Pengrowth Energy (PGH) 40-F 2014 FY Annual report (Canada)

MANAGEMENT’S DISCUSSION & ANALYSIS

The following Management’s Discussion and Analysis ("MD&A") of financial results should be read in conjunction with the audited Consolidated Financial Statements for the year ended December 31, 2014 of Pengrowth Energy Corporation ("Pengrowth" or the "Corporation"). This MD&A is based on information available to February 26, 2015.

Pengrowth’s fourth quarter and annual results for 2014 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.

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, "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, "NYMEX" refers to New York Mercantile Exchange, "NGI Chicago" refers to Chicago natural gas price point and "AESO" refers to Alberta power 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"), remediation, reclamation and abandonment expenses, clean-up and remediation costs, 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 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 and meet financial covenants and our ability to add production and reserves through our development, exploitation and exploration activities. Although management considers these assumptions to be reasonable based on information currently available to it, they may prove to be incorrect.

By their very nature, forward-looking statements involve inherent risks and uncertainties, both general and specific, and risks that predictions, forecasts, projections and other forward-looking statements will not be achieved. We caution

PENGROWTH 2014 Management's Discussion and Analysis 1

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 annual Consolidated Financial Statements, management information circular, quarterly reports, material change reports and news releases. Copies of Pengrowth’s public filings are available on SEDAR at www.sedar.com and EDGAR 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 Consolidated Financial Statements are prepared in accordance with IFRS. The preparation of Consolidated Financial Statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingencies at the date of the Consolidated Financial Statements and revenues and expenses during the reporting year. Actual results could differ from those estimated.

In particular, information about significant areas of estimation uncertainty and critical judgments in applying accounting policies that have the most significant effect on the amounts recognized in the Consolidated Financial Statements is described below:

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 goodwill and 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.

PENGROWTH 2014 Management's Discussion and Analysis 2

Determination of Cash Generating Units ("CGUs")

CGUs are the smallest group of assets that generate cash inflows from continuing use that are largely independent of the cash inflows of other assets or groups of assets. The recoverability of development and production asset carrying values are assessed at the CGU level. 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. In assessing the recoverability of oil and gas properties, 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 Obligations

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 2014, Pengrowth’s ARO risk free discount rate changed from 3.25 percent to 2.3 percent due to a decrease 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. The test is based on estimates of proved plus probable reserves, production rates, oil and natural gas prices, future costs, discount rate and other relevant assumptions. Undeveloped land, contingent resources and infrastructure may also be considered. 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 Consolidated Financial Statements of future periods.

Fair value of risk management contracts

Pengrowth records risk management contracts at fair value with changes in fair value recognized in the Consolidated Statements of Income (Loss). The fair values are determined using observable market data and external counterparty information.

Valuation of trade and other receivables, and prepayments to suppliers

Management estimates the likelihood of the collection of trade and other receivables and recovery of prepayments based on 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.

COMPARATIVE FIGURES

Certain comparative figures have been restated to conform to the current period presentation.

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 Consolidated 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.

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.

PENGROWTH 2014 Management's Discussion and Analysis 3

Operating netbacks do not have standardized meanings prescribed by GAAP. Pengrowth’s operating netbacks have been calculated by taking balances directly from the Consolidated Statements of Income (Loss) and dividing by production. 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 Consolidated Balance Sheets, and total capitalization is the sum of total debt and shareholders’ equity.

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, power and interest 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, as applicable, that may significantly impact net income (loss) from period to period.

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 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.

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 price 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 the year end share price 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 2014 Management's Discussion and Analysis 4

2014 and 2015 GUIDANCE

The following table provides a summary of Pengrowth's 2014 Guidance and actual results:

	2014 Actual	2014 Guidance (1)
Production (boe/d)	73,288	71,000 - 73,000
Capital expenditures ($ millions)	904.0	740 - 770
Royalty expenses (% of sales)	17.9	16 - 18
Operating expenses ($/boe)	15.53	15.20 - 15.80
Cash G&A expenses ($/boe)	3.15	3.15 - 3.25
Funds flow from operations ($ millions)	505.7	500 - 540
EBITDA ($ millions) (2)	557.4	575 - 625

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

⁽²⁾  Guidance EBITDA calculated as funds flow from operations plus interest and financing charges less expenditures on remediation.

2014 average production of 73,288 boe/d exceeded 2014 Guidance driven by performance of the new Cardium development wells partly offset by third party capacity constraints at Pine Creek, downtime at Sable Island and several minor property divestitures completed in 2014.

2014 capital expenditures amounted to $904.0 million, including $442.3 million invested in all phases at Lindbergh and $338.1 million invested in non-thermal development capital. Pengrowth also acquired 32.6 gross/net sections of prospective liquids-rich Montney lands at Bernadet in north eastern British Columbia for $123.6 million in the fourth quarter which was not contemplated in 2014 Guidance of $740 - $770 million.

2014 royalty, operating and G&A expenses were in line with 2014 Guidance.

2014 funds flow from operations was at the lower end of 2014 Guidance, and 2014 EBITDA was below 2014 Guidance primarily due to unplanned clean up and remediation costs.

The following table provides Pengrowth's previously announced 2015 Guidance:

	2015 Guidance
Production (boe/d)	73,000 - 75,000
Capital expenditures ($ millions)	190 - 210
Royalty expenses (% of sales)	12 - 15
Operating expenses ($/boe) (1)	15.50 - 16.50
Cash G&A expenses ($/boe) (1)	3.20 - 3.30

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

Pengrowth’s 2015 capital program of $200 million represents a 78 percent decrease from 2014 actual capital expenditures of $904.0 million. The program includes $125 million of non-thermal capital focused on optimization and enhancement activities targeting ongoing production and does not contemplate an active drilling program. Thermal capital of $75 million at Lindbergh is allocated to engineering design work on Phase II, the building of the sales pipeline connection to Husky Energy Inc. ("Husky"), installation of downhole pumps on all new wells and the addition of treating capability at the existing facilities to increase throughput capacity. Pengrowth is maintaining spending on its asset integrity and maintenance programs.

Despite the reduction in 2015 capital spending, Pengrowth expects to grow volumes to a range of 73,000 - 75,000 boe/d in 2015 due to the anticipated volumes from the first commercial phase at Lindbergh.

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FINANCIAL HIGHLIGHTS

	Three months ended					Twelve months ended
($ millions except per boe amounts)	Dec 31, 2014		Sept 30, 2014	Dec 31, 2013		Dec 31, 2014		Dec 31, 2013
Production (boe/d)	71,802		72,472	77,371		73,288		84,527
Capital expenditures	258.8		191.9	239.7		904.0		695.8
Funds flow from operations	115.8		129.0	105.9		505.7		560.9
Operating netback ($/boe)(1)	24.04		24.91	20.82		25.64		24.35
Adjusted net income (loss)	(854.8	)	3.4	(37.3	)	(879.0	)	(183.8	)
Net income (loss)	(506.0	)	52.2	(91.1	)	(578.8	)	(316.9	)

⁽¹⁾  Including realized commodity risk management.

Funds Flow from Operations

($ millions)	Q3/14 vs. Q4/14			% Change		Q4/13 vs. Q4/14			% Change		2013 vs. 2014			% Change
Funds flow from operations for comparative period	Q3/14	129.0				Q4/13	105.9				2013	560.9
Increase (decrease) due to:
Volumes		(14.1	)	(11	)		(32.6	)	(31	)		(235.1	)	(42	)
Prices including differentials		(62.7	)	(49	)		(20.4	)	(19	)		141.0		25
Realized commodity risk management		50.3		39			37.4		35			(41.1	)	(7	)
Other income including sulphur		(0.8	)	(1	)		0.8		1			(2.4	)	—
Royalties		14.3		11			11.6		11			6.5		1
Expenses:
Operating		7.9		6			14.7		14			67.1		12
Cash G&A		(0.6	)	—			0.5		—			3.5		1
Interest & financing		(0.5	)	—			3.6		3			19.5		3
Other expenses including transportation		(7.0	)	(5	)		(5.7	)	(5	)		(14.2	)	(3	)
Net change		(13.2	)	(10	)		9.9		9			(55.2	)	(10	)
Funds flow from operations	Q4/14	115.8				Q4/14	115.8				2014	505.7

Fourth quarter of 2014 funds flow from operations decreased 10 percent compared to the third quarter of 2014 primarily due to lower volumes as a result of minor property dispositions and temporary solution gas restrictions in the Swan Hills area. The impact of lower commodity prices was more than offset by realized commodity risk management gains, along with lower royalties and operating expenses.

Fourth quarter of 2014 funds flow from operations increased 9 percent compared to the same period in 2013 as the impact of lower volumes and commodity prices was more than offset by realized commodity risk management gains, along with lower royalties and operating expenses.

Full year 2014 funds flow from operations decreased 10 percent compared to 2013 mainly due to lower volumes resulting from 2013 and 2014 property dispositions which were mostly offset by an increase in natural gas prices and lower operating and interest expenses year over year.

Net Income (Loss)

Pengrowth recorded a net loss of $506.0 million in the fourth quarter of 2014 compared to net income of $52.2 million in the third quarter of 2014 and a net loss of $91.1 million in the fourth quarter of 2013. The substantial increase in net loss was primarily a result of non-cash impairment charges of approximately $858 million after-tax, recorded in the fourth quarter of 2014, partly offset by an increase in unrealized gain on commodity risk management.

Full year 2014 net loss of $578.8 million increased $261.9 million compared to a net loss of $316.9 million in 2013 mainly due to non-cash impairment charges of approximately $858 million after-tax, recorded in the fourth quarter of 2014, partly offset by an increase in unrealized gain on commodity risk management and the absence of the 2013 loss on disposition of properties.

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Adjusted Net Income (Loss)

Pengrowth reports adjusted net income (loss) to remove the effect of unrealized gains and losses, however, non-cash impairment charges of approximately $858 million after-tax recorded in the fourth quarter of 2014 are included. The following table provides a reconciliation of net income (loss) to adjusted net income (loss):

	Three months ended						Twelve months ended
($ millions)	Dec 31, 2014		Sept 30, 2014		Dec 31, 2013		Dec 31, 2014		Dec 31, 2013
Net income (loss)	(506.0	)	52.2		(91.1	)	(578.8	)	(316.9	)
Excluded non-cash items in net income (loss):
Unrealized gain (loss) on commodity, power and interest risk management	501.3		121.1		(39.1	)	499.6		(87.0	)
Unrealized foreign exchange loss(1)	(29.8	)	(42.7	)	(28.2	)	(79.0	)	(63.0	)
Unrealized loss on investments	—		(5.0	)	—		(5.0	)	(15.0	)
Tax effect on non-cash items above	(122.7	)	(24.6	)	13.5		(115.4	)	31.9
Total excluded	348.8		48.8		(53.8	)	300.2		(133.1	)
Adjusted net income (loss)	(854.8	)	3.4		(37.3	)	(879.0	)	(183.8	)

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

The following table represents a continuity of adjusted net income (loss):
($ millions)	Q3/14 vs. Q4/14			Q4/13 vs. Q4/14			2013 vs. 2014
Adjusted net income (loss) for comparative period	Q3/14	3.4		Q4/13	(37.3	)	2013	(183.8	)
Funds flow from operations increase (decrease)		(13.2	)		9.9			(55.2	)
DD&A and accretion expense decrease		0.9			3.5			59.3
Impairment charges increase		(994.6	)		(994.6	)		(994.6	)
Loss on property dispositions decrease		1.7			29.4			199.0
Other		1.9			2.3			1.8
Estimated tax on above		145.1			132.0			94.5
Net change		(858.2	)		(817.5	)		(695.2	)
Adjusted net loss	Q4/14	(854.8	)	Q4/14	(854.8	)	2014	(879.0	)

Pengrowth posted an adjusted net loss of $854.8 million in the fourth quarter of 2014 compared to adjusted net income of $3.4 million in the third quarter of 2014 and an adjusted net loss of $37.3 million in the fourth quarter of 2013. The increase in the adjusted net loss was primarily due to non-cash impairment charges Pengrowth recorded given the significant downturn in commodity benchmark prices in late 2014.

Full year 2014 adjusted net loss of $879.0 million increased $695.2 million compared to an adjusted net loss of $183.8 million in 2013 also due to non-cash impairment charges recorded in the fourth quarter of 2014 partly offset by reduced losses on disposition of properties and lower DD&A in 2014.

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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		(Cdn$ millions)
West Texas Intermediate Oil (2) (3)	U.S.$/bbl	$	49.87	$	1.00
Light oil						7.2
Heavy oil						7.0
Oil risk management (4)						(11.7	)
NGLs						3.2
Net impact of U.S.$1/bbl increase in WTI						5.7
Oil differentials
Light oil	U.S.$/bbl	$	5.77	$	1.00	(7.2	)
Heavy oil	U.S.$/bbl	$	14.11	$	1.00	(7.0	)
Net impact of U.S.$1/bbl increase in differentials						(14.2	)
AECO Natural Gas (2) (3)	Cdn$/Mcf	$	2.76	$	0.10
Natural gas						6.0
Natural gas risk management (4)						(3.0	)
Net impact of Cdn$0.10/Mcf increase in AECO						3.0

⁽¹⁾  Calculations are performed independently and are not indicative of actual results when multiple variables change at the same time. An exchange rate of $1Cdn = $0.80 U.S. was used.

⁽²⁾  Commodity price is based on an estimation of the 12 month forward price curve at February 1, 2015 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 risk management contracts as at February 1, 2015.

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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, 2014	Sept 30, 2014	Dec 31, 2013	Dec 31, 2014	Dec 31, 2013
Drilling, completions and facilities
Lindbergh	80.4	110.5	136.0	442.3	306.4
Non-thermal	34.9	61.5	72.8	256.5	299.8
Total drilling, completions and facilities	115.3	172.0	208.8	698.8	606.2
Land & seismic acquisitions (1)	123.9	0.3	1.1	129.3	2.9
Maintenance capital	17.8	19.1	26.6	72.8	81.9
Development capital	257.0	191.4	236.5	900.9	691.0
Other capital	1.8	0.5	3.2	3.1	4.8
Capital expenditures	258.8	191.9	239.7	904.0	695.8

⁽¹⁾  Seismic acquisitions are net of seismic sales revenue.

Fourth quarter of 2014 capital expenditures were $258.8 million following the ongoing strategy of executing on projects that maximize cash flow while taking advantage of significant opportunities to expand Pengrowth's development inventoryand continuing to invest in the first commercial phase of the Lindbergh thermal project. Approximately 48 percent of the fourth quarter of 2014 capital expenditures were invested inthe acquisition of 32.6 gross/net sections of prospective liquids-rich Montney lands at Bernadet in north eastern British Columbia, 31 percent was spent at Lindbergh, and the remaining 21 percent was spent on non-thermal activity including drilling 13 (5.5 net) wells.

2014 capital spending totaled $904.0 million of which approximately 49 percent was invested at Lindbergh, 37 percent was invested in non-thermal activity with the remaining 14 percent invested in the Bernadet land acquisition.

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 resulting in an efficient steam oil ratio which translates into a lower operating cost structure and higher netbacks compared to many thermal projects. A two well pair pilot project at Lindbergh was brought on stream in February 2012 and the results have exceeded type curve and steam oil ratio expectations. 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. The Environmental Impact Assessment ("EIA") application for the Lindbergh expansion to 30,000 bbl/d was submitted to the regulators in December 2013.

During the fourth quarter of 2014, $80.4 million was invested at Lindbergh, bringing the year to date spending to $442.3 million. Construction of the initial 12,500 bbl/d commercial phase of Lindbergh was completed on time with steaming operations commencing in December 2014. Steam circulation on the 20 well pairs is following the same time line established for the pilot well pairs. Operations have commenced on all three well pads and production is expected to build through 2015 as downhole pumps are installed.

Pengrowth has entered into a transportation agreement with Husky for delivery of production from the initial commercial phase of Lindbergh to Hardisty, Alberta, with options to nominate additional future volumes as Lindbergh expands. Pengrowth retains maximum flexibility in regards to transportation options at Lindbergh and will be able to utilize both rail and pipeline to move production to markets and maximize netbacks. Construction of the pipeline is underway with an expected on stream date in the third quarter of 2015.

Operations at the pilot project continued to show strong results during the fourth quarter of 2014 with combined field production from the two well pairs averaging 1,689 bbl/d of bitumen. The average Instantaneous Steam Oil Ratio ("ISOR") for the fourth quarter of 2014 was 2.5. Since steaming commenced in February 2012, cumulative production

PENGROWTH 2014 Management's Discussion and Analysis 9

from the two well pairs exceeded 1.6 million bbls of bitumen by December 31, 2014 with a Cumulative Steam Oil Ratio ("CSOR") of 2.1. The pilot well pairs began their natural decline in 2014.

Lindbergh is expected to provide Pengrowth with the potential to ultimately develop annual bitumen production of 40,000 to 50,000 bbl/d. This is expected to be low cost production with low sustaining capital requirements and long reserve life.

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 of Southern Alberta 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 light oil accumulations in the Swan Hills area of northern Alberta providing low decline production and strong cash flow.

Development continued during the fourth quarter of 2014 in the Greater Olds/Garrington area with an additional 7 (3.2 net) wells drilled in the Cardium and an additional 2 (0.5 net) wells drilled in the Glauconite formation, all with 100 percent success. Two of the new Cardium wells are on stream, and 2 other wells have been tested, with initial test data and early production results meeting or exceeding expectations. Pengrowth’s fourth quarter of 2014 development program included 3 (0.8 net) wells in the Slave Point formation at Sawn Lake and 1 (1.0 net) injection well at Judy Creek supporting incremental production and reserves in the miscible flood. Pengrowth also completed and tied in 2 Groundbirch Montney horizontal wells in the fourth quarter of 2014 completed with high intensity multi-stage hydraulic fracturing technology. The initial production results from the 2 (2.0 net) Groundbirch wells indicate performance that significantly exceeds Pengrowth's historic Groundbirch production results.

Pengrowth acquired an additional 32.6 gross/net sections of prospective liquids-rich lands in the heart of the Montney fairway at Bernadet in north eastern British Columbia at the November 5, 2014 Crown land sale. This acquisition extends Pengrowth's legacy position in the Bernadet area of 4.0 gross/net sections and is expected to provide significant scalable, low risk development drilling inventory in addition to Pengrowth's existing Montney inventory in Groundbirch. With the addition of the Bernadet lands, Pengrowth is now well positioned with a focused multi-year conventional drilling inventory of light oil and liquids-rich natural gas prospects that complement Pengrowth's thermal opportunities.

2015 Capital Program

Pengrowth’s 2015 capital program of $200 million represents a 78 percent decrease from 2014 actual capital expenditures of $904.0 million. The program includes $125 million of non-thermal capital focused on optimization and enhancement activities targeting ongoing production and does not contemplate an active drilling program. Thermal capital of $75 million at Lindbergh is allocated to engineering design work on Phase II, the building of the sales pipeline connection to Husky, installation of downhole pumps on all new wells and the addition of treating capability at the existing facilities to increase throughput capacity.

PENGROWTH 2014 Management's Discussion and Analysis 10

RESERVES AND PERFORMANCE MEASURES

Reserves - Company Interest at Forecast Prices

Reserves Summary (MMboe except as noted)	2014		2013		2012
Proved Reserves
Additions + revisions for the year	32.9		83.4		21.0
Net acquisitions (dispositions) for the year	(3.2	)	(45.6	)	75.9
Total proved reserves at period end	310.1		307.0		300.1
Proved reserve replacement ratio excluding net acquisitions (dispositions)	123	%	270%		66	%
Proved reserve replacement ratio including net acquisitions (dispositions)	111	%	122%		306	%
Proved plus Probable Reserves (P+P)
Additions + revisions for the year	112.4		65.3		103.8
Net acquisitions (dispositions) for the year	(5.6	)	(69.0	)	109.4
Total proved plus probable reserves at period end	557.4		477.4		512.0
Total production (MMboe) (1)	26.8		30.9		31.7
P+P Reserve replacement ratio excluding net acquisitions (dispositions)	420	%	211%		327	%
P+P Reserve replacement ratio including net acquisitions (dispositions) (2)	399	%	(12	)%	672	%

⁽¹⁾  Includes production from Lindbergh pilot project.

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

Pengrowth’s 2014 total proved reserves increased 1 percent from 2013, while total proved plus probable reserves increased 17 percent. Pengrowth added 32.9 MMboe of proved reserves and 112.4 MMboe of total proved plus probable reserves in 2014 from development and optimization activities in non-thermal properties, and ongoing reservoir delineation and the submission of a regulatory application to expand the development of the Lindbergh thermal project. The 2014 reserve additions resulted in an organic reserve replacement ratio of 420 percent for total proved plus probable reserves excluding net acquisitions and dispositions.

Further details of Pengrowth’s 2014 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	2014		2013		2012		3 year weighted average
Excluding Net Acquisitions (Dispositions) (F&D)
Excluding changes in FDC
F&D costs per boe - (P+P)	$	8.03	$	10.61	$	4.44	$	7.30
Recycle ratio (1) (2)	3.2		2.3		5.3		3.4
Including changes in FDC
F&D costs per boe - (P+P)	$	22.33	$	21.96	$	16.85	$	20.22
Recycle ratio (1)	1.1		1.1		1.4		1.2

⁽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.

2014 total proved plus probable F&D cost, including changes in FDC, was $22.33/boe, staying relatively flat year over year with a slight increase from 2013.

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 2014 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 1.2.

PENGROWTH 2014 Management's Discussion and Analysis 11

Other Performance Measures	2014	2013	2012
Production per share (boe/share)	0.05	0.06	0.07
Production per debt adjusted share (boe/share) (1)	0.03	0.04	0.04
P+P reserves per share (boe/share)	1.04	0.91	1.00
P+P reserves per debt adjusted share (boe/share) (1)	0.54	0.62	0.60

⁽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, 2014 production and total proved plus probable reserves per share decreased from 2013, primarily due to increased debt resulting from the weakening of the Canadian dollar and the decrease in Pengrowth’s share price used to convert the debt to shares at December 31, 2014, offsetting the 17 percent increase in proved plus probable reserves.

PRODUCTION

	Three months ended						Twelve months ended
Daily production	Dec 31, 2014	% of total	Sept 30, 2014	% of total	Dec 31, 2013	% of total	Dec 31, 2014	% of total	Dec 31, 2013	% of total
Light oil (bbls)	19,361	27	21,359	30	22,488	29	21,228	29	27,061	32
Heavy oil (bbls)	8,299	12	8,246	11	8,369	11	8,251	11	8,355	10
Natural gas liquids (bbls)	9,381	13	9,403	13	10,476	13	10,130	14	10,476	12
Natural gas (Mcf)	208,563	48	200,786	46	216,231	47	202,076	46	231,812	46
Total boe per day	71,802		72,472		77,371		73,288		84,527

Fourth quarter of 2014 average daily production decreased 1 percent compared to the third quarter of 2014 as the effects of minor property dispositions and solution gas restrictions at Swan Hills were offset by increased Sable Island natural gas production after repairs and maintenance work was completed in the third quarter of 2014. Strong performance from the 2 well Groundbirch development program also contributed to the fourth quarter of 2014 production. Fourth quarter and full year 2014 production decreased 7 percent and 13 percent compared to the same periods last year, respectively, due to significant property dispositions in late 2013 and several minor dispositions in 2014, partly offset by production additions from the Cardium development program.

Light Oil

Fourth quarter of 2014 light oil production decreased 9 percent and 14 percent compared to the third quarter of 2014 and fourth quarter of 2013, respectively, due to several minor 2014 property dispositions coupled with solution gas restrictions in the Swan Hills area during the fourth quarter of 2014. Full year 2014 light oil production decreased 22 percent compared to 2013 due to the late 2013 property dispositions and several minor 2014 dispositions, partly offset by new production from the Cardium development program.

Heavy Oil

Fourth quarter of 2014 heavy oil production increased 1 percent compared to the third quarter of 2014 due to slightly higher production at Lindbergh and Bodo. Fourth quarter and full year 2014 heavy oil production decreased 1 percent compared to the same periods last year due to anticipated declines at the Lindbergh pilot project partly offset by higher production from a development program in the Bodo area.

NGLs

Fourth quarter of 2014 NGL production remained unchanged compared to the third quarter of 2014 but declined 10 percent compared to the fourth quarter of 2013 due to the absence of a Sable Island condensate shipment included in the fourth quarter of 2013. Full year 2014 NGL production decreased 3 percent compared to 2013 largely due to the late 2013 property dispositions partly offset by new Cardium production.

Natural Gas

Fourth quarter of 2014 natural gas production increased 4 percent compared to the third quarter of 2014 due to positive additions from the Groundbirch development program combined with less repair and maintenance downtime at Sable Island. Fourth quarter and full year 2014 natural gas production decreased 4 percent and 13 percent compared to the same periods last year, respectively, mainly as a result of the late 2013 property dispositions, partly offset by new Cardium and Groundbirch production.

PENGROWTH 2014 Management's Discussion and Analysis 12

COMMODITY PRICES

Oil and Liquids Prices Excluding Realized Commodity Risk Management

	Three months ended						Twelve months ended
(Cdn$/bbl)	Dec 31, 2014		Sept 30, 2014		Dec 31, 2013		Dec 31, 2014		Dec 31, 2013
Average Benchmark Prices
WTI oil	83.05		105.83		102.75		102.44		101.07
Edmonton par light oil	75.79		97.20		87.07		94.50		93.47
WCS heavy oil	66.85		83.84		69.07		81.03		75.14
Average Differentials to WTI
Edmonton par	(7.26	)	(8.63	)	(15.68	)	(7.94	)	(7.60	)
WCS heavy oil	(16.20	)	(21.99	)	(33.68	)	(21.41	)	(25.93	)
Average Sales Prices
Light oil	72.93		94.04		83.23		92.10		89.68
Heavy oil	61.56		78.43		61.43		75.21		67.98
Natural gas liquids	39.51		52.94		60.49		52.17		55.81

Fourth quarter of 2014 WTI crude oil price averaged Cdn$83.05/bbl, a decrease of 22 percent and 19 percent compared to the third quarter of 2014 and the fourth quarter of 2013, respectively. The rapid decline in global crude oil prices resulting from an oversupply of crude oil in late 2014 was partially mitigated by a decline in the Canadian dollar versus the U.S. dollar, as Pengrowth reports its revenues in Canadian dollars. Full year 2014 WTI crude oil price averaged Cdn$102.44/bbl, an increase of 1 percent compared to the full year 2013 price.

Fourth quarter of 2014 Edmonton par light oil differentials narrowed by 16 percent and 54 percent compared to the third quarter of 2014 and the fourth quarter of 2013, respectively. Full year 2014 light oil differentials widened by 4 percent compared to full year 2013 differentials.

Fourth quarter of 2014 WCS heavy oil differentials narrowed by 26 percent and 52 percent compared to the third quarter of 2014 and the fourth quarter of 2013, respectively. Full year 2014 heavy oil differentials narrowed by 17 percent compared to full year 2013 differentials.

Location and quality differentials, growing U.S. crude oil production as well as transportation bottlenecks are the primary drivers that move Canadian crude oil differentials to WTI. When differentials widen significantly, Pengrowth takes proactive steps to improve realizations, including transporting some crude oil by rail.

Pengrowth's fourth quarter and full year 2014 average oil and liquids sales prices moved in conjunction with the above described benchmark prices and differentials.

Natural Gas Prices Excluding Realized Commodity Risk Management

	Three months ended						Twelve months ended
(Cdn$)	Dec 31, 2014		Sept 30, 2014		Dec 31, 2013		Dec 31, 2014		Dec 31, 2013
Average Benchmark Prices
NYMEX gas (per MMBtu)	4.36		4.30		4.05		4.71		3.82
AECO monthly gas (per MMBtu)	4.01		4.22		3.15		4.42		3.16
Average Differential to NYMEX
AECO differential (per MMBtu)	(0.35	)	(0.08	)	(0.90	)	(0.29	)	(0.66	)
Average Sales Prices
Natural gas (per Mcf) (1)	4.02		4.05		3.18		4.74		3.19

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

The NYMEX natural gas benchmark price averaged Cdn$4.36/MMBtu in the fourth quarter of 2014 resulting in an increase of 1 percent and 8 percent compared to the third quarter of 2014 and the fourth quarter of 2013, respectively. Full year 2014 NYMEX price increased 23 percent compared the same period last year. The increase in prices resulted from low natural gas storage in the key consuming regions of North America in the first half of 2014 coupled with a decline in the Canadian dollar.

PENGROWTH 2014 Management's Discussion and Analysis 13

Fourth quarter of 2014 AECO gas prices averaged Cdn$4.01/MMBtu, representing a decline of 5 percent compared to the third quarter of 2014. The decline in AECO price resulted from a widening of the differential between NYMEX and AECO. Fourth quarter and full year 2014 AECO prices increased 27 percent and 40 percent compared to the same periods in 2013, respectively. Higher NYMEX and a narrowing of the differential between AECO and NYMEX were the primary drivers behind the higher AECO prices.

Fourth quarter of 2014 realized natural gas sales price of Cdn$4.02/Mcf was essentially unchanged compared to the third quarter of 2014 in spite of the AECO gas price declining 5 percent as Pengrowth also sells its natural gas at several additional sales points which yielded higher prices than AECO. Fourth quarter and full year 2014 realized natural gas sales prices increased 26 percent and 49 percent compared to the same periods in 2013, respectively, mainly due to higher natural gas benchmark prices and a narrowing of the differential between NYMEX and AECO.

Total Average Sales Prices Excluding Realized Commodity Risk Management

	Three months ended			Twelve months ended
($/boe)	Dec 31, 2014	Sept 30, 2014	Dec 31, 2013	Dec 31, 2014	Dec 31, 2013
Average sales prices	43.61	54.73	47.92	55.42	51.10
Other production income including sulphur	0.52	0.63	0.37	0.54	0.54
Total oil and gas sales	44.13	55.36	48.29	55.96	51.64

Fourth quarter of 2014 average sales price of Cdn$43.61/boe decreased 20 percent and 9 percent compared to the third quarter of 2014 and the fourth quarter of 2013, respectively, mostly due to declines in crude oil benchmark prices. Full year 2014 average sales price increased 8 percent compared to full year 2013, as stronger benchmark prices from the first half of 2014 outweighed the rapid decline in prices seen in the fourth quarter of 2014.

Commodity Risk Management Gains (Losses)

	Three months ended						Twelve months ended
($ millions except per unit amounts)	Dec 31, 2014		Sept 30, 2014		Dec 31, 2013		Dec 31, 2014		Dec 31, 2013
Realized
Oil risk management	24.3		(23.9	)	(17.5	)	(66.5	)	(60.5	)
$/bbl (1)	9.55		(8.77	)	(6.16	)	(6.18	)	(4.68	)
Natural gas risk management	(2.6	)	(4.7	)	1.8		(29.6	)	5.5
$/Mcf	(0.14	)	(0.25	)	0.09		(0.40	)	0.07
Total realized gain (loss)	21.7		(28.6	)	(15.7	)	(96.1	)	(55.0	)
$/boe	3.29		(4.29	)	(2.21	)	(3.60	)	(1.78	)
Unrealized
Unrealized commodity risk management assets (liabilities) at period end	421.1		(84.2	)	(80.0	)	421.1		(80.0	)
Less: Unrealized commodity risk management assets (liabilities) at beginning of period	(84.2	)	(205.8	)	(40.9	)	(80.0	)	7.0
Unrealized gain (loss) on commodity risk management contracts for the period	505.3		121.6		(39.1	)	501.1		(87.0	)

⁽¹⁾  Includes light and heavy oil.

Pengrowth has an active commodity risk management program which primarily uses forward price swaps and puts to manage the exposure to commodity price fluctuations and provide a measure of stability and predictability to cash flows. Changes in the business environment are regularly monitored by management and the Board of Directors to ensure that Pengrowth's active risk management program is adequate and aligned with the long term strategic goals of the Corporation. Managing cash flow was of particular importance in 2014 as significant cash was required to complete the first commercial phase of Lindbergh. In addition to forward price swaps and puts, Pengrowth also engages in oil price differential swaps using a combination of financial and physical contracts.

Realized commodity risk management gains and 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 contracts. Realized losses result when the average fixed risk management contracted price is lower than the benchmark prices, while realized gains are recorded when the average fixed risk

PENGROWTH 2014 Management's Discussion and Analysis 14

management contracted price is higher than the benchmark prices at settlement. Realized gains and losses are settled monthly and directly impact cash flow for the period.

As per the table above, realized commodity risk management gains were recorded in the fourth quarter of 2014 compared to losses in the third quarter of 2014 and the fourth quarter of 2013 primarily resulting from a decline in the oil benchmark price. Full year 2014 realized commodity risk management losses increased compared to the same period last year mainly due to a rise in natural gas benchmark prices year over year.

Unrealized gains and losses also vary period to period and are a function of the volumes under risk management contracts, the fixed prices of those risk management contracts and the forward curvepricing for the commodities under risk management contracts at the end of the period. Unrealized losses result when the forward price curve moves higher 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. Unrealized commodity risk management gains and losses do not impact cash flow for the period.

Forward Contracts - Commodity and Power Risk Management

The following table provides a summary of the fixed prices of the commodity and power risk management contracts in place at December 31, 2014 (see Note 17 to the audited Consolidated Financial Statements for more information on Pengrowth's risk management contracts):

Crude Oil Swaps and Puts
Reference point	Yearly average volume (bbl/d)	Year	% of total 2015 oil production Guidance (1)	Price/bbl ($Cdn)
WTI	26,000	2015	75%	93.99
WTI	19,482	2016	56%	90.39
Natural Gas Swaps and Puts
Reference point	Yearly average volume (MMBtu/d)	Year	% of 2015 natural gas production Guidance	Price/MMBtu ($Cdn)
AECO & NGI Chicago Index	86,279	2015	46%	3.84
AECO	37,887	2016	20%	3.79
AECO	21,877	2017	12%	4.01
AECO	4,739	2018	3%	3.89
Power
Reference point	Yearly average volume (MW)	Year	% of estimated power purchases	Price/MWh ($Cdn)
AESO	40	2015	79%	49.53
AESO	10	2016	15%	50.00

⁽¹⁾  Includes light and heavy crude oil. After the successful 2013 divestment program, 2015 oil risk management contracts represent over 65 percent of 2015 production Guidance. Pengrowth's Board of Directors has approved the retention of the risk management contracts already in place.

In addition to the above table, Pengrowth has financial and physical contracts to manage oil price differentials. See Note 17 to the audited Consolidated Financial Statements for more information.

PENGROWTH 2014 Management's Discussion and Analysis 15

Commodity and Power Price Sensitivity on Risk Management Contracts as at December 31, 2014

($ millions)
Oil	Cdn$1/bbl increase in future oil prices		Cdn$1/bbl decrease in future oil prices
Unrealized pre-tax gain (loss) on oil risk management	(16.5	)	16.5
Natural gas	Cdn$0.25/MMBtu increase in future natural gas prices		Cdn$0.25/MMBtu decrease in future natural gas prices
Unrealized pre-tax gain (loss) on natural gas risk management	(13.6	)	13.5
Power	Cdn$1/MWh increase in future power prices		Cdn$1/MWh decrease in future power prices
Unrealized pre-tax gain (loss) on power risk management	0.4		(0.4	)

The changes in fair value of the forward risk management contracts directly affect reported net income (loss) through the unrealized amounts recorded in the Consolidated 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, 2014, revenue and cash flow would have been $421.1 million higher 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 $421.1 million is composed of assets of $292.3 million relating to risk management contracts expiring within one year and assets of $128.8 million relating to risk management contracts expiring beyond one year.

Pengrowth has not designated any outstanding commodity risk management contracts as hedges for accounting purposes and therefore records these risk management contracts on the Consolidated Balance Sheets at their fair value and recognizes changes in fair value on the Consolidated 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 Consolidated 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 (income) expense.

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 purchases as follows:

Forward Period	Percent of Estimated Production	Percent of Estimated Power Purchases
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%

As a result of the successful 2013 divestment program, 2015 oil risk management contracts represent over 65 percent of 2015 production Guidance. Pengrowth's Board of Directors approved the retention of the risk management contracts already in place.

PENGROWTH 2014 Management's Discussion and Analysis 16

OIL AND GAS SALES EXCLUDING REALIZED COMMODITY RISK MANAGEMENT

Contribution Analysis

The following table shows the contribution of each product category to oil and gas sales:

	Three months ended						Twelve months ended
($ millions except percentages)	Dec 31, 2014	% of total	Sept 30, 2014	% of total	Dec 31, 2013	% of total	Dec 31, 2014	% of total	Dec 31, 2013	% of total
Light oil	129.9	45	184.8	50	172.2	50	713.6	48	885.8	56
Heavy oil	47.0	16	59.5	16	47.3	14	226.5	15	207.3	13
Natural gas liquids	34.1	12	45.8	13	58.3	17	192.9	13	213.4	13
Natural gas	77.1	26	74.8	20	63.3	18	349.4	23	270.0	17
Other income including sulphur	3.4	1	4.2	1	2.6	1	14.5	1	16.9	1
Total oil and gas sales (1)	291.5		369.1		343.7		1,496.9		1,593.4

⁽¹⁾  Excluding realized commodity risk management.

Price and Volume Analysis

Quarter ended December 31, 2014 versus Quarter ended September 30, 2014

The following table illustrates the effect of changes in prices and volumes on the components of oil and gas sales:

($ millions)	Light oil		Heavy oil		NGLs		Natural gas		Other (2)		Total
Quarter ended September 30, 2014 (1)	184.8		59.5		45.8		74.8		4.2		369.1
Effect of change in product prices and differentials	(37.6	)	(12.9	)	(11.6	)	(0.6	)	—		(62.7	)
Effect of change in sales volumes	(17.3	)	0.4		(0.1	)	2.9		—		(14.1	)
Other	—		—		—		—		(0.8	)	(0.8	)
Quarter ended December 31, 2014 (1)	129.9		47.0		34.1		77.1		3.4		291.5

⁽¹⁾  Excluding realized commodity risk management.

⁽²⁾  Primarily sulphur sales.

Light oil sales decreased 30 percent in the fourth quarter of 2014 compared to the third quarter of 2014 resulting from a decrease in the Edmonton par light oil benchmark price combined with lower sales volumes due to minor property dispositions and temporary solution gas restrictions in the Swan Hills area. Heavy oil sales decreased 21 percent in response to a decrease in the WCS benchmark. NGL sales decreased 26 percent driven by lower prices in the fourth quarter of 2014. Natural gas sales increased 3 percent in response to higher sales volumes from the Groundbirch development program combined with less downtime at Sable Island.

Quarter ended December 31, 2014versus Quarter endedDecember 31, 2013

The following table illustrates the effect of changes in prices and volumes on the components of oil and gas sales:

($ millions)	Light oil		Heavy oil		NGLs		Natural gas		Other (2)	Total
Quarter ended December 31, 2013 (1)	172.2		47.3		58.3		63.3		2.6	343.7
Effect of change in product prices and differentials	(18.4	)	0.1		(18.1	)	16.0		—	(20.4	)
Effect of change in sales volumes	(23.9	)	(0.4	)	(6.1	)	(2.2	)	—	(32.6	)
Other	—		—		—		—		0.8	0.8
Quarter ended December 31, 2014 (1)	129.9		47.0		34.1		77.1		3.4	291.5

⁽¹⁾  Excluding realized commodity risk management.

⁽²⁾  Primarily sulphur sales.

Light oil sales decreased 25 percent in the fourth quarter of 2014 compared to the same period in 2013 due to lower volumes from several minor 2014 property dispositions and temporary solution gas restrictions in the Swan Hills area coupled with a decrease in the Edmonton par light oil price. Heavy oil sales were essentially unchanged. NGL sales decreased 42 percent driven by lower prices compared to the same period last year. Natural gas sales increased 22 percent due to higher natural gas benchmark prices year over year.

PENGROWTH 2014 Management's Discussion and Analysis 17

Twelve Months ended December 31, 2014versusTwelve Months ended December 31, 2013

The following table illustrates the effect of changes in prices and volumes on the components of oil and gas sales:

($ millions)	Light oil		Heavy oil		NGLs		Natural gas		Other (2)		Total
Twelve months ended December 31, 2013 (1)	885.8		207.3		213.4		270.0		16.9		1,593.4
Effect of change in product prices and differentials	18.7		21.8		(13.5	)	114.0		—		141.0
Effect of change in sales volumes	(190.9	)	(2.6	)	(7.0	)	(34.6	)	—		(235.1	)
Other	—		—		—		—		(2.4	)	(2.4	)
Twelve months ended December 31, 2014 (1)	713.6		226.5		192.9		349.4		14.5		1,496.9

⁽¹⁾  Excluding realized commodity risk management.

⁽²⁾  Primarily sulphur sales.

Full year 2014 light oil sales decreased 19 percent compared to 2013 due to lower sales volumes relating to the late 2013 disposition program in addition to several minor 2014 property dispositions partly offset by an increase in the Edmonton par light oil price year over year. Heavy oil sales increased 9 percent resulting from an improvement in the WCS benchmark price. NGL sales decreased 10 percent impacted by lower pentane and butane prices in 2014 coupled with lower volumes. Natural gas sales increased 29 percent due to higher natural gas benchmark prices partly offset by lower sales volumes from the late 2013 property dispositions and natural declines.

ROYALTY EXPENSES

($ millions except per boe amounts and percentages)	Three months ended			Twelve months ended
	Dec 31, 2014	Sept 30, 2014	Dec 31, 2013	Dec 31, 2014	Dec 31, 2013
Royalty expenses	51.2	65.5	62.8	268.6	275.1
$/boe	7.75	9.83	8.82	10.04	8.92
Royalties as a percent of oil and gas sales (%) (1)	17.6	17.7	18.3	17.9	17.3

⁽¹⁾  Excluding realized commodity risk management.

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

Fourth quarter of 2014 royalties as a percentage of sales remained consistent with the third quarter of 2014. Fourth quarter of 2014 royalties as a percentage of sales decreased to 17.6 percent from 18.3 percent in the fourth quarter of 2013 mainly due to lower Sable Island royalties and lower freehold royalties. Full year 2014 royalties as a percentage of sales increased to 17.9 percent from 17.3 percent in 2013 impacted by an increase in natural gas reference prices and unfavourable gas cost allowance adjustments recorded in 2014.

OPERATING EXPENSES

($ millions except per boe amounts)	Three months ended			Twelve months ended
	Dec 31, 2014	Sept 30, 2014	Dec 31, 2013	Dec 31, 2014	Dec 31, 2013
Operating expenses	94.5	102.4	109.2	415.4	482.5
$/boe	14.31	15.36	15.34	15.53	15.64

Fourth quarter of 2014 operating expenses decreased $7.9 million or 8 percent compared to the third quarter of 2014 primarily due to lower power and turnaround costs combined with lower costs as a result of minor asset sales during the third quarter of 2014. On a per boe basis, fourth quarter of 2014 operating expenses decreased $1.05/boe as a result of the lower expenses, as mentioned above.

Fourth quarter of 2014 operating expenses decreased $14.7 million or 13 percent compared to the fourth quarter of 2013 primarily due to lower power, processing and gathering fees and from minor asset sales during the third quarter of 2014. On a per boe basis, fourth quarter of 2014 operating expenses decreased $1.03/boe compared to the fourth quarter of 2013 due to the above mentioned cost decreases partly offset by reduced production.

Full year 2014 operating expenses decreased $67.1 million or 14 percent due to the absence of operating expenses from properties divested throughout 2013 and 2014 as well as lower power costs, partly offset by increased turnaround costs in 2014. On a per boe basis, 2014 operating expenses decreased $0.11/boe compared to 2013 driven by lower costs partly offset by reduced production resulting mainly from the 2013 and 2014 dispositions.

PENGROWTH 2014 Management's Discussion and Analysis 18

TRANSPORTATION EXPENSES

($ millions except per boe amounts)	Three months ended			Twelve months ended
	Dec 31, 2014	Sept 30, 2014	Dec 31, 2013	Dec 31, 2014	Dec 31, 2013
Transportation expenses	8.7	6.5	7.8	30.8	29.4
$/boe	1.32	0.97	1.10	1.15	0.95

Fourth quarter of 2014 transportation expenses increased $2.2 million or 34 percent compared to the third quarter of 2014. During the fourth quarter of 2014, Pengrowth commenced directly marketing and delivering natural gas to the Chicago sales point using Pengrowth's existing Alliance pipeline capacity. Previously, Pengrowth's Alliance pipeline capacity was managed by a third party. Although Pengrowth's transportation expense increased, the realized natural gas price also increased. In addition, higher trucking costs at various locations also contributed to the increase in transportation expenses in the fourth quarter of 2014. On a per boe basis, fourth quarter of 2014 transportation expenses increased $0.35/boe compared to the third quarter of 2014 driven by increased transportation expenses, as described above.

Fourth quarter of 2014 transportation expenses increased $0.9 million or 12 percent compared to the fourth quarter of 2013 also resulting from moving natural gas directly into the Chicago market. On a per boe basis, fourth quarter of 2014 transportation expenses increased $0.22/boe compared to the same period last year due to higher transportation costs and lower production volumes.

Full year 2014 transportation expenses increased $1.4 million or 5 percent compared to 2013 mainly due to higher sales product trucking costs at Lochend. During the second half of 2014, pipeline infrastructure development was completed at Lochend. Also contributing to higher transportation costs in 2014 was the direct use by Pengrowth of its Alliance pipeline capacity as described above; where prior to the fourth quarter of 2014, the Alliance connected gas was sold at the wellhead, thereby not incurring transportation expenses. On a per boe basis, 2014 transportation costs increased $0.20/boe compared to 2013 due to the increase in transportation expenses combined with a decrease in production volumes.

Pengrowth incurs transportation expenses 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 also incurs transportation expenses on its oil and NGL production including sales product trucking costs and pipeline costs up to the custody transfer point. Pengrowth has elected to sell approximately 70 percent of its crude oil at market points beyond the wellhead, incurring transportation costs prior to custody transfer points. The transportation expenses are dependent upon third party rates and the distance the product travels prior to changing ownership or custody.

PENGROWTH 2014 Management's Discussion and Analysis 19

OPERATING NETBACKS

Pengrowth’s operating netbacks have been calculated by taking balances directly from the Consolidated Statements of Income (Loss) and dividing by production. Certain assumptions have been made in allocating operating expenses and royalty injection credits between products. 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 ($/boe)	Dec 31, 2014		Sept 30, 2014		Dec 31, 2013		Dec 31, 2014		Dec 31, 2013
Oil & gas sales (includes other income)	44.13		55.36		48.29		55.96		51.64
Royalties	(7.75	)	(9.83	)	(8.82	)	(10.04	)	(8.92	)
Operating expenses	(14.31	)	(15.36	)	(15.34	)	(15.53	)	(15.64	)
Transportation expenses	(1.32	)	(0.97	)	(1.10	)	(1.15	)	(0.95	)
Operating netback before realized commodity risk management	20.75		29.20		23.03		29.24		26.13
Realized commodity risk management	3.29		(4.29	)	(2.21	)	(3.60	)	(1.78	)
Operating netback	24.04		24.91		20.82		25.64		24.35
Light Oil Netback Excluding Realized Commodity Risk Management ($/bbl)
Sales	72.93		94.04		83.23		92.10		89.68
Royalties	(17.71	)	(19.91	)	(19.84	)	(19.96	)	(18.71	)
Operating expenses	(15.78	)	(15.99	)	(16.57	)	(15.80	)	(17.04	)
Transportation expenses	(2.18	)	(1.65	)	(2.22	)	(2.10	)	(1.65	)
Light oil operating netback	37.26		56.49		44.60		54.24		52.28
Heavy Oil Netback Excluding Realized Commodity Risk Management ($/bbl)
Sales	61.56		78.43		61.43		75.21		67.98
Royalties	(10.58	)	(13.09	)	(9.90	)	(11.71	)	(9.79	)
Operating expenses	(19.97	)	(16.80	)	(17.36	)	(18.58	)	(18.97	)
Transportation expenses	(1.64	)	(1.67	)	(1.36	)	(1.74	)	(1.62	)
Heavy oil operating netback	29.37		46.87		32.81		43.18		37.60
NGLs Netback Excluding Realized Commodity Risk Management ($/bbl)
Sales	39.51		52.94		60.49		52.17		55.81
Royalties	(9.19	)	(14.38	)	(15.47	)	(14.61	)	(15.33	)
Operating expenses	(13.40	)	(15.53	)	(14.30	)	(15.28	)	(15.03	)
Transportation expenses	—		—		(0.01	)	—		(0.05	)
NGLs operating netback	16.92		23.03		30.71		22.28		25.40
Natural Gas Netback Excluding Realized Commodity Risk Management ($/Mcf)
Sales	4.02		4.05		3.18		4.74		3.19
Royalties (1)	(0.19	)	(0.22	)	0.04		(0.33	)	(0.02	)
Operating expenses	(2.06	)	(2.43	)	(2.39	)	(2.45	)	(2.35	)
Transportation expenses	(0.20	)	(0.11	)	(0.11	)	(0.13	)	(0.09	)
Natural gas operating netback ($/Mcf)	1.57		1.29		0.72		1.83		0.73
Natural gas operating netback ($/boe)	9.42		7.74		4.32		10.98		4.38
CONTRIBUTION BASED ON OPERATING NETBACKS
Light oil	50	%	58	%	57	%	55	%	65	%
Heavy oil	17	%	19	%	16	%	17	%	15	%
Natural gas liquids	11	%	10	%	18	%	11	%	12	%
Natural gas	22	%	13	%	9	%	17	%	8	%

⁽¹⁾  Fourth quarter of 2013 contains a favourable prior period adjustment.

PENGROWTH 2014 Management's Discussion and Analysis 20

Pengrowth realized a weighted average operating netback of $24.04/boe in the fourth quarter of 2014 representing a 3 percent decrease compared to the third quarter of 2014 primarily due to lower benchmark prices partly offset by realized risk management gains instead of losses and lower royalties and operating expenses. When comparing the fourth quarter of 2014 to the same period last year, the operating netback increased 15 percent mainly driven by realized risk management gains instead of losses and lower royalties and operating expenses.

Full year 2014 operating netback increased 5 percent compared to 2013 resulting mainly from higher benchmark prices year over year.

GENERAL AND ADMINISTRATIVE EXPENSES

	Three months ended			Twelve months ended
($ millions except per boe amounts)	Dec 31, 2014	Sept 30, 2014	Dec 31, 2013	Dec 31, 2014	Dec 31, 2013
Cash G&A expenses	21.2	20.6	21.7	84.3	87.8
$/boe	3.21	3.09	3.05	3.15	2.85
Non-cash G&A expenses	2.6	5.0	2.5	16.0	15.0
$/boe	0.39	0.75	0.35	0.60	0.48
Total G&A	23.8	25.6	24.2	100.3	102.8
$/boe	3.60	3.84	3.40	3.75	3.33

Fourth quarter of 2014 cash G&A expenses were $0.6 million or $0.12/boe higher compared to the third quarter of 2014 mainly due to year end reserve reporting fees.

Fourth quarter of 2014 cash G&A expenses decreased $0.5 million compared to the same period last year resulting primarily from lower personnel costs. On a per boe basis, fourth quarter of 2014 cash G&A expenses increased $0.16/boe compared to the same period last year primarily due to the impact of lower production volumes in 2014 partly offset by lower costs.

Full year 2014 cash G&A expenses were $3.5 million lower compared to 2013 due to staffing decreases associated with the 2013 dispositions as well as lower office rent. On a per boe basis, 2014 cash G&A expenses increased $0.30/boe due to lower production volumes partly offset by lower expenses, as discussed above.

The non-cash component of G&A represents the compensation expenses associated with Pengrowth’s Long Term Incentive Plan ("LTIP"). See Note 13 to the audited Consolidated Financial Statements for additional information. The compensation costs associated with this plan are expensed over the applicable vesting periods.

Fourth quarter of 2014 non-cash G&A expenses decreased $2.4 million compared to the third quarter of 2014 resulting from a lower performance multiplier on previously expensed grants. Fourth quarter of 2014 non-cash G&A expenses remained relatively unchanged compared to the same period last year.

Full year 2014 non-cash G&A expenses increased $1.0 million compared to 2013 due to slightly higher long term incentive plan grants in 2014.

During 2014, $14.7 million (2013 - $16.0 million) of directly attributable G&A costs were capitalized to Property, Plant and Equipment ("PP&E").

UNREALIZED LOSS ON INVESTMENTS

Pengrowth owns 1.0 million shares of a private corporation with an estimated fair value of $nil at December 31, 2014. The fair value is based in part on the lack of success of recent private placement equity offerings by the private company.

As the fair value at December 31, 2014 was estimated to be $nil (December 31, 2013 - $5 million) Pengrowth recorded an unrealized loss of $5 million in 2014 (2013 - $15 million loss). See Note 4 to the audited Consolidated Financial Statements for additional information.

PENGROWTH 2014 Management's Discussion and Analysis 21

DEPLETION, DEPRECIATION, AMORTIZATION AND ACCRETION

	Three months ended			Twelve months ended
($ millions except per boe amounts)	Dec 31, 2014	Sept 30, 2014	Dec 31, 2013	Dec 31, 2014	Dec 31, 2013
Depletion, depreciation and amortization	127.7	128.5	130.7	517.0	574.6
$/boe	19.33	19.27	18.36	19.33	18.62
Accretion	4.4	4.5	4.9	18.8	20.5
$/boe	0.67	0.67	0.69	0.70	0.66

Fourth quarter of 2014 DD&A expense decreased $0.8 million and $3.0 million compared to the third quarter of 2014 and fourth quarter of 2013, respectively, mainly due to the decrease in production volumes related to several minor 2014 property dispositions.

Full year 2014 DD&A expense decreased $57.6 million compared to 2013 due to lower production volumes related to the 2013 property dispositions and several minor 2014 property dispositions.

Fourth quarter of 2014 accretion expense remained relatively unchanged compared to the third quarter of 2014. Fourth quarter and full year 2014 accretion expense decreased $0.5 million and $1.7 million compared to the same periods last year, respectively, mainly due to decreases in the ARO liability resulting from property dispositions and discount rate changes.

EXPLORATION AND EVALUATION ASSETS ("E&E")

Pengrowth's E&E assets consist of exploration and development projects which are pending the determination of proved plus probable reserves and production. During the fourth quarter of 2014, Pengrowth acquired 32.6 gross/net sections of prospective liquids-rich Montney lands at Bernadet in north eastern British Columbia. The vast majority of the $490.1 million of E&E assets on the Consolidated Balance Sheets relate to the Groundbirch and Bernadet areas in north eastern British Columbia. See Note 6 of the audited Consolidated Financial Statements for more information.

IMPAIRMENTS

	Three months ended			Twelve months ended
($ millions)	Dec 31, 2014	Sept 30, 2014	Dec 31, 2013	Dec 31, 2014	Dec 31, 2013
PP&E impairment	486.3	—	—	486.3	—
E&E impairment	57.0	—	—	57.0	—
Goodwill impairment	451.3	—	—	451.3	—
Total impairment	994.6	—	—	994.6	—

PP&E 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. In light of a significant and rapid decline in oil benchmark prices in the fourth quarter of 2014 and continued softening in natural gas prices, impairment tests were carried out on all CGUs at December 31, 2014, resulting in a $486.3 million PP&E impairment on three CGUs at December 31, 2014. The impairment tests carried out were based on reserve values using pre-tax discount rates of 10 - 15 percent - varying from CGU to CGU (December 31, 2013: 8 - 15 percent), January 1, 2015 independent reserves evaluator's forecast pricing and an inflation rate of 2 percent. The recoverable amount of each CGU was determined using fair value less costs to sell.

All CGUs were negatively impacted by a downturn in the forward benchmark prices and those CGUs that previously used a discount rate of 8 percent were further impacted by the move to a discount rate of 10 percent in calculating the present value of the associated reserves. The increase in discount rate reflects the increased market uncertainty facing Western Canadian oil and gas companies.

The impairments noted above were recorded on the Consolidated Statements of Income (Loss) at December 31, 2014 and may be reversed, excluding goodwill, if and when the fair values of the CGUs increase in the future periods. However, the impairment test is sensitive to lower commodity prices, which have been under significant downward pressure recently. Further declines in commodity prices could result in additional impairment charges if the recoverable

PENGROWTH 2014 Management's Discussion and Analysis 22

values are further eroded by price decreases. See Note 5 to the audited Consolidated Financial Statements for additional information.

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. No impairment was recognized on any of the CGUs tested at December 31, 2013.

Exploration and Evaluation Impairments

In conjunction with the Montney CGU, Pengrowth evaluated its Groundbirch project for an impairment. This was in accordance with Pengrowth's policy and IFRS which states that the impairment of ongoing E&E projects should be assessed on the cash flow from the applicable CGUs in the operating segment. It was determined that the recoverable amount was below the carrying amount, thus a $57.0 million impairment on the Groundbirch E&E asset was recorded at December 31, 2014.

The recoverable amount is generally computed by reference to the present value of the future cash flows expected to be derived from production of proved plus probable reserves for the operating segment. Undeveloped land and contingent resources were also considered in the recoverable amount. Changes in forward price estimates, production costs or recovery rates may change the economic status of contingent resources and may ultimately result in contingent resources being restated. The Groundbirch E&E impairment test was based on reserve values using a pre-tax discount rate of 10 percent; independent reserves evaluator January 1, 2015 forecast pricing and an inflation rate of 2 percent; and contingent resources using a pre-tax discount rate of 12 percent. See Notes 5 and 6 to the audited Consolidated Financial Statements for more information.

An impairment test was performed on January 1, 2013 upon transfer of the Lindbergh Project to PP&E. The net present value of the proved plus probable reserves, as determined by the external reserve evaluator, supported the carrying value of the Lindbergh Project, and as such, no impairment was required.

Goodwill Impairments

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 and E&E.

At December 31, 2014, impairment tests were performed, which resulted in a $451.3 million impairment of goodwill to both CGU specific and groups of CGUs goodwill. All CGUs were negatively impacted by a downturn in the forward benchmark prices, and several CGUs were impacted by increasing the discount rate from 8 to 10 percent for present valuing the reserves. See Note 7 to the audited Consolidated Financial Statements for more information.

As at December 31, 2014, Pengrowth has remaining goodwill of $202.2 million (December 31, 2013 - $672.7 million) which is not specific to any CGU. In addition to the $451.3 million in impairment charges, several minor 2014 property dispositions resulted in a $19.2 million decrease in goodwill in 2014 (2013 - $28.0 million).

At December 31, 2013, an impairment test was performed with no impairments to goodwill recorded.

INTEREST AND FINANCING CHARGES

	Three months ended						Twelve months ended
($ millions)	Dec 31, 2014		Sept 30, 2014		Dec 31, 2013		Dec 31, 2014		Dec 31, 2013
Interest and financing charges	27.6		26.0		24.6		105.6		100.2
Capitalized interest	(9.9	)	(8.8	)	(3.3	)	(31.0	)	(6.1	)
Total interest and financing charges	17.7		17.2		21.3		74.6		94.1

At December 31, 2014, Pengrowth had approximately $1.8 billion in total long term debt composed of $1.5 billion of fixed rate debt, $0.2 billion in term credit facility and $0.1 billion in convertible debentures. Total long term debt consists primarily of U.S. dollar denominated fixed rate notes at a weighted average interest rate of 5.7 percent. The term credit facility had an average 3.8 percent interest rate and convertible debentures have a 6.25 percent coupon.

Fourth quarter of 2014 interest and financing charges, before capitalized interest, increased $1.6 million and $3.0 million compared to the third quarter of 2014 and fourth quarter of 2013, respectively, from borrowing on the term credit facility in the fourth quarter of 2014 and higher interest expense on U.S. term debt resulting from the weakening of the Canadian Dollar.

PENGROWTH 2014 Management's Discussion and Analysis 23

Full year 2014 interest and financing charges, before capitalized interest, increased $5.4 million compared to 2013 mainly due to higher interest expense on the U.S. and U.K. term debt as a result of the weaker Canadian dollar relative to last year.

In accordance with IFRS, interest is capitalized for qualifying assets in the construction phase based on costs incurred on the project and the average cost of borrowing. During the year ended December 31, 2014, $31.0 million (December 31, 2013 - $6.1 million) of interest was capitalized on the Lindbergh thermal project to PP&E using a capitalization rate of 5.7 percent (December 31, 2013 - 5.7 percent). Pengrowth anticipates to cease capitalizing interest on the first phase of Lindbergh in the first half of 2015.

OTHER (INCOME) EXPENSE

Full year 2014 other expense of $19.3 million includes a $22.6 million provision for clean-up and remediation costs at a northern Alberta oil property incurred in the first quarter of 2014 partly offset by gains on remediation trust funds and interest income.

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 recovery of $14.4 million in the fourth quarter of 2014 compared to a deferred tax expense of $32.6 million in the third quarter of 2014 and a deferred tax recovery of $18.6 million in the fourth quarter of 2013. Full year 2014 deferred tax recovery amounted to $20.4 million compared to $73.2 million recorded in 2013.

No current income taxes were paid by Pengrowth in 2014 or 2013. See Note 11 to the audited Consolidated Financial Statements for additional information.

PENGROWTH 2014 Management's Discussion and Analysis 24

FOREIGN CURRENCY GAINS (LOSSES)

	Three months ended						Twelve months ended
($ millions)	Dec 31, 2014		Sept 30, 2014		Dec 31, 2013		Dec 31, 2014		Dec 31, 2013
Currency exchange rate ($1Cdn = $U.S.) at period end	0.86		0.89		0.94		0.86		0.94
Unrealized foreign exchange loss on U.S. dollar denominated debt	(47.9	)	(63.9	)	(39.9	)	(114.9	)	(83.4	)
Unrealized foreign exchange gain (loss) on U.K. pound sterling denominated debt	0.5		0.7		(6.1	)	(2.9	)	(9.4	)
Total unrealized foreign exchange loss from translation of foreign denominated debt	(47.4	)	(63.2	)	(46.0	)	(117.8	)	(92.8	)
Unrealized gain on U.S. foreign exchange risk management contracts	17.3		20.8		12.0		34.9		21.0
Unrealized gain (loss) on U.K. foreign exchange risk management contracts	0.3		(0.3	)	5.8		3.9		8.8
Total unrealized gain on foreign exchange risk management contracts	17.6		20.5		17.8		38.8		29.8
Total unrealized foreign exchange loss	(29.8	)	(42.7	)	(28.2	)	(79.0	)	(63.0	)
Total realized foreign exchange gain (loss)	(0.3	)	0.8		(0.2	)	(1.0	)	1.1

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 the amount of debt denominated in a foreign currency.

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. dollar 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, 2014, the fair value of these foreign exchange derivative contracts was an asset of $58.0 million included on the Consolidated Balance Sheets with changes in the fair value between Balance Sheet dates reported on the Consolidated Statements of Income (Loss) as an unrealized foreign exchange (gain) loss.

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	50.0	70	%	0.98
Swap	July 2017	400.0	250.0	63	%	0.97
Swap	August 2018	265.0	125.0	47	%	0.96
Swap	October 2019	35.0	15.0	43	%	0.94
Swap	May 2020	115.5	20.0	17	%	0.95
No contracts	October 2022	105.0	—	—		—
No contracts	October 2024	195.0	—	—		—
		1,187.0	460.0	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)
50.0	December 2015	0.50
15.0	October 2019	0.63

PENGROWTH 2014 Management's Discussion and Analysis 25

At December 31, 2014, the fair value of these foreign exchange derivative contracts was a liability of $7.2 million included on the Consolidated Balance Sheets with changes in the fair value between Balance Sheet dates reported on the Consolidated Statements of Income (Loss) as an unrealized foreign exchange (gain) loss.

At December 31, 2014, 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 - NET PRESENT VALUE

($ millions)	Dec 31, 2014		Dec 31, 2013		Change
ARO, opening balance	606.2		868.9		(262.7	)
Revisions due to discount rate changes (1)	211.5		(195.0	)	406.5
Expenditures on remediation	(22.9	)	(29.6	)	6.7
ARO on dispositions	(66.5	)	(84.0	)	17.5
Accretion and other	52.5		45.9		6.6
ARO, closing balance	780.8		606.2		174.6

⁽¹⁾  2014 amount relates to change in the discount rate from 3.25 percent to 2.3 percent. 2013 amount relates to change in the discount rate from 2.5 percent to 3.25 percent. 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.

2014 ARO liability increased $174.6 million mainly due to a change in the risk free discount rate from 3.25 percent at December 31, 2013 to 2.3 percent at December 31, 2014 which increased the liability by $211.5 million. The rate decrease reflects a decrease in the 30 year Canadian Government long term bond rate which drives Pengrowth’s estimate of the ARO discount rate. Partly offsetting this upward revision were several minor 2014 property dispositions which decreased the ARO liability by $66.5 million.

Pengrowth has estimated the net present value of its total ARO to be $780.8 million as at December 31, 2014 (December 31, 2013 – $606.2 million), based on a total escalated future liability of $2.0 billion (December 31, 2013 – $2.1 billion). The majority of the costs are expected to be incurred between 2038 and 2079. A risk free discount rate of 2.3 percent per annum and an ARO specific inflation rate of 1.5 percent were used to calculate the net present value of the ARO at December 31, 2014.

REMEDIATION TRUST FUNDS AND REMEDIATION AND ABANDONMENT EXPENSE

During 2014, Pengrowth contributed $5.0 million (December 31, 2013 - $4.6 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 $60.4 million at December 31, 2014 (December 31, 2013 - $54.7 million).

Pengrowth has a contractual obligation to make contributions to a remediation trust fund that is used to cover certain ARO on its Judy Creek properties in the Swan Hills area. Pengrowth makes monthly contributions to the fund of $0.10/boe of production from the Judy Creek properties and an annual lump sum contribution of $0.25 million.

Pengrowth has a contractual obligation to make contributions to a remediation trust fund that will be used to fund the ARO of the Sable Island properties and facilities. Since 2007, Pengrowth made a monthly contribution to the fund at a rate of $0.52/MMBtu of its share of natural gas production and $1.04/bbl of its share of natural gas liquids production from Sable Island. Starting in January 2015, the new rates are $4.17/MMBtu of its share of natural gas production and $8.36/bbl of its share of natural gas liquids production.

See Note 4 to the audited Consolidated Financial Statements for additional information.

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, 2014, Pengrowth spent $22.9 million on abandonment and reclamation (December 31, 2013 - $29.6 million). Pengrowth expects to spend approximately $25 million in 2015 on reclamation and abandonment, excluding contributions to remediation trust funds and orphan well levies from the Alberta Energy Regulator.

PENGROWTH 2014 Management's Discussion and Analysis 26

CLIMATE CHANGE PROGRAMS

Effective July 1, 2007, Alberta regulates Greenhouse Gas ("GHG") emissions under the Climate Change and Emissions Management Act of 2007. 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 will report 2014 emission reduction information on these facilities by March 31, 2015, as scheduled. It is anticipated that the Olds Gas Plant and the Judy Creek Gas Conservation Plant will achieve the reduction targets for 2014, however the Quirk Creek Gas Plant is not expected to achieve the reduction target. During 2014, Pengrowth purchased approximately $0.7 million of Emission Performance Credits payable to the Alberta Climate Change and Emissions Management Fund relating to the 2013 Quirk Creek Gas Plant emissions reporting.

ACQUISITIONS AND DISPOSITIONS

	Three months ended						Twelve months ended
($ millions)	Dec 31, 2014		Sept 30, 2014		Dec 31, 2013		Dec 31, 2014		Dec 31, 2013
Property acquisitions	1.2		13.7		12.1		17.0		16.0
Proceeds on property dispositions	(21.0	)	(43.0	)	(41.3	)	(84.5	)	(993.7	)
Net cash acquisitions (dispositions)	(19.8	)	(29.3	)	(29.2	)	(67.5	)	(977.7	)

During 2014, Pengrowth successfully closed several minor non-core property dispositions for aggregate net proceeds of $84.5 million resulting in pre-tax gains of $23.3 million. Pengrowth also completed several minor asset acquisitions for $17.0 million, excluding the $123.6 million land acquisition at Bernadet which is reflected in capital spending.

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, resulting in pre-tax losses of $175.7 million. The proceeds were used to pay down the term credit facility in 2013 and fund the first commercial phase of Lindbergh.

WORKING CAPITAL

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

At December 31, 2014, Pengrowth had a working capital surplus of $22.7 million as current assets exceeded current liabilities. In comparison, Pengrowth had a working capital surplus of $179.3 million at December 31, 2013. The year over year decrease in the working capital surplus was due to a $nil cash balance at December 31, 2014 compared to $448.5 million at December 31, 2013, partly offset by a $299.6 million increase in the current asset fair value of risk management contracts at December 31, 2014. The cash balance of $448.5 million at the start of 2014 was used to fund the Lindbergh capital program.

PENGROWTH 2014 Management's Discussion and Analysis 27

FINANCIAL RESOURCES AND LIQUIDITY

As at:	Dec 31, 2014		Dec 31, 2013		Change
($ millions)
Term credit facilities	191.0		—		191.0
Senior unsecured notes (1)	1,531.0		1,412.7		118.3
Senior debt	1,722.0		1,412.7		309.3
Convertible debentures	137.2		236.0		(98.8	)
Total debt before working capital	1,859.2		1,648.7		210.5
Working capital surplus (2)	(22.7	)	(179.3	)	156.6
Total debt	1,836.5		1,469.4		367.1
Twelve months trailing:	Dec 31, 2014		Dec 31, 2013		Change
($ millions, except ratios and percentages)
Net loss	(578.8	)	(316.9	)	(261.9	)
Add (deduct):
Interest and financing charges	74.6		94.1		(19.5	)
Deferred income tax recovery	(20.4	)	(73.2	)	52.8
Depletion, depreciation, amortization and accretion	535.8		595.1		(59.3	)
EBITDA	11.2		299.1		(287.9	)
Add other items:
Impairment	994.6		—		994.6
(Gain) loss on disposition of properties	(23.3	)	175.7		(199.0	)
Other non-cash items (3)	(402.2	)	180.2		(582.4	)
Adjusted EBITDA	580.3		655.0		(74.7	)
Senior debt before working capital to Adjusted EBITDA (4)	3.0		2.2		0.8
Total debt before working capital to Adjusted EBITDA (5)	3.2		2.5		0.7
Total debt to Adjusted EBITDA (6)	3.2		2.2		1.0
Total capitalization (7)	4,763.3		5,157.7		(394.4	)
Total debt as a percentage of total capitalization	38.6	%	28.5	%

⁽¹⁾  Includes current and long term portions.

⁽²⁾  Working capital surplus is calculated as current liabilities less current assets per the Consolidated Balance Sheets, excluding the current portion of long term debt.

⁽³⁾  Primarily resulting from the impact of unrealized fair value changes in risk management contracts and unrealized foreign exchange on long term debt.

⁽⁴⁾  Indicative of debt covenant for senior debt before working capital to EBITDA of 3.5 times.

⁽⁵⁾  Indicative of debt covenant for total debt before working capital to EBITDA of 4.0 times.

⁽⁶⁾  Not indicative of the actual debt covenants. See the Financial Covenants section for more information.

⁽⁷⁾  Total capitalization includes total debt plus Shareholders' Equity per the Consolidated Balance Sheets.

At December 31, 2014, total debt increased $367.1 million from December 31, 2013 mainly due to the term credit facility balance increasing to $191.0 million, and a decrease in the working capital surplus which was used to help fund general corporate activities including capital expenditures and dividends. Also, a $118.3 million increase in the U.S. senior unsecured notes due to the weakening of the Canadian dollar contributed to the change. This was partly offset by a decrease in convertible debentures as one of the series matured and was paid off, using the term credit facility, on December 31, 2014.

The trailing twelve months total debt to Adjusted EBITDA ratio increased to 3.2x at December 31, 2014, compared to 2.2x at December 31, 2013 mainly due to the increase in total debt and a decrease in funds flow from operations.

In light of the rapid decline in commodity prices in late 2014, Pengrowth has taken extensive and proactive measures for 2015 to ensure the Corporation's financial health and sustainability in a low commodity price environment. In addition to Pengrowth's extensive risk management program, these new initiatives include:

• A significantly reduced capital program for 2015 of $200 million, representing a 78 percent reduction from actual 2014 capital spending, with no decrease in expected production compared to 2014 due to anticipated volume contribution from the first commercial phase at Lindbergh.

PENGROWTH 2014 Management's Discussion and Analysis 28

• A deferral in the development plan for Lindbergh that is still expected to deliver annual bitumen production of 40,000 to 50,000 bbl/d.

• A 50 percent dividend reduction to $0.02 per share per month, which aims to balance 2015 cash inflows with capital obligations and dividends.

• Enhanced focus on management of all aspects of capital, operating and G&A cost structures.

• Commitment to ongoing risk management efforts to protect future cash flows and capital programs. Pengrowth has extensive oil and natural gas risk management contracts in place through 2015 and 2016 that are expected to provide a significant degree of cash flow certainty notwithstanding the current low commodity price environment.

Term Credit Facilities

Pengrowth maintains a $1 billion revolving credit facility which had a balance of $191.0 million at December 31, 2014 (December 31, 2013 - $nil) and had $25.0 million (December 31, 2013 - $35.8 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 notional credit capacity from a syndicate of seven Canadian and four foreign banks, and can be extended at Pengrowth’s discretion any time prior to maturity, subject to syndicate approval. The facility has a maturity date of July 26, 2017.

Pengrowth also maintains a $50 million demand operating facility with one Canadian bank. At December 31, 2014, this facility had a balance of $9.0 million (December 31, 2013 - $nil) and had $0.9 million (December 31, 2013 - $0.8 million) of outstanding letters of credit. When utilized together with any overdraft amounts, this facility appears on the Consolidated Balance Sheets as a current liability in bank indebtedness, as applicable.

Together, these two facilities provided Pengrowth with approximately $822 million of combined notional credit capacity at December 31, 2014, with the ability to expand the facilities by an additional $250 million. Use of the remaining credit capacity is still subject to complying with all financial covenants.

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, 2014.

On January 24, 2014, Pengrowth amended the credit facility by increasing the maximum permitted senior debt before working capital to EBITDA (as calculated in accordance with the debt agreements) ratio from 3.0 to 3.5 times and the total debt before working capital to EBITDA ratio from 3.5 to 4.0 times until December 31, 2015. As at December 31, 2014, Pengrowth's actual ratios pursuant to these two covenants were at 2.9 times and 3.1 times, respectively. The financial covenants are now substantially similar between the credit facilities and the senior unsecured notes. The ratios on the credit facility will revert back to their prior levels of 3.0 and 3.5 times, respectively, 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 Lindbergh production can contribute to the EBITDA calculation.

All loan agreements can be found on SEDAR at www.sedar.com filed under "Other" or "Material Document" and on EDGAR at www.sec.gov.

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 Consolidated Financial Statements.

The key financial covenants as at December 31, 2014 are summarized below:

1.Total senior debt before working capital must not exceed 3.5 times EBITDA for the last four fiscal quarters (credit facility - 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 (credit facility - 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 when financing an acquisition, where it would be acceptable for total debt to trailing EBITDA to temporarily exceed the 4.0 times noted above. 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

PENGROWTH 2014 Management's Discussion and Analysis 29

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 issuing equity. Details of these measures are included in Note 16 to the audited Consolidated Financial Statements.

Dividend Reinvestment Plan

Pengrowth's 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, 2014, 9.2 million shares were issued under the DRIP program for cash proceeds of $51.8 million compared to 8.6 million shares issued for total proceeds of $44.9 million in 2013.

Off-Balance Sheet Financing

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 and foreign currency exposure. Pengrowth’s policy is not to utilize financial instruments for trading or speculative purposes. See Note 2 to the audited Consolidated Financial Statements for a description of the accounting policies for financial instruments and Note 17 to the audited Consolidated 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, 2014		Sept 30, 2014		Dec 31, 2013		Dec 31, 2014		Dec 31, 2013
Funds flow from operations	115.8		129.0		105.9		505.7		560.9
Dividends declared	63.9		63.6		62.5		253.6		248.5
Funds flow from operations less dividends declared	51.9		65.4		43.4		252.1		312.4
Per share	0.10		0.12		0.08		0.48		0.60
Payout ratio (1)	55	%	49	%	59	%	50	%	44	%

⁽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 17 to the audited Consolidated Financial Statements.

PENGROWTH 2014 Management's Discussion and Analysis 30

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, 2014		Sept 30, 2014		Dec 31, 2013		Dec 31, 2014		Dec 31, 2013
Proceeds from DRIP	12.3		13.1		11.7		51.8		44.9
Per share	0.02		0.02		0.02		0.10		0.09
Net payout ratio (%) (1)	45	%	39	%	48	%	40	%	36	%

⁽¹⁾  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 during the fourth quarter of 2014 and 20 percent for the full year 2014.

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).

In January 2015, Pengrowth's Board approved a monthly dividend of $0.02 per share starting with the dividend payable on March 16, 2015. The previous dividend level of $0.04 per share was based on higher commodity prices and, given the current low commodity price environment and the uncertainty over how long it will persist, Pengrowth believes that it was prudent to lower the amount of its monthly dividend to ensure that it balances its 2015 cash inflows with capital obligations and dividends in a lower commodity price environment.

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 31, 2014 for an aggregate cash dividend of $0.48 per share. For the same period in 2013, Pengrowth also paid $0.04 per share in each of the months January through December for an aggregate cash dividend of $0.48 per share.

PENGROWTH 2014 Management's Discussion and Analysis 31

SUMMARY OF QUARTERLY RESULTS

The following table is a summary of quarterly information for 2014 and 2013:

2014	Q1		Q2		Q3		Q4
Oil and gas sales ($ millions) (1)	429.2		407.1		369.1		291.5
Net income (loss) ($ millions)	(116.2	)	(8.8	)	52.2		(506.0	)
Net income (loss) per share ($)	(0.22	)	(0.02	)	0.10		(0.95	)
Net income (loss) per share - diluted ($)	(0.22	)	(0.02	)	0.10		(0.95	)
Adjusted net income (loss) ($ millions)	(2.8	)	(24.8	)	3.4		(854.8	)
Funds flow from operations ($ millions)	139.5		121.4		129.0		115.8
Dividends declared ($ millions)	62.8		63.3		63.6		63.9
Dividends declared per share ($)	0.12		0.12		0.12		0.12
Daily production (boe/d)	75,102		73,823		72,472		71,802
Total production (Mboe)	6,759		6,718		6,667		6,606
Average sales price ($/boe) (1)	63.00		60.08		54.73		43.61
Operating netback ($/boe) (2)	29.71		23.86		24.91		24.04
2013	Q1		Q2		Q3		Q4
Oil and gas sales ($ millions) (1)	393.5		416.6		439.6		343.7
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 ($)	0.12		0.12		0.12		0.12
Daily production (boe/d)	89,702		87,909		83,275		77,371
Total production (Mboe)	8,073		8,000		7,661		7,118
Average sales price ($/boe) (1)	48.18		51.55		56.64		47.92
Operating netback ($/boe) (2)	24.79		24.44		27.10		20.82

⁽¹⁾  Excluding realized commodity risk management.

⁽²⁾  Including realized commodity risk management.

Fourth quarter of 2014 average sales price decreased compared to all of the preceding quarters of 2014 and 2013, as per table above, driven by a rapid decline in the oil benchmark prices seen in late 2014. In contrast, the first and second quarters of 2014 average sales prices were the highest posted average prices since the fourth quarter of 2008 driven by an increase in the benchmark prices at that time.

Quarterly production in 2014 is lower compared to all four quarters in 2013 primarily due to property dispositions, lower natural gas production resulting from natural declines as a result of capital investment being directed mainly to oil development programs, in addition to a few fields with third party capacity constraints.

First quarter of 2014 posted the highest operating netback since the fourth quarter of 2011 resulting from higher benchmark prices in early 2014. The operating netback has decreased to $24.04/boe in the fourth quarter of 2014 as a result of the rapid decline in oil benchmark prices.

Quarterly net income (loss) has also been affected by non-cash charges, in particular depletion, depreciation and amortization, impairment charges, unrealized gain (loss) on investments, accretion of ARO, unrealized risk management gains (losses), unrealized foreign exchange gains (losses), gains (losses) on property divestments, and deferred taxes. Funds flow from operations was also impacted by changes in royalty expense, operating and G&A costs.

PENGROWTH 2014 Management's Discussion and Analysis 32

SELECTED ANNUAL INFORMATION

The table below provides a summary of selected annual information for the years ended 2014, 2013 and 2012.

	Twelve months ended December 31
($ millions unless otherwise indicated)	2014		2013		2012
Oil and gas sales (1)	1,496.9		1,593.4		1,458.2
Net income (loss)	(578.8	)	(316.9	)	12.7
Net income (loss) per share ($)	(1.10	)	(0.61	)	0.03
Net income (loss) per share - diluted ($)	(1.10	)	(0.61	)	0.03
Dividends declared per share ($)	0.48		0.48		0.66
Total assets	6,169.8		6,633.2		7,469.9
Long term debt (2)	1,859.2		1,648.7		1,767.7
Shareholders' equity	2,926.8		3,688.3		4,190.3
Number of shares outstanding at year end (thousands)	533,438		522,031		511,804

⁽¹⁾  Excluding realized commodity risk management.

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

COMMITMENTS AND CONTRACTUAL OBLIGATIONS

($ millions)	2015	2016	2017	2018	2019	Thereafter	Total
Convertible debentures (1)	—	—	136.8	—	—	—	136.8
Interest payments on convertible debentures	8.6	8.6	2.1	—	—	—	19.3
Long term debt (2)	173.3	—	655.1	322.4	67.7	507.0	1,725.5
Interest payments on long term debt (3)	90.9	85.3	69.2	40.3	25.4	65.4	376.5
Operating leases (4)	13.1	12.8	12.0	10.9	9.5	51.9	110.2
Pipeline transportation	30.7	16.5	20.7	22.0	19.7	144.8	254.4
Other	17.9	2.9	0.7	0.7	0.3	11.0	33.5
	334.5	126.1	896.6	396.3	122.6	780.1	2,656.2

⁽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 and excludes related foreign exchange risk management contracts.

⁽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 cash flow available for distribution to shareholders as dividends 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. Some of 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, bitumen, 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 affect Pengrowth’s ability to maintain its current dividend rate, spend capital and meet obligations. The impairment test is sensitive to lower realized commodity prices, which have been under significant downward pressure in recent months, particularly oil 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.

PENGROWTH 2014 Management's Discussion and Analysis 33

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 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 or term debt.

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.

• 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 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.

PENGROWTH 2014 Management's Discussion and Analysis 34

• 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 ability to pay 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, 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 Pengrowth’s ability to pay dividends to shareholders.

• Delays or failure to secure regulatory approvals for 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 also be adversely affected.

• Pengrowth’s oil and gas reserves will be depleted over time and the level of cash flow from operations and the value of the common shares could materially decrease 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 Pengrowth’s common shares and dividends to shareholders.

• Dividends and the market price of the common shares could be adversely affected by unforeseen title defects.

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 substantially increased 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 its ability to pay dividends.

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Foreign Currency Risk

• Pengrowth has substantial exposure to the U.S. dollar. Any decrease in the Canadian dollar relative to the U.S. dollar results in an increase in the Canadian dollar equivalent of Pengrowth’s U.S. dollar denominated term debt as Pengrowth reports and prepares its covenant calculations in Canadian dollars. A significant decrease in the value of the Canadian dollar relative to the U.S. dollar could cause Pengrowth to be in violation of its debt covenants resulting in Pengrowth being in default under its borrowing agreements.

General Business Risks

• Investors’ interest in the oil and gas sector may change over time which would affect the availability of capital and the value of Pengrowth common shares.

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

• Canadian / U.S. exchange rates influence revenues and, to a lesser extent, operating and capital costs. Pengrowth is also exposed to foreign currency fluctuations on the U.S. dollar denominated term debt 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 January1, 2014, Pengrowth adopted amendments to IAS 32 Financial Instruments: Presentation (“IAS 32”) relating to offsetting financial assets and financial liabilities. 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 retrospective adoption of this standard had no impact on the amounts recorded in the Consolidated Financial Statements.

On January 1, 2014, Pengrowth adopted IFRIC 21 Levies ("IFRIC 21"). IFRIC 21 clarifies that an entity recognizes a liability for a levy when the activity that triggers payment, as identified by the relevant legislation, occurs. The interpretation also clarifies that no liability should be recognized before the specified minimum threshold to trigger that levy is reached. The retrospective adoption of this interpretation had no impact on the amounts recorded in the Consolidated Financial Statements.

ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED

In May 2014, the IASB issued IFRS 15 Revenue from Contracts with Customers ("IFRS 15"). The new standard is effective for annual periods beginning on or after January 1, 2017. Earlier application is permitted. The standard contains a single model that applies to contracts with customers and two approaches to recognising revenue: at a point in time or over time. The model features a contract-based five-step analysis of transactions to determine whether, how much and when revenue is recognized. New estimates and judgmental thresholds have been introduced, which may affect the amount and/or timing of revenue recognized. The new standard applies to contracts with customers. It does not apply to insurance contracts, financial instruments or lease contracts, which fall in the scope of other IFRSs. Pengrowth intends to adopt IFRS 15 in its Consolidated Financial Statements for the annual period beginning on January 1, 2017. The extent of the impact of adoption of the standard has not yet been determined.

In July 2014, the IASB issued the complete IFRS 9 (IFRS 9 (2014)). The mandatory effective date of IFRS 9 is for annual periods beginning on or after January 1, 2018 and must be applied retrospectively with some exemptions. Early adoption is permitted. The restatement of prior periods is not required and is only permitted if information is available without the use of hindsight. IFRS 9 (2014) introduces new requirements for the classification and measurement of financial assets. Under IFRS 9 (2014), financial assets are classified and measured based on the business model in which they are held and the characteristics of their contractual cash flows. The standard introduces additional changes relating to financial liabilities. It also amends the impairment model by introducing a new “expected credit loss” model for calculating impairment. IFRS 9 (2014) also includes a new general hedge accounting standard which aligns hedge accounting more closely with risk management. This new standard does not fundamentally change the types of hedging relationships or the requirement to measure and recognize ineffectiveness, however it will provide more hedging strategies that are used for risk management to qualify for hedge accounting and introduce more judgment to assess the effectiveness of a hedging relationship. Special transitional requirements have been set for the application of the

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new general hedging model. Pengrowth intends to adopt IFRS 9 (2014) in its Consolidated Financial Statements for the annual period beginning on January 1, 2018. The extent of the impact of adoption of the standard has not yet been determined.

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, 2014. 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, 2014, 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.

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 Consolidated 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 Consolidated 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 Consolidated 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, 2014. 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 (2013).

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Based on Pengrowth's evaluation, management concluded that Pengrowth's internal control over financial reporting was effective as of December 31, 2014.

The effectiveness of internal control over financial reporting as of December 31, 2014 was audited by KPMG LLP, an independent registered public accounting firm, as stated in their report, which is included with Pengrowth's audited Consolidated Financial Statements for the year ended December 31, 2014. No changes were made to Pengrowth's internal control over financial reporting during the year ending December 31, 2014 that have materially affected, or are reasonably likely to materially affect, the internal controls over financial reporting.

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