Pengrowth Energy (PGH) 40-F 2015 FY Annual report (Canada)

MANAGEMENT’S DISCUSSION & ANALYSIS

The following Management’s Discussion and Analysis ("MD&A") of financial results should be read in conjunction with the audited Consolidated Financial Statements for the year ended December 31, 2015 of Pengrowth Energy Corporation ("Pengrowth" or the "Corporation"). This MD&A is based on information available to February 24, 2016.

Pengrowth’s fourth quarter and annual results for 2015 are contained within this MD&A.

BUSINESS OF THE CORPORATION

Pengrowth is a Canadian resource company that is engaged in the production, development, exploration and acquisition of oil and natural gas assets. The financial and operating results from property dispositions are included in Pengrowth’s results up to the time of closing for each disposition.

FREQUENTLY RECURRING TERMS

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

ADVISORY REGARDING FORWARD-LOOKING STATEMENTS

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

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

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

PENGROWTH 2015 Management's Discussion and Analysis 1

readers not to place undue reliance on these statements as a number of important factors could cause the actual results to differ materially from the beliefs, plans, objectives, expectations and anticipations, estimates and intentions expressed in such forward-looking statements. These factors include, but are not limited to: the volatility of oil and gas prices; Canadian light and heavy oil differentials; production and development costs and capital expenditures; the imprecision of reserve estimates and estimates of recoverable quantities of oil, natural gas and liquids; Pengrowth's ability to replace and expand oil and gas reserves, ability to produce those reserves; production may be impacted by unforeseen events such as equipment and transportation failures and weather related issues; environmental claims and liabilities; incorrect assessments of value when making acquisitions; increases in debt service charges; the loss of key personnel; the marketability of production; defaults by third party operators; unforeseen title defects; fluctuations in foreign currency and exchange rates; inadequate insurance coverage; counterparty risk; compliance with environmental laws and regulations; 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 audited 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 historical production data. Estimates are reviewed and revised as appropriate. Revisions occur as a result of changes in prices, costs, fiscal regimes and reservoir performance or a change in Pengrowth's plans with respect to future development or operating practices.

PENGROWTH 2015 Management's Discussion and Analysis 2

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 December 31, 2015 ARO risk free discount rate of 2.3 percent remained unchanged from December 31, 2014.

Impairment testing

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

Fair value of risk management contracts

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

Valuation of trade and other receivables, and prepayments to suppliers

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

COMPARATIVE FIGURES

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

ADDITIONAL GAAP MEASURE

Funds Flow from Operations

Pengrowth uses funds flow from operations, a Generally Accepted Accounting Principles ("GAAP") measure that is not defined under IFRS. Management believes that in addition to cash provided by operations, funds flow from operations, as reported as a subtotal in the Consolidated Statements of Cash Flow is a useful supplemental measure as it provides an indication of the funds generated by Pengrowth’s principal business activities prior to consideration of changes in working capital and remediation expenditures, but after interest and financing charges are deducted.

PENGROWTH 2015 Management's Discussion and Analysis 3

Pengrowth considers this to be a key measure of performance as it demonstrates its ability to generate cash flow necessary to fund capital investments and debt repayment as well as dividends, as applicable.

Funds flow from operations per share is calculated as funds flow from operations divided by weighted average number of shares outstanding for the period.

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.

Operating netbacks do not have standardized meanings prescribed by GAAP. Pengrowth’s operating netbacks have been calculated by taking oil and gas sales, royalties, operating and transportation expenses as well as realized commodity risk management balances, as applicable, directly from the Consolidated Statements of Income (Loss) and dividing by production for the period. See the section of this MD&A entitled Operating Netbacks for a discussion of the calculation.

Management monitors Pengrowth’s capital structure using non-GAAP financial metrics as per the Financial Resources and Liquidity section of this MD&A. These metrics are: senior debt before working capital to the trailing twelve months Earnings Before Interest, Taxes, Depletion, Depreciation, Amortization, Accretion, and other non-cash items ("Adjusted EBITDA"); total debt before working capital to Adjusted EBITDA; Adjusted EBITDA to interest expense; and senior debt before working capital as a percentage of total book capitalization. Total book capitalization is the sum of senior debt before working capital 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, non-cash mark to market gains and losses on investments and unrealized foreign exchange gains and losses, as applicable, that may significantly impact net income (loss) from period to period. Adjusted net income (loss) per share is calculated as adjusted net income (loss) divided by weighted average number of shares outstanding for the period.

Payout ratio is a term used to evaluate financial flexibility and the capacity to fund dividends. Payout ratio is defined on a percentage basis as dividends declared divided by funds flow from operations.

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.

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.

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

Average Instantaneous Steam Oil Ratio ("ISOR") measures the current or instantaneous rate of steam required to produce a barrel of bitumen.

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.

PENGROWTH 2015 Management's Discussion and Analysis 4

TREATMENT OF LINDBERGH RESULTS

Prior to April 1, 2015, only the Lindbergh pilot project production and related revenue and expenses were included in the reported financial and operating information and all expenses, net of revenue, from the first commercial phase of the Lindbergh thermal project ("Lindbergh Phase 1") were capitalized. After declaration of commerciality effective April 1, 2015, all Lindbergh related revenues and expenses are included in the 2015 financial and operating results. The combined results are referred to as Lindbergh throughout this document.

2015 ACTUAL RESULTS VS. 2015 GUIDANCE

The following table provides a summary of Pengrowth's 2015 Guidance and actual results:

	2015 Actual	2015 Guidance (1)
Production (boe/d)	71,409	70,000 - 72,000
Capital expenditures ($ millions)	183.8	190 - 210 (2)
Royalty expenses (% of sales)	10.8	11 - 14
Operating expenses ($/boe)	14.28	15.50 - 16.50
Cash G&A expenses ($/boe)	3.34	3.50 - 3.60

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

⁽²⁾  Revised in the second quarter of 2015 from previous 2015 Guidance of $220 - $240 million.

2015 average daily production of 71,409 boe/d was at the higher end of 2015 Guidance.

2015 capital expenditures amounting to $183.8 million were slightly below 2015 Guidance resulting from further capital spending curtailments in the fourth quarter of 2015.

2015 royalty expenses as a percentage of sales were slightly below the lower end of 2015 Guidance as a result of lower than expected commodity prices.

2015 operating expenses per boe were below 2015 Guidance mostly driven by lower than anticipated operating costs on non-operated properties, significant favourable prior period adjustments and the exclusion of Lindbergh Phase 1 operating expenses in the first quarter of 2015, which had higher than average operating expenses per boe due to lower production.

Cash G&A expenses per boe were below the lower end of 2015 Guidance resulting from staff reductions and several cost saving initiatives.

2016 GUIDANCE

The following table provides Pengrowth's previously announced 2016 Guidance which does not reflect any acquisition or divestment activity:

	2016 Guidance (1) (2)
Production (boe/d)	59,000 - 61,000
Capital expenditures ($ millions)	60 - 70
Royalty expenses (% of sales)	7 - 8
Operating expenses ($/boe)	15.25 - 16.25
Cash G&A expenses ($/boe)	2.75 - 3.25

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

⁽²⁾  Based on WTI price of U.S.$30/bbl, AECO natural gas price of Cdn$2.40/Mcf and an exchange rate of Cdn$1 = U.S.$0.70.

PENGROWTH 2015 Management's Discussion and Analysis 5

FINANCIAL HIGHLIGHTS

	Three months ended						Twelve months ended
($ millions except per boe amounts)	Dec 31, 2015		Sept 30, 2015		Dec 31, 2014		Dec 31, 2015		Dec 31, 2014
Production (boe/d)	67,934		74,239		71,802		71,409		73,288
Capital expenditures	19.1		15.5		258.8		183.8		904.0
Funds flow from operations (1)	114.2		120.6		115.8		459.3		505.7
Operating netback ($/boe)(2)	25.07		25.48		24.04		24.97		25.64
Adjusted net loss (3)	(463.4	)	(374.0	)	(854.8	)	(811.4	)	(879.0	)
Net loss (3)	(468.6	)	(329.6	)	(506.0	)	(1,093.1	)	(578.8	)

⁽¹⁾  Funds flow from operations for the three and twelve months ended December 31, 2015 excludes $0.2 million and $94.1 million, respectively, of gains related to the 2015 settlement of foreign exchange swap contracts.

⁽²⁾  Including realized commodity risk management.

⁽³⁾  Includes non-cash after-tax impairment charges and after-tax loss or gain on dispositions as follows: $467.1 million in the fourth quarter of 2015, $375.1 million in the third quarter of 2015, $842.0 million in the fourth quarter of 2014, $861.6 million for full year 2015 and $840.5 million for full year 2014.

Funds Flow from Operations

($ millions)	Q3/15 vs. Q4/15			% Change		Q4/14 vs. Q4/15			% Change		2014 vs. 2015			% Change
Funds flow from operations for comparative period	Q3/15	120.6				Q4/14	115.8				2014	505.7
Increase (decrease) due to:
Volumes		(19.5	)	(16	)		0.1		—			(15.6	)	(3	)
Prices including differentials		(24.5	)	(20	)		(122.2	)	(106	)		(648.2	)	(128	)
Realized commodity risk management		13.2		11			76.0		66			423.1		84
Other income including sulphur		1.2		1			(0.3	)	—			(2.3	)	—
Royalties		—		—			32.1		28			179.1		35
Expenses:
Operating		9.6		8			13.1		11			43.3		9
Cash G&A		8.4		7			5.4		5			(2.7	)	(1	)
Interest & financing		0.6		—			(10.2	)	(9	)		(29.3	)	(6	)
Other expenses including transportation		4.6		4			4.4		4			6.2		1
Net change		(6.4	)	(5	)		(1.6	)	(1	)		(46.4	)	(9	)
Funds flow from operations (1)	Q4/15	114.2				Q4/15	114.2				2015	459.3

⁽¹⁾  Funds flow from operations for the three and twelve months ended December 31, 2015 excludes $0.2 million and $94.1 million, respectively, of gains related to the 2015 settlement of foreign exchange swap contracts.

Pengrowth's fourth quarter of 2015 funds flow from operations decreased 5 percent compared to the third quarter of 2015. This was driven by the impact of lower commodity prices and volumes which were mostly offset by higher realized commodity risk management gains, lower operating, cash G&A and other expenses.

Fourth quarter of 2015 funds flow from operations decreased only 1 percent compared to the same period last year as the unfavourable impact of significantly lower commodity prices was mitigated by increased realized commodity risk management gains combined with lower royalties and operating expenses.

Pengrowth's full year 2015 funds flow from operations decreased 9 percent compared to 2014 also driven by the impact of significantly lower commodity prices and higher interest and financing charges primarily related to the impact of foreign exchange. These decreases were largely offset by realized commodity risk management gains, along with lower royalties and operating expenses.

Net Loss

Pengrowth recorded $1,000.5 million (approximately $789 million after-tax) of non-cash impairment charges in 2015 compared to $994.6 million (approximately $858 million after-tax) in 2014. These impairment charges significantly impacted Pengrowth's 2015 and 2014 reported earnings.

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The net loss of $468.6 million in the fourth quarter of 2015 compared to the net loss of $329.6 million in the third quarter of 2015 increased due to higher non-cash impairment charges, a lower increase in fair value of commodity risk management contracts combined with the higher loss on disposition of properties.

The net loss of $468.6 million in the fourth quarter of 2015 compared to the net loss of $506.0 million in the fourth quarter of 2014 decreased due to lower non-cash impairment charges, lower DD&A and increased deferred income tax recovery which were mostly offset by a lower increase in fair value of commodity risk management contracts combined with the higher loss on disposition of properties.

Full year 2015 net loss of $1,093.1 million compared to a net loss of $578.8 million in 2014 increased primarily due to a significant change in fair value of commodity risk management contracts year over year.

Adjusted Net Loss

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

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

	Three months ended						Twelve months ended
($ millions)	Dec 31, 2015		Sept 30, 2015		Dec 31, 2014		Dec 31, 2015		Dec 31, 2014
Net loss	(468.6	)	(329.6	)	(506.0	)	(1,093.1	)	(578.8	)
Exclude non-cash items from net loss:
Change in fair value of commodity and power risk management contracts	35.5		120.9		501.3		(49.4	)	499.6
Unrealized foreign exchange loss (1)	(25.0	)	(41.3	)	(29.8	)	(235.2	)	(79.0	)
Unrealized loss on investments	—		—		—		—		(5.0	)
Tax effect on non-cash items above	(15.7	)	(35.2	)	(122.7	)	2.9		(115.4	)
Total excluded	(5.2	)	44.4		348.8		(281.7	)	300.2
Adjusted net loss	(463.4	)	(374.0	)	(854.8	)	(811.4	)	(879.0	)

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

The following table represents a continuity of adjusted net loss:
($ millions)	Q3/15 vs. Q4/15			Q4/14 vs. Q4/15			2014 vs. 2015
Adjusted net loss for comparative period	Q3/15	(374.0	)	Q4/14	(854.8	)	2014	(879.0	)
Funds flow from operations decrease		(6.4	)		(1.6	)		(46.4	)
DD&A and accretion expense decrease		16.4			23.3			63.4
Impairment charges (increase) decrease (1)		(36.5	)		476.1			(5.9	)
Realized foreign exchange gain on settled FX swaps increase		0.2			0.2			94.1
Loss on property dispositions increase		(71.8	)		(93.1	)		(121.4	)
Other		(1.7	)		(0.5	)		(0.2	)
Estimated tax on above including tax rate change		10.4			(13.0	)		84.0
Net change		(89.4	)		391.4			67.6
Adjusted net loss	Q4/15	(463.4	)	Q4/15	(463.4	)	2015	(811.4	)

⁽¹⁾  See Notes 5 and 7 to the December 31, 2015 audited Consolidated Financial Statements for additional information.

Pengrowth posted an adjusted net loss of $463.4 million in the fourth quarter of 2015 compared to an adjusted net loss of $374.0 million in the third quarter of 2015 due to higher loss on disposition of properties and higher non-cash impairment charges.

The fourth quarter of 2015 adjusted net loss improved $391.4 million compared to the same period last year primarily due to lower fourth quarter of 2015 non-cash impairment charges relative to the fourth quarter of 2014.

Pengrowth's full year 2015 adjusted net loss of $811.4 million compared to the adjusted net loss of $879.0 million in 2014 represents an improvement of $67.6 million primarily driven by the realized foreign exchange gain from settlement

PENGROWTH 2015 Management's Discussion and Analysis 7

of U.S. swap contracts in 2015. Higher loss on disposition of properties and lower funds flow from operations during the most recent year were largely offset by lower DD&A.

Sensitivity of Funds Flow from Operations to Commodity Prices

The following table illustrates the sensitivity of funds flow from operations to changes in commodity prices after taking into account Pengrowth’s commodity risk management contracts and outlook on oil differentials. See Note 17 to the December 31, 2015 audited Consolidated Financial Statements for more information on Pengrowth's risk management contracts.

						Estimated Impact on 12 Month Funds Flow
COMMODITY PRICE ENVIRONMENT (1)		Assumption		Change		(Cdn$ millions)
West Texas Intermediate Oil (2) (3)	U.S.$/bbl	$	36.28	$	1.00
Light oil						6.1
Heavy oil						8.4
Oil risk management (4)						(11.5	)
NGLs						3.5
Net impact of U.S.$1/bbl increase in WTI						6.5
Oil differentials
Light oil	U.S.$/bbl	$	3.44	$	1.00	(6.1	)
Heavy oil	U.S.$/bbl	$	16.35	$	1.00	(8.4	)
Oil differentials risk management (4)						4.1
Net impact of U.S.$1/bbl increase in differentials						(10.4	)
AECO Natural Gas (2) (3)	Cdn$/Mcf	$	2.32	$	0.10
Natural gas						4.6
Natural gas risk management (4)						(4.5	)
Net impact of Cdn$0.10/Mcf increase in AECO						0.1

⁽¹⁾  Calculations are performed independently and are not indicative of actual results when multiple variables change at the same time. An exchange rate of Cdn$1 = U.S.$0.70 was used.

⁽²⁾  Commodity price is based on an estimation of the 12 month forward price curve at January 26, 2016 and does not include the impact of commodity risk management contracts.

⁽³⁾  The calculated impact on revenue/cash flow is only applicable within a limited range of the change indicated and is based on production guidance levels contained herein.

⁽⁴⁾  Includes commodity risk management contracts as at December 31, 2015.

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RESULTS OF OPERATIONS

All volumes, wells and spending amounts stated below reflect Pengrowth’s net working interest for both operated and non-operated properties unless otherwise stated. Prior to April 1, 2015, the Lindbergh Phase 1 expenses, net of revenue, were capitalized, in accordance with IFRS. As a result of the declaration of commerciality in respect of the Lindbergh project, commencing April 1, 2015, financial and operating results from the Lindbergh Phase 1 project are reflected in Pengrowth’s results.

CAPITAL EXPENDITURES

	Three months ended			Twelve months ended
($ millions)	Dec 31, 2015	Sept 30, 2015	Dec 31, 2014	Dec 31, 2015	Dec 31, 2014
Drilling, completions and facilities
Lindbergh (1)	6.3	3.3	80.4	87.2	442.3
Conventional	0.4	0.3	34.9	42.2	256.5
Total drilling, completions and facilities	6.7	3.6	115.3	129.4	698.8
Land & seismic acquisitions (2)	—	0.1	123.9	0.6	129.3
Maintenance capital	11.9	11.6	17.8	51.1	72.8
Development capital	18.6	15.3	257.0	181.1	900.9
Other capital	0.5	0.2	1.8	2.7	3.1
Capital expenditures	19.1	15.5	258.8	183.8	904.0

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

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

Pengrowth continued with its strategy of deferring significant development capital expenditures until a sustained recovery in commodity prices is present. Fourth quarter of 2015 capital expenditures were limited to $19.1 million. Approximately 33 percent of the fourth quarter of 2015 capital was spent at Lindbergh and 62 percent was spent on turnaround, safety, integrity, maintenance and enhancement activities. The remaining capital was primarily spent at Pengrowth's conventional properties.

Pengrowth's full year 2015 capital spending amounted to $183.8 million, of which approximately 47 percent was invested at Lindbergh and 23 percent on drilling, completions and facilities at Pengrowth's conventional properties with the remaining 30 percent invested in safety, integrity, maintenance at Pengrowth's conventional properties, land and seismic.

Focus Areas

Lindbergh

Pengrowth’s 100 percent owned and operated Lindbergh thermal project is located in the Cold Lake area of Alberta and encompasses 42.5 sections of land. Cost advantages of the Lindbergh resource include enhanced bitumen quality and flow characteristics resulting in an efficient steam oil ratio which translates into a lower operating cost structure and higher netbacks compared to many other thermal projects. The project recycles on site in excess of 95 percent of water used in operations. The first commercial phase of Lindbergh was sanctioned by Pengrowth’s Board of Directors in January 2013, first steam was announced in December 2014, commerciality was declared as of April 1, 2015, and the pilot well pairs were redirected to the commercial facility on April 11, 2015. The Environmental Impact Assessment ("EIA") application for the Lindbergh expansion to 30,000 bbl/d was submitted to the regulators in December 2013, with approval anticipated in the first half of 2016. Lindbergh may be developed in stages with the ultimate potential for bitumen production of 40,000 to 50,000 bbl/d. This is expected to be low cost production with low sustaining capital requirements and long reserve life.

PENGROWTH 2015 Management's Discussion and Analysis 9

	Three months ended
Average Commodity Prices	Dec 31, 2015		Sept 30, 2015		Jun 30, 2015
Average exchange rate (Cdn$1 = U.S.$)	0.75		0.76		0.81
WTI oil (U.S.$/bbl)	42.17		46.43		57.96
Average WSC Differentials to WTI (U.S.$/bbl)	(14.48	)	(13.09	)	(11.59	)
WCS heavy oil (U.S.$/bbl)	27.69		33.34		46.37
WCS heavy oil (Cdn$/bbl)	36.86		43.86		57.00
Lindbergh Heavy Oil Netback (Cdn$/bbl)
Sales	27.10		35.23		49.12
Royalties	(0.41	)	(0.92	)	(1.03	)
Operating expenses	(9.86	)	(9.66	)	(12.66	)
Transportation expenses	(2.74	)	(2.96	)	(4.26	)
Lindbergh heavy oil operating netback	14.09		21.69		31.17
Lindbergh Heavy Oil Production (bbl/d)	14,274		14,564		10,930
Average Instantaneous Steam Oil Ratio ("ISOR")	2.1		2.1		2.5

Lindbergh generated a netback of $14.09/bbl in the fourth quarter of 2015 down significantly from the prior quarters in 2015 due to the lower WCS benchmark price. The netback excludes realized commodity risk management gains.

The fourth quarter of 2015 production was impacted by a scheduled partial plant turnaround, as required to meet Alberta Pressure Equipment Safety Regulations for the facilities, and minor unexpected production interruptions. Production ramp-up resumed following these interruptions with average field production for the month of December 2015 of 15,098 bbl/d which allowed the fourth quarter production to remain essentially flat compared to the third quarter of 2015 but still exceeding the nameplate capacity of the first commercial phase of Lindbergh of 12,500 bbl/d.

Conventional Oil and Gas

Pengrowth’s significant conventional oil and gas portfolio includes a large, contiguous land base in the Greater Olds/Garrington area, encompassing over 480 gross (221 net) sections of land, with opportunities in the Cardium, Viking and Mannville sands as well as in the Mississippian carbonate section. The existing, extensive gathering and processing infrastructure provides an efficient platform for continued development in this area. Pengrowth also controls large light oil accumulations in the Swan Hills area of northern Alberta with low production decline rates and strong cash flow, as well as Montney natural gas opportunities with potentially significant liquid yield in north eastern British Columbia.

Conventional development was curtailed early in 2015, with the fourth quarter of 2015 capital spending of $11.9 million focused on safety, maintenance and integrity of existing assets and minor partner operated activity.

PENGROWTH 2015 Management's Discussion and Analysis 10

RESERVES AND PERFORMANCE MEASURES

Reserves - Company Interest at Forecast Prices

Reserves Summary (MMboe except as noted)	2015		2014		2013
Proved Reserves
Additions + revisions for the year	(6.1	)	32.9		83.4
Net dispositions for the year	(25.8	)	(3.2	)	(45.6	)
Total proved reserves at period end	252.1		310.1		307.0
Proved reserve replacement ratio excluding net dispositions	(23	)%	123	%	270	%
Proved reserve replacement ratio including net dispositions	(122	)%	111	%	122	%
Proved plus Probable Reserves (P+P)
Additions + revisions for the year	73.6		112.4		65.3
Net dispositions for the year	(35.8	)	(5.6	)	(69.0	)
Total proved plus probable reserves at period end	569.1		557.4		477.4
Total production (MMboe)	26.1		26.8		30.9
P+P Reserve replacement ratio excluding net dispositions	282	%	420	%	211	%
P+P Reserve replacement ratio including net dispositions	145	%	399	%	(12	)%

Pengrowth’s 2015 total proved reserves decreased 19 percent from 2014, while total proved plus probable reserves increased 2 percent. The decrease of 6.1 MMboe of proved reserves relating to additions and revisions in 2015 was primarily due to negative revisions caused by lower commodity price forecasts. Pengrowth added 73.6 MMboe of total proved plus probable reserves in 2015 from development and optimization activities in non-thermal properties, and ongoing reservoir delineation of the Lindbergh thermal project, partially offset by the impact of lower commodity price forecasts. The 2015 reserve additions resulted in a reserve replacement ratio of 282 percent for total proved plus probable reserves excluding net dispositions, and 145 percent including net dispositions.

Further details of Pengrowth’s 2015 year end reserves, F&D and FD&A calculations are provided in the AIF which is filed on SEDAR (www.sedar.com) or the 40-F filed on EDGAR (www.sec.gov).

Performance Measures

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

Finding & Development Costs & Recycle Ratio	2015		2014		2013		3 year weighted average
Excluding Net Dispositions (F&D)
Excluding changes in FDC
F&D costs per boe - (P+P)	$	2.47	$	8.03	$	10.61	$	7.07
Recycle ratio (1)	10.1		3.2		2.3		3.5
Including changes in FDC
F&D costs per boe - (P+P)	$	7.12	$	22.33	$	21.96	$	17.78
Recycle ratio (1)	3.5		1.1		1.1		1.4

⁽¹⁾  Recycle ratio is calculated as operating netback, including commodity risk management, per boe divided by F&D costs per boe based on proved plus probable reserves.

2015 total proved plus probable F&D cost, including changes in FDC, was $7.12/boe, decreasing significantly from 2014 as a result of adding relatively low cost bitumen and Montney gas reserves and reduced forecasts of FDC primarily due to drilling cost efficiencies.

Recycle ratio is an important performance measure in assessing investment profitability and provides a comparison to our competitors. Pengrowth’s operating results and capital program in 2015 yielded a recycle ratio, excluding net dispositions and including changes in FDC, of 3.5 on a proved plus probable basis. The improvement in the 2015 recycle ratio from prior years is primarily due to reduced F&D costs as the 2015 netback remained relatively stable compared to 2014 and 2013 despite the lower commodity prices. This can be attributed to Pengrowth's commodity risk management which mitigated lower commodity prices in 2015.

PENGROWTH 2015 Management's Discussion and Analysis 11

PRODUCTION

	Three months ended						Twelve months ended
Daily production	Dec 31, 2015	% of total	Sept 30, 2015	% of total	Dec 31, 2014	% of total	Dec 31, 2015	% of total	Dec 31, 2014	% of total
Light oil (bbls)	14,153	21	15,680	21	19,361	27	16,329	23	21,228	29
Heavy oil (bbls)	18,089	27	20,489	28	8,299	12	15,914	22	8,251	11
Natural gas liquids (bbls)	8,205	12	8,331	11	9,381	13	8,619	12	10,130	14
Natural gas (Mcf)	164,922	40	178,428	40	208,563	48	183,276	43	202,076	46
Total boe per day	67,934		74,239		71,802		71,409		73,288

Fourth quarter of 2015 average daily production decreased 8 percent compared to the third quarter of 2015 due to the property dispositions that closed in the fourth quarter of 2015, planned and unplanned outages, and natural declines.

Fourth quarter and full year 2015 average daily production decreased 5 percent and 3 percent, respectively, compared to the same periods last year. The inclusion of Lindbergh Phase 1 production and additions from the 2014 Groundbirch development program mostly offset the impacts of 2014 and 2015 property dispositions, production declines and approximately 1,000 boe/d of shut-in uneconomic natural gas production.

Light Oil

Fourth quarter of 2015 light oil production decreased 10 percent compared to the third quarter of 2015 primarily due to well downtime in the Lochend/Garrington and Oak areas as well as natural declines.

Fourth quarter and full year 2015 light oil production decreased 27 percent and 23 percent, respectively, compared to the same periods last year. These decreases result from natural declines combined with well and facility downtime in 2015. The 2014 Red Earth disposition also contributed to the decreases.

Heavy Oil

Fourth quarter of 2015 heavy oil production decreased 12 percent compared to the third quarter of 2015 resulting from the disposition of the Bodo and Jenner properties in the fourth quarter of 2015.

Fourth quarter and full year 2015 heavy oil production increased 118 percent and 93 percent, respectively, compared to the same periods last year due to inclusion of the Lindbergh Phase 1 production partially offset by the impact of the Bodo and Jenner dispositions.

NGLs

Fourth quarter of 2015 NGL production decreased 2 percent compared to the third quarter of 2015 due to lower NGL sales at Judy Creek which were mostly offset by a partial Sable Offshore Energy Project ("SOEP") condensate shipment which occurred in October 2015.

Fourth quarter and full year 2015 NGL production decreased 13 percent and 15 percent, respectively, compared to the same periods last year mainly due to natural declines combined with a planned turnaround at Judy Creek in 2015.

Natural Gas

Fourth quarter of 2015 natural gas production decreased 8 percent compared to the third quarter of 2015 primarily due to the absence of volumes from the 2015 dispositions and natural declines in 2015.

Fourth quarter and full year 2015 natural gas production decreased 21 percent and 9 percent, respectively, compared to the same periods last year. This was primarily due to 2015 dispositions and natural declines. Also contributing to the declines was the impact of shut-in uneconomic natural gas production partially offset by additions from the 2014 Groundbirch development program.

PENGROWTH 2015 Management's Discussion and Analysis 12

COMMODITY PRICES

Oil and Liquids Prices Excluding Realized Commodity Risk Management

	Three months ended						Twelve months ended
(U.S.$/bbl)	Dec 31, 2015		Sept 30, 2015		Dec 31, 2014		Dec 31, 2015		Dec 31, 2014
Average exchange rate (Cdn$1 = U.S.$)	0.75		0.76		0.88		0.78		0.91
Average Benchmark Prices
WTI oil	42.17		46.43		73.15		48.76		93.00
Average WSC Differentials to WTI	(14.48	)	(13.09	)	(14.24	)	(13.51	)	(19.40	)
WCS heavy oil	27.69		33.34		58.91		35.25		73.60

	Three months ended						Twelve months ended
(Cdn$/bbl)	Dec 31, 2015		Sept 30, 2015		Dec 31, 2014		Dec 31, 2015		Dec 31, 2014
Average Benchmark Prices
WTI oil	56.21		61.42		83.05		62.11		102.44
Edmonton par light oil	52.93		56.89		75.79		57.20		94.50
WCS heavy oil	36.86		43.86		66.85		44.79		81.03
Average Differentials to WTI
Edmonton par	(3.28	)	(4.53	)	(7.26	)	(4.91	)	(7.94	)
WCS heavy oil	(19.35	)	(17.56	)	(16.20	)	(17.32	)	(21.41	)
Average Sales Prices
Light oil	49.00		54.76		72.93		54.06		92.10
Heavy oil	28.72		35.60		61.56		37.75		75.21
Natural gas liquids	21.86		18.79		39.51		24.29		52.17

Fourth quarter of 2015 WTI crude oil price averaged Cdn$56.21/bbl, a decrease of 8 percent and 32 percent compared to the third quarter of 2015 and fourth quarter of 2014, respectively. Full year 2015 WTI crude oil price averaged Cdn$62.11/bbl, a decrease of 39 percent compared to 2014. The decline in global crude oil prices continued throughout 2015 as the excess supply of crude oil persisted. For Canadian producers such as Pengrowth that report revenues in Canadian dollars, the decline in the U.S. dollar based WTI crude oil price was partially muted by the decline in the value of the Canadian dollar relative to the U.S. dollar.

Edmonton par light oil price averaged Cdn$52.93/bbl in the fourth quarter of 2015, representing a decrease of 7 percent and 30 percent compared to the third quarter of 2015 and fourth quarter of 2014, respectively. Full year 2015 Edmonton par light oil price averaged Cdn$57.20/bbl, a decrease of 39 percent compared to full year 2014. Lower WTI prices, slightly offset by the narrowing of the light oil differential between Edmonton par and WTI, were the main drivers behind the decreases quarter over quarter and year over year.

WCS heavy oil price averaged Cdn$36.86/bbl in the fourth quarter of 2015, a decrease of 16 percent and 45 percent compared to the third quarter of 2015 and fourth quarter of 2014, respectively. Full year 2015 WCS heavy oil price averaged Cdn$44.79/bbl, a decrease of 45 percent compared to the same period in 2014. Lower WTI prices coupled with a widening of the heavy oil differential in the fourth quarter of 2015 were the primary drivers behind lower WCS heavy oil price compared to the third quarter of 2015 and the fourth quarter of 2014. Full year 2015 WCS price was lower due to weaker WTI price partially offset by a narrowing of the heavy oil differential in 2015.

Location and quality differentials, growing U.S. crude oil production as well as transportation bottlenecks influence Canadian crude oil price differentials relative to WTI. When differentials widen significantly, Pengrowth can take proactive steps to improve realizations, including delivering crude oil to rail terminals.

Pengrowth's fourth quarter and full year 2015 average realized oil sales prices, excluding realized commodity risk management, moved in conjunction with the above described benchmark prices and differentials, as per the table above.

PENGROWTH 2015 Management's Discussion and Analysis 13

Sales of natural gas liquids (NGLs) primarily comprise propane, butane, pentane and condensate. All NGLs experienced significant price reductions in the second half of 2015 due to over-supply, with propane's realization actually being negative in the third quarter of 2015. Negative realizations can occur when the transportation cost exceeds the product price, yet production may continue as NGLs are often byproducts of natural gas production.

Pengrowth's average realized NGL sales price increased 16 percent from the third quarter of 2015 primarily due to the propane realization turning positive in the fourth quarter of 2015. The fourth quarter and full year 2015 average realized NGL sales prices decreased 45 percent and 53 percent, respectively, compared to the same period in 2014 driven by the significant declines in commodity prices, as described above.

Natural Gas Prices Excluding Realized Commodity Risk Management

	Three months ended						Twelve months ended
(Cdn$)	Dec 31, 2015		Sept 30, 2015		Dec 31, 2014		Dec 31, 2015		Dec 31, 2014
Average Benchmark Prices
NYMEX gas (per MMBtu)	2.98		3.62		4.36		3.35		4.71
AECO monthly gas (per MMBtu)	2.65		2.83		4.01		2.77		4.42
Average Differential to NYMEX
AECO differential (per MMBtu)	(0.33	)	(0.79	)	(0.35	)	(0.58	)	(0.29	)
Average Sales Prices
Natural gas (per Mcf) (1)	2.50		3.02		4.02		3.00		4.74

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

Pengrowth sells its natural gas at several different sales points in addition to AECO monthly. This can result in a significant variance between Pengrowth's realized natural gas price and the benchmark prices for the same period.

The NYMEX natural gas benchmark price averaged Cdn$2.98/MMBtu in the fourth quarter of 2015, a decrease of 18 percent compared to the third quarter of 2015 and 32 percent compared to the fourth quarter of 2014. Full year 2015 NYMEX natural gas price averaged Cdn$3.35/MMBtu, a decrease of 29 percent compared to 2014. The decrease in fourth quarter 2015 NYMEX price compared to the third quarter of 2015 and the fourth quarter of 2014 resulted from decreased demand for natural gas due to higher than normal temperatures across much of North America. Full year 2015 prices were also lower compared to 2014 due to continued growth in natural gas supplies.

AECO monthly gas price averaged Cdn$2.65/MMBtu in the fourth quarter of 2015, a decrease of 6 percent and 34 percent compared to the third quarter of 2015 and the fourth quarter of 2014, respectively. A weaker NYMEX benchmark price offset by a narrowing of the differential between NYMEX and AECO was the driver behind the lower prices. Full year 2015 AECO monthly gas price averaged Cdn$2.77/MMBtu, a decrease of 37 percent compared to 2014. The full year decline in prices resulted from a lower NYMEX benchmark coupled with a widening of the differential between NYMEX and AECO.

Pengrowth's fourth quarter and full year 2015 average realized natural gas sales prices, excluding realized commodity risk management, decreased, as per the table above, in conjunction with the above described benchmark prices and differentials. In addition to this, the fourth quarter of 2015 average natural gas sales price contained an unfavourable adjustment relating to a Northeast BC property.

Total Average Sales Prices

	Three months ended			Twelve months ended
($/boe)	Dec 31, 2015	Sept 30, 2015	Dec 31, 2014	Dec 31, 2015	Dec 31, 2014
Average sales prices	26.56	30.75	43.61	31.41	55.42
Other production income including sulphur	0.50	0.27	0.52	0.47	0.54
Total oil and gas sales price	27.06	31.02	44.13	31.88	55.96
Realized commodity risk management gain (loss)	15.63	12.38	3.29	12.55	(3.60	)
Total oil and gas sales price including realized commodity risk management	42.69	43.40	47.42	44.43	52.36

PENGROWTH 2015 Management's Discussion and Analysis 14

Pengrowth’s fourth quarter of 2015 average realized sales price, before the effects of commodity risk management activities, was Cdn$26.56/boe and represented a decrease of 14 percent and 39 percent compared to the third quarter of 2015 and fourth quarter of 2014, respectively. Full year 2015 average realized sales price, before the effects of commodity risk management, of Cdn$31.41/boe declined 43 percent compared to full year 2014. The decrease in 2015 average sales price, before the effects of commodity risk management, compared to the same periods in 2014 resulted from lower benchmark prices for both crude oil and natural gas described earlier.

In spite of significant decrease in average sales prices, Pengrowth’s fourth quarter of 2015 average realized price after commodity risk management declined only 2 percent and 10 percent compared to the third quarter of 2015 and fourth quarter of 2014, respectively. For full year 2015, Pengrowth realized an average price of Cdn$44.43/boe, a decrease of 15 percent compared to 2014. The decline in realized prices year over year was due to the decrease in benchmark prices mentioned above, partly offset by the strength of Pengrowth's risk management program.

Realized Commodity Risk Management Gains (Losses)

	Three months ended				Twelve months ended
($ millions except per unit amounts)	Dec 31, 2015	Sept 30, 2015	Dec 31, 2014		Dec 31, 2015	Dec 31, 2014
Oil risk management	88.2	76.7	24.3		294.4	(66.5	)
$/bbl (1)	29.73	23.05	9.55		25.02	(6.18	)
Natural gas risk management	9.5	7.8	(2.6	)	32.6	(29.6	)
$/Mcf	0.63	0.48	(0.14	)	0.49	(0.40	)
Total realized gain (loss)	97.7	84.5	21.7		327.0	(96.1	)
$/boe	15.63	12.38	3.29		12.55	(3.60	)

⁽¹⁾  Includes light and heavy oil.

Pengrowth has an active commodity risk management program which primarily uses forward price swaps and puts to manage the exposure to commodity price fluctuations and provide a measure of stability and predictability to cash flows. Changes in the business environment are regularly monitored by management and the Board of Directors to ensure that Pengrowth's active risk management program is adequate and aligned with the long term strategic goals of the Corporation. In addition to forward price swaps and puts, Pengrowth also manages a part of its exposure to oil price differentials using financial swaps.

Realized commodity risk management gains and losses vary from period to period and are a function of the volumes under risk management contracts, the fixed prices of those risk management contracts and the benchmarkpricing for the commodities under risk management contracts. Realized losses result when the average fixed risk management contracted price is lower than the benchmark prices, while realized gains are recorded when the average fixed risk management contracted price is higher than the benchmark prices at settlement. Realized gains and losses directly impact cash flow for the period.

A realized commodity risk management gain of $97.7 million or $15.63/boe was recorded in the fourth quarter of 2015, compared to gains of $84.5 million or $12.38/boe in the third quarter of 2015 and $21.7 million or $3.29/boe in the fourth quarter of 2014, resulting from further decline in the oil and natural gas benchmark prices during the fourth quarter of 2015.

Full year 2015 realized commodity risk management gain of $327.0 million or $12.55/boe compared to a loss of $96.1 million or $3.60/boe in 2014 was mostly driven by a decline in the oil and natural gas benchmark prices starting in the second half of 2014.

Changes in Fair Value of Commodity Risk Management Contracts

	Three months ended				Twelve months ended
($ millions)	Dec 31, 2015	Sept 30, 2015	Dec 31, 2014		Dec 31, 2015		Dec 31, 2014
Fair value of commodity risk management assets at period end	370.5	335.2	421.1		370.5		421.1
Less: Fair value of commodity risk management assets (liabilities) at beginning of period	335.2	214.7	(84.2	)	421.1		(80.0	)
Increase (decrease) in fair value of commodity risk management contracts for the period	35.3	120.5	505.3		(50.6	)	501.1

PENGROWTH 2015 Management's Discussion and Analysis 15

Changes in fair value of commodity risk management contracts vary period to period and are a function of the volumes under risk management contracts, the fixed prices of those risk management contracts and the forward curvepricing for the commodities under risk management contracts at the end of the period. 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 an increase in fair value of commodity risk management contracts of $35.3 million in the fourth quarter of 2015 as fair value of commodity risk management assets increased at December 31, 2015 relative to the beginning of the period. This was a result of the downward movement in the forward curve pricing partially offset by actual settlements of contracts, or realized commodity risk management gains, of $97.7 million in the fourth quarter of 2015.

Pengrowth recorded a $50.6 million decrease in fair value of commodity risk management contracts for the twelve months ended December 31, 2015 as fair value of commodity risk management assets decreased at December 31, 2015 relative to the beginning of the period. This was a result of the settlement of contracts, or realized commodity risk management gains, of $327.0 million in 2015 largely offset by the downward movement in the forward curve pricing.

Forward Contracts - Commodity and Power Risk Management

Pengrowth uses crude oil and natural gas swaps and puts to manage its exposure to commodity price fluctuations. In addition, financial and physical contracts are sometimes used to manage oil price differentials. These contracts, as well as the power risk management contracts in place at December 31, 2015, are summarized in the following table:

Crude Oil Swaps and Puts
Reference point	Year	Volume (bbl/d)	% of total 2016 oil production Guidance (1)	Price/bbl ($Cdn) (2)
WTI	2016	22,239	74%	88.58
WTI	2017	5,000	17%	78.73
WTI	2018	5,500	18%	80.49
Crude Oil Differential Swaps
Reference point	Year	Volume (bbl/d)	% of total 2016 oil production Guidance (1)	Price/bbl ($Cdn)
Edmonton Light Sweet	2016	7,000	23%	Cdn WTI less $7.02
Western Canada Select	2016	8,000	27%	Cdn WTI less $18.32
Natural Gas Swaps and Puts
Reference point	Remaining Term	Volume (MMBtu/d)	% of 2016 natural gas production Guidance	Price/MMBtu ($Cdn)
AECO	2016	126,758	93%	3.28
AECO	2017	90,594	67%	3.47
AECO	2018	66,347	49%	3.59
AECO	2019	2,370	2%	3.52
Power
Reference point	Remaining Term	Volume (MW)	% of estimated power purchases	Price/MWh ($Cdn)
AESO	2016	20	32%	44.13

⁽¹⁾  Includes light and heavy crude oil.

⁽²⁾  WTI $U.S. contracts were converted at the period end exchange rate.

As a result of the 2015 divestment program, 2016 natural gas risk management contracts represent over 90 percent of 2016 production Guidance.

PENGROWTH 2015 Management's Discussion and Analysis 16

See the Commodity Price Contracts section in Note 17 to the December 31, 2015 audited Consolidated Financial Statements for more information.

Commodity and Power Price Sensitivity on Risk Management Contracts as at December 31, 2015

($ millions)
Oil swaps and puts	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	(12.0	)	12.0
Oil differentials	Cdn$1 decrease in future oil differential		Cdn$1 increase in future oil differential
Increase (decrease) to fair value of financial differential risk management contracts	(5.5	)	5.5
Natural gas swaps and puts	Cdn$0.25/MMBtu increase in future natural gas prices		Cdn$0.25/MMBtu decrease in future natural gas prices
Increase (decrease) to fair value of natural gas risk management contracts	(25.9	)	25.9

The changes in fair value of the forward risk management contracts directly affect reported net income (loss) through the unrealized amounts recorded in the Consolidated Statements of Income (Loss) during the period. The effect on cash flow will be recognized separately only upon settlement of the risk management contracts, which could vary significantly from the unrealized amount recorded due to timing and prices when each contract is settled.

If each commodity risk management contract were to have settled at December 31, 2015, revenue and cash flow would have been $370.5 million higher than if the risk management contracts were not in place based on the estimated fair value of the risk management contracts at period end. The $370.5 million is composed of net assets of $287.1 million relating to risk management contracts expiring within one year and assets of $83.4 million relating to risk management contracts expiring beyond one year.

Pengrowth has not designated any outstanding commodity risk management contracts as hedges for accounting purposes and therefore records these risk management contracts on the Consolidated Balance Sheets at their fair value and recognizes changes in fair value 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 crude oil and natural gas contracts are recorded separately on the Consolidated Statements of Income (Loss) and impact cash flow at that time. Realized risk management gains (losses) on power contracts are recorded in operating expenses and the unrealized amounts are recorded in other (income) expense.

Given the low commodity price environment and Pengrowth's current level of debt, the Board of Directors approved a one time measure on September 18, 2015 which allows for up to 90 percent of estimated production to be under risk management until December 31, 2018. After December 31, 2018, the 90 percent limit will revert to the previous limit of 65 percent for a rolling 1 to 24 month period.

As at December 31, 2015, Pengrowth's Board has authorized it to sell forward its production and purchase risk management contracts by product volume or power purchases as follows:

Forward Period	Percent of Estimated Production	Forward Period	Percent of Estimated Power Purchases
1 - 36 Months	Up to 90%	1 - 24 Months	Up to 80%
37 - 45 Months	Up to 50%	25 - 36 Months	Up to 50%
46 - 60 Months	Up to 25%	37 - 60 Months	Up to 25%

PENGROWTH 2015 Management's Discussion and Analysis 17

OIL AND GAS SALES EXCLUDING REALIZED COMMODITY RISK MANAGEMENT

Oil and Gas Sales Contribution Analysis

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

	Three months ended						Twelve months ended
($ millions except percentages)	Dec 31, 2015	% of total	Sept 30, 2015	% of total	Dec 31, 2014	% of total	Dec 31, 2015	% of total	Dec 31, 2014	% of total
Light oil	63.8	38	79.0	37	129.9	45	322.2	39	713.6	48
Heavy oil	47.8	28	67.1	32	47.0	16	219.3	27	226.5	15
Natural gas liquids	16.5	10	14.4	7	34.1	12	76.4	9	192.9	13
Natural gas	37.9	22	49.5	23	77.1	26	200.7	24	349.4	23
Other income including sulphur	3.1	2	1.9	1	3.4	1	12.2	1	14.5	1
Total oil and gas sales (1)	169.1		211.9		291.5		830.8		1,496.9

⁽¹⁾  Excluding realized commodity risk management.

Price and Volume Analysis

Quarter ended December 31, 2015 versus Quarter ended September 30, 2015

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

($ millions)	Light oil		Heavy oil		NGLs		Natural gas		Other (2)	Total
Quarter ended September 30, 2015 (1)	79.0		67.1		14.4		49.5		1.9	211.9
Effect of change in product prices and differentials	(7.5	)	(11.4	)	2.3		(7.9	)	—	(24.5	)
Effect of change in sales volumes	(7.7	)	(7.9	)	(0.2	)	(3.7	)	—	(19.5	)
Other	—		—		—		—		1.2	1.2
Quarter ended December 31, 2015 (1)	63.8		47.8		16.5		37.9		3.1	169.1

⁽¹⁾  Excluding realized commodity risk management.

⁽²⁾  Primarily sulphur sales.

Light oil sales decreased 19 percent in the fourth quarter of 2015 compared to the third quarter of 2015 driven by a 6 percent decrease in the Edmonton par light oil benchmark price and lower light oil sales volumes. Fourth quarter of 2015 heavy oil sales decreased 29 percent due to a 15 percent decline in WCS heavy oil benchmark price combined with lower volumes due to the Bodo and Jenner property dispositions. NGL sales increased 15 percent primarily due to the increase in propane price compared to the third quarter of 2015. Natural gas sales decreased 23 percent due to lower natural gas benchmark prices and lower sales volumes compared to the third quarter of 2015.

Quarter ended December 31, 2015versus Quarter endedDecember 31, 2014

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

($ millions)	Light oil		Heavy oil		NGLs		Natural gas		Other (2)		Total
Quarter ended December 31, 2014 (1)	129.9		47.0		34.1		77.1		3.4		291.5
Effect of change in product prices and differentials	(31.2	)	(54.6	)	(13.3	)	(23.1	)	—		(122.2	)
Effect of change in sales volumes	(34.9	)	55.4		(4.3	)	(16.1	)	—		0.1
Other	—		—		—		—		(0.3	)	(0.3	)
Quarter ended December 31, 2015 (1)	63.8		47.8		16.5		37.9		3.1		169.1

⁽¹⁾  Excluding realized commodity risk management.

⁽²⁾  Primarily sulphur sales.

Light oil sales decreased 51 percent in the fourth quarter of 2015 compared to the same period in 2014 due to a 29 percent decrease in the Edmonton par light oil benchmark price combined with lower light oil sales volumes. Fourth quarter of 2015 heavy oil sales increased 2 percent compared to the same period last year resulting from inclusion of the Lindbergh Phase 1 sales volumes largely offset by the impact of a 44 percent decrease in the WCS heavy oil benchmark price. NGL sales decreased 52 percent also driven by the impact of lower commodity prices and lower volumes. Natural gas sales decreased 51 percent primarily due to significantly lower natural gas benchmark prices relative to the fourth quarter of 2014 combined with lower natural gas sales volumes.

PENGROWTH 2015 Management's Discussion and Analysis 18

Twelve Months ended December 31, 2015 versus Twelve Months ended December 31, 2014

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

($ millions)	Light oil		Heavy oil		NGLs		Natural gas		Other (2)		Total
Twelve months ended December 31, 2014 (1)	713.6		226.5		192.9		349.4		14.5		1,496.9
Effect of change in product prices and differentials	(226.7	)	(217.6	)	(87.7	)	(116.2	)	—		(648.2	)
Effect of change in sales volumes	(164.7	)	210.4		(28.8	)	(32.5	)	—		(15.6	)
Other	—		—		—		—		(2.3	)	(2.3	)
Twelve months ended December 31, 2015 (1)	322.2		219.3		76.4		200.7		12.2		830.8

⁽¹⁾  Excluding realized commodity risk management.

⁽²⁾  Primarily sulphur sales.

Full year 2015 light oil sales decreased 55 percent compared to the same period in 2014 due to a 39 percent decrease in the Edmonton par light oil benchmark price combined with lower light oil sales volumes. Heavy oil sales decreased 3 percent as the effect of the 45 percent decrease in the WCS heavy oil benchmark price exceeded the inclusion of the nine months of Lindbergh Phase 1 sales volumes. NGL sales decreased 60 percent driven by the impact of lower commodity prices and lower volumes. Natural gas sales decreased 43 percent due to significantly lower natural gas benchmark prices relative to 2014 combined with lower natural gas volumes.

ROYALTY EXPENSES

($ millions except per boe amounts and percentages)	Three months ended			Twelve months ended
	Dec 31, 2015	Sept 30, 2015	Dec 31, 2014	Dec 31, 2015	Dec 31, 2014
Royalty expenses	19.1	19.1	51.2	89.5	268.6
$/boe	3.06	2.80	7.75	3.43	10.04
Royalties as a percent of oil and gas sales (%) (1)	11.3	9.0	17.6	10.8	17.9

⁽¹⁾  Excluding realized commodity risk management.

Royalties include Crown, freehold, overriding royalties and mineral taxes. Lindbergh Phase 1 royalties are also incorporated as of April 1, 2015.

The applicable Lindbergh Phase 1 royalty rates are price sensitive and change depending on whether the project is pre-payout or post-payout. The project will reach payout when its cumulative revenues exceed its cumulative eligible costs. The royalty rate applicable to the pre-payout Lindbergh Phase 1 project varies from 1 percent when the monthly Cdn$ equivalent WTI price is less than or equal to $55/bbl to 9 percent when the Cdn$ equivalent WTI price is in excess of $120/bbl. The Lindbergh Phase 1 project is currently in pre-payout.

Fourth quarter of 2015 royalties as a percentage of sales increased to 11.3 percent from 9.0 percent in the third quarter of 2015 primarily due to a downward adjustment of the Gas Cost Allowance ("GCA") for 2015.

Fourth quarter of 2015 royalties as a percentage of sales decreased to 11.3 percent from 17.6 percent in the fourth quarter of 2014 primarily driven by the favourable effect of lower commodity prices on royalties in 2015 as well as the impact of the Lindbergh Phase 1 royalties which are currently subject to pre-payout royalty rates. This was partly offset by lower GCA in 2015.

Full year 2015 royalties as a percentage of sales also decreased to 10.8 percent from 17.9 percent in 2014 because of the impact of lower 2015 commodity prices and inclusion of the Lindbergh Phase 1 royalties as of April 1, 2015 partly offset by lower GCA.

In January 2016, the Government of Alberta completed a review of the province’s oil and gas royalty system. The new royalty system was announced and included no changes for 10 years for existing wells, and is intended to improve transparency and disclosure around royalty information. There were no changes to oil sands royalties. The non-oil sands wells drilled after January 1, 2017, will be subject to a new royalty regime, the details of which have yet to be released.

PENGROWTH 2015 Management's Discussion and Analysis 19

OPERATING EXPENSES

($ millions except per boe amounts)	Three months ended			Twelve months ended
	Dec 31, 2015	Sept 30, 2015	Dec 31, 2014	Dec 31, 2015	Dec 31, 2014
Operating expenses	81.4	91.0	94.5	372.1	415.4
$/boe	13.02	13.32	14.31	14.28	15.53

Fourth quarter of 2015 operating expenses decreased $9.6 million or 11 percent compared to the third quarter of 2015 due to the absence of operating expenses related to divested properties combined with a significant favourable prior period processing fee throughput adjustment in the fourth quarter of 2015. On a per boe basis, fourth quarter of 2015 operating expenses decreased $0.30/boe compared to the third quarter of 2015 primarily due to divestment of properties with higher per boe operating expenses partly offset by lower production volumes.

Fourth quarter of 2015 operating expenses decreased $13.1 million or 14 percent compared to the fourth quarter of 2014 due to lower utilities as well as the absence of expenses related to property dispositions and expenses related to the uneconomic shut-in of gas volumes. In light of low commodity prices, Pengrowth's ongoing focus on cost control efforts is also reflected in lower operating costs in the current quarter. Partly offsetting these decreases was inclusion of the Lindbergh Phase 1 operating expenses as of April 1, 2015. On a per boe basis, fourth quarter of 2015 operating expenses decreased $1.29/boe compared to the fourth quarter of 2014, primarily due to lower costs as described above, and inclusion of Lindbergh Phase 1 operating expenses of $9.86/boe, which are lower than average per boe operating expenses. This was partly offset by lower production volumes in the fourth quarter of 2015.

Full year 2015 operating expenses decreased $43.3 million or 10 percent compared to 2014 as a result of lower utilities, the absence of expenses related to property dispositions and uneconomic shut-in gas volumes as well as ongoing cost control efforts. This was partially offset by inclusion of the Lindbergh Phase 1 operating expenses in the results as of April 1, 2015. On a per boe basis, full year 2015 operating expenses decreased $1.25/boe compared to the same period last year mostly due to the impact of lower costs noted above and inclusion of nine months of Lindbergh Phase 1 operating expenses of $10.55/boe.

TRANSPORTATION EXPENSES

($ millions except per boe amounts)	Three months ended			Twelve months ended
	Dec 31, 2015	Sept 30, 2015	Dec 31, 2014	Dec 31, 2015	Dec 31, 2014
Transportation expenses	9.6	12.3	8.7	45.5	30.8
$/boe	1.54	1.80	1.32	1.75	1.15

Fourth quarter of 2015 transportation expenses decreased $2.7 million or $0.26/boe compared to the third quarter of 2015. This was primarily due to lower trucking costs at Lochend and Swan Hills combined with lower natural gas volumes being directly marketed and delivered to the Chicago sales point.

Fourth quarter and full year 2015 transportation expenses increased $0.9 million or $0.22/boe and $14.7 million or $0.60/boe, respectively, compared to the same periods in 2014 resulting from higher pipeline tariffs in addition to incremental Lindbergh Phase 1 production transportation expenses.

Pengrowth entered into a transportation agreement with Husky in late 2014 for delivery of production from Lindbergh to Hardisty, Alberta, with options to nominate additional future volumes as Lindbergh expands. Pengrowth retains maximum flexibility in regards to transportation options at Lindbergh and will be able to utilize both rail and pipeline to move production to markets and maximize netbacks. Construction and commissioning of the pipeline was completed in late June 2015 and the pipeline has been in full operation since the beginning of the third quarter of 2015, allowing Pengrowth to replace Lindbergh trucking costs with lower pipeline tolls.

Pengrowth incurs transportation expenses for its natural gas production once the product enters a pipeline at a title transfer point. Pengrowth has the option to sell some of its natural gas directly to markets outside of Alberta by incurring additional transportation costs. Pengrowth also incurs transportation expenses on its oil and NGL production including sales product trucking costs and pipeline costs up to the custody transfer point. Pengrowth has elected to sell approximately 75 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.

PENGROWTH 2015 Management's Discussion and Analysis 20

OPERATING NETBACKS

Pengrowth’s operating netbacks have been calculated by taking balances directly from the Consolidated Statements of Income (Loss) and dividing by production for the period. Certain assumptions have been made in allocating operating expenses and royalty injection credits between products. Operating netbacks as presented below may not be comparable to similar measures presented by other companies, as there are no standardized measures.

Combined Netback Including Realized Commodity Risk Management ($/boe)	Three months ended						Twelve months ended
	Dec 31, 2015		Sept 30, 2015		Dec 31, 2014		Dec 31, 2015		Dec 31, 2014
Oil & gas sales (includes other income)	27.06		31.02		44.13		31.88		55.96
Royalties	(3.06	)	(2.80	)	(7.75	)	(3.43	)	(10.04	)
Operating expenses	(13.02	)	(13.32	)	(14.31	)	(14.28	)	(15.53	)
Transportation expenses	(1.54	)	(1.80	)	(1.32	)	(1.75	)	(1.15	)
Operating netback before realized commodity risk management	9.44		13.10		20.75		12.42		29.24
Realized commodity risk management	15.63		12.38		3.29		12.55		(3.60	)
Operating netback	25.07		25.48		24.04		24.97		25.64
Light Oil Netback Excluding Realized Commodity Risk Management ($/bbl)
Sales	49.00		54.76		72.93		54.06		92.10
Royalties	(7.48	)	(9.18	)	(17.71	)	(7.89	)	(19.96	)
Operating expenses	(17.84	)	(16.00	)	(15.78	)	(16.60	)	(15.80	)
Transportation expenses	(1.12	)	(1.66	)	(2.18	)	(1.78	)	(2.10	)
Light oil operating netback	22.56		27.92		37.26		27.79		54.24
Heavy Oil Netback Excluding Realized Commodity Risk Management ($/bbl) (1)
Sales	28.72		35.60		61.56		37.75		75.21
Royalties	(1.10	)	(1.82	)	(10.58	)	(2.00	)	(11.71	)
Operating expenses	(11.26	)	(11.87	)	(19.97	)	(13.31	)	(18.58	)
Transportation expenses	(2.30	)	(2.41	)	(1.64	)	(2.45	)	(1.74	)
Heavy oil operating netback	14.06		19.50		29.37		19.99		43.18
NGLs Netback Excluding Realized Commodity Risk Management ($/bbl)
Sales	21.86		18.79		39.51		24.29		52.17
Royalties	(4.65	)	(4.69	)	(9.19	)	(7.92	)	(14.61	)
Operating expenses	(14.20	)	(13.89	)	(13.40	)	(14.30	)	(15.28	)
NGLs operating netback	3.01		0.21		16.92		2.07		22.28
Natural Gas Netback Excluding Realized Commodity Risk Management ($/Mcf)
Sales	2.50		3.02		4.02		3.00		4.74
Royalties (2)	(0.26	)	0.07		(0.19	)	(0.09	)	(0.33	)
Operating expenses	(1.89	)	(2.13	)	(2.06	)	(2.26	)	(2.45	)
Transportation expenses	(0.28	)	(0.32	)	(0.20	)	(0.31	)	(0.13	)
Natural gas operating netback ($/Mcf)	0.07		0.64		1.57		0.34		1.83
Natural gas operating netback ($/boe)	0.42		3.84		9.42		2.04		10.98
CONTRIBUTION BASED ON OPERATING NETBACKS
Light oil	52	%	46	%	50	%	54	%	55	%
Heavy oil	42	%	42	%	17	%	37	%	17	%
Natural gas liquids	4	%	—	%	11	%	2	%	11	%
Natural gas	2	%	12	%	22	%	7	%	17	%

⁽¹⁾  Includes Lindbergh operating results.

⁽²⁾  Third quarter of 2015 royalties impacted by Gas Cost Allowance and other incentives.

PENGROWTH 2015 Management's Discussion and Analysis 21

Pengrowth realized an operating netback of $25.07/boe in the fourth quarter of 2015 representing a 2 percent decrease compared to the third quarter of 2015 primarily due to the impact of lower benchmark prices partly offset by higher realized commodity risk management gains.

The operating netback increased 4 percent in the fourth quarter of 2015 compared to the same period last year as higher realized commodity risk management gains, lower royalties and operating expenses, more than offset the impact of steep declines in commodity prices year over year.

Similarly, Pengrowth's full year 2015 operating netback decreased 3 percent compared to the same period last year as the significant decline in commodity prices in 2015 was mostly mitigated by the realized commodity risk management gains, lower royalties and lower operating expenses.

GENERAL AND ADMINISTRATIVE EXPENSES

	Three months ended			Twelve months ended
($ millions except per boe amounts)	Dec 31, 2015	Sept 30, 2015	Dec 31, 2014	Dec 31, 2015	Dec 31, 2014
Cash G&A expenses (1)	15.8	24.2	21.2	87.0	84.3
$/boe	2.53	3.54	3.21	3.34	3.15
Non-cash G&A expenses (1)	2.3	1.4	2.6	12.7	16.0
$/boe	0.37	0.21	0.39	0.49	0.60
Total G&A (1)	18.1	25.6	23.8	99.7	100.3
$/boe	2.90	3.75	3.60	3.83	3.75

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

Fourth quarter of 2015 cash G&A expenses decreased $8.4 million or $1.01/boe compared to the third quarter of 2015 primarily due to the absence of $4.8 million of severance costs incurred in the third quarter as well as lower personnel costs resulting from significant staff reductions. Fourth quarter of 2015 cash G&A expenses decreased $5.4 million or $0.68/boe compared to the fourth quarter of 2014 primarily due to lower personnel costs resulting from significant staff reductions partly offset by lower recoveries in 2015.

Full year 2015 cash G&A expenses were $2.7 million or $0.19/boe higher compared to the same period last year driven by severance costs incurred and lower recoveries in 2015. This was partially offset by lower personnel costs resulting from 2015 staff reductions late in the third quarter of 2015, combined with lower IT and other costs. Pengrowth's 2016 full year cash G&A Guidance is $65 million.

The non-cash component of G&A represents the compensation expenses associated with Pengrowth’s Long Term Incentive Plan ("LTIP"). See Note 13 to the December 31, 2015 audited Consolidated Financial Statements for additional information. The compensation costs associated with this plan are expensed over the applicable vesting periods.

Fourth quarter of 2015 non-cash G&A expenses increased $0.9 million compared to the third quarter of 2015 due to the absence of the third quarter staff reduction related forfeiture adjustment. Fourth quarter of 2015 non-cash G&A expenses remained relatively flat compared to the same period last year.

Full year 2015 non-cash G&A expenses decreased $3.3 million compared to 2014 driven by higher forfeitures in 2015.

During the twelve months ended December 31, 2015, $8.5 million (December 31, 2014 - $14.7 million) of directly attributable G&A costs were capitalized to Property, Plant and Equipment ("PP&E").

DEPLETION, DEPRECIATION, AMORTIZATION AND ACCRETION

	Three months ended			Twelve months ended
($ millions except per boe amounts)	Dec 31, 2015	Sept 30, 2015	Dec 31, 2014	Dec 31, 2015	Dec 31, 2014
Depletion, depreciation and amortization	104.9	120.8	127.7	455.3	517.0
$/boe	16.78	17.69	19.33	17.47	19.33
Accretion	3.9	4.4	4.4	17.1	18.8
$/boe	0.62	0.64	0.67	0.66	0.70

PENGROWTH 2015 Management's Discussion and Analysis 22

Fourth quarter of 2015 DD&A expense decreased $15.9 million compared to the third quarter of 2015 primarily due to the absence of depletion on properties divested in the fourth quarter of 2015 in addition to lower net book values resulting from the third quarter of 2015 PP&E impairment charges.

Fourth quarter and full year 2015 DD&A expense decreased $22.8 million and $61.7 million, respectively, compared to the same periods last year. The absence of depletion related to several 2014 and 2015 property dispositions, combined with lower net book values resulting from the PP&E impairment charges recorded in the fourth quarter of 2014 and third quarter of 2015 were the main reasons for the lower expense. This was partially offset by additional DD&A relating to the Lindbergh Phase 1 production in 2015.

On a per boe basis, fourth quarter and full year 2015 DD&A decreased relative to all respective comparative periods primarily due to lower DD&A expense as described above.

Fourth quarter of 2015 ARO accretion expense decreased $0.5 million compared to the third quarter of 2015 and fourth quarter of 2014, respectively, primarily due to the absence of ARO liability associated with divested properties.

Full year 2015 accretion expense decreased $1.7 million compared to 2014 due to the absence of ARO liability associated with several 2014 and 2015 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.

During the fourth quarter of 2014, Pengrowth acquired 32.6 gross/net sections of prospective liquids-rich Montney lands at Bernadet in north eastern British Columbia.

E&E assets totaled $494.8 million at December 31, 2015, primarily related to the Groundbirch and Bernadet properties in north eastern British Columbia. See Note 6 to the December 31, 2015 audited Consolidated Financial Statements for more information.

IMPAIRMENTS

	Three months ended			Twelve months ended
($ millions)	Dec 31, 2015	Sept 30, 2015	Dec 31, 2014	Dec 31, 2015	Dec 31, 2014
PP&E impairment	401.0	409.0	486.3	810.0	486.3
E&E Impairment	—	—	57.0	—	57.0
Goodwill impairment	117.5	73.0	451.3	190.5	451.3
Total impairment	518.5	482.0	994.6	1,000.5	994.6

PP&E Impairments

IFRS requires an impairment test to assess the recoverable value of the PP&E within each CGU whenever there is an indication of impairment. In light of a significant and sustained decline in both oil and natural gas benchmark prices throughout 2015, impairment tests were carried out on six CGUs at September 30, 2015, resulting in a $409.0 million PP&E impairment. Additional impairment tests were carried out on all CGUs at December 31, 2015, resulting in a $401.0 million PP&E impairment at December 31, 2015. The December 31, 2015 impairment tests carried out were based on reserve values using a pre-tax discount rate of 10 percent, January 1, 2016 independent reserves evaluator's forecast pricing and an inflation rate of 2 percent. At December 31, 2014, Pengrowth used pre-tax discount rates ranging between 10 percent and 15 percent with the latter rate used for Lindbergh. Lindbergh discount rate was lowered at December 31, 2015 following commercial production in 2015. The recoverable amount of each CGU was determined using value in use. All CGUs were negatively impacted by a downturn in the forward benchmark prices. See Note 5 to the audited Consolidated Financial Statements for additional information.

The impairments noted above were recorded on the Consolidated Statements Loss at December 31, 2015 and may be reversed, excluding goodwill, if and when the fair values of the CGUs increase in future periods. However, the impairment test is sensitive to lower commodity prices, which have been under significant downward pressure since 2014. Further declines in commodity prices could result in additional impairment charges if the recoverable values are further eroded by price decreases.

PENGROWTH 2015 Management's Discussion and Analysis 23

At December 31, 2014, impairment tests were carried out on all CGUs in light of significant and rapid declines in benchmark prices at that time. This resulted in a $486.3 million PP&E impairment recorded at December 31, 2014.

E&E Impairments

In conjunction with the Montney CGU, which has both PP&E and E&E, Pengrowth evaluated Groundbirch for an impairment. This was in accordance with Pengrowth's policy and IFRS which states that the impairment of ongoing E&E projects should be assessed on the cash flow from the applicable CGUs in the operating segment. It was determined that the recoverable amount exceeded the carrying amount and, as such, no impairment was recorded for the year ended December 31, 2015.

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 and probable reserves for the operating segment. Undeveloped land, contingent resources and management's estimate of additional drilling locations 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 and contingent resource values using a pre-tax discount rate of 10 percent; independent reserves evaluator January 1, 2016 forecast pricing and an inflation rate of 2 percent; and management's estimate of the risked net present value of additional drilling locations. See Notes 5 and 6 to the audited Consolidated Financial Statements for more information.

At December 31, 2014, Pengrowth also evaluated the Groundbirch project in conjunction with the Montney CGU for impairment. It was determined that the recoverable amount was below the carrying amount, resulting in a $57.0 million impairment at December 31, 2014.

Goodwill Impairments

In accordance with IFRS, goodwill is assessed for impairment at each year end, or when there is an indication of impairment, in conjunction with the assessment for impairment of PP&E and E&E.

During 2015, all CGUs were negatively impacted by a downturn in the forward benchmark prices resulting in goodwill impairment testing at September 30, 2015 and at December 31, 2015. At September 30, 2015, Pengrowth impaired goodwill by $73.0 million. In conjunction with PP&E impairment testing at year end 2015, it was determined that the entire balance of goodwill was impaired at December 31, 2015. Pengrowth therefore recognized an additional $117.5 million impairment eliminating the remaining goodwill balance at December 31, 2015, which may not be reversed. In addition to the impairment charges, several non-core 2015 property dispositions resulted in an $11.7 million decrease in goodwill in 2015 (2014 - $19.2 million).

At December 31, 2014, goodwill impairment tests were performed. This resulted in a $451.3 million goodwill impairment, reducing the goodwill balance to $202.2 million at December 31, 2014. See Note 7 to the December 31, 2015 audited Consolidated Financial Statements for more information.

INTEREST AND FINANCING CHARGES

	Three months ended						Twelve months ended
($ millions)	Dec 31, 2015		Sept 30, 2015		Dec 31, 2014		Dec 31, 2015		Dec 31, 2014
Interest and financing charges	28.5		29.3		27.6		116.3		105.6
Capitalized interest	(0.6	)	(0.8	)	(9.9	)	(12.4	)	(31.0	)
Total interest and financing charges	27.9		28.5		17.7		103.9		74.6

At December 31, 2015, Pengrowth had approximately $1.8 billion in total debt before working capital composed of $1.6 billion of fixed rate debt, $0.1 billion of credit facilities borrowings and $0.1 billion in convertible debentures.Total fixed rate debt consists primarily of U.S. dollar denominated fixed rate notes at a weighted average interest rate of 5.8 percent. The credit facilities had an average 3.3 percent interest rate and the convertible debentures have a 6.25 percent coupon.

Fourth quarter of 2015 interest and financing charges, before capitalized interest, decreased $0.8 million compared to the third quarter of 2015 due to lower borrowings on the credit facilities in the fourth quarter resulting from utilization of property disposition proceeds. Higher Canadian equivalent interest expense on U.S. term debt, resulting from the weakening of the Canadian Dollar, was offset by the absence of interest relating to the U.K. term debt repaid on December 1, 2015.

PENGROWTH 2015 Management's Discussion and Analysis 24

Fourth quarter and full year 2015 interest and financing charges, before capitalized interest, increased $0.9 million and $10.7 million compared to the same periods in 2014, respectively. The increase was due to the additional interest incurred from higher borrowings on the credit facilities throughout 2015 compared to 2014 and higher Canadian equivalent interest expense on U.S. term debt resulting from the weakening of the Canadian Dollar. This was partially offset by the absence of interest pertaining to a convertible debenture which was repaid in December 2014, and the repayment in May 2015 of the U.S.$71.5 million (Cdn$86.6 million) unsecured notes.

Following commercial declaration of the project on April 1, 2015, Pengrowth ceased capitalizing interest on the Lindbergh Phase 1 project. 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, 2015, $12.4 million (December 31, 2014 - $31.0 million) of interest was capitalized on the Lindbergh project to PP&E using Pengrowth's weighted average cost of debt of 5.4 percent (December 31, 2014 - 5.7 percent).

OTHER (INCOME) EXPENSE

Full year 2015 other income of $2.7 million, relating mostly to investment income on remediation trust funds, compares to the full year 2014 other expense of $24.3 million. 2014 other expense included a $22.6 million provision for clean-up and remediation costs at a northern Alberta oil property incurred in the first quarter of 2014 partly offset by gains on remediation trust funds and interest income.

TAXES

Deferred income tax is a non-cash item relating to temporary differences between the accounting and tax basis of Pengrowth’s assets and liabilities and has no immediate impact on Pengrowth’s cash flows. Pengrowth recorded a deferred tax recovery of $108.4 million in the fourth quarter of 2015, compared to a deferred tax recovery of $78.5 million in the third quarter of 2015, and a $14.4 million deferred tax recovery in the fourth quarter of 2014. This is primarily due to a PP&E impairment of $401.0 million and $409.0 in the fourth quarter and third quarter of 2015 respectively. Full year 2015 deferred tax recovery amounted to $222.7 million compared to a deferred tax recovery of $20.4 million in 2014.

Pengrowth has certain income tax filings from predecessor entities that are in dispute with tax authorities and has recorded a payable of $9.5 million it is required to remit to the Canada Revenue Agency ("CRA") 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 $9.5 million has been recorded as a long term receivable.

No current income taxes were paid by Pengrowth in 2015 or 2014. See Note 11 to the December 31, 2015 audited Consolidated Financial Statements for additional information.

PENGROWTH 2015 Management's Discussion and Analysis 25

FOREIGN CURRENCY GAINS (LOSSES)

	Three months ended						Twelve months ended
($ millions)	Dec 31, 2015		Sept 30, 2015		Dec 31, 2014		Dec 31, 2015		Dec 31, 2014
Currency exchange rate (Cdn$1 = U.S.$) at period end	0.72		0.75		0.86		0.72		0.86
Unrealized foreign exchange loss on U.S. dollar denominated debt	(55.7	)	(95.8	)	(47.9	)	(253.8	)	(114.9	)
Unrealized foreign exchange gain (loss) on U.K. pound sterling denominated debt	(0.1	)	(3.7	)	0.5		(13.9	)	(2.9	)
Total unrealized foreign exchange loss from translation of foreign denominated debt	(55.8	)	(99.5	)	(47.4	)	(267.7	)	(117.8	)
Unrealized gain on U.S. foreign exchange risk management contracts	31.0		54.1		17.3		19.2		34.9
Unrealized gain (loss) on U.K. foreign exchange risk management contracts	(0.2	)	4.1		0.3		13.3		3.9
Total unrealized gain on foreign exchange risk management contracts	30.8		58.2		17.6		32.5		38.8
Net unrealized foreign exchange loss	(25.0	)	(41.3	)	(29.8	)	(235.2	)	(79.0	)
Net realized foreign exchange gain (loss)	0.3		(0.6	)	(0.3	)	91.5		(1.0	)

As more than 85 percent of Pengrowth’s total debt before working capital is denominated in foreign currencies, the majority of Pengrowth’s unrealized foreign exchange gains and losses is 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 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 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.

U.S. Swap Contracts

Pengrowth holds a series of swap contracts which were transacted in order to fix the foreign exchange rate on a portion of Pengrowth’s U.S. dollar denominated term debt. The swaps partially offset foreign exchange gains/losses on U.S. dollar denominated debt. Each swap requires Pengrowth to buy U.S. dollars at a predetermined rate and time, based upon maturity dates of the U.S. dollar term debt.

During the first quarter of 2015, Pengrowth monetized U.S.$410 million of swap contracts that fixed the foreign exchange rate on Pengrowth’s U.S. dollar denominated term debt. This resulted in a Cdn$84.1 million realized foreign exchange gain in the first quarter of 2015 and the cash proceeds were used to pay down a portion of the credit facilities. The foreign exchange swap contracts of U.S.$50 million associated with the May 2015 U.S. term debt series settled in tandem with its maturity, resulting in a Cdn$9.8 million realized foreign exchange gain recorded in the second quarter of 2015. Together, these transactions brought 2015 realized foreign exchange gains from settlement of U.S. swap contracts to Cdn$93.9 million. Subsequent to the above mentioned monetization, Pengrowth entered into a series of new foreign exchange swap contracts as outlined in the table below. At December 31, 2015, Pengrowth held a total of U.S.$920.0 million in foreign exchange swap contracts at a weighted average fixed rate of U.S.$0.78 per Cdn$1 compared to U.S.$460 million at December 31, 2014 at a weighted average fixed rate of U.S.$0.96 per Cdn$1.

Contract type	Settlement date	Principal amount (U.S.$ millions)	Swapped amount (U.S.$ millions)	% of principal swapped		Fixed rate (Cdn$1 = U.S.$)
Swap	July 2017	400.0	400.0	100	%	0.79
Swap	August 2018	265.0	265.0	100	%	0.78
Swap	October 2019	35.0	35.0	100	%	0.78
Swap	May 2020	115.5	115.0	100	%	0.78
Swap	October 2022	105.0	105.0	100	%	0.77
No contracts	October 2024	195.0	—	—	%	—
		1,115.5	920.0	82	%

PENGROWTH 2015 Management's Discussion and Analysis 26

At December 31, 2015, the fair value of the U.S. foreign exchange derivative contracts was an asset of Cdn$77.2 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.

U.K. Swap Contracts

Pengrowth entered into foreign exchange risk management contracts when it issued the U.K. pound sterling term notes. The foreign exchange swap contract associated with the U.K. term debt which matured on December 1, 2015, settled in tandem with its maturity resulting in a Cdn$0.2 million realized foreign exchange gain recorded in the fourth quarter of 2015.

At December 31, 2015, 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:

Amount (U.K. pound sterling millions)	Settlement date	Fixed rate (Cdn$1 = U.K. pound sterling)
15.0	October 2019	0.63

At December 31, 2015, the fair value of the U.K. foreign exchange derivative contracts was a net asset of $6.1 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 Rate Sensitivity

At December 31, 2015, each Cdn$0.01 exchange rate change would result in approximately a Cdn$9.2 million pre-tax change in the fair value of the U.S. risk management contracts and a Cdn$0.2 million pre-tax change in the fair value of the U.K. risk management contracts.

ASSET RETIREMENT OBLIGATIONS - NET PRESENT VALUE

($ millions)	Dec 31, 2015		Dec 31, 2014		Change
ARO, beginning of year	780.8		606.2		174.6
Revisions due to discount rate changes (1)	—		211.5		(211.5	)
Expenditures on remediation/provisions settled	(19.0	)	(22.9	)	3.9
ARO on dispositions	(112.4	)	(66.5	)	(45.9	)
Incurred during the period	16.8		10.3		6.5
Accretion	17.1		18.8		(1.7	)
Other revisions	20.1		23.4		(3.3	)
ARO, end of year	703.4		780.8		(77.4	)

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

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, 2015, ARO liability decreased $77.4 million mainly due to the $112.4 million reduction resulting from the 2015 property dispositions. Pengrowth has estimated the net present value of its total ARO to be $703.4 million as at December 31, 2015 (December 31, 2014 – $780.8 million), based on a total escalated future liability of $1.7 billion (December 31, 2014 – $2.0 billion). The majority of the costs are expected to be incurred between 2040 and 2080. A risk free discount rate of 2.3 percent per annum and an ARO specific inflation rate of 1.5 percent were used to calculate the net present value of the ARO at December 31, 2015.

PENGROWTH 2015 Management's Discussion and Analysis 27

REMEDIATION TRUST FUNDS AND REMEDIATION AND ABANDONMENT EXPENSE

During 2015, Pengrowth contributed $21.4 million (December 31, 2014 - $5.0 million), into externally managed trust funds established to fund certain abandonment and reclamation costs associated with Judy Creek and Sable Offshore Energy Project ("SOEP"). The total balance of the remediation trust funds was $79.6 million at December 31, 2015 (December 31, 2014 - $60.4 million).

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

Pengrowth has a contractual obligation to make contributions to a remediation trust fund that will be used to fund the ARO of the SOEP properties and facilities. In 2015, Pengrowth made a monthly contribution to the fund at a rate of $4.17/MMBtu of its share of natural gas production and $8.36/bbl of its share of natural gas liquids production from SOEP. Starting in January 2016, the new rates are $6.64/MMBtu of its share of natural gas production and $13.29/bbl of its share of natural gas liquids production.

See Note 4 to the December 31, 2015 audited Consolidated Financial Statements for additional information.

Pengrowth takes a proactive approach to managing its well abandonment and site restoration obligations. There is an on-going program to abandon wells and reclaim well and facility sites. For 2015, Pengrowth spent $19.0 million on abandonment and reclamation (December 31, 2014 - $22.9 million). Pengrowth expects to spend approximately $20.9 million in 2016 on abandonment and reclamation activities, excluding contributions to remediation trust funds and orphan well levies from the Alberta Energy Regulator.

CLIMATE CHANGE PROGRAMS

Effective July 1, 2007, Alberta regulates Greenhouse Gas ("GHG") emissions under the Climate Change and Emissions Management Act of 2007. Under the Act, the Specified Gas Reporting Regulation ("SGRR") imposes annual GHG emissions reporting requirements on all Alberta facilities that emit more than 50,000 tonnes of greenhouse gases per year.

Pengrowth is subject to the Specified Gas Emitters Regulation (“SGER”), which imposes GHG emissions intensity limits and reduction requirements for owners of facilities that emit 100,000 tonnes per year or more of GHG. Recent amendments to the SGER have increased the maximum emission intensity reduction requirement for facility owners from 12 percent to 15 percent over baseline emission levels for those facilities in 2016, and 20 percent starting in 2017. The baseline for facilities is an average of 2003, 2004 and 2005 emissions. Facilities can meet these required reductions in three ways: audited emission reductions in their operations; purchased Alberta-based offset carbon credits or contributions to the Alberta Climate Change and Emissions Management Fund. Unused reduction credits from one year may be carried forward to future years. The recent SGER amendments have increased the price for such credits from $15/tonne to $20/tonne for 2016 and $30/tonne beginning in 2017.

In 2015, Pengrowth had three operated facilities that are subject to the annual 12 percent reduction: the Olds Gas Plant, the Judy Creek Gas Conservation Plant and the Quirk Creek Gas Plant. Pengrowth will submit the 2015 SGER Compliance reports summarizing emissions reduction information on these facilities by March 31, 2016, as scheduled. It is anticipated that the Olds Gas Plant and the Judy Creek Gas Conservation Plant will achieve the reduction targets for 2015; however the Quirk Creek Gas Plant is not expected to achieve the reduction target. During 2015, Pengrowth purchased approximately $0.2 million of Emission Performance Credits payable to the Alberta Climate Change and Emissions Management Fund relating to the 2014 Quirk Creek Gas Plant emissions reporting. Pengrowth expects to purchase a similar amount in the first quarter of 2016 relating to the 2015 emissions reporting.

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.

PENGROWTH 2015 Management's Discussion and Analysis 28

The extent and magnitude of these additional programs cannot be reliably or accurately estimated at this time because specific legislative and regulatory requirements have not been finalized.

ACQUISITIONS AND DISPOSITIONS

	Three months ended						Twelve months ended
($ millions)	Dec 31, 2015		Sept 30, 2015		Dec 31, 2014		Dec 31, 2015		Dec 31, 2014
Property acquisitions	—		0.9		1.2		0.9		17.0
Proceeds on property dispositions	(183.4	)	(3.1	)	(21.0	)	(210.5	)	(84.5	)
Net cash dispositions	(183.4	)	(2.2	)	(19.8	)	(209.6	)	(67.5	)

During 2015, Pengrowth successfully closed the dispositions of its non-core Jenner and Bodo assets and other minor properties for proceeds of $210.5 million, net of closing adjustments, resulting in pre-tax losses of $98.1 million. The proceeds were used to reduce the Company's outstanding debt as part of the strategy of strengthening the balance sheet.

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

WORKING CAPITAL

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

At December 31, 2015, Pengrowth had a working capital surplus of $185.3 million compared to a working capital surplus of $33.4 million at December 31, 2014. The increase in the working capital surplus at December 31, 2015 can be primarily attributed to a decrease in accounts payable year over year resulting from significantly lower capital and operating expenses.

PENGROWTH 2015 Management's Discussion and Analysis 29

FINANCIAL RESOURCES AND LIQUIDITY

Pengrowth has in place a $1.0 billion revolving, committed credit facility (“Credit Facility”) supported by a syndicate of eleven international and domestic banks in addition to a $50 million demand facility (“Demand Facility”) issued by a large Canadian financial institution. The Credit Facility was renewed in March 2015, without any material changes to its terms, conditions, financial covenants or committed amount, and matures in March 2019. Pengrowth can access the unutilized portion of the Credit Facility, provided it remains in compliance with all financial covenants.

In excess of 85 percent of Pengrowth’s total debt before working capital consists of long term notes denominated in foreign currencies. Each long term note is governed by a Note Purchase Agreement. These Notes have fixed coupon rates and maturity dates between 2017 and 2024.

The covenants, terms and conditions substantially match across all the lending agreements and at December 31, 2015 Pengrowth was in compliance with all conditions contained within the Credit Facility, Demand Facility and Note Purchase Agreements.

As at:	Dec 31, 2015		Dec 31, 2014		Change
($ millions)
Credit facilities	107.7		201.7		(94.0	)
Senior unsecured notes (1)	1,611.8		1,531.0		80.8
Senior debt	1,719.5		1,732.7		(13.2	)
Convertible debentures	137.0		137.2		(0.2	)
Total debt before working capital	1,856.5		1,869.9		(13.4	)
Working capital surplus (2)	(185.3	)	(33.4	)	(151.9	)
Total debt	1,671.2		1,836.5		(165.3	)
Twelve months trailing:	Dec 31, 2015		Dec 31, 2014		Change
($ millions, except ratios and percentages)
Net loss	(1,093.1	)	(578.8	)	(514.3	)
Add (deduct):
Interest and financing charges	103.9		74.6		29.3
Deferred income tax recovery	(222.7	)	(20.4	)	(202.3	)
Depletion, depreciation, amortization and accretion	472.4		535.8		(63.4	)
EBITDA	(739.5	)	11.2		(750.7	)
Add other items:
Impairment	1,000.5		994.6		5.9
(Gain) loss on disposition of properties	98.1		(23.3	)	121.4
Other non-cash items (3)	298.2		(402.2	)	700.4
Adjusted EBITDA	657.3		580.3		77.0
Senior debt before working capital to Adjusted EBITDA (4)	2.6		3.0		(0.4	)
Total debt before working capital to Adjusted EBITDA (5)	2.8		3.2		(0.4	)
Total book capitalization (6)	3,484.5		4,659.5		(1,175.0	)
Senior debt before working capital as a percentage of total book capitalization (7)	49.3	%	37.2	%
Adjusted EBITDA to interest expense (8)	6.3		7.8		(1.5	)

⁽¹⁾  Includes current and long term portions, as applicable.

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

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

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

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

⁽⁶⁾  Total book capitalization includes senior debt before working capital plus Shareholders' Equity per the Consolidated Balance Sheets.

⁽⁷⁾  Indicative of debt covenant for senior debt before working capital which must be less than 55 percent of total book capitalization.

⁽⁸⁾  Indicative of debt covenant for EBITDA must not be less than four times interest expense for the last four fiscal quarters.

The trailing twelve month total debt before working capital to Adjusted EBITDA decreased to 2.8 times at December 31, 2015 from 3.2 times at December 31, 2014 mainly due to higher Adjusted EBITDA driven by the Cdn$94.1 million of the 2015 realized foreign exchange gains from monetization and settlement of the U.S. and U.K. swap contracts.

PENGROWTH 2015 Management's Discussion and Analysis 30

Total Debt Before Working Capital Continuity

(Cdn$ millions)	2014 vs. 2015
Total debt before working capital at December 31, 2014	1,869.9
Increase (decrease) due to:
Foreign exchange impact of the weakening Canadian dollar on U.S. denominated debt	264.7
Foreign exchange impact of the weakening Canadian dollar on U.K. denominated debt	3.5
U.S. senior unsecured note settled in May 2015	(86.6	)
U.K. senior unsecured note settled in December 2015	(100.8	)
Credit facilities paid down in 2015	(94.0	)
Other	(0.2	)
Total decrease	(13.4	)
Total debt before working capital at December 31, 2015	1,856.5

At December 31, 2015, total debt before working capital decreased $13.4 million compared to December 31, 2014 as per the table above. As the majority of Pengrowth's debt is denominated in U.S. dollars and U.K. pound sterling, the weakening Canadian dollar drove up reported total debt before working capital year over year. Although Pengrowth manages its foreign exchange exposure through swap contracts, the unrealized gain or loss associated with these swaps is not included in either the reported year end debt balance or the table above.

Despite lower commodity prices, drawings on the credit facilities decreased $94.0 million year over year. The proceeds from the 2015 divestment activities and realized gains associated with Pengrowth’s commodity and foreign exchange risk management program were used to pay down not only the outstanding credit facility balance but also the May 2015 senior unsecured notes of U.S.$71.5 million (Cdn$86.6 million) and December 2015 senior unsecured notes of U.K.£50.0 million (Cdn$100.8 million) upon maturity.

Although not incorporated in the table above, the impact of the weakening of the Canadian dollar on the total debt was partially mitigated by Pengrowth's foreign exchange risk management program where the fair value of the foreign exchange derivative contracts was an asset of Cdn$83.3 million on the Consolidated Balance Sheets at December 31, 2015.

As noted previously, in the first quarter of 2015 Pengrowth monetized the majority of its U.S. swap contracts that fixed the foreign exchange rate on Pengrowth’s U.S. dollar denominated term debt which resulted in a Cdn$84.1 million realized foreign exchange gain in the first quarter of 2015. The liquidated swaps were immediately replaced with new swaps at then current market rates. In addition, the foreign exchange swap contracts associated with the May 2015 U.S. and December 2015 U.K. term debt series settled in tandem with their respective maturities, resulting in a further Cdn$10.0 million of realized foreign exchange gains in 2015. Together, these transactions brought 2015 realized foreign exchange gains to Cdn$94.1 million.

Financial Covenants

Pengrowth’s senior unsecured notes and credit facilities are subject to a number of covenants, all of which were met at all times during the preceding twelve months, and at December 31, 2015. All loan agreements can be found on SEDAR at www.sedar.com filed under "Other" or "Material Document" and on EDGAR at www.sec.gov.

The key financial covenants as at December 31, 2015 are summarized below:

Covenant	Limit	Actual at December 31, 2015 (1)
Total senior debt before working capital must not exceed 3.5 times EBITDA for the last four fiscal quarters	< 3.5 times	2.7 times
Total debt before working capital must not exceed 4.0 times EBITDA for the last four fiscal quarters	< 4.0 times	2.9 times
Total senior debt before working capital must be less than 55 percent of total book capitalization	< 55%	50%
EBITDA must not be less than four times interest expense for the last four fiscal quarters	> 4 times	6.2 times

⁽¹⁾  As senior unsecured notes and Credit Facilities have slightly different covenant calculations, the calculated covenants at December 31, 2015 represent those closest to the limits.

PENGROWTH 2015 Management's Discussion and Analysis 31

The calculation for each financial covenant is based on specific definitions within the agreements, is not in accordance with IFRS, is substantially similar to the calculations noted in the Financial Resources and Liquidity section table, and cannot be readily replicated by referring to Pengrowth’s Consolidated Financial Statements.

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, absent a cure, result in other loans also being in default. In the event that non-compliance continued, Pengrowth would have to repay, refinance or re-negotiate the terms and conditions of the debt.

If certain financial ratios reach or exceed certain levels, management may consider steps to improve these ratios. These steps may include, but are not limited to property dispositions, monetizing risk management contracts, reducing capital expenditures or dividends as well as issuing equity.

Pengrowth amended its term credit facility in December 2015 to increase the maximum permitted senior debt before working capital to total book capitalization ratio from 50 percent to 55 percent. This change now aligns this covenant between the credit facilities and senior unsecured debt at a 55 percent limit.

Measures in Response to Continued Low Commodity Prices

Pengrowth remains committed to reducing its overall debt and has taken proactive and extensive measures in early 2016 to ensure the Corporation's financial health and sustainability including:

• Pengrowth plans to continue with its non-core asset sales process throughout 2016 in an effort to achieve its previously set disposition target of an additional $300 million.

• The 2016 capital program of approximately $60 to $70 million has no capital allocated for drilling, but does contemplate some minor capital to advance long-term projects, namely at Lindbergh and Bernadet, as these projects represent strategic low cost opportunities for longer-term production growth. The bulk of Pengrowth’s 2016 capital program will be focused on safety, asset integrity and maintenance programs.

• A deferral of Lindbergh Phase II capital spending for at least one more year.

• Continued focus on management of all aspects of cost structures including G&A and operating expenses.

• Pengrowth has extensive oil and natural gas risk management contracts in place through the end of 2016 that are expected to provide a significant degree of cash flow certainty notwithstanding the current low commodity price environment. The Company also has significant natural gas risk management contracts in place for 2017 and 2018 and continues to target opportunities to add additional crude oil contracts for 2017 and 2018 as commodity price opportunities present themselves.

• Pengrowth's Board of Directors approved suspending the $0.01 per share quarterly dividend on January 20, 2016. No cash dividend will be paid for the first quarter of 2016. The Board will continue to review the dividend policy on a quarterly basis.

Credit Facilities

Pengrowth's extendible revolving term credit facility had an outstanding balance of $104.0 million at December 31, 2015 (December 31, 2014 - $191.0 million) and $21.6 million (December 31, 2014 - $25.0 million) in outstanding letters of credit, for a total utilization of $125.6 million (December 31, 2014 - $216.0 million). The credit facility includes an expansion feature of $250 million providing Pengrowth with up to $1.25 billion of notional credit capacity which can be extended at Pengrowth’s discretion any time prior to maturity, subject to syndicate approval.

Pengrowth's demand operating facility had a balance of $2.5 million at December 31, 2015 (December 31, 2014 - $9.0 million) and $1.4 million (December 31, 2014 - $0.9 million) of outstanding letters of credit. When utilized together with any overdraft amounts, this facility appears on the Consolidated Balance Sheets as a current liability in bank indebtedness, as applicable.

Together, these two facilities provided Pengrowth with approximately $919 million of combined notional credit capacity at December 31, 2015, with the ability to expand the facilities by an additional $250 million. Use of the remaining credit capacity is still subject to compliance with all financial covenants and could require increased cash flow to support any increase in debt.

Off-Balance Sheet Financing

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

PENGROWTH 2015 Management's Discussion and Analysis 32

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, 2015 audited Consolidated Financial Statements for a description of the accounting policies for financial instruments and Note 17 to the December 31, 2015 audited Consolidated Financial Statements for additional information regarding the fair value of Pengrowth’s financial instruments.

FUNDS FLOW FROM OPERATIONS AND DIVIDENDS

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

	Three months ended						Twelve months ended
($ millions, except per share amounts)	Dec 31, 2015		Sept 30, 2015		Dec 31, 2014		Dec 31, 2015		Dec 31, 2014
Funds flow from operations	114.2		120.6		115.8		459.3		505.7
Dividends declared	5.5		21.8		63.9		101.0		253.6
Funds flow from operations less dividends declared	108.7		98.8		51.9		358.3		252.1
Per share	0.20		0.18		0.10		0.66		0.48
Payout ratio (1) (2)	5	%	18	%	55	%	22	%	50	%

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

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

As a result of the depleting nature of Pengrowth's oil and gas assets, capital expenditures are required to offset production declines while other capital is required to maintain facilities, acquire prospective lands and prepare future projects. Capital spending and acquisitions may be funded by the excess of funds flow from operations less dividends declared, as applicable, through the sale of existing properties, additional debt or the issuance of equity. Pengrowth does not deduct capital expenditures when calculating funds flow from operations.

Funds flow from operations is derived from producing and selling oil, natural gas and related products and is therefore highly dependent on commodity prices. Pengrowth enters into forward commodity risk management contracts to mitigate price volatility and to provide a measure of stability to monthly cash flow. Details of commodity risk management contracts are contained in Note 17 to the December 31, 2015 audited Consolidated Financial Statements.

PENGROWTH 2015 Management's Discussion and Analysis 33

DIVIDENDS

Pengrowth’s Board of Directors and management regularly review the level of dividends. Pengrowth’s Board considers a number of factors, including expectations of future commodity prices, capital expenditure requirements and the availability of debt and equity capital. Dividends can and may fluctuate in the future as a result of the volatility in commodity prices, changes in production levels and capital expenditure requirements. Pengrowth has no restrictions on the payment of its dividends other than maintaining its financial covenants in its borrowings and restrictions in the Business Corporations Act (Alberta). In response to the low commodity price environment and near term price outlook, the dividend amount and policy was altered in 2015 and early 2016 by Pengrowth's Board of Directors.

During 2015 and 2014, Pengrowth paid the following dividends:

	Dividend amount paid (Cdn$ per share)
Month	2015	2014
January	0.04	0.04
February	0.04	0.04
March	0.02	0.04
April	0.02	0.04
May	0.02	0.04
June	0.02	0.04
July	0.02	0.04
August	0.02	0.04
September	0.02	0.04
October	—	0.04
November	—	0.04
December (1)	0.01	0.04
Total dividends paid per share	0.23	0.48

⁽¹⁾  December 2015 represents the quarterly payment of $0.01 per share.

On January 20, 2016, the Board suspended the quarterly payment of $0.01 per share. No cash dividend will be paid for the first quarter of 2016. The Board will continue to review the dividend policy on a quarterly basis.

Dividend Reinvestment Plan ("DRIP")

On September 1, 2015 the Board of Directors approved the suspension of the DRIP.

During 2015, 6.4 million shares were issued under the DRIP program for cash proceeds of $18.7 million compared to 9.2 million shares issued for total proceeds of $51.8 million in 2014.

PENGROWTH 2015 Management's Discussion and Analysis 34

SUMMARY OF QUARTERLY RESULTS

The following table is a summary of quarterly information for 2015 and 2014:

2015	Q1		Q2		Q3		Q4
Oil and gas sales ($ millions) (1)	199.9		249.9		211.9		169.1
Net loss ($ millions)	(160.5	)	(134.4	)	(329.6	)	(468.6	)
Net loss per share ($)	(0.30	)	(0.25	)	(0.61	)	(0.86	)
Net loss per share - diluted ($)	(0.30	)	(0.25	)	(0.61	)	(0.86	)
Adjusted net income (loss) ($ millions)	64.8		(38.9	)	(374.0	)	(463.4	)
Funds flow from operations ($ millions) (2)	113.0		111.5		120.6		114.2
Dividends declared ($ millions)	42.9		30.8		21.8		5.5
Dividends declared per share ($)	0.08		0.06		0.04		0.01
Daily production (boe/d)	69,334		74,113		74,239		67,934
Total production (Mboe)	6,240		6,744		6,830		6,250
Average sales price ($/boe) (1)	31.39		36.58		30.75		26.56
Operating netback ($/boe) (3)	25.37		23.98		25.48		25.07
2014	Q1		Q2		Q3		Q4
Oil and gas sales ($ millions) (1)	429.2		407.1		369.1		291.5
Net income (loss) ($ millions)	(116.2	)	(8.8	)	52.2		(506.0	)
Net income (loss) per share ($)	(0.22	)	(0.02	)	0.10		(0.95	)
Net income (loss) per share - diluted ($)	(0.22	)	(0.02	)	0.10		(0.95	)
Adjusted net income (loss) ($ millions)	(2.8	)	(24.8	)	3.4		(854.8	)
Funds flow from operations ($ millions)	139.5		121.4		129.0		115.8
Dividends declared ($ millions)	62.8		63.3		63.6		63.9
Dividends declared per share ($)	0.12		0.12		0.12		0.12
Daily production (boe/d)	75,102		73,823		72,472		71,802
Total production (Mboe)	6,759		6,718		6,667		6,606
Average sales price ($/boe) (1)	63.00		60.08		54.73		43.61
Operating netback ($/boe) (3)	29.71		23.86		24.91		24.04

⁽¹⁾  Excluding realized commodity risk management.

⁽²⁾  First, second and fourth quarters of 2015 funds flow from operations exclude $84.1 million, $9.8 million and $0.2 million, respectively, related to the settlement of foreign exchange swap contracts.

⁽³⁾  Including realized commodity risk management.

Fourth quarter of 2015 oil and gas sales were lower than all of the preceding quarters of 2015 and 2014, as per the table above, mostly driven by a continued decline in the benchmark prices throughout 2015. In contrast, the first and second quarters of 2014 oil and gas sales were at the highest level during the two year period driven by an increase in the benchmark prices at that time. The impact of the declining benchmark prices on oil and gas sales has been offset somewhat by the weakening Canadian dollar throughout the two year period.

Although oil and gas sales have declined significantly throughout 2014 and 2015, driven by a steep decline in the oil benchmark prices, operating netbacks and funds flow from operations remained strong primarily due to realized commodity risk management gains in 2015.

Fourth quarter of 2015 production was lower than all of the preceding quarters of 2015 and 2014 resulting primarily from property dispositions and natural declines due to capital spending curtailments in the current low commodity price environment. In contrast, the third quarter of 2015 production was the highest quarterly production since the first quarter of 2014 resulting from inclusion and ramp up of the Lindbergh Phase 1 production.

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

PENGROWTH 2015 Management's Discussion and Analysis 35

Pengrowth's fourth and third quarters of 2015 and fourth quarter of 2014 net loss and adjusted net loss were negatively impacted by non-cash after-tax impairment charges of approximately $414 million, $375 million and $858 million, respectively.

As a result of the $84.1 million realized foreign exchange gain from monetizing several U.S./Canadian dollar swap contracts, the first quarter of 2015 contained Pengrowth's highest adjusted net income since the first quarter of 2011.

SELECTED ANNUAL INFORMATION

The table below provides a summary of selected annual information for the years ended 2015, 2014 and 2013:

	Twelve months ended December 31
($ millions unless otherwise indicated)	2015		2014		2013
Oil and gas sales (1)	830.8		1,496.9		1,593.4
Net loss	(1,093.1	)	(578.8	)	(316.9	)
Net loss per share ($)	(2.02	)	(1.10	)	(0.61	)
Net loss per share - diluted ($)	(2.02	)	(1.10	)	(0.61	)
Dividends declared per share ($)	0.19		0.48		0.48
Total assets	4,550.7		6,169.8		6,633.2
Long term debt (2)	1,852.8		1,859.2		1,648.7
Shareholders' equity	1,765.0		2,926.8		3,688.3
Number of shares outstanding at year end (thousands)	543,033		533,438		522,031

⁽¹⁾  Excluding realized commodity risk management.

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

COMMITMENTS AND CONTRACTUAL OBLIGATIONS

($ millions)	2016	2017	2018	2019	2020	Thereafter	Total
Convertible debentures (1)	—	137.0	—	—	—	—	137.0
Interest payments on convertible debentures	8.6	2.1	—	—	—	—	10.7
Long term debt (2)	—	553.6	381.8	185.5	159.9	440.2	1,721.0
Interest payments on long term debt (3)	96.1	80.7	51.1	31.0	21.8	55.5	336.2
Operating leases (4)	14.2	13.1	9.8	9.7	10.0	42.7	99.5
Pipeline transportation	28.7	24.8	24.6	23.6	23.8	102.5	228.0
Other	12.9	1.7	1.1	0.4	0.4	14.0	30.5
	160.5	813.0	468.4	250.2	215.9	654.9	2,562.9

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

⁽²⁾  The debt repayment includes foreign denominated fixed rate debt translated using the year end exchange rate and excludes related foreign exchange risk management contracts.

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

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

SUBSEQUENT EVENT

On January 20, 2016, Pengrowth's Board of Directors amended the dividend policy suspending the quarterly payment of $0.01 per share. No cash dividend will be paid for the first quarter of 2016. The Board will continue to review the dividend policy on a quarterly basis.

BUSINESS RISKS

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

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

PENGROWTH 2015 Management's Discussion and Analysis 36

Risks associated with Commodity Prices

• The prices of Pengrowth’s products (crude oil, bitumen, natural gas and NGLs) fluctuate due to many factors including local and global market supply and demand, weather patterns, availability of pipeline and rail transportation capacity, availability of refining capacity, discount for Western Canadian light and heavy oil and natural gas, and political and economic stability.

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

• Substantial and sustained reductions in commodity prices or equity markets, including Pengrowth’s share price, in some circumstances could result in Pengrowth recording an impairment loss as well as affect Pengrowth’s ability to maintain its dividend (if and when it is reinstated), spend capital, service its debt and meet its other obligations. The impairment test is sensitive to lower realized commodity prices, which have been under significant downward pressure in recent months, particularly oil prices. Further declines in commodity prices could result in additional impairment charges as the cushions in the CGU impairment tests have been eroded by price decreases and operating cost increases.

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 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 and Demand Facility. If an event of non-compliance continued, Pengrowth would have to repay the relevant debt, refinance the debt or negotiate new terms with the debt holders and may be prevented from paying dividends to shareholders.

• Pengrowth received notification from the New York Stock Exchange (“NYSE”) on October 29, 2015 that it was no longer in compliance with one of the NYSE’s listing standards, as the closing price of Pengrowth’s common stock was less than US$1.00 per share over a consecutive 30 day trading-day period. Pengrowth has 6 months from the date of notification to regain compliance with the NYSE’s price listing standard to avoid delisting. Delisting could negatively impact liquidity.

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

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

Risks associated with Legislation and Regulatory Changes

• Government royalties, income taxes, commodity 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, we may be required to incur significant costs to comply with future regulations to reduce greenhouse gas and other emissions.

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

PENGROWTH 2015 Management's Discussion and Analysis 37

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

• EIA or other regulatory approval is required to produce annual average bitumen production in excess of nameplate capacity of 12,500 bbl/d at Lindbergh.

Risks associated with Operations

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

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

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

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

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

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

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

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

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

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

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

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

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

• The 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 heavy oil that would otherwise remain trapped within the reservoir rock. The amount and cost of steam required, the additional oil recovered, the quality of the oil produced, the ability to recycle produced water into steam and the ability to manage costs will determine the economic viability for a thermal project.

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

PENGROWTH 2015 Management's Discussion and Analysis 38

Risks associated with Strategy

• Capital re-investment on our existing assets may not yield the expected benefits and related value creation. Drilling opportunities may prove to be more costly or less productive than anticipated. In addition, the dedication of a larger percentage of our cash flow to such opportunities may reduce the funds available for dividend payments to shareholders. In such an event, the market value of the common shares may also be adversely affected.

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

• Incorrect assessments of value at the time of acquisitions could adversely affect the value of Pengrowth’s common shares.

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

Asset Concentration Risks

• With the sale of over $1.2 billion of assets since 2012, in part to fund the first commercial phase of Lindbergh, Pengrowth's assets have become much less diversified and increasingly concentrated in one project, product type (bitumen) and one area/formation. A failure to execute at Lindbergh 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 may change over time which would affect the availability of capital and the value of Pengrowth common shares.

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

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

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

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

ACCOUNTING PRONOUNCEMENTS ADOPTED

There were no new or amended accounting standards adopted during the twelve months ended December 31, 2015.

ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED

In May 2014, the IASB issued IFRS 15 Revenue from Contracts with Customers ("IFRS 15"). The new standard is effective for annual periods beginning on or after January 1, 2018. Earlier application is permitted. The standard contains a single model that applies to contracts with customers and two approaches to recognising revenue: at a point in time or over time. The model features a contract-based five-step analysis of transactions to determine whether, how much and when revenue is recognized. New estimates and judgmental thresholds have been introduced, which may affect the amount and/or timing of revenue recognized. The new standard applies to contracts with customers. It does not apply to insurance contracts, financial instruments or lease contracts, which fall in the scope of other IFRSs. Pengrowth intends to adopt IFRS 15 in its Consolidated Financial Statements for the annual period beginning on January 1, 2018. Pengrowth does not expect the standard to have a material impact on the financial statements.

PENGROWTH 2015 Management's Discussion and Analysis 39

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

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 assets and liabilities for most leases. The extent of the impact of adoption of the standard has not yet been determined.

DISCLOSURE AND INTERNAL CONTROLS

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

The CEO, Derek Evans, and the CFO, Christopher Webster, evaluated the effectiveness of Pengrowth’s disclosure controls and procedures for the year ending December 31, 2015. 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, 2015, 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

PENGROWTH 2015 Management's Discussion and Analysis 40

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, 2015. 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).

Based on Pengrowth's evaluation, management concluded that Pengrowth's internal control over financial reporting was effective as of December 31, 2015.

The effectiveness of internal control over financial reporting as of December 31, 2015 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, 2015. No changes were made to Pengrowth's internal control over financial reporting during the year ending December 31, 2015 that have materially affected, or are reasonably likely to materially affect, the internal controls over financial reporting.

PENGROWTH 2015 Management's Discussion and Analysis 41