Pengrowth Energy (PGH) 6-K Summary of Financial & Operating Results

MANAGEMENT’S DISCUSSION & ANALYSIS

The following Management’s Discussion and Analysis ("MD&A") of financial results should be read in conjunction with the unaudited Consolidated Financial Statements for the three and nine months ended September 30, 2015 of Pengrowth Energy Corporation ("Pengrowth" or the "Corporation"). This MD&A is based on information available to November 3, 2015.

Pengrowth’s third quarter and year to date 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.

PENGROWTH Third Quarter 2015 Management's Discussion and Analysis 1

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

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

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

CRITICAL ACCOUNTING ESTIMATES

The unaudited Consolidated Financial Statements are prepared in accordance with IFRS. The preparation of unaudited 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 unaudited Consolidated Financial Statements and revenues and expenses during the reporting period. Actual results could differ from those estimated.

Pengrowth’s ARO risk free discount rate changed from 2.3 percent at December 31, 2014 to 2.0 percent at March 31, 2015 and back to 2.3 percent at June 30, 2015. The changes were due to fluctuations in the 30 year Canadian Government long term bond rate which drives Pengrowth’s estimate of the ARO discount rate. The ARO rate remained at 2.3 percent at September 30, 2015. There were no significant changes to Pengrowth's critical accounting estimates in the nine months ended September 30, 2015. For more information about Pengrowth's critical accounting estimates refer to the December 31, 2014 annual report.

For a description of Pengrowth's accounting policies regarding impairments, see Note 2 to the December 31, 2014 audited Consolidated Financial Statements and Note 2 to the September 30, 2015 unaudited Consolidated Financial Statements.

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

PENGROWTH Third Quarter 2015 Management's Discussion and Analysis 2

of changes in working capital and remediation expenditures. Pengrowth considers this to be a key measure of performance as it demonstrates its ability to generate cash flow necessary to fund dividends and capital investments.

NON-GAAP FINANCIAL MEASURES

This MD&A refers to certain financial measures that are not determined in accordance with IFRS. These measures do not have standardized meanings and may not be comparable to similar measures presented by other oil and gas companies.

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. 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; and senior debt before working capital as a percentage of total book capitalization. Total book capitalization is the sum of total 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, power and interest 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.

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.

OPERATIONAL MEASURES

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

When converting natural gas to equivalent barrels of oil within this MD&A, Pengrowth uses the industry standard of six Mcf to one boe. Barrels of oil equivalent may be misleading, particularly if used in isolation; a conversion ratio of six Mcf of natural gas to one boe is based on an energy equivalency conversion and does not represent a value equivalency at the wellhead.

CURRENCY

All amounts are stated in Canadian dollars unless otherwise specified.

PENGROWTH Third Quarter 2015 Management's Discussion and Analysis 3

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. Upon declaration of commerciality effective April 1, 2015, all Lindbergh related revenues and expenses are included in the third quarter and year to date 2015 financial and operating results. The combined results are referred to as Lindbergh throughout this document.

2015 GUIDANCE

The following table provides a summary of full year 2015 Guidance and actual results for the nine months ended September 30, 2015:

	Actual
	Year to date Sept 30, 2015	Full year 2015 Guidance (1)
Production (boe/d)	72,580	70,000 - 72,000
Capital expenditures ($ millions)	164.7	190 - 210 (2)
Royalty expenses (% of sales)	10.6	11 - 14
Operating expenses ($/boe)	14.67	15.50 - 16.50
Cash G&A expenses ($/boe)	3.59	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.

Year to date 2015 production of 72,580 boe/d slightly exceeded full year 2015 Guidance, and is anticipated to be within Guidance for the full year 2015.

Year to date 2015 capital expenditures amounted to $164.7 million, representing approximately 82 percent of Pengrowth's 2015 Guidance. Capital expenditures for the full year are anticipated to remain within 2015 Guidance.

Year to date 2015 royalty expenses as a percentage of sales and operating expenses per boe were below full year 2015 Guidance, and are anticipated to be at the lower end of Guidance for the full year 2015. Cash G&A expenses per boe were in line with full year 2015 Guidance and are anticipated to remain as such for the full year 2015.

RESPONSE TO LOW COMMODITY PRICE ENVIRONMENT

Since the rapid and significant decline in commodity prices commenced in late 2014, Pengrowth has taken extensive and prudent measures throughout 2015 to ensure the Corporation's financial health and sustainability in the current low commodity price environment. These measures are:

• A significantly reduced capital program for 2015 to $200 million, representing a 78 percent reduction from actual 2014 capital spending. The reduction has had a minimal impact on 2015 production as production gains from Lindbergh have offset production declines from conventional properties.

• A revised dividend policy of $0.01 per quarter that aims to allow Pengrowth to live within cash flows while accelerating debt repayment.

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

• Enhanced focus on management of all aspects of capital, operating and G&A cost structures. Capital cost reductions on most services have been 20 to 25 percent, while head office staff have been reduced by 30 percent this year across all levels of the organization.

• Active foreign exchange risk management which reduces the exposure of Pengrowth's foreign denominated debt to foreign exchange rate fluctuations.

• Monetization of U.S. swap contracts in March 2015, resulting in a Cdn$84.1 million realized foreign exchange gain.

• Pengrowth continued to look for opportunities to layer in additional commodity risk management contracts in 2017 and 2018.

PENGROWTH Third Quarter 2015 Management's Discussion and Analysis 4

FINANCIAL HIGHLIGHTS

	Three months ended					Nine months ended
($ millions except per boe amounts)	Sept 30, 2015		Jun 30, 2015		Sept 30, 2014	Sept 30, 2015		Sept 30, 2014
Production (boe/d)	74,239		74,113		72,472	72,580		73,789
Capital expenditures	15.5		50.8		191.9	164.7		645.2
Funds flow from operations (1)	120.6		111.5		129.0	345.1		389.9
Operating netback ($/boe)(2)	25.48		23.98		24.91	24.93		26.17
Adjusted net income (loss) (3)	(374.0	)	(38.9	)	3.4	(348.1	)	(24.2	)
Net income (loss)	(329.6	)	(134.4	)	52.2	(624.5	)	(72.8	)

⁽¹⁾  Funds flow from operations for the nine months ended September 30, 2015 excludes $93.9 million of gains related to the 2015 settlement of foreign exchange swap contracts.

⁽²⁾  Including realized commodity risk management.

⁽³⁾  Includes third quarter of 2015 non-cash impairment charges of approximately $375 million after-tax.

Funds Flow from Operations

($ millions)	Q2/15 vs. Q3/15			% Change		Q3/14 vs. Q3/15			% Change		YTD 2014 vs. 2015			% Change
Funds flow from operations for comparative period	Q2/15	111.5				Q3/14	129.0				YTD 2014	389.9
Increase (decrease) due to:
Volumes		8.8		8			25.7		20			(15.6	)	(4	)
Prices including differentials		(45.5	)	(41	)		(180.6	)	(140	)		(526.1	)	(135	)
Realized commodity risk management		25.4		23			113.1		88			347.1		89
Other income including sulphur		(1.3	)	(1	)		(2.3	)	(2	)		(2.0	)	(1	)
Royalties		7.4		7			46.4		36			147.0		39
Expenses:
Operating		15.8		14			11.4		9			30.2		8
Cash G&A		(2.1	)	(2	)		(3.6	)	(3	)		(8.1	)	(2	)
Interest & financing		(0.7	)	(1	)		(11.3	)	(9	)		(19.1	)	(5	)
Other expenses including transportation		1.3		1			(7.2	)	(6	)		1.8		—
Net change		9.1		8			(8.4	)	(7	)		(44.8	)	(11	)
Funds flow from operations (1)	Q3/15	120.6				Q3/15	120.6				YTD 2015	345.1

⁽¹⁾  Funds flow from operations for the nine months ended September 30, 2015 excludes $93.9 million of gains related to the 2015 settlement of foreign exchange swap contracts.

Pengrowth's third quarter of 2015 funds flow from operations increased 8 percent compared to the second quarter of 2015. This was driven by higher realized commodity risk management gains and heavy oil sales volumes combined with lower operating expenses and royalties which, together, more than offset the impact of lower commodity prices in the third quarter of 2015.

Third quarter of 2015 funds flow from operations decreased 7 percent compared to the same period last year mainly due to significantly lower commodity prices which were largely offset by realized commodity risk management gains and lower royalties.

Pengrowth's year to date 2015 funds flow from operations decreased 11 percent compared to the same period in 2014 as the impacts of significantly lower commodity prices and lower volumes were mostly offset by realized commodity risk management gains, along with lower royalties and operating expenses.

Net Income (Loss)

Pengrowth recorded a larger net loss of $329.6 million in the third quarter of 2015 compared to a net loss of $134.4 million in the second quarter of 2015 primarily due to non-cash impairment charges of $482.0 million (approximately $375 million after-tax), recorded in the third quarter of 2015, partially offset by an increase in fair value of commodity risk management contracts.

PENGROWTH Third Quarter 2015 Management's Discussion and Analysis 5

Pengrowth recorded a net loss of $329.6 million in the third quarter of 2015 compared to net income of $52.2 million in the third quarter of 2014 primarily due to the non-cash impairment charges recorded in the third quarter of 2015.

The year to date 2015 net loss was $551.7 million higher compared to 2014 also due to the non-cash impairment charges recorded in the third quarter of 2015, higher unrealized foreign exchange losses, driven by the impact of the weakening Canadian dollar on U.S. denominated debt, and a decrease in fair value of commodity risk management contracts. This was partially offset by the settlement of the U.S./Canadian dollar swap contracts in 2015 resulting in $93.9 million ($81.9 million after-tax) of realized foreign exchange gains.

Adjusted Net Income (Loss)

Pengrowth reports adjusted net income (loss) to remove the effect of unrealized gains and losses. The following table provides a reconciliation of net income (loss) to adjusted net income (loss):

	Three months ended						Nine months ended
($ millions)	Sept 30, 2015		Jun 30, 2015		Sept 30, 2014		Sept 30, 2015		Sept 30, 2014
Net income (loss)	(329.6	)	(134.4	)	52.2		(624.5	)	(72.8	)
Excluded non-cash items in net income (loss):
Change in fair value of commodity, power and interest risk management contracts	120.9		(137.2	)	121.1		(84.9	)	(1.7	)
Unrealized foreign exchange gain (loss) (1)	(41.3	)	5.1		(42.7	)	(210.2	)	(49.2	)
Unrealized loss on investments	—		—		(5.0	)	—		(5.0	)
Tax effect on non-cash items above	(35.2	)	36.6		(24.6	)	18.7		7.3
Total excluded	44.4		(95.5	)	48.8		(276.4	)	(48.6	)
Adjusted net income (loss)	(374.0	)	(38.9	)	3.4		(348.1	)	(24.2	)

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

The following table represents a continuity of adjusted net income (loss):
($ millions)	Q2/15 vs. Q3/15			Q3/14 vs. Q3/15			YTD 2014 vs. 2015
Adjusted net income (loss) for comparative period	Q2/15	(38.9	)	Q3/14	3.4		YTD 2014	(24.2	)
Funds flow from operations increase (decrease)		9.1			(8.4	)		(44.8	)
DD&A and accretion expense (increase) decrease		(4.2	)		7.8			40.1
Impairment charges increase (1)		(482.0	)		(482.0	)		(482.0	)
Realized foreign exchange gain on settled U.S. dollar swaps increase (decrease)		(9.8	)		—			93.9
Loss on property dispositions (increase) decrease		27.1			(19.6	)		(28.3	)
Other		5.3			3.1			0.3
Estimated tax on above including tax rate change		119.4			121.7			96.9
Net change		(335.1	)		(377.4	)		(323.9	)
Adjusted net income (loss)	Q3/15	(374.0	)	Q3/15	(374.0	)	YTD 2015	(348.1	)

⁽¹⁾  See Note 2 to the September 30, 2015 unaudited Consolidated Financial Statements for additional information.

Pengrowth posted an adjusted net loss of $374.0 million in the third quarter of 2015 compared to an adjusted net loss of $38.9 million in the second quarter of 2015 and adjusted net income of $3.4 million in the third quarter of 2014, primarily driven by the non-cash impairment charges recorded in the third quarter of 2015.

Pengrowth's year to date 2015 adjusted net loss of $348.1 million compared to the adjusted net loss of $24.2 million in the same period last year was also driven by the non-cash impairment charges recorded in the third quarter of 2015, partially offset by the realized foreign exchange gain from settling a series of U.S. dollar swap contracts in 2015.

PENGROWTH Third Quarter 2015 Management's Discussion and Analysis 6

Price Sensitivity

The following table illustrates the sensitivity of funds flow from operations to changes in commodity prices after taking into account Pengrowth’s risk management contracts and outlook on oil differentials. See Note 12 to the September 30, 2015 unaudited 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	$	49.80	$	1.00
Light oil						6.4
Heavy oil						9.1
Oil risk management (4)						(14.4	)
NGLs						3.3
Net impact of U.S.$1/bbl increase in WTI						4.4
Oil differentials
Light oil	U.S.$/bbl	$	5.72	$	1.00	(6.4	)
Heavy oil	U.S.$/bbl	$	17.53	$	1.00	(9.1	)
Oil differentials risk management (4)						1.6
Net impact of U.S.$1/bbl increase in differentials						(13.9	)
AECO Natural Gas (2) (3)	Cdn$/Mcf	$	2.95	$	0.10
Natural gas						5.5
Natural gas risk management (4)						(4.6	)
Net impact of Cdn$0.10/Mcf increase in AECO						0.9

⁽¹⁾  Calculations are performed independently and are not indicative of actual results when multiple variables change at the same time. An exchange rate of $1Cdn = $0.76 U.S. was used.

⁽²⁾  Commodity price is based on an estimation of the 12 month forward price curve at September 17, 2015 and does not include the impact of risk management contracts.

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

⁽⁴⁾  Includes risk management contracts as at September 30, 2015.

PENGROWTH Third Quarter 2015 Management's Discussion and Analysis 7

RESULTS OF OPERATIONS

All volumes, wells and spending amounts stated below reflect Pengrowth’s net working interest for both operated and non-operated properties unless otherwise stated. These amounts include production, revenue, costs and royalties associated with Lindbergh Phase 1 since April 1, 2015.

CAPITAL EXPENDITURES

	Three months ended			Nine months ended
($ millions)	Sept 30, 2015	Jun 30, 2015	Sept 30, 2014	Sept 30, 2015	Sept 30, 2014
Drilling, completions and facilities
Lindbergh (1)	3.3	28.4	110.5	80.8	361.9
Conventional	0.3	3.7	61.5	41.9	221.6
Total drilling, completions and facilities	3.6	32.1	172.0	122.7	583.5
Land & seismic acquisitions (2)	0.1	0.3	0.3	0.6	5.4
Maintenance capital	11.6	17.2	19.1	39.2	55.0
Development capital	15.3	49.6	191.4	162.5	643.9
Other capital	0.2	1.2	0.5	2.2	1.3
Capital expenditures	15.5	50.8	191.9	164.7	645.2

⁽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 coupled with a more economic cost structure is present, limiting third quarter of 2015 capital expenditures to $15.5 million. Approximately 23 percent of the third quarter of 2015 capital was spent at Lindbergh, 74 percent was spent on turnaround, maintenance and enhancement activities at Pengrowth's conventional properties and the remainder was spent on minor partner operated development and other capital.

Year to date 2015 capital spending amounted to $164.7 million, of which approximately 50 percent was invested at Lindbergh and 25 percent on drilling, completions and facilities at Pengrowth's conventional properties with the remaining 25 percent invested in maintenance at Pengrowth's conventional properties, land, seismic and other capital.

Focus Areas

Lindbergh

Pengrowth’s 100 percent owned and operated Lindbergh thermal project is located in the Cold Lake area of Alberta and encompasses 42.5 sections of land. Cost advantages of the Lindbergh resource include enhanced bitumen quality and flow characteristics resulting in an efficient steam oil ratio which translates into a lower operating cost structure and higher netbacks compared to many thermal projects. 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.

Production at Lindbergh continued to ramp up with the third quarter of 2015 production averaging 14,564 bbl/d with an Instantaneous Steam Oil Ratio ("ISOR") of 2.1 compared to the second quarter of 2015 average production of 10,930 bbl/d at an ISOR of 2.5. These volumes include production from the former two well pair pilot project. The nameplate capacity of the first commercial phase of Lindbergh is 12,500 bbl/d.

Despite the current low commodity price environment, Lindbergh generated a strong netback in the third quarter of 2015. The netback below excludes realized commodity risk management gains. Lindbergh operating expenses are expected to be higher in the fourth quarter of 2015 due to a scheduled turnaround as required to meet Alberta Pressure Equipment Safety Regulations for the facilities.

PENGROWTH Third Quarter 2015 Management's Discussion and Analysis 8

	Three months ended
Lindbergh Heavy Oil Netback ($/boe)	Sept 30, 2015		Jun 30, 2015
Sales	35.23		49.12
Royalties	(0.92	)	(1.03	)
Operating expenses	(9.66	)	(12.66	)
Transportation expenses	(2.96	)	(4.26	)
Lindbergh heavy oil operating netback	21.69		31.17

Pengrowth has entered into a transportation agreement with Husky 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 was in full operation for the entire third quarter of 2015 allowing Pengrowth to replace Lindbergh trucking costs with lower pipeline tolls.

Lindbergh provides Pengrowth with the potential to ultimately develop 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.

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 500 gross (250 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 significant liquid yields in north eastern British Columbia.

Conventional development was curtailed in 2015, with the third quarter of 2015 capital spending of $11.7 million focused on maintenance and enhancement of existing facilities and minor partner operated development.

PRODUCTION

	Three months ended						Nine months ended
Daily production	Sept 30, 2015	% of total	Jun 30, 2015	% of total	Sept 30, 2014	% of total	Sept 30, 2015	% of total	Sept 30, 2014	% of total
Light oil (bbls)	15,680	21	16,766	23	21,359	30	17,063	24	21,857	30
Heavy oil (bbls)	20,489	28	16,804	23	8,246	11	15,182	21	8,235	11
Natural gas liquids (bbls)	8,331	11	8,978	12	9,403	13	8,759	12	10,382	14
Natural gas (Mcf)	178,428	40	189,384	42	200,786	46	189,461	43	199,890	45
Total boe per day	74,239		74,113		72,472		72,580		73,789

Third quarter of 2015 average daily production remained unchanged compared to the second quarter of 2015 as increased Lindbergh Phase 1 production more than offset the impact of third party turnaround, maintenance activities, natural declines and 2015 property dispositions.

Third quarter of 2015 average daily production increased 2 percent compared to the same period last year as the inclusion of Lindbergh Phase 1 production and additions from the 2014 Groundbirch development program more than offset the impact of 2014 and 2015 property dispositions, production declines related to 2015 capital development curtailments and approximately 1,100 boe/d of shut-in uneconomic natural gas production.

Year to date 2015 average daily production decreased 2 percent compared to the same period last year also due to the impact of 2014 and 2015 property dispositions, production declines related to 2015 capital development curtailments and shut-in of uneconomic natural gas production. These decreases were mostly offset by the Lindbergh Phase 1 production and additions from the 2014 Groundbirch development program.

PENGROWTH Third Quarter 2015 Management's Discussion and Analysis 9

Light Oil

Third quarter of 2015 light oil production decreased 6 percent compared to the second quarter of 2015 mainly due to third party turnaround activity, natural declines and minor well downtime in the Lochend/Garrington area.

Third quarter and year to date 2015 light oil production decreased 27 percent and 22 percent compared to the same periods last year, respectively. These decreases were due to reduced 2015 capital development, particularly affecting Lochend/Garrington production, combined with Judy Creek well downtime and facility restrictions in early 2015. Also contributing to the decrease was the impact of 2014 dispositions.

Heavy Oil

Third quarter of 2015 heavy oil production increased 22 percent compared to the second quarter of 2015 resulting from the continued ramp up of the Lindbergh Phase 1 production. The third quarter of 2015 Lindbergh production averaged 14,564 bbl/d at an ISOR of 2.1. These volumes include production from the former two well pair pilot project.

Third quarter and year to date 2015 heavy oil production increased 148 percent and 84 percent compared to the same periods in 2014, respectively, due to inclusion of the Lindbergh Phase 1 production partially offset by reduced production from Jenner due to reduced development activity in 2015.

NGLs

Third quarter of 2015 NGL production decreased 7 percent compared to the second quarter of 2015 due to the absence of a Sable Offshore Energy Project ("SOEP") condensate shipment which occurred in the second quarter of 2015.

Third quarter and year to date 2015 NGL production decreased 11 percent and 16 percent compared to the same periods last year, respectively, mainly due to reduced 2015 capital development at Lochend/Garrington area combined with well downtime at Judy Creek in early 2015.

Natural Gas

Third quarter of 2015 natural gas production decreased 6 percent compared to the second quarter of 2015 primarily as a result of 2015 dispositions in addition to a maintenance related outage at SOEP. Reduced capital spending in 2015 also contributed to the natural gas production decrease.

Third quarter and year to date 2015 natural gas production decreased 11 percent and 5 percent compared to the same periods last year, respectively. This was primarily due to the 2015 dispositions and reduced 2015 capital development. Also contributing to the declines were third party turnaround activities and shut-in of uneconomic natural gas production partially offset by additions from the 2014 Groundbirch development program.

COMMODITY PRICES

Oil and Liquids Prices Excluding Realized Commodity Risk Management

	Three months ended						Nine months ended
(Cdn$/bbl)	Sept 30, 2015		Jun 30, 2015		Sept 30, 2014		Sept 30, 2015		Sept 30, 2014
Average Benchmark Prices
WTI oil	61.42		71.24		105.83		64.09		108.97
Edmonton par light oil	56.89		67.73		97.20		58.64		100.80
WCS heavy oil	43.86		57.00		83.84		47.47		85.82
Average Differentials to WTI
Edmonton par	(4.53	)	(3.51	)	(8.63	)	(5.45	)	(8.17	)
WCS heavy oil	(17.56	)	(14.24	)	(21.99	)	(16.62	)	(23.15	)
Average Sales Prices
Light oil	54.76		63.05		94.04		55.47		97.82
Heavy oil	35.60		50.42		78.43		41.38		79.84
Natural gas liquids	18.79		31.33		52.94		25.05		56.03

Third quarter of 2015 WTI crude oil price averaged Cdn$61.42/bbl, a decrease of 14 percent and 42 percent compared to the second quarter of 2015 and third quarter of 2014, respectively. Year to date 2015 WTI crude oil price averaged Cdn$64.09/bbl, a decrease of 41 percent compared to the same period in 2014. The weakness in global crude oil prices resulting from an oversupply of global crude oil, which continues to persist, is putting further pressure on current

PENGROWTH Third Quarter 2015 Management's Discussion and Analysis 10

and forward crude oil prices. Partially mitigating the decrease in crude oil prices was the decline in the value of the Canadian dollar relative to the U.S. dollar. As Pengrowth reports its revenues in Canadian dollars, the weaker Canadian dollar partially offset the declines in the U.S. dollar based WTI price.

Edmonton par light oil price averaged Cdn$56.89/bbl in the third quarter of 2015, representing a decrease of 16 percent and 41 percent compared to the second quarter of 2015 and third quarter of 2014, respectively. Year to date 2015 Edmonton par light oil price averaged Cdn$58.64/bbl, a decrease of 42 percent compared to the same period in 2014. Lower WTI prices were the main driver behind the decrease quarter over quarter and year over year, slightly offset by the narrowing of the light oil differential in 2015 relative to 2014.

WCS heavy oil price averaged Cdn$43.86/bbl in the third quarter of 2015, a decrease of 23 percent and 48 percent compared to the second quarter of 2015 and third quarter of 2014, respectively. Year to date 2015 WCS heavy oil price averaged Cdn$47.47/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 third quarter of 2015 were the primary drivers behind lower WCS heavy oil price compared to the second quarter of 2015. Lower WTI prices partially offset by a narrowing of the heavy oil differential in 2015 resulted in the lower third quarter and year to date 2015 WCS heavy oil price compared to the same periods last year.

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 takes proactive steps to improve realizations, including delivering crude oil to rail terminals.

Pengrowth's third quarter and year to date 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.

Sales of natural gas liquids (NGLs) primarily comprise propane, butane, pentane and condensate. All NGLs experienced significant price reductions in the quarter due to over-supply, with propane's realization actually negative. 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 was Cdn$18.79/bbl during the third quarter of 2015, a decrease of 40 percent and 65 percent compared to the second quarter of 2015 and third quarter of 2014, respectively. Year to date 2015 realized NGL price of Cdn$25.05/bbl declined 55 percent compared to the same period in 2014.

Natural Gas Prices Excluding Realized Commodity Risk Management

	Three months ended						Nine months ended
(Cdn$)	Sept 30, 2015		Jun 30, 2015		Sept 30, 2014		Sept 30, 2015		Sept 30, 2014
Average Benchmark Prices
NYMEX gas (per MMBtu)	3.62		3.37		4.30		3.48		4.83
AECO monthly gas (per MMBtu)	2.83		2.67		4.22		2.81		4.55
Average Differential to NYMEX
AECO differential (per MMBtu)	(0.79	)	(0.70	)	(0.08	)	(0.67	)	(0.28	)
Average Sales Prices
Natural gas (per Mcf) (1)	3.02		2.77		4.05		3.15		4.99

⁽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$3.62/MMBtu in the third quarter of 2015, an increase of 7 percent compared to the second quarter of 2015 and a decrease of 16 percent compared to the third quarter of 2014. Year to date 2015 NYMEX natural gas price averaged Cdn$3.48/MMBtu, a decrease of 28 percent compared to the same period in 2014. The increase in the third quarter of 2015 NYMEX price compared to the second quarter of 2015 resulted from increased demand during the summer months due to higher than normal temperatures across much of North America. The decrease in the third quarter and year to date 2015 NYMEX prices compared to the same periods in 2014 resulted from weaker demand across North America coupled with continued growth in natural gas supplies.

PENGROWTH Third Quarter 2015 Management's Discussion and Analysis 11

Third quarter of 2015 AECO monthly gas price averaged Cdn$2.83/MMBtu, representing an increase of 6 percent compared to the second quarter of 2015, but a decline of 33 percent compared to the third quarter of 2014. Year to date 2015 AECO monthly gas price averaged Cdn$2.81/MMBtu, a decrease of 38 percent compared to the same period in 2014. The steep decline in the AECO monthly prices compared to the same periods in 2014 resulted from a decline of the NYMEX benchmark coupled with a widening of the differential between NYMEX and AECO.

Pengrowth's third quarter and year to date 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.

Total Average Sales Prices

	Three months ended				Nine months ended
($/boe)	Sept 30, 2015	Jun 30, 2015	Sept 30, 2014		Sept 30, 2015	Sept 30, 2014
Average sales prices	30.75	36.58	54.73		32.94	59.29
Other production income including sulphur	0.27	0.47	0.63		0.46	0.55
Total oil and gas sales price	31.02	37.05	55.36		33.40	59.84
Realized commodity risk management gain (loss)	12.38	8.77	(4.29	)	11.57	(5.85	)
Total oil and gas sales price including realized commodity risk management	43.40	45.82	51.07		44.97	53.99

Pengrowth’s third quarter of 2015 average realized sales price, before the effects of commodity risk management activities, was Cdn$30.75/boe and represented a decrease of 16 percent and 44 percent compared to the second quarter of 2015 and third quarter of 2014, respectively. Year to date 2015 average realized sales price of Cdn$32.94/boe declined 44 percent compared to the same period in 2014. The third quarter of 2015 decrease in average sales price relative to the second quarter of 2015 was the result of lower crude oil benchmark prices partially offset by higher natural gas benchmark prices. Third quarter and year to date 2015 decrease in average sales prices relative to the same periods last year was due to declines in both crude oil and natural gas benchmark prices.

After taking into account the impacts of commodity risk management activities and other income, Pengrowth’s third quarter of 2015 average realized price was Cdn$43.40/boe, a decline of 5 percent and 15 percent compared to the second quarter of 2015 and third quarter of 2014, respectively. Year to date 2015, Pengrowth’s average realized price was Cdn$44.97/boe, a decrease of 17 percent compared to the same period in 2014. The decline in realized prices year over year was due to the decrease in benchmark prices mentioned above, offset by the strength of Pengrowth's active risk management program.

Realized Commodity Risk Management Gains (Losses)

	Three months ended				Nine months ended
($ millions except per unit amounts)	Sept 30, 2015	Jun 30, 2015	Sept 30, 2014		Sept 30, 2015	Sept 30, 2014
Oil risk management	76.7	50.1	(23.9	)	206.2	(90.8	)
$/bbl (1)	23.05	16.40	(8.77	)	23.42	(11.05	)
Natural gas risk management	7.8	9.0	(4.7	)	23.1	(27.0	)
$/Mcf	0.48	0.52	(0.25	)	0.45	(0.49	)
Total realized gain (loss)	84.5	59.1	(28.6	)	229.3	(117.8	)
$/boe	12.38	8.77	(4.29	)	11.57	(5.85	)

⁽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 oil price differentials using a combination of financial swaps and physical contracts.

Realized commodity risk management gains and losses vary from period to period and are a function of the volumes under risk management contracts, the fixed prices of those risk management contracts and the benchmarkpricing for

PENGROWTH Third Quarter 2015 Management's Discussion and Analysis 12

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 $84.5 million or $12.38/boe was recorded in the third quarter of 2015 compared to a $59.1 million or $8.77/boe gain in the second quarter of 2015 as the third quarter of 2015 decrease in the oil benchmark price translated into higher realized commodity risk management gains.

Third quarter and year to date 2015 realized commodity risk management gains of $84.5 million or $12.38/boe and $229.3 million or $11.57/boe, respectively, compared to losses in the same periods last year, as per the table above, resulted primarily from a decline in the oil benchmark prices starting in the second half of 2014.

Changes in Fair Value of Commodity Risk Management Contracts

	Three months ended					Nine months ended
($ millions)	Sept 30, 2015	Jun 30, 2015		Sept 30, 2014		Sept 30, 2015		Sept 30, 2014
Fair value of commodity risk management assets (liabilities) at period end	335.2	214.7		(84.2	)	335.2		(84.2	)
Less: Fair value of commodity risk management assets (liabilities) at beginning of period	214.7	354.3		(205.8	)	421.1		(80.0	)
Increase (decrease) in fair value of commodity risk management contracts for the period	120.5	(139.6	)	121.6		(85.9	)	(4.2	)

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 $120.5 million in the third quarter of 2015 as fair value of commodity risk management assets increased at September 30, 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 $84.5 million in the third quarter of 2015.

Pengrowth recorded an $85.9 million decrease in fair value of commodity risk management contracts for the nine months ended September 30, 2015 as fair value of commodity risk management assets decreased at September 30, 2015 relative to the beginning of the period. This was a result of the settlements of contracts, or realized commodity risk management gains, of $229.3 million in 2015 partially offset by the downward movement in the forward curve pricing.

PENGROWTH Third Quarter 2015 Management's Discussion and Analysis 13

Forward Contracts - Commodity and Power Risk Management

Pengrowth uses crude oil and natural gas swaps and puts to manage commodity price fluctuations. In addition, financial and physical contracts are used to manage oil price differentials. These contracts as well as the power risk management contracts in place at September 30, 2015 are summarized in the following table:

Crude Oil Swaps and Puts
Reference point	Remaining Term	Volume (bbl/d)	% of total 2015 oil production Guidance (1)	Price/bbl ($Cdn) (2)
WTI	Oct 1, 2015 - Dec 31, 2015	26,000	78%	93.68
WTI	2016	21,485	64%	89.21
WTI	2017	4,000	12%	79.07
WTI	2018	5,500	16%	80.49
Crude Oil Differentials
Financial Swap Contracts
Reference point	Remaining Term	Volume (bbl/d)	% of total 2015 oil production Guidance (1)	Price/bbl ($Cdn)
Western Canada Select	Oct 1, 2015 - Dec 31, 2015	13,000	39%	Cdn WTI less $18.61
Edmonton Light Sweet	Oct 1, 2015 - Dec 31, 2015	6,000	18%	Cdn WTI less $7.63
Edmonton Light Sweet	2016	7,000	21%	Cdn WTI less $7.02
Western Canada Select	2016	8,000	24%	Cdn WTI less $18.32
Physical Delivery Contracts
Reference point	Remaining Term	Volume (bbl/d)	% of total 2015 oil production Guidance (1)	Price/bbl ($Cdn)
Edmonton Light Sweet	Oct 1, 2015 - Dec 31, 2015	5,119	15%	Cdn WTI less $7.78
Natural Gas Swaps and Puts
Reference point	Remaining Term	Volume (MMBtu/d)	% of 2015 natural gas production Guidance	Price/MMBtu ($Cdn)
AECO & NGI Chicago Index	Oct 1, 2015 - Dec 31, 2015	105,597	59%	3.69
AECO	2016	117,280	65%	3.32
AECO	2017	85,855	48%	3.50
AECO	2018	66,347	37%	3.59
AECO	2019	2,370	1%	3.52
Power
Reference point	Remaining Term	Volume (MW)	% of estimated power purchases	Price/MWh ($Cdn)
AESO	Oct 1, 2015 - Dec 31, 2015	40	79%	49.53
AESO	2016	20	31%	44.13

⁽¹⁾  Includes light and heavy crude oil.

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

See the Financial Crude Oil Contracts and Physical Delivery Contracts sections in Note 12 to the September 30, 2015 unaudited Consolidated Financial Statements for more information.

PENGROWTH Third Quarter 2015 Management's Discussion and Analysis 14

Commodity and Power Price Sensitivity on Risk Management Contracts as at September 30, 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		($13.9	)		$13.9
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		($7.2	)		$7.2
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		($27.0	)		$27.0

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 September 30, 2015, revenue and cash flow would have been $335.2 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 $335.2 million is composed of net assets of $248.3 million relating to risk management contracts expiring within one year and net assets of $86.9 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 65 percent for a period of 1 to 24 months.

As at September 30, 2015 Pengrowth may sell forward its production and purchase risk management contracts by product volume or power purchases as follows:

Forward Period	Percent of Estimated Production	Forward Period	Percent of Estimated Power Purchases
1 - 39 Months	Up to 90%	1 - 24 Months	Up to 80%
40 - 48 Months	Up to 50%	25 - 36 Months	Up to 50%
49 - 60 Months	Up to 25%	37 - 60 Months	Up to 25%

PENGROWTH Third Quarter 2015 Management's Discussion and Analysis 15

OIL AND GAS SALES EXCLUDING REALIZED COMMODITY RISK MANAGEMENT

Contribution Analysis

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

	Three months ended						Nine months ended
($ millions except percentages)	Sept 30, 2015	% of total	Jun 30, 2015	% of total	Sept 30, 2014	% of total	Sept 30, 2015	% of total	Sept 30, 2014	% of total
Light oil	79.0	37	96.2	39	184.8	50	258.4	39	583.7	48
Heavy oil	67.1	32	77.1	31	59.5	16	171.5	26	179.5	15
Natural gas liquids	14.4	7	25.6	10	45.8	13	59.9	9	158.8	13
Natural gas	49.5	23	47.8	19	74.8	20	162.8	25	272.3	23
Other income including sulphur	1.9	1	3.2	1	4.2	1	9.1	1	11.1	1
Total oil and gas sales (1)	211.9		249.9		369.1		661.7		1,205.4

⁽¹⁾  Excluding realized commodity risk management.

Price and Volume Analysis

Quarter ended September 30, 2015 versus Quarter ended June 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 June 30, 2015 (1)	96.2		77.1		25.6		47.8		3.2		249.9
Effect of change in product prices and differentials	(12.0	)	(27.9	)	(9.6	)	4.0		—		(45.5	)
Effect of change in sales volumes	(5.2	)	17.9		(1.6	)	(2.3	)	—		8.8
Other	—		—		—		—		(1.3	)	(1.3	)
Quarter ended September 30, 2015 (1)	79.0		67.1		14.4		49.5		1.9		211.9

⁽¹⁾  Excluding realized commodity risk management.

⁽²⁾  Primarily sulphur sales.

Light oil sales decreased 18 percent in the third quarter of 2015 compared to the second quarter of 2015 primarily due to a 16 percent decrease in the Edmonton par light oil benchmark price. Lower light oil volumes also contributed to the decrease in light oil sales. Third quarter of 2015 heavy oil sales decreased 13 percent due to a 23 percent decline in WCS heavy oil benchmark price which was largely offset by the additional Lindbergh Phase 1 sales volumes. NGL sales decreased 44 percent mainly due to the impact of lower commodity prices. Natural gas sales increased 4 percent due to a higher realized natural gas price partially offset by lower sales volumes compared to the second quarter of 2015.

Quarter ended September 30, 2015versus Quarter endedSeptember 30, 2014

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

($ millions)	Light oil		Heavy oil		NGLs		Natural gas		Other (2)		Total
Quarter ended September 30, 2014 (1)	184.8		59.5		45.8		74.8		4.2		369.1
Effect of change in product prices and differentials	(56.7	)	(80.7	)	(26.2	)	(17.0	)	—		(180.6	)
Effect of change in sales volumes	(49.1	)	88.3		(5.2	)	(8.3	)	—		25.7
Other	—		—		—		—		(2.3	)	(2.3	)
Quarter ended September 30, 2015 (1)	79.0		67.1		14.4		49.5		1.9		211.9

⁽¹⁾  Excluding realized commodity risk management.

⁽²⁾  Primarily sulphur sales.

Light oil sales decreased 57 percent in the third quarter of 2015 compared to the same period in 2014 due to a 41 percent decrease in the Edmonton par light oil benchmark price combined with lower light oil sales volumes. Third quarter of 2015 heavy oil sales increased 13 percent compared to the same period last year resulting from inclusion of the Lindbergh Phase 1 sales volumes partially offset by the impact of a 48 percent decrease in the WCS heavy oil benchmark price. NGL sales decreased 69 percent also driven by the impact of lower commodity prices and lower volumes. Natural gas sales decreased 34 percent primarily due to significantly lower natural gas benchmark prices relative to the third quarter of 2014.

PENGROWTH Third Quarter 2015 Management's Discussion and Analysis 16

Nine Months ended September 30, 2015 versus Nine Months ended September 30, 2014

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

($ millions)	Light oil		Heavy oil		NGLs		Natural gas		Other (2)		Total
Nine months ended September 30, 2014 (1)	583.7		179.5		158.8		272.3		11.1		1,205.4
Effect of change in product prices and differentials	(197.3	)	(159.4	)	(74.1	)	(95.3	)	—		(526.1	)
Effect of change in sales volumes	(128.0	)	151.4		(24.8	)	(14.2	)	—		(15.6	)
Other	—		—		—		—		(2.0	)	(2.0	)
Nine months ended September 30, 2015 (1)	258.4		171.5		59.9		162.8		9.1		661.7

⁽¹⁾  Excluding realized commodity risk management.

⁽²⁾  Primarily sulphur sales.

Year to date 2015 light oil sales decreased 56 percent compared to the same period in 2014 due to a 42 percent decrease in the Edmonton par light oil benchmark price combined with lower light oil sales volumes. Heavy oil sales decreased 4 percent as the effect of the 45 percent decrease in the WCS heavy oil benchmark price exceeded the inclusion of the Lindbergh Phase 1 sales volumes. NGL sales decreased 62 percent driven by the impact of lower commodity prices and lower volumes. Natural gas sales decreased 40 percent due to significantly lower natural gas benchmark prices relative to 2014 combined with lower volumes.

ROYALTY EXPENSES

($ millions except per boe amounts and percentages)	Three months ended			Nine months ended
	Sept 30, 2015	Jun 30, 2015	Sept 30, 2014	Sept 30, 2015	Sept 30, 2014
Royalty expenses	19.1	26.5	65.5	70.4	217.4
$/boe	2.80	3.93	9.83	3.55	10.79
Royalties as a percent of oil and gas sales (%) (1)	9.0	10.6	17.7	10.6	18.0

⁽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 following the declaration of commerciality.

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.

Third quarter of 2015 royalties as a percentage of sales decreased to 9.0 percent from 10.6 percent in the second quarter of 2015 and 17.7 percent in the third 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. Third quarter of 2015 royalties were also favourably impacted by Gas Cost Allowance and other incentives.

Year to date 2015 royalties as a percentage of sales decreased to 10.6 percent from 18.0 percent in 2014 also impacted by lower 2015 commodity prices and inclusion of the Lindbergh Phase 1 royalties as of April 1, 2015.

OPERATING EXPENSES

($ millions except per boe amounts)	Three months ended			Nine months ended
	Sept 30, 2015	Jun 30, 2015	Sept 30, 2014	Sept 30, 2015	Sept 30, 2014
Operating expenses	91.0	106.8	102.4	290.7	320.9
$/boe	13.32	15.83	15.36	14.67	15.93

Third quarter of 2015 operating expenses decreased $15.8 million or 15 percent compared to the second quarter of 2015 due to lower utilities, absence of second quarter turnaround costs and lower environmental costs. On a per boe basis, third quarter of 2015 operating expenses decreased $2.51/boe compared to the second quarter of 2015 primarily due to lower costs in the third quarter described above, as production volumes remained relatively unchanged.

PENGROWTH Third Quarter 2015 Management's Discussion and Analysis 17

Third quarter of 2015 operating expenses decreased $11.4 million or 11 percent compared to the third quarter of 2014 due to lower utilities, the absence of expenses related to property dispositions and the uneconomic shut-in of gas volumes as well as lower environmental costs. These decreases were partially offset by inclusion of the Lindbergh Phase 1 operating expenses in the third quarter of 2015 operating expenses. On a per boe basis, third quarter of 2015 operating expenses decreased $2.04/boe compared to the third quarter of 2014 primarily due to lower costs and higher production in the third quarter of 2015. Inclusion of Lindbergh Phase 1 operating expenses of $9.66/boe, which are lower than overall per boe operating expenses, also contributed to the $2.04/boe decrease.

Year to date 2015 operating expenses decreased $30.2 million or 9 percent compared to the same period in 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 year to date 2015 results. On a per boe basis, year to date 2015 operating expenses decreased $1.26/boe compared to the same period last year mostly due to the impact of lower costs noted above. Inclusion of Lindbergh Phase 1 operating expenses of $11.54/boe, which are lower than overall per boe operating expenses, also contributed to the $1.26/boe decrease.

TRANSPORTATION EXPENSES

($ millions except per boe amounts)	Three months ended			Nine months ended
	Sept 30, 2015	Jun 30, 2015	Sept 30, 2014	Sept 30, 2015	Sept 30, 2014
Transportation expenses	12.3	14.0	6.5	35.9	22.1
$/boe	1.80	2.08	0.97	1.82	1.10

Third quarter of 2015 transportation expenses decreased $1.7 million or $0.28/boe compared to the second quarter of 2015. This was primarily due to lower transportation expenses at Lochend and Lindbergh.

Third quarter and year to date 2015 transportation expenses increased $5.8 million or $0.83/boe and $13.8 million or $0.72/boe compared to the same periods in 2014, respectively, resulting from higher pipeline tariffs and moving natural gas directly into the Chicago market in 2015 in addition to the incremental Lindbergh Phase 1 production transportation expenses. Pengrowth commenced directly marketing and delivering natural gas to the Chicago sales point in November of 2014 using Pengrowth's existing Alliance pipeline capacity with the intent to increase the overall netback. Previously, Pengrowth's Alliance pipeline capacity was managed by a third party and with the direct assumption of the pipeline capacity this has increased reported transportation expenses.

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 72 percent of its crude oil at market points beyond the wellhead, incurring transportation costs prior to custody transfer points. The transportation expenses are dependent upon third party rates and the distance the product travels prior to changing ownership or custody.

PENGROWTH Third Quarter 2015 Management's Discussion and Analysis 18

OPERATING NETBACKS

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

Combined Netback Including Realized Commodity Risk Management ($/boe)	Three months ended						Nine months ended
	Sept 30, 2015		Jun 30, 2015		Sept 30, 2014		Sept 30, 2015		Sept 30, 2014
Oil & gas sales (includes other income)	31.02		37.05		55.36		33.40		59.84
Royalties	(2.80	)	(3.93	)	(9.83	)	(3.55	)	(10.79	)
Operating expenses	(13.32	)	(15.83	)	(15.36	)	(14.67	)	(15.93	)
Transportation expenses	(1.80	)	(2.08	)	(0.97	)	(1.82	)	(1.10	)
Operating netback before realized commodity risk management	13.10		15.21		29.20		13.36		32.02
Realized commodity risk management	12.38		8.77		(4.29	)	11.57		(5.85	)
Operating netback	25.48		23.98		24.91		24.93		26.17
Light Oil Netback Excluding Realized Commodity Risk Management ($/bbl)
Sales	54.76		63.05		94.04		55.47		97.82
Royalties	(9.18	)	(6.68	)	(19.91	)	(8.00	)	(20.64	)
Operating expenses	(16.00	)	(21.03	)	(15.99	)	(17.41	)	(15.88	)
Transportation expenses	(1.66	)	(2.07	)	(1.65	)	(1.97	)	(2.07	)
Light oil operating netback	27.92		33.27		56.49		28.09		59.23
Heavy Oil Netback Excluding Realized Commodity Risk Management ($/bbl) (1)
Sales	35.60		50.42		78.43		41.38		79.84
Royalties	(1.82	)	(2.09	)	(13.09	)	(2.36	)	(12.10	)
Operating expenses	(11.87	)	(14.86	)	(16.80	)	(14.08	)	(18.11	)
Transportation expenses	(2.41	)	(3.11	)	(1.67	)	(2.51	)	(1.78	)
Heavy oil operating netback	19.50		30.36		46.87		22.43		47.85
NGLs Netback Excluding Realized Commodity Risk Management ($/bbl)
Sales	18.79		31.33		52.94		25.05		56.03
Royalties	(4.69	)	(13.71	)	(14.38	)	(8.96	)	(16.27	)
Operating expenses	(13.89	)	(16.18	)	(15.53	)	(14.74	)	(15.74	)
NGLs operating netback	0.21		1.44		23.03		1.35		24.02
Natural Gas Netback Excluding Realized Commodity Risk Management ($/Mcf)
Sales	3.02		2.77		4.05		3.15		4.99
Royalties (2)	0.07		(0.11	)	(0.22	)	(0.04	)	(0.38	)
Operating expenses	(2.13	)	(2.25	)	(2.43	)	(2.24	)	(2.58	)
Transportation expenses	(0.32	)	(0.35	)	(0.11	)	(0.32	)	(0.10	)
Natural gas operating netback ($/Mcf)	0.64		0.06		1.29		0.55		1.93
Natural gas operating netback ($/boe)	3.84		0.36		7.74		3.30		11.58
CONTRIBUTION BASED ON OPERATING NETBACKS
Light oil	46	%	51	%	58	%	51	%	56	%
Heavy oil	42	%	47	%	19	%	37	%	17	%
Natural gas liquids	—	%	1	%	10	%	1	%	11	%
Natural gas	12	%	1	%	13	%	11	%	16	%

⁽¹⁾  Includes Lindbergh operating results.

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

PENGROWTH Third Quarter 2015 Management's Discussion and Analysis 19

Pengrowth realized an operating netback of $25.48/boe in the third quarter of 2015 representing a 6 percent increase compared to the second quarter of 2015 as higher realized commodity risk management gains combined with lower operating expenses more than offset the impact of lower crude oil benchmark prices.

The operating netback increased 2 percent in the third quarter of 2015 compared to the same period last year as higher realized commodity risk management gains, lower royalties and operating expenses mitigated the impact of steep declines in commodity prices.

Similarly, the year to date 2015 operating netback only decreased 5 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			Nine months ended
($ millions except per boe amounts)	Sept 30, 2015	Jun 30, 2015	Sept 30, 2014	Sept 30, 2015	Sept 30, 2014
Cash G&A expenses (1)	24.2	22.1	20.6	71.2	63.1
$/boe	3.54	3.28	3.09	3.59	3.13
Non-cash G&A expenses (1)	1.4	4.6	5.0	10.4	13.4
$/boe	0.21	0.68	0.75	0.53	0.67
Total G&A (1)	25.6	26.7	25.6	81.6	76.5
$/boe	3.75	3.96	3.84	4.12	3.80

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

Third quarter of 2015 cash G&A expenses included $4.8 million of severance costs which were the primary driver behind the $2.1 million or $0.26/boe and $3.6 million or $0.45/boe increase in the third quarter of 2015 compared to the second quarter of 2015 and third quarter of 2014, respectively. The estimated annual total G&A savings related to staff reductions are approximately $17 million.

Year to date 2015 cash G&A expenses were $8.1 million or $0.46/boe higher compared to the same period last year also due to severance costs as well as lower recoveries in 2015.

The non-cash component of G&A represents the compensation expenses associated with Pengrowth’s Long Term Incentive Plan ("LTIP"). See Note 9 to the September 30, 2015 unaudited Consolidated Financial Statements for additional information. The compensation costs associated with this plan are expensed over the applicable vesting periods.

Third quarter of 2015 non-cash G&A expenses decreased $3.2 million and $3.6 million compared to the second quarter of 2015 and third quarter of 2014 due to increased LTIP forfeitures resulting from staff reductions in 2015. Year to date 2015 non-cash G&A expenses decreased $3.0 million compared to the same period in 2014 also due to higher forfeitures in 2015.

During the nine months ended September 30, 2015, $7.5 million (September 30, 2014 - $11.7 million) of directly attributable G&A costs were capitalized to Property, Plant and Equipment ("PP&E").

DEPLETION, DEPRECIATION, AMORTIZATION AND ACCRETION

	Three months ended			Nine months ended
($ millions except per boe amounts)	Sept 30, 2015	Jun 30, 2015	Sept 30, 2014	Sept 30, 2015	Sept 30, 2014
Depletion, depreciation and amortization	120.8	116.7	128.5	350.4	389.3
$/boe	17.69	17.30	19.27	17.68	19.33
Accretion	4.4	4.3	4.5	13.2	14.4
$/boe	0.64	0.64	0.67	0.67	0.71

Third quarter of 2015 DD&A expense increased $4.1 million compared to the second quarter of 2015 mainly due to the impact of increased Lindbergh Phase 1 production, partially offset by lower depletion on the conventional properties.

Third quarter and year to date 2015 DD&A expense decreased $7.7 million or $1.58/boe and $38.9 million or $1.65/boe compared to the same periods last year, respectively, due to lower net book values resulting from the fourth quarter

PENGROWTH Third Quarter 2015 Management's Discussion and Analysis 20

of 2014 PP&E impairment charges, combined with the absence of depletion related to several minor 2014 and 2015 property dispositions. This was partially offset by additional DD&A relating to the Lindbergh Phase 1 production in 2015.

Third quarter of 2015 ARO accretion expense remained relatively unchanged compared to the second quarter of 2015 and third quarter of 2014. The year to date 2015 accretion expense decreased $1.2 million compared to the same period last year resulting primarily from lower discount rates.

IMPAIRMENTS

	Three months ended			Nine months ended
($ millions)	Sept 30, 2015	Jun 30, 2015	Sept 30, 2014	Sept 30, 2015	Sept 30, 2014
PP&E impairment	409.0	—	—	409.0	—
Goodwill impairment	73.0	—	—	73.0	—
Total impairment	482.0	—	—	482.0	—

PP&E Impairments

IFRS requires an impairment test to assess the recoverable value of the PP&E within each Cash Generating Unit ("CGU") whenever there is an indication of impairment. In light of a significant and sustained decline in both oil and natural gas benchmark prices in the third quarter of 2015 compared to year end 2014, impairment tests were carried out on six CGUs at September 30, 2015. This resulted in a $409.0 million PP&E impairment at September 30, 2015. The impairment tests carried out were based on December 31, 2014 reserves (adjusted for price related economic revisions, 2015 divestments and production, as well as 15 percent cost reductions), using a pre-tax discount rate of 10 percent, October 1, 2015 independent reserves evaluator's forecast pricing, and an inflation rate of 2 percent. The recoverable amount of each CGU was determined using fair value less costs to sell. October 1, 2015 independent reserves evaluator's forecast pricing decreased by an average of 15 to 20 percent, varying from benchmark to benchmark, relative to January 1, 2015 reserves evaluator's forecast pricing.

The impairments noted above were recorded on the Consolidated Statements of Income (Loss) at September 30, 2015 and may be reversed, excluding goodwill, if and when the fair values of the CGUs increase in the future periods. However, the impairment test is sensitive to lower commodity prices, which have been under significant downward pressure recently. Further declines in commodity prices could result in additional impairment charges if the recoverable values are further eroded by price decreases. See Note 2 to the September 30, 2015 unaudited Consolidated Financial Statements for additional information.

E&E Impairments

The majority of Pengrowth’s E&E assets relate to Montney lands in the Groundbirch and Bernadet areas of north eastern BC. Pengrowth did not determine that there was an impairment trigger at September 30, 2015 due to recent drilling performance and technological improvements which will be incorporated into year end reserve and contingent resource reports.

Goodwill Impairments

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

At September 30, 2015, impairment tests were performed, which resulted in a $73.0 million impairment of goodwill to non CGU specific goodwill. All tested CGUs were negatively impacted by a downturn in the forward benchmark prices. See Note 4 to the September 30, 2015 unaudited Consolidated Financial Statements for more information.

As at September 30, 2015, Pengrowth has remaining goodwill of $126.0 million (December 31, 2014 - $202.2 million) which is not specific to any CGU. In addition to the $73.0 million in impairment charges, several minor 2015 property dispositions resulted in a $3.2 million decrease in goodwill in 2015.

PENGROWTH Third Quarter 2015 Management's Discussion and Analysis 21

INTEREST AND FINANCING CHARGES

	Three months ended						Nine months ended
($ millions)	Sept 30, 2015		Jun 30, 2015		Sept 30, 2014		Sept 30, 2015		Sept 30, 2014
Interest and financing charges	29.3		28.4		26.0		87.8		78.0
Capitalized interest	(0.8	)	(0.6	)	(8.8	)	(11.8	)	(21.1	)
Total interest and financing charges	28.5		27.8		17.2		76.0		56.9

At September 30, 2015, Pengrowth had approximately $2.0 billion in total debt before working capital composed of $1.6 billion of fixed rate debt, $0.3 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 3.2 percent interest rate and the convertible debentures have a 6.25 percent coupon.

Third quarter of 2015 interest and financing charges, before capitalized interest, increased $0.9 million compared to the second quarter of 2015 due to higher Canadian equivalent interest expense on U.S. term debt resulting from further weakening of the Canadian Dollar during the third quarter of 2015.

Third quarter and year to date 2015 interest and financing charges, before capitalized interest, increased $3.3 million and $9.8 million compared to the same periods in 2014, respectively. The increase was due to the additional interest incurred from borrowings on the credit facilities in 2015 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.

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 nine months ended September 30, 2015, $11.8 million (September 30, 2014 - $21.1 million) of interest was capitalized on the Lindbergh project to PP&E using Pengrowth's weighted average cost of debt of 5.4 percent (September 30, 2014 - 5.7 percent).

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 $78.5 million in the third quarter of 2015, primarily due to the third quarter of 2015 PP&E impairment of $409.0 million, compared to a deferred tax recovery of $30.9 million in the second quarter of 2015 and a $32.6 million deferred tax expense in the third quarter of 2014. Year to date 2015 deferred tax recovery amounted to $114.3 million compared to a deferred tax recovery of $6.0 million in 2014.

No current income taxes were paid by Pengrowth in 2015 or 2014. See Note 7 to the September 30, 2015 unaudited Consolidated Financial Statements for additional information.

PENGROWTH Third Quarter 2015 Management's Discussion and Analysis 22

FOREIGN CURRENCY GAINS (LOSSES)

	Three months ended						Nine months ended
($ millions)	Sept 30, 2015		Jun 30, 2015		Sept 30, 2014		Sept 30, 2015		Sept 30, 2014
Currency exchange rate ($1Cdn = $U.S.) at period end	0.75		0.80		0.89		0.75		0.89
Unrealized foreign exchange gain (loss) on U.S. dollar denominated debt	(95.8	)	24.1		(63.9	)	(198.1	)	(67.0	)
Unrealized foreign exchange gain (loss) on U.K. pound sterling denominated debt	(3.7	)	(5.4	)	0.7		(13.8	)	(3.4	)
Total unrealized foreign exchange gain (loss) from translation of foreign denominated debt	(99.5	)	18.7		(63.2	)	(211.9	)	(70.4	)
Unrealized gain (loss) on U.S. foreign exchange risk management contracts	54.1		(19.0	)	20.8		(11.8	)	17.6
Unrealized gain (loss) on U.K. foreign exchange risk management contracts	4.1		5.4		(0.3	)	13.5		3.6
Total unrealized gain (loss) on foreign exchange risk management contracts	58.2		(13.6	)	20.5		1.7		21.2
Net unrealized foreign exchange gain (loss)	(41.3	)	5.1		(42.7	)	(210.2	)	(49.2	)
Net realized foreign exchange gain (loss)	(0.6	)	9.2		0.8		91.2		(0.7	)

Approximately 70 percent of Pengrowth’s total debt before working capital is denominated in U.S. dollars causing reported debt balances to fluctuate with changes in the value of the Canadian dollar relative to the U.S. dollar. The majority of Pengrowth’s unrealized foreign exchange gains and losses are attributable to the translation of this debt and the related foreign exchange swap contracts Pengrowth employs to manage this risk.

The gains or losses on principal restatement 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.

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 all of its U.S. swap contracts that fixed the foreign exchange rate on Pengrowth’s U.S. dollar denominated term debt, except for contracts related to the May 2015 term debt settlement. 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 associated with the May 2015 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 year to date 2015 realized foreign exchange gains from settlement of swap contracts to Cdn$93.9 million. Subsequent to the above mentioned monetization, Pengrowth has entered into a series of new foreign exchange swap contracts as outlined in the table below. At September 30, 2015, Pengrowth held a total of U.S.$920.0 million in foreign exchange swap contracts at a weighted average fixed rate of $0.78U.S per $1Cdn compared to U.S.$460 million at December 31, 2014 at a weighted average fixed rate of $0.96U.S per $1Cdn.

Contract type	Settlement date	Principal amount (U.S.$ millions)	Swapped amount (U.S.$ millions)	% of principal swapped		Fixed rate ($1Cdn = $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	%

At September 30, 2015, the fair value of these foreign exchange derivative contracts was an asset of Cdn$46.1 million and has been included on the Consolidated Balance Sheets. Changes in the fair value of these contracts between

PENGROWTH Third Quarter 2015 Management's Discussion and Analysis 23

Balance Sheet dates are reported on the Consolidated Statements of Income (Loss) as an unrealized foreign exchange (gain) loss.

Approximately 6 percent of Pengrowth’s total debt before working capital is denominated in U.K. pound sterling causing reported debt balances to fluctuate with changes in the value of the Canadian dollar relative to the U.K. pound sterling. To mitigate these fluctuations, Pengrowth entered into foreign exchange risk management contracts when it issued the U.K. pound sterling term notes. These contracts fix the Canadian dollar to the U.K. pound sterling exchange rate on the interest and principal of the U.K. pound sterling denominated debt as follows:

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

At September 30, 2015, the fair value of these foreign exchange derivative contracts was a net asset of $6.3 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.

At September 30, 2015, each Cdn$0.01 exchange rate change would result in approximately a $9.3 million pre-tax change in the fair value of the U.S. risk management contracts and a $0.7 million pre-tax change in the fair value of the U.K. risk management contracts.

ASSET RETIREMENT OBLIGATIONS - NET PRESENT VALUE

At September 30, 2015, Pengrowth's ARO liability decreased $9.1 million compared to December 31, 2014. This was primarily due to minor property dispositions in 2015. Pengrowth has estimated the net present value of its total ARO to be $771.7 million as at September 30, 2015 (December 31, 2014 – $780.8 million), based on a total escalated future liability of $2.0 billion (December 31, 2014 – $2.0 billion). The majority of the costs are expected to be incurred between 2038 and 2079. A risk free discount rate of 2.3 percent per annum and an ARO specific inflation rate of 1.5 percent were used to calculate the net present value of the ARO at September 30, 2015.

ACQUISITIONS AND DISPOSITIONS

	Three months ended						Nine months ended
($ millions)	Sept 30, 2015		Jun 30, 2015		Sept 30, 2014		Sept 30, 2015		Sept 30, 2014
Property acquisitions	0.9		—		13.7		0.9		15.8
Proceeds on property dispositions	(3.1	)	(23.5	)	(43.0	)	(27.1	)	(63.5	)
Net cash dispositions	(2.2	)	(23.5	)	(29.3	)	(26.2	)	(47.7	)

Year to date 2015, Pengrowth successfully closed several minor property dispositions for aggregate proceeds of $27.1 million. See Note 14 to the September 30, 2015 unaudited Consolidated Financial Statements for dispositions announced subsequent to September 30, 2015.

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 September 30, 2015, Pengrowth had a working capital surplus of $172.8 million compared to a working capital surplus of $33.4 million at December 31, 2014 and a working capital deficiency of $214.2 million at September 30, 2014 mainly driven by an increase in the current asset pertaining to the fair value of risk management contracts at September 30, 2015.

PENGROWTH Third Quarter 2015 Management's Discussion and Analysis 24

FINANCIAL RESOURCES AND LIQUIDITY

At September 30, 2015, more than 70 percent of Pengrowth’s total debt before working capital is denominated in U.S. dollars causing reported debt balances to fluctuate with changes in the value of the Canadian dollar. Although, Pengrowth manages this foreign exchange exposure through swaps, the unrealized gain or loss associated with these swaps is not included in the table below.

As at:	Sept 30, 2015		Dec 31, 2014		Sept 30, 2014
($ millions)
Credit facilities	275.0		201.7		—
Senior unsecured notes (1)	1,657.0		1,531.0		1,483.7
Senior debt	1,932.0		1,732.7		1,483.7
Convertible debentures (1)	137.1		137.2		235.3
Total debt before working capital	2,069.1		1,869.9		1,719.0
Working capital (surplus) deficiency (2)	(172.8	)	(33.4	)	214.2
Total debt	1,896.3		1,836.5		1,933.2
Twelve months trailing:	Sept 30, 2015		Dec 31, 2014		Sept 30, 2014
($ millions, except ratios and percentages)
Net loss	(1,130.5	)	(578.8	)	(163.9	)
Add (deduct):
Interest and financing charges	93.7		74.6		78.2
Deferred income tax recovery	(128.7	)	(20.4	)	(24.6	)
Depletion, depreciation, amortization and accretion	495.7		535.8		539.3
EBITDA	(669.8	)	11.2		429.0
Add other items:
Impairment	1,476.6		994.6		—
(Gain) loss on disposition of properties	5.0		(23.3	)	6.1
Other non-cash items (3)	(163.3	)	(402.2	)	138.9
Adjusted EBITDA	648.5		580.3		574.0
Senior debt before working capital to Adjusted EBITDA (4)	3.0		3.0		2.6
Total debt before working capital to Adjusted EBITDA (5)	3.2		3.2		3.0
Total book capitalization (6)	4,305.9		4,796.7		5,200.5
Senior debt before working capital as a percentage of total book capitalization (7)	44.9	%	36.1	%	28.5	%

⁽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 total 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 50 percent of total book capitalization.

In order to reduce overall debt, Pengrowth monetized swap contracts that fixed the foreign exchange rate on a portion of its U.S. dollar senior unsecured notes, which in addition to the foreign exchange gains from the expiration of swaps relating to the May 2015 term debt maturity, amounted to $93.9 million year to date 2015. The cash proceeds from these realized foreign exchange gains were used to pay down the credit facilities; however, this was offset by the cash required to reduce accounts payable since December 31, 2014.

September 30, 2015 total debt before working capital increased $199.2 million compared to December 31, 2014. As a majority of Pengrowth's debt is denominated in U.S. dollars and U.K. pound sterling, weakening of the Canadian dollar relative to these currencies since December 31, 2014 drove the total debt before working capital balance up by approximately $208 million. Although not incorporated in the table above, this increase was partially mitigated by Pengrowth's foreign exchange risk management program with the fair value of the foreign exchange derivative contracts being an asset of Cdn$52.5 million included on the Consolidated Balance Sheets at September 30, 2015.

PENGROWTH Third Quarter 2015 Management's Discussion and Analysis 25

As maturity of the May 2015 tranche of the senior unsecured notes of U.S.$71.5 million (Cdn$86.6 million) was financed through the credit facilities, this represents the majority of the increase in drawings on the credit facilities at September 30, 2015 relative to December 31, 2014.

September 30, 2015 total debt before working capital increased $350.1 million compared to September 30, 2014. In addition to the increased drawings on the credit facilities, weakening of the Canadian dollar resulted in approximately $250 million increase in total debt before working capital at September 30, 2015. As a result of this increase, the trailing twelve month total debt before working capital to Adjusted EBITDA increased to 3.2 times at September 30, 2015 from 3.0 times at September 30, 2014.

Credit Facilities

Pengrowth maintains a $1 billion extendible revolving term credit facility which had an outstanding balance of $260.0 million at September 30, 2015 (December 31, 2014 - $191.0 million) and $21.8 million (December 31, 2014 - $25.0 million) in outstanding letters of credit. The credit facility includes an expansion feature of $250 million providing Pengrowth with up to $1.25 billion of notional credit capacity from a syndicate of seven Canadian and four foreign banks, and can be extended at Pengrowth’s discretion any time prior to maturity, subject to syndicate approval. The facility was renewed on March 30, 2015 and has a maturity date of March 30, 2019 with covenants substantially matching those set out in the senior unsecured notes.

Pengrowth also maintains a $50 million demand operating facility with one Canadian bank. At September 30, 2015, this facility had a balance of $14.0 million (December 31, 2014 - $9.0 million) and $1.1 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 $752 million of combined notional credit capacity at September 30, 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.

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 September 30, 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 calculation for each financial covenant is based on specific definitions within the agreements, is not in accordance with IFRS, is substantially similar to Adjusted EBITDA, and cannot be readily replicated by referring to Pengrowth’s Consolidated Financial Statements.

The key financial covenants as at September 30, 2015 are summarized below:

1.Total senior debt before working capital must not exceed 3.5 times EBITDA for the last four fiscal quarters;

2.Total debt before working capital must not exceed 4.0 times EBITDA for the last four fiscal quarters;

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

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

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

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

As mentioned above, Pengrowth amended its term credit facility on March 30, 2015 to include a maximum permitted senior debt before working capital to EBITDA (as calculated in accordance with the debt agreements) ratio of 3.5 times, now substantially matching that set out in its senior unsecured notes, and the total debt before working capital to EBITDA ratio of 4.0 times.

PENGROWTH Third Quarter 2015 Management's Discussion and Analysis 26

As at September 30, 2015, Pengrowth's actual ratios pursuant to the covenants of total senior debt before working capital to twelve month trailing EBITDA was at 3.0 times, and total debt before working capital to twelve month trailing EBITDA was at 3.2 times. The actual covenant, pursuant to the credit facility, of total senior debt before working capital as a percent of total book capitalization was at 45.2 percent and the trailing twelve month EBITDA was at 6.9 times interest expense for the last four fiscal quarters.

Dividend Reinvestment Plan

On September 1, 2015 Pengrowth's Board of Directors approved a change to the Corporation's dividend policy, moving to a quarterly payment of $0.01 per share replacing the previous dividend policy of a monthly payment of $0.02 per share. The new dividend policy came in effect following the payment of the $0.02 per share dividend on September 15, 2015 with the first quarterly payment expected to be paid on December 15, 2015.

In conjunction with the dividend policy change, Pengrowth's Board also approved the suspension of the DRIP, effective with the quarterly dividend payable on December 15, 2015. Shareholders previously enrolled in the DRIP will receive their quarterly dividends as cash starting with December 15, 2015 payment.

During the nine months ended September 30, 2015, 6.4 million shares were issued under the DRIP program for cash proceeds of $18.7 million compared to 5.9 million shares issued for total proceeds of $39.5 million for the same period in 2014.

Off-Balance Sheet Financing

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

FINANCIAL INSTRUMENTS

Pengrowth uses financial instruments to manage its exposure to commodity and power price fluctuations and foreign currency exposure. Pengrowth’s policy is not to utilize financial instruments for trading or speculative purposes. See Note 2 to the December 31, 2014 audited Consolidated Financial Statements for a description of the accounting policies for financial instruments and Note 12 to the September 30, 2015 unaudited 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						Nine months ended
($ millions, except per share amounts)	Sept 30, 2015		Jun 30, 2015		Sept 30, 2014		Sept 30, 2015		Sept 30, 2014
Funds flow from operations	120.6		111.5		129.0		345.1		389.9
Dividends declared	21.8		30.8		63.6		95.5		189.7
Funds flow from operations less dividends declared	98.8		80.7		65.4		249.6		200.2
Per share	0.18		0.15		0.12		0.46		0.38
Payout ratio (1)	18	%	28	%	49	%	28	%	49	%

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

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

Funds flow from operations is derived from producing and selling oil, natural gas and related products and is therefore highly dependent on commodity prices. Pengrowth enters into forward commodity risk management contracts to mitigate price volatility and to provide a measure of stability to monthly cash flow. Details of commodity risk management contracts are contained in Note 12 to the September 30, 2015 unaudited Consolidated Financial Statements.

PENGROWTH Third Quarter 2015 Management's Discussion and Analysis 27

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).

As a result of the continued weakness in commodity prices, Pengrowth's Board of Directors approved a new dividend policy on September 1, 2015, moving to a quarterly payment of $0.01 per share ($0.04 per share annually). With the macro environment continuing to deteriorate and given the outlook for a prolonged weakness in commodity prices, Pengrowth believes that it is prudent to preserve capital and accelerate its efforts to reduce overall indebtedness.

The new dividend policy came into effect following the payment of the $0.02 per share dividend payable on September 15, 2015 with the first quarterly payment expected to be paid on December 15, 2015. Subsequent dividends are expected to be paid on the 15th (or next business day) of March, June, September and December each year. In addition, Pengrowth's Board also approved the suspension of the DRIP, effective with the quarterly dividend payable on December 15, 2015. Shareholders previously enrolled in the DRIP will instead receive their dividends as cash.

Pengrowth paid $0.04 per share in January and February of 2015 and $0.02 per share in March through September 2015 for an aggregate cash dividend of $0.22 per share for the nine months ended September 30, 2015. For the same period in 2014, Pengrowth paid $0.04 per share in each of the months January through September for an aggregate cash dividend of $0.36 per share.

PENGROWTH Third Quarter 2015 Management's Discussion and Analysis 28

SUMMARY OF QUARTERLY RESULTS

The following table is a summary of quarterly information for 2015, 2014 and 2013:

2015	Q1		Q2		Q3
Oil and gas sales ($ millions) (1)	199.9		249.9		211.9
Net loss ($ millions)	(160.5	)	(134.4	)	(329.6	)
Net loss per share ($)	(0.30	)	(0.25	)	(0.61	)
Net loss per share - diluted ($)	(0.30	)	(0.25	)	(0.61	)
Adjusted net income (loss) ($ millions)	64.8		(38.9	)	(374.0	)
Funds flow from operations ($ millions) (2)	113.0		111.5		120.6
Dividends declared ($ millions)	42.9		30.8		21.8
Dividends declared per share ($)	0.08		0.06		0.04
Daily production (boe/d)	69,334		74,113		74,239
Total production (Mboe)	6,240		6,744		6,830
Average sales price ($/boe) (1)	31.39		36.58		30.75
Operating netback ($/boe) (3)	25.37		23.98		25.48
2014	Q1		Q2		Q3		Q4
Oil and gas sales ($ 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 ($/boe) (3)	29.71		23.86		24.91		24.04
2013	Q1		Q2		Q3		Q4
Oil and gas sales ($ millions) (1)	393.5		416.6		439.6		343.7
Net loss ($ millions)	(65.1	)	(53.4	)	(107.3	)	(91.1	)
Net loss per share ($)	(0.13	)	(0.10	)	(0.21	)	(0.17	)
Net loss per share - diluted ($)	(0.13	)	(0.10	)	(0.21	)	(0.17	)
Adjusted net loss ($ millions)	(1.1	)	(37.2	)	(108.2	)	(37.3	)
Funds flow from operations ($ millions)	147.5		146.0		161.5		105.9
Dividends declared ($ millions)	61.6		62.1		62.3		62.5
Dividends declared per share ($)	0.12		0.12		0.12		0.12
Daily production (boe/d)	89,702		87,909		83,275		77,371
Total production (Mboe)	8,073		8,000		7,661		7,118
Average sales price ($/boe) (1)	48.18		51.55		56.64		47.92
Operating netback ($/boe) (3)	24.79		24.44		27.10		20.82

⁽¹⁾  Excluding realized commodity risk management.

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

⁽³⁾  Including realized commodity risk management.

Third quarter of 2015 average sales price was lower than preceding quarters of 2014 and 2013, as per the table above, mostly driven by a continued decline in the oil benchmark prices throughout 2015. In contrast, the first and second quarters of 2014 average sales prices were the highest posted average prices since the fourth quarter of 2008 driven by an increase in the benchmark prices at that time.

PENGROWTH Third Quarter 2015 Management's Discussion and Analysis 29

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

Third quarter of 2015 production was the highest quarterly production since the first quarter of 2014 resulting from inclusion of the Lindbergh Phase 1 production. First quarter of 2015 production was lower compared to the preceding quarters of 2014 and 2013 primarily due to property dispositions, lower natural gas production resulting from natural declines and capital spending curtailments in the current low commodity price environment.

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 taxes. Funds flow from operations was also impacted by changes in royalty expense, operating and G&A costs.

Pengrowth's third quarter 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 $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.

SUBSEQUENT EVENTS

On October 22, 2015, Pengrowth entered into a Purchase and Sale agreement for the disposition of its non-core Jenner area properties in south eastern Alberta for cash consideration of $80 million, prior to closing adjustments. The sale is expected to close prior to year end and result in an after tax loss of approximately $38 million.

On October 29, 2015, Pengrowth received notification from the New York Stock Exchange ("NYSE") 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 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.

On October 30, 2015, Pengrowth closed the sale of its non-core Bodo property in eastern Alberta and western Saskatchewan for cash consideration of $95 million, prior to closing adjustments. It is not expected that a material gain or loss on this transaction will be recorded.

BUSINESS RISKS

Pengrowth is exposed to normal market risks inherent in the oil and natural gas business, the details of which are set out in the AIF of the Corporation dated February 26, 2015 available on SEDAR at www.sedar.com and EDGAR at www.sec.gov.

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.

At the end of the interim period ended September 30, 2015, Pengrowth did not have any material weakness relating to design of its internal control over financial reporting. Pengrowth has not limited the scope of its design of disclosure controls and procedures and internal control over financial reporting to exclude controls, policies and procedures of (i) a proportionately consolidated entity in which Pengrowth has an interest; (ii) a variable interest entity in which Pengrowth has an interest; or (iii) a business that Pengrowth acquired not more than 365 days before September 30, 2015 and summary financial information about these items has been proportionately consolidated or consolidated in Pengrowth's Consolidated Financial Statements. During the interim period ended September 30, 2015, no change occurred to Pengrowth's internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, Pengrowth's internal control over financial reporting.

It should be noted that while Pengrowth’s Chief Executive Officer ("CEO") and Chief Financial Officer ("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.

PENGROWTH Third Quarter 2015 Management's Discussion and Analysis 30