Pengrowth Energy (PGH) 6-K Current report (foreign)

MANAGEMENT’S DISCUSSION & ANALYSIS

The following Management’s Discussion and Analysis ("MD&A") of financial results should be read in conjunction with the unaudited Financial Statements for the three and nine months ended September 30, 2014 of Pengrowth Energy Corporation ("Pengrowth" or the "Corporation"). This MD&A is based on information available to October 30, 2014.

Pengrowth’s third quarter and year to date results for 2014 are contained within this MD&A.

BUSINESS OF THE CORPORATION

Pengrowth is a Canadian resource company that is engaged in the production, development, exploration and acquisition of oil and natural gas assets.

FREQUENTLY RECURRING TERMS

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

ADVISORY REGARDING FORWARD-LOOKING STATEMENTS

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

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

By their very nature, forward-looking statements involve inherent risks and uncertainties, both general and specific, and risks that predictions, forecasts, projections and other forward-looking statements will not be achieved. We caution readers not to place undue reliance on these statements as a number of important factors could cause the actual

PENGROWTH Third Quarter 2014 Management's Discussion and Analysis 1

results to differ materially from the beliefs, plans, objectives, expectations and anticipations, estimates and intentions expressed in such forward-looking statements. These factors include, but are not limited to: the volatility of oil and gas prices; Canadian light and heavy oil differentials; production and development costs and capital expenditures; the imprecision of reserve estimates and estimates of recoverable quantities of oil, natural gas and liquids; Pengrowth's ability to replace and expand oil and gas reserves, ability to produce those reserves; production may be impacted by unforeseen events such as equipment and transportation failures and weather related issues; environmental claims and liabilities; incorrect assessments of value when making acquisitions; increases in debt service charges; the loss of key personnel; the marketability of production; defaults by third party operators; unforeseen title defects; fluctuations in foreign currency and exchange rates; inadequate insurance coverage; counterparty risk; compliance with environmental laws and regulations; changes in tax and royalty laws; Pengrowth's ability to access external sources of debt and equity capital; the implementation of new International Financial Reporting Standards ("IFRS"); and the implementation of greenhouse gas emissions legislation. Further information regarding these factors may be found under the heading "Business Risks" herein and under "Risk Factors" in Pengrowth's most recent Annual Information Form ("AIF"), and in Pengrowth’s most recent audited Financial Statements, management information circular, quarterly reports, material change reports and news releases. Copies of Pengrowth’s Canadian public filings are available on SEDAR at www.sedar.com. Pengrowth’s U.S. public filings, including the most recent annual report form 40-F as supplemented by its filings on form 6-K, are available 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 Financial Statements are prepared in accordance with IFRS. Management is required to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the unaudited Financial Statements and revenues and expenses for the period ended. Certain of these estimates may change from period to period resulting in a material impact on Pengrowth’s results. Pengrowth's ARO risk free discount rate changed from 3.25 percent to 2.7 percent (3.0 percent at June 30, 2014) during the first nine months of 2014 due to a decrease in the 30 year Canadian Government long term bond rate which drives Pengrowth's estimate of the ARO discount rate. There were no other changes to Pengrowth's critical accounting estimates in the nine months ended September 30, 2014. For more information refer to the December 31, 2013 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 in the Statements of Cash Flow is a useful supplemental measure as it provides an indication of the funds generated by Pengrowth’s principal business activities prior to consideration of changes in working capital and remediation expenditures. Pengrowth considers this to be a key measure of performance as it demonstrates its ability to generate cash flow necessary to fund dividends and capital investments.

NON-GAAP FINANCIAL MEASURES

This MD&A refers to certain financial measures that are not determined in accordance with IFRS. These measures do not have standardized meanings and may not be comparable to similar measures presented by other oil and gas companies. Measures such as operating netbacks do not have standardized meanings prescribed by GAAP. See the section of this MD&A entitled Operating Netbacks for a discussion of the calculation.

PENGROWTH Third Quarter 2014 Management's Discussion and Analysis 2

The current level of capital expenditures funded through retained cash flow, as compared to debt or equity, can be determined when it is compared to the difference in funds flow from operations and dividends paid as shown on the Statements of Cash Flow.

Management monitors Pengrowth’s capital structure using non-GAAP financial metrics. The two metrics are total debt to the trailing twelve months Earnings Before Interest, Taxes, Depletion, Depreciation, Amortization, Accretion, and other non-cash items ("Adjusted EBITDA") and total debt to total capitalization. Total debt is the sum of working capital and long term debt including convertible debentures as shown on the Balance Sheets, and total capitalization is the sum of total debt and shareholders’ equity.

Payout ratio and net payout ratio are terms used to evaluate financial flexibility and the capacity to fund dividends. Payout ratio is defined on a percentage basis as dividends declared divided by funds flow from operations. Net payout ratio is calculated as dividends declared net of proceeds from the Dividend Reinvestment Plan ("DRIP") divided by funds flow from operations. Management believes that, in addition to net income (loss), adjusted net income (loss) is a useful supplemental measure as it reflects the underlying performance of Pengrowth’s business activities by excluding the after tax effect of non-cash commodity, power and interest mark to market gains and losses, non-cash mark to market gains and losses on investments, unrealized foreign exchange gains and losses and gains on acquisitions, as applicable, that may significantly impact net income (loss) from period to period. Management believes that segregating G&A expenses into cash and non-cash expenses is useful to the reader, as non-cash expenses only affect net income (loss) but not funds flow from operations.

OPERATIONAL MEASURES

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

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

CURRENCY

All amounts are stated in Canadian dollars unless otherwise specified.

PENGROWTH Third Quarter 2014 Management's Discussion and Analysis 3

2014 GUIDANCE

The following table provides a summary of full year 2014 Guidance and actual results for the nine months ended September 30, 2014.

	Actual
	Year to date September 30, 2014	Full year 2014 Guidance
Production (boe/d)	73,789	71,000 - 73,000
Capital expenditures ($ millions)	645.2	740 - 770
Royalty expenses (% of sales)	18.0	16 - 18
Operating expenses ($/boe) (1)	15.93	15.20 - 15.80
Cash G&A expenses ($/boe) (1)	3.13	3.15 - 3.25

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

Year to date 2014 average production of 73,789 boe/d exceeds 2014 Guidance driven by performance of the new Cardium development wells partly offset by third party capacity constraints at Pine Creek, downtime at Sable Island and a minor property divestiture in Northern Alberta completed in the third quarter. Pengrowth is on plan to deliver near the top end of full-year production Guidance of 71,000 - 73,000 boe/d.

Year to date 2014 capital expenditures amounted to $645.2 million, including $361.9 million invested at Lindbergh. Pengrowth is on track to achieve the full year 2014 capital expenditures Guidance of $740 - $770 million.

Year to date 2014 royalty expenses as a percentage of sales were at the higher end of 2014 Guidance mainly due to prior year Gas Cost Allowance ("GCA") adjustments. Full year 2014 royalty expenses as a percentage of sales are expected to be within 2014 Guidance.

Year to date 2014 operating expenses of $15.93/boe exceeds 2014 Guidance due to planned turnaround activities in the second quarter of 2014. Pengrowth anticipates full year 2014 operating expenses per boe to be within 2014 Guidance.

Year to date 2014 cash G&A expenses of $3.13/boe are at the low end of 2014 Guidance of $3.15/boe - $3.25/boe.

FINANCIAL HIGHLIGHTS

	Three months ended					Nine months ended
($ millions except per boe amounts)	Sept 30, 2014	Jun 30, 2014		Sept 30, 2013		Sept 30, 2014		Sept 30, 2013
Production (boe/d)	72,472	73,823		83,275		73,789		86,938
Capital expenditures	191.9	219.6		176.2		645.2		456.1
Funds flow from operations	129.0	121.4		161.5		389.9		455.0
Operating netback ($/boe)(1)	24.91	23.86		27.10		26.17		25.41
Adjusted net income (loss)	3.4	(24.8	)	(108.2	)	(24.2	)	(146.5	)
Net income (loss)	52.2	(8.8	)	(107.3	)	(72.8	)	(225.8	)

⁽¹⁾  Including realized commodity risk management.

PENGROWTH Third Quarter 2014 Management's Discussion and Analysis 4

Funds Flow from Operations

($ millions)	Q2/14 vs. Q3/14			% Change		Q3/13 vs. Q3/14			% Change		YTD 2013 vs. 2014			% Change
Funds flow from operations for comparative period	Q2/14	121.4				Q3/13	161.5				YTD 2013	455.0
Increase (decrease) due to:
Volumes		(5.8	)	(5	)		(66.6	)	(41	)		(204.3	)	(45	)
Prices including differentials		(32.9	)	(27	)		(2.4	)	(1	)		163.2		36
Realized commodity risk management		18.3		15			(3.2	)	(2	)		(78.5	)	(17	)
Other income including sulphur		0.7		1			(1.5	)	(1	)		(3.2	)	(1	)
Royalties		12.7		10			7.1		4			(5.1	)	(1	)
Expenses:
Operating		12.1		10			23.2		14			52.4		12
Cash G&A		(1.2	)	(1	)		(0.6	)	—			3.0		1
Interest & financing		1.9		2			6.5		4			15.9		3
Other expenses including transportation		1.8		1			5.0		3			(8.5	)	(2	)
Net change		7.6		6			(32.5	)	(20	)		(65.1	)	(14	)
Funds flow from operations	Q3/14	129.0				Q3/14	129.0				YTD 2014	389.9

Third quarter of 2014 funds flow from operations increased 6 percent compared to the second quarter of 2014 despite decreases in commodity prices in the third quarter of 2014. The increase is a result of lower realized commodity risk management losses, lower royalties and operating expenses.

Third quarter of 2014 funds flow from operations decreased 20 percent compared to the same period last year largely due to a decrease in volumes associated with the 2013 property dispositions partly offset by lower operating expenses and royalties.

Year to date 2014 funds flow from operations decreased 14 percent compared to the same period in 2013 mainly due to lower volumes from 2013 property dispositions and an increase in realized commodity risk management losses partly offset by higher commodity prices and lower operating expenses year over year.

Net Income (Loss)

Pengrowth recorded net income of $52.2 million in the third quarter of 2014 representing a $61.0 million improvement compared to a net loss of $8.8 million in the second quarter of 2014.This was a result of higher funds flow from operations and an unrealized gain on commodity risk management partly offset by an unrealized foreign exchange loss in the third quarter of 2014. Third quarter of 2014 net income of $52.2 million improved $159.5 million compared to a net loss of $107.3 million in the third quarter of 2013 resulting from an unrealized gain on commodity risk management and a gain on disposition of properties versus losses recorded in the third quarter of 2013 partly offset by an unrealized foreign exchange loss in the current quarter, deferred income tax expense versus a recovery and a decrease in funds flow from operations.

Year to date 2014 net loss of $72.8 million decreased $153.0 million compared to a net loss of $225.8 million for the same period last year predominantly due to a gain on disposition of properties year to date 2014 versus a loss in 2013 and reduced current year DD&A partly offset by a decrease in funds flow from operations.

PENGROWTH Third Quarter 2014 Management's Discussion and Analysis 5

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, 2014		Jun 30, 2014		Sept 30, 2013		Sept 30, 2014		Sept 30, 2013
Net income (loss)	52.2		(8.8	)	(107.3	)	(72.8	)	(225.8	)
Excluded non-cash items in net income (loss):
Unrealized gain (loss) on commodity, power and interest risk management	121.1		(12.6	)	(17.9	)	(1.7	)	(47.9	)
Unrealized foreign exchange gain (loss)(1)	(42.7	)	29.1		16.4		(49.2	)	(34.8	)
Unrealized loss on investments	(5.0	)	—		—		(5.0	)	(15.0	)
Tax effect on non-cash items above	(24.6	)	(0.5	)	2.4		7.3		18.4
Total excluded	48.8		16.0		0.9		(48.6	)	(79.3	)
Adjusted net income (loss)	3.4		(24.8	)	(108.2	)	(24.2	)	(146.5	)

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

The following table represents a continuity of adjusted net income (loss):
($ millions)	Q2/14 vs. Q3/14			Q3/13 vs. Q3/14			YTD 2013 vs. 2014
Adjusted net loss for comparative period	Q2/14	(24.8	)	Q3/13	(108.2	)	YTD 2013	(146.5	)
Funds flow from operations increase (decrease)		7.6			(32.5	)		(65.1	)
DD&A and accretion expense decrease		2.6			7.6			55.8
Loss on property dispositions decrease		30.9			173.7			169.6
Other		0.4			0.7			(0.5	)
Estimated tax on above		(13.3	)		(37.9	)		(37.5	)
Net change		28.2			111.6			122.3
Adjusted net income (loss)	Q3/14	3.4		Q3/14	3.4		YTD 2014	(24.2	)

Pengrowth posted adjusted net income of $3.4 million in the third quarter of 2014 representing an improvement of $28.2 million compared to the second quarter of 2014 primarily due to reduced losses on disposition of properties. Third quarter of 2014 adjusted net income of $3.4 million represents an improvement of $111.6 million compared to the third quarter of 2013 also due to reduced losses on disposition of properties partly offset by a decrease in funds flow from operations.

Year to date 2014 adjusted net loss of $24.2 million represents an improvement of $122.3 million compared to the same period in 2013 due to reduced losses on disposition of properties and lower DD&A partly offset by a decrease in funds flow from operations.

PENGROWTH Third Quarter 2014 Management's Discussion and Analysis 6

Price Sensitivity

The following table illustrates the sensitivity of funds flow from operations to changes in commodity prices after taking into account Pengrowth’s risk management contracts and outlook on oil differentials:

						Estimated Impact on 12 Month Funds Flow
COMMODITY PRICE ENVIRONMENT (1)		Assumption		Change		(Cdn$ millions)
West Texas Intermediate Oil (2) (3)	U.S.$/bbl	$	80.28	$	1.00
Light oil						6.5
Heavy oil						5.1
Oil risk management (4)						(10.2	)
NGLs						2.4
Net impact of U.S.$1/bbl increase in WTI						3.8
Oil differentials (5)
Light oil	U.S.$/bbl	$	6.78	$	1.00	(6.5	)
Heavy oil	U.S.$/bbl	$	23.99	$	1.00	(5.1	)
Net impact of U.S.$1/bbl increase in differentials						(11.6	)
AECO Natural Gas (2) (3)	Cdn$/Mcf	$	3.90	$	0.10
Natural gas						5.6
Natural gas risk management (4)						(3.1	)
Net impact of Cdn$0.10/Mcf increase in AECO						2.5

⁽¹⁾  Calculations are performed independently and are not indicative of actual results when multiple variables change at the same time.

⁽²⁾  Commodity price is based on an estimation of the 12 month forward price curve at October 15, 2014 and does not include the impact of risk management contracts.

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

⁽⁴⁾  Includes risk management contracts as at October 15, 2014.

⁽⁵⁾  Includes a light oil differential of approximately 8% of WTI per bbl and a heavy oil differential of approximately 30% of WTI per bbl.

PENGROWTH Third Quarter 2014 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, 2014	Jun 30, 2014	Sept 30, 2013		Sept 30, 2014	Sept 30, 2013
Drilling, completions and facilities
Lindbergh	110.5	124.1	93.9		361.9	170.4
Non-thermal	61.5	73.4	62.7		221.6	227.0
Total drilling, completions and facilities	172.0	197.5	156.6		583.5	397.4
Land & seismic acquisitions (1)	0.3	0.5	(0.1	)	5.4	1.8
Maintenance capital	19.1	21.6	19.6		55.0	55.3
Development capital	191.4	219.6	176.1		643.9	454.5
Other capital	0.5	—	0.1		1.3	1.6
Capital expenditures	191.9	219.6	176.2		645.2	456.1

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

Third quarter of 2014 capital expenditures were $191.9 million following the strategy of selecting and executing projects that maximize cash flow and provide the highest rates of return while continuing to invest in the first commercial phase of the Lindbergh thermal project. Approximately 90 percent of the third quarter of 2014 capital expenditures were invested in drilling, completions and facilities, with the majority of the remaining 10 percent spent on maintenance capital. Year to date 2014 capital spending amounted to $645.2 million of which approximately 90 percent was invested in drilling, completions and facilities with the remaining 10 percent invested in maintenance, land, seismic and other capital.

Pengrowth invested 58 percent of the third quarter of 2014 capital expenditures in the Lindbergh commercial project.

Also in the quarter, Pengrowth participated in the drilling of 23 (15.0 net) non-thermal wells in other areas, all of which were successful.

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 which result in higher netbacks compared to many thermal projects. A two well pair pilot project at Lindbergh was brought on stream in February 2012 and the results continue to exceed type curve expectations. The 12,500 bbl/d first commercial phase of Lindbergh was sanctioned by Pengrowth’s Board of Directors in January 2013 and Alberta Environmental Protection and Enhancement Act approval was received for the first commercial phase in July 2013. The Environmental Impact Assessment ("EIA") application for the Lindbergh expansion to 30,000 bbl/d was submitted to the regulators in December 2013.

Lindbergh is expected to provide Pengrowth with the potential to develop annual production of up to 50,000 bbl/d of bitumen within five years. This is expected to be strong netback production, low cost, with low decline rates, long reserve life and low sustaining capital requirements, resulting in a sustainable total return model that supports growth in cash flow per share and the ability to fund an attractive dividend.

Pengrowth has entered into a transportation agreement with Husky Energy for delivery of production from the initial commercial phase of Lindbergh to Hardisty, Alberta, with options to nominate future volumes as Lindbergh expands. Pengrowth will retain maximum flexibility in regards to transportation options at Lindbergh and will be able to utilize both rail and pipeline to move production to markets and maximize netbacks.

During the third quarter of 2014, $110.5 million was invested at Lindbergh, bringing the year to date spending to $361.9 million.  In October, commissioning and start-up activities commenced at the 12,500 bbl/d Lindbergh commercial facility. It is anticipated that steam will be circulated through the well pairs starting in early December. Using the pilot ramp up

PENGROWTH Third Quarter 2014 Management's Discussion and Analysis 8

 ��                                                              

as an analog, first oil is expected in January of 2015, but revenue and associated costs will continue to be capitalized until commerciality is declared, currently anticipated to be late in the first quarter of 2015.

Operations at the pilot project continued to show strong results during the third quarter of 2014 with combined field production from the two well pairs averaging 1,626 bbl/d of bitumen. The average Instantaneous Steam Oil Ratio ("ISOR") for the third quarter of 2014 was 2.4. Since steaming commenced in February 2012, cumulative production from the two well pairs has exceeded 1.4 million bbls of bitumen by September 30, 2014 with a Cumulative Steam Oil Ratio ("CSOR") of 2.1. After 32 months to September 30, 2014, of higher than expected production rates and reserves recovered to date, the pilot well pairs are expected to continue their natural decline in 2014 and, as expected, the ISOR will increase.

Non-Thermal Oil and Gas

Pengrowth’s significant non-thermal oil and gas portfolio includes a large contiguous land base in the Greater Olds/Garrington area encompassing over 500 gross (250 net) sections of land with stacked opportunities in the Cardium, Viking and Mannville sands as well as in the Mississippian carbonate section. An extensive gathering and processing infrastructure provides an efficient platform for continued development in this area. Pengrowth also controls large light oil accumulations in the Swan Hills area of Northern Alberta providing ongoing development projects with low decline production and strong cash flow.

During the third quarter of 2014, development continued in the Greater Olds/Garrington area with an additional 10 (5.2 net) wells drilled in the Cardium and an additional 5 (1.8 net) wells drilled in the Elkton, Ellerslie and Glauconite formations, all with 100% success. Based on initial test data and early production results, the Cardium wells appear to be meeting or exceeding type curve expectations.

Pengrowth’s third quarter of 2014 development program also included 2 (2.0 net) injection wells and 1 (1.0 net) well in the Lloydminster formation at Bodo as well as 2 (2.0 net) wells at Groundbirch in the Montney. The Groundbirch wells are expected to be completed and on stream before year-end. In addition, Pengrowth drilled 2 (2.0 net) injection wells and 1 (1.0 net) well at Judy Creek supporting incremental production and reserves in the miscible flood.

PRODUCTION

	Three months ended						Nine months ended
Daily production	Sept 30, 2014	% of total	Jun 30, 2014	% of total	Sept 30, 2013	% of total	Sept 30, 2014	% of total	Sept 30, 2013	% of total
Light oil (bbls)	21,359	30	21,780	30	27,102	32	21,857	30	28,602	33
Heavy oil (bbls)	8,246	11	8,203	11	8,812	11	8,235	11	8,351	10
Natural gas liquids (bbls)	9,403	13	11,008	15	9,847	12	10,382	14	10,476	12
Natural gas (Mcf)	200,786	46	196,989	44	225,081	45	199,890	45	237,063	45
Total boe per day	72,472		73,823		83,275		73,789		86,938

Third quarter of 2014 average daily production decreased 2 percent compared to the second quarter of 2014 as expected, mainly due to the absence of the second quarter Sable Island condensate shipment, a small property disposition and natural declines, partly offset by continued strong performance from the Cardium development program. Third quarter and year to date 2014 production decreased 13 percent and 15 percent, respectively, when compared to the same periods last year due to significant property dispositions in late 2013 and natural production declines, partly offset by production additions from the Cardium development program.

Light Oil

Third quarter of 2014 light oil production decreased 2 percent compared to the second quarter of 2014 primarily due to a minor property disposition in Northern Alberta. Third quarter and year to date 2014 light oil production decreased 21 percent and 24 percent when compared to the same periods last year, respectively, due to the late 2013 dispositions partly offset by new production from the Cardium development program.

PENGROWTH Third Quarter 2014 Management's Discussion and Analysis 9

Heavy Oil

Third quarter of 2014 heavy oil production increased 1 percent compared to the second quarter of 2014 due to slightly higher production from non-operated properties. Third quarter and year to date 2014 heavy oil production decreased 6 percent and 1 percent compared to the same periods last year, respectively. These decreases were due to anticipated natural declines at the Lindbergh pilot project partly offset by the new production from the development drilling at Jenner and higher production from the Bodo area.

NGLs

Third quarter of 2014 NGL production decreased 15 percent compared to the second quarter of 2014 mainly due to the absence of the second quarter Sable Island condensate shipment. Third quarter and year to date 2014 NGL production decreased 5 percent and 1 percent compared to the same periods last year, respectively, due to the late 2013 dispositions and natural declines, partly offset by new Cardium production.

Natural Gas

Third quarter of 2014 natural gas production increased 2 percent compared to the second quarter of 2014 as new Cardium production and a decrease in turnaround activity more than offset natural declines. Third quarter and year to date 2014 natural gas production decreased 11 percent and 16 percent compared to the same periods last year, respectively, as a result of the late 2013 property dispositions and natural declines, partly offset by new Cardium production.

COMMODITY PRICES

Oil and Liquids Prices Excluding Realized Commodity Risk Management

	Three months ended						Nine months ended
(Cdn$/bbl)	Sept 30, 2014		Jun 30, 2014		Sept 30, 2013		Sept 30, 2014		Sept 30, 2013
Average Benchmark Prices
WTI oil	105.83		112.29		107.97		108.97		102.28
Edmonton par light oil	97.20		105.62		104.89		100.80		95.64
WCS heavy oil	83.84		90.46		88.92		85.82		78.89
Average Differentials to WTI
Edmonton par	(8.63	)	(6.67	)	(3.08	)	(8.17	)	(6.64	)
WCS heavy oil	(21.99	)	(21.83	)	(19.05	)	(23.15	)	(23.39	)
Average Sales Prices
Light oil	94.04		102.37		101.11		97.82		91.39
Heavy oil	78.43		84.00		88.19		79.84		70.18
Natural gas liquids	52.94		55.70		57.18		56.03		54.23

Third quarter of 2014 WTI crude oil price averaged Cdn$105.83/bbl, a decrease of 6 percent compared to the second quarter of 2014 and a decrease of 2 percent compared to the third quarter of 2013. Year to date 2014 WTI crude oil price averaged Cdn$108.97/bbl, an increase of 7 percent compared to the same period in 2013.

Third quarter of 2014 light oil differential increased 29 percent and 180 percent compared to the second quarter of 2014 and third quarter of 2013, respectively. Furthermore, year to date 2014 light oil differential increased 23 percent compared to the same period in 2013.

Third quarter of 2014 heavy oil differential was essentially unchanged from the second quarter of 2014, however it increased 15 percent compared to the third quarter of 2013. Year to date 2014, heavy oil differential narrowed 1 percent compared to the same period in 2013.

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

Pengrowth's third quarter and year to date 2014 average oil and liquids sales prices moved in conjunction with the above benchmark prices.

PENGROWTH Third Quarter 2014 Management's Discussion and Analysis 10

Natural Gas Prices Excluding Realized Commodity Risk Management

	Three months ended						Nine months ended
(Cdn$)	Sept 30, 2014		Jun 30, 2014		Sept 30, 2013		Sept 30, 2014		Sept 30, 2013
Average Benchmark Prices
NYMEX gas (per MMBtu)	4.30		4.99		3.63		4.83		3.84
AECO monthly gas (per MMBtu)	4.22		4.69		2.82		4.55		3.16
Average Differential to NYMEX
AECO differential (per MMBtu)	(0.08	)	(0.30	)	(0.81	)	(0.28	)	(0.68	)
Average Sales Prices
Natural gas (per Mcf) (1)	4.05		4.59		2.83		4.99		3.19

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

The NYMEX natural gas benchmark price averaged Cdn$4.30/MMBtu in the third quarter of 2014, a decline of 14 percent compared to the second quarter of 2014 largely due to lower natural gas demand across much of North America during the summer months. Third quarter and year to date 2014 NYMEX prices increased 18 percent and 26 percent compared to the same periods last year, respectively, driven by low natural gas storage in the key consuming regions of North America.

Third quarter of 2014 AECO gas prices averaged Cdn$4.22/MMBtu, representing a decline of 10 percent compared to the second quarter of 2014. A lower decline in AECO prices resulted from a narrowing of the basis spread between NYMEX and AECO. Third quarter and year to date 2014 AECO prices increased 50 percent and 44 percent compared to the same periods last year, respectively, due to higher benchmark prices and a narrowing of the basis spread between AECO and NYMEX.

Third quarter of 2014 natural gas sales price of Cdn$4.05/Mcf decreased 12 percent compared to the second quarter of 2014 due to the decrease in the natural gas benchmark prices. Third quarter and year to date 2014 natural gas sales prices increased 43 percent and 56 percent compared to the same periods last year, respectively, due to higher natural gas benchmark prices.

Total Average Sales Prices Excluding Realized Commodity Risk Management

	Three months ended			Nine months ended
($/boe)	Sept 30, 2014	Jun 30, 2014	Sept 30, 2013	Sept 30, 2014	Sept 30, 2013
Average sales prices	54.73	60.08	56.64	59.29	52.05
Other production income including sulphur	0.63	0.52	0.74	0.55	0.61
Total oil and gas sales	55.36	60.60	57.38	59.84	52.66

Third quarter of 2014 average sales price of Cdn$54.73/boe decreased 9 percent compared to the second quarter of 2014 due to lower pricing for all products led by declines in crude oil and natural gas pricing. Compared to the third quarter of 2013, the third quarter of 2014 sales price declined 3 percent as higher prices for natural gas were offset by lower crude oil pricing.

Year to date 2014 average sales prices increased 14 percent compared to the same period last year in response to higher sales prices for all products.

PENGROWTH Third Quarter 2014 Management's Discussion and Analysis 11

Commodity Risk Management Gains (Losses)

	Three months ended						Nine months ended
($ millions except per unit amounts)	Sept 30, 2014		Jun 30, 2014		Sept 30, 2013		Sept 30, 2014		Sept 30, 2013
Realized
Oil risk management	(23.9	)	(37.3	)	(31.3	)	(90.8	)	(43.0	)
$/bbl (1)	(8.77	)	(13.67	)	(9.47	)	(11.05	)	(4.26	)
Natural gas risk management	(4.7	)	(9.6	)	5.9		(27.0	)	3.7
$/Mcf	(0.25	)	(0.54	)	0.28		(0.49	)	0.06
Total realized loss	(28.6	)	(46.9	)	(25.4	)	(117.8	)	(39.3	)
$/boe	(4.29	)	(6.98	)	(3.32	)	(5.85	)	(1.66	)
Unrealized
Unrealized commodity risk management liabilities at period end	(84.2	)	(205.8	)	(40.9	)	(84.2	)	(40.9	)
Less: Unrealized commodity risk management assets (liabilities) at beginning of period	(205.8	)	(192.2	)	(23.0	)	(80.0	)	7.0
Unrealized gain (loss) on commodity risk management contracts for the period	121.6		(13.6	)	(17.9	)	(4.2	)	(47.9	)

⁽¹⁾  Includes light and heavy oil.

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

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

Realized commodity risk management losses decreased in the third quarter of 2014 compared to the second quarter of 2014 resulting from declines in both oil and natural gas benchmark prices. In contrast, third quarter of 2014 realized losses increased compared to the same period last year driven by higher natural gas benchmark prices partly offset by the effect of lower WTI. Year to date 2014 realized commodity risk management losses increased compared to the same period last year due to a rise in both oil and natural gas benchmark prices.

Unrealized gains and losses also vary period to period and are a function of the volumes under risk management contracts, the fixed prices of those risk management contracts and the forward curvepricing for the commodities under risk management contracts at the end of the period. Unrealized losses result when the forward price curve moves higher than the fixed price, with the magnitude of the loss being proportional to the movement in the forward price curve while unrealized gains result when the forward price curve moves lower than the fixed price, with the magnitude of the gain being proportional to the movement in the forward price curve. Unrealized commodity risk management gains and losses do not impact cash flow for the period.

PENGROWTH Third Quarter 2014 Management's Discussion and Analysis 12

Forward Contracts - Commodity and Power Risk Management

The following table provides a summary of the fixed prices of the commodity and power risk management contracts in place at September 30, 2014 (see Note 13 to the unaudited Financial Statements for more information on Pengrowth's risk management contracts):

Crude Oil Swaps and Puts
Reference point	Volume (bbl/d)	Remaining term	% of total oil production Guidance (1)	Price/bbl ($Cdn)
WTI	23,000	Oct 1, 2014 - Dec 31, 2014	77%	94.51
WTI	26,000	2015	63%	93.99
WTI	14,982	2016	33%	94.96
Natural Gas Swaps and Puts
Reference point	Volume (MMBtu/d)	Remaining term	% natural gas production Guidance	Price/MMBtu ($Cdn)
AECO & NGI Chicago Index	118,738	Oct 1, 2014 - Dec 31, 2014	59%	3.81
AECO & NGI Chicago Index	83,909	2015	47%	3.85
AECO	28,402	2016	18%	3.85
AECO	7,109	2017	5%	4.22
Power
Reference point	Volume (MW)	Remaining term	% of estimated power purchases	Price/MWh ($Cdn)
AESO	55	Oct 1, 2014 - Dec 31, 2014	78%	55.63
AESO	40	2015	79%	49.53
AESO	10	2016	15%	50.00

⁽¹⁾  Includes light and heavy crude oil. After the successful 2013 divestment program, oil risk management contracts represent over 65 percent of 2014 production Guidance for remaining 2014. Pengrowth's Board of Directors has approved the retention of the risk management contracts already in place.

In addition to the above table, Pengrowth has financial and physical contracts to manage oil price differentials. See Note 13 to the unaudited Financial Statements for more information.

Commodity and Power Price Sensitivity on Risk Management Contracts as at September 30, 2014

($ millions)
Oil	Cdn$1/bbl increase in future oil prices		Cdn$1/bbl decrease in future oil prices
Unrealized pre-tax gain (loss) on oil risk management	(17.0	)	17.0
Natural gas	Cdn$0.25/MMBtu increase in future natural gas prices		Cdn$0.25/MMBtu decrease in future natural gas prices
Unrealized pre-tax gain (loss) on natural gas risk management	(13.3	)	13.3
Power	Cdn$1/MWh increase in future power prices		Cdn$1/MWh decrease in future power prices
Unrealized pre-tax gain (loss) on power risk management	0.6		(0.6	)

The changes in fair value of the forward risk management contracts directly affect reported net income (loss) through the unrealized amounts recorded in the 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, 2014, revenue and cash flow would have been $84.2 million lower than if the risk management contracts were not in place based on the estimated fair value of the risk management contracts at period end. The $84.2 million is composed of liabilities of $60.4 million relating to risk management contracts expiring within one year and liabilities of $23.8 million relating to risk management contracts expiring beyond one year.

PENGROWTH Third Quarter 2014 Management's Discussion and Analysis 13

Pengrowth has not designated any outstanding commodity risk management contracts as hedges for accounting purposes and therefore records these risk management contracts on the Balance Sheets at their fair value and recognizes changes in fair value on the Statements of Income (Loss) as unrealized commodity risk management gains (losses). The volatility in net income (loss) will continue to the extent that the fair value of the commodity risk management contracts fluctuates. However, these non-cash amounts do not affect Pengrowth’s cash flow until realized.

Realized commodity risk management gains (losses) on crude oil and natural gas contracts are recorded separately on the Statements of Income (Loss) and impact cash flow at that time. Realized risk management gains (losses) on power contracts are recorded in operating expenses and the unrealized amounts are recorded in other (income) expense.

In accordance with policies approved by its Board of Directors, Pengrowth may sell forward its production and purchase risk management contracts by product volume or power purchases as follows:

Forward Period	Percent of Estimated Production	Percent of Estimated Power Purchases
1 - 24 Months	Up to 65%	Up to 80%
25 - 36 Months	Up to 30%	Up to 50%
37 - 60 Months	Up to 25%	Up to 25%

After the successful 2013 divestment program, oil risk management contracts represent over 65 percent of 2014 production Guidance for remaining 2014. Pengrowth's Board of Directors has approved the retention of the risk management contracts already in place.

OIL AND GAS SALES EXCLUDING REALIZED COMMODITY RISK MANAGEMENT

Contribution Analysis

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

	Three months ended						Nine months ended
($ millions except percentages)	Sept 30, 2014	% of total	Jun 30, 2014	% of total	Sept 30, 2013	% of total	Sept 30, 2014	% of total	Sept 30, 2013	% of total
Light oil	184.8	50	202.9	50	252.1	58	583.7	48	713.6	57
Heavy oil	59.5	16	62.7	15	71.5	16	179.5	15	160.0	13
Natural gas liquids	45.8	13	55.8	14	51.8	12	158.8	13	155.1	12
Natural gas	74.8	20	82.2	20	58.5	13	272.3	23	206.7	17
Other income including sulphur	4.2	1	3.5	1	5.7	1	11.1	1	14.3	1
Total oil and gas sales (1)	369.1		407.1		439.6		1,205.4		1,249.7

⁽¹⁾  Excluding realized commodity risk management.

Price and Volume Analysis

Quarter ended September 30, 2014 versus Quarter ended June 30, 2014

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

($ millions)	Light oil		Heavy oil		NGLs		Natural gas		Other (2)	Total
Quarter ended June 30, 2014 (1)	202.9		62.7		55.8		82.2		3.5	407.1
Effect of change in product prices and differentials	(16.4	)	(4.2	)	(2.4	)	(9.9	)	—	(32.9	)
Effect of change in sales volumes	(1.7	)	1.0		(7.6	)	2.5		—	(5.8	)
Other	—		—		—		—		0.7	0.7
Quarter ended September 30, 2014 (1)	184.8		59.5		45.8		74.8		4.2	369.1

⁽¹⁾  Excluding realized commodity risk management.

⁽²⁾  Primarily sulphur sales.

Light oil sales decreased 9 percent in the third quarter of 2014 compared to the second quarter of 2014 resulting from a decrease in the Edmonton par light oil benchmark price combined with lower sales volumes resulting from a minor property disposition and pipeline outages in the third quarter of 2014. Heavy oil sales decreased 5 percent in response to a decrease in the WCS benchmark price partly offset by an increase in volumes. NGL sales decreased 18 percent due to the absence of the Sable Island condensate shipment combined with lower pentane prices in the third quarter

PENGROWTH Third Quarter 2014 Management's Discussion and Analysis 14

of 2014. Natural gas sales decreased 9 percent due to lower natural gas benchmark prices partly offset by higher sales volumes.

Quarter ended September 30, 2014versus Quarter endedSeptember 30, 2013

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

($ millions)	Light oil		Heavy oil		NGLs		Natural gas		Other (2)		Total
Quarter ended September 30, 2013 (1)	252.1		71.5		51.8		58.5		5.7		439.6
Effect of change in product prices and differentials	(13.9	)	(7.4	)	(3.7	)	22.6		—		(2.4	)
Effect of change in sales volumes	(53.4	)	(4.6	)	(2.3	)	(6.3	)	—		(66.6	)
Other	—		—		—		—		(1.5	)	(1.5	)
Quarter ended September 30, 2014 (1)	184.8		59.5		45.8		74.8		4.2		369.1

⁽¹⁾  Excluding realized commodity risk management.

⁽²⁾  Primarily sulphur sales.

Light oil sales decreased 27 percent in the third quarter of 2014 compared to the same period in 2013 due to lower sales volumes from the 2013 disposition program coupled with a decrease in the Edmonton par light oil price. Heavy oil sales decreased 17 percent resulting from both a lower WCS benchmark price and lower production volumes. NGL sales decreased 12 percent impacted by the 2013 dispositions and lower pentane prices compared to the same period last year. Natural gas sales increased 28 percent due to higher natural gas benchmark prices partly offset by lower sales volumes from the 2013 property dispositions as well as natural declines.

Nine Months ended September 30, 2014versusNine Months ended September 30, 2013

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

($ millions)	Light oil		Heavy oil		NGLs		Natural gas		Other (2)		Total
Nine months ended September 30, 2013 (1)	713.6		160.0		155.1		206.7		14.3		1,249.7
Effect of change in product prices and differentials	38.4		21.7		5.1		98.0		—		163.2
Effect of change in sales volumes	(168.3	)	(2.2	)	(1.4	)	(32.4	)	—		(204.3	)
Other	—		—		—		—		(3.2	)	(3.2	)
Nine months ended September 30, 2014 (1)	583.7		179.5		158.8		272.3		11.1		1,205.4

⁽¹⁾  Excluding realized commodity risk management.

⁽²⁾  Primarily sulphur sales.

Year to date 2014 light oil sales decreased 18 percent compared to the same period in 2013 due to lower sales volumes from the 2013 disposition program partly offset by an increase in the Edmonton par light oil price year over year. Heavy oil sales increased 12 percent resulting from an improvement in the WCS benchmark price. Similarly, NGL sales increased 2 percent impacted by higher benchmark prices. Natural gas sales increased 32 percent due to higher natural gas benchmark prices partly offset by lower sales volumes from the 2013 property dispositions and natural declines.

ROYALTY EXPENSES

($ millions except per boe amounts and percentages)	Three months ended			Nine months ended
	Sept 30, 2014	Jun 30, 2014	Sept 30, 2013	Sept 30, 2014	Sept 30, 2013
Royalty expenses	65.5	78.2	72.6	217.4	212.3
$/boe	9.83	11.64	9.47	10.79	8.95
Royalties as a percent of oil and gas sales (%) (1)	17.7	19.2	16.5	18.0	17.0

⁽¹⁾  Excluding realized commodity risk management.

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

Third quarter of 2014 royalties as a percentage of sales decreased to 17.7 percent from 19.2 percent in the the second quarter of 2014 due to a decrease in commodity prices and the absence of an unfavourable GCA adjustment recorded in the second quarter of 2014. Third quarter of 2014 royalties as a percentage of sales increased to 17.7 percent from 16.5 percent in the the third quarter of 2013 primarily due to the absence of a favourable freehold mineral tax adjustment recorded in the third quarter of last year.

PENGROWTH Third Quarter 2014 Management's Discussion and Analysis 15

Year to date 2014 royalties as a percentage of sales increased to 18.0 percent from 17.0 percent for the same period last year driven by an increase in commodity prices coupled with unfavourable GCA adjustments recorded in 2014.

OPERATING EXPENSES

($ millions except per boe amounts)	Three months ended			Nine months ended
	Sept 30, 2014	Jun 30, 2014	Sept 30, 2013	Sept 30, 2014	Sept 30, 2013
Operating expenses	102.4	114.5	125.6	320.9	373.3
$/boe	15.36	17.05	16.39	15.93	15.73

Third quarter of 2014 operating expenses decreased $12.1 million or 11 percent compared to the second quarter of 2014 primarily due to the absence of turnaround costs incurred in the second quarter of 2014. On a per boe basis, third quarter of 2014 operating expenses decreased $1.69/boe as a result of the lower expenses, as mentioned above.

Third quarter of 2014 operating expenses decreased $23.2 million or 18 percent compared to the third quarter of 2013 due to the absence of operating expenses from properties divested in 2013 combined with lower power costs in 2014. On a per boe basis, third quarter of 2014 operating expenses decreased $1.03/boe compared to the third quarter of 2013 due to the above mentioned cost decreases partly offset by reduced production primarily resulting from the 2013 dispositions.

Year to date 2014 operating expenses decreased $52.4 million or 14 percent due to the absence of operating expenses from divested properties and lower power costs partly offset by increased turnaround costs in 2014. On a per boe basis, 2014 year to date operating expenses increased $0.20/boe compared to the same period last year primarily due to the increased turnaround costs in 2014 combined with reduced production resulting mainly from the 2013 dispositions.

TRANSPORTATION EXPENSES

($ millions except per boe amounts)	Three months ended			Nine months ended
	Sept 30, 2014	Jun 30, 2014	Sept 30, 2013	Sept 30, 2014	Sept 30, 2013
Transportation expenses	6.5	7.2	8.4	22.1	21.6
$/boe	0.97	1.07	1.10	1.10	0.91

Third quarter of 2014 transportation expenses decreased $0.7 million or 10 percent compared to the second quarter of 2014 mainly as a result of lower sales product trucking costs due to oil pipeline infrastructure development at Lochend. On a per boe basis, third quarter of 2014 transportation expenses decreased $0.10/boe compared to the second quarter of 2014 due to the decrease in sales product trucking costs. Third quarter of 2014 transportation expenses decreased $1.9 million or 23 percent compared to the third quarter of 2013 also resulting from the lower sales product trucking costs due to oil pipeline infrastructure development at Lochend. On a per boe basis, third quarter of 2014 transportation expenses decreased $0.13/boe compared to the same period last year due to lower sales product trucking costs partly offset by lower production volumes.

Year to date 2014 transportation expenses increased $0.5 million or 2 percent compared to the same period in 2013 mainly due to higher sales product trucking costs partly offset by lower oil pipeline transportation costs due to an increase in sales volumes at the wellhead. On a per boe basis, 2014 year to date transportation costs increased $0.19/boe compared to the same period in 2013 due to the increase in sales product trucking costs combined with a decrease in production volumes.

Pengrowth incurs transportation expenses for its natural gas production once the product enters a pipeline at a title transfer point. Pengrowth has the option to sell some of its natural gas directly to markets outside of Alberta by incurring additional transportation costs. Pengrowth sells most of its natural gas without incurring significant additional transportation costs. Pengrowth also incurs transportation expenses on its oil and NGL production including sales product trucking costs and pipeline costs up to the custody transfer point. Pengrowth has elected to sell approximately 55 percent of its crude oil at market points beyond the wellhead incurring transportation costs to the first major trading point. The transportation expenses are dependent upon third party rates and distance the product travels prior to changing ownership or custody.

PENGROWTH Third Quarter 2014 Management's Discussion and Analysis 16

OPERATING NETBACKS

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

	Three months ended						Nine months ended
Combined Netback ($/boe)	Sept 30, 2014		Jun 30, 2014		Sept 30, 2013		Sept 30, 2014		Sept 30, 2013
Oil & gas sales (includes other income)	55.36		60.60		57.38		59.84		52.66
Royalties	(9.83	)	(11.64	)	(9.47	)	(10.79	)	(8.95	)
Operating expenses	(15.36	)	(17.05	)	(16.39	)	(15.93	)	(15.73	)
Transportation expenses	(0.97	)	(1.07	)	(1.10	)	(1.10	)	(0.91	)
Operating netback before realized commodity risk management	29.20		30.84		30.42		32.02		27.07
Realized commodity risk management	(4.29	)	(6.98	)	(3.32	)	(5.85	)	(1.66	)
Operating netback	24.91		23.86		27.10		26.17		25.41
Light Oil Netback Excluding Realized Commodity Risk Management ($/bbl)
Sales	94.04		102.37		101.11		97.82		91.39
Royalties	(19.91	)	(22.22	)	(20.76	)	(20.64	)	(18.14	)
Operating expenses	(15.99	)	(15.64	)	(17.38	)	(15.88	)	(17.42	)
Transportation expenses	(1.65	)	(1.99	)	(1.93	)	(2.07	)	(1.49	)
Light oil operating netback	56.49		62.52		61.04		59.23		54.34
Heavy Oil Netback Excluding Realized Commodity Risk Management ($/bbl)
Sales	78.43		84.00		88.19		79.84		70.18
Royalties	(13.09	)	(13.40	)	(12.79	)	(12.10	)	(9.76	)
Operating expenses	(16.80	)	(20.65	)	(19.91	)	(18.11	)	(19.52	)
Transportation expenses	(1.67	)	(1.80	)	(1.93	)	(1.78	)	(1.71	)
Heavy oil operating netback	46.87		48.15		53.56		47.85		39.19
NGLs Netback Excluding Realized Commodity Risk Management ($/bbl)
Sales	52.94		55.70		57.18		56.03		54.23
Royalties	(14.38	)	(16.92	)	(15.43	)	(16.27	)	(15.29	)
Operating expenses	(15.53	)	(16.69	)	(15.79	)	(15.74	)	(15.14	)
Transportation expenses	—		—		(0.04	)	—		(0.06	)
NGLs operating netback	23.03		22.09		25.92		24.02		23.74
Natural Gas Netback Excluding Realized Commodity Risk Management ($/Mcf)
Sales	4.05		4.59		2.83		4.99		3.19
Royalties (1)	(0.22	)	(0.40	)	0.17		(0.38	)	(0.04	)
Operating expenses	(2.43	)	(2.87	)	(2.51	)	(2.58	)	(2.31	)
Transportation expenses	(0.11	)	(0.11	)	(0.09	)	(0.10	)	(0.09	)
Natural gas operating netback ($/Mcf)	1.29		1.21		0.40		1.93		0.75
Natural gas operating netback ($/boe)	7.74		7.26		2.40		11.58		4.50
CONTRIBUTION BASED ON OPERATING NETBACKS
Light oil	58	%	61	%	67	%	56	%	67	%
Heavy oil	19	%	17	%	19	%	17	%	14	%
Natural gas liquids	10	%	11	%	10	%	11	%	11	%
Natural gas	13	%	11	%	4	%	16	%	8	%

⁽¹⁾  Third quarter of 2013 contains a favourable freehold mineral tax adjustment.

PENGROWTH Third Quarter 2014 Management's Discussion and Analysis 17

Pengrowth realized a weighted average operating netback of $24.91/boe in the third quarter of 2014 representing a 4 percent increase compared to the second quarter of 2014 primarily due to lower expenses and royalties partly offset by the effect of lower benchmark prices. When comparing the third quarter of 2014 to the same period last year, the operating netback decreased 8 percent primarily driven by lower oil benchmark prices.

Year to date 2014 operating netback increased 3 percent compared to the same period last year as the effect of the higher benchmark prices was partly offset by higher expenses and royalties.

GENERAL AND ADMINISTRATIVE EXPENSES

	Three months ended			Nine months ended
($ millions except per boe amounts)	Sept 30, 2014	Jun 30, 2014	Sept 30, 2013	Sept 30, 2014	Sept 30, 2013
Cash G&A expenses	20.6	19.4	20.0	63.1	66.1
$/boe	3.09	2.89	2.61	3.13	2.79
Non-cash G&A expenses	5.0	4.9	4.4	13.4	12.5
$/boe	0.75	0.73	0.57	0.67	0.52
Total G&A	25.6	24.3	24.4	76.5	78.6
$/boe	3.84	3.62	3.18	3.80	3.31

Third quarter of 2014 cash G&A expenses were $1.2 million higher compared to the second quarter of 2014 mainly due to higher professional fees and severance costs. On a per boe basis, third quarter of 2014 cash G&A expenses increased $0.20/boe compared to the second quarter of 2014 due to the increase in costs, discussed above.

Third quarter of 2014 cash G&A expenses remained relatively unchanged compared to the same period last year. On a per boe basis, third quarter of 2014 cash G&A expenses increased $0.48/boe compared to the same period last year primarily due to the impact of lower production volumes in 2014.

Year to date 2014 cash G&A expenses were $3.0 million lower compared to 2013 due to staffing decreases associated with the 2013 dispositions as well as lower office rent. On a per boe basis, year to date 2014 cash G&A expenses increased $0.34/boe due to lower production volumes partly offset by lower expenses, as discussed above.

The non-cash component of G&A represents the compensation expenses associated with Pengrowth’s Long Term Incentive Plans ("LTIP"). See Note 10 to the unaudited Financial Statements for additional information. The compensation costs associated with these plans are expensed over the applicable vesting period.

Third quarter of 2014 non-cash G&A expenses remained relatively unchanged compared to the second quarter of 2014. Third quarter and year to date 2014 non-cash G&A expenses increased $0.6 million and $0.9 million compared to the same periods in 2013, respectively, due to slightly higher long term incentive plan grants in 2014.

During the nine months ended September 30, 2014, $11.7 million (September 30, 2013 - $12.1 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, 2014	Jun 30, 2014	Sept 30, 2013	Sept 30, 2014	Sept 30, 2013
Depletion, depreciation and amortization	128.5	130.7	135.7	389.3	443.9
$/boe	19.27	19.46	17.71	19.33	18.70
Accretion	4.5	4.9	4.9	14.4	15.6
$/boe	0.67	0.73	0.64	0.71	0.66

Third quarter of 2014 DD&A expense decreased $2.2 million compared to the second quarter of 2014, and decreased $7.2 million compared to the third quarter of 2013 mainly due to the decrease in production volumes. This is the same reason why year to date 2014 DD&A expense decreased $54.6 million or 12 percent.

Third quarter of 2014 accretion expense remained relatively unchanged compared to the second quarter of 2014 and the third quarter of 2013. Year to date 2014 accretion expense decreased $1.2 million mainly due to decreases in the ARO liability resulting from property dispositions and discount rate changes.

PENGROWTH Third Quarter 2014 Management's Discussion and Analysis 18

INTEREST AND FINANCING CHARGES

	Three months ended						Nine months ended
($ millions)	Sept 30, 2014		Jun 30, 2014		Sept 30, 2013		Sept 30, 2014		Sept 30, 2013
Interest and financing charges	26.0		26.1		25.5		78.0		75.6
Capitalized interest	(8.8	)	(7.0	)	(1.8	)	(21.1	)	(2.8	)
Total interest and financing charges	17.2		19.1		23.7		56.9		72.8

At September 30, 2014, Pengrowth had approximately $1.7 billion in total long term debt composed of $1.5 billion of fixed rate debt and $0.2 billion in convertible debentures, including the current portions. Total long term debt consists primarily of U.S. dollar denominated fixed rate notes at a weighted average interest rate of 5.7 percent and convertible debentures with a 6.25 percent coupon. At September 30, 2014, Pengrowth had no drawings on its syndicated bank facility.

Third quarter of 2014 interest and financing charges, before capitalized interest, remained relatively unchanged compared to the second quarter of 2014. Third quarter and year to date 2014 interest and financing charges, before capitalized interest, increased $0.5 million and $2.4 million compared to the same periods last year, respectively, mainly due to higher interest on the U.S. term debt as a result of the weaker Canadian dollar.

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, 2014, $21.1 million (September 30, 2013 - $2.8 million) of interest was capitalized on the Lindbergh thermal project to PP&E using a capitalization rate of 5.7 percent (September 30, 2013 - 5.7 percent).

OTHER (INCOME) EXPENSE

Year to date 2014 other expense of $11.7 million includes a $20 million provision for clean-up and remediation costs on a Northern Alberta oil property incurred in the first quarter of 2014 partly offset by gains on remediation trust funds and interest income.

TAXES

Deferred income tax is a non-cash item relating to temporary differences between the accounting and tax basis of Pengrowth’s assets and liabilities and has no immediate impact on Pengrowth’s cash flows. Pengrowth recorded a deferred tax expense of $32.6 million in the third quarter of 2014 compared to deferred tax reductions of $4.8 million and $32.3 million in the second quarter of 2014 and third quarter of 2013, respectively. Year to date 2014 deferred tax reduction amounted to $6.0 million compared to $54.6 million recorded during the same period last year.

No current income taxes were paid by Pengrowth in 2014 or 2013. See Note 8 to the unaudited Financial Statements for additional information.

PENGROWTH Third Quarter 2014 Management's Discussion and Analysis 19

FOREIGN CURRENCY GAINS (LOSSES)

	Three months ended						Nine months ended
($ millions)	Sept 30, 2014		Jun 30, 2014		Sept 30, 2013		Sept 30, 2014		Sept 30, 2013
Currency exchange rate ($1Cdn = $U.S.) at period end	0.89		0.94		0.97		0.89		0.97
Unrealized foreign exchange gain (loss) on U.S. dollar denominated debt	(63.9	)	46.5		26.1		(67.0	)	(43.5	)
Unrealized foreign exchange gain (loss) on U.K. pound sterling denominated debt	0.7		1.2		(4.5	)	(3.4	)	(3.3	)
Total unrealized foreign exchange gain (loss) from translation of foreign denominated debt	(63.2	)	47.7		21.6		(70.4	)	(46.8	)
Unrealized gain (loss) on U.S. foreign exchange risk management contracts	20.8		(16.9	)	(9.8	)	17.6		9.0
Unrealized gain (loss) on U.K. foreign exchange risk management contracts	(0.3	)	(1.7	)	4.6		3.6		3.0
Total unrealized gain (loss) on foreign exchange risk management contracts	20.5		(18.6	)	(5.2	)	21.2		12.0
Total unrealized foreign exchange gain (loss)	(42.7	)	29.1		16.4		(49.2	)	(34.8	)
Total realized foreign exchange gain (loss)	0.8		(1.4	)	(0.1	)	(0.7	)	1.3

Pengrowth’s unrealized foreign exchange gains and losses are primarily attributable to the translation of the foreign denominated long term debt and the related foreign exchange risk management contracts. The gains or losses on principal restatement are calculated by comparing the translated Canadian dollar balance of foreign denominated long term debt from one period to another. The magnitude of the gains and losses is proportionate to the magnitude of the exchange rate fluctuation between the opening and closing rates for the respective periods and any new foreign debt issued.

Pengrowth holds a series of swap contracts which were transacted in order to fix the foreign exchange rate on a portion of Pengrowth’s U.S. dollar denominated term debt. The swaps partially offset foreign exchange gains/losses on U.S. 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, 2014, the fair value of these foreign exchange derivative contracts was an asset of $40.7 million included on the Balance Sheets with changes in the fair value between Balance Sheet dates reported on the Statements of Income (Loss) as an unrealized foreign exchange (gain) loss.

Contract type	Settlement date	Principal amount (U.S.$ millions)	Swapped amount (U.S.$ millions)	% of principal swapped		Fixed rate ($1Cdn = $U.S.)
Swap	May 2015	71.5	50	70	%	0.98
Swap	July 2017	400	250	63	%	0.97
Swap	August 2018	265	125	47	%	0.96
Swap	October 2019	35	15	43	%	0.94
Swap	May 2020	115.5	20	17	%	0.95
No contracts	October 2022	105	—	—		—
No contracts	October 2024	195	—	—		—
		1,187	460	39	%

To mitigate the fluctuations in the U.K. pound sterling denominated long term debt Pengrowth entered into foreign exchange risk management contracts when it issued the U.K. pound sterling term notes. These contracts fix the Canadian dollar to the U.K. pound sterling exchange rate on the interest and principal of the U.K. pound sterling denominated debt as follows:

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

PENGROWTH Third Quarter 2014 Management's Discussion and Analysis 20

At September 30, 2014, each Cdn$0.01 exchange rate change would result in approximately a $4.6 million pre-tax change in the fair value of the U.S. risk management contracts and a $0.7 million pre-tax change in the fair value of the U.K. risk management contracts.

ASSET RETIREMENT OBLIGATIONS

For the nine months ended September 30, 2014, Pengrowth's ARO liability increased $54.7 million relative to December 31, 2013 mainly due to a change in the risk free discount rate from 3.25 percent to 2.7 percent. The rate decrease reflects a decrease in the 30 year Canadian Government long term bond rate which drives Pengrowth’s estimate of the ARO discount rate. This resulted in an upward ARO liability revision of $107.9 million with the offset recorded in PP&E. Partly offsetting this upward revision were property dispositions which decreased the ARO liability by $59.6 million.

Pengrowth has estimated the net present value of its total ARO to be $660.9 million as at September 30, 2014 (December 31, 2013 – $606.2 million), based on a total escalated future liability of $2.0 billion (December 31, 2013 – $2.1 billion). These costs are expected to be incurred over 65 years with the majority of the costs to be incurred between 2038 and 2078. A risk free discount rate of 2.7 percent per annum and an inflation rate of 1.5 percent were used to calculate the net present value of the ARO at September 30, 2014.

ACQUISITIONS AND DISPOSITIONS

	Three months ended						Nine months ended
($ millions)	Sept 30, 2014		Jun 30, 2014		Sept 30, 2013		Sept 30, 2014		Sept 30, 2013
Property acquisitions	13.7		0.1		3.0		15.8		3.9
Proceeds on property dispositions	(43.0	)	(21.1	)	(626.4	)	(63.5	)	(952.4	)
Net cash acquisitions (dispositions)	(29.3	)	(21.0	)	(623.4	)	(47.7	)	(948.5	)

Year to date 2014 Pengrowth has successfully closed a number of minor non-core property dispositions for aggregate net proceeds of $63.5 million.

WORKING CAPITAL

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

At September 30, 2014, Pengrowth had a working capital deficiency due to current liabilities exceeding current assets by $214.2 million as the cash balance decreased due to spending at Lindbergh. In comparison, Pengrowth had working capital surpluses of $179.3 million and $367.4 million at December 31, 2013 and September 30, 2013, respectively, as current assets exceeded current liabilities at those times primarily from higher cash balances following the 2013 property dispositions.

PENGROWTH Third Quarter 2014 Management's Discussion and Analysis 21

FINANCIAL RESOURCES AND LIQUIDITY

As at:	Sept 30, 2014		Dec 31, 2013		Sept 30, 2013
($ millions)
Term credit facilities	—		—		—
Senior unsecured notes (1)	1,483.7		1,412.7		1,366.8
Senior debt	1,483.7		1,412.7		1,366.8
Convertible debentures (1)	235.3		236.0		236.3
Total debt before working capital	1,719.0		1,648.7		1,603.1
Working capital (surplus) deficiency (2)	214.2		(179.3	)	(367.4	)
Total debt	1,933.2		1,469.4		1,235.7
Twelve months trailing:	Sept 30, 2014		Dec 31, 2013		Sept 30, 2013
($ millions, except ratios and percentages)
Net loss	(163.9	)	(316.9	)	(226.8	)
Add (deduct):
Interest & financing charges and accretion expense	97.5		114.6		119.8
Deferred income tax reduction	(24.6	)	(73.2	)	(64.7	)
Depletion, depreciation and amortization	520.0		574.6		609.0
EBITDA	429.0		299.1		437.3
Add other items:
Loss on disposition of properties	6.1		175.7		167.7
Other non-cash items	138.9		180.2		138.2
Adjusted EBITDA	574.0		655.0		743.2
Senior debt before working capital to Adjusted EBITDA (3)	2.6		2.2		1.8
Total debt before working capital to Adjusted EBITDA (4)	3.0		2.5		2.2
Total debt to Adjusted EBITDA (5)	3.4		2.2		1.7
Total capitalization (6)	5,414.7		5,157.7		5,061.1
Total debt as a percentage of total capitalization	35.7	%	28.5	%	24.4	%

⁽¹⁾  Includes current and long term portions.

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

⁽³⁾  Indicative of debt covenant for senior debt before working capital to EBITDA of 3.5 times.

⁽⁴⁾  Indicative of debt covenant for total debt before working capital to EBITDA of 4.0 times.

⁽⁵⁾  Not indicative of the actual debt covenants. See the Financial Covenants section for more information.

⁽⁶⁾  Total capitalization includes total debt plus Shareholders' Equity per the Balance Sheets.

At September 30, 2014, total debt increased $463.8 million from December 31, 2013 and $697.5 million from September 30, 2013 primarily due to a lower cash balance, as spending ramped up at Lindbergh, and an increase in the U.S. senior unsecured notes due to the weakening of the Canadian dollar.

The trailing twelve months total debt to Adjusted EBITDA ratio increased to 3.4x at September 30, 2014, compared to 2.2x at December 31, 2013 and 1.7x at September 30, 2013 mainly due to the increase in total debt and a decrease in Adjusted EBITDA as a result of 2013 property dispositions. This increase was expected and will continue until the first phase of Lingbergh is contributing to Adjusted EBITDA.

Term Credit Facilities

Pengrowth maintains a $1 billion revolving credit facility which was undrawn at September 30, 2014 (December 31, 2013 - $nil) and had $33.3 million (December 31, 2013 - $35.8 million) in outstanding letters of credit. The credit facility includes an expansion feature of $250 million providing Pengrowth with up to $1.25 billion of credit capacity from a syndicate of seven Canadian and four foreign banks, and can be extended at Pengrowth’s discretion any time prior to maturity, subject to syndicate approval. The facility has a maturity date of July 26, 2017.

Pengrowth also maintains a $50 million demand operating facility with one Canadian bank. At September 30, 2014, this facility was undrawn (December 31, 2013 - $nil) and had $0.8 million (December 31, 2013 - $0.8 million) of

PENGROWTH Third Quarter 2014 Management's Discussion and Analysis 22

outstanding letters of credit. When utilized together with any overdraft amounts, this facility would appear on the Balance Sheets as a current liability in bank indebtedness, as applicable.

Together, these two facilities and the cash balance of $42.0 million provided Pengrowth with approximately $1.1 billion of combined credit capacity and cash at September 30, 2014, with the ability to expand the facilities by an additional $250 million.

Financial Covenants

Pengrowth’s senior unsecured notes and credit facilities are subject to a number of covenants, all of which were met at all times during the preceding twelve months, and at September 30, 2014.

On January 24, 2014, Pengrowth amended the credit facility by increasing the maximum permitted senior debt before working capital to EBITDA (as calculated in accordance with the debt agreements) ratio from 3.0 to 3.5 times and the total debt before working capital to EBITDA ratio from 3.5 to 4.0 times until December 31, 2015. As at September 30, 2014, Pengrowth's actual ratios pursuant to these two covenants were at 2.7 times and 3.1 times, respectively. The financial covenants are now substantially similar between the credit facilities and the senior unsecured notes. The ratios on the credit facility will revert back to their prior levels of 3.0 and 3.5 times, respectively, after December 31, 2015. The covenant amendments were obtained as a proactive step while Pengrowth completes construction of the first 12,500 bbl/d commercial phase of Lindbergh and a full year of Lindbergh production can contribute to the EBITDA calculation.

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

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

The key financial covenants as at September 30, 2014 are summarized below:

1.Total senior debt before working capital must not exceed 3.5 times EBITDA for the last four fiscal quarters (credit facility - 3.0 times after December 31, 2015);

2.Total debt before working capital must not exceed 4.0 times EBITDA for the last four fiscal quarters (credit facility - 3.5 times after December 31, 2015);

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

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

There may be instances, such as when financing an acquisition, where it would be acceptable for total debt to trailing EBITDA to be temporarily offside. In the event of a significant acquisition, certain credit facility financial covenants are relaxed for two fiscal quarters after the close of the acquisition. Pengrowth may prepare pro forma financial statements for debt covenant purposes and has additional flexibility under its debt covenants for a set period of time. This would be a strategic decision recommended by management and approved by the Board of Directors with steps taken in the subsequent period to restore Pengrowth’s capital structure based on its capital management objectives.

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

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

Dividend Reinvestment Plan

Pengrowth's DRIP allows shareholders to reinvest cash dividends in additional shares of the Corporation. Under the DRIP, the shares are issued from treasury at a 5 percent discount to the weighted average closing price of Pengrowth’s common shares as determined by the plan.

During the nine months ended September 30, 2014, 5.9 million shares were issued under the DRIP program for cash proceeds of $39.5 million compared to 6.7 million shares for total proceeds of $33.2 million in the same period last year.

PENGROWTH Third Quarter 2014 Management's Discussion and Analysis 23

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 most recent audited Financial Statements for a description of the accounting policies for financial instruments and Note 13 to the unaudited Financial Statements for additional information regarding the fair value of Pengrowth’s financial instruments.

FUNDS FLOW FROM OPERATIONS AND DIVIDENDS

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

	Three months ended						Nine months ended
($ millions, except per share amounts)	Sept 30, 2014		Jun 30, 2014		Sept 30, 2013		Sept 30, 2014		Sept 30, 2013
Funds flow from operations	129.0		121.4		161.5		389.9		455.0
Dividends declared	63.6		63.3		62.3		189.7		186.0
Funds flow from operations less dividends declared	65.4		58.1		99.2		200.2		269.0
Per share	0.12		0.11		0.19		0.38		0.52
Payout ratio (1)	49	%	52	%	39	%	49	%	41	%

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

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

Funds flow from operations is derived from producing and selling oil, natural gas and related products and is therefore highly dependent on commodity prices. Pengrowth enters into forward commodity risk management contracts to mitigate price volatility and to provide a measure of stability to monthly cash flow. Details of commodity risk management contracts are contained in Note 13 to the unaudited Financial Statements.

The following table provides the net payout ratio when the proceeds of the DRIP are netted against dividends declared to reflect Pengrowth’s net cash outlay:

	Three months ended						Nine months ended
($ millions, except per share amounts)	Sept 30, 2014		Jun 30, 2014		Sept 30, 2013		Sept 30, 2014		Sept 30, 2013
Proceeds from DRIP	13.1		13.3		11.0		39.5		33.2
Per share	0.02		0.03		0.02		0.08		0.06
Net payout ratio (%) (1)	39	%	41	%	32	%	39	%	34	%

⁽¹⁾  Net payout ratio is calculated as dividends declared net of proceeds from the DRIP divided by funds flow from operations.

DRIP participation was equivalent to approximately 21 percent of the total dividend during both the third quarter and year to date 2014.

DIVIDENDS

The Board of Directors and management regularly review the level of dividends. The board considers a number of factors, including expectations of future commodity prices, capital expenditure requirements, and the availability of debt and equity capital. Although the Corporation is committed to maintaining the dividend, there can be no certainty that Pengrowth will be able to maintain current levels of dividends and dividends can and may fluctuate in the future as a result of the volatility in commodity prices, changes in production levels and capital expenditure requirements. Pengrowth has no restrictions on the payment of its dividends other than maintaining its financial covenants in its borrowings and restrictions in the Business Corporations Act (Alberta).

Dividends are generally paid to shareholders on the fifteenth day or next business day of the month. Pengrowth paid $0.04 per share in each of the nine months January through September 30, 2014 for an aggregate cash dividend of

PENGROWTH Third Quarter 2014 Management's Discussion and Analysis 24

$0.36 per share. For the same period in 2013, Pengrowth also paid $0.04 per share in each of the months January through September for an aggregate cash dividend of $0.36 per share.

SUMMARY OF QUARTERLY RESULTS

The following table is a summary of quarterly information for 2014, 2013 and 2012:

2014	Q1		Q2		Q3
Oil and gas sales ($ millions) (1)	429.2		407.1		369.1
Net income (loss) ($ millions)	(116.2	)	(8.8	)	52.2
Net income (loss) per share ($)	(0.22	)	(0.02	)	0.10
Net income (loss) per share - diluted ($)	(0.22	)	(0.02	)	0.10
Adjusted net income (loss) ($ millions)	(2.8	)	(24.8	)	3.4
Funds flow from operations ($ millions)	139.5		121.4		129.0
Dividends declared ($ millions)	62.8		63.3		63.6
Dividends declared per share ($)	0.12		0.12		0.12
Daily production (boe/d)	75,102		73,823		72,472
Total production (Mboe)	6,759		6,718		6,667
Average sales price ($/boe) (1)	63.00		60.08		54.73
Operating netback ($/boe) (2)	29.71		23.86		24.91
2013	Q1		Q2		Q3		Q4
Oil and gas sales ($ millions) (1)	393.5		416.6		439.6		343.7
Net loss ($ millions)	(65.1	)	(53.4	)	(107.3	)	(91.1	)
Net loss per share ($)	(0.13	)	(0.10	)	(0.21	)	(0.17	)
Net loss per share - diluted ($)	(0.13	)	(0.10	)	(0.21	)	(0.17	)
Adjusted net loss ($ millions)	(1.1	)	(37.2	)	(108.2	)	(37.3	)
Funds flow from operations ($ millions)	147.5		146.0		161.5		105.9
Dividends declared ($ millions)	61.6		62.1		62.3		62.5
Dividends declared per share ($)	0.12		0.12		0.12		0.12
Daily production (boe/d)	89,702		87,909		83,275		77,371
Total production (Mboe)	8,073		8,000		7,661		7,118
Average sales price ($/boe) (1)	48.18		51.55		56.64		47.92
Operating netback ($/boe) (2)	24.79		24.44		27.10		20.82
2012	Q1		Q2		Q3		Q4
Oil and gas sales ($ millions) (1)	341.2		321.5		381.5		414.0
Net income (loss) ($ millions) (3)	0.7		36.8		(23.8	)	(1.0	)
Net income (loss) per share ($) (3)	—		0.09		(0.05	)	—
Net income (loss) per share - diluted ($) (3)	—		0.09		(0.05	)	—
Adjusted net income (loss) ($ millions)	(5.4	)	(89.6	)	(18.8	)	24.1
Funds flow from operations ($ millions)	113.6		94.4		141.1		189.7
Dividends declared ($ millions)	76.1		86.4		60.6		61.3
Dividends declared per share ($)	0.21		0.21		0.12		0.12
Daily production (boe/d)	75,618		78,870		94,284		94,039
Total production (Mboe)	6,881		7,177		8,674		8,652
Average sales price ($/boe) (1)	48.99		44.05		43.53		47.31
Operating netback ($/boe) (2) (4)	22.48		21.47		22.25		27.87

⁽¹⁾  Excluding realized commodity risk management.

⁽²⁾  Including realized commodity risk management.

⁽³⁾  As required under IFRS, changes in accounting for the NAL Acquisition that arose in the fourth quarter of 2012 were adjusted retrospective to the second quarter of 2012.

⁽⁴⁾  As of January 1, 2013 certain technical support costs, previously included in operating expenses, are included in G&A. 2012 operating netbacks have been adjusted accordingly to conform to presentation in the current period.

PENGROWTH Third Quarter 2014 Management's Discussion and Analysis 25

Third quarter of 2014 average sales price decreased compared to both the first and second quarters of 2014 driven by a decline in the benchmark prices. Quarterly production in 2014 is lower than the preceding quarters mainly due to 2013 property dispositions, lower natural gas production resulting from natural declines as a result of capital investment being directed mainly to oil development programs, in addition to a few fields with third party capacity constraints. Production increases in the second and third quarters of 2012 were primarily a result of the NAL Energy Corporation acquisition on May 31, 2012.

First quarter of 2014 posted the highest operating netback since the fourth quarter of 2011 resulting from higher natural gas prices and an increase in light and heavy oil benchmark prices. Pengrowth's first and second quarter of 2014 average sales prices were the highest posted average prices since the fourth quarter of 2008 driven by an increase in the benchmark prices.

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

COMMITMENTS AND CONTRACTUAL OBLIGATIONS

Pengrowth entered into a lease amendment and extension agreement with respect to its Calgary head office lease effective March 31, 2014. The agreement saw two floors returned to the landlord in 2014 and extended the existing lease term for the remaining floors from 2018 to 2025, resulting in an additional operating lease commitment over the extended term of approximately $57 million.

Pengrowth entered into a transportation agreement in the third quarter of 2014 with Husky Energy in preparation for the anticipated Lindbergh production growth resulting in an additional commitment of approximately $161 million from 2015 to 2025.

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 28, 2014 available on SEDAR at www.sedar.com.

ACCOUNTING PRONOUNCEMENTS ADOPTED

On January1, 2014, Pengrowth adopted amendments to IAS 32 Financial Instruments: Presentation (“IAS 32”) relating to offsetting financial assets and financial liabilities. The amendments clarify when an entity has a legally enforceable right to offset and certain other requirements that are necessary to present a net financial asset or liability. The retrospective adoption of this standard had no impact on the amounts recorded in the Financial Statements.

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

DISCLOSURE AND INTERNAL CONTROLS

As a Canadian reporting issuer with securities listed on both the TSX and the NYSE, Pengrowth is required to comply with Multilateral Instrument 52-109 - Certification of Disclosure in Issuers’ Annual and Interim Filings, as well as the Sarbanes Oxley Act ("SOX") enacted in the United States.

At the end of the interim period ended September 30, 2014, 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, 2014 and summary financial information about these items has been proportionately consolidated or consolidated in Pengrowth's Financial Statements. During the interim period ended September 30, 2014, 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.

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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.

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