Pengrowth Energy 6K Summary of Financial & Operating Results | PGH 2 Nov 16

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, 2016 of Pengrowth Energy Corporation ("Pengrowth" or the "Corporation"). This MD&A is based on information available to November 2, 2016.

Pengrowth’s third quarter and year to date 2016 results 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, Asset Retirement Obligations ("ARO"), remediation, reclamation and abandonment expenses, clean-up and remediation costs, capital expenditures, development activities, cash General and Administrative Expenses ("G&A"), Lindbergh expansion plans, production capacity, anticipated low costs and sustaining capital and proceeds from the disposal of properties. Statements relating to "reserves" are forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions that the reserves described exist in the quantities predicted or estimated and can profitably be produced in the future.

Forward-looking statements and information are based on Pengrowth's current beliefs as well as assumptions made by, and information currently available to, Pengrowth concerning general economic and financial market conditions, anticipated financial performance, business prospects, strategies, regulatory developments, including in respect of taxation, royalty rates and environmental protection, future capital expenditures and the timing thereof, future oil and natural gas commodity prices and differentials between light, 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 2016 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; actions by government authorities, including the imposition or reassessment of taxes including changes in income taxes and royalty laws; Pengrowth's ability to access external sources of debt and equity capital; new International Financial Reporting Standards ("IFRS"); and the implementation of greenhouse gas emissions legislation and the impact of carbon taxes. Further information regarding these factors may be found under the heading "Business Risks" herein and under "Risk Factors" in Pengrowth's most recent Annual Information Form ("AIF"), and in Pengrowth’s most recent audited annual Consolidated Financial Statements, management information circular, quarterly reports, material change reports and news releases. Copies of Pengrowth’s public filings are available on SEDAR at www.sedar.com and EDGAR at www.sec.gov.

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

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

CRITICAL ACCOUNTING ESTIMATES

The 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, 2015 to 2.0 percent at March 31, 2016. The rate changed to 1.7 percent at June 30, 2016 and remained at that level at September 30, 2016. The ARO risk free discount rate changes were driven by a decrease in the 30 year Canadian Government long term bond rate. There were no other changes to Pengrowth's critical accounting estimates in the nine months ended September 30, 2016. For more information about Pengrowth's critical accounting estimates refer to the December 31, 2015 annual report.

COMPARATIVE FIGURES

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

ADDITIONAL GAAP MEASURE

Funds Flow from Operations

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



PENGROWTH Third Quarter 2016 Management's Discussion and Analysis		2

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

NON-GAAP FINANCIAL MEASURES

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

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

Management monitors Pengrowth’s capital structure using non-GAAP financial metrics as per the Financial Resources and Liquidity section of this MD&A. These metrics are: senior debt before working capital to the trailing twelve months Earnings Before Interest, Taxes, Depletion, Depreciation, Amortization, Accretion, and other non-cash items ("Adjusted EBITDA"); total debt before working capital to Adjusted EBITDA; Adjusted EBITDA to interest expense; and senior debt before working capital as a percentage of total book capitalization. For the purposes of covenant calculations only, convertible debentures, letters of credit and finance leases are incorporated in senior and total debt before working capital for covenant purposes. Total book capitalization is the sum of senior debt before working capital for covenant purposes and shareholders' equity.

Management believes that, in addition to net income (loss), adjusted net income (loss) is a useful supplemental measure as it reflects the underlying performance of Pengrowth’s business activities by excluding the after-tax effect of non-cash changes in fair value of commodity and power risk management contracts as well as unrealized foreign exchange gains and losses that may significantly impact net income (loss) from period to period.

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

Management believes that segregating G&A expenses into cash and non-cash expenses is useful to the reader, as non-cash expenses only affect net income (loss) but not funds flow from operations. Cash and non-cash G&A expenses per boe are calculated by dividing cash and non-cash G&A expenses by production for the period.

OPERATIONAL MEASURES

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

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

Average Steam Oil Ratio ("SOR") measures the average rate of steam required to produce a barrel of bitumen.

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

CURRENCY

All amounts are stated in Canadian dollars unless otherwise specified.



PENGROWTH Third Quarter 2016 Management's Discussion and Analysis		3

2016 GUIDANCE

The following table provides a summary of full year 2016 Guidance and actual results for the nine months ended September 30, 2016:



	Actual Year to date Sept 30, 2016	Full year 2016 Guidance ^{(1) (2)}
Production (boe/d)	57,966	56,000 - 58,000
Capital expenditures ($ millions)	36.0	60 - 70
Royalty expenses (% of sales)	6.5	7 - 8
Operating expenses ($/boe)	12.93	13.50 - 14.25
Cash G&A expenses ($/boe)	3.31	2.75 - 3.25


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


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

Year to date 2016 average daily production of 57,966 boe/d was at the high end of full year 2016 Guidance. Full year daily production is expected to remain within full year 2016 Guidance.

Year to date 2016 capital expenditures amounted to $36.0 million and are anticipated to be within full year 2016 Guidance.

Year to date 2016 royalty expenses as a percentage of sales were below full year 2016 Guidance. Full year royalty expenses as a percentage of sales are anticipated to be within full year 2016 Guidance.

Year to date 2016 operating expenses per boe were below full year 2016 Guidance, driven by Pengrowth's continued focus on cost reduction efforts, and are anticipated to be within full year 2016 Guidance.

Year to date 2016 cash G&A expenses per boe were slightly above full year 2016 Guidance primarily due to the mark-to-market impact of the cash-settled Long Term Incentive Plans ("LTIP"). Full year cash G&A expenses per boe are anticipated to be within full year 2016 Guidance.



PENGROWTH Third Quarter 2016 Management's Discussion and Analysis		4

FINANCIAL HIGHLIGHTS



	Three months ended						Nine months ended
($ millions except per boe amounts)	Sept 30, 2016		Jun 30, 2016		Sept 30, 2015		Sept 30, 2016		Sept 30, 2015
Production (boe/d)	55,137		56,735		74,239		57,966		72,580
Capital expenditures	15.3		12.0		15.5		36.0		164.7
Funds flow from operations ^{(1) (2)}	122.7		89.1		120.6		318.0		345.1
Operating netback ($/boe) ⁽³⁾	32.13		25.46		25.48		28.25		24.93
Adjusted net income (loss)	18.6		(16.5	)	(374.0	)	2.7		(348.1	)
Net income (loss)	(52.9	)	(173.4	)	(329.6	)	(201.3	)	(624.5	)


⁽¹⁾	Funds flow from operations for the three and nine months ended September 30, 2016 includes $41.6 million related to the early settlement of 2018/2019 commodity risk management contracts.


⁽²⁾	Funds flow from operations for the nine months ended September 30, 2015 excludes $93.9 million related to the 2015 settlement of foreign exchange swap contracts as this was considered a financing activity.


⁽³⁾	Includes realized commodity risk management.

During the third quarter of 2016, Pengrowth early settled all of its 2018 oil commodity risk management contracts and all of its 2018 and 2019 natural gas risk management contracts for total proceeds of $41.6 million. The early settlement provides additional near term financial flexibility. These proceeds, together with surplus funds flow in the quarter, brought Pengrowth’s cash balance to $139.5 million at September 30, 2016 with no amounts drawn on its $1.0 billion credit facility.

Funds Flow from Operations



($ millions)	Q2/16 vs. Q3/16			% Change		Q3/15 vs. Q3/16			% Change		YTD 2015 vs. 2016			% Change
Funds flow from operations for comparative period ⁽¹⁾	Q2/16	89.1				Q3/15	120.6				YTD 2015	345.1
Increase (decrease) due to:
Volumes		(3.3	)	(4	)		(55.6	)	(46	)		(121.4	)	(35	)
Prices including differentials		11.7		13			(10.1	)	(8	)		(138.4	)	(40	)
Realized commodity risk management ⁽²⁾		27.3		31			19.9		16			79.2		23
Other income including sulphur		—		—			(0.6	)	—			(4.9	)	(2	)
Royalties		(2.2	)	(2	)		9.1		7			44.5		13
Expenses:
Operating		(1.9	)	(2	)		22.4		19			85.3		25
Cash G&A		4.2		5			9.4		8			18.6		5
Interest & financing		0.1		—			2.2		2			(3.2	)	(1	)
Other - including transportation		(2.3	)	(3	)		5.4		4			13.2		4
Net change		33.6		38			2.1		2			(27.1	)	(8	)
Funds flow from operations ⁽²⁾	Q3/16	122.7				Q3/16	122.7				YTD 2016	318.0


⁽¹⁾	Funds flow from operations for the nine months ended September 30, 2015 excludes $93.9 million related to the 2015 settlement of foreign exchange swap contracts as this was considered a financing activity.


⁽²⁾	Funds flow from operations for the three and nine months ended September 30, 2016 includes $41.6 million related to the early settlement of 2018/2019 commodity risk management contracts.

Pengrowth's third quarter of 2016 funds flow from operations increased 38 percent from the second quarter of 2016 driven by higher realized commodity risk management gains in addition to improved natural gas and NGL pricing partly offset by lower volumes. Third quarter of 2016 realized commodity risk management gains were $27.3 million higher compared to the second quarter of 2016 primarily due to the early settlement of 2018 and 2019 commodity risk management contracts partly offset by lower natural gas risk management gains driven by the increase in natural gas benchmark prices.

Third quarter 2016 funds flow from operations increased 2 percent compared to the third quarter 2015 primarily due to increased realized commodity risk management gains combined with lower operating, cash G&A, transportation expenses and lower royalties, largely offset by a decrease in commodity prices and volumes. Year to date 2016 funds flow from operations decreased 8 percent compared to the same period in 2015 due to lower commodity prices and volumes, largely offset by lower operating expenses combined with increased realized commodity risk management gains, lower royalties and lower cash G&A.



PENGROWTH Third Quarter 2016 Management's Discussion and Analysis		5

Net Income (Loss)

Pengrowth recorded a net loss of $52.9 million in the third quarter of 2016, an improvement of $120.5 million from the second quarter 2016 net loss primarily due to lower losses in the third quarter resulting from the change in fair value of commodity risk management contracts. The net loss was $276.7 million lower in the third quarter of 2016 compared to the third quarter of 2015 primarily due to the absence of non-cash PP&E and goodwill impairment charges of $482.0 million ($375 million after-tax) recorded in the third quarter of 2015, partially offset by a decrease in the fair value of commodity risk management contracts.

Year to date 2016 net loss was $423.2 million lower compared to 2015 primarily due to the absence of the impairment charges recorded in the third quarter of 2015.

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, 2016		Jun 30, 2016		Sept 30, 2015		Sept 30, 2016		Sept 30, 2015
Net income (loss)	(52.9	)	(173.4	)	(329.6	)	(201.3	)	(624.5	)
Exclude non-cash items from net income (loss):
Change in fair value of commodity and power risk management contracts	(84.8	)	(223.2	)	120.9		(318.4	)	(84.9	)
Unrealized foreign exchange gain (loss) ⁽¹⁾	(9.7	)	5.8		(41.3	)	28.2		(210.2	)
Tax effect on non-cash items above	23.0		60.5		(35.2	)	86.2		18.7
Total excluded	(71.5	)	(156.9	)	44.4		(204.0	)	(276.4	)
Adjusted net income (loss)	18.6		(16.5	)	(374.0	)	2.7		(348.1	)


⁽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)	Q2/16 vs. Q3/16			Q3/15 vs. Q3/16			YTD 2015 vs. 2016
Adjusted net income (loss) for comparative period	Q2/16	(16.5	)	Q3/15	(374.0	)	YTD 2015	(348.1	)
Funds flow from operations increase (decrease)		33.6			2.1			(27.1	)
DD&A and accretion expense (increase) decrease		3.9			33.9			77.5
Impairment charges decrease		—			482.0			482.0
Realized foreign exchange gain on settled FX swaps increase (decrease)		—			—			(93.9	)
Loss on property dispositions (increase) decrease		11.3			(2.8	)		6.0
Other		0.3			(0.8	)		4.6
Estimated tax on above including tax rate change		(14.0	)		(121.8	)		(98.3	)
Net change		35.1			392.6			350.8
Adjusted net income (loss)	Q3/16	18.6		Q3/16	18.6		YTD 2016	2.7

Pengrowth posted adjusted net income of $18.6 million in the third quarter of 2016 compared to the adjusted net loss of $16.5 million in the second quarter of 2016. The $35.1 million improvement was primarily due to higher funds flow from operations which included $41.6 million from early settlement of commodity risk management contracts.

Third quarter of 2016 adjusted net income of $18.6 million represents a $392.6 million improvement compared to the same period last year primarily due to the absence of the non-cash impairment charges of $482.0 million ($375 million after-tax) recorded in the third quarter of 2015.

Year to date 2016 adjusted net income of $2.7 million was a $350.8 million improvement from the same period last year, primarily driven by the absence of the non-cash impairment charges recorded in 2015 and lower DD&A expense partly offset by the absence of $93.9 million of realized foreign exchange gains related to the settlement of a series of U.S. dollar swap contracts in 2015.



PENGROWTH Third Quarter 2016 Management's Discussion and Analysis		6

Sensitivity of Funds Flow from Operations to Commodity Prices

The following table illustrates the sensitivity of funds flow from operations to increases in commodity prices after taking into account Pengrowth’s commodity risk management contracts and outlook on oil differentials. See Note 11 to the September 30, 2016 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		$52.03		$1.00
Light oil						4.7
Heavy oil						7.0
Oil risk management ⁽⁴⁾						(9.4	)
NGLs						3.0
Net impact of U.S.$1/bbl increase in WTI						5.3
Oil differentials
Light oil	U.S.$/bbl		$3.37		$1.00	(4.7	)
Heavy oil	U.S.$/bbl		$14.85		$1.00	(7.0	)
Oil differentials risk management ⁽⁴⁾						0.6
Net impact of U.S.$1/bbl increase in differentials						(11.1	)
AECO Natural Gas ^{(2) (3)}	Cdn$/Mcf		$3.09		$0.10
Natural gas						4.0
Natural gas risk management ⁽⁴⁾						(3.7	)
Net impact of Cdn$0.10/Mcf increase in AECO						0.3


⁽¹⁾	Calculations are performed independently and are not indicative of actual results when multiple variables change at the same time. The exchange rate at October 18, 2016 of Cdn$1 = U.S.$0.7633 was used for the 12 month period.


⁽²⁾	Commodity price is based on an estimation of the 12 month forward price curve at October 18, 2016 and does not include the impact of commodity risk management contracts.


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


⁽⁴⁾	Includes commodity risk management contracts as at September 30, 2016.



PENGROWTH Third Quarter 2016 Management's Discussion and Analysis		7

RESULTS OF OPERATIONS

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

CAPITAL EXPENDITURES



	Three months ended					Nine months ended
($ millions)	Sept 30, 2016		Jun 30, 2016		Sept 30, 2015	Sept 30, 2016		Sept 30, 2015
Drilling, completions and facilities
Lindbergh ⁽¹⁾	4.3		2.7		3.3	9.1		80.8
Conventional	1.2		0.3		0.3	2.7		41.9
Total drilling, completions and facilities	5.5		3.0		3.6	11.8		122.7
Land & seismic acquisitions ⁽²⁾	(0.5	)	(0.8	)	0.1	(1.1	)	0.6
Maintenance capital	9.9		9.5		11.6	24.5		39.2
Development capital	14.9		11.7		15.3	35.2		162.5
Other capital	0.4		0.3		0.2	0.8		2.2
Capital expenditures	15.3		12.0		15.5	36.0		164.7


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


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

Pengrowth continued with its strategy of deferring significant development capital expenditures until a sustained recovery in commodity prices is evident. Third quarter of 2016 capital expenditures were limited to $15.3 million with $4.3 million spent at Lindbergh and the remainder spent on turnaround, safety, integrity, maintenance and enhancement activities at Pengrowth's conventional properties.

Year to date 2016 capital expenditures were $36.0 million with $9.1 million spent at Lindbergh and the remainder spent at Pengrowth's conventional properties, as mentioned above. Pengrowth anticipates between $25 and $30 million of additional capital spending by the end of 2016, primarily related to Lindbergh Phase 1 optimization and Phase 2 engineering work in addition to integrity and maintenance work at Pengrowth's conventional properties.

Focus Areas

Lindbergh

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

The EPEA approval allows Pengrowth to continue to produce phase one above the 12,500 bbl/d nameplate capacity, and provides the opportunity for incremental optimization spending to increase production to approximately 18,000 bbl/d. Engineering work continues on the second phase which, once constructed and commissioned, would allow Pengrowth to take total production to a nameplate capacity of 30,000 bbl/d.

Conventional Oil and Gas

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



PENGROWTH Third Quarter 2016 Management's Discussion and Analysis		8

Conventional development continues to be curtailed, with the third quarter of 2016 capital spending of $10.6 million focused on safety, maintenance and integrity of existing assets combined with minor partner operated activity.

PRODUCTION



	Three months ended						Nine months ended
Daily production	Sept 30, 2016	% of total	Jun 30, 2016	% of total	Sept 30, 2015	% of total	Sept 30, 2016	% of total	Sept 30, 2015	% of total
Light oil (bbls)	11,221	20	11,747	21	15,680	21	12,118	21	17,063	24
Heavy oil (bbls)	15,190	28	15,502	27	20,489	28	15,711	27	15,182	21
Natural gas liquids (bbls)	7,139	13	7,778	14	8,331	11	7,691	13	8,759	12
Natural gas (Mcf)	129,520	39	130,248	38	178,428	40	134,672	39	189,461	43
Total boe per day	55,137		56,735		74,239		57,966		72,580

Third quarter of 2016 average daily production decreased 3 percent compared to the second quarter of 2016 mainly due to a planned turnaround at Carson Creek combined with maintenance related outages and natural declines. These declines were in large part offset by higher production from Olds following the second quarter turnaround.

Third quarter and year to date 2016 average daily production decreased 26 percent and 20 percent, respectively, compared to the same periods in 2015 primarily due to the absence of volumes from divested properties and natural declines. Year to date 2016 declines were partly offset by the inclusion of 9 months of Lindbergh commercial production in 2016 vs. 6 months in 2015.

Light Oil

Third quarter of 2016 light oil production decreased 4 percent compared to the second quarter of 2016 primarily due to the Carson Creek turnaround, integrity and maintenance work done at Judy Creek and natural declines.

Third quarter and year to date 2016 light oil production decreased 28 percent and 29 percent, respectively, compared to the same periods last year mainly due to natural declines and planned integrity and maintenance work combined with Carson Creek turnaround and property dispositions.

Heavy Oil

Third quarter of 2016 heavy oil production decreased 2 percent compared to the second quarter of 2016 resulting from an unscheduled maintenance outage at Lindbergh that required the complete shutdown of the facility for two days in September and extended for one day into October. The impact of the outage combined with higher frequency of pump replacements in the third quarter of 2016 was approximately 450 bbl/d of lost production. Third quarter of 2016 production at Lindbergh averaged 15,190 barrels per day at an average steam oil ratio ("SOR") of 2.5. This accounted for all of Pengrowth's third quarter of 2016 heavy oil production.

Third quarter of 2016 heavy oil production decreased 26 percent compared to the same period last year due to property divestments. Year to date 2016 heavy oil production increased 3 percent compared to 2015 due to the inclusion of 9 months of Lindbergh commercial production in 2016 vs. 6 months in 2015 which, combined with the ramp-up, more than offset the impact of property divestments year over year.

NGLs

Third quarter of 2016 NGL production decreased 8 percent compared to the second quarter of 2016 mainly due to lower ethane recoveries at Westward Ho combined with the impact of the Carson Creek turnaround.

Third quarter and year to date 2016 NGL production decreased 14 percent and 12 percent, respectively, compared to the same periods last year mainly due to the impact of the Carson Creek turnaround, natural declines and property divestments.

Natural Gas

Third quarter of 2016 natural gas production decreased 1 percent compared to the second quarter of 2016 primarily due to the impacts of natural declines, a planned maintenance outage at Sable Offshore Energy Project ("SOEP") and the Carson Creek turnaround which were mostly offset by higher production from Olds following the turnaround in the second quarter of 2016.

Third quarter and year to date 2016 natural gas production decreased 27 percent and 29 percent, respectively, compared to the same periods last year. This was primarily due to property divestments and natural declines in addition to



PENGROWTH Third Quarter 2016 Management's Discussion and Analysis		9

turnaround and maintenance related outages. Approximately 1,000 boe/d of uneconomic natural gas production remained shut-in during the first nine months of 2016.

COMMODITY PRICES

Oil and Liquids Prices Excluding Realized Commodity Risk Management



	Three months ended						Nine months ended
(U.S.$/bbl)	Sept 30, 2016		Jun 30, 2016		Sept 30, 2015		Sept 30, 2016		Sept 30, 2015
Average exchange rate (Cdn$1 = U.S.$)	0.77		0.78		0.76		0.76		0.79
Average Benchmark Prices
WTI oil	44.94		45.60		46.44		41.37		50.98
WCS differential to WTI	(13.49	)	(13.31	)	(13.21	)	(13.68	)	(13.18	)
WCS heavy oil	31.45		32.29		33.23		27.69		37.80



	Three months ended						Nine months ended
(Cdn$/bbl)	Sept 30, 2016		Jun 30, 2016		Sept 30, 2015		Sept 30, 2016		Sept 30, 2015
Average Benchmark Prices
WTI oil	58.65		58.78		61.42		54.48		64.09
Edmonton par light oil	54.80		54.78		56.89		50.18		58.64
WCS heavy oil	41.04		41.62		43.86		36.37		47.47
Differentials to WTI
Edmonton par	(3.85	)	(4.00	)	(4.53	)	(4.30	)	(5.45	)
WCS heavy oil	(17.61	)	(17.16	)	(17.56	)	(18.11	)	(16.62	)
Average Sales Prices
Light oil	52.50		52.85		54.76		47.50		55.47
Heavy oil	34.13		34.10		35.60		27.69		41.38
Natural gas liquids	21.62		18.93		18.79		19.74		25.05

Third quarter of 2016 saw some stability emerge in the energy markets with U.S. dollar WTI crude oil prices remaining similar to the second quarter. WTI averaged U.S.$44.94/bbl during the third quarter of 2016, down 1 percent from the second quarter of 2016 and down 3 percent compared to the same period last year. Year to date 2016 average U.S. dollar WTI crude oil prices were 19 percent lower than in 2015, reflecting the weakness in prices that emerged in the first half of 2016.

For Canadian producers, exchange rates, location and quality differentials as well as transportation bottlenecks are all factors that influence the Canadian crude oil prices received. Movements in the Canadian dollar versus the U.S. dollar influence the relative Canadian equivalent prices that Canadian companies realize. Quality differentials and transportation bottlenecks result in light oil and heavy oil differentials relative to the U.S. based WTI benchmark, leading to Canadian producers receiving discounted prices for their product. After taking into consideration the changes in the underlying benchmark prices and the changes in foreign exchange between the Canadian and US dollars, the Canadian equivalent pricing for light and heavy crude oils moved in line with the price differentials and the underlying benchmark.

Third quarter of 2016 light oil differential narrowed by 4 percent from the second quarter of 2016. Third quarter and year to date 2016 light oil differentials narrowed 15 percent and 21 percent, respectively, compared to the same periods in 2015. This narrowing of the differentials was reflective of the increase in transportation availability for Canadian light crude oil. Third quarter of 2016 heavy oil differential widened by 3 percent from the second quarter, reflecting seasonal changes in demand coupled with the return of heavy oil production that was impacted by the Fort McMurray fires in the second quarter. Year to date heavy oil differentials moved in tandem with the changes in the underlying benchmark as noted earlier.

Pengrowth’s third quarter of 2016 average realized price for light oil and heavy oil remained constant compared to the second quarter of 2016, consistent with minimal changes seen in benchmark prices. Third quarter of 2016 light oil and



PENGROWTH Third Quarter 2016 Management's Discussion and Analysis		10

heavy oil realized pricing both decreased 4 percent compared to the third quarter of 2015 reflecting the weaker benchmark pricing.

Year to date 2016 light oil and heavy oil realized prices were down 14 percent and 33 percent, respectively, compared to 2015. Weaker benchmark prices partly offset by the impact of a weaker Canadian dollar and a narrowing of the light oil differential were the primary drivers behind the lower realized prices for light oil. For heavy oil, weaker benchmark prices coupled with a widening of the heavy oil differential partly offset by a weaker Canadian dollar were the drivers behind the lower year to date 2016 realized prices compared to 2015.

Sales of natural gas liquids (NGLs) primarily comprise propane, butane, pentane and condensate. Price realizations for NGLs in the third quarter of 2016 increased by 14 percent from the previous quarter and similarly, prices were higher by 15 percent compared to the third quarter of 2015. Slight improvements in component prices for butane and pentane were the main drivers behind the higher realized pricing for NGLs. Year to date 2016 realized NGL prices also reflected the changes in the benchmark prices, but were also impacted by an over-supply of product which resulted in realized prices being 21 percent lower compared to 2015.

Natural Gas Prices Excluding Realized Commodity Risk Management



	Three months ended						Nine months ended
(Cdn$)	Sept 30, 2016		Jun 30, 2016		Sept 30, 2015		Sept 30, 2016		Sept 30, 2015
Average Benchmark Prices
NYMEX gas (per MMBtu)	3.64		2.89		3.62		3.09		3.48
AECO monthly gas (per MMBtu)	2.20		1.25		2.83		1.85		2.81
Differential to NYMEX
AECO differential (per MMBtu)	(1.44	)	(1.64	)	(0.79	)	(1.24	)	(0.67	)
Average Sales Price
Natural gas (per Mcf) ⁽¹⁾	2.37		1.51		3.02		2.01		3.15


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

The U.S. based NYMEX natural gas price continued to recover during the third quarter of 2016, as an unusually warm summer impacted the supply/demand fundamentals in the U.S. contributing to the price increase. Third quarter of 2016 NYMEX gas price averaged Cdn$3.64/MMBtu, an increase of 26 percent compared to the second quarter of 2016. Third quarter of 2016 prices remained unchanged compared to the same period last year, while year to date 2016 prices declined 11 percent compared to 2015. The lower prices were primarily a function of weaker demand in the first half of 2016, coupled with an oversupply of natural gas across much of North America.

Similarly, Western Canadian natural gas prices increased substantially in the third quarter of 2016 with the AECO monthly gas price averaging Cdn$2.20/MMBtu, representing an increase of 76 percent compared to the second quarter of 2016. The resumption of production in oil sands operations in Fort McMurray, coupled with stronger demand across the continent were the primary drivers behind the increase quarter over quarter. However, third quarter and year to date 2016, AECO prices continued to be under pressure, trading down 22 percent and 34 percent, respectively compared to the same periods in 2015. Transportation issues and lack of take-away capacity from the major producing centers in British Columbia, coupled with record inventories have resulted in significant discounts for Western Canadian natural gas compared to U.S. natural gas. These factors together with the negative impact of the Fort McMurray fires on gas demand in the second quarter, have resulted in the discount to NYMEX increasing substantially when compared to the same periods in 2015.

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

Pengrowth’s third quarter of 2016 average sales price for natural gas, before the impacts of commodity risk management activities, increased 57 percent from the second quarter of 2016, reflecting the improvement in benchmark pricing and a narrowing of the AECO price differential compared to NYMEX. Third quarter and year to date 2016 natural gas realized prices were lower by 22 percent and 36 percent, respectively, compared to the same periods last year, primarily due to the reasons mentioned above.



PENGROWTH Third Quarter 2016 Management's Discussion and Analysis		11

Total Average Sales Prices



	Three months ended			Nine months ended
($/boe)	Sept 30, 2016	Jun 30, 2016	Sept 30, 2015	Sept 30, 2016	Sept 30, 2015
Average sales price	28.45	26.32	30.75	24.73	32.94
Other production income including sulphur	0.25	0.25	0.27	0.27	0.46
Total oil and gas sales price	28.70	26.57	31.02	25.00	33.40
Realized commodity risk management gain (loss) ⁽¹⁾	20.58	14.93	12.38	19.42	11.57
Total oil and gas sales price including realized commodity risk management	49.28	41.50	43.40	44.42	44.97


⁽¹⁾	Third quarter and year to date 2016 include $41.6 million or $8.20/boe and $2.62/boe, respectively, related to the early settlement of 2018/2019 commodity risk management contracts.

Pengrowth’s third quarter of 2016 average realized sales price, before the effects of commodity risk management activities, of $28.45/boe increased 8 percent from the second quarter of 2016 reflecting the increase in the NGL and natural gas benchmark prices. Third quarter and year to date 2016 average realized sales price, before the effects of commodity risk management activities, declined 7 percent and 25 percent, respectively, compared to the same periods last year reflecting the 2016 declines in benchmark pricing relative to 2015.

Realized Commodity Risk Management Gains (Losses)



	Three months ended			Nine months ended
($ millions except per unit amounts)	Sept 30, 2016	Jun 30, 2016	Sept 30, 2015	Sept 30, 2016	Sept 30, 2015
Oil risk management gain (loss) ⁽¹⁾	75.8	54.6	76.7	241.9	206.2
$/bbl ^{(1) (2)}	31.20	22.02	23.05	31.72	23.42
Natural gas risk management gain (loss) ⁽³⁾	28.6	22.5	7.8	66.6	23.1
$/Mcf ⁽³⁾	2.40	1.90	0.48	1.80	0.45
Total realized commodity risk management gain (loss) ⁽⁴⁾	104.4	77.1	84.5	308.5	229.3
$/boe ⁽⁴⁾	20.58	14.93	12.38	19.42	11.57


⁽¹⁾	Third quarter and year to date 2016 include $24.3 million or $10.00/bbl and $3.19/bbl, respectively, related to the early settlement of 2018 oil risk management contracts.


⁽²⁾	Includes light and heavy oil.


⁽³⁾	Third quarter and year to date 2016 include $17.3 million or $1.45/Mcf and $0.47/Mcf, respectively, related to the early settlement of 2018/2019 natural gas risk management contracts.


⁽⁴⁾	Third quarter and year to date 2016 include $41.6 million or $8.20/boe and $2.62/boe, respectively, related to the early settlement of 2018/2019 commodity risk management contracts.

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

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

A realized commodity risk management gain of $104.4 million or $20.58/boe was recorded in the third quarter of 2016, compared to a gain of $77.1 million or $14.93/boe in the second quarter of 2016. The higher realized gain in the third quarter of 2016 was primarily due to $41.6 million from the early settlement of 2018 and 2019 risk management contracts partly offset by lower natural gas risk management gains driven by an increase in the natural gas benchmark prices.

Third quarter of 2016 realized risk management gains increased $19.9 million compared to the same period last year also driven by the early settlement of 2018 and 2019 risk management contracts, partly offset by lower volumes and contracted prices for oil risk management period over period.



PENGROWTH Third Quarter 2016 Management's Discussion and Analysis		12

Year to date 2016 realized risk management gains increased $79.2 million compared to 2015 also mainly driven by the early settlement of 2018 and 2019 risk management contracts for $41.6 million, in addition to the impact of lower oil and natural gas benchmark prices year over year.

Changes in Fair Value of Commodity Risk Management Contracts



	Three months ended					Nine months ended
($ millions)	Sept 30, 2016		Jun 30, 2016		Sept 30, 2015	Sept 30, 2016		Sept 30, 2015
Fair value of commodity risk management assets (liabilities) at period end	51.1		136.0		335.2	51.1		335.2
Less: Fair value of commodity risk management assets (liabilities) at beginning of period	136.0		360.3		214.7	370.5		421.1
Increase (decrease) in fair value of commodity risk management contracts for the period	(84.9	)	(224.3	)	120.5	(319.4	)	(85.9	)

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

Pengrowth recorded a decrease in the fair value of commodity risk management contracts of $84.9 million in the third quarter of 2016 as the fair value of commodity risk management assets of $51.1 million at September 30, 2016 decreased relative to June 30, 2016. The assets decreased at September 30, 2016 primarily as a result of the actual settlements of contracts, or realized commodity risk management gains, of $104.4 million in the third quarter of 2016, including the $41.6 million from the early settlement of 2018 and 2019 contracts.

Pengrowth recorded a $319.4 million decrease in the fair value of commodity risk management contracts for the nine months ended September 30, 2016 as fair value of commodity risk management assets decreased at September 30, 2016 relative to the beginning of the period. This was also primarily a result of the settlements of contracts, or realized commodity risk management gains, of $308.5 million in 2016.



PENGROWTH Third Quarter 2016 Management's Discussion and Analysis		13

Forward Contracts - Commodity and Power Risk Management

Pengrowth uses primarily crude oil and natural gas swaps to manage its exposure to commodity price fluctuations. In addition, financial and physical contracts are sometimes used to manage oil price differentials. These contracts, as well as the power risk management contracts in place at September 30, 2016, are summarized in the following table:



Crude Oil Swaps
Reference point	Remaining Term	Volume (bbl/d)	% of total 2016 oil production Guidance ⁽¹⁾	Price/bbl ($Cdn) ⁽²⁾
WTI	Q4 2016	23,000	81%	83.27
WTI	2017	18,500	65%	65.54
Crude Oil Differential Swaps
Reference point	Remaining Term	Volume (bbl/d)	% of total 2016 oil production Guidance ⁽¹⁾	Price/bbl ($Cdn)
Edmonton Light Sweet	Q4 2016	7,000	25%	Cdn WTI less $6.85
Western Canada Select	Q4 2016	8,000	28%	Cdn WTI less $18.32
Natural Gas Swaps
Reference point	Remaining Term	Volume (MMBtu/d)	% of 2016 natural gas production Guidance	Price/MMBtu ($Cdn)
AECO	Q4 2016	127,955	99%	3.30
AECO	2017	104,811	81%	3.37
Power
Reference point	Remaining Term	Volume (MW)	% of estimated power purchases	Price/MWh ($Cdn)
AESO	Q4 2016	20	32%	44.13


⁽¹⁾	Includes light and heavy crude oil.


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

Given the low commodity price environment and Pengrowth's 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 is expected to revert to the previous limit of 65 percent for a rolling 1 to 24 month period, 50 percent for a rolling 25 to 48 month period, and 25 percent for a rolling 49 to 60 month period.

As at September 30, 2016, Pengrowth's Board has authorized it to sell forward its production and purchase risk management contracts by product volume or power purchases as follows:



Forward Period	Percent of Estimated Production	Forward Period	Percent of Estimated Power Purchases
1 - 27 Months	Up to 90%	1 - 24 Months	Up to 80%
28 - 48 Months	Up to 50%	25 - 36 Months	Up to 50%
49 - 60 Months	Up to 25%	37 - 60 Months	Up to 25%

As a result of the 2015 divestment program, 2016 natural gas risk management contracts represent over 90 percent of 2016 production Guidance. Exceeding the 90 percent limit has also been approved by Pengrowth's Board.

See the Commodity Price Contracts section in Note 11 to the September 30, 2016 unaudited Consolidated Financial Statements for more information.



PENGROWTH Third Quarter 2016 Management's Discussion and Analysis		14

Commodity Price Sensitivity on Risk Management Contracts as at September 30, 2016



($ millions)
Oil swaps	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	(8.8	)	8.8
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	(1.4	)	1.4
Natural gas swaps	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	(12.5	)	12.5

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

If each commodity risk management contract were to have settled at September 30, 2016, revenue and cash flow would have been $51.1 million higher than if the risk management contracts were not in place based on the estimated fair value of the risk management contracts at period end. The $51.1 million is composed of net assets of $53.2 million relating to risk management contracts expiring within one year and net liabilities of $2.1 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.

OIL AND GAS SALES EXCLUDING REALIZED COMMODITY RISK MANAGEMENT

Oil and Gas Sales Contribution Analysis

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



	Three months ended						Nine months ended
($ millions except percentages)	Sept 30, 2016	% of total	Jun 30, 2016	% of total	Sept 30, 2015	% of total	Sept 30, 2016	% of total	Sept 30, 2015	% of total
Light oil	54.2	37	56.5	41	79.0	37	157.7	40	258.4	39
Heavy oil	47.7	33	48.1	35	67.1	32	119.2	30	171.5	26
Natural gas liquids	14.2	10	13.4	10	14.4	7	41.6	10	59.9	9
Natural gas	28.2	19	17.9	13	49.5	23	74.3	19	162.8	25
Other income including sulphur	1.3	1	1.3	1	1.9	1	4.2	1	9.1	1
Total oil and gas sales ⁽¹⁾	145.6		137.2		211.9		397.0		661.7


⁽¹⁾	Excludes realized commodity risk management.



PENGROWTH Third Quarter 2016 Management's Discussion and Analysis		15

Price and Volume Analysis

Quarter ended September 30, 2016 versus Quarter ended June 30, 2016

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, 2016 ⁽¹⁾	56.5		48.1		13.4		17.9	1.3	137.2
Effect of change in product prices and differentials	(0.4	)	0.1		1.8		10.2	—	11.7
Effect of change in sales volumes	(1.9	)	(0.5	)	(1.0	)	0.1	—	(3.3	)
Other	—		—		—		—	—	—
Quarter ended September 30, 2016 ⁽¹⁾	54.2		47.7		14.2		28.2	1.3	145.6


⁽¹⁾	Excludes realized commodity risk management.


⁽²⁾	Primarily sulphur sales.

Light oil sales decreased 4 percent in the third quarter of 2016 compared to the second quarter of 2016 driven by lower light oil sales volumes. Third quarter of 2016 heavy oil sales remained relatively constant compared to the second quarter of 2016. NGL sales increased 6 percent from the second quarter of 2016 primarily due to an increase in average sales prices partly offset by lower sales volumes. Natural gas sales increased 58 percent compared to the second quarter of 2016 driven by higher natural gas benchmark prices.

Quarter ended September 30, 2016 versus Quarter ended September 30, 2015

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



($ millions)	Light oil		Heavy oil		NGLs		Natural gas		Other ⁽²⁾		Total
Quarter ended September 30, 2015 ⁽¹⁾	79.0		67.1		14.4		49.5		1.9		211.9
Effect of change in product prices and differentials	(2.3	)	(2.0	)	1.9		(7.7	)	—		(10.1	)
Effect of change in sales volumes	(22.5	)	(17.4	)	(2.1	)	(13.6	)	—		(55.6	)
Other	—		—		—		—		(0.6	)	(0.6	)
Quarter ended September 30, 2016 ⁽¹⁾	54.2		47.7		14.2		28.2		1.3		145.6


⁽¹⁾	Excludes realized commodity risk management.


⁽²⁾	Primarily sulphur sales.

Light oil sales decreased 31 percent in the third quarter of 2016 compared to the same period in 2015 mainly due to lower light oil sales volumes combined with a 4 percent decrease in the Edmonton par light oil benchmark price. Third quarter of 2016 heavy oil sales decreased 29 percent compared to the same period last year resulting from a decrease in heavy oil sales volumes from asset dispositions, combined with a 6 percent decrease in the WCS heavy oil benchmark price. NGL sales remained relatively constant compared to the third quarter of 2015. Natural gas sales decreased 43 percent due to lower natural gas sales volumes and significantly lower natural gas benchmark prices.

Nine Months ended September 30, 2016 versus Nine Months ended September 30, 2015

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



($ millions)	Light oil		Heavy oil		NGLs		Natural gas		Other ⁽²⁾		Total
Nine months ended September 30, 2015 ⁽¹⁾	258.4		171.5		59.9		162.8		9.1		661.7
Effect of change in product prices and differentials	(26.5	)	(58.9	)	(11.2	)	(41.8	)	—		(138.4	)
Effect of change in sales volumes	(74.2	)	6.6		(7.1	)	(46.7	)	—		(121.4	)
Other	—		—		—		—		(4.9	)	(4.9	)
Nine months ended September 30, 2016 ⁽¹⁾	157.7		119.2		41.6		74.3		4.2		397.0


⁽¹⁾	Excludes realized commodity risk management.


⁽²⁾	Primarily sulphur sales.

Year to date 2016 light oil sales decreased 39 percent compared to the same period in 2015 resulting from lower light oil sales volumes combined with a 14 percent decrease in the Edmonton par light oil benchmark price. Heavy oil sales decreased 30 percent resulting from a 23 percent decrease in the WCS heavy oil benchmark price partly offset by incremental Lindbergh production volumes. NGL sales decreased 31 percent driven by the impact of lower commodity



PENGROWTH Third Quarter 2016 Management's Discussion and Analysis		16

prices and lower sales volumes. Natural gas sales decreased 54 percent due to lower natural gas sales volumes and significantly lower natural gas benchmark prices.

ROYALTY EXPENSES



($ millions except per boe amounts and percentages)	Three months ended			Nine months ended
($ millions except per boe amounts and percentages)	Sept 30, 2016	Jun 30, 2016	Sept 30, 2015	Sept 30, 2016	Sept 30, 2015
Royalty expenses	10.0	7.8	19.1	25.9	70.4
$/boe	1.97	1.51	2.80	1.63	3.55
Royalties as a percent of oil and gas sales (%) ⁽¹⁾	6.9	5.7	9.0	6.5	10.6


⁽¹⁾	Excludes 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, that being the date that commerciality was declared.

The applicable Lindbergh Phase 1 royalty rates are price sensitive and they change depending on whether the project is pre-payout or post-payout. The Lindbergh Phase 1 project is currently in pre-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.

Third quarter of 2016 royalties as a percentage of sales increased to 6.9 percent from 5.7 percent in the second quarter of 2016 mainly driven by a third quarter increase in light oil par prices and NGL reference prices as prescribed by the Alberta Energy and used in determining crown royalty volumes. Also contributing to the third quarter of 2016 increase in royalty rate was the absence of a favourable prior year SOEP royalty true-up recorded in the second quarter of 2016.

Third quarter and year to date 2016 royalties as a percentage of sales decreased to 6.9 percent and 6.5 percent, respectively, from 9.0 percent and 10.6 percent in 2015 impacted by lower commodity prices in 2016, favourable prior year adjustments as well as inclusion of the Lindbergh Phase 1 royalties as of April 1, 2015. Partially offsetting this trend on a year to date basis was an unfavourable thirteenth month adjustment relating to Gas Cost Allowance ("GCA") recorded in the second quarter of 2016.

OPERATING EXPENSES



($ millions except per boe amounts)	Three months ended			Nine months ended
($ millions except per boe amounts)	Sept 30, 2016	Jun 30, 2016	Sept 30, 2015	Sept 30, 2016	Sept 30, 2015
Operating expenses	68.6	66.7	91.0	205.4	290.7
$/boe	13.52	12.92	13.32	12.93	14.67

Third quarter of 2016 operating expenses increased $1.9 million or 3 percent compared to the second quarter of 2016 driven by the Carson Creek turnaround costs, maintenance and integrity work as well as higher utility costs. This was largely offset by the absence of operating expenses related to the second quarter turnaround at Olds. On a per boe basis, third quarter of 2016 operating expenses increased $0.60/boe compared to the second quarter of 2016 primarily due to the above mentioned increases in costs.

Third quarter and year to date 2016 operating expenses decreased $22.4 million or 25 percent and $85.3 million or 29 percent, respectively, compared to the same periods in 2015. This was due to the absence of expenses related to divested properties and lower utility costs combined with reduced activity and lower third party service rates. Partly offsetting these decreases were 9 months of Lindbergh Phase 1 operating expenses included in year to date 2016 compared to only 6 months in the same period in 2015, as commerciality of Lindbergh Phase 1 was declared on April 1, 2015. On a per boe basis, third quarter of 2016 operating expenses increased $0.20/boe compared to the same period last year as the decrease in production volumes outpaced the decrease in costs. Year to date 2016 operating expenses per boe decreased $1.74/boe driven by lower costs and inclusion of Lindbergh Phase 1 operating expenses, which are lower than Pengrowth's average per boe operating expenses, partly offset by a decrease in production volumes.



PENGROWTH Third Quarter 2016 Management's Discussion and Analysis		17

TRANSPORTATION EXPENSES



($ millions except per boe amounts)	Three months ended			Nine months ended
($ millions except per boe amounts)	Sept 30, 2016	Jun 30, 2016	Sept 30, 2015	Sept 30, 2016	Sept 30, 2015
Transportation expenses	8.4	8.3	12.3	25.5	35.9
$/boe	1.66	1.61	1.80	1.61	1.82

Third quarter of 2016 transportation expenses were relatively unchanged from the second quarter of 2016.

Third quarter and year to date 2016 transportation expenses decreased $3.9 million and $10.4 million, respectively, compared to the same periods last year primarily due to the absence of costs related to direct marketing and delivery of natural gas volumes to the Chicago sales point combined with lower trucking expenses primarily at Lindbergh which was pipeline connected on July 1, 2015. These year to date decreases were partly offset by transportation expenses from Lindbergh Phase 1 incremental production.

On a per boe basis, third quarter of 2016 transportation expenses remained relatively unchanged compared to the second quarter of 2016. Third quarter and year to date 2016 transportation expenses per boe decreased $0.14/boe and $0.21/boe, respectively, compared to the same periods last year driven by lower transportation expenses, as described above, partly offset by lower production volumes in 2016.

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. As at September 30, 2016, Pengrowth has elected to sell approximately 77 percent of its production at market points beyond the wellhead, incurring transportation costs prior to custody transfer points. The transportation expenses are dependent upon third party rates and the distance the product travels prior to changing ownership or custody.



PENGROWTH Third Quarter 2016 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 for the period. Certain assumptions have been made in allocating operating expenses and royalty injection credits between products. Operating netbacks as presented below may not be comparable to similar measures presented by other companies, as there are no standardized measures.



Combined Netback Including Realized Commodity Risk Management ($/boe) ⁽¹⁾	Three months ended						Nine months ended
	Sept 30, 2016		Jun 30, 2016		Sept 30, 2015		Sept 30, 2016		Sept 30, 2015
Oil & gas sales (includes other income)	28.70		26.57		31.02		25.00		33.40
Royalties	(1.97	)	(1.51	)	(2.80	)	(1.63	)	(3.55	)
Operating expenses	(13.52	)	(12.92	)	(13.32	)	(12.93	)	(14.67	)
Transportation expenses	(1.66	)	(1.61	)	(1.80	)	(1.61	)	(1.82	)
Operating netback before realized commodity risk management	11.55		10.53		13.10		8.83		13.36
Realized commodity risk management ⁽²⁾	20.58		14.93		12.38		19.42		11.57
Operating netback	32.13		25.46		25.48		28.25		24.93

Light Oil Netback Excluding Realized Commodity Risk Management ($/bbl)
Sales	52.50		52.85		54.76		47.50		55.47
Royalties ⁽³⁾	(7.40	)	(4.37	)	(9.18	)	(5.02	)	(8.00	)
Operating expenses ⁽⁴⁾	(18.83	)	(12.82	)	(16.00	)	(16.46	)	(17.41	)
Transportation expenses	(1.68	)	(1.42	)	(1.66	)	(1.40	)	(1.97	)
Light oil operating netback	24.59		34.24		27.92		24.62		28.09
Heavy Oil Netback Excluding Realized Commodity Risk Management ($/bbl) ⁽¹⁾
Sales	34.13		34.10		35.60		27.69		41.38
Royalties ⁽⁵⁾	(0.71	)	0.03		(1.82	)	(0.48	)	(2.36	)
Operating expenses	(9.14	)	(7.91	)	(11.87	)	(8.60	)	(14.08	)
Transportation expenses	(2.86	)	(2.93	)	(2.41	)	(2.87	)	(2.51	)
Heavy oil operating netback	21.42		23.29		19.50		15.74		22.43
NGLs Netback Excluding Realized Commodity Risk Management ($/bbl)
Sales	21.62		18.93		18.79		19.74		25.05
Royalties	(4.75	)	(4.43	)	(4.69	)	(4.76	)	(8.96	)
Operating expenses	(15.37	)	(15.17	)	(13.89	)	(14.50	)	(14.74	)
NGLs operating netback	1.50		(0.67	)	0.21		0.48		1.35
Natural Gas Netback Excluding Realized Commodity Risk Management ($/Mcf)
Sales	2.37		1.51		3.02		2.01		3.15
Royalties ⁽⁶⁾	0.15		—		0.07		0.08		(0.04	)
Operating expenses	(2.20	)	(2.62	)	(2.13	)	(2.25	)	(2.24	)
Transportation expenses	(0.22	)	(0.23	)	(0.32	)	(0.23	)	(0.32	)
Natural gas operating netback ($/Mcf)	0.10		(1.34	)	0.64		(0.39	)	0.55
Natural gas operating netback ($/boe)	0.60		(8.04	)	3.84		(2.34	)	3.30
CONTRIBUTION BASED ON OPERATING NETBACKS
Light oil	44	%	69	%	46	%	60	%	51	%
Heavy oil	52	%	62	%	42	%	50	%	37	%
Natural gas liquids	2	%	(1	)%	—	%	1	%	1	%
Natural gas	2	%	(30	)%	12	%	(11	)%	11	%


⁽¹⁾	Includes Lindbergh operating results as of April 1, 2015.


⁽²⁾	Third quarter and year to date 2016 include $8.20/boe and $2.62/boe, respectively, related to the early settlement of 2018/2019 commodity risk management contracts.


⁽³⁾	Third quarter of 2016 light oil royalties impacted by an increase in light oil par prices.


⁽⁴⁾	Third quarter of 2016 impacted by turnaround costs, maintenance and integrity work.


⁽⁵⁾	Second quarter of 2016 includes a favourable adjustment relating to a prior year enhanced oil recovery incentive.


⁽⁶⁾	Natural gas royalties impacted by GCA and favourable adjustments to royalties as well as royalty incentives.



PENGROWTH Third Quarter 2016 Management's Discussion and Analysis		19

Pengrowth realized an operating netback, including commodity risk management, of $32.13/boe in the third quarter of 2016 representing a 26 percent increase compared to both the second quarter of 2016 and third quarter of 2015. This was primarily due to the impact of the realized risk management gains from both 2016 risk management contracts and early settlement of 2018 and 2019 commodity risk management contracts.

Year to date 2016 operating netback, including commodity risk management, increased 13 percent compared to the same period last year mainly resulting from lower royalties and operating expenses. Lower realized pricing was mostly mitigated by realized commodity risk management gains from both 2016 risk management contracts and early settlement of 2018 and 2019 commodity risk management contracts.

Lindbergh generated an operating netback of $21.72/bbl in the third quarter of 2016 slightly down from $22.69/bbl in the second quarter of 2016 driven by an increase in operating expenses from higher utility and pump replacement costs in the third quarter of 2016. The Lindbergh netback excludes risk management which is reported at the corporate level.

GENERAL AND ADMINISTRATIVE EXPENSES



	Three months ended				Nine months ended
($ millions except per boe amounts)	Sept 30, 2016	Jun 30, 2016	Sept 30, 2015		Sept 30, 2016	Sept 30, 2015
Cash G&A expenses ⁽¹⁾	14.8	19.0	24.2		52.6	71.2
$/boe	2.92	3.68	3.54		3.31	3.59
Non-cash G&A expenses ⁽¹⁾	2.9	2.8	1.4		9.4	10.4
$/boe	0.57	0.54	0.21		0.59	0.53
Total G&A ⁽¹⁾	17.7	21.8	25.6		62.0	81.6
$/boe	3.49	4.22	3.75		3.90	4.12

($ millions)
Cash G&A before share based compensation expense ⁽¹⁾	14.4	16.8	25.0		48.0	71.3

Share based compensation expense ⁽¹⁾:
Cash-settled share based compensation	0.4	2.2	(0.8	)	4.6	(0.1	)
Share-settled share based compensation	2.9	2.8	1.4		9.4	10.4
Total share based compensation expense	3.3	5.0	0.6		14.0	10.3
Total G&A ⁽¹⁾	17.7	21.8	25.6		62.0	81.6


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

Third quarter of 2016 cash G&A expenses of $14.8 million decreased $4.2 million compared to the second quarter of 2016 primarily due to lower professional fees and personnel costs combined with favourable adjustments to the cash-settled share based compensation expense. This was driven by the mark-to-market impact of Pengrowth's share price which decreased 12 percent from June 30, 2016 to September 30, 2016.

Third quarter and year to date 2016 cash G&A expenses decreased $9.4 million or 39 percent and $18.6 million or 26 percent, respectively, compared to the same periods last year primarily due to lower personnel costs, resulting from significant staff reductions in the second half of 2015, combined with lower professional fees, IT and office expenses. These decreases were partly offset by lower recoveries and an increase in the cash-settled share based compensation expense in 2016. The increase in the cash-settled share based compensation expense was due to expensing of the 2016 annual grants over the applicable vesting periods and the mark-to-market impact of the increase in Pengrowth's share price. The September 30, 2016 closing share price increased 103 percent relative to December 31, 2015, driving the reported cash-settled share based compensation expense up. However, no cash outlay will be made until the actual exercise. See Note 8 to the September 30, 2016 unaudited Consolidated Financial Statements for additional information on Pengrowth's cash-settled LTIP. The compensation costs associated with these plans are expensed over the applicable vesting periods.

Commencing in 2016, certain employees receive cash-settled LTIP in place of previously received share-settled LTIP. Cash-settled LTIP entitles the holder to a cash payment equivalent to the value of a number of Common Shares (including the reinvestment of deemed dividends, as applicable) which vest evenly over a period of three years or less.



PENGROWTH Third Quarter 2016 Management's Discussion and Analysis		20

On a per boe basis, third quarter of 2016 cash G&A expenses decreased $0.76/boe and $0.62/boe compared to the second quarter of 2016 and third quarter of 2015, respectively, due to lower cash G&A expenses. Year to date 2016 cash G&A per boe decreased $0.28/boe driven by lower expenses partly offset by lower production volumes in 2016.

The non-cash component of G&A represents the compensation expenses associated with Pengrowth’s share-settled LTIP. See Note 8 to the September 30, 2016 unaudited Consolidated Financial Statements for additional information on Pengrowth's share-settled LTIP. The compensation costs associated with these plans are expensed over the applicable vesting periods.

Third quarter of 2016 non-cash G&A expenses was essentially unchanged compared to the second quarter of 2016 and increased $1.5 million compared to the third quarter of 2015 primarily due to the absence of the favourable LTIP forfeiture adjustment related to staff reductions recorded in the third quarter of 2015.

Year to date 2016 non-cash G&A expenses decreased $1.0 million or 10 percent compared to 2015 due to lower share-settled grants combined with lower performance factors in 2016 and higher forfeiture rates related to 2015 staff reductions.

During the nine months ended September 30, 2016, $2.4 million (September 30, 2015 - $7.5 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, 2016	Jun 30, 2016	Sept 30, 2015	Sept 30, 2016	Sept 30, 2015
Depletion, depreciation and amortization	87.7	91.3	120.8	274.6	350.4
$/boe	17.29	17.68	17.69	17.29	17.68
Accretion	3.6	3.9	4.4	11.5	13.2
$/boe	0.71	0.76	0.64	0.72	0.67

Third quarter of 2016 DD&A expense decreased $3.6 million compared to the second quarter of 2016 primarily due to a 3 percent decrease in production volumes in the third quarter of 2016.

Third quarter and year to date 2016 DD&A expense decreased $33.1 million and $75.8 million compared to the same periods last year, respectively, due to lower net book values resulting from 2015 PP&E impairment charges combined with the absence of depletion related to divested properties.

Third quarter of 2016 ARO accretion expense remained relatively unchanged compared to the second quarter of 2016. Third quarter and year to date 2016 accretion expense decreased $0.8 million and $1.7 million compared to the same periods last year, respectively, resulting primarily from lower discount rates.

INTEREST AND FINANCING CHARGES



	Three months ended						Nine months ended
($ millions)	Sept 30, 2016		Jun 30, 2016		Sept 30, 2015		Sept 30, 2016		Sept 30, 2015
Interest and financing charges	27.1		27.1		29.3		81.5		87.8
Capitalized interest	(0.8	)	(0.7	)	(0.8	)	(2.3	)	(11.8	)
Total interest and financing charges	26.3		26.4		28.5		79.2		76.0

At September 30, 2016, Pengrowth had approximately $1.6 billion in total debt before working capital, composed of $1.5 billion of fixed rate debt (June 30, 2016 - $1.5 billion; September 30, 2015 - $1.6 billion), no credit facility borrowings (June 30, 2016 - nil; September 30, 2015 - $0.3 billion) and $0.1 billion of convertible debentures (June 30, 2016 - $0.1 billion; September 30, 2015 - $0.1 billion). Total fixed rate debt consists primarily of U.S. dollar denominated notes at a weighted average interest rate of 5.8 percent. The convertible debentures have a 6.25 percent coupon.

Third quarter of 2016 interest and financing charges, before capitalized interest, remained unchanged compared to the second quarter of 2016.

Third quarter 2016 interest and financing charges, before capitalized interest, decreased $2.2 million compared to the third quarter of 2015 mainly due to lower borrowings on the credit facilities in 2016, resulting from utilization of



PENGROWTH Third Quarter 2016 Management's Discussion and Analysis		21

disposition proceeds and surplus funds flow. Also contributing to the decrease was the absence of interest relating to the U.K. term debt repaid on December 1, 2015 partly offset by additional financing charges related to the finance lease of the co-generation facilities at Lindbergh, discussed in the Acquisitions and Dispositions section of this MD&A.

Year to date 2016 interest and financing charges, before capitalized interest, decreased $6.3 million compared to 2015 also due to lower borrowings on the credit facilities in 2016 and the absence of interest relating to the U.K. term debt repaid on December 1, 2015 combined with the gain on redemption of convertible debentures realized in 2016. These decreases were partly offset by higher Canadian equivalent interest expense on U.S. term debt, resulting from the weaker average Canadian Dollar and additional financing charges related to the finance lease of the co-generation facilities at Lindbergh.

Following declaration of commerciality at the Lindbergh project on April 1, 2015, Pengrowth ceased capitalizing interest on the first commercial phase of the 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, 2016, $2.3 million (September 30, 2015 - $11.8 million) of interest was capitalized on the Lindbergh project to PP&E using Pengrowth's weighted average cost of debt of 5.6 percent (September 30, 2015 - 5.4 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 $14.9 million in the third quarter of 2016, compared to deferred tax recoveries of $66.4 million and $78.5 million in the second quarter of 2016 and the third quarter of 2015, respectively. This is primarily due to temporary differences related to the change in fair value of commodity risk management contracts in the third quarter of 2016 and third quarter of 2015 PP&E impairment charges recorded.

See Note 6 to the September 30, 2016 unaudited Consolidated Financial Statements for additional information.

FOREIGN CURRENCY GAINS (LOSSES)



	Three months ended						Nine months ended
($ millions)	Sept 30, 2016		Jun 30, 2016		Sept 30, 2015		Sept 30, 2016		Sept 30, 2015
Currency exchange rate (Cdn$1 = U.S.$) at period end	0.76		0.77		0.75		0.76		0.75
Unrealized foreign exchange gain (loss) on U.S. dollar denominated debt ⁽¹⁾	(22.8	)	7.3		(95.8	)	81.6		(198.1	)
Unrealized foreign exchange gain (loss) on U.K. pound sterling denominated debt ⁽¹⁾	0.3		2.2		(3.7	)	5.1		(13.8	)
Total unrealized foreign exchange gain (loss) from translation of foreign denominated debt	(22.5	)	9.5		(99.5	)	86.7		(211.9	)
Unrealized gain (loss) on U.S. foreign exchange risk management contracts	12.9		(1.6	)	54.1		(53.9	)	(11.8	)
Unrealized gain (loss) on U.K. foreign exchange risk management contracts	(0.1	)	(2.1	)	4.1		(4.6	)	13.5
Total unrealized gain (loss) on foreign exchange risk management contracts	12.8		(3.7	)	58.2		(58.5	)	1.7
Net unrealized foreign exchange gain (loss)	(9.7	)	5.8		(41.3	)	28.2		(210.2	)
Net realized foreign exchange gain (loss) ⁽²⁾	0.5		0.7		(0.6	)	(0.3	)	91.2


⁽¹⁾	Includes both principal and interest.


⁽²⁾	Nine months ended September 30, 2015 amount includes $93.9 million related to the settlement of foreign exchange swap contracts.

As 90 percent of Pengrowth’s total debt before working capital is denominated in foreign currencies at September 30, 2016 the majority of Pengrowth’s unrealized foreign exchange gains and losses are attributable to the translation of this debt into Canadian dollars and changes in the fair value of the related foreign exchange swap contracts Pengrowth employs to manage this risk.

The gains or losses on foreign debt principal restatement each period are calculated by comparing the translated Canadian dollar balance of foreign currency denominated long term debt from one period to another. The magnitude 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 Third Quarter 2016 Management's Discussion and Analysis		22

U.S. Swap Contracts

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

At September 30, 2016, Pengrowth held a total of U.S.$920.0 million in foreign exchange swap contracts at a weighted average fixed rate of U.S.$0.78 per Cdn$1.



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

At September 30, 2016, the fair value of the U.S. foreign exchange derivative contracts was an asset of Cdn$23.3 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.

U.K. Swap Contracts

Pengrowth entered into foreign exchange risk management contracts when it issued the U.K. pound sterling term notes. At September 30, 2016, Pengrowth held the following contract fixing the Canadian dollar to the U.K. pound sterling exchange rate on the interest and principal of the U.K. pound sterling denominated debt maturing in October 2019:



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

At September 30, 2016, the fair value of the U.K. foreign exchange derivative contracts was a net asset of $1.5 million and has been included on the Consolidated Balance Sheets. Changes in the fair value of these contracts between Balance Sheet dates are reported on the Consolidated Statements of Income (Loss) as an unrealized foreign exchange (gain) loss.

Foreign Exchange Rate Sensitivity

At September 30, 2016, each Cdn$0.01 exchange rate change would result in approximately a Cdn$9.2 million pre-tax change in the fair value of the U.S. risk management contracts and a Cdn$0.2 million pre-tax change in the fair value of the U.K. risk management contracts.

ASSET RETIREMENT OBLIGATIONS - NET PRESENT VALUE

At September 30, 2016, Pengrowth's ARO liability increased by $149.7 million compared to December 31, 2015. This was primarily due to a change in the risk free discount rate from 2.3 percent at December 31, 2015 to 1.7 percent at September 30, 2016 which increased the ARO liability by $161.5 million. The rate change reflects a decrease in the 30 year Canadian Government long term bond rate which drives Pengrowth’s estimate of the ARO discount rate. Partly offsetting this increase were reductions resulting from property divestments and remediation spending.

Pengrowth has estimated the net present value of its total ARO to be $853.1 million as at September 30, 2016 (December 31, 2015 – $703.4 million), based on a total escalated future liability of $1.7 billion (December 31, 2015 – $1.7 billion). The majority of the costs are expected to be incurred between 2040 and 2080. A risk free discount rate of 1.7 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, 2016.



PENGROWTH Third Quarter 2016 Management's Discussion and Analysis		23

ACQUISITIONS AND DISPOSITIONS



	Three months ended					Nine months ended
($ millions)	Sept 30, 2016		Jun 30, 2016	Sept 30, 2015		Sept 30, 2016		Sept 30, 2015
Property acquisitions	(1.3	)	—	(0.9	)	(1.3	)	(0.9	)
Proceeds on property dispositions	2.2		34.6	3.1		49.6		27.1
Net cash proceeds from dispositions	0.9		34.6	2.2		48.3		26.2

Year to date 2016, Pengrowth had minimal acquisition activity and dispositions were primarily related to the successful sale and leaseback of the co-generation facilities at the Lindbergh thermal oil project in Cold Lake Alberta for proceeds of $35.0 million in the second quarter of 2016, and other minor dispositions partly offset by minor sales price adjustments to previously closed dispositions.

WORKING CAPITAL

Working capital surplus or deficiency is calculated as current assets less current liabilities per the Consolidated Balance Sheets.

At September 30, 2016, Pengrowth had a working capital deficiency of $505.7 million, as current liabilities included $524.5 million of senior unsecured notes and $126.7 million of convertible debentures which are due within one year. Excluding the current portions of the senior unsecured notes and convertible debentures, Pengrowth had a working capital surplus of $145.5 million, primarily from the $139.5 million cash balance.

At December 31, 2015, Pengrowth had a working capital surplus of $181.6 million which was a result of the current asset portion of the fair value of risk management contracts and receivables exceeding the current liabilities.

FINANCIAL RESOURCES AND LIQUIDITY

Cash On Hand

Credit Facilities

Pengrowth has in place a $1.0 billion revolving, committed credit facility (“Credit Facility”) supported by a syndicate of eleven international and domestic banks in addition to a $50 million demand facility (“Demand Facility”) issued by a large Canadian financial institution. The Credit Facility was renewed in March 2015 and matures in March 2019. Pengrowth can access the unutilized portion of the Credit Facility, provided it remains in compliance with all financial covenants.

Pengrowth's extendible revolving term Credit Facility had a $nil balance at September 30, 2016 (December 31, 2015 - $104.0 million) and $39.5 million of outstanding letters of credit (December 31, 2015 - $21.6 million). The Credit Facility includes an expansion feature of $250 million providing Pengrowth with up to $1.25 billion of notional credit capacity which can be extended at Pengrowth’s discretion any time prior to maturity, subject to syndicate approval. When utilized, the Credit Facility appears on the Consolidated Balance Sheets as long term debt.

Pengrowth's Demand Facility had a $nil balance at September 30, 2016 (December 31, 2015 - $2.5 million) and $1.0 million of outstanding letters of credit (December 31, 2015 - $1.4 million). When utilized, together with any overdraft amounts, the Demand Facility appears on the Consolidated Balance Sheets as a current liability in bank indebtedness, as applicable.

Together, these two facilities provided Pengrowth with approximately $1.0 billion of combined notional credit capacity at September 30, 2016, 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.



PENGROWTH Third Quarter 2016 Management's Discussion and Analysis		24

Financial Covenants

Pengrowth’s senior unsecured notes and credit facilities are subject to a number of covenants, all of which were met at all relevant times during the preceding twelve months and at September 30, 2016. Details of the calculations follow in the table below.

The Corporation's ratio of trailing twelve month senior debt to Adjusted EBITDA increased to 3.2 times at September 30, 2016 from 2.9 times at December 31, 2015 as the impact of a decrease in Adjusted EBITDA outweighed the decrease in senior debt for covenant purposes at September 30, 2016. Excluded from the calculation; however, was $139.5 million of cash on hand at September 30, 2016. The Corporation’s senior debt to total book capitalization was 52 percent at September 30, 2016, unchanged from December 31, 2015. Should a significant reduction in equity, such as from impairment charges or other losses occur in the future, the senior debt to total book capitalization covenant ratio of 55 percent could be exceeded in which case the effect of any such breach would be as outlined below. 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.

Pengrowth anticipates it will remain in compliance with its covenants for the remainder of 2016 and into the middle of 2017. However, absent an improvement in realizations for oil and natural gas, Pengrowth may not remain in compliance with certain financial covenants in its senior unsecured notes and credit facilities during the second half of 2017. Pengrowth is proactively in discussions with the lenders of its syndicated Credit Facility and with the holders of its senior term notes in an effort to seek covenant amendments to provide the Company with additional financial flexibility as it works to reduce its debt position. If the Company is unable to obtain a waiver or relaxation of its debt covenants and is not able to remain in compliance with them, the senior unsecured notes and credit facilities may become due on demand and the undrawn portion of the credit facilities would no longer be available to the Company. There are currently no drawings on the credit facilities.

During the third quarter of 2016, Pengrowth's cash on hand increased by $85.4 million to a total of $139.5 million at September 30, 2016. The Company has no scheduled debt maturities prior to the $126.7 million of convertible debentures which are due on March 31, 2017, and expects to have approximately $200 million of cash on hand at the end of 2016.

Pengrowth will continue with its marketing efforts on the assets it has recently had in the market, and all other monetization opportunities, including risk management contract monetization, will be pursued. The Company remains confident in its ability to complete additional transactions to further advance its debt reduction objectives.



PENGROWTH Third Quarter 2016 Management's Discussion and Analysis		25

Covenant Calculations



Twelve month trailing actual covenants ⁽¹⁾:		Sept 30, 2016		Dec 31, 2015		Limit
Senior debt before working capital to Adjusted EBITDA	=A÷D	3.2		2.9		< 3.5 times
Total debt before working capital to Adjusted EBITDA	=A÷D	3.2		2.9		< 4.0 times
Senior debt before working capital as a percentage of total book capitalization	=A÷B	52	%	52	%	< 55%
Adjusted EBITDA to interest expense	=D÷C	5.1		6.2		> 4 times
As at:
($ millions)		Sept 30, 2016		Dec 31, 2015		Change
Credit facilities ⁽²⁾		—		107.7		(107.7	)
Senior unsecured notes ⁽³⁾		1,526.6		1,611.8		(85.2	)
Convertible debentures ^{(3) (4)}		126.7		137.0		(10.3	)
Total debt before working capital ⁽³⁾		1,653.3		1,856.5		(203.2	)
Finance leases ⁽⁴⁾		38.2		4.3		33.9
Letters of credit ⁽⁴⁾		40.5		23.0		17.5
Senior debt before working capital for covenant purposes ^{(3) (4)}	A	1,732.0		1,883.8		(151.8	)

Total book capitalization ⁽⁵⁾	B	3,305.5		3,648.8		(343.3	)
Twelve months trailing:
($ millions)
Net income (loss)		(669.9	)	(1,093.1	)	423.2
Add (deduct):
Interest and financing charges	C	107.1		103.9		3.2
Deferred income tax expense (recovery)		(191.9	)	(222.7	)	30.8
Depletion, depreciation, amortization and accretion		394.9		472.4		(77.5	)
EBITDA		(359.8	)	(739.5	)	379.7
Add (deduct) other items:
Impairment		518.5		1,000.5		(482.0	)
(Gain) loss on disposition of properties		92.1		98.1		(6.0	)
Other non-cash items ⁽⁶⁾		292.5		284.3		8.2
Adjusted EBITDA	D	543.3		643.4		(100.1	)


⁽¹⁾	The actual covenants presented in the table reflect those closest to the limits. Calculations for each financial covenant are based on specific definitions within the agreements and contain adjustments, pursuant to the agreements, some of which cannot be readily replicated by referring to Pengrowth’s Consolidated Financial Statements.


⁽²⁾	Includes bank indebtedness, as applicable.


⁽³⁾	Includes current and long term portions, as applicable.


⁽⁴⁾	For the purposes of covenant calculations only, convertible debentures, letters of credit and finance leases are incorporated in senior and total debt before working capital for covenant purposes.


⁽⁵⁾	Total book capitalization includes senior debt before working capital for covenant purposes plus Shareholders' Equity per the Consolidated Balance Sheets.


⁽⁶⁾	Includes the impact of changes in fair value of commodity risk management contracts, unrealized foreign exchange on long term debt, and any other adjustments pursuant to the actual covenant calculations.



PENGROWTH Third Quarter 2016 Management's Discussion and Analysis		26

Total Debt Before Working Capital Continuity



(Cdn$ millions)	December 31, 2015 vs. September 30, 2016
Total debt before working capital at December 31, 2015 ⁽¹⁾	1,856.5
Increase (decrease) due to:
Foreign exchange impact of the stronger Canadian dollar on U.S. denominated debt	(80.7	)
Foreign exchange impact of the stronger Canadian dollar on U.K. denominated debt	(5.1	)
Credit facilities paid down in 2016	(107.7	)
Convertible debenture paid down in 2016	(10.2	)
Issue cost and premium amortization	0.5
Total increase (decrease)	(203.2	)
Total debt before working capital at September 30, 2016 ⁽¹⁾	1,653.3


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

As of September 30, 2016, Pengrowth's long term notes denominated in foreign currencies comprised 90 percent of the total debt before working capital. Each long term note is governed by a Note Purchase Agreement. These notes have fixed coupon rates and maturity dates between 2017 and 2024.

At September 30, 2016, total debt before working capital decreased $203.2 million compared to December 31, 2015, as per the table above. As the majority of Pengrowth's debt is denominated in U.S. dollars and U.K. pound sterling, the stronger period end Canadian dollar drove down reported senior debt before working capital relative to December 31, 2015. Pengrowth manages its foreign exchange exposure through swap contracts with the fair value reflected as a net asset of Cdn$24.8 million on the Consolidated Balance Sheets at September 30, 2016. This fair value is not reflected in the above table.

Despite lower commodity prices, drawings under the credit facilities decreased from $107.7 million at December 31, 2015 to $nil at September 30, 2016 as surplus funds flow and proceeds from divestment activities were used to pay down the outstanding credit facility balance.

In February 2016, Pengrowth commenced a Normal Course Issuer Bid ("NCIB") to purchase up to 10 percent or $13.7 million of face value of convertible debentures. Through September 30, 2016, Pengrowth repurchased $10.2 million of principal amount of convertible debentures. See Note 3 to the September 30, 2016 unaudited Consolidated Financial Statements for more information.

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, 2015 audited Consolidated Financial Statements for a description of the accounting policies for financial instruments and Note 11 to the September 30, 2016 unaudited Consolidated Financial Statements for additional information regarding the fair value of Pengrowth’s financial instruments.



PENGROWTH Third Quarter 2016 Management's Discussion and Analysis		27

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, 2016		Jun 30, 2016		Sept 30, 2015		Sept 30, 2016		Sept 30, 2015
Funds flow from operations ^{(1) (2)}	122.7		89.1		120.6		318.0		345.1
Dividends declared	—		—		21.8		—		95.5
Funds flow from operations less dividends declared	122.7		89.1		98.8		318.0		249.6
Per share	0.22		0.16		0.18		0.58		0.46
Payout ratio ^{(3) (4)}	—	%	—	%	18	%	—	%	28	%


⁽¹⁾	Funds flow from operations for the three and nine months ended September 30, 2016 includes $41.6 million related to the early settlement of 2018/2019 commodity risk management contracts.


⁽²⁾	Funds flow from operations for the nine months ended September 30, 2015 excludes $93.9 million related to the 2015 settlement of foreign exchange swap contracts as this was considered a financing activity.


⁽³⁾	Payout ratio is calculated as dividends declared divided by funds flow from operations.


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

As a result of the depleting nature of 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, and as applicable, through the sale of existing properties, issuance of 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 cash flow. Details of commodity risk management contracts are contained in Note 11 to the September 30, 2016 unaudited Consolidated Financial Statements.

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. In response to the low commodity price environment and near term price outlook, Pengrowth's Board of Directors suspended the quarterly payment of $0.01 per share on January 20, 2016. No cash dividend was paid in the first nine months of 2016. The Board will continue to review the dividend policy on a quarterly basis.



	Dividend amounts paid (Cdn$ per share)
Month	2016	2015
January	—	0.04
February	—	0.04
March	—	0.02
April	—	0.02
May	—	0.02
June	—	0.02
July	—	0.02
August	—	0.02
September	—	0.02
Total dividends paid per share	—	0.22



PENGROWTH Third Quarter 2016 Management's Discussion and Analysis		28

SUMMARY OF QUARTERLY RESULTS

The following table is a summary of quarterly information for 2016, 2015 and 2014:



2016	Q1		Q2		Q3
Oil and gas sales ($ millions) ⁽¹⁾	114.2		137.2		145.6
Net income (loss) ($ millions)	25.0		(173.4	)	(52.9	)
Net income (loss) per share ($)	0.05		(0.32	)	(0.10	)
Net income (loss) per share - diluted ($)	0.05		(0.32	)	(0.10	)
Adjusted net income (loss) ($ millions)	0.5		(16.5	)	18.6
Funds flow from operations ($ millions) ⁽²⁾	106.2		89.1		122.7
Dividends declared ($ millions)	—		—		—
Dividends declared per share ($)	—		—		—
Daily production (boe/d)	62,056		56,735		55,137
Total production (Mboe)	5,647		5,163		5,073
Average sales price ($/boe) ⁽¹⁾	19.94		26.32		28.45
Operating netback ($/boe) ⁽³⁾	27.31		25.46		32.13
2015	Q1		Q2		Q3		Q4
Oil and gas sales ($ millions) ⁽¹⁾	199.9		249.9		211.9		169.1
Net income (loss) ($ millions)	(160.5	)	(134.4	)	(329.6	)	(468.6	)
Net income (loss) per share ($)	(0.30	)	(0.25	)	(0.61	)	(0.86	)
Net income (loss) per share - diluted ($)	(0.30	)	(0.25	)	(0.61	)	(0.86	)
Adjusted net income (loss) ($ millions)	64.8		(38.9	)	(374.0	)	(463.4	)
Funds flow from operations ($ millions) ⁽⁴⁾	113.0		111.5		120.6		114.2
Dividends declared ($ millions)	42.9		30.8		21.8		5.5
Dividends declared per share ($)	0.08		0.06		0.04		0.01
Daily production (boe/d)	69,334		74,113		74,239		67,934
Total production (Mboe)	6,240		6,744		6,830		6,250
Average sales price ($/boe) ⁽¹⁾	31.39		36.58		30.75		26.56
Operating netback ($/boe) ⁽³⁾	25.37		23.98		25.48		25.07
2014	Q1		Q2		Q3		Q4
Oil and gas sales ($ millions) ⁽¹⁾	429.2		407.1		369.1		291.5
Net income (loss) ($ millions)	(116.2	)	(8.8	)	52.2		(506.0	)
Net income (loss) per share ($)	(0.22	)	(0.02	)	0.10		(0.95	)
Net income (loss) per share - diluted ($)	(0.22	)	(0.02	)	0.10		(0.95	)
Adjusted net income (loss) ($ millions)	(2.8	)	(24.8	)	3.4		(854.8	)
Funds flow from operations ($ millions)	139.5		121.4		129.0		115.8
Dividends declared ($ millions)	62.8		63.3		63.6		63.9
Dividends declared per share ($)	0.12		0.12		0.12		0.12
Daily production (boe/d)	75,102		73,823		72,472		71,802
Total production (Mboe)	6,759		6,718		6,667		6,606
Average sales price ($/boe) ⁽¹⁾	63.00		60.08		54.73		43.61
Operating netback ($/boe) ⁽³⁾	29.71		23.86		24.91		24.04


⁽¹⁾	Excludes realized commodity risk management.


⁽²⁾	Funds flow from operations for the three months ended September 30, 2016 includes $41.6 million related to early settlement of 2018/2019 commodity risk management contracts.


⁽³⁾	Includes realized commodity risk management.


⁽⁴⁾	First, second and fourth quarters of 2015 funds flow from operations exclude $84.1 million, $9.8 million and $0.2 million, respectively, related to the settlement of foreign exchange swap contracts as these were considered financing activities.

Third quarter of 2016 average sales price increased compared to the second and first quarters of 2016, but remained lower than most preceding quarters in 2015 and 2014, as per the table above, mostly driven by a decline in the benchmark prices. The impact of the declining benchmark prices on oil and gas sales has been offset somewhat by



PENGROWTH Third Quarter 2016 Management's Discussion and Analysis		29

the weakening Canadian dollar throughout the two year period.

Although oil and gas sales have declined significantly throughout 2016, 2015 and 2014, driven by a steep decline in the oil and natural gas benchmark prices, operating netbacks and funds flow from operations remained strong primarily due to realized commodity risk management gains.

Third quarter of 2016 production was lower than all of the preceding quarters of 2016, 2015 and 2014 resulting primarily from property dispositions and natural declines due to capital spending curtailments in the current low commodity price environment. In contrast, the third quarter of 2015 production was the highest quarterly production since the first quarter of 2014 resulting from inclusion and ramp up of the Lindbergh Phase 1 production.

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

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 24, 2016 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, 2016, 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, 2016 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, 2016, 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 2016 Management's Discussion and Analysis		30

Pengrowth Energy (PGH) Inactive 6-KSummary of Financial & Operating Results