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, 2017 of Pengrowth Energy Corporation ("Pengrowth" or the "Corporation"). This MD&A is based on information available to February 28, 2018.

Pengrowth’s fourth quarter and annual results for 2017 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 divested properties are included in Pengrowth’s results up to the month-end nearest the date 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, "CO2" refers to carbon dioxide which is a gas at room temperature and pressure, "SAGD" refers to steam assisted gravity drainage, "diluent" refers to a hydrocarbon based diluting agent required to facilitate the transportation of bitumen, "dilbit" or "diluted bitumen" refers to diluent blended with bitumen. 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, Asset Retirement Obligations ("ARO"), remediation, reclamation and abandonment expenses, clean-up and remediation costs, capital expenditures, development activities, cash General and Administrative Expenses ("G&A"), onerous office lease contracts, Lindbergh expansion plans, production capacity, anticipated low costs and sustaining capital 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 oil and bitumen 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

PENGROWTH 2017 Management's Discussion and Analysis 1

activities. Although management considers these assumptions to be reasonable based on information currently available to it, they may prove to be incorrect.

By their very nature, forward-looking statements involve inherent risks and uncertainties, both general and specific, and risks that predictions, forecasts, projections and other forward-looking statements will not be achieved. We caution readers not to place undue reliance on these statements as a number of important factors could cause the actual results to differ materially from the beliefs, plans, objectives, expectations and anticipations, estimates and intentions expressed in such forward-looking statements. These factors include, but are not limited to: the volatility of oil and gas prices; Canadian light oil and bitumen 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; actions by government authorities, including the imposition or reassessment of taxes including changes in income taxes and royalty laws; Pengrowth's ability to access external sources of debt and equity capital; new International Financial Reporting Standards ("IFRS"); and the implementation of greenhouse gas emissions legislation and the impact of carbon taxes. 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 audited Consolidated Financial Statements are prepared in accordance with IFRS. The preparation of these 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 audited Consolidated Financial Statements and revenues and expenses during the reporting period. 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 audited 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 and contingent resources on an ad hoc basis. Reserves form the basis for the calculation of depletion charges, while oil and gas reserves and contingent resources are used in the assessment of impairment of goodwill and oil and gas assets. Reserves and contingent resources 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

PENGROWTH 2017 Management's Discussion and Analysis 2

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.

Contingent resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. Contingencies may include factors such as economic, legal, environmental, political and regulatory matters or a lack of markets. Contingent resources do not constitute, and should not be confused with, reserves.

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. Pengrowth uses the 30 year Canadian Government long term bond rate to estimate its ARO discount rate.

Pengrowth’s ARO risk free discount rate was 2.3 percent at December 31, 2017 remaining unchanged from December 31, 2016.

Impairment testing

CGUs are tested for impairment 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. 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 prior years' comparative figures have been reclassified to conform to presentation adopted in the current year.

ADOPTION OF IFRS 15

Pengrowth has elected in the fourth quarter of 2017 to early adopt IFRS 15 Revenue from Contracts with Customers ('IFRS 15") for 2017 using the cumulative effect method. Under this method, prior years' financial statements have not

PENGROWTH 2017 Management's Discussion and Analysis 3

been restated and the cumulative effect on net earnings of the application of IFRS 15 to revenue contracts in progress at January 1, 2017 is nil. Pengrowth management reviewed its revenue streams and major contracts with customers using the IFRS 15 five step model and there were no material changes to net earnings or timing of produced petroleum revenue recognized. It should be noted, however, that certain Income Statement line item reclassifications were made. See Accounting Pronouncements section of this MD&A as well as Notes 2 and 14 to the December 31, 2017 audited Consolidated Financial Statements for more information.

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.

Management monitors Pengrowth’s capital structure and covenant compliance using non-GAAP financial metrics some of which are discussed in the Financial Resources and Liquidity section of this MD&A. These metrics are:

– trailing twelve months Earnings Before Interest, Taxes, Depletion, Depreciation, Amortization, Accretion ("EBITDA"), other items and EBITDA related to material divestments ("Adjusted EBITDA");

– trailing twelve months interest expense excluding interest expense related to debt repaid with proceeds from divestments ("Adjusted Interest Expense");

– Adjusted EBITDA to Adjusted Interest Expense ratio (the "Interest Coverage" ratio);

– Debt before working capital to the trailing twelve months Adjusted EBITDA; and

– Total debt before working capital as a percentage of total book capitalization ("Debt to Book Capitalization").

For the purposes of certain covenant calculations only, letters of credit and finance leases are incorporated in senior and total debt before working capital for covenant purposes. Total book capitalization is the sum of senior debt before working capital for covenant purposes 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 changes in fair value of commodity and power risk management contracts as well as unrealized foreign exchange gains and losses that may significantly impact net income (loss) from period to period.

Produced petroleum revenue is a useful measure of revenue as it only includes the revenue from company interest production, by excluding processing income and revenue from purchased products, such as diluent and other third party volumes. This measure can be expressed on a per boe basis.

Net operating expenses are calculated as operating expenses less processing income primarily generated by processing third party volumes at processing facilities where Pengrowth has an ownership interest. This measure is also expressed on a per boe basis and is a useful supplemental measure for management.

Royalty expenses as a percent of produced petroleum revenue is a useful measure as it reflects overall royalty percentage related to revenues which are subject to royalties.

Pengrowth’s operating netbacks are defined as produced petroleum revenue, less royalties, less net operating expenses and less transportation expenses divided by production for the period. Operating netbacks can be expressed either before or after realized commodity risk management. Operating netbacks may not be comparable to similar measures presented by other companies, as there are no standardized measures.

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. Cash and non-cash G&A expenses per boe are calculated by dividing cash and non-cash G&A expenses by production for the period.

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.

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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 method primarily applicable to the burner tip and does not represent a value equivalency at the wellhead.

Steam Oil Ratio ("SOR") measures the rate of steam required to produce a barrel of bitumen. This can be expressed either as an average or at a point in time.

These measures do not have standardized meanings and may not be comparable to similar measures presented by other oil and gas companies.

CURRENCY

All amounts are stated in Canadian dollars unless otherwise specified.

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CORPORATE OVERVIEW

Following the asset divestitures in 2017, Pengrowth’s asset portfolio consists primarily of two key long-term, 100 percent operated growth assets at Lindbergh and Groundbirch. These assets will form the foundation of Pengrowth’s growth strategy over the next several years and are expected to position the Company to deliver low decline production and cash flow growth.

Pengrowth’s Lindbergh thermal project is located in the Cold Lake area of Alberta and encompasses 42.5 sections of land. The project utilizes steam assisted gravity drainage ("SAGD") to produce bitumen from the Lloydminster formation. The project has an ultimate productive capacity of 40,000 to 50,000 bbl/d once fully developed. Pengrowth also has a 50 percent working interest in the Selina oil sands property, located approximately 30 kilometers northeast of Lindbergh. An EPEA application was filed in December 2016 for a thermal project at Selina designed for an annual gross production rate of 12,500 bbl/d of bitumen.

Pengrowth’s Groundbirch property is located within the Montney fairway in northeast British Columbia and encompasses 19 sections of land. The project produces natural gas from the Montney formation by utilizing horizontal wells and multi-stage fracture technology. The Company currently has 360 net (unrisked) drilling locations to facilitate future development opportunities. In addition, Pengrowth operates a 30 MMcf/d facility to process and deliver natural gas onto major transport pipelines, which will serve in part to indirectly fulfill Pengrowth's natural gas needs at Lindbergh.

On February 20, 2018, Pengrowth announced the planned retirement of Derek Evans as President and CEO effective March 15, 2018 and the appointment of Mr. Peter D. Sametz as his successor. Mr. Evans will continue in a transitional advisory role until June 30, 2018 to provide support during the leadership transition.

2017 ACTUAL RESULTS VS. 2017 GUIDANCE

The following table provides a summary of full year 2017 Guidance and actual results for the twelve months endedDecember 31, 2017:

	2017 Actual	2017 Guidance (1)
Production (boe/d)	40,428	39,500 - 41,500
Capital expenditures ($ millions)	117.9	125
Funds flow from operations ($ millions)	69.4	65
Royalty expenses (% of produced petroleum revenue) (2) (3)	9.4	9.0
Net operating expenses ($/boe) (2)	13.45	13.00 - 13.50
Cash G&A expenses ($/boe) (2)	3.84	3.50 - 4.00

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

⁽²⁾  See definition under section "Non-GAAP Financial Measures".

⁽³⁾  Excludes financial commodity risk management activities.

The financial and operating results from divested properties are included in Pengrowth’s results up to the month-end nearest the date of closing of each disposition. 2017 results include financial and operating results from Judy Creek up to May 31, 2017, Olds/Garrington results up to July 31, 2017, non-core legacy Alberta and Swan Hills assets up to October 31, 2017 and Quirk Creek up to December 31, 2017.

2017 actual results were all within full year Guidance. December 2017 actual production averaged 20,670 boe/d which was slightly higher than December 2017 production Guidance of 20,000 boe/d.

2018 GUIDANCE

The following table provides Pengrowth's previously announced 2018 Guidance:

	2018 Guidance (1)
Production (boe/d)	22,500 - 23,500
Capital expenditures ($ millions)	65
Royalty expenses (% of produced petroleum revenue) (2) (3)	6.0
Net operating expenses ($/boe) (2)	10.50 - 11.50
Cash G&A expenses ($/boe) (2)	3.10 - 3.35

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

⁽²⁾  See definition under section "Non-GAAP Financial Measures".

⁽³⁾  Excludes financial commodity risk management activities.

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FINANCIAL HIGHLIGHTS

	Three months ended				Twelve months ended
($ millions except per boe amounts)	Dec 31, 2017		Dec 31, 2016		Dec 31, 2017		Dec 31, 2016
Total debt before working capital (1)	610.5		1,687.3		610.5		1,687.3
Production (boe/d)	24,702		54,354		40,428		57,058
Capital expenditures	28.2		28.4		117.9		64.4
Funds flow from operations (2) (3)	13.5		111.7		69.4		429.7
Operating netback before realized commodity risk management ($/boe) (4)	18.96		15.16		14.57		10.15
Adjusted net income (loss) (4) (5)	(217.1	)	45.3		(745.6	)	48.0
Net income (loss) (5)	(210.4	)	(92.4	)	(683.8	)	(293.7	)

⁽¹⁾  Includes Credit Facilities, current and long term portions of term notes and convertible debentures, as applicable. Excludes letters of credit and finance leases.

⁽²⁾  Funds flow from operations for the twelve months ended December 31, 2017 includes a $12.7 million loss related to the early settlement of commodity risk management contracts.

⁽³⁾  Funds flow from operations for the three and twelve months ended December 31, 2017 exclude $34.8 million and $37.6 million, respectively, of losses from the settlement of foreign exchange swap contracts related to the prepayment of term notes as this was considered a financing activity.

⁽⁴⁾  See definition under section "Non-GAAP Financial Measures".

⁽⁵⁾  Three and twelve months ended December 31, 2017 include impairment charges of $130.0 million ($95 million after-tax) and $634.4 million ($463 million after-tax), respectively, primarily related to 2017 property dispositions.

2017 Highlights:

• Total debt before working capital was reduced by Cdn$1,076.8 million during 2017 primarily through the prepayment of the U.S.$400 million 6.35 percent term notes, U.S.$265 million 6.98 percent notes, Cdn$15 million 6.61 percent notes, prepayments of Cdn$115.4 million of principal during the fourth quarter on the remaining outstanding term notes, and the repayment of Cdn$126.6 million of convertible debentures at maturity.

• Formalized an agreement with bank syndicate and noteholders removing and relaxing certain financial covenants through September 30, 2019.

• In the first quarter, Pengrowth closed the sale of a 4.0 percent gross overriding royalty ("GORR") interest on the Lindbergh property and certain seismic assets for proceeds of $250 million. A pre-tax gain on disposition of $144.7 million, net of transaction costs, was recorded.

• In the second quarter, Pengrowth sold its non-producing Montney lands at Bernadet in north east British Columbia for cash consideration of $92 million. A pre-tax loss on disposition of $33.4 million was recorded.

• In the third quarter, the Judy Creek assets were sold for total consideration of $185 million, before customary adjustments. A $71.0 million pre-tax PP&E impairment was recorded related to this transaction. Pengrowth also sold its Olds/Garrington assets for cash consideration of $300 million, before customary adjustments. A $306.3 million pre-tax PP&E impairment was recorded related to this transaction.

• In the fourth quarter, Pengrowth sold its remaining Swan Hills assets in north central Alberta for total consideration of $150 million, subject to customary adjustments, resulting in a pre-tax loss on disposition of $169.0 million. Pengrowth also closed the sale of the vast majority of its remaining non-core legacy assets in Alberta for nominal cash consideration and the assumption of abandonment and reclamation liabilities by the purchaser. A $56.1 million pre-tax PP&E impairment was recorded related to this transaction.

• Funds flow from operations was $69.4 million in 2017, net of restructuring related severance costs of $10.5 million.

• Additional expense reductions were accomplished with 2017 net operating expenses and cash G&A expenses decreasing $77.0 million and $13.8 million, respectively, compared to 2016.

• 10 producer, 10 injector, 2 infill and 2 observation wells were drilled at the Lindbergh thermal project in 2017.

• 4 wells were drilled as part of the drilling and optimization program at Groundbirch in 2017. The wells will be completed in early 2018.

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Funds Flow from Operations

($ millions)		Q4/16 vs. Q4/17		% Change		2016 vs. 2017			% Change
Funds flow from operations for comparative period	Q4/16	111.7				2016	429.7
Increase (decrease) due to:
Volumes		(91.3	)	(82	)		(170.5	)	(40	)
Prices including differentials		7.6		7			96.0		22
Realized commodity risk management		(83.8	)	(75	)		(405.5	)	(94	)
Royalties		6.1		5			(5.8	)	(1	)
Expenses:
Net operating		42.1		38			77.0		18
Cash G&A		5.2		5			13.8		3
Interest & financing		13.9		12			34.8		8
Restructuring costs - severance		(1.3	)	(1	)		(10.5	)	(2	)
Other - including transportation		3.3		3			10.4		2
Net change		(98.2	)	(88	)		(360.3	)	(84	)
Funds flow from operations (1) (2)	Q4/17	13.5				2017	69.4

⁽¹⁾  Funds flow from operations for the twelve months ended December 31, 2017 includes a $12.7 million loss related to the early settlement of commodity risk management contracts.

⁽²⁾  Funds flow from operations for the three months and twelve months ended December 31, 2017 exclude $34.8 million and $37.6 million, respectively, of losses from the settlement of foreign exchange swap contracts related to the prepayment of term notes as this was considered a financing activity.

Pengrowth's fourth quarter of 2017 funds flow from operations decreased 88 percent compared to the same period in 2016 primarily driven by divestment of properties resulting in lower volumes year over year combined with the absence of significant realized commodity risk management gains. Partly offsetting these were lower operating expenses and interest and financing charges.

Full year 2017 funds flow from operations decreased 84 percent compared to the same period in 2016 also driven by the absence of funds flow related to divested properties and the absence of significant realized commodity risk management gains in 2016. These were partly offset by higher commodity prices combined with decreased G&A and interest and financing charges. Restructuring costs of $10.5 million related to severance costs also impacted 2017 funds flow from operations.

Pengrowth realized a commodity risk management loss of $6.6 million in the fourth quarter of 2017 compared to a gain of $77.2 million in the same period in 2016, with the $83.8 million decrease primarily due to lower contracted crude oil and natural gas commodity risk management volumes and fixed prices compared to the same period in 2016. Full year 2017 Pengrowth realized a commodity risk management loss of $19.8 million compared to a gain of $385.7 million in the same period in 2016, with the $405.5 million decrease due to lower contracted crude oil and natural gas commodity risk management volumes along with lower fixed prices compared to 2016.

Net Income (Loss)

Pengrowth recorded a net loss of $210.4 million in the fourth quarter of 2017 compared to a net loss of $92.4 million in the fourth quarter of 2016 primarily due to impairment of the Groundbirch E&E gas asset, lower funds flow from operations primarily related to divested properties, realized foreign exchange losses recorded in the quarter as a result of the settlement of U.S. dollar swap contracts and loss on extinguishment of debt as a result of the debt restructuring completed in the quarter. These were partly offset by unrealized foreign exchange gains recorded in the fourth quarter of 2017, lower unrealized commodity risk management losses and lower DD&A expenses.

Full year 2017 net loss was $390.1 million higher compared to 2016 due to impairment charges of $634.4 million (approximately $463 million after-tax) coupled with lower funds flow from operations related to 2017 divestments, partly offset by the absence of unrealized commodity risk management losses recorded in 2016 and lower DD&A expenses.

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Adjusted Net Income (Loss)

Pengrowth reports adjusted net income (loss) to remove the effect of unrealized gains and losses.

The following table provides a reconciliation of net income (loss) to adjusted net income (loss):

	Three months ended				Twelve months ended
($ millions)	Dec 31, 2017		Dec 31, 2016		Dec 31, 2017		Dec 31, 2016
Net income (loss)	(210.4	)	(92.4	)	(683.8	)	(293.7	)
Exclude non-cash items from net income (loss):
Change in fair value of commodity and power risk management contracts	(33.3	)	(104.4	)	14.2		(422.8	)
Unrealized foreign exchange gain (loss) (1)	31.0		(61.6	)	51.4		(33.4	)
Tax effect on non-cash items above	9.0		28.3		(3.8	)	114.5
Total excluded	6.7		(137.7	)	61.8		(341.7	)
Adjusted net income (loss) (2)	(217.1	)	45.3		(745.6	)	48.0

⁽¹⁾  Relates to the foreign denominated debt net of associated foreign exchange risk management contracts.

⁽²⁾  See definition under section "Non-GAAP Financial Measures".

The following table represents a continuity of adjusted net income (loss):
($ millions)		Q4/16 vs. Q4/17		2016 vs. 2017
Adjusted net income (loss) for comparative period	Q4/16	45.3		2016	48.0
Funds flow from operations increase (decrease)		(98.2	)		(360.3	)
DD&A and accretion expense (increase) decrease		45.7			146.0
Impairment charges (increase) decrease		(130.0	)		(634.4	)
Realized foreign exchange gain (loss) on settled FX swaps		(81.8	)		(84.6	)
Loss on property dispositions (increase) decrease		(9.0	)		(35.5	)
Restructuring costs - onerous office lease contracts		(18.5	)		(26.5	)
Loss on extinguishment of debt		(49.2	)		(56.7	)
Other		11.6			9.7
Estimated tax on above		67.0			248.7
Net change		(262.4	)		(793.6	)
Adjusted net income (loss) (1)	Q4/17	(217.1	)	2017	(745.6	)

⁽¹⁾  See definition under section "Non-GAAP Financial Measures".

Pengrowth posted an adjusted net loss of $217.1 million in the fourth quarter of 2017 compared to adjusted net income of $45.3 million in the fourth quarter of 2016. The $262.4 million decrease was primarily due to impairment of E&E gas assets, lower funds flow from operations combined with realized foreign exchange loss on settled FX swaps and loss on extinguishment of debt, all of which were recorded in the fourth quarter of 2017. This was partly offset by lower DD&A expenses resulting from property divestments.

Pengrowth posted a full year 2017 adjusted net loss of $745.6 million compared to adjusted net income of $48.0 million in 2016 primarily driven by 2017 PP&E impairment charges related to asset dispositions, E&E impairments, lower funds flow from operations, realized foreign exchange loss on settled FX swaps in 2017, loss on extinguishment of debt, loss on property dispositions and restructuring costs pertaining to an onerous office lease contract. This was partly offset by lower DD&A expenses.

PENGROWTH 2017 Management's Discussion and Analysis 9

Sensitivity of Funds Flow from Operations to Commodity Prices

The following table illustrates the sensitivity of funds flow from operations to increases in commodity prices and differentials after taking into account Pengrowth’s commodity risk management contracts and outlook on oil differentials. See Note 17 to the December 31, 2017 audited Consolidated Financial Statements for more information on Pengrowth's risk management contracts. 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.

						Estimated Impact on 12 Month Funds Flow
COMMODITY PRICE ENVIRONMENT (1)		Assumption		Change		(Cdn$ millions)
West Texas Intermediate Oil (2)	U.S.$/bbl		$62.91		$1.00
Bitumen						7.3
Oil risk management (3)						(4.5	)
Light oil and NGLs						0.5
Net impact of U.S.$1/bbl increase in WTI						3.3
Oil differentials (2)
Bitumen	U.S.$/bbl		$27.13		$1.00	(7.3	)
Light oil	U.S.$/bbl		$3.12		$1.00	(0.4	)
Physical oil differential risk management (4)						7.7
Net impact of U.S.$1/bbl increase in differentials						—
AECO Natural Gas (2)	Cdn$/Mcf		$1.20		$0.10
Natural gas						0.9
Net impact of Cdn$0.10/Mcf increase in AECO						0.9

⁽¹⁾  Calculations are performed independently and are not indicative of actual results when multiple variables change at the same time. The exchange rate of Cdn$1 = U.S.$0.81 was used for the 12 month period.

⁽²⁾  Commodity price is based on an estimation of the 12 month forward price curve at February 2, 2018 and does not include the impact of commodity risk management contracts.

⁽³⁾  Includes commodity risk management contracts as at February 2, 2018.

⁽⁴⁾  Reflects 2018 physical delivery contracts for 17,000 bbl/d of diluted bitumen at a fixed price differential of approximately U.S.$16.82/bbl. See Commodity Prices section of this MD&A for more information.

FINANCIAL RESOURCES AND LIQUIDITY

Debt Restructuring

On October 12, 2017, Pengrowth entered into agreements with the lenders in its syndicated Credit Facility and the holders of its remaining term notes (collectively referred to as the "Lenders") amending certain terms of its Credit Facility and term notes. Highlights of the agreements are:

• The prepayment of all of the term notes due August 21, 2018 (U.S.$265 million and Cdn$15 million) and additional prepayments of Cdn$115.4 million of principal during the fourth quarter on the remaining outstanding term notes.

• Amendments to the existing financial covenants effective for the quarter ending September 30, 2017 through to and including the quarter ending September 30, 2019 in the case of its term notes, and expiring on March 31, 2019 in the case of its Credit Facility (the "Waiver Period"). During the Waiver Period:

◦ The Debt to Adjusted EBITDA ratio covenant and the Debt to Book Capitalization ratio covenant do not apply.

◦ The trailing 12 month Adjusted EBITDA to Adjusted Interest Expense minimum ratio covenant is revised as follows:

Year	Q1	Q2	Q3	Q4
2017	n/a	n/a	4.0 times	0.77 times
2018	0.75 times	0.68 times	1.03 times	1.01 times
2019	1.13 times	1.19 times	1.23 times	4.0 times

PENGROWTH 2017 Management's Discussion and Analysis 10

• The Lenders were granted security over Pengrowth’s assets, similar to other oil and gas borrowing base loans.

• The remaining outstanding term notes maturing in 2019 through 2024 are subject to a two percentage point increase in interest rates (which increases to three percentage points on January 1, 2020). A one-time amendment fee of 0.5 percent on outstanding term notes was also paid to the holders of term notes due after 2018.

• The aggregate credit limit under the Credit Facility was reduced to $330 million following the closing of the Swan Hills asset sale, the $50 million Demand Credit Facility was eliminated and interest rates under the Credit Facility increased by 2 percentage points. A one time amendment fee of 0.5 percent of the aggregate credit limit was paid to the syndicate members of the Credit Facility.

• The 2017 debt restructuring was a substantial modification of terms and was therefore reflected as an extinguishment of debt for accounting purposes with a Loss on extinguishment of debt reflected in the 2017 Consolidated Statement of Income (Loss) in the amount of $56.7 million composed of $55.2 million of debt restructuring costs and $1.5 million of remaining unamortized issue costs. Debt restructuring costs comprised the amendment fees, make whole payments on the principal prepayments, as well as professional fees.

Capital Resources

At December 31, 2017, Pengrowth had in place a secured $330.0 million revolving, committed term Credit Facility supported by a syndicate of 11 domestic and international banks which matures on March 31, 2019.

Debt Maturities

The Company has no scheduled debt maturities in 2018. The Credit Facility had a $109.0 million balance at December 31, 2017 (December 31, 2016 - $nil) and $69.4 million of outstanding letters of credit, inclusive of the now eliminated demand facility's letters of credit (December 31, 2016 - $51.3 million).

There are no term note maturities until October 2019.

Financial Covenants

Pursuant to the debt amending agreements, the only applicable covenant during the Waiver Period is the trailing 12 month Adjusted EBITDA to Adjusted Interest Expense ratio (the "Interest Coverage" ratio). The Interest Coverage ratio changes each quarter until the fourth quarter of 2019 for term notes and until the March 31, 2019 maturity for the Credit Facility after which it remains at 4.0 times, as noted above. Also after the Waiver Period, the Debt to Adjusted EBITDA ratio covenant of 3.5 times, and the Debt to Book Capitalization ratio covenant of 55 percent will be applicable again.

The calculation of the Interest Coverage ratio is based on specific definitions within the agreements and contains adjustments, pursuant to the agreements, some of which cannot be readily replicated by referring to Pengrowth’s Consolidated Financial Statements. Trailing 12 month EBITDA can be adjusted for certain one-time cash items, estimated EBITDA from material divested or acquired properties and non-cash items. Trailing 12 month interest expense can be adjusted for the interest expense related to debt repaid with asset divestment proceeds.

Pengrowth's Interest Coverage ratio was 1.6 times at December 31, 2017, which was above the fourth quarter of 2017 covenant of 0.77 times.

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

PENGROWTH 2017 Management's Discussion and Analysis 11

Covenant Calculation

Twelve month trailing actual covenant (1):
Interest Coverage ratio at December 31, 2017	1.6
Minimum Interest Coverage compliance ratio required at December 31, 2017	0.77
Twelve month trailing Adjusted Interest Expense ($ millions):	Dec 31, 2017
Interest and financing charges	70.7
Less fees and interest on debt repaid with asset divestment proceeds (1)	(34.3	)
Adjusted Interest Expense	36.4
Twelve month trailing Adjusted EBITDA ($ millions):
Net income (loss)	(683.8	)
Add (deduct):
Interest and financing charges	70.7
Deferred income tax expense (recovery)	(223.8	)
Depletion, depreciation, amortization and accretion	219.0
Impairment	634.4
(Gain) loss on disposition of properties	62.6
Other items (2)	67.8
EBITDA related to material dispositions (2)	(88.9	)
Adjusted EBITDA	58.0

⁽¹⁾  Calculation of the financial covenant is based on specific definitions within the agreements and contains adjustments, pursuant to the agreements, some of which cannot be readily replicated by referring to Pengrowth’s Consolidated Financial Statements.

⁽²⁾  Includes the impact of changes in fair value of commodity risk management contracts, unrealized foreign exchange on long term debt, and other adjustments pursuant to the actual covenant calculations, including certain allocated G&A expenses.

Total Debt Before Working Capital Continuity

(Cdn$ millions)	December 31, 2016 vs. December 31, 2017
Total debt before working capital at December 31, 2016 (1)	1,687.3
Increase (decrease) due to:
Foreign exchange impact of the stronger Canadian dollar on U.S. denominated debt	(65.7	)
Foreign exchange impact of the weaker Canadian dollar on U.K. denominated debt	0.6
Credit facilities and bank indebtedness increase	109.0
Term notes repayment	(996.0	)
Convertible debenture repayment	(126.6	)
Issue cost amortization	1.9
Total increase (decrease)	(1,076.8	)
Total debt before working capital at December 31, 2017 (1)	610.5

⁽¹⁾  Includes Credit Facilities, current and long term portions of term notes and convertible debentures, as applicable.

At December 31, 2017, total debt before working capital decreased by Cdn$1,076.8 million compared to December 31, 2016, as per the table above. The prepayment of U.S.$400 million and U.S.$265 million of term notes, prepayment of Cdn$130.4 million on the remaining outstanding term notes combined with the repayment of convertible debentures at maturity were the primary drivers for the decrease.

As of December 31, 2017, Pengrowth's foreign denominated term notes comprised 79 percent of the total debt before working capital. Each term note is governed by a Note Purchase Agreement. See Note 8 to the December 31, 2017 audited Consolidated Financial Statements for additional information.

Off-Balance Sheet Financing

Pengrowth does not have any off-balance sheet financing arrangements.

PENGROWTH 2017 Management's Discussion and Analysis 12

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, 2017	Dec 31, 2016		Dec 31, 2017	Dec 31, 2016
Drilling, completions and facilities
Lindbergh (1)	12.1	12.1		79.5	21.2
Groundbirch and conventional assets	15.4	1.4		22.0	4.1
Total drilling, completions and facilities	27.5	13.5		101.5	25.3
Land & seismic acquisitions (2)	0.2	0.9		0.4	(0.2	)
Maintenance capital	0.4	14.1		15.3	38.6
Development capital	28.1	28.5		117.2	63.7
Other capital	0.1	(0.1	)	0.7	0.7
Capital expenditures	28.2	28.4		117.9	64.4

⁽¹⁾  Excludes capitalized interest, see Interest and Financing Charges section of the MD&A.

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

Fourth quarter of 2017 capital expenditures were $28.2 million and primarily focused on Pengrowth's two core assets Lindbergh and Groundbirch. Lindbergh capital spending was focused primarily on completion of the Phase 1 optimization program which entailed drilling a total of 10 well pairs and 2 infill wells in 2017. 1 well pair and the 2 infill wells commenced production in the third quarter. Steam was circulated in the fourth quarter on 6 well pairs with 2 of these pairs being converted to SAGD production by the end of the fourth quarter of 2017, and 4 of these pairs scheduled for conversion to SAGD production in the first quarter of 2018. The 3 remaining well pairs are on schedule for equipment installation to allow steaming in the first quarter of 2018 with conversion to SAGD production in the second quarter 2018. Groundbirch capital expenditures were focused on a drilling and optimization program. Pengrowth completed drilling of the remaining 3 wells for a total of 4 wells drilled in 2017 at Groundbirch together with construction of a new sales line to the Nova Gas Transmission Ltd. system. Pengrowth anticipates the completion of this project by the second quarter of 2018 with gas sales increasing to approximately 30 MMcf/d from December 2017 production of approximately 9 MMcf/d.

Full year 2017 capital expenditures were $117.9 million, with $84.8 million spent at Lindbergh inclusive of maintenance capital, $21.6 million spent at Groundbirch, and the remainder spent on maintenance at Pengrowth's conventional properties.

2018 Capital Program

Pengrowth’s 2018 capital budget of $65 million is expected to grow overall corporate production volumes through the course of the year from a December 2017 exit production rate of approximately 19,000 boe/d, excluding the Quirk Creek production volumes, to an estimated 2018 exit rate of approximately 24,000 boe/d, representing approximately 25 percent production growth in 2018.

Pengrowth allocated approximately $45 million towards continued development and maintenance activities at its Lindbergh thermal project. 2018 development plans at Lindbergh include approximately $33 million focused on continued optimization activities, including the drilling of 8 additional infill wells. The 8 infill wells in the 2018 capital program are expected to be drilled in the second quarter of 2018 with production in the fourth quarter of 2018, increasing Lindbergh production to approximately 18,000 bbl/d by the end of the year. The remaining $12 million of capital is for maintenance activities to support the continued production growth from existing operations.

At Groundbirch, Pengrowth allocated approximately $17 million to fund the completion and tie-in of the 4 wells which were drilled in 2017. The completion of these wells is expected to increase natural gas production from Groundbirch from December's production of approximately 9 MMcf/d to approximately 30 MMcf/d, with the initial volumes coming in April 2018. In addition to the drilling and completion program, Pengrowth is working on the completion of a compression project which will allow the Company to shift transportation of natural gas production at Groundbirch away from Station

PENGROWTH 2017 Management's Discussion and Analysis 13

2 and onto the Nova system in Alberta. Once Groundbirch production reaches 30 MMcf/d, it will approximate the natural gas consumption at Lindbergh.

The 2018 capital program also includes approximately $3 million of capital that has been allocated to Pengrowth’s remaining conventional assets as well as for general corporate purposes.

OIL AND GAS RESERVES

Reserves - Company Interest at Forecast Prices

Reserves Summary (1) (MMboe except as noted)	2017		2016
Proved Reserves
Additions + revisions for the year	27.7		60.7
Net dispositions for the year	(106.0	)	(6.1	)
Total proved reserves at period end	192.7		285.8
Proved reserve future development costs ($ millions)	1,932		1,980
Proved plus Probable Reserves (P+P)
Additions + revisions for the year	3.0		76.2
Net dispositions for the year	(150.1	)	(15.9	)
Total proved plus probable reserves at period end	446.6		608.5
P+P reserve future development costs ($ millions)	4,941		5,234
Total production (MMboe)	14.8		20.9

⁽¹⁾  Based on January 1, 2018 GLJ pricing and prepared in accordance with NI 51-101.

Pengrowth’s 2017 total proved reserves and total proved plus probable reserves decreased by 33 percent and 27 percent, respectively, from 2016. This decrease is attributed to the disposition activity that occurred in 2017. The reserve additions due to development activity and technical revisions were 27.7 MMboe for total proved reserves and 3.0 MMboe for total proved plus probable reserves. These additions were primarily due to positive performance revisions and drilling additions relating to undeveloped locations at Lindbergh, along with positive performance revisions at Groundbirch.

Details of Pengrowth’s 2017 year end reserves are provided in its AIF which is filed on SEDAR (www.sedar.com) or the 40-F filed on EDGAR (www.sec.gov).

PRODUCTION

	Three months ended				Twelve months ended
Daily production	Dec 31, 2017	% of total	Dec 31, 2016	% of total	Dec 31, 2017	% of total	Dec 31, 2016	% of total
Light oil (bbl/d)	2,094	8	10,597	19	6,872	17	11,736	21
Bitumen (bbl/d)	14,430	58	15,209	28	13,754	34	15,585	27
Natural gas liquids (bbl/d)	1,136	5	7,976	15	4,574	11	7,763	14
Natural gas (Mcf/d)	42,251	29	123,434	38	91,367	38	131,847	38
Total boe/d	24,702		54,354		40,428		57,058

Fourth quarter and full year 2017 average daily production decreased 55 percent and 29 percent, respectively, compared to the same periods in 2016 mainly due to property divestments combined with natural declines and planned maintenance related downtime.

Fourth quarter and full year 2017 light oil production decreased 80 percent and 41 percent, respectively, relative to the same periods in 2016 primarily due to the Olds/Garrington and Swan Hills/Judy Creek dispositions.

Bitumen production decreased 5 percent in the fourth quarter of 2017 compared to the same period in 2016 as planned downtime and natural declines at Lindbergh outpaced the production growth from new wells drilled in 2017 as the majority of the new production will occur in 2018. Full year 2017 bitumen production decreased 12 percent mostly attributed to planned turnaround downtime at Lindbergh in addition to natural declines and absence of production from an unrelated property that was disposed of in 2016.

PENGROWTH 2017 Management's Discussion and Analysis 14

Fourth quarter and full year 2017 natural gas liquids production decreased 86 percent and 41 percent, respectively, compared to the same periods in 2016 primarily due to the Olds/Garrington and Swan Hills/Judy Creek dispositions.

Natural gas production decreased 66 percent and 31 percent in the fourth quarter and full year 2017, respectively, compared to the same periods in 2016 due to dispositions combined with natural declines and planned maintenance related downtime.

COMMODITY PRICES

Oil and Liquids Prices Excluding Realized Commodity Risk Management from Financial Contracts

	Three months ended				Twelve months ended
(U.S.$/bbl)	Dec 31, 2017		Dec 31, 2016		Dec 31, 2017		Dec 31, 2016
Average exchange rate (Cdn$1 = U.S.$)	0.79		0.75		0.77		0.75
Average Benchmark Prices
WTI oil	55.39		49.33		50.93		43.37
WCS differential to WTI	(12.28	)	(14.33	)	(11.96	)	(13.84	)
WCS oil	43.11		35.00		38.97		29.53

	Three months ended				Twelve months ended
(Cdn$/bbl)	Dec 31, 2017		Dec 31, 2016		Dec 31, 2017		Dec 31, 2016
Average Benchmark Prices
WTI oil	70.45		65.78		66.09		57.32
Edmonton par light oil	68.98		61.62		62.90		53.05
WCS oil	54.83		46.67		50.53		38.96
Differentials to WTI
Edmonton par	(1.47	)	(4.16	)	(3.19	)	(4.27	)
WCS oil	(15.62	)	(19.11	)	(15.56	)	(18.36	)
Average Sales Prices
Light oil	61.25		59.59		59.52		50.24
Bitumen (1) (2)	41.28		37.88		36.17		30.19
Natural gas liquids	50.71		30.80		33.96		22.60

⁽¹⁾  Fourth quarter and full year 2017 bitumen average sale prices were lower by approximately Cdn$4.86/bbl and Cdn$5.72/bbl, respectively, due to the impact of physical delivery contracts.

⁽²⁾  Calculated based on bitumen sales volumes and excludes diluent.

WTI crude oil prices continued to improve in the fourth quarter of 2017 with prices averaging U.S.$55.39/bbl, an increase of 12 percent from the same period in 2016. Full year 2017 WTI price averaged U.S.$50.93/bbl, representing a 17 percent improvement from the average prices in 2016 of U.S.$43.37/bbl.

For Canadian producers, exchange rates, location and quality differentials as well as transportation bottlenecks are all factors that influence the Canadian crude oil prices received. Movements in the Canadian dollar versus the U.S. dollar influence the relative Canadian equivalent prices that Canadian companies realize. Quality differentials and transportation bottlenecks result in Edmonton par and WCS differentials relative to the U.S. based WTI benchmark, leading to Canadian producers receiving discounted prices for their product.

WCS benchmark prices benefited from a narrowing of the WCS to WTI price differential in 2017 compared to 2016 as a result of production disruptions impacting the supply of Canadian bitumen in the first half of 2017. During the fourth quarter of 2017, the WCS index to WTI price differential narrowed to an average of U.S.$12.28/bbl compared to U.S.$14.33/bbl in the fourth quarter 2016 however bitumen spot prices declined as a result of pipeline disruptions in late 2017. Fourth quarter of 2017 bitumen average sales price increased to Cdn$41.28/bbl representing a 9 percent increase from the same period in 2016. Pengrowth uses physical delivery contracts to ensure access to markets, protect against pipeline apportionment, limit credit risk and exposure to widening WCS differentials. Since Pengrowth's physical delivery fixed price differential contracts averaged approximately U.S.$15.70/bbl, this resulted in a lower realized bitumen sales price by approximately Cdn$4.86/bbl as compared to index prices in the fourth quarter of 2017. At the end of the fourth

PENGROWTH 2017 Management's Discussion and Analysis 15

quarter and into early 2018, the WCS to WTI differential widened significantly due to transportation constraints, however as a result of Pengrowth's physical delivery contracts, the impacts of the wider price differential are expected to be minimized in 2018. A full summary of Pengrowth's WCS differential contracts is included below in the Commodity Risk Management section.

After taking into consideration the changes in foreign exchange between the Canadian and US dollars, the Canadian equivalent pricing for light oil moved in line with the price differentials and the underlying benchmark. Pengrowth’s fourth quarter of 2017 average light oil sales price of Cdn$61.25/bbl increased 3 percent compared to the same period in 2016, while full year 2017 light oil sales price increased by 18 percent, consistent with improvements in benchmark prices.

Full year 2017 light oil and bitumen average sales prices increased 18 percent and 20 percent, respectively, consistent with the gains in benchmark prices. Stronger benchmark prices coupled with the narrowing of the light oil differential were the primary drivers behind the higher light oil average sales prices. Full year 2017 bitumen average sales price increase was driven by a 30 percent increase in WCS partly offset by the physical delivery differential loss of approximately Cdn$5.72/bbl.

Sales of natural gas liquids (NGLs) primarily comprise propane, butane, pentane and condensate. Price realizations for NGLs in the fourth quarter of 2017 increased by 65 percent compared to the same period in 2016 driven by improvement in benchmarks. Full year 2017 realized NGL prices also reflected the changes in the benchmark prices, with 2017 full year realized prices being 50 percent higher compared to the same period in 2016.

Natural Gas Prices Excluding Realized Commodity Risk Management from Financial Contracts

	Three months ended				Twelve months ended
(Cdn$)	Dec 31, 2017		Dec 31, 2016		Dec 31, 2017		Dec 31, 2016
Average Benchmark Prices
NYMEX gas (per MMBtu)	3.71		4.24		3.92		3.38
AECO monthly gas (per MMBtu)	1.98		2.81		2.43		2.09
Differential to NYMEX
AECO differential (per MMBtu)	(1.73	)	(1.43	)	(1.49	)	(1.29	)
Average Sales Price
Natural gas (per Mcf) (1)	3.22		3.03		2.96		2.25

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

The U.S. based NYMEX natural gas price decreased 13 percent to Cdn$3.71/MMBtu during the fourth quarter of 2017 compared to the same period in 2016 primarily due to slightly milder weather impacting demand. Full year 2017 natural gas prices improved 16 percent to Cdn$3.92/MMBtu compared to 2016, as improved supply/demand fundamentals in the U.S. contributed to the price increase.

The price realized by the Company for natural gas production from Western Canada is primarily determined by the AECO benchmark and based on Canadian fundamentals. Pengrowth also sells its natural gas at several other sales points in addition to AECO monthly, which can result in a significant variance between Pengrowth's realized natural gas prices and the benchmark prices in any given period.

Western Canadian natural gas prices decreased in the fourth quarter of 2017 with the AECO monthly gas price averaging Cdn$1.98/MMBtu, a decrease of 30 percent compared to the same period in 2016. The large decrease in Canadian benchmark prices was primarily due to an oversupply of Canadian natural gas and transportation constraints contributing to a widening of the price differential between NYMEX and AECO. Full year 2017 AECO price increased by 16 percent compared to 2016 largely following the NYMEX increase.

Pengrowth’s fourth quarter of 2017 average sales price for natural gas, before the impact of commodity risk management activities, increased 6 percent from the same period in 2016 despite a 30 percent decrease in AECO as a result of selling at several sales points including Algonquin City Gate trading hub in the Northeast U.S. for SOEP gas. Full year 2017 average sales price for natural gas, before the impacts of commodity risk management activities, increased 32 percent from 2016, consistent with the improvement in AECO benchmark pricing, coupled with the impact of selling at other sales points in addition to AECO monthly, as mentioned above.

PENGROWTH 2017 Management's Discussion and Analysis 16

Produced Petroleum Revenue Realizations

	Three months ended			Twelve months ended
($/boe)	Dec 31, 2017		Dec 31, 2016	Dec 31, 2017		Dec 31, 2016
Produced petroleum revenue (1)	37.14		33.62	32.96		26.86
Realized commodity risk management gain (loss)	(2.90	)	15.44	(1.34	)	18.47
Total including realized commodity risk management	34.24		49.06	31.62		45.33

⁽¹⁾  Calculated based on light oil, bitumen, natural gas liquids and natural gas sales volumes and excludes processing income, diluent and other revenue. See definition under section "Non-GAAP Financial Measures".

Pengrowth’s fourth quarter and full year 2017 produced petroleum revenue realizations of $37.14/boe and $32.96/boe increased 10 percent and 23 percent, respectively, compared to the same periods in 2016, reflecting the increase in prices for all commodities.

A realized commodity risk management loss of $2.90/boe was recorded in the fourth quarter of 2017, compared to a gain of $15.44/boe in the fourth quarter of 2016. The significant decrease was primarily due to lower contracted crude oil and natural gas risk management volumes in the fourth quarter of 2017. Full year 2017, Pengrowth incurred a realized commodity risk management loss of $1.34/boe, compared to a gain of $18.47/boe in 2016 primarily due to lower contracted crude oil and natural gas risk management volumes in 2017.

Realized Commodity Risk Management Gains (Losses) from Financial Contracts

	Three months ended			Twelve months ended
($ millions except per unit amounts)	Dec 31, 2017		Dec 31, 2016	Dec 31, 2017		Dec 31, 2016
Oil risk management gain (loss)	(9.0	)	47.3	(25.8	)	289.2
$/bbl (1)	(5.92	)	19.92	(3.43	)	28.92
Natural gas risk management gain (loss)	2.4		29.9	6.0		96.5
$/Mcf	0.62		2.63	0.18		2.00
Total realized commodity risk management gain (loss)	(6.6	)	77.2	(19.8	)	385.7
$/boe	(2.90	)	15.44	(1.34	)	18.47

⁽¹⁾  Includes light oil and bitumen.

Pengrowth has an active commodity risk management program which primarily uses forward price swaps 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. See the Forward Contracts - Commodity Risk Management section of this document for information on the Company's forward price swaps and physical delivery 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 at settlement. Realized losses result when the average fixed risk management contracted prices are lower than the benchmark prices, while realized gains are recorded when the average fixed risk management contracted prices are higher than the benchmark prices at settlement. Realized gains and losses directly impact cash flow for the period.

A realized commodity risk management loss of $6.6 million was recorded in the fourth quarter of 2017, compared to a gain of $77.2 million in the fourth quarter of 2016 primarily due to lower volumes under risk management and lower contracted commodity risk management prices for both crude oil and natural gas in the fourth quarter of 2017. A realized commodity risk management loss of $19.8 million was recorded in 2017, compared to a gain of $385.7 million in the same period in 2016 due to the lower contracted crude oil and natural gas commodity risk management volumes in 2017.

PENGROWTH 2017 Management's Discussion and Analysis 17

Changes in Fair Value of Financial Commodity Risk Management Contracts

	Three months ended				Twelve months ended
($ millions)	Dec 31, 2017		Dec 31, 2016		Dec 31, 2017		Dec 31, 2016
Fair value of commodity risk management assets (liabilities) at period end	(39.8	)	(54.0	)	(39.8	)	(54.0	)
Less: Fair value of commodity risk management assets (liabilities) at beginning of period	(6.5	)	51.1		(54.0	)	370.5
Change in fair value of commodity risk management contracts for the period	(33.3	)	(105.1	)	14.2		(424.5	)

Changes in fair value of commodity risk management contracts vary period to period and are a function of the volumes under risk management contracts, actual settlements of risk management contracts during the period, 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. A decrease in fair value of commodity risk management contracts occurs when the forward price curve moves higher in relation to the fixed price, with the magnitude of the change being proportional to the movement in the forward price curve. An increase in fair value of commodity risk management contracts occurs when the forward price curve moves lower in relation to the fixed price, with the magnitude of the change being proportional to the movement in the forward price curve. Changes in fair value of commodity risk management contracts are also affected by the change in volumes under risk management in the period. Changes in fair value of commodity risk management contracts are reported on the Consolidated Statements of Income (Loss) and do not impact cash flow for the period.

Pengrowth recorded a decrease of $33.3 million in the fair value of commodity risk management contracts at December 31, 2017, as the fair value of commodity risk management liabilities from September 30, 2017 of $6.5 million increased to a liability of $39.8 million at December 31, 2017. The change was primarily the result of change in forward price curves and the settlement of contracts in the fourth quarter of 2017.

The fair value of commodity risk management contracts increased $14.2 million at December 31, 2017, relative to December 31, 2016 mainly as a result of lower volumes and fixed prices under risk management, changes in forward price curves and the $19.8 million realized losses on settlement of contracts in 2017.

Forward Contracts - Commodity Risk Management

Pengrowth primarily uses crude oil and natural gas swaps and collars to manage its exposure to commodity price fluctuations. In addition, financial and physical contracts are sometimes used to manage oil price differentials.

At December 31, 2017, Pengrowth had the following financial contracts outstanding:

Crude Oil
Financial Swap Contracts
Reference point	Term	Volume (bbl/d)	Price/bbl (U.S.$)
WTI	2018	8,000	49.97

Collars			Price/bbl (U.S.$)
Reference point	Term	Volume (bbl/d)	Bought Puts	Sold Calls
WTI	2018	2,000	$48.00	$53.48

Pengrowth recorded a $39.8 million liability related to forward crude oil swaps and collars at December 31, 2017. The impact of realized financial contracts is included in the Realized gain (loss) on commodity risk management as per the Consolidated Statements of Income (Loss).

PENGROWTH 2017 Management's Discussion and Analysis 18

At December 31, 2017, physical delivery contracts were held for the purpose of delivery of non-financial items in accordance with Pengrowth's expected sales requirements. The prices per bbl as per the table below, include an apportionment protection fee to guarantee flow assurance in the event export pipelines are restricted.

WCS Differentials
Physical Delivery Contracts
Reference point	Term	Volume of diluted bitumen (bbl/d)	Price/bbl (U.S.$)
Western Canada Select	2018	12,000	WTI less $16.95
Western Canada Select	2018	5,000	WTI less $16.50 - $19.25
Western Canada Select	2019	2,500	WTI less $17.95
Western Canada Select	2019	5,000	WTI less $17.70 - $20.45

In the fourth quarter of 2017, Pengrowth produced an average of 14,430 bbl/d of bitumen and sold an average of 20,520 bbl/d of diluted bitumen at Hardisty. Physical delivery contracts are not considered financial instruments and therefore, no asset or liability has been recognized in the Consolidated Financial Statements related to these contracts. The impact of realized physical delivery contracts is included in Oil and gas sales, as per the Consolidated Statements of Income (Loss), and therefore in realized average sales prices.

See the Commodity Price Contracts section in Note 17 to the December 31, 2017 audited Consolidated Financial Statements for more information.

Financial Risk Management Contracts Sensitivity to Commodity Prices as at December 31, 2017

($ millions)
Crude oil swaps and collars	Cdn$1/bbl increase in future oil prices		Cdn$1/bbl decrease in future oil prices
Increase (decrease) to fair value of oil risk management contracts	(3.5	)	3.5

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 was to have settled at December 31, 2017, revenue and cash flow would have been $39.8 million lower than if the risk management contracts were not in place based on the estimated fair value of the risk management contracts at period end. The $39.8 million liability was related to risk management contracts expiring within 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 of commodity risk management contracts on the Consolidated Statements of Income (Loss). 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 financial crude oil and natural gas contracts are recorded separately on the Consolidated Statements of Income (Loss) and impact cash flow at that time.

PENGROWTH 2017 Management's Discussion and Analysis 19

OIL AND GAS SALES

The following table shows the composition of oil and gas sales:

	Three months ended		Twelve months ended
($ millions)	Dec 31, 2017	Dec 31, 2016	Dec 31, 2017	Dec 31, 2016
Light oil	11.8	58.1	149.3	215.8
Bitumen	54.8	53.0	181.6	172.2
Natural gas liquids	5.3	22.6	56.7	64.2
Natural gas	12.5	34.4	98.8	108.7
Produced petroleum revenue (1)	84.4	168.1	486.4	560.9
Diluent and other revenue	46.1	1.1	187.0	5.3
Oil and gas sales (2) (3)	130.5	169.2	673.4	566.2

⁽¹⁾  See definition under section "Non-GAAP Financial Measures".

⁽²⁾  Excludes realized commodity risk management from financial contracts.

⁽³⁾  Adoption of IFRS 15 was effective January 1, 2017 using cumulative effect approach without restating prior period comparatives. See Notes 2 and 14 to the December 31, 2017 audited Consolidated Financial Statements.

In order to reduce viscosity and meet pipeline specifications, bitumen requires blending with a diluent. The cost of diluent is mostly recovered when the blended product, also known as dilbit or diluted bitumen, is sold at Hardisty. This is reflected in diluent and other revenue together with processing income.

Price and Volume Analysis

Quarter ended December 31, 2017versus Quarter endedDecember 31, 2016

The following table illustrates the effect of changes in prices and volumes on the components of produced petroleum revenue:

($ millions)	Light oil		Bitumen		NGLs		Natural gas		Produced petroleum revenue
Quarter ended December 31, 2016 (1)	58.1		53.0		22.6		34.4		168.1
Effect of change in product prices and differentials	0.3		4.5		2.1		0.7		7.6
Effect of change in sales volumes	(46.6	)	(2.7	)	(19.4	)	(22.6	)	(91.3	)
Quarter ended December 31, 2017 (1)	11.8		54.8		5.3		12.5		84.4

⁽¹⁾  Excludes realized commodity risk management from financial contracts.

Light oil sales decreased 80 percent in the fourth quarter of 2017 compared to the fourth quarter of 2016 primarily due to lower sales volumes resulting from the Olds/Garrington and Swan Hills/Judy Creek dispositions. Bitumen sales remained virtually unchanged in the fourth quarter of 2017 compared to the same period in 2016 as the 17 percent improvement in WCS benchmark price was partially offset by a decrease in sales volumes, planned downtime and natural declines. NGL and natural gas sales decreased 77 percent and 64 percent, respectively, compared to the fourth quarter of 2016 also due to the decrease in sales volumes related to divestments. These decreases were partly offset by an improvement in realized prices.

Twelve Months ended December 31, 2017 versus Twelve Months ended December 31, 2016

The following table illustrates the effect of changes in prices and volumes on the components of produced petroleum revenue:

($ millions)	Light oil		Bitumen		NGLs		Natural gas		Produced petroleum revenue
Twelve months ended December 31, 2016 (1)	215.8		172.2		64.2		108.7		560.9
Effect of change in product prices and differentials	23.3		30.0		19.0		23.7		96.0
Effect of change in sales volumes	(89.8	)	(20.6	)	(26.5	)	(33.6	)	(170.5	)
Twelve months ended December 31, 2017 (1)	149.3		181.6		56.7		98.8		486.4

⁽¹⁾  Excludes realized commodity risk management from financial contracts.

PENGROWTH 2017 Management's Discussion and Analysis 20

Full year 2017 light oil sales decreased 31 percent compared to 2016 resulting from lower sales volumes due to divestments partially offset by a 19 percent improvement in the Edmonton par light oil benchmark price. Bitumen sales increased 5 percent resulting from a 30 percent increase in the WCS benchmark price partly offset by lower volumes related to planned downtime and natural declines at Lindbergh combined with losses on physical delivery contracts. NGL sales decreased 12 percent driven by the impact of lower sales volumes as a result of divestments largely offset by higher benchmark prices. Natural gas sales decreased 9 percent due to lower sales volumes, partly offset by improved natural gas benchmark prices.

ROYALTIES

($ millions except per boe amounts and percentages)	Three months ended		Twelve months ended
	Dec 31, 2017	Dec 31, 2016	Dec 31, 2017	Dec 31, 2016
Royalties, net of incentives	8.0	14.1	45.8	40.0
$/boe	3.52	2.82	3.10	1.91
Royalties as a percent of produced petroleum revenue (%) (1) (2)	9.5	8.4	9.4	7.1

⁽¹⁾  Excludes realized commodity risk management from financial contracts.

⁽²⁾  See definition under section "Non-GAAP Financial Measures".

Royalties include Crown, freehold, overriding royalties, mineral taxes and Gas Cost Allowance ("GCA").

Fourth quarter of 2017 royalties as a percent of produced petroleum revenues increased to 9.5 from 8.4 in the fourth quarter of 2016. The overall increase in royalty rates is attributed to property dispositions combined with the effect of increased pricing in 2017 and the inclusion of the 4.0 percent Lindbergh gross overriding royalty commencing in January 2017. The increase in full year 2017 royalty rate to 9.4 percent from 7.1 percent in 2016 was the result of property dispositions, higher pricing in 2017 and inclusion of the Lindbergh GORR.

NET OPERATING EXPENSES

($ millions except per boe amounts)	Three months ended		Twelve months ended
	Dec 31, 2017	Dec 31, 2016	Dec 31, 2017	Dec 31, 2016
Operating expenses (1)	30.1	70.0	217.5	275.4
Less: Processing income (2)	2.2	n/a	19.1	n/a
Net operating expenses (3)	27.9	70.0	198.4	275.4
$/boe	12.28	14.00	13.45	13.19

⁽¹⁾  Adoption of IFRS 15 was effective January 1, 2017 using cumulative effect approach without restating prior period comparatives. See Notes 2 and 14 to the December 31, 2017 audited Consolidated Financial Statements.

⁽²⁾  Processing income for the three and twelve months ended December 31, 2016 was $7.3 million and $27.4 million, respectively. Operating expenses for 2016 were not restated as a result of IFRS 15 adoption consistent with the cumulative effect approach.

⁽³⁾  See definition under section "Non-GAAP Financial Measures".

Fourth quarter and full year 2017 net operating expenses decreased $42.1 million or 60 percent and $77.0 million or 28 percent, respectively, compared to the same periods in 2016 primarily due to the absence of operating expenses associated with the divested properties. Full year 2017 decrease in net operating expenses was partly offset by increased costs for planned turnarounds and purchased fuel costs at Lindbergh.

On a per boe basis, fourth quarter of 2017 net operating expenses decreased $1.72/boe mostly driven by property dispositions. Full year 2017 net operating expenses per boe remained relatively unchanged compared to the same period in 2016 as decreases in production volumes and higher turnaround and fuel costs in 2017 offset decreases in costs.

PENGROWTH 2017 Management's Discussion and Analysis 21

DILUENT AND OTHER PURCHASES

	Three months ended		Twelve months ended
($ millions)	Dec 31, 2017	Dec 31, 2016	Dec 31, 2017	Dec 31, 2016
Diluent purchases	41.4	n/a	147.2	n/a
Other product purchases	1.3	n/a	16.3	n/a
Diluent and other purchases (1)	42.7	n/a	163.5	n/a

⁽¹⁾  Adoption of IFRS 15 was effective January 1, 2017 using cumulative effect approach without restating prior period comparatives. See Notes 2 and 14 to the December 31, 2017 audited Consolidated Financial Statements.

Diluent purchases reflect the cost of diluent required for processing activities and blending with bitumen to reduce viscosity and meet pipeline specifications. Other product purchases include third party hydrocarbons purchased for resale.

TRANSPORTATION EXPENSES

($ millions except per boe amounts)	Three months ended		Twelve months ended
	Dec 31, 2017	Dec 31, 2016	Dec 31, 2017	Dec 31, 2016
Transportation expenses	5.4	8.2	27.1	33.7
$/boe	2.38	1.64	1.84	1.61

Fourth quarter and full year 2017 transportation expenses decreased $2.8 million and $6.6 million, respectively, compared to the same periods of 2016 primarily due to the impacts of property divestments. On a per boe basis, the increases in 2017 relative to the same periods in 2016 result from Lindbergh representing a higher proportion of total production after the 2017 dispositions, and at a higher than average transportation cost per boe.

Pengrowth incurs transportation expenses for its natural gas production once the product enters a pipeline at a title transfer point. 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. As at December 31, 2017, Pengrowth has elected to sell approximately 90 percent of its production 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.

OPERATING NETBACKS

Pengrowth’s operating netbacks are defined as produced petroleum revenue, less royalties, less net operating expenses and less transportation expenses divided by production for the period. Operating netbacks may not be comparable to similar measures presented by other companies, as there are no standardized measures.

	Three months ended				Twelve months ended
Operating Netbacks ($/boe) (1)	Dec 31, 2017		Dec 31, 2016		Dec 31, 2017		Dec 31, 2016
Produced petroleum revenue	37.14		33.62		32.96		26.86
Royalties	(3.52	)	(2.82	)	(3.10	)	(1.91	)
Net operating expenses	(12.28	)	(14.00	)	(13.45	)	(13.19	)
Transportation expenses	(2.38	)	(1.64	)	(1.84	)	(1.61	)
Operating netbacks before realized commodity risk management	18.96		15.16		14.57		10.15
Realized commodity risk management	(2.90	)	15.44		(1.34	)	18.47
Operating netbacks ($/boe)	16.06		30.60		13.23		28.62

⁽¹⁾  See definition under section "Non-GAAP Financial Measures".

Fourth quarter and full year 2017 operating netbacks, before realized commodity risk management, increased 25 percent and 44 percent, respectively, compared to the same periods in 2016 in response to an increase in benchmark commodity prices year over year.

Fourth quarter and full year 2017 operating netbacks, after realized commodity risk management, decreased 48 percent and 54 percent, respectively, compared to the same periods in 2016 primarily due to the absence of substantial realized commodity risk management gains recorded in 2016.

PENGROWTH 2017 Management's Discussion and Analysis 22

GENERAL AND ADMINISTRATIVE EXPENSES

	Three months ended			Twelve months ended
($ millions except per boe amounts)	Dec 31, 2017		Dec 31, 2016	Dec 31, 2017		Dec 31, 2016
Cash G&A expenses (1)	12.6		17.8	56.6		70.4
$/boe	5.54		3.56	3.84		3.37
Non-cash G&A expenses (1)	(1.3	)	3.8	4.9		13.2
$/boe	(0.57	)	0.76	0.33		0.63
Total G&A (1)	11.3		21.6	61.5		83.6
$/boe	4.97		4.32	4.17		4.00
($ millions)
Cash G&A before share based compensation expense (1)	13.2		17.1	57.4		65.1
Share based compensation expense (1):
Cash-settled share based compensation	(0.6	)	0.7	(0.8	)	5.3
Share-settled share based compensation	(1.3	)	3.8	4.9		13.2
Total share based compensation expense	(1.9	)	4.5	4.1		18.5
Total G&A (1)	11.3		21.6	61.5		83.6

⁽¹⁾  Net of recoveries and capitalization, as applicable.

Fourth quarter 2017 cash G&A expenses decreased $5.2 million or 29 percent compared to the fourth quarter 2016 primarily due to reductions in staffing as a result of asset dispositions. Full year 2017 cash G&A expenses decreased $13.8 million or 20 percent compared to the prior year, also driven by reductions in staffing and a decrease in cash-settled share based compensation expense. The decrease in the cash-settled share based compensation expense was due to the mark-to-market impact of Pengrowth's share price which decreased 48 percent relative to the beginning of the year. See Note 13 to the December 31, 2017 audited Consolidated Financial Statements for additional information on Pengrowth's cash-settled Long Term Incentive Plans ("LTIP"). The compensation costs associated with these plans are expensed over the applicable vesting periods and are determined based on the fair value of the share units at the grant date and are subsequently adjusted to reflect the fair value of the share units at each period end. On a per boe basis, fourth quarter and full year 2017 cash G&A expenses increased $1.98/boe and $0.47/boe compared to the same periods in 2016, respectively, as decreases in production volumes outpaced decreases in cash G&A expenses.

The non-cash component of G&A represents the compensation expenses associated with Pengrowth’s share-settled LTIP. See Note 13 to the December 31, 2017 audited Consolidated Financial Statements for additional information on Pengrowth's share-settled LTIP. The compensation costs associated with these plans are expensed over the applicable vesting periods.

Fourth quarter and full year 2017 non-cash G&A expenses decreased $5.1 million and $8.3 million or 134 percent and 63 percent, respectively, compared to the same periods in 2016 primarily due to lower share-settled incentive grants and increased forfeiture rate estimates related to staff reductions.

During the twelve months ended December 31, 2017, $2.3 million (December 31, 2016 - $3.2 million) of directly attributable G&A costs were capitalized to Property, Plant and Equipment ("PP&E").

RESTRUCTURING COSTS

	Three months ended		Twelve months ended
($ millions)	Dec 31, 2017	Dec 31, 2016	Dec 31, 2017	Dec 31, 2016
Severance costs	1.3	—	10.5	—
Onerous office lease contracts	18.5	—	26.5	—
Total restructuring costs	19.8	—	37.0	—

PENGROWTH 2017 Management's Discussion and Analysis 23

Pengrowth completed a number of significant asset dispositions which led to a management decision to complete an operational restructuring commencing in the third quarter of 2017. This resulted in significantly lower staff levels and, accordingly, substantial vacant office space.

Pengrowth recognized a $37.0 million restructuring cost in 2017 composed of $10.5 million of severance costs from staff reductions and $26.5 million for an onerous office lease obligation related to excess office space. The economic benefits of the office lease were exceeded by the unavoidable costs of the lease contracts over the remaining term.

LOSS ON EXTINGUISHMENT OF DEBT

After performing quantitative and qualitative analysis of the previously discussed debt restructuring, it was concluded that debt terms have been substantially modified and, as such, the modification was accounted for as an extinguishment of the old debt.

Loss on extinguishment of debt was reflected in the year ended December 31, 2017 Consolidated Statements of Income (Loss) in the amount of $56.7 million and was composed of $55.2 million of debt restructuring costs and $1.5 million of remaining unamortized issue costs. Debt restructuring costs included the amendment fees, make whole payments on the principal prepayments, and related professional fees.

DEPLETION, DEPRECIATION, AMORTIZATION AND ACCRETION

	Three months ended		Twelve months ended
($ millions except per boe amounts)	Dec 31, 2017	Dec 31, 2016	Dec 31, 2017	Dec 31, 2016
Depletion, depreciation and amortization	31.9	75.3	207.6	349.9
$/boe	14.04	15.06	14.07	16.76
Accretion	1.3	3.6	11.4	15.1
$/boe	0.57	0.72	0.77	0.72

Fourth quarter and full year 2017 DD&A expense decreased $43.4 million and $142.3 million, respectively, compared to the same periods in 2016 primarily due to a lower depletable base resulting from property divestments and changes in reserves and future development costs relative to 2016. On a per boe basis, fourth quarter and full year 2017 DD&A decreased $1.02/boe and $2.69/boe, respectively, compared to the same periods in 2016 as the decreases in DD&A outpaced decreases in volumes.

Fourth quarter and full year 2017 ARO accretion expense decreased $2.3 million and $3.7 million, respectively, compared to the same periods in 2016 due to the absence of accretion related to the ARO liability associated with 2017 property dispositions.

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.

E&E assets totaled $232.0 million at December 31, 2017 and were primarily related to the Groundbirch gas property in north eastern British Columbia. During 2017, Pengrowth disposed of certain E&E assets, including its Bernadet property in north eastern British Columbia, resulting in the reduction in E&E assets of $134.3 million from December 31, 2016. During the fourth quarter of 2017, it was determined that recoverable amounts were below the carrying amounts on certain E&E gas projects resulting in a $130.0 million impairment in the year. See the Impairments section of this MD&A and Note 6 to the December 31, 2017 audited Consolidated Financial Statements for more information.

PENGROWTH 2017 Management's Discussion and Analysis 24

IMPAIRMENTS

	Three months ended		Twelve months ended
($ millions)	Dec 31, 2017	Dec 31, 2016	Dec 31, 2017	Dec 31, 2016
PP&E impairments	—	—	504.4	—
E&E impairments	130.0	—	130.0	—
Total impairments	130.0	—	634.4	—

PP&E Impairments

PP&E impairment charges recorded for the year ended December 31, 2017 totaled $504.4 million (December 31, 2016 - $nil). Throughout 2017's asset dispositions, there were several instances where a purchase and sale agreement ("PSA") was signed subsequent to the respective quarter end for proceeds less than net book value therefore being an indicator of impairment. In these situations, where the sales price in a PSA was below the carrying amount, an impairment was recorded. In addition, remaining assets in the Southern and Northern CGUs were impaired down to $nil based on the nominal value received for similar asset transactions and the Company's focus on Lindbergh and Groundbirch.

Upon completion of the various asset dispositions in 2017, Pengrowth's remaining CGUs include Lindbergh, Groundbirch, Sable Offshore Energy Project ("SOEP"), Northern and Southern.

E&E Impairments

For the year ended December 31, 2017, Pengrowth evaluated Groundbirch gas property for an impairment in conjunction with the Montney CGU, comprising both PP&E and E&E assets, due to the negative impact resulting from the significant downturn in the forward natural gas benchmark prices late in 2017. 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 $129.0 million impairment on the Groundbirch E&E asset was recorded in the fourth quarter of 2017. In addition, a $1.0 million impairment was recognized on other minor E&E projects as no further exploration or evaluation is intended on those projects.

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. 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 for proven reserves and 12 percent for probable reserves; independent reserves evaluator January 1, 2018 forecast pricing and an inflation rate of 2 percent; and contingent resources using a pre-tax discount rate of 15 percent. The recoverable amount was determined using value in use. See Note 6 to the December 31, 2017 audited Consolidated Financial Statements for more information.

INTEREST AND FINANCING CHARGES

	Three months ended				Twelve months ended
($ millions)	Dec 31, 2017		Dec 31, 2016		Dec 31, 2017		Dec 31, 2016
Interest and financing charges	13.4		27.0		74.4		108.5
Capitalized interest	(1.0	)	(0.7	)	(3.7	)	(3.0	)
Total interest and financing charges	12.4		26.3		70.7		105.5

At December 31, 2017, Pengrowth had $501.5 million in outstanding fixed rate debt and $109.0 million of Credit Facility borrowings.Total fixed rate debt consists primarily of U.S. dollar denominated term notes at a weighted average interest rate of 6.6 percent and the Credit Facility had an average 6.3 percent interest rate.

Fourth quarter and full year 2017 interest and financing charges, before capitalized interest, decreased $13.6 million or 50 percent and $34.1 million or 31 percent, respectively, compared to the same periods in 2016 reflecting the impact of the prepayments of term notes of approximately $1 billion throughout 2017, and the repayment of $126.6 million of convertible debentures at maturity on March 31, 2017.

PENGROWTH 2017 Management's Discussion and Analysis 25

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 twelve months ended December 31, 2017, $3.7 million (December 31, 2016 - $3.0 million) of interest was capitalized on the Lindbergh project to PP&E using Pengrowth's weighted average cost of debt of 5.7 percent (December 31, 2016 - 5.7 percent).

OTHER (INCOME) EXPENSE

Full year 2017 other income of $7.4 million, represented an increase of $4.7 million from 2016. The increase is primarily due to receiving an insurance settlement, higher investment income 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 $57.6 million in the fourth quarter of 2017 compared to a deferred tax recovery of $9.9 million in the fourth quarter of 2016. This was primarily due to the temporary differences related to PP&E impairment charges and temporary differences related to asset dispositions that closed in 2017. Full year 2017 deferred tax recovery amounted to $223.8 million compared to a recovery of $93.4 million in 2016 driven by the above mentioned temporary differences.

Pengrowth has certain income tax filings from predecessor entities that are in dispute with tax authorities and has paid $9.5 million and $2.7 million to the Canada Revenue Agency ("CRA") and the Alberta Tax and Revenue Administration, respectively, to formally begin the process of challenging the particular taxation year. Pengrowth believes that its filings to-date are correct and that it will be successful in defending its positions. Therefore, no provision for any potential income tax liability was recorded and the $12.2 million has been recorded as a long term receivable.

See Notes 4 and 11 to the December 31, 2017 audited Consolidated Financial Statements for additional information.

FOREIGN CURRENCY GAINS (LOSSES)

	Three months ended				Twelve months ended
($ millions)	Dec 31, 2017		Dec 31, 2016		Dec 31, 2017		Dec 31, 2016
Currency exchange rate (Cdn$1 = U.S.$) at beginning of period	0.80		0.76		0.74		0.72
Currency exchange rate (Cdn$1 = U.S.$) at period end	0.80		0.74		0.80		0.74
Unrealized foreign exchange gain (loss) on U.S. dollar denominated debt (1)	(4.9	)	(34.8	)	66.1		46.8
Unrealized foreign exchange gain (loss) on U.K. pound sterling denominated debt (1)	(0.3	)	0.7		(0.5	)	5.8
Total unrealized foreign exchange gain (loss) from translation of foreign denominated debt	(5.2	)	(34.1	)	65.6		52.6
Unrealized gain (loss) on U.S. foreign exchange risk management contracts (2)	35.8		(26.7	)	(15.0	)	(80.6	)
Unrealized gain (loss) on U.K. foreign exchange risk management contracts	0.4		(0.8	)	0.8		(5.4	)
Total unrealized gain (loss) on foreign exchange risk management contracts	36.2		(27.5	)	(14.2	)	(86.0	)
Net unrealized foreign exchange gain (loss)	31.0		(61.6	)	51.4		(33.4	)
Net realized foreign exchange gain (loss) (3)	(34.4	)	46.8		(38.4	)	46.5

⁽¹⁾  Includes both principal and interest.

⁽²⁾  Includes both foreign exchange risk management contracts associated with the U.S. term notesand with the U.S. dollar fixed price WCS differential.

⁽³⁾  Twelve months ended December 31, 2017 includes $37.6 million loss from settlement of foreign exchange swap contracts related to the prepayment of term notes.

As 79 percent of Pengrowth’s total debt before working capital is denominated in foreign currencies at December 31, 2017, the majority of Pengrowth’s unrealized foreign exchange gains and losses are attributable to the translation of this debt into Canadian dollars and changes in the fair value of the related foreign exchange swap contracts Pengrowth employs to manage this risk.

The gains or losses on foreign debt principal restatement each period are calculated by comparing the translated Canadian dollar balance of foreign currency denominated long term debt from one period to another. The magnitude

PENGROWTH 2017 Management's Discussion and Analysis 26

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.

Foreign Exchange Contracts Associated with U.S. Dollar Denominated Term Debt

Pengrowth holds a series of swap contracts which were transacted in order to fix the foreign exchange rate on a portion of principal for 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.

In March 2017, U.S.$300 million of foreign exchange swap contracts settled in tandem with the U.S.$300 million prepayment of the U.S.$400 million term notes due July 26, 2017. This resulted in a Cdn$2.8 million realized foreign exchange loss in the first quarter of 2017.

In October 2017, U.S.$365 million of foreign exchange swap contracts settled along with the U.S.$265 million prepayment of the term notes due August 21, 2018 and additional prepayments of the remaining outstanding U.S. term notes. This resulted in a Cdn$34.8 million realized foreign exchange loss in the fourth quarter of 2017.

At December 31, 2017, Pengrowth held a total of U.S.$255 million in foreign exchange swap contracts compared to U.S.$920 million at December 31, 2016 at a weighted average rate of U.S.$0.75 per Cdn$1 as follows:

Principal amount (U.S.$ millions)	Swapped amount (U.S.$ millions)	% of principal swapped		Average fixed rate (Cdn$1 = U.S.$)
366.3	255.0	70	%	0.75

At December 31, 2017, the fair value of these U.S. foreign exchange derivative contracts was a liability of Cdn$18.6 million and has been included on the Consolidated Balance Sheets. Changes in the fair value of these contracts between Balance Sheet dates are reported on the Consolidated Statements of Income (Loss) as an unrealized foreign exchange (gain) loss.

Foreign Exchange Contracts Associated with U.K. Pound Sterling Denominated Term Debt

Pengrowth entered into foreign exchange risk management contracts when it issued the U.K. pound sterling denominated term debt. At December 31, 2017, Pengrowth held the following contract fixing the Canadian dollar to the U.K. pound sterling exchange rate on the interest and principal of the U.K. pound sterling denominated debt maturing in October 2019:

Principal amount (U.K. pound sterling millions)	Swapped amount (U.K. pound sterling millions)	% of principal swapped (1)		Fixed rate (Cdn$1 = U.K. pound sterling)
12.1	15.0	124	%	0.63

⁽¹⁾  Exceeds 100 percent as swaps were not liquidated when portion of the principal amount of term note was early repaid in the fourth quarter of 2017.

At December 31, 2017, the fair value of the U.K. foreign exchange derivative contracts was a net asset of $1.7 million and has been included on the Consolidated Balance Sheets. Changes in the fair value of these contracts between Balance Sheet dates are reported on the Consolidated Statements of Income (Loss) as an unrealized foreign exchange (gain) loss.

Foreign Denominated Term Debt Sensitivity to Foreign Exchange Rate

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

	Cdn$0.01 Exchange rate change
Foreign exchange sensitivity as at December 31, 2017 ($ millions)	Cdn - U.S.	Cdn - U.K.
Unrealized foreign exchange gain or loss on foreign denominated debt	3.7	0.1
Unrealized foreign exchange risk management gain or loss	2.6	0.1
Net pre-tax impact on Consolidated Statements of Income (Loss)	1.1	—

PENGROWTH 2017 Management's Discussion and Analysis 27

ASSET RETIREMENT OBLIGATIONS - NET PRESENT VALUE

($ millions)	Dec 31, 2017		Dec 31, 2016		Change
ARO, beginning of year	652.3		703.4		(51.1	)
Expenditures on remediation/provisions settled	(15.9	)	(20.0	)	4.1
ARO on dispositions	(420.4	)	(11.8	)	(408.6	)
Incurred during the period	5.4		—		5.4
Accretion	11.4		15.1		(3.7	)
Other revisions	3.9		(34.4	)	38.3
ARO, end of year (1)	236.7		652.3		(415.6	)

⁽¹⁾  Expected to be funded from the SOEP remediation trust funds of $111.6 million at December 31, 2017, and $125.1 million remaining to be funded with future cash flows.

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.

At December 31, 2017, the ARO liability decreased $415.6 million or 64 percent from December 31, 2016 primarily reflecting the decrease in ARO associated the asset dispositions that closed in 2017.

Pengrowth has estimated the net present value of its total ARO to be $236.7 million as at December 31, 2017 (December 31, 2016 – $652.3 million), based on a total escalated future liability of $420.2 million (December 31, 2016 – $2.1 billion). Pengrowth has been contributing to an externally managed trust fund established to fund certain abandonment and reclamation costs associated with its interest in the SOEP. The total balance of the SOEP remediation trust fund at December 31, 2017 was $111.6 million (December 31, 2016 - $99.3 million) and is included in Other Assets on the Consolidated Balance Sheets. The fund balance substantially represents Pengrowth's share of the estimated costs of the SOEP abandonment and remediation and the fund is not considered in calculating the ARO balance above. The costs relating to SOEP abandonment and reclamation are expected to be incurred over the next 3 to 4 years.

Pursuant to the royalty agreement with the Province of Nova Scotia, Pengrowth is entitled to deduct certain monies spent on abandonment and decommissioning activities from royalties otherwise payable, and, once the field ceases production, to obtain a refund of previously paid royalties. It is estimated that the deducted and refunded royalties will be approximately 25-30 percent of Pengrowth's share of remaining abandonment and decommissioning spending. Such spending is currently estimated to be approximately $110 million. Refunds of previously paid offshore royalties are recognized as receivables only when production in a field has ceased and as abandonment and decommissioning spending has been incurred. The reduction and refund are expected to be received as cash over the next 5 years, but they have not been recognized as receivables nor offset against the ARO.

The abandonment and reclamation costs on other assets, not covered by a fund, are expected to be incurred between 2035 and 2080. A risk free discount rate of 2.3 percent per annum (December 31, 2016 - 2.3 percent) and an ARO specific inflation rate of 1.5 percent (December 31, 2016 - 1.5 percent) were used to calculate the net present value of the ARO at December 31, 2017.

REMEDIATION TRUST FUNDS AND REMEDIATION AND ABANDONMENT EXPENSE

During 2017, Pengrowth contributed $17.1 million (December 31, 2016 - $30.1 million), into externally managed trust funds established to fund certain abandonment and reclamation costs associated with Judy Creek and SOEP. The total balance of the remediation trust funds was $111.6 million at December 31, 2017 (December 31, 2016 - $106.5 million). During the third and fourth quarters of 2017, Pengrowth disposed of its interests in the Judy Creek properties in the Swan Hills area assets, including the related remediation trust funds totaling $4.8 million.

Pengrowth has a contractual obligation to make contributions to a remediation trust fund that will be used to fund the ARO of the SOEP properties and facilities. In 2017, Pengrowth made monthly contributions to the fund at a rate of $4.04/MMBtu of its share of natural gas production and $7.59/bbl of its share of natural gas liquids production from SOEP. Starting in January 2018, the rates decreased to $1.40/MMBtu of Pengrowth's share of natural gas production and $2.62/bbl of Pengrowth's share of natural gas liquids production.

See Note 4 to the December 31, 2017 audited Consolidated Financial Statements for additional information.

PENGROWTH 2017 Management's Discussion and Analysis 28

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. In 2017, Pengrowth spent $15.9 million on abandonment and reclamation (December 31, 2016 - $20.0 million). Pengrowth expects to spend approximately $29.9 million in 2018 on abandonment and reclamation activities, excluding contributions to remediation trust funds and orphan well levies from the Alberta Energy Regulator. Over 80 percent of the planned spending in 2018 relates to SOEP and will be recovered from the remediation trust fund.

CLIMATE CHANGE PROGRAMS

The Province of Alberta regulates Greenhouse Gas ("GHG") emissions under the Climate Change and Emissions Management Act. Under that 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.

Pengrowth was also subject to the Specified Gas Emitters Regulation (“SGER”) through December 31, 2017, which imposes GHG emissions intensity limits and reduction requirements for owners of facilities that emit 100,000 tonnes per year or more of GHG. 2015 amendments to the SGER increased the maximum emission intensity reduction requirement for facility owners from 15 percent, over baseline emission levels for those facilities in 2016, to 20 percent starting in 2017. The baseline for facilities is an average of 2003, 2004 and 2005 emissions. Facilities can meet required compliance 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 emission performance credits ("EPC") from one year may be carried forward to future years. The 2015 SGER amendments increased the price of compliance from $20/tonne CO2e for 2016 to $30/tonne CO2e beginning in 2017.

For parts of 2017, Pengrowth had three operated facilities that are subject to the annual 20 percent reduction: the Olds Gas Plant (disposed on August 11, 2017), the Judy Creek Gas Conservation Plant (disposed on July 6, 2017) and the Quirk Creek Gas Plant (disposed on December 21, 2017). The facility licenses for Judy Creek Gas Conservation Plant and Old Gas Plant have been transferred to the respective purchasers and therefore SGER compliance reporting and associated compliance payments for 2017 production (due March 31, 2018) will be the purchasers' responsibility. The Quirk Creek Gas Plant was divested prior to 2018 but it is expected that the compliance reporting and payments for 2017 will be Pengrowth's responsibility as they pertain to 2017 operations. Pengrowth expects to purchase approximately $0.4 million (net of EPCs in inventory) of EPCs payable to the Alberta Climate Change and Emissions Management Fund for 2017 operations.

In November 2015, the Government of Alberta announced its Climate Leadership Plan (“CLP”) highlighting four key strategies that the government will implement to address climate change:

1. the complete phase-out of coal-fired sources of electricity by 2030;

2. an Alberta economy-wide price on GHG emissions of $30/tonne;

3. capping oil sands emissions to a province-wide total of 100 megatonnes per year, with certain exceptions for cogeneration power sources and new upgrading capacity; and

4. reducing methane emissions from oil and gas activities by 45 percent by 2025.

In early 2018, the Government of Alberta announced its new Carbon Competitiveness Incentive Regulations ("CCIR"). Some highlights of CCIR are as follows:

• It replaces the current SGER as of January 1, 2018;

• There will be a phase in period with transition exemptions for 2018 (50 percent) and 2019 (75 percent) - meaning that compliance payments will be adjusted by the respective percentages for these first 2 years of operation under the CCIR;

• A facility can only use 40 percent of existing Emission Performance Credits (“EPCs”) in inventory to meet compliance. EPCs in inventory that were generated prior to 2014 will expire in 2021. EPC’s generated between 2014 and 2016 will expire in 2022 and EPC’s generated from 2017 and later will expire after 8 years;

• The CCIR will be based on industry sector emission performance per unit of production type - Output Based Allocation ("OBA");

• The OBA benchmarks will be based on the average of 2013, 2014 and 2015 CO2e emissions.

PENGROWTH 2017 Management's Discussion and Analysis 29

Given the 2017 divestments of the 3 operated facilities noted above, Pengrowth does not expect any impact as a result of the CCIR on those facilities. However, the Lindbergh facilities will be subject to the CCIR effective January 1, 2018, and will be based on Lindbergh’s CO2e per m3 of bitumen relative to the in situ sector benchmark. In 2018, there will be no compliance payment required for Lindbergh for 2017 operations. The estimated impact for 2018 operations relating to Lindbergh is $0.7 million (payable March 31, 2019). The majority of the impact of the Climate Leadership Plan is not expected until 2023.

ACQUISITIONS AND DISPOSITIONS

	Three months ended			Twelve months ended
($ millions)	Dec 31, 2017		Dec 31, 2016	Dec 31, 2017		Dec 31, 2016
Property acquisitions	(0.1	)	—	(0.1	)	(1.3	)
Proceeds from property dispositions (1)	118.4		10.6	910.2		60.2
Net cash proceeds from dispositions	118.3		10.6	910.1		58.9

⁽¹⁾  Proceeds are net of transaction costs, closing adjustments and, where applicable, deferred proceeds.

Proceeds from property dispositions amounted to $118.4 million in the fourth quarter of 2017 as Pengrowth successfully closed the Swan Hills area, and Quirk Creek asset dispositions.

In addition, full year 2017 proceeds from property dispositions included proceeds from the sale of Olds/Garrington, Judy Creek area, non-producing Montney lands at Bernadet in north eastern British Columbia, the 4.0 percent GORR interest on the Lindbergh thermal property and certain seismic assets, as well as other minor properties.

The 2017 property dispositions resulted in losses on disposition of properties of $62.6 million (2016 - $27.1 million).

WORKING CAPITAL

Working capital surplus or deficiency is calculated as current assets less current liabilities per the Consolidated Balance Sheets. At December 31, 2017, Pengrowth had a working capital deficiency of $80.6 million as current assets were exceeded by current liabilities.

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 December 31, 2017 audited Consolidated Financial Statements for a description of the accounting policies for financial instruments and Note 17 to the December 31, 2017 audited Consolidated Financial Statements for additional information regarding the fair value of Pengrowth’s financial instruments.

PENGROWTH 2017 Management's Discussion and Analysis 30

SUMMARY OF QUARTERLY RESULTS

	2017								2016
	Q4		Q3		Q2		Q1		Q4		Q3		Q2		Q1
Oil and gas sales ($ millions) (1)	130.5		125.1		197.9		219.9		169.2		145.6		137.2		114.2
Net income (loss) ($ millions)	(210.4	)	(144.7	)	(242.4	)	(86.3	)	(92.4	)	(52.9	)	(173.4	)	25.0
Net income (loss) per share ($)	(0.38	)	(0.26	)	(0.44	)	(0.16	)	(0.17	)	(0.10	)	(0.32	)	0.05
Net income (loss) per share - diluted ($)	(0.38	)	(0.26	)	(0.44	)	(0.16	)	(0.17	)	(0.10	)	(0.32	)	0.05
Funds flow from operations ($ millions) (2) (3) (4) (5)	13.5		(0.3	)	29.3		26.9		111.7		122.7		89.1		106.2
Daily production (boe/d)	24,702		35,072		49,349		52,957		54,354		55,137		56,735		62,056
Produced petroleum revenue ($/boe) (1) (6)	37.14		28.08		32.56		34.66		33.62		28.45		26.32		19.94
Operating netback ($/boe) (6) (7)	16.06		11.06		13.16		13.43		30.60		31.88		25.21		27.03

⁽¹⁾  Excludes realized commodity risk management from financial contracts. Adoption of IFRS 15 was effective January 1, 2017 using cumulative effect approach without restating prior period comparatives. See Notes 2 and 14 to the December 31, 2017 audited Consolidated Financial Statements.

⁽²⁾  First quarter of 2017 funds flow from operations includes a $12.7 million loss related to the early settlement of commodity risk management contracts.

⁽³⁾  Fourth quarter of 2016 funds flow from operations includes $35.6 million of gains related to the early settlement of commodity risk management contracts and excludes $47.0 million related to the settlement of foreign exchange swap contracts as this was considered a financing activity.

⁽⁴⁾  Third quarter of 2016 funds flow from operations includes $41.6 million of gains related to early settlement of commodity risk management contracts.

⁽⁵⁾  Fourth quarter of 2017 funds flow from operations excludes $34.8 million loss related to the settlement of foreign exchange swap contracts as this was considered a financing activity.

⁽⁶⁾  See definition under section "Non-GAAP Financial Measures".

⁽⁷⁾  Includes realized commodity risk management.

Pengrowth recorded a net loss of $210.4 million in the fourth quarter of 2017 primarily due to impairment of the Groundbirch E&E asset, absence of funds flow related to divested properties combined with realized foreign exchange loss on settled FX swaps and loss on extinguishment of debt, which were recorded in the fourth quarter of 2017. Second quarter of 2017 net loss increased from the preceding quarters primarily due to lower funds flow from operations and PP&E impairment charges.

Fourth quarter of 2017 funds flow from operations increased by $13.8 million compared to the third quarter of 2017 primarily due to lower severance costs related to restructuring coupled with improvements in benchmark prices and lower operating costs. Quarterly funds flow from operations for 2017 decreased compared to all quarters in 2016 primarily driven by the absence of the funds flow related to disposed properties and absence of realized commodity risk management gains recorded in 2016.

Fourth quarter of 2017 produced petroleum revenue per boe increased compared to the preceding quarters of 2017 and 2016 due to continued improvements in underlying benchmark prices.

Oil and gas sales in the third and fourth quarters of 2017 decreased compared to the all prior quarters in 2016 and 2017 due mainly to 2017 property dispositions, partially offset by improvements in benchmark prices. Fourth quarter of 2017 operating netbacks, after realized commodity risk management decreased compared to 2016, as per the table above, due to the absence of the substantial realized commodity risk management gains recorded in 2016.

Fourth quarter of 2017 production was lower than all of the preceding quarters in 2016 and 2017, as per the table above, resulting primarily from 2017 property dispositions and natural declines due to capital spending curtailments.

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

PENGROWTH 2017 Management's Discussion and Analysis 31

SELECTED ANNUAL INFORMATION

The table below provides a summary of selected annual information for the years ended 2017, 2016 and 2015:

	Twelve months ended December 31
($ millions unless otherwise indicated)	2017		2016		2015
Oil and gas sales (1)	673.4		566.2		830.8
Net income (loss)	(683.8	)	(293.7	)	(1,093.1	)
Net income (loss) per share ($)	(1.24	)	(0.54	)	(2.02	)
Net income (loss) per share - diluted ($)	(1.24	)	(0.54	)	(2.02	)
Dividends declared per share ($)	—		—		0.19
Total assets	1,910.9		4,117.1		4,562.9
Long term debt (2)	610.5		1,687.3		1,852.8
Shareholders' equity	806.2		1,485.0		1,765.0
Number of shares outstanding at year end (thousands)	552,246		547,709		543,033

⁽¹⁾  Excluding realized commodity risk management from financial contracts. Adoption of IFRS 15 was effective January 1, 2017 using cumulative effect approach without restating prior period comparatives. See Notes 2 and 14 to the December 31, 2017 audited Consolidated Financial Statements.

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

COMMITMENTS AND CONTRACTUAL OBLIGATIONS

($ millions)	2018	2019	2020	2021	2022	Thereafter	Total
Long term debt (1)	—	164.9	118.3	—	127.6	199.7	610.5
Interest payments on long term debt (2)	39.6	33.8	23.7	20.2	18.6	22.1	158.0
Operating leases (3)	7.1	9.3	9.7	9.6	9.6	18.7	64.0
Pipeline transportation	27.8	28.2	29.7	30.1	30.2	76.3	222.3
Other	14.0	0.3	0.3	0.2	0.2	3.5	18.5
	88.5	236.5	181.7	60.1	186.2	320.3	1,073.3

⁽¹⁾  The debt repayment includes foreign denominated fixed rate debt translated using the year end exchange rate and excludes related foreign exchange risk management contracts.

⁽²⁾  Interest payments are calculated at fixed rate debt interest rates and December 31, 2017 period end exchange rate.

⁽³⁾  Includes office rent and other commitments.

PENGROWTH 2017 Management's Discussion and Analysis 32

BUSINESS RISKS

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

The value of Pengrowth common shares is 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 Pengrowth's 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 oil, bitumen and natural gas, and political and economic stability.

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

• Substantial and sustained reductions in commodity prices or equity and debt 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 spend capital, develop its properties, reinstate or maintain a dividend on its shares, service its debt and meet its other obligations. An impairment test is sensitive to lower realized commodity prices, which have been under significant downward pressure in recent years. Declines in commodity prices could result in impairment charges as the cushions in the CGU impairment tests have been eroded by commodity price decreases.

Risks associated with Liquidity

• Capital markets may restrict Pengrowth’s access to capital and raise its cost of capital and 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 and to repay or refinance indebtedness when due 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 most circumstances, being in default of one loan will result in other loans also being in default and restrict access to the Credit Facility. If an event of non-compliance occurs and cannot be remedied during an applicable remedy period, if any, Pengrowth would have to repay the relevant debt, refinance the debt or negotiate new terms with the debt holders.

• In event of default on Pengrowth's debt, the net proceeds of any foreclosure sale would be allocated to the repayment of the lenders, note holders and other creditors and only the remainder, if any, would be available for distribution to the 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 and other taxes, levies, fees and any audits may 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, Pengrowth 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.

PENGROWTH 2017 Management's Discussion and Analysis 33

• Changes to accounting policies may result in significant adjustments to Pengrowth's financial results, which could negatively impact Pengrowth's business, including increasing the risk of failing a financial covenant contained within the Credit Facility or term debt.

Risks associated with Operations

• The marketability of Pengrowth's 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 the 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.

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

• Geological and operational risks affect the quantity and quality of reserves and the costs of recovering those reserves. Pengrowth's actual results will vary from the 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 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 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.

• 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 Corporation has substantial future asset retirement obligations. There is a risk that the magnitude of these payments may be larger than expected and that the timing of such payments may accelerate. Either of these factors could increase financial costs for the Corporation.

• 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 bitumen 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 Pengrowth's ability to sell the 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 bitumen.

Risks associated with Strategy

• Capital re-investment on Pengrowth's 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.

PENGROWTH 2017 Management's Discussion and Analysis 34

• Pengrowth’s oil and gas reserves will be depleted over time and the level of cash flow from operations and the value of Pengrowth's 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.

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

Asset Concentration Risks

• With the sale of over $2.3 billion of assets since 2012, in part to fund the first commercial phase of Lindbergh, Pengrowth's assets have become less diversified and increasingly concentrated in one project (Lindbergh), product type (bitumen) and one area/formation (the Lloydminster formation). A failure to execute at Lindbergh (whether as a result of capital constraints, operational issues or otherwise) or any of the Corporation's remaining core properties could have a significant adverse effect on Pengrowth.

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 change over time which affects the availability of capital and the value of Pengrowth common shares.

• Pengrowth is subject to a variety of information technology and system risks, including potential breakdown, invasion, virus, cyber-attack, cyber-fraud, security breach, and destruction or interruption of our information technology systems by third parties or insiders which could lead to corruption or exposure of confidential, fiduciary or proprietary information, interruption to communications or operations or disruption to our business activities or our competitive position. It could also result in material financial loss, regulatory action and sanctions, reputational harm and/or legal liability, which, in turn, could materially adversely affect our business, financial condition or profitability.

• Inflation may result in escalating costs, which could impact the value of Pengrowth's 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.

PENGROWTH 2017 Management's Discussion and Analysis 35

ACCOUNTING PRONOUNCEMENTS ADOPTED

IFRS 15 Revenue from Contracts with Customers

On May 28, 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, 2018. Earlier application is permitted. On April 12, 2016, the IASB issued Clarification to IFRS 15, which is effective at the same time as IFRS 15. The standard contains a single model that applies to contracts with customers and two approaches to recognizing revenue: at a point in time or over time. The model features a contract-based five-step analysis of transactions to determine the nature of an entity's obligation to perform and 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 has elected in the fourth quarter of 2017 to early adopt IFRS 15 for 2017 using the cumulative effect method. Under this method, prior years' financial statements have not been restated and the cumulative effect on net earnings of the application of IFRS 15 to revenue contracts in progress at January 1, 2017 is nil. Pengrowth management reviewed its revenue streams and major contracts with customers using the IFRS 15 five step model and there were no material changes to net earnings or timing of produced petroleum revenue recognized. It should be noted, however, that certain Income Statement line item reclassifications were made. See Notes 2 and 14 to the December 31, 2017 audited Consolidated Financial Statements for more information including additional disclosure as required under IFRS 15.

Disclosure Initiative Amendments to IAS 7

Pengrowth adopted Disclosure Initiative Amendments to IAS 7 on December 31, 2017. Additional disclosures for changes in debt arising from cash and non-cash activities have been included in Note 9 to the audited Consolidated Financial Statements. As permitted by IAS 7, comparative information has not been presented.

ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED

IFRS 9 Financial Instruments

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. Pengrowth does not anticipate material changes in the carrying value of its financial instruments nor from the credit loss impairment model upon adoption of IFRS 9 (2014).

IFRS 9 (2014) requires retrospective application for modifications of financial liabilities which do not result in de-recognition or extinguishment of liabilities. Pengrowth's debt restructuring completed in 2017 included substantial modification of terms and as such was accounted for as an extinguishment with Loss on extinguishment of debt reflected in the year ended December 31, 2017 Consolidated Statements of Income (Loss).

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 new general hedging model. Pengrowth does not currently apply hedge accounting and does not currently intend to apply hedge accounting to its existing risk management contracts.

IFRS 16 Leases

In January 2016, the IASB issued the complete IFRS 16 Leases ("IFRS 16") which replaces IAS 17, Leases. The effective date of IFRS 16 is for annual periods beginning on or after January 1, 2019 and early adoption is permitted. Under IFRS 16, a single recognition and measurement model will apply for lessees which will require recognition of

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assets and liabilities for most leases. Pengrowth is currently evaluating the impact that the adoption of this standard will have on its financial statements.

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, 2017. 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, 2017, 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, 2017. 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 at December 31, 2017.

The effectiveness of internal control over financial reporting as at December 31, 2017 was audited by KPMG LLP, an independent registered public accounting firm, as stated in their attestation report, which is included with Pengrowth's audited Consolidated Financial Statements for the year ended December 31, 2017. No changes were made to Pengrowth's internal control over financial reporting during the year ending December 31, 2017 that have materially affected, or are reasonably likely to materially affect, the internal controls over financial reporting.

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