1)	24.2	24.4	26.4	102.8	102.3
$/boe	3.40	3.18	3.05	3.33	3.26

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

Fourth quarter cash G&A expenses were $1.7 million higher compared to the third quarter primarily due to higher professional fees. On a per boe basis, cash G&A costs increased 17 percent impacted by higher costs and a decrease in production in the fourth quarter.

Comparing the fourth quarter to the same period last year, cash G&A expenses decreased $3.4 million mainly due to lower personnel costs resulting from staffing decreases following the 2013 disposition program. On a per boe basis, cash G&A costs increased 5 percent in the fourth quarter compared to the same period last year as the benefit of the lower costs was offset by an 18 percent decrease in production.

2013 cash G&A costs decreased $2.3 million compared to 2012 resulting from staffing decreases following the 2013 disposition program. On a per boe basis, cash G&A costs remained relatively unchanged year over year.

The non-cash component of G&A represents the compensation expense associated with Pengrowth’s Long Term Incentive Plans ("LTIP"). See Note 14 to the audited Financial Statements for additional information. The compensation costs associated with these plans are expensed over the applicable vesting period. Fourth quarter of 2013 non-cash G&A expense decreased $1.9 million compared to the third quarter driven by a lower performance multiplier on previously expensed grants.

The increases in non-cash G&A expense in the fourth quarter and full year 2013 compared to the same periods last year were due to new LTIP grants in 2013.

During the three months ended December 31, 2013, $3.9 million (December 31, 2012 - $2.2 million) of G&A costs were capitalized to Property, Plant and Equipment ("PP&E"). For the twelve months ended December 31, 2013, $16.0 million (December 31, 2012 - $10.1 million) were capitalized.

UNREALIZED LOSS ON INVESTMENTS

Pengrowth owns 1.0 million shares of a private corporation with an estimated fair value of $5.0 million at December 31, 2013 compared to $20.0 million at December 31, 2012. The decrease since December 31, 2012 resulted in an

PENGROWTH 2013 Management's Discussion and Analysis 19

unrealized loss of $15.0 million recognized in 2013 ($15.0 million unrealized loss recognized in 2012). See Note 5 to the audited Financial Statements for additional information.

DEPLETION, DEPRECIATION, AMORTIZATION AND ACCRETION

	Three months ended			Twelve months ended
($ millions except per boe amounts)	Dec 31, 2013	Sept 30, 2013	Dec 31, 2012	Dec 31, 2013	Dec 31, 2012
Depletion, depreciation and amortization	130.7	135.7	165.1	574.6	567.3
$/boe	18.36	17.71	19.08	18.62	18.08
Accretion	4.9	4.9	5.7	20.5	20.4
$/boe	0.69	0.64	0.66	0.66	0.65

Fourth quarter depletion expense decreased 4 and 21 percent compared to the third quarter of 2013 and fourth quarter of 2012, respectively, mainly due to the 2013 dispositions. The 2013 depletion expense increased 1 percent compared to 2012, as a full year of depletion on PP&E from the NAL Acquisition on May 31, 2012 was partly offset by the absence of depletion related to the 2013 property dispositions. On a per boe basis, depletion increased 4 percent and decreased 4 percent in the fourth quarter compared to the third quarter of 2013 and fourth quarter of 2012, respectively. These changes are mainly a result of the timing of when the property dispositions closed and the associated volumes and depletion expense recorded. The full year 2013 rate increased 3 percent compared to 2012 as a result of having a higher depletable base for the full year of 2013 due to the NAL Acquisition, partly offset by the disposition timing discussed above.

Fourth quarter accretion expense remained relatively flat compared to the third quarter, but it decreased 14 percent compared to the fourth quarter of 2012 largely due to decreases in the ARO liabilities resulting from property dispositions and the change in the discount rate in 2013. The 2013 accretion expense remained unchanged compared to 2012 as an increase in ARO from the NAL Acquisition for the full year was offset by decreases to the ARO liabilities from the property dispositions and change in the discount rate.

EXPLORATION AND EVALUATION ASSETS

A substantial portion of the $419.3 million Exploration and Evaluation ("E&E") asset on the Balance Sheets relates to the Groundbirch project in northeast B.C. The future recoverability of the book value is dependent on expectations of future natural gas prices, which could impact management’s decisions relating to drilling commitments and lease retention. Pengrowth is taking steps to preserve the Groundbirch leases. In the future, if management decides to not move the project forward then a significant portion of the E&E balance could be derecognized. The project currently meets Pengrowth’s investment hurdles given today’s price forecasts, however the economics on oil projects are more favorable and therefore the Corporation has focused its capital budget to the development of non-thermal and thermal oil projects.

IMPAIRMENTS

IFRS requires an impairment test to assess the recoverable value of the PP&E within each CGU whenever there is an indication of impairment. At December 31, 2013, there were no indications of impairment, however due to the required annual goodwill impairment test, all of the CGUs that have associated goodwill were tested. In 2012, impairment tests were performed at June 30, 2012 and December 31, 2012. The recoverable amounts of each CGU was based on the higher of value in use or fair value less costs to sell which are generally the same. The impairment tests carried out were based on reserve values using discount rates of 8 - 15 percent, varying from CGU to CGU, and an inflation rate of 2 percent. Based on the impairment tests carried out, there were no impairments at December 31, 2013. The impairment test is sensitive to lower commodity prices, which have been under significant downward pressure in recent years, particularly natural gas prices. Further declines in commodity prices could result in additional impairment charges as the cushions in the CGU impairment tests have been eroded by price decreases and operating cost increases. At June 30 2012, the carrying value of the producing Groundbirch CGU exceeded the fair value less costs to sell and an impairment of $30.0 million on PP&E was recognized. There were no other impairments recorded in 2012. The impairment noted above may be reversed if the fair value of the producing Groundbirch CGU increases in future periods. See Note 6 to the audited Financial Statements for additional information.

For E&E in 2012, it was determined that there would be no future drilling in the Horn River area due to low natural gas prices and a lack of infrastructure. Accordingly, there would be no additional capital spent to hold Pengrowth’s existing leases in the area, the majority of which would be left to expire. As a result, the carrying value of the Horn River assets was written down to nil, resulting in an impairment of $48.3 million on E&E assets at June 30, 2012.Subsequent to June 30, 2012 there have been no indications of impairment of E&E assets requiring Pengrowth to perform an impairment test. However an impairment test was performed on January 1, 2013 upon transfer of the Lindbergh project

PENGROWTH 2013 Management's Discussion and Analysis 20

to PP&E as it is an IFRS requirement. The net present value of the proved and probable reserves, as determined by the external resource evaluator supported the carrying value of the Lindbergh project, as such, no impairment was required.

INTEREST AND FINANCING CHARGES

	Three months ended					Twelve months ended
($ millions)	Dec 31, 2013		Sept 30, 2013		Dec 31, 2012	Dec 31, 2013		Dec 31, 2012
Interest and financing charges	24.6		25.5		25.7	100.2		86.4
Capitalized interest	(3.3	)	(1.8	)	—	(6.1	)	—
Total interest and financing charges	21.3		23.7		25.7	94.1		86.4

At December 31, 2013, Pengrowth had approximately $1.6 billion in total long term debt composed of $1.4 billion of fixed rate debt and $0.2 billion in convertible debentures, including the current portion. Total long term debt consists primarily of U.S. dollar denominated fixed rate notes at a weighted average interest rate of 5.7 percent and convertible debentures with a 6.25 percent coupon. At December 31, 2013, Pengrowth had no drawings on its syndicated bank facility.

Fourth quarter interest and financing charges, before capitalized interest, decreased $0.9 million compared to the third quarter as fees expensed on the previous syndicated bank facility from the third quarter were not repeated in the fourth quarter.

Fourth quarter interest and financing charges, before capitalized interest, decreased $1.1 million compared to the same period last year. This was largely a result of repaying the syndicated credit facility from asset sales proceeds in 2013. In 2012, $160.0 million was outstanding on the syndicated credit facility at December 31, 2012.

2013 interest and financing charges, before capitalized interest, increased $13.8 million compared to 2012. This was a result of incremental interest expense on the debt and convertible debentures assumed with the NAL Acquisition on May 31, 2012.

Pengrowth is required under IFRS to capitalize interest for qualifying assets in the construction phase based on costs incurred on the project and the average cost of borrowing. Interest capitalization to a qualifying asset ceases once construction is substantially complete. During the three months ended December 31, 2013, $3.3 million (December 31, 2012 – $nil) of interest was capitalized on the Lindbergh thermal project to PP&E using a capitalization rate of 5.7 percent (December 31, 2012 – nil). During the twelve months endedDecember 31, 2013, $6.1 million (December 31, 2012 – $nil) of interest was capitalized on the Lindbergh thermal project to PP&E using a capitalization rate of 5.7 percent (December 31, 2012 – nil).

Pengrowth has various floating to fixed interest rate swap contracts which were acquired with NAL in 2012, the last of which expires in March 2014. Under these contracts, Pengrowth pays a fixed rate and receives a floating rate, the Canadian three months Bankers Acceptance CDOR ("Canadian Depository Offered Rate"), on the notional amounts. The fair value of the interest rate derivative contracts has been included on the Balance Sheets with changes in the fair value reported separately on the Statements of Income (Loss) as part of interest and financing charges. See Note 18 to the audited Financial Statements for additional information.

TAXES

Deferred income tax is a non-cash item relating to temporary differences between the accounting and tax basis of Pengrowth’s assets and liabilities and has no immediate impact on Pengrowth’s cash flows. Pengrowth recorded a deferred tax reduction of $18.6 million in the fourth quarter of 2013 compared to deferred tax reductions of $32.3 million and $10.1 million in the third quarter of 2013 and the fourth quarter of 2012, respectively. For the full year 2013, Pengrowth recorded a $73.2 million deferred tax reduction compared to a $32.0 million reduction in 2012.

No current income taxes were paid by Pengrowth in 2013 or 2012 and based upon current tax legislation, anticipated capital spending and economic conditions, Pengrowth does not anticipate having to pay corporate income tax until at least 2018. See Note 12 to the audited Financial Statements for additional information.

PENGROWTH 2013 Management's Discussion and Analysis 21

FOREIGN CURRENCY GAINS (LOSSES)

	Three months ended						Twelve months ended
($ millions)	Dec 31, 2013		Sept 30, 2013		Dec 31, 2012		Dec 31, 2013		Dec 31, 2012
Currency exchange rate ($1Cdn = $U.S.) at period end	0.94		0.97		1.01		0.94		1.01
Unrealized foreign exchange gain (loss) on U.S. dollar denominated debt	(39.9	)	26.1		(14.2	)	(83.4	)	16.4
Unrealized foreign exchange loss on U.K. pound sterling denominated debt	(6.1	)	(4.5	)	(2.0	)	(9.4	)	(2.4	)
Total unrealized foreign exchange gain (loss) from translation of foreign denominated debt	(46.0	)	21.6		(16.2	)	(92.8	)	14.0
Unrealized gain (loss) on U.S. foreign exchange risk management contracts	12.0		(9.8	)	1.1		21.0		3.7
Unrealized gain on U.K. foreign exchange risk management contracts	5.8		4.6		1.8		8.8		4.2
Total unrealized gain (loss) on foreign exchange risk management contracts	17.8		(5.2	)	2.9		29.8		7.9
Total unrealized foreign exchange gain (loss)	(28.2	)	16.4		(13.3	)	(63.0	)	21.9
Total realized foreign exchange gain (loss)	(0.2	)	(0.1	)	(0.6	)	1.1		(1.0	)

Pengrowth’s unrealized foreign exchange gains and losses are primarily attributable to the translation of the foreign denominated long term debt and the related foreign exchange risk management contracts. The gains or losses on principal restatement are calculated by comparing the translated Canadian dollar balance of foreign denominated long term debt from one period to another. The magnitude of the gains and losses is proportionate to the magnitude of the exchange rate fluctuation between the opening and closing rates for the respective periods and any new foreign debt issued.

The fourth quarter of 2013 unrealized loss on foreign denominated debt amounted to $46.0 million compared to a gain of $21.6 million in the third quarter. This was mainly the result of the Canadian dollar weakening relative to the U.S. dollar in the fourth quarter of 2013 as opposed to its strengthening in the third quarter of 2013. The unrealized loss on foreign denominated debt increased by $29.8 million in the fourth quarter compared to the same period last year as weakening of the Canadian dollar was more prominent in the fourth quarter of 2013.

The unrealized loss on foreign denominated debt for the full year 2013 amounted to $92.8 million compared to an unrealized gain of $14.0 million in 2012. This change was a result of the Canadian dollar weakening in 2013 contrary to 2012 during which the Canadian dollar strengthened resulting in the unrealized foreign exchange gains at that time.

Pengrowth holds a series of swap contracts which were transacted in order to fix the foreign exchange rate on a portion of Pengrowth’s U.S. dollar denominated term debt. The swaps partially offset foreign exchange gains/losses on U.S. denominated debt. Each swap requires Pengrowth to buy U.S. dollars at a predetermined rate and time, based upon maturity dates of the U.S. dollar term debt. At December 31, 2013, the fair value of these foreign exchange derivative contracts was an asset of $23.1 million included on the Balance Sheets with changes in the fair value between Balance Sheet dates reported on the Statements of Income (Loss) as an unrealized foreign exchange (gain) loss. Fourth quarter and full year 2013 unrealized gains on foreign exchange risk management amounted to $17.8 million and $29.8 million, respectively, partly offsetting unrealized losses on principal restatement. Pengrowth realized a foreign exchange gain of $1.7 million relating to a swap that settled in April of 2013.

PENGROWTH 2013 Management's Discussion and Analysis 22

Contract type	Settlement date	Principal amount (U.S.$ millions)	Swapped amount (U.S.$ millions)	% of principal swapped		Fixed rate ($1Cdn = $U.S.)
Swap	May 2015	71.5	50	70	%	0.98
Swap	July 2017	400	250	63	%	0.97
Swap	August 2018	265	125	47	%	0.96
Swap	October 2019	35	15	43	%	0.94
Swap	May 2020	115.5	20	17	%	0.95
N/A	October 2022	105	—	—		—
N/A	October 2024	195	—	—		—
		1,187	460	39	%

To mitigate the fluctuations in the U.K. pound sterling denominated long term debt Pengrowth entered into foreign exchange risk management contracts when it issued the U.K. pound sterling term notes. These contracts fix the Canadian dollar to the U.K. pound sterling exchange rate on the interest and principal of the U.K. pound sterling denominated debt as follows:

Amount (U.K. pound sterling millions)	Settlement date	Fixed rate ($1Cdn = U.K. pound sterling)
50	December 2015	0.50
15	October 2019	0.63

At December 31, 2013, each Cdn$0.01 exchange rate change would result in approximately a $4.6 million pre-tax change in the fair value of the U.S. risk management contracts and a $0.7 million pre-tax change in the fair value of the U.K. risk management contracts.

ASSET RETIREMENT OBLIGATIONS

($ millions)	Dec 31, 2013		Dec 31, 2012		Change
ARO, opening balance	868.9		660.8		208.1
Assumed in business combinations	—		47.4		(47.4	)
Revisions due to discount rate changes (1)	(195.0	)	178.1		(373.1	)
Expenditures on remediation	(29.6	)	(27.6	)	(2.0	)
ARO on dispositions	(84.0	)	(5.5	)	(78.5	)
Accretion and other	45.9		15.7		30.2
ARO, closing balance	606.2		868.9		(262.7	)

⁽¹⁾  2013 amount relates to change in the discount rate from 2.5 percent to 3.25 percent. 2012 amount relates to the change in the discount rate from 8 percent to 2.5 percent on the ARO balances assumed in the business combinations. The offset to both revisions is recorded in PP&E.

The total future ARO is based on management’s estimate of costs to remediate, reclaim and abandon wells and facilities having regard for Pengrowth’s working interest and the estimated timing of the costs to be incurred in future periods. Pengrowth has developed an internal process to calculate these estimates which considers applicable regulations, actual and anticipated costs, type and size of well or facility and the geographic location.

The 2013 ARO liability decreased by $262.7 million mainly due to a change in the risk free discount rate from 2.5 percent to 3.25 percent reflecting an increase in the 30 year Canadian Government long term bond rate which drives Pengrowth’s estimate of the ARO discount rate. This resulted in a downward revision of $195.0 million with the offset recorded in PP&E. The ARO liability also decreased by $84.0 million due to 2013 property dispositions.

Pengrowth has estimated the net present value of its total ARO to be $606.2 million as at December 31, 2013 (December 31, 2012 – $868.9 million), based on a total escalated future liability of $2.1 billion (December 31, 2012 – $2.4 billion). These costs are expected to be incurred over 65 years with the majority of the costs to be incurred between 2038 and 2078. A risk free discount rate of 3.25 percent per annum and an inflation rate of 1.5 percent were used to calculate the net present value of the ARO at December 31, 2013.

PENGROWTH 2013 Management's Discussion and Analysis 23

REMEDIATION TRUST FUNDS AND REMEDIATION AND ABANDONMENT EXPENSE

During 2013, Pengrowth’s contributions were $4.6 million (December 31, 2012 - $6.3 million), into trust funds established to fund certain abandonment and reclamation costs associated with Judy Creek and Sable Island. The total balance of the remediation trust funds was $54.7 million at December 31, 2013 (December 31, 2012 - $53.8 million).

As a working interest holder in Sable Island, Pengrowth is under a contractual obligation to contribute to a remediation trust fund. The funding levels are based on the raw production delivered and processed at the various facilities. Funding levels for this fund may change each year pending a review by the owners.

Pengrowth takes a proactive approach to managing its well abandonment and site restoration obligations. There is an on-going program to abandon wells and reclaim well and facility sites. Through December 31, 2013, Pengrowth spent $29.6 million on abandonment and reclamation (December 31, 2012 - $27.6 million). Pengrowth expects to spend approximately $15 million in 2014 on reclamation and abandonment, excluding contributions to remediation trust funds and orphan well levies from the Alberta Energy Regulator.

CLIMATE CHANGE PROGRAMS

Since becoming effective July 1, 2007, Alberta regulates Greenhouse Gas ("GHG") emissions under the Climate Change and Emissions Management Act. Under the Act the Specified Gas Reporting Regulation ("SGRR") imposes annual GHG emissions reporting requirements on all Alberta facilities that emit more than 50,000 tonnes of greenhouse gases per year. Also under the Act, the Specified Gas Emitters Regulation ("SGER") requires Alberta facilities that emit more than 100,000 tonnes of greenhouse gases per year to reduce emissions intensity by 12 percent annually over baseline emission levels for those facilities. The baseline for facilities is an average of 2003, 2004 and 2005 emissions. Facilities can meet these required reductions in three ways: audited emission reductions in their operations; purchased Alberta-based offset carbon credits or contributions to the Alberta Climate Change and Emissions Management Fund. Unused reduction credits from one year may be carried forward to future years.

Pengrowth has three operated facilities that are subject to the annual 12 percent reduction: the Olds Gas Plant, the Judy Creek Gas Conservation Plant and the Quirk Creek Gas Plant. Pengrowth has reported emission reduction information on these facilities in 2013.

GOODWILL

In accordance with IFRS, goodwill is assessed for impairment at each year end, or when there is an indication of impairment, in conjunction with the assessment for impairment of PP&E. At December 31, 2013 and December 31, 2012, an impairment test was performed with no impairments to goodwill recorded. As at December 31, 2013, Pengrowth has goodwill of $672.7 million ($700.7 million at December 31, 2012). The $28.0 million decrease in goodwill year over year was a result of the 2013 disposition program. See Note 8 to the audited Financial Statements for details.

ACQUISITIONS AND DISPOSITIONS

	Three months ended						Twelve months ended
($ millions)	Dec 31, 2013		Sept 30, 2013		Dec 31, 2012		Dec 31, 2013		Dec 31, 2012
Property acquisitions	12.1		3.0		65.3		16.0		113.2
Proceeds on property dispositions	(41.3	)	(626.4	)	(9.1	)	(993.7	)	(26.6	)
Net cash acquisitions (dispositions)	(29.2	)	(623.4	)	56.2		(977.7	)	86.6

During 2013, Pengrowth successfully closed the disposition of its non-core southeast Saskatchewan assets, non-operated Weyburn property and other minor properties for proceeds of $993.7 million, net of closing adjustments. As previously announced, proceeds were used to pay down the term credit facility with the remainder intended to notionally fund the first commercial phase of Lindbergh.

On May 31, 2012, Pengrowth acquired all issued and outstanding common shares of NAL resulting in the issuance of 131.2 million Pengrowth common shares to former NAL shareholders, as well as the assumption by Pengrowth of NAL’s convertible debentures and long term debt. The gain on acquisition amounted to $73.5 million and was recorded as a separate line item on the 2012 Statement of Income and approximately $22 million of transaction costs were recorded in other expense. During 2012, Pengrowth also acquired properties in the Lochend area for $61.4 million.

PENGROWTH 2013 Management's Discussion and Analysis 24

WORKING CAPITAL

Working capital surplus is calculated as current liabilities less current assets per the Balance Sheets, excluding the current portions of long term debt and convertible debentures.

At December 31, 2013, Pengrowth had a working capital surplus as current assets exceeded current liabilities by $179.3 million due to a cash balance of $448.5 million on hand after the 2013 property dispositions. At December 31, 2012, Pengrowth also had a working capital surplus as current assets exceeded current liabilities by $178.5 million, primarily due to the inclusion of $317.3 million of Weyburn assets held for sale in current assets.

FINANCIAL RESOURCES AND LIQUIDITY

As at:	Dec 31, 2013		Dec 31, 2012		Change
($ millions, except ratios and percentages)
Term credit facilities	—		160.0		(160.0	)
Senior unsecured notes (1)	1,412.7		1,370.6		42.1
Long term debt	1,412.7		1,530.6		(117.9	)
Convertible debentures (1)	236.0		237.1		(1.1	)
Total debt excluding working capital	1,648.7		1,767.7		(119.0	)
Working capital surplus (2)	(179.3	)	(178.5	)	(0.8	)
Total debt	1,469.4		1,589.2		(119.8	)
Twelve months trailing:	Dec 31, 2013		Dec 31, 2012		Change
Net income (loss)	(316.9	)	12.7		(329.6	)
Add (deduct):
Interest & financing charges and accretion expense	114.6		106.8		7.8
Deferred income tax reduction	(73.2	)	(32.0	)	(41.2	)
Depletion, depreciation and amortization	574.6		567.3		7.3
EBITDA	299.1		654.8		(355.7	)
Add (deduct) other items:
Impairment of assets	—		78.3		(78.3	)
(Gain) loss on disposition of properties	175.7		(10.0	)	185.7
Other non-cash	180.2		(97.9	)	278.1
Adjusted EBITDA	655.0		625.2		29.8
Total debt excluding working capital to Adjusted EBITDA	2.5		2.8		(0.3	)
Total debt to Adjusted EBITDA (3)	2.2		2.5		(0.3	)
Total capitalization (4)	5,157.7		5,779.5		(621.8	)
Total debt as a percentage of total capitalization	28.5	%	27.5	%

⁽¹⁾  Includes current and long term portions.

⁽²⁾  Working capital (surplus) deficiency is calculated as current liabilities less current assets per the Balance Sheets, excluding the current portions of long term debt and convertible debentures.

⁽³⁾  The December 31, 2012 ratio in the table only includes seven months of Adjusted EBITDA from the NAL acquisition. Including the prior five months of NAL Adjusted EBITDA would result in a total debt to Adjusted EBITDA ratio of approximately 2.2x.

⁽⁴⁾  Total capitalization includes total debt plus Shareholders' Equity per the Balance Sheets.

At December 31, 2013, total debt decreased $119.8 million from December 31, 2012 primarily due to repayment of the term credit facilities and a repayment of U.S.$50 million of senior unsecured notes partly offset by weakening of the Canadian dollar in 2013.

The trailing twelve months total debt to Adjusted EBITDA ratio decreased to 2.2x at December 31, 2013, compared to 2.5x at December 31, 2012 due to an increase in Adjusted EBITDA and a decrease in total debt.

Term Credit Facilities

Pengrowth maintains a $1 billion revolving credit facility which at December 31, 2013 was undrawn (December 31, 2012 - $160.0 million) and had $35.8 million (December 31, 2012 - $28 million) in outstanding letters of credit. The credit facility includes an expansion feature of $250 million providing Pengrowth with up to $1.25 billion of credit capacity from a syndicate of seven Canadian and four foreign banks, and can be extended at Pengrowth’s discretion any time

PENGROWTH 2013 Management's Discussion and Analysis 25

prior to maturity, subject to syndicate approval. The facility was renewed in July of 2013 and now has a maturity date of July 26, 2017 with all other material terms and conditions remaining unchanged.

Pengrowth also maintains a $50 million demand operating facility with one Canadian bank. At December 31, 2013, this facility was undrawn (December 31, 2012 - $nil) and had $0.8 million (December 31, 2012 - $0.9 million) of outstanding letters of credit. When utilized together with any overdraft amounts, this facility appears on the Balance Sheets as a current liability in bank indebtedness.

Together, these two facilities and the cash balance of $448.5 million provided Pengrowth with approximately $1.5 billion of combined credit capacity and cash at December 31, 2013, 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 times during the preceding twelve months, and at December 31, 2013.

There were no changes to Pengrowth’s covenants in the twelve months ended December 31, 2013, however, on January 24, 2014 Pengrowth amended the credit facility by increasing the maximum permitted senior debt to EBITDA ratio from 3.0 to 3.5 and the total debt to EBITDA ratio from 3.5 to 4.0 until December 31, 2015. The ratios revert back to their prior permitted levels of 3.0 and 3.5 after December 31, 2015. The covenant amendments were obtained as a proactive step while Pengrowth completes construction of the first 12,500 bbl/d commercial phase of Lindbergh and a full year of production can contribute to the EBITDA calculation. Pengrowth's current forecast does not project violating the original covenants.

All loan agreements can be found on SEDAR (www.sedar.com) filed under "Other" or "Material Document".

The calculation for each financial covenant is based on specific definitions, is not in accordance with IFRS, is similar to Adjusted EBITDA, and cannot be readily replicated by referring to Pengrowth’s Financial Statements. The financial covenants are substantially similar between the credit facilities and the senior unsecured notes.

The key financial covenants as at February 28, 2014 are summarized below:

1.Total senior debt before working capital must not exceed 3.5 times EBITDA for the last four fiscal quarters (3.0 times after December 31, 2015);

2.Total debt before working capital must not exceed 4.0 times EBITDA for the last four fiscal quarters (3.5 times after December 31, 2015);

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

4.EBITDA must not be less than four times interest expense for the last four fiscal quarters.

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

Failing a financial covenant may result in one or more of Pengrowth’s loans being in default. In certain circumstances, being in default of one loan will, absent a cure, result in other loans 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 dividends to shareholders.

If certain financial ratios reach or exceed certain levels, management may consider steps to improve these ratios. These steps may include, but are not limited to property dispositions, reducing capital expenditures or dividends as well as raising equity. Details of these measures are included in Note 17 to the audited Financial Statements.

Dividend Reinvestment Plan

DRIP allows shareholders to reinvest cash dividends in additional shares of the Corporation. Under the DRIP, the shares are issued from treasury at a 5 percent discount to the weighted average closing price of Pengrowth’s common shares as determined by the plan.

During the twelve months ended December 31, 2013, 8.6 million shares were issued under the DRIP program for cash proceeds of $44.9 million compared to 8.3 million shares (19.3 million shares including the now suspended Premium

PENGROWTH 2013 Management's Discussion and Analysis 26

Dividend^TM plan) for total proceeds of $60.1 million ($135.9 million including the now suspended Premium Dividend^TM plan) for the same period last year.

Pengrowth does not have any off balance sheet financing arrangements.

FINANCIAL INSTRUMENTS

Pengrowth uses financial instruments to manage its exposure to commodity and power price fluctuations, foreign currency and interest rate exposures. Pengrowth’s policy is not to utilize financial instruments for trading or speculative purposes. See Note 2 to the audited Financial Statements for a description of the accounting policies for financial instruments and Note 18 to the audited Financial Statements for additional information regarding the fair value of Pengrowth’s financial instruments.

FUNDS FLOW FROM OPERATIONS AND DIVIDENDS

The following table provides funds flow from operations, dividends declared, the excess of funds flow from operations over dividends, and payout ratio:

	Three months ended						Twelve months ended
($ millions, except per share amounts)	Dec 31, 2013		Sept 30, 2013		Dec 31, 2012		Dec 31, 2013		Dec 31, 2012
Funds flow from operations	105.9		161.5		189.7		560.9		538.8
Dividends declared	62.5		62.3		61.3		248.5		284.4
Funds flow from operations less dividends declared	43.4		99.2		128.4		312.4		254.4
Per share	0.08		0.19		0.25		0.60		0.57
Payout ratio (1)	59	%	39	%	32	%	44	%	53	%

⁽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 declines while other capital is required to maintain facilities, acquire prospective lands and prepare future projects. Capital spending and acquisitions may be funded by the excess of funds flow from operations less dividends declared, through the sale of existing properties, additional debt or the issuance 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 highly dependent on commodity prices. Pengrowth enters into forward commodity risk management contracts to mitigate price volatility and to provide a measure of stability to monthly cash flow. Details of commodity risk management contracts are contained in Note 18 to the audited Financial Statements.

The following table provides the net payout ratio when the proceeds of the DRIP are netted against dividends declared to reflect Pengrowth’s net cash outlay:

	Three months ended						Twelve months ended
($ millions, except per share amounts)	Dec 31, 2013		Sept 30, 2013		Dec 31, 2012		Dec 31, 2013		Dec 31, 2012
Proceeds from DRIP (1)	11.7		11.0		26.2		44.9		135.9
Per share	0.02		0.02		0.05		0.09		0.30
Net payout ratio (%) (2)	48	%	32	%	19	%	36	%	28	%

⁽¹⁾  Premium Dividend^™ program was suspended in December of 2012. The 2012 comparative figures include the proceeds from the Premium Dividend^™ program.

⁽²⁾  Net payout ratio is calculated as dividends declared net of proceeds from the DRIP divided by funds flow from operations.

DRIP participation was equivalent to approximately 19 percent of the total dividend in the fourth quarter of 2013 compared to 18 percent in the third quarter and 43 percent in the fourth quarter of 2012. The 2013 DRIP participation was approximately 18 percent compared to 48 percent in 2012. The decreases in the 2013 periods compared to 2012 are due to the Premium Dividend^TM program being suspended in December of 2012.

DIVIDENDS

The Board of Directors and management regularly review the level of dividends. The board considers a number of factors, including expectations of future commodity prices, capital expenditure requirements, and the availability of debt and equity capital. Although the Corporation is committed to maintaining the dividend, there can be no certainty that Pengrowth will be able to maintain current levels of dividends and dividends can and may fluctuate in the future as a result of the volatility in commodity prices, changes in production levels and capital expenditure requirements. Pengrowth has no restrictions on the payment of its dividends other than maintaining its financial covenants in its borrowings and restrictions in the Business Corporations Act (Alberta).

Dividends are generally paid to shareholders on the fifteenth day or next business day of the month. Pengrowth paid $0.04 per share in each of the twelve months January through December of 2013 for an aggregate cash dividend of $0.48 per share. For the same period in 2012, Pengrowth paid $0.07 per share in each of the months January through July and $0.04 per share in each of the months August through December of 2012 for an aggregate cash dividend of $0.69 per share.

SUMMARY OF QUARTERLY RESULTS

The following table is a summary of quarterly information for 2013 and 2012.

2013	Q1		Q2		Q3		Q4
Oil and gas sales ($ millions) (1)	390.9		405.3		414.2		328.0
Net loss ($ millions)	(65.1	)	(53.4	)	(107.3	)	(91.1	)
Net loss per share ($)	(0.13	)	(0.10	)	(0.21	)	(0.17	)
Net loss per share - diluted ($)	(0.13	)	(0.10	)	(0.21	)	(0.17	)
Adjusted net loss ($ millions)	(1.1	)	(37.2	)	(108.2	)	(37.3	)
Funds flow from operations ($ millions)	147.5		146.0		161.5		105.9
Dividends declared ($ millions)	61.6		62.1		62.3		62.5
Dividends declared per share ($)	0.12		0.12		0.12		0.12
Daily production (boe/d)	89,702		87,909		83,275		77,371
Total production (Mboe)	8,073		8,000		7,661		7,118
Average realized price ($/boe) (1)	47.85		50.16		53.32		45.71
Operating netback ($/boe) (1)	24.79		24.44		27.10		20.82
2012	Q1		Q2		Q3		Q4
Oil and gas sales ($ millions) (1)	328.5		328.3		391.9		431.6
Net income (loss) ($ millions) (2)	0.7		36.8		(23.8	)	(1.0	)
Net income (loss) per share ($) (2)	—		0.09		(0.05	)	—
Net income (loss) per share - diluted ($) (2)	—		0.09		(0.05	)	—
Adjusted net income (loss) ($ millions)	(5.4	)	(89.6	)	(18.8	)	24.1
Funds flow from operations ($ millions)	113.6		94.4		141.1		189.7
Dividends declared ($ millions)	76.1		86.4		60.6		61.3
Dividends declared per share ($)	0.21		0.21		0.12		0.12
Daily production (boe/d)	75,618		78,870		94,284		94,039
Total production (Mboe)	6,881		7,177		8,674		8,652
Average realized price ($/boe) (1)	47.14		45.00		44.73		49.36
Operating netback ($/boe) (1) (3)	22.48		21.47		22.25		27.87

⁽¹⁾ Includes realized commodity risk management gains and losses.

⁽²⁾  As required under IFRS, changes in accounting for the NAL Acquisition that arose in the fourth quarter of 2012 were adjusted retrospective to the second quarter of 2012.

⁽³⁾  Prior periods restated to conform to presentation in the current period.

Fourth quarter of 2013 production was lower than the preceding six quarters mainly due to property dispositions, while widened differentials experienced in the quarter resulted in the lowest quarterly operating netback in the last two years. The third quarter of 2013 production decrease was also a result of property dispositions. First quarter of 2013 production was lower than third and fourth quarters of 2012 due to natural gas production declines, property dispositions, third party processing restrictions as well as the absence of the Sable Island condensate shipment. Production increased in the second, third and fourth quarters of 2012, primarily as a result of the NAL Acquisition on May 31, 2012. In addition to natural declines and property dispositions, production decreases were also a result of production limitations due to a Sable Island Venture platform outage since the third quarter of 2012 through to the fourth quarter of 2013.

Quarterly net income (loss) has also been affected by non-cash charges, in particular depletion, depreciation and amortization, impairment charges, gain on acquisition, unrealized gain (loss) on investments, accretion of ARO, unrealized risk management gains (losses), unrealized foreign exchange gains (losses), gains (losses) on property

PENGROWTH 2013 Management's Discussion and Analysis 27

divestments, and deferred taxes. Funds flow from operations was also impacted by changes in royalty expense, operating and general and administrative costs.

SELECTED ANNUAL INFORMATION

The table below provides a summary of selected annual financial information for the years ended 2013, 2012 and 2011.

	Twelve months ended December 31
($ millions unless otherwise indicated)	2013		2012	2011
Oil and gas sales (1)	1,538.4		1,480.3	1,453.7
Net income (loss)	(316.9	)	12.7	84.5
Net income (loss) per share ($)	(0.61	)	0.03	0.25
Net income (loss) per share - diluted ($)	(0.61	)	0.03	0.25
Dividends declared per share ($)	0.48		0.66	0.84
Total assets	6,633.2		7,469.9	5,644.7
Long term debt (2)	1,648.7		1,767.7	1,007.7
Shareholders' equity	3,688.3		4,190.3	3,347.3
Number of shares outstanding at year end (thousands)	522,031		511,804	360,282

⁽¹⁾  Includes realized commodity risk management gains and losses.

⁽²⁾  Includes current and long term portions of long term debt and convertible debentures, as applicable.

COMMITMENTS AND CONTRACTUAL OBLIGATIONS

($ millions)	2014	2015	2016	2017	2018	Thereafter	Total
Convertible debentures (1)	97.9	—	—	136.8	—	—	234.7
Interest payments on convertible debentures	14.7	8.6	8.6	2.1	—	—	34.0
Long term debt (2)	—	164.2	—	425.4	296.9	530.6	1,417.1
Interest payments on long term debt (3)	80.0	77.3	71.8	59.9	37.1	83.7	409.8
Operating leases (4)	16.8	15.6	15.2	14.6	3.8	—	66.0
Pipeline transportation	27.4	25.5	9.1	5.9	4.3	27.7	99.9
Lindbergh capital	42.4	—	—	—	—	—	42.4
Remediation trust fund payments	0.3	0.3	0.3	0.3	0.3	11.0	12.5
	279.5	291.5	105.0	645.0	342.4	653.0	2,316.4

⁽¹⁾ Assumes no conversion of convertible debentures prior to maturity.

⁽²⁾  The debt repayment includes foreign denominated fixed rate debt translated using the year end exchange rate.

⁽³⁾  Interest payments are calculated at period end exchange rates and interest rates except for fixed rate debt which is calculated at the actual interest rate.

⁽⁴⁾  Includes office rent, vehicle leases and other.

BUSINESS RISKS

The following factors should not be considered exhaustive. Additional risks are outlined in the Corporation’s most recent Annual Information Form ("AIF") which is available on SEDAR at www.sedar.com.

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

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, availability of pipeline and rail transportation capacity, availability of refining capacity, discount for Western Canadian light and heavy oil and natural gas, and political and economic stability.

• Production could be shut-in at specific wells or fields in times of low commodity prices.

• Substantial and sustained reductions in commodity prices or equity markets, including Pengrowth’s share price, in some circumstances could result in Pengrowth recording an impairment loss as well as affecting the ability to maintain the current dividends, spend capital and meet obligations. The impairment test is sensitive to lower

PENGROWTH 2013 Management's Discussion and Analysis 28

realized commodity prices, which have been under significant downward pressure in recent years, particularly natural gas prices. Further declines in commodity prices could result in additional impairment charges as the cushions in the CGU impairment tests have been eroded by price decreases and operating cost increases.

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 acquisition opportunities may be impaired.

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

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

• Failing a financial covenant may result in one or more of Pengrowth’s loans being in default. In certain circumstances, being in default of one loan will result in other loans also being in default. In the event that an event of non-compliance continued, Pengrowth would have to repay the relevant debt, refinance the debt or negotiate new terms with the debt holders and may have to suspend dividends to shareholders.

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

• Uncertainty in international financial markets could lead to constrained capital markets, increased cost of capital and negative 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 fees could 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 substantial capital and operating expenses to comply with increasingly complex laws and regulations covering the protection of the environment and human health and safety. In particular, we may be required to incur significant costs to comply with future regulations to reduce greenhouse gas and other emissions.

• Regulations surrounding the fracture stimulation of wells, including increasing disclosure and restrictions, differ and depend on the area of operation. Pengrowth may have to adjust its operational practices, increase compliance and incur additional costs as a result.

• Changes to accounting policies may result in significant adjustments to our financial results, which could negatively impact 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, rail lines and processing facilities. Operational or economic factors may result in the inability to deliver our products to market.

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

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

• Limitations on the availability of specialized equipment, goods and services, during periods of increased activity within the oil and gas sector, may adversely impact timing of operations.

• Oil and gas operations can be negatively impacted by certain weather conditions, including floods, 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 the pace of capital and operating expenditures. If these operators fail to perform their duties properly, or

PENGROWTH 2013 Management's Discussion and Analysis 29

become insolvent, we may experience interruptions in production and revenues from these properties or incur additional liabilities and expenses as a result of the default of these third party operators.

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

• 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 the common shares.

• During periods of increased activity within the oil and gas sector, the cost of goods and services may increase substantially and it may be more difficult to hire and retain staff and the cost for skilled labour may increase substantially.

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

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

• Delays or failure to secure regulatory approvals for thermal projects may result in capital being spent with reduced economics, reduced or no further reserves being booked, and reduced or no associated future production and cash flow.

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

• The success of a thermal project such as Lindbergh will depend, in part, on our ability to sell our production at a desirable price. Current transportation and refining constraints have resulted in a volatile price environment with a substantial discount (differential) being paid for heavy oil and bitumen.

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 larger percentage of our cash flow to such opportunities may reduce the funds available for dividend payments to shareholders. In such 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 our common shares could be reduced if reserves and production are not replaced. The ability to replace production depends on the amount of capital invested and success in developing existing reserves, acquiring new reserves and financing this development and acquisition activity within the context of the capital markets.

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

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

Asset Concentration Risks

• Pengrowth sold almost $1 billion of assets in 2013 to fund, inter alia, the first commercial phase of Lindbergh. These asset sales, combined with the significant investment into Lindbergh increases Pengrowth’s asset concentration and a failure (cost overruns, delays, performance issues, etc.) to execute at Lindbergh could have a significant adverse effect on Pengrowth and our ability to pay dividends.

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.

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

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

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

ACCOUNTING PRONOUNCEMENTS ADOPTED

On January 1, 2013, Pengrowth adopted new standards with respect to IFRS 10 Consolidated Financial Statements, IFRS 11 Joint Arrangements, IFRS 12 Disclosures of Interests in Other Entities, as well as the consequential amendments to IAS 28 Investments in Associates and Joint Ventures (2011), IFRS 13 Fair Value Measurement and IFRS 7 Amendments to Financial Instrument Disclosures. The adoption of these standards had no impact on the amounts recorded in the Financial Statements as at December 31, 2013 but did result in additional disclosures with regards to IFRS 13 and IFRS 7.

Amendments to IAS 36: Impairment of Assets ("IAS 36 Amendments")

IAS 36 Amendments, Recoverable Amount Disclosures for Non-Financial Assets, was published in May 2013. Under the amendments, the recoverable amount is required to be disclosed only when an impairment loss has been recognized or reversed. The amendments were required to be applied retrospectively for years beginning on or after January 1, 2014, with early adoption allowed. Pengrowth has elected to early adopt these amendments effective January 1, 2013.

ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED

Offsetting Financial Assets and Financial Liabilities (Amendments to IAS 32 Financial Instruments: Presentation (“IAS 32”)

The amendments to IAS 32 clarify the requirements for offsetting financial instruments. The amendments clarify when an entity has a legally enforceable right to offset and certain other requirements that are necessary to present a net financial asset or liability.

The amendments to IAS 32 are to be applied retrospectively for annual periods beginning on or after January 1, 2014, with early adoption allowed. Pengrowth is currently assessing the impact of this amendment on the presentation of its accounts receivable and payable related to commodity, power, interest and foreign exchange contracts.

DISCLOSURE AND INTERNAL CONTROLS

As a Canadian reporting issuer with securities listed on both the TSX and the NYSE, Pengrowth is required to comply with Multilateral Instrument 52-109 - Certification of Disclosure in Issuers’ Annual and Interim Filings, as well as the Sarbanes Oxley Act (“SOX”) enacted in the United States. Both the Canadian and U.S. certification rules include similar requirements where both the Chief Executive Officer (“CEO”) and the Chief Financial Officer (“CFO”) must assess and certify as to the effectiveness of the disclosure controls and procedures as defined in Canada by Multilateral Instrument 52-109 - Certification of Disclosure in Issuers’ Annual and Interim Filings and in the United States by Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended.

The CEO, Derek Evans, and the CFO, Christopher Webster, evaluated the effectiveness of Pengrowth’s disclosure controls and procedures for the year ending December 31, 2013. This evaluation considered the functions performed by its Disclosure Committee, the review and oversight of all executive officers and the board, as well as the process and systems in place for filing regulatory and public information. Pengrowth’s established review process and disclosure controls are designed to provide reasonable assurance that all required information, reports and filings required under Canadian securities legislation and United States securities laws are properly submitted and recorded in accordance with those requirements.

Based on that evaluation, the CEO and CFO concluded that the design and operation of Pengrowth's disclosure controls and procedures were effective at the reasonable assurance level as at December 31, 2013, to ensure that information required to be disclosed by us in reports that we file under Canadian and U.S. securities laws is gathered, recorded, processed, summarized and reported within the time periods specified under Canadian and U.S. securities laws and is accumulated and communicated to the management of Pengrowth Energy Corporation, including the CEO and CFO, to allow timely decisions regarding required disclosure as required under Canadian and U.S. securities laws.

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

INTERNAL CONTROL OVER FINANCIAL REPORTING

Pengrowth's management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended and in Canada as defined in Multilateral Instrument 52-109 - Certification of Disclosure in Issuers’ Annual and Interim Filings. Pengrowth's internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of Pengrowth's financial reporting and the preparation of Pengrowth's Financial Statements for external purposes in accordance with IFRS for note disclosure purposes. Pengrowth's internal control over financial reporting includes those policies and procedures that: pertain to the maintenance of records that in reasonable detail accurately and fairly reflect Pengrowth's transactions and disposition of the assets; provide reasonable assurance that transactions are recorded as necessary to permit preparation of Pengrowth's Financial Statements in accordance with IFRS and that receipts and expenditures of Pengrowth's assets are being made only in accordance with authorizations of Pengrowth's management and directors; and provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of Pengrowth's assets that could have a material effect on Pengrowth's Financial Statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Pengrowth's management, with the participation of Pengrowth's principal executive officer and principal financial officer, evaluated the effectiveness of Pengrowth's internal control over financial reporting as of December 31, 2013. In making this evaluation, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) in Internal Control-Integrated Framework (1992).

Based on Pengrowth's evaluation, management concluded that Pengrowth's internal control over financial reporting was effective as of December 31, 2013.

The effectiveness of internal control over financial reporting as of December 31, 2013 was audited by KPMG LLP, an independent registered public accounting firm, as stated in their report, which is included with Pengrowth's audited Financial Statements for the year ended December 31, 2013. No changes were made to Pengrowth's internal control over financial reporting during the year ending December 31, 2013 that have materially affected, or are reasonably likely to materially affect, the internal controls over financial reporting.

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