40-F

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 40-F

o REGISTRATION STATEMENT PURSUANT TO SECTION 12 OF THE SECURITIES EXCHANGE ACT OF 1934

þ ANNUAL REPORT PURSUANT TO SECTION 13(a) OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended: December 31, 2017 Commission File Number: 1-31253

PENGROWTH ENERGY CORPORATION

(Exact name of Registrant as specified in its charter)

Alberta, Canada

(Province or other jurisdiction of incorporation or organization)

1311	None
(Primary Standard Industrial Classification Code Number)	(I.R.S. Employer Identification Number)

Suite 1600, 222 Third Avenue S.W.

Calgary, Alberta Canada T2P 0B4

(403) 233-0224

(Address and telephone number of Registrant’s principal executive offices)

Puglisi & Associates

850 Library Avenue, Suite 204

Newark, Delaware 19711

(302) 738-6680

(Name, address (including zip code) and telephone number (including area code)

of agent for service in the United States)

Securities registered or to be registered pursuant to Section 12(b) of the Act.

Title of each class	Name of each exchange on which registered
Common Shares	New York Stock Exchange

Securities registered or to be registered pursuant to Section 12(g) of the Act.

None

(Title of Class)

Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act.

None

(Title of Class)

For Annual Reports indicate by check mark the information filed with this Form:

þ Annual information form þ Audited annual financial statements

Indicate the number of outstanding shares of each of the issuer’s classes of capital or common stock as of the close of the period covered by the annual report:

There were 552,246,104 Common Shares, of no par value, outstanding as of December 31, 2017.

Indicate by check mark whether the Registrant by filing the information contained in this Form is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934 (the "Exchange Act"). If "Yes" is marked, indicate the file number assigned to the Registrant in connection with such Rule.

Yes o 82-______ No þ

Indicate by check mark whether the Registrant (1) has filed all reports to be filed by Section 13 or 15(d) of the Exchange Act during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports) and (2) has been subject to filing requirements for the past 90 days.

Yes þ No o

Indicate by check mark whether the Registrant is an emerging growth company as defined in Rule 12b-2 of the Exchange Act.

Emerging growth company o

If an emerging growth company that prepares its financial statements in accordance with U.S. GAAP, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards† provided pursuant to Section 13(a) of the Exchange Act. o

†The term "new or revised financial accounting standard" refers to any update issued by the Financial Accounting Standards Board to its Accounting Standards Codification after April 5, 2012.

This Annual Report on Form 40-F shall be incorporated by reference into or as an exhibit to, as applicable, the registrant’s Registration Statement on Form F-3D (File No. 333-180888) under the Securities Act of 1933, as amended.

        CERTIFICATIONS AND DISCLOSURE REGARDING CONTROLS AND PROCEDURES

Certifications. See Exhibits 99.7, 99.8, 99.9 and 99.10 to this Annual Report on Form 40-F.

Disclosure Controls and Procedures. The required disclosure is included in the section entitled “Disclosure and Internal Controls” contained in the Registrant’s Management’s Discussion and Analysis for the fiscal year ended December 31, 2017, filed as part of this Annual Report on Form 40-F.

Management’s Annual Report on Internal Control Over Financial Reporting. The required disclosure is included in the section entitled “Internal Control Over Financial Reporting” contained in the Registrant’s Management’s Discussion and Analysis for the fiscal year ended December 31, 2017, filed as part of this Annual Report on Form 40-F.

Attestation Report of the Registered Public Accounting Firm. The required disclosure is included in the “Independent Auditors’ Report of Registered Public Accounting Firm” that accompanies the Registrant’s Consolidated Financial Statements for the fiscal year ended December 31, 2017, filed as part of this Annual Report on Form 40-F.

Changes in Internal Control Over Financial Reporting. During the fiscal year ended December 31, 2017, there were no changes in the Registrant’s internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the Registrant’s internal control over financial reporting.

NOTICES PURSUANT TO REGULATION BTR

None.

IDENTIFICATION OF THE AUDIT COMMITTEE

The Registrant has a separately-designated standing audit committee established in accordance with Section 3(a)(58)(A) of the Exchange Act. The members of the audit committee are: Kelvin B. Johnston, James D. McFarland, A. Terence Poole and Jamie C. Sokalsky.

AUDIT COMMITTEE FINANCIAL EXPERT

The board of directors of the Registrant has determined that each of A. Terence Poole and Jamie C. Sokalsky, members of the Registrant’s audit committee, qualify as audit committee financial experts for purposes of paragraph (8) of General Instruction B to Form 40-F. The board of directors has further determined that each of Messrs. Poole and Sokalsky is also independent, as that term is defined in the New York Stock Exchange Listed Company Manual. The Commission has indicated that the designation of each of Messrs. Poole and Sokalsky as an audit committee financial expert does not make any of them an “expert” for any purpose, impose any duties, obligations or liabilities on them that are greater than those imposed on members of the audit committee and the board of directors who do not carry this designation or affect the duties, obligations or liabilities of any other member of the audit committee or the board of directors.

ADDITIONAL DISCLOSURE

Code of Ethics.

The Registrant has adopted a “code of ethics” (as that term is defined in Form 40-F), entitled the “Code of Business Conduct and Ethics”, that applies to all of its employees, including its principal executive officer, principal financial officer, principal accounting officer or controller, and persons performing similar functions.

There were no substantive amendments to the code of ethics during the Registrant's most recently completed fiscal year.

No waivers were granted from the code of ethics (including implicit waivers, in respect of the Registrant's Chief Executive Officer, Chief Financial Officer or its principal accounting officers) during the Registrant's most recently completed fiscal year.

The Code of Business Conduct & Ethics is available for viewing on the registrant’s website at www.pengrowth.com.

Principal Accountant Fees and Services.

The required disclosure is included under the heading “Principal Accountant Fees and Services” at page 59 of the Registrant’s Annual Information Form for the fiscal year ended December 31, 2017, filed as part of this Annual Report on Form 40-F as Exhibit 99.1 hereto.

Pre-Approval Policies and Procedures.

The required disclosure is included under the heading “Pre-Approval Policies and Procedures” at page 60 of the Registrant’s Annual Information Form for the fiscal year ended December 31, 2017, filed as part of this Annual Report on Form 40-F as Exhibit 99.1 hereto.

Off-Balance Sheet Arrangements.

The required disclosure is included under the heading “Off-Balance Sheet Arrangements” at page 61 of the Registrant’s Annual Information Form for the fiscal year ended December 31, 2017, filed as part of this Annual Report on Form 40-F as Exhibit 99.1 hereto.

Tabular Disclosure of Contractual Obligations.

The required disclosure is included under the heading “Commitments and Contractual Obligations” at page 32 of the Registrant’s Management’s Discussion and Analysis for the fiscal year ended December 31, 2017, filed as part of this Annual Report on Form 40-as Exhibit 99.2 hereto.

UNDERTAKING

Registrant undertakes to make available, in person or by telephone, representatives to respond to inquiries made by the Commission staff, and to furnish promptly, when requested to do so by the Commission staff, information relating to: the securities registered pursuant to Form 40-F; the securities in relation to which the obligation to file an annual report on Form 40-F arises; or transactions in said securities.

CONSENT TO SERVICE OF PROCESS

The registrant has previously filed a Form F-X in connection with the class of securities in relation to which the obligation to file this report arises.

Any changes to the name or address of the agent for service of process of the Registrant shall be communicated promptly to the Commission by an amendment to the Form F-X referencing the file number of the Registrant.

SIGNATURES

Pursuant to the requirements of the Exchange Act, the Registrant certifies that it meets all of the requirements for filing on Form 40-F and has duly caused this Annual Report to be signed on its behalf by the undersigned, thereunto duly authorized.

Date: February 28, 2018	PENGROWTH ENERGY CORPORATION
	By:	/s/ Derek W. Evans
		Name: Derek W. Evans
		Title: President and Chief Executive Officer

EXHIBIT INDEX

Exhibit	Description
99.1	Pengrowth Energy Corporation Annual Information Form for the year ended December 31, 2017
99.2	Management’s Discussion and Analysis for the fiscal year ended December 31, 2017
99.3	Consolidated Financial Statements of Pengrowth Energy Corporation for the fiscal year ended December 31, 2017, including Management’s Report to Shareholders and the Auditors’ Reports
99.4	Supplemental Unaudited Disclosures about Oil and Gas Producing Activities required under United States Generally Accepted Accounting Principles
99.5	Consent of Independent Registered Public Accounting Firm
99.6	Consent of GLJ Petroleum Consultants Ltd.
99.7	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350
99.8	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350
99.9	Certification of Chief Executive Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934
99.10	Certification of Chief Financial Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934

EX-99.1

nTABLE OF CONTENTS

GLOSSARY OF TERMS AND ABBREVIATIONS	1
CONVERSION	5
PRESENTATION OF OUR FINANCIAL INFORMATION	5
PRESENTATION OF OUR RESERVE AND RESOURCE INFORMATION	5
FORWARD-LOOKING STATEMENTS	5
PENGROWTH ENERGY CORPORATION	7
Introduction	7
General Development of the Business	7
DESCRIPTION OF OUR BUSINESS	9
General	9
Business Strategy	9
OPERATIONAL INFORMATION	10
Principal Producing Properties	10
Statement of Oil and Gas Reserves and Reserves Data	11
Additional Information Relating to Reserves Data	22
Significant Factors or Uncertainties Affecting Reserves Data	23
Future Development Costs	23
Finding, Development and Acquisition Costs	23
Recycle Ratio	26
Reserve Life Index	26
Reserve Replacement	26
Other Oil and Gas Information	27
Forward Contracts	27
Tax Horizon	28
Costs Incurred	28
Exploration and Development Activities	28
Production Estimates	28
Production History (Netback)	29
DESCRIPTION OF CAPITAL STRUCTURE	29
DIVIDENDS	30
INDUSTRY CONDITIONS	31
RISK FACTORS	41
MARKET FOR SECURITIES	56
DIRECTORS AND OFFICERS	57
Corporate Cease Trade Orders, Bankruptcies, Personal Bankruptcies, Penalties or Sanctions	58
AUDIT AND RISK COMMITTEE	59
Principal Accountant Fees and Services	59
Pre-approval Policies and Procedures	60
CONFLICTS OF INTEREST	60
LEGAL PROCEEDINGS	60
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS	61
INTERESTS OF EXPERTS	61
AUDITORS, TRANSFER AGENT AND REGISTRAR	61
MATERIAL CONTRACTS	61
CODE OF ETHICS	61
OFF-BALANCE SHEET ARRANGEMENTS	61
DISCLOSURE PURSUANT TO THE REQUIREMENTS OF THE NEW YORK STOCK EXCHANGE	62
ADDITIONAL INFORMATION	62
APPENDIX A - Supplemental Disclosure - Contingent Resources
APPENDIX B - Report on Reserves Data and Contingent Resources Data by Independent Qualified Reserves Evaluator                          (Form 51-101F2)
APPENDIX C - Report of Management and Directors on Oil and Gas Disclosure (Form 51-101F3)
APPENDIX D - Audit and Risk Committee Terms of Reference
Unless otherwise indicated, all of the information provided in this Annual Information Form is as at December 31, 2017

GLOSSARY OF TERMS AND ABBREVIATIONS

The following terms in this Annual Information Form have the meanings set forth below:

Corporate

"2010 Note Purchase Agreements" means, collectively, the separate and several note purchase agreements dated May 11, 2010 among us and the purchasers listed therein, as amended;

"2010 Senior Notes" means the US$115.5 million (original issue amount) of senior unsecured notes issued under the 2010 Note Purchase Agreements;

"2012 Note Purchase Agreements" means, collectively, the separate and several note purchase agreements dated October 18, 2012 among us and the purchasers listed therein, as amended;

"2012 Senior Notes" means the US$335 million, £15 million and $25 million (original issue amounts) of senior unsecured notes collectively issued under the 2012 Note Purchase Agreements;

"ABCA" means the Business Corporations Act (Alberta), R.S.A. 2000, c.B-9, as amended, including the regulations promulgated thereunder;

"Board" or "Board of Directors" refers to our board of directors;

"CCAA" means the Companies' Creditors Arrangement Act (Canada);

"Common Shares" means our common shares;

"Corporation" and "Pengrowth", "we", "us" and "our" refers to Pengrowth Energy Corporation and all of our wholly-owned direct and indirect subsidiary entities on a consolidated basis as well as our predecessors, Pengrowth Corporation and Pengrowth Energy Trust;

"Credit Facility" refers to Pengrowth's $330 million Amended and Restated Credit Agreement dated October 12, 2017 among Pengrowth and a syndicate of eleven financial institutions;

"Shareholders" means holders of Common Shares;

"Tax Act" refers to the Income Tax Act (Canada) and the regulations thereunder, as amended from time to time; and

"Term Notes" means, collectively, the 2010 Senior Notes and the 2012 Senior Notes.

Engineering

"abandonment and reclamation costs" means all costs associated with the process of restoring a property that has been disturbed by oil and gas activities to a standard imposed by applicable government or regulatory authorities;

"Best Estimate" is a best estimate of the quantity of oil or gas that will be recovered from the accumulation, which under probabilistic methodology reflects a fifty percent confidence level;

"Bitumen" means a naturally occurring solid or semi-sold hydrocarbon: (a) consisting of mainly of heavier hydrocarbons, with a viscosity greater than 10,000 mPa-s or 10,000 cPmeasured at the hydrocarbon's original temperature in the reservoir and at atmospheric pressure on a gas-free basis, and (b) that is not primarily recoverable at economic rates through a well without the implementation of enhanced recovery methods;

"by-product" means a substance that is recovered as a consequence of producing a product type;

"coal bed methane" means natural gas that: (a) primarily consists of methane, and (b) is contained in a coal deposit;

"COGE Handbook" means the "Canadian Oil and Gas Evaluation Handbook" maintained by the Society of Petroleum Evaluation Engineers (Calgary Chapter), as amended from time to time;

"Company Interest" is equal to our gross interest plus Pengrowth's Royalty Interest; that is, the Working Interest share of production or reserves prior to the deduction of royalties plus any Royalty Interest in production or reserves at the wellhead;

"Contingent Resources" are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. The contingencies may include factors such as economics, legal, environmental, political, regulatory or lack of markets. Contingent Resources are classified in accordance with the level of certainty associated with the estimates and further sub-classified and risked according to their project maturity and chance of development. Contingent Resources do not constitute, and should not be confused with, reserves;

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"conventional natural gas" means natural gas that has been generated elsewhere and has migrated as a result of hydrodynamic forces and is trapped in discrete accumulations by seals that may be formed by localized structural, depositional or erosional geological features;

"Developed Non-Producing Reserves" refers to those reserves that either have not been on production, or have previously been on production but are shut-in and the date of resumption of production is unknown;

"Developed Producing Reserves" refers to those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty;

"Developed Reserves" refers to those reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure (e.g. when compared to the cost of drilling a well) to put the reserves on production;

"Future Development Costs" or "FDC" refers to the amount of capital estimated by the independent evaluator that will be required to maintain production or bring non-producing, undeveloped or probable reserves on stream;

"Future Net Revenue" means a forecast of revenue, estimated using forecast prices and costs or constant prices and costs, arising from the anticipated development and production of resources, net of the associated royalties, operating costs, development costs and abandonment and reclamation costs;

"GLJ" refers to GLJ Petroleum Consultants Ltd., independent petroleum consultants, Calgary, Alberta;

"GLJ Report" refers to the reserve report prepared by GLJ, dated February 28, 2018 with an effective date of December 31, 2017;

"gross" with respect to: (i) our interest in production or reserves, refers to our Working Interest share (operated or non-operated) before the deduction of royalties and without including any of our Royalty Interests; (ii) our wells, refers to the total number of wells in which we have an interest; and (iii) our properties, refers to the total area of properties in which we have an interest;

"heavy crude oil" means crude oil with a relative density greater than 10 ^oAPI and less than or equal to 22.3 ^oAPI;

"High Estimate" is an optimistic estimate of the quantity of oil or gas that will be recovered from the accumulation, which under probabilistic methodology reflects a ten percent confidence level;

"hydrocarbon" means a compound consisting of hydrogen and carbon, which, when naturally occurring, may also contain other elements such as sulphur;

"Instantaneous Steam-Oil Ratio" or "ISOR" refers to the efficiency of a steam injection recovery process and is the measure of the volume of steam, in equivalent barrels of water, required to produce one barrel of bitumen, currently or at any time;

"light crude oil" means crude oil with a relative density greater than 31.1 ^oAPI;

"Low Estimate" is a conservative estimate of the quantity of oil or gas that will be recovered from the accumulation, which under probabilistic methodology reflects a ninety percent confidence level;

"medium crude oil" means crude oil with a relative density greater than 22.3 ^oAPI and less than or equal to 31.1 ^oAPI;

"natural gas" means a naturally occurring mixture of hydrocarbon gases and other gases;

"natural gas liquids" means those hydrocarbon components that can be recovered from natural gas as a liquid including, but not limited to, ethane, propane, butanes, pentanes plus, and condensates;

"net" with respect to: (i) our interest in production or reserves, refers to our Working Interest share (operated or non-operated) after the deduction of royalty obligations, plus our Royalty Interests in production or reserves; (ii) our interest in wells, refers to the number of wells obtained by aggregating our Working Interest in each of our gross wells; and (iii) our interest in a property, refers to the total area in which we have an interest multiplied by the Working Interest owned by us;

"Possible Reserves" are those additional reserves that are less certain to be recovered than Probable Reserves. It is unlikely that the actual remaining quantities recovered will exceed the sum of Proved Plus Probable plus Possible Reserves;

"Probable Reserves" are those additional reserves that are less certain to be recovered than Proved Reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated Proved plus Probable Reserves;

"Probable Undeveloped Reserves" refers to those Probable Reserves that are Undeveloped Reserves;

"Proved Developed Non-Producing Reserves" refers to those Proved Reserves that are Developed Non-Producing Reserves;

"Proved Developed Producing Reserves" refers to those Proved Reserves that are Developed Producing Reserves;

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"Proved Developed Reserves" refers to those Proved Reserves that are Developed Reserves;

"Proved Reserves" are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated Proved Reserves;

"Proved Undeveloped Reserves" refers to those Proved Reserves that are Undeveloped Reserves;

"Recycle Ratio" refers to the ratio resulting from the quotient of operating netback and F&D or FD&A Costs;

"Remaining Reserve Life" refers to the expected productive life of the property or fifty years, whichever is less;

"Reserve Life Index" or "RLI"refers to the number of years determined by dividing Company Interest reserves of a property by the next year’s forecast Company Interest production for the corresponding reserve category from such property. The reserves and next year’s forecast production for such property come from the GLJ Report;

"reserves" refers to estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, as of a given date, based on: (i) analysis of drilling, geological, geophysical and engineering data; (ii) the use of established technology; and (iii) specified economic conditions which are generally accepted as being reasonable and shall be disclosed; reserves are classified according to the degree of certainty associated with the estimate (e.g., proved, probable);

"risked" means adjusted for the probability of loss or failure in accordance with the COGE Handbook;

"Royalty Interest(s)" refers to Pengrowth's interest in production and payment that is based on the gross production at the wellhead; a royalty is paid in either cash or kind, but is paid on a value calculated at the wellhead;

"shale gas" means natural gas (a) contained in dense organic-rich rocks, including low-permeability shales, siltstones and carbonates, in which the natural gas is primarily adsorbed on the kerogen or clay minerals, and (b) that usually requires the use of hydraulic fracturing to achieve economic production rates;

"Total Proved Plus Probable Reserves" or "P+P" means the aggregate of Proved Reserves and Probable Reserves;

"Undeveloped Reserves" refers to those reserves expected to be recovered from known accumulations where a significant expenditure (e.g. the cost of drilling a well) is required to render them capable of production; they must fully meet the requirements of the reserves classification (proved, probable, possible) to which they are assigned; and

"Working Interest" refers to the percentage of undivided interest, excluding Royalty Interests, held by Pengrowth in an oil and gas property.

Abbreviations

"$M" and "$MM" refers to thousands of dollars and millions of dollars, respectively;

"AECO" refers to AECO/NIT, the Alberta natural gas benchmark price;

"AER" refers to the Alberta Energy Regulator;

"API" refers to the American Petroleum Institute;

"^oAPI" refers to an indication of the specific gravity of crude oil measured on the API gravity scale;

"bbl", "Mbbl" and "MMbbl" refers to barrels, thousands of barrels and millions of barrels, respectively;

"bbl/d" refers to barrels per day;

"BOE", "Mboe" and "MMboe" refers to barrels of oil equivalent, thousands of barrels of oil equivalent and millions of barrels of oil equivalent, respectively, on the basis of one BOE being equal to one barrel of oil or NGL or six Mcf of natural gas;

"BOE/d" refers to barrels of oil equivalent per day;

"CBM" refers to natural gas, primarily methane, producible from coal seams, commonly called coal bed methane;

"Cdn$" refers to Canadian dollars;

"CO₂" refers to carbon dioxide which is a gas at room temperature and pressure. However, at higher pressures, such as those used in EOR miscible floods, carbon dioxide is a liquid;

"cP" refers to centipoise, a unit measure of viscosity;

"CSOR" refers to the efficiency of a steam injection recovery process and is a measure of the cumulative volume of steam, in equivalent barrels of water, required to produce a cumulative volume of bitumen as of the same point in time;

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"EDGAR" refers to the Electronic Data Gathering Analysis and Retrieval System maintained by the SEC;

"EOR" refers to enhanced oil recovery;

"EPEA" means the Environmental Protection and Enhancement Act (Alberta), RSA 2000, c E-12, as amended, including the regulations promulgated thereunder;

"F&D Costs" refers to finding and development costs;

"FD&A Costs" refers to finding, development and acquisition costs;

"FDC" refers to Future Development Costs;

"GHG" refers to greenhouse gas;

"H₂S" refers to hydrogen sulphide gas;

"IFRS" refers to International Financial Reporting Standards;

"ISOR" refers to Instantaneous Steam Oil Ratio;

"Mcf", "MMcf" and "Bcf" refers to thousands of cubic feet, millions of cubic feet and billions of cubic feet, respectively;

"McfGE" refers to thousand cubic feet of gas equivalent on the basis of one barrel of oil or one barrel of NGL being equal to six Mcf of natural gas;

"Mcf/d" and "MMcf/d" refers to thousands of cubic feet per day and millions of cubic feet per day, respectively;

"MMBtu" refers to million British thermal units;

"mPa-s" refers to millipascal-second, a derived metric system international measurement unit of dynamic viscosity;

"MW" refers to megawatts;

"NGL" refers to natural gas liquids;

"NYSE" refers to the New York Stock Exchange;

"P+P" refers to Total Proved Plus Probable Reserves;

"RLI" refers to Reserve Life Index;

"SAGD" refers to steam assisted gravity drainage;

"SEC" refers to the United States Securities and Exchange Commission;

"SEDAR" refers to the System for Electronic Document Analysis and Retrieval of the Canadian Securities Administrators;

"TSX" refers to the Toronto Stock Exchange;

"US$" refers to United States dollars;

"US GAAP" refers to United States generally accepted accounting principles;

"WCS" refers to Western Canada Select;

"WCSB" refers to the Western Canadian Sedimentary Basin; and

"WTI" refers to West Texas Intermediate crude oil.

Disclosure provided herein in respect of a BOE and an McfGE may be misleading, particularly if used in isolation. A BOE conversion ratio of six (6) Mcf of natural gas to one barrel of oil and an McfGE conversion ratio of one barrel of oil to six (6) Mcf of natural gas is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. In addition, given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalent of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value.

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CONVERSION

In this Annual Information Form, measurements are given in standard imperial or metric units only. The following table sets forth certain standard conversions:

To Convert From	To	Multiply by
Mcf	cubic metre	28.174
Mcf	BOE	0.1667
bbl	BOE	1.0
MMBtu	gigajoule	1.0546
cubic metre	bbl	6.29
metre	feet	3.281
mile	kilometre	1.609
hectare	acre	2.471

PRESENTATION OF OUR FINANCIAL INFORMATION

Financial information in this Annual Information Form has been prepared in accordance with International Financial Reporting Standards ("IFRS"). IFRS differs in some significant respects from United States generally accepted accounting principles ("US GAAP") and thus our financial statements may not be comparable to the financial statements of companies following US GAAP.

Unless otherwise stated, all sums of money referred to in this Annual Information Form are expressed in Canadian dollars.

PRESENTATION OF OUR RESERVE AND RESOURCE INFORMATION

National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities ("NI 51-101") of the Canadian Securities Administrators permits oil and gas issuers, in their filings with Canadian securities regulators, to disclose not only Proved Reserves but also Probable Reserves, Possible Reserves and Contingent Resources, and to disclose reserves and production on a gross basis before deducting royalties. Probable Reserves and Possible Reserves are of a higher risk and are less likely to be accurately estimated or recovered than Proved Reserves. Contingent Resources are higher risk than Probable Reserves and Possible Reserves and are less likely to be accurately estimated or recovered than Probable Reserves or Possible Reserves. Because we are permitted to prepare this Annual Information Form in accordance with Canadian disclosure requirements, we have disclosed in this Annual Information Form resources designated as Probable Reserves, Possible Reserves and Contingent Resources and have disclosed reserves and production on a gross basis before deducting royalties.

Current SEC reporting requirements permit oil and gas companies to disclose Probable Reserves and Possible Reserves, in addition to the required disclosure of Proved Reserves. If this Annual Information Form was required to be prepared in accordance with US disclosure requirements, the SEC's requirements would prohibit Contingent Resources from being disclosed. Under current SEC requirements, net quantities of reserves are required to be disclosed, which requires disclosure on an after royalties basis and does not include reserves relating to the interests of others. For a description of these and additional differences between Canadian and US standards of reporting reserves, see "Risk Factors — Canadian and United States practices differ in reporting reserves and production and our estimates may not be comparable to those of companies in the United States". Additional information prepared in accordance with the US Financial Accounting Standards Board's Accounting Standards Update (Extractive Activities-Oil and Gas (Topic 932)) relating to our oil and gas reserves is set forth in our current Form 40-F, which is available through EDGAR at the SEC's website at www.sec.gov.

FORWARD-LOOKING STATEMENTS

This Annual Information Form 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 Annual Information Form include, but are not limited to: business strategy and strengths, goals, focus and the effects thereof, capital expenditures, reserves, resources, reserve life indices, estimated production, remaining producing reserves lives, operating expenses, asset retirement obligations, royalty rates, net present values of Future Net Revenue from reserves, commodity prices and costs, exchange rates, development plans and programs, Future Development Costs and the funding thereof, tax horizon, future income taxes, abandonment and reclamation costs and expiring acreage. Statements relating to reserves and resources are forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions that the reserves and resources described exist in the quantities predicted or estimated and can profitably be produced in the future.

PENGROWTH ENERGY CORPORATION | 2017 ANNUAL INFORMATION FORM     5

Forward-looking statements and information are based on our current beliefs as well as assumptions made by, and information currently available to, us concerning anticipated financial performance, business prospects, strategies, regulatory developments, future bitumen, oil and natural gas commodity prices and differentials between light crude oil, medium crude oil and heavy crude oil prices, future oil and natural gas production levels, future exchange rates, the proceeds of anticipated divestitures, the amount of future cash dividends paid by the Corporation, the cost of expanding our property holdings, our ability to obtain equipment in a timely manner to carry out development activities, our ability to market our oil and gas successfully to current and new customers, the impact of increasing competition, our ability to obtain financing on acceptable terms, and our ability to add production and reserves through our acquisition, development 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 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; production and development costs and capital expenditures; the imprecision of reserve estimates and estimates of recoverable quantities of oil, natural gas and liquids; unforeseen operating problems; pipeline or delivery constraints; our ability to replace and expand oil and gas reserves; 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; our ability to access external sources of debt and equity capital; and the implementation of GHG emissions legislation. Further information regarding these factors may be found under the heading "Risk Factors" in this Annual Information Form, under the heading "Business Risks" in our Management's Discussion and Analysis for the year ended December 31, 2017, and in our most recent consolidated financial statements, management information circular, quarterly reports, material change reports and news releases.

Readers are cautioned 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 Annual Information Form are made as of the date of this document and we do not undertake any obligation to update publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise, except as required by applicable law. The forward-looking statements contained in this Annual Information Form are expressly qualified by this cautionary statement.

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nPENGROWTH ENERGY CORPORATION

INTRODUCTION

The Corporation is engaged in the development, production and acquisition of, and the exploration for, oil and natural gas reserves in the provinces of Alberta, British Columbia, Saskatchewan and Nova Scotia. The Corporation is the successor to Pengrowth Energy Trust.

The Corporation was originally incorporated pursuant to the ABCA on October 4, 2010, as 1562803 Alberta Ltd. and changed its name to Pengrowth Energy Corporation on December 2, 2010. The Corporation amalgamated with its wholly-owned subsidiaries NAL Energy Corporation, NAL Properties Inc. and NAL Canada West Inc. on January 1, 2013.

The head office and registered office of the Corporation is located at 1600, 222 – 3rd Avenue S.W., Calgary, Alberta, Canada, T2P 0B4.

GENERAL DEVELOPMENT OF THE BUSINESS

Recent Developments

On February 20, 2018, we announced that Derek Evans, our President and Chief Executive Officer, would be retiring as a director and officer of the Corporation on March 14, 2018 and that he would be succeeded in his roles by Mr. Peter Sametz.

On February 9, 2018, Seymour Schulich acquired beneficial ownership or control of an additional 2,000,000 Common Shares bringing his aggregate holdings to 136,000,000 Common Shares representing 24.63 percent of our outstanding Common Shares.

On January 26, 2018, Seymour Schulich acquired beneficial ownership or control of an additional 1,000,000 Common Shares bringing his aggregate holdings to 134,000,000 Common Shares representing 24.26 percent of our outstanding Common Shares.

On January 25, 2018, we announced the promotion of Randy Steele to the position of Chief Operating Officer and the departure of Steve De Maio, who was our Senior Vice President, Thermal Operations, since May 2015 and prior thereto, our Vice President, In-Situ Oil Development and Operations.

On January 17, 2018, we announced our 2018 capital program and provided guidance on 2018 expected production and costs. Our 2018 capital budget reflects our plan to spend $65 million in 2018.

Three Year Historical Overview

On December 21, 2017, we completed the sale of our Quirk Creek assets in Southern Alberta for total cash consideration of $6.5 million, to be received in installments, subject to customary adjustments.

On December 19, 2017, Seymour Schulich acquired beneficial ownership or control of an additional 3,000,000 Common Shares bringing his aggregate holdings to 133,000,000 Common Shares representing 24.08 percent of our then issued and outstanding Common Shares.

On December 1, 2017, we received notice from the NYSE that our Common Shares were no longer in compliance with one of the exchange's continued listing standards resulting from the average closing price of our Common Shares being less than US$1.00 per share over a consecutive 30 trading-day period.

On November 16, 2017 and December 8, 2017, we prepaid an aggregate of approximately $40 million of our senior notes.

On November 3, 2017, we completed the sale of our remaining Swan Hills assets for $150 million, $12.5 million of which was deferred until June 2018, before customary closing adjustments with the net proceeds used to reduce indebtedness.

On November 1, 2017, we announced that we had received notification from the NYSE that we were back in compliance with the continued listing standards of the NYSE as of October 31, 2017.

On October 23, 2017, we completed the sale of the vast majority of our non-core Alberta legacy assets for nominal cash consideration and the assumption by the purchaser of abandonment and reclamation liabilities.

On October 12, 2017, we prepaid all US$265 million of our outstanding 6.98 percent 2008 senior notes, all $15 million of our outstanding 6.61 percent 2008 senior notes and approximately $78 million of remaining senior notes. We also announced that we had finalized the terms of amending agreements with our lenders under our Credit Facility and with the holders of our remaining Term Notes. The amendments included the granting of security over our assets, a substantial reduction in the size of our credit facility and a relaxation of existing covenant ratios for a period up to and including the quarter ended September 30, 2019.

On October 2, 2017, Mr. Seymour Schulich announced that he had acquired beneficial ownership or control of an additional 21,000,000 Common Shares bringing his aggregate holdings to 130,000,000 Common Shares representing 23.5 percent of the then issued and outstanding Common Shares.

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On August 11, 2017, we completed the sale of our Olds/Garrington assets for cash consideration of $300 million prior to closing adjustments.

On July 6, 2017, we completed the sale of a portion of our Swan Hills assets in North Central Alberta for total cash consideration of $185 million, prior to closing adjustments.

On June 2, 2017, we prepaid the remaining outstanding US$100 million of our 6.35 percent 2007 senior notes.

On May 16, 2017, we received notice from the NYSE that our Common Shares were no longer in compliance with one of the exchange's continued listing standards resulting from the average closing price of our common shares being less than US$1.00 per share over a consecutive 30 trading-day period.

On April 11, 2017, we completed the sale of our non-producing Montney lands at Bernadet in North East British Columbia for cash consideration of $92 million.

On April 3, 2017, we announced that we had prepaid US$300 million of our 6.35 percent 2007 senior notes.

On March 31, 2017, we redeemed all $126.6 million of our 6.25 percent series B convertible debentures on maturity, with cash on hand.

On February 9, 2017, we amended our Credit Facility to remove the Senior Debt to Total Capitalization covenant.

On February 8, 2017, Ms. Margaret L. Byl resigned from our Board for medical reasons.

On January 18, 2017, we announced our 2017 interim capital program and provided guidance on 2017 expected production and costs. Our 2017 interim capital budget reflected our plan to spend $125 million in 2017.

On January 6, 2017, we completed the sale of a four percent non-convertible gross overriding royalty on our Lindbergh assets and an interest in certain proprietary seismic for aggregate cash consideration of $250 million. The four percent overriding royalty would represent a 10.7 percent decrease (at a ten percent discount rate) in the December 31, 2016 P+P net present value of future net revenue for Lindbergh.

2016

On December 21, 2016, we amended our Term Notes to waive compliance at December 31, 2016, with the Total Debt to Total Capitalization covenant.

On December 14, 2016, we announced that we had entered into a definitive agreement for the sale of a four percent non-convertible gross overriding royalty interest on our Lindbergh thermal project and an interest in certain proprietary seismic for $250 million aggregate cash consideration.

On October 6, 2016, we announced a 21 percent increase in our P+P reserves at our Lindbergh thermal project and a corresponding 63 percent increase in the value of our P+P reserves from $1.56 billion to $2.55 billion, compared to year end 2015.

On June 28, 2016, Messrs. John B. Zaozirny and Michael S. Parrett retired as directors of the Corporation. Mr. Kelvin B. Johnston was appointed Chairman of the Board to fill the vacancy created by Mr. Zaozirny's retirement.

On May 30, 2016, we announced that we had received approval under the EPEA for our 17,500 bbl/d second commercial phase of our Lindbergh thermal project.

On May 3, 2016, we reported our first quarter financial results and announced that we had received notification from the NYSE that we were back in compliance with the continued listing standards of the NYSE as of April 29, 2016.

On March 23, 2016, Mr. Seymour Schulich announced that he had acquired beneficial ownership or control of an aggregate of 80,000,000 Common Shares representing 14.7 percent of the then issued and outstanding Common Shares. Over the remainder of 2016, Mr. Schulich made several additional acquisitions. In his most recent filing dated February 9, 2017, Mr. Schulich announced that he beneficially owns or controls 109,000,000 Common Shares representing 19.90 percent of the then issued and outstanding Common Shares.

On February 25, 2016, we announced the launch of a normal course issuer bid for up to 10 percent of our 6.25 percent series B convertible debentures. Through to December 31, 2016, the Corporation had repurchased and cancelled an aggregate of $10.2 million principal amount of the outstanding 6.25 percent series B convertible debentures at an aggregate cost of $9.2 million. This normal course issuer bid expired on February 28, 2017 with no additional repurchases in 2017.

On January 20, 2016, we announced our 2016 capital program and provided guidance on 2016 expected production and costs. Our 2016 capital budget reflected our plan to spend between $60 and $70 million in 2016. We also announced, at the same time, the suspension of our dividend until further notice.

2015

On December 1, 2015, our 5.46 percent £50,000,000 term notes matured and were repaid.

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On December 10, 2015, we amended our Credit Facility by increasing the maximum permitted Senior Debt to Total Capitalization ratio from 50 percent to 55 percent. This amendment was obtained to align this covenant between our Credit Agreement and various note purchase agreements which already allowed a maximum Senior Debt to Total Capitalization ratio of 55 percent. All other material terms and conditions remained unchanged.

On November 30, 2015, we completed the sale of our non-core Jenner assets in southeastern Alberta for cash consideration of $77.6 million (after closing adjustments).

On November 3, 2015, we reported our third quarter financial results including a non-cash, after-tax impairment charge of $375 million.

On October 30, 2015, we completed the sale of our non-core Bodo property in eastern Alberta for $86.7 million (after closing adjustments).

On October 29, 2015, we announced the receipt of notification from the NYSE of non-compliance with its continued listing standards resulting from the average closing price of our Common Shares being less than US$1.00 per share over a consecutive 30 trading-day period.

On September 1, 2015, we announced a change to our dividend policy, moving to a quarterly payment at a rate of $0.01 per share per quarter and suspending the dividend reinvestment and optional common share purchase plan.

On June 8, 2015, we reported that production from our Lindbergh thermal project exceeded the project's nameplate capacity of 12,500 bbl/d.

On May 12, 2015, we announced the appointments of Steve De Maio as Senior Vice President, Thermal Operations and Randy Steele asSenior Vice President, Conventional Operations.

On May 11, 2015, our 4.67 percent US$71.5 million senior notes, series A matured and were repaid.

On April 28, 2015, we announced the departures of Marlon McDougall and James Causgrove who were our Chief Operating Officer and Senior Vice President, Operations, respectively.

On April 14, 2015, we announced the appointment of Jamie Sokalsky to our Board.

On March 30, 2015 we renewed and extended our Credit Facility from July 26, 2017 to March 31, 2019. At this time we also amended the maximum permitted Senior Debt to EBITDA ratio from 3.0 to 3.5 and the Total Debt to EBITDA ratio from 3.5 to 4.0.

On February 26, 2015, we announced our 2014 year end results including a non-cash, after-tax impairment charge of approximately $858 million.

On January 21, 2015, we announced our 2015 capital program and provided guidance on 2015 expected production and costs. We also announced a reduction in our dividend from $0.04 per share per month to $0.02 per share per month beginning with the dividend payable on March 16, 2015. Our 2015 capital budget reflected our plan to spend between $220 million and $240 million in 2015.

DESCRIPTION OF OUR BUSINESS

GENERAL

We are engaged in the development, production and acquisition of, and the exploration for, oil and natural gas reserves in the provinces of Alberta, British Columbia, Saskatchewan and Nova Scotia. Our long term goal is to maximize value creation for the benefit of our Shareholders. Our competitive position is dependent on our ability to execute our business strategy. We believe we have the skills and financial capacity to develop our opportunities. A key factor affecting our finances is commodity prices over which we have no control.

As at December 31, 2017, we had 186 permanent employees.

BUSINESS STRATEGY

Our corporate strategy is to build a sustainable entity through the development of our large accumulations of bitumen and natural gas with their associated low declines and low cost structures.

Our operational focus is to progress with a measured development of our thermal project at Lindbergh. We continue to deploy horizontal well multi-stage fracturing technology at our natural gas property at Groundbirch. Both Lindbergh and Groundbirch provide significant future drilling and development opportunities with Lindbergh having the potential to produce 40,000 to 50,000 bbl/d of bitumen. See additional details on these properties under “Operational Information – Principal Producing Properties” below.

For 2018, we have established a $65 million capital spending level that is focused on adding production volumes from our two, core 100 percent owned assets at Lindbergh and Groundbirch.

We have rigorous health, safety and environmental protection policies aimed at ensuring that our operations are conducted in a safe and prudent manner. These policies also encompass our remediation, abandonment and site reclamation activities.

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OPERATIONAL INFORMATION

PRINCIPAL PRODUCING PROPERTIES

The following table summarizes our principal producing properties as of December 31, 2017 based on the GLJ Report using forecast prices and costs. The following table utilizes data from the GLJ Report in respect of our oil and gas properties effective December 31, 2017. The table also contains our average daily production of oil, bitumen, natural gas, shale gas and NGL for the year ended December 31, 2017.

Summary of Company Interest at December 31, 2017⁽¹⁾
(Forecast Prices and Costs)⁽²⁾ 

	P+P	Remaining	P+P Reserve	P+P Value Before Tax	2017 Oil	2017 Bitumen	2017 Gas	2017 Shale Gas	2017 NGL	2017 Total
	Reserves	Reserve Life	Life Index	Discounted at 10%(4)	Production	Production	Production	Production	Production	Production
Field	(Mboe(3))	(years)	(years)	($MM)	(bbl/d)	(bbl/d)	(MMcf/d)	(MMcf/d)	(bbl/d)	(BOE/d(3))
Lindbergh	317,057	26	44.5	1,763,534	-	13,754	-	-	-	13,754
Groundbirch	124,409	50	133.8	346,491	-	-	-	10.4	-	1,729
Subtotal	441,466	50	54.9	2,110,025	-	13,754	-	10.4	-	15,483
Remainder(5)	5,166	50	4.9	60,251	6,872.1	-	81	-	4,573.8	24,945
Total	446,632	50	49.0	2,170,276	6,872.1	13,754	81	10.4	4,573.8	40,428

Notes:

(1) The estimates of reserves and Future Net Revenue for individual properties may not reflect the same confidence level as estimates of reserves and Future Net Revenue for all properties, due to the effects of aggregation.

(2) Forecast prices are shown under the heading "Pricing Assumptions".

(3) Natural gas has been converted to barrels of oil equivalent on the basis of six (6) Mcf of natural gas being equal to one barrel of oil.

(4) Estimated Future Net Revenues disclosed do not represent fair market value.

(5) "Remainder" includes our Working Interests and Royalty Interests in 16 other properties.

Lindbergh

The Lindbergh thermal property is located approximately 420 kilometres north east of Calgary, Alberta and 50 kilometres south of Bonnyville, Alberta. We have a 100 percent Working Interest in the Lindbergh oil sands leases, located in the Cold Lake oil sands district in northeastern Alberta and covering 20,800 net acres (32.5 sections). Our Lindbergh area assets include our 100 percent owned Muriel Lake property located approximately eight kilometres to the north east of the Lindbergh lease and is comprised of an additional 6,400 net acres (10 sections). The Corporation has drilled and evaluated 214 gross wells, including evaluation/observation wells, SAGD well pairs and in-fill wells since acquiring the Lindbergh area properties in 2004. Additionally, Pengrowth has 101 square kilometres of interpreted proprietary three dimensional seismic data covering our prospective properties.

The main bitumen resource at Lindbergh is located within the Lloydminster Formation of the Mannville Group, at an approximate depth of 500 metres. Oil gravity (quality) ranges from 9.5 - 11 ^oAPI. The average exploitable reservoir pay thickness is 19.2 metres in the 12,500 bbl/d first phase commercial project area. There appears to be no top water or top gas thief zones within the Lloydminster Formation in the project development area. A competent cap-rock is provided by the General Petroleum shale, which is pervasive and consistent throughout the area.

The Lindbergh pilot facility, well pad and two SAGD well pairs were constructed, drilled and completed in December 2011 with first steam in February 2012. In July 2013, the first commercial development project received regulatory approval under EPEA and Pengrowth constructed a central processing facility ("CPF"), three well pads, surface pipelines, 20 well pairs, a 15 MW cogeneration plant and other associated infrastructure with a design capacity of 12,500 bbl/d of bitumen. The pilot wells were tied into the new CPF and the project achieved first steam in December 2014. Production has consistently been above the design capacity of 12,500 bbl/d since start up.

In May 2016, regulatory approval was received to increase the average annual production throughput to 30,000 bbl/d of bitumen at Lindbergh. As a result, the Phase 1aexpansion project was initiated in 2017 and is anticipated to increase produced bitumen rates to in excess of 18,000 bbl/d peak production by the end of 2018. Phase 1a includes nine new well pairs from a new pad location, as well as one new well pair and two infill wells from an existing pad and an anticipated eight new infill wells to be drilled and completed from a second existing pad location in 2017. As of December 31, 2017, two infill wells and seven well pairs were on stream in varying phases of operation with the remaining wells anticipated to be drilled and on stream through the second and third quarters of 2018.

Over the life of the current Phase 1 commercial project, a total of 159 well pairs (including the 32 existing well pairs) are expected to be drilled from several pad sites within the project area, recovering Proved Reserves of 164 MMbbl of bitumen remaining as of December 31, 2017. The production life for each individual well pair is expected to be eight to nine years.

With expansion to 40,000 bbl/day of capacity, the project is expected to recover 317 MMbbl of Total Proved Plus Probable Reserves as of December 31, 2017, from a total of 268 well pairs, including the 32 existing well pairs, and 266 infill wells, including the two existing infill wells (online in June, 2017). The EPEA and scheme amendment application for the expansion to 40,000 bbl/d was approved on August 1, 2017. Given the strong results to-date, additional productivity is thought to be possible and anticipated from the existing

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infrastructure and from future expansion opportunities. There is also potential for further development to attain approximately 50,000 bbl/d over all of the Pengrowth lands in the Lindbergh area when including the Muriel Lake lease.

As mentioned above under "General Development of the Business - Three Year Historical Overview" , in January 2017, we sold a four percent non-convertible gross overriding royalty on our Lindbergh assets and an interest in certain proprietary seismic for aggregate cash consideration of $250 million.

For additional information, see “Lindbergh Oil Sands Reserves and Contingent Resources” in Appendix A to this Annual Information Form.

On December 13, 2016, the Corporation and Koch Oil Sands Operating ULC ("Koch") submitted an EPEA application to the AER with respect to the potential development of the Selina SAGD Project located approximately 50 kilometres south east of Bonnyville, Alberta. The proposed project is designed for an annual average production rate of 12,500 bbl/d of bitumen. It is a 50/50 joint venture between the Corporation and Koch. Koch is the operator of this project. AER approval for these applications typically requires 24 months.

For additional information, see "Selina Oil Sands Contingent Resources" in Appendix A to this Annual Information Form.

Groundbirch

Our Groundbirch property is located approximately 40 kilometres south west of Fort St. John, British Columbia and covers an area of 12,536 gross/net acres. We have a 100 percent Working Interest in these lands. At Groundbirch, we currently have 17 producing wells producing approximately 9.5 MMcf/d of gas from the Montney formation, with little or no liquids.

The gas bearing Montney formation occurs at a vertical depth of approximately 2,200 metres and has a gross thickness of up to 230 metres. The Montney consists of thin, laminated interbedded sands, silts and shales and has very low permeability, in the order of one micro-Darcy. As a result of the very low permeability, the reservoir is developed with horizontal wells using multi-stage fracture technology.

During 2017, Pengrowth completed the drilling of four horizontal Montney wells at Groundbirch. All four wells are landed in the Upper Montney zone. Two wells are landed in the U2 (mid-horizon in the Upper Montney) with 1,300 metre and 3,000 metre lateral lengths, respectively, and two are landed in the U3 (lower horizon in the Upper Montney), each with 1,300 metre lateral lengths. Well stimulations, tie-in and completion of the gas plant sales gas pipeline tie-in to TransCanada Pipeline's ("TCPL's") NOVA Gas Transmission Ltd. System ("NGTL system") are expected to be completed for April 2018 commissioning. When fully operational, the anticipated sales gas volume is expected to be 30 MMcf/d flowing onto TCPL's NGTL system in Alberta.

For additional information, see “Groundbirch Reserves and Contingent Resources” in Appendix A to this Annual Information Form.

STATEMENT OF OIL AND GAS RESERVES AND RESERVES DATA

Disclosure of Reserves Data

The information in this section is based upon an evaluation by GLJ, prepared in accordance with NI 51-101, with an effective date of December 31, 2017 contained in the GLJ Report, with the exception of information relating to income tax and the after-tax Future Net Revenues associated with our reserves, which we determined. The effective date of the information in this section is December 31, 2017 and the preparation date is January 18, 2018 when the final information was provided. The information in this section summarizes our oil, liquids and natural gas reserves and the net present values of Future Net Revenue for these reserves using GLJ's forecast prices and costs and constant prices and costs. We engaged GLJ to provide an independent evaluation of Proved Reserves and Proved Plus Probable Reserves for all our properties. It is our practice to obtain an engineering report evaluating all of our Proved Reserves and Probable Reserves as at December 31 of each year. Only in respect of the Lindbergh oil sands property and the Groundbirch natural gas property did GLJ evaluate Possible Reserves and Contingent Resources. GLJ also evaluated Contingent Resources in our Selina oil sands property. The GLJ evaluation of Possible Reserves and Contingent Resources is discussed in Appendix A to this Annual Information Form. All of our reserves are in Canada in the provinces of Alberta, British Columbia, Saskatchewan and Nova Scotia. In certain instances in this Annual Information Form, we have presented estimates of reserves, Future Net Revenue and Contingent Resources for individual properties. The estimates of reserves, Future Net Revenue and Contingent Resources for individual properties may not reflect the same confidence level as estimates of reserves, Future Net Revenue and Contingent Resources for all properties, due to the effects of aggregation.

The following tables set forth certain information relating to our oil and natural gas reserves and the net present value of the estimated Future Net Revenue associated with such reserves as at December 31, 2017 contained in the GLJ Report. These tables summarize the data contained in the GLJ Report, and, as a result, may contain slightly different numbers than the GLJ Report due to rounding. Columns or rows may not add due to rounding.

Our Future Net Revenues associated with the production and reserves contained in this Annual Information Form reflect the royalty programs in-place on December 31, 2017.

The information set forth below is derived from the GLJ Report, which has been prepared in accordance with the standards contained in the Canadian Oil and Gas Evaluation ("COGE") Handbook and the reserves definitions contained in NI 51-101 and the COGE Handbook. The GLJ Report incorporates estimates of abandonment and reclamation costs for existing and future wells to which reserves have been assigned and for certain facilities. The GLJ forecasts of Future Net Revenue are stated prior to any provision for income taxes, interest

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costs or general and administrative costs and after the deduction of estimated future capital expenditures for wells to which reserves have been assigned. The estimated Future Net Revenue shown below does not represent the fair market value of the properties. There is no assurance that such price and cost assumptions will be attained and variances could be material. The recovery and estimates of crude oil, NGL and natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual crude oil, NGL and natural gas reserves may be greater than or less than the estimates provided herein.

We determined the Future Net Revenue and present value of Future Net Revenue after income taxes by utilizing GLJ’s before income tax Future Net Revenue and our estimate of income tax. Our estimate of cash income tax makes use of the following assumptions:

• Corporate income tax at the current legislated rate;

• Annual general and administrative expenses at the current rate;

• Interest expense at the current rate;

• Tax pool deductions utilizing our existing $2.4 billion of tax pools and forecasted additions to our tax pools from capital expenditures as forecast by GLJ; and

• Any such other additional deductions and adjustments as is and would be consistent with the manner in which we file and would file future tax returns.

The after-tax net present value of our oil and gas properties reflects the tax burden of our properties on a stand-alone basis. It does not provide an estimate of the value of us as a business entity, which may be significantly different.

The net revenues estimated in the GLJ Report represent estimates of the revenues from oil and gas sales from our petroleum and natural gas properties together with an estimate of processing revenues less royalties (net of incentives), mineral taxes, field operating expenses, certain abandonment and reclamation costs and capital obligations. These net revenues are not the same as cash flows from operating activities reported by the Corporation in our statement of cash flows. The GLJ Report does not estimate general and administrative expenses and interest.

In accordance with the requirements of NI 51-101, the Report on Reserves Data and Contingent Resources Data by Independent Qualified Reserves Evaluator or Auditor in Form 51-101F2 and the Report of Management and Directors on Oil and Gas Disclosure in Form 51-101F3 are attached to this Annual Information Form as Appendices B and C, respectively.

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Reserves Data (Forecast Prices and Costs)

Summary of Oil and Gas Reserves as of December 31, 2017
(Forecast Prices and Costs)⁽¹⁾ 

	Light Crude Oil and Medium Crude Oil			Heavy Crude Oil			Bitumen			Natural Gas Liquids
	Company Interest	Gross Interest	Net Interest	Company Interest	Gross Interest	Net Interest	Company Interest	Gross Interest	Net Interest	Company Interest	Gross Interest	Net Interest
Reserves Category	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)
Proved Reserves
Proved Developed Producing	1,976	1,975	1,774	-	-	-	24,733	24,733	22,721	97	96	84
Proved Developed Non-Producing	57	56	54	-	-	-	-	-	-	43	42	34
Proved Undeveloped	6	6	5	-	-	-	138,600	138,600	106,621	2	2	2
Total Proved Reserves	2,038	2,037	1,833	-	-	-	163,334	163,334	129,342	142	141	121
Probable Reserves	673	672	603	-	-	-	153,724	153,724	116,620	29	29	25
Total Proved Plus Probable Reserves	2,712	2,709	2,437	-	-	-	317,057	317,057	245,961	171	170	145

	Conventional Natural Gas			Shale Gas			Coal Bed Methane			Total Oil Equivalent Basis(2)
	Company Interest	Gross Interest	Net Interest	Company Interest	Gross Interest	Net Interest	Company Interest	Gross Interest	Net Interest	Company Interest	Gross Interest	Net Interest
Reserves Category	(MMcf)	(MMcf)	(MMcf)	(MMcf)	(MMcf)	(MMcf)	(MMcf)	(MMcf)	(MMcf)	(Mboe)	(Mboe)	(Mboe)
Proved Reserves
Proved Developed Producing	4,776	4,630	4,324	31,354	31,354	29,490	2,582	2,500	2,412	33,257	33,218	30,617
Proved Developed Non-Producing	2,117	2,059	1,829	-	-	-	646	646	595	560	549	492
Proved Undeveloped	-	-	-	121,493	121,493	106,297	258	258	245	158,900	158,900	124,385
Total Proved Reserves	6,892	6,689	6,154	152,847	152,847	135,786	3,486	3,404	3,251	192,718	192,668	155,494
Probable Reserves	1,339	1,262	1,202	593,606	593,606	500,802	1,980	1,943	1,865	253,914	253,894	201,226
Total Proved Plus Probable Reserves	8,231	7,951	7,356	746,452	746,452	636,588	5,465	5,348	5,116	446,632	446,561	356,720

Notes:

(1) Forecast prices are shown under the heading "Pricing Assumptions".

(2) Natural gas has been converted to barrels of oil equivalent on the basis of six (6) Mcf of natural gas being equal to one barrel of oil.

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Summary of Net Present Value of Future Net Revenue as of December 31, 2017
Before and After Income Taxes (Forecast Prices and Costs)⁽¹⁾ 

	Before Income Taxes Discounted at (%/year) - $MM										Unit Value Before Income Tax Discounted at 10%/year(2) (3)
Reserves Category	0	%	5	%	10	%	15	%	20	%	$/BOE	$/McfGE
Proved Reserves
Proved Developed Producing	568		516		472		433		400		15.40	2.57
Proved Developed Non-Producing	4		2		1		1		1		2.42	0.40
Proved Undeveloped	3,102		1,442		759		435		263		6.10	1.02
Total Proved Reserves	3,674		1,960		1,231		869		663		7.92	1.32
Probable Reserves	4,417		2,016		939		415		146		4.67	0.78
Total Proved Plus Probable Reserves	8,090		3,976		2,170		1,285		809		6.08	1.01

	After Income Taxes Discounted at (%/year)(4) - $MM
Reserves Category	0	%	5	%	10	%	15	%	20	%
Proved Reserves
Proved Developed Producing	568		516		472		433		400
Proved Developed Non-Producing	4		2		1		1		1
Proved Undeveloped	2,477		1,290		718		421		255
Total Proved Reserves	3,049		1,807		1,191		855		656
Probable Reserves	3,029		1,380		617		242		48
Total Proved Plus Probable Reserves	6,078		3,187		1,808		1,097		701

Notes:

(1) Forecast prices are shown under the heading "Pricing Assumptions".

(2) Net present value of Future Net Revenue per reserve unit values are based on our net reserves.

(3) Natural gas has been converted to barrels of oil equivalent on the basis of six (6) Mcf of natural gas being equal to one barrel of oil. Oil and NGL have been converted to thousand cubic feet of natural gas equivalent on the basis of one barrel of oil or NGL being equal to six (6) Mcf of natural gas.

(4) After-tax values were calculated using current corporate tax rates, existing tax pools and additions to the tax pools through capital expenditures as forecast by GLJ. See – "Operational Information - Statement of Oil and Gas Reserves and Reserves Data – Disclosure of Reserves Data" for additional descriptions of the assumptions made in calculating the after-tax values.

Total Future Net Revenue (undiscounted) as of December 31, 2017
(Forecast Prices and Costs)⁽¹⁾ ($MM)

Reserves Category	Revenue	Royalties(2)	Operating Costs	Development Costs	Abandonment and Reclamation Costs(3)	Future Net Revenue Before Income Taxes	Income Tax	Future Net Revenue After Income Taxes
Total Proved	12,132	2,580	3,602	1,932	344	3,674	624	3,050
Total Proved Plus Probable	24,951	5,574	5,745	4,941	601	8,090	2,012	6,078

Notes:

(1) Forecast prices are shown under the heading "Pricing Assumptions".

(2) Crown royalties payable to the provinces of Alberta, British Columbia, Saskatchewan and Nova Scotia, freehold and over-riding royalties payable and other minor burdens.

(3) Includes GLJ’s forecast of well abandonment and reclamation costs, abandonment of Sable Island facilities and subsea pipelines and abandonment and reclamation of the Lindbergh central processing facility, based on estimates by the Corporation, but does not include abandonment and surface reclamation costs for any other facilities. See "Operational Information – Significant Factors or Uncertainties Affecting Reserves Data - Additional Information Concerning Abandonment & Reclamation Costs".

PENGROWTH ENERGY CORPORATION | 2017 ANNUAL INFORMATION FORM     14

Net Present Value of Future Net Revenue By Product Type as of December 31, 2017
(Forecast Prices and Costs)⁽¹⁾ 

		Future Net Revenue Before Income Taxes (discounted at 10%/year)	Unit Value(4)(5)
Reserves Category	Product Type	($MM)	($/BOE)	($/McfGE)
Total Proved	Light Crude Oil and Medium Crude Oil (including solution gas and other by-products)(2)	33	16.30	2.72
	Heavy Crude Oil (including solution gas and other by-products)(2)	-	-	-
	Bitumen	1,098	8.49	1.42
	Conventional Natural Gas (including by-products but excluding solution gas from oil wells)(3)	2	2.41	0.40
	Shale Gas	97	4.31	0.72
	Coal Bed Methane	-	0.76	0.13
	Total	1,231	7.92	1.32
Total Proved Plus Probable	Light Crude Oil and Medium Crude Oil (including solution gas and other by-products)(2)	41	15.22	2.54
	Heavy Crude Oil (including solution gas and other by-products)(2)	-	-	-
	Bitumen	1,713	6.97	1.16
	Conventional Natural Gas (including by-products but excluding solution gas from oil wells)(3)	4	3.64	0.61
	Shale Gas	411	3.87	0.65
	Coal Bed Methane	1	1.49	0.25
	Total	2,170	6.08	1.01

Notes:

(1) Forecast prices are shown under the heading "Pricing Assumptions".

(2) NGL associated with the production of solution gas are included as a by-product.

(3) NGL associated with the production of natural gas are included as a by-product.

(4) Net present value of Future Net Revenue per BOE or McfGE are based on our net reserves.

(5) Natural gas has been converted to barrels of oil equivalent on the basis of six (6) Mcf of natural gas being equal to one barrel of oil. Oil and NGL have been converted to thousand cubic feet of natural gas equivalent on the basis of one barrel of oil or NGL being equal to six (6) Mcf of natural gas.

PENGROWTH ENERGY CORPORATION | 2017 ANNUAL INFORMATION FORM     15

Reserves Data (Constant Prices and Costs)

Summary of Oil and Gas Reserves as of December 31, 2017
(Constant Prices and Costs)⁽¹⁾ 

	Light Crude Oil and Medium Crude Oil			Heavy Crude Oil			Bitumen			Natural Gas Liquids
	Company Interest	Gross Interest	Net Interest	Company Interest	Gross Interest	Net Interest	Company Interest	Gross Interest	Net Interest	Company Interest	Gross Interest	Net Interest
Reserves Category	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)
Proved Reserves
Proved Developed Producing	1,794	1,793	1,614	-	-	-	24,012	24,012	22,355	90	90	79
Proved Developed Non-Producing	55	54	52	-	-	-	-	-	-	9	9	8
Proved Undeveloped	5	5	4	-	-	-	138,314	138,314	121,870	2	2	2
Total Proved Reserves	1,853	1,852	1,670	-	-	-	162,327	162,327	144,225	102	101	89
Probable Reserves	601	600	541	-	-	-	154,731	154,731	132,819	18	18	16
Total Proved Plus Probable Reserves	2,454	2,452	2,211	-	-	-	317,057	317,057	277,044	120	119	104

	Conventional Natural Gas			Shale Gas			Coal Bed Methane			Total Oil Equivalent Basis(2)
	Company Interest	Gross Interest	Net Interest	Company Interest	Gross Interest	Net Interest	Company Interest	Gross Interest	Net Interest	Company Interest	Gross Interest	Net Interest
Reserves Category	(MMcf)	(MMcf)	(MMcf)	(MMcf)	(MMcf)	(MMcf)	(MMcf)	(MMcf)	(MMcf)	(Mboe)	(Mboe)	(Mboe)
Proved Reserves
Proved Developed Producing	4,177	4,135	3,817	25,573	25,573	24,807	1,567	1,522	1,465	31,115	31,100	29,062
Proved Developed Non-Producing	728	694	660	-	-	-	498	498	465	268	262	247
Proved Undeveloped	-	-	-	120,569	120,569	111,119	-	-	-	158,417	157,417	140,396
Total Proved Reserves	4,905	4,829	4,476	146,143	146,143	135,926	2,065	2,020	1,930	189,800	189,778	169,706
Probable Reserves	707	700	655	585,179	585,179	522,089	501	496	464	253,081	253,078	220,577
Total Proved Plus Probable Reserves	5,612	5,529	5,131	731,322	731,322	658,015	2,566	2,516	2,393	442,882	442,856	390,282

Notes:

(1) Constant prices are shown under the heading "Pricing Assumptions".

(2) Natural gas has been converted to barrels of oil equivalent on the basis of six (6) Mcf of natural gas being equal to one barrel of oil.

PENGROWTH ENERGY CORPORATION | 2017 ANNUAL INFORMATION FORM     16

Summary of Net Present Value of Future Net Revenue as of December 31, 2017
Before and After Income Taxes (Constant Prices and Costs)⁽¹⁾ 

	Before Income Taxes Discounted at (%/year) - $MM										Unit Value Before Income Taxes Discounted at 10%/year(2)(3)
Reserves Category	0	%	5	%	10	%	15	%	20	%	$/BOE	$/McfGE
Proved Reserves
Proved Developed Producing	519		489		458		429		403		15.76	2.63
Proved Developed Non-Producing	58		132		146		137		120		0.59	0.1
Proved Undeveloped	954		391		142		24		(33	)	2.05	0.34
Total Proved Reserves	1,531		1,012		746		590		490		4.39	0.73
Probable Reserves	1,664		583		123		(86	)	(182	)	0.56	0.09
Total Proved Plus Probable Reserves	3,195		1,595		868		505		308		2.22	0.37

	After Income Taxes Discounted at (%/year)(4)  - $MM
Reserves Category	0	%	5	%	10	%	15	%	20	%
Proved Reserves
Proved Developed Producing	519		489		458		429		403
Proved Developed Non-Producing	58		132		146		137		120
Proved Undeveloped	942		400		138		27		(33	)
Total Proved Reserves	1,520		1,021		742		593		490
Probable Reserves	1,061		331		15		(145	)	(214	)
Total Proved Plus Probable Reserves	2,581		1,352		757		448		276

Notes:

(1) Constant prices are shown under the heading "Pricing Assumptions".

(2) Net present value of Future Net Revenue per reserve unit values are based on our net reserves.

(3) Natural gas has been converted to barrels of oil equivalent on the basis of six (6) Mcf of natural gas being equal to one barrel of oil. Oil and NGL have been converted to thousand cubic feet of natural gas equivalent on the basis of one barrel of oil or NGL being equal to six (6) Mcf of natural gas.

(4) After-tax values were calculated using current corporate tax rates, existing tax pools and additions to the tax pools through capital expenditures as forecast by GLJ. See – "Operational Information - Statement of Oil and Gas Reserves and Reserves Data – Disclosure of Reserves Data" for additional descriptions of the assumptions made in calculating the after-tax values.

Total Future Net Revenue (undiscounted) as of December 31, 2017
(Constant Prices and Costs)⁽¹⁾ ($MM)

Reserves Category	Revenue	Royalties(2)	Operating Costs	Development Costs	Abandonment and Reclamation Costs(3)	Future Net Revenue Before Income Taxes	Income Tax	Future Net Revenue After Income Taxes
Total Proved	6,837	730	2,400	1,919	257	1,531	12	1,519
Total Proved Plus Probable	14,306	1,732	4,058	4,897	424	3,195	616	2,579

Notes:

(1) Constant prices are shown under the heading "Pricing Assumptions".

(2) Crown royalties payable to the provinces of Alberta, British Columbia, Saskatchewan and Nova Scotia, freehold and over-riding royalties payable and other minor burdens.

(3) Includes GLJ’s forecast of well abandonment and reclamation costs, abandonment of Sable Island facilities and subsea pipelines, and abandonment and reclamation of the Lindbergh central processing facilities, based on estimates by the Corporation, but does not include abandonment and surface reclamation costs for any other facilities. See "Operational Information – Significant Factors or Uncertainties Affecting Reserves Data - Additional Information Concerning Abandonment & Reclamation Costs".

PENGROWTH ENERGY CORPORATION | 2017 ANNUAL INFORMATION FORM     17

Net Present Value of Future Net Revenue By Product Type as of December 31, 2017
(Constant Prices and Costs)⁽¹⁾ 

		Future Net Revenue Before Income Taxes (discounted at 10%/year)		Unit Value(4)(5)
Reserves Category	Product Type	($MM)		($/BOE)		($/McfGE)
Total Proved	Light Crude Oil and Medium Crude Oil (including solution gas and other by-products)(2)	23		12.27		2.04
	Heavy Crude Oil (including solution gas and other by-products)(2)	-		-		-
	Bitumen	687		4.76		0.79
	Conventional Natural Gas (including by-products but excluding solution gas from oil wells)(3)	(1	)	(2.26	)	(0.38)
	Shale Gas	38		1.69		0.28
	Coal Bed Methane	(1	)	(2.17	)	(0.36)
	Total	746		4.39		0.73
Total Proved Plus Probable	Light Crude Oil and Medium Crude Oil (including solution gas and other by-products)(2)	27		10.96		1.83
	Heavy Crude Oil (including solution gas and other by-products)(2)	-		-		-
	Bitumen	672		2.43		0.40
	Conventional Natural Gas (including by-products but excluding solution gas from oil wells)(3)	-		(0.56	)	(0.09)
	Shale Gas	170		1.55		0.26
	Coal Bed Methane	-		(1.22	)	(0.20)
	Total	868		2.22		0.37

Notes:

(1) Constant prices are shown under the heading "Pricing Assumptions".

(2) NGL associated with the production of solution gas are included as a by-product.

(3) NGL associated with the production of natural gas are included as a by-product.

(4) Net present value of Future Net Revenue per BOE or McfGE are based on our net reserves.

(5) Natural gas has been converted to barrels of oil equivalent on the basis of six (6) Mcf of natural gas being equal to one barrel of oil. Oil and NGL have been converted to thousand cubic feet of natural gas equivalent on the basis of one barrel of oil or NGL being equal to six (6) Mcf of natural gas.

PENGROWTH ENERGY CORPORATION | 2017 ANNUAL INFORMATION FORM     18

Pricing Assumptions

Forecast Prices used in Estimates

The forecast price and cost assumptions assume the continuance of current laws and regulations and changes in wellhead selling prices, and take into account forecasted two percent annual inflation with respect to future operating and capital costs. The forecast prices are provided in the table below and reflect GLJ's January 1, 2018 price forecast as referred to in the GLJ Report.

	Oil						Natural Gas	Natural Gas Liquids(1)
	WTI Cushing Oklahoma	Edmonton Par Price 40°API	Cromer Medium 29°API	WCS Stream Quality	Hardisty Heavy 12°API	Lindbergh Bitumen Wellhead Calculated(5)	AECO Gas Price	Propane	Butane	Pentanes Plus	Inflation Rates(2)	Exchange Rate(3)
Year	(US$/bbl)	(Cdn$/bbl)	(Cdn$/bbl)	(Cdn$/bbl)	(Cdn$/bbl)	(Cdn$/bbl)	(Cdn$/MMBtu)	(Cdn$/bbl)	(Cdn$/bbl)	(Cdn$/bbl)	(%/year)	(US$/Cdn$)
2017(4)	50.88	62.78	59.90	50.46	44.56	33.28	2.16	28.64	44.58	66.80	1.6	0.7711
2018	59.00	70.25	65.34	48.89	39.63	32.18	2.20	40.40	53.74	76.42	2.0	0.7900
2019	59.00	70.25	65.34	53.16	45.71	39.04	2.54	36.53	49.18	74.68	2.0	0.7900
2020	60.00	70.31	65.39	56.25	49.81	43.58	2.88	35.93	49.22	74.38	2.0	0.8000
2021	63.00	72.84	67.74	59.26	52.89	46.69	3.24	36.06	50.99	77.16	2.0	0.8100
2022	66.00	75.61	70.32	62.20	55.89	49.72	3.47	36.29	52.93	79.88	2.0	0.8200
2023	69.00	78.31	72.83	65.06	58.82	52.67	3.58	37.59	54.82	82.53	2.0	0.8300
2024	72.00	81.93	76.19	68.67	62.43	56.29	3.66	39.33	57.35	86.14	2.0	0.8300
2025	75.00	85.54	79.55	72.29	66.05	59.90	3.73	41.06	59.88	89.76	2.0	0.8300
2026	77.33	88.35	82.16	75.10	68.86	62.61	3.80	42.41	61.84	92.57	2.0	0.8300
2027	78.88	90.22	83.90	76.96	70.72	64.38	3.88	43.30	63.15	94.43	2.0	0.8300
thereafter	+2%/year	+2%/year	+2%/year	+2%/year	+2%/year	+2%/year	+2%/year	+2%/year	+2%/year	+2%/year	2.0	0.8300

Notes:

(1) FOB Edmonton.

(2) Inflation rates for forecasting prices and costs.

(3) The exchange rates used to generate the benchmark reference prices in this table.

(4) Actual average historical prices for 2017.

(5) Lindbergh forecast wellhead prices are calculated accounting for all diluent/blending and transportation costs.

Constant Prices used in Estimates

The constant price assumptions assume the continuance of current laws, regulations and operating costs in effect on the date of the GLJ Report. Product prices were determined from the actual prices on the first day of each month during 2017 and were not escalated. In addition to the product prices, operating and capital costs have no inflationary increase. The constant prices are as follows:

Oil

Natural Gas

Natural Gas Liquids(1)

WTI Cushing Oklahoma

Edmonton Par Price 40°API

Cromer Medium 29°API

WCS Stream Quality

Hardisty Heavy 12°API

Lindbergh Bitumen Wellhead Calculated(2)

AECO Gas Price

Propane

Butane

Pentanes Plus

Inflation Rate

Exchange Rate

Year

(US$/bbl)

(Cdn$/bbl)

(Cdn$/bbl)

(Cdn$/bbl)

(Cdn$/bbl)

(Cdn$/bbl)

(Cdn$/MMBtu)

(Cdn$/bbl)

(Cdn$/bbl)

(Cdn$/bbl)

(%/year)

(US$/Cdn$)

2018 and thereafter

51.03

63.43

60.55

51.09

45.18

39.18

2.35

28.38

44.70

67.46

0.0

0.7690

Notes:

(1) FOB Edmonton.

(2) Lindbergh constant wellhead price is calculated accounting for all diluent/blending and transportation costs.

PENGROWTH ENERGY CORPORATION | 2017 ANNUAL INFORMATION FORM     19

Reserves Reconciliation

The following tables provide a reconciliation of our gross reserves of crude oil, bitumen, natural gas and NGL for the year ended December 31, 2017, presented using forecast prices and costs. All reserves are located in Canada.

Gross Reserves Reconciliation By Principal Product Type
(Forecast Prices and Costs)

	Light Crude Oil and Medium Crude Oil						Heavy Crude Oil						Bitumen						Natural Gas Liquids
	Proved		Probable		Proved Plus Probable		Proved		Probable		Proved Plus Probable		Proved		Probable		Proved Plus Probable		Proved		Probable		Proved Plus Probable
	(Mbbl)		(Mbbl)		(Mbbl)		(Mbbl)		(Mbbl)		(Mbbl)		(Mbbl)		(Mbbl)		(Mbbl)		(Mbbl)		(Mbbl)		(Mbbl)
December 31, 2016	40,110		16,828		56,938		2		1		4		146,265		171,640		317,905		24,439		11,633		36,073
Extensions & Improved Recovery	-		-		-		-		-		-		16,542		(16,542	)	-		-		-		-
Infill Drilling	-		-		-		-		-		-		1,325		(1,325	)	-		-		-		-
Technical Revisions	(181	)	(149	)	(330	)	-		-		-		4,221		(49	)	4,172		164		(91	)	73
Discoveries	-		-		-		-		-		-		-		-		-		-		-		-
Acquisitions	-		-		-		-		-		-		-		-		-		-		-		-
Dispositions	(35,330	)	(16,000	)	(51,330	)	(2	)	(1	)	(3	)	-		-		-		(22,781	)	(11,506	)	(34,287	)
Economic Factors	(62	)	(7	)	(69	)	-		-		-		-		-		-		(21	)	(8	)	(29	)
Production	(2,501	)	-		(2,501	)	-		-		-		(5,020	)	-		(5,020	)	(1,661	)	-		(1,661	)
December 31, 2017	2,037		672		2,709		-		-		-		163,334		153,724		317,057		141		29		170

	Conventional Natural Gas						Shale Gas						Coal Bed Methane						Total Oil Equivalent Basis(1)
	Proved		Probable		Proved Plus Probable		Proved		Probable		Proved Plus Probable		Proved		Probable		Proved Plus Probable		Proved		Probable		Proved Plus Probable
	(MMcf)		(MMcf)		(MMcf)		(MMcf)		(MMcf)		(MMcf)		(MMcf)		(MMcf)		(MMcf)		(Mboe)		(Mboe)		(Mboe)
December 31, 2016	311,992		141,498		453,490		117,492		585,146		702,638		18,567		8,546		27,113		285,491		322,635		608,126
Extensions & Improved Recovery	-		-		-		31,525		(31,525	)	-		-		-		-		21,796		(21,796	)	-
Infill Drilling	-		-		-		-		-		-		-		-		-		1,325		(1,325	)	-
Technical Revisions	4,341		(2,211	)	2,130		3,082		(4,077	)	(995	)	(1,069	)	378		(691	)	5,264		(1,274	)	3,990
Discoveries	-		-		-		-		-		-		-		-		-		-		-		-
Acquisitions	-		-		-		5,094		43,627		48,721		-		-		-		849		7,271		8,120
Dispositions	(280,187	)	(137,100	)	(417,286	)	-		-		-		(11,195	)	(5,868	)	(17,063	)	(106,677	)	(51,335	)	(158,011	)
Economic Factors	(1,762	)	(926	)	(2,688	)	(559	)	434		(124	)	(1,230	)	(1,113	)	(2,343	)	(674	)	(282	)	(957	)
Production	(27,695	)	-		(27,695	)	(3,787	)	-		(3,787	)	(1,669	)	-		(1,669	)	(14,707	)	-		(14,707	)
December 31, 2017	6,689		1,262		7,951		152,847		593,606		746,452		3,404		1,943		5,348		192,668		253,384		446,561

Notes:

(1) Natural gas has been converted to barrels of oil equivalent on the basis of six (6) Mcf of natural gas being equal to one barrel of oil.

PENGROWTH ENERGY CORPORATION | 2017 ANNUAL INFORMATION FORM     20

At December 31, 2017, Company Interest Total Proved Plus Probable Reserves at forecast prices and costs were 446.6 MMboe as compared to 608.5 MMboe reported at year end 2016. The following additional GLJ reserves reconciliation is presented for year end December 31, 2017.

Company Interest Reserves Reconciliation on Total Oil Equivalent Basis – Mboe⁽¹⁾(Forecast Prices and Costs)

	Proved Developed Producing Reserves		Proved Reserves		Total Proved Plus Probable Reserve
December 31, 2016	115,493		285,806		608,549
Extensions & Improved Recovery	12,919		21,796		-
Infill Drilling	246		1,325		-
Technical Revisions	2,024		5,219		3,929
Discoveries	-		-		-
Acquisitions	85		849		8,120
Dispositions	(82,406	)	(106,847	)	(158,254	)
Economic Factors	(348	)	(674	)	(957	)
Production	(14,756	)	(14,756	)	(14,756	)
December 31, 2017	33,257		192,718		446,632

Note:

(1) Natural gas has been converted to barrels of oil equivalent on the basis of six (6) Mcf of natural gas being equal to one barrel of oil.

Significant factors bearing on the reserves reconciliation were as follows:

• Net reserve changes from drilling activity, improved recovery, technical revisions and economic factors replaced 188 percent and 20 percent of 2017 production for Proved Reserves and Total Proved Plus Probable Reserves, respectively. At Lindbergh, net reserve changes replaced 440 percent and 83 percent of 2017 production for Proved Reserves and Total Proved Plus Probable Reserves, respectively. At Groundbirch, net reserve changes resulted in 900 percent and -30 percent reserve replacement of 2017 production for Proved Reserves and Total Proved Plus Probable Reserves, respectively. The negative reserve replacement percent on the Total Proved Plus Probable Reserves at Groundbirch is a result of economic factors due to lower gas price forecast and the addition of a one percent increase on gas shrinkage. If reserves associated with assets disposed of in 2017 were included in the reserve replacement calculations, reserve replacement would have been -531 percent and -997 percent for Proved Reserves and Total Proved Plus Probable Reserves, respectively.

• New reserve additions for development activity during 2017 amounted to 23 MMboe of Proved Reserves. The most significant addition occurred at Lindbergh where Proved Reserves were booked for an area that was previously cyclic steam stimulated. Additional Proved Reserves were also booked at Lindbergh for future infill wells off the pad drilled in 2017 (Pad D04). At Groundbirch, Proved Reserves were booked for section 01-081-21W6 due to offsetting competitor activity.

• Technical revisions resulted in a net increase of 5.2 MMboe of Proved Reserves and 3.9 MMboe of Total Proved Plus Probable Reserves. This was primarily due to the re-allocation of drainage area to undeveloped pads. There was also a positive technical revision due to performance at both Lindbergh and Groundbirch. The decrease due to economic factors, predominantly due to gas price reduction, is estimated at 0.7 MMboe for Proved Reserves and 1.0 MMboe for Total Proved Plus Probable Reserves.

• Acquisition of a small partner working interest in the Groundbirch area resulted in an increase of 8.1 MMboe of Total Proved Plus Probable Reserves.

• Disposition activity in 2017 resulted in a decrease of 106.8 MMboe and 158.3 MMboe of Proved Reserves and Total Proved Plus Probable Reserves, respectively. The properties disposed of were the greater Olds area, the Swan Hills area, W4/W5 properties, Quirk Creek and numerous minor properties. These dispositions resulted in a reduction of 38 percent of Proved Reserves being sold and 26 percent of Total Proved Plus Probable Reserves being sold. Disposition activity had the largest impact on reserve changes for 2017.

Note: All reserves discussed above relate to Company Interest reserves.

PENGROWTH ENERGY CORPORATION | 2017 ANNUAL INFORMATION FORM     21

ADDITIONAL INFORMATION RELATING TO RESERVES DATA

Undeveloped Reserves

Undeveloped Reserves are those reserves expected to be recovered from known accumulations where a significant expenditure is required to render them capable of production.

Proved Undeveloped Reserves and Probable Undeveloped Reserves have been estimated in accordance with procedures and standards contained in the COGE Handbook. In general, Undeveloped Reserves are scheduled to be developed within the next two to five years. Much of the remaining capital scheduled beyond this period is for staged developments such as the Lindbergh thermal project and Groundbirch Montney gas development. Other slightly longer term capital expenditures are for oil and gas development which has been deferred due to the low commodity price environment.

Company Gross Reserves First Attributed by Year⁽¹⁾ 

Proved Undeveloped Reserves
	Light Crude Oil and Medium Crude Oil		Heavy Crude Oil		Bitumen		Natural Gas Liquids		Conventional Natural Gas		Shale Gas		Coal Bed Methane		Total Oil Equivalent
	(Mbbl)		(Mbbl)		(Mbbl)		(Mbbl)		(MMcf)		(MMcf)		(MMcf)		(Mboe)(2)
	First Attributed	Total at year end	First Attributed	Total at year end	First Attributed	Total at year end	First Attributed	Total at year end	First Attributed	Total at year end	First Attributed	Total at year end	First Attributed	Total at year end	First Attributed	Total at year end
2015	571	6,418	-	1,512	-	82,204	448	1,277	4,730	21,512	20,825	86,662	-	6,336	5,278	110,495
2016	345	5,232	-	-	45,978	130,007	2,920	4,760	23,826	43,240	-	86,677	-	5,093	53,214	162,500
2017	3	6	-	-	5,053	138,600	2	2	-	-	31,525	121,493	-	258	10,312	158,900

Probable Undeveloped Reserves
	Light Crude Oil and Medium Crude Oil		Heavy Crude Oil		Bitumen		Natural Gas Liquids		Conventional Natural Gas		Shale Gas		Coal Bed Methane		Total Oil Equivalent
	(Mbbl)		(Mbbl)		(Mbbl)		(Mbbl)		(MMcf)		(MMcf)		(MMcf)		(Mboe)(2)
	First Attributed	Total at year end	First Attributed	Total at year end	First Attributed	Total at year end	First Attributed	Total at year end	First Attributed	Total at year end	First Attributed	Total at year end	First Attributed	Total at year end	First Attributed	Total at year end
2015	776	6,333	-	5,374	19,185	155,201	492	2,304	6,534	34,975	361,210	561,604	-	5,544	81,744	269,565
2016	581	5,245	-	-	9,000	166,850	2,522	5,405	22,345	57,020	13,230	574,818	-	5,039	18,032	283,646
2017	1	1	-	-	-	146,854	1	1	-	-	-	584,005	-	1,128	2	244,378

Notes:

(1) "First Attributed" refers to reserves first attributed at year end of the corresponding fiscal year.

(2) Natural gas has been converted to barrels of oil equivalent on the basis of six (6) Mcf of natural gas being equal to one barrel of oil.

Proved Undeveloped Reserves

Proved Undeveloped Reserves comprise approximately 82.4 percent of Company Interest Proved Reserves on a BOE basis. Company Interest Proved Undeveloped Reserves of 158.9 MMboe were assigned by GLJ in accordance with NI 51-101. In general, Proved Undeveloped Reserves were assigned to certain properties because we intend to make the necessary capital commitments to convert the Undeveloped Reserves to Proved Developed Producing Reserves in the next few years. Proved Undeveloped Reserves have been primarily assigned for future oil sands development and development drilling.

The Lindbergh thermal project which came on stream in 2015 accounts for 87 percent of our Proved Undeveloped Reserves. SAGD well pairs and infill wells are forecast to be drilled until 2042. The pace of development is currently limited by the production and steam capacity of the existing central processing facility for the Phase 1 commercial project. The Groundbirch Montney gas property amounts to approximately 13 percent of our Proved Undeveloped Reserves. Drilling is forecast by GLJ to occur over the next three years to develop these reserves.

Probable Undeveloped Reserves

Probable Undeveloped Reserves were assigned by GLJ in accordance with the requirements and standards of NI 51-101 and the COGE Handbook. Our Probable Undeveloped Reserves amount to 244.4 MMboe and represent about 54.7 percent of the Total Proved Plus Probable Reserves. Probable Undeveloped Reserves are assigned for similar reasons and generally to the same properties as Proved Undeveloped Reserves, but also meet the requirements of the reserve classification to which they belong. Our largest Probable Undeveloped Reserves are distributed among certain properties as a percent of the total as follows: Lindbergh (60 percent) and Groundbirch (40 percent).

PENGROWTH ENERGY CORPORATION | 2017 ANNUAL INFORMATION FORM     22

SIGNIFICANT FACTORS OR UNCERTAINTIES AFFECTING RESERVES DATA

Additional Information Concerning Abandonment & Reclamation Costs

The total future abandonment and reclamation costs are based on management's estimate of costs to abandon, remediate and reclaim all wells and facilities having regard to our Working Interest and the estimated timing of the costs to be incurred in future periods and are referred to herein as the Corporation's asset retirement obligations. We have developed a process to calculate these estimates, which considers applicable regulations, actual and anticipated costs, type and size of the well or facility and the geographic location. These costs relate to wells and facilities in properties that may or may not have reserves attributed to them.

GLJ's forecast of well abandonment and reclamation costs for all wells with reserves assigned, abandonment costs for all Sable Island offshore and onshore facilities and pipelines upstream of the plant gate and abandonment and reclamation costs for the Lindbergh central processing facilities, based on estimates provided by the Corporation, are included in their report and therefore in their estimate of Future Net Revenue. All other abandonment and reclamation costs are not reflected in GLJ's estimate of Future Net Revenue.

We have estimated the net present value (discounted at ten percent per annum) of our total asset retirement obligations, which are inclusive of those costs estimated by GLJ, to be approximately $101 million as at December 31, 2017, based on a total future liability (inflated at 1.5 percent per annum) of approximately $451 million. Fifty percent of these costs are expected to be incurred after 2056.

The following table summarizes our total current asset retirement obligations as at December 31, 2017:

Asset Retirement Obligations

	2018	2019	2020	Remainder	Total
Total Abandonment, Reclamation, Remediation & Dismantling ($millions)	24	31	47	349	451
Discounted at ten percent ($millions)	22	25	35	18	101

The above table excludes asset retirement obligations associated with future development and, in particular, the development associated with Proved Developed Non-Producing, Proved Undeveloped and Probable Undeveloped Reserves, except where such activity would be coincidental with existing operations. GLJ’s Proved Developed Producing reserve evaluation at forecast prices and costs is the best comparison to our current operation and includes $203 million ($129 million when discounted at ten percent) of the current asset retirement obligations in the above table. Elsewhere, where we describe Future Net Revenue, only the GLJ forecast of abandonment obligation is included in the values.

FUTURE DEVELOPMENT COSTS

The following table outlines development costs deducted in the estimation of Future Net Revenue calculated utilizing both constant and forecast prices and costs, undiscounted and using a discount rate of ten percent per annum for the years indicated. All of such development costs are estimated to be incurred in Canada.

Future Development Costs ($millions)

							Total
Reserve Category	2018	2019	2020	2021	2022	Remainder	Undiscounted	Discounted at 10%
Proved Reserves (Constant Prices and Costs)	31	161	139	105	39	1,446	1,919	719
Proved Reserves (Forecast Prices and Costs)	31	163	140	105	39	1,455	1,932	723
Proved & Probable Reserves (Forecast Prices and Costs)	65	374	618	367	141	3,377	4,941	2,333

There are no reserves that are expected to be limited in their recovery due to their cost of development.

FINDING, DEVELOPMENT AND ACQUISITION COSTS

Finding and Development Costs

During 2017, we spent $117.4 million on development, maintenance and optimization, which added 23.1 MMboe of Proved Reserves excluding revisions. Incorporating the net positive revisions resulted in an overall change of 27.7 MMboe of Proved Reserves and 3.0 MMboe of Total Proved Plus Probable Reserves. The development and optimization expenditures exclude $0.7 million in corporate expenditures for information technology projects and equipment inventory. The largest reserve additions were for drilling extensions and infill drilling at Lindbergh.

Finding and Developments Costs are not necessarily calculated in the same manner by all issuers. Accordingly, they should not be used to make comparisons amongst different issuers.

PENGROWTH ENERGY CORPORATION | 2017 ANNUAL INFORMATION FORM     23

Acquisitions and Divestitures

During 2017, the Corporation completed $986.9 million of asset dispositions (before customary closing costs and adjustments) and also acquired approximately $0.1 million of minor assets. The 2017 dispositions were comprised primarily of our Bernadet, Swan Hills, Judy Creek, Olds Garrington, Quirk Creek and numerous other minor Alberta conventional assets as well as a 4.0 percent gross overriding royalty on our Lindbergh asset.

Future Development Costs

The calculation of F&D Costs include changes in forecasted FDC relating to the reserves. These forecasts of FDC will change with time due to ongoing development activity, inflationary changes or reduction in capital costs and acquisition or disposition of assets. We provide the calculation of FD&A Costs both with and without change in FDC. We include FD&A Costs because we believe that acquisitions and dispositions can have a significant impact on our ongoing reserve replacement costs.

Finding, Development and Acquisition Costs - Company Interest Reserves
(Forecast Prices and Costs)

Proved Reserves	2017		2016		2015		2015-20167 Total/Weighted Average
Costs Excluding Future Development Costs
Exploration and Development Capital Expenditures - $MM	117.4		64.2		181.8		363.4
Exploration and Development Reserve Additions including Revisions - MMboe	27.7		60.7		(6.1	)	82.3
Finding and Development Cost - $/BOE(1)	4.24		1.06		(29.80	)	4.42
Net Acquisition (Disposition) Capital - $MM	(986.7	)	(58.9	)	(209.6	)	(1,255.2	)
Net Acquisition (Disposition) Reserve Additions - MMboe	(106.0	)	(6.1	)	(25.8	)	(137.9	)
Net Acquisition Cost - $/BOE	9.31		9.66		8.12		9.10
Total Capital Expenditures including Net Acquisitions (Dispositions) - $MM	(869.3	)	5.3		(27.8	)	(891.8	)
Reserve Additions including Net Acquisitions (Dispositions) - MMboe	(78.3	)	54.6		(31.9	)	(55.6	)
Finding, Development and Acquisition Cost - $/BOE	11.10		0.10		0.87		16.03
Costs Including Future Development Costs
Exploration and Development Capital Expenditures - $MM	117.4		64.2		181.8		363.4
Exploration and Development Change in FDC - $MM	261.5		423.6		(239.7	)	445.4
Exploration and Development Capital including Change in FDC - $MM	378.8		487.8		(57.9	)	808.7
Exploration and Development Reserve Additions including Revisions - MMboe	27.7		60.7		(6.1	)	82.3
Finding and Development Cost - $/BOE	13.69		8.04		9.49		9.83
Net Acquisition (Disposition) Capital - $MM	(986.7	)	(58.9	)	(209.6	)	(1,255.2	)
Net Acquisition (Disposition) FDC - $MM	(309.2	)	(40.6	)	(107.3	)	(457.1	)
Net Acquisition (Disposition) Capital including FDC - $MM	(1,295.9	)	(99.5	)	(316.9	)	(1,712.3	)
Net Acquisition (Disposition) Reserve Additions - MMboe	(106.0	)	(6.1	)	(25.8	)	(137.9	)
Net Acquisition Cost - $/BOE	12.23		16.31		12.28		12.42
Total Capital Expenditures including Net Acquisitions (Dispositions) - $MM	(869.3	)	5.3		(27.8	)	(891.8	)
Total Change in FDC - $MM	(47.7	)	383.0		(347.0	)	(11.7	)
Total Capital including Change in FDC - $MM	(917.1	)	388.3		(374.8	)	(903.6	)
Reserve Additions including Net Acquisitions (Dispositions) - MMboe	(78.3	)	54.6		(31.9	)	(55.6	)
Finding, Development and Acquisition Cost including FDC - $/BOE	11.71		7.11		11.75		16.24

PENGROWTH ENERGY CORPORATION | 2017 ANNUAL INFORMATION FORM     24

Total Proved Plus Probable Reserves	2017		2016		2015		2015-2017 Total/Weighted Average
Costs Excluding Future Development Costs
Exploration and Development Capital Expenditures - $MM	117.4		64.2		181.8		363.4
Exploration and Development Reserve Additions including Revisions - MMboe	3.0		76.2		73.6		152.8
Finding and Development Cost - $/BOE(2)	39.49		0.84		2.47		2.38
Net Acquisition (Disposition) Capital - $MM	(986.7	)	(58.9	)	(209.6	)	(1,255.2	)
Net Acquisition (Disposition) Reserve Additions - MMboe	(150.1	)	(15.9	)	(35.8	)	(201.8	)
Net Acquisition Cost - $/BOE	6.57		3.70		5.85		6.22
Total Capital Expenditures including Net Acquisitions (Dispositions) - $MM	(869.3	)	5.3		(27.8	)	(891.8	)
Reserve Additions including Net Acquisitions (Dispositions) - MMboe	(147.2	)	60.3		37.8		(49.1	)
Finding, Development and Acquisition Cost - $/BOE(3)	5.91		0.09		(0.74	)	18.18
Costs Including Future Development Costs
Exploration and Development Capital Expenditures - $MM	117.4		64.2		181.8		363.4
Exploration and Development Change in FDC - $MM	163.1		193.7		341.9		698.7
Exploration and Development Capital including Change in FDC - $MM	280.5		257.9		523.7		1,062.1
Exploration and Development Reserve Additions including Revisions - MMboe	3.0		76.2		73.6		152.8
Finding and Development Cost - $/BOE(4)	94.36		3.38		7.12		6.95
Net Acquisition (Disposition) Capital - $MM	(986.7	)	(58.9	)	(209.6	)	(1,255.2	)
Net Acquisition (Disposition) FDC - $MM	(455.8	)	(124.7	)	(133.9	)	(714.4	)
Net Acquisition (Disposition) Capital including FDC - $MM	(1,442.5	)	(183.6	)	(343.5	)	(1,969.6	)
Net Acquisition (Disposition) Reserve Additions - MMboe	(150.1	)	(15.9	)	(35.8	)	(201.8	)
Net Acquisition Cost - $/BOE	9.61		11.55		9.59		9.76
Total Capital Expenditures including Net Acquisitions (Dispositions) - $MM	(869.3	)	5.3		(27.8	)	(891.8	)
Total Change in FDC - $MM	(292.7	)	69.0		208.0		(15.7	)
Total Capital including Change in FDC - $MM	(1,162.0	)	74.3		180.2		(907.5	)
Reserve Additions including Net Acquisitions (Dispositions) – MMboe	(147.2	)	60.3		37.8		(49.1	)
Finding Development and Acquisition Cost including FDC - $/BOE	7.90		1.23		4.77		18.50

Notes:

(1) The negative 2015 F&D Cost excluding FDC for Proved Reserves is due to the negative reserve change including revisions.

(2) The high F&D Cost excluding FDC for 2017 P+P Reserves is largely due to the 2017 capital activity focusing on promoting existing Probable Reserves to Proved Reserves combined with minor reserves adds.

(3) The negative FD&A Costs excluding FDC for 2015 P+P Reserves are due to the proceeds from dispositions exceeding capital expenditures plus acquisition costs.

(4) The high F&D Cost including FDC for 2017 is due to increased estimated FDC.

The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserves additions for that year.

PENGROWTH ENERGY CORPORATION | 2017 ANNUAL INFORMATION FORM     25

RECYCLE RATIO

We calculate the Recycle Ratio to measure our performance. It reflects the amount of cash flow relative to investment. To calculate the Recycle Ratio, we divide annual operating netback by annual F&D Costs including change in FDC. Recycle ratios are not necessarily calculated in the same manner by all issuers. Accordingly, they should not be used to make comparisons amongst different issuers.

	2017	2016	2015	2015-2017 Weighted Average(4)
Operating Netback (after risk management), $/BOE(1)	13.23	28.62	24.50	23.19
Total Proved Reserves
Proved F&D, $/BOE(2)	13.69	8.04	9.49	9.83
Proved Recycle Ratio	0.97	3.60	2.60	2.36
Total Proved Plus Probable Reserves
P+P F&D, $/BOE(2)(3)	94.36	3.38	7.12	6.95
P+P Recycle Ratio	0.14	8.50	3.40	3.34

Notes:

(1) Operating netback is calculated as shown in "Production History (Netback)".

(2) F&D uses Exploration and Development capital including change in FDC divided by Exploration and Development Reserve Additions including Revisions as shown above.

(3) The high F&D Cost including FDC for 2017 is due to increased estimated FDC.

(4) The three year weighted average is a better indicator of reserve replacement and Recycle Ratio performance given the timing difference between when reserves are booked and when capital is spent to develop them.

RESERVE LIFE INDEX

The Reserve Life Index ("RLI") provides a comparative measure of the longevity of the resources. We calculate the RLI by dividing 2017 Company Interest year end reserves by GLJ’s 2018 forecasted production. RLIs are not necessarily comparative between different issuers as there is some variation in calculation methodology.

	Proved Producing Reserves	Total Proved Reserves	Total Proved Plus Probable Reserves
RLI, years	4.0	23.0	49.0
Reserves, Mboe(1)(2)	33.3	192.7	446.6
2018 Forecast Production, BOE/d(1)	22,646	22,936	24,952

Notes:

(1) Both reserves and production are Company Interest.

(2) Reserves are calculated using Forecast Prices and Costs.

RESERVE REPLACEMENT

We provide reserve replacement data as an indication of the effectiveness of our investments made and the relative impact of that investment. The reserve replacement figures are calculated with and without net acquisitions included by dividing reserve additions by the current year's production. Reserve replacement figures should not be relied upon as being predictive of future performance or reserve growth or recoveries. Different issuers may calculate reserve replacement in different manners. Accordingly, reserve replacement ratios should not be treated as being standardized or comparable.

	2017		2016	2015		Weighted Average/Total 2015-2017
Without Net Acquisitions Proved Plus Probable Replacement (%)	20		365	282		247
P+P Additions plus Revisions, MMboe(1)	3.0		76.2	73.6		152.8
With Net Acquisitions Proved Plus Probable Replacement (%)	(997	)	289	145		(79	)
P+P Additions, Revisions plus net Acquisitions, MMboe(1)	(147.2	)	60.3	37.8		(49.1	)
Without Net Acquisitions Total Proved Replacement (%)	187		290	(23	)	133
Total Proved Additions plus Revisions, MMboe(1)	27.7		60.7	(6.1	)	82.3
With Net Acquisitions Total Proved Replacement (%)	(531	)	261	(122	)	(90	)
Total Proved Additions, Revisions plus net Acquisitions, MMboe(1)	(78.3	)	54.6	(31.9	)	(55.6	)
Current Year Production, MMboe(1)	14.8		20.9	26.1		61.8

Note:

(1) Both reserves and production are Company Interest.

PENGROWTH ENERGY CORPORATION | 2017 ANNUAL INFORMATION FORM     26

OTHER OIL AND GAS INFORMATION

Oil and Gas Wells

As at December 31, 2017, we had an interest in 594 gross (239 net) producing oil and natural gas wells and 1,282 gross (577 net) non-producing wells. All wells are onshore except for wells in Nova Scotia which are all offshore.

		Producing		Non-Producing		Total
		Gross	Net	Gross	Net	Gross	Net
Crude Oil Wells
	Alberta	48	18	79	47	127	65
	British Columbia	60	33	179	114	239	147
	Saskatchewan	62	2	28	6	90	8
Bitumen Wells
	Alberta	30	30	6	1	36	31
Natural Gas Wells
	Alberta	252	93	81	44	333	137
	British Columbia	122	60	222	126	344	187
	Saskatchewan	1	1	10	2	11	2
	Nova Scotia	19	2	2	-	21	2
Service Wells(1)
	Alberta	-	-	132	81	132	81
	British Columbia	-	-	183	121	183	121
	Saskatchewan	-	-	347	24	347	24
Other(2)
	Alberta	-	-	9	7	9	7
	British Columbia	-	-	4	4	4	4
	Saskatchewan	-	-	-	-	-	-
Total		594	239	1,282	577	1,876	817

Notes:

(1) Service Wells include disposal, injector, water source and observation wells.

(2) Other includes standing, zonally abandoned and suspended wellbores with undefined zones.

Properties with No Attributed Reserves

The following table sets forth the gross and net acres of unproved properties held by us as at December 31, 2017 and the maximum net area of unproved properties for which we expect our rights to explore, develop and exploit to expire during 2018. There are no material work commitments necessary to maintain these properties.

When determining gross and net acreage for two or more leases covering the same lands but different rights, the acreage is reported for each lease. Where there are multiple discontinuous rights in a single lease, the acreage is reported only once.

Unproved Properties as at December 31, 2017

Location	Gross Acres	Net Acres	Maximum Net Acres Expected to Expire During 2018
Alberta	75,325	42,703	13,400
British Columbia	239,464	104,865	8,731
Nova Scotia	146,728	11,427	-
Saskatchewan	4,404	1,932	-
Total	465,921	160,927	22,131

The expiring acreage is being evaluated and attempts will be made to maintain our rights on the acreage. Historically, efforts to maintain our rights on acreage on activity have been successful.

FORWARD CONTRACTS

We use financial derivatives or fixed price contracts to manage our exposure to fluctuations in commodity prices and foreign currency exchange rates. A description of such instruments is provided in Note 17 of our annual audited consolidated financial statements and related Management's Discussion and Analysis for the year ended December 31, 2017, which may be found on our website at www.pengrowth.com, on SEDAR at www.sedar.comand on EDGAR at www.sec.gov.

PENGROWTH ENERGY CORPORATION | 2017 ANNUAL INFORMATION FORM     27

TAX HORIZON

We have not paid cash income tax in the past year and based upon current tax legislation, anticipated capital spending and economic conditions, we do not anticipate having to pay corporate income tax until at least 2028, partially as a result of our $2.4 billion of tax pools.

COSTS INCURRED

The following table outlines property acquisition, exploration and development costs that we incurred during the financial year ended December 31, 2017. These costs include only those costs which are cash or cash equivalent.

	Amount
Nature of Cost	($million)
Acquisition Costs
Proved	0.1
Unproved	-
Exploration Costs(1)	(0.3	)
Development Costs	117.5
Total	117.3

Note:

(1) Negative due to seismic sales exceeding purchases.

EXPLORATION AND DEVELOPMENT ACTIVITIES

The following table summarizes the number of wells drilled during the financial year ended December 31, 2017.

	Development		Exploration		Total
Wells	Gross	Net	Gross	Net	Gross	Net
Gas	5	4	-	-	5	4
Oil	-	-	-	-	-	-
Bitumen	12	12	-	-	12	12
Service/Injection	10	10	-	-	10	10
Stratigraphic Test	2	2	-	-	2	2
Dry	-	-	-	-	-	-
Total	29	28	-	-	29	28

PRODUCTION ESTIMATES

The following table summarizes the 2018 average daily volume of gross production estimated by GLJ for all properties held on December 31, 2017 using constant and forecast prices and costs, all of which will be produced in Canada. These estimates assume certain activities take place, such as the development of Undeveloped Reserves, and that there are no dispositions. We estimate our 2018 Company Interest production to be between 22,500 and 23,500 BOE/d.

	2018 Estimated Production
	Constant Prices and Costs			Forecast Prices and Costs
	Total Proved	Total Probable	Total Proved Plus Probable	Total Proved	Total Probable	Total Proved Plus Probable
Light Crude Oil and Medium Crude Oil (bbl/d)	821	20	841	821	20	841
Heavy Crude Oil (bbl/d)	-	-	-	-	-	-
Bitumen (bbl/d)	18,739	763	19,502	18,739	763	19,502
Conventional Natural Gas (Mcf/d)	8,700	761	9,461	8,700	761	9,461
Shale Gas (Mcf/d)	8,857	6,430	15,287	8,857	6,430	15,287
Coal Bed Methane (Mcf/d)	1,243	18	1,260	1,243	18	1,260
Natural Gas Liquids (bbl/d)	213	31	244	213	31	244
Total (BOE/d)	22,907	2,015	24,922	22,907	2,015	24,922

PENGROWTH ENERGY CORPORATION | 2017 ANNUAL INFORMATION FORM     28

PRODUCTION HISTORY (NETBACK)

The following table summarizes, for each quarter of our most recent financial year, certain of our production information in respect of our Company Interest production, product prices received, royalties paid, operating expenses and resulting operating netbacks.

	QUARTER ENDED								YEAR ENDED
	Mar 31, 2017		June 30, 2017		Sept 30, 2017		Dec 31, 2017		Dec 31, 2017
Barrels of Oil Equivalent(1) (including realized commodity risk management)
Average Daily Oil Production(2) (BOE/d)	52,957		49,349		35,072		24,702		40,428
Produced petroleum revenue ($/BOE)	34.66		32.56		28.08		37.14		32.96
Royalties ($/BOE)	(3.30	)	(3.56	)	(1.89	)	(3.52	)	(3.10	)
Net operating expenses ($/BOE)	(12.71	)	(14.03	)	(14.54	)	(12.28	)	(13.45	)
Transportation costs ($/BOE)	(1.74	)	(1.74	)	(1.74	)	(2.38	)	(1.84	)
Realized commodity risk management	(3.48	)	(0.07	)	1.15		(2.90	)	(1.34	)
Operating netback ($/BOE)	13.43		13.16		11.06		16.06		13.23
Light Crude Oil (excluding realized commodity risk management)
Average Daily Oil Production(2) (bbl/d)	10,710		9,322		5,472		2,094		6,872
Sales price ($/bbl)	61.73		60.36		53.24		61.25		59.52
Royalties ($/bbl)	(8.80	)	(10.26	)	(8.23	)	(11.86	)	(9.41	)
Net operating expenses ($/bbl)	(15.02	)	(14.93	)	(16.43	)	(20.33	)	(15.39	)
Transportation costs ($/bbl)	(1.41	)	(1.80	)	(1.04	)	(1.96	)	(1.51	)
Operating netback ($/bbl)	36.50		33.37		27.54		27.10		33.21
Bitumen (excluding realized commodity risk management)
Average Daily Bitumen Production(2) (bbl/d)	14,865		13,657		12,086		14,430		13,754
Sales price ($/bbl)	36.78		34.20		31.57		41.28		36.17
Royalties ($/bbl)	(2.36	)	(2.31	)	(2.59	)	(2.91	)	(2.54	)
Net operating expenses ($/bbl)	(11.85	)	(12.06	)	(14.60	)	(10.62	)	(12.18	)
Transportation costs ($/bbl)	(2.90	)	(2.90	)	(2.90	)	(2.90	)	(2.90	)
Operating netback ($/bbl)	19.67		16.93		11.48		24.85		18.55
Natural Gas (excluding realized commodity risk management)
Average Daily Natural Gas Production(2) (Mcf/d)	121,250		118,939		83,979		42,251		91,367
Sales price ($/Mcf)	3.27		3.01		2.33		3.22		2.96
Royalties ($/Mcf)	0.19		0.14		0.38		(0.01	)	0.19
Net operating expenses ($/Mcf)	(1.99	)	(2.43	)	(2.34	)	(2.29	)	(2.27	)
Transportation costs ($/Mcf)	(0.28	)	(0.25	)	(0.23	)	(0.31	)	(0.26	)
Operating netback ($/Mcf)	1.19		0.47		0.14		0.61		0.62
NGL (excluding realized commodity risk management)
Average Daily NGL Production(2) (bbl/d)	7,173		6,547		3,517		11,136		4,574
Sales price ($/bbl)	32.22		33.40		33.07		50.71		33.96
Royalties ($/bbl)	(9.42	)	(9.98	)	(6.46	)	(16.77	)	(9.50	)
Net operating expenses ($/bbl)	(13.21	)	(15.19	)	(13.22	)	(9.28	)	(13.76	)
Transportation costs ($/bbl	-		-		-		-		-
Operating netback ($/bbl)	9.59		8.23		13.39		24.66		10.70

Notes:

(1) Natural gas has been converted to barrels of oil equivalent on the basis of six (6) Mcf of natural gas being equal to one BOE.

(2) Before the deductions of royalties.

DESCRIPTION OF CAPITAL STRUCTURE

Our authorized capital consists of an unlimited number of Common Shares and 10,000,000 preferred shares, issuable in series ("Preferred Shares"). The following is a summary of the rights, privileges, restrictions and conditions attaching to the securities, which comprise our share capital.

Common Shares

Holders of our Common Shares are entitled to notice of, to attend and to one vote per share held at any meeting of our Shareholders (other than meetings of a class or series of our shares other than the Common Shares as such). Holders of our Common Shares will be entitled to receive dividends as and when declared by our Board on our Common Shares as a class, subject to prior satisfaction of all preferential rights to dividends attached to shares of other classes of our shares ranking in priority to the Common Shares in respect of dividends. Holders of our Common Shares will be entitled in the event of any liquidation, dissolution or winding-up of us, whether voluntary or involuntary, or any other distribution of our assets among our Shareholders for the purpose of winding-up our affairs, and subject to prior satisfaction of all preferential rights to return of capital on dissolution attached to all shares of other classes of our shares ranking in priority to the Common Shares in respect of return of capital on dissolution, to share rateably, together with the holders of shares of any other class of our shares ranking equally with the Common Shares in respect of return of capital on dissolution, in such of our assets as are available for distribution.

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Preferred Shares

The Preferred Shares may be issued in one or more series, at any time or from time to time. Before any shares of a particular series are issued, our Board will fix the number of shares that will form such series and will, subject to the limitations set out in the preferred share terms described below, fix the designation, rights, privileges, restrictions and conditions to be attached to the Preferred Shares of such series, including, but without in any way limiting or restricting the generality of the foregoing, the rate, amount or method of calculation of dividends thereon, the time and place of payment of dividends, the consideration for and the terms and conditions of any purchase for cancellation, retraction or redemption thereof, conversion or exchange rights (if any), and whether into or for our securities or otherwise, voting rights attached thereto (if any), the terms and conditions of any share purchase or retirement plan or sinking fund, and restrictions on the payment of dividends on any shares other than Preferred Shares or payment in respect of capital on any of our shares or creation or issue of debt or equity securities; the whole subject to filing of Articles of Amendment setting forth a description of such series including the designation, rights, privileges, restrictions and conditions attached to the shares of such series. Notwithstanding the foregoing: (a) our Board may at any time or from time to time change the rights, privileges, restrictions and conditions attached to unissued shares of any series of Preferred Shares; and (b) other than in the case of a failure to declare or pay dividends specified in any series of the Preferred Share, the voting rights attached to the Preferred Shares will be limited to one vote per Preferred Share at any meeting where the Preferred Shares and Common Shares vote together as a single class.

Term Notes and Credit Facility

A full description of our Term Notes and Credit Facility can be found in the notes and management discussion and analysis accompanying our December 31, 2017 audited financial statements.

Stock Exchange Listings

Our Common Shares are listed and posted for trading on the TSX under the symbol "PGF" and on the NYSE under the symbol "PGH". Our 6.25 percent series B convertible debentures were listed and posted for trading on the TSX under the symbol "PGF.DB.B" until they matured on March 31, 2017.

DIVIDENDS

Effective January 20, 2016, we suspended paying a dividend. Prior to suspending our dividend, a decision which is reviewed quarterly, we paid a quarterly dividend to our Shareholders on the 15^th day (or the first business day following the 15^th) of each of March, June, September and December. The record date for any dividend prior to suspension was the last business day of the month preceding the dividend date or such other date as may be determined by our Board.

Historical Dividends

Dividends can and may fluctuate in the future. Actual future cash dividends, if any, will be subject to the discretion of our Board of Directors and may vary depending on a variety of factors and conditions existing from time to time, including fluctuations in commodity prices, production levels, capital expenditure requirements, debt service requirements, operating costs, royalty burdens, foreign exchange rates and the satisfaction of the liquidity and solvency tests imposed by the ABCA for the declaration and payment of dividends. We cannot provide assurance that cash flow will be available for distribution to Shareholders in the amounts anticipated or at all. See "RiskFactors".

The following table sets forth dividends declared by the Corporation for the three most recently completed financial years on the outstanding Common Shares for the periods indicated, with each amount being paid in the following month. Prior to October 2015, dividends were paid monthly. No dividends have been declared or paid since November 2015.

Month Declared	2017 ($/share)	2016 ($/share)	2015 ($/share)
January	-	-	0.04
February	-	-	0.02
March	-	-	0.02
April	-	-	0.02
May	-	-	0.02
June	-	-	0.02
July	-	-	0.02
August	-	-	0.02
September	-	-	-
October	-	-	-
November	-	-	0.01
December	-	-	-
Total	-	-	0.19

All of these dividends are "eligible dividends" for the purposes of the Tax Act.

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Restrictions on Dividends

Our ability to pay cash dividends to Shareholders is prohibited by our Credit Facility and the note purchase agreements relating to our Term Notes and may also be restricted by the solvency tests in the ABCA.

The payment of dividends by a corporation is governed by the liquidity and insolvency tests described in the ABCA. Pursuant to the ABCA, after the payment of a dividend, we must be able to pay our liabilities as they become due, and the realizable value of our assets must be greater than our liabilities and the legal stated capital of our outstanding securities. As at December 31, 2017, our legal stated capital was approximately $250 million.

INDUSTRY CONDITIONS

Companies carrying on business in the crude oil and natural gas sector in Canada are subject to extensive controls and regulations imposed through legislation of the federal government and the provincial governments where the companies have assets or operations. While these regulations do not affect Pengrowth's operations in any manner that is materially different than they affect other similarly-sized industry participants with similar assets and operations, investors should consider such regulations carefully. Although governmental legislation is a matter of public record, we are unable to predict what additional legislation or amendments governments may enact in the future.

Pengrowth holds interests in crude oil and natural gas properties, along with related assets, primarily in the Canadian provinces of Alberta, British Columbia, Saskatchewan and Nova Scotia. Our assets and operations are regulated by administrative agencies deriving authority from underlying legislation. Regulated aspects of our upstream crude oil and natural gas business include all manner of activities associated with the exploration for and production of crude oil and natural gas, including, among other matters: (i) permits for the drilling of wells; (ii) technical drilling and well requirements; (iii) permitted locations and access of operation sites; (iv) operating standards regarding conservation of produced substances and avoidance of waste, such as restricting flaring and venting; (v) minimizing environmental impacts; (vi) storage, injection and disposal of substances associated with production operations; and (vii) the abandonment and reclamation of impacted sites. In order to conduct crude oil and natural gas operations and remain in good standing with the applicable provincial regulatory scheme, producers must comply with applicable legislation, regulations, orders, directives and other directions (all of which are subject to governmental oversight, review and revision, from time to time). Compliance in this regard can be costly and a breach of the same may result in fines or other sanctions. The discussion below outlines certain pertinent conditions and regulations that impact the crude oil and natural gas industry in Western Canada.

Pricing and Marketing in Canada

Crude Oil

Producers of crude oil are entitled to negotiate sales contracts directly with crude oil purchasers, which results in the market determining the price of crude oil. Worldwide supply and demand factors primarily determine crude oil prices; however, regional market and transportation issues also influence prices. The specific price depends, in part, on crude oil quality, prices of competing fuels, distance to market, availability of transportation, value of refined products, supply/demand balance and contractual terms of sale.

Natural Gas

The price of natural gas sold in intra-provincial, interprovincial and international trade is determined by negotiation between buyers and sellers. The price received by a natural gas producer depends, in part, on the price of competing natural gas supplies and other fuels, natural gas quality, distance to market, availability of transportation, length of contract term, weather conditions, supply/demand balance and other contractual terms. Spot and future prices can also be influenced by supply and demand fundamentals on various trading platforms.

Natural Gas Liquids

The price of NGLs sold in intra-provincial, interprovincial and international trade is determined by negotiation between buyers and sellers. Such price depends, in part, on the quality of the NGLs, price of competing chemical stock, distance to market, access to downstream transportation, length of contract term, supply/demand balance and other contractual terms.

Exports from Canada

Crude oil, natural gas and NGLs exports from Canada are subject to the National Energy Board Act (Canada) (the "NEB Act") and the National Energy Board Act Part VI (Oil and Gas) Regulation (the "Part VI Regulation"). The NEB Act and the Part VI Regulation authorize crude oil, natural gas and NGLs exports under either short-term orders or long-term licences. To obtain a crude oil export licence, a mandatory public hearing with the National Energy Board (the "NEB") is required, which is no longer the case for natural gas and NGLs. For natural gas and NGLs, the NEB uses a written process that includes a public comment period for impacted persons. Following the comment period, the NEB completes its assessment of the application and either approves or denies the application. For natural gas, the maximum duration of an export licence is 40 years and, for crude oil and other gas substances (e.g. NGLs), the maximum term is 25 years. All crude oil, natural gas and NGLs licences require the approval of the cabinet of the Canadian federal government.

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Orders from the NEB provide a short-term alternative to export licences and may be issued more expediently, since they do not require a public hearing or approval from the cabinet of the Canadian federal government. Orders are issued pursuant to the Part VI Regulation for up to one or two years depending on the substance, with the exception of natural gas (other than NGLs) for which an order may be issued for up to twenty years for quantities not exceeding 30,000 m³ per day.

As to price, exporters are free to negotiate prices and other terms with purchasers, provided that the export contracts continue to meet certain other criteria prescribed by the NEB and the federal government.

Pengrowth does not directly enter into contracts to export its production outside of Canada.

As discussed in more detail below, one major constraint to the export of crude oil, natural gas and NGLs outside of Canada is the deficit of overall pipeline and other transportation capacity to transport production from Western Canada to the United States and other international markets. Although certain pipeline or other transportation projects are underway, many contemplated projects have been cancelled or are delayed due to regulatory hurdles, court challenges and economic and political factors. The transportation capacity deficit is not likely to be resolved quickly given the significant length of time required to complete major pipeline or other transportation projects once all regulatory and other hurdles have been cleared. In addition, production of crude oil, natural gas and NGLs in Canada is expected to continue to increase, which may further exacerbate the transportation capacity deficit.

Transportation Constraints and Market Access

Producers negotiate with pipeline operators (or other transportation providers) to transport their products, which may be done on a firm or interruptible basis. Due to growing production and a lack of new and expanded pipeline and rail infrastructure capacity, producers in Western Canada have experienced low pricing relative to other markets in the last several years. Transportation availability is highly variable across different areas and regions, which can determine the nature of transportation commitments available, the numbers of potential customers that can be reached in a cost-effective manner and the price received.

Developing a strong network of transportation infrastructure for crude oil, natural gas and NGLs, including by means of pipelines, rail, marine and trucks, in order to obtain better access to domestic and international markets has been a significant challenge to the Canadian crude oil and natural gas industry. Improved means of access to global markets, especially the Midwest United States and export shipping terminals on the west coast of Canada, would help to alleviate the pressures of pricing discussed. Several proposals have been announced to increase pipeline capacity out of Western Canada, to reach Eastern Canada, the United States and international markets via export shipping terminals on the west coast of Canada. While certain projects are proceeding, the regulatory approval process as well as economic and political factors for transportation and other export infrastructure has led to the delay of many pipeline projects or their cancellation altogether.

Under the Canadian constitution, interprovincial and international pipelines fall within the federal government's jurisdiction and require approval by both the NEB and the cabinet of the federal government. However, recent years have seen a perceived lack of policy and regulatory certainty at a federal level. Although the current federal government recently introduced draft legislation to amend the current federal approval processes, it is uncertain when the new legislation will be brought into force and whether any changes to the draft legislation will be made before the legislation is brought into force. It is also uncertain whether any new approval process adopted by the federal government will result in a more efficient approval process. The lack of regulatory certainty is likely to have an influence on investment decisions for major projects. Even when projects are approved on a federal level, such projects often face further delays due to interference by provincial and municipal governments as well as court challenges on various issues such as indigenous title, the government's duty to consult and accommodate indigenous peoples and the sufficiency of environmental review processes, which creates further uncertainty. Export pipelines from Canada to the United States face additional uncertainty as such pipelines require approvals of several levels of government in the United States.

Natural gas prices in Alberta and British Columbia have also been constrained in recent years due to increasing North American supply, limited access to markets and limited storage capacity. While companies that secure firm access to transport their natural gas production out of Western Canada may be able to access more markets and obtain better pricing, other companies may be forced to accept spot pricing in Western Canada for their natural gas, which in the last several years has generally been depressed (at times producers have received negative pricing for their natural gas production). Required repairs or upgrades to existing pipeline systems have also led to further reduced capacity and apportionment of firm access, which in Western Canada may be further exacerbated by natural gas storage limitations. Additionally, while a number of liquefied natural gas export plants have been proposed for the west coast of Canada, government decision-making, regulatory uncertainty, opposition from environmental and indigenous groups, and changing market conditions, have resulted in the cancellation or delay of many of these projects.

The North American Free Trade Agreement and Other Trade Agreements

The North American Free Trade Agreement ("NAFTA") among the governments of Canada, the United States and Mexico came into force on January 1, 1994. Under the terms of NAFTA, Canada remains free to determine whether exports of energy resources to the United States or Mexico will be allowed, provided that any export restrictions do not: (i) reduce the proportion of energy resources exported relative to the total supply of goods of Canada as compared to the proportion prevailing in the most recent 36 month period; (ii) impose an export price higher than the domestic price (subject to an exception with respect to certain measures which only restrict the volume

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of exports); and (iii) disrupt normal channels of supply. Further, all three signatory counties are prohibited from imposing a minimum or maximum price requirement on exports (where any other form of quantitative restriction is prohibited) and imports (except as permitted in the enforcement of countervailing and anti-dumping orders and undertakings). NAFTA also requires energy regulators to ensure the orderly and equitable implementation of any regulatory changes and to ensure that the application of such changes will cause minimal disruption to contractual arrangements and avoid undue interference with pricing, marketing and distribution arrangements.

In 2017, the United States government announced its intention to renegotiate NAFTA. As a result, Canada, the United States and Mexico began renegotiating the terms of NAFTA in mid-2017. The United States has also suggested that it might give notice of the termination of NAFTA if it is not satisfied with the outcome of the renegotiations. If the United States does give notice of its intent to terminate or withdraw from NAFTA, the earliest such termination or withdrawal could occur would be six months after such notice is given. The renegotiations are still underway and theoutcome of such negotiations remain unclear, but as the United States remains by far Canada's largest trade partner and the largest international market for the export of crude oil, natural gas and NGLs from Canada, any changes to, or termination of, NAFTA could have an impact on Western Canada's crude oil and natural gas industry at large, including the Corporation's business.

Canada has also pursued a number of other international free trade agreements with other countries around the world. As a result, a number of free trade or similar agreements are in force between Canada and certain other countries while in other circumstances Canada has been unsuccessful in its efforts. Canada and the European Union recently agreed to the Comprehensive Economic and Trade Agreement ("CETA"), which provides for duty-free, quota-free market access for Canadian oil and gas products to the European Union. Although CETA remains subject to ratification by certain national legislatures in the European Union, provisional application of CETA commenced on September 21, 2017. In addition, Canada and ten other countries recently concluded discussions and agreed on the draft text of the Comprehensive and Progressive Agreement for Trans-Pacific Partnership ("CPTPP"), which is intended to allow for preferential market access among the countries that are parties to the CPTPP. The text of CPTPP has not been finalized or published and the agreement remains subject to ratification by the governments of each of the countries involved. While it is uncertain what effect CETA, CPTPP or any other trade agreements will have on the oil and gas industry in Canada, the lack of available infrastructure for the offshore export of oil and gas may limit the ability of Canadian oil and gas producers to benefit from such trade agreements.

Land Tenure

The respective provincial governments (i.e. the Crown), predominantly own the mineral rights to crude oil and natural gas located in Western Canada, with the exception of Manitoba (which only owns 20 percent of the mineral rights). Provincial governments grant rights to explore for and produce crude oil and natural gas pursuant to leases, licences and permits for varying terms, and on conditions set forth in provincial legislation, including requirements to perform specific work or make payments. The provincial governments in Western Canada's provinces conduct regular land sales where crude oil and natural gas companies bid for leases to explore for and produce crude oil and natural gas pursuant to mineral rights owned by the respective provincial governments. The leases generally have a fixed term; however, a lease may generally be continued after the initial term where certain minimum thresholds of production have been reached, all lease rental payments have been paid on time and other conditions are satisfied.

To develop crude oil and natural gas resources, it is necessary for the mineral estate owner to have access to the surface lands as well. Each province has developed its own process for obtaining surface access to conduct operations that operators must follow throughout the lifespan of a well, including notification requirements and providing compensation for affected persons for lost land use and surface damage.

Each of the provinces of Alberta, British Columbia and Saskatchewan have implemented legislation providing for the reversion to the Crown of mineral rights to deep, non-productive geological formations at the conclusion of the primary term of a lease or licence. Additionally, the provinces of Alberta and British Columbia have shallow rights reversion for shallow, non-productive geological formations for new leases and licences.

In addition to Crown ownership of the rights to crude oil and natural gas, private ownership of crude oil and natural gas (i.e. freehold mineral lands) also exists in the provinces of Alberta, British Columbia and Saskatchewan. In each of the provinces of Alberta, British Columbia and Saskatchewan approximately 19 percent, 6 percent and 30 percent, respectively, of the mineral rights are owned by private freehold owners. Rights to explore for and produce such crude oil and natural gas are granted by a lease or other contract on such terms and conditions as may be negotiated between the owner of such mineral rights and crude oil and natural gas explorers and producers.

An additional category of mineral rights ownership includes ownership by the Canadian federal government of some legacy mineral lands and within indigenous reservations designated under the Indian Act (Canada). Indian Oil and Gas Canada ("IOGC"), which is a federal government agency, manages subsurface and surface leases, in consultation with the applicable indigenous peoples, for exploration and production of crude oil and natural gas on indigenous reservations.

Royalties and Incentives

General

Each province has legislation and regulations that govern royalties, production rates and other matters. The royalty regime in a given province is a significant factor in the profitability of oilsands projects, and crude oil, natural gas and NGLs production. Royalties payable

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on production from lands where the Crown does not hold the mineral rights are determined by negotiation between the mineral freehold owner and the lessee, although production from such lands is subject to certain provincial taxes and royalties. Royalties from production on Crown lands are determined by governmental regulation and are generally calculated as a percentage of the value of gross production. The rate of royalties payable generally depends in part on prescribed reference prices, well productivity, geographical location, field discovery date, method of recovery and the type or quality of the petroleum substance produced.

Occasionally the governments of Western Canada's provinces create incentive programs for exploration and development. Such programs often provide for royalty rate reductions, royalty holidays or royalty tax credits and are often introduced when commodity prices are low to encourage exploration and development activity. In addition, such programs may be introduced to encourage producers to undertake initiatives using new technologies that may enhance or improve recovery of crude oil, natural gas and NGLs.

Producers and working interest owners of crude oil and natural gas rights may also carve out additional royalties or royalty-like interests through non-public transactions, which include the creation of instruments such as overriding royalties, net profits interests and net carried interests.

Alberta

In Alberta, the provincial government royalty rates apply to Crown-owned mineral rights. In 2016, Alberta adopted a modernized Alberta royalty framework (the "Modernized Framework") that applies to all wells drilled after January 1, 2017. The previous royalty framework (the "Old Framework") will continue to apply to wells drilled prior to January 1, 2017 for a period of ten years ending on December 31, 2026. After the expiry of this ten-year period, these older wells will become subject to the Modernized Framework.

The Modernized Framework applies to all hydrocarbons other than oil sands which will remain subject to their existing royalty regime. Royalties on production from non-oil sands wells under the Modernized Framework are determined on a "revenue-minus-costs" basis with the cost component based on a Drilling and Completion Cost Allowance formula for each well, depending on its vertical depth and/or horizontal length. The formula is based on the industry’s average drilling and completion costs as determined by the Alberta Energy Regulator (the "AER") on an annual basis.

Producers pay a flat royalty rate of five percent of gross revenue from each well that is subject to the Modernized Framework until the well reaches payout. Payout for a well is the point at which cumulative gross revenues from the well equals the Drilling and Completion Cost Allowance for the well set by the AER. After payout, producers pay an increased post-payout royalty on revenues of between five percent and 40 percentdetermined by reference to the then current commodity prices of the various hydrocarbons. Similar to the Old Framework, the post-payout royalty rate under the Modernized Framework varies with commodity prices. Once production in a mature well drops below a threshold level where the rate of production is too low to sustain the full royalty burden, its royalty rate is adjusted downward towards a minimum of five percent as the mature well's production declines. As the Modernized Framework uses deemed drilling and completion costs in calculating the royalty and not the actual drilling and completion costs incurred by a producer, low cost producers benefit if their well costs are lower than the Drilling and Completion Cost Allowance and, accordingly, they continue to pay the lower 5% royalty rate for a period of time after their wells achieve actual payout.

The Old Framework is applicable to all conventional crude oil and natural gas wells drilled prior to January 1, 2017 and bitumen production. Subject to certain available incentives, effective from the January 2011 production month, royalty rates for conventional crude oil production under the Old Framework range from a base rate of zero percent to a cap of 40 percent. Subject to certain available incentives, effective from the January 2011 production month, royalty rates for natural gas production under the Old Framework range from a base rate of five percent to a cap of 36 percent. The Old Framework also includes a natural gas royalty formula which provides for a reduction based on the measured depth of the well below 2,000 metres deep, as well as the acid gas content of the produced gas. Under the Old Framework, the royalty rate applicable to NGLs is a flat rate of 40 percent for pentanes and 30 percent for butanes and propane. Currently, producers of crude oil and natural gas from Crown lands in Alberta are also required to pay annual rental payments, at a rate of $3.50 per hectare, and make monthly royalty payments in respect of crude oil and natural gas produced.

Oil sands production is also subject to Alberta's royalty regime. The Modernized Framework did not change the oil sands royalty framework. Prior to payout of an oil sands project, the royalty is payable on gross revenues of an oil sands project. Gross revenue royalty rates range between one percent and nine percent depending on the market price of crude oil, determined using the average monthly price, expressed in Canadian dollars, for Western Texas Intermediate crude oil at Cushing, Oklahoma. Rates are one percent when the market price of crude oil is less than or equal to $55 per barrel and increase for every dollar of market price of crude oil increase to a maximum of nine percent when crude oil is priced at $120 or higher. After payout, the royalty payable is the greater of the gross revenue royalty based on the gross revenue royalty rate of between one percent and nine percent and the net revenue royalty based on the net revenue royalty rate. Net revenue royalty rates start at 25 percent and increase for every dollar of market price of crude oil increase above $55 up to 40 percent when crude oil is priced at $120 or higher.

The Government of Alberta has from time to time implemented drilling credits, incentives or transitional royalty programs to encourage crude oil and natural gas development and new drilling. In addition, the Government of Alberta has implemented certain initiatives intended to accelerate technological development and facilitate the development of unconventional resources, including as applied to coalbed methane wells, shale gas wells and horizontal crude oil and natural gas wells.

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Freehold mineral taxes are levied for production from freehold mineral lands on an annual basis on calendar year production. Freehold mineral taxes are calculated using a tax formula that takes into consideration, among other things, the amount of production, the hours of production, the value of each unit of production, the tax rate and the percentages that the owners hold in the title. On average, in Alberta the tax levied is four percent of revenues reported from freehold mineral title properties. The freehold mineral taxes would be in addition to any royalty or other payment paid to the owner of such freehold mineral rights, which are established through private negotiation.

British Columbia

Producers of crude oil in British Columbia receive royalty invoices each month for every well or unitized tract that is producing and/or reporting sales. The royalty calculation takes into account the production of crude oil on a well-by-well basis, which can be up to 40 percent, based on factors such as the volume of crude oil produced by the well or tract and the crude oil vintage, which depends on density of the substance and when the crude oil pool was located. Royalty rates are reduced on low-productivity wells and other wells with applicable royalty exemptions to reflect higher per-unit costs of exploration and extraction.

Producers of natural gas and NGLs in British Columbia receive royalty invoices each month for every well or unitized tract that is producing and/or reporting sales. Different royalty rates apply for natural gas, NGLs and natural gas by-products. For natural gas, the royalty rate can be up to 27 percent of the value of the natural gas and is based on whether the gas is classified as conservation gas or non-conservation gas, as well as reference prices and the select price. For NGLs and condensates, the royalty rate is fixed at 20 percent.

The royalties payable by each producer will thus vary depending on the types of wells and the characteristics of the substances being produced. Additionally, the Government of British Columbia maintains a number of targeted royalty programs for key resource areas intended to increase the competitiveness of British Columbia's low productivity natural gas wells. These include both royalty credit and royalty reduction programs.

Producers of crude oil and natural gas from freehold lands in British Columbia are required to pay monthly freehold production taxes. For crude oil, the applicable freehold production tax is based on the volume of monthly production, which is either a flat rate, or, beyond a certain production level, is determined using a sliding scale formula based on the production level. For natural gas, the applicable freehold production tax is a flat rate, or, at certain production levels, is determined using a sliding scale formula based on a reference price, and depends on whether the natural gas is conservation gas or non-conservation gas. The production tax rate for freehold NGLs is a flat rate of 12.25 percent. Additionally, owners of mineral rights in British Columbia must pay an annual mineral land tax that is equivalent to $4.94 per hectare of producing lands. Non-producing lands are taxed on a sliding scale depending on the total number of hectares owned by the entity.

Saskatchewan

In Saskatchewan, the Crown owns approximately 80 percent of the crude oil and natural gas rights, with the remainder being freehold lands. For Crown lands, taxes (the "Resource Surcharge") and royalties are applicable to revenue generated by entities focused on crude oil and natural gas operations. The Resource Surcharge rate is three percent of the value of sales of all crude oil and natural gas produced from wells drilled in Saskatchewan prior to October 1, 2002. For crude oil and natural gas produced from wells drilled in Saskatchewan after September 30, 2002, the Resource Surcharge rate is 1.7 percent of the value of sales. In addition, a mineral rights tax is charged to mineral rights holders paid on an annual basis at the rate of $1.50 per acre owned.

In addition to such surcharges and taxes, the Crown royalty payable in respect of crude oil depends on the type and vintage of crude oil, the quantity of crude oil produced in a month, the value of the crude oil produced and specified adjustment factors determined monthly by the provincial government. The ultimate royalty payable ranges from five percent to 20 percent depending on the classification of the crude oil, and additional marginal royalty rates may apply, between 30 percent and 45 percent, where average wellhead prices received are above base prices. This means that producers may pay varying royalties each month, depending on pricing factors, governmental adjustments and the underlying characteristics of the producer's assets.

The amount payable as a Crown royalty in respect of production of natural gas and NGLs is determined by a sliding scale based on the monthly provincial average gas price published by the Government of Saskatchewan, the quantity produced in a given month, the type of natural gas, the classification of the natural gas and the finished drilling date of the respective well. Similar to crude oil royalties, the royalties payable on natural gas will range from five percent to 20 percent, and additional marginal royalty rates may apply between 30 percent to 45 percent, where average wellhead prices are above base prices. Again, this means that producers may pay varying royalties each month, depending on pricing factors, governmental adjustments and the underlying characteristics of the producer's assets.

The Government of Saskatchewan currently provides a number of targeted incentive programs. These include both royalty reduction and incentive volume programs, with targeted programs in effect for certain vertical crude oil wells, exploratory gas wells, horizontal crude oil and natural gas wells, enhanced crude oil recovery wells and high water-cut crude oil wells.

For production from freehold lands, producers must pay a freehold production tax, determined by first determining the Crown royalty rate, and then subtracting a calculated production tax factor. Depending on the classification of the petroleum substance produced, this subtraction factor may range between 6.9 and 12.5, however, in certain circumstances, the minimum rate for freehold production tax can

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be zero. This means that the ultimate tax payable to the Crown by producers on freehold lands will vary based on the underlying characteristics of the producer's assets.

Nova Scotia

The Government of Nova Scotia has established a generic royalty regime in respect of oil and gas produced from offshore Nova Scotia based on revenues and profits. Such regime contemplates a multi-tier royalty in which the royalty rate fluctuates when certain threshold levels of rates of return on capital have been reached and offers lower royalties for a first project in a new area, being a "high risk project". Notwithstanding the generic royalty regime, royalties in respect of offshore Nova Scotia oil and gas production may be determined contractually between the participant and the Government of Nova Scotia.

Freehold and Other Types of Non-Crown Royalties

Royalties on production from privately-owned freehold lands are negotiated between the mineral freehold owner and the lessee under a negotiated lease or other contract.

In addition to the royalties payable to the mineral owners, producers of crude oil and natural gas from freehold lands in each of the Western Canadian provinces are required to pay freehold mineral taxes or production taxes. Freehold mineral taxes or production taxes are taxes levied by a provincial government on crude oil and natural gas production from lands where the Crown does not hold the mineral rights. A description of the freehold mineral taxes payable in each of the Western Canadian provinces is included in the above descriptions of the royalty regimes in such provinces.

IOGC is a special agency responsible for managing and regulating the crude oil and natural gas resources located on indigenous reservations across Canada. IOGC's responsibilities include negotiating and issuing the crude oil and natural gas agreements between indigenous groups and crude oil and natural gas companies, as well as collecting royalty revenues on behalf of indigenous groups and depositing the revenues in their trust accounts. While certain standards exist, the exact terms and conditions of each crude oil and natural gas lease dictate the calculation of royalties owed, which may vary depending on the involvement of the specific indigenous group. Ultimately, the relevant indigenous group must approve the terms.

Regulatory Authorities and Environmental Regulation

General

The crude oil and natural gas industry is currently subject to environmental regulation under a variety of Canadian federal, provincial, territorial and municipal laws and regulations, all of which are subject to governmental review and revision from time to time. Such regulations provide for, among other things, restrictions and prohibitions on the spill, release or emission of various substances produced in association with certain crude oil and natural gas industry operations, such as sulphur dioxide and nitrous oxide. The regulatory regimes set out the requirements with respect to oilfield waste handling and storage, habitat protection and the satisfactory operation, maintenance, abandonment and reclamation of well and facility sites. Compliance with such regulations can require significant expenditures and a breach of such requirements may result in suspension or revocation of necessary licences and authorizations, civil liability and the imposition of material fines and penalties. In addition to these specific, known requirements, future changes to environmental legislation, including anticipated legislation for air pollution and greenhouse gas ("GHG") emissions, may impose further requirements on operators and other companies in the crude oil and natural gas industry.

Federal

Canadian environmental regulation is the responsibility of both the federal and provincial governments. Where there is a direct conflict between federal and provincial environmental legislation in relation to the same matter, the federal law will prevail. However, such conflicts are uncommon. The federal government has primary jurisdiction over federal works, undertakings and federally regulated industries such as railways, aviation and interprovincial transport including interprovincial pipelines.

On June 20, 2016, the federal government launched a review of current environmental and regulatory processes. On February 8, 2018, the Government of Canada introduced draft legislation to overhaul the existing environmental assessment process and replace the NEB with the Canadian Energy Regulator ("CER"). Pursuant to the draft legislation, the Impact Assessment Agency of Canada (the "Agency") would replace the Canadian Environmental Assessment Agency. It appears that additional categories of projects may be included within the new impact assessment process, such as large-scale wind power facilities and in-situ oilsands facilities. The revamped approval process for applicable major developments will have specific legislated timelines at each stage of the formal impact assessment process. The Agency's process would focus on: (i) early engagement by proponents to engage the Agency and all stakeholders such as the public and indigenous groups prior to the formal impact assessment process; (ii) potentially increased public participation where the project undergoes a panel review; (iii) providing analysis of the potential impacts and effects of a project without making recommendations, to support a public-interest approach to decision-making, with cost-benefit determinations and approvals made by the Minister of Environment and Climate Change or the cabinet of the federal government; (iv) analyzing further specified factors for projects such as alternatives to the project and social and indigenous issues in addition to health, environmental and economic impacts; and (v) overseeing an expanded follow-up, monitoring and enforcement process with increased involvement of indigenous peoples and communities. As to the proposed CER, many of its activities would be similar to the NEB, albeit with a different structure and the notable exception that the CER would no

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longer have primary responsibility in the consideration of the new major projects, instead focusing on the lifecycle regulation (e.g. overseeing construction, tolls and tariffs, operations and eventual winding down) of approved projects, while providing for expanded participation by communities and indigenous peoples. It is unclear when the new regulatory scheme will come into force or whether any amendments will be made prior to coming into force. Until then, the federal government's interim principles released on January 27, 2016 will continue to guide decision-making authorities for projects currently undergoing environmental assessment. The eventual effects of the proposed regulatory scheme on proponents of major projects remains unclear.

On May 12, 2017, the federal government introduced the Oil Tanker Moratorium Act in Parliament. This legislation is aimed at providing coastal protection in northern British Columbia by prohibiting crude oil tankers carrying more than 12,500 metric tonnes of crude oil or persistent crude oil products from stopping, loading, or unloading crude oil in that area. Parliament is still considering the bill, which passed second reading on October 4, 2017. If implemented, the legislation may prevent the building of pipelines to, and export terminals located on, the portion of the British Columbia coast subject to the moratorium and, as a result, negatively affect the ability of producers to access global markets.

Alberta

The AER is the single regulator responsible for all resource development in Alberta. The AER is responsible for ensuring the safe, efficient, orderly and environmentally responsible development of hydrocarbon resources including allocating and conserving water resources, managing public lands, and protecting the environment. The AER's responsibilities exclude the functions of the Alberta Utilities Commission and the Surface Rights Board, as well as Alberta Energy's responsibility for mineral tenure. The objective behind a single regulator is an enhanced regulatory regime that is intended to be efficient, attractive to business and investors and effective in supporting public safety, environmental management and resource conservation while respecting the rights of landowners.

The Government of Alberta relies on regional planning to accomplish its responsible resource development goals. Its approach to natural resource management provides for engagement and consultation with stakeholders and the publicand examines the cumulative impacts of development on the environment and communities by incorporating the management of all resources, including energy, minerals, land, air, water and biodiversity. While the AER is the primary regulator for energy development, several other governmental departments and agencies may be involved in land use issues, including Alberta Environment and Parks, Alberta Energy, the Policy Management Office, the Aboriginal Consultation Office and the Land Use Secretariat.

The Government of Alberta's land-use policy for surface land in Alberta sets out an approach to manage public and private land use and natural resource development in a manner that is consistent with the long-term economic, environmental and social goals of the province. It calls for the development of seven region-specific land-use plans in order to manage the combined impacts of existing and future land use within a specific region and the incorporation of a cumulative effects management approach into such plans. As a result, several regional plans have been implemented and others are in the process of being implemented. These regional plans may affect further development and operations in such regions.

British Columbia

In British Columbia, the Oil and Gas Activities Act (the "OGAA") impacts conventional crude oil and natural gas producers, shale gas producers and other operators of crude oil and natural gas facilities in the province. Under the OGAA, the British Columbia Oil and Gas Commission (the "Commission") has broad powers, particularly with respect to compliance and enforcement and the setting of technical safety and operational standards for crude oil and natural gas activities. The Environmental Protection and Management Regulation establishes the government's environmental objectives for water, riparian habitats, wildlife and wildlife habitat, old-growth forests and cultural heritage resources. The OGAA requires the Commission to consider these environmental objectives in deciding whether or not to authorize a crude oil or natural gas activity. In addition, although not an exclusively environmental statute, the Petroleum and Natural Gas Act, in conjunction with the OGAA, requires proponents to obtain various approvals before undertaking exploration or production work, such as geophysical licences, geophysical exploration project approvals, permits for the exclusive right to do geological work and geophysical exploration work, and well, test hole and water-source well authorizations. Such approvals are given subject to environmental considerations and licences and project approvals can be suspended or cancelled for failure to comply with this legislation or its regulations.

Saskatchewan

The Saskatchewan Ministry of the Economy, Petroleum Branch, is the primary regulator of crude oil and natural gas activities in the province. In May 2011, the Government of Saskatchewan passed changes to The Oil and Gas Conservation Act (the "SKOGCA"), the act governing the regulation of resource development operations in the province. Although the associated Bill received Royal Assent on May 18, 2011, it was not proclaimed into force until April 1, 2012, in conjunction with the release of The Oil and Gas Conservation Regulations, 2012 (the "OGCR") and The Petroleum Registry and Electronic Documents Regulations (the "Registry Regulations"). The aim of the amendments to the SKOGCA, and the associated regulations, is to provide resource companies investing in Saskatchewan's energy and resource industries with the best support services and business and regulatory systems available. With the enactment of the Registry Regulations and the OGCR, the Government of Saskatchewan has implemented a number of operational requirements, including the increased demand for record-keeping, increased testing requirements for injection wells and increased investigation and enforcement powers; and, procedural requirements including those related to Saskatchewan's participation as partner in the Petroleum Registry of Alberta.

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Liability Management Rating Program

Alberta

The AER administers the Licensee Liability Rating Program (the "AB LLR Program"). The AB LLR Program is a liability management program governing most conventional upstream crude oil and natural gas wells, facilities and pipelines. Alberta's Oil and Gas Conservation Act (the "OGCA") establishes an orphan fund (the "Orphan Fund") to pay the costs to suspend, abandon, remediate and reclaim a well, facility or pipeline included in the AB LLR Program if a licensee or working interest participant ("WIP") becomes insolvent or is unable to meet its obligations. The Orphan Fund is funded by licensees in the AB LLR Program through a levy administered by the AER. The AB LLR Program is designed to minimize the risk to the Orphan Fund posed by unfunded liability of licensees and to prevent the taxpayers of Alberta from incurring costs to suspend, abandon, remediate and reclaim wells, facilities or pipelines. The AB LLR Program requires a licensee whose deemed liabilities exceed its deemed assets to provide the AER with a security deposit. The ratio of deemed assets to deemed liabilities is assessed once each month and where a security deposit is deemed to be required, the failure to post any required amounts may result in the initiation of enforcement action by the AER. The AER publishes the liability management rating for each licensee on a monthly basis on its public website.

In Redwater Energy Corporation (Re) ("Redwater"), the Court of Queen's Bench of Alberta found that there was an operational conflict between the abandonment and reclamation provisions of the OGCA, including the AB LLR Program, and the Bankruptcy and Insolvency Act (the "BIA"). This ruling meant that receivers and trustees have the right to renounce assets within insolvency proceedings, which was affirmed by a majority of the Alberta Court of Appeal. Such a conflict renders the AER's legislated authority unenforceable to impose abandonment orders against licensees or to require a licensee to pay a security deposit before approving a transfer when such a licensee is insolvent. Effectively, this means that abandonment costs will be borne by the industry-funded Orphan Well Fund or the province in these instances because any financial resources of the insolvent licensee will first be used to satisfy secured creditors under the BIA. This decision is currently under appeal to the Supreme Court of Canada, with final resolution expected in 2018.

In response to Redwater, the AER issued several bulletins and interim rule changes to govern while the case is appealed and to allow the Government of Alberta to develop appropriate regulatory measures to adequately address environmental liabilities. The AER's Directive 067: Eligibility Requirements for Acquiring and Holding Energy Licences and Approvals, which deals with licence eligibility to operate wells and facilities, was amended and now requires extensive corporate governance and shareholder information, with a particular focus on any previous companies of directors and officers that have been subject to insolvency proceedings in the last five years. All transfers of well, facility and pipeline licences in the province are subject to AER approval. As a condition of transferring existing AER licences, approvals and permits, all are assessed on a non-routine basis and the AER now requires all transferees to demonstrate that they have a liability management rating ("LMR"), being the ratio of a licensee's assets to liabilities, of 2.0 or higher immediately following the transfer, or to otherwise prove that it can satisfy its abandonment and reclamation obligations. The AER may make further rule changes in response to Redwater at any time, especially as the case heads towards a final determination, which means that additional obligations and/or different requirements may be forthcoming.

The AER has also implemented the Inactive Well Compliance Program (the "IWCP") to address the growing inventory of inactive wells in Alberta and to increase the AER's surveillance and compliance efforts under Directive 013: Suspension Requirements for Wells ("Directive 013"). The IWCP applies to all inactive wells that are noncompliant with Directive 013 as of April 1, 2015. The objective is to bring all inactive noncompliant wells under the IWCP into compliance with the requirements of Directive 013 within five years. As of April 1, 2015, each licensee is required to bring 20 percent of its inactive wells into compliance every year, either by reactivating or by suspending the wells in accordance with Directive 013 or by abandoning them in accordance with Directive 020: Well Abandonment. The list of current wells subject to the IWCP is available on the AER's Digital Data Submission system. The AER has announced that from April 1, 2015 to April 1, 2016, the number of noncompliant wells subject to the IWCP fell from 25,792 to 17,470, with 76 percent of licensees operating in the province having met their annual quota. The IWCP completed its second year on March 31, 2017. Overall, the AER has announced that licensees brought 19 percent of non-compliant wells in the IWCP into compliance with AER requirements in the second year of the IWCP.

British Columbia

The Commission oversees a similar Liability Management Rating Program (the "BC LMR Program"), which is designed to manage public liability exposure related to crude oil and natural gas activities by ensuring that permit holders carry the financial risks and regulatory responsibility of their operations through to regulatory closure. Under the BC LMR Program, the Commission determines the required security deposits for permit holders under the OGAA. The LMR is the ratio of a permit holder's deemed assets to deemed liabilities. Permit holders whose deemed liabilities exceed deemed assets (i.e., an LMR of below a ratio of 1.0) will be considered at-risk and reviewed for a security deposit. Permit holders that fail to comply with security deposit requirements are deemed non-compliant under the OGAAand enter the compliance and enforcement framework. The Commission has announced that it is working to determine how best to manage risks in light of the Redwater decision, so changes may be forthcoming.

Saskatchewan

The Ministry of the Economy administrates the Licensee Liability Rating Program (the "SK LLR Program"). The SK LLR Program is designed to assess and manage the financial risk that a licensee's well and facility abandonment and reclamation liabilities pose to an orphan fund (the "Oil and Gas Orphan Fund") established under the SKOGCA. The Oil and Gas Orphan Fund is responsible for carrying out the abandonment and reclamation of wells and facilities contained within the SK LLR Program when a licensee or WIP is defunct or missing.

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The SK LLR Program requires a licensee whose deemed liabilities exceed its deemed assets (i.e., an LLR of below 1.0) to post a security deposit. The ratio of deemed assets to deemed liabilities is assessed once each month for all licensees of crude oil, natural gas and service wells and upstream crude oil and natural gas facilities. On August 19, 2016, the Ministry of the Economy released a notice to all operators introducing interim measures in response to Redwater. Among other things, the Ministry announced that it considers all licence transfer applications non-routine as the Ministry does not strictly rely on the standard LMR calculation in evaluating deposit requirements, and that further changes may be forthcoming.

Climate Change Regulation

Climate change regulation at both the federal and provincial level has the potential to significantly affect the regulatory environment of the crude oil and natural gas industry in Canada.

In general, there is some uncertainty with regard to the impacts of federal or provincial climate change and environmental laws and regulations, as it is currently not possible to predict the extent of future requirements. Any new laws and regulations, or additional requirements to existing laws and regulations, could have a material impact on the Corporation's operations and cash flow.

Federal

Canada has been a signatory to the United Nations Framework Convention on Climate Change (the "UNFCCC") since 1992. Since its inception, the UNFCCC has instigated numerous policy experiments with respect to climate governance. On April 22, 2016, 197 countries signed the Paris Agreement, committing to prevent global temperatures from rising more than 2° Celsius above pre-industrial levels and to pursue efforts to limit this rise to no more than 1.5° Celsius. As of February 1, 2018, 174 of the 197 parties to the convention have ratified the Paris Agreement.

Following the Paris Agreement and its ratification in Canada, the Government of Canada pledged to cut its emissions by 30 percent from 2005 levels by 2030. Further, on December 9, 2016, the Government of Canada released the Pan-Canadian Framework on Clean Growth and Climate Change (the "Framework"). The Framework provided for a carbon-pricing strategy, with a carbon tax starting at $10/tonne, increasing annually until it reaches $50/tonne in 2022. A draft legislative proposal for the federal carbon pricing system was released on January 15, 2018. This system would apply in provinces and territories that request it and in those that do not have a carbon pricing system in place that meets the federal standards in 2018. Four provinces currently have carbon pricing systems in place that would meet federal requirements (Alberta, British Columbia, Ontario and Quebec). The federal government will accept comments on the draft legislative proposals to implement the federal carbon pricing system until February 12, 2018.

On May 27, 2017, the federal government published draft regulations to reduce emissions of methane from the crude oil and natural gas sector. The proposed regulations aim to reduce unintentional leaks and intentional venting of methane, as well as ensuring that crude oil and natural gas operations use low-emission equipment and processes, by introducing new control measures. Among other things, the proposed regulations limit how much methane upstream oil and gas facilities are permitted to vent. These facilities would need to capture the gas and either re-use it, re-inject it, send it to a sales pipeline, or route it to a flare. In addition, in provinces other than Alberta and British Columbia (which already regulate such activities), well completions by hydraulic fracturing would be required to conserve or destroy gas instead of venting. The federal government anticipates that these actions will reduce GHG emissions by about 20 megatonnes by 2030.

Alberta

On November 22, 2015, the Government of Alberta introduced its Climate Leadership Plan (the "CLP"). The CLP has four areas of focus: implementing a carbon price on GHG emissions, phasing out coal-generated electricity and developing renewable energy, legislating an oil sands emission limit, and introducing a new methane emissions reduction plan. The Government of Alberta has since introduced new legislation to give effect to these initiatives. The Climate Leadership Act came into force on January 1, 2017 and enabled a carbon levy that increased from $20 to $30 per tonne on January 1, 2018. The levy is anticipated to increase again in 2021 in line with the federal legislation. On December 14, 2016, the Oil Sands Emissions Limit Act came into force, establishing a 100 megatonne limit for GHG emissions from all oil sands sites, excluding some attributable to upgraders, the electric energy portion of cogeneration and other prescribed emissions.

The Carbon Competitiveness Incentives Regulation (the "CCIR"), which replaces the Specified Gas Emitters Regulation, came into effect on January 1, 2018. Unlike the previous regulation, which set emission reduction requirements, the CCIR imposes an output-based benchmark on competitors in the same emitting industry. The aim is to reduce annual GHG emissions by 20 megatonnes by 2020 and 50 megatonnes by 2030, and targets facilities that emit more than 100,000 tonnes of GHGs per year and mandates quarterly and final reporting requirements. The CCIR compliance obligations will be reduced by 50 percent and 25 percent for 2018 and 2019, respectively, with no reduction for 2020 onward. In addition to the industry-specific benchmarks, each benchmark will decrease annually at a rate of one percent, beginning in 2020. The Government of Alberta intends for this strategy to align with the federal Framework.

The Government of Alberta also signaled its intention through its CLP to implement regulations that would lower annual methane emissions by 45 percent by 2025. Regulations are planned to take effect in 2020 to ensure the 2025 target is met.

Alberta was also the first jurisdiction in North America to direct dedicated funding to implement carbon capture and storage technology across industrial sectors. Alberta has committed $1.24 billion over 15 years to fund two large-scale carbon capture and storage projects that will begin commercializing the technology on the scale needed to be successful. On December 2, 2010, the Government of Alberta passed the Carbon Capture and Storage Statutes Amendment Act, 2010. It deemed the pore space underlying all land in Alberta to be,

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and to have always been the property of the Crown and provided for the assumption of long-term liability for carbon sequestration projects by the Crown, subject to the satisfaction of certain conditions.

Based on 2016 emissions, we retired Emission Performance Credits from inventory, in the amount of $198,400, to meet compliance for our Quirk Creek Gas Plant. We were not required to purchase Emission Performance Credits for the Olds Gas Plant and Judy Creek Gas Conservation Plant and subsequently received carbon credits for this reduction.

British Columbia

On August 19, 2016, the Government of British Columbia launched its Climate Leadership Plan, which aims to reduce British Columbia's net annual emissions by up to 25 million tonnes below current forecasts by 2050 and recommit the province to achieving its target of reducing emissions by 80 percent below 2007 levels by 2050. Additionally, British Columbia seeks to generate at least 93 percent of its electricity from clean or renewable sources and build the infrastructure necessary to transmit it. The legislation established no date for this target.

British Columbia was also the first Canadian province to implement a revenue-neutral carbon tax. In 2012, the carbon tax was frozen at $30/tonne. However, in its September update to the 2017/2018 Budget, the Government signalled raising the carbon tax to $35/tonne in April 2018.

On January 1, 2016, the Greenhouse Gas Industrial Reporting and Control Act (the "GGIRCA") came into effect, which streamlined the regulatory process for large emitting facilities. The GGIRCA sets out various performance standards for different industrial sectors and provides for emissions offsets through the purchase of credits or through emission offsetting projects.

Saskatchewan

On May 11, 2009, the Government of Saskatchewan announced the Management and Reduction of Greenhouse Gases Act (the "MRGGA")to regulate GHG emissions in the province. The MRGGA, partially proclaimed into force on January 1, 2018, establishes a framework to reduce GHG emissions by 20 percent of 2006 levels by 2020. On October 18, 2016, the Government of Saskatchewan released a White Paper on Climate Change, resisting a carbon tax and committing to an approach that focuses on technological innovation and adaptation.

Nova Scotia

The Province of Nova Scotia has set a goal of lowering greenhouse gas emissions by ten percent below 1990 levels by 2020 and has implemented the Environmental Goals and Sustainable Prosperity Act. The Crown must report annually the amount of reductions achieved in the province but there is no mechanism for measuring compliance nor are there any consequences for failing to meet the goal.

General Discussion

At present, we are not paying any direct costs or penalties as a result of air emission exceedances other than the purchase of credits in relation to our Quirk Creek gas plant. However, the direct and indirect costs of the various GHG regulations, existing and proposed, may at some time and under certain conditions adversely affect our business, operations and financial results. Equipment that meets future emission standards may not be available on an economic basis and other compliance and/or engineering methods to reduce our emissions and associated emissions intensity to future required levels may temporarily increase operating costs. Offset, performance or fund credits may not be available for acquisition or may not be available on an economic basis. Any failure to meet emission reduction compliance obligations requirements may materially adversely affect our business and may result in an increased cost for purchasing offset carbon credits until compliant. There is also a risk that one or more levels of government could impose additional emissions or emissions intensity reduction requirements or taxes on emissions created by us or by consumers of our products. The imposition of such measures might negatively affect our costs and prices for our products and have an adverse effect on earnings and results of operations.

Accountability and Transparency

In 2015, the federal government's Extractive Sector Transparency Measures Act (the "ESTMA") came into effect, which imposed mandatory reporting requirements on certain entities engaged in the "commercial development of oil, gas or minerals", including exploration, extraction and holding permits. All companies subject to ESTMA must report payments over CAD$100,000 made to any level of a Canadian or foreign government (including indigenous groups), including royalty payments, taxes (other than consumption taxes and personal income taxes), fees, production entitlements, bonuses, dividends (other than ordinary dividends paid to shareholders), infrastructure improvement payments and other prescribed categories of payments.

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RISK FACTORS

If any of the following risks occur, our production, revenues and financial condition could be materially impaired, with a resulting decrease in the market price of, our Common Shares. As a result, the trading price of our Common Shares could decline, and you could lose all or part of your investment. Additional risks are described under the heading "Business Risks" in our Management's Discussion and Analysis for the year ended December 31, 2017.

The trading price of our Common Shares is subject to substantial volatility often based on factors related and unrelated to our financial performance or prospects.

Factors unrelated to our performance could include macroeconomic developments nationally, within North America or globally, domestic and global commodity prices or current perceptions of the oil and gas market. In certain jurisdictions institutions, including government sponsored entities, have determined to decrease their ownership in oil and gas entities which may impact the liquidity of certain securities and may put downward pressure on the trading price of those securities. Similarly, the market price of our Common Shares could be subject to significant fluctuations in response to variations in our operating results, financial condition, liquidity and other internal factors. Factors that could affect the market price of our Common Shares that are unrelated to our performance include domestic and global commodity prices and market perceptions of the attractiveness of particular industries. The price at which our Common Shares will trade cannot be accurately predicted.

Low oil and natural gas prices could have a material adverse effect on our results of operations and financial condition, which, in turn, could negatively affect the market price of the Common Shares.

The market price of the Common Shares depends, in part, on the prices we receive for our oil and natural gas production. Oil and natural gas prices can fluctuate widely on a month-to-month, or even a day-to-day, basis in response to a variety of factors that are beyond our control. While oil prices are set in a much broader global market, natural gas prices are largely dependent on North American economies. Additional factors include:

• global energy policy, including the ability of OPEC to set and maintain production levels for oil and non-OPEC member countries' decisions on production levels;

• geo-political conditions;

• worldwide economic conditions including ongoing credit and liquidity concerns;

• weather conditions including weather-related disruptions to the North American natural gas supply;

• the supply and price of foreign and North American produced oil and natural gas;

• the level of consumer demand;

• the price and availability of alternative fuels;

• the proximity to, and capacity of, transportation facilities;

• the effect of worldwide energy conservation measures; and

• government regulation.

Recent market events and conditions, including global excess oil and natural gas supply, recent actions taken by OPEC and non-OPEC member countries' decisions on production levels, slowing growth in emerging economies, market volatility and disruptions in Asia, sovereign debt levels in various countries and political upheavals, have caused significant weakness and volatility in commodity prices. North American crude oil price differentials are also expected to continue to be volatile throughout 2018 which will have an impact on crude oil prices for Canadian producers.

These events and conditions have caused a significant decrease in the valuation of oil and gas companies and a decrease in confidence in the oil and gas industry. These difficulties have been exacerbated in Canada by political and other actions resulting in uncertainty surrounding regulatory, tax, royalty changes and environmental regulation.

In addition, the inability to get the necessary approvals to build pipelines, liquefied natural gas plants and other facilities to provide better access to markets for the oil and gas industry in Western Canada has led to downward price pressure on oil and gas produced in Western Canada and additional uncertainty and reduced confidence in the oil and gas industry in Western Canada.

Failure to comply with the covenants in the agreements governing our debt could adversely affect our financial condition.

We are required to comply with the covenants in our Credit Facility and the Term Notes. We have negotiated a period of covenant relaxation with the holders of our Term Notes and lenders under our Credit Facility which relaxation period applies, in the case of our Credit Facility, until expiry on March 31, 2019 and, in the case of our Term Notes, through to and including the quarter ended September 30, 2019.

Furthermore, if we are unable to pay the debt service charges or otherwise commit an event of default, such as bankruptcy, our lenders may receive judgment and have an unsecured claim on our properties. The proceeds of any sale would be applied to satisfy amounts owed to the creditors. Only after the proceeds of that sale were applied towards the debt would the remainder, if any, be available for the benefit

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of our Shareholders. If we grant our creditors security over our assets, non-payment of debt service charges or other default could result in the seizure of our assets by the secured creditors.

Our Credit Facility may not provide sufficient liquidity and a failure to renew our Credit Facility could adversely affect our financial condition.

Our existing Credit Facility and any replacement credit facility may not provide sufficient liquidity. The amounts available under our existing Credit Facility may not be sufficient for future operations, or we may not be able to obtain additional financing on economic terms attractive to us, if at all. There can be no assurance that the amount of our Credit Facility will be adequate for our future financial obligations, including our future capital expenditure program, or that we will be able to obtain additional funds. In the event we are unable to refinance our debt obligations, it may impact our ability to fund our ongoing operations. In the event that the Credit Facility is not extended before March 31, 2019, indebtedness under the Credit Facility will be repayable at that time. In addition, we are required to repay the Term Notes on maturity. There is also a risk that the Credit Facility will not be renewed for the same amount or on the same terms. See "Dividends - Revolving Credit Facility”.

Uncertainty in the capital markets may restrict the availability or increase the cost of capital or borrowing required for future development and acquisitions.

The future development of our business may be dependent on our ability to obtain additional capital including, but not limited to, debt and equity financing. Unpredictable financial markets and the associated credit impacts may impede our ability to secure and maintain cost effective financing and limit our ability to achieve timely access to capital markets on acceptable terms and conditions. If external sources of capital become limited or unavailable, our ability to make capital investments, continue our business plan, meet all of our financial obligations as they come due and maintain existing properties may be impaired. Should a lack of financing and uncertainty in the capital markets adversely impact our ability to refinance debt, additional equity may be issued which could have a dilutive effect on Shareholders.

Our ability to obtain additional capital is dependent on, among other things, a general interest in energy industry investments and, in particular, interest in our securities along with our ability to maintain our credit ratings. If we are unable to maintain our indebtedness and financial ratios at levels acceptable to our credit rating agencies, or should our business prospects deteriorate, our credit ratings could be downgraded, which would adversely affect the value of our outstanding securities and existing debt and our ability to obtain new financing and may increase our borrowing costs.

From time to time we may enter into transactions which may be financed in whole or in part with debt. The level of our indebtedness from time to time could impair our ability to obtain additional financing on a timely basis to take advantage of business opportunities that may arise.

Political uncertainty has impacted financial and economic markets.

In the last several years, the United States and certain European countries have experienced significant political events that have cast uncertainty on global financial and economic markets. During the 2016 presidential campaign a number of election promises were made and the new American administration has begun taking steps to implement certain of these promises. The administration has announced withdrawal of the United States from the Trans-Pacific Partnership and Congress has passed sweeping tax reform, which, among other things, significantly reduces U.S. corporate tax rates. This may affect competitiveness of other jurisdictions, including Canada. The North American Free Trade Agreement is currently under renegotiation and the result is uncertain at this time. The administration has also taken action with respect to reduction of regulation which may also affect relative competitiveness of other jurisdictions. It is unclear exactly what other actions the administration in the United States will implement, and if implemented, how these actions may impact Canada and in particular the oil and gas industry. Any actions taken by the new United States administration may have a negative impact on the Canadian economy and on the businesses, financial conditions, results of operations and the valuation of Canadian oil and gas companies, including Pengrowth.

In addition to the political disruption in the United States, the citizens of the United Kingdom recently voted to withdraw from the European Union and the Government of the United Kingdom has begun taken steps to implement such withdrawal.

A change in federal, provincial or municipal governments in Canada may have an impact on the directions taken by such governments on matters that may impact the oil and gas industry including the balance between economic development and environmental policy such as the potential impact of the recent change of government in British Columbia and announcements and actions by the government of British Columbia that may impact the completion of the Trans-Mountain Pipeline project and other infrastructure projects.

The amount of future dividends, if any, may vary.

On January 20, 2016, as a result of volatile, uncertain and exceptionally low oil prices, we suspended our monthly dividend until further notice. The amount of future dividends paid by us, if any, will be subject to the discretion of our Board of Directors and may vary depending on a variety of factors, forecasts and conditions existing from time to time, including fluctuations in commodity prices, production levels, capital expenditure requirements, debt service requirements, operating costs, royalty burdens, foreign exchange rates and the satisfaction of the liquidity and solvency tests imposed by the ABCA for the declaration and payment of dividends. Depending on these and various

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other factors, many of which will be beyond our control, we may change our dividend policy from time to time and, as a result, any future dividends could be reduced or suspended entirely.

The future treatment of dividends for tax purposes will be subject to the nature and composition of dividends paid by us and potential legislative and regulatory changes. Dividends may be reduced during periods of lower funds from operations, which result from lower commodity prices and any decision by us to finance capital expenditures using funds from operations.

Our success depends in large measure on certain key and qualified personnel.

The loss of the services of key personnel may have a material adverse effect on our business, financial condition, results of operations and prospects. The contributions of the existing management team to our immediate and near term operations are likely to be of central importance. In addition, the competition for qualified personnel in the oil and natural gas industry is intense and there can be no assurance that we will be able to continue to attract and retain all personnel necessary for the development and operation of our business. Investors must rely upon the ability, expertise, judgment, discretion, integrity and good faith of our management.

Actual production, reserves and resources will vary from estimates, and those variations could be material and may negatively affect the market price of the Common Shares.

The value of the Common Shares will depend upon, among other things, our reserves and resources. In making strategic decisions, we rely upon reports prepared by our independent reserve engineers and our own internal estimates. Estimating future production, reserves and resources is inherently uncertain. Ultimately, actual production, revenues and expenditures for the underlying properties will vary from estimates and those variations could be material. Changes in the prices of, and markets for, oil and natural gas from those anticipated at the time of making such assessments will affect the return on, and value of, our Common Shares. The reserves, resources and cash flow information contained in the reserve information herein represent estimates only. Petroleum engineers consider many factors and make assumptions in estimating reserves and resources.

Those factors and assumptions include:

• historical production from the area compared with production rates from similar producing areas;

• the assumed effect of government regulation;

• assumptions about future commodity prices, exchange rates, production and development costs, capital expenditures,    abandonment costs, environmental liabilities, and applicable royalty regimes;

• initial production rates;

• production decline rates;

• ultimate recovery of reserves and resources;

• marketability of production; and

• other government levies that may be imposed over the producing life of reserves.

If any of these factors and assumptions prove to be inaccurate, our actual results may vary materially from our reserve and resource estimates. Many of these factors are subject to change and are beyond our control. In particular, changes in the prices of, and markets for, oil and natural gas from those anticipated at the time of making such assessments will affect the return on, and value of, our Common Shares. In addition, all such assessments involve a measure of geological and engineering uncertainty that could result in lower production and reserves and resources than anticipated. A portion of our reserves are classified as "undeveloped" and are subject to greater uncertainty than reserves classified as "developed".

In accordance with normal industry practices, we engage independent petroleum engineers to conduct a detailed engineering evaluation of our oil and gas properties for the purpose of estimating our reserves as part of our year end reporting process. As a result of that evaluation, we may increase or decrease the estimates of our reserves. We do not consider an increase or decrease in the estimates of our reserves in the range of up to five percent to be material or inconsistent with normal industry practice. Any significant reduction to the estimates of our reserves resulting from any such evaluation could have a material adverse effect on the value of our Common Shares.

If we are unable to acquire or develop additional reserves, the value of the Common Shares may decline.

Oil and natural gas operations involve many risks that even a combination of experience, knowledge and careful evaluation may not be able to overcome. Our long-term commercial success depends on our ability to find, acquire, develop and commercially produce oil and natural gas reserves. Without the continual addition of new reserves, our existing reserves, and the production from them, will decline over time as we produce from such reserves. A future increase in our reserves will depend on both our ability to explore and develop our existing properties and on our ability to select and acquire suitable producing properties or prospects. There is no assurance that we will be able to continue to find satisfactory properties to acquire or participate in. Moreover, our management may determine that current markets, terms of acquisition and, participation or pricing conditions make potential acquisitions or participation uneconomic. There is also no assurance that we will discover or acquire further commercial quantities of oil and natural gas.

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Future oil and natural gas exploration may involve unprofitable efforts from dry wells as well as from wells that are productive but do not produce sufficient petroleum substances to return a profit after drilling, completing (including hydraulic fracturing), operating and other costs. Completion of a well does not ensure a profit on the investment or recovery of drilling, completion and operating costs.

Drilling hazards, environmental damage and various field operating conditions could greatly increase the cost of operations and adversely affect the production from successful wells. Field operating conditions include, but are not limited to, delays in obtaining governmental approvals or consents, and shut-in wells resulting from extreme weather conditions, insufficient storage or transportation capacity or geological and mechanical conditions. While diligent well supervision and effective maintenance operations can contribute to maximizing production rates over time, it is not possible to eliminate production delays and declines from normal field operating conditions, which can negatively affect revenue and cash flow levels to varying degrees.

The amount of oil and natural gas that we can produce and sell is subject to the accessibility, availability, proximity and capacity of gathering, processing and pipeline systems

We deliver our products through gathering, processing and pipeline systems some of which we do not own. Access to the pipeline capacity for the transport of crude oil into the United States has become inadequate for the amount of Canadian production being exported to the United States and has recently resulted in significantly lower amounts being realized by Canadian producers compared with the WTI price for crude oil. Although opportunities to move oil by rail continue to grow and will provide new outlets for access to North American refineries otherwise not reachable via existing pipeline infrastructure, supply in excess of current pipeline and refining capacity is expected to continue to exist. Although we currently do not directly transport oil by rail, we could be affected by both positive and negative impacts (i.e. pricing of our oil sales from supply/demand issues) that could result from significant fluctuations to this transport method. Material structural changes are required to reduce these bottlenecks and the resulting steep price discounts. A variety of new pipeline expansion projects to provide increased access to eastern Canadian and Gulf Coast refineries, as well as new off-shore markets, have been announced and are in various stages of review and approval. There can be no assurance that such regulatory approvals will be secured on a timely basis or at all. The lack of firm pipeline capacity continues to affect the oil and natural gas industry and limit the ability to produce and to market oil and natural gas production. In addition, the pro-rationing of capacity on inter-provincial pipeline systems also continues to affect the ability to export oil and natural gas.

The lack of access to capacity in any of the gathering, processing and pipeline systems, and in particular the processing facilities, could result in our inability to realize the full economic potential of our production or in a reduction of the price offered for our production. Any significant change in market factors or other conditions affecting these infrastructure systems and facilities, as well as any delays or uncertainty in constructing new infrastructure systems and facilities could harm our business and, in turn, our financial condition.

A portion of our production may, from time to time, be processed through facilities owned by third parties and which we do not have control of. From time to time, these facilities may discontinue or decrease operations either as a result of normal servicing requirements or as a result of unexpected events. A discontinuance or decrease of operations could materially adversely affect our ability to process our production and to deliver the same for sale. Certain pipeline leaks have gained media and other stakeholder attention and may result in additional regulation or changes in law which could impede the conduct of our business or make our operations more expensive.

Following major accidents in Lac-Megantic, Quebec and North Dakota, the Transportation Safety Board of Canada and the U.S. National Transportation Board have recommended additional regulations for railway tank cars carrying crude oil. These recommendations include, among others, the imposition of higher standards for all DOT-111 tank cars carrying crude oil and the increased auditing of shippers to ensure they properly classify hazardous materials and have adequate safety plans in place. The increased regulation of rail transportation may reduce the ability of railway lines to alleviate pipeline capacity issues and add additional costs to the transportation of crude oil by rail.

If oil and natural gas prices remain at their current levels or decrease further, our estimates of total reserves and the values thereof may be reduced.

Our reserves as at December 31, 2017 are estimated using forecast pricing escalating prices. These prices are substantially above current oil and natural gas prices. If oil and gas prices stay at current levels or drop further our reserves may be substantially reduced as economic limits of developed reserves are reached earlier and undeveloped reserves become uneconomic at such prices. Even if some reserves remain economic at lower price levels, sustained low prices may compel us to re-evaluate our development plans and reduce or eliminate various projects with marginal economics.

In addition to possibly resulting in a decrease in the value of our economically recoverable reserves, lower commodity prices may also result in a decrease in the value of our infrastructure and facilities, all of which could also have the effect of requiring a write down of the carrying value of our oil and gas assets on our balance sheet and the recognition of an impairment charge in our income statement.

In addition, lower commodity prices have restricted, and are anticipated to continue to restrict, our cash flow resulting in a reduced capital expenditure budget. As a result, we may not be able to replace our production with additional reserves and both our production and reserves could be reduced on a year over year basis.

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Uncertainty in the industry may restrict the availability or increase the cost of borrowing required for future development and acquisitions.

Due to the conditions in the oil and gas industry and/or global economic and political volatility, we may from time to time have restricted access to capital and increased borrowing costs. The current conditions in the oil and gas industry have negatively impacted the ability of oil and gas companies to access additional financing. Commodity prices continue to be depressed and have fallen dramatically since 2014 and while prices have recently increased they remain volatile as a result of various factors including actions taken to limit OPEC and non-OPEC production and increasing production by US shale producers. There remains a substantial amount of uncertainty as to when and if commodity prices will recover. Continued depressed oil and natural gas prices have caused decreases, and may cause further decreases, in our cash flow. To the extent that external sources of capital become limited, unavailable or available on onerous terms, our ability to access sufficient capital for our capital expenditures and acquisitions could be impaired and, as a result, may have a material adverse effect on our ability to execute our business strategy and on our financial condition. There can be no assurance that financing will be available or sufficient to meet these requirements or for other corporate purposes or, if financing is available, that it will be on terms appropriate and acceptable to us. Should the lack of financing and uncertainty in the capital markets adversely impact our ability to refinance debt, additional equity may be issued resulting in a dilutive effect on current and future Shareholders.

In the normal course of our business, we have entered into contractual arrangements with third parties that subject us to the risk that such parties may default on their obligations.

We are exposed to third party credit risk through our contractual arrangements with current or future joint venture partners, marketers of our petroleum and natural gas production and other parties. In the event such entities fail to meet their contractual obligations to us, such failures could have a material adverse effect on our business, financial condition, results of operations and prospects. In addition, poor credit conditions in the industry and of joint venture partners may impact a joint venture partner’s willingness to participate in our ongoing capital program, potentially delaying the program and the results of such program until we find a suitable alternative partner.

We engage in hedging activities which could limit the full benefit of commodity price increases.

From time to time we enter into agreements to receive fixed prices for our oil and natural gas production to offset the risk of revenue losses if commodity prices decline. However, to the extent that we engage in price risk management activities to protect ourselves from commodity price declines, we may also be prevented from realizing the full benefits of price increases above the levels of the derivative instruments used to manage price risk. In addition, our hedging arrangements may expose us to the risk of financial loss in certain circumstances, including instances in which:

• production falls short of the hedged volumes;

• there is a widening of price-basis differentials between delivery points for production and the delivery point assumed in the hedge arrangement;

• the counterparties to the hedging arrangements or other price risk management contracts fail to perform under those arrangements; or

• a sudden unexpected event materially impacts oil and natural gas prices.

From time to time we may also enter into agreements to fix the exchange rate of Canadian to United States dollars in order to offset the risk of revenue losses if the Canadian dollar increases in value compared to the United States dollar. However, if the Canadian dollar declines in value compared to the United States dollar, we will not benefit from the fluctuating exchange rate. In addition, although a low value of the Canadian dollar relative to the United States dollar may positively affect the price we receive for our oil and natural gas production, it could also result in an increase in the price for certain goods used for our operations, which may have a negative impact on our financial results.

Our operation of oil and natural gas wells could subject us to potential environmental claims and liabilities, which will be funded out of our cash flow and will reduce cash flow otherwise available for dividend to Shareholders.

All phases of the oil and natural gas business present environmental risks and hazards and are subject to environmental regulation pursuant to a variety of federal, provincial and local laws and regulations. Environmental legislation provides for, among other things, restrictions and prohibitions on the spill, release or emission of various substances produced in association with oil and gas industry operations. In addition, such legislation sets out the requirements with respect to oilfield waste handling and storage, habitat protection and the satisfactory operation, maintenance, abandonment and reclamation of well and facility sites.

Alberta, Saskatchewan and British Columbia have developed liability management programs designed to prevent taxpayers from incurring costs associated with suspension, abandonment, remediation and reclamation of wells, facilities and pipelines in the event that a licensee or permit holder is unable to satisfy its regulatory obligations. These programs involve an assessment of the ratio of a licensee's deemed assets to deemed liabilities. If a licensee's deemed liabilities exceed its deemed assets, a security deposit is generally required. Changes to the required ratio of our deemed assets to deemed liabilities or other changes to the requirements of liability management programs may result in significant increases to our compliance obligations. In addition, the liability management regime may prevent or interfere with our ability to acquire or dispose of assets as both the vendor and the purchaser of oil and gas assets must be in compliance with the liability management programs (both before and after the transfer of the assets) for the applicable regulatory agency to allow for the

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transfer of such assets. The recent Alberta Court of Queen's Bench decision, Redwater Energy Corporation (Re) 2016 ABQB 278, found an operational conflict between the Bankruptcy and Insolvency Act and the AER's abandonment and reclamation powers when the licensee is insolvent which was affirmed by a majority of the Alberta Court of Appeal, and has been appealed by the AER to the Supreme Court of Canada for final determination. In response to the decision, the AER issued interim rules to administer the liability management program until the Government of Alberta can develop new regulatory measures to adequately address environmental liabilities. There remains a great deal of uncertainty as to what new regulatory measures will be developed by the provinces or in concert with the federal government, as the final ruling will become binding in all Canadian jurisdictions. See "Industry Conditions - Regulatory Authorities and Environmental Regulation - Liability Management Rating Programs".

Compliance with environmental legislation can require significant expenditures and a breach of applicable environmental legislation may result in the imposition of fines and penalties, some of which may be material. Environmental legislation is evolving in a manner expected to result in stricter standards and enforcement, larger fines and liability and potentially increased capital expenditures and operating costs. The discharge of oil, natural gas or other pollutants into the air, soil or water may give rise to liabilities to governments and third parties and may require us to incur costs to remedy such discharge. Although we believe that we will be in material compliance with current applicable environmental compliance requirements, no assurance can be given that environmental laws will not result in a curtailment of production or a material increase in the costs of production, development or exploration activities or otherwise have a material adverse effect on our business, financial condition, results of operations and prospects.

Compliance with greenhouse gas emissions regulations may result in increased operational costs.

Our exploration and production facilities and other operations and activities emit greenhouse gases which may require us to comply with greenhouse gas emissions legislation at the provincial or federal level. Climate change policy is evolving at regional, national and international levels, and political and economic events may significantly affect the scope and timing of climate change measures that are ultimately put in place. As a signatory to the UNFCCC and a signatory to the Paris Agreement, which was ratified in Canada on October 3, 2016, the Government of Canada pledged to cut its GHG emissions by 30 per cent from 2005 levels by 2030. One of the pertinent policies announced to date by the Government of Canada to reduce GHG emission is the planned implementation of a nation-wide price on carbon emissions. Provincially, the Government of Alberta has already implemented a carbon levy on almost all sources of GHG emissions, now at a rate of $30 per tonne. The direct or indirect costs of compliance with GHG-related regulations may have a material adverse effect on our business, financial condition, results of operations and prospects. Some of our significant facilities may ultimately be subject to future regional, provincial and/or federal climate change regulations to manage GHG emissions. In addition, concerns about climate change have resulted in a number of environmental activists and members of the public opposing the continued exploitation and development of fossil fuels. Given the evolving nature of the debate related to climate change and the control of GHG and resulting requirements, it is expected that current and future climate change regulations will have the effect of increasing our operating expenses and in the long-term reducing the demand for oil and gas production resulting in a decrease in our profitability and a reduction in the value of our assets or asset write-offs. See "Industry Conditions - Regulatory Authorities and Environmental Regulation - Climate Change Regulation".

Taxes on carbon emissions affect the demand for oil and natural gas, our operating expenses and may impair our ability to compete.

The majority of countries across the globe have agreed to reduce their carbon emissions in accordance with the Paris Agreement. See "Industry Conditions - Regulatory Authorities and Environmental Regulation - Climate Change Regulation". In Canada, the federal and certain provincial governments have implemented legislation aimed at incentivizing the use of alternatives fuels and in turn reducing carbon emissions. The taxes placed on carbon emissions may have the effect of decreasing the demand for oil and natural gas products and at the same time, increasing our operating expenses, each of which may have a material adverse effect on our profitability and financial condition. Further, the imposition of carbon taxes puts us at a disadvantage with our counterparts who operate in jurisdictions where there are less costly carbon regulations.

We may be unable to successfully compete with other industry participants, which could negatively affect the market price of the Common Shares.

The petroleum industry is competitive in all its phases. We compete with numerous other entities in the search for, and the acquisition of, oil and natural gas properties and in the marketing of oil and natural gas. Our competitors include oil and natural gas companies that have substantially greater financial resources, staff and facilities than us. Our ability to increase our reserves in the future will depend not only on our ability to explore and develop our present properties, but also on our ability to select and acquire other suitable producing properties or prospects for exploratory drilling. Competitive factors in the distribution and marketing of oil and natural gas include price, methods, and reliability of delivery and storage.

The oil industry is characterized by rapid and significant technological advancements and introductions of new products and services utilizing new technologies.

Other oil companies may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we can. There can be no assurance that we will be able to respond to such competitive pressures and implement such technologies on a timely basis or at an acceptable cost. One or more of the technologies currently utilized by us or implemented in the future may become obsolete. In such case, our business, financial condition and results of

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operations could be materially adversely affected. If we are unable to utilize the most advanced commercially available technology, our business, financial condition and results of operations could be materially adversely affected.

Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, and technological advances in fuel economy and renewable energy generation devices could reduce the demand for oil and liquid hydrocarbons.

Recently, certain jurisdictions have implemented policies or incentives to decrease the use of fossil fuels and encourage the use of renewable fuel alternatives, which may lessen the demand for petroleum products and put downward pressure on commodity prices. In addition, advancements in energy efficient products have a similar effect on the demand for oil and gas products. We cannot predict the impact of changing demand for oil and natural gas products, and any major changes may have a material adverse effect on our business, financial condition, results of operations and cash flows.

Incorrect assessments of value at the time of acquisitions could adversely affect the value of our Common Shares.

Acquisitions of oil and gas properties or companies are based in large part on engineering and economic assessments made by independent engineers. These assessments include a series of assumptions regarding such factors as recoverability and marketability of oil and gas, future prices of oil and gas and operating costs, future capital expenditures and royalties and other government levies which will be imposed over the producing life of the reserves. Many of these factors are subject to change and are beyond our control. All such assessments involve a measure of geologic and engineering uncertainty which could result in lower than anticipated production and reserves.

If we default on our debts, the net proceeds of any foreclosure sale would be allocated to the repayment of our lenders, note holders and other creditors and only the remainder, if any, would be available for distribution to our Shareholders.

Variations in interest rates, exchange rates and scheduled principal repayments could result in significant changes in the amount we are required to apply to the service of our outstanding indebtedness. If we become unable to pay our debt service charges or otherwise cause an event of default to occur, access to our Credit Facility can become restricted and our lenders may foreclose on, or sell, our properties. The net proceeds of any such sale will be allocated firstly to the repayment of our lenders and other creditors and only the remainder, if any, would be payable to Shareholders. In addition, we may not be able to refinance some or all of these debt obligations through the issuance of new debt obligations on the same terms, and we may be required to refinance through the issuance of new debt obligations on less favourable terms or through the issuance of additional securities or through other means.

We are required to comply with covenants under our Credit Facility and Term Notes. Events beyond our control may contribute to our failure to comply with such covenants. Failing a financial covenant may result in access to our Credit Facility becoming restricted and/or one or more of our 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, we would have to repay, refinance or re-negotiate the terms and conditions of the debt.

If any of our lenders require repayment of all or portion of the amounts outstanding under our loans for any reason, including for a default of a covenant, there is no certainty that we would be in a position to make such repayment. Given the current market conditions and the lack of confidence in the Canadian oil and gas industry, we may have difficulty raising additional funds or if it we are able to do so, it may be on unfavourable and highly dilutive terms.

A decline in our ability to market our oil and natural gas production could have a material adverse effect on production levels or on the price received for production, which, in turn, could affect the market price of the Common Shares.

The marketability of our production depends in part upon the availability, proximity and capacity of gas gathering systems, pipelines, railway lines and processing and storage facilities. United States federal and state and Canadian federal and provincial regulation of oil and gas production and transportation, general economic and political conditions, changes in supply and demand, market conditions and other conditions affecting infrastructure systems and facilities could adversely affect our ability to produce and market oil and natural gas. If market factors dramatically change, the financial impact on us could be substantial. The availability of markets is beyond our control.

The lack of firm pipeline capacity continues to affect the oil industry and limit the ability to transport produced oil and gas to market. In addition, the pro-rationing of capacity on inter-provincial pipeline systems continues to affect the ability to export oil. Unexpected shut downs or curtailment of capacity of pipelines for maintenance or integrity work or because of actions taken by regulators could also affect our production, operations and financial results. Furthermore, producers are increasingly turning to rail as an alternative means of transportation. In recent years, the volume of crude oil shipped by rail in North America has increased dramatically. Any significant change in market factors or other conditions affecting these infrastructure systems and facilities, as well as any delays or uncertainty in constructing new infrastructure systems and facilities could harm our business and, in turn, our financial condition, results of operations and cash flows.

Announcements and actions taken by the governments of British Columbia and Alberta relating to approval of infrastructure projects may continue to intensify, leading to increased challenges to interprovincial and international infrastructure projects moving forward. In addition, while the federal government has recently introduced draft legislation to overhaul the existing environmental assessment process and replace the NEB with a new regulatory agency, the impact of the new proposed regulatory scheme on proponents and the timing of receipt of approvals of major projects remains unclear.

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Following major accidents in Lac-Megantic, Quebec and North Dakota, the Transportation Safety Board of Canada and the U.S. National Transportation Board have recommended additional regulations for railway tank cars carrying crude oil. In June 2015, as a result of these recommendations, the Government of Canada passed the Safe and Accountable Rail Act which increased insurance obligations on the shipment of crude oil by rail, imposed a per tonne levy of $1.65 on crude oil shipped by rail to compensate victims and for environmental cleanup in the event of a railway accident. In addition to this legislation, new regulations have implemented the TC-117 standard for all rail tank cars carrying flammable liquids which formalized the commitment to retrofit, and eventually phase out DOT-111 tank cars carrying crude oil. The increased regulation of rail transportation may reduce the ability of railway lines to alleviate pipeline capacity issues and adds additional costs to the transportation of crude oil by rail. On July 13, 2016, the Minister of Transport (Canada) issued Protective Direction No. 38, which directed that the shipping of crude oil on DOT-111 tank cars end by November 1, 2016. Tank cars entering Canada from the United States will be monitored to ensure they are compliant with Protective Direction No. 38.

Our financial performance also depends on revenues from the sale of commodities which differ in quality and location from underlying commodity prices quoted on financial exchanges. Of particular importance are the price differentials between our light/medium crude oil, heavy crude oil (in particular the light/heavy differential) and bitumen and quoted market prices. Not only are these discounts influenced by regional supply and demand factors, they are also influenced by other factors such as transportation costs, capacity and interruptions; refining demand; the availability and cost of diluent used to blend and transport product; and the quality of the oil produced, all of which are beyond our control.

Midstream and pipeline companies may take actions to maximize their return on investment which may in turn adversely affect producers and shippers, especially when combined with a regulatory framework that may not always align with the interests of particular shippers.

The operation of a portion of our properties is largely dependent on the ability of third party operators, and harm to their business could cause delays and additional expenses in our receiving revenues, which could negatively affect the market price of the Common Shares.

The continuing production from a property, and to some extent the marketing of production, is dependent upon the ability of the operators of our properties. Approximately eight percent of our properties are operated by third parties, based on daily production. If, in situations where we are not the operator, the operator fails to perform these functions properly or becomes insolvent, revenues may be reduced. Revenues from production generally flow through the operator and, where we are not the operator; there is a risk of delay and additional expense in receiving such revenues.

The operation of the wells located on properties not operated by us are generally governed by operating agreements which typically require the operator to conduct operations in a good and workman-like manner. Operating agreements generally provide, however, that the operator will have no liability to the other non-operating working interest owners for losses sustained or liabilities incurred, except such as may result from gross negligence or wilful misconduct. In addition, third-party operators are generally not fiduciaries with respect to us or our Shareholders. As owner of working interests in properties not operated by us, we will generally have a cause of action for damages arising from a breach of the operator’s duty. Although not established by definitive legal precedent, it is unlikely that we or our Shareholders would be entitled to bring suit against third party operators to enforce the terms of the operating agreements. Therefore, our Shareholders will be dependent upon us, as owner of the working interest, to enforce such rights.

In addition, due to the current low and volatile commodity prices, many companies, including companies that may operate some of the assets in which we have an interest, may be in financial difficulty, which could impact their ability to fund and pursue capital expenditures, carry out their operations in a safe and effective manner and satisfy regulatory requirements with respect to abandonment and reclamation obligations. If companies that operate some of the assets in which we have an interest fail to satisfy regulatory requirements with respect to abandonment and reclamation obligations we may be required to satisfy such obligations and to seek reimbursement from such companies. To the extent that any of such companies go bankrupt, become insolvent or make a proposal or institute any proceedings relating to bankruptcy or insolvency, it could result in such assets being shut-in, us potentially becoming subject to additional liabilities relating to such assets and us having difficulty collecting revenue due from such operators or recovering amounts owing to us from such operators for their share of abandonment and reclamation obligations. Any of these factors could materially adversely affect our financial and operational results.

The market price of the Common Shares could be adversely affected by unforeseen title defects.

Although title reviews may be conducted prior to the purchase of oil and natural gas producing properties or the commencement of drilling wells, such reviews do not guarantee or certify that an unforeseen defect in the chain of title will not arise. Our actual interest in properties may, accordingly, vary from our records. If a title defect does exist, it is possible that we may lose all or a portion of the properties to which the title defect relates, which may have a material adverse effect on our business, financial condition, results of operations and prospects. There may be valid challenges to title, or legislative changes which affect title, to the oil and natural gas properties we control that could impair our activities on them and result in a reduction of the revenue received by us.

We could be negatively impacted by changes in asset retirement obligations.

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

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Fluctuations in foreign currency exchange rates and interest rates could adversely affect our business and the market price of the Common Shares.

World oil and natural gas prices are quoted in United States dollars. The Canadian/United States dollar exchange rate fluctuates over time and as a consequence affects the price received by Canadian producers of oil and natural gas. Material increases in the value of the Canadian dollar relative to the United States dollar will negatively affect our production revenues. Future Canadian/United States exchange rates could, accordingly, affect the future value of our reserves as determined by independent evaluators.

Pengrowth has substantial exposure to the U.S. dollar. Any decrease in the value of the Canadian dollar relative to the U.S. dollar results in an increase in the Canadian dollar equivalent of Pengrowth's U.S. dollar denominated term debt as Pengrowth reports and prepares its covenant calculations in Canadian dollars. A significant decrease in the value of the Canadian dollar relative to the U.S. dollar could cause Pengrowth to be in violation of its debt covenants resulting in Pengrowth being in default of its debt covenants.

To the extent that we engage in risk management activities related to foreign exchange rates, there is a credit risk associated with counterparties with which we may contract.

An increase in interest rates could result in a significant increase in the amount we pay to service debt, resulting in a reduced amount available to fund our exploration and development activities and could negatively impact the market price of our Common Shares.

We may incur material costs as a result of compliance with health, safety and environmental laws and regulations which could negatively affect our financial condition and, therefore decrease the market price of the Common Shares.

Compliance with environmental laws and regulations could materially increase our costs. We may incur substantial capital and operating costs to comply with increasingly complex laws and regulations covering the protection of the environment and human health and safety. In particular, we may be required to incur significant costs to comply with legislation and regulations to reduce emissions of greenhouse gases into the air. See “Industry Conditions”.

Lower oil and gas prices increase the risk of write-downs of our oil and gas property investments which could be viewed unfavourably in the market or could limit our ability to borrow funds or comply with covenants contained in our current or future credit agreements or other debt instruments.

Under Canadian accounting rules, the net capitalized cost of oil and gas properties may not exceed a "ceiling limit" which is based, in part, upon estimated future net cash flows from reserves. If the net capitalized costs exceed this limit, we must charge the amount of the excess against earnings. As oil and gas prices and engineering price decks decline, our net capitalized cost may approach and, in certain circumstances, exceed this cost ceiling, resulting in a charge against earnings. Under United States accounting rules, the cost ceiling is generally lower than under Canadian rules because the future net cash flows used in the United States ceiling test are based on proved reserves only. Accordingly, we would have more risk of a ceiling test write-down in a declining price environment if we reported under United States generally accepted accounting principles. While these write-downs would not affect cash flow, the charge to earnings could be viewed unfavourably in the market or could limit our ability to borrow funds or comply with covenants contained in our current or future credit agreements or other debt instruments.

The ability of investors resident in the United States to enforce civil remedies may be negatively affected for a number of reasons.

We are an Alberta corporation. We have our principal places of business in Canada. All of our directors and officers are residents of Canada and all or a substantial portion of our assets and the assets of such persons are located outside of the United States. Consequently, it may be difficult for United States investors to affect service of process within the United States upon us or such persons or to realize in the United States upon judgments of courts of the United States predicated upon civil remedies under the United States federal securities laws, as amended. Investors should not assume that Canadian courts:

• will enforce judgments of United States courts obtained in actions against us or such persons predicated upon the civil liability provisions of the United States federal securities laws or the securities or "blue sky" laws of any state within the United States; or

• will enforce, in original actions, liabilities against us or such persons predicated upon the United States federal securities laws or any such state securities or blue sky laws.

Future acquisitions may result in substantial future dilution of your Common Shares.

One of our objectives is to continually add to our reserves through acquisitions and through development. Our success is, in part, dependent on our ability to raise capital from time to time. Shareholders may also suffer dilution in connection with future issuances of Common Shares.

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Canadian and United States practices differ in reporting reserves and production and our estimates may not be comparable to those of companies in the United States.

We report our production and reserve quantities in accordance with Canadian practices and specifically in accordance with NI 51-101. These practices are different from the practices used to report production and to estimate reserves in reports and other materials filed with the SEC by companies in the United States.

We incorporate additional information with respect to production and reserves which is either not required to be included or prohibited under rules of the SEC and practices in the United States. We follow the Canadian practice of reporting gross production and reserve volumes; however, we also follow the United States practice of separately reporting these volumes on a net basis (after the deduction of royalties and similar payments). We also follow the Canadian practice of using forecast prices and costs when we estimate our reserves. The SEC permits, but does not require, the disclosure of reserves based on forecast prices and costs.

Reserve information contained herein may include estimates of proved, proved plus probable and possible reserves, as well as resources. The SEC permits, but does not require, the inclusion of estimates of probable and possible reserves in filings made with it by United States oil and gas companies. The SEC does not permit the inclusion of estimates of resources in reports filed with it by United States companies.

Changes in government regulations that affect the crude oil and natural gas industry could adversely affect us.

Various levels of governments impose extensive controls and regulations on oil and natural gas operations (including exploration, development, production, pricing, marketing and transportation). Governments may regulate or intervene with respect to exploration and production activities, prices, taxes and royalties. Amendments to these controls and regulations may occur from time to time in response to economic or political conditions. The implementation of new regulations or the modification of existing regulations affecting the oil and natural gas industry could reduce demand for crude oil and natural gas and increase our costs, either of which may have a material adverse effect on our business, financial condition, results of operations and prospects. Recently, the federal government and certain provincial governments have taken steps to initiate protocols and regulations to limit the release of methane from oil and gas operations. Such draft regulations and protocols may require additional expenditures or otherwise negatively impact our operations, which may affect our profitability. See "Industry Conditions - Regulatory Authorities and Environmental Regulation - Climate Change Regulations".

In order to conduct oil and natural gas operations, we will require regulatory permits, licenses, registrations, approvals and authorizations from various governmental authorities. There can be no assurance that we will be able to obtain all of the permits, licenses, registrations, approvals and authorizations that may be required to conduct operations that we may wish to undertake. In addition to regulatory requirements pertaining to the production, marketing and sale of oil and natural gas mentioned above, our business and financial condition could be influenced by federal legislation affecting, in particular, foreign investment, through legislation such as the Competition Act (Canada) and the Investment Canada Act (Canada).

Our hydraulic fracturing activities are subject to increasing regulation.

Hydraulic fracturing involves the injection of water, sand and small amounts of additives under pressure into rock formations to stimulate hydrocarbon (oil and natural gas) production. Specifically, hydraulic fracturing is used to produce commercial quantities of oil and natural gas from reservoirs that were previously unproductive.

The proliferation of the use of hydraulic fracturing as a recovery technique employed in oil and natural gas drilling has given rise to increased public scrutiny of its environmental aspects, particularly with respect to its potential impact on local aquifers. Pengrowth utilizes hydraulic fracturing in a significant portion of the light oil wells it drills and completes. Pengrowth believes that the hydraulic fracturing that it conducts, given the depth and location of the wells and its consistent utilization of good oilfield practices, is environmentally sound and would not give rise to similar concerns respecting local aquifers.

Pengrowth anticipates that there will be a trend towards increased regulatory requirements concerning hydraulic fracturing in the future. In 2012, the Canadian Association of Petroleum Producers announced hydraulic fracturing operating practices designed to improve water management and water and fluids reporting for shale gas and tight gas development across Canada.

In Alberta, the AER, has implemented requirements for: (i) electronically reporting fracture fluid data, including service provider, fracture scenario, carrier fluid type, proppant type and additives for wells that have been fractured; (ii) electronically reporting water source data, including source location, source type, diversion permit information and volume for all water used in hydraulic fracturing operations with water quality information required for groundwater sources; and (iii) reporting fluid and water source data in daily reports of operations. On May 21, 2013, the AER issued a directive establishing requirements for: (i) preventing the loss of well integrity at a subject well; (ii) assessing, planning for, and mitigating the risks of interwellbore communication with offset wells; (iii) notifying licensees of at-risk offset wells related to hydraulic fracturing operations; (iv) protecting nonsaline aquifers from hydraulic fracturing operations conducted at depths less than 100 metres below of the base of groundwater protection; and (v) notifying the AER about hydraulic fracturing operations.

Due to recent seismic activity reported in the Fox Creek area of Alberta, the AER announced in February 2015, seismic monitoring and reporting requirements for hydraulic fracturing operators in the Duvernay zone in the Fox Creek area. These requirements include, among others, an assessment of the potential for seismicity prior to operations, the implementation of a response plan to address potential events, and the suspension of operations if a seismic event above a particular threshold occurs. The AER continues to monitor seismic activity around the province and may extend these requirements to other areas of the province if necessary.

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The Province of British Columbia requires operators to electronically submit reporting information for all hydraulic fracture stimulations performed after May 1, 2013.

The safe disposal of the hydraulic fracturing fluids (including the additives) and water recovered from oil and natural gas wells is subject to ongoing regulatory review by the federal and provincial governments, including its effect on fresh water supplies and the ability of such water to be recycled, amongst other things.

Any new laws, regulations or permitting requirements regarding hydraulic fracturing could lead to operational delays, increased operating costs, third party or governmental claims, and could increase our costs of compliance and doing business as well as delay the development of oil and natural gas resources from shale formations, which are not commercial without the use of hydraulic fracturing. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we are ultimately able to produce from our reserves.

We may become involved in, named a as a party to, or be the subject of, various legal proceedings including regulatory proceedings, tax proceedings and legal actions, related to personal injuries, property damage, property tax, land rights, the environment and contract disputes.

The outcome of outstanding, pending or future proceedings cannot be predicted with certainty and may be determined adversely to us and as a result, could have a material adverse effect on our assets, liabilities, business, financial condition and results of operations.

Aboriginal peoples have claimed aboriginal title and rights to portions of western Canada.

We are not aware that any claims have been made in respect of our properties and assets; however, if a claim arose and was successful such claim may have a material adverse effect on our business, financial condition, results of operations and prospects.

We may disclose confidential information relating to our business, operations or affairs while discussing potential business relationships or other transactions with third parties.

Although confidentiality agreements are generally signed by third parties prior to the disclosure of any confidential information, a breach could put us at competitive risk and may cause significant damage to our business. The harm to our business from a breach of confidentiality cannot presently be quantified, but may be material and may not be compensable in damages. There is no assurance that, in the event of a breach of confidentiality, we will be able to obtain equitable remedies, such as injunctive relief, from a court of competent jurisdiction in a timely manner, if at all, in order to prevent or mitigate any damage to its business that such a breach of confidentiality may cause.

We file all required income tax returns and we believe that we are in full compliance with the provisions of the Tax Act and all other applicable provincial tax legislation.

However, such returns are subject to reassessment by the applicable taxation authority. In the event of a successful reassessment of us, whether by re-characterization of exploration and development expenditures or otherwise, such reassessment may have an impact on current and future taxes payable.

Income tax laws relating to the oil and gas industry, such as the treatment of resource taxation or dividends, may in the future be changed or interpreted in a manner that adversely affects us. Furthermore, tax authorities having jurisdiction over us may disagree with how we calculate our income for tax purposes or could change administrative practices to our detriment.

The level of activity in the Canadian oil and natural gas industry is influenced by seasonal weather patterns.

Wet weather and spring thaw may make the ground unstable. Consequently, municipalities and provincial transportation departments enforce road bans that restrict the movement of rigs and other heavy equipment, thereby reducing activity levels. Roads bans and other restrictions generally result in a reduction of drilling and exploratory activities and may also result in the shut-in of some of our production if not otherwise tied-in. Certain oil and natural gas producing areas are located in areas that are inaccessible other than during the winter months because the ground surrounding the sites in these areas consists of swampy terrain. In addition, extreme cold weather, heavy snowfall and heavy rainfall may restrict our ability to access properties, cause operational difficulties including damage to machinery or contribute to personnel injury because of dangerous working conditions.

Terrorist attacks and the threat of terrorist attacks may have an adverse impact on us.

Energy sector participants, including us, are a potential target for terrorists. The possibility that infrastructure facilities may be direct targets of, or indirect casualties of, an act of terror and the implementation of security measures as a precaution against possible terrorist attacks may result in increased cost to our business.

Delays in business operations could adversely affect the market price of the Common Shares.

In addition to the usual delays in payment by purchasers of oil and natural gas to the operators of our properties, and the delays of those operators in remitting payment to us, payments between any of these parties may also be delayed by:

• restrictions imposed by lenders;

• accounting delays;

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• delays in the sale or delivery of products;

• delays in the connection of wells to a gathering system;

• blowouts or other accidents;

• adjustments for prior periods;

• recovery by the operator of expenses incurred in the operation of the properties; or

• the establishment by the operator of reserves for these expenses.

Any of these delays could reduce the amount of cash available for dividend to Shareholders in a given period and expose us to additional third party credit risks.

Changes in market-based factors may adversely affect the trading price of the Common Shares.

The market price of our Common Shares is sensitive to a variety of market based factors including, but not limited to, interest rates, foreign exchange rates and the comparability of the Common Shares to other yield-oriented securities. Any changes in these market-based factors may adversely affect the trading price of the Common Shares. In addition, in certain jurisdictions institutions, including government sponsored entities, have determined to decrease their ownership in oil and gas entities which may impact the liquidity of certain securities and may put downward pressure on the trading price of those securities.

We rely on our reputation to continue our operations and to attract and retain investors and employees

Any environmental damage, loss of life, injury or damage to property caused by our operations could damage our reputation in the areas in which we operate. Negative sentiment towards us could result in a lack of willingness of municipal authorities being willing to grant the necessary licenses or permits for us to operate our business and in residents in the areas where we are doing business opposing further operations in the area by us. If we develop a reputation of having an unsafe work site it may impact our ability to attract and retain the necessary skilled employees and consultant to operate our business. Further, our reputation could be affected by actions and activities of other corporations operating in the oil and gas industry, over which we have no control. In addition, environmental damage, loss of life, injury or damage to property caused by our operations could result in negative investor sentiment towards us, which may result in limiting our access to capital, increasing the cost of capital, and decreasing the price and liquidity of our Common Shares.

Changing investor sentiment towards the oil and gas industry may impact our access to, and cost of, capital

A number of factors, including the concerns of the effects of the use of fossil fuels on climate change, concerns of the impact of oil and gas operations on the environment, concerns of environmental damage relating to spills of petroleum products during transportation and concerns about indigenous rights, have affected certain investors' sentiments towards investing in the oil and gas industry. As a result of these concerns, some institutional, retail and public investors have announced that they no longer are willing to fund or invest in oil and gas properties or companies or are reducing the amount thereof over time. In addition, certain institutional investors are requesting that issuers develop and implement more robust social, environmental and governance policies and practices. Developing and implementing such policies and practices can involve significant costs and require a significant time commitment from our Board, management and employees. Failing to implement the policies and practices as requested by institutional investors may result in such investors reducing their investment in us or not investing in us at all. Any reduction in the investor base interested or willing to invest in the oil and gas industry and more specifically, Pengrowth, may result in limiting our access to capital, increasing the cost of capital, and decreasing the price and liquidity of our Common Shares.

We are dependent on our information technology infrastructure.

We have become increasingly dependent upon the availability, capacity, reliability and security of our information technology infrastructure and our ability to expand and continually update this infrastructure, to conduct daily operations. We depend on various information technology systems to estimate reserve quantities, process and record financial data, manage our land base, analyze seismic information, administer our contracts with our operators and lessees and communicate with employees and third-party partners.

Further, we are subject to a variety of information technology and system risks as a part of our normal course operations, including potential breakdown, invasion, virus, cyber-attack, cyber-fraud, security breach, and destruction or interruption of our information technology systems by third parties or insiders. Unauthorized access to these systems by employees or third parties could lead to corruption or exposure of confidential, fiduciary or proprietary information, interruption to communications or operations or disruption to our business activities or our competitive position. In addition, cyber phishing attempts, in which a malicious party attempts to obtain sensitive information such as usernames, passwords, and credit card details (and money) by disguising as a trustworthy entity in an electronic communication, have become more widespread and sophisticated in recent years. If we become a victim to a cyber phishing attack it could result in a loss or theft of our financial resources or critical data and information or could result in a loss of control of our technological infrastructure or financial resources. Further, disruption of critical information technology services, or breaches of information security, could result in material financial loss, regulatory action and sanctions, reputational harm and/or legal liability, which, in turn, could materially adversely affect our business, financial condition or profitability. We apply technical and process controls in line with industry-accepted standards to protect our information assets and systems; however, these controls may not adequately prevent cyber-security breaches. The significance of any such event is difficult to quantify, but may in certain circumstances be material and could have a material adverse effect on our business, financial condition and results of operations.

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We rely on our business resiliency plans.

Failure to develop effective business resiliency plans could disrupt operations and cause financial losses, which could materially adversely affect our business, financial condition or profitability.

We are dependent on the availability of our personnel, office facilities and the proper functioning of our computer and telecommunications systems. While management has implemented a business continuity program, which is reviewed and updated regularly there can be no assurance that our business will not be interrupted and materially adversely affected during a disaster such as a severe weather event, fire, significant water damage, widespread pandemic, a prolonged loss of electricity or explosion or being collaterally damaged by any of the foregoing occurring to neighbouring businesses. While management believes the business continuity program has been developed to minimize any disruption, there can be no assurance of business continuity in the event that there are disruptions of normal operations. A disaster could materially interrupt business operations and if the disaster recovery plans prove to be ineffective, it could cause material financial loss, loss of human capital, reputational harm or legal liability, which, in turn, could materially adversely affect our business, financial condition or profitability.

The industry in which we operate exposes us to potential liabilities that may not be covered by insurance.

Oil and natural gas exploration, development and production operations are subject to all the risks and hazards typically associated with such operations, including, but not limited to, fire, explosion, blowouts, sour gas releases, spills and other environmental hazards. These typical risks and hazards could result in substantial damage to oil and natural gas wells, production facilities, other property, the environment and personal injury. Particularly, we may explore for and produce sour natural gas in certain areas. An unintentional leak of sour natural gas could result in personal injury, loss of life or damage to property and may necessitate an evacuation of populated areas, all of which could result in liability to us.

Oil and natural gas production operations are also subject to all the risks typically associated with such operations, including encountering unexpected formations or pressures, premature decline of reservoirs and the invasion of water into producing formations. Losses resulting from the occurrence of any of these risks may have a material adverse effect on our business, financial condition, results of operations and prospects.

As is standard industry practice, we are not fully insured against all of these risks, nor are all risks insurable. Although we maintain liability insurance in an amount that we consider consistent with industry practice, liabilities associated with certain risks could exceed policy limits or not be covered. In either event we could incur significant costs.

If there are delays in our projects, this may delay our expected revenues from operations.

We manage a variety of small and large projects in the conduct of our business. Project delays may delay expected revenues from operations. Significant project cost overruns could make a project uneconomic. Our ability to execute projects and market oil and natural gas depends upon numerous factors beyond our control, including:

• the availability of processing capacity;

• the availability and proximity of pipeline capacity;

• the availability of storage capacity;

• the availability of, and the ability to acquire, water supplies needed for drilling and, hydraulic fracturing, and waterfloods or our ability to dispose of water used or removed from strata at a reasonable cost and in accordance with applicable environmental regulations;

• the effects of inclement weather;

• the availability of drilling and related equipment;

• unexpected cost increases;

• accidental events;

• currency fluctuations;

• changes in regulations;

• the availability and productivity of skilled labour; and

• the regulation of the oil and natural gas industry by various levels of government and governmental agencies.

Because of these factors, we could be unable to execute projects on time, on budget or at all, and may be unable to market the oil and natural gas that we produce effectively.

We may be subject to growth-related risks including capacity constraints and pressure on our internal systems and controls.

Our ability to manage growth effectively will require us to continue to implement and improve our operational and financial systems and to expand, train and manage our employee base. Our inability to deal with this growth may have a material adverse effect on our business, financial condition, results of operations and prospects.

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Potential conflicts of interest.

Certain of our directors are also directors of other oil and gas companies and as such may, in certain circumstances, have a conflict of interest requiring them to abstain from certain decisions. Conflicts, if any, will be subject to the procedures and remedies of the ABCA which require the director or officer who is a party to, or is a director or an officer of, or has a material interest in any person who is a party to, a material contract or proposed material contract with us disclose his or her interest and, in the case of directors, to refrain from voting on any matter in respect of such contract unless otherwise permitted under the ABCA.

Asset Concentration

With the sale of approximately $2.3 billion of assets since 2012, in part to fund the first commercial phase of our Lindbergh Project, our assets have become much less diversified and increasingly concentrated in one project, product type (bitumen) and one area/formation. A failure to execute at Lindbergh or Groundbirch could have a significant adverse effect on Pengrowth.

LindberghThermal Project Specific Risks

Further expansion of our Lindbergh thermal project will require substantial capital investment over the coming years, if completed in large phases. In addition to the above, there are certain additional risk factors associated with the development of our Lindbergh thermal project. These include the following:

Ability to Fund Development

As a result of SAGD projects being highly capital-intensive and front-end loaded, there is a risk that Pengrowth will not have the ability to fund the Phase 2 or Phase 2A expansion as currently designed. If this scenario is to arise, Pengrowth may look at other options to expand the Lindbergh project through smaller, less capital-intensive expansion options with the most favourable economics that resource exploitation planning and facility design will allow.

Any expansion phases of the Lindbergh thermal project are not anticipated to be constructed on a turn-key basis. Additionally, given the state of development of the Lindbergh thermal project, various changes to the project may be made. The information contained herein related to the Lindbergh thermal project, including, without limitation, reserve and economic evaluations, assumes no material changes being made to the project or its scope.

Should expansion phases of the Lindbergh thermal project be sanctioned by our Board, it is anticipated that the industry could also be in a period of substantial oil sands development and industrial activity. We will need to compete for equipment, supplies, services, and labour in this environment which could result in increased costs, shortages of goods and services that delay progress, or both. Increased competition for equipment, materials and labour may result in increased costs that could have a material adverse effect on our business, financial condition or results of operations. As such, there are risks associated with project cost estimates provided by us. Cost estimates are provided prior to engineering being 100 percent complete. The final scope, design and detailed engineering are required to reduce the margin of error. Accordingly, actual costs may vary from estimates and these differences may be material.

Operating Costs

The operating costs of the Lindbergh thermal project have the potential to vary considerably throughout the operating period and will be significant components of the cost of production of any petroleum products produced by the Lindbergh thermal project. Project economics and our overall earnings may be reduced if increases in operating costs are incurred. Factors which could affect operating costs include, without limitation;

• the amount and cost of labour to operate the Lindbergh thermal project;

• the cost of catalyst and chemicals;

• the actual steam oil ratio required to operate the SAGD well pairs;

• the cost of natural gas and electricity;

• power outages, particularly in winter when freeze-ups could occur;

• produced sand causing issues of erosion, hot spots and corrosion;

• reliability of the facilities;

• the maintenance cost of the facilities;

• the cost to transport sales products and the cost to dispose of certain by-products;

• the cost of well maintenance and workovers as a result of decreased productivity;

• the cost of insurance; and

• catastrophic events such as fires, earthquakes, storms or explosions.

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Infrastructure for the Lindbergh Thermal Project

We depend, to a large extent, on third party designers, contractors and suppliers to design and construct the necessary facilities and infrastructure for any expansion phases of the Lindbergh thermal project. We rely on certain infrastructure owned and operated or to be constructed by others, including, without limitation, pipelines for the transportation of diluent and produced bitumen to the market, natural gas, water source and disposal pipelines and electrical grid transmission lines for the provision and/or sale of electricity to us. The failure of any or all of these third parties to supply utilities, services or construct the infrastructure required for the Lindbergh thermal project would negatively impact our operation and financial results.

In-situ Extraction

Current SAGD technologies for in-situ recovery of heavy crude oil and bitumen are energy intensive, requiring significant consumption of natural gas and other fuels in the production of steam which is used in the recovery process. The amount of steam required in the production process can also vary and significantly impact costs. The performance of the reservoir can also impact the timing and levels of production using this technology.

Recovery of Bitumen

Recovering bitumen from oil sands involves particular risks and uncertainties. SAGD bitumen recovery facilities and development and expansion of production can entail significant capital outlays. SAGD projects like Lindbergh are susceptible to loss of production, slowdowns, or restrictions on their ability to produce higher value products due to the interdependence of component systems. Severe weather conditions can cause reduced production and in some situations result in higher costs.

Access to Diluent Supplies at Favourable Prices

Bitumen is characterized by high specific gravity or weight and high viscosity or resistance to flow. Diluent, a hydrocarbon based diluting agent, is required to facilitate the transportation of bitumen. A shortfall in the supply of diluent may cause its price to increase thereby increasing the cost to transport bitumen to market and correspondingly increasing our operating costs, decreasing our net revenues and negatively impacting the overall profitability of the Lindbergh thermal project.

Marketing of Production

The market prices for heavy crude oil (which includes bitumen blends) are lower than the established market indices for light or medium grades of oil, due principally to diluent prices and the higher transportation and refining costs associated with heavy crude oil. Also, the market for heavy crude oil is more limited than for light and medium grades of oil, making it more susceptible to supply and demand fundamentals. Future price differentials are uncertain and any increase in heavy crude oil differentials could have an adverse effect on the anticipated returns from the Lindbergh thermal project as well as our overall business, financial condition, results of operations and cash flows.

Regulatory Approvals

Throughout the life of the Lindbergh Project, scheme amendments, EPEA and Water Act (Alberta) approval amendments may be required. Pengrowth submitted a scheme amendment and an EPEA update in February 2017, to increase the maximum oil rate of the Phase 2 development project to 40,000 bbl/day. This approval was received on August 1, 2017. When going through any regulatory review process, the risk areas include but are not limited to; the regulators' ability to review the above application and associated supplemental information requests, third party reviews on behalf of the regulator taking longer than anticipated, Statements of Concern submitted by industry operators, land owners, grazing lease holders, municipalities and First Nation and Métis groups in the region as well as technical or environmental issues identified in the submission in regard to surface infrastructure, subsurface reservoir, cap rock, surface or subsurface water, etc. These issues or concerns may take a significant amount of time to meet the regulators' requirements to mitigate or eliminate leading to delays in the approval process. Unresolved Statements of Concern may require a hearing with the regulators which may or may not be resolved in favor of Pengrowth and, if resolved via a hearing, will also add delays and cost to the timing of approvals.

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MARKET FOR SECURITIES

Our outstanding Common Shares are listed and posted for trading on the NYSE under the symbol "PGH" and on the TSX under the symbol "PGF". The following tables set forth certain trading information for the Common Shares in 2017 as reported by the TSX and the NYSE.

	TSX			NYSE
	($) High	($) Low	Volume	(US$) High	(US$) Low	Volume
January	2.02	1.61	28,289,089	1.50	1.24	18,993,332
February	1.79	1.53	21,336,862	1.37	1.15	16,999,758
March	1.73	1.29	42,243,797	1.30	0.96	30,197,020
April	1.57	1.31	19,074,863	1.18	0.96	21,148,699
May	1.44	1.05	34,321,400	1.06	0.76	23,681,463
June	1.18	0.97	22,647,017	0.88	0.73	13,313,892
July	1.08	0.90	13,387,887	0.82	0.71	10,357,064
August	0.93	0.68	17,135,152	0.75	0.54	12,756,588
September	1.52	0.71	58,336,821	1.23	0.59	26,913,140
October	1.45	1.12	20,797,271	1.12	0.91	14,073,231
November	1.52	1.00	17,718,190	1.20	0.78	14,238,403
December	1.19	0.91	19,048,760	0.93	0.72	13,514,433

Our 6.25 percent series B convertible debentures were listed and posted for trading on the TSX under the symbol "PGF.DB.B" until their maturity on March 31, 2017. The following table sets forth certain trading information for our 6.25 percent series B convertible debentures in 2017 as reported by the TSX.

	6.25% SERIES B CONVERTIBLE DEBENTURES
	($) High	($) Low	Volume
January	100.31	99.60	5,648,000
February	100.51	99.78	1,168,000
March	100.11	99.79	2,901,000

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DIRECTORS AND OFFICERS

The name, jurisdiction of residence, position held and principal occupation for the previous five years of each of our directors and officers are set out below:

Name and Jurisdiction of Residence	Position with Pengrowth	Principal Occupation
Kelvin B. Johnston(1)(2)(3)(4)  Alberta, Canada	Chairman and Director (Director since 2012)	President of Wylander Crude Corp. and Vice President, Corporate Development of Lakeview Energy Inc.
Derek W. Evans(6)  Alberta, Canada	President, Chief Executive Officer and Director (Director since 2009)(5)	President and Chief Executive Officer of Pengrowth.
Wayne K. Foo(3)(4)  Alberta, Canada	Director (Director since 2006)(5)	Chair of the Board of Parex Resources Inc. (energy company) since May 11, 2017; prior thereto, Chief Executive Officer of Parex Resources Inc. since January 2015; prior thereto, President and Chief Executive Officer of Parex Resources Inc.
James D. McFarland(1)(2)  Alberta, Canada	Director (Director since 2010)(5)	Corporate Director since December 31, 2017; prior thereto, President, Chief Executive Officer and Director of Valeura Energy Inc. from June 2010 until October 19, 2017 and Chief Executive Officer and Director thereafter until his retirement on December 31, 2017.
A. Terence Poole(1)  Alberta, Canada	Director (Director since 2005)(5)	Business Consultant and Corporate Director.
Jamie C. Sokalsky(1)(4)  Ontario, Canada	Director (Director since 2015)	Corporate Director since September 2014 and prior thereto, Director, President and Chief Executive Officer of Barrick Gold Corporation.
D. Michael G. Stewart(2)(3)  Alberta, Canada	Director (Director since 2006)(5)	Corporate Director.
Douglas C. Bowles Alberta, Canada	Vice President and Controller	Vice President and Controller of Pengrowth.
David M. Granger Alberta, Canada	Vice President, Human Resources	Vice President, Human Resources of Pengrowth since April 2016; prior thereto, Principal, Ener-G HR Consulting Ltd. from April 2014 to March 2016 and prior thereto, Vice President, Human Resources, Brewers Retail Inc.
Andrew D. Grasby Alberta, Canada	Senior Vice President, General Counsel & Corporate Secretary	Senior Vice President, General Counsel & Corporate Secretary of Pengrowth.
Randall S. Steele Alberta, Canada	Chief Operating Officer	Chief Operating Officer since January 2018; prior thereto, Senior Vice President, Conventional Operations of Pengrowth since May 2015 and prior thereto, General Manager, Conventional Operations of Pengrowth since 2013.
Christopher G. Webster Alberta, Canada	Chief Financial Officer	Chief Financial Officer of Pengrowth.

Notes:

(1) Member of the Audit and Risk Committee.

(2) Member of Compensation Committee.

(3) Member of Corporate Governance and Nominating Committee.

(4) Member of Reserves, Health, Safety and Environment Committee.

(5) Denotes year first appointed as a director of Pengrowth Corporation, a predecessor of ours. Each of the directors has agreed to serve as such until the next annual meeting of shareholders or until their successor is duly appointed.

(6) Prior to January 1, 2016, Mr. Evans was a director of Endurance Energy Ltd. (a private oil and gas company) which filed for protection under the CCAA in May 2016.

As at December 31, 2017, the foregoing directors and officers, as a group, beneficially owned, directly or indirectly, 3,837,596 Common Shares or approximately 0.69 percent of the issued and outstanding Common Shares and held rights and options to acquire a further 9,021,464 Common Shares (assuming 100 percent vesting of all performance-based rights). The information as to shares beneficially owned, not being within our knowledge, has been furnished by the respective individuals.

The term of office for each director expires at the next annual meeting of Shareholders.

PENGROWTH ENERGY CORPORATION | 2017 ANNUAL INFORMATION FORM     57

Corporate Cease Trade Orders, Bankruptcies, Personal Bankruptcies, Penalties or Sanctions

No director or executive officer is as at the date hereof, or has been within ten years of the date hereof, a director or chief executive officer or chief financial officer of any company, including us, that:

(a) while the director or executive officer was acting in the capacity as director, chief executive officer or chief financial officer was the subject of a cease trade or similar order or an order that denied the relevant company access to any exemption under securities legislation, for a period of more than 30 consecutive days; or

(b) was subject to a cease trade or similar order, or an order that denied the relevant company access to any exemption under securities legislation, for a period of more than 30 consecutive days, after the director or executive officer ceased to be a director, chief executive officer or chief financial officer and which resulted from an event that occurred while that person was acting in the capacity as director, chief executive officer or chief financial officer.

Other than as set out above, no current director or executive officer or securityholder holding a sufficient number of our securities to affect materially our control has, within the last ten years prior to the date hereof, been a director or executive officer of any company (including us) that, while such person was acting in that capacity, or within a year of that person ceasing to act in that capacity, became bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency or was subject to or instituted any proceedings, arrangement or compromise with creditors or had a receiver, receiver manager or trustee appointed to hold its assets.

In addition, no current director or executive officer or securityholder holding a sufficient number of our securities to affect materially our control has, within the last ten years prior to the date hereof, become bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency, or become subject to or instituted any proceedings, arrangement or compromise with creditors, or had a receiver, receiver manager or trustee appointed to hold the assets of the director, officer or securityholder.

No current director or executive officer or securityholder holding a sufficient number of our securities to affect materially control of us has been subject to: (i) any penalties or sanctions imposed by a court relating to securities legislation or by a securities regulatory authority or has entered into a settlement agreement with a securities regulatory authority; or (ii) any other penalties or sanctions imposed by a court or regulatory body that would likely be considered important to a reasonable investor in making an investment decision.

PENGROWTH ENERGY CORPORATION | 2017 ANNUAL INFORMATION FORM     58

AUDIT AND RISK COMMITTEE

The Audit and Risk Committee is appointed annually by our Board of Directors. The responsibilities and duties of the Audit and Risk Committee are set forth in the Audit and Risk Committee Terms of Reference attached hereto as Appendix D. The following table sets forth the name of each of the current members of our Audit and Risk Committee, whether such member is independent and financially literate, as those terms are defined in National Instrument 52-110 Audit Committees, and the relevant education and experience of each member:

Name	Independent	Financially Literate	Relevant Education and Experience
Kelvin B. Johnston	Yes	Yes	Mr. Johnston is an executive with more than 30 years' experience in the oil and gas industry. Mr. Johnston serves as President of Wylander Crude Corp., a private oil and gas company, a position he has held since July 2006, and as Vice President, Corporate Development of Lakeview Energy Inc., a private oil and gas company, a position held since June 2009. He is currently a managing director of JOG Capital Corp., a provider of private equity to Canadian junior exploration and production companies. Prior positions include serving as President and Chief Executive Officer of Alberta Clipper Energy Inc., Vice-President, Exploration of Thunder Energy Ltd., and various senior technical, executive and board capacities at Husky Oil Ltd., Startech Energy Inc., Impact Energy Inc., Mustang Resources Ltd. and Peerless Energy Inc. Mr. Johnston holds a Bachelor of Science (Hons) degree in Geology from the University of Manitoba and a Masters degree in Economics from the University of Calgary.
James D. McFarland	Yes	Yes	Mr. McFarland has more than 45 years' experience in the oil and gas industry, most recently as President, Chief Executive Officer, director and co-founder of Valeura Energy Inc., a TSX listed issuer. Prior thereto Mr. McFarland was President, Chief Executive Officer, director and a co-founder of Verenex Energy Inc., a TSX listed issuer. He has served in senior executive roles as Managing Director of Southern Pacific Petroleum N.L. in Australia (an Australian Securities Exchange listed issuer), President and Chief Operating Officer of Husky Oil Limited (a TSX listed issuer) and in a wide range of upstream and corporate functions in an earlier 23-year career with Imperial Oil Limited and other ExxonMobil affiliates in Canada, the US and western Europe. Mr. McFarland currently serves as a director of MEG Energy Corp. and Valeura Energy Inc., and is a past director of Aventura Energy Inc., Vermilion Energy Trust and Vermilion Resources Ltd. (all TSX-listed issuers). Mr. McFarland is a member of the Association of Professional Engineers and Geoscientists of Alberta, the Society of Petroleum Engineers International, the Program Committee of the World Petroleum Council and the Institute of Corporate Directors. He is also a past member of the Australian Institute of Company Directors. Mr. McFarland received a Bachelor of Science in Chemical Engineering from Queen's University and a Master of Science in Petroleum Engineering from the University of Alberta.
A. Terence Poole	Yes	Yes	Mr. Poole brings extensive senior financial management, accounting, capital and debt market experience to Pengrowth. He retired from Nova Chemicals Corporation in 2006 where he had held various senior management positions including Executive Vice President, Corporate Strategy and Development. Mr. Poole currently serves on the board of directors for Methanex Corporation. Mr. Poole received a Bachelor of Commerce degree from Dalhousie University and holds a Chartered Professional Accountant designation.
Jamie C. Sokalsky	Yes	Yes	Mr. Sokalsky currently serves as the Chairman of Probe Metals Inc., a TSX-V listed company. He is currently a member of the audit committees of Agnico-Eagle Mines Limited and Royal Gold Inc., both TSX-listed companies. He was formerly President and Chief Executive Officer of Barrick Gold Corporation (2012-2014) and prior to that, Executive Vice President and Chief Financial Officer of Barrick Gold Corporation (1999-2012). He is the former Chairman of Probe Mines Limited. He holds a Bachelor of Commerce degree (honours) from Lakehead University and is a Chartered Professional Accountant.

Principal Accountant Fees and Services

The following table provides information about the aggregate fees billed to us for professional services rendered by KPMG LLP during fiscal 2017 and 2016:

	2017 ($thousands)	2016 ($thousands)
Audit Fees	900	884
Audit Related Fees	-	-
Tax Compliance and Preparation Services	23	8
Other Tax Services	23	13
All Other Fees	105	75
Total	1,051	980

PENGROWTH ENERGY CORPORATION | 2017 ANNUAL INFORMATION FORM     59

Audit Fees

Audit fees consist of fees for the audit of our annual financial statements and services that are normally provided in connection with statutory and regulatory filings or engagements.

Audit-Related Fees

Audit-related fees normally include due diligence reviews in connection with acquisitions, research of accounting and audit-related issues and the completion of audits required by contracts to which we are a party.

Tax Fees

During 2016 and 2017 the services provided in this category included assistance and advice in relation to the preparation of income tax returns for us and our subsidiaries, tax advice and planning and commodity tax consultation.

All Other Fees

During 2016 and 2017 the services provided in this category relate to translation of financial statements, management discussion and analysis and other regulatory filings into French.

Pre-Approval Policies and Procedures

Pengrowth has adopted the following policies and procedures with respect to the pre-approval of audit and permitted non-audit services to be provided by KPMG LLP. The Audit and Risk Committee approves a schedule which summarizes the services to be provided that the Audit and Risk Committee believes to be typical, recurring or otherwise likely to be provided by KPMG LLP. The schedule generally covers the period between the adoption of the schedule and the end of the year, but at the option of the Audit and Risk Committee, may cover a shorter or longer period. The list of services is sufficiently detailed as to the particular services to be provided to ensure that: (i) the Audit and Risk Committee knows precisely what services it is being asked to pre-approve; and (ii) it is not necessary for any member of Pengrowth's management to make a judgment as to whether a proposed service fits within the pre-approved services. Services that arise that were not contemplated in the schedule must be pre-approved by the Audit and Risk Committee chairman or a delegate of the Audit and Risk Committee. The full Audit and Risk Committee is informed of the services at its next meeting.

Pengrowth has not approved any non-audit services on the basis of the de minimis exemptions. All non-audit services are pre-approved by the Audit and Risk Committee in accordance with the pre-approval policy referenced herein.

CONFLICTS OF INTEREST

Our Board of Directors supervises our management of our business and affairs. The Board of Directors approves significant strategic operational decisions and all decisions relating to:

• the issuance of additional Common Shares;

• material acquisitions and dispositions of properties;

• material capital expenditures;

• borrowing; and

• the payment of dividends.

Circumstances may arise where members of our Board of Directors serve as directors or officers of corporations which are in competition to our interests. The Board of Directors reviews potential conflicts of interest at each meeting. No assurances can be given that opportunities identified by such board members will be provided to us. In addition, some members of our senior management team sit as directors of other corporations. Any such positions must be disclosed to the Board of Directors and approved by the Chief Executive Officer.

LEGAL PROCEEDINGS

We are sometimes named as a defendant in litigation. The nature of these claims is usually related to settlement of normal operational or labour issues. The outcome of such claims against us are not determinable at this time, however they are not expected to have a materially adverse effect on us as a whole. We are not, and have not been at any time within the most recently completed financial year, a party to any legal proceedings, known or contemplated, where the damages involved, excluding interest and costs, exceed ten percent of our assets.

See "Risk Factors - We may become involved in, named a as a party to, or be the subject of, various legal proceedings including regulatory proceedings, tax proceedings and legal actions, related to personal injuries, property damage, property tax, land rights, the environment and contract disputes".

PENGROWTH ENERGY CORPORATION | 2017 ANNUAL INFORMATION FORM     60

INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS

Other than as discussed herein, there are no material interests, direct or indirect, of any of our directors, executive officers, senior officers, any direct or indirect Shareholder who beneficially owns, or who exercises control over, more than ten percent of our outstanding Common Shares or any known associate or affiliate of such persons, in any transaction within the three most recently completed financial years or during the current financial year that has materially affected or is reasonably expected to materially affect us.

INTERESTS OF EXPERTS

As of the date hereof, the directors and officers of GLJ, as a group, beneficially own, directly or indirectly, less than one percent of the outstanding Common Shares.

KPMG LLP are our auditors and have confirmed that they are independent with respect to us within the meaning of the relevant rules and related interpretations prescribed by the relevant professional bodies in Canada and any applicable legislation or regulations and also that they are independent accountants with respect to us under all relevant U.S. professional and regulatory standards.

AUDITORS, TRANSFER AGENT AND REGISTRAR

The transfer agent and registrar for the Common Shares is Computershare Trust Company of Canada at its principal office in the City of Toronto, Ontario. Our auditors are KPMG LLP, Chartered Accountants in Calgary, Alberta.

MATERIAL CONTRACTS

The only material contracts entered into by us or Pengrowth Energy Trust during the most recently completed financial year, or before the most recently completed financial year and still in effect, other than during the ordinary course of business, are as follows:

(i) the Credit Facility;

(ii) the Note Purchase Agreement dated October 18, 2012, as amended, concerning the 2012 Senior Notes; and

(iii) the Note Purchase Agreement dated May 11, 2010, as amended, concerning the 2010 Senior Notes.

Copies of these contracts and the relevant amendments have been filed by us on SEDAR and are available through the SEDAR website at www.sedar.com.

CODE OF ETHICS

Pengrowth has adopted a code of ethics, as that term is defined in Form 40-F under the US Securities Exchange Act of 1934 (the "Code of Ethics") that applies to Pengrowth's management, including its Chief Executive Officer, Chief Financial Officer and principal accounting officers. The Code of Ethics is available for viewing on our website www.pengrowth.com under the name "Code of Business Conduct and Ethics", and is available in print to any Shareholder who requests it. Requests for copies of the Code of Ethics should be made by contacting: Investor Relations, Pengrowth Energy Corporation, Suite 1600, 222 – 3^rd Avenue S.W., Calgary, Alberta, Canada, T2P 0B4.

The Board adopted an amended and restated Code of Ethics on November 4, 2015. All Directors, officers, employees, consultants and contractors are required to accept the Code of Ethics annually.

During the year ended December 31, 2017, Pengrowth has not granted any waivers (including implicit waivers) from the Code of Ethics in respect of its Chief Executive Officer, Chief Financial Officer or its principal accounting officers.

OFF-BALANCE SHEET ARRANGEMENTS

Pengrowth has no off-balance sheet arrangements.

PENGROWTH ENERGY CORPORATION | 2017 ANNUAL INFORMATION FORM     61

DISCLOSURE PURSUANT TO THE REQUIREMENTS
OF THE NEW YORK STOCK EXCHANGE

As a Canadian reporting issuer with securities listed on the TSX and the NYSE, Pengrowth has in place a system of corporate governance practices which complies with Canadian securities laws and the TSX corporate governance guidelines as well as the corporate governance rules of the NYSE applicable to foreign private issuers. Pengrowth qualifies as a foreign private issuer under SEC rules and therefore only certain of the NYSE rules are applicable to Pengrowth. However, Pengrowth benchmarks its policies and procedures against major North American entities, with a view to adopting the best practices when appropriate to its circumstances.

The Board of Directors of the Corporation has adopted and published a Corporate Governance Policy which affirms Pengrowth's commitment to maintaining a high standard of corporate governance. This policy is published on Pengrowth's website at www.pengrowth.com. The Board of Directors of the Corporation has also adopted Terms of Reference for each of an Audit and Risk Committee, a Corporate Governance and Nominating Committee, a Compensation Committee, and a Reserves, Health, Safety and Environment Committee, a Code of Business Conduct and Ethics, a Corporate Disclosure Policy and a Policy on Trading in Securities, each of which is published on Pengrowth's website, and is available in print to any Shareholder who requests it. The Audit and Risk Committee's Terms of Reference are attached hereto as Appendix D. From time to time, special committees of the Board of Directors are formed with prescribed mandates.

There is only one significant way in which Pengrowth's corporate governance practices differ from those required to be followed by domestic United States issuers under the NYSE Listed Company Manual. The NYSE Listed Company Manual requires shareholder approval of all equity compensation plans and any material revisions to such plans, regardless of whether the securities to be delivered under such plans are newly issued or purchased on the open market, subject to a few limited exceptions. In contrast, the TSX rules require shareholder approval of equity compensation plans only when such plans involve newly issued securities. Additionally, if an equity compensation plan provides a procedure for its amendment, the TSX rules require shareholder approval of amendments only where the amendment involves a reduction in the exercise price or an extension of the term of options held by insiders. Pengrowth follows the TSX rules regarding shareholder approval of equity compensation plans.

ADDITIONAL INFORMATION

Additional information, including directors' and officers' remuneration, the principal holders of Common Shares and securities authorized for issuance under equity compensation plans, is contained in our Management Information Circular which relates to the Annual Meeting of Shareholders expected to be held on June 26, 2018. Additional financial information is contained in our comparative consolidated financial statements and associated management's discussion and analysis for the years ended December 31, 2017, 2016 and 2015.

Additional information relating to us may be found on SEDAR at www.sedar.com and on EDGAR at the SEC's website at www.sec.gov.

For additional copies of the Annual Information Form and the materials listed in the preceding paragraphs please contact:

Investor Relations

Pengrowth Energy Corporation

Suite 1600, 222 – 3rd Avenue S.W.

Calgary, Alberta T2P 0B4

Telephone: (403) 233-0224

Toll Free: (855) 336-8814

Facsimile: (403) 265-6251

Website: www.pengrowth.com

E-mail: investorrelations@pengrowth.com

PENGROWTH ENERGY CORPORATION | 2017 ANNUAL INFORMATION FORM     62

APPENDIX A

SUPPLEMENTAL DISCLOSURE - CONTINGENT RESOURCES

The Corporation has engaged GLJ to prepare Contingent Resource evaluations of its Lindbergh, Selina and Groundbirch properties. The following is a brief description of these properties and a summary of those evaluations.

Lindbergh Oil Sands Reserves and Contingent Resources

The Lindbergh property is described above under "Principal Producing Properties - Lindbergh".

Proved Reserves, Probable Reserves and Possible Reserves have been assigned within the approved Phase 1 and Phase 2 project area. Furthermore, there are Contingent Resources for the area beyond the reserves. GLJ has updated its evaluation of the reserves and Contingent Resources for Lindbergh as of December 31, 2017. The evaluation was limited to portions of the reservoir amenable to SAGD. The profitability of the commercial project will be sensitive to oil prices and reservoir quality.

The tables below summarize the estimated volumes and net present value of Future Net Revenue for the Company Interest reserves and Contingent Resources attributable to the Lindbergh property based upon forecast prices and costs. Contingent Resources are reported by category and project maturity sub-class, unrisked and risked for chance of development. The estimates are in accordance with the definitions and guidelines in the COGE Handbook and NI 51-101. Please note that reserves and Contingent Resources involve different risks associated with achieving commerciality. Under the fiscal conditions, including commodity price and cost assumptions, applied in the estimation of reserves, the likelihood that a project will achieve commerciality is effectively 100 percent, whereas the likelihood of a Contingent Resource achieving commerciality will be less than 100 percent.

Summary of Gross Bitumen Reserves as of December 31, 2017
(Forecast Prices and Costs)

	Bitumen - Reserves Category
	Total Proved	Total Proved Plus Probable	Total Proved Plus Probable Plus Possible
Gross Reserves (Mbbl)	163,334	307,057	407,028

Summary of Gross Bitumen Contingent Resources as of December 31, 2017
(Forecast Prices and Costs)

	Bitumen - Contingent Resource Category
Project Maturity Sub-Class(1)	Low Estimate		Best Estimate		High Estimate
Development Pending(2) - Unrisked (Mbbl)	17,066		35,955		59,254
Chance of Development	95	%	95	%	95	%
Development Pending - Risked (Mbbl)	16,212		34,157		56,291
Development Unclarified(3) - Unrisked (Mbbl)	-		66,855		95,832
Chance of Development	-		58	%	58	%
Development Unclarified - Risked (Mbbl)	-		38,509		55,199

Notes:

(1) Project maturity describes the stage of an exploration or development project and broadly corresponds to the chance of commerciality of the project. The project maturity sub-classes (in order of increasing chance of commerciality) are: development not viable, development unclarified, development on hold and development pending. The boundaries between the maturity sub-classes represent "decision gates" that reflect the actions (business decisions) required by the resource owner to move the project up the maturity "ladder" toward commercial production. The project maturity sub-class is accompanied by an estimate of the probability of progressing to the next level of maturity, which is independent of the uncertainty associated with the range of recoverable volumes.

(2) Development Pending describes the status of a project where resolution of the final conditions for development is being actively pursued (high chance of development).

(3) Development Unclarified describes the status of a project where the evaluation is incomplete and there is ongoing activity to resolve any risks and uncertainties.

PENGROWTH ENERGY CORPORATION | 2017 ANNUAL INFORMATION FORM     APPENDIX A | I

Summary of Net Bitumen Reserves as of December 31, 2017
(Forecast Prices and Costs)

	Bitumen - Reserves Category
	Total Proved	Total Proved Plus Probable	Total Proved Plus Probable Plus Possible
Net Reserves (Mbbl)	129,342	245,961	304,899

Summary of Net Bitumen Contingent Resources as of December 31, 2017
(Forecast Prices and Costs)

	Bitumen - Contingent Resource Category
Project Maturity Sub-Class(1)	Low Estimate		Best Estimate		High Estimate
Development Pending(2) - Unrisked (Mbbl)	14,097		28,051		47,711
Chance of Development	95	%	95	%	95	%
Development Pending - Risked (Mbbl)	13,392		26,648		45,325
Development Unclarified(3) - Unrisked (Mbbl)	-		54,572		75,509
Chance of Development	-		58	%	58	%
Development Unclarified - Risked (Mbbl)	-		31,434		43,493

Notes:

(1) Project maturity describes the stage of an exploration or development project and broadly corresponds to the chance of commerciality of the project. The project maturity sub-classes (in order of increasing chance of commerciality) are: development not viable, development unclarified, development on hold and development pending. The boundaries between the maturity sub-classes represent "decision gates" that reflect the actions (business decisions) required by the resource owner to move the project up the maturity "ladder" toward commercial production. The project maturity sub-class is accompanied by an estimate of the probability of progressing to the next level of maturity, which is independent of the uncertainty associated with the range of recoverable volumes.

(2) Development Pending describes the status of a project where resolution of the final conditions for development is being actively pursued (high chance of development).

(3) Development Unclarified describes the status of a project where the evaluation is incomplete and there is ongoing activity to resolve any risks and uncertainties.

Summary of Bitumen Reserves
Net Present Value of Future Net Revenue as of December 31, 2017
(Forecast Prices and Costs)

	Before Income Taxes Discounted at (%/year) - $MM
Reserves Category	0%	5%	10%	15%	20%
Total Proved	3,375	1,779	1,112	787	604
Total Proved Plus Probable	6,437	3,219	1,764	1,045	661
Total Proved Plus Probable Plus Possible	9,723	4,428	2,338	1,395	913

PENGROWTH ENERGY CORPORATION | 2017 ANNUAL INFORMATION FORM     APPENDIX A | II

Summary of Bitumen Contingent Resources
Net Present Value of Future Net Revenue as of December 31, 2017
(Forecast Prices and Costs)

			Before Income Taxes Discounted at (%/year) - $MM
Project Maturity Sub-Class			0%	5%	10%	15%	20%
Development Pending	Low Estimate	Unrisked	260	54	11	2	-
		Chance of Development	95%	95%	95%	95%	95%
		Risked	247	51	11	2	-
	Best Estimate	Unrisked	656	193	58	18	5
		Chance of Development	95%	95%	95%	95%	95%
		Risked	623	183	55	17	5
	High Estimate	Unrisked	793	499	270	133	57
		Chance of Development	95%	95%	95%	95%	95%
		Risked	754	474	256	126	54
Development Unclarified	Low Estimate	Unrisked	-	-	-	-	-
		Chance of Development	-	-	-	-	-
		Risked	-	-	-	-	-
	Best Estimate	Unrisked	773	226	35	(28)	(45)
		Chance of Development	58%	58%	58%	58%	58%
		Risked	445	130	20	(16)	(26)
	High Estimate	Unrisked	1,645	468	119	8	(27)
		Chance of Development	58%	58%	58%	58%	58%
		Risked	947	270	69	5	(16)

Note:

(1) An estimate of risked net present value of future net revenue of Contingent Resources is preliminary in nature and is provided to assist the reader in reaching an opinion on the merit and likelihood of the Corporation proceeding with the required investment. It includes Contingent Resources that are considered too uncertain with respect to the chance of development to be classified as reserves. There is uncertainty that the risked net present value of future net revenue will be realized.

Proved Reserves, Probable Reserves and Possible Reserves have been assigned within the region of the current and proposed commercial development areas where the pool has been sufficiently delineated. The Proved and Probable Reserves attributed to the Lindbergh property have been included in the reserves disclosed under "Statement of Oil and Gas Reserves and Reserves Data".

Contingent Resources have been assigned to the remaining areas of the reservoir within the property that meet certain minimum criteria. Contingent Resources are estimated on the basis of a technically feasible SAGD recovery project having been defined. However, there is uncertainty that it will be commercially viable to produce any portion of the Contingent Resources.

A significant portion of the resource volumes are still classified as a Contingent Resource rather than a reserve due to the following contingencies:

• Higher evaluation well density – additional drilling within the area of the known accumulation is required to allow further project and reserves definition.

• Firm development plans and company commitment for future development phases – confirmation of corporate intent to proceed with defined expansion plans, beyond the initial expansion phase, within an acceptable time period.

• Final project design and sanctioning for any potential future expansion phases.

The Contingent Resources are evaluated based on the same fiscal conditions used in the assessment of reserves and, as such, are expected to be economic. They are estimated on the basis of established technology, namely the application of SAGD technology in sandstone reservoirs. We anticipate the contingencies mentioned above will be satisfied over time which should allow us to book some portion of the Contingent Resources as Proved Reserves, Probable Reserves and Possible Reserves in future years.

The development pending project maturity sub-class relates to the Contingent Resources assigned to areas of the reservoir around the edge of the main Lindbergh pool. It is an extension of the existing commercial development and within the area covered by the Phase 2 expansion application which received regulatory approval in 2016. There is a very high expectation that development will occur for the remaining development pending Contingent Resources but requires a firm development plan and commitment by the Corporation to proceed with the required capital expenditure for additional wells, making use of existing and proposed expansion facility capacity. A chance of development of 95 percent has thus been assigned to these development pending Contingent Resources.

PENGROWTH ENERGY CORPORATION | 2017 ANNUAL INFORMATION FORM     APPENDIX A | III

The development unclarified project maturity sub-class relates to the Contingent Resources assigned to a standalone SAGD development on the Muriel Lake lands. The development unclarified Contingent Resources here are based on a pre-development study. The total Best Estimate gross unrisked capital cost to achieve commercial production is estimated to be $435 million with first major capital expenditures forecast in 2024 and production to commence in 2026. There is more risk associated with the chance of developing this portion of the project relating to the uncertainty in the economics, which requires high quality cost estimates, regulatory approval of a standalone development and the need for a firm development plan which will proceed in a reasonable timeframe. Based on these uncertainties, a chance of development of 58 percent has been assigned.

Selina Oil Sands Contingent Resources

The Selina property is a potential joint venture SAGD development that is described above under "Principal Producing Properties - Lindbergh".

GLJ has evaluated the Selina property as of December 31, 2017, and has assigned Contingent Resources based on the potential for developing the oil sands reservoir as a SAGD project. The evaluation was limited to portions of the reservoir amenable to SAGD. The profitability of the proposed project will be sensitive to oil prices and reservoir quality.

The tables below summarize the estimated volumes and net present value of Future Net Revenue for the Company Interest Contingent Resources attributable to the Selina property based upon forecast prices and costs. Contingent Resources are reported by category and project maturity sub-class, unrisked and risked for chance of development. The estimates are in accordance with the definitions and guidelines in the COGE Handbook and NI 51-101. Please note that Contingent Resources involve risks associated with achieving commerciality. Under the fiscal conditions, including commodity price and cost assumptions, applied in the estimation of Contingent Resources, the likelihood that a project will achieve commerciality is less than 100 percent.

Summary of Gross Bitumen Contingent Resources as of December 31, 2017
(Forecast Prices and Costs)

	Bitumen - Contingent Resource Category
Project Maturity Sub-Class(1)	Low Estimate		Best Estimate		High Estimate
Development Pending(2) - Unrisked (Mbbl)	37,090		56,088		74,632
Chance of Development	90	%	90	%	90	%
Development Pending - Risked (Mbbl)	33,381		50,479		67,169

Notes:

(1) Project maturity describes the stage of an exploration or development project and broadly corresponds to the chance of commerciality of the project. The project maturity sub-classes (in order of increasing chance of commerciality) are: development not viable, development unclarified, development on hold and development pending. The boundaries between the maturity sub-classes represent "decision gates" that reflect the actions (business decisions) required by the resource owner to move the project up the maturity "ladder" toward commercial production. The project maturity sub-class is accompanied by an estimate of the probability of progressing to the next level of maturity, which is independent of the uncertainty associated with the range of recoverable volumes.

(2) Development Pending describes the status of a project where resolution of the final conditions for development is being actively pursued (high chance of development).

Summary of Net Bitumen Contingent Resources as of December 31, 2017
(Forecast Prices and Costs)

	Bitumen - Contingent Resource Category
Project Maturity Sub-Class(1)	Low Estimate		Best Estimate		High Estimate
Development Pending(2) - Unrisked (Mbbl)	32,583		46,786		60,333
Chance of Development	90	%	90	%	90	%
Development Pending - Risked (Mbbl)	29,324		42,108		54,300

Notes:

(1) Project maturity describes the stage of an exploration or development project and broadly corresponds to the chance of commerciality of the project. The project maturity sub-classes (in order of increasing chance of commerciality) are: development not viable, development unclarified, development on hold and development pending. The boundaries between the maturity sub-classes represent "decision gates" that reflect the actions (business decisions) required by the resource owner to move the project up the maturity "ladder" toward commercial production. The project maturity sub-class is accompanied by an estimate of the probability of progressing to the next level of maturity, which is independent of the uncertainty associated with the range of recoverable volumes.

(2) Development Pending describes the status of a project where resolution of the final conditions for development is being actively pursued (high chance of development).

PENGROWTH ENERGY CORPORATION | 2017 ANNUAL INFORMATION FORM     APPENDIX A | IV

Summary of Bitumen Contingent Resources
Net Present Value of Future Net Revenue as of December 31, 2017
(Forecast Prices and Costs)

			Before Income Taxes Discounted at (%/year) - $MM
Project Maturity Sub-Class			0%	5%	10%	15%	20%
Development Pending	Low Estimate	Unrisked	456	146	20	(34)	(58)
		Chance of Development	90%	90%	90%	90%	90%
		Risked	411	132	18	(31)	(52)
	Best Estimate	Unrisked	1,109	357	110	14	(28)
		Chance of Development	90%	90%	90%	90%	90%
		Risked	998	321	99	12	(25)
	High Estimate	Unrisked	1,897	518	159	36	(15)
		Chance of Development	90%	90%	90%	90%	90%
		Risked	1,707	466	143	32	(14)

Note:

(1) An estimate of risked net present value of future net revenue of Contingent Resources is preliminary in nature and is provided to assist the reader in reaching an opinion on the merit and likelihood of the Corporation proceeding with the required investment. It includes Contingent Resources that are considered too uncertain with respect to the chance of development to be classified as reserves. There is uncertainty that the risked net present value of future net revenue will be realized.

Pengrowth has a 50 percent working interest in the Selina oil sands property. It is located approximately 30 kilometres northeast of our Lindbergh property where we currently operate a commercial SAGD project. The Selina property contains a similar bitumen accumulation in the Lloydminster formation to Lindbergh.

Contingent Resources have been assigned to areas of the reservoir within the Selina property that meet certain minimum criteria. Contingent Resources are estimated on the basis of a technically feasible SAGD recovery project having been defined by analogy to our nearby Lindbergh property. However, there is uncertainty that it will be commercially viable to produce any portion of the Contingent Resources.

The resource volumes are classified as a Contingent Resource rather than a reserve due to the following contingencies:

• Higher evaluation well density - additional drilling within the area of the known accumulation is required to allow further project and reserves definition.

• Regulatory approval of the EPEA application for commercial development is required.

• Firm development plans, including high quality capital estimates, and each owner's commitment for future development - confirmation of corporate intent to proceed with defined development plans within an acceptable time period.

• Final project design and sanctioning for commercial development.

The Contingent Resources are evaluated based on the same fiscal conditions used in the assessment of reserves and, as such, are expected to be economic. They are estimated on the basis of established technology, namely the application of SAGD technology in sandstone reservoirs. We anticipate the contingencies mentioned above will be satisfied over time which should allow us to book some portion of the Contingent Resources as Proved Reserves, Probable Reserves and Possible Reserves in future years.

The Contingent Resources at Selina have a development pending project maturity sub-classification. In December 2016, Pengrowth and Koch jointly submitted an EPEA application for a commercial SAGD development. The development pending Contingent Resources are based on a pre-development study. The total Best Estimate gross capital cost to achieve commercial production is estimated to be $488 million with first major capital expenditures forecast in 2020 and production to commence in 2022. There is a high expectation that development will occur but requires regulatory approval, a firm development plan and commitment by the owners to proceed with the required capital expenditure for the well pairs and proposed central facility. A chance of development of 90 percent has thus been assigned to the development pending Contingent Resources.

Groundbirch Reserves and Contingent Resources

The Groundbirch property is described above under "Principal Producing Properties - Groundbirch".

Commercial production at Groundbirch was established in 2010 and there are 17 wells currently producing. For those areas producing and immediately adjacent to existing wells, GLJ has assigned Proved Reserves, Probable Reserves and Possible Reserves. For areas outside of this and in prospective deeper intervals, GLJ has completed a Contingent Resource assessment. The expectation is to continue developing our lands with four to five wells per section in each of multiple layers to fully exploit the thick reservoir and keep our existing gas processing facility full. With favourable economic conditions, our plan is to expand our facility capacity

PENGROWTH ENERGY CORPORATION | 2017 ANNUAL INFORMATION FORM     APPENDIX A | V

and increase the pace of development in the near future. In evaluating reserves and Contingent Resources, as of December 31, 2017, the GLJ forecasts are consistent with this development scenario.

The tables below summarize the estimated volumes and net present value of Future Net Revenue for the Company Interest reserves and Contingent Resources attributable to the Groundbirch property based upon forecast prices and costs. Contingent Resources are reported by category and project maturity sub-class, unrisked and risked for chance of development. The estimates are in accordance with the definitions and guidelines in the COGE Handbook and NI 51-101. Please note that reserves and Contingent Resources involve different risks associated with achieving commerciality. Under the fiscal conditions, including commodity price and cost assumptions, applied in the estimation of reserves, the likelihood that a project will achieve commerciality is effectively 100 percent, whereas the likelihood of a Contingent Resource achieving commerciality will be less than 100 percent.

Summary of Gross Shale Gas Reserves as of December 31, 2017
(Forecast Prices and Costs)

	Shale Gas - Reserves Category
	Total Proved	Total Proved Plus Probable	Total Proved Plus Probable Plus Possible
Gross Reserves (MMcf)	152,847	746,452	914,539

Summary of Gross Shale Gas Contingent Resources as of December 31, 2017
(Forecast Prices and Costs)

	Shale Gas - Contingent Resource Category
Project Maturity Sub-Class(1)	Low Estimate		Best Estimate		High Estimate
Development Pending(2) - Unrisked (MMcf)	432,886		623,895		784,231
Chance of Development	85	%	85	%	85	%
Development Pending - Risked (MMcf)	367,953		530,311		666,597

Notes:

(1) Project maturity describes the stage of an exploration or development project and broadly corresponds to the chance of commerciality of the project. The project maturity sub-classes (in order of increasing chance of commerciality) are: development not viable, development unclarified, development on hold and development pending. The boundaries between the maturity sub-classes represent "decision gates" that reflect the actions (business decisions) required by the resource owner to move the project up the maturity "ladder" toward commercial production. The project maturity sub-class is accompanied by an estimate of the probability of progressing to the next level of maturity, which is independent of the uncertainty associated with the range of recoverable volumes.

(2) Development Pending describes the status of a project where resolution of the final conditions for development is being actively pursued (high chance of development).

Summary of Net Shale Gas Reserves as of December 31, 2017
(Forecast Prices and Costs)

	Shale Gas - Reserves Category
	Total Proved	Total Proved Plus Probable	Total Proved Plus Probable Plus Possible
Net Reserves (MMcf)	135,786	636,588	772,456

PENGROWTH ENERGY CORPORATION | 2017 ANNUAL INFORMATION FORM     APPENDIX A | VI

Summary of Net Shale Gas Contingent Resources as of December 31, 2017
(Forecast Prices and Costs)

	Shale Gas - Contingent Resource Category
Project Maturity Sub-Class(1)	Low Estimate		Best Estimate		High Estimate
Development Pending(2) - Unrisked (MMcf)	432,886		623,895		784,231
Chance of Development	85	%	85	%	85	%
Development Pending - Risked (MMcf)	367,953		530,311		666,597

Notes:

(1) Project maturity describes the stage of an exploration or development project and broadly corresponds to the chance of commerciality of the project. The project maturity sub-classes (in order of increasing chance of commerciality) are: development not viable, development unclarified, development on hold and development pending. The boundaries between the maturity sub-classes represent "decision gates" that reflect the actions (business decisions) required by the resource owner to move the project up the maturity "ladder" toward commercial production. The project maturity sub-class is accompanied by an estimate of the probability of progressing to the next level of maturity, which is independent of the uncertainty associated with the range of recoverable volumes.

(2) Development Pending describes the status of a project where resolution of the final conditions for development is being actively pursued (high chance of development).

Summary of Shale Gas Reserves
Net Present Value of Future Net Revenue as of December 31, 2017
(Forecast Prices and Costs)

	Before Income Taxes Discounted at (%/year) - $MM
Reserves Category	0%	5%	10%	15%	20%
Total Proved	233	125	70	39	20
Total Proved Plus Probable	1,564	685	346	187	102
Total Proved Plus Probable Plus Possible	2,166	860	427	236	135

Summary of Shale Gas Contingent Resources
Net Present Value of Future Net Revenue as of December 31, 2017
(Forecast Prices and Costs)

			Before Income Taxes Discounted at (%/year) - $MM
Project Maturity Sub-Class			0%	5%	10%	15%	20%
Development Pending	Low Estimate	Unrisked	1,023	384	161	71	32
		Chance of Development	85%	85%	85%	85%	85%
		Risked	870	326	137	61	27
	Best Estimate	Unrisked	1,892	672	282	128	59
		Chance of Development	85%	85%	85%	85%	85%
		Risked	1,608	571	240	109	50
	High Estimate	Unrisked	2,638	887	370	174	87
		Chance of Development	85%	85%	85%	85%	85%
		Risked	2,242	754	314	148	74

Note:

(1) An estimate of risked net present value of future net revenue of Contingent Resources is preliminary in nature and is provided to assist the reader in reaching an opinion on the merit and likelihood of the Corporation proceeding with the required investment. It includes Contingent Resources that are considered too uncertain with respect to the chance of development to be classified as reserves. There is uncertainty that the risked net present value of future net revenue will be realized.

Proved Reserves, Probable Reserves and Possible Reserves have been assigned to existing wells and the adjacent undeveloped lands where the Montney reservoir has been sufficiently delineated and development is expected to occur in a reasonable timeframe. The Proved and Probable Reserves attributed to the Groundbirch property have been included in the reserves disclosed under "Statement of Oil and Gas Reserves and Reserves Data".

Contingent Resources are assigned on the basis of a technically feasible recovery project having been defined using established technology, which includes the drilling of horizontal wells and the application of multi-stage fracture techniques. These Contingent Resources are expected to be economic to develop. The Groundbirch Montney shale gas resource is in the early stage of

PENGROWTH ENERGY CORPORATION | 2017 ANNUAL INFORMATION FORM     APPENDIX A | VII

development. Contingent Resources are assigned by GLJ beyond those areas with reserves, to regions of the field where the zone is delineated to an appropriate level to understand the reservoir, and to remove reservoir risk. Additional drilling, completion and test data is required for planning and design purposes with respect to well spacing, pipeline and facility capacity and scheduling of further development. The reclassification of these Contingent Resources as reserves is contingent upon:

• A positive commercial environment with respect to prices and capital costs;

• The need for long term competitive drilling and completion costs;

• Creation and execution of a development plan that will proceed in an acceptable time period which involves an aggressive drilling pace and significant facility expansion; and

• Corporate approval and commitment to spend the required capital to develop these Contingent Resources.

Pengrowth is currently actively pursuing resolution of these contingencies, however, there is uncertainty that it will be commercially viable to produce any portion of the Contingent Resources.

The Contingent Resources are sub-classified on the basis of their project maturity level as development pending. As we step out further from the existing development, there is risk associated with the chance of development as it is forecast further into the future, requiring long term development plans and an ongoing capital commitment by the Corporation.

There is a high expectation that the development pending Contingent Resources will be produced and a chance of development of 85 percent has been assigned. The Contingent Resources are an extension of the existing area where there is production and undeveloped reserves assigned. The uncertainties relate to longer term drilling and completion costs and a development plan and commitment by Pengrowth to pursue development within the next five year period. Growth plans are in place for this to happen.

PENGROWTH ENERGY CORPORATION | 2017 ANNUAL INFORMATION FORM     APPENDIX A | VIII

APPENDIX B

FORM 51-101F2
REPORT ON RESERVES DATA AND CONTINGENT RESOURCES DATA

BY INDEPENDENT QUALIFIED RESERVES
EVALUATOR OR AUDITOR

To the board of directors of Pengrowth Energy Corporation (the "Corporation"):

1. We have evaluated the Corporation's reserves data and contingent resources data as at last day of the reporting issuer's most recently completed financial year. The reserves data are estimates of proved reserves and probable reserves and related future net revenue as at last day of the reporting issuer's most recently completed financial year, estimated using forecast prices and costs. The contingent resources data is risked estimates of volume of contingent resources and related risked net present value of future net revenue as at last day of the reporting issuer's most recently completed financial year, estimated using forecast prices and costs.

2. The reserves data and contingent resources data are the responsibility of the Corporation's management. Our responsibility is to express an opinion on the reserves data and contingent resources data based on our evaluation.

3. We carried out our evaluation in accordance with standards set out in the Canadian Oil and Gas Evaluation Handbook as amended from time to time (the "COGE Handbook") maintained by the Society of Petroleum Evaluation Engineers (Calgary Chapter).

4. Those standards require that we plan and perform an evaluation to obtain reasonable assurance as to whether the reserves data and contingent resources data are free of material misstatement. An evaluation also includes assessing whether the reserves data and contingent resources data are in accordance with principles and definitions presented in the COGE Handbook.

5. The following table shows the net present value of future net revenue (before deduction of income taxes) attributed to proved plus probable reserves, estimated using forecast prices and costs and calculated using a discount rate of 10 percent, included in the reserves data of the Corporation evaluated for the year ended last day of the reporting issuer's most recently completed financial year, and identifies the respective portions thereof that we have evaluated and reported on to the Corporation's management/board of directors:

Independent Qualified Reserves Evaluator or Auditor	Effective Date of Evaluation Report	Location of Reserves (Country or Foreign Geographic Area)	Net Present Value of Future Net Revenue (before income taxes, 10% discount rate - $M)
			Audited	Evaluated	Reviewed	Total
GLJ Petroleum Consultants	December 31, 2017	Canada	-	2,170,276	-	2,170,276

6. The following tables set forth the risked volume and risked net present value of future net revenue (before deduction of income taxes) attributed to best estimate contingent resources, estimated using forecast prices and costs and calculated using a discount rate of 10 percent, included in the Corporation's statement prepared in accordance with Form 51-101F1 and identifies the respective portions of the contingent resources data that we have evaluated and reported on to the Corporation's management/board of directors:

Classification	Independent Qualified Reserves Evaluator or Auditor	Effective Date of Evaluation Report	Location of Resources Other than Reserves (Country or Foreign Geographic Area)	Risked Volume (MMboe)	Risked Net Present Value of Future Net Revenue (before income taxes, 10% discount rate - $M)
					Audited	Evaluated	Total
Development Pending Contingent Resources (2C)	GLJ Petroleum Consultants	December 31, 2017	Canada	192.0	-	393,625	393,625

Classification	Independent Qualified Reserves Evaluator or Auditor	Effective Date of Evaluation Report	Location of Resources Other than Reserves (Country or Foreign Geographic Area)	Risked Volume (MMboe)
Development Unclarified Contingent Resources	GLJ Petroleum Consultants	December 31, 2017	Canada	38.5

PENGROWTH ENERGY CORPORATION | 2017 ANNUAL INFORMATION FORM     APPENDIX B | I

7. In our opinion, the reserves data and contingent resources data respectively evaluated by us have, in all material respects, been determined and are in accordance with the COGE Handbook, consistently applied. We express no opinion on the reserves data and contingent resources data that we reviewed but did not audit or evaluate.

8. We have no responsibility to update our reports referred to in paragraphs 5 and 6 for events and circumstances occurring after the effective date of our reports.

9. Because the reserves data and contingent resources data are based on judgements regarding future events, actual results will vary and the variations may be material.

Executed as to our report referred to above:

GLJ Petroleum Consultants Ltd., Calgary, Alberta, Canada, February 28, 2018

(signed) "Todd J. Ikeda"

Todd J. Ikeda, P.Eng.

Vice President

PENGROWTH ENERGY CORPORATION | 2017 ANNUAL INFORMATION FORM     APPENDIX B | II

APPENDIX C

FORM 51-101F3
REPORT OF
MANAGEMENT AND DIRECTORS ON
RESERVES DATA AND OTHER INFORMATION

Management of Pengrowth Energy Corporation (the "Corporation") are responsible for the preparation and disclosure of information with respect to the Corporation’s oil and gas activities in accordance with securities regulatory requirements. This information includes reserves data, which are estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2017, estimated using forecast prices and costs and includes contingent resources data, which are risked estimates of the volume of contingent resources and related risked net present value of future net revenue as at December 31, 2017, estimated using forecast prices and costs.

An independent qualified reserves evaluator has evaluated the Corporation's reserves data and contingent resources data. The report of the independent qualified reserves evaluator will be filed with securities regulatory authorities concurrently with this report.

The Reserves, Health, Safety and Environment Committee of the board of directors of the Corporation has:

(a) reviewed the Corporation's procedures for providing information to the independent qualified reserves evaluator;

(b) met with the independent qualified reserves evaluator to determine whether any restrictions affected the ability of the independent qualified reserves evaluator to report without reservation; and

(c) reviewed the reserves data and the contingent resources data with management and the independent qualified reserves evaluator.

The Reserves, Health, Safety and Environment Committee of the board of directors has reviewed the Corporation's procedures for assembling and reporting other information associated with oil and gas activities and has reviewed that information with management. The board of directors has, on the recommendation of the Reserves, Health, Safety and Environment Committee, approved:

(a) the content and filing with securities regulatory authorities of Form 51-101F1 containing reserves data and contingent resources data and other oil and gas information;

(b) the filing of Form 51-101F2 which is the report of the independent qualified reserves evaluator on the reserves data, contingent resources data, or prospective resources data; and

(c) the content and filing of this report.

Because the reserves data and contingent resources data are based on judgments regarding future events, actual results will vary and the variations may be material.

(signed) "Derek W. Evans"	(signed) "Randall S. Steele"
Derek W. Evans	Randall S. Steele
President and Chief Executive Officer	Chief Operating Officer
(signed) "Wayne K. Foo"	(signed) "Kelvin B. Johnston"
Wayne K. Foo	Kelvin B. Johnston
Director	Chairman of the Board
February 28, 2018

PENGROWTH ENERGY CORPORATION | 2017 ANNUAL INFORMATION FORM     APPENDIX C | I

APPENDIX D

AUDIT AND RISK COMMITTEETERMS OF REFERENCE

	PENGROWTH ENERGY CORPORATION Policies and Practices	Page 1 of 11
TERMS OF REFERENCE AUDIT AND RISK COMMITTEE

OBJECTIVES

The Audit and Risk Committee (the "Committee") is appointed by the board of directors (the "Board") of Pengrowth Energy Corporation (the "Corporation") to assist the Board in fulfilling its oversight responsibilities. The Corporation, together with its subsidiaries and affiliates, are collectively referred to herein as "Pengrowth".

The Committee's primary duties and responsibilities are to:

• monitor the performance of Pengrowth's internal audit function and the integrity of Pengrowth's financial reporting process and systems of internal controls regarding finance, accounting, and legal compliance;

• assist Board oversight of: (i) the integrity of Pengrowth's financial statements; (ii) Pengrowth's compliance with legal and regulatory requirements; and (iii) the performance of Pengrowth's internal audit function and independent auditors;

• monitor the independence, qualification and performance of Pengrowth's external auditors;

• provide an avenue of communication among the external auditors, the internal auditors, management and the Board; and

• oversee Pengrowth’s risk management processes.

The Committee will continuously review and modify its terms of reference with regard to, and to reflect changes in, the business environment, industry standards on matters of corporate governance, additional standards which the Committee believes may be applicable to Pengrowth's business, the location of Pengrowth's business and its shareholders and the application of laws and policies.

COMPOSITION

Committee members must meet the requirements of applicable securities laws and each of the stock exchanges on which the shares of Pengrowth trade. The Committee shall consist of not less than three and not more than six directors all of whom shall be "independent" and "financially literate", as those terms are defined in National Instrument 52-110 Audit Committees ("NI 52-110") of the Canadian Securities Administrators (as set out in Schedule "A" hereto), Rule 10A-3 promulgated under the Securities Exchange Act of 1934 (as set out in Schedule "B" hereto), and Section 303A.02 of the New York Stock Exchange Listed Company Manual (as set out in Schedule "C" hereto), as applicable, and as "financially literate" is interpreted by the Board in its business judgement. In addition, at least one member of the Committee must have accounting or related financial management expertise as defined by paragraph (8) of general instruction B to Form 40-F and as interpreted by the Board in its business judgement.

The members of the Committee shall be appointed by the Board as members of the Committee and shall continue as such until their successors are appointed or until they cease to be directors of the Corporation. At any time, the Board may fill any vacancy in the membership of the Committee.

The chair of the Committee (the "Chair") will be appointed by the Board or, if one is not appointed, the members of the Committee may elect a chair by vote of a majority of the membership of such committee.

PENGROWTH ENERGY CORPORATION | 2017 ANNUAL INFORMATION FORM     APPENDIX D | I

MEETINGS AND MINUTES

The Committee shall meet at least four times annually, or more frequently if determined necessary to carry out its responsibilities.

A meeting may be called by any member of the Committee, the Chairman of the Board or the President and Chief Executive Officer ("CEO") of the Corporation. A notice of the time and place of every meeting of the Committee shall be given in writing to each member of the Committee at least two business days prior to the time fixed for such meeting, unless notice of a meeting is waived by all members entitled to attend. Attendance of a member of the Committee at a meeting shall constitute waiver of notice of the meeting except where a member attends a meeting for the express purpose of objecting to the transaction of any business on the grounds that the meeting was not lawfully called.

A quorum for meetings of the Committee shall require a majority of its members present in person or by telephone. If the Chair of the Committee is not present at any meeting of the Committee, one of the other members of the Committee present at the meeting will be chosen to preside by a majority of the members of the Committee present at that meeting.

The President and CEO of the Corporation shall be available to advise the Committee, shall receive notice of meetings and may attend meetings of the Committee at the invitation of the Chair. Other management representatives, as well as Pengrowth's internal and external auditors, shall be invited to attend as necessary. Notwithstanding the foregoing, the Chair of the Committee shall hold in camera sessions, without management present, at every meeting of the Committee.

Decisions of the Committee shall be determined by a majority of the votes cast.

The Committee shall appoint a member of the Committee, the Corporate Secretary or another officer of Pengrowth to act as secretary at each meeting for the purpose of recording the minutes of each meeting.

The Committee shall provide the Board with a summary of all meetings together with a copy of the minutes from such meetings. Where minutes have not yet been prepared, the Chair shall provide the Board with oral reports on the activities of the Committee. All information reviewed and discussed by the Committee at any meeting shall be referred to in the minutes and made available for examination by the Board upon request to the Chair.

SCOPE, DUTIES AND RESPONSIBILITIES

MANDATORY DUTIES

REVIEW PROCEDURES

Pursuant to the requirements of NI 52-110 and other applicable laws, the Committee will:

1. Review and reassess the adequacy of the Committee's terms of reference at least annually, submit the terms of reference to the Board for approval and have the document published annually in Pengrowth's annual information circular and at least every three years in accordance with the regulations of the United States' Securities and Exchange Commission.

2. Prior to filing or public distribution, review, discuss with management and the internal and external auditors and recommend to the Board for approval, Pengrowth's audited annual financial statements, annual earnings press releases, annual information form, all financial statements including the related management's discussion and analysis required in prospectuses and other offering memoranda, financial statements required by regulatory authorities, all prospectuses and all documents which may be incorporated by reference into a prospectus, including without limitation, the annual information circular. Approve, on behalf of the Board, Pengrowth's interim financial statements and related management's discussion and analysis and interim earnings press releases. This review should include discussions with management, the internal auditors and the external auditors of significant issues regarding accounting principles, practices and judgements. Discuss any significant changes to Pengrowth's accounting principles and any matters required to be communicated to the Committee by the external auditors in accordance with generally accepted auditing standards.

3. Ensure that adequate procedures are in place for the review of Pengrowth's public disclosure of financial information extracted or derived from Pengrowth's financial statements, other than the public disclosure referred to in paragraph 2 above and periodically assess the adequacy of those procedures.

PENGROWTH ENERGY CORPORATION | 2017 ANNUAL INFORMATION FORM     APPENDIX D | II

4. Be responsible for reviewing the disclosure contained in Pengrowth's annual information form as required by Form 52-110F1 Audit Committee Information Required in an AIF, attached to NI 52-110. If proxies are solicited for the election of directors of Pengrowth, the Committee shall be responsible for ensuring that Pengrowth's information circular includes a cross-reference to the sections in Pengrowth's annual information form that contain the information required by Form 52-110F1.

EXTERNAL AUDITORS

1. The Committee shall advise the external auditors of their accountability to the Committee and the Board as representatives of Pengrowth’s shareholders to whom the external auditors are ultimately responsible. The external auditors shall report directly to the Committee. The Committee is directly responsible for overseeing the work of the external auditors, shall review at least annually the independence and performance of the external auditors and shall annually recommend to the Board the appointment of the external auditors or approve any discharge of auditors when circumstances warrant. The Committee shall, on an annual basis, obtain and review a report by the external auditor describing: (i) the external auditor's internal quality-control procedures; (ii) any material issues raised by the most recent internal quality-control review, or peer review, of the external auditors, or by any inquiry or investigation by governmental or professional authorities, within the preceding five years, respecting one or more independent audits carried out by the external auditors, and any steps taken to deal with any such issues; and (iii) all relationships between the independent auditor and Pengrowth.

2. Approve the fees and other compensation to be paid to the external auditors.

3. Pre-approve all services to be provided to Pengrowth or its subsidiary entities by Pengrowth's external auditors and all related terms of engagement.

OTHER COMMITTEE RESPONSIBILITIES

1. Establish procedures for: (i) the receipt, retention and treatment of complaints received by Pengrowth regarding accounting, internal accounting controls, or auditing matters; and (ii) the confidential and anonymous submission by employees of Pengrowth of concerns regarding questionable accounting or auditing matters.

2. Review and approve Pengrowth's hiring policies regarding partners, employees and former partners and employees of the present and former external auditors of Pengrowth.

DISCRETIONARY DUTIES

The Committee's responsibilities may, at the Board's discretion, also include the following:

REVIEW PROCEDURES

1. In consultation with management, the internal auditors and the external auditors, consider the integrity of Pengrowth's financial reporting processes and controls and the performance of Pengrowth's internal financial accounting staff; discuss significant financial risk exposures and the steps management has taken to monitor, control and report such exposures; and review significant findings prepared by the internal or external auditors together with management's responses.

2. Review, with financial management, the internal auditors and the external auditors, Pengrowth's policies relating to risk management and risk assessment.

3. Meet separately with each of management, the internal auditors and the external auditors to discuss difficulties or concerns, specifically: (i) any difficulties encountered in the course of the audit work, including any restrictions on the scope of activities or access to requested information, and any significant disagreements with management; (ii) any changes required in the planned scope of the audit; and (iii) the responsibilities, budget, and staffing of the internal audit function, and report to the Board on such meetings.

4. Conduct an annual performance evaluation of the Committee.

PENGROWTH ENERGY CORPORATION | 2017 ANNUAL INFORMATION FORM     APPENDIX D | III

INTERNAL AUDITORS

1. Review the annual audit plans of the internal auditors.

2. Review the significant findings prepared by the internal auditors and recommendations issued by any external party relating to internal audit issues, together with management's response.

3. Review the adequacy of the resources of the internal auditors to ensure the objectivity and independence of the internal audit function.

4. Consult with management on management's appointment, replacement, reassignment or dismissal of the internal auditors.

5. Ensure that the internal auditors have access to the Chairman of the Board and the President and CEO.

EXTERNAL AUDITORS

1. On an annual basis, the Committee should review and discuss with the external auditors all significant relationships they have with Pengrowth that could impair the auditors' independence.

2. The Committee shall review the external auditors audit plan – discuss scope, staffing, locations, and reliance upon management and general audit approach.

3. Consider the external auditors' judgments about the quality and appropriateness of Pengrowth's accounting principles as applied in its financial reporting.

4. Be responsible for the resolution of disagreements between management and the external auditors regarding financial performance.

5. Ensure compliance by the external auditors with the requirements set forth in National Instrument 52 108 Auditor Oversight.

6. Ensure that the external auditors are participants in good standing with the Canadian Public Accountability Board ("CPAB") and participate in the oversight programs established by the CPAB from time to time and that the external auditors have complied with any restrictions or sanctions imposed by the CPAB as of the date of the applicable auditor's report relating to Pengrowth's annual audited financial statements.

7. Monitor compliance with the lead auditor rotation requirements of Regulation S-X.

RISK MANAGEMENT POLICIES

Review and recommend for approval by the Board changes considered advisable, after consultation with officers of the Corporation, to the Corporation’s policies relating to:

(a) The risks inherent in the Corporation’s businesses, facilities, strategic direction;

(b) The overall risk management strategies (including insurance coverage);

(c) The risk retention philosophy and the resulting uninsured exposure of the Corporation; and

(d) The loss prevention policies, risk management and hedging programs, and standard and accountabilities of the Corporation in the context of competitive and operational considerations.

RISK MANAGEMENT PROCESSES

Review with management at least annually the Corporation’s processes to identify, monitor, evaluate and address important enterprise-wide business risks.

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FINANCIAL RISK MANAGEMENT

Review with management activity related to management of financial risks to the Corporation.

OTHER COMMITTEE RESPONSIBILITIES

1. On at least an annual basis, review with Pengrowth's legal counsel any legal matters that could have a significant impact on the organization's financial statements, Pengrowth's compliance with applicable laws and regulations, and inquiries received from regulators or governmental agencies.

2. Annually prepare a report to shareholders as required by the United States' Securities and Exchange Commission; the report should be included in Pengrowth's annual information circular.

3. Ensure due compliance with each obligation to certify, on an annual and interim basis, internal control over financial reporting and disclosure controls and procedures in accordance with applicable securities laws and regulations.

4. Review all exceptions to established policies, procedures and internal controls of Pengrowth, which have been approved by any two officers of Pengrowth.

5. Perform any other activities consistent with this Charter, Pengrowth's by-laws, and other governing law as the Committee or the Board deems necessary or appropriate.

6. Maintain minutes of meetings and periodically report to the Board on significant results of the foregoing activities.

COMMUNICATION, AUTHORITYTOENGAGEADVISORSANDEXPENSES

The Committee shall have direct access to such officers and employees of the Corporation, including the Corporation's internal and external auditors and to any other consultants or advisors, as well as to such information respecting Pengrowth it considers necessary to perform its duties and responsibilities.

Any employee may bring before the Committee, on a confidential basis, any concerns relating to matters over which the Committee has oversight responsibilities.

The Committee has the authority to engage the external auditors, independent legal counsel and other advisors as it determines necessary to carry out its duties and to set the compensation for any auditors, counsel and other advisors, such engagement to be at the Corporation's expense. The Corporation shall be responsible for all other expenses of the Committee that are deemed necessary or appropriate by the Committee in order to carry out its duties.

As last amended by the Board of Pengrowth on November 3, 2016.

Last reviewed and approved by the Board of Pengrowth on November 9, 2017.

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Schedule "A"

National Instrument 52-110 - Audit Committees

Meaning of "Independence"

1. An audit committee member is independent if he or she has no direct or indirect material relationship with Pengrowth.

2. For the purposes of paragraph 1, a "material relationship" is a relationship which could, in the view of the Board, be reasonably expected to interfere with the exercise of a member's independent judgment.

3. Despite paragraph 2, the following individuals are considered to have a material relationship with Pengrowth:

(a) an individual who is, or has been within the last three years, an employee or executive officer of Pengrowth;

(b) an individual whose immediate family member is, or has been within the last three years, an executive officer of Pengrowth;

(c) an individual who:

i. is a partner of a firm that is Pengrowth's internal or external auditor,

ii. is an employee of that firm, or

iii. was within the last three years a partner or employee of that firm and personally worked on Pengrowth's audit within that time;

(d) an individual whose spouse, minor child or stepchild, or child or stepchild who shares a home with the individual:

i. is a partner of a firm that is Pengrowth's internal or external auditor,

ii. is an employee of that firm and participates in its audit, assurance or tax compliance (but not tax planning) practice, or

iii. was within the last three years a partner or employee of that firm and personally worked on Pengrowth's audit within that time;

(e) an individual who, or whose immediate family member, is or has been within the last three years, an executive officer of an entity if any of Pengrowth's current executive officers serves or served at that same time on the entity's compensation committee; and

(f) an individual who received, or whose immediate family member who is employed as an executive officer of Pengrowth received, more than $75,000 in direct compensation from Pengrowth during any 12 month period within the last three years.

4. For the purposes of paragraphs 3(c) and 3(d), a partner does not include a fixed income partner whose interest in the firm that is the internal or external auditor is limited to the receipt of fixed amounts of compensation (including deferred compensation) for prior service with that firm if the compensation is not contingent in any way on continued service.

5. For the purposes of paragraph 3(f), direct compensation does not include

(a) remuneration for acting as a member of the Board or of any committee of the Board, and

(b) the receipt of fixed amounts of compensation under a retirement plan (including deferred compensation) for prior service with Pengrowth if the compensation is not contingent in any way on continued service.

6. Despite paragraph 3, an individual will not be considered to have a material relationship with Pengrowth solely because the individual or his or her immediate family member

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(a) has previously acted as an interim chief executive officer of Pengrowth, or

(b) acts, or has previously acted, as a chair or vice-chair of the Board or of any committee of the Board on a part-time basis.

7. For the purpose of paragraph 3, "Pengrowth" includes all of its subsidiary entities.

8. Despite any determination made under paragraphs 3 through 7 above, an individual who

(a) accepts, directly or indirectly, any consulting, advisory or other compensatory fee from Pengrowth or any subsidiary entity of Pengrowth, other than as remuneration for acting in his or her capacity as a member of the Board or any Board committee, or as a part-time chair or vice-chair of the Board or any Board committee; or

(b) is an affiliated entity of Pengrowth or any of its subsidiary entities,

is considered to have a material relationship with Pengrowth.

9. For the purposes of paragraph 8, the indirect acceptance by an individual of any consulting, advisory or other compensatory fee includes acceptance of a fee by

(a) an individual's spouse, minor child or stepchild, or a child or stepchild who shares the individual's home; or

(b) an entity in which such individual is a partner, member, an officer such as a managing director occupying a comparable position or executive officer, or occupies a similar position (except limited partners, non-managing members and those occupying similar positions who, in each case, have no active role in providing services to the entity) and which provides accounting, consulting, legal, investment banking or financial advisory services to Pengrowth or any subsidiary entity of Pengrowth.

10. For the purposes of paragraph 8, compensatory fees do not include the receipt of fixed amounts of compensation under a retirement plan (including deferred compensation) for prior service with Pengrowth if the compensation is not contingent in any way on continued service.

Standard of "Financial Literacy"

An individual is financially literate if he or she has the ability to read and understand a set of financial statements that present a breadth and level of complexity of accounting issues that are generally comparable to the breadth and complexity of the issues that can reasonably be expected to be raised by Pengrowth's financial statements.

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Schedule "B"

Excerpts from Rule 10A-3 of the Securities and Exchange Act of 1934

Standard of "Independence"

b.    Required standards.

1.    Independence.

i. Each member of the audit committee must be a member of the board of directors of the listed issuer, and must otherwise be independent; provided that, where a listed issuer is one of two dual holding companies, those companies may designate one audit committee for both companies so long as each member of the audit committee is a member of the board of directors of at least one of such dual holding companies.

ii. Independence requirements for non-investment company issuers. In order to be considered to be independent for purposes of this paragraph (b)(1), a member of an audit committee of a listed issuer that is not an investment company may not, other than in his or her capacity as a member of the audit committee, the board of directors, or any other board committee:

A. Accept directly or indirectly any consulting, advisory, or other compensatory fee from the issuer or any subsidiary thereof, provided that, unless the rules of the national securities exchange or national securities association provide otherwise, compensatory fees do not include the receipt of fixed amounts of compensation under a retirement plan (including deferred compensation) for prior service with the listed issuer (provided that such compensation is not contingent in any way on continued service); or

B. Be an affiliated person of the issuer or any subsidiary thereof.

e. Definitions. Unless the context otherwise requires, all terms used in this section have the same meaning as in the Act. In addition, unless the context otherwise requires, the following definitions apply for purposes of this section:

1.

i. The term affiliate of, or a person affiliated with, a specified person, means a person that directly, or indirectly through one or more intermediaries, controls, or is controlled by, or is under common control with, the person specified.

ii.    

A. A person will be deemed not to be in control of a specified person for purposes of this section if the person:

1. Is not the beneficial owner, directly or indirectly, of more than 10% of any class of voting equity securities of the specified person; and

2. Is not an executive officer of the specified person.

B. Paragraph (e)(1)(ii)(A) of this section only creates a safe harbor position that a person does not control a specified person. The existence of the safe harbor does not create a presumption in any way that a person exceeding the ownership requirement in paragraph (e)(1)(ii)(A)(1) of this section controls or is otherwise an affiliate of a specified person.

iii. The following will be deemed to be affiliates:

A.    An executive officer of an affiliate;

B.    A director who also is an employee of an affiliate;

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C.    A general partner of an affiliate; and

D.    A managing member of an affiliate.

iv. For purposes of paragraph (e)(1)(i) of this section, dual holding companies will not be deemed to be affiliates of or persons affiliated with each other by virtue of their dual holding company arrangements with each other, including where directors of one dual holding company are also directors of the other dual holding company, or where directors of one or both dual holding companies are also directors of the businesses jointly controlled, directly or indirectly, by the dual holding companies (and, in each case, receive only ordinary-course compensation for serving as a member of the board of directors, audit committee or any other board committee of the dual holding companies or any entity that is jointly controlled, directly or indirectly, by the dual holding companies).

4. The term control (including the terms controlling, controlled by and under common control with) means the possession, direct or indirect, of the power to direct or cause the direction of the management and policies of a person, whether through the ownership of voting securities, by contract, or otherwise.

8. The term indirect acceptance by a member of an audit committee of any consulting, advisory or other compensatory fee includes acceptance of such a fee by a spouse, a minor child or stepchild or a child or stepchild sharing a home with the member or by an entity in which such member is a partner, member, an officer such as a managing director occupying a comparable position or executive officer, or occupies a similar position (except limited partners, non-managing members and those occupying similar positions who, in each case, have no active role in providing services to the entity) and which provides accounting, consulting, legal, investment banking or financial advisory services to the issuer or any subsidiary of the issuer.

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Schedule "C"

Excerpts from Section 303A.00 of the New York Stock Exchange Listed Company Manual

303A.02 "Independence" Tests

The NYSE Listed Company Manual contains the following provisions regarding the independence requirements of members of the audit committee:

(a) (i)    No director qualifies as "independent" unless the board of directors affirmatively determines that the director has no material relationship with the listed company (either directly or as a partner, shareholder or officer of an organization that has a relationship with the company).

(ii) In addition, in affirmatively determining the independence of any director who will serve on the compensation committee of the listed company's board of directors, the board of directors must consider all factors specifically relevant to determining whether a director has a relationship to the listed company which is material to that director's ability to be independent from management in connection with the duties of a compensation committee member, including, but not limited to:

(A) the source of compensation of such director, including any consulting, advisory or other compensatory fee paid by the listed company to such director; and

(B) whether such director is affiliated with the listed company, a subsidiary of the listed company or an affiliate of a subsidiary of the listed company.

(b) In addition, a director is not independent if:

(i) The director is, or has been within the last three years, an employee of the listed company, or an immediate family member is, or has been within the last three years, an executive officer, of the listed company.

(ii) The director has received, or has an immediate family member who has received, during any twelve-month period within the last three years, more than $120,000 in direct compensation from the listed company, other than director and committee fees and pension or other forms of deferred compensation for prior service (provided such compensation is not contingent in any way on continued service).

(iii) (A) The director is a current partner or employee of a firm that is the listed company's internal or external auditor; (B) the director has an immediate family member who is a current partner of such a firm; (C) the director has an immediate family member who is a current employee of such a firm and personally works on the listed company's audit; or (D) the director or an immediate family member was within the last three years a partner or employee of such a firm and personally worked on the listed company's audit within that time.

(iv) The director or an immediate family member is, or has been within the last three years, employed as an executive officer of another company where any of the listed company's present executive officers at the same time serves or served on that company's compensation committee.

(v) The director is a current employee, or an immediate family member is a current executive officer, of a company that has made payments to, or received payments from, the listed company for property or services in an amount which, in any of the last three fiscal years, exceeds the greater of $1 million, or 2% of such other company's consolidated gross revenues.

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General Commentary to Section 303A.02(b):

An "immediate family member" includes a person's spouse, parents, children, siblings, mothers and fathers-in-law, sons and daughters-in-law, brothers and sisters-in-law, and anyone (other than domestic employees) who shares such person's home. When applying the look-back provisions in Section 303A.02(b), listed companies need not consider individuals who are no longer immediate family members as a result of legal separation or divorce, or those who have died or become incapacitated.

In addition, references to the "listed company" or "company" include any parent or subsidiary in a consolidated group with the listed company or such other company as is relevant to any determination under the independent standards set forth in this Section 303A.02(b).

For purposes of Section 303A, the term "executive officer" has the same meaning specified for the term "officer" in Rule 16a-1(f) under the Securities Exchange Act of 1934 as follows:

The term "officer" shall mean an issuer's president, principal financial officer, principal accounting officer (or, if there is no such accounting officer, the controller), any vice-president of the issuer in charge of a principal business unit, division or function (such as sales, administration or finance), any other officer who performs a policy-making function, or any other person who performs similar policy-making functions for the issuer. Officers of the issuer's parent(s) or subsidiaries shall be deemed officers of the issuer if they perform such policy-making functions for the issuer. In addition, when the issuer is a limited partnership, officers or employees of the general partner(s) who perform policy-making functions for the limited partnership are deemed officers of the limited partnership. When the issuer is a trust, officers or employees of the trustee(s) who perform policy-making functions for the trust are deemed officers of the trust.

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EX-99.2

MANAGEMENT’S DISCUSSION & ANALYSIS

The following Management’s Discussion and Analysis ("MD&A") of financial results should be read in conjunction with the audited Consolidated Financial Statements for the year ended December 31, 2017 of Pengrowth Energy Corporation ("Pengrowth" or the "Corporation"). This MD&A is based on information available to February 28, 2018.

Pengrowth’s fourth quarter and annual results for 2017 are contained within this MD&A.

BUSINESS OF THE CORPORATION

Pengrowth is a Canadian resource company that is engaged in the production, development, exploration and acquisition of oil and natural gas assets. The financial and operating results from divested properties are included in Pengrowth’s results up to the month-end nearest the date of closing for each disposition.

FREQUENTLY RECURRING TERMS

Pengrowth uses the following frequently recurring industry terms in this MD&A: "bbls" refers to barrels, "bbl/d" refers to barrels per day, "Mbbls" refers to thousands of barrels, "boe" refers to barrels of oil equivalent, "boe/d" refers to barrels of oil equivalent per day, "Mboe"refers to thousand boe, "MMboe" refers to million boe, "Mcf" refers to thousand cubic feet, "Mcf/d" refers to thousand cubic feet per day, "MMcf" refers to million cubic feet, "Bcf" refers to billion cubic feet, "MMBtu" refers to million British thermal units, "MMBtu/d" refers to million British thermal units per day, "MW" refers to megawatt, "MWh" refers to megawatt hour, "WTI" refers to West Texas Intermediate crude oil price, "WCS" refers to Western Canadian Select crude oil price, "AECO" refers to Alberta natural gas price point, "NYMEX" refers to New York Mercantile Exchange, "NGI Chicago" refers to Chicago natural gas price point and "AESO" refers to Alberta power price point, "CO2" refers to carbon dioxide which is a gas at room temperature and pressure, "SAGD" refers to steam assisted gravity drainage, "diluent" refers to a hydrocarbon based diluting agent required to facilitate the transportation of bitumen, "dilbit" or "diluted bitumen" refers to diluent blended with bitumen. Disclosure provided herein in respect of a boe may be misleading, particularly if used in isolation. A boe conversion ratio of six Mcf of natural gas to one barrel of crude oil equivalent is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

ADVISORY REGARDING FORWARD-LOOKING STATEMENTS

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

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

PENGROWTH 2017 Management's Discussion and Analysis 1

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

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

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

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

CRITICAL ACCOUNTING ESTIMATES

The audited Consolidated Financial Statements are prepared in accordance with IFRS. The preparation of these Consolidated Financial Statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingencies at the date of the audited Consolidated Financial Statements and revenues and expenses during the reporting period. Actual results could differ from those estimated.

In particular, information about significant areas of estimation uncertainty and critical judgments in applying accounting policies that have the most significant effect on the amounts recognized in the audited Consolidated Financial Statements is described below:

Estimating oil and gas reserves

Pengrowth engages a qualified, independent oil and gas reserves evaluator to perform an estimation of the Corporation’s oil and gas reserves at least annually and contingent resources on an ad hoc basis. Reserves form the basis for the calculation of depletion charges, while oil and gas reserves and contingent resources are used in the assessment of impairment of goodwill and oil and gas assets. Reserves and contingent resources are estimated using the reserve definitions and guidelines prescribed by National Instrument 51-101 (“NI 51-101”) and the Canadian Oil and Gas Evaluation Handbook (“COGEH”).

Proved plus probable reserves are defined as the "best estimate" of quantities of oil, natural gas and related substances estimated to be commercially recoverable from known accumulations, from a given date forward, based on drilling, geological, geophysical and engineering data, the use of established technology and specified economic conditions. It is equally likely that the actual remaining quantities recovered will be greater than or less than the sum of the estimated proved plus probable reserves. The estimates are made using all available geological and reservoir data as well as

PENGROWTH 2017 Management's Discussion and Analysis 2

historical production data. Estimates are reviewed and revised as appropriate. Revisions occur as a result of changes in prices, costs, fiscal regimes and reservoir performance or a change in Pengrowth's plans with respect to future development or operating practices.

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

Determination of Cash Generating Units ("CGUs")

CGUs are the smallest group of assets that generate cash inflows from continuing use that are largely independent of the cash inflows of other assets or groups of assets. The recoverability of development and production asset carrying values are assessed at the CGU level. Determination of what constitutes a CGU is subject to management’s judgment. The asset composition of a CGU can directly impact the recoverability of the assets included therein. In assessing the recoverability of oil and gas properties, each CGU’s carrying value is compared to its recoverable amount, defined as the greater of fair value less costs to sell and value in use.

Asset Retirement Obligations

Pengrowth estimates obligations under environmental regulations in respect of decommissioning and site restoration. These obligations are determined based on the expected present value of expenses required in the process of plugging and abandoning wells, dismantling of wellheads, production and transportation facilities and restoration of producing areas in accordance with relevant legislation, discounted from the date when expenses are expected to be incurred. Most of the abandonment of Pengrowth's wells is estimated to take place far in the future. Therefore, changes in estimated timing of future expenses, estimated logistics of performing abandonment work, the inflation assumption, and the discount rate used to present value future expenses could have a significant effect on the carrying amount of the decommissioning provision. Pengrowth uses the 30 year Canadian Government long term bond rate to estimate its ARO discount rate.

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

Impairment testing

CGUs are tested for impairment when there is an indication of impairment. The test is based on estimates of proved plus probable reserves, production rates, oil and natural gas prices, future costs, discount rate and other relevant assumptions. Undeveloped land, contingent resources and infrastructure may also be considered. By their nature, these estimates are subject to measurement uncertainty and may impact the Consolidated Financial Statements of future periods.

Fair value of risk management contracts

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

Valuation of trade and other receivables, and prepayments to suppliers

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

COMPARATIVE FIGURES

Certain prior years' comparative figures have been reclassified to conform to presentation adopted in the current year.

ADOPTION OF IFRS 15

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

PENGROWTH 2017 Management's Discussion and Analysis 3

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

NON-GAAP FINANCIAL MEASURES

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

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

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

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

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

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

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

For the purposes of certain covenant calculations only, letters of credit and finance leases are incorporated in senior and total debt before working capital for covenant purposes. Total book capitalization is the sum of senior debt before working capital for covenant purposes and shareholders' equity.

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

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

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

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

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

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

OPERATIONAL MEASURES

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

PENGROWTH 2017 Management's Discussion and Analysis 4

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

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

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

CURRENCY

All amounts are stated in Canadian dollars unless otherwise specified.

PENGROWTH 2017 Management's Discussion and Analysis 5

CORPORATE OVERVIEW

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

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

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

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

2017 ACTUAL RESULTS VS. 2017 GUIDANCE

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

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

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

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

⁽³⁾  Excludes financial commodity risk management activities.

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

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

2018 GUIDANCE

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

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

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

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

⁽³⁾  Excludes financial commodity risk management activities.

PENGROWTH 2017 Management's Discussion and Analysis 6

FINANCIAL HIGHLIGHTS

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

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

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

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

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

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

2017 Highlights:

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

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

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

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

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

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

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

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

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

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

PENGROWTH 2017 Management's Discussion and Analysis 7

Funds Flow from Operations

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

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

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

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

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

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

Net Income (Loss)

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

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

PENGROWTH 2017 Management's Discussion and Analysis 8

Adjusted Net Income (Loss)

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

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

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

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

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

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

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

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

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

PENGROWTH 2017 Management's Discussion and Analysis 9

Sensitivity of Funds Flow from Operations to Commodity Prices

The following table illustrates the sensitivity of funds flow from operations to increases in commodity prices and differentials after taking into account Pengrowth’s commodity risk management contracts and outlook on oil differentials. See Note 17 to the December 31, 2017 audited Consolidated Financial Statements for more information on Pengrowth's risk management contracts. The calculated impact on revenue/cash flow is only applicable within a limited range of the change indicated and is based on production guidance levels contained herein.

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

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

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

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

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

FINANCIAL RESOURCES AND LIQUIDITY

Debt Restructuring

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

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

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

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

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

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

PENGROWTH 2017 Management's Discussion and Analysis 10

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

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

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

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

Capital Resources

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

Debt Maturities

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

There are no term note maturities until October 2019.

Financial Covenants

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

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

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

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

PENGROWTH 2017 Management's Discussion and Analysis 11

Covenant Calculation

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

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

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

Total Debt Before Working Capital Continuity

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

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

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

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

Off-Balance Sheet Financing

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

PENGROWTH 2017 Management's Discussion and Analysis 12

RESULTS OF OPERATIONS

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

CAPITAL EXPENDITURES

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

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

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

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

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

2018 Capital Program

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

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

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

PENGROWTH 2017 Management's Discussion and Analysis 13

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

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

OIL AND GAS RESERVES

Reserves - Company Interest at Forecast Prices

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

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

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

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

PRODUCTION

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

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

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

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

PENGROWTH 2017 Management's Discussion and Analysis 14

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

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

COMMODITY PRICES

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

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

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

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

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

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

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

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

PENGROWTH 2017 Management's Discussion and Analysis 15

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

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

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

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

Natural Gas Prices Excluding Realized Commodity Risk Management from Financial Contracts

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

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

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

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

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

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

PENGROWTH 2017 Management's Discussion and Analysis 16

Produced Petroleum Revenue Realizations

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

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

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

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

Realized Commodity Risk Management Gains (Losses) from Financial Contracts

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

⁽¹⁾  Includes light oil and bitumen.

Pengrowth has an active commodity risk management program which primarily uses forward price swaps to manage the exposure to commodity price fluctuations and provide a measure of stability and predictability to cash flows. Changes in the business environment are regularly monitored by management and the Board of Directors to ensure that Pengrowth's active risk management program is adequate and aligned with the long term strategic goals of the Corporation. See the Forward Contracts - Commodity Risk Management section of this document for information on the Company's forward price swaps and physical delivery contracts.

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

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

PENGROWTH 2017 Management's Discussion and Analysis 17

Changes in Fair Value of Financial Commodity Risk Management Contracts

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

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

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

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

Forward Contracts - Commodity Risk Management

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

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

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

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

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

PENGROWTH 2017 Management's Discussion and Analysis 18

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

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

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

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

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

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

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

If each commodity risk management contract was to have settled at December 31, 2017, revenue and cash flow would have been $39.8 million lower than if the risk management contracts were not in place based on the estimated fair value of the risk management contracts at period end. The $39.8 million liability was related to risk management contracts expiring within one year.

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

Realized commodity risk management gains (losses) on financial crude oil and natural gas contracts are recorded separately on the Consolidated Statements of Income (Loss) and impact cash flow at that time.

PENGROWTH 2017 Management's Discussion and Analysis 19

OIL AND GAS SALES

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

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

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

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

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

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

Price and Volume Analysis

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

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

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

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

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

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

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

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

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

PENGROWTH 2017 Management's Discussion and Analysis 20

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

ROYALTIES

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

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

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

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

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

NET OPERATING EXPENSES

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

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

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

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

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

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

PENGROWTH 2017 Management's Discussion and Analysis 21

DILUENT AND OTHER PURCHASES

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

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

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

TRANSPORTATION EXPENSES

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

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

Pengrowth incurs transportation expenses for its natural gas production once the product enters a pipeline at a title transfer point. Pengrowth also incurs transportation expenses on its oil and NGL production including sales product trucking costs and pipeline costs up to the custody transfer point. As at December 31, 2017, Pengrowth has elected to sell approximately 90 percent of its production at market points beyond the wellhead, incurring transportation costs prior to custody transfer points. The transportation expenses are dependent upon third party rates and the distance the product travels prior to changing ownership or custody.

OPERATING NETBACKS

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

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

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

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

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

PENGROWTH 2017 Management's Discussion and Analysis 22

GENERAL AND ADMINISTRATIVE EXPENSES

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

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

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

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

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

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

RESTRUCTURING COSTS

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

PENGROWTH 2017 Management's Discussion and Analysis 23

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

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

LOSS ON EXTINGUISHMENT OF DEBT

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

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

DEPLETION, DEPRECIATION, AMORTIZATION AND ACCRETION

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

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

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

EXPLORATION AND EVALUATION ASSETS ("E&E")

Pengrowth's E&E assets consist of exploration and development projects which are pending the determination of proved plus probable reserves and production.

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

PENGROWTH 2017 Management's Discussion and Analysis 24

IMPAIRMENTS

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

PP&E Impairments

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

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

E&E Impairments

For the year ended December 31, 2017, Pengrowth evaluated Groundbirch gas property for an impairment in conjunction with the Montney CGU, comprising both PP&E and E&E assets, due to the negative impact resulting from the significant downturn in the forward natural gas benchmark prices late in 2017. This was in accordance with Pengrowth's policy and IFRS which states that the impairment of ongoing E&E projects should be assessed on the cash flow from the applicable CGUs in the operating segment. It was determined that the recoverable amount was below the carrying amount, thus a $129.0 million impairment on the Groundbirch E&E asset was recorded in the fourth quarter of 2017. In addition, a $1.0 million impairment was recognized on other minor E&E projects as no further exploration or evaluation is intended on those projects.

The recoverable amount is generally computed by reference to the present value of the future cash flows expected to be derived from production of proved plus probable reserves for the operating segment. Contingent resources were also considered in the recoverable amount. Changes in forward price estimates, production costs or recovery rates may change the economic status of contingent resources and may ultimately result in contingent resources being restated. The Groundbirch E&E impairment test was based on reserve values using a pre-tax discount rate of 10 percent for proven reserves and 12 percent for probable reserves; independent reserves evaluator January 1, 2018 forecast pricing and an inflation rate of 2 percent; and contingent resources using a pre-tax discount rate of 15 percent. The recoverable amount was determined using value in use. See Note 6 to the December 31, 2017 audited Consolidated Financial Statements for more information.

INTEREST AND FINANCING CHARGES

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

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

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

PENGROWTH 2017 Management's Discussion and Analysis 25

In accordance with IFRS, interest is capitalized for qualifying assets in the construction phase based on costs incurred on the project and the average cost of borrowing. During the twelve months ended December 31, 2017, $3.7 million (December 31, 2016 - $3.0 million) of interest was capitalized on the Lindbergh project to PP&E using Pengrowth's weighted average cost of debt of 5.7 percent (December 31, 2016 - 5.7 percent).

OTHER (INCOME) EXPENSE

Full year 2017 other income of $7.4 million, represented an increase of $4.7 million from 2016. The increase is primarily due to receiving an insurance settlement, higher investment income on remediation trust funds and interest income.

TAXES

Deferred income tax is a non-cash item relating to temporary differences between the accounting and tax basis of Pengrowth’s assets and liabilities and has no immediate impact on Pengrowth’s cash flows. Pengrowth recorded a deferred tax recovery of $57.6 million in the fourth quarter of 2017 compared to a deferred tax recovery of $9.9 million in the fourth quarter of 2016. This was primarily due to the temporary differences related to PP&E impairment charges and temporary differences related to asset dispositions that closed in 2017. Full year 2017 deferred tax recovery amounted to $223.8 million compared to a recovery of $93.4 million in 2016 driven by the above mentioned temporary differences.

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

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

FOREIGN CURRENCY GAINS (LOSSES)

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

⁽¹⁾  Includes both principal and interest.

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

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

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

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

PENGROWTH 2017 Management's Discussion and Analysis 26

of the gains and losses is proportionate to the magnitude of the exchange rate fluctuation between the opening and closing rates for the respective periods and the amount of debt denominated in a foreign currency.

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

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

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

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

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

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

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

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

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

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

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

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

Foreign Denominated Term Debt Sensitivity to Foreign Exchange Rate

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

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

PENGROWTH 2017 Management's Discussion and Analysis 27

ASSET RETIREMENT OBLIGATIONS - NET PRESENT VALUE

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

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

The total future ARO is based on management’s estimate of costs to remediate, reclaim and abandon wells and facilities having regard for Pengrowth’s working interest and the estimated timing of the costs to be incurred in future periods. Pengrowth has developed an internal process to calculate these estimates which considers applicable regulations, actual and anticipated costs, type and size of well or facility and the geographic location.

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

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

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

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

REMEDIATION TRUST FUNDS AND REMEDIATION AND ABANDONMENT EXPENSE

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

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

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

PENGROWTH 2017 Management's Discussion and Analysis 28

Pengrowth takes a proactive approach to managing its well abandonment and site restoration obligations. There is an on-going program to abandon wells and reclaim well and facility sites. In 2017, Pengrowth spent $15.9 million on abandonment and reclamation (December 31, 2016 - $20.0 million). Pengrowth expects to spend approximately $29.9 million in 2018 on abandonment and reclamation activities, excluding contributions to remediation trust funds and orphan well levies from the Alberta Energy Regulator. Over 80 percent of the planned spending in 2018 relates to SOEP and will be recovered from the remediation trust fund.

CLIMATE CHANGE PROGRAMS

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

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

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

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

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

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

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

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

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

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

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

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

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

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

PENGROWTH 2017 Management's Discussion and Analysis 29

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

ACQUISITIONS AND DISPOSITIONS

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

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

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

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

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

WORKING CAPITAL

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

FINANCIAL INSTRUMENTS

Pengrowth uses financial instruments to manage its exposure to commodity and power price fluctuations and foreign currency exposure. Pengrowth’s policy is not to utilize financial instruments for trading or speculative purposes. See Note 2 to the December 31, 2017 audited Consolidated Financial Statements for a description of the accounting policies for financial instruments and Note 17 to the December 31, 2017 audited Consolidated Financial Statements for additional information regarding the fair value of Pengrowth’s financial instruments.

PENGROWTH 2017 Management's Discussion and Analysis 30

SUMMARY OF QUARTERLY RESULTS

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

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

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

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

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

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

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

⁽⁷⁾  Includes realized commodity risk management.

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

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

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

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

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

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

PENGROWTH 2017 Management's Discussion and Analysis 31

SELECTED ANNUAL INFORMATION

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

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

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

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

COMMITMENTS AND CONTRACTUAL OBLIGATIONS

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

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

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

⁽³⁾  Includes office rent and other commitments.

PENGROWTH 2017 Management's Discussion and Analysis 32

BUSINESS RISKS

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

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

Risks associated with Commodity Prices

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

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

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

Risks associated with Liquidity

• Capital markets may restrict Pengrowth’s access to capital and raise its cost of capital and borrowing costs. To the extent that external sources of capital become limited or cost prohibitive, Pengrowth’s ability to fund future development and acquisition opportunities and to repay or refinance indebtedness when due may be impaired.

• Pengrowth is exposed to third party credit risk through its oil and gas sales, financial hedging transactions and joint venture activities. The failure of any counterparties to meet their contractual obligations could adversely impact Pengrowth.

• Changing interest rates influence borrowing costs and the availability of capital.

• Failing a financial covenant may result in one or more of Pengrowth’s loans being in default. In most circumstances, being in default of one loan will result in other loans also being in default and restrict access to the Credit Facility. If an event of non-compliance occurs and cannot be remedied during an applicable remedy period, if any, Pengrowth would have to repay the relevant debt, refinance the debt or negotiate new terms with the debt holders.

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

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

Risks associated with Legislation and Regulatory Changes

• Government royalties, income taxes, commodity and other taxes, levies, fees and any audits may have a significant economic impact on Pengrowth’s financial results. Changes to federal and provincial legislation governing such royalties, taxes and fees could have a material impact on Pengrowth’s financial results and the value of Pengrowth’s common shares.

• Environmental laws and regulatory initiatives impact Pengrowth financially and operationally. We may incur substantial capital and operating expenses to comply with increasingly complex laws and regulations covering the protection of the environment and human health and safety. In particular, Pengrowth may be required to incur significant costs to comply with future regulations to reduce greenhouse gas and other emissions.

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

PENGROWTH 2017 Management's Discussion and Analysis 33

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

Risks associated with Operations

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

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

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

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

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

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

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

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

• Delays in business operations could adversely affect the market price of the common shares.

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

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

• Actual production and reserves will vary from estimates, and those variations could be material and may negatively affect the market price of the common shares.

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

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

• The performance and results of a thermal project such as Lindbergh is dependent on the ability of the steam to access the reservoir and efficiently move additional bitumen that would otherwise remain trapped within the reservoir rock. The amount and cost of steam required, the additional oil recovered, the quality of the oil produced, the ability to recycle produced water into steam and the ability to manage costs will determine the economic viability for a thermal project.

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

Risks associated with Strategy

• Capital re-investment on Pengrowth's existing assets may not yield the expected benefits and related value creation. Drilling opportunities may prove to be more costly or less productive than anticipated.

PENGROWTH 2017 Management's Discussion and Analysis 34

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

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

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

Asset Concentration Risks

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

Foreign Currency Risk

• Pengrowth has substantial exposure to the U.S. dollar. Any decrease in the Canadian dollar relative to the U.S. dollar results in an increase in the Canadian dollar equivalent of Pengrowth’s U.S. dollar denominated term debt as Pengrowth reports and prepares its covenant calculations in Canadian dollars. A significant decrease in the value of the Canadian dollar relative to the U.S. dollar could cause Pengrowth to be in violation of its debt covenants resulting in Pengrowth being in default under its borrowing agreements.

General Business Risks

• Investors’ interest in the oil and gas sector change over time which affects the availability of capital and the value of Pengrowth common shares.

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

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

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

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

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

PENGROWTH 2017 Management's Discussion and Analysis 35

ACCOUNTING PRONOUNCEMENTS ADOPTED

IFRS 15 Revenue from Contracts with Customers

On May 28, 2014, the IASB issued IFRS 15 Revenue from Contracts with Customers ("IFRS 15"). The new standard is effective for annual periods beginning on or after January 1, 2018. Earlier application is permitted. On April 12, 2016, the IASB issued Clarification to IFRS 15, which is effective at the same time as IFRS 15. The standard contains a single model that applies to contracts with customers and two approaches to recognizing revenue: at a point in time or over time. The model features a contract-based five-step analysis of transactions to determine the nature of an entity's obligation to perform and whether, how much and when revenue is recognized. New estimates and judgmental thresholds have been introduced, which may affect the amount and/or timing of revenue recognized. The new standard applies to contracts with customers. It does not apply to insurance contracts, financial instruments or lease contracts, which fall in the scope of other IFRSs.

Pengrowth has elected in the fourth quarter of 2017 to early adopt IFRS 15 for 2017 using the cumulative effect method. Under this method, prior years' financial statements have not been restated and the cumulative effect on net earnings of the application of IFRS 15 to revenue contracts in progress at January 1, 2017 is nil. Pengrowth management reviewed its revenue streams and major contracts with customers using the IFRS 15 five step model and there were no material changes to net earnings or timing of produced petroleum revenue recognized. It should be noted, however, that certain Income Statement line item reclassifications were made. See Notes 2 and 14 to the December 31, 2017 audited Consolidated Financial Statements for more information including additional disclosure as required under IFRS 15.

Disclosure Initiative Amendments to IAS 7

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

ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED

IFRS 9 Financial Instruments

In July 2014, the IASB issued the complete IFRS 9 ("IFRS 9 (2014)"). The mandatory effective date of IFRS 9 is for annual periods beginning on or after January 1, 2018 and must be applied retrospectively with some exemptions. Early adoption is permitted. The restatement of prior periods is not required and is only permitted if information is available without the use of hindsight. IFRS 9 (2014) introduces new requirements for the classification and measurement of financial assets. Under IFRS 9 (2014), financial assets are classified and measured based on the business model in which they are held and the characteristics of their contractual cash flows. The standard introduces additional changes relating to financial liabilities. It also amends the impairment model by introducing a new ‘expected credit loss’ model for calculating impairment. Pengrowth does not anticipate material changes in the carrying value of its financial instruments nor from the credit loss impairment model upon adoption of IFRS 9 (2014).

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

IFRS 9 (2014) also includes a new general hedge accounting standard which aligns hedge accounting more closely with risk management. This new standard does not fundamentally change the types of hedging relationships or the requirement to measure and recognize ineffectiveness; however it will provide more hedging strategies that are used for risk management to qualify for hedge accounting and introduce more judgment to assess the effectiveness of a hedging relationship. Special transitional requirements have been set for the application of the new general hedging model. Pengrowth does not currently apply hedge accounting and does not currently intend to apply hedge accounting to its existing risk management contracts.

IFRS 16 Leases

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

PENGROWTH 2017 Management's Discussion and Analysis 36

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

DISCLOSURE AND INTERNAL CONTROLS

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

The CEO, Derek Evans, and the CFO, Christopher Webster, evaluated the effectiveness of Pengrowth’s disclosure controls and procedures for the year ending December 31, 2017. This evaluation considered the functions performed by its Disclosure Committee, the review and oversight of all executive officers and the Board, as well as the process and systems in place for filing regulatory and public information. Pengrowth’s established review process and disclosure controls are designed to provide reasonable assurance that all required information, reports and filings required under Canadian securities legislation and United States securities laws are properly submitted and recorded in accordance with those requirements.

Based on that evaluation, the CEO and CFO concluded that the design and operation of Pengrowth's disclosure controls and procedures were effective at the reasonable assurance level as at December 31, 2017, to ensure that information required to be disclosed by us in reports that we file under Canadian and U.S. securities laws is gathered, recorded, processed, summarized and reported within the time periods specified under Canadian and U.S. securities laws and is accumulated and communicated to the management of Pengrowth Energy Corporation, including the CEO and CFO, to allow timely decisions regarding required disclosure as required under Canadian and U.S. securities laws.

It should be noted that while Pengrowth’s CEO and CFO believe that Pengrowth’s disclosure controls and procedures provide a reasonable level of assurance that they are effective, they do not expect that Pengrowth’s disclosure controls and procedures or internal control over financial reporting will prevent all errors and fraud. A control system, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met.

INTERNAL CONTROL OVER FINANCIAL REPORTING

Pengrowth's management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended and in Canada as defined in Multilateral Instrument 52-109 - Certification of Disclosure in Issuers’ Annual and Interim Filings. Pengrowth's internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of Pengrowth's financial reporting and the preparation of Pengrowth's Consolidated Financial Statements for external purposes in accordance with IFRS for note disclosure purposes. Pengrowth's internal control over financial reporting includes those policies and procedures that: pertain to the maintenance of records that in reasonable detail accurately and fairly reflect Pengrowth's transactions and disposition of the assets; provide reasonable assurance that transactions are recorded as necessary to permit preparation of Pengrowth's Consolidated Financial Statements in accordance with IFRS and that receipts and expenditures of Pengrowth's assets are being made only in accordance with authorizations of Pengrowth's management and directors; and provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of Pengrowth's assets that could have a material effect on Pengrowth's Consolidated Financial Statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Pengrowth's management, with the participation of Pengrowth's principal executive officer and principal financial officer, evaluated the effectiveness of Pengrowth's internal control over financial reporting as of December 31, 2017. In making this evaluation, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) in Internal Control-Integrated Framework (2013).

PENGROWTH 2017 Management's Discussion and Analysis 37

Based on Pengrowth's evaluation, management concluded that Pengrowth's internal control over financial reporting was effective as at December 31, 2017.

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

PENGROWTH 2017 Management's Discussion and Analysis 38

EX-99.3

MANAGEMENT'S REPORT TO SHAREHOLDERS

Management’s Responsibility to Shareholders

The Consolidated Financial Statements and the notes to the Consolidated Financial Statements are the responsibility of the management of Pengrowth Energy Corporation. They have been prepared in accordance with International Financial Reporting Standards ("IFRS") as issued by the International Accounting Standards Board which have been adopted in Canada. Financial information that is presented in the Management Discussion and Analysis is consistent with the Consolidated Financial Statements.

In preparation of these statements, estimates are sometimes necessary because a precise determination of certain assets and liabilities is dependant on future events. Management believes such estimates have been based on careful judgments and have been properly reflected in the accompanying Consolidated Financial Statements.

Management is responsible for the reliability and integrity of the Consolidated Financial Statements, the notes to the Consolidated Financial Statements, and other financial information contained in this report. In order to ensure that management fulfills its responsibilities for financial reporting, we have established an organizational structure that provides appropriate delegation of authority, division of responsibilities, and selection and training of properly qualified personnel. Management is also responsible for the development of internal controls over the financial reporting process.

The Board of Directors ("the Board") is assisted in exercising its responsibilities through the Audit and Risk Committee ("the Committee") of the Board, which is composed of four independent directors. The Committee meets regularly with management and the independent auditors to satisfy itself that management’s responsibilities are properly discharged, to review the Consolidated Financial Statements and to recommend approval of the Consolidated Financial Statements to the Board.

KPMG LLP, the independent auditors appointed by the shareholders, have audited Pengrowth Energy Corporation’s Consolidated Financial Statements in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States) and provided an independent professional opinion. The auditors have full and unrestricted access to the Committee to discuss the audit and their related findings as to the integrity of the financial reporting process.

Derek W. Evans	Christopher G. Webster
President and Chief Executive Officer	Chief Financial Officer

February 28, 2018

PENGROWTH 2017 Financial Results 1

KPMG LLP

205 5th Avenue SW

Suite 3100

Calgary AB

T2P 4B9

Telephone (403) 691-8000

Fax (403) 691-8008

www.kpmg.ca

INDEPENDENT AUDITORS’ REPORT OF REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholders and Directors of Pengrowth Energy Corporation

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated financial statements of Pengrowth Energy Corporation, which comprise the consolidated balance sheets as at December 31, 2017 and December 31, 2016, the consolidated statements of income (loss), consolidated statements of cash flow and statements of consolidated shareholders’ equity for the years then ended, and the related notes, comprising a summary of significant accounting policies and other explanatory information (collectively referred to as the “consolidated financial statements”).

In our opinion, the consolidated financial statements present fairly, in all material respects, the consolidated financial position of Pengrowth Energy Corporation as at December 31, 2017 and December 31, 2016, and its consolidated financial performance and its consolidated cash flows for the years then ended in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board.

Change in Accounting Policy

Without qualifying our opinion on the financial statements, we draw attention to Notes 2 and 14 to the financial statements, which indicates that the Company has changed its method of accounting for revenue in 2017, due to adoption of IFRS 15 Revenue from Contracts with Customers.

Report on Internal Control over Financial Reporting

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Pengrowth Energy Corporation’s internal control over financial reporting as of December 31, 2017, based on the criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 28, 2018 expressed an unmodified (unqualified) opinion on the effectiveness of Pengrowth Energy Corporation’s internal control over financial reporting.

Basis for Opinion

A - Management’s Responsibility for the Consolidated Financial Statements

Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board, and for such internal control as management determines is necessary to enable the preparation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.

KPMG LLP is a Canadian limited liability partnership and a member firm of the KPMG network of independent member firms affiliated with KPMG International Cooperative (“KPMG International”), a Swiss entity. KPMG Canada provides services to KPMG LLP.

PENGROWTH 2017 Financial Results 2

B - Auditors’ Responsibility

Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement, whether due to error or fraud. Those standards also require that we comply with ethical requirements, including independence. We are required to be independent with respect to Pengrowth Energy Corporation in accordance with the ethical requirements that are relevant to our audit of the consolidated financial statements in Canada, the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and PCAOB. We are a public accounting firm registered with the PCAOB.

An audit includes performing procedures to assess the risks of material misstatements of the consolidated financial statements, whether due to error or fraud, and performing procedures to respond to those risks. Such procedures included obtaining and examining, on a test basis, audit evidence regarding the amounts and disclosures in the consolidated financial statements. The procedures selected depend on our judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, we consider internal control relevant to the entity’s preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances.

An audit also includes evaluating the appropriateness of accounting policies and principles used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements.

We believe that the audit evidence we have obtained in our audits is sufficient and appropriate to provide a basis for our audit opinion.

Chartered Professional Accountants

We have served as Pengrowth Energy Corporation’s auditor since 1988.

Calgary, Canada

February 28, 2018

PENGROWTH 2017 Financial Results 3

KPMG LLP

205 5th Avenue SW

Suite 3100

Calgary AB

T2P 4B9

Telephone (403) 691-8000

Fax (403) 691-8008

www.kpmg.ca

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholders of Pengrowth Energy Corporation

Opinion on Internal Control Over Financial Reporting

We have audited Pengrowth Energy Corporation’s (the “Corporation”) internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

In our opinion, the Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017, based on the criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

Report on the Consolidated Financial Statements

We also have audited, in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated financial statements of the Corporation, which comprise the consolidated statements of financial position of Pengrowth Energy Corporation as at December 31, 2017 and December 31, 2016, and its consolidated financial performance and its consolidated cash flows for the years then ended, and the related notes, comprising a summary of significant accounting policies and other explanatory information (collectively referred to as the “consolidated financial statements”), and our report dated February 28, 2018 expressed an unmodified (unqualified) opinion on those consolidated financial statements.

Basis for Opinion

The Corporation’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB and in accordance with the ethical requirements that are relevant to our audit of the financial statements in Canada.

KPMG LLP is a Canadian limited liability partnership and a member firm of the KPMG network of independent member firms affiliated with KPMG International Cooperative (“KPMG International”), a Swiss entity. KPMG Canada provides services to KPMG LLP.

PENGROWTH 2017 Financial Results 4

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control Over Financial Reporting

A Corporation’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Chartered Professional Accountants

February 28, 2018

Calgary, Canada

PENGROWTH 2017 Financial Results 5

PENGROWTH ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS

(Stated in millions of Canadian dollars)

		As at			As at
		December 31, 2017			December 31, 2016
	Note	As adjusted *
ASSETS
Current Assets
Cash and cash equivalents		$	1.1		$	286.7
Accounts receivable		105.7			126.6
Fair value of risk management contracts	17	—			2.9
Other assets	4	24.0			—
Assets held for sale	5	—			117.5
		130.8			533.7
Fair value of risk management contracts	17	1.9			1.0
Other assets	4	99.8			118.7
Property, plant and equipment	5	1,104.2			2,849.0
Exploration and evaluation assets	6	232.0			496.3
Deferred income taxes	11	342.2			118.4
TOTAL ASSETS		$	1,910.9		$	4,117.1
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Accounts payable		$	136.2		$	189.6
Fair value of risk management contracts	17	40.0			55.3
Convertible debentures	7	—			126.6
Current portion of long term debt	8	—			537.0
Current portion of provisions and other liabilities	10	35.2			22.1
		211.4			930.6
Fair value of risk management contracts	17	18.6			5.3
Long term debt	8	610.5			1,023.7
Provisions and other liabilities	10	264.2			672.5
		1,104.7			2,632.1
Shareholders' Equity
Shareholders' capital	12	4,829.7			4,815.1
Contributed surplus		13.3			22.9
Deficit		(4,036.8		)	(3,353.0		)
		806.2			1,485.0
Commitments and contingencies	19, 20
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY		$	1,910.9		$	4,117.1

* See Notes 2 and 14.

See accompanying notes to the Consolidated Financial Statements.

Approved on behalf of the Board of Directors of Pengrowth Energy Corporation

Director	Director

PENGROWTH 2017 Financial Results 6

PENGROWTH ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF INCOME (LOSS)

(Stated in millions of Canadian dollars, except per share amounts)

		Year ended December 31
		2017			2016
	Note	As adjusted *
REVENUES
Oil and gas sales	2, 14	$	673.4		$	566.2
Royalties, net of incentives		(45.8		)	(40.0		)
		627.6			526.2
Realized gain (loss) on commodity risk management	17	(19.8		)	385.7
Change in fair value of commodity risk management contracts	17	14.2			(424.5		)
		622.0			487.4
EXPENSES
Operating	2, 14	217.5			275.4
Diluent and other purchases	2, 14	163.5			—
Transportation		27.1			33.7
General and administrative		61.5			83.6
Depletion, depreciation and amortization	5	207.6			349.9
Impairment	5, 6	634.4			—
		1,311.6			742.6
OPERATING INCOME (LOSS)		(689.6		)	(255.2		)
Other (income) expense items
(Gain) loss on disposition of properties	5, 6	62.6			27.1
Unrealized foreign exchange (gain) loss	18	(51.4		)	33.4
Realized foreign exchange (gain) loss	18	38.4			(46.5		)
Interest and financing charges		70.7			105.5
Restructuring costs	10	37.0			—
Loss on extinguishment of debt	8	56.7			—
Accretion	10	11.4			15.1
Other (income) expense		(7.4		)	(2.7		)
INCOME (LOSS) BEFORE TAXES		(907.6		)	(387.1		)
Deferred income tax (recovery) expense	11	(223.8		)	(93.4		)
NET INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS)		$	(683.8	)	$	(293.7	)
NET INCOME (LOSS) PER SHARE	16
Basic		$	(1.24	)	$	(0.54	)
Diluted		$	(1.24	)	$	(0.54	)

* See Notes 2 and 14.

See accompanying notes to the Consolidated Financial Statements.

PENGROWTH 2017 Financial Results 7

PENGROWTH ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOW

(Stated in millions of Canadian dollars)

		Year ended December 31
		2017			2016
	Note	As adjusted *
CASH PROVIDED BY (USED FOR):
OPERATING
Net income (loss) and comprehensive income (loss)		$	(683.8	)	$	(293.7	)
Non-cash items
Depletion, depreciation, amortization and accretion	5, 10	219.0			365.0
Impairment	5, 6	634.4			—
Deferred income tax (recovery) expense	11	(223.8		)	(93.4		)
Unrealized foreign exchange (gain) loss	18	(51.4		)	33.4
Change in fair value of commodity risk management contracts	17	(14.2		)	424.5
Share based compensation	13	4.9			13.2
(Gain) loss on disposition of properties	5, 6	62.6			27.1
Restructuring costs - onerous office lease contracts	10	26.5			—
Other items		0.9			0.6
Loss on extinguishment of debt	8	56.7			—
Foreign exchange derivative settlements	17	37.6			(47.0		)
Funds flow from operations		69.4			429.7
Interest and financing charges		70.7			105.5
Expenditures on remediation	10	(15.9		)	(20.0		)
Change in non-cash operating working capital	15	18.2			(21.5		)
Cash flow from operating activities		142.4			493.7
FINANCING
Bank indebtedness (repayment)	8	—			(3.7		)
Long term debt (repayment)	8	(937.2		)	(104.0		)
Convertible debentures repayment	7	(126.6		)	—
Convertible debentures repurchase	7	—			(10.2		)
Foreign exchange derivative settlements	17	(37.6		)	47.0
Interest and financing charges paid		(100.8		)	(108.6		)
Cash flow from financing activities		(1,202.2		)	(179.5		)
INVESTING
Capital expenditures		(117.9		)	(64.4		)
Property acquisitions		(0.1		)	(1.3		)
Proceeds on property dispositions		910.2			60.2
Contributions to remediation trust funds and other items		(10.5		)	(29.6		)
Change in non-cash investing working capital	15	(7.5		)	7.6
Cash flow from investing activities		774.2			(27.5		)
CHANGE IN CASH AND CASH EQUIVALENTS		(285.6		)	286.7
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR		286.7			—
CASH AND CASH EQUIVALENTS AT END OF YEAR		$	1.1		$	286.7

* See Notes 2 and 14.

See accompanying notes to the Consolidated Financial Statements.

PENGROWTH 2017 Financial Results 8

PENGROWTH ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY

(Stated in millions of Canadian dollars)

		Year ended December 31
	Note	2017			2016
		As adjusted *
SHAREHOLDERS' CAPITAL	12
Balance, beginning of year		$	4,815.1		$	4,797.0
Share based compensation		14.6			18.1
Balance, end of year		4,829.7			4,815.1
CONTRIBUTED SURPLUS
Balance, beginning of year		22.9			27.3
Share based compensation	13	5.0			13.7
Exercise of share based compensation awards		(14.6		)	(18.1		)
Balance, end of year		13.3			22.9
DEFICIT
Balance, beginning of year		(3,353.0		)	(3,059.3		)
Net income (loss)		(683.8		)	(293.7		)
Balance, end of year		(4,036.8		)	(3,353.0		)
TOTAL SHAREHOLDERS' EQUITY		$	806.2		$	1,485.0

* See Notes 2 and 14.

See accompanying notes to the Consolidated Financial Statements.

PENGROWTH 2017 Financial Results 9

PENGROWTH ENERGY CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

AS AT AND FOR THE YEARS ENDED DECEMBER 31, 2017 AND 2016

(Tabular amounts are stated in millions of Canadian dollars except per share amounts and as otherwise stated)

1. BUSINESS OF THE CORPORATION

Pengrowth Energy Corporation ("Pengrowth" or the "Corporation") is a Canadian resource company that is engaged in the production, development, exploration and acquisition of oil and natural gas assets. The Consolidated Financial Statements include the accounts of the Corporation, and its subsidiary, collectively referred to as Pengrowth. All inter-entity transactions have been eliminated.

2. SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

These Consolidated Financial Statements have been prepared in accordance with the International Financial Reporting Standards (“IFRS”) issued by the International Accounting Standards Board (“IASB”) and International Financial Reporting Interpretations Committee (“IFRIC”). Except for the changes below, Pengrowth has consistently applied the accounting policies to all periods presented in these consolidated financial statements.

Pengrowth’s operations are viewed as a single operating segment by the chief operating decision maker (CEO) of the Corporation for the purpose of resource allocation and assessing performance.

The Consolidated Financial Statements were authorized for release by the Board of Directors on February 28, 2018.

Accounting Pronouncement adopted - IFRS 15 Revenue from Contracts with Customers

On May 28, 2014, the IASB issued IFRS 15 Revenue from Contracts with Customers ("IFRS 15"). The new standard is effective for annual periods beginning on or after January 1, 2018. Earlier application is permitted. On April 12, 2016, the IASB issued Clarification to IFRS 15, which is effective at the same time as IFRS 15. The standard contains a single model that applies to contracts with customers and two approaches to recognizing revenue: at a point in time or over time. The model features a contract-based five-step analysis of transactions to determine the nature of an entity's obligation to perform and whether, how much and when revenue is recognized. New estimates and judgmental thresholds have been introduced, which may affect the amount and/or timing of revenue recognized. The new standard applies to contracts with customers. It does not apply to insurance contracts, financial instruments or lease contracts, which fall in the scope of other IFRSs.

Pengrowth has elected in the fourth quarter of 2017 to early adopt IFRS 15 for 2017 using the cumulative effect method. Under this method, prior years' financial statements have not been restated and the cumulative effect on net earnings of the application of IFRS 15 to revenue contracts in progress at January 1, 2017 is nil. Pengrowth management reviewed its revenue streams and major contracts with customers using the IFRS 15 five step model and there were no material changes to net earnings or timing of produced petroleum revenue recognized. It should be noted, however, that certain Income Statement line item reclassifications were made. Refer to Note 14 for more information including additional disclosure as required under IFRS 15.

Impact of Early Adoption of IFRS 15 on Interim 2017 Financial Statements

As a result of the adoption of IFRS 15, no cumulative effect adjustment to retained earnings was required. In accordance with the new standard, effective January 1, 2017, Pengrowth includes sales of diluent and other products as well as processing income in its Oil and gas sales consistent with the application of IFRS 15 including its principal versus agent evaluation requirements. This change has no impact on operating income (loss), income (loss) before taxes, net income (loss) or Cash Flows. The adoption of IFRS 15 alters the presentation of, and calculations for, Oil and gas sales and Operating expenses, and introduces a new Income Statement line for Diluent and other purchases for 2017. As per the table below, certain amounts in 2017 unaudited interim financial statements have been adjusted as follows:

PENGROWTH 2017 Financial Results 10

	2017
	Q1	Q2	Q3
Oil and gas sales as previously reported	166.5	147.2	91.5
Diluent and other sales	46.7	45.2	28.9
Processing income	6.7	5.5	4.7
Adjusted Oil and gas sales	219.9	197.9	125.1
Diluent and other purchases as previously reported	—	—	—
Cost of diluent and other purchases	46.7	45.2	28.9
Adjusted Diluent and other purchases	46.7	45.2	28.9
Operating expenses as previously reported	60.6	63.0	46.9
Processing income	6.7	5.5	4.7
Adjusted operating expenses	67.3	68.5	51.6

Revenue Recognition

Under IFRS 15, revenue from the sale of commodities is calculated by reference to consideration specified in contracts with customers and recognized when control of the product is transferred to the buyer. The nature of each of its performance obligations, including roles of third parties and partners, are evaluated to determine if the Company acts as a principal, and therefore recognizes revenue on a gross basis, or as an agent, and therefore recognizes revenue on a net basis. The Company acts as the principal when it controls the product delivered before the control passes to its customer.

Pengrowth earns revenue from the following major sources:

• Sales from the production of, and royalty (and gross overriding royalty) interests in, light oil, natural gas, natural gas liquids, sulphur and from the sale of diluted bitumen and purchased products;

• Fees charged to third parties for processing and other services (i.e. gas and other product processing, contract operating etc.) provided at facilities where Pengrowth has an ownership interest.

Revenue from the sale of diluted bitumen, light oil, natural gas, natural gas liquids and sulphur is recognized based on the consideration specified in contracts with customers. Pengrowth recognizes revenue when control of the product transfers to the buyer and collection is reasonably assured. This is generally at the point in time when the customer obtains legal title to the product which is when it is physically transferred to the pipeline or other transportation method agreed upon. Revenues from processing activities are recognized over time as processing occurs, and are generally billed monthly. Royalty income is recognized monthly as it accrues in accordance with the terms of the royalty agreements.

Pengrowth has reviewed its revenue streams and major contracts with customers using the IFRS 15 five step model and there are no material changes to timing of revenue recognized, however the gross versus net presentation resulted in material changes to certain items in the 2017 Income Statement with no impact to net income (loss).

When allocating the transaction price realized in contracts with multiple performance obligations over a longer period to multiple performance obligations using relative standalone selling prices, management is required to make estimates of the prices at which Pengrowth would sell the product separately to customers. When making this estimate, management considers market prices and market conditions and cash flows the entity intends to realize based on risk management policies, based on cost and cash flows the entity intends to realize based on risk management policies, based on cost and margin objectives. Pengrowth does not currently have any contracts with multiple performance obligations.

Property, Plant and Equipment (“PP&E”) and Exploration and Evaluation (“E&E”) Assets

Pengrowth capitalizes all costs of developing and acquiring oil and gas properties. These costs include lease acquisition costs, geological and geophysical expenditures, costs of drilling and completion of wells, plant and production equipment costs and related overhead charges. Pengrowth capitalizes a portion of general and administrative costs and share based compensation expense associated with exploration and development activities. Repairs and maintenance costs are expensed as incurred.

PENGROWTH 2017 Financial Results 11

Property, Plant and Equipment

PP&E is stated at cost less accumulated depletion, depreciation and amortization, and accumulated impairment losses. The initial cost of an asset comprises its purchase price or construction cost, costs attributable to bringing the asset into operation, the initial estimate of asset retirement obligation and, for qualifying assets, borrowing costs. When significant parts of an item of PP&E, including oil and natural gas interests, have different useful lives, they are accounted for as separate items.

Exploration and Evaluation Assets

Costs of exploring for and evaluating certain oil and natural gas properties are capitalized within E&E assets. These E&E assets include lease acquisition costs, geological and geophysical expenditures, costs of drilling and completion of wells, plant and production equipment costs and related overhead charges. E&E assets do not include costs of general prospecting, or evaluation costs incurred prior to having obtained the legal rights to explore an area, which are expensed as incurred. Interest is not capitalized on E&E assets.

E&E assets are not depleted or depreciated and are carried forward until technical feasibility and commercial viability is considered to be determined. The technical feasibility and commercial viability is generally considered to be determined when proved plus probable reserves are determined to exist and the commercial production of oil and gas has commenced. A review of each exploration license or field is carried out, at least annually, to ascertain whether the project is technically feasible and commercially viable. Upon determination of technical feasibility and commercial viability, E&E assets attributable to those reserves are first tested for impairment and then reclassified from E&E assets to PP&E.

Subsequent Costs

Costs incurred subsequent to the determination of technical feasibility and commercial viability and the costs of replacing parts of PP&E are recognized as oil and natural gas interests only when they increase the future economic benefits embodied in the specific asset to which they relate. Such capitalized oil and natural gas interests generally represent costs incurred in developing proved and/or probable reserves and bringing in or enhancing production from such reserves, and are accumulated on a field or geotechnical area basis.

The carrying amount of any replaced or sold component is de-recognized. The costs of the day-to-day servicing of PP&E are expensed as incurred.

Pengrowth capitalizes a portion of general and administrative costs directly associated with exploration and development activities. Pengrowth capitalizes interest incurred in construction of qualifying assets, if applicable. Qualifying assets are defined by Pengrowth as capital projects that require capital expenditures over a period greater than one year, in order to produce oil or gas from a specific property. Interest capitalization to a qualifying asset ceases once the asset is substantially available for its intended use.

Assets Held for Sale

Non-current assets are classified as held for sale if their carrying amounts will be recovered through a sale transaction rather than through continuing use. This condition is met when the sale is highly probable and the asset is available for immediate sale in its present condition. For the sale to be highly probable, Management must be committed to sell the asset and an active program to locate a buyer and complete the sale must have been initiated. The asset must be actively marketed for sale at a price that is reasonable in relation to its current fair value and the sale should be expected to be completed within one year from the date of classification. Non-current assets classified as held for sale are measured at the lower of the carrying amount and fair value less costs of disposal, with impairments recognized in the Consolidated Statements of Income (Loss) in the period measured.

Dispositions

Gains or losses are recognized in the Consolidated Statements of Income (Loss) on dispositions of PP&E and certain E&E assets, including asset swaps, farm-out transactions, gross overriding royalty and property dispositions. The gain or loss is measured as the difference between the fair value of the proceeds and the carrying value of the assets disposed, including capitalized future asset retirement obligations and any associated goodwill.

Depletion and Depreciation

The net carrying value of developed or producing fields or groups of fields is depleted using the unit of production method by reference to the ratio of production in the period to the related proved plus probable reserves, taking into account estimated future development costs necessary to bring those reserves into production. Future development

PENGROWTH 2017 Financial Results 12

costs are estimated taking into account the level of development required to produce the reserves. These estimates are reviewed by independent reserve engineers at least annually. Pengrowth’s total proved plus probable reserves are estimated by an independent reserve evaluator and represent the "best estimate" of quantities of oil, natural gas and related substances to be commercially recoverable from known accumulations, from a given date forward, based on geological and engineering data. It is equally likely that the actual remaining quantities recovered will be greater than or less than the sum of the estimated proved plus probable reserves. Properties with no remaining production and reserves are fully depleted in the year that production ceases. Assets under construction are not depleted or depreciated until available for their intended use.

For other assets, depreciation is recognized in the Consolidated Statements of Income (Loss) using either a straight line or declining balance basis over the estimated useful lives of each part of an item of PP&E. The estimated useful lives for other assets for the current and comparative periods are as follows:

-	Office equipment	60 months
-	Leasehold improvements and finance leases	Lease term/Useful life
-	Computers	36 months
-	Deferred hydrocarbon injectants	24 months
-	Motor vehicles	60 months

Depreciation methods, useful lives and residual values are reviewed annually.

Farmouts

Under IFRS, farmouts are considered a disposition of a partial interest in a property. The proceeds on the disposition are generally considered to be the capital spent, or estimated to be spent, by the farmee in order to earn the interest. When the agreed upon work commitment has been completed, the farmee has earned their interest. It is at this stage that Pengrowth records a gain or loss on disposition, as the difference between the estimated capital and the carrying value of the disposed interest, in the Consolidated Statements of Income (Loss).

Leased Assets

Assets held by Pengrowth under leases which transfer to the Corporation substantially all of the risks and rewards of ownership are classified as finance leases. On initial recognition, the leased asset is measured at an amount equal to the lower of its fair value and the present value of the minimum lease payments. Subsequent to initial recognition, the asset is accounted for in accordance with the accounting policy applicable to that asset. Minimum lease payments made under finance leases are apportioned between the finance expense and the reduction of the outstanding liability. The finance expense is allocated to each period during the lease term so as to produce a constant periodic rate of interest on the remaining balance of the liability.

Assets held under other leases are classified as operating leases and are not recognized in the Consolidated Balance Sheets. Payments made under operating leases are recognized in the Consolidated Statements of Income (Loss) on a straight-line basis over the term of the lease. Lease incentives received are recognized as an integral part of the total lease expense, over the term of the lease.

At inception of certain arrangements, the Corporation determines whether such arrangement is or contains a lease. This will be the case if the following two criteria are met:

• The fulfillment of the arrangement is dependent on the use of a specific asset or assets; and

• The arrangement contains the right to use the asset(s).

Goodwill and Business Combinations

Goodwill may arise on business combinations and represents the excess of the cost of the acquisition over the net fair value of the identifiable assets, liabilities and contingent liabilities of the acquired assets or company. When the excess is negative, it is recognized immediately in the Consolidated Statements of Income (Loss).

Impairment

Non-Financial Assets

Property, Plant and Equipment

For the purpose of impairment testing, PP&E is grouped together into the smallest group of assets that generate cash inflows from continuing use that are largely independent of the cash inflows of other assets or groups of assets - cash generating unit (the “CGU”). CGUs are tested when there is an indication of impairment, such as sustained decreases

PENGROWTH 2017 Financial Results 13

in commodity prices or significant downward revisions in reserves volumes. An impairment loss is recognized to the extent the carrying value of the CGU exceeds its recoverable amount. Impairment losses are recognized in the Consolidated Statements of Income (Loss).

The recoverable amount of a CGU is the higher of its value in use and the fair value less costs to sell. In determining the recoverable amount, the estimated future cash flows are discounted to their present value using a pre-tax discount rate that reflects current market assessments of the cost of capital, which take into account the time value of money and the risks specific to the asset. The recoverable amount is generally computed by reference to the present value of the future cash flows expected to be derived from production of proved and probable reserves. Undeveloped land, contingent resources and infrastructure may also be considered in the recoverable amount.

Impairment losses in respect of PP&E recognized in prior periods are assessed at each reporting date for any indications that the loss has decreased or no longer exists. In such circumstances, the recoverable amount is determined and to the extent the loss is reduced, it is reversed. An impairment loss is reversed only to the lesser of the revised recoverable amount or the carrying amount that would have been determined, net of depletion and depreciation or amortization, if no impairment loss had been recognized.

Exploration and Evaluation Assets

E&E assets are tested for impairment when there is an indication that a particular E&E project may be impaired. Examples of indicators of impairment include a significant price decline over an extended period, the decision to delay or no longer pursue the E&E project, an expiry of the rights to explore in an area, or failure to receive regulatory approval. In addition, E&E assets are assessed for impairment upon their reclassification to producing assets (oil and natural gas interests in PP&E). In assessing the impairment of E&E assets, the carrying value of the E&E assets would be compared to their estimated recoverable amount and, in certain circumstances, could be tested in conjunction with PP&E impairment testing of related CGUs. The impairment of E&E assets would be recognized in the Consolidated Statements of Income (Loss).

Financial Assets

A financial asset is assessed at each reporting date to determine whether there is any objective evidence that it is impaired. A financial asset is considered to be impaired if objective evidence, including failure to pay on time, indicates that one or more events have had a negative effect on the estimated future cash flows of that asset.

An impairment loss in respect of a financial asset, measured at amortized cost, is calculated as the difference between its carrying amount and the present value of the estimated future cash flows discounted at the original effective interest rate. Significant financial assets are tested for impairment on an individual basis. The remaining financial assets are assessed collectively in groups that share similar credit risk characteristics.

Any impairment losses of financial assets are recognized in the Consolidated Statements of Income (Loss). An impairment loss is reversed if the reversal can be related objectively to an event occurring after the impairment loss was recognized. For financial assets measured at amortized cost, the reversal is recognized in the Consolidated Statements of Income (Loss).

Provisions and Other Liabilities

A provision is recognized if, as a result of a past event, the Corporation has a present legal or constructive obligation that can be estimated reliably and it is probable that an outflow of economic benefits will be required to settle the obligation. Provisions are determined by discounting the expected future cash flows at the appropriate discount rate. Provisions are not permitted for future operating losses.

Asset Retirement Obligations (“ARO”)

Pengrowth initially recognizes the net present value of an ARO in the period in which it is incurred when a reasonable estimate of the net present value can be made. The net present value of the estimated ARO is recorded as a liability, with a corresponding increase in the carrying amount of the related asset. The capitalized asset is depleted on the unit of production method based on proved plus probable reserves. The liability is increased each reporting period due to the passage of time and the amount of such accretion is expensed to income in the period. Actual costs incurred upon the settlement of the ARO are charged against the ARO. Management reviews the ARO estimate and changes, if any, are applied prospectively. Revisions made to the ARO estimate are recorded as an increase or decrease to the ARO liability with a corresponding change made to the carrying amount of the related asset. The carrying amount of both the liability and the capitalized asset, net of accumulated depreciation, are derecognized if the asset is subsequently disposed. The ARO liability is presented as Provisions on the Consolidated Balance Sheets. Refunds of previously

PENGROWTH 2017 Financial Results 14

paid offshore royalties are recognized as receivables only when production in a field has ceased and as abandonment and decommissioning spending has been incurred.

Pengrowth has placed cash in a segregated, independently managed, remediation trust fund account to fund ARO for the Sable Offshore Energy Project ("SOEP") property. The fund is reflected in Other Assets on the Consolidated Balance Sheets.

Finance Leases

Finance lease transactions are also categorized in Provisions and other liabilities.

Onerous Office Lease Contracts

Onerous office lease obligation related to excess office space is recognized when the unavoidable costs of the lease contracts over the remaining term exceed the economic benefits of the office lease. The onerous office lease provision is calculated as present value of future lease payments the Company is obligated to make under the lease contracts less any recoveries under current or anticipated sublease agreements over the remaining life of the lease.

Other Liabilities

Pengrowth also categorizes cash-settled long term incentive plan ("LTIP") grants andcash deferred bonus, within this grouping.

Income Taxes

Income tax (recovery) expense is composed of current and deferred tax. Income tax (recovery) expense is recognized in the Consolidated Statements of Income (Loss) except to the extent that it relates to items recognized directly in equity.

Current tax is the expected tax payable on the taxable income for the year, using tax rates enacted or substantively enacted at the reporting date, and any adjustment to tax payable in respect of previous years.

Deferred tax is recognized using the asset and liability method of accounting for income taxes. Under this method, income tax liabilities and assets are recognized for the estimated tax consequences attributable to differences between the amounts reported in the Consolidated Financial Statements and their respective tax bases, using substantively enacted income tax rates. Deferred tax assets are recognized for unused tax losses, unused tax credits and deductible temporary differences to the extent that it is probable that future taxable profits will be available against which they can be used. Future taxable profits are determined based on the reversal of relevant taxable temporary differences. If the amount of taxable temporary difference is insufficient to recognize a deferred tax asset in full, then future taxable profits, adjusted for reversals of existing temporary differences, are considered, based on Pengrowth's business plans.

The effect of a change in income tax rates on deferred income tax liabilities and assets is recognized in income in the period the change occurs. Deferred tax assets and liabilities are offset if there is a legally enforceable right to offset current tax liabilities and assets, and they relate to income taxes levied by the same tax authority on the same taxable entity. Deferred tax assets are reviewed at each reporting date and are reduced to the extent that it is no longer probable that the related tax benefit will be realized; these reductions are reversed when the probability of future taxable profits improves.

Pengrowth’s policy for income tax uncertainties is that tax benefits will be recognized only when it is more likely than not the position will be sustained on examination.

Share Based Compensation Plans

Pengrowth has share-settled and cash-settled share based compensation plans, which are described in Note 13.

i) Share-settled LTIP

Compensation expense is based on the estimated fair value of the share-settled award at the date of grant. Compensation expenses associated with the share-settled plans are recognized in the Consolidated Statements of Income (Loss) over the vesting period of the plan with a corresponding increase to contributed surplus. Pengrowth estimates the forfeiture rate for each type of share based award at the date of grant. Any consideration received upon the exercise of the awards together with the amount of non-cash compensation expense recognized in contributed surplus is recorded as an increase in shareholders’ capital at the time of exercise.

PENGROWTH 2017 Financial Results 15

ii) Cash-settled LTIP

Each cash-settled RSU entitles the holder to a cash payment equivalent to the value of a number of common shares (including the reinvestment of deemed dividends, if applicable) which vest evenly over a period of three years or less. Furthermore, the independent members of the Board of Directors also receive cash-settled long term incentives called Phantom Deferred Share Units ("PhantomDSUs"). Each Phantom DSU entitles the holder to a cash payment equivalent to the value of a number of common shares (including the reinvestment of deemed dividends, if applicable) to be paid upon the individual ceasing to be a Director for any reason.

Compensation expense associated with the cash-settled LTIP is determined based on the fair value of the share units at the grant date and is subsequently adjusted to reflect the fair value of the share units at each period end, including notional dividends, as applicable. Pengrowth estimates the forfeiture rate for each type of share based award at the date of grant. This valuation incorporates the period end share price and the number of cash-settled LTIP units outstanding at each period end. Compensation expense is recognized in the Statements of Income (Loss) with a corresponding increase or decrease in liabilities. Classification of the associated short term and long term liabilities is dependent on the expected payout dates.

Financial Instruments

Financial instruments are utilized by Pengrowth to manage its exposure to commodity and power price fluctuations, as well as foreign currency exposures. Pengrowth’s policy is not to utilize financial instruments for trading or speculative purposes.

Financial instruments are classified into one of five categories: (i) fair value through profit or loss, (ii) held to maturity investments, (iii) loans and receivables, (iv) available for sale financial assets or (v) other liabilities.

Accounts receivable are classified as loans and receivables which are measured at amortized cost.

Investments held in the remediation trust funds and other investments have been designated as fair value through profit or loss and are measured at fair value. Any change in the fair value is recognized in the Consolidated Statements of Income (Loss).

Bank indebtedness, accounts payable, convertible debentures and long term debt have been classified as other liabilities which are measured at amortized cost using the effective interest rate method.

Pengrowth has accounted for its physical delivery sales contracts, which were entered into and continue to be held for the purpose of receipt or delivery of non-financial items in accordance with its expected purchase, sale or usage requirements as executory contracts. As such, these contracts are not considered to be derivative financial instruments and have not been recorded at fair value on the Consolidated Balance Sheets. Settlements on these physical delivery sales contracts are recognized in revenue in the period of settlement.

All derivatives must be classified as fair value through profit or loss and measured at fair value with changes in fair value over a reporting period recognized in net income (loss).

The receipts or payments arising from derivative commodity contracts are presented as realized gain (loss) on commodity risk management while the unrealized gains and losses are presented as changes in fair value of commodity risk management contracts.

The receipts or payments arising from derivative power contracts are included in operating expenses. The unrealized gains and losses on derivative power contracts are included in other (income) expense.

The receipts or payments arising from derivative foreign exchange contracts are presented as realized foreign exchange (gain) loss while the unrealized gains and losses are presented as unrealized foreign exchange (gain) loss.

Transaction costs incurred in connection with the issuance of term debt instruments with a maturity of greater than one year are deducted against the carrying value of the debt and amortized to net income (loss) using the effective interest rate method over the expected life of the debt.

Pengrowth capitalizes transaction costs incurred in connection with the renewal of the revolving Credit Facility with a maturity date greater than one year and amortizes the cost to net income (loss) on a straight line basis over the term of the facility.

PENGROWTH 2017 Financial Results 16

Fair Value Measurement

All financial assets and liabilities for which fair value is measured or disclosed in the Consolidated Financial Statements are further categorized using a three-level hierarchy that reflects the significance of the lowest level of inputs used in determining fair value:

• Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

• Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1. Prices in Level 2 are either directly or indirectly observable as of the reporting date. Level 2 valuations are based on inputs, including quoted forward prices for commodities, time value and volatility factors, which can be substantially observed or corroborated in the marketplace.

• Level 3 – Valuations in this level are those with inputs for the asset or liability that are not based on observable market data.

Implementation of IFRS 9 (2014) - Financial Instruments

Pengrowth intends to adopt IFRS 9 (2014) in its Consolidated Financial Statements for the annual period beginning on January 1, 2018. The standard is generally required to be adopted retrospectively with or without restatement of prior periods in accordance with transition requirements. Pengrowth does not anticipate changes in measurement or reclassification of its financial instruments from implementation of IFRS 9 (2014).

Foreign Currency

The functional and reporting currency of the Corporation is Canadian dollars. Transactions in foreign currencies are translated to Canadian dollars at the exchange rates on the date of the transactions. Monetary assets and liabilities denominated in foreign currencies are translated into Canadian dollars at the exchange rate in effect on the Consolidated Balance Sheet date. Foreign exchange gains and losses are recognized in the Consolidated Statements of Income (Loss).

Jointly Controlled Operations

A significant proportion of Pengrowth’s petroleum and natural gas development and production activities are conducted through jointly controlled operations that are not conducted through separate vehicles and accordingly, the accounts reflect only Pengrowth’s interest in such activities.

Related Parties

Related parties are persons or entities that have control or significant influence over Pengrowth, as well as key management personnel. Note 21 provides information on compensation expense related to key management personnel. Pengrowth has no significant transactions with any other related parties.

Diluent and other purchases

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

Equity Investment

Pengrowth utilizes the equity method of accounting for investments subject to significant influence, if applicable. Under this method, investments are initially recorded at cost and adjusted thereafter to include Pengrowth’s pro rata share of post-acquisition earnings. Any dividends received or receivable from the investee would reduce the carrying value of the investment.

Estimates

The preparation of 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 Consolidated Financial Statements and revenues and expenses during the reporting year. Actual results could differ from those estimated.

In particular, information about significant areas of estimation uncertainty and critical judgments in applying accounting policies that have the most significant effect on the amounts recognized in the Consolidated Financial Statements is described below:

PENGROWTH 2017 Financial Results 17

Estimating oil and gas reserves and contingent resources

Pengrowth engages a qualified, independent oil and gas reserves evaluator to perform an estimation of the Corporation’s oil and gas reserves at least annually and contingent resources on an ad hoc basis. Reserves form the basis for the calculation of depletion charges, while oil and gas reserves and contingent resources are used in the assessment of impairment of goodwill and oil and gas assets. Reserves and contingent resources are estimated using the reserve definitions and guidelines prescribed by National Instrument 51-101 (“NI 51-101”) and the Canadian Oil and Gas Evaluation Handbook (“COGEH”).

Proved plus probable reserves are defined as the "best estimate" of quantities of oil, natural gas and related substances estimated to be commercially recoverable from known accumulations, from a given date forward, based on drilling, geological, geophysical and engineering data, the use of established technology and specified economic conditions. It is equally likely that the actual remaining quantities recovered will be greater than or less than the sum of the estimated proved plus probable reserves. The estimates are made using all available geological and reservoir data as well as historical production data. Estimates are reviewed and revised as appropriate. Revisions occur as a result of changes in prices, costs, fiscal regimes and reservoir performance or a change in Pengrowth's plans with respect to future development or operating practices.

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

Determination of CGUs

The recoverability of development and production asset carrying values are assessed at the CGU level. Determination of what constitutes a CGU is subject to management’s judgment. The asset composition of a CGU can directly impact the recoverability of the assets included therein. In assessing the recoverability of oil and gas properties, each CGU's carrying value is compared to its recoverable amount, defined as the fair value less costs to sell.

Asset Retirement Obligations

Pengrowth estimates obligations under environmental regulations in respect of decommissioning and site restoration. These obligations are determined based on the expected present value of expenses required in the process of plugging and abandoning wells, dismantling of wellheads, production and transportation facilities and restoration of producing areas in accordance with relevant legislation, discounted from the date when expenses are expected to be incurred. Most of the abandonment of Pengrowth's wells is estimated to take place far in the future. Therefore, changes in estimated timing of future expenses, estimated logistics of performing abandonment work, the inflation assumption, and the discount rate used to present value future expenses could have a significant effect on the carrying amount of the decommissioning provision.

Impairment testing

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

Fair value of risk management contracts

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

Valuation of trade and other receivables, and prepayments to suppliers

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

PENGROWTH 2017 Financial Results 18

Net Income (Loss) per Share

Basic net income (loss) per share is calculated using the weighted average number of shares outstanding for the year. Diluted net income (loss) per share amounts includes the dilutive effect of share units under the share-settled long term incentive plans using the treasury stock method. The treasury stock method assumes that any proceeds obtained on the exercise of any dilutive share units would be used to repurchase common shares at the average trading price during the period.

The dilutive effect of convertible debentures is calculated using net income (loss) for the period, adjusted for the after tax interest on the convertible debentures assuming they were converted at the start of the period; and adding to the diluted number of shares the weighted average shares issuable if the convertible debentures were converted at the start of the period.

Cash and Term Deposits

Cash and term deposits include demand deposits and term deposits with original maturities of less than 90 days.

OTHER ACCOUNTING PRONOUNCEMENTS ADOPTED

Disclosure Initiative Amendments to IAS 7

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

COMPARATIVE FIGURES

Certain prior years' comparative figures have been reclassified to conform to presentation adopted in the current year.

3. ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED

IFRS 9 Financial Instruments

In July 2014, the IASB issued the complete IFRS 9 ("IFRS 9 (2014)"). The mandatory effective date of IFRS 9 (2014) is for annual periods beginning on or after January 1, 2018 and must be applied retrospectively with some exemptions. Early adoption is permitted. The restatement of prior periods is not required and is only permitted if information is available without the use of hindsight. IFRS 9 (2014) introduces new requirements for the classification and measurement of financial assets. Under IFRS 9 (2014), financial assets are classified and measured based on the business model in which they are held and the characteristics of their contractual cash flows. The standard introduces additional changes relating to financial liabilities. It also amends the impairment model by introducing a new ‘expected credit loss’ model for calculating impairment. Pengrowth does not anticipate material changes in the carrying value of its financial instruments nor from the credit loss impairment model upon adoption of IFRS 9 (2014).

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

IFRS 9 (2014) also includes a new general hedge accounting standard which aligns hedge accounting more closely with risk management. This new standard does not fundamentally change the types of hedging relationships or the requirement to measure and recognize ineffectiveness; however it will provide more hedging strategies that are used for risk management to qualify for hedge accounting and introduce more judgment to assess the effectiveness of a hedging relationship. Special transitional requirements have been set for the application of the new general hedging model. Pengrowth does not currently apply hedge accounting and does not currently intend to apply hedge accounting to its existing risk management contracts.

IFRS 16 Leases

In January 2016, the IASB issued the complete IFRS 16 Leases ("IFRS 16") which replaces IAS 17, Leases. The effective date of IFRS 16 is for annual periods beginning on or after January 1, 2019 and early adoption is permitted. Under IFRS 16, a single recognition and measurement model will apply for lessees which will require recognition of assets and liabilities for most leases. Pengrowth is currently evaluating the impact that the adoption of this standard will have on its financial statements.

PENGROWTH 2017 Financial Results 19

4. OTHER ASSETS

	As at
	December 31, 2017		December 31, 2016
Remediation trust funds - current	$	24.0	$	—
Remediation trust funds - non-current	87.6		106.5
Prepaid tax assessment	12.2		12.2
	$	123.8	$	118.7

REMEDIATION TRUST FUNDS

Pengrowth has a contractual obligation to make contributions to an independently managed remediation trust fund that is used to fund the ARO of the SOEP properties and facilities. In 2016, Pengrowth made a monthly contribution to the fund at a rate of $6.64/MMBtu of its share of natural gas production and $13.29/bbl of its share of natural gas liquids production from SOEP. In 2017, the rates decreased to $4.04/MMBtu of Pengrowth's share of natural gas production and $7.59/bbl of Pengrowth's share of natural gas liquids production. The investment in the SOEP fund is classified as fair value through profit or loss. Investment income is recognized when earned and is recorded in other (income) expense.

Pengrowth is expected to spend approximately $24 million in 2018 for its share of the estimated costs of the SOEP abandonment and remediation program. The planned spending will be funded through the remediation trust fund, a portion of which was classified as current asset in the Consolidated Balance Sheet at December 31, 2017.

During the third and fourth quarters of 2017, Pengrowth disposed of its interests in the Judy Creek properties in the Swan Hills area, including associated remediation trust funds totaling approximately $4.8 million.

The following table reconciles Pengrowth’s investment in remediation trust funds for the periods noted below:

	Remediation Trust Funds
Balance, December 31, 2015	$	79.6
Contributions	26.9
Remediation expenditures	(0.9		)
Investment income	3.2
Unrealized gain (loss)	(2.3		)
Balance, December 31, 2016	$	106.5
Contributions	14.0
Remediation expenditures	(6.6		)
Investment income	3.1
Unrealized gain (loss)	(0.6		)
Dispositions	$	(4.8	)
Balance, December 31, 2017	$	111.6

PREPAID TAX ASSESSMENT

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

PENGROWTH 2017 Financial Results 20

5. PROPERTY, PLANT AND EQUIPMENT ("PP&E")

Cost or deemed cost	Oil and natural gas assets			Other equipment			Total
Balance, December 31, 2015	$	6,973.5		$	88.9		$	7,062.4
Additions to PP&E	89.9			1.9			91.8
Property acquisitions	1.3			—			1.3
Change in asset retirement obligations	(34.4		)	—			(34.4		)
Divestitures	(191.5		)	—			(191.5		)
Balance, December 31, 2016	$	6,838.8		$	90.8		$	6,929.6
Additions to PP&E	120.7			0.8			121.5
Property acquisitions	0.1			—			0.1
Change in asset retirement obligations	9.3			—			9.3
Divestitures	(3,151.2		)	(3.7		)	(3,154.9		)
Balance, December 31, 2017	$	3,817.7		$	87.9		$	3,905.6
Accumulated depletion, amortization and impairment losses	Oil and natural gas assets			Other equipment			Total
Balance, December 31, 2015	$	3,639.5		$	76.1		$	3,715.6
Depletion and amortization for the period	345.6			4.3			349.9
Divestitures	(102.4		)	—			(102.4		)
Balance, December 31, 2016	$	3,882.7		$	80.4		$	3,963.1
Depletion and amortization for the period	204.4			3.2			207.6
Impairment	504.4			—			504.4
Divestitures	(1,871.2		)	(2.5		)	(1,873.7		)
Balance, December 31, 2017	$	2,720.3		$	81.1		$	2,801.4
Net book value	Oil and natural gas assets			Other equipment			Total
As at December 31, 2017
Assets held for sale	$	—		$	—		$	—
Long term	1,097.4			6.8			1,104.2
	$	1,097.4		$	6.8		$	1,104.2
As at December 31, 2016
Assets held for sale	$	117.5		$	—		$	117.5
Long term	2,838.6			10.4			2,849.0
	$	2,956.1		$	10.4		$	2,966.5

For the year ended December 31, 2017, $2.3 million (December 31, 2016 – $3.2 million) of directly attributable general and administrative costs were capitalized to PP&E.

At December 31, 2017, $5.8 million (December 31, 2016 - $5.8 million) of net book value relating to the Lindbergh project was excluded from the calculation of depletion as those amounts were considered a project in the construction phase.

Pengrowth capitalizes interest for qualifying assets in the construction phase based on costs incurred on the project and the average cost of borrowing. During the year ended December 31, 2017, $3.7 million (December 31, 2016 – $3.0 million) of interest was capitalized on the Lindbergh Project to PP&E using Pengrowth's weighted average cost of debt of 5.7 percent (December 31, 2016 – 5.7 percent).

In 2017, Pengrowth executed and completed a substantial asset disposition program to enable it to reduce indebtedness and focus on its key growth assets.

PENGROWTH 2017 Financial Results 21

In the first quarter, Pengrowth successfully closed the sale of a 4.0 percent gross overriding royalty ("GORR") interest on its Lindbergh thermal property and certain seismic assets for proceeds of $250.0 million.

In the third quarter of 2017, Pengrowth successfully closed the disposition of its Judy Creek area assets in north central Alberta and its Olds/Garrington area assets in central Alberta for aggregate proceeds of $485.0 million, before customary adjustments.

In the fourth quarter of 2017, Pengrowth successfully closed the disposition of its remaining Swan Hills area assets in north central Alberta for proceeds of $150.0 million, before customary adjustments and closed the sale of the vast majority of its remaining non-core legacy assets in Alberta for nominal cash consideration and the assumption of abandonment and reclamation liabilities by the purchaser.

As a result of dispositions that closed in 2017, approximately $3.2 billion of costs and $1.9 billion of accumulated depletion were removed from PP&E.

IMPAIRMENT

Impairment charges recorded for the year ended December 31, 2017 totaled $634.4 million (December 31, 2016 - $nil) of which $504.4 million represented PP&E impairments. Throughout 2017's asset dispositions, there were several instances where a purchase and sale agreement ("PSA") was signed subsequent to the respective quarter end for proceeds less than net book value, therefore, being an indicator of impairment. In these situations, where the sales price in a PSA was below the carrying amount, an impairment was recorded. In addition, remaining assets in the Southern and Northern CGUs were impaired down to $nil based on the nominal value received for similar asset transactions.

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

6. EXPLORATION AND EVALUATION ASSETS ("E&E")

Cost or deemed cost
Balance, December 31, 2015	$	494.8
Additions	1.5
Balance, December 31, 2016	$	496.3
Divestitures	(134.3		)
Impairment	(130.0		)
Balance, December 31, 2017	$	232.0

In the second quarter of 2017, Pengrowth closed the sale of its non-producing Montney lands at Bernadet in north eastern British Columbia for cash consideration of $92.0 million.

In the third quarter of 2017, Pengrowth announced that the agreement to sell certain of its Swan Hills area assets for $180.0 million was terminated. Included in this disposition were the assets in the non producing Devil area which were recorded as an E&E asset. None of the purchase price was attributed to the Devil lands resulting in a loss on assets held for sale of $9.0 million in the first quarter of 2017. Pengrowth subsequently closed the sale of these assets for $150.0 million cash consideration, subject to customary adjustments. Included in this disposition are the Devil lands which were part of the terminated sale in July.

IMPAIRMENT TESTING

For the year ended December 31, 2017, Pengrowth evaluated Groundbirch gas property for an impairment in conjunction with the Montney CGU, comprising both PP&E and E&E, due to the negative impact resulting from the significant downturn in the forward natural gas benchmark prices late in 2017. This was in accordance with Pengrowth's policy and IFRS which states that the impairment of ongoing E&E projects should be assessed on the cash flow from the applicable CGUs in the operating segment. It was determined that the recoverable amount was below the carrying amount, thus a $129.0 million impairment on the Groundbirch E&E asset was recorded in the fourth quarter of 2017. In addition, $1.0 million impairment was recognized on other minor E&E projects as no further exploration or evaluation is intended on those projects.

PENGROWTH 2017 Financial Results 22

The recoverable amount is generally computed by reference to the present value of the future cash flows expected to be derived from production of proved plus probable reserves for the operating segment. Contingent resources were also considered in the recoverable amount. Changes in forward price estimates, production costs or recovery rates may change the economic status of contingent resources and may ultimately result in contingent resources being restated. The Groundbirch E&E impairment test was based on proved reserve values using a pre-tax discount rate of 10 percent, probable reserve values using a pre-tax discount rate of 12 percent, independent reserves evaluator January 1, 2018 forecast pricing and an inflation rate of 2 percent, and contingent resources using a pre-tax discount rate of 15 percent. The recoverable amount was determined using value in use.

The estimates of the above recoverable amounts were determined based on the following information, as applicable:

The net present value of the CGUs oil and gas reserves using:

i. Proved plus probable reserves as estimated by Pengrowth’s independent reserves evaluator, and

ii. The commodity price forecast of Pengrowth’s independent reserves evaluator as noted below,

Discounted at an estimated market discount rate.

Key input estimates used in the determination of cash flows from oil and gas reserves include the following:

(a) Reserves. Assumptions that are valid at the time of reserve estimation may change significantly when new information becomes available. Changes in forward price estimates, production costs or recovery rates may change the economic status of reserves and may ultimately result in reserves being restated.

(b) Oil and natural gas prices. Forward price estimates for oil and natural gas are used in the cash flow model.

Commodity prices have fluctuated widely in recent years due to global and regional factors including supply and demand fundamentals, inventory levels, exchange rates, weather, economic and geopolitical factors.

(c) Discount rate. The discount rate used to calculate the net present value of cash flows is based on estimates of an approximate cost of capital for potential acquirers of Pengrowth or Pengrowth’s CGUs. Changes in the general economic environment could result in significant changes to this estimate.

Below are the forward natural gas price estimates used in the December 31, 2017 impairment test:

	AECO gas (1)
Year	(Cdn$/MMBtu)
2018	2.20
2019	2.54
2020	2.88
2021	3.24
2022	3.47
2023	3.58
2024	3.66
2025	3.73
2026	3.80
2027	3.88
Thereafter	+ 2.0 percent/yr

⁽¹⁾  Prices represent forecasted amounts as at January 1, 2018 by Pengrowth's independent reserves evaluator.

PENGROWTH 2017 Financial Results 23

7. CONVERTIBLE DEBENTURES

On March 31, 2017, all $126.6 million of the outstanding convertible debentures matured and were repaid and settled with cash on hand.

The following table summarizes the activity associated with the convertible debentures:

	Series B - 6.25 percent
Maturity date	March 31, 2017
Conversion price (per Pengrowth share)	$	11.51
Balance, December 31, 2015	$	137.0
Repurchase of convertible debentures	(10.2		)
Premium accretion	(0.2		)
Balance, December 31, 2016	$	126.6
Repayment of convertible debentures	(126.6		)
Balance, December 31, 2017	$	—
Face value, December 31, 2017	$	—

8. LONG TERM DEBT

AMENDMENTS TO LONG TERM DEBT

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

• The prepayment of all of the term notes due August 21, 2018 (U.S.$265 million and Cdn$15 million) and additional prepayments of Cdn$115.4 million of principal during the fourth quarter of 2017 on the remaining outstanding term notes.

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

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

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

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

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

• The remaining outstanding term notes maturing in 2019 through 2024 are subject to a 2.0 percentage point increase in interest rates (which increases to 3.0 percentage points on January 1, 2020). A one-time amendment fee of 0.5 percent on outstanding term notes was also paid to the holders of term notes due after 2018.

• The aggregate credit limit under the Credit Facility was reduced to $330 million following the closing of the Swan Hills asset sale, the $50 million Demand Credit Facility was eliminated and interest rates under the Credit Facility increased by 2.0 percentage points. A one time amendment fee of 0.5 percent of the aggregate credit limit was paid to the syndicate members of the Credit Facility.

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

PENGROWTH 2017 Financial Results 24

Financial Covenants

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

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

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

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

As at December 31, 2017, Pengrowth had the following outstanding long term debt:

	As at
	December 31, 2017		December 31, 2016
U.S. dollar denominated term notes:
400 million at 6.35 percent due July 26, 2017	$	—	$	537.0
265 million at 6.98 percent due August 21, 2018 (1)	—		355.6
35 million at 5.49 percent due October 18, 2019 (2)	35.3		46.9
115.5 million at 7.98 percent due May 11, 2020 (3)	118.3		154.8
105 million at 6.07 percent due October 18, 2022 (4)	107.1		140.6
195 million at 6.17 percent due October 18, 2024 (5)	199.7		261.1
	$	460.4	$	1,496.0
U.K. pound sterling denominated term notes:
15 million at 5.45 percent due October 18, 2019 (6)	$	20.6	$	24.8
Canadian dollar term notes:
15 million at 6.61 percent due August 21, 2018 (1)	$	—	$	15.0
25 million at 6.74 percent due October 18, 2022 (7)	20.5		24.9
	$	20.5	$	39.9
Canadian dollar term Credit Facility borrowings	$	109.0	$	—
Total long term debt	$	610.5	$	1,560.7
Current portion of long term debt	$	—	$	537.0
Non-current portion of long term debt	610.5		1,023.7
	$	610.5	$	1,560.7

⁽¹⁾  There was no outstanding balance following the early repayment on October 12, 2017.

⁽²⁾  The remaining balance of U.S.$28.1 million term notes were outstanding, following the early repayment of U.S.$6.9 million in the fourth quarter of 2017.

⁽³⁾  The remaining balance of U.S.$94.1 million term notes were outstanding, following the early repayment of U.S.$21.4 million in the fourth quarter of 2017.

⁽⁴⁾  The remaining balance of U.S.$85.2 million term notes were outstanding, following the early repayment of U.S.$19.8 million in the fourth quarter of 2017.

⁽⁵⁾  The remaining balance of U.S.$158.9 million term notes were outstanding, following the early repayment of U.S.$36.1 million in the fourth quarter of 2017.

⁽⁶⁾  The remaining balance of U.K. pound sterling 12.1 million term notes were outstanding, following the early repayment of U.K. pound sterling 2.9 million in the fourth quarter of 2017.

⁽⁷⁾  The remaining balance of Cdn$20.5 million term notes were outstanding, following the early repayment of Cdn$4.5 million in the fourth quarter of 2017.

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

PENGROWTH 2017 Financial Results 25

The Facility carried floating interest rates that were expected to range between 3.6 percent and 5.25 percent over bankers’ acceptance rates, depending on Pengrowth’s ratio of senior debt to earnings before interest, taxes and non-cash items. At December 31, 2017, the available facility had drawings of $109.0 million (December 31, 2016 – $nil) and letters of credit in the amount of $69.4 million (December 31, 2016 – $51.3 million) were outstanding.

During 2017, Pengrowth prepaid its U.S.$400.0 million6.35 percent senior unsecured notes, its U.S.$265 million6.98 percent senior unsecured notes and its Cdn$15.0 million6.61 percent senior unsecured notes. Additional prepayments of Cdn$115.4 million of principal were made on the remaining outstanding term notes in the fourth quarter of 2017. Pursuant to the relevant Note Purchase Agreements, amendment fees and make whole payments on the principal prepayments totaling Cdn$37.6 million were paid in addition to the principal for a total amount of Cdn$1.0 billion.

As of December 31, 2017, an unrealized cumulative foreign exchange loss of $96.2 million (December 31, 2016 - $353.3 million) has been recognized on the remaining U.S. dollar term notes since the date of issuance. As of December 31, 2017, an unrealized cumulative foreign exchange loss of $1.4 million (December 31, 2016 - $1.1 million) has been recognized on the remaining U.K. pound sterling denominated term notes since the date of issuance. See Note 17 for additional information about foreign exchange risk management and the impact on the Consolidated Financial Statements.

The five year schedule of long term debt repayment based on current maturity dates and assuming the revolving Credit Facility is not renewed is as follows: 2018 - $nil, 2019 - $164.9 million, 2020 - $118.3 million, 2021 - $nil, 2022 - $127.6 million.

9. CAPITAL DISCLOSURES

Pengrowth defines its capital as shareholders’ equity, long term debt, convertible debentures, bank indebtedness and working capital, as applicable.

Due to the rapid deterioration of commodity prices commencing in late 2014, Pengrowth took several steps to manage its capital, primarily relating to reducing debt. Capital spending was reduced, non-core assets were divested, foreign exchange and commodity risk management swaps were monetized, the dividend was initially reduced and then suspended, the term Credit Facility was renewed for four years, and the covenants were largely aligned between the senior unsecured notes and term Credit Facility. Surplus cash was used to repay debt.

The only financial covenant relating to the term notes and Credit Facility is the Interest Coverage ratio. The minimum ratio for the quarter ending September 30, 2017 through to and including the quarter ending September 30, 2019 is as follows:

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

Management monitors Pengrowth's capital structure using non-GAAP financial metrics, primarily trailing twelve months Earnings Before Interest, Taxes, Depletion, Depreciation, Amortization, Accretion, and other non-cash items ("AdjustedEBITDA") to Adjusted Interest Expense, or "Interest Coverage" ratio. Pengrowth seeks to manage this ratio with the objective of being able to finance its growth strategy while maintaining sufficient flexibility under the debt covenant.

Compliance with the interest coverage ratio is closely monitored by management as part of Pengrowth’s overall capital management objectives. The covenant is based on specific definitions prescribed in the debt agreements. Throughout the period, Pengrowth was in compliance with all financial covenants.

At December 31, 2017, Pengrowth has approximately $150 million of capacity on its Credit Facility, net of drawings and outstanding letters of credit.

Pengrowth continues to pursue other capital opportunities for when the Credit Facility expires on March 31, 2019 and for when the Waiver Period expires in the fourth quarter of 2019.

PENGROWTH 2017 Financial Results 26

The following table provides a reconciliation between the opening and closing balances for liabilities arising from financing activities at December 31, 2017:

	Term Notes			Canadian dollar Term Credit Facility		Convertible debentures
Balance December 31, 2016	$	1,560.7		$	—	$	126.6
Increase (decrease) due to:
Foreign exchange impact of the Canadian dollar on U.S. and U.K. denominated debt	(65.1		)	—		—
Credit facility borrowing	—			109.0		—
Repayment	(996.0		)	—		(126.6		)
Issue cost amortization	1.9			—		—
Balance, December 31, 2017	$	501.5		$	109.0	$	—

The following is a summary of Pengrowth’s capital structure, excluding shareholders’ equity:

	As at
	December 31, 2017		December 31, 2016
Long term debt (1)	$	610.5	$	1,560.7
Convertible debentures	—		126.6
Working capital (surplus) deficiency (2)	80.6		(266.7		)
	$	691.1	$	1,420.6

⁽¹⁾  Includes current portion of term notes and bank indebtedness, as applicable.

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

PENGROWTH 2017 Financial Results 27

10. PROVISIONS AND OTHER LIABILITIES

Provisions and other liabilities are composed of Asset Retirement Obligations ("ARO"), finance leases, restructuring onerous office lease and other liabilities. The following table provides a continuity of the balances for the following periods:

	Asset retirement obligations			Finance leases			Restructuring provision - onerous office lease contracts			Other liabilities			Total
Balance, December 31, 2015	$	703.4		$	4.3		$	—		$	0.3		$	708.0
Incurred during the period	—			35.0			—			2.9			37.9
Property dispositions	(11.8		)	—			—			—			(11.8		)
Expenditures on remediation/provisions settled	(20.0		)	(1.4		)	—			(0.1		)	(21.5		)
Other revisions	(34.4		)	—			—			1.3			(33.1		)
Accretion (amortization)	15.1			—			—			—			15.1
Balance, December 31, 2016	$	652.3		$	37.9		$	—		$	4.4		$	694.6
Incurred during the period	5.4			—			26.5			(1.5		)	30.4
Property dispositions	(420.4		)	(2.0		)	—			—			(422.4		)
Expenditures on remediation/provisions settled	(15.9		)	(1.7		)	(0.3		)	(0.6		)	(18.5		)
Other revisions	3.9			—			—			—			3.9
Accretion (amortization)	11.4			—			—			—			11.4
Balance, December 31 2017	$	236.7		$	34.2		$	26.2		$	2.3		$	299.4

As at December 31, 2017	Asset retirement obligations		Finance leases		Restructuring provision - onerous office lease contracts		Other liabilities		Total
Current	$	29.9	$	0.9	$	4.4	$	—	$	35.2
Long term	206.8		33.3		21.8		2.3		264.2
	$	236.7	$	34.2	$	26.2	$	2.3	$	299.4
As at December 31, 2016
Current	$	20.0	$	1.5	$	—	$	0.6	$	22.1
Long term	632.3		36.4		—		3.8		672.5
	$	652.3	$	37.9	$	—	$	4.4	$	694.6

Reductions to ARO from the asset dispositions that closed in 2017 totaled $420.4 million.

The following assumptions were used to estimate the ARO liability:

	As at
	December 31, 2017			December 31, 2016
Total escalated future costs	$	420.2		$	2,120.4
Discount rate, per annum	2.3		%	2.3		%
Inflation rate, per annum	1.5		%	1.5		%

Pengrowth has been contributing to an externally managed trust fund established to fund abandonment and reclamation costs associated with SOEP. These costs are expected to be incurred within the next 3 to 4 years. The abandonment and reclamation costs on other assets, not covered by a fund, are expected to be incurred between 2035 and 2080.

RESTRUCTURING PROVISION - ONEROUS OFFICE LEASE CONTRACTS

Pengrowth completed significant asset dispositions which led to a management decision to complete an operational restructuring commencing in the third quarter of 2017. Reduction of staff levels and excess office space resulted in Pengrowth recognizing a $37.0 million restructuring cost in 2017.

PENGROWTH 2017 Financial Results 28

As part of the $37.0 million restructuring costs, Pengrowth recorded a $26.5 million provision related to a portion of its office lease obligation that is considered an onerous contract, as the economic benefits from actual or potential subleases were exceeded by the unavoidable costs of the lease contract over the remaining term.

Also included in the $37.0 million restructuring costs were $10.5 million of severance costs which were classified as a current payable in the Consolidated Balance Sheets due to the short term nature of expected payment dates.

11. DEFERRED INCOME TAXES

A reconciliation of the deferred income tax recovery calculated based on the income (loss) before taxes at the statutory tax rate to the actual provision for deferred income taxes is as follows:

	Year ended December 31
	2017			2016
Income (loss) before taxes	$	(907.6	)	$	(387.1	)
Combined federal and provincial tax rate	27.08		%	27.09		%
Expected income tax expense (recovery)	$	(245.8	)	$	(104.9	)
Change in unrecognized deferred tax asset	22.6			9.8
Foreign exchange (gain) loss (1)	(2.0		)	(1.8		)
Effect of change in corporate tax rate	(0.2		)	—
Other including share based compensation	1.6			3.5
Deferred income tax expense (recovery)	$	(223.8	)	$	(93.4	)

⁽¹⁾ Reflects the 50 percent non-taxable portion of foreign exchange gains and losses and related risk management contracts.

The net deferred income tax asset (liability) is composed of:

	As at
	December 31, 2017			December 31, 2016
Deferred tax liabilities associated with:
PP&E and E&E assets	$	(132.3	)	$	(411.0	)
Less deferred tax assets associated with:
Non-capital losses and financing charges	399.6			325.9
Provisions	64.1			176.6
Risk management contracts	10.8			14.6
Long term debt	—			12.1
Convertible debentures	—			0.2
Net deferred tax asset (liability)	$	342.2		$	118.4

In calculating the deferred income tax asset in 2017, Pengrowth included $1,460.2 million (2016 - $1,234.6 million) of non-capital losses available for carry forward to reduce taxable income in future years. These losses expire between 2025 and 2037. Pengrowth has determined that it is likely that future taxable profit will be available to utilize these losses.

Deferred tax assets have not been recognized with respect to the following items:

	As at
	December 31, 2017		December 31, 2016
Deductible temporary differences	$	204.0	$	188.9
Tax losses	109.8		40.2
	$	313.8	$	229.1

PENGROWTH 2017 Financial Results 29

A continuity of the net deferred income tax asset (liability) for 2017 and 2016 is detailed in the following tables:

Movement in deferred tax asset (liability) during the year	Balance Jan 1, 2017			Recognized in profit or loss			Balance Dec 31, 2017
PP&E and E&E assets	$	(411.0	)	$	278.7		$	(132.3	)
Non-capital losses and financing charges	325.9			73.7			399.6
Provisions	176.6			(112.5		)	64.1
Risk management contracts	14.6			(3.8		)	10.8
Long term debt	12.1			(12.1		)	—
Convertible debentures	0.2			(0.2		)	—
Share issue costs	—			—			—
	$	118.4		$	223.8		$	342.2

Movement in deferred tax asset (liability) during the year	Balance Jan 1, 2016			Recognized in profit or loss			Balance Dec 31, 2016
PP&E and E&E assets	(405.3		)	(5.7		)	(411.0		)
Non-capital losses and financing charges	328.7			(2.8		)	325.9
Provisions	190.2			(13.6		)	176.6
Risk management contracts	(99.8		)	114.4			14.6
Long term debt	10.8			1.3			12.1
Convertible debentures	0.2			—			0.2
Share issue costs	0.2			(0.2		)	—
	$	25.0		$	93.4		$	118.4

Deferred income tax is a non-cash item relating to the temporary differences between the accounting and tax basis of Pengrowth's assets and liabilities and has no immediate impact on Pengrowth's cash flows.

12. SHAREHOLDERS’ CAPITAL

Pengrowth is authorized to issue an unlimited number of common shares and up to 10 million preferred shares. No preferred shares have been issued.

	2017			2016
(Common shares in 000's)	Number of common shares	Amount		Number of common shares	Amount
Balance, beginning of year	547,709	$	4,815.1	543,033	$	4,797.0
Share based compensation (non-cash exercised)	4,537	14.6		4,676	18.1
Balance, end of year	552,246	$	4,829.7	547,709	$	4,815.1

13. LONG TERM INCENTIVE PLANS ("LTIP")

Pengrowth’s Long Term Incentive Plan ("LTIP"), as described below, is used to grant awards of share based compensation.

(i) SHARE-SETTLED LTIP

Pengrowth’s share-settled LTIP has the following components:

(a) Performance Share Units ("PSUs")

PSUs entitle the holder to a number of common shares to be issued in the third year after grant. Prior to 2016, PSUs were awarded to employees, officers and consultants. Commencing in 2016, PSUs are only awarded to individuals in senior leadership roles whose responsibilities are thought to have a more direct impact on the share price. PSUs are subject to a performance factor ranging from 0 percent to 200 percent of the number of PSUs granted plus the amount of reinvested notional dividends, if applicable.

PENGROWTH 2017 Financial Results 30

(b) Restricted Share Units ("RSUs")

RSUs entitle the holder to a number of common shares plus reinvested notional dividends, if applicable, to be issued at vesting in three even tranches in the three years following grant. Prior to 2016, RSUs were awarded to employees, officers and consultants. Commencing in 2016, RSUs are only awarded to individuals in mid-level leadership roles. The RSUs generally vest on the first, second and third anniversary date from the date of grant.

(c) Deferred Share Units ("DSUs")

As of 2014, there were no new grants of the share-settled DSUs as independent members of the Board of Directors receive cash-settled Phantom DSUs instead. Prior to 2014, DSUs were issued to the independent members of the Board of Directors only. Each DSU entitled the holder to one common share plus reinvested notional dividends, if applicable, since the grant date of the DSU. The DSUs vest upon grant but can only be converted to common shares upon the holder ceasing to be a Director of Pengrowth. The number of common shares ultimately issued will be equal to the number of DSUs initially granted to the holder plus the amount of reinvested notional dividends, if applicable, accruing during the term of the DSUs.

The following table provides a continuity of the share-settled LTIP:

(number of share units - 000's)	PSUs		RSUs		DSUs
Outstanding, December 31, 2015	4,640		5,341		302
Granted	3,049		6,553		—
Forfeited	(460	)	(737	)	—
Exercised	(1,695	)	(2,721	)	(104	)
Performance adjustment	704		—		—
Outstanding, December 31, 2016	6,238		8,436		198
Granted	2,124		4,578		—
Forfeited	(486	)	(2,195	)	—
Exercised	(1,104	)	(3,436	)	—
Performance adjustment	(1,738	)	—		—
Outstanding, December 31, 2017	5,034		7,383		198

Pengrowth's Board may determine, in its sole discretion, that any shares issuable pursuant to new grants could be paid in cash equal to the fair market value of the shares otherwise issuable.

A rolling and reloading plan with a maximum of 3.2 percent of the issued and outstanding common shares may be reserved for issuance under all share-settled compensation plans in the aggregate, as approved by shareholders. As at December 31, 2017, the number of shares issuable under the share-settled compensation plans, in aggregate, represents 2.3 percent of the issued and outstanding common shares, which is within the limit.

Compensation expense related to PSU, RSU, and DSU share-settled plans is based on the fair value of the share units at the date of grant. The fair value of the PSUs is determined at the date of grant using the closing share price and is adjusted for the estimated performance multiplier. The amount of compensation expense is impacted by an estimated forfeiture rate at the date of grant and as more information comes available. For PSU and RSU grants in 2015, 2016 and 2017, the estimated forfeiture rates range from 25 to 55 percent depending on the vesting period. There was no forfeiture rate applied for DSUs as they vested immediately upon grant. For PSUs, the number of shares awarded at the end of the vesting period is subject to certain performance conditions. Fluctuations in compensation expense may occur due to changes in estimating the outcome of the performance conditions. Compensation expense is recognized in net income (loss) over the vesting period with a corresponding increase or decrease to contributed surplus. Upon the issuance of common shares at the end of the vesting period, shareholders’ capital is increased and contributed surplus is decreased by the amount of compensation expense incurred during the vesting period. The shares are issued from treasury upon vesting.

For the year ended December 31, 2017, Pengrowth recorded $5.0 million of compensation expense related to the share-settled LTIP units (December 31, 2016 - $13.7 million). The weighted average grant date fair value was $1.40 per share unit for the 2017 grants (December 31, 2016 - $1.02 per share unit for the 2016 grants). As at December 31, 2017, the amount of compensation expense to be recognized over the remaining vesting period was $5.4 million or $0.51 per share unit (December 31, 2016 - $9.8 million or $0.78 per share unit) subject to the determination of the

PENGROWTH 2017 Financial Results 31

performance multiplier, if applicable. The unrecognized compensation cost will be expensed to net income (loss) over the remaining weighted average vesting period of 1.3 years.

(ii) PREVIOUS LTIP

Prior to January 1, 2011, Pengrowth had a Deferred Entitlement Share Unit ("DESU") Plan that was used while Pengrowth was a trust and is being phased out. As at December 31, 2017, all of the grants were fully vested and the total outstanding balance was composed of grants made prior to January 1, 2011 to the independent members of the Board of Directors. DESUs are not exercisable by the independent Directors and do not expire until they cease to be Directors for any reason. As at December 31, 2017, 163,867 common shares (December 31, 2016 - 163,867 common shares) were reserved for issuance under the Deferred Entitlement Share Unit ("DESU") Plan. The DESUs are entitled to deemed dividends, if applicable.

(iii) CASH-SETTLED LTIP    

(a) Cash-Settled Restricted Share Units ("Cash-Settled RSUs")

Commencing in 2016, certain employees receive cash-settled RSUs in place of previously received share-settled long term incentives. Each cash-settled RSU entitles the holder to a cash payment equivalent to the value of a number of common shares (including the reinvestment of deemed dividends, if applicable) which vest in three even tranches in the three years following grant. Compensation expense associated with the cash-settled RSUs is determined based on the fair value of the share units at the grant date and is subsequently adjusted to reflect the fair value of the share units at each period end. This valuation incorporates the period end share price and the number of cash-settled RSUs outstanding at each period end. The amount of compensation expense is impacted by an estimated forfeiture rate at the date of grant and as more information comes available. For the cash-settled RSU grants in 2016 and 2017, the estimated forfeiture rates range from 50 to 80 percent depending on the vesting period. During the year ended December 31, 2017, compensation reduction of $0.2 million (December 31, 2016 - $3.6 million expense) was recognized in the Consolidated Statements of Income (Loss) with a corresponding increase or decrease in liabilities. As at December 31, 2017, $1.5 million (December 31, 2016 - $3.6 million) of total liability was recorded in the Consolidated Balance Sheets. Classification of the associated short term and long term liabilities is dependent on the expected payout dates.

(b) Cash-Settled Phantom Deferred Share Units ("Phantom DSUs")

Independent members of the Board of Directors receive cash-settled Phantom DSUs. Each Phantom DSU entitles the holder to a cash payment equivalent to the value of a number of common shares (including deemed dividends, if applicable) to be paid upon the individual ceasing to be a Director for any reason, subject to the right to defer payment until up to December 31 of the year following their departure from the Board. Compensation expense associated with the Phantom DSUs is determined based on the fair value of the Phantom DSUs at the grant date and is subsequently adjusted to reflect the fair value of the associated common shares at each period end. This valuation incorporates the period end share price and the number of Phantom DSUs outstanding at each period end including notional dividends, if applicable. Compensation expense is recognized in net income (loss) with a corresponding increase or decrease in liabilities. Classification of the associated short term and long term liabilities is dependent on the expected payout dates.

As at December 31, 2017, Phantom DSUs awarded to Directors had a corresponding liability of $1.4 million (December 31, 2016 - $2.6 million). For the year ended December 31, 2017, Pengrowth recorded a $0.6 million compensation reduction (December 31, 2016 - $2.3 million expense) related to Phantom DSUs.

PENGROWTH 2017 Financial Results 32

The following table provides a continuity of the cash-settled LTIP:

(number of share units - 000's)	Cash-settled RSUs		Phantom DSUs
Outstanding, December 31, 2015	—		397
Granted	4,559		1,024
Forfeited	(330	)	—
Exercised	—		(75	)
Outstanding, December 31, 2016	4,229		1,346
Granted	3,163		492
Forfeited	(3,148	)	—
Exercised	(1,341	)	(462	)
Outstanding, December 31, 2017	2,903		1,376

TOTAL SHARE BASED COMPENSATION EXPENSE

Total share based compensation expenses are included in both general and administrative and operating expenses on the Consolidated Statements of Income (Loss)and are composed of the following:

	Year ended December 31
	2017			2016
Non-cash share based compensation	$	5.0		$	13.7
Amounts capitalized in the period	(0.1		)	(0.5		)
Non-cash share based compensation expense	$	4.9		$	13.2
Cash-settled RSUs (reduction) expense	$	(0.2	)	$	3.6
Cash-settled Phantom DSUs (reduction) expense	$	(0.6	)	$	2.3
Total share based compensation expense	$	4.1		$	19.1

14. REVENUE

Pengrowth sells its production pursuant to fixed or variable price contracts. The transaction price for variable priced contracts is based on the commodity price, adjusted for quality, location or other factors, whereby each component of the pricing formula can be either fixed or variable, depending on the contract terms. Under its contracts, Pengrowth is required to deliver fixed volumes of diluted bitumen, and variable volumes of light oil, natural gas, natural gas liquids, and sulphur to the contract counterparty. The amount of revenue recognized is based on the agreed transaction price, whereby any variability in revenue relates specifically to its efforts to transfer production, and therefore the resulting revenue is allocated to the production delivered in the period during which the variability occurs. As a result, none of the variable revenue is considered constrained.

Light oil, natural gas liquids and natural gas are mostly sold under contracts of varying price and volume terms of up to one year. Pengrowth’s diluted bitumen is currently sold on multi-year contracts expiring in 2019 for a fixed quantity of diluted bitumen at a fixed differential to WTI, with WTI being variable, as detailed in Note 17. Revenues are typically collected on the 25^th day of the month following production. Processing fees charged to third parties are generally sold under multi-year contracts at fixed fees that vary by volume.

Adoption of IFRS 15 Revenue from Contracts with Customers

In the fourth quarter of 2017, Pengrowth elected to early adopt IFRS 15 Revenue from contracts with customers as detailed in Note 2, using the cumulative effect approach. The impact to Oil and gas sales as a result of adopting IFRS 15 was an increase of $182.6 million of revenues, with a corresponding and offsetting increase to Operating expenses and Diluent and other purchases of $163.5 million and $19.1 million, respectively, for the twelve months ended December 31, 2017, resulting in no impact to net income (loss).

PENGROWTH 2017 Financial Results 33

The following table presents Pengrowth’s Oil and gas sales disaggregated by revenue source:

	Year ended December 31
	2017
Light oil	149.3
Bitumen	181.6
Natural gas liquids	56.7
Natural gas	98.8
Produced petroleum revenue	486.4
Diluent	147.2
Processing income	19.1
Other revenue	20.7
Total oil and gas sales	$	673.4

During 2017, Pengrowth had one fixed price physical delivery contract for approximately 12 MMcf/d of natural gas.

Pengrowth has variable price physical delivery contracts for the sale of diluted bitumen with 2 parties, Phillips 66 Canada Ltd. and BP Products North America Inc., with revenue from those customers representing approximately 36 percent and 12 percent, respectively, of the Company's total 2017 Oil and gas sales.

The vast majority of 2017 revenues are derived from variable price contracts based on index prices, while only approximately 0.2 percent of revenues were from the fixed price natural gas contracts noted above.

Included in accounts receivable at December 31, 2017 is $40.2 million (December 31, 2016 - $76.5 million for December 2016 production) of accrued Oil and gas sales related to December 2017 production. The decrease in the amount of accrued revenue is related to property divestments.

15. OTHER CASH FLOW DISCLOSURES

CHANGE IN NON-CASH OPERATING WORKING CAPITAL AND OTHER ASSETS

	Year ended December 31
Cash provided by (used for):	2017			2016
Accounts receivable	$	40.9		$	25.0
Accounts payable	(22.7		)	(43.8		)
Prepaid tax assessment	—			(2.7		)
	$	18.2		$	(21.5	)

CHANGE IN NON-CASH INVESTING WORKING CAPITAL 

	Year ended December 31
Cash used for:	2017			2016
Accounts payable, including capital accruals	$	(7.5	)	$	7.6

PENGROWTH 2017 Financial Results 34

16. AMOUNTS PER SHARE

The following table reconciles the weighted average number of shares used in the basic and diluted net income (loss) per share calculations:

	Year ended December 31
(000's)	2017	2016
Weighted average number of shares - basic and diluted	551,193	546,566

For the year ended December 31, 2017, 9.3 million shares (December 31, 2016 - 7.8 million) that are issuable on exercise of the share based compensation plans were excluded from the diluted net income (loss) per share calculation as their effect is anti-dilutive.

17. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

Pengrowth’s financial instruments are composed of accounts receivable, accounts payable, risk management assets and liabilities, remediation trust funds, finance lease obligation, bank indebtedness, convertible debentures and long term debt, as applicable.

Details of Pengrowth’s significant accounting policies for recognition and measurement of financial instruments are disclosed in Note 2 to the December 31, 2017 audited Consolidated Financial Statements.

RISK MANAGEMENT OVERVIEW

Pengrowth has exposure to certain market risks related to volatility in commodity and power prices, interest rates and foreign exchange rates. Derivative instruments are used to manage exposure to these risks. Pengrowth’s policy is not to utilize financial instruments for trading or speculative purposes.

The Board of Directors and management have overall responsibility for the establishment of risk management strategies and objectives. Pengrowth’s risk management policies are established to identify the risks faced by Pengrowth, to set appropriate risk limits, and to monitor adherence to risk limits. Risk management policies are reviewed regularly to reflect changes in market conditions and Pengrowth’s activities.

MARKET RISK

Market risk is the risk that the fair value, or future cash flows of financial assets and liabilities, will fluctuate due to movements in market prices. Market risk is composed of commodity and power price risk, foreign currency risk and interest rate risk, as applicable.

Commodity Price Risk

Pengrowth is exposed to commodity price risk as prices for oil and gas products fluctuate in response to many factors including local and global supply and demand, weather patterns, pipeline transportation, political stability and economic factors. Commodity price fluctuations are an inherent part of the oil and gas business. Pengrowth mitigates some of the exposure to commodity price risk to protect the return on acquisitions and provide a level of stability to operating cash flow. Pengrowth may utilize financial and physical delivery contracts to fix the commodity price associated with a portion of its future production. The use of forward and futures contracts are governed by formal policies and is subject to limits established by the Board of Directors. The Board of Directors and management may re-evaluate these limits as needed in response to specific events such as market activity, additional leverage, acquisitions or other transactions where Pengrowth’s capital structure may be subject to more risk from commodity prices.

Commodity Price Contracts

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

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

PENGROWTH 2017 Financial Results 35

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

During the first quarter of 2017, Pengrowth early settled its 2017 crude oil swap contracts in place at the time for an aggregate loss of $12.7 million.

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

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

Physical Delivery Contracts

As at December 31, 2017, physical delivery contracts were held for the purpose of delivery of non-financial items in accordance with Pengrowth's expected sales requirements. The prices per bbl, as per the table below, include an apportionment protection fee to guarantee flow assurance in the event export pipelines are restricted. Physical delivery contracts are not considered financial instruments and therefore, no asset or liability has been recognized in the Consolidated Financial Statements.

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

Foreign Exchange Risk

Pengrowth is exposed to foreign currency fluctuations as crude oil and natural gas prices received are referenced to U.S. dollar denominated prices.

Pengrowth is exposed to foreign currency fluctuation on the U.S. dollar and U.K. pound sterling denominated senior unsecured notes for both interest and principal payments. Pengrowth has mitigated some of this risk by entering into a series of futures and swap contracts in order to fix the foreign exchange rate on a portion of the U.S. dollar and the U.K. pound sterling denominated senior unsecured notes.

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

Pengrowth entered into a foreign exchange risk management contract when it issued the U.K. pound sterling term debt. This contract fixes 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: 

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

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

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

A series of swap contracts were transacted in order to fix the foreign exchange rate on a portion of Pengrowth’s U.S. dollar denominated term debt. Each swap requires Pengrowth to buy U.S. dollars at a predetermined rate and time based upon the maturity dates of the U.S. denominated term debt. 

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

PENGROWTH 2017 Financial Results 36

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

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

Foreign Denominated Term Debt Sensitivity to Foreign Exchange Rate

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

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

Interest Rate Risk

Pengrowth is exposed to interest rate risk on any outstanding balances on the Canadian dollar revolving Credit Facility.

Interest Rate Sensitivity - Bank Interest Cost

As at December 31, 2017, Pengrowth had $610.5 million of current and non-current long term debt (December 31, 2016 - $1.6 billion), and $nil of convertible debentures outstanding (December 31, 2016 - $0.1 billion) of which $109.0 million was based on floating interest rates (December 31, 2016 - $nil). A 1 percent increase in interest rates would increase pre-tax interest expense by approximately $1.1 million for the year ended December 31, 2017 (December 31, 2016 - $nil), assuming the amount was outstanding for the entire period.

PENGROWTH 2017 Financial Results 37

Summary of Gains and Losses on Risk Management Contracts

Pengrowth’s risk management contracts are recorded on the Consolidated Balance Sheets at their estimated fair value and split between current and non-current assets and liabilities on a contract by contract basis, netted by counterparty. Realized and unrealized gains and losses are included in the Consolidated Statements of Income (Loss).

The following tables provide details of the fair value of risk management contracts that appear on the Consolidated Balance Sheets and the unrealized and realized gains and losses on risk management recorded in the Consolidated Statements of Income (Loss).

As at and for the year ended December 31, 2017	Commodity contracts (1)			Power contracts			Foreign exchange contracts (2)			Total
Non-current portion of risk management assets	$	—		$	—		$	1.9		$	1.9
Current portion of risk management liabilities	(39.8		)	—			(0.2		)	(40.0		)
Non-current portion of risk management liabilities	—			—			(18.6		)	(18.6		)
Risk management assets (liabilities), end of year	$	(39.8	)	$	—		$	(16.9	)	$	(56.7	)
Less: Risk management assets (liabilities) at beginning of year	(54.0		)	—			(2.7		)	(56.7		)
Unrealized gain (loss) on risk management contracts for the year	$	14.2		$	—		$	(14.2	)	$	—
Realized gain (loss) on risk management contracts for the year	(19.8		)	—			(37.6		)	(57.4		)
Total unrealized and realized gain (loss) on risk management contracts for the year	$	(5.6	)	$	—		$	(51.8	)	$	(57.4	)
As at and for the year ended December 31, 2016	Commodity contracts(1)			Power contracts (3)			Foreign exchange contracts (2)			Total
Current portion of risk management assets	$	—		$	—		$	2.9		$	2.9
Non-current portion of risk management assets	—			—			1.0			1.0
Current portion of risk management liabilities	(54.0		)	—			(1.3		)	(55.3		)
Non-current portion of risk management liabilities	—			—			(5.3		)	(5.3		)
Risk management assets (liabilities), end of year	$	(54.0	)	$	—		$	(2.7	)	$	(56.7	)
Less: Risk management assets (liabilities) at beginning of year	370.5			(1.7		)	83.3			452.1
Unrealized gain (loss) on risk management contracts for the year	$	(424.5	)	$	1.7		$	(86.0	)	$	(508.8	)
Realized gain (loss) on risk management contracts for the year	385.7			(4.5		)	47.0			428.2
Total unrealized and realized gain (loss) on risk management contracts for the year	$	(38.8	)	$	(2.8	)	$	(39.0	)	$	(80.6	)

⁽¹⁾  Unrealized and realized gains and losses are presented as separate line items in the Consolidated Statements of Income (Loss).

⁽²⁾  Unrealized and realized gains and losses are included as part of separate line items in the Consolidated Statements of Income (Loss).

⁽³⁾  Unrealized gains and losses are included in other (income) expense. Realized gains and losses are included in operating expense.

PENGROWTH 2017 Financial Results 38

Fair Value

The fair value of cash and cash equivalents, accounts receivable, prepaid tax assessment, accounts payable and bank indebtedness approximate their carrying amount due to the short-term nature of those instruments. The fair value of the Canadian dollar term Credit Facility, as applicable, is equal to its carrying amount as the facility bears interest at floating rates and credit spreads within the facility are indicative of market rates. The fair values of the remediation trust funds are equal to their carrying amount as these assets are carried at their estimated fair value. The following tables provide fair value measurement information for other financial assets and liabilities.

					Fair value measurements using:
As at December 31, 2017	Carrying amount		Fair value		Quoted prices in active markets (Level 1)		Significant other observable inputs (Level 2)		Significant unobservable inputs (Level 3)
Financial Assets
Remediation trust funds	$	111.6	$	111.6	$	111.6	$	—	$	—
Fair value of risk management contracts	1.9		1.9		—		1.9		—
Financial Liabilities
U.S. dollar denominated term notes	460.4		509.5		—		509.5		—
Cdn dollar term notes	20.5		22.8		—		22.8		—
U.K. pound sterling denominated term notes	20.6		21.7		—		21.7		—
Fair value of risk management contracts	58.6		58.6		—		58.6		—
					Fair value measurements using:
As at December 31, 2016	Carrying amount		Fair value		Quoted prices in active markets (Level 1)		Significant other observable inputs (Level 2)		Significant unobservable inputs (Level 3)
Financial Assets
Remediation trust funds	$	106.5	$	106.5	$	106.5	$	—	$	—
Fair value of risk management contracts	3.9		3.9		—		3.9		—
Financial Liabilities
Convertible debentures	126.6		126.7		126.7		—		—
U.S. dollar denominated senior unsecured notes	1,496.0		1,527.7		—		1,527.7		—
Cdn dollar senior unsecured notes	39.9		41.3		—		41.3		—
U.K. pound sterling denominated unsecured notes	24.8		25.5		—		25.5		—
Fair value of risk management contracts	60.6		60.6		—		60.6		—

Level 1 Fair Value Measurements

Financial assets and liabilities are recorded at fair value based on quoted prices in active markets.

Level 2 Fair Value Measurements

Risk management contracts - the fair value of the risk management contracts is based on commodity, power and foreign exchange curves that are readily available or, in their absence, third-party market indications and forecasts priced on the last trading day of the applicable period.

Derivative contracts are recorded at fair value on the Consolidated Balance Sheets as current or long-term assets or liabilities, based on their values on a contract by contract basis, netted by counterparty. The derivative contracts fair values are all considered level 2 under the fair value hierarchy.

PENGROWTH 2017 Financial Results 39

The fair value of the term notes is determined based on the risk free interest rate on government debt instruments of similar maturities, adjusted for estimated credit risk, industry risk and market risk premiums.

CREDIT RISK

Credit risk is the risk of financial loss to Pengrowth if a counterparty to a financial instrument fails to meet its contractual obligations. A significant portion of Pengrowth’s accounts receivable are with customers in the oil and gas industry and are subject to normal industry credit risks. Uncertainty in the credit markets, should it exist, may restrict the ability of Pengrowth’s normal business counterparties to meet their obligations to Pengrowth. Additional credit risk could exist where little or none previously existed. Pengrowth manages its credit risk by performing a credit review on each marketing counterparty and following a credit practice that limits transactions according to the counterparty’s credit rating as assessed by Pengrowth. In addition, Pengrowth may require letters of credit or parental guarantees from certain counterparties to mitigate some of the credit risk associated with the amounts owing by the counterparty. The use of financial swap agreements involves a degree of credit risk that Pengrowth manages through its credit policies which are designed to limit eligible counterparties to those with investment grade credit ratings or better. The carrying value of accounts receivable and risk management assets represents Pengrowth’s maximum credit exposure.

Pengrowth sells a significant portion of its oil and gas to a limited number of counterparties. In 2017, Pengrowth has 2 counterparties that individually account for more than 10 percent of annual revenue. All of the counterparties are large trading companies and subject to regular internal credit reviews.

Pengrowth considers amounts over 90 days as past due. As at December 31, 2017, the amount of accounts receivable that were past due was not significant. Pengrowth has not recorded a significant allowance for doubtful accounts during 2017 or 2016 and has no significant bad debt provision at December 31, 2017. Pengrowth’s objectives, processes and policies for managing credit risk have not changed from the previous year.

The components of accounts receivable are as follows:

	As at
	December 31, 2017		December 31, 2016
Trade	$	97.5	$	110.3
Prepaid and other	8.2		16.3
	$	105.7	$	126.6

PENGROWTH 2017 Financial Results 40

LIQUIDITY RISK

Liquidity risk is the risk that Pengrowth will not be able to meet its financial obligations as they fall due. Pengrowth’s approach to managing liquidity is to ensure, as much as possible, that it will always have sufficient liquidity to meet its liabilities when due, under normal and stressed conditions. Management closely monitors cash flow requirements to ensure that it has sufficient cash on demand or borrowing capacity to meet operational and financial obligations over the next three years. Pengrowth maintains a secured $330.0 million revolving, committed term Credit Facility. Use of the remaining credit capacity is still subject to complying with the financial covenant as discussed in Note 9. Pengrowth’s term notes and term Credit Facilities are secured and equally ranked.

Pengrowth’s current and non-current financial liabilities are as follows:

As at December 31, 2017	Carrying amount		Contractual cash flows		Year 1		Year 2		Years 3-5		More than 5 years
Accounts payable	$	136.2	$	136.2	$	136.2	$	—	$	—	$	—
Commodity risk management contracts	39.8		39.8		39.8		—		—		—
Cdn dollar senior unsecured notes (2)	20.5		27.1		1.4		1.4		24.3		—
U.S. dollar denominated term notes (1)	460.4		601.3		30.2		65.2		284.0		221.9
U.K. pound sterling denominated term notes (1)	20.6		22.6		1.1		21.5		—		—
Cdn dollar term Credit Facility borrowings (2)	109.0		117.6		6.9		110.7		—		—
Finance leases	34.2		76.8		4.4		4.2		12.6		55.6
Foreign exchange risk management contracts	18.8		20.8		0.2		4.3		16.3		—
Other liabilities	2.3		3.2		—		1.4		0.3		1.5

⁽¹⁾  Contractual cash flows include future interest payments and term notes calculated at December 31, 2017 period end exchange rate.

⁽²⁾  Contractual cash flows include future interest payments.

As at December 31, 2016	Carrying amount		Contractual cash flows		Year 1		Year 2		Years 3-5		More than 5 years
Accounts payable	$	189.6	$	189.6	$	189.6	$	—	$	—	$	—
Convertible debentures	126.6		130.5		130.5		—		—		—
Commodity risk management contracts	54.0		54.0		54.0		—		—		—
Cdn dollar senior unsecured notes (1)	39.9		48.5		2.2		16.8		3.6		25.9
U.S. dollar denominated senior unsecured notes (1)	1,496.0		1,726.8		623.7		399.2		266.0		437.9
U.K. pound sterling denominated unsecured notes (1)	24.8		27.3		0.9		0.9		25.5		—
Finance leases	37.9		90.7		5.7		5.0		14.2		65.8
Foreign exchange risk management contracts	6.6		6.1		1.3		1.7		2.4		0.7
Other liabilities	4.4		8.3		0.6		2.9		2.8		2.0
Remediation trust fund payments	—		12.5		0.3		0.3		0.9		11.0

⁽¹⁾  Contractual cash flows include future interest payments and senior unsecured notes calculated at December 31, 2016 period end exchange rate.

FINANCIAL RISK MANAGEMENT CONTRACTS – GROSS AMOUNTS

Risk management contracts assets and liabilities are offset and the net amount presented in the Consolidated Balance Sheets when the Corporation has a legal right to offset the amounts and intends either to settle them on a net basis or to realize the asset and settle the liability simultaneously.

PENGROWTH 2017 Financial Results 41

The following table sets out gross amounts relating to risk management contracts assets and liabilities that have been presented on a net basis on the Consolidated Balance Sheets:

	As at
Gross amounts	December 31, 2017			December 31, 2016
Risk management contracts
Current asset	$	—		$	3.0
Non-current asset	1.9			1.0
Current liability	(40.0		)	(55.4		)
Non-current liability	(18.6		)	(5.3		)
	$	(56.7	)	$	(56.7	)

18. FOREIGN EXCHANGE (GAIN) LOSS

	Year ended December 31
	2017			2016
Currency exchange rate (Cdn$1 = U.S.$) at beginning of year	$	0.74		$	0.72
Currency exchange rate (Cdn$1 = U.S.$) at year end	$	0.80		$	0.74
Unrealized foreign exchange (gain) loss on U.S. dollar denominated debt (1)	$	(66.1	)	$	(46.8	)
Unrealized foreign exchange (gain) loss on U.K. pound sterling denominated debt (1)	0.5			(5.8		)
Total unrealized foreign exchange (gain) loss from translation of foreign denominated debt	$	(65.6	)	$	(52.6	)
Unrealized (gain) loss on U.S. foreign exchange risk management contracts (2)	$	15.0		$	80.6
Unrealized (gain) loss on U.K. foreign exchange risk management contracts	(0.8		)	5.4
Total unrealized (gain) loss on foreign exchange risk management contracts	$	14.2		$	86.0
Net unrealized foreign exchange (gain) loss	$	(51.4	)	$	33.4
Net realized foreign exchange (gain) loss (3)	$	38.4		$	(46.5	)

⁽¹⁾  Includes both principal and interest.

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

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

19. COMMITMENTS

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

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

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

⁽³⁾  Includes office rent and other commitments.

PENGROWTH 2017 Financial Results 42

20. CONTINGENCIES

Pengrowth has been named as a defendant in various litigation matters. The nature of these claims is usually related to settlement of normal operational issues and labour issues. The outcome of such claims against Pengrowth is not determinable at this time; however, their ultimate resolution is not expected to have a materially adverse effect on Pengrowth as a whole.

21. SUPPLEMENTARY DISCLOSURES

CONSOLIDATED STATEMENTS OF INCOME (LOSS)

Pengrowth’s Consolidated Statements of Income (Loss) are prepared primarily by the nature of expense, with the exception of employee compensation costs which are included in both operating and general and administrative expense line items.

The following table details the amount of total employee compensation costs (including share based compensation expense) included in the operating and general and administrative expense line items in the Consolidated Statements of Income (Loss).

	Year ended December 31
	2017		2016
Operating	$	30.1	$	44.1
General and administrative	35.5		50.2
Total employee compensation costs	$	65.6	$	94.3

KEY MANAGEMENT PERSONNEL

Pengrowth has determined that the key management personnel of the Corporation are its officers and directors. In addition to the officers’ salaries and directors’ fees, the Corporation also provides other compensation to both groups including long term equity based incentives.

The following table provides information on compensation expense related to officers and directors. During 2017, Pengrowth had 6 non-executive directors and 7 officers (2016 - 6 non-executive directors and 7 officers).

Year ended December 31, 2017	Wages & benefits paid		Bonus and other compensation paid		Share based compensation expense			Severance paid		Total
Directors	$	0.6	$	—	$	(0.6	)	$	—	$	—
Officers	2.2		2.7		1.9			—		6.8
	$	2.8	$	2.7	$	1.3		$	—	$	6.8
Year ended December 31, 2016	Wages & benefits paid		Bonus and other compensation paid		Share based compensation expense			Severance paid		Total
Directors	$	0.6	$	—	$	2.3		$	—	$	2.9
Officers	2.8		0.7		5.3			0.6		9.4
	$	3.4	$	0.7	$	7.6		$	0.6	$	12.3

PENGROWTH 2017 Financial Results 43

EX-99.4

SUPPLEMENTAL UNAUDITED DISCLOSURES

ABOUT OIL AND GAS PRODUCING ACTIVITIES REQUIRED UNDER UNITED

STATES GENERALLY ACCEPTED ACCOUNTING PRINCIPLES

SUPPLEMENTAL INFORMATION — OIL AND GAS PRODUCING ACTIVITIES

(unaudited)

The following are supplementary oil and gas disclosures required as a result of Pengrowth Energy Corporation ("Pengrowth") being an SEC registrant. All amounts pertain to Pengrowth’s audited annual consolidated financial statements prepared in accordance with International Financial Reporting Standards ("IFRS"). All amounts are in millions of Canadian dollars unless otherwise noted.

OIL AND GAS RESERVES

Users of this information should be aware that the process of estimating quantities of "proved" and "proved developed" crude oil and natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history, and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions to existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the significance of the subjective decisions required and variances in available data for various reservoirs make these estimates generally less precise than other estimates presented in connection with financial statement disclosures.

Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations.

Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

Canadian provincial royalties are determined based on a graduated percentage scale which varies with prices and production volumes. Canadian reserves, as presented on a net basis, assume royalty rates in existence at the time the estimates were made, Pengrowth’s estimated future production volumes and SEC Modernization of Oil and Gas Reporting rules, using the average of the first-day-of-the-month prices for the prior 12 month period. This same 12 month average price is also used in calculating the aggregate amount of (and changes in) future cash inflows related to the standardized measure of discounted future net cash flows. The unaudited supplemental information on oil and gas exploration and production activities for 2017 and 2016 has been presented in accordance with the SEC Modernization of Oil and Gas Reporting reserve estimation and disclosure rules. Future fluctuations in prices, production rates, or changes in political or regulatory environments could cause Pengrowth's share of future production from Canadian reserves to be materially different from that presented.

Subsequent to December 31, 2017, no major discovery or other favorable or adverse event is believed to have caused a material change in the estimates of proved or proved developed reserves as of that date.

1

COSTS INCURRED IN OIL AND GAS PROPERTY ACQUISITION, EXPLORATION AND DEVELOPMENT ACTIVITIES

Costs incurred in oil and gas producing activities for the years ended December 31 are as follows:

(millions of dollars)	2017			2016
Property acquisition costs
- Proved	$	0.1		$	1.3
- Unproved	—			—
Exploration costs	(0.3		)	0.3
Development costs	(289.9		)	20.2
Injectants costs	—			0.4
	$	(290.1	)	$	22.2

Acquisition costs include costs incurred to purchase, lease, or otherwise acquire oil and gas properties.

Development and exploration costs include the costs for drilling and equipping development and exploratory wells, constructing facilities to extract, treat, gather and store oil and gas, and land rights purchases. These costs also include capitalized amounts associated with asset retirement obligations and capitalized interest. Dispositions of provisions are deducted from development costs incurred.

Injectants (mostly ethane and methane) are used in miscible flood programs to stimulate incremental oil recovery. The cost of injectants purchased from third parties for miscible flood projects is deferred and amortized over the period of expected future economic benefit which is estimated to be 24 months. All properties with miscible floods were disposed of during 2017.

Pengrowth capitalizes a portion of general and administrative costs associated with exploration and development activities.

Approximately $237.8 million (2016 – $502.1 million) of capitalized costs to acquire and evaluate unproven and development properties has been excluded from depletion.

2

CAPITALIZED COSTS RELATING TO OIL AND GAS PRODUCING ACTIVITIES

The capitalized costs and related accumulated depreciation, depletion and amortization, including impairments, relating to Pengrowth’s oil and gas exploration, development and producing activities at December 31 consist of:

(millions of dollars)	2017		2016
Oil and natural gas assets	$	1,097.4	$	2,956.1
Add: Exploration and evaluation assets	232.0		496.3
	$	1,329.4	$	3,452.4
Unproved oil and gas properties
Unproven properties included in oil and natural gas assets	$	154.9	$	864.9
Exploration and evaluation assets	232.0		496.3
	$	386.9	$	1,361.2
Proved oil & gas properties	942.5		2,091.2
Total capitalized costs	$	1,329.4	$	3,452.4

3

OIL AND GAS RESERVE INFORMATION

All of Pengrowth’s proved oil, natural gas liquids, and natural gas reserves are located in Canada, in the provinces of Alberta, British Columbia, Saskatchewan and Nova Scotia. Pengrowth’s proved developed and undeveloped reserves after deductions of royalties are summarized below:

Net Proved Developed and Undeveloped Reserves After Royalties	Crude Oil			Bitumen			NGLs			Natural Gas
	MMbbls			MMbbls			MMbbls			Bcf
End of year 2015	39.7			95.3			10.7			331.4
Revisions of previous estimates (including infill drilling & improved recovery)	(1.2	)		16.0		a	5.0		b	21.7		b
Purchase of reserves in place	—			—			—			—
Sale of reserves in place	(4.3	)		—			(0.1	)		(6.6	)
Discoveries and extensions	—			36.1		c	0.9			8.0
Production	(3.9	)		(5.5	)		(2.3	)		(42.7	)
End of Year 2016	30.3			141.9			14.2			311.8
Revisions of previous estimates (including infill drilling & improved recovery)	0.2			1.9		d	0.2			9.9		e
Purchase of reserves in place	—			—			—			4.5		f
Sale of reserves in place	(26.4	)	g	—			(12.7	)	g	(179.1	)	g
Discoveries and extensions	—			5.4		h	—			28.6		i
Production	(2.5	)		(5.0	)		(1.7	)		(33.4	)
End of Year 2017	1.6			144.2			—			142.3
Notes Re Significant Changes:
(a) Primarily due to lower royalties for the Lindbergh oil sands development resulting from the lower constant bitumen price used in the reserve evaluation at December 31, 2016 and improved performance.
(b) Due to improved performance and infill drilling in various properties.
(c) Primarily due to reserves associated with regulatory approval of Lindbergh oil sands Phase 2 expansion.
(d) Primarily due to infill drilling and technical revisions due to digitized mapping at Lindbergh.
(e) Primarily due to improved constant pricing resulting in recovery of late life reserves.
(f) Acquisition of a small partner working interest in the Groundbirch area resulting in an increase of Total Proved Plus Probable Reserves.
(g) Primarily due to our non-core asset disposition program as described under "Acquisitions and Divestitures" on page 26 of Pengrowth's Annual Information Form, to our Form 40-F dated February 28, 2018.
(h) Proved reserve additions booked in Lindbergh for a previously cyclic steam stimulated ("CSS") area as described under the "Statement of Oil and Gas Reserves and Reserves data" on page 23 of Pengrowth's Annual Information Form, to our Form 40-F dated February 28, 2018.
(i) Proved Reserves booked at Groundbirch due to offsetting competitor activity.
Net Proved Developed and Undeveloped Reserves After Royalties	Crude Oil			Bitumen			NGLs			Natural Gas
	MMbbls			MMbbls			MMbbls			Bcf
Net Proved Developed Reserves After Royalty
End of year 2015	33.4			16.5			10.3			242.4
End of year 2016	26.5			13.9			11.7			207.6
End of year 2017	1.6			22.4			—			31.2
Net Proved Undeveloped Reserves After Royalty
End of year 2015	6.3			78.8			0.4			89.0
End of year 2016	3.8			128.0			2.5			104.2
End of year 2017	—			121.8			—			111.1

4

Notes:

1. Net after royalty reserves are Pengrowth’s lessor royalty, overriding royalty, and working interest share of the gross remaining reserves, after deduction of any crown, freehold and overriding royalties. Crown royalties are subject to change by legislation or regulation and vary depending on production rates, selling prices and potential timing of initial production.

2. Reserves are the estimated quantities of crude oil, natural gas and related substances anticipated from geological and engineering data to be recoverable from known accumulations, from a given date forward, by known technology, under existing operating conditions and the average of the commodity prices on the first day of each month for the years ended December 31, 2017 and 2016.

3. Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.

4. Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are reserves that are expected to be recovered from known accumulations where a significant expenditure is required.

5

STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL AND GAS RESERVES

The following information is based on crude oil and natural gas reserve and production volumes estimated by the independent engineering consultants of Pengrowth. It may be useful for certain comparison purposes, but should not be solely relied upon in evaluating Pengrowth or its performance. Further, information contained in the following table should not be considered as representative of realistic assessments of future cash flows, nor should the Standardized Measure of Discounted Future Net Cash Flows be viewed as representative of the current value of Pengrowth’s reserves.

The future cash flows presented below are based on cost rates, and statutory income tax rates in existence as of the date of the projections and the average of commodity prices in effect on the first day of each month for the year ended December 31, 2017 and December 31, 2016. It is expected that revisions to some estimates of crude oil and natural gas reserves may occur in the future, due to development and production of the reserves that may occur in periods other than those assumed, and actual prices realized and costs incurred may vary significantly from those used.

Management does not rely upon the following information in making investment and operating decisions. Such decisions are based upon a wide range of factors, including estimates of probable as well as proved reserves, and varying price and cost assumptions considered more representative of a range of possible economic conditions that may be anticipated.

The computation of the standardized measure of discounted future net cash flows relating to proved oil and gas reserves at December 31, 2017 was based on the following average of the first-day-of-the-month benchmark prices for the twelve-month period before the end of the year: Edmonton par crude oil price of $63.43/bbl (2016 - $52.12/bbl) and AECO natural gas price of $2.35/MMBtu (2016 - $2.18/MMBtu).

STANDARDIZED MEASURE OF DISCOUNTED FUTURE CASH FLOW RELATING TO PROVED OIL AND GAS RESERVES

The following table sets forth the standardized measure of discounted future net cash flows at 10% from projected production of Pengrowth’s crude oil and natural gas reserves at December 31, for the years presented.

(millions of dollars)	2017			2016
Future cash inflows	$	6,838		$	6,801
Future costs
- Future production costs	(3,388		)	(4,227		)
- Future developments costs	(1,919		)	(1,464		)
- Future income taxes	(12		)	—
Future net cash flows	$	1,519		$	1,110
Deduct: 10% annual discount factor	(777		)	(569		)
Standardized measure of discounted future net cash flows	$	742		$	541

6

CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE CASH FLOW RELATING TO PROVED OIL AND GAS RESERVES

At December 31, for the years presented, the following table sets forth the changes in the standardized measure of discounted future net cash flows at 10%.

(millions of dollars)	2017			2016
Future discounted net cash flow at beginning of year	$	541		$	713
Sales and transfers of oil and gas, net of production costs, produced during the period	(199		)	(599		)
Net change in sales & transfer prices related to future production	484			(474		)
Previously estimated development costs incurred during the period	117			63
Changes in estimated future development costs	(158		)	(92		)
Net change due to extensions, discoveries, and improved recovery	45			87
Change due to revisions (including infill drilling & improved recovery)	17			53
Accretion of discount	54			71
Acquisition of reserves	3			—
Sales of reserves in place	(156		)	(20		)
Net change in income taxes	(4		)	—
Other - unspecified	(2		)	739
Future discounted net cash flow at end of year	$	742		$	541

Note:

1. The schedules above are calculated using year-end costs, statutory tax rates and proved oil and gas reserves and the average of the commodity prices on the first day of each month for the years ended December 31, 2017 and 2016. The value of exploration properties and probable reserves, future exploration costs, future changes in oil and gas prices and in production and development costs are excluded because they are not individually significant.

7

OTHER OIL AND GAS INFORMATION

Exploration and Development Activities

The following table summarizes the number of wells drilled during the financial year ended December 31, 2017.

	Development		Exploration		Total
Wells	Gross	Net	Gross	Net	Gross	Net
Natural Gas	5.0	4.0	—	—	5.0	4.0
Crude Oil	—	—	—	—	—	—
Bitumen	12.0	12.0	—	—	12.0	12.0
Service	10.0	10.0	—	—	10.0	10.0
Stratigraphic Test	2.0	2.0	—	—	2.0	2.0
Dry	—	—	—	—	—	—
Total	29.0	28.0	—	—	29.0	28.0

The following table summarizes the number of wells drilled during the financial year ended December 31, 2016.

	Development		Exploration		Total
Wells	Gross	Net	Gross	Net	Gross	Net
Natural Gas	1.0	0.2	—	—	1.0	0.2
Crude Oil	—	—	—	—	—	—
Bitumen	—	—	—	—	—	—
Service	—	—	—	—	—	—
Stratigraphic Test	—	—	—	—	—	—
Dry	—	—	—	—	—	—
Total	1.0	0.2	—	—	1.0	0.2

The following table summarizes the number of wells drilled during the financial year ended December 31, 2015.

	Development		Exploration		Total
Wells	Gross	Net	Gross	Net	Gross	Net
Natural Gas	2.0	1.4	—	—	2.0	1.4
Crude Oil	7.0	5.4	1.0	0.3	8.0	5.7
Bitumen	—	—	—	—	—	—
Service	—	—	—	—	—	—
Stratigraphic Test	—	—	—	—	—	—
Dry	—	—	—	—	—	—
Total	9.0	6.8	1.0	0.3	10.0	7.1

8

Oil and Gas Wells

As at December 31, 2017, we had an interest in 594 gross (239 net) producing oil and natural gas wells and 1,282 gross (577 net) non-producing wells. All wells are onshore except for wells in Nova Scotia which are all offshore.

	Producing		Non-Producing		Total
	Gross	Net	Gross	Net	Gross	Net
Crude Oil Wells
Alberta	48	18	79	47	127	65
British Columbia	60	33	179	114	239	147
Saskatchewan	62	2	28	6	90	8
Bitumen Wells
Alberta	30	30	6	1	36	31
Natural Gas Wells
Alberta	252	93	81	44	333	137
British Columbia	122	60	222	126	344	187
Saskatchewan	1	1	10	2	11	3
Nova Scotia	19	2	2	—	21	2
Service Wells (1)
Alberta	—	—	132	81	132	81
British Columbia	—	—	183	121	183	121
Saskatchewan	—	—	347	24	347	24
Other (2)
Alberta	—	—	9	7	9	7
British Columbia	—	—	4	4	4	4
Saskatchewan	—	—	—	—	—	—
Total	594	239	1,282	577	1,876	817

Note:

(1) Service Wells include disposal, injector, water source and observation wells.

(2) Other includes standing, zonally abandoned and suspended wellbores with undefined zones.

9

EX-99.5

KPMG LLP

205 5th Avenue SW

Suite 3100

Calgary AB

T2P 4B9

Telephone (403) 691-8000

Fax (403) 691-8008

www.kpmg.ca

Consent of Independent Registered Public Accounting Firm

The Board of Directors of Pengrowth Energy Corporation

We consent to the use of our reports, each dated February 28, 2018, with respect to the financial statements and the effectiveness of internal control over financial reporting included in this annual report on Form 40-F.

We also consent to the incorporation by reference of such reports in the Registration Statements on Form F-3D (No. 333-180888) of Pengrowth Energy Corporation.

Chartered Professional Accountants

February 28, 2018

Calgary, Canada

KPMG LLP is a Canadian limited liability partnership and a member firm of the KPMG network of independent member firms affiliated with KPMG International Cooperative (“KPMG International”), a Swiss entity. KPMG Canada provides services to KPMG LLP.

EX-99.6

LETTER OF CONSENT

TO: Pengrowth Energy Corporation

2100, 222-3^rd Avenue SW

Calgary, Alberta T2P OB4

We hereby consent to the reference to our name and report evaluating Pengrowth Energy Corporation’s oil and gas reserves as of December 31, 2017 and the information derived from our reports, as described or incorporated by reference in: (i) Pengrowth Energy Corporation’s Annual Report on Form 40-F for the year ended December 31, 2017 and (ii) the Registration Statement on Form F-3D (File No. 333-180888) filed with the United States Securities and Exchange Commission pursuant to the Securities Exchange Act of 1934, as amended, or the Securities Act of 1933, as amended, as applicable.

Yours truly,

GLJ PETROLEUM CONSULTANTS LTD.

/s/ "Todd J. Ikeda"

Todd J. Ikeda, P. Eng

Vice President

Calgary, Alberta

February 28, 2018

______________________________________________________________

4100, 400 - 3rd Avenue S.W., Calgary, Alberta, Canada T2P 4H2 | (403) 266-9500 | GLJPC.com

EX-99.7

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED

PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Pengrowth Energy Corporation (the “Company”) on Form 40-F for the fiscal year ended December 31, 2017, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Derek W. Evans, President and Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:

1. The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Dated: February 28, 2018

/s/ Derek W. Evans

Name: Derek W. Evans

Title: President and Chief Executive Officer

EX-99.8

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED

PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Pengrowth Energy Corporation (the “Company”) on Form 40-F for the fiscal year ended December 31, 2017, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Christopher G. Webster, Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:

1.	The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
2.	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Dated: February 28, 2018

/s/ Christopher G. Webster

Name: Christopher G. Webster

Title: Chief Financial Officer

EX-99.9

CERTIFICATION PURSUANT TO RULE 13a-14 OR 15d-14 OF THE

SECURITIES EXCHANGE ACT OF 1934, AS ADOPTED PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Derek W. Evans, certify that:

1.	I have reviewed this annual report on Form 40-F of Pengrowth Energy Corporation;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the issuer as of, and for, the periods presented in this report;
4.	The issuer’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the issuer and have:

(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
(c)	Evaluated the effectiveness of the issuer’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d)	Disclosed in this report any change in the issuer’s internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the issuer’s internal control over financial reporting; and

5. The issuer’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the issuer’s auditors and the audit committee of the issuer’s board of directors (or persons performing the equivalent functions):

(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the issuer’s ability to record, process, summarize and report financial information; and
(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the issuer’s internal control over financial reporting.

Dated: February 28, 2018

/s/ Derek W. Evans

Name: Derek W. Evans

Title: President and Chief Executive Officer

EX-99.10

CERTIFICATION PURSUANT TO RULE 13a-14 OR 15d-14 OF THE

SECURITIES EXCHANGE ACT OF 1934, AS ADOPTED PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Christopher G. Webster, certify that:

1.	I have reviewed this annual report on Form 40-F of Pengrowth Energy Corporation;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the issuer as of, and for, the periods presented in this report;
4.	The issuer’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the issuer and have:

	(a)		Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
	(b)		Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
	(c)		Evaluated the effectiveness of the issuer’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
	(d)		Disclosed in this report any change in the issuer’s internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the issuer’s internal control over financial reporting; and
5.		The issuer’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the issuer’s auditors and the audit committee of the issuer’s board of directors (or persons performing the equivalent functions):

(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the issuer’s ability to record, process, summarize and report financial information; and
(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the issuer’s internal control over financial reporting.

Dated: February 28, 2018

/s/ Christopher G. Webster

Name: Christopher G. Webster

Title: Chief Financial Officer

XML

Document and Entity Information	12 Months Ended
	Dec. 31, 2017 shares
Document And Entity Information [Abstract]
Entity Registrant Name	PENGROWTH ENERGY Corp
Entity Central Index Key	0001088166
Document Type	40-F
Document Period End Date	Dec. 31, 2017
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2017
Document Fiscal Period Focus	FY
Entity Current Reporting Status	Yes
Entity Common Stock, Shares Outstanding	552,246,104

XML

CONSOLIDATED BALANCE SHEETS - CAD CAD in Millions		Dec. 31, 2017	[1]	Dec. 31, 2016
Current Assets
Cash and cash equivalents	[2]	CAD 1.1		CAD 286.7
Accounts receivable		105.7		126.6
Fair value of risk management contracts		0.0		2.9
Other assets		24.0		0.0
Assets held for sale		0.0		117.5
Current assets		130.8		533.7
Fair value of risk management contracts		1.9		1.0
Other assets		99.8		118.7
Property, plant and equipment		1,104.2		2,849.0
Exploration and evaluation assets		232.0		496.3
Deferred income taxes		342.2		118.4
TOTAL ASSETS		1,910.9		4,117.1
Current Liabilities
Accounts payable		136.2		189.6
Fair value of risk management contracts		40.0		55.3
Convertible debentures		0.0		126.6
Current portion of long term debt		0.0		537.0
Current portion of provisions and other liabilities		35.2		22.1
Current liabilities		211.4		930.6
Fair value of risk management contracts		18.6		5.3
Long term debt		610.5		1,023.7
Provisions and other liabilities		264.2		672.5
Liabilities		1,104.7		2,632.1
Shareholders' Equity
Shareholders' capital		4,829.7		4,815.1
Contributed surplus		13.3		22.9
Deficit		(4,036.8)		(3,353.0)
Equity		806.2		1,485.0
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY		CAD 1,910.9		CAD 4,117.1

[1] See Notes 2 and 14.

[2] See Notes 2 and 14.

XML

CONSOLIDATED STATEMENTS OF INCOME (LOSS) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	[1]	Dec. 31, 2016
REVENUES
Oil and gas sales	CAD 673.4		CAD 566.2
Royalties, net of incentives	(45.8)		(40.0)
Revenue from oil and gas sales (net royalties, net of incentives)	627.6		526.2
Realized gain (loss) on commodity risk management	(19.8)		385.7
Change in fair value of commodity risk management contracts	14.2		(424.5)
Revenue	622.0		487.4
EXPENSES
Operating	217.5		275.4
Diluent and other purchases	163.5		0.0
Transportation	27.1		33.7
General and administrative	61.5		83.6
Depletion, depreciation and amortization	207.6		349.9
Impairment	634.4		0.0
Operating expenses	1,311.6		742.6
OPERATING INCOME (LOSS)	(689.6)		(255.2)
Other (income) expense items
(Gain) loss on disposition of properties	62.6		27.1
Unrealized foreign exchange (gain) loss	(51.4)		33.4
Realized foreign exchange (gain) loss	38.4		(46.5)
Interest and financing charges	70.7		105.5
Restructuring costs	37.0		0.0
Loss on extinguishment of debt	56.7	[2]	0.0
Accretion	11.4		15.1
Other (income) expense	(7.4)		(2.7)
INCOME (LOSS) BEFORE TAXES	(907.6)		(387.1)
Deferred income tax (recovery) expense	(223.8)		(93.4)
NET INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS)	CAD (683.8)	[2]	CAD (293.7)
Earnings per share [abstract]
Basic (in CAD per share)	CAD (1.24)		CAD (0.54)
Diluted (in CAD per share)	CAD (1.24)		CAD (0.54)

[1] See Notes 2 and 14.

[2] See Notes 2 and 14.

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CONSOLIDATED STATEMENTS OF CASH FLOW CAD in Millions, $ in Millions		12 Months Ended
		Dec. 31, 2017 CAD		Dec. 31, 2016 CAD
OPERATING
Net income (loss) and comprehensive income (loss)		CAD (683.8)	[1],[2]	CAD (293.7)
Non-cash items
Depletion, depreciation, amortization and accretion		219.0	[2]	365.0
Impairment		634.4	[2]	0.0
Deferred income tax (recovery) expense		(223.8)	[2]	(93.4)
Unrealized foreign exchange (gain) loss		(51.4)	[2]	33.4
Change in fair value of commodity risk management contracts		(14.2)	[2]	424.5
Share based compensation		4.9	[2]	13.2
(Gain) loss on disposition of properties		62.6	[2]	27.1
Restructuring costs - onerous office lease contracts		26.5	[2]	0.0
Other items		0.9	[2]	0.6
Loss on extinguishment of debt		56.7	[1],[2]	0.0
Foreign exchange derivative settlements		37.6	[2]	(47.0)
Funds flow from operations		69.4	[2]	429.7
Interest and financing charges		70.7	[2]	105.5
Expenditures on remediation		(15.9)	[2]	(20.0)
Change in non-cash operating working capital		18.2	[2]	(21.5)
Cash flow from operating activities		142.4	[2]	493.7
FINANCING
Bank indebtedness (repayment)		0.0	[2]	(3.7)
Long term debt (repayment)		(937.2)	[2]	(104.0)
Convertible debentures repayment		(126.6)	[2]	0.0
Convertible debentures repurchase		0.0	[2]	(10.2)
Foreign exchange derivative settlements		(37.6)	[2]	47.0
Interest and financing charges paid		(100.8)	[2]	(108.6)
Cash flow from financing activities		(1,202.2)	[2]	(179.5)
INVESTING
Capital expenditures		117.9	[2]	64.4
Property acquisitions		(0.1)	[2]	(1.3)
Proceeds on property dispositions		910.2	[2]	60.2
Contributions to remediation trust funds and other items		(10.5)	[2]	(29.6)
Change in non-cash investing working capital		(7.5)	[2]	7.6
Cash flow from investing activities		774.2	[2]	(27.5)
CHANGE IN CASH AND CASH EQUIVALENTS		(285.6)	[2]	286.7
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR		286.7	[2]	0.0
CASH AND CASH EQUIVALENTS AT END OF YEAR	[2]	CAD 1.1	[3]	CAD 286.7

[1] See Notes 2 and 14.

[2] See Notes 2 and 14.

[3] See Notes 2 and 14.

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CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY - CAD CAD in Millions		Total		SHAREHOLDERS' CAPITAL		CONTRIBUTED SURPLUS		DEFICIT
Balance, beginning of year at Dec. 31, 2015				CAD 4,797.0		CAD 27.3		CAD (3,059.3)
Share based compensation				18.1		13.7
Exercise of share based compensation awards						(18.1)
Net income (loss)		CAD (293.7)						(293.7)
Balance, end of year at Dec. 31, 2016		1,485.0		4,815.1	[1]	22.9	[1]	(3,353.0)	[1]
Share based compensation	[1]			14.6		5.0
Exercise of share based compensation awards	[1]					(14.6)
Net income (loss)		(683.8)	[2],[3]					(683.8)
Balance, end of year at Dec. 31, 2017		CAD 806.2	[4]	CAD 4,829.7	[1]	CAD 13.3	[1]	CAD (4,036.8)	[1]

[1] See Notes 2 and 14.

[2] See Notes 2 and 14.

[3] See Notes 2 and 14.

[4] See Notes 2 and 14.

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BUSINESS OF THE CORPORATION

12 Months Ended

Dec. 31, 2017

Corporate Information And Statement of IFRS Compliance [Abstract]

BUSINESS OF THE CORPORATION

1. BUSINESS OF THE CORPORATION

Pengrowth Energy Corporation ("Pengrowth" or the "Corporation") is a Canadian resource company that is engaged in the production, development, exploration and acquisition of oil and natural gas assets. The Consolidated Financial Statements include the accounts of the Corporation, and its subsidiary, collectively referred to as Pengrowth. All inter-entity transactions have been eliminated.

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SIGNIFICANT ACCOUNTING POLICIES

12 Months Ended

Dec. 31, 2017

Disclosure of changes in accounting policies, accounting estimates and errors [Abstract]

SIGNIFICANT ACCOUNTING POLICIES

2. SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

These Consolidated Financial Statements have been prepared in accordance with the International Financial Reporting Standards (“IFRS”) issued by the International Accounting Standards Board (“IASB”) and International Financial Reporting Interpretations Committee (“IFRIC”). Except for the changes below, Pengrowth has consistently applied the accounting policies to all periods presented in these consolidated financial statements.

Pengrowth’s operations are viewed as a single operating segment by the chief operating decision maker (CEO) of the Corporation for the purpose of resource allocation and assessing performance.

The Consolidated Financial Statements were authorized for release by the Board of Directors on February 28, 2018.

Accounting Pronouncement adopted - IFRS 15 Revenue from Contracts with Customers

On May 28, 2014, the IASB issued IFRS 15 Revenue from Contracts with Customers ("IFRS 15"). The new standard is effective for annual periods beginning on or after January 1, 2018. Earlier application is permitted. On April 12, 2016, the IASB issued Clarification to IFRS 15, which is effective at the same time as IFRS 15. The standard contains a single model that applies to contracts with customers and two approaches to recognizing revenue: at a point in time or over time. The model features a contract-based five-step analysis of transactions to determine the nature of an entity's obligation to perform and whether, how much and when revenue is recognized. New estimates and judgmental thresholds have been introduced, which may affect the amount and/or timing of revenue recognized. The new standard applies to contracts with customers. It does not apply to insurance contracts, financial instruments or lease contracts, which fall in the scope of other IFRSs.

Pengrowth has elected in the fourth quarter of 2017 to early adopt IFRS 15 for 2017 using the cumulative effect method. Under this method, prior years' financial statements have not been restated and the cumulative effect on net earnings of the application of IFRS 15 to revenue contracts in progress at January 1, 2017 is nil. Pengrowth management reviewed its revenue streams and major contracts with customers using the IFRS 15 five step model and there were no material changes to net earnings or timing of produced petroleum revenue recognized. It should be noted, however, that certain Income Statement line item reclassifications were made. Refer to Note 14 for more information including additional disclosure as required under IFRS 15.

Impact of Early Adoption of IFRS 15 on Interim 2017 Financial Statements

As a result of the adoption of IFRS 15, no cumulative effect adjustment to retained earnings was required. In accordance with the new standard, effective January 1, 2017, Pengrowth includes sales of diluent and other products as well as processing income in its Oil and gas sales consistent with the application of IFRS 15 including its principal versus agent evaluation requirements. This change has no impact on operating income (loss), income (loss) before taxes, net income (loss) or Cash Flows. The adoption of IFRS 15 alters the presentation of, and calculations for, Oil and gas sales and Operating expenses, and introduces a new Income Statement line for Diluent and other purchases for 2017. As per the table below, certain amounts in 2017 unaudited interim financial statements have been adjusted as follows:

	2017
	Q1	Q2	Q3
Oil and gas sales as previously reported	166.5	147.2	91.5
Diluent and other sales	46.7	45.2	28.9
Processing income	6.7	5.5	4.7
Adjusted Oil and gas sales	219.9	197.9	125.1
Diluent and other purchases as previously reported	—	—	—
Cost of diluent and other purchases	46.7	45.2	28.9
Adjusted Diluent and other purchases	46.7	45.2	28.9
Operating expenses as previously reported	60.6	63.0	46.9
Processing income	6.7	5.5	4.7
Adjusted operating expenses	67.3	68.5	51.6

Revenue Recognition

Under IFRS 15, revenue from the sale of commodities is calculated by reference to consideration specified in contracts with customers and recognized when control of the product is transferred to the buyer. The nature of each of its performance obligations, including roles of third parties and partners, are evaluated to determine if the Company acts as a principal, and therefore recognizes revenue on a gross basis, or as an agent, and therefore recognizes revenue on a net basis. The Company acts as the principal when it controls the product delivered before the control passes to its customer.

Pengrowth earns revenue from the following major sources:

• Sales from the production of, and royalty (and gross overriding royalty) interests in, light oil, natural gas, natural gas liquids, sulphur and from the sale of diluted bitumen and purchased products;

• Fees charged to third parties for processing and other services (i.e. gas and other product processing, contract operating etc.) provided at facilities where Pengrowth has an ownership interest.

Revenue from the sale of diluted bitumen, light oil, natural gas, natural gas liquids and sulphur is recognized based on the consideration specified in contracts with customers. Pengrowth recognizes revenue when control of the product transfers to the buyer and collection is reasonably assured. This is generally at the point in time when the customer obtains legal title to the product which is when it is physically transferred to the pipeline or other transportation method agreed upon. Revenues from processing activities are recognized over time as processing occurs, and are generally billed monthly. Royalty income is recognized monthly as it accrues in accordance with the terms of the royalty agreements.

Pengrowth has reviewed its revenue streams and major contracts with customers using the IFRS 15 five step model and there are no material changes to timing of revenue recognized, however the gross versus net presentation resulted in material changes to certain items in the 2017 Income Statement with no impact to net income (loss).

When allocating the transaction price realized in contracts with multiple performance obligations over a longer period to multiple performance obligations using relative standalone selling prices, management is required to make estimates of the prices at which Pengrowth would sell the product separately to customers. When making this estimate, management considers market prices and market conditions and cash flows the entity intends to realize based on risk management policies, based on cost and cash flows the entity intends to realize based on risk management policies, based on cost and margin objectives. Pengrowth does not currently have any contracts with multiple performance obligations.

Property, Plant and Equipment (“PP&E”) and Exploration and Evaluation (“E&E”) Assets

Pengrowth capitalizes all costs of developing and acquiring oil and gas properties. These costs include lease acquisition costs, geological and geophysical expenditures, costs of drilling and completion of wells, plant and production equipment costs and related overhead charges. Pengrowth capitalizes a portion of general and administrative costs and share based compensation expense associated with exploration and development activities. Repairs and maintenance costs are expensed as incurred.

Property, Plant and Equipment

PP&E is stated at cost less accumulated depletion, depreciation and amortization, and accumulated impairment losses. The initial cost of an asset comprises its purchase price or construction cost, costs attributable to bringing the asset into operation, the initial estimate of asset retirement obligation and, for qualifying assets, borrowing costs. When significant parts of an item of PP&E, including oil and natural gas interests, have different useful lives, they are accounted for as separate items.

Exploration and Evaluation Assets

Costs of exploring for and evaluating certain oil and natural gas properties are capitalized within E&E assets. These E&E assets include lease acquisition costs, geological and geophysical expenditures, costs of drilling and completion of wells, plant and production equipment costs and related overhead charges. E&E assets do not include costs of general prospecting, or evaluation costs incurred prior to having obtained the legal rights to explore an area, which are expensed as incurred. Interest is not capitalized on E&E assets.

E&E assets are not depleted or depreciated and are carried forward until technical feasibility and commercial viability is considered to be determined. The technical feasibility and commercial viability is generally considered to be determined when proved plus probable reserves are determined to exist and the commercial production of oil and gas has commenced. A review of each exploration license or field is carried out, at least annually, to ascertain whether the project is technically feasible and commercially viable. Upon determination of technical feasibility and commercial viability, E&E assets attributable to those reserves are first tested for impairment and then reclassified from E&E assets to PP&E.

Subsequent Costs

Costs incurred subsequent to the determination of technical feasibility and commercial viability and the costs of replacing parts of PP&E are recognized as oil and natural gas interests only when they increase the future economic benefits embodied in the specific asset to which they relate. Such capitalized oil and natural gas interests generally represent costs incurred in developing proved and/or probable reserves and bringing in or enhancing production from such reserves, and are accumulated on a field or geotechnical area basis.

The carrying amount of any replaced or sold component is de-recognized. The costs of the day-to-day servicing of PP&E are expensed as incurred.

Pengrowth capitalizes a portion of general and administrative costs directly associated with exploration and development activities. Pengrowth capitalizes interest incurred in construction of qualifying assets, if applicable. Qualifying assets are defined by Pengrowth as capital projects that require capital expenditures over a period greater than one year, in order to produce oil or gas from a specific property. Interest capitalization to a qualifying asset ceases once the asset is substantially available for its intended use.

Assets Held for Sale

Non-current assets are classified as held for sale if their carrying amounts will be recovered through a sale transaction rather than through continuing use. This condition is met when the sale is highly probable and the asset is available for immediate sale in its present condition. For the sale to be highly probable, Management must be committed to sell the asset and an active program to locate a buyer and complete the sale must have been initiated. The asset must be actively marketed for sale at a price that is reasonable in relation to its current fair value and the sale should be expected to be completed within one year from the date of classification. Non-current assets classified as held for sale are measured at the lower of the carrying amount and fair value less costs of disposal, with impairments recognized in the Consolidated Statements of Income (Loss) in the period measured.

Dispositions

Gains or losses are recognized in the Consolidated Statements of Income (Loss) on dispositions of PP&E and certain E&E assets, including asset swaps, farm-out transactions, gross overriding royalty and property dispositions. The gain or loss is measured as the difference between the fair value of the proceeds and the carrying value of the assets disposed, including capitalized future asset retirement obligations and any associated goodwill.

Depletion and Depreciation

The net carrying value of developed or producing fields or groups of fields is depleted using the unit of production method by reference to the ratio of production in the period to the related proved plus probable reserves, taking into account estimated future development costs necessary to bring those reserves into production. Future development costs are estimated taking into account the level of development required to produce the reserves. These estimates are reviewed by independent reserve engineers at least annually. Pengrowth’s total proved plus probable reserves are estimated by an independent reserve evaluator and represent the "best estimate" of quantities of oil, natural gas and related substances to be commercially recoverable from known accumulations, from a given date forward, based on geological and engineering data. It is equally likely that the actual remaining quantities recovered will be greater than or less than the sum of the estimated proved plus probable reserves. Properties with no remaining production and reserves are fully depleted in the year that production ceases. Assets under construction are not depleted or depreciated until available for their intended use.

For other assets, depreciation is recognized in the Consolidated Statements of Income (Loss) using either a straight line or declining balance basis over the estimated useful lives of each part of an item of PP&E. The estimated useful lives for other assets for the current and comparative periods are as follows:

-	Office equipment	60 months
-	Leasehold improvements and finance leases	Lease term/Useful life
-	Computers	36 months
-	Deferred hydrocarbon injectants	24 months
-	Motor vehicles	60 months

Depreciation methods, useful lives and residual values are reviewed annually.

Farmouts

Under IFRS, farmouts are considered a disposition of a partial interest in a property. The proceeds on the disposition are generally considered to be the capital spent, or estimated to be spent, by the farmee in order to earn the interest. When the agreed upon work commitment has been completed, the farmee has earned their interest. It is at this stage that Pengrowth records a gain or loss on disposition, as the difference between the estimated capital and the carrying value of the disposed interest, in the Consolidated Statements of Income (Loss).

Leased Assets

Assets held by Pengrowth under leases which transfer to the Corporation substantially all of the risks and rewards of ownership are classified as finance leases. On initial recognition, the leased asset is measured at an amount equal to the lower of its fair value and the present value of the minimum lease payments. Subsequent to initial recognition, the asset is accounted for in accordance with the accounting policy applicable to that asset. Minimum lease payments made under finance leases are apportioned between the finance expense and the reduction of the outstanding liability. The finance expense is allocated to each period during the lease term so as to produce a constant periodic rate of interest on the remaining balance of the liability.

Assets held under other leases are classified as operating leases and are not recognized in the Consolidated Balance Sheets. Payments made under operating leases are recognized in the Consolidated Statements of Income (Loss) on a straight-line basis over the term of the lease. Lease incentives received are recognized as an integral part of the total lease expense, over the term of the lease.

At inception of certain arrangements, the Corporation determines whether such arrangement is or contains a lease. This will be the case if the following two criteria are met:

• The fulfillment of the arrangement is dependent on the use of a specific asset or assets; and

• The arrangement contains the right to use the asset(s).

Goodwill and Business Combinations

Goodwill may arise on business combinations and represents the excess of the cost of the acquisition over the net fair value of the identifiable assets, liabilities and contingent liabilities of the acquired assets or company. When the excess is negative, it is recognized immediately in the Consolidated Statements of Income (Loss).

Impairment

Non-Financial Assets

Property, Plant and Equipment

For the purpose of impairment testing, PP&E is grouped together into the smallest group of assets that generate cash inflows from continuing use that are largely independent of the cash inflows of other assets or groups of assets - cash generating unit (the “CGU”). CGUs are tested when there is an indication of impairment, such as sustained decreases in commodity prices or significant downward revisions in reserves volumes. An impairment loss is recognized to the extent the carrying value of the CGU exceeds its recoverable amount. Impairment losses are recognized in the Consolidated Statements of Income (Loss).

The recoverable amount of a CGU is the higher of its value in use and the fair value less costs to sell. In determining the recoverable amount, the estimated future cash flows are discounted to their present value using a pre-tax discount rate that reflects current market assessments of the cost of capital, which take into account the time value of money and the risks specific to the asset. The recoverable amount is generally computed by reference to the present value of the future cash flows expected to be derived from production of proved and probable reserves. Undeveloped land, contingent resources and infrastructure may also be considered in the recoverable amount.

Impairment losses in respect of PP&E recognized in prior periods are assessed at each reporting date for any indications that the loss has decreased or no longer exists. In such circumstances, the recoverable amount is determined and to the extent the loss is reduced, it is reversed. An impairment loss is reversed only to the lesser of the revised recoverable amount or the carrying amount that would have been determined, net of depletion and depreciation or amortization, if no impairment loss had been recognized.

Exploration and Evaluation Assets

E&E assets are tested for impairment when there is an indication that a particular E&E project may be impaired. Examples of indicators of impairment include a significant price decline over an extended period, the decision to delay or no longer pursue the E&E project, an expiry of the rights to explore in an area, or failure to receive regulatory approval. In addition, E&E assets are assessed for impairment upon their reclassification to producing assets (oil and natural gas interests in PP&E). In assessing the impairment of E&E assets, the carrying value of the E&E assets would be compared to their estimated recoverable amount and, in certain circumstances, could be tested in conjunction with PP&E impairment testing of related CGUs. The impairment of E&E assets would be recognized in the Consolidated Statements of Income (Loss).

Financial Assets

A financial asset is assessed at each reporting date to determine whether there is any objective evidence that it is impaired. A financial asset is considered to be impaired if objective evidence, including failure to pay on time, indicates that one or more events have had a negative effect on the estimated future cash flows of that asset.

An impairment loss in respect of a financial asset, measured at amortized cost, is calculated as the difference between its carrying amount and the present value of the estimated future cash flows discounted at the original effective interest rate. Significant financial assets are tested for impairment on an individual basis. The remaining financial assets are assessed collectively in groups that share similar credit risk characteristics.

Any impairment losses of financial assets are recognized in the Consolidated Statements of Income (Loss). An impairment loss is reversed if the reversal can be related objectively to an event occurring after the impairment loss was recognized. For financial assets measured at amortized cost, the reversal is recognized in the Consolidated Statements of Income (Loss).

Provisions and Other Liabilities

A provision is recognized if, as a result of a past event, the Corporation has a present legal or constructive obligation that can be estimated reliably and it is probable that an outflow of economic benefits will be required to settle the obligation. Provisions are determined by discounting the expected future cash flows at the appropriate discount rate. Provisions are not permitted for future operating losses.

Asset Retirement Obligations (“ARO”)

Pengrowth initially recognizes the net present value of an ARO in the period in which it is incurred when a reasonable estimate of the net present value can be made. The net present value of the estimated ARO is recorded as a liability, with a corresponding increase in the carrying amount of the related asset. The capitalized asset is depleted on the unit of production method based on proved plus probable reserves. The liability is increased each reporting period due to the passage of time and the amount of such accretion is expensed to income in the period. Actual costs incurred upon the settlement of the ARO are charged against the ARO. Management reviews the ARO estimate and changes, if any, are applied prospectively. Revisions made to the ARO estimate are recorded as an increase or decrease to the ARO liability with a corresponding change made to the carrying amount of the related asset. The carrying amount of both the liability and the capitalized asset, net of accumulated depreciation, are derecognized if the asset is subsequently disposed. The ARO liability is presented as Provisions on the Consolidated Balance Sheets. Refunds of previously paid offshore royalties are recognized as receivables only when production in a field has ceased and as abandonment and decommissioning spending has been incurred.

Pengrowth has placed cash in a segregated, independently managed, remediation trust fund account to fund ARO for the Sable Offshore Energy Project ("SOEP") property. The fund is reflected in Other Assets on the Consolidated Balance Sheets.

Finance Leases

Finance lease transactions are also categorized in Provisions and other liabilities.

Onerous Office Lease Contracts

Onerous office lease obligation related to excess office space is recognized when the unavoidable costs of the lease contracts over the remaining term exceed the economic benefits of the office lease. The onerous office lease provision is calculated as present value of future lease payments the Company is obligated to make under the lease contracts less any recoveries under current or anticipated sublease agreements over the remaining life of the lease.

Other Liabilities

Pengrowth also categorizes cash-settled long term incentive plan ("LTIP") grants andcash deferred bonus, within this grouping.

Income Taxes

Income tax (recovery) expense is composed of current and deferred tax. Income tax (recovery) expense is recognized in the Consolidated Statements of Income (Loss) except to the extent that it relates to items recognized directly in equity.

Current tax is the expected tax payable on the taxable income for the year, using tax rates enacted or substantively enacted at the reporting date, and any adjustment to tax payable in respect of previous years.

Deferred tax is recognized using the asset and liability method of accounting for income taxes. Under this method, income tax liabilities and assets are recognized for the estimated tax consequences attributable to differences between the amounts reported in the Consolidated Financial Statements and their respective tax bases, using substantively enacted income tax rates. Deferred tax assets are recognized for unused tax losses, unused tax credits and deductible temporary differences to the extent that it is probable that future taxable profits will be available against which they can be used. Future taxable profits are determined based on the reversal of relevant taxable temporary differences. If the amount of taxable temporary difference is insufficient to recognize a deferred tax asset in full, then future taxable profits, adjusted for reversals of existing temporary differences, are considered, based on Pengrowth's business plans.

The effect of a change in income tax rates on deferred income tax liabilities and assets is recognized in income in the period the change occurs. Deferred tax assets and liabilities are offset if there is a legally enforceable right to offset current tax liabilities and assets, and they relate to income taxes levied by the same tax authority on the same taxable entity. Deferred tax assets are reviewed at each reporting date and are reduced to the extent that it is no longer probable that the related tax benefit will be realized; these reductions are reversed when the probability of future taxable profits improves.

Pengrowth’s policy for income tax uncertainties is that tax benefits will be recognized only when it is more likely than not the position will be sustained on examination.

Share Based Compensation Plans

Pengrowth has share-settled and cash-settled share based compensation plans, which are described in Note 13.

i) Share-settled LTIP

Compensation expense is based on the estimated fair value of the share-settled award at the date of grant. Compensation expenses associated with the share-settled plans are recognized in the Consolidated Statements of Income (Loss) over the vesting period of the plan with a corresponding increase to contributed surplus. Pengrowth estimates the forfeiture rate for each type of share based award at the date of grant. Any consideration received upon the exercise of the awards together with the amount of non-cash compensation expense recognized in contributed surplus is recorded as an increase in shareholders’ capital at the time of exercise.

ii) Cash-settled LTIP

Each cash-settled RSU entitles the holder to a cash payment equivalent to the value of a number of common shares (including the reinvestment of deemed dividends, if applicable) which vest evenly over a period of three years or less. Furthermore, the independent members of the Board of Directors also receive cash-settled long term incentives called Phantom Deferred Share Units ("PhantomDSUs"). Each Phantom DSU entitles the holder to a cash payment equivalent to the value of a number of common shares (including the reinvestment of deemed dividends, if applicable) to be paid upon the individual ceasing to be a Director for any reason.

Compensation expense associated with the cash-settled LTIP is determined based on the fair value of the share units at the grant date and is subsequently adjusted to reflect the fair value of the share units at each period end, including notional dividends, as applicable. Pengrowth estimates the forfeiture rate for each type of share based award at the date of grant. This valuation incorporates the period end share price and the number of cash-settled LTIP units outstanding at each period end. Compensation expense is recognized in the Statements of Income (Loss) with a corresponding increase or decrease in liabilities. Classification of the associated short term and long term liabilities is dependent on the expected payout dates.

Financial Instruments

Financial instruments are utilized by Pengrowth to manage its exposure to commodity and power price fluctuations, as well as foreign currency exposures. Pengrowth’s policy is not to utilize financial instruments for trading or speculative purposes.

Financial instruments are classified into one of five categories: (i) fair value through profit or loss, (ii) held to maturity investments, (iii) loans and receivables, (iv) available for sale financial assets or (v) other liabilities.

Accounts receivable are classified as loans and receivables which are measured at amortized cost.

Investments held in the remediation trust funds and other investments have been designated as fair value through profit or loss and are measured at fair value. Any change in the fair value is recognized in the Consolidated Statements of Income (Loss).

Bank indebtedness, accounts payable, convertible debentures and long term debt have been classified as other liabilities which are measured at amortized cost using the effective interest rate method.

Pengrowth has accounted for its physical delivery sales contracts, which were entered into and continue to be held for the purpose of receipt or delivery of non-financial items in accordance with its expected purchase, sale or usage requirements as executory contracts. As such, these contracts are not considered to be derivative financial instruments and have not been recorded at fair value on the Consolidated Balance Sheets. Settlements on these physical delivery sales contracts are recognized in revenue in the period of settlement.

All derivatives must be classified as fair value through profit or loss and measured at fair value with changes in fair value over a reporting period recognized in net income (loss).

The receipts or payments arising from derivative commodity contracts are presented as realized gain (loss) on commodity risk management while the unrealized gains and losses are presented as changes in fair value of commodity risk management contracts.

The receipts or payments arising from derivative power contracts are included in operating expenses. The unrealized gains and losses on derivative power contracts are included in other (income) expense.

The receipts or payments arising from derivative foreign exchange contracts are presented as realized foreign exchange (gain) loss while the unrealized gains and losses are presented as unrealized foreign exchange (gain) loss.

Transaction costs incurred in connection with the issuance of term debt instruments with a maturity of greater than one year are deducted against the carrying value of the debt and amortized to net income (loss) using the effective interest rate method over the expected life of the debt.

Pengrowth capitalizes transaction costs incurred in connection with the renewal of the revolving Credit Facility with a maturity date greater than one year and amortizes the cost to net income (loss) on a straight line basis over the term of the facility.

Fair Value Measurement

All financial assets and liabilities for which fair value is measured or disclosed in the Consolidated Financial Statements are further categorized using a three-level hierarchy that reflects the significance of the lowest level of inputs used in determining fair value:

• Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

• Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1. Prices in Level 2 are either directly or indirectly observable as of the reporting date. Level 2 valuations are based on inputs, including quoted forward prices for commodities, time value and volatility factors, which can be substantially observed or corroborated in the marketplace.

• Level 3 – Valuations in this level are those with inputs for the asset or liability that are not based on observable market data.

Implementation of IFRS 9 (2014) - Financial Instruments

Pengrowth intends to adopt IFRS 9 (2014) in its Consolidated Financial Statements for the annual period beginning on January 1, 2018. The standard is generally required to be adopted retrospectively with or without restatement of prior periods in accordance with transition requirements. Pengrowth does not anticipate changes in measurement or reclassification of its financial instruments from implementation of IFRS 9 (2014).

Foreign Currency

The functional and reporting currency of the Corporation is Canadian dollars. Transactions in foreign currencies are translated to Canadian dollars at the exchange rates on the date of the transactions. Monetary assets and liabilities denominated in foreign currencies are translated into Canadian dollars at the exchange rate in effect on the Consolidated Balance Sheet date. Foreign exchange gains and losses are recognized in the Consolidated Statements of Income (Loss).

Jointly Controlled Operations

A significant proportion of Pengrowth’s petroleum and natural gas development and production activities are conducted through jointly controlled operations that are not conducted through separate vehicles and accordingly, the accounts reflect only Pengrowth’s interest in such activities.

Related Parties

Related parties are persons or entities that have control or significant influence over Pengrowth, as well as key management personnel. Note 21 provides information on compensation expense related to key management personnel. Pengrowth has no significant transactions with any other related parties.

Diluent and other purchases

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

Equity Investment

Pengrowth utilizes the equity method of accounting for investments subject to significant influence, if applicable. Under this method, investments are initially recorded at cost and adjusted thereafter to include Pengrowth’s pro rata share of post-acquisition earnings. Any dividends received or receivable from the investee would reduce the carrying value of the investment.

Estimates

The preparation of 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 Consolidated Financial Statements and revenues and expenses during the reporting year. Actual results could differ from those estimated.

In particular, information about significant areas of estimation uncertainty and critical judgments in applying accounting policies that have the most significant effect on the amounts recognized in the Consolidated Financial Statements is described below:

Estimating oil and gas reserves and contingent resources

Pengrowth engages a qualified, independent oil and gas reserves evaluator to perform an estimation of the Corporation’s oil and gas reserves at least annually and contingent resources on an ad hoc basis. Reserves form the basis for the calculation of depletion charges, while oil and gas reserves and contingent resources are used in the assessment of impairment of goodwill and oil and gas assets. Reserves and contingent resources are estimated using the reserve definitions and guidelines prescribed by National Instrument 51-101 (“NI 51-101”) and the Canadian Oil and Gas Evaluation Handbook (“COGEH”).

Proved plus probable reserves are defined as the "best estimate" of quantities of oil, natural gas and related substances estimated to be commercially recoverable from known accumulations, from a given date forward, based on drilling, geological, geophysical and engineering data, the use of established technology and specified economic conditions. It is equally likely that the actual remaining quantities recovered will be greater than or less than the sum of the estimated proved plus probable reserves. The estimates are made using all available geological and reservoir data as well as historical production data. Estimates are reviewed and revised as appropriate. Revisions occur as a result of changes in prices, costs, fiscal regimes and reservoir performance or a change in Pengrowth's plans with respect to future development or operating practices.

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

Determination of CGUs

The recoverability of development and production asset carrying values are assessed at the CGU level. Determination of what constitutes a CGU is subject to management’s judgment. The asset composition of a CGU can directly impact the recoverability of the assets included therein. In assessing the recoverability of oil and gas properties, each CGU's carrying value is compared to its recoverable amount, defined as the fair value less costs to sell.

Asset Retirement Obligations

Pengrowth estimates obligations under environmental regulations in respect of decommissioning and site restoration. These obligations are determined based on the expected present value of expenses required in the process of plugging and abandoning wells, dismantling of wellheads, production and transportation facilities and restoration of producing areas in accordance with relevant legislation, discounted from the date when expenses are expected to be incurred. Most of the abandonment of Pengrowth's wells is estimated to take place far in the future. Therefore, changes in estimated timing of future expenses, estimated logistics of performing abandonment work, the inflation assumption, and the discount rate used to present value future expenses could have a significant effect on the carrying amount of the decommissioning provision.

Impairment testing

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

Fair value of risk management contracts

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

Valuation of trade and other receivables, and prepayments to suppliers

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

Net Income (Loss) per Share

Basic net income (loss) per share is calculated using the weighted average number of shares outstanding for the year. Diluted net income (loss) per share amounts includes the dilutive effect of share units under the share-settled long term incentive plans using the treasury stock method. The treasury stock method assumes that any proceeds obtained on the exercise of any dilutive share units would be used to repurchase common shares at the average trading price during the period.

The dilutive effect of convertible debentures is calculated using net income (loss) for the period, adjusted for the after tax interest on the convertible debentures assuming they were converted at the start of the period; and adding to the diluted number of shares the weighted average shares issuable if the convertible debentures were converted at the start of the period.

Cash and Term Deposits

Cash and term deposits include demand deposits and term deposits with original maturities of less than 90 days.

OTHER ACCOUNTING PRONOUNCEMENTS ADOPTED

Disclosure Initiative Amendments to IAS 7

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

COMPARATIVE FIGURES

Certain prior years' comparative figures have been reclassified to conform to presentation adopted in the current year.

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ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED

12 Months Ended

Dec. 31, 2017

Disclosure of changes in accounting policies, accounting estimates and errors [Abstract]

ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED

3. ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED

IFRS 9 Financial Instruments

In July 2014, the IASB issued the complete IFRS 9 ("IFRS 9 (2014)"). The mandatory effective date of IFRS 9 (2014) is for annual periods beginning on or after January 1, 2018 and must be applied retrospectively with some exemptions. Early adoption is permitted. The restatement of prior periods is not required and is only permitted if information is available without the use of hindsight. IFRS 9 (2014) introduces new requirements for the classification and measurement of financial assets. Under IFRS 9 (2014), financial assets are classified and measured based on the business model in which they are held and the characteristics of their contractual cash flows. The standard introduces additional changes relating to financial liabilities. It also amends the impairment model by introducing a new ‘expected credit loss’ model for calculating impairment. Pengrowth does not anticipate material changes in the carrying value of its financial instruments nor from the credit loss impairment model upon adoption of IFRS 9 (2014).

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

IFRS 9 (2014) also includes a new general hedge accounting standard which aligns hedge accounting more closely with risk management. This new standard does not fundamentally change the types of hedging relationships or the requirement to measure and recognize ineffectiveness; however it will provide more hedging strategies that are used for risk management to qualify for hedge accounting and introduce more judgment to assess the effectiveness of a hedging relationship. Special transitional requirements have been set for the application of the new general hedging model. Pengrowth does not currently apply hedge accounting and does not currently intend to apply hedge accounting to its existing risk management contracts.

IFRS 16 Leases

In January 2016, the IASB issued the complete IFRS 16 Leases ("IFRS 16") which replaces IAS 17, Leases. The effective date of IFRS 16 is for annual periods beginning on or after January 1, 2019 and early adoption is permitted. Under IFRS 16, a single recognition and measurement model will apply for lessees which will require recognition of assets and liabilities for most leases. Pengrowth is currently evaluating the impact that the adoption of this standard will have on its financial statements.

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OTHER ASSETS

12 Months Ended

Dec. 31, 2017

Disclosure Of Other Assets [Abstract]

OTHER ASSETS

4. OTHER ASSETS

	As at
	December 31, 2017		December 31, 2016
Remediation trust funds - current	$	24.0	$	—
Remediation trust funds - non-current	87.6		106.5
Prepaid tax assessment	12.2		12.2
	$	123.8	$	118.7

REMEDIATION TRUST FUNDS

Pengrowth has a contractual obligation to make contributions to an independently managed remediation trust fund that is used to fund the ARO of the SOEP properties and facilities. In 2016, Pengrowth made a monthly contribution to the fund at a rate of $6.64/MMBtu of its share of natural gas production and $13.29/bbl of its share of natural gas liquids production from SOEP. In 2017, the rates decreased to $4.04/MMBtu of Pengrowth's share of natural gas production and $7.59/bbl of Pengrowth's share of natural gas liquids production. The investment in the SOEP fund is classified as fair value through profit or loss. Investment income is recognized when earned and is recorded in other (income) expense.

Pengrowth is expected to spend approximately $24 million in 2018 for its share of the estimated costs of the SOEP abandonment and remediation program. The planned spending will be funded through the remediation trust fund, a portion of which was classified as current asset in the Consolidated Balance Sheet at December 31, 2017.

During the third and fourth quarters of 2017, Pengrowth disposed of its interests in the Judy Creek properties in the Swan Hills area, including associated remediation trust funds totaling approximately $4.8 million.

The following table reconciles Pengrowth’s investment in remediation trust funds for the periods noted below:

	Remediation Trust Funds
Balance, December 31, 2015	$	79.6
Contributions	26.9
Remediation expenditures	(0.9		)
Investment income	3.2
Unrealized gain (loss)	(2.3		)
Balance, December 31, 2016	$	106.5
Contributions	14.0
Remediation expenditures	(6.6		)
Investment income	3.1
Unrealized gain (loss)	(0.6		)
Dispositions	$	(4.8	)
Balance, December 31, 2017	$	111.6

PREPAID TAX ASSESSMENT

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

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PROPERTY, PLANT AND EQUIPMENT ("PP&E")

12 Months Ended

Dec. 31, 2017

Property, plant and equipment [abstract]

PROPERTY, PLANT AND EQUIPMENT (PP&E)

5. PROPERTY, PLANT AND EQUIPMENT ("PP&E")

Cost or deemed cost	Oil and natural gas assets			Other equipment			Total
Balance, December 31, 2015	$	6,973.5		$	88.9		$	7,062.4
Additions to PP&E	89.9			1.9			91.8
Property acquisitions	1.3			—			1.3
Change in asset retirement obligations	(34.4		)	—			(34.4		)
Divestitures	(191.5		)	—			(191.5		)
Balance, December 31, 2016	$	6,838.8		$	90.8		$	6,929.6
Additions to PP&E	120.7			0.8			121.5
Property acquisitions	0.1			—			0.1
Change in asset retirement obligations	9.3			—			9.3
Divestitures	(3,151.2		)	(3.7		)	(3,154.9		)
Balance, December 31, 2017	$	3,817.7		$	87.9		$	3,905.6
Accumulated depletion, amortization and impairment losses	Oil and natural gas assets			Other equipment			Total
Balance, December 31, 2015	$	3,639.5		$	76.1		$	3,715.6
Depletion and amortization for the period	345.6			4.3			349.9
Divestitures	(102.4		)	—			(102.4		)
Balance, December 31, 2016	$	3,882.7		$	80.4		$	3,963.1
Depletion and amortization for the period	204.4			3.2			207.6
Impairment	504.4			—			504.4
Divestitures	(1,871.2		)	(2.5		)	(1,873.7		)
Balance, December 31, 2017	$	2,720.3		$	81.1		$	2,801.4
Net book value	Oil and natural gas assets			Other equipment			Total
As at December 31, 2017
Assets held for sale	$	—		$	—		$	—
Long term	1,097.4			6.8			1,104.2
	$	1,097.4		$	6.8		$	1,104.2
As at December 31, 2016
Assets held for sale	$	117.5		$	—		$	117.5
Long term	2,838.6			10.4			2,849.0
	$	2,956.1		$	10.4		$	2,966.5

For the year ended December 31, 2017, $2.3 million (December 31, 2016 – $3.2 million) of directly attributable general and administrative costs were capitalized to PP&E.

At December 31, 2017, $5.8 million (December 31, 2016 - $5.8 million) of net book value relating to the Lindbergh project was excluded from the calculation of depletion as those amounts were considered a project in the construction phase.

Pengrowth capitalizes interest for qualifying assets in the construction phase based on costs incurred on the project and the average cost of borrowing. During the year ended December 31, 2017, $3.7 million (December 31, 2016 – $3.0 million) of interest was capitalized on the Lindbergh Project to PP&E using Pengrowth's weighted average cost of debt of 5.7 percent (December 31, 2016 – 5.7 percent).

In 2017, Pengrowth executed and completed a substantial asset disposition program to enable it to reduce indebtedness and focus on its key growth assets.

In the first quarter, Pengrowth successfully closed the sale of a 4.0 percent gross overriding royalty ("GORR") interest on its Lindbergh thermal property and certain seismic assets for proceeds of $250.0 million.

In the third quarter of 2017, Pengrowth successfully closed the disposition of its Judy Creek area assets in north central Alberta and its Olds/Garrington area assets in central Alberta for aggregate proceeds of $485.0 million, before customary adjustments.

In the fourth quarter of 2017, Pengrowth successfully closed the disposition of its remaining Swan Hills area assets in north central Alberta for proceeds of $150.0 million, before customary adjustments and closed the sale of the vast majority of its remaining non-core legacy assets in Alberta for nominal cash consideration and the assumption of abandonment and reclamation liabilities by the purchaser.

As a result of dispositions that closed in 2017, approximately $3.2 billion of costs and $1.9 billion of accumulated depletion were removed from PP&E.

IMPAIRMENT

Impairment charges recorded for the year ended December 31, 2017 totaled $634.4 million (December 31, 2016 - $nil) of which $504.4 million represented PP&E impairments. Throughout 2017's asset dispositions, there were several instances where a purchase and sale agreement ("PSA") was signed subsequent to the respective quarter end for proceeds less than net book value, therefore, being an indicator of impairment. In these situations, where the sales price in a PSA was below the carrying amount, an impairment was recorded. In addition, remaining assets in the Southern and Northern CGUs were impaired down to $nil based on the nominal value received for similar asset transactions.

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

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EXPLORATION AND EVALUATION ASSETS ("E&E")

12 Months Ended

Dec. 31, 2017

Exploration For And Evaluation Of Mineral Resources [Abstract]

EXPLORATION AND EVAULATION ASSETS (E&E)

6. EXPLORATION AND EVALUATION ASSETS ("E&E")

Cost or deemed cost
Balance, December 31, 2015	$	494.8
Additions	1.5
Balance, December 31, 2016	$	496.3
Divestitures	(134.3		)
Impairment	(130.0		)
Balance, December 31, 2017	$	232.0

In the second quarter of 2017, Pengrowth closed the sale of its non-producing Montney lands at Bernadet in north eastern British Columbia for cash consideration of $92.0 million.

In the third quarter of 2017, Pengrowth announced that the agreement to sell certain of its Swan Hills area assets for $180.0 million was terminated. Included in this disposition were the assets in the non producing Devil area which were recorded as an E&E asset. None of the purchase price was attributed to the Devil lands resulting in a loss on assets held for sale of $9.0 million in the first quarter of 2017. Pengrowth subsequently closed the sale of these assets for $150.0 million cash consideration, subject to customary adjustments. Included in this disposition are the Devil lands which were part of the terminated sale in July.

IMPAIRMENT TESTING

For the year ended December 31, 2017, Pengrowth evaluated Groundbirch gas property for an impairment in conjunction with the Montney CGU, comprising both PP&E and E&E, due to the negative impact resulting from the significant downturn in the forward natural gas benchmark prices late in 2017. This was in accordance with Pengrowth's policy and IFRS which states that the impairment of ongoing E&E projects should be assessed on the cash flow from the applicable CGUs in the operating segment. It was determined that the recoverable amount was below the carrying amount, thus a $129.0 million impairment on the Groundbirch E&E asset was recorded in the fourth quarter of 2017. In addition, $1.0 million impairment was recognized on other minor E&E projects as no further exploration or evaluation is intended on those projects.

The recoverable amount is generally computed by reference to the present value of the future cash flows expected to be derived from production of proved plus probable reserves for the operating segment. Contingent resources were also considered in the recoverable amount. Changes in forward price estimates, production costs or recovery rates may change the economic status of contingent resources and may ultimately result in contingent resources being restated. The Groundbirch E&E impairment test was based on proved reserve values using a pre-tax discount rate of 10 percent, probable reserve values using a pre-tax discount rate of 12 percent, independent reserves evaluator January 1, 2018 forecast pricing and an inflation rate of 2 percent, and contingent resources using a pre-tax discount rate of 15 percent. The recoverable amount was determined using value in use.

The estimates of the above recoverable amounts were determined based on the following information, as applicable:

The net present value of the CGUs oil and gas reserves using:

i. Proved plus probable reserves as estimated by Pengrowth’s independent reserves evaluator, and

ii. The commodity price forecast of Pengrowth’s independent reserves evaluator as noted below,

Discounted at an estimated market discount rate.

Key input estimates used in the determination of cash flows from oil and gas reserves include the following:

(a) Reserves. Assumptions that are valid at the time of reserve estimation may change significantly when new information becomes available. Changes in forward price estimates, production costs or recovery rates may change the economic status of reserves and may ultimately result in reserves being restated.

(b) Oil and natural gas prices. Forward price estimates for oil and natural gas are used in the cash flow model.

Commodity prices have fluctuated widely in recent years due to global and regional factors including supply and demand fundamentals, inventory levels, exchange rates, weather, economic and geopolitical factors.

(c) Discount rate. The discount rate used to calculate the net present value of cash flows is based on estimates of an approximate cost of capital for potential acquirers of Pengrowth or Pengrowth’s CGUs. Changes in the general economic environment could result in significant changes to this estimate.

Below are the forward natural gas price estimates used in the December 31, 2017 impairment test:

	AECO gas (1)
Year	(Cdn$/MMBtu)
2018	2.20
2019	2.54
2020	2.88
2021	3.24
2022	3.47
2023	3.58
2024	3.66
2025	3.73
2026	3.80
2027	3.88
Thereafter	+ 2.0 percent/yr

⁽¹⁾  Prices represent forecasted amounts as at January 1, 2018 by Pengrowth's independent reserves evaluator.

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CONVERTIBLE DEBENTURES

12 Months Ended

Dec. 31, 2017

Disclosure of detailed information about financial instruments [abstract]

CONVERTIBLE DEBENTURES

7. CONVERTIBLE DEBENTURES

On March 31, 2017, all $126.6 million of the outstanding convertible debentures matured and were repaid and settled with cash on hand.

The following table summarizes the activity associated with the convertible debentures:

	Series B - 6.25 percent
Maturity date	March 31, 2017
Conversion price (per Pengrowth share)	$	11.51
Balance, December 31, 2015	$	137.0
Repurchase of convertible debentures	(10.2		)
Premium accretion	(0.2		)
Balance, December 31, 2016	$	126.6
Repayment of convertible debentures	(126.6		)
Balance, December 31, 2017	$	—
Face value, December 31, 2017	$	—

8. LONG TERM DEBT

AMENDMENTS TO LONG TERM DEBT

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

• The prepayment of all of the term notes due August 21, 2018 (U.S.$265 million and Cdn$15 million) and additional prepayments of Cdn$115.4 million of principal during the fourth quarter of 2017 on the remaining outstanding term notes.

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

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

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

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

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

• The remaining outstanding term notes maturing in 2019 through 2024 are subject to a 2.0 percentage point increase in interest rates (which increases to 3.0 percentage points on January 1, 2020). A one-time amendment fee of 0.5 percent on outstanding term notes was also paid to the holders of term notes due after 2018.

• The aggregate credit limit under the Credit Facility was reduced to $330 million following the closing of the Swan Hills asset sale, the $50 million Demand Credit Facility was eliminated and interest rates under the Credit Facility increased by 2.0 percentage points. A one time amendment fee of 0.5 percent of the aggregate credit limit was paid to the syndicate members of the Credit Facility.

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

Financial Covenants

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

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

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

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

As at December 31, 2017, Pengrowth had the following outstanding long term debt:

	As at
	December 31, 2017		December 31, 2016
U.S. dollar denominated term notes:
400 million at 6.35 percent due July 26, 2017	$	—	$	537.0
265 million at 6.98 percent due August 21, 2018 (1)	—		355.6
35 million at 5.49 percent due October 18, 2019 (2)	35.3		46.9
115.5 million at 7.98 percent due May 11, 2020 (3)	118.3		154.8
105 million at 6.07 percent due October 18, 2022 (4)	107.1		140.6
195 million at 6.17 percent due October 18, 2024 (5)	199.7		261.1
	$	460.4	$	1,496.0
U.K. pound sterling denominated term notes:
15 million at 5.45 percent due October 18, 2019 (6)	$	20.6	$	24.8
Canadian dollar term notes:
15 million at 6.61 percent due August 21, 2018 (1)	$	—	$	15.0
25 million at 6.74 percent due October 18, 2022 (7)	20.5		24.9
	$	20.5	$	39.9
Canadian dollar term Credit Facility borrowings	$	109.0	$	—
Total long term debt	$	610.5	$	1,560.7
Current portion of long term debt	$	—	$	537.0
Non-current portion of long term debt	610.5		1,023.7
	$	610.5	$	1,560.7

⁽¹⁾  There was no outstanding balance following the early repayment on October 12, 2017.

⁽²⁾  The remaining balance of U.S.$28.1 million term notes were outstanding, following the early repayment of U.S.$6.9 million in the fourth quarter of 2017.

⁽³⁾  The remaining balance of U.S.$94.1 million term notes were outstanding, following the early repayment of U.S.$21.4 million in the fourth quarter of 2017.

⁽⁴⁾  The remaining balance of U.S.$85.2 million term notes were outstanding, following the early repayment of U.S.$19.8 million in the fourth quarter of 2017.

⁽⁵⁾  The remaining balance of U.S.$158.9 million term notes were outstanding, following the early repayment of U.S.$36.1 million in the fourth quarter of 2017.

⁽⁶⁾  The remaining balance of U.K. pound sterling 12.1 million term notes were outstanding, following the early repayment of U.K. pound sterling 2.9 million in the fourth quarter of 2017.

⁽⁷⁾  The remaining balance of Cdn$20.5 million term notes were outstanding, following the early repayment of Cdn$4.5 million in the fourth quarter of 2017.

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

The Facility carried floating interest rates that were expected to range between 3.6 percent and 5.25 percent over bankers’ acceptance rates, depending on Pengrowth’s ratio of senior debt to earnings before interest, taxes and non-cash items. At December 31, 2017, the available facility had drawings of $109.0 million (December 31, 2016 – $nil) and letters of credit in the amount of $69.4 million (December 31, 2016 – $51.3 million) were outstanding.

During 2017, Pengrowth prepaid its U.S.$400.0 million6.35 percent senior unsecured notes, its U.S.$265 million6.98 percent senior unsecured notes and its Cdn$15.0 million6.61 percent senior unsecured notes. Additional prepayments of Cdn$115.4 million of principal were made on the remaining outstanding term notes in the fourth quarter of 2017. Pursuant to the relevant Note Purchase Agreements, amendment fees and make whole payments on the principal prepayments totaling Cdn$37.6 million were paid in addition to the principal for a total amount of Cdn$1.0 billion.

As of December 31, 2017, an unrealized cumulative foreign exchange loss of $96.2 million (December 31, 2016 - $353.3 million) has been recognized on the remaining U.S. dollar term notes since the date of issuance. As of December 31, 2017, an unrealized cumulative foreign exchange loss of $1.4 million (December 31, 2016 - $1.1 million) has been recognized on the remaining U.K. pound sterling denominated term notes since the date of issuance. See Note 17 for additional information about foreign exchange risk management and the impact on the Consolidated Financial Statements.

The five year schedule of long term debt repayment based on current maturity dates and assuming the revolving Credit Facility is not renewed is as follows: 2018 - $nil, 2019 - $164.9 million, 2020 - $118.3 million, 2021 - $nil, 2022 - $127.6 million.

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LONG TERM DEBT

12 Months Ended

Dec. 31, 2017

Disclosure of detailed information about financial instruments [abstract]

LONG TERM DEBT

7. CONVERTIBLE DEBENTURES

On March 31, 2017, all $126.6 million of the outstanding convertible debentures matured and were repaid and settled with cash on hand.

The following table summarizes the activity associated with the convertible debentures:

	Series B - 6.25 percent
Maturity date	March 31, 2017
Conversion price (per Pengrowth share)	$	11.51
Balance, December 31, 2015	$	137.0
Repurchase of convertible debentures	(10.2		)
Premium accretion	(0.2		)
Balance, December 31, 2016	$	126.6
Repayment of convertible debentures	(126.6		)
Balance, December 31, 2017	$	—
Face value, December 31, 2017	$	—

8. LONG TERM DEBT

AMENDMENTS TO LONG TERM DEBT

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

• The prepayment of all of the term notes due August 21, 2018 (U.S.$265 million and Cdn$15 million) and additional prepayments of Cdn$115.4 million of principal during the fourth quarter of 2017 on the remaining outstanding term notes.

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

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

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

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

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

• The remaining outstanding term notes maturing in 2019 through 2024 are subject to a 2.0 percentage point increase in interest rates (which increases to 3.0 percentage points on January 1, 2020). A one-time amendment fee of 0.5 percent on outstanding term notes was also paid to the holders of term notes due after 2018.

• The aggregate credit limit under the Credit Facility was reduced to $330 million following the closing of the Swan Hills asset sale, the $50 million Demand Credit Facility was eliminated and interest rates under the Credit Facility increased by 2.0 percentage points. A one time amendment fee of 0.5 percent of the aggregate credit limit was paid to the syndicate members of the Credit Facility.

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

Financial Covenants

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

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

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

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

As at December 31, 2017, Pengrowth had the following outstanding long term debt:

	As at
	December 31, 2017		December 31, 2016
U.S. dollar denominated term notes:
400 million at 6.35 percent due July 26, 2017	$	—	$	537.0
265 million at 6.98 percent due August 21, 2018 (1)	—		355.6
35 million at 5.49 percent due October 18, 2019 (2)	35.3		46.9
115.5 million at 7.98 percent due May 11, 2020 (3)	118.3		154.8
105 million at 6.07 percent due October 18, 2022 (4)	107.1		140.6
195 million at 6.17 percent due October 18, 2024 (5)	199.7		261.1
	$	460.4	$	1,496.0
U.K. pound sterling denominated term notes:
15 million at 5.45 percent due October 18, 2019 (6)	$	20.6	$	24.8
Canadian dollar term notes:
15 million at 6.61 percent due August 21, 2018 (1)	$	—	$	15.0
25 million at 6.74 percent due October 18, 2022 (7)	20.5		24.9
	$	20.5	$	39.9
Canadian dollar term Credit Facility borrowings	$	109.0	$	—
Total long term debt	$	610.5	$	1,560.7
Current portion of long term debt	$	—	$	537.0
Non-current portion of long term debt	610.5		1,023.7
	$	610.5	$	1,560.7

⁽¹⁾  There was no outstanding balance following the early repayment on October 12, 2017.

⁽²⁾  The remaining balance of U.S.$28.1 million term notes were outstanding, following the early repayment of U.S.$6.9 million in the fourth quarter of 2017.

⁽³⁾  The remaining balance of U.S.$94.1 million term notes were outstanding, following the early repayment of U.S.$21.4 million in the fourth quarter of 2017.

⁽⁴⁾  The remaining balance of U.S.$85.2 million term notes were outstanding, following the early repayment of U.S.$19.8 million in the fourth quarter of 2017.

⁽⁵⁾  The remaining balance of U.S.$158.9 million term notes were outstanding, following the early repayment of U.S.$36.1 million in the fourth quarter of 2017.

⁽⁶⁾  The remaining balance of U.K. pound sterling 12.1 million term notes were outstanding, following the early repayment of U.K. pound sterling 2.9 million in the fourth quarter of 2017.

⁽⁷⁾  The remaining balance of Cdn$20.5 million term notes were outstanding, following the early repayment of Cdn$4.5 million in the fourth quarter of 2017.

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

The Facility carried floating interest rates that were expected to range between 3.6 percent and 5.25 percent over bankers’ acceptance rates, depending on Pengrowth’s ratio of senior debt to earnings before interest, taxes and non-cash items. At December 31, 2017, the available facility had drawings of $109.0 million (December 31, 2016 – $nil) and letters of credit in the amount of $69.4 million (December 31, 2016 – $51.3 million) were outstanding.

During 2017, Pengrowth prepaid its U.S.$400.0 million6.35 percent senior unsecured notes, its U.S.$265 million6.98 percent senior unsecured notes and its Cdn$15.0 million6.61 percent senior unsecured notes. Additional prepayments of Cdn$115.4 million of principal were made on the remaining outstanding term notes in the fourth quarter of 2017. Pursuant to the relevant Note Purchase Agreements, amendment fees and make whole payments on the principal prepayments totaling Cdn$37.6 million were paid in addition to the principal for a total amount of Cdn$1.0 billion.

As of December 31, 2017, an unrealized cumulative foreign exchange loss of $96.2 million (December 31, 2016 - $353.3 million) has been recognized on the remaining U.S. dollar term notes since the date of issuance. As of December 31, 2017, an unrealized cumulative foreign exchange loss of $1.4 million (December 31, 2016 - $1.1 million) has been recognized on the remaining U.K. pound sterling denominated term notes since the date of issuance. See Note 17 for additional information about foreign exchange risk management and the impact on the Consolidated Financial Statements.

The five year schedule of long term debt repayment based on current maturity dates and assuming the revolving Credit Facility is not renewed is as follows: 2018 - $nil, 2019 - $164.9 million, 2020 - $118.3 million, 2021 - $nil, 2022 - $127.6 million.

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CAPITAL DISCLOSURES

12 Months Ended

Dec. 31, 2017

Disclosure of share capital, reserves and other equity interest [Abstract]

CAPITAL DISCLOSURES

9. CAPITAL DISCLOSURES

Pengrowth defines its capital as shareholders’ equity, long term debt, convertible debentures, bank indebtedness and working capital, as applicable.

Due to the rapid deterioration of commodity prices commencing in late 2014, Pengrowth took several steps to manage its capital, primarily relating to reducing debt. Capital spending was reduced, non-core assets were divested, foreign exchange and commodity risk management swaps were monetized, the dividend was initially reduced and then suspended, the term Credit Facility was renewed for four years, and the covenants were largely aligned between the senior unsecured notes and term Credit Facility. Surplus cash was used to repay debt.

The only financial covenant relating to the term notes and Credit Facility is the Interest Coverage ratio. The minimum ratio for the quarter ending September 30, 2017 through to and including the quarter ending September 30, 2019 is as follows:

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

Management monitors Pengrowth's capital structure using non-GAAP financial metrics, primarily trailing twelve months Earnings Before Interest, Taxes, Depletion, Depreciation, Amortization, Accretion, and other non-cash items ("AdjustedEBITDA") to Adjusted Interest Expense, or "Interest Coverage" ratio. Pengrowth seeks to manage this ratio with the objective of being able to finance its growth strategy while maintaining sufficient flexibility under the debt covenant.

Compliance with the interest coverage ratio is closely monitored by management as part of Pengrowth’s overall capital management objectives. The covenant is based on specific definitions prescribed in the debt agreements. Throughout the period, Pengrowth was in compliance with all financial covenants.

At December 31, 2017, Pengrowth has approximately $150 million of capacity on its Credit Facility, net of drawings and outstanding letters of credit.

Pengrowth continues to pursue other capital opportunities for when the Credit Facility expires on March 31, 2019 and for when the Waiver Period expires in the fourth quarter of 2019.

The following table provides a reconciliation between the opening and closing balances for liabilities arising from financing activities at December 31, 2017:

	Term Notes			Canadian dollar Term Credit Facility		Convertible debentures
Balance December 31, 2016	$	1,560.7		$	—	$	126.6
Increase (decrease) due to:
Foreign exchange impact of the Canadian dollar on U.S. and U.K. denominated debt	(65.1		)	—		—
Credit facility borrowing	—			109.0		—
Repayment	(996.0		)	—		(126.6		)
Issue cost amortization	1.9			—		—
Balance, December 31, 2017	$	501.5		$	109.0	$	—

The following is a summary of Pengrowth’s capital structure, excluding shareholders’ equity:

	As at
	December 31, 2017		December 31, 2016
Long term debt (1)	$	610.5	$	1,560.7
Convertible debentures	—		126.6
Working capital (surplus) deficiency (2)	80.6		(266.7		)
	$	691.1	$	1,420.6

⁽¹⁾  Includes current portion of term notes and bank indebtedness, as applicable.

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

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PROVISIONS AND OTHER LIABILITIES

12 Months Ended

Dec. 31, 2017

Disclosure of other provisions, contingent liabilities and contingent assets [Abstract]

PROVISIONS AND OTHER LIABILITIES

10. PROVISIONS AND OTHER LIABILITIES

Provisions and other liabilities are composed of Asset Retirement Obligations ("ARO"), finance leases, restructuring onerous office lease and other liabilities. The following table provides a continuity of the balances for the following periods:

	Asset retirement obligations			Finance leases			Restructuring provision - onerous office lease contracts			Other liabilities			Total
Balance, December 31, 2015	$	703.4		$	4.3		$	—		$	0.3		$	708.0
Incurred during the period	—			35.0			—			2.9			37.9
Property dispositions	(11.8		)	—			—			—			(11.8		)
Expenditures on remediation/provisions settled	(20.0		)	(1.4		)	—			(0.1		)	(21.5		)
Other revisions	(34.4		)	—			—			1.3			(33.1		)
Accretion (amortization)	15.1			—			—			—			15.1
Balance, December 31, 2016	$	652.3		$	37.9		$	—		$	4.4		$	694.6
Incurred during the period	5.4			—			26.5			(1.5		)	30.4
Property dispositions	(420.4		)	(2.0		)	—			—			(422.4		)
Expenditures on remediation/provisions settled	(15.9		)	(1.7		)	(0.3		)	(0.6		)	(18.5		)
Other revisions	3.9			—			—			—			3.9
Accretion (amortization)	11.4			—			—			—			11.4
Balance, December 31 2017	$	236.7		$	34.2		$	26.2		$	2.3		$	299.4

As at December 31, 2017	Asset retirement obligations		Finance leases		Restructuring provision - onerous office lease contracts		Other liabilities		Total
Current	$	29.9	$	0.9	$	4.4	$	—	$	35.2
Long term	206.8		33.3		21.8		2.3		264.2
	$	236.7	$	34.2	$	26.2	$	2.3	$	299.4
As at December 31, 2016
Current	$	20.0	$	1.5	$	—	$	0.6	$	22.1
Long term	632.3		36.4		—		3.8		672.5
	$	652.3	$	37.9	$	—	$	4.4	$	694.6

Reductions to ARO from the asset dispositions that closed in 2017 totaled $420.4 million.

The following assumptions were used to estimate the ARO liability:

	As at
	December 31, 2017			December 31, 2016
Total escalated future costs	$	420.2		$	2,120.4
Discount rate, per annum	2.3		%	2.3		%
Inflation rate, per annum	1.5		%	1.5		%

Pengrowth has been contributing to an externally managed trust fund established to fund abandonment and reclamation costs associated with SOEP. These costs are expected to be incurred within the next 3 to 4 years. The abandonment and reclamation costs on other assets, not covered by a fund, are expected to be incurred between 2035 and 2080.

RESTRUCTURING PROVISION - ONEROUS OFFICE LEASE CONTRACTS

Pengrowth completed significant asset dispositions which led to a management decision to complete an operational restructuring commencing in the third quarter of 2017. Reduction of staff levels and excess office space resulted in Pengrowth recognizing a $37.0 million restructuring cost in 2017.

As part of the $37.0 million restructuring costs, Pengrowth recorded a $26.5 million provision related to a portion of its office lease obligation that is considered an onerous contract, as the economic benefits from actual or potential subleases were exceeded by the unavoidable costs of the lease contract over the remaining term.

Also included in the $37.0 million restructuring costs were $10.5 million of severance costs which were classified as a current payable in the Consolidated Balance Sheets due to the short term nature of expected payment dates.

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DEFERRED INCOME TAXES

12 Months Ended

Dec. 31, 2017

Disclosure of income tax [Abstract]

DEFERRED INCOME TAXES

11. DEFERRED INCOME TAXES

A reconciliation of the deferred income tax recovery calculated based on the income (loss) before taxes at the statutory tax rate to the actual provision for deferred income taxes is as follows:

	Year ended December 31
	2017			2016
Income (loss) before taxes	$	(907.6	)	$	(387.1	)
Combined federal and provincial tax rate	27.08		%	27.09		%
Expected income tax expense (recovery)	$	(245.8	)	$	(104.9	)
Change in unrecognized deferred tax asset	22.6			9.8
Foreign exchange (gain) loss (1)	(2.0		)	(1.8		)
Effect of change in corporate tax rate	(0.2		)	—
Other including share based compensation	1.6			3.5
Deferred income tax expense (recovery)	$	(223.8	)	$	(93.4	)

⁽¹⁾ Reflects the 50 percent non-taxable portion of foreign exchange gains and losses and related risk management contracts.

The net deferred income tax asset (liability) is composed of:

	As at
	December 31, 2017			December 31, 2016
Deferred tax liabilities associated with:
PP&E and E&E assets	$	(132.3	)	$	(411.0	)
Less deferred tax assets associated with:
Non-capital losses and financing charges	399.6			325.9
Provisions	64.1			176.6
Risk management contracts	10.8			14.6
Long term debt	—			12.1
Convertible debentures	—			0.2
Net deferred tax asset (liability)	$	342.2		$	118.4

In calculating the deferred income tax asset in 2017, Pengrowth included $1,460.2 million (2016 - $1,234.6 million) of non-capital losses available for carry forward to reduce taxable income in future years. These losses expire between 2025 and 2037. Pengrowth has determined that it is likely that future taxable profit will be available to utilize these losses.

Deferred tax assets have not been recognized with respect to the following items:

	As at
	December 31, 2017		December 31, 2016
Deductible temporary differences	$	204.0	$	188.9
Tax losses	109.8		40.2
	$	313.8	$	229.1

A continuity of the net deferred income tax asset (liability) for 2017 and 2016 is detailed in the following tables:

Movement in deferred tax asset (liability) during the year	Balance Jan 1, 2017			Recognized in profit or loss			Balance Dec 31, 2017
PP&E and E&E assets	$	(411.0	)	$	278.7		$	(132.3	)
Non-capital losses and financing charges	325.9			73.7			399.6
Provisions	176.6			(112.5		)	64.1
Risk management contracts	14.6			(3.8		)	10.8
Long term debt	12.1			(12.1		)	—
Convertible debentures	0.2			(0.2		)	—
Share issue costs	—			—			—
	$	118.4		$	223.8		$	342.2

Movement in deferred tax asset (liability) during the year	Balance Jan 1, 2016			Recognized in profit or loss			Balance Dec 31, 2016
PP&E and E&E assets	(405.3		)	(5.7		)	(411.0		)
Non-capital losses and financing charges	328.7			(2.8		)	325.9
Provisions	190.2			(13.6		)	176.6
Risk management contracts	(99.8		)	114.4			14.6
Long term debt	10.8			1.3			12.1
Convertible debentures	0.2			—			0.2
Share issue costs	0.2			(0.2		)	—
	$	25.0		$	93.4		$	118.4

Deferred income tax is a non-cash item relating to the temporary differences between the accounting and tax basis of Pengrowth's assets and liabilities and has no immediate impact on Pengrowth's cash flows.

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SHAREHOLDERS' CAPITAL

12 Months Ended

Dec. 31, 2017

Share Capital, Reserves And Other Equity Interest [Abstract]

SHAREHOLDERS' CAPITAL

12. SHAREHOLDERS’ CAPITAL

Pengrowth is authorized to issue an unlimited number of common shares and up to 10 million preferred shares. No preferred shares have been issued.

	2017			2016
(Common shares in 000's)	Number of common shares	Amount		Number of common shares	Amount
Balance, beginning of year	547,709	$	4,815.1	543,033	$	4,797.0
Share based compensation (non-cash exercised)	4,537	14.6		4,676	18.1
Balance, end of year	552,246	$	4,829.7	547,709	$	4,815.1

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LONG TERM INCENTIVE PLANS ("LTIP")

12 Months Ended

Dec. 31, 2017

Disclosure of share-based payment arrangements [Abstract]

LONG TERM INCENTIVE PLANS (LTIP)

13. LONG TERM INCENTIVE PLANS ("LTIP")

Pengrowth’s Long Term Incentive Plan ("LTIP"), as described below, is used to grant awards of share based compensation.

(i) SHARE-SETTLED LTIP

Pengrowth’s share-settled LTIP has the following components:

(a) Performance Share Units ("PSUs")

PSUs entitle the holder to a number of common shares to be issued in the third year after grant. Prior to 2016, PSUs were awarded to employees, officers and consultants. Commencing in 2016, PSUs are only awarded to individuals in senior leadership roles whose responsibilities are thought to have a more direct impact on the share price. PSUs are subject to a performance factor ranging from 0 percent to 200 percent of the number of PSUs granted plus the amount of reinvested notional dividends, if applicable.

(b) Restricted Share Units ("RSUs")

RSUs entitle the holder to a number of common shares plus reinvested notional dividends, if applicable, to be issued at vesting in three even tranches in the three years following grant. Prior to 2016, RSUs were awarded to employees, officers and consultants. Commencing in 2016, RSUs are only awarded to individuals in mid-level leadership roles. The RSUs generally vest on the first, second and third anniversary date from the date of grant.

(c) Deferred Share Units ("DSUs")

As of 2014, there were no new grants of the share-settled DSUs as independent members of the Board of Directors receive cash-settled Phantom DSUs instead. Prior to 2014, DSUs were issued to the independent members of the Board of Directors only. Each DSU entitled the holder to one common share plus reinvested notional dividends, if applicable, since the grant date of the DSU. The DSUs vest upon grant but can only be converted to common shares upon the holder ceasing to be a Director of Pengrowth. The number of common shares ultimately issued will be equal to the number of DSUs initially granted to the holder plus the amount of reinvested notional dividends, if applicable, accruing during the term of the DSUs.

The following table provides a continuity of the share-settled LTIP:

(number of share units - 000's)	PSUs		RSUs		DSUs
Outstanding, December 31, 2015	4,640		5,341		302
Granted	3,049		6,553		—
Forfeited	(460	)	(737	)	—
Exercised	(1,695	)	(2,721	)	(104	)
Performance adjustment	704		—		—
Outstanding, December 31, 2016	6,238		8,436		198
Granted	2,124		4,578		—
Forfeited	(486	)	(2,195	)	—
Exercised	(1,104	)	(3,436	)	—
Performance adjustment	(1,738	)	—		—
Outstanding, December 31, 2017	5,034		7,383		198

Pengrowth's Board may determine, in its sole discretion, that any shares issuable pursuant to new grants could be paid in cash equal to the fair market value of the shares otherwise issuable.

A rolling and reloading plan with a maximum of 3.2 percent of the issued and outstanding common shares may be reserved for issuance under all share-settled compensation plans in the aggregate, as approved by shareholders. As at December 31, 2017, the number of shares issuable under the share-settled compensation plans, in aggregate, represents 2.3 percent of the issued and outstanding common shares, which is within the limit.

Compensation expense related to PSU, RSU, and DSU share-settled plans is based on the fair value of the share units at the date of grant. The fair value of the PSUs is determined at the date of grant using the closing share price and is adjusted for the estimated performance multiplier. The amount of compensation expense is impacted by an estimated forfeiture rate at the date of grant and as more information comes available. For PSU and RSU grants in 2015, 2016 and 2017, the estimated forfeiture rates range from 25 to 55 percent depending on the vesting period. There was no forfeiture rate applied for DSUs as they vested immediately upon grant. For PSUs, the number of shares awarded at the end of the vesting period is subject to certain performance conditions. Fluctuations in compensation expense may occur due to changes in estimating the outcome of the performance conditions. Compensation expense is recognized in net income (loss) over the vesting period with a corresponding increase or decrease to contributed surplus. Upon the issuance of common shares at the end of the vesting period, shareholders’ capital is increased and contributed surplus is decreased by the amount of compensation expense incurred during the vesting period. The shares are issued from treasury upon vesting.

For the year ended December 31, 2017, Pengrowth recorded $5.0 million of compensation expense related to the share-settled LTIP units (December 31, 2016 - $13.7 million). The weighted average grant date fair value was $1.40 per share unit for the 2017 grants (December 31, 2016 - $1.02 per share unit for the 2016 grants). As at December 31, 2017, the amount of compensation expense to be recognized over the remaining vesting period was $5.4 million or $0.51 per share unit (December 31, 2016 - $9.8 million or $0.78 per share unit) subject to the determination of the performance multiplier, if applicable. The unrecognized compensation cost will be expensed to net income (loss) over the remaining weighted average vesting period of 1.3 years.

(ii) PREVIOUS LTIP

Prior to January 1, 2011, Pengrowth had a Deferred Entitlement Share Unit ("DESU") Plan that was used while Pengrowth was a trust and is being phased out. As at December 31, 2017, all of the grants were fully vested and the total outstanding balance was composed of grants made prior to January 1, 2011 to the independent members of the Board of Directors. DESUs are not exercisable by the independent Directors and do not expire until they cease to be Directors for any reason. As at December 31, 2017, 163,867 common shares (December 31, 2016 - 163,867 common shares) were reserved for issuance under the Deferred Entitlement Share Unit ("DESU") Plan. The DESUs are entitled to deemed dividends, if applicable.

(iii) CASH-SETTLED LTIP    

(a) Cash-Settled Restricted Share Units ("Cash-Settled RSUs")

Commencing in 2016, certain employees receive cash-settled RSUs in place of previously received share-settled long term incentives. Each cash-settled RSU entitles the holder to a cash payment equivalent to the value of a number of common shares (including the reinvestment of deemed dividends, if applicable) which vest in three even tranches in the three years following grant. Compensation expense associated with the cash-settled RSUs is determined based on the fair value of the share units at the grant date and is subsequently adjusted to reflect the fair value of the share units at each period end. This valuation incorporates the period end share price and the number of cash-settled RSUs outstanding at each period end. The amount of compensation expense is impacted by an estimated forfeiture rate at the date of grant and as more information comes available. For the cash-settled RSU grants in 2016 and 2017, the estimated forfeiture rates range from 50 to 80 percent depending on the vesting period. During the year ended December 31, 2017, compensation reduction of $0.2 million (December 31, 2016 - $3.6 million expense) was recognized in the Consolidated Statements of Income (Loss) with a corresponding increase or decrease in liabilities. As at December 31, 2017, $1.5 million (December 31, 2016 - $3.6 million) of total liability was recorded in the Consolidated Balance Sheets. Classification of the associated short term and long term liabilities is dependent on the expected payout dates.

(b) Cash-Settled Phantom Deferred Share Units ("Phantom DSUs")

Independent members of the Board of Directors receive cash-settled Phantom DSUs. Each Phantom DSU entitles the holder to a cash payment equivalent to the value of a number of common shares (including deemed dividends, if applicable) to be paid upon the individual ceasing to be a Director for any reason, subject to the right to defer payment until up to December 31 of the year following their departure from the Board. Compensation expense associated with the Phantom DSUs is determined based on the fair value of the Phantom DSUs at the grant date and is subsequently adjusted to reflect the fair value of the associated common shares at each period end. This valuation incorporates the period end share price and the number of Phantom DSUs outstanding at each period end including notional dividends, if applicable. Compensation expense is recognized in net income (loss) with a corresponding increase or decrease in liabilities. Classification of the associated short term and long term liabilities is dependent on the expected payout dates.

As at December 31, 2017, Phantom DSUs awarded to Directors had a corresponding liability of $1.4 million (December 31, 2016 - $2.6 million). For the year ended December 31, 2017, Pengrowth recorded a $0.6 million compensation reduction (December 31, 2016 - $2.3 million expense) related to Phantom DSUs.

The following table provides a continuity of the cash-settled LTIP:

(number of share units - 000's)	Cash-settled RSUs		Phantom DSUs
Outstanding, December 31, 2015	—		397
Granted	4,559		1,024
Forfeited	(330	)	—
Exercised	—		(75	)
Outstanding, December 31, 2016	4,229		1,346
Granted	3,163		492
Forfeited	(3,148	)	—
Exercised	(1,341	)	(462	)
Outstanding, December 31, 2017	2,903		1,376

TOTAL SHARE BASED COMPENSATION EXPENSE

Total share based compensation expenses are included in both general and administrative and operating expenses on the Consolidated Statements of Income (Loss)and are composed of the following:

	Year ended December 31
	2017			2016
Non-cash share based compensation	$	5.0		$	13.7
Amounts capitalized in the period	(0.1		)	(0.5		)
Non-cash share based compensation expense	$	4.9		$	13.2
Cash-settled RSUs (reduction) expense	$	(0.2	)	$	3.6
Cash-settled Phantom DSUs (reduction) expense	$	(0.6	)	$	2.3
Total share based compensation expense	$	4.1		$	19.1

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REVENUE

12 Months Ended

Dec. 31, 2017

Disclosure of revenue [Abstract]

REVENUE

14. REVENUE

Pengrowth sells its production pursuant to fixed or variable price contracts. The transaction price for variable priced contracts is based on the commodity price, adjusted for quality, location or other factors, whereby each component of the pricing formula can be either fixed or variable, depending on the contract terms. Under its contracts, Pengrowth is required to deliver fixed volumes of diluted bitumen, and variable volumes of light oil, natural gas, natural gas liquids, and sulphur to the contract counterparty. The amount of revenue recognized is based on the agreed transaction price, whereby any variability in revenue relates specifically to its efforts to transfer production, and therefore the resulting revenue is allocated to the production delivered in the period during which the variability occurs. As a result, none of the variable revenue is considered constrained.

Light oil, natural gas liquids and natural gas are mostly sold under contracts of varying price and volume terms of up to one year. Pengrowth’s diluted bitumen is currently sold on multi-year contracts expiring in 2019 for a fixed quantity of diluted bitumen at a fixed differential to WTI, with WTI being variable, as detailed in Note 17. Revenues are typically collected on the 25^th day of the month following production. Processing fees charged to third parties are generally sold under multi-year contracts at fixed fees that vary by volume.

Adoption of IFRS 15 Revenue from Contracts with Customers

In the fourth quarter of 2017, Pengrowth elected to early adopt IFRS 15 Revenue from contracts with customers as detailed in Note 2, using the cumulative effect approach. The impact to Oil and gas sales as a result of adopting IFRS 15 was an increase of $182.6 million of revenues, with a corresponding and offsetting increase to Operating expenses and Diluent and other purchases of $163.5 million and $19.1 million, respectively, for the twelve months ended December 31, 2017, resulting in no impact to net income (loss).

The following table presents Pengrowth’s Oil and gas sales disaggregated by revenue source:

	Year ended December 31
	2017
Light oil	149.3
Bitumen	181.6
Natural gas liquids	56.7
Natural gas	98.8
Produced petroleum revenue	486.4
Diluent	147.2
Processing income	19.1
Other revenue	20.7
Total oil and gas sales	$	673.4

During 2017, Pengrowth had one fixed price physical delivery contract for approximately 12 MMcf/d of natural gas.

Pengrowth has variable price physical delivery contracts for the sale of diluted bitumen with 2 parties, Phillips 66 Canada Ltd. and BP Products North America Inc., with revenue from those customers representing approximately 36 percent and 12 percent, respectively, of the Company's total 2017 Oil and gas sales.

The vast majority of 2017 revenues are derived from variable price contracts based on index prices, while only approximately 0.2 percent of revenues were from the fixed price natural gas contracts noted above.

Included in accounts receivable at December 31, 2017 is $40.2 million (December 31, 2016 - $76.5 million for December 2016 production) of accrued Oil and gas sales related to December 2017 production. The decrease in the amount of accrued revenue is related to property divestments.

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OTHER CASH FLOW DISCLOSURES

12 Months Ended

Dec. 31, 2017

Cash Flow Statement [Abstract]

OTHER CASH FLOW DISCLOSURES

15. OTHER CASH FLOW DISCLOSURES

CHANGE IN NON-CASH OPERATING WORKING CAPITAL AND OTHER ASSETS

	Year ended December 31
Cash provided by (used for):	2017			2016
Accounts receivable	$	40.9		$	25.0
Accounts payable	(22.7		)	(43.8		)
Prepaid tax assessment	—			(2.7		)
	$	18.2		$	(21.5	)

CHANGE IN NON-CASH INVESTING WORKING CAPITAL 

	Year ended December 31
Cash used for:	2017			2016
Accounts payable, including capital accruals	$	(7.5	)	$	7.6

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AMOUNTS PER SHARE

12 Months Ended

Dec. 31, 2017

Earnings per share [abstract]

AMOUNTS PER SHARE

16. AMOUNTS PER SHARE

The following table reconciles the weighted average number of shares used in the basic and diluted net income (loss) per share calculations:

	Year ended December 31
(000's)	2017	2016
Weighted average number of shares - basic and diluted	551,193	546,566

For the year ended December 31, 2017, 9.3 million shares (December 31, 2016 - 7.8 million) that are issuable on exercise of the share based compensation plans were excluded from the diluted net income (loss) per share calculation as their effect is anti-dilutive.

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FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

12 Months Ended

Dec. 31, 2017

Disclosure of detailed information about financial instruments [abstract]

FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

17. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

Pengrowth’s financial instruments are composed of accounts receivable, accounts payable, risk management assets and liabilities, remediation trust funds, finance lease obligation, bank indebtedness, convertible debentures and long term debt, as applicable.

Details of Pengrowth’s significant accounting policies for recognition and measurement of financial instruments are disclosed in Note 2 to the December 31, 2017 audited Consolidated Financial Statements.

RISK MANAGEMENT OVERVIEW

Pengrowth has exposure to certain market risks related to volatility in commodity and power prices, interest rates and foreign exchange rates. Derivative instruments are used to manage exposure to these risks. Pengrowth’s policy is not to utilize financial instruments for trading or speculative purposes.

The Board of Directors and management have overall responsibility for the establishment of risk management strategies and objectives. Pengrowth’s risk management policies are established to identify the risks faced by Pengrowth, to set appropriate risk limits, and to monitor adherence to risk limits. Risk management policies are reviewed regularly to reflect changes in market conditions and Pengrowth’s activities.

MARKET RISK

Market risk is the risk that the fair value, or future cash flows of financial assets and liabilities, will fluctuate due to movements in market prices. Market risk is composed of commodity and power price risk, foreign currency risk and interest rate risk, as applicable.

Commodity Price Risk

Pengrowth is exposed to commodity price risk as prices for oil and gas products fluctuate in response to many factors including local and global supply and demand, weather patterns, pipeline transportation, political stability and economic factors. Commodity price fluctuations are an inherent part of the oil and gas business. Pengrowth mitigates some of the exposure to commodity price risk to protect the return on acquisitions and provide a level of stability to operating cash flow. Pengrowth may utilize financial and physical delivery contracts to fix the commodity price associated with a portion of its future production. The use of forward and futures contracts are governed by formal policies and is subject to limits established by the Board of Directors. The Board of Directors and management may re-evaluate these limits as needed in response to specific events such as market activity, additional leverage, acquisitions or other transactions where Pengrowth’s capital structure may be subject to more risk from commodity prices.

Commodity Price Contracts

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

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

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

During the first quarter of 2017, Pengrowth early settled its 2017 crude oil swap contracts in place at the time for an aggregate loss of $12.7 million.

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

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

Physical Delivery Contracts

As at December 31, 2017, physical delivery contracts were held for the purpose of delivery of non-financial items in accordance with Pengrowth's expected sales requirements. The prices per bbl, as per the table below, include an apportionment protection fee to guarantee flow assurance in the event export pipelines are restricted. Physical delivery contracts are not considered financial instruments and therefore, no asset or liability has been recognized in the Consolidated Financial Statements.

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

Foreign Exchange Risk

Pengrowth is exposed to foreign currency fluctuations as crude oil and natural gas prices received are referenced to U.S. dollar denominated prices.

Pengrowth is exposed to foreign currency fluctuation on the U.S. dollar and U.K. pound sterling denominated senior unsecured notes for both interest and principal payments. Pengrowth has mitigated some of this risk by entering into a series of futures and swap contracts in order to fix the foreign exchange rate on a portion of the U.S. dollar and the U.K. pound sterling denominated senior unsecured notes.

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

Pengrowth entered into a foreign exchange risk management contract when it issued the U.K. pound sterling term debt. This contract fixes 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: 

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

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

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

A series of swap contracts were transacted in order to fix the foreign exchange rate on a portion of Pengrowth’s U.S. dollar denominated term debt. Each swap requires Pengrowth to buy U.S. dollars at a predetermined rate and time based upon the maturity dates of the U.S. denominated term debt. 

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

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

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

Foreign Denominated Term Debt Sensitivity to Foreign Exchange Rate

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

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

Interest Rate Risk

Pengrowth is exposed to interest rate risk on any outstanding balances on the Canadian dollar revolving Credit Facility.

Interest Rate Sensitivity - Bank Interest Cost

As at December 31, 2017, Pengrowth had $610.5 million of current and non-current long term debt (December 31, 2016 - $1.6 billion), and $nil of convertible debentures outstanding (December 31, 2016 - $0.1 billion) of which $109.0 million was based on floating interest rates (December 31, 2016 - $nil). A 1 percent increase in interest rates would increase pre-tax interest expense by approximately $1.1 million for the year ended December 31, 2017 (December 31, 2016 - $nil), assuming the amount was outstanding for the entire period.

Summary of Gains and Losses on Risk Management Contracts

Pengrowth’s risk management contracts are recorded on the Consolidated Balance Sheets at their estimated fair value and split between current and non-current assets and liabilities on a contract by contract basis, netted by counterparty. Realized and unrealized gains and losses are included in the Consolidated Statements of Income (Loss).

The following tables provide details of the fair value of risk management contracts that appear on the Consolidated Balance Sheets and the unrealized and realized gains and losses on risk management recorded in the Consolidated Statements of Income (Loss).

As at and for the year ended December 31, 2017	Commodity contracts (1)			Power contracts			Foreign exchange contracts (2)			Total
Non-current portion of risk management assets	$	—		$	—		$	1.9		$	1.9
Current portion of risk management liabilities	(39.8		)	—			(0.2		)	(40.0		)
Non-current portion of risk management liabilities	—			—			(18.6		)	(18.6		)
Risk management assets (liabilities), end of year	$	(39.8	)	$	—		$	(16.9	)	$	(56.7	)
Less: Risk management assets (liabilities) at beginning of year	(54.0		)	—			(2.7		)	(56.7		)
Unrealized gain (loss) on risk management contracts for the year	$	14.2		$	—		$	(14.2	)	$	—
Realized gain (loss) on risk management contracts for the year	(19.8		)	—			(37.6		)	(57.4		)
Total unrealized and realized gain (loss) on risk management contracts for the year	$	(5.6	)	$	—		$	(51.8	)	$	(57.4	)
As at and for the year ended December 31, 2016	Commodity contracts(1)			Power contracts (3)			Foreign exchange contracts (2)			Total
Current portion of risk management assets	$	—		$	—		$	2.9		$	2.9
Non-current portion of risk management assets	—			—			1.0			1.0
Current portion of risk management liabilities	(54.0		)	—			(1.3		)	(55.3		)
Non-current portion of risk management liabilities	—			—			(5.3		)	(5.3		)
Risk management assets (liabilities), end of year	$	(54.0	)	$	—		$	(2.7	)	$	(56.7	)
Less: Risk management assets (liabilities) at beginning of year	370.5			(1.7		)	83.3			452.1
Unrealized gain (loss) on risk management contracts for the year	$	(424.5	)	$	1.7		$	(86.0	)	$	(508.8	)
Realized gain (loss) on risk management contracts for the year	385.7			(4.5		)	47.0			428.2
Total unrealized and realized gain (loss) on risk management contracts for the year	$	(38.8	)	$	(2.8	)	$	(39.0	)	$	(80.6	)

⁽¹⁾  Unrealized and realized gains and losses are presented as separate line items in the Consolidated Statements of Income (Loss).

⁽²⁾  Unrealized and realized gains and losses are included as part of separate line items in the Consolidated Statements of Income (Loss).

⁽³⁾  Unrealized gains and losses are included in other (income) expense. Realized gains and losses are included in operating expense.

Fair Value

The fair value of cash and cash equivalents, accounts receivable, prepaid tax assessment, accounts payable and bank indebtedness approximate their carrying amount due to the short-term nature of those instruments. The fair value of the Canadian dollar term Credit Facility, as applicable, is equal to its carrying amount as the facility bears interest at floating rates and credit spreads within the facility are indicative of market rates. The fair values of the remediation trust funds are equal to their carrying amount as these assets are carried at their estimated fair value. The following tables provide fair value measurement information for other financial assets and liabilities.

					Fair value measurements using:
As at December 31, 2017	Carrying amount		Fair value		Quoted prices in active markets (Level 1)		Significant other observable inputs (Level 2)		Significant unobservable inputs (Level 3)
Financial Assets
Remediation trust funds	$	111.6	$	111.6	$	111.6	$	—	$	—
Fair value of risk management contracts	1.9		1.9		—		1.9		—
Financial Liabilities
U.S. dollar denominated term notes	460.4		509.5		—		509.5		—
Cdn dollar term notes	20.5		22.8		—		22.8		—
U.K. pound sterling denominated term notes	20.6		21.7		—		21.7		—
Fair value of risk management contracts	58.6		58.6		—		58.6		—
					Fair value measurements using:
As at December 31, 2016	Carrying amount		Fair value		Quoted prices in active markets (Level 1)		Significant other observable inputs (Level 2)		Significant unobservable inputs (Level 3)
Financial Assets
Remediation trust funds	$	106.5	$	106.5	$	106.5	$	—	$	—
Fair value of risk management contracts	3.9		3.9		—		3.9		—
Financial Liabilities
Convertible debentures	126.6		126.7		126.7		—		—
U.S. dollar denominated senior unsecured notes	1,496.0		1,527.7		—		1,527.7		—
Cdn dollar senior unsecured notes	39.9		41.3		—		41.3		—
U.K. pound sterling denominated unsecured notes	24.8		25.5		—		25.5		—
Fair value of risk management contracts	60.6		60.6		—		60.6		—

Level 1 Fair Value Measurements

Financial assets and liabilities are recorded at fair value based on quoted prices in active markets.

Level 2 Fair Value Measurements

Risk management contracts - the fair value of the risk management contracts is based on commodity, power and foreign exchange curves that are readily available or, in their absence, third-party market indications and forecasts priced on the last trading day of the applicable period.

Derivative contracts are recorded at fair value on the Consolidated Balance Sheets as current or long-term assets or liabilities, based on their values on a contract by contract basis, netted by counterparty. The derivative contracts fair values are all considered level 2 under the fair value hierarchy.

The fair value of the term notes is determined based on the risk free interest rate on government debt instruments of similar maturities, adjusted for estimated credit risk, industry risk and market risk premiums.

CREDIT RISK

Credit risk is the risk of financial loss to Pengrowth if a counterparty to a financial instrument fails to meet its contractual obligations. A significant portion of Pengrowth’s accounts receivable are with customers in the oil and gas industry and are subject to normal industry credit risks. Uncertainty in the credit markets, should it exist, may restrict the ability of Pengrowth’s normal business counterparties to meet their obligations to Pengrowth. Additional credit risk could exist where little or none previously existed. Pengrowth manages its credit risk by performing a credit review on each marketing counterparty and following a credit practice that limits transactions according to the counterparty’s credit rating as assessed by Pengrowth. In addition, Pengrowth may require letters of credit or parental guarantees from certain counterparties to mitigate some of the credit risk associated with the amounts owing by the counterparty. The use of financial swap agreements involves a degree of credit risk that Pengrowth manages through its credit policies which are designed to limit eligible counterparties to those with investment grade credit ratings or better. The carrying value of accounts receivable and risk management assets represents Pengrowth’s maximum credit exposure.

Pengrowth sells a significant portion of its oil and gas to a limited number of counterparties. In 2017, Pengrowth has 2 counterparties that individually account for more than 10 percent of annual revenue. All of the counterparties are large trading companies and subject to regular internal credit reviews.

Pengrowth considers amounts over 90 days as past due. As at December 31, 2017, the amount of accounts receivable that were past due was not significant. Pengrowth has not recorded a significant allowance for doubtful accounts during 2017 or 2016 and has no significant bad debt provision at December 31, 2017. Pengrowth’s objectives, processes and policies for managing credit risk have not changed from the previous year.

The components of accounts receivable are as follows:

	As at
	December 31, 2017		December 31, 2016
Trade	$	97.5	$	110.3
Prepaid and other	8.2		16.3
	$	105.7	$	126.6

LIQUIDITY RISK

Liquidity risk is the risk that Pengrowth will not be able to meet its financial obligations as they fall due. Pengrowth’s approach to managing liquidity is to ensure, as much as possible, that it will always have sufficient liquidity to meet its liabilities when due, under normal and stressed conditions. Management closely monitors cash flow requirements to ensure that it has sufficient cash on demand or borrowing capacity to meet operational and financial obligations over the next three years. Pengrowth maintains a secured $330.0 million revolving, committed term Credit Facility. Use of the remaining credit capacity is still subject to complying with the financial covenant as discussed in Note 9. Pengrowth’s term notes and term Credit Facilities are secured and equally ranked.

Pengrowth’s current and non-current financial liabilities are as follows:

As at December 31, 2017	Carrying amount		Contractual cash flows		Year 1		Year 2		Years 3-5		More than 5 years
Accounts payable	$	136.2	$	136.2	$	136.2	$	—	$	—	$	—
Commodity risk management contracts	39.8		39.8		39.8		—		—		—
Cdn dollar senior unsecured notes (2)	20.5		27.1		1.4		1.4		24.3		—
U.S. dollar denominated term notes (1)	460.4		601.3		30.2		65.2		284.0		221.9
U.K. pound sterling denominated term notes (1)	20.6		22.6		1.1		21.5		—		—
Cdn dollar term Credit Facility borrowings (2)	109.0		117.6		6.9		110.7		—		—
Finance leases	34.2		76.8		4.4		4.2		12.6		55.6
Foreign exchange risk management contracts	18.8		20.8		0.2		4.3		16.3		—
Other liabilities	2.3		3.2		—		1.4		0.3		1.5

⁽¹⁾  Contractual cash flows include future interest payments and term notes calculated at December 31, 2017 period end exchange rate.

⁽²⁾  Contractual cash flows include future interest payments.

As at December 31, 2016	Carrying amount		Contractual cash flows		Year 1		Year 2		Years 3-5		More than 5 years
Accounts payable	$	189.6	$	189.6	$	189.6	$	—	$	—	$	—
Convertible debentures	126.6		130.5		130.5		—		—		—
Commodity risk management contracts	54.0		54.0		54.0		—		—		—
Cdn dollar senior unsecured notes (1)	39.9		48.5		2.2		16.8		3.6		25.9
U.S. dollar denominated senior unsecured notes (1)	1,496.0		1,726.8		623.7		399.2		266.0		437.9
U.K. pound sterling denominated unsecured notes (1)	24.8		27.3		0.9		0.9		25.5		—
Finance leases	37.9		90.7		5.7		5.0		14.2		65.8
Foreign exchange risk management contracts	6.6		6.1		1.3		1.7		2.4		0.7
Other liabilities	4.4		8.3		0.6		2.9		2.8		2.0
Remediation trust fund payments	—		12.5		0.3		0.3		0.9		11.0

⁽¹⁾  Contractual cash flows include future interest payments and senior unsecured notes calculated at December 31, 2016 period end exchange rate.

FINANCIAL RISK MANAGEMENT CONTRACTS – GROSS AMOUNTS

Risk management contracts assets and liabilities are offset and the net amount presented in the Consolidated Balance Sheets when the Corporation has a legal right to offset the amounts and intends either to settle them on a net basis or to realize the asset and settle the liability simultaneously.

The following table sets out gross amounts relating to risk management contracts assets and liabilities that have been presented on a net basis on the Consolidated Balance Sheets:

	As at
Gross amounts	December 31, 2017			December 31, 2016
Risk management contracts
Current asset	$	—		$	3.0
Non-current asset	1.9			1.0
Current liability	(40.0		)	(55.4		)
Non-current liability	(18.6		)	(5.3		)
	$	(56.7	)	$	(56.7	)

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COMMITMENTS

12 Months Ended

Dec. 31, 2017

Disclosure Of Commitments [Abstract]

COMMITMENTS

19. COMMITMENTS

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

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

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

⁽³⁾  Includes office rent and other commitments.

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FOREIGN EXCHANGE (GAIN) LOSS

12 Months Ended

Dec. 31, 2017

Effects Of Changes In Foreign Exchange Rates [Abstract]

FOREIGN EXCHANGE (GAIN) LOSS

18. FOREIGN EXCHANGE (GAIN) LOSS

	Year ended December 31
	2017			2016
Currency exchange rate (Cdn$1 = U.S.$) at beginning of year	$	0.74		$	0.72
Currency exchange rate (Cdn$1 = U.S.$) at year end	$	0.80		$	0.74
Unrealized foreign exchange (gain) loss on U.S. dollar denominated debt (1)	$	(66.1	)	$	(46.8	)
Unrealized foreign exchange (gain) loss on U.K. pound sterling denominated debt (1)	0.5			(5.8		)
Total unrealized foreign exchange (gain) loss from translation of foreign denominated debt	$	(65.6	)	$	(52.6	)
Unrealized (gain) loss on U.S. foreign exchange risk management contracts (2)	$	15.0		$	80.6
Unrealized (gain) loss on U.K. foreign exchange risk management contracts	(0.8		)	5.4
Total unrealized (gain) loss on foreign exchange risk management contracts	$	14.2		$	86.0
Net unrealized foreign exchange (gain) loss	$	(51.4	)	$	33.4
Net realized foreign exchange (gain) loss (3)	$	38.4		$	(46.5	)

⁽¹⁾  Includes both principal and interest.

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

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

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CONTINGENCIES

12 Months Ended

Dec. 31, 2017

Disclosure Of Contingencies [Abstract]

CONTINGENCIES

20. CONTINGENCIES

Pengrowth has been named as a defendant in various litigation matters. The nature of these claims is usually related to settlement of normal operational issues and labour issues. The outcome of such claims against Pengrowth is not determinable at this time; however, their ultimate resolution is not expected to have a materially adverse effect on Pengrowth as a whole.

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SUPPLEMENTARY DISCLOSURES

12 Months Ended

Dec. 31, 2017

Disclosure Of Supplementary Disclosures [Abstract]

SUPPLEMENTARY DISCLOSURES

21. SUPPLEMENTARY DISCLOSURES

CONSOLIDATED STATEMENTS OF INCOME (LOSS)

Pengrowth’s Consolidated Statements of Income (Loss) are prepared primarily by the nature of expense, with the exception of employee compensation costs which are included in both operating and general and administrative expense line items.

The following table details the amount of total employee compensation costs (including share based compensation expense) included in the operating and general and administrative expense line items in the Consolidated Statements of Income (Loss).

	Year ended December 31
	2017		2016
Operating	$	30.1	$	44.1
General and administrative	35.5		50.2
Total employee compensation costs	$	65.6	$	94.3

KEY MANAGEMENT PERSONNEL

Pengrowth has determined that the key management personnel of the Corporation are its officers and directors. In addition to the officers’ salaries and directors’ fees, the Corporation also provides other compensation to both groups including long term equity based incentives.

The following table provides information on compensation expense related to officers and directors. During 2017, Pengrowth had 6 non-executive directors and 7 officers (2016 - 6 non-executive directors and 7 officers).

Year ended December 31, 2017	Wages & benefits paid		Bonus and other compensation paid		Share based compensation expense			Severance paid		Total
Directors	$	0.6	$	—	$	(0.6	)	$	—	$	—
Officers	2.2		2.7		1.9			—		6.8
	$	2.8	$	2.7	$	1.3		$	—	$	6.8
Year ended December 31, 2016	Wages & benefits paid		Bonus and other compensation paid		Share based compensation expense			Severance paid		Total
Directors	$	0.6	$	—	$	2.3		$	—	$	2.9
Officers	2.8		0.7		5.3			0.6		9.4
	$	3.4	$	0.7	$	7.6		$	0.6	$	12.3

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SIGNIFICANT ACCOUNTING POLICIES (Policies)

12 Months Ended

Dec. 31, 2017

Disclosure of changes in accounting policies, accounting estimates and errors [Abstract]

Accounting Pronouncements, Adopted and Not Yet Adopted

Accounting Pronouncement adopted - IFRS 15 Revenue from Contracts with Customers

On May 28, 2014, the IASB issued IFRS 15 Revenue from Contracts with Customers ("IFRS 15"). The new standard is effective for annual periods beginning on or after January 1, 2018. Earlier application is permitted. On April 12, 2016, the IASB issued Clarification to IFRS 15, which is effective at the same time as IFRS 15. The standard contains a single model that applies to contracts with customers and two approaches to recognizing revenue: at a point in time or over time. The model features a contract-based five-step analysis of transactions to determine the nature of an entity's obligation to perform and whether, how much and when revenue is recognized. New estimates and judgmental thresholds have been introduced, which may affect the amount and/or timing of revenue recognized. The new standard applies to contracts with customers. It does not apply to insurance contracts, financial instruments or lease contracts, which fall in the scope of other IFRSs.

Pengrowth has elected in the fourth quarter of 2017 to early adopt IFRS 15 for 2017 using the cumulative effect method. Under this method, prior years' financial statements have not been restated and the cumulative effect on net earnings of the application of IFRS 15 to revenue contracts in progress at January 1, 2017 is nil. Pengrowth management reviewed its revenue streams and major contracts with customers using the IFRS 15 five step model and there were no material changes to net earnings or timing of produced petroleum revenue recognized. It should be noted, however, that certain Income Statement line item reclassifications were made. Refer to Note 14 for more information including additional disclosure as required under IFRS 15.

Impact of Early Adoption of IFRS 15 on Interim 2017 Financial Statements

As a result of the adoption of IFRS 15, no cumulative effect adjustment to retained earnings was required. In accordance with the new standard, effective January 1, 2017, Pengrowth includes sales of diluent and other products as well as processing income in its Oil and gas sales consistent with the application of IFRS 15 including its principal versus agent evaluation requirements. This change has no impact on operating income (loss), income (loss) before taxes, net income (loss) or Cash Flows. The adoption of IFRS 15 alters the presentation of, and calculations for, Oil and gas sales and Operating expenses, and introduces a new Income Statement line for Diluent and other purchases for 2017. As per the table below, certain amounts in 2017 unaudited interim financial statements have been adjusted as follows:

	2017
	Q1	Q2	Q3
Oil and gas sales as previously reported	166.5	147.2	91.5
Diluent and other sales	46.7	45.2	28.9
Processing income	6.7	5.5	4.7
Adjusted Oil and gas sales	219.9	197.9	125.1
Diluent and other purchases as previously reported	—	—	—
Cost of diluent and other purchases	46.7	45.2	28.9
Adjusted Diluent and other purchases	46.7	45.2	28.9
Operating expenses as previously reported	60.6	63.0	46.9
Processing income	6.7	5.5	4.7
Adjusted operating expenses	67.3	68.5	51.6

IFRS 9 Financial Instruments

In July 2014, the IASB issued the complete IFRS 9 ("IFRS 9 (2014)"). The mandatory effective date of IFRS 9 (2014) is for annual periods beginning on or after January 1, 2018 and must be applied retrospectively with some exemptions. Early adoption is permitted. The restatement of prior periods is not required and is only permitted if information is available without the use of hindsight. IFRS 9 (2014) introduces new requirements for the classification and measurement of financial assets. Under IFRS 9 (2014), financial assets are classified and measured based on the business model in which they are held and the characteristics of their contractual cash flows. The standard introduces additional changes relating to financial liabilities. It also amends the impairment model by introducing a new ‘expected credit loss’ model for calculating impairment. Pengrowth does not anticipate material changes in the carrying value of its financial instruments nor from the credit loss impairment model upon adoption of IFRS 9 (2014).

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

IFRS 9 (2014) also includes a new general hedge accounting standard which aligns hedge accounting more closely with risk management. This new standard does not fundamentally change the types of hedging relationships or the requirement to measure and recognize ineffectiveness; however it will provide more hedging strategies that are used for risk management to qualify for hedge accounting and introduce more judgment to assess the effectiveness of a hedging relationship. Special transitional requirements have been set for the application of the new general hedging model. Pengrowth does not currently apply hedge accounting and does not currently intend to apply hedge accounting to its existing risk management contracts.

IFRS 16 Leases

In January 2016, the IASB issued the complete IFRS 16 Leases ("IFRS 16") which replaces IAS 17, Leases. The effective date of IFRS 16 is for annual periods beginning on or after January 1, 2019 and early adoption is permitted. Under IFRS 16, a single recognition and measurement model will apply for lessees which will require recognition of assets and liabilities for most leases. Pengrowth is currently evaluating the impact that the adoption of this standard will have on its financial statements.

Revenue Recognition

Revenue Recognition

Under IFRS 15, revenue from the sale of commodities is calculated by reference to consideration specified in contracts with customers and recognized when control of the product is transferred to the buyer. The nature of each of its performance obligations, including roles of third parties and partners, are evaluated to determine if the Company acts as a principal, and therefore recognizes revenue on a gross basis, or as an agent, and therefore recognizes revenue on a net basis. The Company acts as the principal when it controls the product delivered before the control passes to its customer.

Pengrowth earns revenue from the following major sources:

• Sales from the production of, and royalty (and gross overriding royalty) interests in, light oil, natural gas, natural gas liquids, sulphur and from the sale of diluted bitumen and purchased products;

• Fees charged to third parties for processing and other services (i.e. gas and other product processing, contract operating etc.) provided at facilities where Pengrowth has an ownership interest.

Revenue from the sale of diluted bitumen, light oil, natural gas, natural gas liquids and sulphur is recognized based on the consideration specified in contracts with customers. Pengrowth recognizes revenue when control of the product transfers to the buyer and collection is reasonably assured. This is generally at the point in time when the customer obtains legal title to the product which is when it is physically transferred to the pipeline or other transportation method agreed upon. Revenues from processing activities are recognized over time as processing occurs, and are generally billed monthly. Royalty income is recognized monthly as it accrues in accordance with the terms of the royalty agreements.

Pengrowth has reviewed its revenue streams and major contracts with customers using the IFRS 15 five step model and there are no material changes to timing of revenue recognized, however the gross versus net presentation resulted in material changes to certain items in the 2017 Income Statement with no impact to net income (loss).

When allocating the transaction price realized in contracts with multiple performance obligations over a longer period to multiple performance obligations using relative standalone selling prices, management is required to make estimates of the prices at which Pengrowth would sell the product separately to customers. When making this estimate, management considers market prices and market conditions and cash flows the entity intends to realize based on risk management policies, based on cost and cash flows the entity intends to realize based on risk management policies, based on cost and margin objectives. Pengrowth does not currently have any contracts with multiple performance obligations.

Basis of Presentation

Basis of Presentation

These Consolidated Financial Statements have been prepared in accordance with the International Financial Reporting Standards (“IFRS”) issued by the International Accounting Standards Board (“IASB”) and International Financial Reporting Interpretations Committee (“IFRIC”). Except for the changes below, Pengrowth has consistently applied the accounting policies to all periods presented in these consolidated financial statements.

Pengrowth’s operations are viewed as a single operating segment by the chief operating decision maker (CEO) of the Corporation for the purpose of resource allocation and assessing performance.

The Consolidated Financial Statements were authorized for release by the Board of Directors on February 28, 2018.

Property, Plant and Equipment (“PP&E”) and Exploration and Evaluation (“E&E”) Assets

Property, Plant and Equipment (“PP&E”) and Exploration and Evaluation (“E&E”) Assets

Pengrowth capitalizes all costs of developing and acquiring oil and gas properties. These costs include lease acquisition costs, geological and geophysical expenditures, costs of drilling and completion of wells, plant and production equipment costs and related overhead charges. Pengrowth capitalizes a portion of general and administrative costs and share based compensation expense associated with exploration and development activities. Repairs and maintenance costs are expensed as incurred.

Property, Plant and Equipment

PP&E is stated at cost less accumulated depletion, depreciation and amortization, and accumulated impairment losses. The initial cost of an asset comprises its purchase price or construction cost, costs attributable to bringing the asset into operation, the initial estimate of asset retirement obligation and, for qualifying assets, borrowing costs. When significant parts of an item of PP&E, including oil and natural gas interests, have different useful lives, they are accounted for as separate items.

Exploration and Evaluation Assets

Costs of exploring for and evaluating certain oil and natural gas properties are capitalized within E&E assets. These E&E assets include lease acquisition costs, geological and geophysical expenditures, costs of drilling and completion of wells, plant and production equipment costs and related overhead charges. E&E assets do not include costs of general prospecting, or evaluation costs incurred prior to having obtained the legal rights to explore an area, which are expensed as incurred. Interest is not capitalized on E&E assets.

E&E assets are not depleted or depreciated and are carried forward until technical feasibility and commercial viability is considered to be determined. The technical feasibility and commercial viability is generally considered to be determined when proved plus probable reserves are determined to exist and the commercial production of oil and gas has commenced. A review of each exploration license or field is carried out, at least annually, to ascertain whether the project is technically feasible and commercially viable. Upon determination of technical feasibility and commercial viability, E&E assets attributable to those reserves are first tested for impairment and then reclassified from E&E assets to PP&E.

Subsequent Costs

Costs incurred subsequent to the determination of technical feasibility and commercial viability and the costs of replacing parts of PP&E are recognized as oil and natural gas interests only when they increase the future economic benefits embodied in the specific asset to which they relate. Such capitalized oil and natural gas interests generally represent costs incurred in developing proved and/or probable reserves and bringing in or enhancing production from such reserves, and are accumulated on a field or geotechnical area basis.

The carrying amount of any replaced or sold component is de-recognized. The costs of the day-to-day servicing of PP&E are expensed as incurred.

Pengrowth capitalizes a portion of general and administrative costs directly associated with exploration and development activities. Pengrowth capitalizes interest incurred in construction of qualifying assets, if applicable. Qualifying assets are defined by Pengrowth as capital projects that require capital expenditures over a period greater than one year, in order to produce oil or gas from a specific property. Interest capitalization to a qualifying asset ceases once the asset is substantially available for its intended use.

Assets Held for Sale

Assets Held for Sale

Non-current assets are classified as held for sale if their carrying amounts will be recovered through a sale transaction rather than through continuing use. This condition is met when the sale is highly probable and the asset is available for immediate sale in its present condition. For the sale to be highly probable, Management must be committed to sell the asset and an active program to locate a buyer and complete the sale must have been initiated. The asset must be actively marketed for sale at a price that is reasonable in relation to its current fair value and the sale should be expected to be completed within one year from the date of classification. Non-current assets classified as held for sale are measured at the lower of the carrying amount and fair value less costs of disposal, with impairments recognized in the Consolidated Statements of Income (Loss) in the period measured.

Dispositions

Dispositions

Gains or losses are recognized in the Consolidated Statements of Income (Loss) on dispositions of PP&E and certain E&E assets, including asset swaps, farm-out transactions, gross overriding royalty and property dispositions. The gain or loss is measured as the difference between the fair value of the proceeds and the carrying value of the assets disposed, including capitalized future asset retirement obligations and any associated goodwill.

Depletion and Depreciation

Depletion and Depreciation

The net carrying value of developed or producing fields or groups of fields is depleted using the unit of production method by reference to the ratio of production in the period to the related proved plus probable reserves, taking into account estimated future development costs necessary to bring those reserves into production. Future development costs are estimated taking into account the level of development required to produce the reserves. These estimates are reviewed by independent reserve engineers at least annually. Pengrowth’s total proved plus probable reserves are estimated by an independent reserve evaluator and represent the "best estimate" of quantities of oil, natural gas and related substances to be commercially recoverable from known accumulations, from a given date forward, based on geological and engineering data. It is equally likely that the actual remaining quantities recovered will be greater than or less than the sum of the estimated proved plus probable reserves. Properties with no remaining production and reserves are fully depleted in the year that production ceases. Assets under construction are not depleted or depreciated until available for their intended use.

For other assets, depreciation is recognized in the Consolidated Statements of Income (Loss) using either a straight line or declining balance basis over the estimated useful lives of each part of an item of PP&E.

Depreciation methods, useful lives and residual values are reviewed annually.

Farmouts

Farmouts

Under IFRS, farmouts are considered a disposition of a partial interest in a property. The proceeds on the disposition are generally considered to be the capital spent, or estimated to be spent, by the farmee in order to earn the interest. When the agreed upon work commitment has been completed, the farmee has earned their interest. It is at this stage that Pengrowth records a gain or loss on disposition, as the difference between the estimated capital and the carrying value of the disposed interest, in the Consolidated Statements of Income (Loss).

Leased Assets

Leased Assets

Assets held by Pengrowth under leases which transfer to the Corporation substantially all of the risks and rewards of ownership are classified as finance leases. On initial recognition, the leased asset is measured at an amount equal to the lower of its fair value and the present value of the minimum lease payments. Subsequent to initial recognition, the asset is accounted for in accordance with the accounting policy applicable to that asset. Minimum lease payments made under finance leases are apportioned between the finance expense and the reduction of the outstanding liability. The finance expense is allocated to each period during the lease term so as to produce a constant periodic rate of interest on the remaining balance of the liability.

Assets held under other leases are classified as operating leases and are not recognized in the Consolidated Balance Sheets. Payments made under operating leases are recognized in the Consolidated Statements of Income (Loss) on a straight-line basis over the term of the lease. Lease incentives received are recognized as an integral part of the total lease expense, over the term of the lease.

At inception of certain arrangements, the Corporation determines whether such arrangement is or contains a lease. This will be the case if the following two criteria are met:

• The fulfillment of the arrangement is dependent on the use of a specific asset or assets; and

• The arrangement contains the right to use the asset(s).

Goodwill

Goodwill may arise on business combinations and represents the excess of the cost of the acquisition over the net fair value of the identifiable assets, liabilities and contingent liabilities of the acquired assets or company. When the excess is negative, it is recognized immediately in the Consolidated Statements of Income (Loss).

Impairment of Non-Financial Assets

Non-Financial Assets

Property, Plant and Equipment

For the purpose of impairment testing, PP&E is grouped together into the smallest group of assets that generate cash inflows from continuing use that are largely independent of the cash inflows of other assets or groups of assets - cash generating unit (the “CGU”). CGUs are tested when there is an indication of impairment, such as sustained decreases in commodity prices or significant downward revisions in reserves volumes. An impairment loss is recognized to the extent the carrying value of the CGU exceeds its recoverable amount. Impairment losses are recognized in the Consolidated Statements of Income (Loss).

The recoverable amount of a CGU is the higher of its value in use and the fair value less costs to sell. In determining the recoverable amount, the estimated future cash flows are discounted to their present value using a pre-tax discount rate that reflects current market assessments of the cost of capital, which take into account the time value of money and the risks specific to the asset. The recoverable amount is generally computed by reference to the present value of the future cash flows expected to be derived from production of proved and probable reserves. Undeveloped land, contingent resources and infrastructure may also be considered in the recoverable amount.

Impairment losses in respect of PP&E recognized in prior periods are assessed at each reporting date for any indications that the loss has decreased or no longer exists. In such circumstances, the recoverable amount is determined and to the extent the loss is reduced, it is reversed. An impairment loss is reversed only to the lesser of the revised recoverable amount or the carrying amount that would have been determined, net of depletion and depreciation or amortization, if no impairment loss had been recognized.

Exploration and Evaluation Assets

E&E assets are tested for impairment when there is an indication that a particular E&E project may be impaired. Examples of indicators of impairment include a significant price decline over an extended period, the decision to delay or no longer pursue the E&E project, an expiry of the rights to explore in an area, or failure to receive regulatory approval. In addition, E&E assets are assessed for impairment upon their reclassification to producing assets (oil and natural gas interests in PP&E). In assessing the impairment of E&E assets, the carrying value of the E&E assets would be compared to their estimated recoverable amount and, in certain circumstances, could be tested in conjunction with PP&E impairment testing of related CGUs. The impairment of E&E assets would be recognized in the Consolidated Statements of Income (Loss).

Impairment of Financial Assets

Financial Assets

A financial asset is assessed at each reporting date to determine whether there is any objective evidence that it is impaired. A financial asset is considered to be impaired if objective evidence, including failure to pay on time, indicates that one or more events have had a negative effect on the estimated future cash flows of that asset.

An impairment loss in respect of a financial asset, measured at amortized cost, is calculated as the difference between its carrying amount and the present value of the estimated future cash flows discounted at the original effective interest rate. Significant financial assets are tested for impairment on an individual basis. The remaining financial assets are assessed collectively in groups that share similar credit risk characteristics.

Any impairment losses of financial assets are recognized in the Consolidated Statements of Income (Loss). An impairment loss is reversed if the reversal can be related objectively to an event occurring after the impairment loss was recognized. For financial assets measured at amortized cost, the reversal is recognized in the Consolidated Statements of Income (Loss).

Provisions and Other Liabilities

Provisions and Other Liabilities

A provision is recognized if, as a result of a past event, the Corporation has a present legal or constructive obligation that can be estimated reliably and it is probable that an outflow of economic benefits will be required to settle the obligation. Provisions are determined by discounting the expected future cash flows at the appropriate discount rate. Provisions are not permitted for future operating losses.

Asset Retirement Obligations (“ARO”)

Pengrowth initially recognizes the net present value of an ARO in the period in which it is incurred when a reasonable estimate of the net present value can be made. The net present value of the estimated ARO is recorded as a liability, with a corresponding increase in the carrying amount of the related asset. The capitalized asset is depleted on the unit of production method based on proved plus probable reserves. The liability is increased each reporting period due to the passage of time and the amount of such accretion is expensed to income in the period. Actual costs incurred upon the settlement of the ARO are charged against the ARO. Management reviews the ARO estimate and changes, if any, are applied prospectively. Revisions made to the ARO estimate are recorded as an increase or decrease to the ARO liability with a corresponding change made to the carrying amount of the related asset. The carrying amount of both the liability and the capitalized asset, net of accumulated depreciation, are derecognized if the asset is subsequently disposed. The ARO liability is presented as Provisions on the Consolidated Balance Sheets. Refunds of previously paid offshore royalties are recognized as receivables only when production in a field has ceased and as abandonment and decommissioning spending has been incurred.

Pengrowth has placed cash in a segregated, independently managed, remediation trust fund account to fund ARO for the Sable Offshore Energy Project ("SOEP") property. The fund is reflected in Other Assets on the Consolidated Balance Sheets.

Finance Leases

Finance lease transactions are also categorized in Provisions and other liabilities.

Onerous Office Lease Contracts

Onerous office lease obligation related to excess office space is recognized when the unavoidable costs of the lease contracts over the remaining term exceed the economic benefits of the office lease. The onerous office lease provision is calculated as present value of future lease payments the Company is obligated to make under the lease contracts less any recoveries under current or anticipated sublease agreements over the remaining life of the lease.

Other Liabilities

Pengrowth also categorizes cash-settled long term incentive plan ("LTIP") grants andcash deferred bonus, within this grouping.

Income Taxes

Income Taxes

Income tax (recovery) expense is composed of current and deferred tax. Income tax (recovery) expense is recognized in the Consolidated Statements of Income (Loss) except to the extent that it relates to items recognized directly in equity.

Current tax is the expected tax payable on the taxable income for the year, using tax rates enacted or substantively enacted at the reporting date, and any adjustment to tax payable in respect of previous years.

Deferred tax is recognized using the asset and liability method of accounting for income taxes. Under this method, income tax liabilities and assets are recognized for the estimated tax consequences attributable to differences between the amounts reported in the Consolidated Financial Statements and their respective tax bases, using substantively enacted income tax rates. Deferred tax assets are recognized for unused tax losses, unused tax credits and deductible temporary differences to the extent that it is probable that future taxable profits will be available against which they can be used. Future taxable profits are determined based on the reversal of relevant taxable temporary differences. If the amount of taxable temporary difference is insufficient to recognize a deferred tax asset in full, then future taxable profits, adjusted for reversals of existing temporary differences, are considered, based on Pengrowth's business plans.

The effect of a change in income tax rates on deferred income tax liabilities and assets is recognized in income in the period the change occurs. Deferred tax assets and liabilities are offset if there is a legally enforceable right to offset current tax liabilities and assets, and they relate to income taxes levied by the same tax authority on the same taxable entity. Deferred tax assets are reviewed at each reporting date and are reduced to the extent that it is no longer probable that the related tax benefit will be realized; these reductions are reversed when the probability of future taxable profits improves.

Pengrowth’s policy for income tax uncertainties is that tax benefits will be recognized only when it is more likely than not the position will be sustained on examination.

Share Based Compensation Plans

Share Based Compensation Plans

Pengrowth has share-settled and cash-settled share based compensation plans, which are described in Note 13.

i) Share-settled LTIP

Compensation expense is based on the estimated fair value of the share-settled award at the date of grant. Compensation expenses associated with the share-settled plans are recognized in the Consolidated Statements of Income (Loss) over the vesting period of the plan with a corresponding increase to contributed surplus. Pengrowth estimates the forfeiture rate for each type of share based award at the date of grant. Any consideration received upon the exercise of the awards together with the amount of non-cash compensation expense recognized in contributed surplus is recorded as an increase in shareholders’ capital at the time of exercise.

ii) Cash-settled LTIP

Each cash-settled RSU entitles the holder to a cash payment equivalent to the value of a number of common shares (including the reinvestment of deemed dividends, if applicable) which vest evenly over a period of three years or less. Furthermore, the independent members of the Board of Directors also receive cash-settled long term incentives called Phantom Deferred Share Units ("PhantomDSUs"). Each Phantom DSU entitles the holder to a cash payment equivalent to the value of a number of common shares (including the reinvestment of deemed dividends, if applicable) to be paid upon the individual ceasing to be a Director for any reason.

Compensation expense associated with the cash-settled LTIP is determined based on the fair value of the share units at the grant date and is subsequently adjusted to reflect the fair value of the share units at each period end, including notional dividends, as applicable. Pengrowth estimates the forfeiture rate for each type of share based award at the date of grant. This valuation incorporates the period end share price and the number of cash-settled LTIP units outstanding at each period end. Compensation expense is recognized in the Statements of Income (Loss) with a corresponding increase or decrease in liabilities. Classification of the associated short term and long term liabilities is dependent on the expected payout dates.

Financial Instruments

Financial Instruments

Financial instruments are utilized by Pengrowth to manage its exposure to commodity and power price fluctuations, as well as foreign currency exposures. Pengrowth’s policy is not to utilize financial instruments for trading or speculative purposes.

Financial instruments are classified into one of five categories: (i) fair value through profit or loss, (ii) held to maturity investments, (iii) loans and receivables, (iv) available for sale financial assets or (v) other liabilities.

Accounts receivable are classified as loans and receivables which are measured at amortized cost.

Investments held in the remediation trust funds and other investments have been designated as fair value through profit or loss and are measured at fair value. Any change in the fair value is recognized in the Consolidated Statements of Income (Loss).

Bank indebtedness, accounts payable, convertible debentures and long term debt have been classified as other liabilities which are measured at amortized cost using the effective interest rate method.

Pengrowth has accounted for its physical delivery sales contracts, which were entered into and continue to be held for the purpose of receipt or delivery of non-financial items in accordance with its expected purchase, sale or usage requirements as executory contracts. As such, these contracts are not considered to be derivative financial instruments and have not been recorded at fair value on the Consolidated Balance Sheets. Settlements on these physical delivery sales contracts are recognized in revenue in the period of settlement.

All derivatives must be classified as fair value through profit or loss and measured at fair value with changes in fair value over a reporting period recognized in net income (loss).

The receipts or payments arising from derivative commodity contracts are presented as realized gain (loss) on commodity risk management while the unrealized gains and losses are presented as changes in fair value of commodity risk management contracts.

The receipts or payments arising from derivative power contracts are included in operating expenses. The unrealized gains and losses on derivative power contracts are included in other (income) expense.

The receipts or payments arising from derivative foreign exchange contracts are presented as realized foreign exchange (gain) loss while the unrealized gains and losses are presented as unrealized foreign exchange (gain) loss.

Transaction costs incurred in connection with the issuance of term debt instruments with a maturity of greater than one year are deducted against the carrying value of the debt and amortized to net income (loss) using the effective interest rate method over the expected life of the debt.

Pengrowth capitalizes transaction costs incurred in connection with the renewal of the revolving Credit Facility with a maturity date greater than one year and amortizes the cost to net income (loss) on a straight line basis over the term of the facility.

Fair Value Measurement

All financial assets and liabilities for which fair value is measured or disclosed in the Consolidated Financial Statements are further categorized using a three-level hierarchy that reflects the significance of the lowest level of inputs used in determining fair value:

• Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

• Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1. Prices in Level 2 are either directly or indirectly observable as of the reporting date. Level 2 valuations are based on inputs, including quoted forward prices for commodities, time value and volatility factors, which can be substantially observed or corroborated in the marketplace.

• Level 3 – Valuations in this level are those with inputs for the asset or liability that are not based on observable market data.

Implementation of IFRS 9 (2014) - Financial Instruments

Pengrowth intends to adopt IFRS 9 (2014) in its Consolidated Financial Statements for the annual period beginning on January 1, 2018. The standard is generally required to be adopted retrospectively with or without restatement of prior periods in accordance with transition requirements. Pengrowth does not anticipate changes in measurement or reclassification of its financial instruments from implementation of IFRS 9 (2014).

Foreign Currency

Foreign Currency

The functional and reporting currency of the Corporation is Canadian dollars. Transactions in foreign currencies are translated to Canadian dollars at the exchange rates on the date of the transactions. Monetary assets and liabilities denominated in foreign currencies are translated into Canadian dollars at the exchange rate in effect on the Consolidated Balance Sheet date. Foreign exchange gains and losses are recognized in the Consolidated Statements of Income (Loss).

Jointly Controlled Operations

Jointly Controlled Operations

A significant proportion of Pengrowth’s petroleum and natural gas development and production activities are conducted through jointly controlled operations that are not conducted through separate vehicles and accordingly, the accounts reflect only Pengrowth’s interest in such activities.

Related Parties

Related Parties

Related parties are persons or entities that have control or significant influence over Pengrowth, as well as key management personnel. Note 21 provides information on compensation expense related to key management personnel. Pengrowth has no significant transactions with any other related parties.

Diluent and other purchases

Diluent and other purchases

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

Equity Investment

Equity Investment

Pengrowth utilizes the equity method of accounting for investments subject to significant influence, if applicable. Under this method, investments are initially recorded at cost and adjusted thereafter to include Pengrowth’s pro rata share of post-acquisition earnings. Any dividends received or receivable from the investee would reduce the carrying value of the investment.

Estimates

Estimates

The preparation of 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 Consolidated Financial Statements and revenues and expenses during the reporting year. Actual results could differ from those estimated.

In particular, information about significant areas of estimation uncertainty and critical judgments in applying accounting policies that have the most significant effect on the amounts recognized in the Consolidated Financial Statements is described below:

Estimating oil and gas reserves and contingent resources

Pengrowth engages a qualified, independent oil and gas reserves evaluator to perform an estimation of the Corporation’s oil and gas reserves at least annually and contingent resources on an ad hoc basis. Reserves form the basis for the calculation of depletion charges, while oil and gas reserves and contingent resources are used in the assessment of impairment of goodwill and oil and gas assets. Reserves and contingent resources are estimated using the reserve definitions and guidelines prescribed by National Instrument 51-101 (“NI 51-101”) and the Canadian Oil and Gas Evaluation Handbook (“COGEH”).

Proved plus probable reserves are defined as the "best estimate" of quantities of oil, natural gas and related substances estimated to be commercially recoverable from known accumulations, from a given date forward, based on drilling, geological, geophysical and engineering data, the use of established technology and specified economic conditions. It is equally likely that the actual remaining quantities recovered will be greater than or less than the sum of the estimated proved plus probable reserves. The estimates are made using all available geological and reservoir data as well as historical production data. Estimates are reviewed and revised as appropriate. Revisions occur as a result of changes in prices, costs, fiscal regimes and reservoir performance or a change in Pengrowth's plans with respect to future development or operating practices.

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

Determination of CGUs

The recoverability of development and production asset carrying values are assessed at the CGU level. Determination of what constitutes a CGU is subject to management’s judgment. The asset composition of a CGU can directly impact the recoverability of the assets included therein. In assessing the recoverability of oil and gas properties, each CGU's carrying value is compared to its recoverable amount, defined as the fair value less costs to sell.

Asset Retirement Obligations

Pengrowth estimates obligations under environmental regulations in respect of decommissioning and site restoration. These obligations are determined based on the expected present value of expenses required in the process of plugging and abandoning wells, dismantling of wellheads, production and transportation facilities and restoration of producing areas in accordance with relevant legislation, discounted from the date when expenses are expected to be incurred. Most of the abandonment of Pengrowth's wells is estimated to take place far in the future. Therefore, changes in estimated timing of future expenses, estimated logistics of performing abandonment work, the inflation assumption, and the discount rate used to present value future expenses could have a significant effect on the carrying amount of the decommissioning provision.

Impairment testing

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

Fair value of risk management contracts

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

Valuation of trade and other receivables, and prepayments to suppliers

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

Net Income (Loss) per Share

Net Income (Loss) per Share

Basic net income (loss) per share is calculated using the weighted average number of shares outstanding for the year. Diluted net income (loss) per share amounts includes the dilutive effect of share units under the share-settled long term incentive plans using the treasury stock method. The treasury stock method assumes that any proceeds obtained on the exercise of any dilutive share units would be used to repurchase common shares at the average trading price during the period.

The dilutive effect of convertible debentures is calculated using net income (loss) for the period, adjusted for the after tax interest on the convertible debentures assuming they were converted at the start of the period; and adding to the diluted number of shares the weighted average shares issuable if the convertible debentures were converted at the start of the period.

Cash and Term Deposits

Cash and Term Deposits

Cash and term deposits include demand deposits and term deposits with original maturities of less than 90 days.

Comparative Figures

COMPARATIVE FIGURES

Certain prior years' comparative figures have been reclassified to conform to presentation adopted in the current year.

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SIGNIFICANT ACCOUNTING POLICIES (Tables)

12 Months Ended

Dec. 31, 2017

Disclosure of changes in accounting policies, accounting estimates and errors [Abstract]

Restatement of Oil and Gas Sales and Dilutent and Other Product Purchases

operating income (loss), income (loss) before taxes, net income (loss) or Cash Flows. The adoption of IFRS 15 alters the presentation of, and calculations for, Oil and gas sales and Operating expenses, and introduces a new Income Statement line for Diluent and other purchases for 2017. As per the table below, certain amounts in 2017 unaudited interim financial statements have been adjusted as follows:

	2017
	Q1	Q2	Q3
Oil and gas sales as previously reported	166.5	147.2	91.5
Diluent and other sales	46.7	45.2	28.9
Processing income	6.7	5.5	4.7
Adjusted Oil and gas sales	219.9	197.9	125.1
Diluent and other purchases as previously reported	—	—	—
Cost of diluent and other purchases	46.7	45.2	28.9
Adjusted Diluent and other purchases	46.7	45.2	28.9
Operating expenses as previously reported	60.6	63.0	46.9
Processing income	6.7	5.5	4.7
Adjusted operating expenses	67.3	68.5	51.6

Summary of Property, Plant and Equipment

The estimated useful lives for other assets for the current and comparative periods are as follows:

-	Office equipment	60 months
-	Leasehold improvements and finance leases	Lease term/Useful life
-	Computers	36 months
-	Deferred hydrocarbon injectants	24 months
-	Motor vehicles	60 months

Cost or deemed cost	Oil and natural gas assets			Other equipment			Total
Balance, December 31, 2015	$	6,973.5		$	88.9		$	7,062.4
Additions to PP&E	89.9			1.9			91.8
Property acquisitions	1.3			—			1.3
Change in asset retirement obligations	(34.4		)	—			(34.4		)
Divestitures	(191.5		)	—			(191.5		)
Balance, December 31, 2016	$	6,838.8		$	90.8		$	6,929.6
Additions to PP&E	120.7			0.8			121.5
Property acquisitions	0.1			—			0.1
Change in asset retirement obligations	9.3			—			9.3
Divestitures	(3,151.2		)	(3.7		)	(3,154.9		)
Balance, December 31, 2017	$	3,817.7		$	87.9		$	3,905.6
Accumulated depletion, amortization and impairment losses	Oil and natural gas assets			Other equipment			Total
Balance, December 31, 2015	$	3,639.5		$	76.1		$	3,715.6
Depletion and amortization for the period	345.6			4.3			349.9
Divestitures	(102.4		)	—			(102.4		)
Balance, December 31, 2016	$	3,882.7		$	80.4		$	3,963.1
Depletion and amortization for the period	204.4			3.2			207.6
Impairment	504.4			—			504.4
Divestitures	(1,871.2		)	(2.5		)	(1,873.7		)
Balance, December 31, 2017	$	2,720.3		$	81.1		$	2,801.4
Net book value	Oil and natural gas assets			Other equipment			Total
As at December 31, 2017
Assets held for sale	$	—		$	—		$	—
Long term	1,097.4			6.8			1,104.2
	$	1,097.4		$	6.8		$	1,104.2
As at December 31, 2016
Assets held for sale	$	117.5		$	—		$	117.5
Long term	2,838.6			10.4			2,849.0
	$	2,956.1		$	10.4		$	2,966.5

Cost or deemed cost
Balance, December 31, 2015	$	494.8
Additions	1.5
Balance, December 31, 2016	$	496.3
Divestitures	(134.3		)
Impairment	(130.0		)
Balance, December 31, 2017	$	232.0

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OTHER ASSETS (Tables)

12 Months Ended

Dec. 31, 2017

Disclosure Of Other Assets [Abstract]

Components of Other Assets

	As at
	December 31, 2017		December 31, 2016
Remediation trust funds - current	$	24.0	$	—
Remediation trust funds - non-current	87.6		106.5
Prepaid tax assessment	12.2		12.2
	$	123.8	$	118.7

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PROPERTY, PLANT AND EQUIPMENT ("PP&E") (Tables)

12 Months Ended

Dec. 31, 2017

Property, plant and equipment [abstract]

Summary of Property, Plant and Equipment

The estimated useful lives for other assets for the current and comparative periods are as follows:

-	Office equipment	60 months
-	Leasehold improvements and finance leases	Lease term/Useful life
-	Computers	36 months
-	Deferred hydrocarbon injectants	24 months
-	Motor vehicles	60 months

Cost or deemed cost	Oil and natural gas assets			Other equipment			Total
Balance, December 31, 2015	$	6,973.5		$	88.9		$	7,062.4
Additions to PP&E	89.9			1.9			91.8
Property acquisitions	1.3			—			1.3
Change in asset retirement obligations	(34.4		)	—			(34.4		)
Divestitures	(191.5		)	—			(191.5		)
Balance, December 31, 2016	$	6,838.8		$	90.8		$	6,929.6
Additions to PP&E	120.7			0.8			121.5
Property acquisitions	0.1			—			0.1
Change in asset retirement obligations	9.3			—			9.3
Divestitures	(3,151.2		)	(3.7		)	(3,154.9		)
Balance, December 31, 2017	$	3,817.7		$	87.9		$	3,905.6
Accumulated depletion, amortization and impairment losses	Oil and natural gas assets			Other equipment			Total
Balance, December 31, 2015	$	3,639.5		$	76.1		$	3,715.6
Depletion and amortization for the period	345.6			4.3			349.9
Divestitures	(102.4		)	—			(102.4		)
Balance, December 31, 2016	$	3,882.7		$	80.4		$	3,963.1
Depletion and amortization for the period	204.4			3.2			207.6
Impairment	504.4			—			504.4
Divestitures	(1,871.2		)	(2.5		)	(1,873.7		)
Balance, December 31, 2017	$	2,720.3		$	81.1		$	2,801.4
Net book value	Oil and natural gas assets			Other equipment			Total
As at December 31, 2017
Assets held for sale	$	—		$	—		$	—
Long term	1,097.4			6.8			1,104.2
	$	1,097.4		$	6.8		$	1,104.2
As at December 31, 2016
Assets held for sale	$	117.5		$	—		$	117.5
Long term	2,838.6			10.4			2,849.0
	$	2,956.1		$	10.4		$	2,966.5

Cost or deemed cost
Balance, December 31, 2015	$	494.8
Additions	1.5
Balance, December 31, 2016	$	496.3
Divestitures	(134.3		)
Impairment	(130.0		)
Balance, December 31, 2017	$	232.0

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EXPLORATION AND EVALUATION ASSETS ("E&E") (Tables)

12 Months Ended

Dec. 31, 2017

Exploration For And Evaluation Of Mineral Resources [Abstract]

Summary of Exploration and Evaluation Assets

The estimated useful lives for other assets for the current and comparative periods are as follows:

-	Office equipment	60 months
-	Leasehold improvements and finance leases	Lease term/Useful life
-	Computers	36 months
-	Deferred hydrocarbon injectants	24 months
-	Motor vehicles	60 months

Cost or deemed cost	Oil and natural gas assets			Other equipment			Total
Balance, December 31, 2015	$	6,973.5		$	88.9		$	7,062.4
Additions to PP&E	89.9			1.9			91.8
Property acquisitions	1.3			—			1.3
Change in asset retirement obligations	(34.4		)	—			(34.4		)
Divestitures	(191.5		)	—			(191.5		)
Balance, December 31, 2016	$	6,838.8		$	90.8		$	6,929.6
Additions to PP&E	120.7			0.8			121.5
Property acquisitions	0.1			—			0.1
Change in asset retirement obligations	9.3			—			9.3
Divestitures	(3,151.2		)	(3.7		)	(3,154.9		)
Balance, December 31, 2017	$	3,817.7		$	87.9		$	3,905.6
Accumulated depletion, amortization and impairment losses	Oil and natural gas assets			Other equipment			Total
Balance, December 31, 2015	$	3,639.5		$	76.1		$	3,715.6
Depletion and amortization for the period	345.6			4.3			349.9
Divestitures	(102.4		)	—			(102.4		)
Balance, December 31, 2016	$	3,882.7		$	80.4		$	3,963.1
Depletion and amortization for the period	204.4			3.2			207.6
Impairment	504.4			—			504.4
Divestitures	(1,871.2		)	(2.5		)	(1,873.7		)
Balance, December 31, 2017	$	2,720.3		$	81.1		$	2,801.4
Net book value	Oil and natural gas assets			Other equipment			Total
As at December 31, 2017
Assets held for sale	$	—		$	—		$	—
Long term	1,097.4			6.8			1,104.2
	$	1,097.4		$	6.8		$	1,104.2
As at December 31, 2016
Assets held for sale	$	117.5		$	—		$	117.5
Long term	2,838.6			10.4			2,849.0
	$	2,956.1		$	10.4		$	2,966.5

Cost or deemed cost
Balance, December 31, 2015	$	494.8
Additions	1.5
Balance, December 31, 2016	$	496.3
Divestitures	(134.3		)
Impairment	(130.0		)
Balance, December 31, 2017	$	232.0

Estimated Forward Natural Gas Prices for Impairment Testing

Below are the forward natural gas price estimates used in the December 31, 2017 impairment test:

	AECO gas (1)
Year	(Cdn$/MMBtu)
2018	2.20
2019	2.54
2020	2.88
2021	3.24
2022	3.47
2023	3.58
2024	3.66
2025	3.73
2026	3.80
2027	3.88
Thereafter	+ 2.0 percent/yr

⁽¹⁾  Prices represent forecasted amounts as at January 1, 2018 by Pengrowth's independent reserves evaluator.

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CONVERTIBLE DEBENTURES (Tables)

12 Months Ended

Dec. 31, 2017

Disclosure of detailed information about financial instruments [abstract]

Summary of Convertible Debentures

The following table summarizes the activity associated with the convertible debentures:

	Series B - 6.25 percent
Maturity date	March 31, 2017
Conversion price (per Pengrowth share)	$	11.51
Balance, December 31, 2015	$	137.0
Repurchase of convertible debentures	(10.2		)
Premium accretion	(0.2		)
Balance, December 31, 2016	$	126.6
Repayment of convertible debentures	(126.6		)
Balance, December 31, 2017	$	—
Face value, December 31, 2017	$	—

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

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

	As at
	December 31, 2017		December 31, 2016
U.S. dollar denominated term notes:
400 million at 6.35 percent due July 26, 2017	$	—	$	537.0
265 million at 6.98 percent due August 21, 2018 (1)	—		355.6
35 million at 5.49 percent due October 18, 2019 (2)	35.3		46.9
115.5 million at 7.98 percent due May 11, 2020 (3)	118.3		154.8
105 million at 6.07 percent due October 18, 2022 (4)	107.1		140.6
195 million at 6.17 percent due October 18, 2024 (5)	199.7		261.1
	$	460.4	$	1,496.0
U.K. pound sterling denominated term notes:
15 million at 5.45 percent due October 18, 2019 (6)	$	20.6	$	24.8
Canadian dollar term notes:
15 million at 6.61 percent due August 21, 2018 (1)	$	—	$	15.0
25 million at 6.74 percent due October 18, 2022 (7)	20.5		24.9
	$	20.5	$	39.9
Canadian dollar term Credit Facility borrowings	$	109.0	$	—
Total long term debt	$	610.5	$	1,560.7
Current portion of long term debt	$	—	$	537.0
Non-current portion of long term debt	610.5		1,023.7
	$	610.5	$	1,560.7

⁽¹⁾  There was no outstanding balance following the early repayment on October 12, 2017.

⁽²⁾  The remaining balance of U.S.$28.1 million term notes were outstanding, following the early repayment of U.S.$6.9 million in the fourth quarter of 2017.

⁽³⁾  The remaining balance of U.S.$94.1 million term notes were outstanding, following the early repayment of U.S.$21.4 million in the fourth quarter of 2017.

⁽⁴⁾  The remaining balance of U.S.$85.2 million term notes were outstanding, following the early repayment of U.S.$19.8 million in the fourth quarter of 2017.

⁽⁵⁾  The remaining balance of U.S.$158.9 million term notes were outstanding, following the early repayment of U.S.$36.1 million in the fourth quarter of 2017.

⁽⁶⁾  The remaining balance of U.K. pound sterling 12.1 million term notes were outstanding, following the early repayment of U.K. pound sterling 2.9 million in the fourth quarter of 2017.

⁽⁷⁾  The remaining balance of Cdn$20.5 million term notes were outstanding, following the early repayment of Cdn$4.5 million in the fourth quarter of 2017.

The following table provides a reconciliation between the opening and closing balances for liabilities arising from financing activities at December 31, 2017:

	Term Notes			Canadian dollar Term Credit Facility		Convertible debentures
Balance December 31, 2016	$	1,560.7		$	—	$	126.6
Increase (decrease) due to:
Foreign exchange impact of the Canadian dollar on U.S. and U.K. denominated debt	(65.1		)	—		—
Credit facility borrowing	—			109.0		—
Repayment	(996.0		)	—		(126.6		)
Issue cost amortization	1.9			—		—
Balance, December 31, 2017	$	501.5		$	109.0	$	—

The minimum ratio for the quarter ending September 30, 2017 through to and including the quarter ending September 30, 2019 is as follows:

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

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LONG TERM DEBT (Tables)

12 Months Ended

Dec. 31, 2017

Disclosure of detailed information about financial instruments [abstract]

Summary of Long Term Debt

The following table summarizes the activity associated with the convertible debentures:

	Series B - 6.25 percent
Maturity date	March 31, 2017
Conversion price (per Pengrowth share)	$	11.51
Balance, December 31, 2015	$	137.0
Repurchase of convertible debentures	(10.2		)
Premium accretion	(0.2		)
Balance, December 31, 2016	$	126.6
Repayment of convertible debentures	(126.6		)
Balance, December 31, 2017	$	—
Face value, December 31, 2017	$	—

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

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

	As at
	December 31, 2017		December 31, 2016
U.S. dollar denominated term notes:
400 million at 6.35 percent due July 26, 2017	$	—	$	537.0
265 million at 6.98 percent due August 21, 2018 (1)	—		355.6
35 million at 5.49 percent due October 18, 2019 (2)	35.3		46.9
115.5 million at 7.98 percent due May 11, 2020 (3)	118.3		154.8
105 million at 6.07 percent due October 18, 2022 (4)	107.1		140.6
195 million at 6.17 percent due October 18, 2024 (5)	199.7		261.1
	$	460.4	$	1,496.0
U.K. pound sterling denominated term notes:
15 million at 5.45 percent due October 18, 2019 (6)	$	20.6	$	24.8
Canadian dollar term notes:
15 million at 6.61 percent due August 21, 2018 (1)	$	—	$	15.0
25 million at 6.74 percent due October 18, 2022 (7)	20.5		24.9
	$	20.5	$	39.9
Canadian dollar term Credit Facility borrowings	$	109.0	$	—
Total long term debt	$	610.5	$	1,560.7
Current portion of long term debt	$	—	$	537.0
Non-current portion of long term debt	610.5		1,023.7
	$	610.5	$	1,560.7

⁽¹⁾  There was no outstanding balance following the early repayment on October 12, 2017.

⁽²⁾  The remaining balance of U.S.$28.1 million term notes were outstanding, following the early repayment of U.S.$6.9 million in the fourth quarter of 2017.

⁽³⁾  The remaining balance of U.S.$94.1 million term notes were outstanding, following the early repayment of U.S.$21.4 million in the fourth quarter of 2017.

⁽⁴⁾  The remaining balance of U.S.$85.2 million term notes were outstanding, following the early repayment of U.S.$19.8 million in the fourth quarter of 2017.

⁽⁵⁾  The remaining balance of U.S.$158.9 million term notes were outstanding, following the early repayment of U.S.$36.1 million in the fourth quarter of 2017.

⁽⁶⁾  The remaining balance of U.K. pound sterling 12.1 million term notes were outstanding, following the early repayment of U.K. pound sterling 2.9 million in the fourth quarter of 2017.

⁽⁷⁾  The remaining balance of Cdn$20.5 million term notes were outstanding, following the early repayment of Cdn$4.5 million in the fourth quarter of 2017.

The following table provides a reconciliation between the opening and closing balances for liabilities arising from financing activities at December 31, 2017:

	Term Notes			Canadian dollar Term Credit Facility		Convertible debentures
Balance December 31, 2016	$	1,560.7		$	—	$	126.6
Increase (decrease) due to:
Foreign exchange impact of the Canadian dollar on U.S. and U.K. denominated debt	(65.1		)	—		—
Credit facility borrowing	—			109.0		—
Repayment	(996.0		)	—		(126.6		)
Issue cost amortization	1.9			—		—
Balance, December 31, 2017	$	501.5		$	109.0	$	—

The minimum ratio for the quarter ending September 30, 2017 through to and including the quarter ending September 30, 2019 is as follows:

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

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CAPITAL DISCLOSURES (Tables)

12 Months Ended

Dec. 31, 2017

Disclosure of share capital, reserves and other equity interest [Abstract]

Summary of Long Term Debt

The following table summarizes the activity associated with the convertible debentures:

	Series B - 6.25 percent
Maturity date	March 31, 2017
Conversion price (per Pengrowth share)	$	11.51
Balance, December 31, 2015	$	137.0
Repurchase of convertible debentures	(10.2		)
Premium accretion	(0.2		)
Balance, December 31, 2016	$	126.6
Repayment of convertible debentures	(126.6		)
Balance, December 31, 2017	$	—
Face value, December 31, 2017	$	—

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

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

	As at
	December 31, 2017		December 31, 2016
U.S. dollar denominated term notes:
400 million at 6.35 percent due July 26, 2017	$	—	$	537.0
265 million at 6.98 percent due August 21, 2018 (1)	—		355.6
35 million at 5.49 percent due October 18, 2019 (2)	35.3		46.9
115.5 million at 7.98 percent due May 11, 2020 (3)	118.3		154.8
105 million at 6.07 percent due October 18, 2022 (4)	107.1		140.6
195 million at 6.17 percent due October 18, 2024 (5)	199.7		261.1
	$	460.4	$	1,496.0
U.K. pound sterling denominated term notes:
15 million at 5.45 percent due October 18, 2019 (6)	$	20.6	$	24.8
Canadian dollar term notes:
15 million at 6.61 percent due August 21, 2018 (1)	$	—	$	15.0
25 million at 6.74 percent due October 18, 2022 (7)	20.5		24.9
	$	20.5	$	39.9
Canadian dollar term Credit Facility borrowings	$	109.0	$	—
Total long term debt	$	610.5	$	1,560.7
Current portion of long term debt	$	—	$	537.0
Non-current portion of long term debt	610.5		1,023.7
	$	610.5	$	1,560.7

⁽¹⁾  There was no outstanding balance following the early repayment on October 12, 2017.

⁽²⁾  The remaining balance of U.S.$28.1 million term notes were outstanding, following the early repayment of U.S.$6.9 million in the fourth quarter of 2017.

⁽³⁾  The remaining balance of U.S.$94.1 million term notes were outstanding, following the early repayment of U.S.$21.4 million in the fourth quarter of 2017.

⁽⁴⁾  The remaining balance of U.S.$85.2 million term notes were outstanding, following the early repayment of U.S.$19.8 million in the fourth quarter of 2017.

⁽⁵⁾  The remaining balance of U.S.$158.9 million term notes were outstanding, following the early repayment of U.S.$36.1 million in the fourth quarter of 2017.

⁽⁶⁾  The remaining balance of U.K. pound sterling 12.1 million term notes were outstanding, following the early repayment of U.K. pound sterling 2.9 million in the fourth quarter of 2017.

⁽⁷⁾  The remaining balance of Cdn$20.5 million term notes were outstanding, following the early repayment of Cdn$4.5 million in the fourth quarter of 2017.

The following table provides a reconciliation between the opening and closing balances for liabilities arising from financing activities at December 31, 2017:

	Term Notes			Canadian dollar Term Credit Facility		Convertible debentures
Balance December 31, 2016	$	1,560.7		$	—	$	126.6
Increase (decrease) due to:
Foreign exchange impact of the Canadian dollar on U.S. and U.K. denominated debt	(65.1		)	—		—
Credit facility borrowing	—			109.0		—
Repayment	(996.0		)	—		(126.6		)
Issue cost amortization	1.9			—		—
Balance, December 31, 2017	$	501.5		$	109.0	$	—

The minimum ratio for the quarter ending September 30, 2017 through to and including the quarter ending September 30, 2019 is as follows:

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

Disclosure of capital structure

The following is a summary of Pengrowth’s capital structure, excluding shareholders’ equity:

	As at
	December 31, 2017		December 31, 2016
Long term debt (1)	$	610.5	$	1,560.7
Convertible debentures	—		126.6
Working capital (surplus) deficiency (2)	80.6		(266.7		)
	$	691.1	$	1,420.6

⁽¹⁾  Includes current portion of term notes and bank indebtedness, as applicable.

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

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PROVISIONS AND OTHER LIABILITIES (Tables)

12 Months Ended

Dec. 31, 2017

Disclosure of other provisions, contingent liabilities and contingent assets [Abstract]

Disclosure of provisions

The following table provides a continuity of the balances for the following periods:

	Asset retirement obligations			Finance leases			Restructuring provision - onerous office lease contracts			Other liabilities			Total
Balance, December 31, 2015	$	703.4		$	4.3		$	—		$	0.3		$	708.0
Incurred during the period	—			35.0			—			2.9			37.9
Property dispositions	(11.8		)	—			—			—			(11.8		)
Expenditures on remediation/provisions settled	(20.0		)	(1.4		)	—			(0.1		)	(21.5		)
Other revisions	(34.4		)	—			—			1.3			(33.1		)
Accretion (amortization)	15.1			—			—			—			15.1
Balance, December 31, 2016	$	652.3		$	37.9		$	—		$	4.4		$	694.6
Incurred during the period	5.4			—			26.5			(1.5		)	30.4
Property dispositions	(420.4		)	(2.0		)	—			—			(422.4		)
Expenditures on remediation/provisions settled	(15.9		)	(1.7		)	(0.3		)	(0.6		)	(18.5		)
Other revisions	3.9			—			—			—			3.9
Accretion (amortization)	11.4			—			—			—			11.4
Balance, December 31 2017	$	236.7		$	34.2		$	26.2		$	2.3		$	299.4

As at December 31, 2017	Asset retirement obligations		Finance leases		Restructuring provision - onerous office lease contracts		Other liabilities		Total
Current	$	29.9	$	0.9	$	4.4	$	—	$	35.2
Long term	206.8		33.3		21.8		2.3		264.2
	$	236.7	$	34.2	$	26.2	$	2.3	$	299.4
As at December 31, 2016
Current	$	20.0	$	1.5	$	—	$	0.6	$	22.1
Long term	632.3		36.4		—		3.8		672.5
	$	652.3	$	37.9	$	—	$	4.4	$	694.6

Assumptions used to estimate asset retirement obligations

The following assumptions were used to estimate the ARO liability:

	As at
	December 31, 2017			December 31, 2016
Total escalated future costs	$	420.2		$	2,120.4
Discount rate, per annum	2.3		%	2.3		%
Inflation rate, per annum	1.5		%	1.5		%

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DEFERRED INCOME TAXES (Tables)

12 Months Ended

Dec. 31, 2017

Disclosure of income tax [Abstract]

Dislcosure of temporary difference, unused tax losses and unused tax credits

The net deferred income tax asset (liability) is composed of:

	As at
	December 31, 2017			December 31, 2016
Deferred tax liabilities associated with:
PP&E and E&E assets	$	(132.3	)	$	(411.0	)
Less deferred tax assets associated with:
Non-capital losses and financing charges	399.6			325.9
Provisions	64.1			176.6
Risk management contracts	10.8			14.6
Long term debt	—			12.1
Convertible debentures	—			0.2
Net deferred tax asset (liability)	$	342.2		$	118.4

A reconciliation of the deferred income tax recovery calculated based on the income (loss) before taxes at the statutory tax rate to the actual provision for deferred income taxes is as follows:

	Year ended December 31
	2017			2016
Income (loss) before taxes	$	(907.6	)	$	(387.1	)
Combined federal and provincial tax rate	27.08		%	27.09		%
Expected income tax expense (recovery)	$	(245.8	)	$	(104.9	)
Change in unrecognized deferred tax asset	22.6			9.8
Foreign exchange (gain) loss (1)	(2.0		)	(1.8		)
Effect of change in corporate tax rate	(0.2		)	—
Other including share based compensation	1.6			3.5
Deferred income tax expense (recovery)	$	(223.8	)	$	(93.4	)

⁽¹⁾ Reflects the 50 percent non-taxable portion of foreign exchange gains and losses and related risk management contracts.

Deferred tax assets have not been recognized with respect to the following items:

	As at
	December 31, 2017		December 31, 2016
Deductible temporary differences	$	204.0	$	188.9
Tax losses	109.8		40.2
	$	313.8	$	229.1

A continuity of the net deferred income tax asset (liability) for 2017 and 2016 is detailed in the following tables:

Movement in deferred tax asset (liability) during the year	Balance Jan 1, 2017			Recognized in profit or loss			Balance Dec 31, 2017
PP&E and E&E assets	$	(411.0	)	$	278.7		$	(132.3	)
Non-capital losses and financing charges	325.9			73.7			399.6
Provisions	176.6			(112.5		)	64.1
Risk management contracts	14.6			(3.8		)	10.8
Long term debt	12.1			(12.1		)	—
Convertible debentures	0.2			(0.2		)	—
Share issue costs	—			—			—
	$	118.4		$	223.8		$	342.2

Movement in deferred tax asset (liability) during the year	Balance Jan 1, 2016			Recognized in profit or loss			Balance Dec 31, 2016
PP&E and E&E assets	(405.3		)	(5.7		)	(411.0		)
Non-capital losses and financing charges	328.7			(2.8		)	325.9
Provisions	190.2			(13.6		)	176.6
Risk management contracts	(99.8		)	114.4			14.6
Long term debt	10.8			1.3			12.1
Convertible debentures	0.2			—			0.2
Share issue costs	0.2			(0.2		)	—
	$	25.0		$	93.4		$	118.4

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SHAREHOLDERS' CAPITAL (Tables)

12 Months Ended

Dec. 31, 2017

Share Capital, Reserves And Other Equity Interest [Abstract]

Summary of Shareholders' Capital

Pengrowth is authorized to issue an unlimited number of common shares and up to 10 million preferred shares. No preferred shares have been issued.

	2017			2016
(Common shares in 000's)	Number of common shares	Amount		Number of common shares	Amount
Balance, beginning of year	547,709	$	4,815.1	543,033	$	4,797.0
Share based compensation (non-cash exercised)	4,537	14.6		4,676	18.1
Balance, end of year	552,246	$	4,829.7	547,709	$	4,815.1

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LONG TERM INCENTIVE PLANS ("LTIP") (Tables)

12 Months Ended

Dec. 31, 2017

Disclosure of share-based payment arrangements [Abstract]

Disclosure of share activity

The following table provides a continuity of the cash-settled LTIP:

(number of share units - 000's)	Cash-settled RSUs		Phantom DSUs
Outstanding, December 31, 2015	—		397
Granted	4,559		1,024
Forfeited	(330	)	—
Exercised	—		(75	)
Outstanding, December 31, 2016	4,229		1,346
Granted	3,163		492
Forfeited	(3,148	)	—
Exercised	(1,341	)	(462	)
Outstanding, December 31, 2017	2,903		1,376

The following table provides a continuity of the share-settled LTIP:

(number of share units - 000's)	PSUs		RSUs		DSUs
Outstanding, December 31, 2015	4,640		5,341		302
Granted	3,049		6,553		—
Forfeited	(460	)	(737	)	—
Exercised	(1,695	)	(2,721	)	(104	)
Performance adjustment	704		—		—
Outstanding, December 31, 2016	6,238		8,436		198
Granted	2,124		4,578		—
Forfeited	(486	)	(2,195	)	—
Exercised	(1,104	)	(3,436	)	—
Performance adjustment	(1,738	)	—		—
Outstanding, December 31, 2017	5,034		7,383		198

Summary of share based compensation expense

Total share based compensation expenses are included in both general and administrative and operating expenses on the Consolidated Statements of Income (Loss)and are composed of the following:

	Year ended December 31
	2017			2016
Non-cash share based compensation	$	5.0		$	13.7
Amounts capitalized in the period	(0.1		)	(0.5		)
Non-cash share based compensation expense	$	4.9		$	13.2
Cash-settled RSUs (reduction) expense	$	(0.2	)	$	3.6
Cash-settled Phantom DSUs (reduction) expense	$	(0.6	)	$	2.3
Total share based compensation expense	$	4.1		$	19.1

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REVENUE (Tables)

12 Months Ended

Dec. 31, 2017

Disclosure of revenue [Abstract]

Disaggregation of revenue

The following table presents Pengrowth’s Oil and gas sales disaggregated by revenue source:

	Year ended December 31
	2017
Light oil	149.3
Bitumen	181.6
Natural gas liquids	56.7
Natural gas	98.8
Produced petroleum revenue	486.4
Diluent	147.2
Processing income	19.1
Other revenue	20.7
Total oil and gas sales	$	673.4

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OTHER CASH FLOW DISCLOSURES (Tables)

12 Months Ended

Dec. 31, 2017

Cash Flow Statement [Abstract]

Change in Non-cash Operating Working Capital, Other Assets, and Non-cash Investing Working Capital

CHANGE IN NON-CASH OPERATING WORKING CAPITAL AND OTHER ASSETS

	Year ended December 31
Cash provided by (used for):	2017			2016
Accounts receivable	$	40.9		$	25.0
Accounts payable	(22.7		)	(43.8		)
Prepaid tax assessment	—			(2.7		)
	$	18.2		$	(21.5	)

CHANGE IN NON-CASH INVESTING WORKING CAPITAL 

	Year ended December 31
Cash used for:	2017			2016
Accounts payable, including capital accruals	$	(7.5	)	$	7.6

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AMOUNTS PER SHARE (Tables)

12 Months Ended

Dec. 31, 2017

Earnings per share [abstract]

Summary of Weighted Average Shares Used in Calculating Amounts Per Share

The following table reconciles the weighted average number of shares used in the basic and diluted net income (loss) per share calculations:

	Year ended December 31
(000's)	2017	2016
Weighted average number of shares - basic and diluted	551,193	546,566

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FINANCIAL INSTRUMENTS AND RISK MANAGEMENT (Tables)

12 Months Ended

Dec. 31, 2017

Disclosure of detailed information about financial instruments [abstract]

Disclosure of detailed information about risk management instruments

The following table sets out gross amounts relating to risk management contracts assets and liabilities that have been presented on a net basis on the Consolidated Balance Sheets:

	As at
Gross amounts	December 31, 2017			December 31, 2016
Risk management contracts
Current asset	$	—		$	3.0
Non-current asset	1.9			1.0
Current liability	(40.0		)	(55.4		)
Non-current liability	(18.6		)	(5.3		)
	$	(56.7	)	$	(56.7	)

This contract fixes 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: 

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

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

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

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

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

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

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

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

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

Disclosure of summary of gains and losses on risk management contracts

The following tables provide details of the fair value of risk management contracts that appear on the Consolidated Balance Sheets and the unrealized and realized gains and losses on risk management recorded in the Consolidated Statements of Income (Loss).

As at and for the year ended December 31, 2017	Commodity contracts (1)			Power contracts			Foreign exchange contracts (2)			Total
Non-current portion of risk management assets	$	—		$	—		$	1.9		$	1.9
Current portion of risk management liabilities	(39.8		)	—			(0.2		)	(40.0		)
Non-current portion of risk management liabilities	—			—			(18.6		)	(18.6		)
Risk management assets (liabilities), end of year	$	(39.8	)	$	—		$	(16.9	)	$	(56.7	)
Less: Risk management assets (liabilities) at beginning of year	(54.0		)	—			(2.7		)	(56.7		)
Unrealized gain (loss) on risk management contracts for the year	$	14.2		$	—		$	(14.2	)	$	—
Realized gain (loss) on risk management contracts for the year	(19.8		)	—			(37.6		)	(57.4		)
Total unrealized and realized gain (loss) on risk management contracts for the year	$	(5.6	)	$	—		$	(51.8	)	$	(57.4	)
As at and for the year ended December 31, 2016	Commodity contracts(1)			Power contracts (3)			Foreign exchange contracts (2)			Total
Current portion of risk management assets	$	—		$	—		$	2.9		$	2.9
Non-current portion of risk management assets	—			—			1.0			1.0
Current portion of risk management liabilities	(54.0		)	—			(1.3		)	(55.3		)
Non-current portion of risk management liabilities	—			—			(5.3		)	(5.3		)
Risk management assets (liabilities), end of year	$	(54.0	)	$	—		$	(2.7	)	$	(56.7	)
Less: Risk management assets (liabilities) at beginning of year	370.5			(1.7		)	83.3			452.1
Unrealized gain (loss) on risk management contracts for the year	$	(424.5	)	$	1.7		$	(86.0	)	$	(508.8	)
Realized gain (loss) on risk management contracts for the year	385.7			(4.5		)	47.0			428.2
Total unrealized and realized gain (loss) on risk management contracts for the year	$	(38.8	)	$	(2.8	)	$	(39.0	)	$	(80.6	)

⁽¹⁾  Unrealized and realized gains and losses are presented as separate line items in the Consolidated Statements of Income (Loss).

⁽²⁾  Unrealized and realized gains and losses are included as part of separate line items in the Consolidated Statements of Income (Loss).

⁽³⁾  Unrealized gains and losses are included in other (income) expense. Realized gains and losses are included in operating expense.

Disclosure of fair value measurement of assets

The following tables provide fair value measurement information for other financial assets and liabilities.

					Fair value measurements using:
As at December 31, 2017	Carrying amount		Fair value		Quoted prices in active markets (Level 1)		Significant other observable inputs (Level 2)		Significant unobservable inputs (Level 3)
Financial Assets
Remediation trust funds	$	111.6	$	111.6	$	111.6	$	—	$	—
Fair value of risk management contracts	1.9		1.9		—		1.9		—
Financial Liabilities
U.S. dollar denominated term notes	460.4		509.5		—		509.5		—
Cdn dollar term notes	20.5		22.8		—		22.8		—
U.K. pound sterling denominated term notes	20.6		21.7		—		21.7		—
Fair value of risk management contracts	58.6		58.6		—		58.6		—
					Fair value measurements using:
As at December 31, 2016	Carrying amount		Fair value		Quoted prices in active markets (Level 1)		Significant other observable inputs (Level 2)		Significant unobservable inputs (Level 3)
Financial Assets
Remediation trust funds	$	106.5	$	106.5	$	106.5	$	—	$	—
Fair value of risk management contracts	3.9		3.9		—		3.9		—
Financial Liabilities
Convertible debentures	126.6		126.7		126.7		—		—
U.S. dollar denominated senior unsecured notes	1,496.0		1,527.7		—		1,527.7		—
Cdn dollar senior unsecured notes	39.9		41.3		—		41.3		—
U.K. pound sterling denominated unsecured notes	24.8		25.5		—		25.5		—
Fair value of risk management contracts	60.6		60.6		—		60.6		—

Disclosure of fair value measurement of liabilities

The following tables provide fair value measurement information for other financial assets and liabilities.

					Fair value measurements using:
As at December 31, 2017	Carrying amount		Fair value		Quoted prices in active markets (Level 1)		Significant other observable inputs (Level 2)		Significant unobservable inputs (Level 3)
Financial Assets
Remediation trust funds	$	111.6	$	111.6	$	111.6	$	—	$	—
Fair value of risk management contracts	1.9		1.9		—		1.9		—
Financial Liabilities
U.S. dollar denominated term notes	460.4		509.5		—		509.5		—
Cdn dollar term notes	20.5		22.8		—		22.8		—
U.K. pound sterling denominated term notes	20.6		21.7		—		21.7		—
Fair value of risk management contracts	58.6		58.6		—		58.6		—
					Fair value measurements using:
As at December 31, 2016	Carrying amount		Fair value		Quoted prices in active markets (Level 1)		Significant other observable inputs (Level 2)		Significant unobservable inputs (Level 3)
Financial Assets
Remediation trust funds	$	106.5	$	106.5	$	106.5	$	—	$	—
Fair value of risk management contracts	3.9		3.9		—		3.9		—
Financial Liabilities
Convertible debentures	126.6		126.7		126.7		—		—
U.S. dollar denominated senior unsecured notes	1,496.0		1,527.7		—		1,527.7		—
Cdn dollar senior unsecured notes	39.9		41.3		—		41.3		—
U.K. pound sterling denominated unsecured notes	24.8		25.5		—		25.5		—
Fair value of risk management contracts	60.6		60.6		—		60.6		—

Components of accounts receivable

The components of accounts receivable are as follows:

	As at
	December 31, 2017		December 31, 2016
Trade	$	97.5	$	110.3
Prepaid and other	8.2		16.3
	$	105.7	$	126.6

Disclosure of how entity manages liquidity risk

Pengrowth’s current and non-current financial liabilities are as follows:

As at December 31, 2017	Carrying amount		Contractual cash flows		Year 1		Year 2		Years 3-5		More than 5 years
Accounts payable	$	136.2	$	136.2	$	136.2	$	—	$	—	$	—
Commodity risk management contracts	39.8		39.8		39.8		—		—		—
Cdn dollar senior unsecured notes (2)	20.5		27.1		1.4		1.4		24.3		—
U.S. dollar denominated term notes (1)	460.4		601.3		30.2		65.2		284.0		221.9
U.K. pound sterling denominated term notes (1)	20.6		22.6		1.1		21.5		—		—
Cdn dollar term Credit Facility borrowings (2)	109.0		117.6		6.9		110.7		—		—
Finance leases	34.2		76.8		4.4		4.2		12.6		55.6
Foreign exchange risk management contracts	18.8		20.8		0.2		4.3		16.3		—
Other liabilities	2.3		3.2		—		1.4		0.3		1.5

⁽¹⁾  Contractual cash flows include future interest payments and term notes calculated at December 31, 2017 period end exchange rate.

⁽²⁾  Contractual cash flows include future interest payments.

As at December 31, 2016	Carrying amount		Contractual cash flows		Year 1		Year 2		Years 3-5		More than 5 years
Accounts payable	$	189.6	$	189.6	$	189.6	$	—	$	—	$	—
Convertible debentures	126.6		130.5		130.5		—		—		—
Commodity risk management contracts	54.0		54.0		54.0		—		—		—
Cdn dollar senior unsecured notes (1)	39.9		48.5		2.2		16.8		3.6		25.9
U.S. dollar denominated senior unsecured notes (1)	1,496.0		1,726.8		623.7		399.2		266.0		437.9
U.K. pound sterling denominated unsecured notes (1)	24.8		27.3		0.9		0.9		25.5		—
Finance leases	37.9		90.7		5.7		5.0		14.2		65.8
Foreign exchange risk management contracts	6.6		6.1		1.3		1.7		2.4		0.7
Other liabilities	4.4		8.3		0.6		2.9		2.8		2.0
Remediation trust fund payments	—		12.5		0.3		0.3		0.9		11.0

⁽¹⁾  Contractual cash flows include future interest payments and senior unsecured notes calculated at December 31, 2016 period end exchange rate.

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COMMITMENTS (Tables)

12 Months Ended

Dec. 31, 2017

Disclosure Of Commitments [Abstract]

Disclosure of maturity analysis for commitments

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

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

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

⁽³⁾  Includes office rent and other commitments.

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FOREIGN EXCHANGE (GAIN) LOSS (Tables)

12 Months Ended

Dec. 31, 2017

Effects Of Changes In Foreign Exchange Rates [Abstract]

Summary of Foreign Exchange (Gain) Loss

	Year ended December 31
	2017			2016
Currency exchange rate (Cdn$1 = U.S.$) at beginning of year	$	0.74		$	0.72
Currency exchange rate (Cdn$1 = U.S.$) at year end	$	0.80		$	0.74
Unrealized foreign exchange (gain) loss on U.S. dollar denominated debt (1)	$	(66.1	)	$	(46.8	)
Unrealized foreign exchange (gain) loss on U.K. pound sterling denominated debt (1)	0.5			(5.8		)
Total unrealized foreign exchange (gain) loss from translation of foreign denominated debt	$	(65.6	)	$	(52.6	)
Unrealized (gain) loss on U.S. foreign exchange risk management contracts (2)	$	15.0		$	80.6
Unrealized (gain) loss on U.K. foreign exchange risk management contracts	(0.8		)	5.4
Total unrealized (gain) loss on foreign exchange risk management contracts	$	14.2		$	86.0
Net unrealized foreign exchange (gain) loss	$	(51.4	)	$	33.4
Net realized foreign exchange (gain) loss (3)	$	38.4		$	(46.5	)

⁽¹⁾  Includes both principal and interest.

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

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

XML

SUPPLEMENTARY DISCLOSURES (Tables)

12 Months Ended

Dec. 31, 2017

Disclosure Of Supplementary Disclosures [Abstract]

Total employee compensation costs

The following table details the amount of total employee compensation costs (including share based compensation expense) included in the operating and general and administrative expense line items in the Consolidated Statements of Income (Loss).

	Year ended December 31
	2017		2016
Operating	$	30.1	$	44.1
General and administrative	35.5		50.2
Total employee compensation costs	$	65.6	$	94.3

Compensation expense related to officers and directors

Year ended December 31, 2017	Wages & benefits paid		Bonus and other compensation paid		Share based compensation expense			Severance paid		Total
Directors	$	0.6	$	—	$	(0.6	)	$	—	$	—
Officers	2.2		2.7		1.9			—		6.8
	$	2.8	$	2.7	$	1.3		$	—	$	6.8
Year ended December 31, 2016	Wages & benefits paid		Bonus and other compensation paid		Share based compensation expense			Severance paid		Total
Directors	$	0.6	$	—	$	2.3		$	—	$	2.9
Officers	2.8		0.7		5.3			0.6		9.4
	$	3.4	$	0.7	$	7.6		$	0.6	$	12.3

XML

SIGNIFICANT ACCOUNTING POLICIES - Restatement of Oil and Gas and Diluent and Other Expenses (Details) - CAD CAD in Millions	3 Months Ended			12 Months Ended
	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2017	[1]	Dec. 31, 2016
Disclosure of voluntary change in accounting policy [line items]
Oil and gas sales	CAD 125.1	CAD 197.9	CAD 219.9	CAD 673.4		CAD 566.2
Diluent and other purchases	28.9	45.2	46.7	163.5		0.0
Processing income	4.7	5.5	6.7
Operating expenses	51.6	68.5	67.3	CAD 1,311.6		CAD 742.6
Previously reported
Disclosure of voluntary change in accounting policy [line items]
Oil and gas sales	91.5	147.2	166.5
Diluent and other purchases	0.0	0.0	0.0
Processing income	CAD 46.9	CAD 63.0	CAD 60.6

[1] See Notes 2 and 14.

XML

SIGNIFICANT ACCOUNTING POLICIES - Estimated Useful Lives of PP&E (Details)	12 Months Ended
	Dec. 31, 2017
Office equipment
Disclosure of detailed information about property, plant and equipment [line items]
Useful lives	60 months
Computers
Disclosure of detailed information about property, plant and equipment [line items]
Useful lives	36 months
Deferred hydrocarbon injectants
Disclosure of detailed information about property, plant and equipment [line items]
Useful lives	24 months
Motor vehicles
Disclosure of detailed information about property, plant and equipment [line items]
Useful lives	60 months

XML

OTHER ASSETS - Components of Other Assets (Details) - CAD CAD in Millions	Dec. 31, 2017	Dec. 31, 2016
Disclosure Of Other Assets [Abstract]
Remediation trust funds - current	CAD 24.0	CAD 0.0
Remediation trust funds - non-current	87.6	106.5
Prepaid tax assessment	12.2	12.2
Other assets	CAD 123.8	CAD 118.7

XML

OTHER ASSETS - Remediation Trust Funds Narrative (Details) CAD in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2017 CAD	Dec. 31, 2017 CAD	Dec. 31, 2017 CAD CAD / MMBTU	Dec. 31, 2017 CAD CAD / bbl	Dec. 31, 2016 CAD	Dec. 31, 2016 CAD CAD / MMBTU	Dec. 31, 2016 CAD CAD / bbl	Dec. 31, 2015 CAD
Disclosure of detailed information about property, plant and equipment [line items]
Expected remediation payments for 2018		CAD 24.0
Lump sum contribution		14.0			CAD 26.9
Remediation trust funds - current and non-current	CAD 111.6	111.6	CAD 111.6	CAD 111.6	CAD 106.5	CAD 106.5	CAD 106.5	CAD 79.6
Dispositions		CAD 4.8
Judy Creek assets
Disclosure of detailed information about property, plant and equipment [line items]
Dispositions	CAD 4.8
SOEP properties
Disclosure of detailed information about property, plant and equipment [line items]
Monthly contribution rate			4.04	7.59		6.64	13.29

XML

OTHER ASSETS - Rollforward of Remediation Trust Funds (Details) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Disclosure Of Other Assets [Abstract]
Beginning balance	CAD 106.5	CAD 79.6
Contributions	14.0	26.9
Remediation expenditures	6.6	(0.9)
Investment income	3.1	3.2
Unrealized gain (loss)	(0.6)	(2.3)
Dispositions	(4.8)
Ending balance	CAD 111.6	CAD 106.5

XML

OTHER ASSETS - Prepaid Tax Assessment Narrative (Details) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Income Tax Contingency [Line Items]
Prepaid tax assessment	CAD 12.2	CAD 12.2
Canada Revenue Agency
Income Tax Contingency [Line Items]
Taxes paid	9.5
Alberta Tax and Revenue Administration
Income Tax Contingency [Line Items]
Taxes paid	CAD 2.7

XML

PROPERTY, PLANT AND EQUIPMENT ("PP&E") - Summary of Property, Plant and Equipment (Details) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017		Dec. 31, 2016	Dec. 31, 2017		Dec. 31, 2016
Reconciliation of changes in property, plant and equipment [abstract]
Beginning balance	CAD 2,849.0
Impairment	504.4
Ending balance	1,104.2	[1]	CAD 2,849.0
Assets held for sale				CAD 0.0	[1]	CAD 117.5
Long term	2,849.0		2,849.0	1,104.2	[1]	2,849.0
Total property, plant and equipment				1,104.2		2,966.5
Cost or deemed cost
Reconciliation of changes in property, plant and equipment [abstract]
Beginning balance	6,929.6		7,062.4
Additions to PP&E	121.5		91.8
Property acquisitions	0.1		1.3
Change in asset retirement obligations	9.3		(34.4)
Divestitures	(3,154.9)		(191.5)
Ending balance	3,905.6		6,929.6
Long term	6,929.6		7,062.4	3,905.6		6,929.6
Accumulated depletion, amortization and impairment losses
Reconciliation of changes in property, plant and equipment [abstract]
Beginning balance	3,963.1		3,715.6
Depletion and amortization for the period	207.6		349.9
Impairment	504.4
Divestitures	(1,873.7)		(102.4)
Ending balance	2,801.4		3,963.1
Long term	3,963.1		3,715.6	2,801.4		3,963.1
Oil and natural gas assets
Reconciliation of changes in property, plant and equipment [abstract]
Beginning balance	2,838.6
Ending balance	1,097.4		2,838.6
Assets held for sale				0.0		117.5
Long term	2,838.6		2,838.6	1,097.4		2,838.6
Total property, plant and equipment				1,097.4		2,956.1
Oil and natural gas assets | Cost or deemed cost
Reconciliation of changes in property, plant and equipment [abstract]
Beginning balance	6,838.8		6,973.5
Additions to PP&E	120.7		89.9
Property acquisitions	0.1		1.3
Change in asset retirement obligations	9.3		(34.4)
Divestitures	(3,151.2)		(191.5)
Ending balance	3,817.7		6,838.8
Long term	6,838.8		6,973.5	3,817.7		6,838.8
Oil and natural gas assets | Accumulated depletion, amortization and impairment losses
Reconciliation of changes in property, plant and equipment [abstract]
Beginning balance	3,882.7		3,639.5
Depletion and amortization for the period	204.4		345.6
Impairment	504.4
Divestitures	(1,871.2)		(102.4)
Ending balance	2,720.3		3,882.7
Long term	3,882.7		3,639.5	2,720.3		3,882.7
Other equipment
Reconciliation of changes in property, plant and equipment [abstract]
Beginning balance	10.4
Ending balance	6.8		10.4
Assets held for sale				0.0		0.0
Long term	10.4		10.4	6.8		10.4
Total property, plant and equipment				6.8		10.4
Other equipment | Cost or deemed cost
Reconciliation of changes in property, plant and equipment [abstract]
Beginning balance	90.8		88.9
Additions to PP&E	0.8		1.9
Property acquisitions	0.0		0.0
Change in asset retirement obligations	0.0		0.0
Divestitures	(3.7)		0.0
Ending balance	87.9		90.8
Long term	90.8		88.9	87.9		90.8
Other equipment | Accumulated depletion, amortization and impairment losses
Reconciliation of changes in property, plant and equipment [abstract]
Beginning balance	80.4		76.1
Depletion and amortization for the period	3.2		4.3
Impairment	0.0
Divestitures	(2.5)		0.0
Ending balance	81.1		80.4
Long term	CAD 80.4		CAD 76.1	CAD 81.1		CAD 80.4

[1] See Notes 2 and 14.

XML

PROPERTY, PLANT AND EQUIPMENT ("PP&E") - Narrative (Details) - CAD		3 Months Ended				12 Months Ended
	Nov. 03, 2017	Dec. 31, 2017		Sep. 30, 2017	Mar. 31, 2017	Dec. 31, 2017		Dec. 31, 2016	Dec. 31, 2015
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment		CAD 1,104,200,000	[1]			CAD 1,104,200,000	[1]	CAD 2,849,000,000
Proceeds on property dispositions						910,200,000	[2]	60,200,000
Impairment loss						634,400,000	[3]	0
Impairment						504,400,000
Cost or deemed cost
Disclosure of detailed information about property, plant and equipment [line items]
Costs capitalized to PP&E						121,500,000		91,800,000
Property, plant and equipment		3,905,600,000				3,905,600,000		6,929,600,000	CAD 7,062,400,000
Disposals, property, plant and equipment						3,154,900,000		191,500,000
Accumulated depletion, amortization and impairment losses
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment		2,801,400,000				2,801,400,000		3,963,100,000	CAD 3,715,600,000
Disposals, property, plant and equipment						1,873,700,000		102,400,000
Impairment						504,400,000
Lindbergh project
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment		5,800,000				CAD 5,800,000		CAD 5,800,000
Weighted average cost of debt						5.70%		5.70%
Lindbergh thermal property
Disclosure of detailed information about property, plant and equipment [line items]
Gross overriding royalty interest					4.00%
Proceeds on property dispositions					CAD 250,000,000
Judy Creek assets
Disclosure of detailed information about property, plant and equipment [line items]
Proceeds on property dispositions	CAD 150,000,000			CAD 485,000,000
Swan Hills assets
Disclosure of detailed information about property, plant and equipment [line items]
Proceeds on property dispositions		150,000,000
Northern and Southern GCUs
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment		CAD 0				CAD 0
General and administrative
Disclosure of detailed information about property, plant and equipment [line items]
Costs capitalized to PP&E						2,300,000		CAD 3,200,000
Interest expense | Lindbergh project
Disclosure of detailed information about property, plant and equipment [line items]
Costs capitalized to PP&E						CAD 3,700,000		CAD 3,000,000

[1] See Notes 2 and 14.

[2] See Notes 2 and 14.

[3] See Notes 2 and 14.

XML

EXPLORATION AND EVALUATION ASSETS ("E&E") - Summary of Exploration and Evaluation Assets (Details) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017		Dec. 31, 2016
Reconciliation of changes in property, plant and equipment [abstract]
Beginning balance	CAD 2,849.0
Impairment	(504.4)
Ending balance	1,104.2	[1]	CAD 2,849.0
Exploration and Evaluation Assets
Reconciliation of changes in property, plant and equipment [abstract]
Beginning balance	496.3		494.8
Additions			1.5
Divestitures	(134.3)
Impairment	(130.0)
Ending balance	CAD 232.0		CAD 496.3

[1] See Notes 2 and 14.

XML

EXPLORATION AND EVALUATION ASSETS ("E&E") - Narrative (Details) - CAD CAD in Millions			3 Months Ended		12 Months Ended
	Nov. 03, 2017	Apr. 11, 2017	Sep. 30, 2017	Mar. 31, 2017	Dec. 31, 2017	[1]	Dec. 31, 2016	Jul. 11, 2017
Disclosure of detailed information about property, plant and equipment [line items]
Proceeds on property dispositions					CAD 910.2		CAD 60.2
Exploration and Evaluation Assets
Disclosure of detailed information about property, plant and equipment [line items]
Proceeds on property dispositions		CAD 92.0
Pre-tax loss on disposition				CAD 9.0
Terminated agreement								CAD 180.0
Judy Creek assets
Disclosure of detailed information about property, plant and equipment [line items]
Proceeds on property dispositions	CAD 150.0		CAD 485.0

[1] See Notes 2 and 14.

XML

EXPLORATION AND EVALUATION ASSETS ("E&E") - Impairment Testing Narrative (Details) - CAD CAD in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2017		Dec. 31, 2016
Disclosure of impairment loss and reversal of impairment loss [line items]
Impairment loss		CAD 634.4	[1]	CAD 0.0
Groundbirch E&E
Disclosure of impairment loss and reversal of impairment loss [line items]
Impairment loss	CAD 129.0
Other minor E&E
Disclosure of impairment loss and reversal of impairment loss [line items]
Impairment loss	CAD 1.0
Exploration and Evaluation reserves | Groundbirch E&E
Disclosure of impairment loss and reversal of impairment loss [line items]
Pre-tax discount rate	10.00%	10.00%
Inflation rate	2.00%	2.00%
Contingent Resources | Groundbirch E&E
Disclosure of impairment loss and reversal of impairment loss [line items]
Pre-tax discount rate	15.00%	15.00%

[1] See Notes 2 and 14.

XML

EXPLORATION AND EVALUATION ASSETS ("E&E") - Forward Natural Gas Prices (Details) - Groundbirch E&E - Exploration and Evaluation reserves	Dec. 31, 2017 CAD / MMBTU
Disclosure of impairment loss and reversal of impairment loss [line items]
Inflation rate	2.00%
2018
Disclosure of impairment loss and reversal of impairment loss [line items]
AECO gas prices (in CDN per MMBtu)	2.20
2019
Disclosure of impairment loss and reversal of impairment loss [line items]
AECO gas prices (in CDN per MMBtu)	2.54
2020
Disclosure of impairment loss and reversal of impairment loss [line items]
AECO gas prices (in CDN per MMBtu)	2.88
2021
Disclosure of impairment loss and reversal of impairment loss [line items]
AECO gas prices (in CDN per MMBtu)	3.24
2022
Disclosure of impairment loss and reversal of impairment loss [line items]
AECO gas prices (in CDN per MMBtu)	3.47
2023
Disclosure of impairment loss and reversal of impairment loss [line items]
AECO gas prices (in CDN per MMBtu)	3.58
2024
Disclosure of impairment loss and reversal of impairment loss [line items]
AECO gas prices (in CDN per MMBtu)	3.66
2025
Disclosure of impairment loss and reversal of impairment loss [line items]
AECO gas prices (in CDN per MMBtu)	3.73
2026
Disclosure of impairment loss and reversal of impairment loss [line items]
AECO gas prices (in CDN per MMBtu)	3.80
2027
Disclosure of impairment loss and reversal of impairment loss [line items]
AECO gas prices (in CDN per MMBtu)	3.88
Thereafter
Disclosure of impairment loss and reversal of impairment loss [line items]
Inflation rate	2.00%

XML

CONVERTIBLE DEBENTURES - Summary of Convertible Debentures (Details) - CAD		12 Months Ended
	Mar. 31, 2017	Dec. 31, 2017		Dec. 31, 2016
Disclosure of detailed information about borrowings [line items]
Beginning balance		CAD 1,560,700,000
Premium accretion		11,400,000	[1]	CAD 15,100,000
Repayment of convertible debentures		(126,600,000)	[2]	0
Ending balance		610,500,000		1,560,700,000
Convertible debentures
Disclosure of detailed information about borrowings [line items]
Interest rate	6.25%
Conversion price (per Pengrowth share)	CAD 11.51
Beginning balance		126,600,000		137,000,000
Repurchase of convertible debentures				(10,200,000)
Premium accretion				(200,000)
Repayment of convertible debentures	CAD (126,600,000)	(126,600,000)
Ending balance		0		CAD 126,600,000
Face value		CAD 0

[1] See Notes 2 and 14.

[2] See Notes 2 and 14.

XML

CONVERTIBLE DEBENTURES - Narrative (Details) - CAD CAD in Millions		12 Months Ended
	Mar. 31, 2017	Dec. 31, 2017		Dec. 31, 2016
Disclosure of detailed information about borrowings [line items]
Repayment of convertible debentures		CAD 126.6	[1]	CAD 0.0
Convertible debentures
Disclosure of detailed information about borrowings [line items]
Repayment of convertible debentures	CAD 126.6	CAD 126.6

[1] See Notes 2 and 14.

XML

LONG TERM DEBT - Amendments to Long Term Debt Narrative (Details) CAD in Millions			3 Months Ended										12 Months Ended
	Oct. 12, 2017 CAD	Oct. 12, 2017 USD ($)	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017 CAD	Sep. 30, 2017	Dec. 31, 2017 CAD		Dec. 31, 2016 CAD	Dec. 31, 2017 USD ($)
Disclosure of detailed information about borrowings [line items]
Repayments of bonds, notes and debentures													CAD 126.6	[1]	CAD 0.0
Loss on extinguishment of debt													56.7	[1],[2]	CAD 0.0
Borrowing costs incurred													55.2
Unamortized issuance costs													CAD 1.5
Interest ratio coverage			4.0	1.23	1.19	1.13	1.01	1.03	0.68	0.75	0.77	4.0	0.77
Senior debt to adjusted EBITDA ratio											3.5		3.5			3.5
Debt to book capitalization ratio													55.00%
Interest coverage ratio, actual											1.6		1.6			1.6
265 million at 6.98 percent due August 21, 2018
Disclosure of detailed information about borrowings [line items]
Repayments of bonds, notes and debentures	CAD 15.0	$ 265,000,000
Face value | $																$ 265,000,000
Cdn dollar term notes
Disclosure of detailed information about borrowings [line items]
Repayments of bonds, notes and debentures	115.4
U.S. dollar denominated term notes
Disclosure of detailed information about borrowings [line items]
Adjustment to interest rate			3.00%								2.00%		2.00%			2.00%
Amendment fee											0.50%		0.50%			0.50%
Credit Facility
Disclosure of detailed information about borrowings [line items]
Adjustment to interest rate											2.00%		2.00%			2.00%
Amendment fee											0.50%		0.50%			0.50%
Credit facility, maximum borrowing capacity											CAD 330.0		CAD 330.0
Demand Operating Facility
Disclosure of detailed information about borrowings [line items]
Credit facility eliminated	50.0
Swan Hills assets | Credit Facility
Disclosure of detailed information about borrowings [line items]
Credit facility, maximum borrowing capacity	CAD 330.0

[1] See Notes 2 and 14.

[2] See Notes 2 and 14.

XML

LONG TERM DEBT - Minimum Interest Coverage Ratios (Details)	3 Months Ended										12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Dec. 31, 2017
Disclosure of detailed information about financial instruments [abstract]
Interest ratio coverage	4.0	1.23	1.19	1.13	1.01	1.03	0.68	0.75	0.77	4.0	0.77

XML

LONG TERM DEBT - Summary of Long Term Debt (Details) CAD in Millions		3 Months Ended		12 Months Ended
	Mar. 30, 2017 CAD	Dec. 31, 2017 CAD	Dec. 31, 2017 USD ($)	Dec. 31, 2017 CAD	[2]	Dec. 31, 2016 CAD	Dec. 31, 2017 GBP (£)	Dec. 31, 2017 CAD		Dec. 31, 2017 USD ($)	Oct. 12, 2017 USD ($)	Mar. 31, 2017 USD ($)
Disclosure of detailed information about borrowings [line items]
Current portion of long term debt						CAD 537.0		CAD 0.0	[1]
Non-current portion of long term debt						1,023.7		610.5	[1]
Total long term debt						1,560.7		610.5
Early repayment of borrowings			$ 115,400,000	CAD 937.2		104.0
U.S. dollar denominated term notes
Disclosure of detailed information about borrowings [line items]
Total long term debt						1,496.0		460.4
400 million at 6.35 percent due July 26, 2017
Disclosure of detailed information about borrowings [line items]
Face value | $										$ 400,000,000.0		$ 400,000,000
Total long term debt						537.0		0.0
Early repayment of borrowings	CAD 1,000.0
265 million at 6.98 percent due August 21, 2018
Disclosure of detailed information about borrowings [line items]
Face value | $										265,000,000
Total long term debt						355.6		0.0			$ 0
35 million at 5.49 percent due October 18, 2019
Disclosure of detailed information about borrowings [line items]
Face value | $										35,000,000
Total long term debt						46.9		35.3
Balance outstanding | $										28,100,000
Early repayment of borrowings | $			6,900,000
115.5 million at 7.98 percent due May 11, 2020
Disclosure of detailed information about borrowings [line items]
Face value | $										115,500,000.0
Total long term debt						154.8		118.3
Balance outstanding | $										94,100,000
Early repayment of borrowings | $			21,400,000
105 million at 6.07 percent due October 18, 2022
Disclosure of detailed information about borrowings [line items]
Face value | $										105,000,000
Total long term debt						140.6		107.1
Balance outstanding | $										85,200,000
Early repayment of borrowings | $			19,800,000
195 million at 6.17 percent due October 18, 2024
Disclosure of detailed information about borrowings [line items]
Face value | $										195,000,000
Total long term debt						261.1		199.7
Balance outstanding | $										158,900,000
Early repayment of borrowings | $			$ 36,100,000
15 million at 5.45 percent due October 18, 2019
Disclosure of detailed information about borrowings [line items]
Face value | £							£ 15,000,000
Total long term debt						24.8		20.6
Balance outstanding | £							£ 12,100,000
Early repayment of borrowings		CAD 2.9
Cdn dollar term notes
Disclosure of detailed information about borrowings [line items]
Total long term debt						39.9		20.5
15 million at 6.61 percent due August 21, 2018
Disclosure of detailed information about borrowings [line items]
Face value | $										15,000,000
Total long term debt						15.0		0.0
25 million at 6.74 percent due October 18, 2022
Disclosure of detailed information about borrowings [line items]
Face value | $										$ 25,000,000
Total long term debt						24.9		20.5
Balance outstanding								20.5
Early repayment of borrowings		CAD 4.5
Canadian dollar term Credit Facility borrowings
Disclosure of detailed information about borrowings [line items]
Total long term debt						CAD 0.0		CAD 109.0
Fixed interest rate | 400 million at 6.35 percent due July 26, 2017
Disclosure of detailed information about borrowings [line items]
Interest rate							6.35%	6.35%		6.35%
Fixed interest rate | 265 million at 6.98 percent due August 21, 2018
Disclosure of detailed information about borrowings [line items]
Interest rate							6.98%	6.98%		6.98%
Fixed interest rate | 35 million at 5.49 percent due October 18, 2019
Disclosure of detailed information about borrowings [line items]
Interest rate							5.49%	5.49%		5.49%
Fixed interest rate | 115.5 million at 7.98 percent due May 11, 2020
Disclosure of detailed information about borrowings [line items]
Interest rate							7.98%	7.98%		7.98%
Fixed interest rate | 105 million at 6.07 percent due October 18, 2022
Disclosure of detailed information about borrowings [line items]
Interest rate							6.07%	6.07%		6.07%
Fixed interest rate | 195 million at 6.17 percent due October 18, 2024
Disclosure of detailed information about borrowings [line items]
Interest rate							6.17%	6.17%		6.17%
Fixed interest rate | 15 million at 5.45 percent due October 18, 2019
Disclosure of detailed information about borrowings [line items]
Interest rate							5.45%	5.45%		5.45%
Fixed interest rate | 15 million at 6.61 percent due August 21, 2018
Disclosure of detailed information about borrowings [line items]
Interest rate							6.61%	6.61%		6.61%
Fixed interest rate | 25 million at 6.74 percent due October 18, 2022
Disclosure of detailed information about borrowings [line items]
Interest rate							6.74%	6.74%		6.74%

[1] See Notes 2 and 14.

[2] See Notes 2 and 14.

XML

LONG TERM DEBT - Long Term Debt Narrative (Details)			3 Months Ended	12 Months Ended
	Oct. 01, 2017 USD ($)	Mar. 30, 2017 CAD	Dec. 31, 2017 USD ($)	Dec. 31, 2017 CAD		Dec. 31, 2016 CAD	Dec. 31, 2017 USD ($)	Oct. 12, 2017 USD ($)	Mar. 31, 2017 USD ($)
Disclosure of detailed information about borrowings [line items]
Amount outstanding				CAD 610,500,000		CAD 1,560,700,000
Early repayment of borrowings			$ 115,400,000	937,200,000	[1]	104,000,000
Credit Facility
Disclosure of detailed information about borrowings [line items]
Amount outstanding				109,000,000		0
Letters Of Credit - Credit Facility
Disclosure of detailed information about borrowings [line items]
Amount outstanding				69,400,000		51,300,000
400 million at 6.35 percent due July 26, 2017
Disclosure of detailed information about borrowings [line items]
Face value | $							$ 400,000,000.0		$ 400,000,000
Amount outstanding				0		537,000,000
Early repayment of borrowings		CAD 1,000,000,000
Early redemption penalty		CAD 37,600,000
U.S. dollar denominated term notes
Disclosure of detailed information about borrowings [line items]
Amount outstanding				460,400,000		1,496,000,000
Unrealized cumulative foreign exchange loss				96,200,000		353,300,000
U.K. pound sterling denominated term notes
Disclosure of detailed information about borrowings [line items]
Amount outstanding				20,600,000		24,800,000
Unrealized cumulative foreign exchange loss				1,400,000		1,100,000
265 million at 6.98 percent due August 21, 2018
Disclosure of detailed information about borrowings [line items]
Face value | $							265,000,000
Amount outstanding				0		355,600,000		$ 0
Early redemption penalty | $	$ 265,000,000
15 million at 6.61 percent due August 21, 2018
Disclosure of detailed information about borrowings [line items]
Face value | $							$ 15,000,000
Amount outstanding				0		15,000,000
Floating interest rate
Disclosure of detailed information about borrowings [line items]
Amount outstanding				CAD 109,000,000		CAD 0
Fixed interest rate | 400 million at 6.35 percent due July 26, 2017
Disclosure of detailed information about borrowings [line items]
Interest rate				6.35%			6.35%
Fixed interest rate | 265 million at 6.98 percent due August 21, 2018
Disclosure of detailed information about borrowings [line items]
Interest rate				6.98%			6.98%
Fixed interest rate | 15 million at 6.61 percent due August 21, 2018
Disclosure of detailed information about borrowings [line items]
Interest rate				6.61%			6.61%
Minimum | Floating interest rate | Credit Facility
Disclosure of detailed information about borrowings [line items]
Interest rate				3.60%			3.60%
Maximum | Floating interest rate | Credit Facility
Disclosure of detailed information about borrowings [line items]
Interest rate				5.25%			5.25%
2018
Disclosure of detailed information about borrowings [line items]
Amount outstanding				CAD 0
2019
Disclosure of detailed information about borrowings [line items]
Amount outstanding				164,900,000
2020
Disclosure of detailed information about borrowings [line items]
Amount outstanding				118,300,000
2021
Disclosure of detailed information about borrowings [line items]
Amount outstanding				0
2022
Disclosure of detailed information about borrowings [line items]
Amount outstanding				CAD 127,600,000

[1] See Notes 2 and 14.

XML

CAPITAL DISCLOSURES - Narrative (Details) - CAD CAD in Millions	Dec. 31, 2017	Dec. 31, 2016
Disclosure of detailed information about borrowings [line items]
Long-term debt	CAD 610.5	CAD 1,560.7
Credit Facility
Disclosure of detailed information about borrowings [line items]
Long-term debt	CAD 150.0

XML

PROVISIONS AND OTHER LIABILITIES - Rollforward of Provisions (Details) - CAD CAD in Millions	3 Months Ended	12 Months Ended
	Sep. 30, 2017	Dec. 31, 2017	Dec. 31, 2016
Disclosure of other provisions [line items]
Beginning balance		CAD 694.6	CAD 708.0
Incurred during the period		30.4	37.9
Property dispositions		(422.4)	(11.8)
Expenditures on remediation/provisions settled		(18.5)	(21.5)
Other revisions		3.9	(33.1)
Accretion (amortization)		11.4	15.1
Ending balance		299.4	694.6
Asset retirement obligations
Disclosure of other provisions [line items]
Beginning balance		652.3	703.4
Incurred during the period		5.4	0.0
Property dispositions		(420.4)	(11.8)
Expenditures on remediation/provisions settled		(15.9)	(20.0)
Other revisions		3.9	(34.4)
Accretion (amortization)		11.4	15.1
Ending balance		236.7	652.3
Finance leases
Disclosure of other provisions [line items]
Beginning balance		37.9	4.3
Incurred during the period		0.0	35.0
Property dispositions		(2.0)	0.0
Expenditures on remediation/provisions settled		(1.7)	(1.4)
Other revisions		0.0	0.0
Ending balance		34.2	37.9
Restructuring provision - onerous office lease contracts
Disclosure of other provisions [line items]
Beginning balance		0.0	0.0
Incurred during the period	CAD 26.5	26.5	0.0
Property dispositions		0.0	0.0
Expenditures on remediation/provisions settled		(0.3)	0.0
Other revisions		0.0	0.0
Ending balance		26.2	0.0
Other liabilities
Disclosure of other provisions [line items]
Beginning balance		4.4	0.3
Incurred during the period		(1.5)	2.9
Property dispositions		0.0	0.0
Expenditures on remediation/provisions settled		(0.6)	(0.1)
Other revisions		0.0	1.3
Ending balance		CAD 2.3	CAD 4.4

XML

CAPITAL DISCLOSURES - Minimum Interest Coverage Ratios (Details) (Details)	3 Months Ended										12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Dec. 31, 2017
Disclosure of share capital, reserves and other equity interest [Abstract]
Interest ratio coverage	4.0	1.23	1.19	1.13	1.01	1.03	0.68	0.75	0.77	4.0	0.77

XML

PROVISIONS AND OTHER LIABILITIES - Components of Provisions (Details) - CAD CAD in Millions	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Disclosure of other provisions [line items]
Current	CAD 35.2	CAD 22.1
Long term	264.2	672.5
Total	299.4	694.6	CAD 708.0
Asset retirement obligations
Disclosure of other provisions [line items]
Current	29.9	20.0
Long term	206.8	632.3
Total	236.7	652.3	703.4
Finance leases
Disclosure of other provisions [line items]
Current	0.9	1.5
Long term	33.3	36.4
Total	34.2	37.9	4.3
Restructuring provision - onerous office lease contracts
Disclosure of other provisions [line items]
Current	4.4	0.0
Long term	21.8	0.0
Total	26.2	0.0	0.0
Other liabilities
Disclosure of other provisions [line items]
Current	0.0	0.6
Long term	2.3	3.8
Total	CAD 2.3	CAD 4.4	CAD 0.3

XML

CAPITAL DISCLOSURES - Capital Structure (Excluding Shareholders' Equity) (Details) - CAD CAD in Millions	Dec. 31, 2017	Dec. 31, 2016
Disclosure of share capital, reserves and other equity interest [Abstract]
Long-term debt	CAD 610.5	CAD 1,560.7
Convertible debentures	0.0	126.6
Working capital (surplus) deficiency	80.6	(266.7)
Capital structure	CAD 691.1	CAD 1,420.6

XML

PROVISIONS AND OTHER LIABILITIES - Narrative (Details) - CAD CAD in Millions	3 Months Ended	12 Months Ended
	Sep. 30, 2017	Dec. 31, 2017		Dec. 31, 2016
Disclosure of other provisions [line items]
Property dispositions		CAD 422.4		CAD 11.8
Restructuring costs	CAD 37.0	37.0	[1]	0.0
Incurred during the period		30.4		37.9
Severance costs	10.5
Restructuring provision - onerous office lease contracts
Disclosure of other provisions [line items]
Property dispositions		0.0		0.0
Incurred during the period	CAD 26.5	26.5		CAD 0.0
Disposed by sale
Disclosure of other provisions [line items]
Property dispositions		CAD 420.4
Minimum
Disclosure of other provisions [line items]
Expected period		3 years
Maximum
Disclosure of other provisions [line items]
Expected period		4 years

[1] See Notes 2 and 14.

XML

CAPITAL DISCLOSURES - Rollforward of Financial Liabilities (Details)	12 Months Ended
	Dec. 31, 2017 CAD
Disclosure of detailed information about borrowings [line items]
Beginning balance	CAD 1,560,700,000
Increase (decrease) due to:
Ending balance	610,500,000
Term Notes
Disclosure of detailed information about borrowings [line items]
Beginning balance	1,560,700,000
Increase (decrease) due to:
Foreign exchange impact of the Canadian dollar on U.S. and U.K. denominated debt	(65,100,000)
Credit facility borrowing	0
Repayment	(996,000,000)
Issue cost amortization	1,900,000
Ending balance	501,500,000
Canadian dollar Term Credit Facility
Disclosure of detailed information about borrowings [line items]
Beginning balance	0
Increase (decrease) due to:
Foreign exchange impact of the Canadian dollar on U.S. and U.K. denominated debt	0
Credit facility borrowing	109,000,000
Repayment	0
Issue cost amortization	0
Ending balance	109,000,000
Convertible debentures
Disclosure of detailed information about borrowings [line items]
Beginning balance	126,600,000
Increase (decrease) due to:
Foreign exchange impact of the Canadian dollar on U.S. and U.K. denominated debt	0
Credit facility borrowing	0
Repayment	(126,600,000)
Issue cost amortization	0
Ending balance	CAD 0

XML

PROVISIONS AND OTHER LIABILITIES - Assumptions in Calculation of ARO (Details) - Asset retirement obligations - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Disclosure of other provisions [line items]
Total escalated future costs	CAD 420.2	CAD 2,120.4
Discount rate, per annum	2.30%	2.30%
Inflation rate, per annum	1.50%	1.50%

XML

DEFERRED INCOME TAXES - Reconciliation of Deferred Income Tax Recovery (Details) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017		Dec. 31, 2016
Disclosure of income tax [Abstract]
Income (loss) before taxes	CAD (907.6)	[1]	CAD (387.1)
Combined federal and provincial tax rate	27.08%		27.09%
Expected income tax expense (recovery)	CAD (245.8)		CAD (104.9)
Change in unrecognized deferred tax asset	22.6		9.8
Foreign exchange (gain) loss	(2.0)		(1.8)
Effect of change in corporate tax rate	(0.2)		0.0
Other including share based compensation	1.6		3.5
Deferred income tax expense (recovery)	CAD (223.8)		CAD (93.4)
Tax rate effect of expense not deductible in determining taxable profit (tax loss)	50.00%

[1] See Notes 2 and 14.

XML

DEFERRED INCOME TAXES - Components of Deferred Tax Assets and Liabilities (Details) - CAD CAD in Millions	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Deferred tax liabilities associated with:
PP&E and E&E assets	CAD (132.3)	CAD (411.0)
Less deferred tax assets associated with:
Non-capital losses and financing charges	399.6	325.9
Provisions	64.1	176.6
Risk management contracts	10.8	14.6
Long term debt	0.0	12.1
Convertible debentures	0.0	0.2
Net deferred tax asset (liability)	CAD 342.2	CAD 118.4	CAD 25.0

XML

DEFERRED INCOME TAXES - Narrative (Details) - CAD CAD in Millions	Dec. 31, 2017	Dec. 31, 2016
Disclosure of income tax [Abstract]
Non-capital losses available for carry forward	CAD 1,460.2	CAD 1,234.6

XML

DEFERRED INCOME TAXES - Unrecognized Deferred Tax Assets (Details) - CAD CAD in Millions	Dec. 31, 2017	Dec. 31, 2016
Disclosure of income tax [Abstract]
Deductible temporary differences	CAD 204.0	CAD 188.9
Tax losses	109.8	40.2
Total	CAD 313.8	CAD 229.1

XML

DEFERRED INCOME TAXES - Continuity of the Net Deferred Income Tax Asset (Liability) (Details) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Reconciliation of changes in deferred tax liability (asset) [abstract]
Beginning balance	CAD 118.4	CAD 25.0
Recognized in profit or loss	223.8	93.4
Ending balance	342.2	118.4
PP&E and E&E assets
Reconciliation of changes in deferred tax liability (asset) [abstract]
Beginning balance	(411.0)	(405.3)
Recognized in profit or loss	278.7	(5.7)
Ending balance	(132.3)	(411.0)
Non-capital losses and financing charges
Reconciliation of changes in deferred tax liability (asset) [abstract]
Beginning balance	325.9	328.7
Recognized in profit or loss	73.7	(2.8)
Ending balance	399.6	325.9
Provisions
Reconciliation of changes in deferred tax liability (asset) [abstract]
Beginning balance	176.6	190.2
Recognized in profit or loss	(112.5)	(13.6)
Ending balance	64.1	176.6
Risk management contracts
Reconciliation of changes in deferred tax liability (asset) [abstract]
Beginning balance	14.6	(99.8)
Recognized in profit or loss	(3.8)	114.4
Ending balance	10.8	14.6
Long term debt
Reconciliation of changes in deferred tax liability (asset) [abstract]
Beginning balance	12.1	10.8
Recognized in profit or loss	(12.1)	1.3
Ending balance	0.0	12.1
Convertible debentures
Reconciliation of changes in deferred tax liability (asset) [abstract]
Beginning balance	0.2	0.2
Recognized in profit or loss	(0.2)	0.0
Ending balance	0.0	0.2
Share issue costs
Reconciliation of changes in deferred tax liability (asset) [abstract]
Beginning balance	0.0	0.2
Recognized in profit or loss		(0.2)
Ending balance	CAD 0.0	CAD 0.0

XML

SHAREHOLDERS' CAPITAL - Summary of Shareholders' Capital (Details) - CAD shares in Thousands, CAD in Millions	12 Months Ended
	Dec. 31, 2017		Dec. 31, 2016
Reconciliation of number of shares outstanding [abstract]
Balance, beginning of year	CAD 4,815.1
Balance, end of year	CAD 4,829.7	[1]	CAD 4,815.1
Common Shares
Reconciliation of number of shares outstanding [abstract]
Balance, beginning of period (in shares)	547,709		543,033
Share based compensation (non-cash exercised) (in shares)	4,537		4,676
Balance, end of period (in shares)	552,246		547,709
Balance, beginning of year	CAD 4,815.1		CAD 4,797.0
Share based compensation (non-cash exercised)	14.6		18.1
Balance, end of year	CAD 4,829.7		CAD 4,815.1

[1] See Notes 2 and 14.

XML

SHAREHOLDERS' CAPITAL - Narrative (Details)	Dec. 31, 2017 shares
Preferred Shares
Disclosure of classes of share capital [line items]
Shares authorized (in shares)	10,000,000

XML

LONG TERM INCENTIVE PLANS ("LTIP") - Continuity of Share-settled LTIP (Details) - shares shares in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
PSUs
Disclosure of terms and conditions of share-based payment arrangement [line items]
Beginning shares	6,238	4,640
Granted	2,124	3,049
Forfeited	(486)	(460)
Exercised	(1,104)	(1,695)
Performance adjustment	(1,738)	704
Ending shares	5,034	6,238
RSUs
Disclosure of terms and conditions of share-based payment arrangement [line items]
Beginning shares	8,436	5,341
Granted	4,578	6,553
Forfeited	(2,195)	(737)
Exercised	(3,436)	(2,721)
Performance adjustment	0	0
Ending shares	7,383	8,436
DSUs
Disclosure of terms and conditions of share-based payment arrangement [line items]
Beginning shares	198	302
Granted	0	0
Forfeited	0	0
Exercised	0	(104)
Performance adjustment	0	0
Ending shares	198	198

XML

LONG TERM INCENTIVE PLANS ("LTIP") - Narrative (Details)	12 Months Ended
	Dec. 31, 2017 CAD tranche CAD / shares shares	Dec. 31, 2016 CAD CAD / shares shares
Disclosure of terms and conditions of share-based payment arrangement [line items]
Percent of outstanding and issued stock authorized for LTIP	3.20%
Actual percent of LTIP shares of outstanding and issued shares	2.30%
Expense (reduction) for share-based compensation	CAD 4,100,000	CAD 19,100,000
Share-settled LTIP units
Disclosure of terms and conditions of share-based payment arrangement [line items]
Expense (reduction) for share-based compensation	5,000,000	13,700,000
Weighted average grant date fair value (in CAD per share)	1.40	1.02
Unrecognized compensation expense	CAD 5,400,000	CAD 9,800,000
Unrecognized compensation expense (in CAD per share) | CAD / shares	CAD 0.51	CAD 0.78
Period for recognition	1 year 3 months 19 days
DESUs
Disclosure of terms and conditions of share-based payment arrangement [line items]
Shares reserved for future issuance (in shares) | shares	163,867	163,867
Cash-settled RSUs
Disclosure of terms and conditions of share-based payment arrangement [line items]
Expense (reduction) for share-based compensation	CAD (200,000)	CAD 3,600,000
Number of tranches | tranche	3
Vesting period	3 years
Liabilities from share-based payment transactions	CAD 1,500,000	3,600,000
Phantom DSUs
Disclosure of terms and conditions of share-based payment arrangement [line items]
Expense (reduction) for share-based compensation	(600,000)	2,300,000
Liabilities from share-based payment transactions	CAD 1,400,000	CAD 2,600,000
Minimum
Disclosure of terms and conditions of share-based payment arrangement [line items]
Anticipated forfeiture rate	25.00%
Minimum | PSUs
Disclosure of terms and conditions of share-based payment arrangement [line items]
Performance factor	0.00%
Minimum | Cash-settled RSUs
Disclosure of terms and conditions of share-based payment arrangement [line items]
Anticipated forfeiture rate	50.00%
Maximum
Disclosure of terms and conditions of share-based payment arrangement [line items]
Anticipated forfeiture rate	55.00%
Maximum | PSUs
Disclosure of terms and conditions of share-based payment arrangement [line items]
Performance factor	200.00%
Maximum | Cash-settled RSUs
Disclosure of terms and conditions of share-based payment arrangement [line items]
Anticipated forfeiture rate	80.00%

XML

LONG TERM INCENTIVE PLANS ("LTIP") - Continuity of Cash-settled LTIP (Details) - shares shares in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Cash-settled RSUs
Disclosure of terms and conditions of share-based payment arrangement [line items]
Beginning shares	4,229	0
Granted	3,163	4,559
Forfeited	(3,148)	(330)
Exercised	(1,341)	0
Ending shares	2,903	4,229
Phantom DSUs
Disclosure of terms and conditions of share-based payment arrangement [line items]
Beginning shares	1,346	397
Granted	492	1,024
Forfeited	0	0
Exercised	(462)	(75)
Ending shares	1,376	1,346

XML

LONG TERM INCENTIVE PLANS ("LTIP") - Share Based Compensation Expense (Details) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017		Dec. 31, 2016
Disclosure of terms and conditions of share-based payment arrangement [line items]
Non-cash share based compensation	CAD 5.0		CAD 13.7
Amounts capitalized in the period	(0.1)		(0.5)
Non-cash share based compensation expense	4.9	[1]	13.2
Expense (reduction) for share-based compensation	4.1		19.1
Cash-settled RSUs
Disclosure of terms and conditions of share-based payment arrangement [line items]
Expense (reduction) for share-based compensation	(0.2)		3.6
Phantom DSUs
Disclosure of terms and conditions of share-based payment arrangement [line items]
Expense (reduction) for share-based compensation	CAD (0.6)		CAD 2.3

[1] See Notes 2 and 14.

XML

REVENUE - Disaggregation of Revenue (Details) - CAD CAD in Millions	3 Months Ended			12 Months Ended
	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2017		Dec. 31, 2016
Disclosure of disaggregation of revenue from contracts with customers [line items]
Oil and gas sales	CAD 125.1	CAD 197.9	CAD 219.9	CAD 673.4	[1]	CAD 566.2
Produced petroleum revenue
Disclosure of disaggregation of revenue from contracts with customers [line items]
Oil and gas sales				486.4
Light oil
Disclosure of disaggregation of revenue from contracts with customers [line items]
Oil and gas sales				149.3
Bitumen
Disclosure of disaggregation of revenue from contracts with customers [line items]
Oil and gas sales				181.6
Natural gas liquids
Disclosure of disaggregation of revenue from contracts with customers [line items]
Oil and gas sales				56.7
Natural gas
Disclosure of disaggregation of revenue from contracts with customers [line items]
Oil and gas sales				98.8
Diluent
Disclosure of disaggregation of revenue from contracts with customers [line items]
Oil and gas sales				147.2
Processing income
Disclosure of disaggregation of revenue from contracts with customers [line items]
Oil and gas sales				19.1
Other revenue
Disclosure of disaggregation of revenue from contracts with customers [line items]
Oil and gas sales				CAD 20.7

[1] See Notes 2 and 14.

XML

REVENUE - Narrative (Details) - CAD CAD in Millions	3 Months Ended			12 Months Ended
	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2017		Dec. 31, 2016
Disclosure of disaggregation of revenue from contracts with customers [line items]
Oil and gas sales	CAD 125.1	CAD 197.9	CAD 219.9	CAD 673.4	[1]	CAD 566.2
Operating expenses	(51.6)	(68.5)	(67.3)	(1,311.6)	[1]	(742.6)
Diluent and other product purchases	CAD (28.9)	CAD (45.2)	CAD (46.7)	(163.5)	[1]	0.0
Accounts receivable				105.7	[2]	126.6
Increase (decrease) due to application of IFRS 15
Disclosure of disaggregation of revenue from contracts with customers [line items]
Oil and gas sales				182.6
Operating expenses				163.5
Diluent and other product purchases				CAD 19.1
Customer concentration risk | BP Products North America Inc. | Oil and gas sales
Disclosure of disaggregation of revenue from contracts with customers [line items]
Concentration risk, percentage				36.00%
Customer concentration risk | Phillips 66 Canada Ltd | Oil and gas sales
Disclosure of disaggregation of revenue from contracts with customers [line items]
Concentration risk, percentage				12.00%
Fixed-price contracts | Product concentration | Oil and gas sales
Disclosure of disaggregation of revenue from contracts with customers [line items]
Concentration risk, percentage				0.20%
Oil and gas sales
Disclosure of disaggregation of revenue from contracts with customers [line items]
Accounts receivable				CAD 40.2		CAD 76.5

[1] See Notes 2 and 14.

[2] See Notes 2 and 14.

XML

OTHER CASH FLOW DISCLOSURES - Change in Non-cash Operating Working Capital and Other Assets (Details) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017		Dec. 31, 2016
Cash Flow Statement [Abstract]
Accounts receivable	CAD 40.9		CAD 25.0
Accounts payable	(22.7)		(43.8)
Prepaid tax assessment	0.0		(2.7)
Change in non-cash operating working capital	CAD 18.2	[1]	CAD (21.5)

[1] See Notes 2 and 14.

XML

OTHER CASH FLOW DISCLOSURES - Change in Non-cash Investing Working Capital (Details) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Cash Flow Statement [Abstract]
Accounts payable, including capital accruals	CAD (7.5)	CAD 7.6

XML

AMOUNTS PER SHARE - Summary of Weighted Average Shares Used in Calculating Amounts Per Share (Details) - shares shares in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Earnings per share [abstract]
Weighted average number of shares - basic and diluted (in shares)	551,193	546,566

XML

AMOUNTS PER SHARE - Narrative (Details) - shares shares in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Share based compensation plans
Earnings per share [line items]
Antidilutive securities excluded from calculation of amounts per share (in shares)	9.3	7.8

XML

FINANCIAL INSTRUMENTS AND RISK MANAGEMENT - Summary of Commodity Price Contracts (Details) CAD in Millions	12 Months Ended
	Dec. 31, 2017 CAD CAD / bbl bbl $ / bbl
Commodity price risk | Financial Crude Oil Contracts: | 2018
Disclosure of detailed information about hedging instruments [line items]
Nominal volume (in bbl/d) | bbl	8,000
Price per unit (in usd per bbl)	49.97
Cdn$1/bbl increase in future oil prices | Financial Crude Oil Contracts:
Disclosure of detailed information about hedging instruments [line items]
Risk exposure associated with instruments sharing characteristic | CAD	CAD (3.5)
Benchmark for sensitivity analysis | CAD / bbl	1
Cdn$1/bbl decrease in future oil prices | Financial Crude Oil Contracts:
Disclosure of detailed information about hedging instruments [line items]
Risk exposure associated with instruments sharing characteristic | CAD	CAD 3.5
Benchmark for sensitivity analysis | CAD / bbl	1
WTI less $16.95 | Commodity price risk | Physical Delivery Contracts | 2018
Disclosure of detailed information about hedging instruments [line items]
Nominal volume (in bbl/d) | bbl	12,000
WTI less $16.95 | Commodity price risk | Physical Delivery Contracts | 2018 | Maximum
Disclosure of detailed information about hedging instruments [line items]
Price per unit (in usd per bbl)	16.95
WTI less $16.50 - $19.25 | Commodity price risk | Physical Delivery Contracts | 2018
Disclosure of detailed information about hedging instruments [line items]
Nominal volume (in bbl/d) | bbl	5,000
WTI less $16.50 - $19.25 | Commodity price risk | Physical Delivery Contracts | 2018 | Maximum
Disclosure of detailed information about hedging instruments [line items]
Price per unit (in usd per bbl)	19.25
WTI less $16.50 - $19.25 | Commodity price risk | Physical Delivery Contracts | 2018 | Minimum
Disclosure of detailed information about hedging instruments [line items]
Price per unit (in usd per bbl)	16.50
WTI less $17.95 | Commodity price risk | Physical Delivery Contracts | 2019
Disclosure of detailed information about hedging instruments [line items]
Nominal volume (in bbl/d) | bbl	2,500
WTI less $17.95 | Commodity price risk | Physical Delivery Contracts | 2019 | Maximum
Disclosure of detailed information about hedging instruments [line items]
Price per unit (in usd per bbl)	17.95
WTI less $17.70 - $20.45 | Commodity price risk | Physical Delivery Contracts | 2019
Disclosure of detailed information about hedging instruments [line items]
Nominal volume (in bbl/d) | bbl	5,000
WTI less $17.70 - $20.45 | Commodity price risk | Physical Delivery Contracts | 2019 | Maximum
Disclosure of detailed information about hedging instruments [line items]
Price per unit (in usd per bbl)	20.45
WTI less $17.70 - $20.45 | Commodity price risk | Physical Delivery Contracts | 2019 | Minimum
Disclosure of detailed information about hedging instruments [line items]
Price per unit (in usd per bbl)	17.70

XML

FINANCIAL INSTRUMENTS AND RISK MANAGEMENT - Narrative (Details)			3 Months Ended			12 Months Ended
	Oct. 01, 2017 USD ($)	Mar. 30, 2017 CAD	Dec. 31, 2017 CAD CAD / $	Dec. 31, 2017 USD ($)	Mar. 31, 2017 CAD	Dec. 31, 2017 CAD CAD / $		Dec. 31, 2016 CAD	Dec. 31, 2017 USD ($) CAD / $	Oct. 12, 2017 USD ($)	Mar. 31, 2017 USD ($)	Dec. 31, 2015 CAD
Disclosure of information about terms and conditions of hedging instruments and how they affect future cash flows [line items]
Realized foreign exchange (gain) loss						CAD 38,400,000	[1]	CAD (46,500,000)
Long-term debt			CAD 610,500,000			610,500,000		1,560,700,000
Early repayment of borrowings				$ 115,400,000		937,200,000	[2]	104,000,000
Swaps | Financial Crude Oil Contracts:
Disclosure of information about terms and conditions of hedging instruments and how they affect future cash flows [line items]
Loss on derivative					CAD 12,700,000
Foreign currency swap contract
Disclosure of information about terms and conditions of hedging instruments and how they affect future cash flows [line items]
Realized foreign exchange (gain) loss						CAD 37,600,000
Currency risk | Foreign currency swap contract | U.S. dollar denominated term notes
Disclosure of information about terms and conditions of hedging instruments and how they affect future cash flows [line items]
Face value | $									$ 366,300,000
Price per unit | CAD / $			0.75			0.75			0.75
400 million at 6.35 percent due July 26, 2017
Disclosure of information about terms and conditions of hedging instruments and how they affect future cash flows [line items]
Face value | $									$ 400,000,000.0		$ 400,000,000
Long-term debt			CAD 0			CAD 0		537,000,000
Early redemption penalty		CAD 37,600,000
Early repayment of borrowings		CAD 1,000,000,000
400 million at 6.35 percent due July 26, 2017 | Foreign currency swap contract
Disclosure of information about terms and conditions of hedging instruments and how they affect future cash flows [line items]
Face value | $	$ 365,000,000										$ 300,000,000
Realized foreign exchange (gain) loss			34,800,000		CAD (2,800,000)
265 million at 6.98 percent due August 21, 2018
Disclosure of information about terms and conditions of hedging instruments and how they affect future cash flows [line items]
Face value | $									$ 265,000,000
Long-term debt			0			0		355,600,000		$ 0
Early redemption penalty | $	$ 265,000,000
Convertible debentures
Disclosure of information about terms and conditions of hedging instruments and how they affect future cash flows [line items]
Face value			0			0
Long-term debt			0			0		126,600,000				CAD 137,000,000
Credit Facility
Disclosure of information about terms and conditions of hedging instruments and how they affect future cash flows [line items]
Credit facility, maximum borrowing capacity			330,000,000			330,000,000
Long-term debt			109,000,000			109,000,000		0
Floating interest rate
Disclosure of information about terms and conditions of hedging instruments and how they affect future cash flows [line items]
Long-term debt			109,000,000			109,000,000		0
Interest rate risk			CAD 1,100,000			CAD 1,100,000		CAD 0

[1] See Notes 2 and 14.

[2] See Notes 2 and 14.

XML

FINANCIAL INSTRUMENTS AND RISK MANAGEMENT - Foreign Exchange Contracts Associated with the Borrowing Obligations (Details) - Dec. 31, 2017 - Currency risk - Foreign currency swap contract £ in Millions, $ in Millions	GBP (£) CAD / £ CAD / $	USD ($) CAD / £ CAD / $
U.K. pound sterling denominated term notes
Disclosure of detailed information about hedging instruments [line items]
Principal amount | £	£ 12.1
Swapped amount | £	£ 15.0
% of principal swapped	123.96694%	123.96694%
Average price (in cad per usd and cad per pound sterling) | CAD / £	0.63	0.63
U.S. dollar denominated term notes
Disclosure of detailed information about hedging instruments [line items]
Principal amount | $		$ 366.3
Swapped amount | $		$ 255.0
% of principal swapped	70.00%	70.00%
Average price (in cad per usd and cad per pound sterling) | CAD / $	0.75	0.75

XML

FINANCIAL INSTRUMENTS AND RISK MANAGEMENT - Summary of Balance Sheet and Income Statement Locations of Risk Management Instruments (Details) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017		Dec. 31, 2016	Dec. 31, 2015
Disclosure of detailed information about hedging instruments [line items]
Current portion of risk management assets	CAD 0.0	[1]	CAD 2.9
Non-current portion of risk management assets	1.9	[1]	1.0
Current portion of risk management liabilities	(40.0)	[1]	(55.3)
Non-current portion of risk management liabilities	(18.6)	[1]	(5.3)
Risk management assets (liabilities)	(56.7)		(56.7)	CAD 452.1
Unrealized gain (loss) on risk management contracts for the year	0.0		(508.8)
Realized gain (loss) on risk management contracts for the year	(57.4)		428.2
Total unrealized and realized gain (loss) on risk management contracts for the year	(57.4)		(80.6)
Commodity contracts
Disclosure of detailed information about hedging instruments [line items]
Current portion of risk management assets			0.0
Non-current portion of risk management assets	0.0		0.0
Current portion of risk management liabilities	(39.8)		(54.0)
Non-current portion of risk management liabilities	0.0		0.0
Risk management assets (liabilities)	(39.8)		(54.0)	370.5
Unrealized gain (loss) on risk management contracts for the year	14.2		(424.5)
Realized gain (loss) on risk management contracts for the year	(19.8)		385.7
Total unrealized and realized gain (loss) on risk management contracts for the year	(5.6)		(38.8)
Power contracts
Disclosure of detailed information about hedging instruments [line items]
Current portion of risk management assets			0.0
Non-current portion of risk management assets	0.0		0.0
Current portion of risk management liabilities	0.0		0.0
Non-current portion of risk management liabilities	0.0		0.0
Risk management assets (liabilities)	0.0		0.0	(1.7)
Unrealized gain (loss) on risk management contracts for the year	0.0		1.7
Realized gain (loss) on risk management contracts for the year	0.0		(4.5)
Total unrealized and realized gain (loss) on risk management contracts for the year	0.0		(2.8)
Foreign exchange contract
Disclosure of detailed information about hedging instruments [line items]
Current portion of risk management assets			2.9
Non-current portion of risk management assets	1.9		1.0
Current portion of risk management liabilities	(0.2)		(1.3)
Non-current portion of risk management liabilities	(18.6)		(5.3)
Risk management assets (liabilities)	(16.9)		(2.7)	CAD 83.3
Unrealized gain (loss) on risk management contracts for the year	(14.2)		(86.0)
Realized gain (loss) on risk management contracts for the year	(37.6)		47.0
Total unrealized and realized gain (loss) on risk management contracts for the year	CAD (51.8)		CAD (39.0)

[1] See Notes 2 and 14.

XML

FINANCIAL INSTRUMENTS AND RISK MANAGEMENT - Foreign Denominated Term Debt Sensitivity to Foreign Exchange Rate (Details) CAD in Millions	Dec. 31, 2017 CAD
Cdn - U.S.
Disclosure of detailed information about hedging instruments [line items]
Net pre-tax impact on Consolidated Statements of Income (Loss)	CAD 1.1
Cdn - U.K.
Disclosure of detailed information about hedging instruments [line items]
Net pre-tax impact on Consolidated Statements of Income (Loss)	0.0
Unrealized foreign exchange gain or loss on foreign denominated debt | Cdn - U.S. | Foreign exchange contract
Disclosure of detailed information about hedging instruments [line items]
Net pre-tax impact on Consolidated Statements of Income (Loss)	3.7
Unrealized foreign exchange gain or loss on foreign denominated debt | Cdn - U.K. | Foreign exchange contract
Disclosure of detailed information about hedging instruments [line items]
Net pre-tax impact on Consolidated Statements of Income (Loss)	0.1
Unrealized foreign exchange risk management gain or loss | Cdn - U.S. | Foreign exchange contract
Disclosure of detailed information about hedging instruments [line items]
Net pre-tax impact on Consolidated Statements of Income (Loss)	2.6
Unrealized foreign exchange risk management gain or loss | Cdn - U.K. | Foreign exchange contract
Disclosure of detailed information about hedging instruments [line items]
Net pre-tax impact on Consolidated Statements of Income (Loss)	CAD 0.1

XML

FINANCIAL INSTRUMENTS AND RISK MANAGEMENT - Summary of Non-current Financial Liabilities & Maturities (Details) - CAD	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Disclosure of maturity analysis for financial assets held for managing liquidity risk [line items]
Amount outstanding	CAD 610,500,000	CAD 1,560,700,000
Year 2
Disclosure of maturity analysis for financial assets held for managing liquidity risk [line items]
Amount outstanding	164,900,000
Accounts payable
Disclosure of maturity analysis for financial assets held for managing liquidity risk [line items]
Amount outstanding	136,200,000	189,600,000
Contractual cash flows	136,200,000	189,600,000
Accounts payable | Year 1
Disclosure of maturity analysis for financial assets held for managing liquidity risk [line items]
Contractual cash flows	136,200,000	189,600,000
Accounts payable | Year 2
Disclosure of maturity analysis for financial assets held for managing liquidity risk [line items]
Contractual cash flows	0	0
Accounts payable | Years 3-5
Disclosure of maturity analysis for financial assets held for managing liquidity risk [line items]
Contractual cash flows	0	0
Accounts payable | More than 5 years
Disclosure of maturity analysis for financial assets held for managing liquidity risk [line items]
Contractual cash flows	0	0
Convertible debentures
Disclosure of maturity analysis for financial assets held for managing liquidity risk [line items]
Amount outstanding	0	126,600,000	CAD 137,000,000
Contractual cash flows		130,500,000
Face value	0
Convertible debentures | Year 1
Disclosure of maturity analysis for financial assets held for managing liquidity risk [line items]
Contractual cash flows		130,500,000
Convertible debentures | Year 2
Disclosure of maturity analysis for financial assets held for managing liquidity risk [line items]
Contractual cash flows		0
Convertible debentures | Years 3-5
Disclosure of maturity analysis for financial assets held for managing liquidity risk [line items]
Contractual cash flows		0
Convertible debentures | More than 5 years
Disclosure of maturity analysis for financial assets held for managing liquidity risk [line items]
Contractual cash flows		0
Cdn dollar term notes
Disclosure of maturity analysis for financial assets held for managing liquidity risk [line items]
Amount outstanding	20,500,000	39,900,000
Contractual cash flows	27,100,000	48,500,000
Cdn dollar term notes | Year 1
Disclosure of maturity analysis for financial assets held for managing liquidity risk [line items]
Contractual cash flows	1,400,000	2,200,000
Cdn dollar term notes | Year 2
Disclosure of maturity analysis for financial assets held for managing liquidity risk [line items]
Contractual cash flows	1,400,000	16,800,000
Cdn dollar term notes | Years 3-5
Disclosure of maturity analysis for financial assets held for managing liquidity risk [line items]
Contractual cash flows	24,300,000	3,600,000
Cdn dollar term notes | More than 5 years
Disclosure of maturity analysis for financial assets held for managing liquidity risk [line items]
Contractual cash flows	0	25,900,000
U.S. dollar denominated term notes
Disclosure of maturity analysis for financial assets held for managing liquidity risk [line items]
Amount outstanding	460,400,000	1,496,000,000
Contractual cash flows	601,300,000	1,726,800,000
U.S. dollar denominated term notes | Year 1
Disclosure of maturity analysis for financial assets held for managing liquidity risk [line items]
Contractual cash flows	30,200,000	623,700,000
U.S. dollar denominated term notes | Year 2
Disclosure of maturity analysis for financial assets held for managing liquidity risk [line items]
Contractual cash flows	65,200,000	399,200,000
U.S. dollar denominated term notes | Years 3-5
Disclosure of maturity analysis for financial assets held for managing liquidity risk [line items]
Contractual cash flows	284,000,000	266,000,000
U.S. dollar denominated term notes | More than 5 years
Disclosure of maturity analysis for financial assets held for managing liquidity risk [line items]
Contractual cash flows	221,900,000	437,900,000
U.K. pound sterling denominated term notes
Disclosure of maturity analysis for financial assets held for managing liquidity risk [line items]
Amount outstanding	20,600,000	24,800,000
Contractual cash flows	22,600,000	27,300,000
U.K. pound sterling denominated term notes | Year 1
Disclosure of maturity analysis for financial assets held for managing liquidity risk [line items]
Contractual cash flows	1,100,000	900,000
U.K. pound sterling denominated term notes | Year 2
Disclosure of maturity analysis for financial assets held for managing liquidity risk [line items]
Contractual cash flows	21,500,000	900,000
U.K. pound sterling denominated term notes | Years 3-5
Disclosure of maturity analysis for financial assets held for managing liquidity risk [line items]
Contractual cash flows	0	25,500,000
U.K. pound sterling denominated term notes | More than 5 years
Disclosure of maturity analysis for financial assets held for managing liquidity risk [line items]
Contractual cash flows	0	0
Canadian dollar term Credit Facility borrowings
Disclosure of maturity analysis for financial assets held for managing liquidity risk [line items]
Amount outstanding	109,000,000	0
Contractual cash flows	117,600,000
Canadian dollar term Credit Facility borrowings | Year 1
Disclosure of maturity analysis for financial assets held for managing liquidity risk [line items]
Contractual cash flows	6,900,000
Canadian dollar term Credit Facility borrowings | Year 2
Disclosure of maturity analysis for financial assets held for managing liquidity risk [line items]
Contractual cash flows	110,700,000
Canadian dollar term Credit Facility borrowings | Years 3-5
Disclosure of maturity analysis for financial assets held for managing liquidity risk [line items]
Contractual cash flows	0
Canadian dollar term Credit Facility borrowings | More than 5 years
Disclosure of maturity analysis for financial assets held for managing liquidity risk [line items]
Contractual cash flows	0
Finance leases
Disclosure of maturity analysis for financial assets held for managing liquidity risk [line items]
Amount outstanding	34,200,000	37,900,000
Contractual cash flows	76,800,000	90,700,000
Finance leases | Year 1
Disclosure of maturity analysis for financial assets held for managing liquidity risk [line items]
Contractual cash flows	4,400,000	5,700,000
Finance leases | Year 2
Disclosure of maturity analysis for financial assets held for managing liquidity risk [line items]
Contractual cash flows	4,200,000	5,000,000
Finance leases | Years 3-5
Disclosure of maturity analysis for financial assets held for managing liquidity risk [line items]
Contractual cash flows	12,600,000	14,200,000
Finance leases | More than 5 years
Disclosure of maturity analysis for financial assets held for managing liquidity risk [line items]
Contractual cash flows	55,600,000	65,800,000
Foreign exchange risk management contracts
Disclosure of maturity analysis for financial assets held for managing liquidity risk [line items]
Amount outstanding	18,800,000	6,600,000
Contractual cash flows	20,800,000	6,100,000
Foreign exchange risk management contracts | Year 1
Disclosure of maturity analysis for financial assets held for managing liquidity risk [line items]
Contractual cash flows	200,000	1,300,000
Foreign exchange risk management contracts | Year 2
Disclosure of maturity analysis for financial assets held for managing liquidity risk [line items]
Contractual cash flows	4,300,000	1,700,000
Foreign exchange risk management contracts | Years 3-5
Disclosure of maturity analysis for financial assets held for managing liquidity risk [line items]
Contractual cash flows	16,300,000	2,400,000
Foreign exchange risk management contracts | More than 5 years
Disclosure of maturity analysis for financial assets held for managing liquidity risk [line items]
Contractual cash flows	0	700,000
Other liabilities
Disclosure of maturity analysis for financial assets held for managing liquidity risk [line items]
Amount outstanding	2,300,000	4,400,000
Contractual cash flows	3,200,000	8,300,000
Other liabilities | Year 1
Disclosure of maturity analysis for financial assets held for managing liquidity risk [line items]
Contractual cash flows	0	600,000
Other liabilities | Year 2
Disclosure of maturity analysis for financial assets held for managing liquidity risk [line items]
Contractual cash flows	1,400,000	2,900,000
Other liabilities | Years 3-5
Disclosure of maturity analysis for financial assets held for managing liquidity risk [line items]
Contractual cash flows	300,000	2,800,000
Other liabilities | More than 5 years
Disclosure of maturity analysis for financial assets held for managing liquidity risk [line items]
Contractual cash flows	1,500,000	2,000,000
Remediation trust fund payments
Disclosure of maturity analysis for financial assets held for managing liquidity risk [line items]
Amount outstanding		0
Contractual cash flows		12,500,000
Remediation trust fund payments | Year 1
Disclosure of maturity analysis for financial assets held for managing liquidity risk [line items]
Contractual cash flows		300,000
Remediation trust fund payments | Year 2
Disclosure of maturity analysis for financial assets held for managing liquidity risk [line items]
Contractual cash flows		300,000
Remediation trust fund payments | Years 3-5
Disclosure of maturity analysis for financial assets held for managing liquidity risk [line items]
Contractual cash flows		900,000
Remediation trust fund payments | More than 5 years
Disclosure of maturity analysis for financial assets held for managing liquidity risk [line items]
Contractual cash flows		11,000,000
Commodity risk management contracts
Disclosure of maturity analysis for financial assets held for managing liquidity risk [line items]
Amount outstanding	39,800,000	54,000,000
Contractual cash flows	39,800,000	54,000,000
Commodity risk management contracts | Year 1
Disclosure of maturity analysis for financial assets held for managing liquidity risk [line items]
Contractual cash flows	39,800,000	54,000,000
Commodity risk management contracts | Year 2
Disclosure of maturity analysis for financial assets held for managing liquidity risk [line items]
Contractual cash flows	0	0
Commodity risk management contracts | Years 3-5
Disclosure of maturity analysis for financial assets held for managing liquidity risk [line items]
Contractual cash flows	0	0
Commodity risk management contracts | More than 5 years
Disclosure of maturity analysis for financial assets held for managing liquidity risk [line items]
Contractual cash flows	CAD 0	CAD 0

XML

FINANCIAL INSTRUMENTS AND RISK MANAGEMENT - Summary of Fair Value Amounts (Details) - CAD CAD in Millions	Dec. 31, 2017		Dec. 31, 2016
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial Assets	CAD 1,910.9	[1]	CAD 4,117.1
Financial Liabilities	1,104.7	[1]	2,632.1
Carrying amount | Convertible debentures
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial Liabilities			126.6
Carrying amount | U.S. dollar denominated term notes
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial Liabilities	460.4		1,496.0
Carrying amount | Cdn dollar term notes
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial Liabilities	20.5		39.9
Carrying amount | U.K. pound sterling denominated term notes
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial Liabilities	20.6		24.8
Carrying amount | Fair value of risk management contracts
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial Liabilities	58.6		60.6
Carrying amount | Remediation trust funds
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial Assets	111.6		106.5
Carrying amount | Fair value of risk management contracts
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial Assets	1.9		3.9
Fair value | Convertible debentures
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial Liabilities			126.7
Fair value | U.S. dollar denominated term notes
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial Liabilities	509.5		1,527.7
Fair value | Cdn dollar term notes
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial Liabilities	22.8		41.3
Fair value | U.K. pound sterling denominated term notes
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial Liabilities	21.7		25.5
Fair value | Fair value of risk management contracts
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial Liabilities	58.6		60.6
Fair value | Remediation trust funds
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial Assets	111.6		106.5
Fair value | Fair value of risk management contracts
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial Assets	1.9		3.9
Fair value | Quoted prices in active markets (Level 1) | Convertible debentures
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial Liabilities			126.7
Fair value | Quoted prices in active markets (Level 1) | U.S. dollar denominated term notes
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial Liabilities	0.0		0.0
Fair value | Quoted prices in active markets (Level 1) | Cdn dollar term notes
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial Liabilities	0.0		0.0
Fair value | Quoted prices in active markets (Level 1) | U.K. pound sterling denominated term notes
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial Liabilities	0.0		0.0
Fair value | Quoted prices in active markets (Level 1) | Fair value of risk management contracts
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial Liabilities	0.0		0.0
Fair value | Quoted prices in active markets (Level 1) | Remediation trust funds
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial Assets	111.6		106.5
Fair value | Quoted prices in active markets (Level 1) | Fair value of risk management contracts
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial Assets	0.0		0.0
Fair value | Significant other observable inputs (Level 2) | Convertible debentures
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial Liabilities			0.0
Fair value | Significant other observable inputs (Level 2) | U.S. dollar denominated term notes
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial Liabilities	509.5		1,527.7
Fair value | Significant other observable inputs (Level 2) | Cdn dollar term notes
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial Liabilities	22.8		41.3
Fair value | Significant other observable inputs (Level 2) | U.K. pound sterling denominated term notes
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial Liabilities	21.7		25.5
Fair value | Significant other observable inputs (Level 2) | Fair value of risk management contracts
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial Liabilities	58.6		60.6
Fair value | Significant other observable inputs (Level 2) | Remediation trust funds
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial Assets	0.0		0.0
Fair value | Significant other observable inputs (Level 2) | Fair value of risk management contracts
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial Assets	1.9		3.9
Fair value | Significant unobservable inputs (Level 3) | Convertible debentures
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial Liabilities			0.0
Fair value | Significant unobservable inputs (Level 3) | U.S. dollar denominated term notes
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial Liabilities	0.0		0.0
Fair value | Significant unobservable inputs (Level 3) | Cdn dollar term notes
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial Liabilities	0.0		0.0
Fair value | Significant unobservable inputs (Level 3) | U.K. pound sterling denominated term notes
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial Liabilities	0.0		0.0
Fair value | Significant unobservable inputs (Level 3) | Fair value of risk management contracts
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial Liabilities	0.0		0.0
Fair value | Significant unobservable inputs (Level 3) | Remediation trust funds
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial Assets	0.0		0.0
Fair value | Significant unobservable inputs (Level 3) | Fair value of risk management contracts
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial Assets	CAD 0.0		CAD 0.0

[1] See Notes 2 and 14.

XML

FINANCIAL INSTRUMENTS AND RISK MANAGEMENT - Components of Accounts Receivable (Details) - CAD CAD in Millions	Dec. 31, 2017		Dec. 31, 2016
Disclosure of detailed information about financial instruments [abstract]
Trade	CAD 97.5		CAD 110.3
Prepaid and other	8.2		16.3
Accounts receivable	CAD 105.7	[1]	CAD 126.6

[1] See Notes 2 and 14.

XML

FINANCIAL INSTRUMENTS AND RISK MANAGEMENT - Risk Management Contracts on the Consolidated Balance Sheets (Details) - CAD CAD in Millions	Dec. 31, 2017		Dec. 31, 2016
Disclosure of detailed information about hedging instruments [line items]
Current asset	CAD 0.0	[1]	CAD 2.9
Non-current asset	1.9	[1]	1.0
Current liability	(40.0)	[1]	(55.3)
Non-current liability	(18.6)	[1]	(5.3)
Risk management contracts
Disclosure of detailed information about hedging instruments [line items]
Current asset	0.0		3.0
Non-current asset	1.9		1.0
Current liability	(40.0)		(55.4)
Non-current liability	(18.6)		(5.3)
Gross derivative amounts	CAD 56.7		CAD 56.7

[1] See Notes 2 and 14.

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COMMITMENTS - Summary of Commitments Maturities (Details)	Dec. 31, 2017 CAD
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Long term debt	CAD 610.5
Interest payments on long term debt	158.0
Operating leases	64.0
Pipeline transportation	222.3
Other	18.5
Commitments	1,073.3
2018
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Long term debt	0.0
Interest payments on long term debt	39.6
Operating leases	7.1
Pipeline transportation	27.8
Other	14.0
Commitments	88.5
2019
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Long term debt	164.9
Interest payments on long term debt	33.8
Operating leases	9.3
Pipeline transportation	28.2
Other	0.3
Commitments	236.5
2020
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Long term debt	118.3
Interest payments on long term debt	23.7
Operating leases	9.7
Pipeline transportation	29.7
Other	0.3
Commitments	181.7
2021
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Long term debt	0.0
Interest payments on long term debt	20.2
Operating leases	9.6
Pipeline transportation	30.1
Other	0.2
Commitments	60.1
2022
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Long term debt	127.6
Interest payments on long term debt	18.6
Operating leases	9.6
Pipeline transportation	30.2
Other	0.2
Commitments	186.2
Thereafter
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Long term debt	199.7
Interest payments on long term debt	22.1
Operating leases	18.7
Pipeline transportation	76.3
Other	3.5
Commitments	CAD 320.3

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FOREIGN EXCHANGE (GAIN) LOSS - Summary of Foreign Exchange (Gain) Loss (Details) CAD in Millions	12 Months Ended
	Dec. 31, 2017 CAD CAD / $		Dec. 31, 2016 CAD CAD / $
Effects Of Changes In Foreign Exchange Rates [Abstract]
Currency exchange rate (Cdn$1 U.S.$) at beginning of year | CAD / $	0.74		0.72
Currency exchange rate (Cdn$1 U.S.$) at year end | CAD / $	0.80		0.74
Disclosure Of Foreign Currency Gains (Losses) [Line Items]
Net unrealized foreign exchange (gain) loss	CAD (51.4)	[1]	CAD 33.4
Net realized foreign exchange (gain) loss	38.4	[1]	(46.5)
Foreign exchange risk management contracts
Disclosure Of Foreign Currency Gains (Losses) [Line Items]
Net unrealized foreign exchange (gain) loss	14.2		86.0
US foreign exchange risk management contracts
Disclosure Of Foreign Currency Gains (Losses) [Line Items]
Net unrealized foreign exchange (gain) loss	15.0		80.6
UK foreign exchange risk management contracts
Disclosure Of Foreign Currency Gains (Losses) [Line Items]
Net unrealized foreign exchange (gain) loss	(0.8)		5.4
Foreign currency swap contract
Disclosure Of Foreign Currency Gains (Losses) [Line Items]
Net realized foreign exchange (gain) loss	37.6
Foreign denominated debt
Disclosure Of Foreign Currency Gains (Losses) [Line Items]
Net unrealized foreign exchange (gain) loss	(65.6)		(52.6)
US dollar denominated debt
Disclosure Of Foreign Currency Gains (Losses) [Line Items]
Net unrealized foreign exchange (gain) loss	(66.1)		(46.8)
U.K. pound sterling denominated term notes
Disclosure Of Foreign Currency Gains (Losses) [Line Items]
Net unrealized foreign exchange (gain) loss	CAD 0.5		CAD (5.8)

[1] See Notes 2 and 14.

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SUPPLEMENTARY DISCLOSURES - Total Employee Compensation Costs (Details) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Disclosure Of Employee Compensation Expenses [Line Items]
Total employee compensation costs	CAD 65.6	CAD 94.3
Operating
Disclosure Of Employee Compensation Expenses [Line Items]
Total employee compensation costs	30.1	44.1
General and administrative
Disclosure Of Employee Compensation Expenses [Line Items]
Total employee compensation costs	CAD 35.5	CAD 50.2

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SUPPLEMENTARY DISCLOSURES - Narrative (Details) - employee	Dec. 31, 2017	Dec. 31, 2016
Directors
Disclosure of transactions between related parties [line items]
Number of employees	6	6
Officers
Disclosure of transactions between related parties [line items]
Number of employees	7	7

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SUPPLEMENTARY DISCLOSURES - Key Management Personnel Costs (Details) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Disclosure of amounts incurred by entity for provision of key management personnel services provided by separate management entities [line items]
Wages & benefits paid	CAD 2.8	CAD 3.4
Bonus and other compensation paid	2.7	0.7
Share based compensation expense	1.3	7.6
Severance paid	0.0	0.6
Total	6.8	12.3
Directors
Disclosure of amounts incurred by entity for provision of key management personnel services provided by separate management entities [line items]
Wages & benefits paid	0.6	0.6
Bonus and other compensation paid	0.0	0.0
Share based compensation expense	(0.6)	2.3
Severance paid	0.0	0.0
Total	0.0	2.9
Officers
Disclosure of amounts incurred by entity for provision of key management personnel services provided by separate management entities [line items]
Wages & benefits paid	2.2	2.8
Bonus and other compensation paid	2.7	0.7
Share based compensation expense	1.9	5.3
Severance paid	0.0	0.6
Total	CAD 6.8	CAD 9.4