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, 2018 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
None	None

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

Common Shares

(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 556,117,090 Common Shares, of no par value, outstanding as of December 31, 2018.

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 has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the Registrant was required to submit such files).

Yes þ No o

Indicate by check mark whether the Registrant is an emerging growth company as defined in Rule 12b-2 of the Securities Exchange Act of 1934, as amended (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, 2018, 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, 2018, 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, 2018, 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, 2018, 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 Chandra A. Henry.

AUDIT COMMITTEE FINANCIAL EXPERT

The board of directors of the Registrant has determined that each of A. Terence Poole and Chandra A. Henry, 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 Mr. Poole and Mrs. Henry 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 Mr. Poole and Mrs. Henry 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.

On November 7, 2018, the Registrant updated its Code of Business Conduct and Ethics to harmonize the code with the requirements set out in the amendments to the Alberta Occupational Health and Safety Act under Bill 30 and to amend its whistleblower procedure.

The description above is qualified in its entirety by reference to the amended Code of Business Conduct and Ethics which is attached hereto as Exhibit 99.11 and incorporated herein by reference.

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 “External Auditor Fees and Services” at page 67 of the Registrant’s Annual Information Form for the fiscal year ended December 31, 2018, 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 67 of the Registrant’s Annual Information Form for the fiscal year ended December 31, 2018, 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 68 of the Registrant’s Annual Information Form for the fiscal year ended December 31, 2018, 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 in tables under the heading “Commitments and Contractual Obligations” at page 27 of the Registrant’s Management’s Discussion and Analysis for the fiscal year ended December 31, 2018, 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.

EXHIBIT INDEX

Exhibit	Description
99.1	Pengrowth Energy Corporation Annual Information Form for the year ended December 31, 2018
99.2	Management’s Discussion and Analysis for the fiscal year ended December 31, 2018
99.3	Consolidated Financial Statements of Pengrowth Energy Corporation for the fiscal year ended December 31, 2018, 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
99.11	Pengrowth Energy Corporation Code of Business Conduct and Ethics dated November 7, 2018
101	Interactive Data File

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: March 5, 2019	PENGROWTH ENERGY CORPORATION
	By:	/s/ Peter D. Sametz
		Name: Peter D. Sametz
		Title: President and Chief Executive Officer

EX-99.1

Pengrowth Energy Corporation

2018 Annual Information Form

March 5, 2019

nTABLE OF CONTENTS

GLOSSARY OF TERMS AND ABBREVIATIONS	1
CONVERSION	5
ADVISORIES	5
PENGROWTH ENERGY CORPORATION	5
Introduction	8
General Development of the Business	8
DESCRIPTION OF OUR BUSINESS	10
PRINCIPAL PRODUCING PROPERTIES	12
STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION	13
Additional Information Relating to Reserves Data	22
Significant Factors or Uncertainties Affecting Reserves Data	23
Future Development Costs	24
Finding, Development and Acquisition Costs	24
Recycle Ratio	27
Reserve Life Index	27
Reserve Replacement	27
Other Oil and Gas Information	28
Significant Factors or Uncertainties Relevant to Properties with no Attributed Reserves	28
Forward Contracts	29
Tax Horizon	29
Costs Incurred	29
Exploration and Development Activities	29
Production Estimates	30
Production History (Netback)	31
INDUSTRY CONDITIONS	31
RISK FACTORS	42
DESCRIPTION OF CAPITAL STRUCTURE	60
MARKET FOR SECURITIES	61
DIRECTORS AND OFFICERS	63
Corporate Cease Trade Orders, Bankruptcies, Personal Bankruptcies, Penalties or Sanctions	63
AUDIT AND RISK COMMITTEE	65
External Auditor Fees and Services	66
Pre-approval Policies and Procedures	66
CONFLICTS OF INTEREST	66
LEGAL PROCEEDINGS	67
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS	67
INTERESTS OF EXPERTS	67
AUDITORS, TRANSFER AGENT AND REGISTRAR	67
MATERIAL CONTRACTS	67
OFF-BALANCE SHEET ARRANGEMENTS	67
CORPORATE GOVERNANCE PRACTICES	68
ADDITIONAL INFORMATION	68
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, 2018

GLOSSARY OF TERMS AND ABBREVIATIONS

The following terms in this Annual Information Form ("AIF") have the meanings set forth below:

"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;

“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;

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

"Audit Committee" means the audit and risk committee of the Board of Directors;

“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 50% confidence level;

“bitumen” means a naturally occurring solid or semi-solid hydrocarbon: (a) consisting mainly of heavier hydrocarbons, with a viscosity greater than 10,000 mPa-s or 10,000 cP measured 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;

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

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

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

"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;

"Common Shares" means our common shares;

“Company Interest” is equal to our gross interest plus our 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;

“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;

"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;

"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;

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"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, in Calgary, Alberta;

"GLJ Report" refers to the reserve report prepared by GLJ dated February 27, 2019 with an effective date of December 31, 2018;

"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;

"Koch" means Koch Oil Sands Operating ULC;

"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 90% 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" or "NGL" 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;

“NI 51-101” means National Instrument 51-101-Standards of Disclosure for Oil and Gas Activities of the Canadian Securities Administrators;

“NI 51-102” means National Instrument 51 102 -Continuous Disclosure Obligations of the Canadian Securities Administrators;

“NI 52-110” means National Instrument 52-110 -Audit Committees of the Canadian Securities Administrators;

"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;

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

"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;

"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;

"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.

"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$" or "$" refers to Canadian dollars;

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"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;

"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;

"km" means kilometres;

"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" or "United States" refers to the United States of America;

"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.

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CONVERSION

In this AIF, measurements are given in standard imperial or metric units. 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

ADVISORIES

The information in this AIF is stated as at December 31, 2018 unless otherwise indicated. For additional information and details, readers are referred to the audited consolidated financial statements for the year ended December 31, 2018 and notes that follow, as well as the accompanying annual Management’s Discussion and Analysis, which are available on SEDAR at www.sedar.com.

CONVERSION OF NATURAL GAS TO BARRELS OF OIL EQUIVALENT

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. 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.

PRESENTATION OF OUR FINANCIAL INFORMATION

Financial information in this AIF 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 AIF 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 AIF in accordance with Canadian disclosure requirements, we have disclosed in this AIF 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 AIF 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 - Other Risks - 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.

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION AND STATEMENTS

This AIF contains forward-looking information and statements (collectively, “forward-looking statements”) within the meaning of applicable Canadian and US securities laws and other information based on Pengrowth’s current expectations, estimates, projections and assumptions that were made by the Corporation in light of information available at the time the statement was made and considering Pengrowth’s experience and historical trends. Forward-looking statements are 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 are based on our current expectations 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 interest and foreign exchange rates,the cost of expanding our property holdings, our ability to obtain equipment in a timely and cost-effective 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 of the Corporation considers these expectations and assumptions to be reasonable based on information currently available to it, they may prove to be incorrect. Many factors could cause the Corporation’s actual results to differ materially from those expressed or implied in any forward-looking statements made by, or on behalf of, the Corporation.

In particular, forward-looking statements included in this AIF include, but are not limited to, statements with respect to:

• Pengrowth’s strategy, business plans and goals, and expectations about the cost and development of certain projects;

• performance of the Corporation’s assets, including production volumes and the costs of planned capital expenditures;

• Pengrowth’s capital expenditure and investment programs and the timing and results therefrom;

• the size of, and future net revenues from, oil and gas reserves;

• the performance characteristics of the Corporation’s oil and gas properties;

• supply and demand for oil and natural gas;

• drilling inventory, drilling plans and timing of drilling, completion and tie-in of wells;

• results of various projects of the Corporation;

• results of operations;

• production, future costs, reserves and production estimates;

• timing of development of undeveloped reserves;

• access to and costs relating to use of facilities and infrastructure;

• financial condition, access to capital and overall financial strategy;

• financial and business prospects and financial outlook;

• treatment under governmental regulatory regimes and tax laws;

• estimates of future net revenues, commodity price forecasts, currency, exchange and interest rate expectations and production estimates;

• the existence, operation and strategy of the Corporation’s commodity price risk management program;

• oil and natural gas production levels and various factors that may impact production levels;

• development activities and costs anticipated to occur or be incurred in 2019, including those identified as Future Development Costs;

• estimated abandonment and reclamations costs and asset retirement obligations;

• anticipated effects of and responses to environmental laws, including climate change laws and estimated compliance costs;

• expectations about changes to laws and the impact thereof;

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• the Corporation’s business, disposition and acquisition strategy, the criteria to be considered in connection therewith, and the benefits to be derived therefrom;

• future development and growth prospects;

• expectations about royalties, operating costs, general administrative costs, costs of services and other costs and expenses;

• ability to meet current and future obligations;

• expectations about income taxes and their impact on Pengrowth, including the tax horizon and taxability of the Corporation;

• weighting of production between different commodities;

• the ability to obtain equipment, services and supplies in a timely manner to carry out our activities; and

• the ability to market oil and natural gas successfully to current and new customers.

Statements relating to “reserves” or “resources” are by their nature 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. The recovery and reserve estimates of the Corporation’s reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. As a consequence, actual results may differ materially from those anticipated in the forward-looking statements.

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 commodity prices; production and development costs and capital expenditures; changes in operating costs; operational risks and uncertainties associated with oil and gas activities, including unexpected formations or pressures, premature declines, fires, blow-outs, equipment failures and other accidents; adverse weather conditions which could disrupt output or impact drilling programs; the accuracy and imprecision of reserve estimates and estimates of recoverable quantities of oil, natural gas and NGLs; unforeseen operating problems; pipeline or delivery capacity and 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 and demand of our products; defaults by third party operators; unforeseen title defects; fluctuations in foreign currency, exchange rates and interest rates; inadequate insurance coverage; counterparty risk; compliance with environmental laws and regulations; actions by governmental authorities, including the imposition or reassessment of, or changes to, taxes, fees, royalties, duties and other government-imposed compliance costs; changes to laws and government policies that could impact the Corporation’s business, including environmental (including climate change and GHG emissions legislation), royalty and tax laws and policies; our ability to access external sources of debt and equity capital; our ability to complete projects on time and on budget; competitive actions from other oil and gas companies or from companies that provide alternative sources of energy; risks and uncertainties associated with obtaining regulatory and stakeholder approval for our operations and exploration and development activities; risks associated with increased activism and public opposition to fossil fuels; risks relating to litigation; and the impact of technology and risks associated with developing and implementing new technologies. Further information regarding these factors may be found under the heading “Risk Factors” in this AIF, under the heading “Business Risks” in our Management’s Discussion and Analysis for the year ended December 31, 2018, and in our most recent consolidated financial statements and Form 40-F on file with Canadian securities commissions at www.sedar.com and the SEC at www.sec.gov. Readers are also referred to the risk factors and assumptions described in other documents that Pengrowth files from time to time with securities regulatory authorities, copies of which are available without charge from the Corporation or at www.sedar.com.

The foregoing list of important 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 AIF 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 AIF are expressly qualified by this cautionary statement.

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nPENGROWTH ENERGY CORPORATION

INTRODUCTION

Pengrowth is a conventional resource developer of Canadian oil and natural gas assets. We are currently focused on growing bitumen production from the Lloydminster formation at our Lindbergh thermal oil project through steam assisted gravity drainage ("SAGD").

Pengrowth’s 100% owned Groundbirch property in the Montney fairway encompasses 19 sections of land. This project fulfills the Lindbergh project’s natural gas needs.

CORPORATE STRUCTURE

The Corporation was 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.

As of December 31, 2018 and the date hereof, the Corporation has no subsidiaries.

GENERAL DEVELOPMENT OF THE BUSINESS

Three Year History

A detailed description on the significant developments of the business of the Corporation over the last three completed financial years is set out below.

Financial Year ended December 31, 2018

On November 8, 2018 Pengrowth announced its 2019 Guidance and a Capital Spending Plan of $45 million with the vast majority of this capital allocated to Lindbergh.

On November 8, 2018 Pengrowth announced a 2% increase in its total Proved Reserves, and a 1% increase in its Proved Plus Probable Reserves.

On October 1, 2018, Chandra Henry was appointed to Pengrowth's Board of Directors.

On June 26, 2018 Pengrowth announced its Multi-Year Development Plan which shifted its growth strategy from a large phase 2 build-out to a more incremental approach to make it possible to grow within cash flow. Pengrowth stated that it expects to grow production at Lindbergh to 35,000 bbl per day by 2023. To achieve this, Pengrowth will seek a third party to operate a co-generation facility at Lindbergh to provide both the electricity and steam required for growth. Low-cost proven technologies such as solvents and gases will also be deployed to enhance steam efficiency.

On June 4, 2018 Pengrowth common shares started trading on the OTCQX under the symbol PGHEF.

On June 1, 2018, Pengrowth received its de-listing notification from the New York Stock Exchange ("NYSE").

On April 18, 2018, we announced that we would not take any additional action to come into compliance with NYSE's listing standards but continued to trade on NYSE until the end of the compliance cure period which expired June 1, 2018.

On March 14, 2018, Mr. Peter Sametz succeeded Mr. Derek Evans as President and Chief Executive Officer.

On February 28, 2018, we announced that, as at December 31, 2017, Pengrowth had Total Proved Reserves of 192.7 MMboe and Total Proved plus Probable Reserves of 446.6 MMboe. 99% of Pengrowth’s Total Proved plus Probable Reserves at December 31, 2017 were attributable to Lindbergh and Groundbirch reflecting the Company's realignment around these two core assets.

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 reflected our plan to spend $65 million in 2018.

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Financial Year ended December 31, 2017

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 1, 2017, we received notice from the NYSE that our Common Shares, trading under the symbol PGH, 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 Term 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 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% 2008 senior notes, all $15 million of our outstanding 6.61% 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 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% 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 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 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% 2007 senior notes.

On March 31, 2017, we redeemed all $126.6 million of our 6.25% 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 4% non-convertible gross overriding royalty on our Lindbergh assets and an interest in certain proprietary seismic for aggregate cash consideration of $250 million. The 4% overriding royalty would represent a 10.7% decrease (at a 10% discount rate) in the December 31, 2016 P+P net present value of Future Net Revenue for Lindbergh.

Financial Year ended December 31, 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 October 6, 2016, we announced a 21% increase in our P+P reserves at our Lindbergh thermal project and a corresponding 63% 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.

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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 February 25, 2016, we announced the launch of a normal course issuer bid for up to 10% of our 6.25% 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% 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.

SIGNIFICANT ACQUISITIONS DURING 2018

We did not complete any significant acquisitions during the most recently completed financial year for which disclosure is required under Part 8 of NI 51-102 Continuous Disclosure Obligations.

DESCRIPTION OF OUR BUSINESS

General

Pengrowth is a conventional resource developer of Canadian oil and natural gas assets. We are currently focused on growing bitumen production from the Lloydminster formation at our Lindbergh thermal oil project through steam assisted gravity drainage ("SAGD"). The project encompasses 32.5 sections of land with regulatory approval for 40,000 bbl/d. As one of the southernmost SAGD projects in Alberta, Lindbergh has natural advantages in terms of location and oil quality that allows flexibility in accessing markets.

Pengrowth’s 100% owned Groundbirch property in the Montney fairway encompasses 19 sections of land. This project fulfills the Lindbergh project’s natural gas needs. Dry natural gas from the Montney formation is produced using horizontal wells and multi-stage fracture technology with drilling potential of up to 360 unrisked net locations. The Corporation operates a 30 MMcf/d facility to process and deliver natural gas onto major pipelines.

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. A key factor affecting our finances is commodity prices over which we have no control.

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 2019, we have established a $45 million capital spending level that is focused on adding production volumes from our two, core 100% owned assets at Lindbergh and Groundbirch. However, until Pengrowth refinances its term debt and renews its credit facility, capital spending will not exceed $21 million.

Specialized Skill and Knowledge

Conducting operations in the oil and natural gas industry require professionals with skills and knowledge in diverse fields of expertise. In the course of our exploration and production activities, we utilize the expertise of geophysicists, geologists and engineers. We face the challenge of attracting and retaining sufficient employees to meet our needs. See “Risk Factors”.

Competitive Conditions

There is strong competition relating to all aspects of the oil and natural gas industry. We actively compete for capital, skilled personnel, undeveloped land, reserve acquisitions, access to equipment, processing facilities and pipeline and refining capacity, and in all other aspects of our operations, with a substantial number of other organizations, many of whom may have greater technical and financial resources than us. Some of those organizations not only explore for, develop, and produce oil and natural gas, but also carry-on refining operations and market petroleum and other products on a world-wide basis and, as such, have greater and more diverse resources on which to draw.

Our larger competitors may be able to better absorb the impact of changes to applicable laws and regulations and may be able to more easily handle longer periods of volatile oil and gas prices. Competitive conditions may be significantly affected by factors beyond our

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control, including international political stability, domestic political stability, overall levels of supply and demand for oil and gas, market prices for oil and natural gas and the markets for synthetic fuels and alternative energy sources.

Cyclical and Seasonal Factors

Our operational results and financial condition are highly dependent on the market price of oil and natural gas. Prices for these commodities have fluctuated widely during recent years and are determined by supply and demand factors, weather, general economic conditions and political environments, as well as conditions in other oil- and natural gas-producing regions. The prices for oil and natural gas are likely to continue to be volatile, and depressed or declining prices for these commodities could have an adverse effect on our financial condition and operations. We actively seek to mitigate such price risks through various risk management strategies including hedging the price of WTI as well as the use of fixed differential apportionment protected physical sales contracts.

The exploration and development of oil and natural gas reserves is dependent on access to areas where production is to be conducted. Access is affected by seasonal weather conditions, including freeze-up and break-up.

Health, Safety and Environmental Protection

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.

We believe that we meet all existing environmental standards and regulations and sufficient amounts are included in our capital expenditure budget to continue to meet current environmental protection requirements.

It is expected that we will incur abandonment and reclamation costs as existing oil and gas properties are abandoned. In 2018, expenditures for normal compliance with environmental regulations as well as expenditures for above-normal compliance were not material to the Corporation.

Code of Ethics

In addition to the health, safety and environmental protection policies, 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 directors, officers, employees, consultants and independent contractors. Topics addressed in the Code of Ethics include conflicts of interest, fraud and corruption, confidential information and compliance with corporate policies, among other matters. All directors, officers, employees, consultants and contractors are required to review and accept the Code of Ethics annually.

During the year ended December 31, 2018, Pengrowth did not grant any waivers (including implicit waivers) from the Code of Ethics.

The Code of Ethics is available for viewing on our website www.pengrowth.com under the heading "Corporate Governance - 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 - 3rd Avenue S.W., Calgary, Alberta, Canada, T2P 0B4.

Employees

As at December 31, 2018, we had 104 permanent employees.

Revenue Sources

For the year ended December 31, 2018, the sale of oil and natural gas accounted for 100% of revenue before royalties. For the year ended December 31, 2017, the sale of oil and natural gas accounted for 100% of revenue before royalties.

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PRINCIPAL PRODUCING PROPERTIES AND OPERATIONS

The following table summarizes our principal producing properties as of December 31, 2018 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, 2018. The table also contains our average daily production of oil, bitumen, natural gas, shale gas and NGL for the year ended December 31, 2018.

Summary of Company Interest at December 31, 2018⁽¹⁾
(Forecast Prices and Costs)⁽²⁾ 

	P+P	Remaining	P+P Reserve	P+P Value Before Tax	2018 Oil	2018 Bitumen	2018 Gas	2018 Shale Gas	2018 NGL	2018 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	311,395	30	48	2,420	-	16,325	-	-	-	16,325
Groundbirch	131,971	50	118	322	-	-	-	17,458	-	2,910
Subtotal	443,366	50	56	2,742	-	16,325	-	17,458	-	19,234
Remainder(5)	3,202	-	-	18	675	-	11,258	-	239	2,790
Total	446,568	50	56	2,760	675	16,325	11,258	17,458	239	22,025

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 13 other properties of which reserves were assigned.

The following is a narrative description of our material oil and gas properties and operations as at December 31, 2018.

Lindbergh

The Lindbergh thermal property is located approximately 420km north east of Calgary, Alberta and 50km south of Bonnyville, Alberta. We have a 100% 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). When discussing contingent resources for Lindbergh, we include our 100% owned Muriel Lake property located approximately 8km to the north east of the Lindbergh lease which is comprised of an additional 6,400 net acres (10 sections). The Corporation has drilled and evaluated 226 gross wells, including evaluation/observation wells, SAGD well pairs and infill 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 12,500 bbl/d of bitumen design rate central processing facility ("CPF"), was constructed commencing in 2013, with first production in 2015. 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 and in August 2017 an EPEA scheme amendment was approved for expansion to 40,000 bbl/d of bitumen at Lindbergh. The Phase 1a expansion project was initiated in 2017 and was anticipated to increase produced bitumen rates to in excess of 18,000 bbl/d peak production by the end of 2018. Phase 1a included 10 new well pairs and 10 infill wells. In 2017, all 10 well pairs and two infill wells were drilled, with 7 of the 10 well pairs and the 2 infill wells being brought on stream, as well. Phase 1a was completed in 2018 with the remaining 3 well pairs being brought on stream, as well as, drilling 8 infill wells and bringing them on stream. As of December 31, 2018, the Phase 1a expansion was completed contributing to the December 31, 2018 produced bitumen exit rate of 19,120 bbl/d.

Over the life of the current Phase 1 commercial project, a total of 158 well pairs (including the 32 existing well pairs) and 35 infill wells (including 10 existing infill wells) are expected to be drilled from several pad sites within the project area, recovering Proved Reserves of 159 MMbbl of bitumen remaining as of December 31, 2018. The production life for each individual well pair is expected to be eight to nine years.

On June 26, 2018, Pengrowth announced its Multi-Year Development Plan which shifted its growth strategy from a large phase 2 build-out to a more incremental approach to make it possible to grow within cash flow. Pengrowth expects to grow production at Lindbergh to 35,000 bbl/d by 2023. To achieve this, Pengrowth will seek a third party to operate a co-generation facility at Lindbergh to provide both the electricity and steam required for growth. Low-cost proven technologies such as solvents and gases will also be deployed to enhance steam efficiency.

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With expansion to 35,000 bbl/day of capacity, the project is expected to recover 311 MMbbl of Total Proved Plus Probable Reserves as of December 31, 2018, from a total of 266 well pairs, including the 32 existing well pairs, and 267 infill wells, including the 10 existing infill wells. Given the strong results to-date, additional productivity is thought to be possible and anticipated from the existing infrastructure and from future expansion opportunities.

As mentioned above under "General Development of the Business - Three Year History" , in January 2017, we sold a 4% 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 AIF.

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 50km south east of Bonnyville, Alberta. The proposed project is designed for an annual average production rate of 12,500 bbl/d of bitumen. The Selina SAGD project is a 50/50 joint venture between the Corporation and Koch. Koch is the operator of this project as of the date of this AIF. Management has been advised that the AER approval process for these applications will take at least 24 months from the date of submission.

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

Groundbirch

Our Groundbirch property is located approximately 40km south west of Fort St. John, British Columbia and covers an area of 12,536 gross/net acres. We have a 100% Working Interest in these lands. At Groundbirch, we currently have 22 producing wells producing approximately 24 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 2018, Pengrowth stimulated three of four horizontal Montney wells at Groundbirch that were drilled in 2017. The fourth well was partially stimulated in 2018 and the final stimulation of remaining stages was executed in January 2019. 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. Gas plant sales gas pipeline tie-in to TransCanada Pipeline's ("TCPL's") NOVA Gas Transmission Ltd. System ("NGTL system") was completed in 2018 with sales gas volume flowing onto TCPL's NGTL system in Alberta.

With facility expansion to 60 MMcf/d of gas throughput, Groundbirch will be capable of meeting the fuel gas needs of our Lindbergh project through to 35,000 bbl/d of bitumen production.

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

STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMAITON

Relevant Dates

This Statement of Reserves Data and Other Oil and Gas Information is dated February 27, 2019 with an effective date of December 31, 2018 unless indicated otherwise. Reserves evaluations have not been updated since the effective date and, thus, do not reflect changes in Pengrowth’s reserves since that date. The preparation date of the information is January 15, 2019.

PENGROWTH ENERGY CORPORATION | 2018 ANNUAL INFORMATION FORM     13

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, 2018 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, 2018 and the preparation date is January 15, 2019 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 AIF. All of our reserves are in Canada in the provinces of Alberta, British Columbia, Saskatchewan and Nova Scotia. In certain instances in this AIF, 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, 2018 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 AIF reflect the royalty programs in-place on December 31, 2018.

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 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 AIF as Appendices B and C, respectively.

PENGROWTH ENERGY CORPORATION | 2018 ANNUAL INFORMATION FORM     14

Reserves Data (Forecast Prices and Costs)

Summary of Oil and Gas Reserves as of December 31, 2018
(Forecast Prices and Costs)⁽¹⁾ 

	Light Crude Oil and Medium Crude Oil		Heavy Crude Oil		Bitumen		Natural Gas Liquids
	Company Gross	Company Net	Company Gross	Company Net	Company Gross	Company Net	Company Gross	Company Net
Reserves Category	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)
Proved Reserves
Proved Developed Producing	561	502	-	-	19,609	17,903	10	8
Proved Developed Non-Producing	600	544	-	-	0	0	53	43
Proved Undeveloped	0	0	-	-	139,544	103,067	0	0
Total Proved Reserves	1,161	1,046	-	-	159,153	120,970	63	51
Probable Reserves	313	275	-	-	152,242	109,771	22	18
Total Proved Plus Probable Reserves	1,474	1,321	-	-	311,395	230,741	86	69

	Conventional Natural Gas		Shale Gas		Coal Bed Methane		Total Oil Equivalent Basis(2)
	Company Gross	Company Net	Company Gross	Company Net	Company Gross	Company Net	Company Gross	Company Net
Reserves Category	(MMcf)	(MMcf)	(MMcf)	(MMcf)	(MMcf)	(MMcf)	(Mboe)	(Mboe)
Proved Reserves
Proved Developed Producing	1,049	951	39,497	37,119	1,717	1,628	27,224	25,030
Proved Developed Non-Producing	2,924	2,775	6,304	5,788	625	573	2,295	2,110
Proved Undeveloped	0	0	147,198	127,506	250	237	164,119	124,357
Total Proved Reserves	3,972	3,726	192,998	170,413	2,592	2,437	193,638	151,496
Probable Reserves	1,177	1,085	598,826	499,454	1,752	1,668	252,869	193,765
Total Proved Plus Probable Reserves	5,149	4,812	791,824	669,867	4,344	4,105	446,508	345,261

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.

PENGROWTH ENERGY CORPORATION | 2018 ANNUAL INFORMATION FORM     15

Summary of Net Present Value of Future Net Revenue as of December 31, 2018
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	498		457		422		391		364		16.85	2.81
Proved Developed Non-Producing	26		20		16		13		11		7.46	1.24
Proved Undeveloped	3,832		1,954		1,112		690		456		8.95	1.49
Total Proved Reserves	4,356		2,431		1,550		1,094		832		10.23	1.71
Probable Reserves	5,377		2,387		1,210		675		402		6.25	1.04
Total Proved Plus Probable Reserves	9,734		4,819		2,760		1,769		1,234		7.99	1.33

	After Income Taxes Discounted at (%/year)(4) - $MM
Reserves Category	0	%	5	%	10	%	15	%	20	%
Proved Reserves
Proved Developed Producing	498		457		422		391		364
Proved Developed Non-Producing	26		20		16		13		11
Proved Undeveloped	3,084		1,688		1,004		639		429
Total Proved Reserves	3,608		2,165		1,441		1,043		804
Probable Reserves	3,576		1,770		940		532		316
Total Proved Plus Probable Reserves	7,184		3,935		2,381		1,574		1,120

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 "Statement of Reserves Data and Other Oil & Gas Information - 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, 2018
(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	12,627	3,069	3,042	1,870	290	4,356	748	3,608
Total Proved Plus Probable	27,422	6,956	5,532	4,635	565	9,734	2,550	7,184

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 "Statement of Reserves Data and Other Oil & Gas Information – Significant Factors or Uncertainties Affecting Reserves Data - Additional Information Concerning Abandonment & Reclamation Costs".

PENGROWTH ENERGY CORPORATION | 2018 ANNUAL INFORMATION FORM     16

Net Present Value of Future Net Revenue By Product Type as of December 31, 2018
(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)	23	20.10	3.35
	Bitumen(2)	1,419	11.73	1.96
	Conventional Natural Gas (including by-products but excluding solution gas from oil wells)(3)	-4	-6.86	-1.14
	Shale Gas(3)	112	3.95	0.66
	Coal Bed Methane(3)	-1	-1.84	-0.31
	Total	1,550	10.23	1.71
Total Proved Plus Probable	Light Crude Oil and Medium Crude Oil (including solution gas and other by-products)(2)	27	18.57	3.10
	Bitumen (2)	2,363	10.24	1.71
	Conventional Natural Gas (including by-products but excluding solution gas from oil wells)(3)	-3	-4.62	-0.77
	Shale Gas(3)	373	3.34	0.56
	Coal Bed Methane(3)	0	-0.26	-0.04
	Total	2,760	7.99	1.33

Notes:

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

(2) Including solution gas and other by-products.

(3) Including by-products but excluding solution gas.

(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 | 2018 ANNUAL INFORMATION FORM     17

Reserves Data (Constant Prices and Costs)

Summary of Oil and Gas Reserves as of December 31, 2018
(Constant Prices and Costs)⁽¹⁾ 

	Light Crude Oil and Medium Crude Oil		Heavy Crude Oil		Bitumen		Natural Gas Liquids
	Company Gross	Company Net	Company Gross	Company Net	Company Gross	Company Net	Company Gross	Company Net
Reserves Category	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)
Proved Reserves
Proved Developed Producing	504	453	-	-	18,863	17,148	10	8
Proved Developed Non-Producing	424	382	-	-	—	—	10	8
Proved Undeveloped	—	—	-	-	138,715	119,521	—	—
Total Proved Reserves	929	835	-	-	157,578	136,669	19	16
Probable Reserves	353	313	-	-	153,589	129,000	5	4
Total Proved Plus Probable Reserves	1,282	1,148	-	-	311,167	265,669	24	20

	Conventional Natural Gas		Shale Gas		Coal Bed Methane		Total Oil Equivalent Basis(2)
	Company Gross	Company Net	Company Gross	Company Net	Company Gross	Company Net	Company Gross	Company Net
Reserves Category	(MMcf)	(MMcf)	(MMcf)	(MMcf)	(MMcf)	(MMcf)	(Mboe)	(Mboe)
Proved Reserves
Proved Developed Producing	1,039	947	31,303	30,364	415	397	24,837	22,893
Proved Developed Non-Producing	788	817	6,017	5,836	—	—	1,568	1,499
Proved Undeveloped	0	0	119,086	115,513	0	0	158,562	138,773
Total Proved Reserves	1,826	1,764	156,405	151,713	415	397	184,967	163,165
Probable Reserves	368	362	597,513	579,578	6	6	253,595	225,975
Total Proved Plus Probable Reserves	2,195	2,126	753,919	731,292	421	402	438,562	389,141

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.

Summary of Net Present Value of Future Net Revenue as of December 31, 2018
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	272		266		257		247		236		11.24	1.87
Proved Developed Non-Producing	11		9		8		7		6		5.29	0.88
Proved Undeveloped	1,018		533		295		166		91		2.13	0.35
Total Proved Reserves	1,300		809		560		420		334		3.43	0.57
Probable Reserves	1,168		452		166		40		(19	)	0.73	0.12
Total Proved Plus Probable Reserves	2,468		1,261		726		460		315		1.87	0.31

	After Income Taxes Discounted at (%/year)(4)  - $MM
Reserves Category	0	%	5	%	10	%	15	%	20	%
Proved Reserves
Proved Developed Producing	272		266		257		247		236
Proved Developed Non-Producing	11		9		8		7		6
Proved Undeveloped	1,018		533		295		166		91
Total Proved Reserves	1,300		809		560		420		334
Probable Reserves	873		367		136		26		(27	)
Total Proved Plus Probable Reserves	2,173		1,176		696		446		307

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 "Statement of Reserves Data and Other Oil & Gas Information – Disclosure of Reserves Data" for additional descriptions of the assumptions made in calculating the after-tax values.

PENGROWTH ENERGY CORPORATION | 2018 ANNUAL INFORMATION FORM     18

Total Future Net Revenue (undiscounted) as of December 31, 2018
(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	5,624	705	1,920	1,486	213	1,300	0	1,300
Total Proved Plus Probable	11,628	1,544	3,513	3,726	376	2,468	295	2,173

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 "Statement of Reserves Data and Other Oil & Gas Information – Significant Factors or Uncertainties Affecting Reserves Data - Additional Information Concerning Abandonment & Reclamation Costs".

Net Present Value of Future Net Revenue By Product Type as of December 31, 2018
(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)	16	17.14	2.86
	Bitumen(2)	546	4.00	0.67
	Conventional Natural Gas (including by-products but excluding solution gas from oil wells)(3)	-5	-22.33	-3.72
	Shale Gas(3)	5	0.18	0.03
	Coal Bed Methane(3)	-2	-27.93	-4.65
	Total	560	3.43	0.57
Total Proved Plus Probable	Light Crude Oil and Medium Crude Oil (including solution gas and other by-products)(2)	19	14.68	2.45
	Bitumen (2)	690	2.60	0.43
	Conventional Natural Gas (including by-products but excluding solution gas from oil wells)(3)	-5	-18.25	-3.04
	Shale Gas(3)	24	0.19	0.03
	Coal Bed Methane(3)	-2	-26.04	-4.34
	Total	726	1.87	0.31

Notes:

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

(2) Including solution gas and other by-products.

(3) Including by-products but excluding solution gas.

(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 | 2018 ANNUAL INFORMATION FORM     19

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 2% 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, 2019 price forecast as referred to in the GLJ Report. For historical prices realized during 2018, see "Production History (Netback)" in this AIF.

	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(4)	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$/Cdn$)
2019	56.25	63.33	58.90	47.67	37.65	48.71	1.85	25.33	21.45	67.67	0.0	0.7500
2020	63.00	75.32	70.05	58.44	51.21	51.04	2.29	32.39	37.66	79.22	2.0	0.7700
2021	67.00	79.75	74.16	65.82	59.51	55.05	2.67	36.68	47.85	83.54	2.0	0.7900
2022	70.00	81.48	75.78	67.90	61.62	56.78	2.90	39.11	57.04	85.49	2.0	0.8100
2023	72.50	83.54	77.69	70.12	63.82	59.08	3.14	41.77	58.48	87.80	2.0	0.8200
2024	75.00	86.06	80.04	72.73	66.45	61.32	3.23	43.03	60.24	90.30	2.0	0.8250
2025	77.50	89.09	82.85	75.76	69.48	64.33	3.34	44.55	62.36	93.33	2.0	0.8250
2026	80.41	92.62	86.13	79.28	73.01	67.35	3.41	46.31	64.83	96.86	2.0	0.8250
2027	82.02	94.57	87.95	81.24	74.96	70.45	3.48	47.28	66.20	98.81	2.0	0.8250
2028	83.66	96.56	89.80	83.22	76.95	71.86	3.54	48.28	67.59	100.80	2.0	0.8250
thereafter	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr	2.0	0.8250

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) 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 2018 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$/Cdn$)

2019 and thereafter

65.56

70.07

70.42

50.44

40.76

33.80

1.46

27.77

33.82

79.39

0.0

0.7754

Notes:

(1) FOB Edmonton.

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

PENGROWTH ENERGY CORPORATION | 2018 ANNUAL INFORMATION FORM     20

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, 2018 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, 2017	2,037		672		2,709		-	-	-	163,334		153,724		317,057		141		29		170
Discoveries	0		0		0		-	-	-	0		0		0		0		0		0
Extensions(1)	—		—		—					—		—		—		—		—		—
Infill Drilling(1)	—		—		—		-	-	-	—		—		—		—		—		—
Improved Recovery(1)	—		—		—		-	-	-	—		—		—		—		—		—
Technical Revisions	(46	)	(154	)	(201	)	-	-	-	1,242		(946	)	296		15		(5	)	10
Acquisitions	11		3		14		-	-	-	—		—		—		—		—		—
Dispositions	(612	)	(215	)	(827	)	-	-	-	—		—		—		(6	)	(2	)	(8	)
Economic Factors	15		7		22		-	-	-	536		(536	)	—		—		—		—
Production	(244	)	—		(244	)	-	-	-	(5,958	)	—		(5,958	)	(86	)	—		(86	)
December 31, 2018	1,161		313		1,474		-	-	-	159,153		152,242		311,395		63		22		86

	Conventional Natural Gas						Shale Gas						Coal Bed Methane						Total Oil Equivalent Basis(2)
	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, 2017	6,689		1,262		7,951		152,847		593,606		746,452		3,404		1,943		5,348		192,668		253,894		446,561
Discoveries	0		0		0		0		0		0		0		0		0		0		0		0
Extensions(1)	—		—		—		36,665		12,625		49,289		—		—		—		6,111		2,104		8,215
Infill Drilling(1)	—		—		—		—		—		—		—		—		—		—		—		—
Improved Recovery(1)	—		—		—		—		—		—		—		—		—		—		—		—
Technical Revisions	1,345		82		1,427		9,859		(6,676	)	3,182		48		(167	)	(119	)	3,085		(2,232	)	854
Acquisitions	—		—		—		—		—		—		—		—		—		11		3		14
Dispositions	(416	)	(154	)	(570	)	—		—		—		—		—		—		(687	)	(243	)	(929	)
Economic Factors	7		(13	)	(5	)	—		(728	)	(728	)	(451	)	(25	)	(475	)	478		(657	)	(180	)
Production	(3,653	)	—		(3,653	)	(6,372	)	0		(6,372	)	(409	)	—		(409	)	(8,027	)	—		(8,027	)
December 31, 2018	3,972		1,177		5,149		192,998		598,826		791,824		2,592		1,752		4,344		193,638		252,869		446,508

Notes:

(1)    These change categories correspond to standards set out in the Canadian Oil and Gas Evaluation Handbook. For reporting under NI 51-101, the aggregate reserves additions under Infill Drilling, Improved Recovery and Extensions should be considered in aggregate as "Extensions and Improved Recovery".

(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 | 2018 ANNUAL INFORMATION FORM     21

At December 31, 2018, Company Interest Total Proved Plus Probable Reserves at forecast prices and costs were 446.6 MMboe as compared to 446.6 MMboe reported at year end 2017. The following additional GLJ reserves reconciliation is presented for year end December 31, 2018.

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

	Total Proved Developed Producing Reserves		Total Proved Reserves		Total Proved Plus Probable Reserve
December 31, 2017	33,257		192,718		446,632
Technical (2)	(605	)	3,548		653
Drilling Extensions	2,312		6,111		8,215
Infill Drilling	955		—		—
Acquisition	11		11		14
Sold	(669	)	(677	)	(919	)
Production	(8,027	)	(8,027	)	(8,027	)
December 31, 2018	27,234		193,684		446,568

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.

(2) Technical reserves include changes due to economic factors

Significant factors bearing on the reserves reconciliation were as follows:

• Net reserve changes from drilling activity, improved recovery, technical revisions and economic factors replaced 120% and 110% of 2018 production for Proved Reserves and Total Proved Plus Probable Reserves, respectively.

• New reserve additions for development activity during 2018 amounted to 6.1 MMboe of Proved Reserves and 8.2 MMboe of Proved Plus Probable Reserves. The most significant addition occurred at Groundbirch where reserves were added in both Proved Reserves and Proved Plus Probable Reserves due to wells drilled in late 2017.

• Technical revisions resulted in a net increase of 3.5 MMboe of Proved Reserves and 0.7 MMboe of Total Proved Plus Probable Reserves. This was primarily due to improved economics at Lindbergh due to increased price forecast on oil, and improved development efficiencies at Groundbirch due to drilling longer laterals.

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

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.

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
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
2018	-	-	-	-	-	139,544	-	-	-	-	26,675	147,198	-	250	4,446	164,119

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
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
2018	-	-	-	-	-	144,792	-	-	-	-	24,071	581,956	-	1,093	4,012	241,967

Notes:

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

PENGROWTH ENERGY CORPORATION | 2018 ANNUAL INFORMATION FORM     22

(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 85% of Company Interest Proved Reserves on a BOE basis. Company Interest Proved Undeveloped Reserves of 164.1 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 85% of our Proved Undeveloped Reserves. SAGD well pairs and infill wells are forecast to be drilled until 2046. 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. It is the Company’s intent to develop Lindbergh Proved Undeveloped Reserves by drilling well pairs and infill wells to continually maximize the central processing facility to 20,000 bbl/d bitumen or approximately 52,000 bbl/d steam.

The Groundbirch Montney gas property amounts to approximately 15% of our Proved Undeveloped Reserves. Drilling is forecast by GLJ to occur over the next five years to develop these reserves. It is the Company’s intent to develop Groundbirch Proved Undeveloped Reserves by maximizing the current plant capacity of 30 MMCF/d in the short term, and then as commodity prices improve, expand the gas plant to 60 MMCF/d and continue to develop Proved Undeveloped Reserves to fill the capacity. The main gathering pipeline has been designed to handle 120 MMCF/d in consideration of future development.

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. Company Interest Probable Undeveloped Reserves amount to 242.0 MMboe and represent about 54.4% 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%) and Groundbirch (40%).

As outlined above, the Lindbergh thermal project accounts for 60% of our Proved Undeveloped Reserves. SAGD well pairs and infill wells are forecast to be drilled until 2046. It is the Company’s intent to develop Lindbergh Proved Plus Probable Undeveloped Reserves by expanding the central processing facility in two increments of 7,500 bbl/d bitumen (19,700 bbl/d steam). The Company has plans to have these expansions occur in 2021 and 2025 respectively, pending commodity price improvement. By the end of 2025, the total facility capacity will be 35,000 bbl/d bitumen with 95,000 bbl/d of steaming capacity. The Undeveloped Proved Plus Probable Reserves will be developed by drilling well pairs and infill wells to continually maximize the central processing facility.

The Groundbirch Montney gas property accounts for 40% of our Probable Undeveloped Reserves. Drilling is forecast by GLJ to occur over the next five to ten years to develop these reserves. It is the Company’s intent to develop the Groundbirch Proved Plus Probable Undeveloped Reserves by expanding the gas plant in 2020 to 60 MMCF/d, followed by an expansion to 120 MMCF/d in 2023, assuming strong commodity pricing. It is the Company’s intent to develop the Proved Plus Probable Reserves by drilling wells to continually maximize the plant capacity thereafter.

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 10% per annum) of our total asset retirement obligations, which are inclusive of those costs estimated by GLJ, to be approximately $99 million as at December 31, 2018, based on a total future liability (inflated at 1.5% per annum). Undiscounted and uninflated, the asset retirement obligations are estimated at approximately $405 million. 50% of these costs are expected to be incurred after 2056.

PENGROWTH ENERGY CORPORATION | 2018 ANNUAL INFORMATION FORM     23

The following table summarizes our total current asset retirement obligations as at December 31, 2018:

Asset Retirement Obligations

	2019	2020	2021	Remainder	Total
Total Abandonment, Reclamation, Remediation & Dismantling ($MM)	31	50	15	309	405
Discounted at 10% ($MM)	28	41	11	19	99

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 $156 million ($101 million when discounted at 10%) 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 10% per annum for the years indicated. All of such development costs are estimated to be incurred in Canada.

Future Development Costs ($MM)

							Total
Reserve Category	2019	2020	2021	2022	2023	Remainder	Undiscounted	Discounted at 10%
Proved Reserves (Constant Prices and Costs)	48	190	124	56	105	963	1,486	685
Proved Reserves (Forecast Prices and Costs)	48	194	135	81	114	1,299	1,870	793
Proved & Probable Reserves (Forecast Prices and Costs)	48	258	330	223	193	3,584	4,635	1,841

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

Finding and Development Costs

During 2018, we spent $64.7 million on development, maintenance and optimization, which added 6.1 MMboe of Proved Reserves and 8.2 MMboe of Proved Plus Probable Reserves, excluding revisions. Incorporating the net positive revisions resulted in an overall change of 9.7 MMboe of Proved Reserves and 8.9 MMboe of Total Proved Plus Probable Reserves. The development and optimization expenditures exclude $0.3 million in corporate expenditures for information technology projects and equipment inventory. The largest reserve additions were for reserves additions at Groundbirch offsetting 2017 activity and for infill wells drilled 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.

Acquisitions and Divestitures

During 2018, the Corporation engaged in minor asset divestiture activity with net proceeds of $0.4MM.

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.

PENGROWTH ENERGY CORPORATION | 2018 ANNUAL INFORMATION FORM     24

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

Proved Reserves	2018		2017		2016		2016-2018 Total/Weighted Average
Costs Excluding Future Development Costs
Exploration and Development Capital Expenditures - $MM	64.7		117.4		64.2		246.3
Exploration and Development Reserve Additions including Revisions - MMboe	9.7		27.7		60.7		98.0
Finding and Development Cost - $/BOE	6.70		4.24		1.06		2.51
Net Acquisition (Disposition) Capital - $MM	(0.4	)	(986.7	)	(58.9	)	(1,046.0	)
Net Acquisition (Disposition) Reserve Additions - MMboe	(0.7	)	(106.0	)	(6.1	)	(112.8	)
Net Acquisition Cost - $/BOE	0.62		9.31		9.66		9.28
Total Capital Expenditures including Net Acquisitions (Dispositions) - $MM	64.3		(869.3	)	5.3		(799.7	)
Reserve Additions including Net Acquisitions (Dispositions) - MMboe	9.0		(78.3	)	54.6		(14.7	)
Finding, Development and Acquisition Cost - $/BOE	7.14		11.10		0.10		54.29
Costs Including Future Development Costs
Exploration and Development Capital Expenditures - $MM	64.7		117.4		64.2		246.3
Exploration and Development Change in FDC - $MM	(61.8	)	261.5		423.6		623.3
Exploration and Development Capital including Change in FDC - $MM	3.0		378.8		487.8		869.6
Exploration and Development Reserve Additions including Revisions - MMboe	9.7		27.7		60.7		98.0
Finding and Development Cost - $/BOE	0.31		13.69		8.04		8.87
Net Acquisition (Disposition) Capital - $MM	(0.4	)	(986.7	)	(58.9	)	(1,046.0	)
Net Acquisition (Disposition) FDC - $MM	(0.5	)	(309.2	)	(40.6	)	(350.3	)
Net Acquisition (Disposition) Capital including FDC - $MM	(0.9	)	(1,295.9	)	(99.5	)	(1,396.3	)
Net Acquisition (Disposition) Reserve Additions - MMboe	(0.7	)	(106.0	)	(6.1	)	(112.8	)
Net Acquisition Cost - $/BOE	1.30		12.23		16.31		12.38
Total Capital Expenditures including Net Acquisitions (Dispositions) - $MM	64.3		(869.3	)	5.3		(799.7	)
Total Change in FDC - $MM	(61.3	)	(47.7	)	383.0		274.0
Total Capital including Change in FDC - $MM	3.0		(917.1	)	388.3		(525.8	)
Reserve Additions including Net Acquisitions (Dispositions) - MMboe	9.0		(78.3	)	54.6		(14.7	)
Finding, Development and Acquisition Cost including FDC - $/BOE	0.33		11.71		7.11		35.69

PENGROWTH ENERGY CORPORATION | 2018 ANNUAL INFORMATION FORM     25

Total Proved Plus Probable Reserves	2018		2017		2016		2016-2018 Total/Weighted Average
Costs Excluding Future Development Costs
Exploration and Development Capital Expenditures - $MM	64.7		117.4		64.2		246.3
Exploration and Development Reserve Additions including Revisions - MMboe	8.9		3.0		76.2		88.0
Finding and Development Cost - $/BOE(1)	7.30		39.49		0.84		2.80
Net Acquisition (Disposition) Capital - $MM	(0.4	)	(986.7	)	(58.9	)	(1,046.0	)
Net Acquisition (Disposition) Reserve Additions - MMboe	(0.9	)	(150.1	)	(15.9	)	(166.9	)
Net Acquisition Cost - $/BOE	0.45		6.57		3.70		6.27
Total Capital Expenditures including Net Acquisitions (Dispositions) - $MM	64.3		(869.3	)	5.3		(799.7	)
Reserve Additions including Net Acquisitions (Dispositions) - MMboe	8.0		(147.2	)	60.3		(78.9	)
Finding, Development and Acquisition Cost - $/BOE	8.08		5.91		0.09		10.14
Costs Including Future Development Costs
Exploration and Development Capital Expenditures - $MM	64.7		117.4		64.2		246.3
Exploration and Development Change in FDC - $MM	(306.8	)	163.1		193.7		50.0
Exploration and Development Capital including Change in FDC - $MM	(242.1	)	280.5		257.9		296.3
Exploration and Development Reserve Additions including Revisions - MMboe	8.9		3.0		76.2		88.0
Finding and Development Cost - $/BOE(2)	(27.29	)	94.36		3.38		3.37
Net Acquisition (Disposition) Capital - $MM	(0.4	)	(986.7	)	(58.9	)	(1,046.0	)
Net Acquisition (Disposition) FDC - $MM	(0.5	)	(455.8	)	(124.7	)	(581.0	)
Net Acquisition (Disposition) Capital including FDC - $MM	(0.9	)	(1,442.5	)	(183.6	)	(1,627.0	)
Net Acquisition (Disposition) Reserve Additions - MMboe	(0.9	)	(150.1	)	(15.9	)	(166.9	)
Net Acquisition Cost - $/BOE	0.96		9.61		11.55		9.75
Total Capital Expenditures including Net Acquisitions (Dispositions) - $MM	64.3		(869.3	)	5.3		(799.7	)
Total Change in FDC - $MM	(306.3	)	(292.7	)	69.0		(530.0	)
Total Capital including Change in FDC - $MM	(242.0	)	(1,162.0	)	74.3		(1,329.7	)
Reserve Additions including Net Acquisitions (Dispositions) – MMboe	8.0		(147.2	)	60.3		(78.9	)
Finding Development and Acquisition Cost including FDC - $/BOE	(30.39	)	7.90		1.23		16.85

Notes:

(1) 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.

(2) The high F&D Cost including FDC for 2017 is due to increased estimated FDC. The negative F&D cost including FDC for 2018 is due to decreased 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 | 2018 ANNUAL INFORMATION FORM     26

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.

	2018	2017	2016	2016-2018 Weighted Average(4)
Operating Netback (after risk management), $/BOE(1)	13.47	13.23	28.62	20.62
Total Proved Reserves
Proved F&D, $/BOE(2)	0.31	13.69	8.04	8.87
Proved Recycle Ratio	43.89	0.99	3.59	2.32
Total Proved Plus Probable Reserves
P+P F&D, $/BOE(2)(3)	-27.29	94.36	3.38	3.37
P+P Recycle Ratio	-0.49	0.14	8.53	6.13

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. The negative F&D cost including FDC for 2018 is due to decreased 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 2018 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	3.6	24.4	55.6
Reserves, MMboe(1)(2)	27.2	193.7	446.6
2019 Forecast Production, BOE/d(1)	20,957	21,705	22,009

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.

	2018	2017		2016	Weighted Average/Total 2016-2018
Without Net Acquisitions Proved Plus Probable Replacement (%)	110	20		365	201
P+P Additions plus Revisions, MMboe(1)	8.9	3.0		76.2	88.0
With Net Acquisitions Proved Plus Probable Replacement (%)	99	(994	)	289	(180	)
P+P Additions, Revisions plus net Acquisitions, MMboe(1)	8	(147.2	)	60.3	(78.9	)
Without Net Acquisitions Total Proved Replacement (%)	120	187		290	224
Total Proved Additions plus Revisions, MMboe(1)	9.7	27.7		60.7	98.0
With Net Acquisitions Total Proved Replacement (%)	112	(529	)	261	(34	)
Total Proved Additions, Revisions plus net Acquisitions, MMboe(1)	9.0	(78.3	)	54.6	(14.7	)
Current Year Production, MMboe(1)	8.0	14.8		20.9	43.7

Note:

(1) Both reserves and production are Company Interest.

PENGROWTH ENERGY CORPORATION | 2018 ANNUAL INFORMATION FORM     27

OTHER OIL AND GAS INFORMATION

Oil and Gas Properties and Wells

As at December 31, 2018, we had an interest in 420 gross (269 net) producing oil and natural gas wells and 917 gross (586 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		78	55	294	201	372	255
	Alberta	38	30	87	76	125	106
	British Columbia	37	23	191	119	228	142
	Saskatchewan	3	1	16	6	19	7
Bitumen Wells		42	42	2	1	44	43
	Alberta	42	42	2	1	44	43
Natural Gas Wells		331	161	333	187	664	348
	Alberta	206	105	72	47	278	152
	British Columbia	105	54	248	136	353	190
	Saskatchewan	1	1	10	4	11	4
	Nova Scotia	19	2	3	0	22	2
Service Wells(1)		-	-	317	208	317	208
	Alberta	-	-	118	90	118	90
	British Columbia	-	-	173	112	173	112
	Saskatchewan	-	-	9	4	9	4
	Nova Scotia			17	1	17	1
Other(2)		-	-	4	1	4	1
	Alberta	-	-	4	1	4	1
Total		451	258	950	597	1,401	855

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, 2018 and the maximum net area of unproved properties for which we expect our rights to explore, develop and exploit to expire during 2019. 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, 2018

Location	Gross Acres	Net Acres	Maximum Net Acres Expected to Expire During 2019
Alberta	86,844	54,529	6,720
British Columbia	225,081	97,137	5,824
Nova Scotia	146,728	11,427	0
Saskatchewan	3,735	1,974	0
Total	462,387	165,067	12,544

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.

Significant Factors or Uncertainties Relevant to Properties with no Attributed Reserves

We have minor property holdings with no attributed reserves that are largely located in North East British Columbia. As noted prior, we continually evaluate and attempt to maintain acreage where economically viable. From this process, some properties are scheduled for economic development activities while others are temporarily held inactive, sold, or allowed to expire and relinquished back to the mineral rights owner.

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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 16 of our annual audited consolidated financial statements and related Management's Discussion and Analysis for the year ended December 31, 2018, which may be found on our website at www.pengrowth.com, on SEDAR at www.sedar.comand on EDGAR at www.sec.gov.

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 2027, partially as a result of our $2.3 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, 2018. These costs, which were all incurred in Canada, include only those costs which are cash or cash equivalent.

	Amount
Nature of Cost	($MM)
Acquisition Costs
Proved	—
Unproved	0
Exploration Costs(1)	(0.2	)
Development Costs	64.7
Total	64.5

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, 2018, all of which were drilled in Canada.

	Development		Exploration		Total
Wells	Gross	Net	Gross	Net	Gross	Net
Gas	-	-	-	-	-	-
Oil	-	-	-	-	-	-
Bitumen	8	8	-	-	8	8
Service/Injection	-	-	-	-	-	-
Total	8	8	-	-	8	8

For a description of our most important current and likely exploration and development activities, please see "Principal Producing Properties and Operations".

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Production Estimates

The following table summarizes the 2019 average daily volume of gross production estimated by GLJ for all properties held on December 31, 2018 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 2019 Company Interest production to be between 22,500 and 23,500 BOE/d.

	2019 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)	373	10	383	373	10	383
Heavy Crude Oil (bbl/d)	0	0	0	0	0	0
Bitumen (bbl/d)	17,899	5	17,904	17,899	5	17,904
Conventional Natural Gas (Mcf/d)	2,572	55	2,627	2,572	55	2,627
Shale Gas (Mcf/d)	16,680	1,660	18,340	16,680	1,660	18,340
Coal Bed Methane (Mcf/d)	1,137	16	1,153	1,137	16	1,153
Natural Gas Liquids (bbl/d)	22	1	23	22	1	23
Total (BOE/d)	21,692	304	21,996	21,692	304	21,996

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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(3)														YEAR ENDED (3)
	Mar 31, 2018				June 30, 2018				Sept 30, 2018				Dec 31, 2018		Dec 31, 2018
Barrels of Oil Equivalent(1) (including realized commodity risk management)
Average Daily Oil Production(2) (BOE/d)	19,541				22,600				21,807				24,104		22,025
Produced petroleum revenue ($/BOE)	39.97				42.59				47.10				24.80		38.24
Royalties ($/BOE)	(2.79	)			(3.99	)			(3.69	)			(1.67	)	(3.01	)
Adjusted operating expenses ($/BOE)	(10.41	)			(10.11	)			(10.72	)			(10.87	)	(10.54	)
Transportation costs ($/BOE)	(2.73	)			(2.67	)			(2.84	)			(3.02	)	(2.82	)
Realized commodity risk management ($/BOE)	(7.96	)			(9.82	)			(11.41	)			(4.69	)	(8.40	)
Operating netback ($/BOE)	16.08				16.00				18.44				4.55		13.47
Light Crude Oil (excluding realized commodity risk management)
Average Daily Oil Production(2) (bbl/d)	798				769				663				476		675
Sales price ($/bbl)	59.87				71.45				72.14				25.12		60.07
Royalties ($/bbl)	(8.82	)			(8.54	)			4.49		(1.00	)	(0.93	)	(4.05	)
Adjusted operating expenses ($/BOE)	(8.03	)	(1.00	)	(7.04	)	(1.00	)	(21.80	)			(45.84	)	(16.42	)
Transportation costs ($/bbl)	(1.89	)			(2.31	)			(2.77	)			(3.84	)	(2.57	)
Operating netback ($/bbl)	41.13				53.56				52.06				(25.49	)	37.03
Bitumen (excluding realized commodity risk management)
Average Daily Bitumen Production(2) (bbl/d)	15,118				15,876				16,408				17,866		16,325
Sales price ($/bbl)	42.33				52.47				56.64				27.50		44.32
Royalties ($/bbl)	(2.57	)			(4.57	)			(4.84	)			(1.95	)	(3.45	)
Adjusted operating expenses ($/BOE)	(10.59	)			(10.79	)			(9.87	)			(9.31	)	(10.11	)
Transportation costs ($/bbl)	(3.01	)			(2.91	)			(3.05	)			(3.10	)	(3.02	)
Operating netback ($/bbl)	26.16				34.20				38.88				13.14		27.74
Natural Gas (excluding realized commodity risk management)
Average Daily Natural Gas Production(2) (Mcf/d)	20,040				34,064				27,604				33,024		28,716
Sales price ($/Mcf)	3.88				1.77				1.61				2.37		2.27
Royalties ($/Mcf)	(0.09	)			(0.12	)			(0.27	)			(0.11	)	(0.15	)
Adjusted operating expenses ($/BOE)	(1.63	)			(1.39	)			(2.04	)			(2.02	)	(1.91	)
Transportation costs ($/Mcf)	(0.29	)			(0.38	)			(0.36	)			(0.47	)	(0.39	)
Operating netback ($/Mcf)	1.87				(0.12	)			(1.06	)			(0.23	)	(0.18	)
NGL (excluding realized commodity risk management)
Average Daily NGL Production(2) (bbl/d)	285				278				135				258		239
Sales price ($/bbl)	54.58				51.39				40.26				63.20		53.88
Royalties ($/bbl)	(20.95	)			(28.39	)			27.78		(1.00	)	(3.37	)	(11.37	)
Adjusted operating expenses ($/BOE)	(13.08	)			(15.58	)			(10.91	)			(29.34	)	(5.24	)
Transportation costs ($/bbl	0.00				0.00				0.00				0.00		0.00
Operating netback ($/bbl)	20.55				7.42				57.13				30.49		37.27

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.

(3) All production occurred in Canada

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, and how such changes may impact our operations and financial condition.

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

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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.

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.

On February 8, 2018, the Government of Canada introduced Bill C-69, draft legislation that, if enacted will replace the NEB with the Canadian Energy Regulatory (“CER”). The CER will take on the NEB’s responsibilities with respect to the export of crude oil, natural gas and NGL from Canada. However it is not proposed that the legislative regime relating to exports of crude oil, natural gas and NGL exports from Canada will substantively change under the new regime as currently drafted.

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.

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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.

Government of Alberta Curtailment Program

In December 2018, the Government of Alberta announced that they would be temporarily curtailing production from all oil producers with more than 10,000 bbl/d of production in Alberta effective January 1, 2019 to achieve an 8.7% or 325,000 bbl/d reduction in total production for the first three months of 2019 (the "Curtailment Program"). The goal of this program is to address the wide differential between the price of Western Canadian Select crude oil and the price of Western Texas Intermediate crude oil (the "Differential")resulting from the market imbalance created by growing production, growing storage inventories, and the lack of transportation capacity for crude oil to global markets. As soon as the Curtailment Program was announced, the Differential dropped substantially.

Pengrowth is impacted by the Curtailment Program. Thanks to early engagement with the Government of Alberta, the government revised their baseline calculation methodology, which originally was excessively punitive to companies that were increasing their production over the course of 2018. Based on the revised baseline calculation methodology, we are permitted to produce up to 17,496 bbl/d for the months of February and March. Pengrowth has also made use of Alberta's Curtailment Consolidation and Transfer framework to increase our production limit. This has allowed Pengrowth to proceed without altering its production guidance for 2019.

Pengrowth is unable to participate fully in the lower Differential that has resulted from the Curtailment Program due to the physical apportionment protected sales contracts we have entered into on 17,500 bbl/d at an average fixed Differential of (US$18.68) to WTI.

While the Curtailment Program originally contemplated being in full force for the first three months with curtailment relief thereafter, it is not known how long the full Curtailment Program will last, when it will be tapered, and to what extent it will be tapered. The Government of Alberta indicated that it expected the curtailment rate to gradually drop over the course of 2019. However, as a result of decreasing Differential and volumes of crude oil and crude bitumen in storage, the Government of Alberta announced on January 30, 2019, that it would ease the mandatory production curtailment beginning February 1, 2019, increasing the allowable production cap by 75,000 bbl/d to a maximum output of approximately 3.63 million bbl/d.

On March 2, 2019, Enbridge announced that operations on their Line 3 pipeline, which were expected to commence in the fourth quarter of 2019, would be delayed by another year due to permitting delays. This delay could cause Alberta's Curtailment Program to continue longer than initially contemplated.

International Trade Agreements

In November, 2018, Canada, the United States and Mexico signed the Canada-United States-Mexico Agreement ("USMCA") to replace the North American Free Trade Agreement ("NAFTA"), which US President Donald J. Trump has indicated his intention to withdraw from. NAFTA, however, remains the North American trade agreement currently in force until the legislative bodies of the three signatory countries

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ratify the USMCA. There is uncertainty surrounding the ratification of the USMCA, when or if NAFTA will come to an end, further contributing to general uncertainty around the future of United States-Canada trade. Under the terms of USMCA, Canada will no longer be subject to the proportionality provisions in NAFTA’s energy chapter, which should permit the expansion of oil and gas exports beyond the US, and a change to the oil and gas rules of origin will allow Canadian exporters to more easily qualify for duty-free treatment for shipments to the US. In particular, the origin of the diluent that is used to facilitate the transportation of crude petroleum oils is disregarded, provided that the diluent constitutes no more than 40 per cent by volume of the good. The US 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 the USMCA (or in the event the USMCA is not ratified) could have an impact on Western Canada's crude oil and natural gas industry at large, including the Corporation's business.

As discussed above, at the end of 2018 the Government of Alberta announced curtailment of Alberta's crude oil and bitumen production for 2019. Curtailment complies with NAFTA's Article 605, under which Canada must make available a consistent proportion of the oil and bitumen produced to the other NAFTA signatories. As a result of the proportionality rule, reducing Canadian supply reduced the required offering under NAFTA, with the result that the amount of crude oil and bitumen that Canada is required to offer, which Canadian crude oil is at depressed prices, may be reduced. It is not clear whether the USMCA will come into force before the Government of Alberta's curtailment order is repealed automatically on December 31, 2019.

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, on December 30, 2018, the Comprehensive and Progressive Agreement for Trans-Pacific Partnership ("CPTPP") entered into force among Canada, Australia, Japan, Mexico, New Zealand and Singapore. On January 14, 2019, the CPTPP entered into force for Vietnam. The CPTPP is intended to allow for preferential market access among the signatories. 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% 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%, 6% and 30%, 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.

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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 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.

In addition, the federal government may from time to time provide incentives to the crude oil and natural gas industry. In November 2018, the federal government announced its plans to implement an accelerated investment incentive, which will provide crude oil and natural gas businesses with eligible Canadian development expenses and Canadian crude oil and natural gas property expenses with a first year deduction of one and a half times the deduction that is otherwise available. The federal government also announced in late 2018 that it will make $1.6 billion available to the crude oil and natural gas industry in light of worsening commodity price differentials. The aid package, however, is mostly in the form of loans and is earmarked for crude oil and natural gas projects related to economic diversification as well as direct funding for clean growth oil and gas projects.

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 5% 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 5% and 40%determined 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 5% 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 0% to a cap of 40%. 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 5% to a cap of 36%. 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% for pentanes and 30% 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

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between 1% and 9% 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 1% 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 9% 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 1% and 9% and the net revenue royalty based on the net revenue royalty rate. Net revenue royalty rates start at 25% and increase for every dollar of market price of crude oil increase above $55 up to 40% 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.

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 4% 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%, 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% 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%.

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%. 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% 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 3% 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% 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 5% to 20% depending on the classification of the crude oil, and additional marginal royalty rates may apply, between 30% and 45%, 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 5% to 20%, and additional marginal royalty rates may apply between 30% to 45%, where

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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 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.

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. Producers and working interest participants may also pay additional royalties to parties other than the mineral freehold owner where such royalties are negotiated through private transactions.

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

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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 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.

The Government of British Columbia recently passed Bill 51 - 2018: Environmental Assessment Act, which replaces the environmental assessment regime that has been in place since 2002. The Government expects that the updated Environmental Assessment Act will enter into force in late 2019. The amendments will subject proposed projects to an enhanced environmental review process similar in substance to the federal environmental assessment process, as well as enhance indigenous engagement in the project approval process with an emphasis on consensus-building.

Saskatchewan

The Saskatchewan Ministry of Energy and Resources 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

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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 Petrinex (the petroleum information network utilized by the Government of Alberta and British Columbia).

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.

The recent decision of the Supreme Court of Canada ("SCC") in Orphan Well Association, et al. v. Grant Thornton Limited, et al, 2019 SCC 5 (commonly known as "Redwater") held that reclamation and abandonment liabilities, including the AB LLR Program, of insolvent oil and gas companies must be dealt with before distribution of the company’s assets or proceeds from the sale of those assets to its creditors, including secured creditors. It is expected that the decision of the SCC in Redwater may result in increased constraint in accessing credit by oil and gas companies as the decision has the effect of affording priority to certain environmental and reclamation obligations that lenders are unable to quantify at the time credit is advanced. The full extent of the regulatory implications of the Redwater decision remain unclear.

In response to Redwater, the AER issued a news release on January 31, 2019 confirming that they are working to understand the full implications of the SCC’s decision. As such, further legislative changes may be forthcoming which could result in additional obligations for the Company and/or different requirements. 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 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% 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 IWCP completed its third year on March 31, 2017.

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 British Columbia Oil and Gas 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 OGAA and enter the compliance and enforcement framework.

In the spring of 2018 the Government of British Columbia passed certain amendments to the OGAA (the "Amendments") which when brought into force, will replace the orphan site reclamation fund tax currently paid by permit holders with a levy paid to the Orphan Site Reclamation Fund ("OSRF"). Similar to Alberta's Orphan Fund, the OSRF is an industry-funded program created to address the abandonment

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and reclamation costs for orphan sites. Permit holders currently make monthly payments of $0.03 per 1,000 cubic metres of marketable gas produced and $0.06 per cubic meter of petroleum produced. The Amendments will require permit holders to pay their proportionate share of the regulated amount of the levy, calculated using each permit holder's proportionate share of the total liabilities of all permit holders required to contribute to the fund. The Amendments permit the B.C. Commission to impose more than one levy in a given calendar year. It is not clear when these provisions of the Amendments changing from a tax based on production to a liability-based payment will be brought into force.

Saskatchewan

The Government of Saskatchewan Ministry of Energy and Resources 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. 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. The Government of Saskatchewan Ministry of Energy and Resources may amend its rules and legislative scheme in light of the Redwater decision.

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, 2019, 195 parties to the convention signed the Paris Agreement.

Following the Paris Agreement and its ratification in Canada, the Government of Canada pledged to cut its emissions by 30% 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. Seven provinces and territories have introduced carbon-pricing systems in place that would meet federal requirements (Alberta, British Columbia, Quebec, Prince Edward Island, Nova Scotia, Newfoundland and Labrador and the Northwest Territories). The federal carbon-pricing regime will take effect in Saskatchewan, Manitoba, Ontario and New Brunswick in April 2019; it will take effect in the Yukon, and Nunavut in July 2019. Saskatchewan and Ontario have challenged the constitutionality of the federal government's pricing regime; New Brunswick has intervened in Saskatchewan's constitutional challenge. In October 2018, the federal government announced an alternative pricing scheme for large electricity generators designed to incentivize a reduction in emissions intensity, rather than encouraging a reduction in generation rates.

On April 26, 2018, the federal government passed the Regulations Respecting Reduction in the Release of Methane and Certain Volatile Organic Compounds (Upstream Oil and Gas Sector) (the "Federal Methane Regulations"). The Federal Methane Regulations seek to reduce emissions of methane from the crude oil and natural gas sector, but will not come into force until January 1, 2020. By introducing a number of new control measures, the Federal Methane 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. Among other things, the Federal Methane 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 annual 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

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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% and 25% 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 1%, beginning in 2020. The Government of Alberta intends for this strategy to align with the federal Framework.

Under the CLP, the AER was tasked with developing requirements to reduce methane emissions from upstream oil and gas operations by 45% relative to 2014 levels by 2025. To affect this, on December 13, 2018, the Alberta Ministry of Energy and the AER updated the AER’s Directive 060: Upstream Petroleum Industry Flaring, Incinerating and Venting and Directive 017: Measurement Requirements for Oil and Gas Operations with methane requirements to meet Alberta’s target. In addition, Energy plans to seek equivalency with the federal methane regulations.

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, 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.

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% below 2007 levels by 2050. Additionally, British Columbia seeks to generate at least 93% of its electricity from clean or renewable sources and build the infrastructure necessary to transmit it. The legislation established no date for this target.

Beginning April 1, 2018, British Columbia’s carbon tax rate was increased to $35 per tonne of carbon dioxide equivalent emissions. The tax rate will increase each year by $5 per tonne until it reaches $50 per tonne in 2021. New revenues generated from increasing the carbon tax will be used to provide carbon tax relief and protect affordability, maintain industry competitiveness and encourage new green initiatives.

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.

In December 2018, the Government of British Columbia released its CleanBC plan aimed at reducing climate pollution. The plan discusses many approaches to this, including reducing methane emissions from natural gas development and introducing a regulatory framework for safe and effective underground carbon storage and direct air capture. The CleanBC Plan indicates that the province will put in place a minimum requirement for 15% renewable content in natural gas by 2030.

On December 5, 2018, the Government of British Columbia announced an updated clean energy plan, "CleanBC", which seeks to ensure that British Columbia achieves 75% of its GHG emissions reduction target by 2030. The CleanBC plan includes a number of strategies targeting the industrial, transportation construction, and waste sectors of the British Columbia economy. Key initiatives include: i) increasing the generation of electricity from clean and renewable energy sources; ii) imposing a 15% renewable content requirement in natural gas by 2030; iii) requiring fuel suppliers to reduce the carbon intensity of diesel and gasoline by 20% by 2030; iv) investing in the electrification of oil and gas production; v) reducing 45% of methane emissions associated with natural gas production; and vi) incentivizing the adoption of zero emissions vehicles. On January 16, 2019, the B.C. Commission announced a series of amendments to the B.C. Drilling and Production Regulation that will require facility and well permit holders to, among other things, reduce natural gas leaks and curb monthly natural gas emissions from their equipment and operations. These new rules will come into effect on January 1, 2020.

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% of 2006 levels by 2020.

In December, 2017, the Government of Saskatchewan released its Prairie Resilience climate change strategy, which outlined multiple commitments to make Saskatchewan more resilient to the climatic, economic and policy impacts of climate change. Under this strategy, the Government proclaimed The Management and Reduction of Greenhouse Gases (General and Electricity Producer) Regulations, which took effect January 1, 2018 and are the next step in an equivalency agreement for provincial coal-fired emissions regulation. Facilities emitting over 10,000 tonnes of GHG must now annually report to the province. In addition, the Government announced output-based

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performance standards that will regulate large industrial facilities to reduce GHG by an additional 5.3 million tonnes from 2019 to 2030, achieving 10% reductions by 2030, as well as introduced the Methane Action Plan and The Oil and Gas Emissions Management Regulations, which will achieve a 4.5 million tonnes carbon dioxide equivalent annual reduction by 2025 and a total reduction of 38.2 million tonnes CO2e between 2020 and 2030.

General Discussion

Since the 2018 release of new Federal and Provincial Emission regulations, we are anticipating increased direct and indirect costs related to operational emissions. Our operations are now governed by the new regulations and, for 2018, our compliance costs were approximately $1.8 million. Currently, our operations are able to bear these costs. While we expect the costs from various GHG regulations, both existing and proposed, to increase costs as production levels rise and the cost per tonne of carbon increases, some of these costs can be mitigated and offset through the favourable treatment that co-generation facilities receive. That said, there is the potential for direct and indirect costs to adversely affect our business, operations and financial results. Equipment replacement to meet future emission standards may be required and could materially impact capital costs for the corporation.  Failure to meet emission compliance benchmarks may adversely affect our business materially by inflating payments to the Climate Management Fund or increasing the cost for purchasing offset carbon credits. There is also a risk that one or more levels of government could impose additional emission reduction requirements, increase the cost of carbon credits, or increase taxes on emissions produced by us or by the 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.

RISK FACTORS

Our business involves the development and production of oil and natural gas in Western Canada. There are a number of risks associated with our operations, some that impact the oil and natural gas industry as a whole and others that are unique to our operations. Many of these risks are beyond our control.

The following is a summary of certain risk factors relating to our business. These risk factors should be read in conjunction with the detailed information appearing elsewhere in this AIF. If any of the following risks or uncertainties occurs, our production, revenue and financial condition could be materially impaired. In that event, the market price of our Common Shares could decline and investors could lose all or part of their investment. Additional risks and uncertainties presently unknown, or that are not believed to be material at this time, may also impair or have a material adverse effect on the Corporation’s operations and financial condition. In addition to the risks described elsewhere and the other information contained in this AIF, investors should carefully consider each of and the cumulative effect of all of the following risk factors. Additional risks are described under the heading “Business Risks” in our Management’s Discussion and Analysis for the year ended December 31, 2018.

Operational Risks

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.

Our financial performance and the market price of our 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. Extended periods of lower commodity prices may reduce our level of spending for oil and gas exploration and development, and may have a material adverse effect on our results of operations. Crude oil and natural gas are commodities that are price-sensitive to numerous worldwide factors, many of which are beyond our control. These factors include, but are not limited to:

• 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;

• worldwide geo-political conditions;

• worldwide economic conditions including ongoing credit and liquidity concerns;

• the costs of exploring for, developing, producing and transporting crude oil, natural gas and natural gas liquids;

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

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• 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

• domestic and foreign government regulation and taxes.

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 2019 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.

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.

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 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. Prices 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. Failure to obtain financing on a timely basis could cause us to forfeit our interest in certain properties, miss certain acquisition opportunities, reduce or terminate operations or delay development and production activities.

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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 that could affect the market price of our Common Shares that are unrelated to our performance could include domestic and global commodity prices, market perceptions of the attractiveness of particular industries, 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. The price at which our Common Shares will trade cannot be accurately predicted.

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, among others:

• 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 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 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, 2018 are estimated using both constant and forecast pricing that escalates in future years. Forecast 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.

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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.

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. Although pipeline expansions are ongoing, the lack of firm pipeline capacity continues to affect the oil and natural gas industry and limits the ability to produce and market petroleum 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 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.

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.

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 recently introduced Bill C-69, An Act to enact the Impact Assessment Act and the Canadian Energy Regulator Act, to amend the Navigation Protection Act and to make consequential amendments to other Acts, with an aim 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.

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. 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.

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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 recently introduced Bill C-69, An Act to enact the Impact Assessment Act and the Canadian Energy Regulator Act, to amend the Navigation Protection Act and to make consequential amendments to other Acts, with an aim 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.

Following major accidents in Lac-Megantic, Quebec and North Dakota, the Transportation Safety Board of Canada and the US 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 (to be adjusted annually) 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.

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.

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

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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.

Our production is concentrated in key producing assets.

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 significant portion of our current and future production and revenue is generated from our Lindbergh and Groundbirch projects. A failure to execute at Lindbergh or Groundbirch could have a material adverse effect on our business, financial condition and profitability.

There are risks associated with our projects, which can impact the revenue generated from our operations.

There are risks associated with the execution and operation of our growth and development projects. We manage a variety of small and large projects in the conduct of our business. Project delays may delay expected revenues from operations. In addition, 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 and storage capacity;

• the availability and proximity of pipeline 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 supply and demand for crude oil and natural gas;

• fluctuations in the market price of crude oil and natural gas;

• the availability of alternative fuel sources;

• the availability of drilling and related equipment;

• unexpected cost increases;

• accidental events;

• currency fluctuations;

• export taxes;

• changes in regulations and the ability to obtain necessary environmental and regulatory approvals;

• 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.

As a result of these and other 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.

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 willful 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

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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.

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.

Future acquisitions or financing activities may result in dilution of your Common Share holdings.

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. We cannot predict the size of future issuances of Common Shares or the issuance of debt instruments or other securities convertible into Common Shares or the effect, if any, that future issuances and sales of securities will have on the market price of the Common Shares. In addition, acquisitions, financings or other transactions involving the issuance of securities may be dilutive to the current holders of Common Shares. There are no restrictions in our articles or by-laws with respect to the number of Common Shares that may be issued and outstanding.

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;

• 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

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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.

Lindbergh Thermal Project Specific Risks.

Continued expansion of our Lindbergh thermal project will require substantial capital investment over the coming years. As discussed above, during June, 2018, we announced our Multi-Year Development Plan which provides for a more incremental growth strategy that is aligned with Pengrowth’s expected cash flow. In addition to the risk factors set out above, there are certain additional risk factors associated with the development of our Lindbergh thermal project. These include the following:

Ability to Fund Development

The capital to be committed to our Lindbergh thermal project during 2019 and onwards will be dependent on the prevailing price of oil, and as such, our ability to fund further development will be impacted by fluctuations in the price of oil. At a WTI price of US$65 per bbl, capital spending is expected to increase to a range of $120 to $125 million in 2019 and be fully funded with generated cash flows. Pengrowth expects to generate free cash flow under this scenario which will be used to pay down debt. If the price of oil is less than WTI US$65 per bbl, Pengrowth may not be in a position to continue capital development activities while also paying down debt with generated free cash flows. See also “Operational Risks - 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.”

With our expansion spending tied to cash flow generation, there is a risk that we will be unable to generate sufficient cash flow to support our planned growth activities. 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, or Pengrowth may explore additional financing opportunities. The inability of Pengrowth to access sufficient capital for its operations could materially adversely affect our financial condition.

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% 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 availability of transportation alternatives;

• 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;

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• the cost of insurance; and

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

Operational Hazards and 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 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. See also “Operational Risks - 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.”

In addition, equipment failures could result in damage to the project facilities and liability to third parties against which we may not be able to fully insure or may elect not to insure because of costs or for other reasons.

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.

Pengrowth expects to implement the use of Non-Condensable Gas (“NCG”) injection and solvents with the hope of enhancing production while lowering the steam requirements for the project. While the implementation of NCG, in tandem with infill wells, is expected to improve operating efficiencies, reduce steam requirements and reduce water use and emissions, there is no certainty that these results will occur. There are additional costs associated with implementing the use of NCG injection and solvents, and there is no certainty that these actions will enhance production while reducing associated costs.

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, various regulatory approvals may be required. These included, but are not limited to, scheme amendments, EPEA and Water Act (Alberta) approval amendments. Pengrowth submitted a scheme amendment and an EPEA update in February 2017, to increase the maximum oil rate of the Lindbergh thermal project to 40,000 bbl/day. This approval was received on August 1, 2017. In early 2018, Pengrowth filed an application with the AER for the use of NCG injection at Lindbergh and received approval in early June 2018.

When going through any regulatory review process, the risk areas include but are not limited to; the regulators’ ability to review the 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. Addressing these issues or concerns may take a significant amount of time and involve associated costs in order to meet the regulators’ requirements, often leading to delays in the approval process. Unresolved statements of

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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, which can have a negative impact on the results of our financial operations.

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

Our success depends on attraction and retention of certain key personnel. Failure to retain critical talent or to attract and retain new talent with the necessary leadership traits, skills and competencies could have a material adverse effect on our results of operations, pace of growth and financial condition. 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.

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, the marketing of oil and natural gas, hiring the equipment and expertise required to safely and cost-effectively develop resources, and constructing and transporting resources. Our competitors include oil and natural gas companies that have substantially greater financial resources, staff and facilities than us. The petroleum industry also competes with other industries in supplying energy, fuel and related products to customers. Key success factors in each of these markets include price, methods, product quality, logistics and reliability of delivery and storage.

Our ability to compete in the future will depend on, among other things, our ability to increase our reserves through the exploration and development of our present properties as well as through selection and acquisition of suitable producing properties or prospects for exploratory drilling.

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.

In the normal course of our activities, we may become involved in, named as a party to, or be the subject of various legal proceedings, including regulatory proceedings, tax proceedings or legal actions related to personal injury, property damage, property tax, land rights, the environment or lease and contract disputes, among other potential claims. Claims under such proceedings may be material or may be indeterminate. 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.

Financial Risks

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. At the expiry of these extensions, we will need to negotiate further extensions with our lenders, or otherwise comply with the covenants in our Credit Facility and the Term Notes. A failure to comply with covenants could result in a default under the Credit Facility and Term Notes, which could result in us being required to repay amounts owing thereunder. The acceleration of indebtedness under one agreement may permit acceleration of indebtedness under other agreements that contain cross default or cross-acceleration provisions.

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 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 or source alternative funding 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.

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If we are unable to repay amounts owing under our Credit Facility, our lenders could proceed to foreclose or otherwise realize upon the collateral granted to them to secure the indebtedness. In addition, the Credit Facility and other credit arrangements may impose operating and financial restrictions on us that could include restrictions on the payment of dividends, the repurchase or making of other distributions with respect to our securities, incurring of additional indebtedness, the provision of guarantees, the assumption of loans, making of capital expenditures, entering into of amalgamations, mergers, take-over bids or disposition of assets, among other restrictions. The imposition of restrictions in respect of our credit arrangements could have a material adverse effect on the results of our operations and our financial condition.

Our level of indebtedness from time to time could impair our ability to obtain additional financing on a timely basis, or at all, to take advantage of business opportunities that may arise.

Our debt and other financial commitments may limit our financial and operating flexibility.

As of December 31, 2018 our long-term debt was approximately $714.6 million. We also have commitments under leases, operational contracts, transportation and storage contracts, and purchase obligations for services and products. Our debt levels and financial commitments could have significant and adverse consequences to our business, including:

• an increased sensitivity to adverse economic and industry conditions;

• a limited ability to fund future working capital and capital expenditures, engage in future acquisitions or development activities, or to otherwise fully realize the value of assets or opportunities, because a substantial portion of our cash flows are required to service debt and other obligations;

• a limited ability to plan for, or react to, industry trends; and

• an uncompetitive position relative to our competitors whose debt and financial commitment levels are lower.

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. If any such third parties go bankrupt, become insolvent or make a proposal or institute any proceedings relating to bankruptcy or insolvency, it could result in Pengrowth being unable to collect all or a portion of any money owing from such parties. Any of these factors could have a material adverse effect on our business, financial condition, results of operations and prospects.

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

Global 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, including Pengrowth. Material increases in the value of the Canadian dollar relative to the United States dollar will negatively affect our production revenues, and could affect the future value of our reserves as determined by independent evaluators.

Pengrowth has substantial exposure to the US dollar. Any decrease in the value of the Canadian dollar relative to the US dollar results in an increase in the Canadian dollar equivalent of Pengrowth’s US 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 US dollar could cause Pengrowth to be in violation of its debt covenants resulting in Pengrowth being in default of its debt obligations.

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 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:

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• production falls short of the hedged volumes or Pengrowth fails to fulfill its obligations related to the underlying physical transaction;

• 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.

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 and our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic, business, market and other conditions, some of which are beyond our control. If our operating and financial results are not sufficient to service current or future indebtedness, Pengrowth may take actions such as reducing or delaying business activities, investments or capital expenditures, selling assets, restructuring or refinancing our debt, or seeking additional equity capital. Furthermore, 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.

There is a very limited public trading market for our Common Shares in the United States, and the market for our Common Shares in the United States may continue to be limited and be sporadic and highly volatile.

There is currently a limited public market for our Common Shares in the United States. Our Common Shares trade over the counter in the United States on the OTCQX market place. We cannot assure you that an active market for our Common Shares will be established or maintained in the future. The OTCQX is not a national securities exchange, and many companies have experienced limited liquidity when traded through this quotation system. Holders of our Common Shares in the United States may, therefore, have difficulty selling their shares, should they decide to do so. In addition, there can be no assurances that such markets in the United States will continue or that any shares, which may be purchased, may be sold without incurring a loss. The market price of our Common Shares in the United States, from time to time, may not necessarily bear any relationship to our book value, assets, past operating results, financial condition or any other established criteria of value, and may not be indicative of the market price for the shares in the future.

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

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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.

Regulatory and Political Risks

Changes in royalty regime may have significant impact on oil and gas production profitability.

Both the federal government and the provincial governments have imposed regulation surrounding royalties, production rates and other related matters. In Alberta, the royalty regime is a significant factor in the profitability of oil and natural gas production. If the regulations surrounding royalties were to be modified, it could have an impact on the economics of our projects. An increase in royalties would reduce our earnings and could make future capital investments, or our current production operations, less economic.

Political uncertainty has impacted and continues to impact 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 2017 and 2018, the United States government took steps to implement and act on certain of the election promises relating to trade and marketability of commodities and tax reform. Among other actions, the United States government withdrew from the Trans-Pacific Partnership and passed sweeping tax reform, which significantly reduced US corporate tax rates. These actions may affect the competitiveness of other jurisdictions, including Canada. In November, 2018, Canada, the United States and Mexico signed the Canada-United States-Mexico Agreement (“USMCA”) to replace the North American Free Trade Agreement, which the United States government has indicated it will be withdrawing from. There is uncertainty surrounding the ratification of the USMCA, further contributing to general instability around the future of United States-Canada trade. It is unclear exactly what other actions the administration in the United States will take, and how these actions may impact Canada and in particular, the oil and gas industry. Any actions taken by the 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, certain European countries have experienced the rise of anti-establishment political parties and public protests held against open-door immigration policies, trade and globalization, and the United Kingdom is working to withdraw from the European Union. To the extent that certain political actions taken in North America, Europe and elsewhere in the world result in a marked decrease in free trade, access to personnel and freedom of movement, it could have an adverse effect on our ability to market our products outside of Canada, increase costs for goods and services required for our operations, reduce access to skilled labour and negatively impact our business, operations, financial conditions and ultimately the market value of our Common Shares.

In addition to international factors, a change in the federal, provincial or municipal governments in Canada could have an impact on the Canadian oil and gas industry, as a result of a shift in the balance between economic development and environmental policy, or changes in the royalty or tax regimes. The announcements and actions taken by the government of British Columbia in the last couple of years have had a direct impact on the completion of pipeline projects and pipeline supply.

Changes and uncertainties in the political environment, both inside and outside of Canada, and the interactions between Canada and other nations, may directly impact the ability and feasibility of Pengrowth to export its products from Canada. Potential regulation in the United States favouring nationalism could disincentive or penalize international trade, which could significantly reduce demand for the Corporation’s goods and impact the price at which the Corporation can sell its products.

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 transfer of such assets. See “Industry Conditions - Regulatory Authorities and Environmental Regulation - Liability Management Rating Program”.

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

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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.

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). These laws and regulations govern, amongst other things:

• the types and quantities of substances and waste materials that may be discharged into the surface and sub-surface environment;

• the use or removal of natural resources (such as water and timber) in exploration and production activities;

• the release of greenhouse gases, such as carbon dioxide and methane, into the atmosphere;

• the abandonment, reclamation and remediation of worksites (including sites of former operations);

• the issuance of permits and other regulatory approvals in connection with exploration, drilling and production activities, the construction of roads, pipelines and other regional transportation infrastructure; and

• marketing and pricing policies, royalties, various taxes and levies including income tax, and foreign trade and investment.

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. In recent years, the federal government and certain provincial governments have taken steps to initiate protocols and regulations to regulate greenhouse gas emissions. Such draft regulations and protocols may have a material adverse effect on the oil and gas industry, including Pengrowth. See “Industry Conditions - Regulatory Authorities and Environmental Regulation - Climate Change Regulation”.

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, obtaining certain

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approvals from regulatory authorities can involve, among other things, stakeholder and Aboriginal consultation, environmental impact assessments and public hearings. Regulatory approvals obtained may be subject to the satisfaction of certain conditions including, but not limited to: security deposit obligations; ongoing regulatory oversight of projects; mitigating or avoiding project impacts; habitat assessments; and other commitments or obligations. Furthermore, regulatory requirements pertaining to the production, marketing and sale of oil and natural, 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).

Failure to obtain applicable regulatory approvals or satisfy any of the conditions thereto on a timely basis on satisfactory terms, or the termination or expiration of applicable licenses, permits and leases, could result in delays, abandonment or restructuring of projects and increased costs. The laws and regulations governing the oil and gas industry may impose significant liabilities on a failure to comply with their requirements, including the possibility of administrative, civil and criminal penalties, cancellation or suspension of permits or authorizations, investigations or other proceedings, which could have a material adverse effect on our operations and financial condition.

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. We utilize hydraulic fracturing in a significant portion of the light oil wells we drill and complete. We believe that the hydraulic fracturing that we conduct, given the depth and location of the wells and 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.

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.

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.

The requirement to consult with Aboriginal Peoples in respect of oil and gas projects and related infrastructure has increased in recent years. The Canadian federal government and the provincial government in Alberta have made a commitment to renew their relationships with the Aboriginal peoples of Canada. The federal government has stated it fully supports the United Nations Declaration on the Rights of Indigenous Peoples (the “Declaration”) without qualification and that Canada intends ‘‘nothing less than to adopt and implement the Declaration in accordance with the Canadian Constitution.’’ On May 30, 2018 the private member’s bill, Bill C-262, An Act to ensure that

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the laws of Canada are in harmony with the United Nations Declaration on the Rights of Indigenous Peoples, a bill which facilitates the full adoption of the Declaration into Canadian Law, was adopted by the House of Commons. It is It is anticipated that the Bill may become law in 2019. If adopted into Canadian Law, it is unclear how the Declaration will impact Crown’s duty to consult with Aboriginal peoples.

We are unable to assess the effect, if any, that any such consultation requirements or adoption of the Declaration into Canadian law may have on our business.

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”.

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.

Public support for climate change action and receptivity to alternative or renewable energy technologies has grown in recent years. Governments in Canada and around the world have responded to these shifting societal attitudes by implementing policies and/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.

Other Risks

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 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.

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.

Potential conflicts of interest.

Certain of our directors are also, or may in the future be, directors or officers of other oil and gas companies and as such may, in certain circumstances, have a conflict of interest requiring them to disclose such interest and 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. See also “Conflicts of Interest”.

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

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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 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, are complex and may in the future be changed or interpreted in a manner that adversely affects us. While we think our tax filing positions are appropriate and supportable, 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.

Weather conditions are difficult to anticipate and cannot be controlled. In these conditions, operations can become difficult or unsafe and can be suspended. Some of our facilities and those that our facilities rely upon (such as pipelines, power, communication and oil field equipment) are vulnerable to these types of extreme weather conditions and may suffer extensive or catastrophic damage as a result. If any such extreme weather were to occur, our ability to operate certain facilities and proceed with exploration or development programs could be seriously or completely impaired or destroyed and could have a material adverse effect on our business, financial condition and results of operations. The insurance we maintain may not be adequate to cover our losses resulting from disasters or other business interruptions.

In addition, 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. Seasonal factors and unexpected weather patterns may lead to declines in exploration and production activity and also to volatility in commodity prices as the demand for natural gas can rise during cold winter months and hot summer months.

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.

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 and with our stakeholders. Negative sentiment towards us could result in a lack of willingness of regulatory authorities

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to grant the necessary licenses or permits for us to operate our business, and resistance from residents in the areas in which we operate. 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. 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. Any of these events could have a material adverse effect on our business, financial condition and results of operation.

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.

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 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 could 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. The payment of uninsured liabilities would reduce the funds available to us and the occurrence of a significant event that we are not fully insured against, or the insolvency of the insurer of such event, could have a material adverse effect on our financial position, results of operations or prospects.

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

The impact that future potential terrorist attacks, regional hostilities or political violence may have on the oil and gas industry, and on our operations in particular, is not known at this time. This uncertainty may affect operations in unpredictable ways. In addition, 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.

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.

Sufficient internal controls are necessary to provide reliable financial reports and assist in fraud prevention.

Effective internal controls are necessary for us to provide reliable financial reports and to help in preventing fraud. Although we undertake a number of procedures in order to help ensure the reliability of our financial reports, including those imposed on us under Canadian securities laws, we cannot be certain that such measures will ensure that we will maintain adequate control over financial processes and reporting.

Failure to implement required new or improved controls, or difficulties encountered in their implementation, could harm our results of operations or cause us to fail to meet our reporting obligations. If Pengrowth or our independent auditors discover a material weakness, the disclosure of that fact, even if quickly remedied, could reduce the market’s confidence in our financial statements and harm the trading price of the Common Shares.

Forward-looking statements and information may prove inaccurate.

Shareholders and prospective investors are cautioned not to place undue reliance on our forward-looking statements and information. By its nature, forward-looking statements and information involve numerous assumptions, known and unknown risk and uncertainties, of both a general and specific nature, that could cause actual results to differ materially from those suggested by the forward-looking statements or contribute to the possibility that predictions, forecasts or projections will prove to be materially inaccurate. Additional information on the risks, assumptions and uncertainties related to forward-looking statements and information are found under the heading “Forward-Looking Statements” in this AIF.

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's Discussion and Analysis accompanying our December 31, 2018 audited financial statements.

Stock Exchange Listings

Our Common Shares are listed and posted for trading on the TSX under the symbol "PGF".  Trading in the common shares of Pengrowth on the NYSE under the symbol "PGH" ceased after markets closed on June 1, 2018 after Pengrowth received notice on December 1, 2017 that its share price had fallen below the NYSE’s continued listing standard for average closing price of less than US $1.00 over a consecutive 30 trading-day period. Pengrowth shares are now traded over-the-counter in the United States on the OTCQX under the symbol "PGHEF". Our 6.25% 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 and Distributions

No dividends or distributions have been declared in the three most recently completed fiscal years and we do not intend to declare or pay any cash dividends in the foreseeable future.

Our ability to pay cash dividends to shareholders of the Corporation is prohibited by our Credit Facility and the note purchase agreements relating to our Term Notes, as well as the financial capacity and solvency tests under the ABCA.

MARKET FOR SECURITIES

Trading Price and Volume

Our outstanding Common Shares are listed and posted for trading under the symbol "PGF" on the TSX under the symbol “PGF” and on the OTCQX under the symbol “PGHEF”. The price ranges and the volumes traded on the TSX for the year ended December 31, 2018 are as follows:

	TSX
	($) High	($) Low	Volume
January	1.17	0.95	14,717,386
February	0.99	0.84	6,379,956
March	0.92	0.78	5,968,971
April	1.21	0.77	13,582,263
May	1.15	0.95	12,517,803
June	0.97	0.84	8,913,701
July	1.21	0.90	13,330,436
August	0.96	0.88	7,689,576
September	1.17	0.84	15,404,384
October	1.24	0.86	23,457,995
November	0.94	0.68	10,621,330
December	0.72	0.47	12,773,319

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Prior Sales

The following table summarizes the issuances of unlisted securities during the year ended December 31, 2018. These unlisted securities were issued pursuant to the Corporation's compensation plans. For further information please see the Management Information Circular dated May 14, 2018 available on our SEDAR profile.

Date of Issuance	Securities	Number of Common Shares Issued/ Issuable or Aggregate Amount	Price/Exercise Price per Security ($)
June 26, 2018	Restricted Share Units	2,350,491	0.87
June 26, 2018	Options	9,250,947	0.87
September 28, 2018	Options	75,972	1.05
September 28, 2018	Restricted Share Units	120,054	1.09
December 20, 2018	Restricted Share Units	52,044	0.57

Escrowed Securities

The Corporation has no escrowed securities or securities subject to contractual restriction on transfer.

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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)  Alberta, Canada	Chairman and Director (Director since 2012)	President of Wylander Crude Corp. (a private oil and gas company) and Vice President, Corporate Development of Lakeview Energy Inc. (a private oil and gas company).
Peter Sametz Alberta, Canada	President, Chief Executive Officer and Director (Director since 2018)	President and Chief Executive Officer of Pengrowth; prior thereto President and Chief Executive Officer of Gemini Corporation from March 2016 to November 2017, and prior thereto President and Chief Operating Officer of Connacher Oil and Gas Limited since 2004.
Wayne K. Foo(2)(3)  Alberta, Canada	Director (Director since 2006)(4)	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.
Chandra A. Henry (1)  Alberta, Canada	Director (Director since 2018)	Chief Financial Officer of WestBlock Inc. (technology company); prior thereto, Director of Finance for GMP Securities LP and prior thereto, Chief Financial Officer of FirstEnergy Capital Corp.
James D. McFarland(1)(3)  Alberta, Canada	Director (Director since 2010)(4)	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)(4)	Business Consultant and Corporate Director.
D. Michael G. Stewart(2)  Alberta, Canada	Director (Director since 2006)(4)	Corporate Director.
Randall S. Steele Alberta, Canada	Chief Operating Officer	Chief Operating Officer of Pengrowth 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 Committee.

(2) Member of Compensation, Corporate Governance and Nominating Committee.

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

(4) Denotes year first appointed as a director of Pengrowth Corporation, a predecessor of ours.

As at December 31, 2018, the foregoing directors and officers, as a group, beneficially owned, directly or indirectly, 3,837,596 Common Shares or approximately 0.69% of the issued and outstanding Common Shares and held rights and options to acquire a further 9,021,464 Common Shares (assuming 100% 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.

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.

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Other than as set out below, no current director or executive officer or securityholder holding a sufficient number of our securities to affect materially our control is, as of the date hereof, or has been, within the last ten years prior to the date hereof, 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.

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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
A. Terence Poole (1)	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 served 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.
Kelvin B. Johnston	Yes	Yes	Mr. Johnston is an executive with more than 35 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. Mr. Johnston serves as director of Leucrotta Exploration Inc., and is a member of the Board of Governors of the Explorers and Producers Assocation of Canada (EPAC).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 Master’s degree in Economics from the University of Calgary.
James D. McFarland	Yes	Yes	Mr. McFarland has more than 46 years’ experience in the oil and gas industry, most recently as a co-founder, director and retired President and Chief Executive Officer of Valeura Energy Inc., a TSX listed issuer. Prior thereto Mr. McFarland was a co-founder, director and President and Chief Executive Officer 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., Valeura Energy Inc. and Arrow Exploration Corp., 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.
Chandra A. Henry	Yes	Yes	Ms. Henry is Chief Financial Officer at WestBlock Inc. Prior thereto Ms. Henry held various senior finance positions including Director of Finance for GMP Securities LP (2016-17) and Chief Financial Officer for FirstEnergy Capital Corp (2001-16). Both firms are leading boutique investment dealers that have served the oil and gas industry for many decades. Ms. Henry has also served as a Director, Treasurer and Chair of the Audit Committee of the Alberta Ballet Company from 2012 to 2018. Ms. Henry has a Bachelor of Commerce degree from the Haskayne School of Business and is both a Chartered Professional Accountant (CPA, CA), a Chartered Financial Analyst Charterholder and is a member of the Institute of Corporate Directors.

Note:

(1)    Chair of the Audit Committee.

Reliance on Certain Exemptions

At no time since the commencement of the Corporation’s most recently completed financial year has the Corporation relied on any exemption from NI 52-110, including Section 2.4 of NI 52-110 (De Minimis Non-Audit Services), or an exemption granted under Part 8 of NI 52-110.

Audit Committee Oversight

At no time since the commencement of our financial year ended December 31, 2018 was a recommendation of the Audit Committee to nominate or compensate an external auditor not adopted by the Board of Directors.

PENGROWTH ENERGY CORPORATION | 2018 ANNUAL INFORMATION FORM     65

External Auditor Fees and Services

The following table provides information about the aggregate fees billed to us for professional services rendered by KPMG LLP during fiscal 2018 and 2017:

	2018 ($thousands)	2017 ($thousands)
Audit Fees	776	900
Audit Related Fees	-	-
Tax Compliance and Preparation Services	40	23
Other Tax Services		23
All Other Fees	75	105
Total	891	1,051

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 include fees billed for assurance and related services that are reasonably related to the performance of the audit or review of our financial statements and are not reported as “Audit Fees”. The services provided in this category 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 2017 and 2018 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 2017 and 2018 the services provided in this category relate to translation of financial statements, management's 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 the 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.

PENGROWTH ENERGY CORPORATION | 2018 ANNUAL INFORMATION FORM     66

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 AND REGULATORY ACTIONS

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 10% of our assets.

In addition, there have not been any (a) penalties or sanctions imposed against the Corporation by a court relating to securities legislation or by a securities regulatory authority during the year ended December 31, 2018, (b) any other penalties or sanctions imposed by a court or regulatory body against the Corporation that would likely be considered important to a reasonable investor in making an investment decision, or (c) settlement agreements entered into by the Corporation before a court relating to securities legislation or with a securities regulatory authority during the year ended December 31, 2018.

See "Risk Factors - Operational Risks - 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".

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 US 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 Professional Accountants in Calgary, Alberta.

MATERIAL CONTRACTS

The only material contracts entered into by us 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.

OFF-BALANCE SHEET ARRANGEMENTS

Pengrowth has no off-balance sheet arrangements.

PENGROWTH ENERGY CORPORATION | 2018 ANNUAL INFORMATION FORM     67

CORPORATE GOVERNANCE PRACTICES

As a Canadian reporting issuer with securities listed on the TSX , Pengrowth has in place a system of corporate governance practices which complies with Canadian securities laws and the TSX corporate governance guidelines. Pengrowth qualifies as a foreign private issuer under SEC rules and 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 the Audit and Risk Committee, the Corporate Governance and Nominating Committee, the Compensation Committee, and the Reserves, Health, Safety and Environment Committee, as well as 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.

ADDITIONAL INFORMATION

Additional information, including directors' and officers' remuneration and indebtedness, the principal holders of Common Shares and securities authorized for issuance under equity compensation plans, is contained in our Management Information Circular for our most recent annual meeting of shareholders that involved the election of directors and can be obtained upon request of Pengrowth at the contact information below. Additional financial information is contained in our comparative consolidated financial statements and associated management's discussion and analysis for the years ended December 31, 2018, 2017 and 2016.

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 AIF 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 | 2018 ANNUAL INFORMATION FORM     68

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, 2018. 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 Pengrowth's 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%, whereas the likelihood of a Contingent Resource achieving commerciality will be less than 100%.

Summary of Gross Bitumen Reserves as of December 31, 2018
(Forecast Prices and Costs)

	Bitumen - Reserves Category
	Total Proved	Total Proved Plus Probable	Total Proved Plus Probable Plus Possible
Gross Reserves (Mbbl)	159,153	311,395	401,210

Summary of Gross Bitumen Contingent Resources as of December 31, 2018
(Forecast Prices and Costs)

	Bitumen - Contingent Resource Category
Project Maturity Sub-Class(1)	Low Estimate		Best Estimate		High Estimate
Development Pending(2) - Unrisked (Mbbl)	16,256		35,773		59,511
Chance of Development	95	%	95	%	95	%
Development Pending - Risked (Mbbl)	15,443		33,985		56,535
Development Unclarified(3) - Unrisked (Mbbl)	-		66,677		97,763
Chance of Development	-		58	%	58	%
Development Unclarified - Risked (Mbbl)	-		38,406		55,160

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 | 2018 ANNUAL INFORMATION FORM     APPENDIX A | I

Summary of Net Bitumen Reserves as of December 31, 2018
(Forecast Prices and Costs)

	Bitumen - Reserves Category
	Total Proved	Total Proved Plus Probable	Total Proved Plus Probable Plus Possible
Net Reserves (Mbbl)	120,970	230,741	288,676

Summary of Net Bitumen Contingent Resources as of December 31, 2018
(Forecast Prices and Costs)

	Bitumen - Contingent Resource Category
Project Maturity Sub-Class(1)	Low Estimate		Best Estimate		High Estimate
Development Pending(2) - Unrisked (Mbbl)	12,910		27,262		45,827
Chance of Development	95	%	95	%	95	%
Development Pending - Risked (Mbbl)	12,265		25,899		43,535
Development Unclarified(3) - Unrisked (Mbbl)	-		52,606		73,060
Chance of Development			58	%	58	%
Development Unclarified - Risked (Mbbl)	-		30,301		42,082

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, 2018
(Forecast Prices and Costs)

	Before Income Taxes Discounted at (%/year) - $MM
Reserves Category	0%	5%	10%	15%	20%
Total Proved	4,043	2,250	1,436	1,018	779
Total Proved Plus Probable	8,161	4,149	2,420	1,577	1,117
Total Proved Plus Probable Plus Possible	12,097	5,371	2,946	1,886	1,341

PENGROWTH ENERGY CORPORATION | 2018 ANNUAL INFORMATION FORM     APPENDIX A | II

Summary of Bitumen Contingent Resources
Net Present Value of Future Net Revenue as of December 31, 2018
(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	335	86	23	6	2
		Chance of Development	95%	95%	95%	95%	95%
		Risked	318	81	22	6	2
	Best Estimate	Unrisked	891	226	59	16	4
		Chance of Development	95%	95%	95%	95%	95%
		Risked	847	214	57	15	4
	High Estimate	Unrisked	1,063	644	337	171	86
		Chance of Development	95%	95%	95%	95%	95%
		Risked	1,010	612	320	162	82
Development Unclarified	Low Estimate	Unrisked	-	-	-	-	-
		Chance of Development	58%	58%	58%	58%	58%
		Risked	-	-	-	-	-
	Best Estimate	Unrisked	1,089	382	115	11	(27)
		Chance of Development	58%	58%	58%	58%	58%
		Risked	627	220	66	7	(16)
	High Estimate	Unrisked	2,116	668	212	53	(7)
		Chance of Development	58%	58%	58%	58%	58%
		Risked	1,219	385	122	30	(4)

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% has thus been assigned to these development pending Contingent Resources.

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

PENGROWTH ENERGY CORPORATION | 2018 ANNUAL INFORMATION FORM     APPENDIX A | III

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% 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, 2018, 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 Pengrowth's 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%.

Summary of Gross Bitumen Contingent Resources as of December 31, 2018
(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, 2018
(Forecast Prices and Costs)

	Bitumen - Contingent Resource Category
Project Maturity Sub-Class(1)	Low Estimate		Best Estimate		High Estimate
Development Pending(2) - Unrisked (Mbbl)	30,814		44,467		57,548
Chance of Development	90	%	90	%	90	%
Development Pending - Risked (Mbbl)	27,733		40,021		51,793

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 | 2018 ANNUAL INFORMATION FORM     APPENDIX A | IV

Summary of Bitumen Contingent Resources
Net Present Value of Future Net Revenue as of December 31, 2018
(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	633	230	67	(5)	(38)
		Chance of Development	90%	90%	90%	90%	90%
		Risked	570	207	60	(4)	(34)
	Best Estimate	Unrisked	1,400	468	165	46	(6)
		Chance of Development	90%	90%	90%	90%	90%
		Risked	1,260	421	148	42	(6)
	High Estimate	Unrisked	2,335	650	217	68	6
		Chance of Development	90%	90%	90%	90%	90%
		Risked	2,101	585	195	61	5

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% working interest in the Selina oil sands property. It is located approximately 30km 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 $503 million with first major capital expenditures forecast in 2021 and production to commence in 2023. 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% 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 22 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 | 2018 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, 2018, 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 Pengrowth's 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%, whereas the likelihood of a Contingent Resource achieving commerciality will be less than 100%.

Summary of Gross Shale Gas Reserves as of December 31, 2018
(Forecast Prices and Costs)

	Shale Gas - Reserves Category
	Total Proved	Total Proved Plus Probable	Total Proved Plus Probable Plus Possible
Gross Reserves (MMcf)	192,998	792,700	947,055

Summary of Gross Shale Gas Contingent Resources as of December 31, 2018
(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)	503,718		730,466		914,067
Chance of Development	85	%	85	%	85	%
Development Pending - Risked (MMcf)	428,160		620,896		776,957

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, 2018
(Forecast Prices and Costs)

	Shale Gas - Reserves Category
	Total Proved	Total Proved Plus Probable	Total Proved Plus Probable Plus Possible
Net Reserves (MMcf)	170,413	669,867	790,862

PENGROWTH ENERGY CORPORATION | 2018 ANNUAL INFORMATION FORM     APPENDIX A | VI

Summary of Net Shale Gas Contingent Resources as of December 31, 2018
(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)	417,864		597,519		739,269
Chance of Development	85	%	85	%	85	%
Development Pending - Risked (MMcf)	355,184		507,891		628,379

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, 2018
(Forecast Prices and Costs)

	Before Income Taxes Discounted at (%/year) - $MM
Reserves Category	0%	5%	10%	15%	20%
Total Proved	294	165	100	64	42
Total Proved Plus Probable	1,540	646	322	178	104
Total Proved Plus Probable Plus Possible	2,096	790	378	206	121

Summary of Shale Gas Contingent Resources
Net Present Value of Future Net Revenue as of December 31, 2018
(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	984	271	82	26	8
		Chance of Development	85%	85%	85%	85%	85%
		Risked	836	230	70	22	7
	Best Estimate	Unrisked	1,765	475	151	52	19
		Chance of Development	85%	85%	85%	85%	85%
		Risked	1,500	404	128	44	16
	High Estimate	Unrisked	2,433	636	201	72	27
		Chance of Development	85%	85%	85%	85%	85%
		Risked	2,068	541	171	61	23

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 development. Contingent Resources are assigned by GLJ beyond those areas with reserves, to regions of the field where the zone

PENGROWTH ENERGY CORPORATION | 2018 ANNUAL INFORMATION FORM     APPENDIX A | VII

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 | 2018 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 December 31, 2018. The reserves data are estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2018, 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 December 31, 2018, 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 December 31, 2018, 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, 2018	Canada	-	2,760,012	-	2,760,012

6. The following tables set forth the risked volume and risked net present value of future net revenue of contingent resources(before deduction of income taxes) attributed to contingent resources, estimated using forecast prices and costs and calculated using a discount rate of 10%, 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, 2018	Canada	187.9	-	332,725	332,725

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, 2018	Canada	38.4

PENGROWTH ENERGY CORPORATION | 2018 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 25, 2019

(signed) "Todd J. Ikeda"

Todd J. Ikeda, P.Eng.

Vice President

PENGROWTH ENERGY CORPORATION | 2018 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, 2018, 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, 2018, 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) "Peter Sametz"	(signed) "Randall S. Steele"
Peter Sametz	Randall S. Steele
President and Chief Executive Officer	Chief Operating Officer
(signed) "James D. McFarland"	(signed) "Kelvin B. Johnston"
James D. McFarland	Kelvin B. Johnston
Director	Chairman of the Board
February 27, 2019

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 | 2018 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, AIF, 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 | 2018 ANNUAL INFORMATION FORM     APPENDIX D | II

4. Be responsible for reviewing the disclosure contained in Pengrowth's AIF 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 AIF 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 | 2018 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.

PENGROWTH ENERGY CORPORATION | 2018 ANNUAL INFORMATION FORM     APPENDIX D | IV

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.

PENGROWTH ENERGY CORPORATION | 2018 ANNUAL INFORMATION FORM     APPENDIX D | V

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

PENGROWTH ENERGY CORPORATION | 2018 ANNUAL INFORMATION FORM     APPENDIX D | VI

(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.

PENGROWTH ENERGY CORPORATION | 2018 ANNUAL INFORMATION FORM     APPENDIX D | VII

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;

PENGROWTH ENERGY CORPORATION | 2018 ANNUAL INFORMATION FORM     APPENDIX D | VIII

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.

PENGROWTH ENERGY CORPORATION | 2018 ANNUAL INFORMATION FORM     APPENDIX D | IX

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 Pengrowth).

(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.

PENGROWTH ENERGY CORPORATION | 2018 ANNUAL INFORMATION FORM     APPENDIX D | X

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.

PENGROWTH ENERGY CORPORATION | 2018 ANNUAL INFORMATION FORM     APPENDIX D | XI

1600, 222 3rd Avenue SW

Calgary , AB T2P 0B4

Canada

Telephone: 403-233-0224

Toll Free: 1-800-233-4122

Fax: 403-265-6251

Website: www.pengrowth.com

Investor Relations

Toll free: 1-855-336-8814

Email: investorrelations@pengrowth.com

TSX:PGF | OTCQX: PGHEF

EX-99.2

MANAGEMENT'S DISCUSSION AND 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, 2018 of Pengrowth Energy Corporation ("Pengrowth" or the "Corporation"). This MD&A is based on information available to March 5, 2019. All amounts are stated in Canadian dollars unless otherwise specified.

TABLE OF CONTENTS

Overview of Pengrowth	1
Key Highlights	2
2018 Results vs. Guidance	4
Oil and Gas Reserves	6
Operating Netback	7
Commodity Prices	8
Financial Results	13
Financial Resources and Liquidity	23
Summary of Quarterly Results	26
Business Risks	27
Critical Accounting Estimates	31
Non-GAAP Financial Measures	33
Disclosure and Internal Controls	36
Advisory Regarding Forward-Looking Statements	38
Glossary and Abbreviations	39

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. Please see the Business Risks section for more information on factors that could cause actual results to differ materially as well as the Advisory Regarding Forward-Looking Statements for an expanded discussion on this topic.

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. These metrics are trailing twelve months earnings before interest, taxes, DD&A, accretion ("EBITDA"), impairment, gain (loss) on disposition of properties, change in fair value of commodity risk management contracts, unrealized foreign exchange gain (loss), non-cash share based compensation expense, restructuring costs and EBITDA related to material divestments ("Adjusted EBITDA"); Adjusted EBITDA to Interest and Financing Charges ratio (the "Interest Coverage" ratio); Total debt before working capital to the trailing twelve months Adjusted EBITDA; Total debt before working capital as a percentage of total book capitalization ("Debt to Book Capitalization"); Adjusted net income (loss); Adjusted funds flow; Free funds flow; Produced petroleum revenue; Adjusted operating expenses; Royalty expenses as a percent of produced petroleum revenue; Operating netback before realized commodity risk management; and Cash G&A expenses. For more information please see the Non-GAAP Financial Measures section of the MD&A.

OVERVIEW OF PENGROWTH

Pengrowth is a conventional resource developer of Canadian oil and natural gas assets currently focused on growing bitumen production from the Lloydminster formation at the Lindbergh thermal oil project through steam assisted gravity drainage ("SAGD"). The project encompasses 32.5 sections of land with regulatory approval for 40,000 bbl/d. As one of the southernmost SAGD projects in Alberta, Lindbergh has natural advantages in terms of location and oil quality that allows flexibility in accessing markets.

Pengrowth’s 100 percent owned Groundbirch property in the Montney fairway encompasses 19 sections of land. This project fulfills the Lindbergh project’s natural gas needs. Dry natural gas from the Montney formation is produced using horizontal wells and multi-stage fracture technology with drilling potential of up to 360 unrisked net locations. The Corporation operates a 30 MMcf/d facility to process and deliver natural gas onto major pipelines.

PENGROWTH 2018 Management's Discussion and Analysis 1

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. 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.

KEY HIGHLIGHTS

	Three months ended				Twelve months ended
($ millions except per boe amounts)	Dec 31, 2018		Dec 31, 2017		Dec 31, 2018		Dec 31, 2017
Average production (boe/d)	24,104		24,702		22,025		40,428
Capital expenditures	9.1		28.2		65.4		117.9
Cash flow from operating activities	9.4		28.4		31.7		142.4
Adjusted funds flow (1)	(2.3	)	13.5		30.6		69.4
Operating netback before realized commodity risk management ($/boe) (1)	9.24		18.96		21.87		14.57
Adjusted net income (loss) (1)	(155.0	)	(217.1	)	(228.2	)	(745.6	)
Net income (loss)	(503.0	)	(210.4	)	(559.3	)	(683.8	)
Total debt before working capital (2)	714.6		610.5		714.6		610.5

⁽¹⁾  See definition under section "Non-GAAP Financial Measures".

⁽²⁾  Includes Credit Facility, current and long term portions of term notes, as applicable, and bank indebtedness. Excludes letters of credit and finance leases.

Cash Flow from Operating Activities

Cash flow from operating activities decreased $19.0 million in the fourth quarter of 2018 compared to the fourth quarter of 2017 driven by significant widening of WCS differentials and higher expenditures on remediation. Full year 2018 cash flow from operating activities decreased $110.7 million compared to last year mainly due to 2017 property divestments, changes in working capital and higher remediation spending.

Adjusted Funds Flow

Fourth quarter of 2018 negative adjusted funds flow of $2.3 million decreased $15.8 million from adjusted funds flow of $13.5 million in the same period last year. This was primarily due to lower realized bitumen prices as a result of wider WCS differentials coupled with higher cost of diluent and impact of lower volumes related to property divestments. These decreases were largely offset by the favourable impact of Pengrowth's WCS physical delivery fixed price differential contracts, higher bitumen production, lower G&A and absence of adjusted operating expenses and royalties related to divested properties.

Full year 2018 adjusted funds flow of $30.6 million decreased $38.8 million compared to last year primarily due to the impact of property divestments, higher realized commodity risk management losses and higher cost of diluent. Partly offsetting these decreases were higher overall realized bitumen prices due to a favourable impact of Pengrowth's WCS physical delivery fixed price differential contracts combined with higher bitumen production in 2018, lower cash G&A and lower interest and financing charges.

Net Income (Loss)

Pengrowth reported a net loss of $503.0 million in the fourth quarter of 2018 compared to a net loss of $210.4 million in the same period last year. The net loss increased primarily due to recording of deferred non-cash tax expense in the fourth quarter as a result of derecognition of a $355.4 million deferred tax asset, combined with lower adjusted funds flow. These were partly offset by an unrealized gain on commodity risk management compared to a loss in the same period last year, absence of loss on debt retirement and lower impairment charges.

Full year 2018 net loss was $559.3 million compared to a net loss of $683.8 million in 2017. The net loss decreased due to lower impairment charges in 2018, absence of losses on both property dispositions and debt retirement combined with lower DD&A expenses. These were mainly offset by deferred non-cash tax expense, as discussed above, together with lower adjusted funds flow.

PENGROWTH 2018 Management's Discussion and Analysis 2

Adjusted Net Income (Loss)

Pengrowth posted an adjusted net loss of $155.0 million in the fourth quarter of 2018 compared to an adjusted net loss of $217.1 million in the same period last year. The $62.1 million decrease in adjusted net loss was primarily due to absence of loss on debt retirement and lower impairment charges, partially offset by higher DD&A expenses.

Full year 2018 adjusted net loss of $228.2 million was $517.4 million lower compared to 2017 primarily due to significant decrease in impairment charges year over year.

FUTURE OPERATIONS

Through 2018, Pengrowth has had discussions with the lead banks in its syndicate regarding a new credit agreement that will permit Pengrowth to access the high yield debt market to refinance substantially all of its existing term notes as further described in Note 7 to the December 31, 2018 audited Consolidated Financial Statements. Pengrowth is also exploring alternative financing arrangements including third party debt providers to refinance its entire debt portfolio. These discussions, if successful, may result in an offer for replacement debt at a higher cost than the current outstanding debt.

Pengrowth engaged Perella Weinberg Partners LP and Tudor, Pickering, Holt & Co ("PWP/TPH") as advisers to assist in exploring financing alternatives. On March 5, 2019, the Board of Directors commenced a formal process with PWP/TPH to explore and develop strategic alternatives (the “Strategic Review”) with a view to strengthening the Corporation's balance sheet and maximizing enterprise value. The Strategic Review is intended to explore a comprehensive range of strategic and transaction alternatives, including a sale, merger or other business combination; a disposition of all or certain assets of the Corporation; recapitalization and refinancing opportunities; sourcing new financing and equity capital; and other alternatives to improve the Corporation's financial position and maximize value. In addition to Pengrowth’s long-life, low-decline assets, the Corporation also has potentially attractive tax attributes that complement its strong base operations. Pengrowth and its advisers expect to actively explore market interest in potential transactions and strategic initiatives with a range of interested parties and capital market participants. There can be no guarantees as to whether the Strategic Review will result in a transaction or the terms or timing of any resulting transaction. Various industry risk factors, including a prolonged or significant decrease in WTI or WCS pricing, could impact the outcome of the Strategic Review Process, Pengrowth’s cash flow, and its ability to address its upcoming debt maturities.

Furthermore, the Corporation is in discussions with the lending syndicate under its $330 million revolving credit facility (the "Credit Facility") on arrangements to extend the maturity date of the Credit Facility through September 30, 2019 to support the Strategic Review. The Corporation's objective is to finalize the extension agreement as soon as possible, and in advance of the current March 31, 2019 maturity date, however, there can be no assurance or guarantee that an extension will be obtained by the Corporation or on what terms.

Due to the rapid deterioration of commodity prices, uncertainty around improvements in global prices, and uncertainty around timing of refinancing of Pengrowth's debt portfolio, there remains a risk around Pengrowth's ability to stay in compliance with its debt covenants at the end of 2019.

As a result, there is significant uncertainty related to these events and conditions that raise substantial doubt about whether the Corporation will continue as a going concern, and therefore, whether it will realize its assets and settle its liabilities in the normal course of business and at the amounts stated in the financial statements. However, management believes that the Corporation will be successful in obtaining alternative debt financing and amending its financial covenants as outlined in Note 8 to the December 31, 2018 audited Consolidated Financial Statements in a timely manner and, accordingly, has prepared the financial statements on a going concern basis.

Accordingly, no adjustments have been made to the financial statements relating to the recoverability and classification of the asset carrying amounts or the amount and classification of liabilities that may be necessary should the consolidated entity not continue as a going concern. At this time, management believes that no asset is likely to be realized for an amount less than the amount at which it is recorded in financial statements as at December 31, 2018.

Pengrowth continues to generate sufficient cash flow to meet its obligations including interest payments, capital spending and abandonment and remediation expenses and plans to settle the October 2019 term notes with internally generated cash flow.

PENGROWTH 2018 Management's Discussion and Analysis 3

2018 ACTUAL RESULTS VS. 2018 GUIDANCE

The following table provides a summary of full year 2018 Guidance and actual results for the twelve months endedDecember 31, 2018:

	2018 Actual Results	2018 Guidance (1)
Average production (boe/d)	22,025	22,500 - 23,500
Capital expenditures ($ millions)	65.4	65
Royalty expenses (% of produced petroleum revenue) (2) (3)	7.9	8.5 (4)
Adjusted operating expenses ($/boe) (2)	10.54	10.50 - 11.50
Cash G&A expenses ($/boe) (2)	3.72	3.50 - 3.85 (4)

⁽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.

⁽⁴⁾  Guidance revised in the second quarter of 2018.

2018 actual daily production of 22,025 was slightly below the low end of 2018 Guidance due to an unplanned power outage at Lindbergh in December. Lindbergh production, however, exited 2018 at 19,120 bbl/d following resolution of the power outage.

2018 actual capital expenditures, royalty expenses as a percent of produced petroleum revenue, adjusted operating expenses and cash G&A expenses were all within 2018 Guidance.

2019 GUIDANCE

The following table provides Pengrowth's 2019 Guidance:

	2019 Guidance (1)
Average production (boe/d)	22,500 - 23,500
Capital expenditures ($ millions)	45
Royalty expenses (% of produced petroleum revenue) (2) (3)	7.0 - 8.0
Adjusted operating expenses ($/boe) (2)	9.25 - 10.00
Cash G&A expenses ($/boe) (2)	2.50 - 2.75

⁽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.

2019 Capital Program

Until Pengrowth refinances its term debt and renews its Credit Facility, capital spending will not exceed $21 million. Pengrowth's initial 2019 Budget calls for a capital spending plan of $45 million, with 76 percent of this capital allocated to Lindbergh. Pengrowth allocated approximately $34 million towards the continued development and maintenance activities at Lindbergh with approximately $22 million focused on continued optimization activities, including drilling of 3 well pairs. Pengrowth will continue to assess timing for commencement of the development program which is anticipated to be no sooner than the second half of 2019. The remaining $11 million of capital is related to maintenance and integrity activities to support the existing operations, including approximately $3 million to finalize the development program from 2018 at Groundbirch, and approximately $8 million of maintenance and integrity capital that has been allocated to the remaining operated assets as well as for general corporate purposes.

MULTI-YEAR DEVELOPMENT PLAN

In June 2018, Pengrowth launched its multi-year development plan to incrementally increase bitumen production at Lindbergh in bite sized steps rather than in one large phase.

Expansion at Lindbergh will be achieved in incremental steps aligning capital spending with Pengrowth’s expected cash flow, shifting the development methodology away from the previously contemplated large single phase approach. Development capital is expected to be focused on drilling new well pairs, additional infill wells, as well as, adding incremental facilities for fluid handling capacity. The Corporation expects to implement the use of Non-Condensable Gas ("NCG") to further enhance production and lower SORs. Regulatory approval for the application of NCG injection

PENGROWTH 2018 Management's Discussion and Analysis 4

at Lindbergh was received in June of 2018. Capital to be committed to Lindbergh in 2020 and onwards will be dependent on the prevailing commodity prices. In addition, Pengrowth continues to assess additional co-generation capacity options at Lindbergh to provide steam and power sufficient enough to support further efficient production expansions to reach approximately 35,000 bbl/d.

With the current commodity price uncertainty, Pengrowth is budgeting for a modest capital program of $45 million in 2019, however, until Pengrowth refinances its term debt and renews its Credit Facility, capital spending will not exceed $21 million.

Lindbergh full year average production volumes are expected to average between 17,750 to 18,250 bbl/d in 2019 with total corporate volumes expected to be between 22,500 to 23,500 boe/d. Pengrowth intends to redirect the free funds flow towards debt repayment and any future expansion will depend on stability and improvement of commodity prices and differentials.

Groundbirch has a low cost structure which supports growth in production and cash flow under a stronger natural gas pricing environment. Capital investment in Groundbirch beyond 2018 will be curtailed until natural gas pricing improves.

CAPITAL INVESTMENTS

	Three months ended		Twelve months ended
($ millions)	Dec 31, 2018	Dec 31, 2017	Dec 31, 2018	Dec 31, 2017
Drilling, completions and facilities
Lindbergh	2.2	12.1	34.1	79.5
Groundbirch and conventional assets	—	15.4	19.9	22.0
Maintenance and other development capital	6.3	0.6	10.7	15.7
Development capital	8.5	28.1	64.7	117.2
Other capital	0.6	0.1	0.7	0.7
Capital expenditures	9.1	28.2	65.4	117.9

Fourth quarter of 2018 capital expenditures of $9.1 million were primarily focused on the finalization of the tie-in activities related to the 2018 Lindbergh infill drilling program, well optimization activities and purchase of equipment for 2019 development program. Production from the 2018 Lindbergh infill drilling program was brought on stream through the fourth quarter of 2018 resulting in production exiting the year at 19,120 bbl/d.

Full year 2018 capital expenditures were $65.4 million, with $43.5 million spent at Lindbergh mostly related to conversion of wells drilled in 2017 to SAGD production and drilling and completion of the 2018 infill drilling program. The capital investment of $19.9 million at Groundbirch included completion and tie-in of 3 wells drilled in late 2017 and finalization of the compression project that enabled Pengrowth to shift transportation of natural gas production from Groundbirch away from Station Two delivery system and onto the Nova Gas Transmission Limited ("NGTL") system. The remaining capital was spent at Pengrowth’s conventional properties.

PRODUCTION

	Three months ended				Twelve months ended
Daily production	Dec 31, 2018	% of total	Dec 31, 2017	% of total	Dec 31, 2018	% of total	Dec 31, 2017	% of total
Bitumen (bbl/d)	17,866	74	14,430	58	16,325	74	13,754	34
Natural gas (Mcf/d)	33,024	23	42,251	29	28,716	22	91,367	38
Light oil (bbl/d)	476	2	2,094	8	675	3	6,872	17
Natural gas liquids (NGL) (bbl/d)	258	1	1,136	5	239	1	4,574	11
Total boe/d	24,104		24,702		22,025		40,428

Fourth quarter of 2018 total average daily production decreased 2 percent compared to the same period in 2017 due to the absence of approximately 5,250 boe/d of production related to properties divested in 2017. Mostly offsetting this impact was the 24 percent increase in bitumen production in the fourth quarter of 2018 compared to the same period in 2017 as the production growth from the Lindbergh infill wells drilled in 2018 outpaced natural declines. In addition, average production at Groundbirch increased 135 percent in the fourth quarter of 2018 compared to the same period last year driven by production ramp up from the three new wells drilled in the fourth quarter of 2017 which commenced

PENGROWTH 2018 Management's Discussion and Analysis 5

flow on the NGTL system on April 1, 2018 and the fourth well which commenced flow in the fourth quarter of 2018. The previously curtailed gas production at Groundbirch due to low natural gas prices was brought back on stream in the fourth quarter of 2018.

The gas production from Groundbirch provides a supply of natural gas for Pengrowth's requirements to generate steam at Lindbergh.

Fourth quarter of 2018 natural gas, light oil and NGL production decreased 22 percent, 77 percent and 77 percent, respectively, compared to the fourth quarter of 2017 due to property divestments.

Full year 2018 total average daily production decreased 46 percent compared to 2017 mainly due to the absence of approximately 21,400 boe/d of production related to 2017 divestments. This was offset by a 19 percent and 68 percent increase in Lindbergh and Groundbirch production, respectively, compared to 2017, as described above.

OIL AND GAS RESERVES

Reserves - Company Interest at Forecast Prices

Reserves Summary (1) (MMboe except as noted)	2018		2017
Proved Reserves
Additions + revisions for the year	9.7		27.7
Net dispositions for the year	(0.7	)	(106.0	)
Total proved reserves at period end	193.7		192.7
Proved reserve future development costs ($ millions)	1,871		1,932
Proved plus Probable Reserves (P+P)
Additions + revisions for the year	8.9		3.0
Net dispositions for the year	(0.9	)	(150.1	)
Total proved plus probable reserves at period end	446.5		446.6
P+P reserve future development costs ($ millions)	4,635		4,941
Total production (MMboe)	8.0		14.8

⁽¹⁾  Based on January 1, 2019 GLJ pricing and prepared in accordance with NI 51-101.

Pengrowth’s 2018 total proved reserves and total proved plus probable reserves remained flat compared to 2017 as reserve additions offset the impact of production. The reserve additions from development activity and technical revisions were 9.7 MMboe for total proved reserves and 8.9 MMboe for total proved plus probable reserves. The reserve additions were primarily related to reserves additions at Groundbirch from development activity over the last 12 months, as well as infill wells drilled at Lindbergh. There were positive technical revisions for both Lindbergh and Groundbirch as a result of capital efficiencies captured for undeveloped reserves.

Details of Pengrowth’s 2018 year end reserves are provided in its AIF which is filed on SEDAR (www.sedar.com) or the annual report on Form 40-F filed on EDGAR (www.sec.gov).

PENGROWTH 2018 Management's Discussion and Analysis 6

OPERATING NETBACKS

Pengrowth’s operating netbacks are defined as produced petroleum revenue, less royalties, less adjusted 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 ($/boe) (1)	Dec 31, 2018		Dec 31, 2017		Dec 31, 2018		Dec 31, 2017
Produced petroleum revenue (1)	24.80		37.14		38.24		32.96
Royalties	(1.67	)	(3.52	)	(3.01	)	(3.10	)
Adjusted operating expenses (1)	(10.87	)	(12.28	)	(10.54	)	(13.45	)
Transportation expenses	(3.02	)	(2.38	)	(2.82	)	(1.84	)
Operating netbacks before realized commodity risk management (1)	9.24		18.96		21.87		14.57
Realized commodity risk management	(4.69	)	(2.90	)	(8.40	)	(1.34	)
Operating netbacks ($/boe)	4.55		16.06		13.47		13.23

⁽¹⁾  See definition under section "Non-GAAP Financial Measures".

Fourth quarter of 2018 operating netback, before realized commodity risk management, decreased 51 percent compared to the same period in 2017 primarily due to a significant decrease in commodity prices with WTI and WCS seeing lower prices in the fourth quarter of 2018 compared to the rest of the year. Full year 2018 operating netback, before realized commodity risk management, increased 50 percent compared to 2017 due to improved realized commodity prices year over year coupled with lower adjusted operating expenses.

Fourth quarter of 2018 operating netbacks, after realized commodity risk management, decreased 72 percent compared to the same period in 2017 mainly due to a decrease in realized prices coupled with higher per boe realized commodity risk management losses in 2018. Full year 2018 operating netbacks, after realized commodity risk management, increased 2 percent as higher realized prices in 2018 and lower adjusted operating expenses more than offset higher per boe realized commodity risk management losses.

PENGROWTH 2018 Management's Discussion and Analysis 7

COMMODITY PRICES

Pengrowth’s revenues are substantially derived from the sale of diluted bitumen, light oil, natural gas and natural gas liquids and are dependent on commodity prices the Corporation receives. The following table shows industry benchmark prices and foreign exchange rates to assist in understanding the impact of commodity prices, price differentials and foreign exchange rates on Pengrowth’s financial results:

Benchmark Prices and Differentials

	Three months ended				Twelve months ended
	Dec 31, 2018		Dec 31, 2017		Dec 31, 2018		Dec 31, 2017
Average Commodity Prices
Crude Oil:
WTI oil (U.S.$/bbl)	58.83		55.39		64.79		50.93
WTI oil (Cdn$/bbl)	77.41		70.45		84.14		66.09
WCS differential to WTI (U.S.$/bbl)	(39.38	)	(12.28	)	(26.60	)	(11.96	)
WCS oil (U.S.$/bbl)	19.45		43.11		38.19		38.97
WCS oil (Cdn$/bbl)	25.59		54.83		49.60		50.53
Condensate:
Condensate at Edmonton (Cdn$/bbl)	59.68		73.74		78.95		66.45
WCS differential to Condensate (Cdn$/bbl)	(34.09	)	(18.91	)	(29.35	)	(15.92	)
Natural Gas:
AECO monthly gas (Cdn$/MMBtu)	1.90		1.98		1.53		2.43
Average Exchange Rate
Cdn$1=U.S.$	0.76		0.79		0.77		0.77

Crude Oil Benchmark Prices and Differentials

The WTI price, which is an important benchmark reflecting the inland North American crude oil price, averaged U.S.$58.83/bbl during the fourth quarter of 2018, reflecting a 6 percent increase compared to the same period in 2017. Full year 2018 WTI price averaged U.S.$64.79/bbl, an increase of 27 percent from 2017.

Despite the increase in WTI, Alberta heavy and light oil producers were subjected to a larger discount for their production. Exchange rates, location, quality differentials and transportation bottlenecks are all factors that impact the price received for Canadian crude oil. WCS is a blend of heavy oil consisting of conventional heavy oil and diluted bitumen and the benchmark price represents the Canadian heavy oil price at Hardisty, Alberta.

The differential between WCS and WTI widened significantly in the fourth quarter of 2018 averaging U.S.$39.38/bbl compared to U.S.$12.28/bbl in the same period in 2017. The unprecedented widening in the differential was the result of new crude oil production coming onstream in Western Canada, rising inventory and refinery turnarounds in the U.S. which temporarily reduced demand. The industry continues to work toward alleviating transportation bottlenecks through crude by rail, existing pipeline optimization and temporary mandated production curtailments in the province of Alberta.

As a result of substantive differentials to WTI, fourth quarter of 2018 average U.S. dollar WCS oil price was 55 percent lower compared to the fourth quarter of 2017. Average full year 2018 U.S. dollar WCS price was 2 percent lower compared to 2017.

Condensate Benchmark Prices and Differentials

In order to meet pipeline specifications and facilitate delivery on pipeline systems, bitumen production is blended with condensate which is used as a diluent to reduce viscosity. Pengrowth’s blending ratio which reflects diluent volumes as a percentage of total blended volumes remained unchanged at approximately 30percent during 2018 as compared to 2017. The WCS to Condensate differential reflects the amount of condensate costs that are not recoverable when selling a barrel of diluted bitumen. The narrower the WCS to Condensate differential, the more condensate costs are recovered. When the demand for condensate in Alberta exceeds the supply available, Edmonton condensate prices may be driven by U.S. Gulf Coast condensate prices plus the cost to transport the condensate to Edmonton. Condensate prices, at Edmonton, decreased in the fourth quarter of 2018 to an average of Cdn$59.68/bbl compared to Cdn$73.74/

PENGROWTH 2018 Management's Discussion and Analysis 8

bbl in the same period in 2017 due to decreasing overall global prices beginning in the fourth quarter of 2018. Condensate prices for full year 2018 increased to an average of Cdn$78.95/bbl compared to Cdn$66.45/bbl in 2017, primarily due to higher demand for diluent in Alberta.

Natural Gas Benchmark Prices and Differentials

The average AECO natural gas prices decreased 4 percent and 37 percent in the fourth quarter of 2018 and full year 2018, respectively, compared to the same periods in 2017 primarily due to an oversupply of Canadian natural gas and transportation constraints.

Average Realizations

	Three months ended				Twelve months ended
(Cdn$)	Dec 31, 2018		Dec 31, 2017		Dec 31, 2018		Dec 31, 2017
Average Sales Price (1)
Diluted bitumen (Cdn$/bbl) (2) (3)	42.23		50.96		56.47		46.17
Diluent cost and transportation (Cdn$/bbl)	(14.73	)	(9.68	)	(12.15	)	(10.00	)
Bitumen (Cdn$/bbl) (4)	27.50		41.28		44.32		36.17
Natural gas sold to third party (Cdn$/Mcf) (5)	1.25		3.22		1.58		2.96
Deemed natural gas sales used in operations (Cdn$/Mcf) (5) (6)	1.12		—		0.69		—
Total natural gas (Cdn$/Mcf) (5)	2.37		3.22		2.27		2.96
Light oil (Cdn$/bbl)	25.12		61.25		60.07		59.52
Natural gas liquids (Cdn$/bbl)	63.20		50.71		53.88		33.96

⁽¹⁾  Excluding realized financial risk management contracts.

⁽²⁾  Calculated based on diluted bitumen sales volumes.

⁽³⁾  During 2018, Pengrowth managed WCS differential with fixed price differential physical delivery contracts of 17,000 bbl/d at approximately U.S.$16.82/bbl of diluted bitumen.

⁽⁴⁾  Calculated based on bitumen sales volumes and excludes diluent sold.

⁽⁵⁾  Average sales prices are recorded in Mcf to reflect the volumetric reporting standard for Pengrowth's natural gas.

⁽⁶⁾  Starting April 1, 2018, a portion of natural gas sales from Groundbirch is used for operational requirements and recorded at AECO/NIT 7A monthly index prices.

Diluted Bitumen and Bitumen Realizations

Pengrowth uses physical delivery contracts to ensure access to markets, protect against pipeline apportionment, and limit credit risk and exposure to widening WCS differentials. Fourth quarter and full year 2018 diluted bitumen sales averaged 25,886 bbl/d and 23,452 bbl/d, respectively, of which 17,000 bbl/d was subject to physical delivery fixed price WCS differential contracts averaging approximately U.S.$16.82/bbl discount to WTI. This resulted in fourth quarter and full year 2018 average diluted bitumen realized prices of Cdn$42.23/bbl and Cdn$56.47/bbl, respectively, exceeding WCS benchmarks in both periods.

Pengrowth’s average bitumen sales price represents the price received for bitumen production from Lindbergh, prior to blending of the product with diluent. Fourth quarter of 2018 bitumen realization was 33 percent lower compared to the same period in 2017 primarily due to the decrease in WCS in the fourth quarter of 2018 coupled with higher condensate costs. The impact of sharp decline in WCS in the fourth quarter, however, was substantially muted by Pengrowth's fixed price differential physical delivery contracts of 17,000 bbl/d at approximately U.S.$16.82/bbl of diluted bitumen. Full year 2018 bitumen realization increased 23 percent compared to 2017, in spite of WCS remaining flat year over year, driven by the favourable impact of the WCS physical delivery fixed price differential contracts in 2018.

Natural Gas, Light Oil and NGL Realizations

Realized pricing for light oil moved in line with the underlying Canadian benchmarks which also experienced wider discounts to global prices. The increase in NGL pricing year over year reflects movements in the underlying benchmark and a more favourable pricing environment for component products.

The price realized by the Corporation for natural gas production from Western Canada is primarily determined by the AECO benchmark and based on Canadian fundamentals. During 2018, Pengrowth also sold its natural gas from SOEP at other sales points including Algonquin City Gate in the Northeast U.S., which resulted in significant variances between Pengrowth's realized natural gas prices and the AECO benchmark prices in 2018.

PENGROWTH 2018 Management's Discussion and Analysis 9

Pengrowth’s fourth quarter and full year 2018 average sales price for natural gas decreased 26 percent and 23 percent, respectively, compared to the same periods in 2017. The lower realized prices correspond to the decrease in AECO benchmark price as noted above, partially offset by the higher Algonquin benchmark price.

Produced Petroleum Revenue Realizations

Produced petroleum revenue realizations are calculated based on bitumen, natural gas, light oil and natural gas liquids sales volumes and exclude processing income, diluent and other revenue.

	Three months ended				Twelve months ended
(Cdn$/boe)	Dec 31, 2018		Dec 31, 2017		Dec 31, 2018		Dec 31, 2017
Produced petroleum revenue (1)	24.80		37.14		38.24		32.96
Realized commodity risk management gain (loss)	(4.69	)	(2.90	)	(8.40	)	(1.34	)
Total including realized commodity risk management	20.11		34.24		29.84		31.62

⁽¹⁾  See definition under section "Non-GAAP Financial Measures".

Pengrowth’s fourth quarter produced petroleum revenue realizations of $24.80/boe decreased 33 percent compared to the same period in 2017 in line with widening of WCS differentials throughout the fourth quarter of 2018. Full year 2018 produced petroleum revenue realizations of $38.24/boe increased 16 percent compared to the same period in 2017, primarily reflecting stronger bitumen realizations year over year.

Realized commodity risk management losses of $4.69/boe and $8.40/boe were recorded in the fourth quarter and full year 2018, respectively, due to WTI exceeding the fixed prices in WTI commodity risk management contracts, all of which expired at the end of 2018. At December 31, 2018, Pengrowth held financial WCS differential swaps for 5,000 bbl/d of dilbit at U.S.$20.88/bbl for 2019.

Commodity Price Risk Management

Realized Commodity Risk Management Gains (Losses) from Financial Contracts

	Three months ended				Twelve months ended
($ millions except per unit amounts)	Dec 31, 2018		Dec 31, 2017		Dec 31, 2018		Dec 31, 2017
Oil risk management gain (loss)	(10.4	)	(9.0	)	(67.5	)	(25.8	)
$/bbl (1)	(6.16	)	(5.92	)	(10.88	)	(3.43	)
Natural gas risk management gain (loss)	—		2.4		—		6.0
$/Mcf	—		0.62		—		0.18
Total realized commodity risk management gain (loss)	(10.4	)	(6.6	)	(67.5	)	(19.8	)
$/boe	(4.69	)	(2.90	)	(8.40	)	(1.34	)

⁽¹⁾  Includes light oil and bitumen.

Pengrowth's commodity risk management program primarily uses forward price swaps and collars to manage the exposure to commodity price and differential 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 risk management program is adequate and aligned with the long term strategic goals of the Corporation.

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.

Realized commodity risk management losses of $10.4 million and $67.5 million were recorded in the fourth quarter and full year 2018, respectively, primarily due to WTI benchmark prices exceeding the fixed prices in WTI commodity risk management contracts, all of which expired at the end of 2018. At December 31, 2018, Pengrowth held financial WCS differential swaps for 5,000 bbl/d of dilbit at U.S.$20.88/bbl for 2019.

PENGROWTH 2018 Management's Discussion and Analysis 10

Changes in Fair Value of Financial Commodity Risk Management Contracts

	Three months ended				Twelve months ended
($ millions)	Dec 31, 2018		Dec 31, 2017		Dec 31, 2018		Dec 31, 2017
Fair value of commodity risk management assets (liabilities) at period end	(4.2	)	(39.8	)	(4.2	)	(39.8	)
Less: Fair value of commodity risk management assets (liabilities) at beginning of period	(26.4	)	(6.5	)	(39.8	)	(54.0	)
Change in fair value of commodity risk management contracts for the period	22.2		(33.3	)	35.6		14.2

Changes in fair value of commodity risk management contracts vary period to period and are a function of the volumes under risk management contracts, 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.

For the three months ended December 31 2018, Pengrowth recorded a change in the fair value of commodity risk management contracts of $22.2 million as the fair value of commodity risk management liabilities at September 30, 2018 of $26.4 million decreased to a liability of $4.2 million at December 31, 2018. The decrease in liability was primarily the result of the settlement of contracts during the fourth quarter of 2018.

Pengrowth recorded a change in the fair value of commodity risk management contracts of $35.6 million at December 31, 2018, an increase relative to December 31, 2017 also as a result of a decrease in fair value of commodity risk management liabilities from the settlement of contracts.

At December 31, 2018, Pengrowth had the following financial contracts outstanding:

Financial Crude Oil Contracts:
Swaps
Differentials
Reference point	Term	Volume of dilbit (bbl/d)	Price/bbl (U.S.$)
Western Canada Select	2019	5,000	WTI less $20.88

Financial Risk Management Contracts Sensitivity to Commodity Prices as at December 31, 2018

($ millions)
Oil differentials	Cdn$1 decrease in future oil differential		Cdn$1 increase in future oil differential
Increase (decrease) to fair value of financial differential risk management contracts	(1.3	)	1.3

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, 2018, revenue and cash flow wouldhave been $4.2 million lower than if the risk management contracts were not in place based on the estimated fair value of the risk management contracts at period end. The $4.2 million liability was related to risk management contracts expiring within one year.

PENGROWTH 2018 Management's Discussion and Analysis 11

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, natural gas and differential contracts are recorded separately on the Consolidated Statements of Income (Loss) and impact cash flow at that time.

Physical Delivery Risk Management Contracts

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 contract prices is included in oil and gas sales, as per the Consolidated Statements of Income (Loss), and therefore in realized average sales prices.

At December 31, 2018, Pengrowth had the following apportionment protected physical delivery contracts outstanding:

WCS Differentials
Physical Delivery Contracts
Reference point	Term	Volume of dilbit (bbl/d)	Price/bbl (U.S.$)
Western Canada Select	2019	2,500	WTI less $17.95
Western Canada Select	2019	2,500	WTI less $23.60 - $26.35
Western Canada Select	2019	5,000	WTI less $17.70 - $20.45
Western Canada Select	Feb 1, 2019 - Feb 1, 2020	2,500	WTI less $20.40 - $23.40

Pengrowth has also entered into a secured term sale agreement at Hardisty for an additional 5,000 bbl/d of dilbit for 2019 that are 100 percent apportionment protected. Pengrowth will settle at the monthly WCS Index less an apportionment protection fee of U.S.$2.00/bbl.

In the fourth quarter of 2018, Pengrowth produced an average of 17,866 bbl/d of bitumen and sold an average of25,886 bbl/d of dilbit at Hardisty. Full year 2018 bitumen production averaged 16,325 bbl/d with an average of 23,452 bbl/d of dilbit sold at Hardisty.

See Note 16 to the December 31, 2018 audited Consolidated Financial Statements for more information.

PENGROWTH 2018 Management's Discussion and Analysis 12

FINANCIAL RESULTS

OIL AND GAS SALES

The following table shows the composition of oil and gas sales:

	Three months ended			Twelve months ended
($ millions)	Dec 31, 2018		Dec 31, 2017	Dec 31, 2018		Dec 31, 2017
Bitumen	45.2		54.8	264.1		181.6
Natural gas (1) (2)	7.2		12.5	23.8		98.8
Light oil	1.1		11.8	14.8		149.3
Natural gas liquids	1.5		5.3	4.7		56.7
Produced petroleum revenue (1)	55.0		84.4	307.4		486.4
Sale of diluent and other	59.6		46.1	232.0		187.0
Less: deemed natural gas sales used in operations (2)	(3.4	)	—	(7.2	)	—
Oil and gas sales (3)	111.2		130.5	532.2		673.4

⁽¹⁾  See definition under section "Non-GAAP Financial Measures".

⁽²⁾  Starting April 1, 2018 incorporates a portion of natural gas sales from Groundbirch used for operational requirements and recorded at AECO/NIT 7A monthly index prices.

⁽³⁾  Excludes realized commodity risk management from financial contracts.

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, 2018 versus Quarter ended December 31, 2017

The following table illustrates the effect of changes in prices and volumes on the components of produced petroleum revenue:

($ millions)	Bitumen		Natural gas (2)		Light oil		NGLs		Produced petroleum revenue (2)
Quarter ended December 31, 2017 (1)	54.8		12.5		11.8		5.3		84.4
Effect of change in product prices and differentials	(22.6	)	(2.6	)	(1.6	)	0.3		(26.5	)
Effect of change in sales volumes	13.0		(2.7	)	(9.1	)	(4.1	)	(2.9	)
Quarter ended December 31, 2018 (1)	45.2		7.2		1.1		1.5		55.0

⁽¹⁾  Excludes realized commodity risk management from financial contracts.

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

Bitumen sales decreased by 18 percent in the fourth quarter of 2018 compared to the same period in 2017 mostly driven by the significant decline in WCS in the fourth quarter of 2018 largely offset by the favourable impact of physical delivery fixed price differential contracts combined with higher production volumes. Natural gas, light oil and NGL sales decreased 42 percent, 91 percent and 72 percent, respectively, compared to the fourth quarter of 2017 primarily due to decreases in sales volumes related to 2017 divestments combined with the decline in realized prices for light oil and natural gas.

PENGROWTH 2018 Management's Discussion and Analysis 13

Twelve Months ended December 31, 2018 versus Twelve Months ended December 31, 2017

The following table illustrates the effect of changes in prices and volumes on the components of produced petroleum revenue:

($ millions)	Bitumen	Natural gas (2)		Light oil		NGLs		Produced petroleum revenue (2)
Twelve months ended December 31, 2017 (1)	181.6	98.8		149.3		56.7		486.4
Effect of change in product prices and differentials	48.6	(7.3	)	0.1		1.7		43.1
Effect of change in sales volumes	33.9	(67.7	)	(134.6	)	(53.7	)	(222.1	)
Twelve months ended December 31, 2018 (1)	264.1	23.8		14.8		4.7		307.4

⁽¹⁾  Excludes realized commodity risk management from financial contracts.

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

Full year 2018 bitumen sales increased 45 percent compared to 2017 resulting from the favorable impact of physical delivery fixed price differential contracts combined with higher production volumes. Natural gas, light oil and NGL sales decreased 76 percent, 90 percent and 92 percent, respectively, compared to 2017 primarily due to the decrease in sales volumes related to 2017 divestments.

ROYALTIES

($ millions except per boe amounts and percentages)	Three months ended		Twelve months ended
	Dec 31, 2018	Dec 31, 2017	Dec 31, 2018	Dec 31, 2017
Royalties, net of incentives	3.7	8.0	24.2	45.8
$/boe	1.67	3.52	3.01	3.10
Royalties as a percent of produced petroleum revenue (%) (1) (2)	6.7	9.5	7.9	9.4

⁽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 GCA.

The Lindbergh Crown royalty rate is price sensitive and varies depending on whether the project is pre-payout or post-payout. Lindbergh is currently in pre-payout, and will reach payout when its cumulative revenues exceed its cumulative eligible costs. The Crown royalty rate applicable to pre-payout varies from 1 percent when the monthly Cdn$ equivalent WTI price is less than or equal to $55/bbl to 9 percent when the Cdn$ equivalent WTI price is in excess of $120/bbl. Lindbergh royalties also incorporate a 4.0 percent gross overriding royalty that is based on posted WCS benchmark prices.

Fourth quarter of 2018 royalties as a percent of produced petroleum revenue decreased to 6.7 percent from 9.5 percent in the fourth quarter of 2017. The overall decrease in the fourth quarter of 2018 royalty rate is primarily attributed to lower Lindbergh gross overriding royalties paid in the quarter as a result of a significant WCS benchmark price decrease compared to the same period last year. This was coupled with the absence of royalties related to divested properties of approximately $3 million.

Full year 2018 royalties as a percent of produced petroleum revenue decreased to 7.9 percent from 9.4 percent in the same period last year driven by the absence of approximately $27 million of royalties related to divested properties. This was partly offset by higher Lindbergh crown royalties year over year driven by an increase in WTI.

PENGROWTH 2018 Management's Discussion and Analysis 14

ADJUSTED OPERATING EXPENSES

($ millions except per boe amounts)	Three months ended				Twelve months ended
	Dec 31, 2018		Dec 31, 2017		Dec 31, 2018		Dec 31, 2017
Operating expenses	21.2		30.1		79.5		217.5
Cost of natural gas used in internal operations (1)	3.4		—		7.2		—
Less: Processing income	(0.5	)	(2.2	)	(2.0	)	(19.1	)
Adjusted operating expenses (1) (2)	24.1		27.9		84.7		198.4
$/boe	10.87		12.28		10.54		13.45

⁽¹⁾  Starting April 1, 2018, incorporates the cost of a portion of natural gas delivered from Groundbirch to the NGTL system and used in operations as energy costs calculated using AECO/NIT 7A monthly index prices.

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

Fourth quarter of 2018 adjusted operating expenses decreased $3.8 million or 14 percent compared to the same period in 2017 primarily due to the absence of approximately $5 million of adjusted operating expenses associated with the divested properties. Adjusted operating expenses related to the remaining assets were relatively unchanged in the fourth quarter of 2018 compared to the fourth quarter of 2017.

Full year 2018 adjusted operating expenses decreased $113.7 million or 57 percent compared to the same period in 2017 primarily due to the absence of approximately $115 million of adjusted operating expenses associated with the divested properties.

On a per boe basis, fourth quarter and full year 2018 adjusted operating expenses decreased $1.41/boe and $2.91/boe, respectively, compared to the same periods last year driven by the impact of property dispositions mentioned above.

DILUENT AND OTHER PURCHASES

	Three months ended		Twelve months ended
($ millions)	Dec 31, 2018	Dec 31, 2017	Dec 31, 2018	Dec 31, 2017
Diluent cost	55.4	41.4	219.3	147.2
Other product purchases	3.7	1.3	10.2	16.3
Diluent and other purchases	59.1	42.7	229.5	163.5

Diluent costs reflect the cost of condensate required for processing activities and blending with bitumen to reduce viscosity and meet pipeline specifications. The amount of condensate costs depends on the volume of diluent required for blending and the price of condensate.

Fourth quarter and full year 2018 diluent costs increased $14.0 million and $72.1 million, respectively, compared to the same periods last year as the increase in bitumen production in 2018 relative to 2017 required higher volume of purchased diluent. In addition, average condensate prices were stronger in 2018 compared with 2017 due to higher demand for diluent in Alberta further increasing the overall cost of purchased condensate. Pengrowth's blending ratio which reflects diluent volumes as a percentage of total blended volumes remained unchanged at approximately 30 percent throughout 2018 as compared to 2017.

Other product purchases include third party hydrocarbons purchased for resale. The reduction in other product purchases in 2018 was due to the impact of 2017 property divestments.

PENGROWTH 2018 Management's Discussion and Analysis 15

TRANSPORTATION EXPENSES

($ millions except per boe amounts)	Three months ended		Twelve months ended
	Dec 31, 2018	Dec 31, 2017	Dec 31, 2018	Dec 31, 2017
Transportation expenses	6.7	5.4	22.7	27.1
$/boe	3.02	2.38	2.82	1.84

Fourth quarter of 2018 transportation expenses increased $1.3 million compared to the same period in 2017 due to incremental transportation expenses related to higher Lindbergh production.

Full year 2018 transportation expenses decreased $4.4 million driven by the absence of transportation expenses related to divested properties of approximately $8.0 million partly offset by incremental transportation expenses related to higher Lindbergh production.

On a per boe basis, the increase in the fourth quarter and full year 2018 relative to the same periods in 2017 resulted from Lindbergh representing a higher proportion of total production following the 2017 dispositions, with Lindbergh having a higher cost per boe than the sold properties.

GENERAL AND ADMINISTRATIVE EXPENSES

	Three months ended			Twelve months ended
($ millions except per boe amounts)	Dec 31, 2018	Dec 31, 2017		Dec 31, 2018	Dec 31, 2017
Cash G&A expenses (1) (2)	4.2	12.6		29.9	56.6
$/boe	1.89	5.54		3.72	3.84
Non-cash G&A expenses (1)	1.7	(1.3	)	4.8	4.9
$/boe	0.77	(0.57	)	0.60	0.33
Total G&A (1)	5.9	11.3		34.7	61.5
$/boe	2.66	4.97		4.32	4.17

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

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

Fourth quarter and full year 2018 cash G&A expenses decreased $8.4 million or 67 percent and $26.7 million or 47 percent, respectively, compared to the same periods in 2017 primarily due to significantly lower staffing costs as well as lower office and IT expenditures. These decreases were driven by corporate restructuring following the 2017 asset divestments.

On a per boe basis, fourth quarter and full year 2018 cash G&A expenses decreased $3.65/boe and $0.12/boe, respectively, compared to the same periods in 2017 reflecting the decreases in cash G&A expenses as described above.

The non-cash component of G&A represents the compensation expenses associated with Pengrowth’s share-settled LTIP (as defined below). See Note 12 to the December 31, 2018 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 non-cash G&A expenses increased $3.0 million compared to the same period in 2017 primarily due to the absence of forfeiture rate increase reflected in the fourth quarter of 2017 which was related to staff reductions. Fourth quarter of 2018 incorporated lower performance factors for 2018 performance year. Full year 2018 non-cash G&A expenses remained relatively unchanged compared to 2017 as the absence of increase in forfeiture rates in 2018 was offset by the introduction of the stock option plan in 2018.

During the twelve months ended December 31, 2018, $1.7 million (December 31, 2017 - $2.3 million) of directly attributable G&A costs were capitalized to Property, Plant and Equipment ("PP&E").

PENGROWTH 2018 Management's Discussion and Analysis 16

RESTRUCTURING COSTS

	Three months ended		Twelve months ended
($ millions)	Dec 31, 2018	Dec 31, 2017	Dec 31, 2018		Dec 31, 2017
Severance costs	0.1	1.3	2.1		10.5
Onerous office lease contracts	—	18.5	(1.7	)	26.5
Total restructuring costs	0.1	19.8	0.4		37.0

During 2017, Pengrowth completed a number of significant asset dispositions which led to a management decision to complete an operational restructuring. For more information about the restructuring costs refer to the December 31, 2017 annual report.

Full year 2018 restructuring costs contained an additional $2.1 million expense relating to severance costs and a $1.7 million reduction related to an estimate revision to the onerous office lease provision.

DEPLETION, DEPRECIATION, AMORTIZATION AND ACCRETION

	Three months ended		Twelve months ended
($ millions except per boe amounts)	Dec 31, 2018	Dec 31, 2017	Dec 31, 2018	Dec 31, 2017
Depletion, depreciation and amortization	64.2	31.9	162.3	207.6
$/boe	28.95	14.04	20.19	14.07
Accretion	1.8	1.3	7.0	11.4
$/boe	0.81	0.57	0.87	0.77

Fourth quarter of 2018 DD&A expenses increased $32.3 million compared to the same period in 2017 primarily due to approximately $32 million of accelerated depletion on properties considered to be at the end of their economic life.

Full year 2018 DD&A expenses decreased $45.3 million compared to 2017 due to the absence of approximately $86 million of DD&A associated with the divested properties, partially offset by the accelerated depletion noted above and higher Lindbergh and Groundbirch DD&A driven by the production growth from the Lindbergh infill wells drilled in 2018 and increased production at Groundbirch.

Excluding accelerated depletion of approximately $32 million, fourth quarter of 2018 DD&A per boe was $14.52/boe remaining relatively unchanged from fourth quarter of 2017. Full year 2018 DD&A per boe, excluding the accelerated depletion of approximately $32 million, was $16.21/boe reflecting a $2.14/boe increase due to higher unit of production compared to 2017.

Accretion includes ARO (as defined below) accretion expense as well as accretion related to the onerous lease provision. Fourth quarter 2018 accretion expense increased $0.5 million compared to the same period last year related to accretion on the onerous lease provision. However, it decreased full year by $4.4 million compared to 2017 primarily due to the absence of accretion related to the ARO liability associated with properties disposed of in 2017.

EXPLORATION AND EVALUATION ASSETS ("E&E")

Pengrowth's E&E assets consist of exploration and development projects which are pending the determination of technical feasibility and commercial viability.

E&E assets totaled $82.6 million at December 31, 2018 and were primarily related to the Groundbirch gas property in north eastern British Columbia. After completion of Pengrowth's 2018 capital program and year end reserves evaluation, certain E&E costs were transferred to PP&E for the year ended December 31, 2018. See Note 6 to the December 31, 2018 audited Consolidated Financial Statements.

PENGROWTH 2018 Management's Discussion and Analysis 17

IMPAIRMENTS

	Three months ended		Twelve months ended
($ millions)	Dec 31, 2018	Dec 31, 2017	Dec 31, 2018	Dec 31, 2017
PP&E impairments	—	—	—	504.4
E&E impairments	91.0	130.0	91.0	130.0
Total impairments	91.0	130.0	91.0	634.4

At December 31, 2017, PP&E impairment charges of $504.4 million were recorded. 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 Cash Generating Units ("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 properties. Refer to Note 5 to the December 31, 2018 audited Consolidated Financial Statements for additional information.

For the year ended December 31, 2018, Pengrowth evaluated the Groundbirch gas property for an impairment in conjunction with the Montney CGU due to the negative impact resulting from the significant downturn in the forward natural gas benchmark prices late in 2018. In accordance with Pengrowth's policy, the E&E assets are assessed in conjunction with the cash flow from the applicable PP&E CGU. It was determined that the recoverable amount of the CGU was below the carrying amount and a $91.0 million impairment on the Groundbirch E&E asset was recorded in the fourth quarter of 2018.

The recoverable amount was computed with reference to the present value of the future cash flows expected to be derived from production of proved plus probable reserves and contingent resources. 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, 2019 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, 2018 audited Consolidated Financial Statements for more information.

At December 31, 2017, Pengrowth evaluated the Groundbirch gas property in conjunction with the Montney CGU for an impairment. It was determined that the recoverable amount was below the carrying amount, resulting in a $129.0 million impairment on the Groundbirch E&E asset in the fourth quarter of December 31, 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.

INTEREST AND FINANCING CHARGES

	Three months ended			Twelve months ended
($ millions)	Dec 31, 2018	Dec 31, 2017		Dec 31, 2018		Dec 31, 2017
Interest and financing charges	13.8	13.4		52.2		74.4
Capitalized interest	—	(1.0	)	(2.4	)	(3.7	)
Total interest and financing charges	13.8	12.4		49.8		70.7

At December 31, 2018, Pengrowth had $541.1 million in outstanding fixed rate debt and $173.5 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 7.4 percent interest rate.

Fourth quarter and full year 2018 interest and financing charges, before capitalized interest, increased $0.4 million or 3 percent compared to the same period last year due to higher borrowings on the Credit Facility in 2018. Full year 2018 interest and financing charges, before capitalized interest, decreased $22.2 million or 30 percent compared to 2017 reflecting the impact of the prepayments of term notes of approximately $1 billion throughout 2017, the repayment of $126.6 million of convertible debentures at maturity on March 31, 2017, partially offset by the incremental interest from increased borrowings on the Credit Facility in 2018.

PENGROWTH 2018 Management's Discussion and Analysis 18

Pengrowth ceased capitalization of interest during the third quarter of 2018 due to the change in the development plan for Lindbergh. During the twelve months ended December 31, 2018, $2.4 million (December 31, 2017 - $3.7 million) of interest was capitalized on the Lindbergh project to PP&E using Pengrowth's weighted average cost of debt of 6.5 percent (December 31, 2017 - 5.7 percent).

TAXES

Deferred income tax is a non-cash item relating to temporary differences between the accounting and tax basis of Pengrowth's assets and liabilities. As at December 31, 2018, Pengrowth was in a net unrecognized deferred tax asset position due to uncertainty of Pengrowth's ability to realize the tax assets in future years. This resulted in a non-cash deferred tax expense of $342.2 million during the year ended December 31, 2018 related to the unrecognized deductible temporary differences in excess of taxable temporary differences of approximately $1.8 billion.

The deferred tax recovery of $223.8 million recognized during the year ended December 31, 2017 was primarily due to temporary differences related to PP&E impairment charges in 2017 and the change in fair value of commodity risk management contracts. See Note 10 to the December 31, 2018 audited Consolidated Financial Statements for more information.

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 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 is more likely than not to 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.

OTHER (INCOME) EXPENSE

Pengrowth recorded $1.2 million of other expenses in 2018 which consisted of an onerous lease expense related to a construction camp at Lindbergh partly offset by investment income on remediation trust fund and a royalty credit carry-back related to SOEP abandonment spending. See the Asset Retirement Obligations section of this MD&A and Note 9 to the December 31, 2018 audited Consolidated Financial Statements for more information.

Full year 2017 other income of $7.4 million included an insurance settlement, investment income on remediation trust funds and interest income.

FOREIGN CURRENCY GAINS (LOSSES)

	Three months ended				Twelve months ended
($ millions)	Dec 31, 2018		Dec 31, 2017		Dec 31, 2018		Dec 31, 2017
Currency exchange rate (Cdn$1 = U.S.$) at beginning of period	0.77		0.80		0.80		0.74
Currency exchange rate (Cdn$1 = U.S.$) at period end	0.73		0.80		0.73		0.80
Unrealized foreign exchange gain (loss) from translation of foreign denominated debt	(27.7	)	(5.2	)	(39.8	)	65.6
Unrealized gain (loss) on foreign exchange risk management contracts	18.9		36.2		24.9		(14.2	)
Net unrealized foreign exchange gain (loss)	(8.8	)	31.0		(14.9	)	51.4
Net realized foreign exchange gain (loss)	0.4		(34.4	)	0.8		(38.4	)

As 73 percent of Pengrowth's total debt before working capital is denominated in foreign currencies at December 31, 2018, the majority of Pengrowth's unrealized foreign exchange gains and losses are attributable to the translation of this debt into Canadian dollars and changes in the fair value of the related foreign exchange swap contracts Pengrowth employs to manage this risk.

The gains or losses on foreign debt principal restatement each period are calculated by comparing the translated Canadian dollar balance of foreign currency denominated long term debt from one period to another. The magnitude of the gains and losses is proportionate to the magnitude of the exchange rate fluctuation between the opening and closing rates for the respective periods and the amount of debt denominated in a foreign currency.

PENGROWTH 2018 Management's Discussion and Analysis 19

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.

At December 31, 2018, Pengrowth held a total of U.S.$255 million in foreign exchange swap contracts 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, 2018, the fair value of these U.S. foreign exchange derivative contracts was an asset of Cdn$5.8 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, 2018, 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 a portion of the principal amount of term note was early repaid in the fourth quarter of 2017.

At December 31, 2018, the fair value of the U.K. foreign exchange derivative contracts was an asset of $2.2 million and has been included on the Consolidated Balance Sheets. Changes in the fair value of these contracts between Balance Sheet dates are reported on the Consolidated Statements of Income (Loss) as an unrealized foreign exchange (gain) loss.

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$0.01 Exchange rate change
Foreign exchange sensitivity as at December 31, 2018 ($ 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 2018 Management's Discussion and Analysis 20

ASSET RETIREMENT OBLIGATIONS - NET PRESENT VALUE

($ millions)	Dec 31, 2018		Dec 31, 2017		Change
ARO, beginning of year	236.7		652.3		(415.6	)
Expenditures on remediation/provisions settled	(23.2	)	(15.9	)	(7.3	)
ARO on disposed properties	(0.9	)	(420.4	)	419.5
Incurred during the period	1.4		5.4		(4.0	)
Accretion	5.4		11.4		(6.0	)
Other revisions	20.5		3.9		16.6
ARO, end of year (1)	239.9		236.7		3.2

⁽¹⁾  Expected to be funded from the SOEP remediation trust fund valued at $98.0 million at December 31, 2018, with the remainder to be funded from 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, 2018, the ARO liability increased $3.2 million from December 31, 2017 primarily due to revisions to inflation, cost and timing estimates, offset by liability settlement of $23.2 million.

Pengrowth has estimated the net present value of its total ARO to be $239.9 million as at December 31, 2018 (December 31, 2017 – $236.7 million), based on a total escalated future liability of $491.7 million (December 31, 2017 – $420.2 million). 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, 2018 was $98.0 million (December 31, 2017 - $111.6 million) and was included in Other Assets on the Consolidated Balance Sheets. The fund balance represents a pre-funding of Pengrowth's entire share of the estimated costs of the SOEP abandonment and remediation, but 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. Abandonment and decommissioning expenditures of approximately $17.9 million in 2018 were funded by the trust fund.

Pursuant to the Royalty Agreement with the Province of Nova Scotia and the Offshore Royalty Regulations, Pengrowth is entitled to deduct certain monies spent on abandonment and decommissioning activities from royalties previously paid. The deduction is claimed when the field ceases production and up to three years thereafter. The operator has established December 2018 as the "Month of Cessation" under the Royalty Agreement and the Regulations. Pengrowth's share of remaining abandonment and decommissioning spending from 2019 to 2021 is currently set at approximately $81 million. It is estimated that the refundable royalties will be approximately 25 percent to 30 percent of this amount.

The majority of the abandonment and reclamation costs on other assets, not covered by a fund, are expected to be incurred between 2035 and 2085. A risk free discount rate of 2.3 percent per annum (December 31, 2017 - 2.3 percent) and an ARO specific inflation rate of 2.0 percent (December 31, 2017 - 1.5 percent) were used to calculate the net present value of the ARO at December 31, 2018.

REMEDIATION TRUST FUNDS AND REMEDIATION AND ABANDONMENT EXPENSE

During 2018, Pengrowth contributed $5.6 million (December 31, 2017 - $17.1 million), into an externally managed trust funds established to fund certain abandonment and reclamation costs associated with SOEP. The total balance of the remediation trust funds was $98.0 million at December 31, 2018 (December 31, 2017 - $111.6 million).

Pengrowth had 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 2018, Pengrowth made monthly contributions to the fund at a rate of $1.41/MMBtu of its share of natural gas production and $2.42/bbl of its share of natural gas liquids production from SOEP. Starting in January 2019, there will no longer be contributions to the remediation trust fund as production has ceased and abandonment and decommissioning spending has begun and will continue for the next 3 to 4 years.

See Note 4 to the December 31, 2018 audited Consolidated Financial Statements for additional information.

PENGROWTH 2018 Management's Discussion and Analysis 21

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 2018, Pengrowth spent $23.2 million on abandonment and reclamation (2017 - $15.9 million). Pengrowth expects to spend approximately $34 million in 2019 on abandonment and reclamation activities, excluding orphan well levies from the Alberta Energy Regulator. Over 70 percent of the planned spending in 2019 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 Carbon Competitive Incentive Regulation (“CCIR”) came into effect January 1, 2018 and imposes annual GHG emissions reporting requirements on all Alberta facilities that emit more than 100,000 tonnes of greenhouse gases per year.

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:

• the complete phase-out of coal-fired sources of electricity by 2030;

• an Alberta economy-wide price on GHG emissions of $30/tonne;

• 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

• 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 Specified Gas Emitters Regulation 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 50 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 benchmarks using emissions 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.

The new CCIR utilizes Oil and Gas industry benchmarks to determine compliance reporting and emissions payment. For 2018 and 2019 operations, the regulator has provided facility specific transitional benchmarks to reduce the initial impact of the newly implemented CCIR. These benchmarks are based on emissions per unit of production, and facilities will pay on the difference between the actual facility emissions per unit of production less the transitional benchmark provided by the regulator. Facilities can meet compliance in three ways: audited emission reductions in their operations to meet industry benchmarks, purchased Alberta-based offset carbon credits, or contributions to the Alberta Climate Change and Emissions Management Fund. In 2018, the cost of compliance was $30/tonne.

The Lindbergh in-situ facility was subject to the CCIR for 2018 operations, and will be based on Lindbergh’s emissions of CO2 equivalent tonnes per m3 of bitumen relative to the in situ sector benchmark. In 2018, there was no compliance payment required for Lindbergh for 2017 operations. The estimated impact for 2018 operations relating to Lindbergh was estimated at $1.4 million (payable March 31, 2019). The impact of the Climate Leadership Plan will continue to increase through 2023 as provincial and Federal climate change programs align.

Uncertainties exist related to the timing and effects of these emerging regulations and resulting requirements making it difficult to accurately determine the impacts and effects on the Corporation. The extent and magnitude of any adverse impacts of current or additional programs or regulations cannot be reliably or accurately estimated at this time, in part because specific legislative and regulatory requirements have not been finalized. Pengrowth is closely monitoring the ongoing development and implementation of the regulatory framework through which the federal and provincial governments are implementing their climate change and emissions reduction policies.

PENGROWTH 2018 Management's Discussion and Analysis 22

ACQUISITIONS AND DISPOSITIONS

	Three months ended				Twelve months ended
($ millions)	Dec 31, 2018		Dec 31, 2017		Dec 31, 2018		Dec 31, 2017
Property acquisitions	(0.2	)	(0.1	)	(0.2	)	(0.1	)
Proceeds from property dispositions (1)	5.5		118.4		23.0		910.2
Net cash proceeds from dispositions	5.3		118.3		22.8		910.1

⁽¹⁾  Proceeds are net of transaction costs and closing adjustments. Where applicable, include deferred proceeds.

Fourth quarter and full year 2018 proceeds from property dispositions include collection of certain deferred proceeds and closing adjustments for dispositions completed in 2017.

Full year 2017 include proceeds from property dispositions from the sale of non-producing Montney lands at Bernadet in north eastern British Columbia, the sale of a 4.0 percent GORR interest on the Lindbergh thermal property and certain seismic assets, the sale of Olds/Garrington and Swan Hills area.

At December 31, 2018, Pengrowth's accounts receivable included approximately $5 million of deferred proceeds relating to 2017 dispositions. These deferred proceeds are expected to be collected within the next 3 months.

ASSETS HELD FOR SALE

At December 31, 2018, Pengrowth presented $16.0 million of certain Southern Alberta conventional assets as assets held for sale, classified as current assets on the Consolidated Balance Sheets. The related ARO of $16.0 million was presented as liabilities associated with assets held for sale and classified as current liabilities on the Consolidated Balance Sheets. The disposition is expected to close in the first quarter of 2019. Cash proceeds on closing of the disposition were nominal.

FINANCIAL RESOURCES AND LIQUIDITY

Debt Maturities and Capital Resources

At December 31, 2018, Pengrowth had in place a secured $330 million revolving committed term credit facility (the "Credit Facility") supported by a syndicate of 11 domestic and international banks with a maturity date of March 31, 2019. The available Credit Facility had drawings of $173.5 million at December 31, 2018 (December 31, 2017 - $109.0), and $75.6 million of outstanding letters of credit (December 31, 2017 - $69.4 million). In addition to the maturity of the Credit Facility in 2019 as described above, certain of the Corporation’s term notes in the aggregate principal amount of Cdn$59.4 million mature on October 18, 2019.

Pengrowth engaged Perella Weinberg Partners LP and Tudor, Pickering, Holt & Co ("PWP/TPH") as advisers to assist in exploring financing alternatives. On March 5, 2019, the Board of Directors commenced a formal process with PWP/TPH to explore and develop strategic alternatives (the “Strategic Review”) with a view to strengthening the Corporation's balance sheet and maximizing enterprise value. The Strategic Review is intended to explore a comprehensive range of strategic and transaction alternatives, including a sale, merger or other business combination; a disposition of all or certain assets of the Corporation; recapitalization and refinancing opportunities; sourcing new financing and equity capital; and other alternatives to improve the Corporation's financial position and maximize value. In addition to Pengrowth’s long-life, low-decline assets, the Corporation also has potentially attractive tax attributes that complement its strong base operations. Pengrowth and its advisers expect to actively explore market interest in potential transactions and strategic initiatives with a range of interested parties and capital market participants. There remains uncertainty and liquidity risk until such time as the Strategic Review Process is completed and Pengrowth implements a transaction, financing arrangement or other strategic alternative that addresses the pending maturities under the Credit Facility and the October 2019 term notes. Pengrowth plans to settle the October 2019 term notes with internally generated cash flow. There can be no guarantees as to whether the Strategic Review will result in a transaction or the terms or timing of any resulting transaction. Various industry risk factors, including a prolonged or significant decrease in WTI or WCS pricing, could impact the outcome of the Strategic Review Process, Pengrowth’s cash flow, and its ability to address its upcoming debt maturities.

The Corporation is in discussions with the lending syndicate under its $330 million revolving Credit Facility on arrangements to extend the maturity date of the Credit Facility through September 30, 2019 to support the Strategic Review. The Corporation's objective is to finalize the extension agreement as soon as possible, and in advance of the

PENGROWTH 2018 Management's Discussion and Analysis 23

current March 31, 2019 maturity date, however, there can be no assurance or guarantee that an extension will be obtained by the Corporation or on what terms.

Due to the rapid deterioration of commodity prices, uncertainty around improvements in global prices, and uncertainty around timing of refinancing of Pengrowth's debt portfolio, there remains a risk around Pengrowth's ability to stay in compliance with its debt covenants at the end of 2019.

Further information regarding the risk factors associated with Pengrowth's capital resources may be found under the headings “Advisory Regarding Forward-Looking Statements” and "Business Risks" herein and under "Risk Factors" in Pengrowth's most recent AIF and management information circular, quarterly reports, material change reports and news releases.

Financial Covenants

Pursuant to the debt amending agreements dated October 12, 2017, amendments to the existing financial covenants are effective through to and including the quarter ending September 30, 2019 in the case of the term notes (the "Waiver Period"). The only applicable covenant during the Waiver Period is the trailing 12 month Adjusted EBITDA to Interest and Financing Charges ratio (the "Interest Coverage" ratio). The Interest Coverage ratio changes each quarter until the fourth quarter of 2019 for term notes after which it remains at 4.0 times, as noted below. Any new or extended Credit Facility could contain new or different covenants and credit limits.

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.

During the Waiver Period:

• The Debt to Adjusted EBITDA ratio covenant and the Debt to Book Capitalization ratio covenants do not apply.

• The trailing 12 month Interest Coverage minimum ratio covenant is revised as follows:

Year	Q1	Q2	Q3	Q4
2018	—	—	—	1.01 times
2019	1.13 times	1.19 times	1.23 times	4.0 times

The calculation of the Interest Coverage ratio is based on specific definitions within the agreements and may contain 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 and financing charges can be adjusted for the fees and interest expense related to debt repaid with asset divestment proceeds. See table below for more information.

Pengrowth was in compliance with its Interest Coverage ratio at 1.6 times at December 31, 2018, which was above the fourth quarter of 2018 minimum compliance covenant of 1.01 times. Due to the return of the Debt to EBITDA covenant and increase of the Interest Coverage ratio to 4.0 times there remains a risk around Pengrowth's ability to stay in compliance with its debt covenants at the end of 2019. See Note 1 to the December 31, 2018 audited Consolidated Financial Statements for additional information.

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 2018 Management's Discussion and Analysis 24

Covenant Calculation

Twelve month trailing actual covenant (1):
Interest Coverage ratio at December 31, 2018	1.6
Minimum Interest Coverage compliance ratio required at December 31, 2018	1.01
Twelve month trailing Interest Expense ($ millions):	Dec 31, 2018
Interest and financing charges	49.8
Twelve month trailing Adjusted EBITDA ($ millions):
Net income (loss)	(559.3	)
Add (deduct):
Interest and financing charges	49.8
Deferred income tax expense (recovery)	342.2
Depletion, depreciation, amortization and accretion	169.3
Impairment	91.0
(Gain) loss on disposition of properties	1.0
Change in fair value of commodity risk management contracts	(35.6	)
Unrealized foreign exchange (gain) loss	14.9
Non-cash share based compensation expense	4.8
Restructuring costs	0.4
Adjusted EBITDA	78.5

⁽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.

Total Debt Before Working Capital

At December 31, 2018 total debt before working capital of $714.6 million comprised $541.1 million of term notes and $173.5 million drawn on the Credit Facility. Compared to December 31, 2017, total debt increased by $104.1 million at December 31, 2018 as drawings on the Credit Facility increased and weakening Canadian dollar negatively impacted the balance.

As of December 31, 2018, Pengrowth's foreign denominated term notes comprised 73 percent of the total debt before working capital. Each term note is governed by a Note Purchase Agreement. See Note 7 to the December 31, 2018 audited Consolidated Financial Statements for additional information.

Off-Balance Sheet Financing

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

WORKING CAPITAL

Working capital surplus or deficiency is calculated as current assets less current liabilities per the Consolidated Balance Sheets. At December 31, 2018, Pengrowth had a working capital deficiency of $268.8 million as current assets were exceeded by current liabilities mostly due to the Credit Facility balance and term notes maturing in 2019 and presented as a current portion of long term debt on the Consolidated Balance Sheet. See Note 7 to the December 31, 2018 audited Consolidated Financial Statements for further information.

FINANCIAL INSTRUMENTS

Pengrowth uses financial instruments to manage its exposure to commodity 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, 2018 audited Consolidated Financial Statements for a description of the accounting policies for financial instruments and Note 16 to the December 31, 2018 audited Consolidated Financial Statements for additional information regarding the fair value of Corporation's financial instruments.

PENGROWTH 2018 Management's Discussion and Analysis 25

SUMMARY OF QUARTERLY RESULTS

	2018								2017
	Q4		Q3		Q2		Q1		Q4		Q3		Q2		Q1
Oil and gas sales ($ millions) (1)	111.2		147.2		147.4		126.4		130.5		125.1		197.9		219.9
Net income (loss) ($ millions)	(503.0	)	(1.6	)	(27.5	)	(27.2	)	(210.4	)	(144.7	)	(242.4	)	(86.3	)
Net income (loss) per share ($)	(0.91	)	—		(0.05	)	(0.05	)	(0.38	)	(0.26	)	(0.44	)	(0.16	)
Net income (loss) per share - diluted ($)	(0.91	)	—		(0.05	)	(0.05	)	(0.38	)	(0.26	)	(0.44	)	(0.16	)
Cash flow from operating activities ($ millions)	9.4		21.8		12.8		(12.3	)	28.4		11.8		36.5		65.7
Adjusted funds flow ($ millions) (2) (3) (4)	(2.3	)	15.6		10.1		7.2		13.5		(0.3	)	29.3		26.9
Daily production (boe/d)	24,104		21,807		22,600		19,541		24,702		35,072		49,349		52,957
Produced petroleum revenue ($/boe) (1) (4)	24.80		47.10		42.59		39.97		37.14		28.08		32.56		34.66
Operating netback ($/boe) (4) (5)	4.55		18.44		16.00		16.08		16.06		11.06		13.16		13.43

⁽¹⁾  Excludes realized commodity risk management from financial contracts.

⁽²⁾  Fourth quarter of 2017 adjusted funds flow excludes $34.8 million loss related to the settlement of foreign exchange swap contracts as this was considered a financing activity.

⁽³⁾  First quarter of 2017 adjusted funds flow includes a $12.7 million loss related to the early settlement of commodity risk management contracts.

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

⁽⁵⁾  Includes realized commodity risk management.

Pengrowth recorded a net loss of $503.0 million in the fourth quarter of 2018 primarily due to derecognition of the deferred tax asset of $342.2 million related to uncertainty of Pengrowth's ability to realize the deferred tax assets in future years, combined with impairment charges of $91.0 million and lower adjusted funds flow.

Fourth quarter of 2018 adjusted funds flow decreased from the preceding quarters primarily due to a significant widening of the WCS differential in the quarter coupled with higher cost of diluent. The widening of the WCS differential was mostly mitigated by Pengrowth's WCS physical delivery fixed price differential contracts combined with higher bitumen production in 2018.

Fourth quarter of 2018 produced petroleum revenue per boe decreased compared to all preceding quarters, as per the table above, due to 2017 property dispositions coupled with an unprecedented increase in the WCS to WTI differential in the fourth quarter of 2018.

Oil and gas sales in the fourth quarter of 2018 decreased from all preceding quarters, as per the table above, also due to decreases in benchmark prices and widening of the WCS differential in the fourth quarter of 2018. Compared to 2017, the decrease is also due to property dispositions. Fourth quarter of 2018 operating netbacks, after realized commodity risk management, decreased significantly compared to all preceding quarters of 2018 and 2017 due to a decrease in realized prices in the fourth quarter of 2018 coupled with higher per boe realized commodity risk management losses related to financial swap contracts.

2018 quarterly production was higher than all of the preceding quarters in 2018, but lower than 2017, as per the table above. The increase resulted primarily from increase in bitumen production in the fourth quarter of 2018 and higher production at Groundbirch. 2018 quarterly production was impacted by the absence of production related to properties divested in 2017 and natural declines related 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. Adjusted funds flow was also impacted by changes in royalty expense, operating expenses and cash G&A costs.

PENGROWTH 2018 Management's Discussion and Analysis 26

SELECTED ANNUAL INFORMATION

The table below provides a summary of selected annual information for the years ended 2018, 2017 and 2016:

	Twelve months ended December 31
($ millions unless otherwise indicated)	2018		2017		2016
Oil and gas sales (1)	532.2		673.4		566.2
Net income (loss)	(559.3	)	(683.8	)	(293.7	)
Net income (loss) per share ($)	(1.01	)	(1.24	)	(0.54	)
Net income (loss) per share - diluted ($)	(1.01	)	(1.24	)	(0.54	)
Total assets	1,344.2		1,910.9		4,117.1
Long term debt (2)	714.6		610.5		1,687.3
Shareholders' equity	251.9		806.2		1,485.0
Number of shares outstanding at year end (thousands)	556,117		552,246		547,709

⁽¹⁾  Excluding realized commodity risk management from financial contracts.

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

COMMITMENTS AND CONTRACTUAL OBLIGATIONS

At December 31, 2018, Pengrowth's commitments are as follows:

($ millions)	2019	2020	2021	2022	2023	Thereafter	Total
Operating leases	1.5	1.5	1.5	1.8	1.8	2.1	10.2
Onerous leases	5.1	5.3	5.2	6.0	4.9	5.8	32.3
Pipeline transportation	27.0	33.8	35.1	35.2	35.5	152.4	319.0
Power infrastructure and other	13.6	0.2	0.2	0.2	0.2	3.9	18.3
	47.2	40.8	42.0	43.2	42.4	164.2	379.8

At December 31, 2018, Pengrowth’s current and non-current contractual cash flows related to financial liabilities are as follows:

($ millions)	Carrying amount	Contractual cash flows	Year 1	Year 2	Years 3-5	More than 5 years
Accounts payable	72.7	72.7	72.7	—	—	—
Commodity risk management contracts	4.2	4.2	4.2	—	—	—
Cdn dollar senior unsecured notes (1)	20.5	25.7	1.4	1.4	22.9	—
U.S. dollar denominated term notes (2)	499.5	619.5	70.7	152.5	169.0	227.3
U.K. pound sterling denominated term notes (2)	21.1	22.0	22.0	—	—	—
Cdn dollar term Credit Facility borrowings (1)	173.5	176.1	176.1	—	—	—
Finance leases	33.4	72.3	4.2	4.2	12.6	51.3
Other liabilities	1.7	1.7	0.1	0.1	—	1.5

⁽¹⁾  Contractual cash flows include future interest payments.

⁽²⁾  Contractual cash flows include future interest payments and term notes calculated at December 31, 2018 period end exchange rate.

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 and EDGAR at www.sec.gov.

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:

PENGROWTH 2018 Management's Discussion and Analysis 27

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 a 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. As a result, a significant uncertainty related to these events and conditions exists which raise substantial doubt about whether the Corporation will continue as a going concern, and therefore, whether it will realize its assets and settle its liabilities in the normal course of business and at the amounts stated in the financial statements.

• 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 Debt Portfolio

• Pengrowth is currently working towards an extension on its Credit Facility until September 30, 2019, which management expects to provide sufficient time to finalize the refinancing of Pengrowth's term notes due October 18, 2019. Pengrowth is in discussions with the lead banks in its syndicate to amend the existing Credit Facility to permit the refinancing of the existing term notes. Alternative financing arrangements for replacement debt will likely be at a higher cost than the current arrangements. There can be no assurance or guarantee that an extension will be obtained by the Corporation.

• Although Pengrowth plans to settle the term notes with internally generated cash flow, there remains material risk that Pengrowth will be unable to do so as a result of uncertainty related to rapid deterioration of commodity prices, uncertainty around improvements in global prices, and uncertainty around timing of refinancing of Pengrowth's debt portfolio. There also remains a risk around Pengrowth's ability to stay in compliance with its debt covenants at the end of 2019.

• Until such time that the term notes are refinanced, there is material uncertainty related to these events and conditions that may cast significant doubt whether the Corporation will continue as a going concern, and therefore, whether it will realize its assets and settle its liabilities in the normal course of business and at the amounts stated in the financial statements.

PENGROWTH 2018 Management's Discussion and Analysis 28

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. The Corporation 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.

• 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.

PENGROWTH 2018 Management's Discussion and Analysis 29

• 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’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.

PENGROWTH 2018 Management's Discussion and Analysis 30

• 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 and EDGAR at www.sec.gov.

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 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 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 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 2018 Management's Discussion and Analysis 31

Pengrowth’s ARO risk free discount rate and ARO specific inflation rate was 2.3 percent and 2.0 percent, respectively, at December 31, 2018.

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, if applicable.

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.

COMPARATIVE FIGURES

Certain prior years' comparative figures have been reclassified to conform to presentation in the current year.

ACCOUNTING PRONOUNCEMENTS ADOPTED

IFRS 9 Financial Instruments

On January 1, 2018, Pengrowth adopted all of the requirements of IFRS 9 (2014), Financial Instruments ("IFRS 9"). This standard replaces IAS 39 - Financial Instruments: recognition and measurement ("IAS 39") and introduces new requirements for the classification and measurement of financial assets and liabilities. It introduces a new general hedge accounting standard, which aligns hedge accounting more closely with risk management. It also modifies the existing impairment model by introducing a new 'expected credit loss' model for calculating impairment. This new standard also increases required disclosures about an entity's risk management strategy, cash flows from hedging activities and the impact of hedge accounting on the consolidated financial statements. Pengrowth has applied IFRS 9 retrospectively in accordance with transition requirements with no impact to opening retained earnings or comparative periods.

IFRS 9 uses a single approach to determine whether a financial asset is measured at amortized cost or fair value, replacing the multiple rules in IAS 39. The approach is based on how an entity manages its financial instruments and the contractual cash flow characteristics of the financial assets. Most of the requirements in IAS 39 for classification and measurement of financial liabilities have been carried forward in IFRS 9.

The adoption of IFRS 9 did not result in any measurement adjustments to Pengrowth's financial assets or financial liabilities. The impact of the change in the impairment model was not significant as the credit-impaired financial assets are not significant.

The adoption of IFRS 9 did not result in any changes in the eligibility of existing hedge relationships. Pengrowth currently has no intentions of designating any of its financial instruments as hedges, or using hedge accounting.

ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED

IFRS 16 Leases

In January 2016, the IASB issued 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 in the final stages of analyzing identified contracts, developing business and accounting processes, making applicable changes to the Corporation's internal controls and calculating the impact that the adoption of this standard will have on its financial statements. Pengrowth has elected to use the modified retrospective approach upon adoption and elected to apply the optional exemptions for short-term and low-value leases. The actual full impact of adoption will depend on the Corporation's incremental borrowing rate, lease portfolio and practical expedients applied. However, Pengrowth anticipates that the most significant impact of adopting IFRS 16 will be the recognition of the lease liabilities on its leases for head office space and the right of use ("ROU") assets, as applicable.

PENGROWTH 2018 Management's Discussion and Analysis 32

Upon adoption of IFRS 16, the Corporation will recognize lease liabilities and ROU assets for all leases identified except for optional exemptions taken. The lease liability will be measured at the present value of the remaining lease payments, discounted using Pengrowth's incremental borrowing rate as at January 1, 2019. The ROU asset will be measured at the amount equal to the lease liability on January 1, 2019 with no impact on retained earnings.

Adoption of IFRS 16 will also result in an increase to Depletion, Depreciation and Amortization due to the recognition of the ROU assets, increase in interest and financing charges, and a decrease to G&A and operating expenses, as applicable. Cash flow from operating activities will increase as a result of the decrease in G&A and operating expenses, as applicable. Cash flow from financing activities will decrease due to the deduction of the interest portion of the principal payments for former operating leases.

OPERATIONAL MEASURES

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

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

Steam Oil Ratio 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.

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, DD&A, accretion ("EBITDA"), impairment, gain (loss) on disposition of properties, change in fair value of commodity risk management contracts, unrealized foreign exchange gain (loss), non-cash share based compensation expense, restructuring costs and EBITDA related to material divestments ("Adjusted EBITDA");

– Adjusted EBITDA to Interest and Financing Charges (the "Interest Coverage" ratio);

– Total 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").

In calculating certain covenants, letters of credit and finance leases are incorporated in total debt before working capital for covenant purposes. Trailing 12 month interest and financing charges can be adjusted for the fees and interest expense related to debt repaid with asset divestment proceeds. Total book capitalization is the sum of total 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 core business activities. Net income (loss) may significantly be impacted by non-cash changes in fair value of commodity risk management contracts and unrealized foreign exchange gains and losses while adjusted net income (loss) excludes the after-tax effect of items which do not represent Pengrowth's core business activities.

Management considers adjusted funds flow to be a key measure of performance as it demonstrates Pengrowth's ability to generate the necessary funds for sustaining capital, future growth through capital investment, and to repay debt. Management believes that such a measure provides an insightful assessment of Pengrowth's operations on a continuing basis by eliminating changes in non-cash operating working capital and actual settlements of ARO which substantially

PENGROWTH 2018 Management's Discussion and Analysis 33

relate to SOEP and are pre funded by an externally managed trust fund. Adjusted funds flow per share is calculated by dividing adjusted funds flow and the weighted average number of shares outstanding.

Free funds flow is defined as adjusted funds flow less capital expenditures. Management believes this is a useful supplemental measure as it reflects funds available for debt repayment.

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. Produced petroleum revenue reflects natural gas sales related to a portion of natural gas delivered from Groundbirch onto the NGTL system and used in other operations as energy costs. This measure can be expressed on a per boe basis.

Adjusted 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, and can be expressed on a per boe basis. Adjusted operating expenses include the cost of a portion of natural gas delivered from the NGTL system and used in operations as energy costs. Management believes this is a useful supplemental measure as it reflects the cash outlay at its processing facilities, being after cost recoveries earned by utilizing spare capacity though processing third party volumes.

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 adjusted 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 adjusted funds flow. 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.

Adjusted Funds Flow

The following table provides a reconciliation of cash flow from operating activities to adjusted funds flow:

	Three months ended				Twelve months ended
($ millions)	Dec 31, 2018		Dec 31, 2017		Dec 31, 2018		Dec 31, 2017
Cash flow from operating activities	9.4		28.4		31.7		142.4
Add (deduct):
Interest and financing charges	(13.8	)	(12.4	)	(49.8	)	(70.7	)
Expenditures on remediation	9.1		2.8		23.2		15.9
Change in non-cash operating working capital	(7.0	)	(5.3	)	25.5		(18.2	)
Total	(11.7	)	(14.9	)	(1.1	)	(73.0	)
Adjusted funds flow	(2.3	)	13.5		30.6		69.4

PENGROWTH 2018 Management's Discussion and Analysis 34

The following table represents a continuity of adjusted funds flow:

($ millions)		Q4/17 vs. Q4/18			2017 vs. 2018
Adjusted funds flow for comparative period	Q4/17	13.5		2017	69.4
Increase (decrease) due to:
Volumes		(2.9	)		(222.1	)
Prices including differentials		(26.5	)		43.1
Realized commodity risk management		(3.8	)		(47.7	)
Royalties		4.3			21.6
Expenses:
Adjusted operating		3.8			113.7
Cash G&A		8.4			26.7
Interest & financing		(1.4	)		20.9
Onerous office lease payments		(0.6	)		(4.9	)
Restructuring costs - severance		1.2			8.4
Other - including transportation		1.7			1.5
Net change		(15.8	)		(38.8	)
Adjusted funds flow	Q4/18	(2.3	)	2018	30.6

Adjusted Net Income (Loss)

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

	Three months ended				Twelve months ended
($ millions)	Dec 31, 2018		Dec 31, 2017		Dec 31, 2018		Dec 31, 2017
Net income (loss)	(503.0	)	(210.4	)	(559.3	)	(683.8	)
Exclude non-cash items from net income (loss):
Change in fair value of commodity risk management contracts	22.2		(33.3	)	35.6		14.2
Unrealized foreign exchange gain (loss) (1)	(8.8	)	31.0		(14.9	)	51.4
Tax effect on non-cash items above	(6.0	)	9.0		(9.6	)	(3.8	)
Tax adjustment	(355.4	)	—		(342.2	)	—
Total excluded	(348.0	)	6.7		(331.1	)	61.8
Adjusted net income (loss) (2)	(155.0	)	(217.1	)	(228.2	)	(745.6	)

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

⁽²⁾  Fourth quarter of 2018 adjusted net loss incorporated $91.0 million of impairment charges and $32.0 million of depletion related to properties at the end of useful life. Fourth quarter of 2017 adjusted net loss incorporated $130.0 million of impairment charges.

The following table represents a continuity of adjusted net income (loss):
($ millions)		Q4/17 vs. Q4/18		2017 vs. 2018
Adjusted net income (loss) for comparative period	Q4/17	(217.1	)	2017	(745.6	)
Adjusted funds flow increase (decrease)		(15.8	)		(38.8	)
DD&A and accretion expense (increase) decrease		(32.8	)		49.7
Impairment charges (increase) decrease		39.0			543.4
Realized foreign exchange gain (loss) on derivative settlements		34.8			37.6
Loss on property dispositions (increase) decrease		15.9			61.6
Onerous lease contracts		18.5			22.9
Onerous office lease payments		0.6			4.9
Loss on extinguishment of debt		49.2			56.7
Other		(4.7	)		(2.6	)
Change in tax		(42.6	)		(218.0	)
Net change		62.1			517.4
Adjusted net income (loss)	Q4/18	(155.0	)	2018	(228.2	)

PENGROWTH 2018 Management's Discussion and Analysis 35

Sensitivity of Adjusted Funds Flow to Commodity Prices

The following table illustrates the sensitivity of adjusted funds flow to increases in commodity prices and differentials after taking into account Pengrowth’s commodity risk management contracts and outlook on oil differentials. See Note 16 to the December 31, 2018 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 Adjusted Funds Flow
COMMODITY PRICE ENVIRONMENT (1)		Assumption		Change		(Cdn$ millions)
West Texas Intermediate Oil (2)	U.S.$/bbl		$53.69		$1.00
Bitumen						8.1
Light oil						0.2
Net impact of U.S.$1/bbl increase in WTI						8.3
Oil differentials (2)
Bitumen	U.S.$/bbl		$16.62		$1.00	(8.1	)
Light oil	U.S.$/bbl		$7.74		$1.00	(0.2	)
Physical oil differential risk management (3)						8.4
Net impact of U.S.$1/bbl increase in differentials						0.1
AECO Natural Gas (2)	Cdn$/Mcf		$1.67		$0.10
Natural gas						1.0
Net impact of Cdn$0.10/Mcf increase in AECO						1.0

⁽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.$0.76 was used for the 12 month period.

⁽²⁾  Commodity price is based on an estimation of the 12 month forward price curve at January 14, 2019 and does not include the impact of commodity risk management contracts.

⁽³⁾  Reflects 2019 physical delivery contracts for 12,500 bbl/d of dilbit and financial swaps for 5,000 bbl/d of dilbit. See Commodity Prices section of this MD&A for more information.

DISCLOSURE AND INTERNAL CONTROLS

As a Canadian reporting issuer with securities listed on the TSX and an SEC registrant, 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.

Management, with the participation of the CEO, Peter Sametz, and the CFO, Christopher Webster, evaluated the effectiveness of Pengrowth’s disclosure controls and procedures for the year ending December 31, 2018. 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, 2018, 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.

PENGROWTH 2018 Management's Discussion and Analysis 36

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. 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, 2018. In making this evaluation, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) in Internal Control-Integrated Framework (2013).

Based on Pengrowth's evaluation, management concluded that Pengrowth's internal control over financial reporting was effective as at December 31, 2018.

The effectiveness of internal control over financial reporting as at December 31, 2018 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, 2018. No changes were made to Pengrowth's internal control over financial reporting during the year ending December 31, 2018 that have materially affected, or are reasonably likely to materially affect, the internal controls over financial reporting.

PENGROWTH 2018 Management's Discussion and Analysis 37

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 applicable U.S. securities legislation including 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, asset carrying amounts, amount and classification of liabilities, the proportion of production of each product type, Pengrowth’s 2019 guidance, production additions from Pengrowth's development program, Pengrowth’s business plan, the geological characteristics of Pengrowth’s properties, royalty expenses, operating expenses, tax horizon, deferred income taxes, management’s expectations as to tax and royalty receivables, ARO, remediation, reclamation and abandonment expenses, clean-up and remediation costs, impact of Climate Leadership Plan; adoption of new accounting pronouncements, capital expenditures, development activities, cash G&A, onerous office lease contracts, Lindbergh expansion plans, flexibility of Pengrowth to change its capital spending plans, production capacity, anticipated benefits from the disposal of properties and timing thereof, ability of management to manage exposure to commodity price fluctuations, the availability and cost of capital, the ability of Pengrowth to pay its current and future debt obligations and stay in compliance with its current and future debt covenants, the ability of Pengrowth to obtain alternative debt financing and amend its financial covenants, anticipated free funds flow and use of free funds flow to pay down debt, the ability of Pengrowth to finalize the refinancing of the term notes, the ability of Pengrowth to realize its assets and settle its liabilities in the normal course of business and at the amounts stated in the financial statements, the ability of Pengrowth’s Groundbirch property to fulfill Lindbergh’s natural gas needs, management's ability to mitigate impact of Alberta's curtailment program, the continued assessment of co-generation capacity at Lindbergh, the anticipated impact of the implementation of NCG to enhance production and lower SORs, and the ability of Pengrowth to remain a going concern. 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 or the lack thereof, the cost of expanding our property holdings, our ability to obtain labour and equipment in a timely manner to carry out development activities, our ability to market our oil and natural gas successfully to current and new customers including transportation availability, the impact of increasing competition, our ability to obtain financing on acceptable terms and meet financial covenants, our ability to add production and reserves through our development, exploitation and exploration activities, our ability to pay our current and future debt obligations and stay in compliance with our current and future debt covenants, our ability to obtain alternative debt financing and amend our financial covenants, and our ability to remain a going concern. 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 risks associated with the oil and gas industry in general; 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,

PENGROWTH 2018 Management's Discussion and Analysis 38

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; Pengrowth's inability to refinance term notes and /or existing Credit Facility; new IFRS and the impact on Pengrowth’s financial statements; and the implementation of greenhouse gas emissions legislation and the impact of carbon taxes; and Pengrowth's ability to remain a going concern. Further information regarding these factors may be found under the heading "Business Risks" herein and under "Risk Factors" in Pengrowth's most recent 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.

GLOSSARY AND ABBREVIATIONS

Pengrowth uses the following frequently recurring industry terms and abbreviations in this MD&A:

"bbl"	barrel	"ARO"	asset retirement obligations
"bbl/d"	barrels per day	"G&A"	general and administrative expenses
"Mbbl"	thousand barrels	"LTIP"	long term incentive plan
"MMbbls"	million barrels	"DD&A"	depletion, depreciation and amortization
"boe"	barrel of oil equivalent (1)	"IFRS"	International Financial Reporting Standards
"boe/d"	barrels of oil equivalent per day (1)	"AIF"	Annual Information Form
"Mboe"	thousand boe (1)	"WTI"	West Texas Intermediate crude oil price
"MMboe"	million boe (1)	"WCS"	Western Canadian Select crude oil price
"Mcf"	thousand cubic feet	"AECO"	Alberta natural gas price point
"Mcf/d"	thousand cubic feet per day	"NYMEX"	New York Mercantile Exchange
"MMcf"	million cubic feet	"SOEP"	Sable Offshore Energy Project
"MMcf/d"	million cubic feet per day	"GCA"	Gas Cost Allowance
"Bcf"	billion cubic feet	"NCG"	Non-Condensable Gas
		"NGTL"	Nova Gas Transmission Limited
"EPEA"	Environmental Protection and Enhancement Act
"CO2"	carbon dioxide which is a gas at room temperature and pressure
"SAGD"	steam assisted gravity drainage
"diluent"	hydrocarbon based diluting agent required to facilitate the transportation of bitumen
"dilbit" or "diluted bitumen"	bitumen blended with diluent
"SOR"	steam oil ratio
"CSOR"	cumulative steam oil ratio

⁽¹⁾  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.

PENGROWTH 2018 Management's Discussion and Analysis 39

EX-99.3

MANAGEMENT'S REPORT TO SHAREHOLDERS

Management’s Responsibility for the Consolidated Financial Statements

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.

Management’s Assessment of Internal Control Over Financial Reporting

Management is also responsible for establishing and maintaining adequate internal control over financial reporting. The internal control system was designed to provide reasonable assurance to Management regarding the preparation and presentation of the Consolidated Financial Statements.

Internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. 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.

Management has assessed the design and effectiveness of internal control over financial reporting as at December 31, 2018. In making its assessment, Management has used the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) framework in Internal Control - Integrated Framework (2013) to evaluate the design and effectiveness of internal control over financial reporting. Based on our evaluation, Management has concluded that internal control over financial reporting was effective as at December 31, 2018.

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.

/s/ Peter D. Sametz	/s/ Christopher G. Webster
Peter D. Sametz	Christopher G. Webster
President and Chief Executive Officer	Chief Financial Officer
Pengrowth Energy Corporation	Pengrowth Energy Corporation

March 5, 2019

PENGROWTH 2018 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

Report of Independent Registered Public Accounting Firm

To the Shareholders and Board of Directors of Pengrowth Energy Corporation

Opinion on the ConsolidatedFinancial Statements

We have audited the accompanying consolidated balance sheets of Pengrowth Energy Corporation (the “Company”) and subsidiaries, as of December 31, 2018 and 2017, the related consolidated statements of income (loss), shareholders’ equity, and cash flows for each of the years then ended, and the related notes (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2018 and 2017, and the results of its operations and its cash flows for the years then ended, in conformity with International Financial Reporting Standards as issued by the International Accounting Standards Board.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated March 5, 2019 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

Going Concern

The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 1 to the consolidated financial statements, the Company has significant uncertainties relating to its ability to meet its financial obligations on scheduled debt maturities and comply with certain debt covenants that raise substantial doubt about its ability to continue as a going concern. Management’s plans in regard to these matters are also described in Note 1. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. 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.

PENGROWTH 2018 Financial Results 2

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ KPMG LLP

Chartered Professional Accountants

We have served as the Company’s auditor since 1988.

Calgary, Canada

March 5, 2019

PENGROWTH 2018 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 Shareholders and Board of Directors of Pengrowth Energy Corporation

Opinion on Internal Control Over Financial Reporting

We have audited Pengrowth Energy Corporation’s (the “Company”) internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Company as of December 31, 2018 and 2017, and the related consolidated statements of income (loss), shareholders’ equity, and cash flows for the years then ended, and related notes (collectively, the consolidated financial statements), and our report dated March 5, 2019 expressed an unqualified opinion on those consolidated financial statements.

Basis for Opinion

The Company’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 Assessment of 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.

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 company’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

PENGROWTH 2018 Financial Results 4

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.

/s/ KPMG LLP

Chartered Professional Accountants

Calgary, Canada

March 5, 2019

PENGROWTH 2018 Financial Results 5

PENGROWTH ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS

(Stated in millions of Canadian dollars)

		As at			As at
	Note	December 31, 2018			December 31, 2017
ASSETS
Current Assets
Cash and cash equivalents			$0.6			$1.1
Accounts receivable		42.8			92.9
Fair value of risk management contracts	16	3.5			—
Other assets	4	33.8			36.8
Assets held for sale	5	16.0			—
		96.7			130.8
Fair value of risk management contracts	16	4.5			1.9
Other assets	4	86.2			99.8
Property, plant and equipment	5	1,074.2			1,104.2
Exploration and evaluation assets	6	82.6			232.0
Deferred income taxes	10	—			342.2
TOTAL ASSETS			$1,344.2			$1,910.9
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Accounts payable			$72.7			$136.2
Fair value of risk management contracts	16	4.2			40.0
Current portion of long term debt	7	232.9			—
Current portion of provisions and other liabilities	9	39.7			35.2
Liabilities associated with assets held for sale	9	16.0			—
		365.5			211.4
Fair value of risk management contracts	16	—			18.6
Long term debt	7	481.7			610.5
Provisions and other liabilities	9	245.1			264.2
		1,092.3			1,104.7
Shareholders' Equity
Shareholders' capital	11	4,838.1			4,829.7
Contributed surplus		9.9			13.3
Deficit		(4,596.1		)	(4,036.8		)
		251.9			806.2
Commitments and contingencies	18, 19
Future Operations	1
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY			$1,344.2			$1,910.9

See accompanying notes to the Consolidated Financial Statements.

Approved on behalf of the Board of Directors of Pengrowth Energy Corporation

Director	Director

PENGROWTH 2018 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
	Note	2018			2017
REVENUES
Oil and gas sales	13		$532.2			$673.4
Royalties, net of incentives		(24.2		)	(45.8		)
		508.0			627.6
Commodity risk management gains (losses)
Realized gain (loss) on commodity risk management	16	(67.5		)	(19.8		)
Change in fair value of commodity risk management contracts	16	35.6			14.2
		476.1			622.0
EXPENSES
Operating		79.5			217.5
Diluent and other purchases		229.5			163.5
Transportation		22.7			27.1
General and administrative		34.7			61.5
Depletion, depreciation and amortization	5	162.3			207.6
Impairment	5, 6	91.0			634.4
		619.7			1,311.6
OPERATING INCOME (LOSS)		(143.6		)	(689.6		)
Other (income) expense items
(Gain) loss on disposition of properties		1.0			62.6
Unrealized foreign exchange (gain) loss	17	14.9			(51.4		)
Realized foreign exchange (gain) loss	17	(0.8		)	38.4
Interest and financing charges	7	49.8			70.7
Restructuring costs		0.4			37.0
Loss on extinguishment of debt		—			56.7
Accretion	9	7.0			11.4
Other (income) expense		1.2			(7.4		)
INCOME (LOSS) BEFORE TAXES		(217.1		)	(907.6		)
Deferred income tax (recovery) expense	10	342.2			(223.8		)
NET INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS)			($559.3	)		($683.8	)
NET INCOME (LOSS) PER SHARE	15
Basic			($1.01	)		($1.24	)
Diluted			($1.01	)		($1.24	)

See accompanying notes to the Consolidated Financial Statements.

PENGROWTH 2018 Financial Results 7

PENGROWTH ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOW

(Stated in millions of Canadian dollars)

		Year ended December 31
	Note	2018			2017
CASH PROVIDED BY (USED FOR):
OPERATING
Net income (loss) and comprehensive income (loss)			($559.3	)		($683.8	)
Non-cash items
Depletion, depreciation, amortization and accretion	5, 9	169.3			219.0
Impairment	5, 6	91.0			634.4
Deferred income tax (recovery) expense	10	342.2			(223.8		)
Unrealized foreign exchange (gain) loss	17	14.9			(51.4		)
Change in fair value of commodity risk management contracts	16	(35.6		)	(14.2		)
Share based compensation	12	4.8			4.9
(Gain) loss on disposition of properties	5, 6	1.0			62.6
Onerous lease contracts	9	3.6			26.5
Other items		3.6			0.9
Onerous office lease payments	9	(4.9		)	—
Loss on extinguishment of debt	7	—			56.7
Foreign exchange derivative settlements	16	—			37.6
Interest and financing charges	7	49.8			70.7
Expenditures on remediation	9	(23.2		)	(15.9		)
Change in non-cash operating working capital	14	(25.5		)	18.2
Cash flow from operating activities		31.7			142.4
FINANCING
Long term debt (repayment)	7	64.5			(937.2		)
Convertible debentures repayment	7	—			(126.6		)
Foreign exchange derivative settlements	16	—			(37.6		)
Interest and financing charges paid	7	(55.9		)	(100.8		)
Cash flow from financing activities		8.6			(1,202.2		)
INVESTING
Capital expenditures		(65.4		)	(117.9		)
Property acquisitions		(0.2		)	(0.1		)
Proceeds on property dispositions		23.0			910.2
Withdrawals from/(contributions to) remediation trust fund		12.3			(10.5		)
Change in non-cash investing working capital	14	(10.5		)	(7.5		)
Cash flow from investing activities		(40.8		)	774.2
CHANGE IN CASH AND CASH EQUIVALENTS		(0.5		)	(285.6		)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR		1.1			286.7
CASH AND CASH EQUIVALENTS AT END OF YEAR			$0.6			$1.1

See accompanying notes to the Consolidated Financial Statements.

PENGROWTH 2018 Financial Results 8

PENGROWTH ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY

(Stated in millions of Canadian dollars)

		Year ended December 31
	Note	2018			2017
SHAREHOLDERS' CAPITAL	11
Balance, beginning of year			$4,829.7			$4,815.1
Exercise of share based compensation awards		8.4			14.6
Balance, end of year		4,838.1			4,829.7
CONTRIBUTED SURPLUS
Balance, beginning of year		13.3			22.9
Share based compensation	12	5.0			5.0
Exercise of share based compensation awards		(8.4		)	(14.6		)
Balance, end of year		9.9			13.3
DEFICIT
Balance, beginning of period		(4,036.8		)	(3,353.0		)
Net income (loss)		(559.3		)	(683.8		)
Balance, end of year		(4,596.1		)	(4,036.8		)
TOTAL SHAREHOLDERS' EQUITY			$251.9			$806.2

See accompanying notes to the Consolidated Financial Statements.

PENGROWTH 2018 Financial Results 9

PENGROWTH ENERGY CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

AS AT AND FOR THE YEARS ENDED DECEMBER 31, 2018 AND 2017

(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 and exploration 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.

Future Operations

Through 2018, Pengrowth has had discussions with the lead banks in its syndicate regarding a new credit agreement that will permit Pengrowth to access the high yield debt market to refinance substantially all of its existing term notes as further described in Note 7. Pengrowth is also exploring alternative financing arrangements including third party debt providers to refinance its entire debt portfolio. These discussions, if successful, may result in an offer for replacement debt at a higher cost than the current outstanding debt.

Pengrowth engaged Perella Weinberg Partners LP and Tudor, Pickering, Holt & Co ("PWP/TPH") as advisers to assist in exploring financing alternatives. On March 5, 2019, the Board of Directors commenced a formal process with PWP/TPH to explore and develop strategic alternatives (the “Strategic Review”) with a view to strengthening the Corporation's balance sheet and maximizing enterprise value. The Strategic Review is intended to explore a comprehensive range of strategic and transaction alternatives, including a sale, merger or other business combination; a disposition of all or certain assets of the Corporation; recapitalization and refinancing opportunities; sourcing new financing and equity capital; and other alternatives to improve the Corporation's financial position and maximize value. In addition to Pengrowth’s long-life, low-decline assets, the Corporation also has potentially attractive tax attributes that complement its strong base operations. Pengrowth and its advisers expect to actively explore market interest in potential transactions and strategic initiatives with a range of interested parties and capital market participants. There can be no guarantees as to whether the Strategic Review will result in a transaction or the terms or timing of any resulting transaction. Various industry risk factors, including a prolonged or significant decrease in WTI or WCS pricing, could impact the outcome of the Strategic Review Process, Pengrowth’s cash flow, and its ability to address its upcoming debt maturities.

Furthermore, the Corporation is in discussions with the lending syndicate under its $330 million revolving credit facility (the "Credit Facility") on arrangements to extend the maturity date of the Credit Facility through September 30, 2019 to support the Strategic Review. The Corporation's objective is to finalize the extension agreement as soon as possible, and in advance of the current March 31, 2019 maturity date, however, there can be no assurance or guarantee that an extension will be obtained by the Corporation or on what terms.

Due to the rapid deterioration of commodity prices, uncertainty around improvements in global prices, and uncertainty around timing of refinancing of Pengrowth's debt portfolio, there remains a risk around Pengrowth's ability to stay in compliance with its debt covenants at the end of 2019.

As a result, there is significant uncertainty related to these events and conditions that raise substantial doubt about whether the Corporation will continue as a going concern, and therefore, whether it will realize its assets and settle its liabilities in the normal course of business and at the amounts stated in the financial statements. However, management believes that the Corporation will be successful in obtaining alternative debt financing and amending its financial covenants as outlined in Note 8 in a timely manner and, accordingly, has prepared the financial statements on a going concern basis.

Accordingly, no adjustments have been made to the financial statements relating to the recoverability and classification of the asset carrying amounts or the amount and classification of liabilities that may be necessary should the consolidated entity not continue as a going concern. At this time, management believes that no asset is likely to be realized for an amount less than the amount at which it is recorded in financial statements as at December 31, 2018.

PENGROWTH 2018 Financial Results 10

Pengrowth continues to generate sufficient cash flow to meet its obligations including interest payments, capital spending and abandonment and remediation expenses and plans to settle the October 2019 term notes with internally generated cash flow.

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”).

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 March 5, 2019.

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 Corporation 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 Corporation 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.

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

PENGROWTH 2018 Financial Results 11

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 on the license or field. 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 with the related PP&E CGU 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 and gross overriding royalty. 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

PENGROWTH 2018 Financial Results 12

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
-	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).

PENGROWTH 2018 Financial Results 13

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 and on transfer of E&E to PP&E. 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 including at the time of transfer, 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

The Corporation has elected to measure loss allowances for trade receivables and contract assets at an amount equal to lifetime expected credit losses (“ECLs”). The Corporation measures loss allowances for the amount due from affiliates at an amount equal to the 12-month ECLs. The maximum period considered when estimating ECLs is the maximum contractual period over which the Corporation is exposed to credit risk.

ECLs are a probability-weighted estimate of credit losses. Credit losses are measured as the present value of all cash shortfalls (i.e. the difference between the cash flows due to the entity in accordance with the contract and the cash flows that the Corporation expects to receive). ECLs are discounted at the effective interest rate of the financial asset.

Loss allowances for financial assets are deducted from the gross carrying amount of the assets. Impairment losses on financial assets are presented under “other expenses” in the statement of loss and comprehensive loss.

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.

Impairment losses on financial assets carried at amortized cost are reversed in the statement of loss and comprehensive loss in subsequent periods if the amount of the loss decreases.

Inventory

Product inventories are valued at the lower of cost and net realizable value on a first-in, first-out weighted average cost basis. The cost of inventory includes all costs incurred in the normal course of business to bring each product to its present location and condition. Net realizable value is the estimated selling price in the ordinary course of business less any expected selling costs. If the carrying amount exceeds net realizable value, a write-down is recognized. The write-down may be reversed in a subsequent period if circumstances which caused it no longer exist and the inventory is still on hand.

Provisions and other liabilities

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 using a risk free rate 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

PENGROWTH 2018 Financial Results 14

estimate and changes, if any, are applied prospectively. Revisions made to the ARO estimates are recorded as an increase or decrease to the ARO liability with a corresponding change made to the carrying amount of the related asset. In case of assets with no remaining production or reserves, revisions to ARO liability are recorded in the Consolidated Statements of Income (Loss). 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 Lease Contracts

The onerous lease obligation relates to excess head office space and an unutilized construction camp at Lindbergh which were recognized as the unavoidable costs of the lease contracts over the remaining term exceeded the economic benefits of the leases. The onerous lease provision is calculated as present value of future lease payments Pengrowth is obligated to make under the lease contracts less any recoveries under current or anticipated sublease agreements over the remaining life of the leases.

Other Liabilities

Pengrowth also categorizes certain cash-settled long term incentive plan ("LTIP") grants 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 a number of share-settled and cash-settled share based compensation plans, which are described in Note 12.

PENGROWTH 2018 Financial Results 15

Share-settled LTIP

Performance Share Units ("PSUs") and Restricted Share Units ("RSUs")

Compensation expense related to PSU and RSU share-settled plans is based on the estimated 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 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.

Stock option plan

Pengrowth uses the Black-Scholes pricing model to calculate the fair value of stock options granted using an estimated forfeiture rate, volatility, risk free rate and expected life. The fair value is recorded as share-based compensation expense over the vesting period with a corresponding amount reflected in contributed surplus. When stock options are exercised, the cash proceeds along with the amount previously recorded as contributed surplus are recorded as share capital.

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. 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. The revaluation of the cash-settled LTIP continues until settlement. Pengrowth estimates the forfeiture rate for each type of share based award at the date of grant.

Financial Instruments

Financial instruments are utilized by Pengrowth to manage its exposure to commodity price fluctuations and foreign currency exposures. Pengrowth’s policy is not to utilize financial instruments for trading or speculative purposes.

IFRS 9 sets out requirements for recognizing and measuring financial assets, financial liabilities and some contracts to buy or sell non-financial items. The Corporation adopted the standard with a date of initial application of January 1, 2018. This standard replaced IAS 39 Financial Instruments: Recognition and Measurement.

IFRS 9 largely retains the existing requirements in IAS 39 for the classification and measurement of financial liabilities. However, it eliminates the previous IAS 39 categories for financial assets of held to maturity, loans and receivables and available for sale. Under IFRS 9, on initial recognition, a financial asset is classified as measured at:

• Amortized cost;

• Fair value through other comprehensive income ("FVTOCI") - debt investment;

• Fair value through other comprehensive income ("FVTOCI") - equity investment;

• Fair value through profit or loss ("FVTPL").

The classification of financial assets under IFRS 9 is generally based on the business model in which a financial asset is managed and its contractual cash flow characteristics.

IFRS 9 replaces the ‘incurred loss’ model in IAS 39 with an ECL model. The new impairment model applies to financial assets measured at amortized cost, contract assets and debt investments at FVOCI, but not to investments in equity instruments. Under IFRS 9, credit losses are recognized earlier than under IAS 39.

PENGROWTH 2018 Financial Results 16

The adoption of IFRS 9 did not result in any changes in the eligibility of existing hedge relationships. Pengrowth currently has no intentions of designating any of its financial instruments as hedges, or using hedge accounting.

The following summarizes Pengrowth's financial assets and financial liabilities as a result of the adoption of IFRS 9:

• Accounts receivable and other assets are measured at amortized cost.

• Investments held in the remediation trust funds and other investments are measured at fair value through profit or loss. Any change in the fair value is recognized in the Consolidated Statements of Income (Loss).

• Bank indebtedness, accounts payable and long term debt have been measured at amortized cost using the effective interest rate method.

• Derivative assets and liabilities must be measured at fair value through profit or loss with changes in fair value over a reporting period recognized in net income (loss).

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.

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 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 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.

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.

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 Owned Assets

A minor proportion of Pengrowth’s petroleum and natural gas development and production activities involve jointly owned assets that are not conducted through separate vehicles and accordingly, the accounts reflect only Pengrowth’s proportionate interest in such activities.

PENGROWTH 2018 Financial Results 17

Related Parties

Related parties are persons or entities that have control or significant influence over Pengrowth, as well as key management personnel. Note 20 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.

Estimates and Judgments

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 or 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 2018 Financial Results 18

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, if applicable.

Identification of impairment indicators

Judgment is required to assess when indicators of impairment or reversals exist and whether calculation of the recoverable amount of an asset is necessary. Management considers internal and external sources of information including petroleum and natural gas prices, expected production volumes, anticipated recoverable quantities of proved and probable reserves and rates used to discount future cash flow estimates. Judgement is required to assess these factors when determining if the carrying amount of an asset is impaired, or in the case of previously impaired asset, whether the carrying amount of the asset has been restored.

Share-based payments

Stock options granted by the Corporation are recorded at fair value using the Black Scholes option pricing model. In assessing the fair value of stock options, estimates have to be made regarding the expected volatility in share price, option life, dividend yield, risk-free rate and estimated forfeitures at the initial grant date.

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 and are subject to changes and volatility in forward prices, foreign exchange rates, and discount rates.

Deferred tax assets

Deferred tax assets (if any) are recognized only to the extent it is considered probable that those assets will be recoverable. This involves an assessment of when those deferred tax assets are likely to reverse and judgment as to whether there will be sufficient taxable profits available to offset the tax assets when they do reverse. This requires assumptions regarding future profitability and is therefore inherently uncertain. To the extent assumptions regarding future profitability change, there can be an increase or decrease in the amounts recognized in respect of deferred tax assets as well as the amounts recognized in profit or loss in the period in which the change occurs.

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 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.

Share capital and warrants

Incremental costs directly attributable to the issue of common shares, warrants and stock options are recognized as a deduction from equity, net of any tax effects.

Cash and Term Deposits

Cash and term deposits include demand deposits and term deposits with original maturities of less than 90 days.

ACCOUNTING PRONOUNCEMENTS ADOPTED

IFRS 9 Financial Instruments

On January 1, 2018, Pengrowth adopted all of the requirements of IFRS 9 (2014), Financial Instruments ("IFRS 9"). This standard replaces IAS 39 - Financial Instruments: recognition and measurement ("IAS 39") and introduces new requirements for the classification and measurement of financial assets and liabilities. It introduces a new general hedge accounting standard, which aligns hedge accounting more closely with risk management. It also modifies the existing impairment model by introducing a new 'expected credit loss' model for calculating impairment. This new standard also increases required disclosures about an entity's risk management strategy, cash flows from hedging activities and the impact of hedge accounting on the consolidated financial statements. Pengrowth has applied IFRS

PENGROWTH 2018 Financial Results 19

9 retrospectively in accordance with transition requirements with no impact to opening retained earnings or comparative periods.

IFRS 9 uses a single approach to determine whether a financial asset is measured at amortized cost or fair value, replacing the multiple rules in IAS 39. The approach is based on how an entity manages its financial instruments and the contractual cash flow characteristics of the financial assets. Most of the requirements in IAS 39 for classification and measurement of financial liabilities have been carried forward in IFRS 9.

The adoption of IFRS 9 did not result in any measurement adjustments to Pengrowth's financial assets or financial liabilities. The impact of the change in the impairment model was not significant as the credit-impaired financial assets are not significant.

The adoption of IFRS 9 did not result in any changes in the eligibility of existing hedge relationships. Pengrowth currently has no intentions of designating any of its financial instruments as hedges, or using hedge accounting.

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 16 Leases

In January 2016, the IASB issued 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 in the final stages of analyzing identified contracts, developing business and accounting processes, making applicable changes to the Corporation's internal controls and calculating the impact that the adoption of this standard will have on its financial statements. Pengrowth has elected to use the modified retrospective approach upon adoption and elected to apply the optional exemptions for short-term and low-value leases. The actual full impact of adoption will depend on the Corporation's incremental borrowing rate, lease portfolio and practical expedients applied. However, Pengrowth anticipates that the most significant impact of adopting IFRS 16 will be the recognition of the lease liabilities on its leases for head office space and the right of use ("ROU") assets, as applicable.

Upon adoption of IFRS 16, the Corporation will recognize lease liabilities and ROU assets for all leases identified except for optional exemptions taken. The lease liability will be measured at the present value of the remaining lease payments, discounted using Pengrowth's incremental borrowing rate as at January 1, 2019. The ROU asset will be measured at the amount equal to the lease liability on January 1, 2019 with no impact on retained earnings.

Adoption of IFRS 16 will also result in an increase to Depletion, Depreciation and Amortization due to the recognition of the ROU assets, increase in interest and financing charges, and a decrease to G&A and operating expenses, as applicable. Cash flow from operating activities will increase as a result of the decrease in G&A and operating expenses, as applicable. Cash flow from financing activities will decrease due to the deduction of the interest portion of the principal payments for former operating leases.

PENGROWTH 2018 Financial Results 20

4. OTHER ASSETS

	As at
	December 31, 2018		December 31, 2017
Remediation trust fund - current		$24.0		$24.0
Remediation trust fund - non-current	74.0		87.6
Prepaid tax assessment	12.2		12.2
Prepaids and deposits	4.1		8.2
Inventory	5.7		4.6
		$120.0		$136.6
Current portion of other assets		$33.8		$36.8
Non-current portion of other assets		$86.2		$99.8

REMEDIATION TRUST FUND

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 2018, Pengrowth made a monthly contribution to the fund at a rate of $1.41/MMBtu of its share of natural gas production and $2.42/bbl of its share of natural gas liquids production from SOEP. In 2019, there will no longer be contributions to the remediation trust fund as production has ceased and abandonment and decommissioning spending has begun and will continue for the next 3 to 4 years. 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 2019 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, and as such the $24 million has been classified as a current asset in the Consolidated Balance Sheet at December 31, 2018.

In 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, 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
Contributions	2.9
Remediation expenditures	(17.9		)
Investment income	2.7
Unrealized gain (loss)	(1.3		)
Balance, December 31, 2018		$98.0

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 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 is more likely than not to 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 2018 Financial Results 21

5. PROPERTY, PLANT AND EQUIPMENT ("PP&E")

Cost or deemed cost	Oil and natural gas assets			Other equipment			Total
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
Additions to PP&E	66.7			0.9			67.6
Property acquisitions	0.2			—			0.2
Transfer from E&E	58.6			—			58.6
Change in asset retirement obligations	21.9			—			21.9
Balance, December 31, 2018		$3,965.1			$88.8			$4,053.9
Accumulated depletion, amortization and impairment losses	Oil and natural gas assets			Other equipment			Total
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
Depletion and amortization for the period	160.4			1.9			162.3
Balance, December 31, 2018		$2,880.7			$83.0			$2,963.7
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, 2018
Assets held for sale		$16.0			$—			$16.0
Long term	1,068.4			5.8			1,074.2
		$1,084.4			$5.8			$1,090.2

For the year ended December 31, 2018, $1.7 million (December 31, 2017 – $2.3 million) of directly attributable general and administrative costs were capitalized to PP&E.

Pengrowth ceased capitalization of interest during the third quarter of 2018 due to the change in the development plan for Lindbergh. During the year ended December 31, 2018, $2.4 million (December 31, 2017 – $3.7 million) of interest was capitalized on the Lindbergh Project to PP&E using Pengrowth's weighted average cost of debt of 6.5 percent (December 31, 2017 – 5.7 percent).

For the year ended December 31, 2017, Pengrowth executed and completed a substantial asset disposition program in order to reduce indebtedness and focus on its key growth assets. As a result of these dispositions, approximately $3.2 billion of costs and $1.9 billion of accumulated depletion were removed from PP&E. Proceeds on disposition of approximately $910.2 million were collected in 2017 and an additional $20.0 million of deferred proceeds were collected in 2018 that had been setup in accounts receivable at December 31, 2017.

At December 31, 2018, there were $4.6 billion (December 31, 2017 - $4.9 billion) of future development costs related to Pengrowth's key growth assets.

PENGROWTH 2018 Financial Results 22

ASSETS HELD FOR SALE

At December 31, 2018, Pengrowth presented $16.0 million of certain Southern Alberta conventional assets as assets held for sale, classified as current assets on the Consolidated Balance Sheets. The related ARO of $16.0 million was presented as liabilities associated with assets held for sale and classified as current liabilities on the Consolidated Balance Sheets. The disposition is expected to close in the first quarter of 2019. Cash proceeds on closing of the disposition were nominal.

IMPAIRMENT

At December 31, 2017, PP&E impairment charges of $504.4 million were recorded. 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 Corporation's focus on Lindbergh and Groundbirch properties. At December 31, 2018 and 2017, impairment triggers were assessed to be present for the Montney CGU based on declines in natural gas prices, but no PP&E impairment was identified. Refer to Note 6 for further discussion.

6. EXPLORATION AND EVALUATION ASSETS ("E&E")

Cost or deemed cost
Balance, December 31, 2016		$496.3
Divestitures	(134.3		)
Impairment	(130.0		)
Balance, December 31, 2017		$232.0
Additions	0.2
Transfer to PP&E	(58.6		)
Impairment	(91.0		)
Balance, December 31, 2018		$82.6

In 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 and closed the sale of the non producing Devil area, for nominal consideration.

IMPAIRMENT TESTING

For the year ended December 31, 2018, Pengrowth evaluated the Groundbirch gas property for an impairment in conjunction with the Montney CGU due to the negative impact resulting from the significant downturn in the forward natural gas benchmark prices late in 2018. In accordance with Pengrowth's policy, the E&E assets are assessed in conjunction with the cash flow from the applicable PP&E CGU. It was determined that the recoverable amount was below the carrying amount, thus a $91.0 million impairment on the Groundbirch E&E asset was recorded in the fourth quarter of 2018.

The recoverable amount was computed with reference to the present value of the future cash flows expected to be derived from production of proved plus probable reserves and contingent resources. 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, 2019 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 was 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.

PENGROWTH 2018 Financial Results 23

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 commodity price estimates used in the December 31, 2018 impairment test:

	AECO gas (1)
Year	(Cdn$/MMBtu)
2019	1.85
2020	2.29
2021	2.67
2022	2.90
2023	3.14
2024	3.23
2025	3.34
2026	3.41
2027	3.48
2028	3.54
Thereafter	+ 2.0 percent/yr

⁽¹⁾  Prices represent forecasted amounts as at January 1, 2019 by Pengrowth's independent reserves evaluator.

At December 31, 2018, the recoverable amount of the Groundbirch E&E gas property was estimated to be approximately $76.3 million.

A sensitivity analysis was performed on impairment based on a 1 percent increase and 1 percent decrease in the discount rates resulting in a $26.6 million increase and $37.4 million decrease in December 31, 2018 impairment, respectively. A sensitivity analysis was also performed on impairment based on a 5 percent increase and 5 percent decrease in the forecast cash flow estimates resulting in a $16.0 million decrease and a $17.3 million increase in impairment. Using a 20 percent discount rate for the contingent resource would have resulted in an increase to impairment by $33.5 million, while a 12 percent rate would have resulted in a decrease to impairment of $45.7 million.

At December 31, 2017, Pengrowth evaluated the Groundbirch gas property in conjunction with the Montney CGU for an impairment. It was determined that the recoverable amount was below the carrying amount, resulting in a $129.0 million impairment on the Groundbirch E&E asset in the fourth quarter of December 31, 2017. In addition, $1.0 million impairment was recognized on other minor E&E projects as no further exploration or evaluation was intended on those projects.

PENGROWTH 2018 Financial Results 24

7. LONG TERM DEBT AND FINANCIAL COVENANTS

LONG TERM DEBT

	As at
	December 31, 2018		December 31, 2017
U.S. dollar denominated term notes:
28.1 million at 5.49 percent due October 18, 2019		$38.3		$35.3
94.1 million at 7.98 percent due May 11, 2020	128.3		118.3
85.2 million at 6.07 percent due October 18, 2022	116.2		107.1
158.9 million at 6.17 percent due October 18, 2024	216.7		199.7
		$499.5		$460.4
U.K. pound sterling denominated term notes:
12.1 million at 5.45 percent due October 18, 2019		$21.1		$20.6
Canadian dollar term notes:
20.5 million at 6.74 percent due October 18, 2022		$20.5		$20.5
Canadian dollar term Credit Facility borrowings		$173.5		$109.0
Total long term debt		$714.6		$610.5
Current portion of long term debt		$232.9		$—
Non-current portion of long term debt		$481.7		$610.5

At December 31, 2018, Pengrowth had in place a secured $330 million revolving committed term Credit Facility supported by a syndicate of 11 domestic and international banks with a maturity date of March 31, 2019.

The Corporation is in discussions with the lending syndicate under its $330 million revolving Credit Facility on arrangements to extend the maturity date of the Credit Facility through September 30, 2019 to support the Strategic Review. The Corporation's objective is to finalize the extension agreement as soon as possible, and in advance of the current March 31, 2019 maturity date, however, there can be no assurance or guarantee that an extension will be obtained by the Corporation or on what terms. Refer to Note 1 for further discussion.

The Credit Facility carried floating interest rates that 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, 2018, the available facility had drawings of $173.5 million (December 31, 2017 – $109.0 million) and letters of credit in the amount of $75.6 million (December 31, 2017 – $69.4 million).

As of December 31, 2018, an unrealized cumulative foreign exchange loss of $135.3 million (December 31, 2017 - $96.2 million) has been recognized on the remaining U.S. dollar term notes since the date of issuance. As of December 31, 2018, an unrealized cumulative foreign exchange loss of $1.9 million (December 31, 2017 - $1.4 million) has been recognized on the remaining U.K. pound sterling denominated term notes since the date of issuance. See Note 16 for additional information about foreign exchange risk management and the impact on the Consolidated Financial Statements.

The five year schedule of long term debt and interest repayments based on current maturity dates and assuming the revolving Credit Facility is not renewed beyond September 30, 2019 is as follows: 2019 - $270.1 million, 2020 - $153.8 million, 2021 - $21.9 million, 2022 - $156.8 million, 2023 - $13.4 million.

During 2017, Pengrowth repaid term notes of approximately $1 billion and $126.6 million of convertible debentures at maturity on March 31, 2017.

FINANCIAL COVENANTS

Pursuant to the debt amending agreements dated October 12, 2017, amendments to the existing financial covenants are effective through to and including the quarter ending September 30, 2019 in the case of the term notes (the "Waiver Period"). The only applicable covenant during the Waiver Period is the trailing 12 month Adjusted EBITDA to Interest

PENGROWTH 2018 Financial Results 25

and Financing Charges (the "Interest Coverage" ratio). The Interest Coverage ratio changes each quarter until the fourth quarter of 2019 after which it remains at 4.0 times. 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. See Financial Resources and Liquidity section of the December 31, 2018 MD&A for more information.

Pengrowth's Interest Coverage ratio was 1.6 times at December 31, 2018, which was above the fourth quarter of 2018 covenant of 1.01 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.

8. CAPITAL DISCLOSURES

Pengrowth defines its capital as shareholders’ equity, long term debt, 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. Through 2018, Pengrowth has had discussions with the lead banks in its syndicate regarding a new credit agreement that will permit Pengrowth to access the high yield debt market to refinance substantially all of its existing term notes. Pengrowth is also exploring alternative financing arrangements including third party debt providers to refinance its entire debt portfolio. These discussions, if successful, may result in an offer for replacement debt at a higher cost than the current outstanding debt.

The Corporation is in discussions with the lending syndicate under its $330 million revolving Credit Facility on arrangements to extend the maturity date of the Credit Facility through September 30, 2019 to support the Strategic Review. The Corporation's objective is to finalize the extension agreement as soon as possible, and in advance of the current March 31, 2019 maturity date, however, there can be no assurance or guarantee that an extension will be obtained by the Corporation or on what terms. Refer to Note 1 for further discussion.

The only financial covenant relating to the term notes and Credit Facility is the Interest Coverage ratio. The Interest Coverage ratio changes each quarter until the fourth quarter of 2019 after which it remains at 4.0 times, as noted below. Any new or extended Credit Facility could contain new or different covenants and credit limits.

Year	Q1	Q2	Q3	Q4
2018	-	-	-	1.01 times
2019	1.13 times	1.19 times	1.23 times	4.0 times

Management monitors Pengrowth’s capital structure and covenant compliance using non-GAAP financial metrics. These metrics are trailing twelve months earnings before interest, taxes, DD&A, accretion ("EBITDA"), impairment, gain (loss) on disposition of properties, change in fair value of commodity risk management contracts, unrealized foreign exchange gain (loss), non-cash share based compensation expense, restructuring costs and EBITDA related to material divestments ("Adjusted EBITDA") and Adjusted EBITDA to Interest and Financing Charges ratio (the "Interest Coverage" ratio). Trailing 12 month interest and financing charges can be adjusted for the fees and interest expense related to debt repaid with asset divestment proceeds.

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 ended December 31, 2018, Pengrowth was in compliance with all financial covenants. Due to the return of the Debt to EBITDA covenant and increase of the Interest Coverage ratio to 4.0 times there remains a risk around Pengrowth's ability to stay in compliance with its debt covenants at the end of 2019.

PENGROWTH 2018 Financial Results 26

At December 31, 2018, Pengrowth has approximately $81.4 million of capacity on its Credit Facility, net of drawings and outstanding letters of credit.

The following table provides a reconciliation between the opening and closing balances for liabilities arising from financing activities at December 31, 2018:

	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		$—
Increase (decrease) due to:
Foreign exchange impact of the Canadian dollar on U.S. and U.K. denominated debt	39.6			—		—
Credit Facility borrowing	—			64.5		—
Balance, December 31, 2018		$541.1			$173.5		$—

The following is a summary of Pengrowth’s capital structure, excluding shareholders’ equity:

	As at
	December 31, 2018		December 31, 2017
Long term debt (1)		$714.6		$610.5
Working capital (surplus) deficiency (2)	35.9		80.6
		$750.5		$691.1

⁽¹⁾  Includes current portion of long term debt, as applicable.

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

PENGROWTH 2018 Financial Results 27

9. PROVISIONS AND OTHER LIABILITIES

Provisions and other liabilities are composed of Asset Retirement Obligations ("ARO"), finance leases, onerous lease contracts and other liabilities. The following table provides a continuity of the balances for the following periods:

	Asset retirement obligations			Finance leases			Onerous lease contracts			Other liabilities			Total
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
Incurred during the period	1.4			—			6.8			(0.4		)	7.8
Property dispositions	(0.9		)	—			—			—			(0.9		)
Expenditures on remediation/provisions settled	(23.2		)	(0.8		)	(5.6		)	(0.2		)	(29.8		)
Revision due to rate changes (1)	24.6			—			—			—			24.6
Other revisions	(4.1		)	—			(3.2		)	—			(7.3		)
Accretion (amortization)	5.4			—			1.6			—			7.0
Balance, December 31, 2018		$239.9			$33.4			$25.8			$1.7			$300.8

⁽¹⁾  Relates to the change in the inflation rate from 1.5 percent to 2.0 percent. The offset is recorded in PP&E.

As at December 31, 2018	Asset retirement obligations		Finance leases		Onerous lease contracts		Other liabilities		Total
Current including assets held for sale (1)		$50.0		$0.7		$4.9		$0.1		$55.7
Long term	189.9		32.7		20.9		1.6		245.1
		$239.9		$33.4		$25.8		$1.7		$300.8
As at December 31, 2017
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

⁽¹⁾  Includes $16.0 million of asset retirement obligation related to assets held for sale at December 31, 2018.

The following assumptions were used to estimate the ARO liability:

	As at
	December 31, 2018			December 31, 2017
Total escalated future costs		$491.7			$420.2
Discount rate, per annum	2.3		%	2.3		%
Inflation rate, per annum	2.0		%	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 majority of the abandonment and reclamation costs on other assets, not covered by a fund, are expected to be incurred between 2035 and 2085.

ONEROUS LEASE CONTRACTS

Pengrowth completed significant asset dispositions which led to a management decision to complete an operational restructuring in 2017. Reduction of staff levels and excess office space resulted in Pengrowth recognizing a $37.0

PENGROWTH 2018 Financial Results 28

million restructuring cost in 2017, of which $26.2 million related to onerous office lease contracts at December 31, 2017 as the economic benefits from actual or potential subleases were exceeded by the unavoidable costs of the lease contract over the remaining term. During the third quarter of 2018, Pengrowth recognized an additional onerous lease of $5.4 million related to the construction camp at Lindbergh and is recorded as part of the $6.8 million incurred during the period under onerous lease contracts. As Pengrowth shifted its development methodology away from the previously contemplated large single phase approach to expansion achieved in incremental steps, the camp will likely not be utilized at Lindbergh. Accordingly, the economic benefits of the construction camp were exceeded by the unavoidable costs of the contract over the remaining term. The total onerous lease contract provision amounted to $25.8 million at December 31, 2018.

10. DEFERRED INCOME TAXES

As at December 31, 2018, Pengrowth did not recognize deductible temporary differences of approximately $1.8 billion primarily consisting of approximately $1.6 billion of non capital losses and $0.2 billion in other temporary differences (PP&E and other) resulting in a $342.2 million non-cash deferred tax expense. These losses expire between 2025 and 2038.

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
	2018			2017
Income (loss) before taxes		($217.1	)		($907.6	)
Combined federal and provincial tax rate	27.10		%	27.08		%
Expected income tax expense (recovery)		($58.8	)		($245.8	)
Change in unrecognized deferred tax asset	397.7			22.6
Foreign exchange (gain) loss (1)	2.0			(2.0		)
Other including share based compensation	1.3			1.4
Deferred income tax expense (recovery)		$342.2			($223.8	)

⁽¹⁾ Reflects the 50 percent non-taxable (deductible) 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, 2018		December 31, 2017
Deferred tax liabilities associated with:
PP&E and E&E assets		$—		($132.3	)
Less deferred tax assets associated with:
Non-capital losses and financing charges	—		399.6
Provisions	—		64.1
Risk management contracts	—		10.8
Net deferred tax asset (liability)		$—		$342.2

A continuity of the net deferred income tax asset (liability) for 2018 and 2017 is detailed in the following tables:

Movement in deferred tax asset (liability) during the year	Balance Jan 1, 2018			Recognized in profit or loss			Balance Dec 31, 2018
PP&E and E&E assets		($132.3	)	$	132.3			$—
Non-capital losses and financing charges	399.6			(399.6		)	—
Provisions	64.1			(64.1		)	—
Risk management contracts	10.8			(10.8		)	—
		$342.2		$	(342.2	)		$—

PENGROWTH 2018 Financial Results 29

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		)	—
		$118.4			$223.8			$342.2

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.

11. 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.

	2018			2017
(Common shares in 000's)	Number of common shares	Amount		Number of common shares	Amount
Balance, beginning of year	552,246		$4,829.7	547,709		$4,815.1
Share based compensation (non-cash exercised)	3,871	8.4		4,537	14.6
Balance, end of year	556,117		$4,838.1	552,246		$4,829.7

12. LONG TERM INCENTIVE PLANS ("LTIP")

(i) SHARE-SETTLED LTIP

At the June 26, 2018 AGM, shareholders approved a rolling and reloading plan that shall not exceed 10 percent of the issued and outstanding common shares to be reserved for issuance under all share-settled compensation plans in the aggregate.

As at December 31, 2018, the number of shares issuable under the share-settled compensation plans, in aggregate, represents 3.1 percent of the issued and outstanding common shares, which is within the limit.

(a) Performance Share Units ("PSUs") and Restricted Share Units ("RSUs")

Performance Share Units ("PSUs")

PSUs entitle the holder to a number of common shares to be issued in the third year after grant. 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. Prior to 2017, PSUs were awarded to employees, officers and consultants. No PSU grants were made in 2018 as PSUs are no longer granted under current LTIP.

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. RSUs are awarded to employees, excluding officers. The RSUs generally vest on the first, second and third anniversary date from the date of grant.

PENGROWTH 2018 Financial Results 30

The following table provides a continuity of the share-settled PSUs and RSUs:

(number of share units - 000's)	PSUs		RSUs
Outstanding, December 31, 2016	6,238		8,436
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
Granted	—		3,006
Forfeited	(1,449	)	(2,444	)
Exercised	(826	)	(3,045	)
Performance adjustment	(138	)	—
Outstanding, December 31, 2018	2,621		4,900

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. As mentioned, no new PSUs will be granted under the current LTIP.

Compensation expense related to PSU and RSU 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 performance multiplier is calculated using the percentile rank of Pengrowth's total shareholder return relative to its peers and can result in cash compensation issued upon vesting of the PSUs ranging from zero to two times the value of the PSUs originally granted. Fluctuations in compensation expense may occur due to changes in estimating the outcome of the performance multiplier conditions. The amount of compensation expense is impacted by an estimated forfeiture rate at the date of grant and as more information becomes available. For PSU and RSU grants in 2016, 2017 and 2018, the estimated forfeiture rates range from 25 to 40 percent depending on the vesting period. 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, 2018, Pengrowth recorded $3.5 million of compensation related to the share-settled PSUs and RSUs (December 31, 2017 - $5.0 million). The weighted average grant date fair value was $0.87 per share unit for the 2018 RSU grants (December 31, 2017 - $1.40 per share for the 2017 RSU and PSU grants). As at December 31, 2018, the amount of compensation expense to be recognized over the remaining vesting period was $2.7 million or $0.32 per share unit (December 31, 2017 - $5.4 million or $0.51 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 1.0 year.

(b) Stock Option Plan

Commencing in June 2018, Pengrowth adopted an Employee Stock Option Plan that provides certain employees with the opportunity to exercise options to purchase common shares of the Corporation. Option exercise prices approximate the market price for the common shares on the date of issuance, vest in three even tranches in the three years following grant and expire after seven years. Compensation expense associated with the options is determined based on the grant date fair value and amortized over the vesting period.

PENGROWTH 2018 Financial Results 31

The following table provides a continuity of stock options outstanding at December 31:

	2018
(number of option units - 000's)	Number outstanding		Weighted average price
Outstanding, December 31, 2017	—			$—
Granted	9,468			$0.87
Forfeited	(141	)		$0.87
Exercised	—			$—
Outstanding, December 31, 2018	9,327			$0.87

The range of exercise prices of stock options outstanding and exercisable at December 31, 2018 was as follows:

Range of exercise prices	Number outstanding (thousands)	Weighted average remaining contractual life (years)	Weighted average exercise price		Number exercisable (thousands)	Weighted average exercise price
$0.87 - $1.05	9,327	6.49		$0.87	—		$—

Pengrowth uses the Black-Scholes pricing model to calculate the fair value of stock options granted using an estimated forfeiture rate, volatility, risk free rate and expected life. The fair value is recorded as stock-based compensation expense over the vesting period with a corresponding amount reflected in contributed surplus. When stock options are exercised, the cash proceeds along with the amount previously recorded as contributed surplus are recorded as share capital.

Estimated fair values for the stock options outstanding were calculated using the following weighted average assumptions:

Fair value per option		$0.46
Risk free interest rate	1.93		%
Expected volatility (1)	65.86		%
Expected life (years)	4.4
Expected forfeiture rate	15.0		%

⁽¹⁾ Expected volatility has been based on historical share volatility of the Corporation.

For the year ended December 31, 2018, Pengrowth recorded $1.5 million of compensation expense related to stock options (December 31, 2017 - $nil). The weighted average grant date fair value was $0.46 per stock option for the 2018 stock option grants (December 31, 2017 - $nil per option). As at December 31, 2018, the amount of compensation expense to be recognized over the remaining vesting period was $2.0 million or $0.22 per option (December 31, 2017 - $nil per option). The unrecognized compensation cost will be expensed to net income (loss) over the remaining weighted average vesting period of 1.41 years.

(ii) PREVIOUS LTIP

As at December 31, 2018, 163,867 common shares (December 31, 2017 - 163,867 common shares) were reserved for issuance under the Deferred Entitlement Share Unit ("DESU") Plan. As at December 31, 2018, 198,477 common shares (December 31, 2017 - 198,477 common shares) were reserved for issuance under the Deferred Share Unit ("DSU") plan.

(iii) CASH-SETTLED LTIP    

(a) Cash-Settled Restricted Share Units ("Cash-Settled RSUs")

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. During the year ended December 31, 2018, compensation reduction of $0.5 million (December 31, 2017 - $0.2 million reduction) was recognized in the Consolidated Statements of Income (Loss) with a corresponding

PENGROWTH 2018 Financial Results 32

increase or decrease in liabilities. As at December 31, 2018, $0.3 million (December 31, 2017 - $1.5 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. No grants were made in 2018 and no new Cash-Settled RSUs will be granted under the current LTIP. The revaluation of the cash-settled RSUs continues until settlement.

(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, 2018, Phantom DSUs awarded to Directors had a corresponding liability of $1.2 million (December 31, 2017 - $1.4 million). For the year ended December 31, 2018, Pengrowth recorded a $0.1 million compensation expense (December 31, 2017 - $0.6 million reduction) related to Phantom DSUs. The revaluation of the cash-settled Phantom DSUs continues until settlement.

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, 2016	4,229		1,346
Granted	3,163		492
Forfeited	(3,148	)	—
Exercised	(1,341	)	(462	)
Outstanding, December 31, 2017	2,903		1,376
Granted	—		847
Forfeited	(1,312	)	—
Exercised	(887	)	(155	)
Outstanding, December 31, 2018	704		2,068

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, 2018			December 31, 2017
Non-cash PSU and RSU expense		$3.5			$5.0
Non-cash stock options expense	1.5			—
Amounts capitalized in the period	(0.2		)	(0.1		)
Non-cash share based compensation expense		$4.8			$4.9
Cash-settled RSUs (reduction) expense		($0.5	)		($0.2	)
Cash-settled Phantom DSUs (reduction) expense		$0.1			($0.6	)
Total share based compensation expense		$4.4			$4.1

13. 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 either be fixed or variable, depending on the contract terms. Under its contracts, Pengrowth is required to deliver fixed and variable volumes of diluted bitumen and variable volumes of light oil, natural gas and

PENGROWTH 2018 Financial Results 33

natural gas liquids 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. The majority of Pengrowth’s diluted bitumen is currently sold on multi-year contracts expiring at the end of 2019 for a fixed quantity of diluted bitumen at a fixed differential to WTI, with WTI being variable, as detailed in Note 16. Revenues are typically collected on the 25^th day of the month following production. Processing fees charged to third parties are generally under multi-year contracts at fixed fees that vary by volume.

The following table presents Pengrowth’s Oil and gas sales disaggregated by revenue source:

	Year ended December 31
	2018		2017
Bitumen		$264.1		$181.6
Natural gas sold to third party (1)	16.6		98.8
Light oil	14.8		149.3
Natural gas liquids	4.7		56.7
Diluent sold	219.3		147.2
Processing income	2.0		19.1
Sale of other product purchased for resale	10.7		20.7
Total oil and gas sales		$532.2		$673.4

⁽¹⁾  Starting April 1, 2018, a portion of natural gas delivered from Groundbirch to the NGTL system is used in other operations as energy costs. As such, $7.2 million related to natural gas used in internal operations is not included in total oil and gas sales.

Pengrowth had no fixed price physical delivery contracts in 2018.

Pengrowth has variable price physical delivery contracts for the sale of diluted bitumen mainly with 2 credit worthy refiners, with revenue from these customers representing approximately 90 percent of the Corporation's full year 2018 oil and gas sales.

Included in accounts receivable at December 31, 2018 is $22.2 million (December 31, 2017 is $40.2 million) of accrued oil and gas sales related to December 2018 production.

14. OTHER CASH FLOW DISCLOSURES

CHANGE IN NON-CASH OPERATING WORKING CAPITAL AND OTHER ASSETS

	Year ended December 31
Cash provided by (used for):	2018			2017
Accounts receivable and other current assets (1)		$28.5			$40.9
Accounts payable	(54.0		)	(22.7		)
		($25.5	)		$18.2

⁽¹⁾  Includes accounts receivable, inventory and prepaids.

CHANGE IN NON-CASH INVESTING WORKING CAPITAL 

	Year ended December 31
Cash used for:	2018			2017
Accounts payable, including capital accruals		($10.5	)		($7.5	)

PENGROWTH 2018 Financial Results 34

15. 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)	2018	2017
Weighted average number of shares - basic and diluted	555,279	551,193

For the years ended December 31, 2018 and 2017, there were no dilutive effects of stock options, RSUs, PSUs, DSUs or DEUs due to the Corporation incurring net losses during these periods.

16. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

Pengrowth’s financial instruments are composed of accounts receivable, other assets, accounts payable, risk management assets and liabilities, remediation trust fund, finance lease obligation, bank indebtedness 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, 2018 audited Consolidated Financial Statements.

RISK MANAGEMENT OVERVIEW

Pengrowth has exposure to certain market risks related to volatility in commodity, differential and power prices, interest rates and foreign exchange rates. Derivative instruments are used to manage exposure to these risks, as applicable. 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, differential 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 and the impact on differentials, 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 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, divestments or other transactions where Pengrowth’s capital structure may be subject to more risk from commodity prices.

PENGROWTH 2018 Financial Results 35

Commodity Price Contracts

As at December 31, 2018, Pengrowth had the following financial contracts outstanding:

Financial Crude Oil Contracts:
Swaps
Differentials
Reference point	Term	Volume of dilbit (bbl/d)	Price per bbl (U.S.$)
Western Canada Select	2019	5,000	WTI less $20.88

Financial Risk Management Contracts Sensitivity to Commodity Prices as at December 31, 2018

Oil differentials	Cdn$1 decrease in future oil differential			Cdn$1 increase in future oil differential
Increase (decrease) to fair value of financial differential risk management contracts		($1.3	)		$1.3

Physical Delivery Contracts

As at December 31, 2018, 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 dilbit (bbl/d)	Term	Price per bbl (U.S.$)
Western Canada Select	2,500	2019	WTI less $17.95
Western Canada Select	2,500	2019	WTI less $23.60 - $26.35
Western Canada Select	5,000	2019	WTI less $17.70 - $20.45
Western Canada Select	2,500	Feb. 1, 2019 - Feb. 1, 2020	WTI less $20.40 - $23.40

Pengrowth has also entered into a secured term sale agreement at Hardisty for an additional 5,000 bbl/d of dilbit for 2019 that are 100 percent apportionment protected. Pengrowth will settle at the monthly WCS Index less an apportionment protection fee of U.S.$2.00/bbl.

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 a portion of the principal amount of term note was early repaid in 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. 

PENGROWTH 2018 Financial Results 36

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, 2018	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, 2018, Pengrowth had $714.6 million of current and non-current long term debt (December 31, 2017 - $610.5 million) of which $173.5 million was based on floating interest rates (December 31, 2017 - $109.0 million). An increase of 1 percent in interest rates would increase pre-tax interest expense by approximately $1.7 million for the year ended December 31, 2018 (December 31, 2017 - $1.1 million), assuming the amount was outstanding for the entire period.

PENGROWTH 2018 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, 2018	Commodity contracts (1)			Foreign exchange contracts (2)			Total
Current portion of risk management assets		$—			$3.5			$3.5
Non-current portion of risk management assets	—			4.5			4.5
Current portion of risk management liabilities	(4.2		)	—			(4.2		)
Risk management assets (liabilities), end of year		($4.2	)		$8.0			$3.8
Less: Risk management assets (liabilities) at beginning of year	(39.8		)	(16.9		)	(56.7		)
Unrealized gain (loss) on risk management contracts for the year		$35.6			$24.9			$60.5
Realized gain (loss) on risk management contracts for the year	(67.5		)	—			(67.5		)
Total unrealized and realized gain (loss) on risk management contracts for the year		($31.9	)		$24.9			($7.0	)
As at and for the year ended December 31, 2017	Commodity contracts (1)			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	)

⁽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 under Foreign exchange (gain) loss in the Consolidated Statements of Income (Loss). See Note 17.

PENGROWTH 2018 Financial Results 38

Fair Value

The fair value of cash and cash equivalents, accounts receivable, remediation trust fund, 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 value of the remediation trust fund is equal to its carrying amount as this asset is carried at its 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, 2018	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 fund		$98.0		$98.0		$98.0		$—		$—
Fair value of risk management contracts	8.0		8.0		—		8.0		—
Financial Liabilities
U.S. dollar denominated term notes	499.5		533.2		—		533.2		—
Cdn dollar term notes	20.5		22.3		—		22.3		—
U.K. pound sterling denominated term notes	21.1		21.4		—		21.4		—
Fair value of risk management contracts	4.2		4.2		—		4.2		—
					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 fund		$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		—

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 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.

PENGROWTH 2018 Financial Results 39

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 cash, accounts receivable, remediation trust fund, 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 2018, 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.

The combined carrying amount of accounts receivable and fair value of derivative assets as at December 31, 2018 was $50.8 million (December 31, 2017 - $94.8 million), representing Pengrowth's maximum credit exposure. The Corporation’s credit provisions are represented by its loss allowance based on lifetime expected credit losses as at December 31, 2018 of $1.2 million (December 31, 2017 - $0.5 million). The amount of the loss allowance was determined based on historical credit loss experience, adjusted for forward-looking factors specific to the debtors and the economic environment. The total amount of accounts receivables 90 days past due amounted to $5.9 million as at December 31, 2018 (December 31, 2017 - $17.5 million).

The accounts receivable is as follows:

	As at
	December 31, 2018		December 31, 2017
Trade		$42.8		$92.9

At December 31, 2018, $25.9 million of trade receivables was related to revenue and the remaining $16.9 million primarily comprise joint venture receivables and deferred proceeds from property dispositions.

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 with a maturity date of March 31, 2019. Use of the remaining credit capacity is still subject to complying with the financial covenant as discussed in Note 7. Pengrowth’s term notes and term Credit Facilities are secured and equally ranked.

Pengrowth engaged Perella Weinberg Partners LP and Tudor, Pickering, Holt & Co ("PWP/TPH") as advisers to assist in exploring financing alternatives. On March 5, 2019, the Board of Directors commenced a formal process with PWP/TPH to explore and develop strategic alternatives (the “Strategic Review”) with a view to strengthening the Corporation's balance sheet and maximizing enterprise value. The Strategic Review is intended to explore a comprehensive range of strategic and transaction alternatives, including a sale, merger or other business combination; a disposition of all or certain assets of the Corporation; recapitalization and refinancing opportunities; sourcing new financing and equity capital; and other alternatives to improve the Corporation's financial position and maximize value. In addition to Pengrowth’s long-life, low-decline assets, the Corporation also has potentially attractive tax attributes that complement its strong base operations. Pengrowth and its advisers expect to actively explore market interest in potential transactions and strategic initiatives with a range of interested parties and capital market participants. There can be no guarantees as to whether the Strategic Review will result in a transaction or the terms or timing of any resulting transaction. Various industry risk factors, including a prolonged or significant decrease in WTI or WCS pricing, could impact the outcome of the Strategic Review Process, Pengrowth’s cash flow, and its ability to address its upcoming debt maturities. Refer to Note 1 for further discussion.

PENGROWTH 2018 Financial Results 40

Pengrowth’s current and non-current financial liabilities are as follows:

As at December 31, 2018	Carrying amount		Contractual cash flows		Year 1		Year 2		Years 3-5		More than 5 years
Accounts payable		$72.7		$72.7		$72.7		$—		$—		$—
Commodity risk management contracts	4.2		4.2		4.2		—		—		—
Cdn dollar senior unsecured notes (1)	20.5		25.7		1.4		1.4		22.9		—
U.S. dollar denominated term notes (2)	499.5		619.5		70.7		152.5		169.0		227.3
U.K. pound sterling denominated term notes (2)	21.1		22.0		22.0		—		—		—
Cdn dollar term Credit Facility borrowings (1)	173.5		176.1		176.1		—		—		—
Finance leases	33.4		72.3		4.2		4.2		12.6		51.3
Other liabilities	1.7		1.7		0.1		0.1		—		1.5

⁽¹⁾  Contractual cash flows include future interest payments.

⁽²⁾  Contractual cash flows include future interest payments and term notes calculated at December 31, 2018 period end exchange rate.

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 (1)	20.5		27.1		1.4		1.4		24.3		—
U.S. dollar denominated term notes (2)	460.4		601.3		30.2		65.2		284.0		221.9
U.K. pound sterling denominated term notes (2)	20.6		22.6		1.1		21.5		—		—
Cdn dollar term Credit Facility borrowings (1)	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.

⁽²⁾  Contractual cash flows include future interest payments and term notes calculated at December 31, 2017 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, 2018			December 31, 2017
Risk management contracts
Current asset		$3.5			$—
Non-current asset	4.5			1.9
Current liability	(4.2		)	(40.0		)
Non-current liability	—			(18.6		)
		$3.8			($56.7	)

PENGROWTH 2018 Financial Results 41

17. FOREIGN EXCHANGE (GAIN) LOSS

	Year ended December 31
	2018			2017
Currency exchange rate (Cdn$1 = U.S.$) at beginning of year		$0.80			$0.74
Currency exchange rate (Cdn$1 = U.S.$) at year end		$0.73			$0.80
Unrealized foreign exchange (gain) loss from translation of foreign denominated debt		$39.8			($65.6	)
Unrealized (gain) loss on foreign exchange risk management contracts	(24.9		)	14.2
Net unrealized foreign exchange (gain) loss		$14.9			($51.4	)
Net realized foreign exchange (gain) loss		($0.8	)		$38.4

18. COMMITMENTS

	2019		2020		2021		2022		2023		Thereafter		Total
Operating leases	1.5		1.5		1.5		1.8		1.8		2.1		10.2
Onerous leases	5.1		5.3		5.2		6.0		4.9		5.8		32.3
Pipeline transportation	27.0		33.8		35.1		35.2		35.5		152.4		319.0
Power infrastructure and other	13.6		0.2		0.2		0.2		0.2		3.9		18.3
	$	47.2	$	40.8	$	42.0	$	43.2	$	42.4	$	164.2	$	379.8

19. 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.

20. 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
	2018		2017
Operating		$12.3		$30.1
General and administrative	20.0		35.5
Total employee compensation costs		$32.3		$65.6

PENGROWTH 2018 Financial Results 42

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 2018, Pengrowth had 7 non-executive directors and 7 officers (2017 - 6 non-executive directors and 7 officers). Pengrowth had 6 non-executive directors and 4 officers at the end of 2018.

Year ended December 31, 2018	Wages & benefits paid		Bonus and other compensation paid		Share based compensation expense			Severance paid		Total
Directors		$0.5		$—		$0.1			$—		$0.6
Officers	2.0		3.7		2.9			2.4		11.0
		$2.5		$3.7		$3.0			$2.4		$11.6
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

PENGROWTH 2018 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 2018 and 2017 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, 2018, 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

RESULTS OF OPERATIONS

(millions of dollars)	2018			2017
Oil and gas sales to external customers, net of royalties	$	515.2		$	627.6
Oil and gas sales used in internal operations	(7.2		)	—
	508.0			627.6
Less:
Operating costs, diluent and other purchases, and transportation	(331.7		)	(408.1		)
Depreciation, depletion, amortization and accretion	(169.3		)	(219.0		)
Impairment	(91.0		)	(634.4		)
Results of operations	$	(84.0	)	$	(633.9	)

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)	2018			2017
Property acquisition costs
- Proved	$	0.2		$	0.1
- Unproved	—			—
Exploration costs	(0.2		)	(0.3		)
Development costs	88.1			(289.9		)
	$	88.1		$	(290.1	)

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.

Pengrowth capitalizes a portion of general and administrative costs associated with exploration and development activities.

Approximately $70.9 million (2017 – $237.8 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)	2018			2017
Cost or deemed cost	$	3,965.1		$	3,817.7
Less: Accumulated depletion, amortization and impairment losses	(2,880.7		)	(2,720.3		)
Oil and natural gas assets	1,084.4			1,097.4
Add: Exploration and evaluation assets	82.6			232.0
	$	1,167.0		$	1,329.4
Unproved oil and gas properties
Unproven properties included in oil and natural gas assets	$	247.6		$	154.9
Exploration and evaluation assets	82.6			232.0
	$	330.2		$	386.9
Proved oil & gas properties	836.8			942.5
Total capitalized costs	$	1,167.0		$	1,329.4

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 2016	30.3			141.9			14.2			311.8
Revisions of previous estimates (including infill drilling & improved recovery)	0.2			1.9		a	0.2			9.9		b
Purchase of reserves in place	—			—			—			4.5		c
Sale of reserves in place	(26.4	)	d	—			(12.7	)	d	(179.1	)	d
Discoveries and extensions	—			5.4		e	—			28.6		f
Production	(2.5	)		(5.0	)		(1.7	)		(33.4	)
End of Year 2017	1.6			144.2			—			142.3
Revisions of previous estimates (including infill drilling & improved recovery)	(0.2	)		(2.1	)		—			(7.2	)	g
Sale of reserves in place	(0.4	)		—			—			(0.3	)
Discoveries and extensions	—			—			—			28.9		h
Production	(0.2	)		(5.5	)		—			(9.8	)
End of Year 2018	0.8			136.6			—			153.9
Notes Re Significant Changes:
(a) Primarily due to infill drilling and technical revisions due to digitized mapping at Lindbergh.
(b) Primarily due to improved constant pricing resulting in recovery of late life reserves.
(c) Acquisition of a small partner working interest in the Groundbirch area resulting in an increase of Total Proved Plus Probable Reserves.
(d) Primarily due to our non-core asset disposition program as described under "Acquisitions and Divestitures" on Page 24 of Pengrowth's 2017 Annual Information Form, to our Form 40-F dated February 28, 2018.
(e) 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 11 of Pengrowth's 2017 Annual Information Form, to our Form 40-F dated February 28, 2018.
(f) Proved Reserves booked at Groundbirch due to offsetting competitor activity.
(g) Primarily due to lower constant gas pricing used in the evaluation at December 31, 2018 resulting in gas reserves being removed due to economic factors across all gas properties.
(h) Due to reserve additions at Groundbirch related to 2017 drilling 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 2016	26.5			13.9			11.7			207.6
End of year 2017	1.6			22.4			—			31.2
End of year 2018	0.8			17.1			—			38.4
Net Proved Undeveloped Reserves After Royalty
End of year 2016	3.8			128.0			2.5			104.2
End of year 2017	—			121.8			—			111.1
End of year 2018	—			119.5			—			115.5

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, 2018 and 2017.

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, 2018 and December 31, 2017. 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, 2018 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 $70.07/bbl (2017 - $63.43/bbl) and AECO natural gas price of $1.46/MMBtu (2017 - $2.35/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)	2018			2017
Future cash inflows	$	4,920		$	6,109
Future costs
- Future production costs	(2,134		)	(2,659		)
- Future developments costs	(1,486		)	(1,919		)
- Future income taxes	—			(12		)
Future net cash flows	$	1,300		$	1,519
Deduct: 10% annual discount factor	(740		)	(777		)
Standardized measure of discounted future net cash flows	$	560		$	742

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)	2018			2017
Future discounted net cash flow at beginning of year	$	742		$	541
Sales and transfers of oil and gas, net of production costs, produced during the period	(178		)	(219		)
Net change in sales & transfer prices related to future production	(227		)	484
Changes in estimated future development costs	34			(41		)
Net change due to extensions, discoveries, and improved recovery	17			45
Change due to revisions (including infill drilling & improved recovery)	(11		)	17
Accretion of discount	75			54
Net sales of reserves in place	(3		)	(153		)
Net change in income taxes	—			(4		)
Other - unspecified	111			18
Future discounted net cash flow at end of year	$	560		$	742

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, 2018 and 2017. 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, 2018.

	Development		Exploration		Total
Wells	Gross	Net	Gross	Net	Gross	Net
Natural Gas	—	—	—	—	—	—
Crude Oil	—	—	—	—	—	—
Bitumen	8.0	8.0	—	—	8.0	8.0
Service	—	—	—	—	—	—
Stratigraphic Test	—	—	—	—	—	—
Dry	—	—	—	—	—	—
Total	8.0	8.0	—	—	8.0	8.0

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	0.0	0.0	1.0	0.2

8

Oil and Gas Wells

As at December 31, 2018, we had an interest in 451 gross (258 net) producing oil and natural gas wells and 950 gross (597 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	38	30	87	76	125	106
British Columbia	37	23	191	119	228	142
Saskatchewan	3	1	16	6	19	7
Bitumen Wells
Alberta	42	42	2	1	44	43
Natural Gas Wells
Alberta	206	105	72	47	278	152
British Columbia	105	54	248	136	353	190
Saskatchewan	1	1	10	4	11	5
Nova Scotia	19	2	3	—	22	2
Service Wells (1)
Alberta	—	—	118	90	118	90
British Columbia	—	—	173	112	173	112
Saskatchewan	—	—	9	4	9	4
Nova Scotia	—	—	17	1	17	1
Other (2)
Alberta	—	—	4	1	4	1
British Columbia	—	—	—	—	—	—
Saskatchewan	—	—	—	—	—	—
Total	451	258	950	597	1,401	855

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 March 5, 2019, 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

March 5, 2019

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

1600, 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, 2018 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, 2018 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

March 5, 2019

______________________________________________________________

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, 2018, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Peter D. Sametz, 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: March 5, 2019

/s/ Peter D. Sametz

Name: Peter D. Sametz

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, 2018, 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: March 5, 2019

/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, Peter D. Sametz, 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: March 5, 2019

/s/ Peter D. Sametz

Name: Peter D. Sametz

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: March 5, 2019

/s/ Christopher G. Webster

Name: Christopher G. Webster

Title: Chief Financial Officer

EX-99.11

Pengrowth Energy Corporation

CODE OF BUSINESS CONDUCT

AND ETHICS

Last Reviewed and Approved by the Board of Directors on November 7, 2018

TABLE OF CONTENTS

Application1

Purpose1

Policy1

Compliance with Code1

Compliance with the Law1

Health, Safety and the Environment1

Maintaining Records2

Accounting and Financial Reporting2

Assistance to Auditors2

Public Reporting2

Conflict of Interest2

Private Business Interest3

Involvement with Not-for-Profit Organizations3

Outside Employment3

Directorships3

Related Party Transaction3

Corporate Property and Opportunities3

Disclosure of Conflict of Interest4

Fraud and Corruption4

Definition of Fraud and Corruption4

Gifts and Entertainment5

Facilitation payments and kickbacks5

Fair Dealings5

Political Activities and Contributions5

Confidential Information6

Use of Confidential Information6

Disclosure of Confidential Information6

Inside Information6

Protection and Use of Assets6

Intellectual Property - Patents, Inventions, Discoveries and Copyrights7

Employee Relations and Reporting7

Compliance with Policies, Procedures and Internal Controls and Exception Reporting7

Incentive Compensation Recoupment Policy7

Reporting Violation or Suspected Violation of this Code or Law7

No Retaliation for Raising Concern8

Consequence of Non-Compliance with Code or Law8

Questions Regarding this Code or Law8

Acknowledgement8

Exceptions8

Appendix "A" Complaint Procedures for Accounting, Financial Reporting and Auditing Matters and Violations of the Code of Business Conduct and Ethics9

Appendix "B" Awareness Statement on Code of Business Conduct and Ethics12

	PENGROWTH ENERGY CORPORATIONPolicies and Practices	Page 1 of 12
CODE OF BUSINESS CONDUCT AND ETHICS

CODE OF BUSINESS CONDUCT AND ETHICS | 1

APPLICATION

Unless expressly provided herein to the contrary, this Code of Business Conduct and Ethics (the "Code") applies to all directors, officers, employees, consultants and contractors (each a "Member") of Pengrowth Energy Corporation and its respective subsidiaries and affiliates (collectively, referred to herein as "Pengrowth").

PURPOSE

This Code summarizes appropriate behaviour for maintaining Pengrowth's reputation for honesty and integrity earned by maintaining the highest standards of business ethics and compliance with applicable laws, rules and regulations in all our interactions with our fellow Members, governments, local communities, securityholders, customers, suppliers, competitors and the public.

POLICY

Pengrowth and all of its Members will adhere to the highest ethical standards and compliance with laws, rules and regulations in all our business activities. Any situation, decision or response should first consider what is right and how it reflects on Pengrowth. Although the various matters described in this Code do not cover the full spectrum of employee and contractor activities, they are indicative of the type of behaviour expected from employees and contractors in all circumstances.

COMPLIANCE WITH CODE

Members are expected to comply with all aspects of this Code. This Code does not specifically address every potential form of unacceptable conduct, and it is expected that Members will exercise good judgment in compliance with the principles set out in this Code. Each Member has a duty to avoid any circumstance that would violate the letter or spirit of this Code.

COMPLIANCE WITH THE LAW

Each Member must ensure that his or her dealings and actions on behalf of Pengrowth comply with the spirit and intent of all relevant legislation, rules and regulations including those set by a self regulatory body or professional organization of all the countries in which Pengrowth operates or where Pengrowth’s securities are listed on the exchanges.

HEALTH, SAFETY AND THE ENVIRONMENT

Pengrowth is committed to safe and healthful working conditions for all Members and third parties, and to conducting its activities in an environmentally responsible manner consistent with the principles of sustainable development.

Members are expected to read, understand and adhere to Pengrowth's Environmental, Health and Safety Policies and Procedures and participate fully in this effort by improving operations to avoid injury or sickness to persons, and damage to property and the environment and by giving due regard to all applicable safety standards, regulatory requirements, technical and conventional standards and restraints.

MAINTAINING RECORDS

Accurate, timely and reliable books of account and records are essential for effective management to ensure Pengrowth meets its business, legal and financial obligations. Members are to safeguard Pengrowth's records and adhere to retention guidelines.

ACCOUNTING AND FINANCIAL REPORTING

Pengrowth is committed to achieving compliance with all applicable securities laws and regulations, accounting standards, accounting controls and audit practices. Every Member is required to follow prescribed accounting and financial reporting procedures. All accounting records should accurately reflect and describe corporate transactions and that all transactions are fairly, completely, accurately, timely and understandably accounted for and recorded in accordance with Pengrowth’s policies and procedures. The recording of such data must not be falsified or altered in any way to conceal or distort assets, liabilities, revenues, expenses or the nature of the activity.

Any suspected violation relating to accounting or financial reporting matters should be reported pursuant to procedures described in Appendix A – “Complaint Procedures for Accounting, Financial Reporting and Auditing Matters and Violations of the Code of Business Conduct and Ethics” to this document.

It is essential that all Members follow established policies, procedures and internal controls. Any exception to established policies, procedures and internal controls (excluding to this Code) is prohibited, unless appropriately authorized in advance by any officer of Pengrowth who shall report all such approved exceptions to the Audit and Risk Committee. Exceptions to this Code are dealt with below under "Exceptions”.

ASSISTANCE TO AUDITORS

No information should be concealed from the internal or external independent auditors.

PUBLIC REPORTING

Persons responsible for the preparation of documents and reports and other public communications that Pengrowth files with, or submits to, the securities commissions and in its other public communications to comply with its obligations under the securities laws and to meet the expectations of its securityholders and other members of the investment community are to exercise the highest standard of care in their preparation in accordance with the applicable laws and must include full fair, accurate, timely and understandable disclosure.

Enquiries from members of the community related to matters of a sensitive nature should be directed to a member of senior management. Any member of senior management receiving such an enquiry is then required to refer the matter to either the President and Chief Executive Officer (the "CEO") or the Chief Financial Officer (the “CFO”) whereby such senior officers will respond on behalf of Pengrowth.

All Members responsible for disclosure are expected to read, understand, adhere to and must act according to Pengrowth's Corporate Disclosure Policy.

CONFLICT OF INTEREST

Members must avoid interests or relationships where their personal interests may affect, or appear to affect, their judgment in acting in the best interests of Pengrowth. This requires that each Member act in such a manner that his or her conduct will bear the closest scrutiny should circumstances demand that it be examined. Where a conflict of interest situation may exist, or be perceived to exist, the Member may be put in a compromising position or his or her judgement may be questioned. Pengrowth wants to ensure that all Members are, and are perceived to be, free to act in the best interests of Pengrowth.

There are many situations which can be classified as conflicts of interest, but the following examples illustrate those that are most common.

Private Business Interest

A Member, either directly or indirectly through his or her immediate family or by any other means, must not have a personal financial interest in, or place himself or herself in a position where he or she could derive a benefit or interest from, a business transaction with Pengrowth, which financial interest or benefit is of such a nature that it would reasonably be expected to create a conflict of interest for the Member.

This, however, does not prevent a Member and his or her family from having ownership in publicly traded shares or equity in companies which may do business with Pengrowth. Nor does it prevent a consultant or contractor from providing his or her services to Pengrowth through a third party corporation.

Involvement with Not-for-Profit Organizations

As a responsible community citizen, Pengrowth encourages and supports Member participation in charitable, educational, cultural, political and not-for-profit organizations. Members are reminded that such participation should not be of a nature or extent that it adversely affects a Member’s job performance or puts the Member in a conflict of interest position.

Outside Employment

Pengrowth recognizes that some employees may, from time to time, hold additional part-time employment outside their employment relationship with Pengrowth. Employees are reminded that any such outside employment should not be of a nature or extent that it adversely affects the employee’s job performance at Pengrowth or put the employee in a conflict of interest position. All employees who hold management positions with Pengrowth shall obtain approval of the CEO before accepting any such outside employment.

Directorships

Any officer or employee shall obtain the approval of the CEO prior to accepting a position as a director of a for-profit company or any business organization. The CEO shall obtain the approval of the Board of Directors prior to accepting a position as a director of a for-profit company or any business organization. A director shall advise the Chairman of the Board prior to accepting a position as a director of a for-profit company or any business organization.

Related Party Transaction

Each director and officer who is a party to a material contract or proposed material contract with Pengrowth or is a director or an officer of or has a material interest in any entity which is a party to a material contract or proposed material contract with Pengrowth of which he has knowledge is required to disclose in writing to the Chairman of the Board the nature and extent of the director's or officer's interest. The Chairman of the Board shall make any such disclosure concerning himself to the Chair of the Compensation and Governance Committee.

Corporate Property and Opportunities

Members are prohibited from taking for themselves, opportunities that arise through the use of corporate property, information or position and from using corporate property, information or position for personal gain.

DISCLOSURE OF CONFLICT OF INTEREST

Disclosure of areas of potential conflict of interest will allow appropriate steps to be taken to protect the individual from these situations.

Officers, employees, consultants and contractors are required to disclose to the CEO in writing all business, commercial or financial interests and activities which might reasonably be regarded as creating an actual or potential conflict with their duties of employment. The CEO will determine whether a conflict of interest does or could exist and, if necessary, advise the person as to what steps should be taken. Directors are required to disclose to the Chair of the Compensation and Governance Committee (or, in the case of the Chair of the Compensation and Governance Committee, to the other members of the Committee) all business, commercial or financial interests and activities which might reasonably be regarded as creating an actual or potential conflict with their duties as directors.

FRAUD AND CORRUPTION

Pengrowth requires all Members at all times to act honestly and with integrity and to safeguard the Pengrowth’s resources for which they are responsible. Pengrowth is committed to protecting all revenue, expenditure and assets from any attempt to gain illegal financial or other benefits.

Any suspected fraud or corruption committed against Pengrowth will be thoroughly investigated and appropriate disciplinary action will be taken against any Member who is found guilty of corrupt or fraudulent conduct. This may include termination of employment and/or referral of the matter to the appropriate law enforcement or regulatory agencies for independent investigation.

Definition of Fraud and Corruption

Corruption is defined as a dishonest activity in which a Member acts contrary to the interests of Pengrowth and abuses his/her position of trust in order to achieve some personal gain or advantage for him or herself or for another person or entity.

Examples of corrupt conduct include but are not limited to:

• payment of secret commissions (bribes or gratuities) in money, or some other value, to other businesses, individuals or public officials

• receipt of bribes or gratuities from other businesses, individuals or public officials

• release of confidential information, for other than a proper business purpose, sometimes in exchange for either a financial or non-financial advantage

• a Member manipulating a tendering process to achieve a desired outcome

• a conflict of interest involving a Member acting in his or her own self-interest rather than the interests of Pengrowth

Fraud is defined as an intentional act by one or more individuals involving the use of deception to obtain an unjust or illegal advantage.

A fraud can typically result in actual or potential financial loss to any person or entity however this is not always the case.

Examples of fraud could include, but are not limited to:

• misappropriation of funds, securities, supplies or other assets including use of assets for private purposes

• causing a loss to Pengrowth or creating a liability for Pengrowth by deception

• improper financial reporting (such as improper revenue recognition and over- or understating assets or liabilities)

• deliberate failure to fulfill our disclosure obligations

• falsifying records

• profiting from insider knowledge of Pengrowth activities

• accepting or seeking anything of value, other than as provided for below under “Gifts and Entertainment”, from contractors, vendors or persons providing services or goods to Pengrowth

• false invoicing for goods or services never rendered or backdating agreements

• submission of exaggerated or wholly fictitious accident, harassment or injury claims

GIFTS AND ENTERTAINMENT

The exchange of gifts and entertainment is a common practice in most business communities and is designed to develop and foster goodwill among business partners. Accepting gifts and entertainment can cause problems when they compromise, or appear to compromise, our ability to make fair and objective business decisions. No gift or entertainment should be accepted, or offered, if it will unfairly influence a business relationship.

There are many factors that influence whether a gift or entertainment is normal and customary. Gifts or entertainment should be moderate, reasonable and in good taste, be of a style or value commonly accepted for business occasions and should not be unusual for the recipient’s job or community. The exchange must create no obligation or sense of obligation and should occur infrequently.

Business entertainment can present situations where discretion is required since some commonly accepted business invitations can include recreational opportunities or event tickets that are of significant value. In these cases, the recipient should ensure that there is a valid business development reason for attending. If the invitation is for an event where the value being received may be significant, prior approval by an officer of Pengrowth is required, or in the case of the CEO, approval by the Chair of the Compensation and Governance Committee. As transportation costs for events can also be significant, payment of these costs by another party is not acceptable and will be covered by Pengrowth if there is a valid business reason to accept the invitation.

FACILITATION PAYMENTS AND KICKBACKS

Pengrowth does not make, and will not accept, facilitation payments or "kickbacks" of any kind. Facilitation payments are typically small, unofficial payments made to secure or expedite a routine government action by a government official; however they may also be payments to or from a private citizen.

If a Member is asked to make a payment on Pengrowth’s behalf, he or she should always be mindful of what the payment is for and whether the amount requested is proportionate to the goods or services provided. Members should always ask for a receipt which details the reason for the payment. If a Member has any suspicions, concerns or queries regarding a payment, he or she should raise them with their immediate supervisor, the CEO or the CFO. Alternatively, if a Member feels unable to raise an issue in this way, he or she can make a confidential, anonymous report pursuant to Pengrowth’s whistleblower procedure described in Appendix “A” hereto.

FAIR DEALINGS

It is Pengrowth's policy to deal fairly and lawfully with all securityholders, customers, suppliers, competitors and Members. All goods and services shall be obtained on a competitive basis at the best value considering price, quality, reliability, availability and delivery.

POLITICAL ACTIVITIES AND CONTRIBUTIONS

Pengrowth respects and supports the right of its employees to participate in political activities. However, these activities should not be conducted on Pengrowth time or involve the use of any Pengrowth resources. Employees will not be reimbursed for personal political contributions.

Pengrowth may occasionally express its views on local and national issues that affect its operations. In such cases, Pengrowth funds and resources may be used, but only when permitted by law and by Pengrowth's strict guidelines. On very limited occasions, Pengrowth may also make limited contributions to political parties or candidates in jurisdictions where it is legal and customary to do so. Pengrowth may pay related administrative and solicitation costs for political action committees formed in accordance with the political laws and regulations. No employee may make or commit to political contributions on behalf of Pengrowth without the approval of the CEO.

CONFIDENTIAL INFORMATION

In the course of their work, Members may have access to information that is confidential, privileged, of value to competitors of Pengrowth or might be damaging to Pengrowth if improperly disclosed. Pengrowth respects privileged business and employee related information, and therefore all Members must protect the confidentiality of such information.

USE OF CONFIDENTIAL INFORMATION

The use or disclosure of confidential information must be for Pengrowth’s purposes only and not for personal benefit or the benefit of others. This applies to disclosure of confidential information concerning Pengrowth or its business activities as well as information with respect to companies having business dealings with Pengrowth. To preserve confidentiality, disclosure and discussion of confidential information should be limited to those individuals who need to know the information. Members are expected to read, understand and adhere to Pengrowth's Corporate Disclosure Policy and Confidentiality Agreements.

DISCLOSURE OF CONFIDENTIAL INFORMATION

Members must guard against improper disclosure of information that may be of competitive value to Pengrowth. Pengrowth is in a competitive environment with other companies. Certain records, reports, papers, devices, processes, plans, methods and apparatus of Pengrowth, including methods of doing business, strategies and information on costs, prices, sales, profits, markets and opportunities are the property of Pengrowth and are considered to be confidential and proprietary. Members must not reveal such confidential information. Confidential information does not include information which is already in the public domain. Certain information may be released by Pengrowth (to comply with securities regulations, for example) however, the release of such information is a decision of the Board of Directors and senior management. If there is any doubt as to what can or cannot be discussed outside of Pengrowth, Members should err on the side of discretion and not communicate any information. For more specific advice, your immediate manager, the CEO, or the CFO should be consulted.

These obligations regarding confidential information continue to apply to all Members following cessation of their employment or contractual relations with Pengrowth. Members are expected to read, understand and adhere to Pengrowth's Corporate Disclosure Policy and Confidentiality Agreements.

INSIDE INFORMATION

Certain information, which Pengrowth treats as confidential, may influence the price or trading of Pengrowth's common shares or other securities if it is disclosed to members of the public. Inside information would include information concerning material exploration well results, major contracts, proposed acquisitions or mergers, and earnings figures. Members shall not use such inside information for their own financial gain or for that of their associates.

If in doubt as to the propriety of actions, the Member should seek the advice of the CEO, or the CFO.. Members are expected to read, understand and adhere to Pengrowth's Policy on Trading in Securities.

PROTECTION AND USE OF ASSETS

All Members are responsible for protecting Pengrowth's assets and their efficient use for legitimate business purposes only. Pengrowth provides Members with computer and Internet access for work purposes. Members are expected to read, understand, acknowledge and adhere to Pengrowth's Acceptable Use Policy for Information System Assets.

INTELLECTUAL PROPERTY - PATENTS, INVENTIONS, DISCOVERIES AND COPYRIGHTS

All intellectual property including inventions, discoveries and copyrights made by Members during or as a result of their employment or contractual relations with Pengrowth (where company time, equipment, resources or pertinent information has been used for personal gain) are the property of Pengrowth unless a written release is obtained from the CEO.

Pengrowth and its Members honour the proprietary rights of others as expressed in patents, copyrights, trademarks and industrial design.

EMPLOYEE RELATIONS AND REPORTING

Pengrowth values the diversity of its Members and is committed to providing equal opportunity in all aspect of employment. In working together, Members must ensure they treat each other with respect, dignity, honesty, fairness and provide a healthy environment that is free of harassment, violence, offensive behaviour and discrimination. Members are encouraged and expected to speak out if they have any concerns with regard to their workplace environment and report any harassment or bullying, whether verbal, sexual, physical, or visual, if it occurs. This includes situations where Members may witness inappropriate conduct toward someone other than themselves. Members seeking further information or guidance in respect of Pengrowth’s policies with respect to harassment and discrimination should consult Pengrowth’s People Policies which are available on Pengrowth’s internal website.

All Members are encouraged to report any behaviour of other Members which they reasonably believe is illegal or unethical and any suspected violation relating conduct matters should be reported pursuant to procedures described in Appendix A – “Complaint Procedures for Accounting, Financial Reporting and Auditing Matters and Violations of the Code of Business Conduct and Ethics” to this document.

COMPLIANCE WITH POLICIES, PROCEDURES AND INTERNAL CONTROLS AND EXCEPTION REPORTING

Members should ensure all transactions with which they are involved are authorized and executed in accordance with Pengrowth's policies and procedures and conform to all legal and accounting requirements. Members are expected to read, understand and adhere to Pengrowth's Delegation of Authorities guideline.

Whenever a Member is in doubt about the application or interpretation of any legal requirement or has questions about whether particular circumstances may involve illegal conduct, the individual should immediately seek the advice of his or her manager.

INCENTIVE COMPENSATION RECOUPMENT POLICY

The Board of Directors shall, in all appropriate circumstances, require reimbursement of any incentive payment to an executive officer where: (1) the payment was predicated upon achieving certain financial results that were subsequently the subject of a substantial restatement of Pengrowth’s financial statements; (2) the Board of Directors determines such individual engaged in intentional misconduct that caused or substantially caused the need for the substantial restatement; and (3) a lower payment would have been made to such individual based upon the restated financial results. In each such instance, Pengrowth will, to the extent practicable, seek to recover from the individual the amount by which the individual’s incentive payments for the relevant period exceeded the lower payment that would have been made based on the restated financial results.

REPORTING VIOLATION OR SUSPECTED VIOLATION OF THIS CODE OR LAW

It is important that Pengrowth be made aware of circumstances that may indicate possible violations of law or this Code. Any violations of this Code must be promptly reported pursuant to procedures described in Appendix A – “Complaint Procedures for Accounting, Financial Reporting and Auditing Matters and Violations of the Code of Business Conduct and Ethics” to this document.

NO RETALIATION FOR RAISING CONCERN

Any Member may submit a complaint regarding a suspected violation of the Code without fear of dismissal or retaliation. Pengrowth and applicable law prohibit any form of retaliation for raising concerns or reporting possible misconduct in good faith or for assisting in the investigation of possible misconduct. No adverse action will be taken against any individual for making a complaint or disclosing information in good faith. Any Member who retaliates in any way against an individual who, in good faith, reports any violation, or suspected violation, of this Code, will be subject to disciplinary action.

CONSEQUENCE OF NON-COMPLIANCE WITH CODE OR LAW

Non-compliance with this Code or the law or other dishonest or unethical business practices are forbidden and may result in disciplinary action, including termination from employment or termination of contractual relations.

Pengrowth is required to cooperate with investigations by regulatory authoritative bodies and quasi-judicial tribunals to the extent that a policy violation breaks a law or regulation.

QUESTIONS REGARDING THIS CODE OR LAW

If a Member has any question of appropriateness in a particular situation, areas of conflict or disagreement with any aspect of this Code or any applicable laws, the matter should be discussed with the CEO, the CFO, or Chairman of the Board of Pengrowth.

This Code is not intended to address all of the situations you may encounter. There will be occasions where Members are confronted by circumstances not covered by this Code or procedure and where Members must make a judgment as to the appropriate course of action. In those circumstances, Members are encouraged to use common sense and to contact their respective supervisor, manager or other appropriate person for guidance.

ACKNOWLEDGEMENT

It is essential that all Members understand and adhere to this Code.

All Members will be asked to acknowledge, in writing, their review of and agreement to be bound by this Code as a condition of their new or continuing employment or contractual relations, as the case may be. This acknowledgment must be made: (i) in the case of directors, upon election or appointment to the Board of Directors of Pengrowth and annually thereafter; (ii) in the case of officers and employees, upon the commencement of employment and annually thereafter, or (iii) in the case of consultants and contractors, upon commencement of this contractual relation and annually thereafter, and such acknowledgement may be provided in electronic format.

The form of certification attached as Appendix "B" is to be used by each Member to disclose any personal facts or dealings that are non-compliant with this Code.

EXCEPTIONS

No provision of this Code will be waived in respect of a director or executive officer unless expressly approved by the Board of Directors. For greater certainty, the exercise of discretion by an executive officer or the Board of Directors, in compliance with this Code, shall not be considered a “waiver” of this Code.

As last amended by the Board of Directors of Pengrowth on ●, 2018.

Last reviewed and approved by the Board of Directors of Pengrowth on ●, 2018.

APPENDIX "A" COMPLAINT PROCEDURES FOR ACCOUNTING, FINANCIAL REPORTINGAND AUDITING MATTERS AND VIOLATIONS OF THE CODE OF BUSINESS CONDUCT AND ETHICS

In order to facilitate the reporting of complaints, the Board of Directors of Pengrowth has established the following procedures for the receipt, retention and treatment of complaints regarding Accounting Matters and Conduct Matters (as defined herein) and for the confidential, anonymous submission by directors, officers and employees of Pengrowth (collectively, “Members”) of concerns regarding questionable Accounting Matters and Conduct Matters.

RECEIPT OF COMPLAINTS

1. Through Management

Any Member may submit a complaint regarding fraud, accounting, internal accounting controls, financial reporting or auditing matters (“Accounting Matters”) or regarding suspected violations of the Code of Business Conduct and Ethics, applicable laws and any other conduct concerns (“Conduct Matters”) to the management of Pengrowth without fear of dismissal or retaliation of any kind.

2. Through Appropriate Committee Chair

Any Member with concerns regarding an Accounting Matter may report their concerns to the Chair of the Audit and Risk Committee. Pengrowth is committed to achieving compliance with all applicable securities laws and regulations, accounting standards, accounting controls and audit practices. The Audit and Risk Committee of Pengrowth will oversee and be responsible for the investigation of the treatment of Member concerns relating to Accounting Matters.

Any Member with concerns regarding a Conduct Matter may report their concerns to the Chair of the Compensation and Governance Committee. The Compensation and Governance Committee of Pengrowth will oversee treatment of Member concerns in Conduct Matters.

All such concerns will be set forth in writing and forwarded in a sealed envelope directly to the Chair of the Audit and Risk Committee or Compensation and Governance Committee, as applicable, in an envelope labelled with a legend such as: “To be opened by the Chair of the Audit and Risk Committee only” or “To be opened by the Chair of the Compensation and Governance Committee only.”

If a Member would like to discuss any matter with the Chair of the Audit and Risk Committee or the Chair of the Compensation and Governance Committee, the Member should indicate this in the submission and include a telephone number at which he or she can be reached, should the Chair of the Audit and Risk Committee or the Chair of the Compensation and Governance Committee deem such communication is appropriate.

3. Through Anonymous Confidential Submission

Any Member may report concerns regarding an Accounting Matter or a Conduct Matter on a confidential or anonymous basis to the Chairman of the Board.

Any member who makes an anonymous submission must be sure to provide sufficient detail to identify the concern being raised. given that the submission is made anonymously, the audit and risk committee or the compensation and governance committee, as the case may be, will be unable to follow up if there are additional questions. the submission should, at a minimum, contain dates, places, persons involved and witnesses or other information sufficient for recipient to investigate and determine whether the submission is valid or made in good faith such that a reasonable investigation or assessment can be conducted. scope of accounting matters covered by these procedures.

These procedures relate to Members’ complaints relating to any questionable Accounting Matters, including, without limitation, the following:

• fraud or deliberate error in the preparation, evaluation, review or audit of any financial statement of Pengrowth;

• fraud or deliberate error in the recording and maintaining of financial records of Pengrowth;

• deficiencies in or non-compliance with Pengrowth's internal accounting controls;

• insider trading;

• accounting and auditing irregularities, including financial statement disclosure as required by any applicable law or regulation;

• misrepresentation or false statement to or by a director, officer, employee or external accountant regarding a matter contained in the financial records, financial reports or audit reports of Pengrowth; or

• deviation from full and fair reporting of Pengrowth's financial condition.

SCOPE OF CONDUCT MATTERS COVERED BY THESE PROCEDURES

These procedures relate to Members’ complaints relating to any questionable Conduct Matters, including, without limitation, the following:

• conflicts of interest;

• breaches of securities laws, other than insider trading and matters related to financial statement disclosure;

• breaches of environmental, employment or labour laws, or any other applicable laws;

• fraudulent insurance and benefit claims;

• violations of Pengrowth’s Code of Business Conduct and Ethics policy;

• release of proprietary information;

• safety, wage, salary and hour issues;

• substance abuse;

• sexual harassment, threats, violence or workplace bullying, including retaliation against whistleblowers;

• theft of goods, services, cash or time; or

• commission or possible commission of criminal offences, including offences under any applicable anti-corruption or anti-bribery legislation.

TREATMENT OF COMPLAINTS

The Chairman of the Board shall inform (i) the Chair of the Audit and Risk Committee of all complaints provided to it in respect of Accounting Matters; and (ii) the Chair of the Compensation and Governance Committee of all complaints provided to it in respect of Conduct Matters.

Upon receipt of a complaint or concern, the Chair of the Audit and Risk Committee or Chair of the Compensation and Governance Committee, as the case may be, will: (i) determine whether or not the complaint actually pertains to an Accounting Matter or a Conduct Matter; and (ii) when possible, acknowledge receipt of the complaint to the sender.

Complaints relating to an Accounting Matter will be reviewed by the Audit and Risk Committee, outside legal counsel or such other person(s) as the Audit and Risk Committee determines to be appropriate. Complaints relating to a Conduct Matter will be reviewed by the Compensation and Governance Committee, outside legal counsel or such other person(s) as the Compensation and Governance Committee determines to be appropriate. In any case, confidentiality will be maintained to the fullest extent possible, consistent with the need to conduct an adequate review. If on preliminary examination the allegation is judged to be wholly without substance or merit, or not made in good faith, the allegation may be dismissed.

Prompt and appropriate investigation and corrective action will be taken when and as warranted in the judgment of the Audit and Risk Committee or the Compensation and Governance Committee, as the case may be.

If the identity of the Member making the complaint, or assisting in investigation of the complaint, is known by anyone within Pengrowth, the Audit and Risk Committee will monitor any disciplinary action against the Member to determine whether it could subject Pengrowth to anti-retaliation liability. Pengrowth will not discharge, demote, suspend, threaten, harass or in any manner discriminate against any individual in the terms and conditions of employment based upon any lawful actions of such individual with respect to reporting of complaints in good faith regarding any Accounting Matter or any Conduct Matter.

Pengrowth will regard the making of any deliberately false or malicious allegations by an employee as a serious offence which may result in recommendations to the Board of Directors or to senior management of Pengrowth for disciplinary action including dismissal for cause and, if warranted, legal proceedings.

REPORTING AND RETENTION OF COMPLAINTS AND INVESTIGATIONS

The Chair of the Audit and Risk Committee and the Chair of the Compensation and Governance Committee will maintain a log of all complaints, tracking their receipt, investigation and resolution and shall prepare a periodic summary report thereof for the Audit and Risk Committee or the Compensation and Governance Committee, as the case may be.

RECORD RETENTION

The Chair of the Audit and Risk Committee and the Chair of the Compensation and Governance Committee will work with the Corporate Secretary to ensure that, as part of each committee's respective records, any such complaints or concerns are retained in a manner which preserves their confidentiality, for a period of at least seven years.

APPENDIX "B"AWARENESS STATEMENT ON CODE OF BUSINESS CONDUCT AND ETHICS

To be completed by all directors, officers, employees, consultants and contractors of Pengrowth Energy Corporation and its subsidiaries ("Pengrowth")

I have recently read the Code of Business Conduct and Ethics of Pengrowth (the "Code"), and I can certify that, except as specifically noted below:

1. I understand the content and consequences of contravening the Code and agree to abide by the Code.

2. I am in compliance with the Code.

3. All facts and dealings which I believe to be non-compliant with the Code have been communicated to the appropriate representative of Pengrowth and are detailed below.

4. (If applicable) After due inquiry and to my best knowledge and belief, no employee, consultant or contractor under my direct supervision is in violation of the Code.

5. I have and will continue to exercise my best efforts to assure full compliance with the Code by myself and (if applicable) all employees, consultants and contractors under my direct supervision.

Print or type name:

Signature:

Title and location:

Date:

Facts and dealings that I believe to be non-compliant with the Code

(Including potential conflict of interest situations)

1.

2.

(If required, provide additional details on separate sheet).

CODE OF BUSINESS CONDUCT AND ETHICS | 2

XML

Document and Entity Information	12 Months Ended
	Dec. 31, 2018 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, 2018
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2018
Document Fiscal Period Focus	FY
Entity Current Reporting Status	Yes
Entity Emerging Growth Company	false
Entity Common Stock, Shares Outstanding	556,117,090

XML

CONSOLIDATED BALANCE SHEETS - CAD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Current Assets
Cash and cash equivalents	$ 0.6	$ 1.1
Accounts receivable	42.8	92.9
Fair value of risk management contracts	3.5	0.0
Other assets	33.8	36.8
Assets held for sale	16.0	0.0
Current assets	96.7	130.8
Fair value of risk management contracts	4.5	1.9
Other assets	86.2	99.8
Property, plant and equipment	1,074.2	1,104.2
Exploration and evaluation assets	82.6	232.0
Deferred income taxes	0.0	342.2
TOTAL ASSETS	1,344.2	1,910.9
Current Liabilities
Accounts payable	72.7	136.2
Fair value of risk management contracts	4.2	40.0
Current portion of long term debt	232.9	0.0
Current portion of provisions and other liabilities	39.7	35.2
Liabilities associated with assets held for sale	16.0	0.0
Current liabilities	365.5	211.4
Fair value of risk management contracts	0.0	18.6
Long term debt	481.7	610.5
Provisions and other liabilities	245.1	264.2
Liabilities	1,092.3	1,104.7
Shareholders' Equity
Shareholders' capital	4,838.1	4,829.7
Contributed surplus	9.9	13.3
Deficit	(4,596.1)	(4,036.8)
Equity	251.9	806.2
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	$ 1,344.2	$ 1,910.9

XML

CONSOLIDATED STATEMENTS OF INCOME (LOSS) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	[1]	Dec. 31, 2017
REVENUES
Oil and gas sales	$ 532.2		$ 673.4
Royalties, net of incentives	(24.2)		(45.8)
Revenue from oil and gas sales (net royalties, net of incentives)	508.0		627.6
Realized gain (loss) on commodity risk management	(67.5)		(19.8)
Change in fair value of commodity risk management contracts	35.6		14.2
Revenue	476.1		622.0
EXPENSES
Operating	79.5		217.5
Diluent and other purchases	229.5		163.5
Transportation	22.7		27.1
General and administrative	34.7		61.5
Depletion, depreciation and amortization	162.3		207.6
Impairment	91.0		634.4
Operating expenses	619.7		1,311.6
OPERATING INCOME (LOSS)	(143.6)		(689.6)
Other (income) expense items
(Gain) loss on disposition of properties	1.0		62.6
Unrealized foreign exchange (gain) loss	14.9		(51.4)
Realized foreign exchange (gain) loss	(0.8)		38.4
Interest and financing charges	49.8		70.7
Restructuring costs	0.4		37.0
Loss on extinguishment of debt	0.0		56.7
Accretion	7.0		11.4
Other (income) expense	1.2		(7.4)
INCOME (LOSS) BEFORE TAXES	(217.1)		(907.6)
Deferred income tax (recovery) expense	342.2		(223.8)
NET INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS)	$ (559.3)		$ (683.8)
Earnings per share [abstract]
Basic (in CAD per share)	$ (1.01)		$ (1.24)
Diluted (in CAD per share)	$ (1.01)		$ (1.24)

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CONSOLIDATED STATEMENTS OF CASH FLOW - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018		Dec. 31, 2017
OPERATING
Net income (loss) and comprehensive income (loss)	$ (559.3)	[1]	$ (683.8)
Non-cash items
Depletion, depreciation, amortization and accretion	169.3		219.0
Impairment	91.0		634.4
Deferred income tax (recovery) expense	342.2		(223.8)
Unrealized foreign exchange (gain) loss	14.9		(51.4)
Change in fair value of commodity risk management contracts	(35.6)		(14.2)
Share based compensation	4.8		4.9
(Gain) loss on disposition of properties	1.0		62.6
Onerous lease contracts	3.6		26.5
Other items	3.6		0.9
Onerous office lease payments	(4.9)		0.0
Loss on extinguishment of debt	0.0	[1]	56.7
Foreign exchange derivative settlements	0.0		37.6
Interest and financing charges	49.8		70.7
Expenditures on remediation	(23.2)		(15.9)
Change in non-cash operating working capital	(25.5)		18.2
Cash flow from operating activities	31.7		142.4
FINANCING
Long term debt (repayment)	64.5		(937.2)
Convertible debentures repayment	0.0		(126.6)
Foreign exchange derivative settlements	0.0		(37.6)
Interest and financing charges paid	(55.9)		(100.8)
Cash flow from financing activities	8.6		(1,202.2)
INVESTING
Capital expenditures	(65.4)		(117.9)
Property acquisitions	(0.2)		(0.1)
Proceeds on property dispositions	23.0		910.2
Withdrawals from/(contributions to) remediation trust fund	12.3		(10.5)
Change in non-cash investing working capital	(10.5)		(7.5)
Cash flow from investing activities	(40.8)		774.2
CHANGE IN CASH AND CASH EQUIVALENTS	(0.5)		(285.6)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR	1.1		286.7
CASH AND CASH EQUIVALENTS AT END OF YEAR	$ 0.6		$ 1.1

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CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY - CAD ($) $ in Millions	Total		SHAREHOLDERS' CAPITAL	CONTRIBUTED SURPLUS	DEFICIT
Balance, beginning of year at Dec. 31, 2016			$ 4,815.1	$ 22.9	$ (3,353.0)
Exercise of share based compensation awards			14.6	(14.6)
Share based compensation				5.0
Net income (loss)	$ (683.8)				(683.8)
Balance, end of year at Dec. 31, 2017	806.2		4,829.7	13.3	(4,036.8)
Exercise of share based compensation awards			8.4	(8.4)
Share based compensation				5.0
Net income (loss)	(559.3)	[1]			(559.3)
Balance, end of year at Dec. 31, 2018	$ 251.9		$ 4,838.1	$ 9.9	$ (4,596.1)

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BUSINESS OF THE CORPORATION

12 Months Ended

Dec. 31, 2018

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 and exploration 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.

Future Operations

Through 2018, Pengrowth has had discussions with the lead banks in its syndicate regarding a new credit agreement that will permit Pengrowth to access the high yield debt market to refinance substantially all of its existing term notes as further described in Note 7. Pengrowth is also exploring alternative financing arrangements including third party debt providers to refinance its entire debt portfolio. These discussions, if successful, may result in an offer for replacement debt at a higher cost than the current outstanding debt.

Pengrowth engaged Perella Weinberg Partners LP and Tudor, Pickering, Holt & Co ("PWP/TPH") as advisers to assist in exploring financing alternatives. On March 5, 2019, the Board of Directors commenced a formal process with PWP/TPH to explore and develop strategic alternatives (the “Strategic Review”) with a view to strengthening the Corporation's balance sheet and maximizing enterprise value. The Strategic Review is intended to explore a comprehensive range of strategic and transaction alternatives, including a sale, merger or other business combination; a disposition of all or certain assets of the Corporation; recapitalization and refinancing opportunities; sourcing new financing and equity capital; and other alternatives to improve the Corporation's financial position and maximize value. In addition to Pengrowth’s long-life, low-decline assets, the Corporation also has potentially attractive tax attributes that complement its strong base operations. Pengrowth and its advisers expect to actively explore market interest in potential transactions and strategic initiatives with a range of interested parties and capital market participants. There can be no guarantees as to whether the Strategic Review will result in a transaction or the terms or timing of any resulting transaction. Various industry risk factors, including a prolonged or significant decrease in WTI or WCS pricing, could impact the outcome of the Strategic Review Process, Pengrowth’s cash flow, and its ability to address its upcoming debt maturities.

Furthermore, the Corporation is in discussions with the lending syndicate under its $330 million revolving credit facility (the "Credit Facility") on arrangements to extend the maturity date of the Credit Facility through September 30, 2019 to support the Strategic Review. The Corporation's objective is to finalize the extension agreement as soon as possible, and in advance of the current March 31, 2019 maturity date, however, there can be no assurance or guarantee that an extension will be obtained by the Corporation or on what terms.

Due to the rapid deterioration of commodity prices, uncertainty around improvements in global prices, and uncertainty around timing of refinancing of Pengrowth's debt portfolio, there remains a risk around Pengrowth's ability to stay in compliance with its debt covenants at the end of 2019.

As a result, there is significant uncertainty related to these events and conditions that raise substantial doubt about whether the Corporation will continue as a going concern, and therefore, whether it will realize its assets and settle its liabilities in the normal course of business and at the amounts stated in the financial statements. However, management believes that the Corporation will be successful in obtaining alternative debt financing and amending its financial covenants as outlined in Note 8 in a timely manner and, accordingly, has prepared the financial statements on a going concern basis.

Accordingly, no adjustments have been made to the financial statements relating to the recoverability and classification of the asset carrying amounts or the amount and classification of liabilities that may be necessary should the consolidated entity not continue as a going concern. At this time, management believes that no asset is likely to be realized for an amount less than the amount at which it is recorded in financial statements as at December 31, 2018.

Pengrowth continues to generate sufficient cash flow to meet its obligations including interest payments, capital spending and abandonment and remediation expenses and plans to settle the October 2019 term notes with internally generated cash flow.

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SIGNIFICANT ACCOUNTING POLICIES

12 Months Ended

Dec. 31, 2018

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”).

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 March 5, 2019.

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 Corporation 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 Corporation 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.

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 on the license or field. 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 with the related PP&E CGU 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 and gross overriding royalty. 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
-	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 and on transfer of E&E to PP&E. 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 including at the time of transfer, 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

The Corporation has elected to measure loss allowances for trade receivables and contract assets at an amount equal to lifetime expected credit losses (“ECLs”). The Corporation measures loss allowances for the amount due from affiliates at an amount equal to the 12-month ECLs. The maximum period considered when estimating ECLs is the maximum contractual period over which the Corporation is exposed to credit risk.

ECLs are a probability-weighted estimate of credit losses. Credit losses are measured as the present value of all cash shortfalls (i.e. the difference between the cash flows due to the entity in accordance with the contract and the cash flows that the Corporation expects to receive). ECLs are discounted at the effective interest rate of the financial asset.

Loss allowances for financial assets are deducted from the gross carrying amount of the assets. Impairment losses on financial assets are presented under “other expenses” in the statement of loss and comprehensive loss.

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.

Impairment losses on financial assets carried at amortized cost are reversed in the statement of loss and comprehensive loss in subsequent periods if the amount of the loss decreases.

Inventory

Product inventories are valued at the lower of cost and net realizable value on a first-in, first-out weighted average cost basis. The cost of inventory includes all costs incurred in the normal course of business to bring each product to its present location and condition. Net realizable value is the estimated selling price in the ordinary course of business less any expected selling costs. If the carrying amount exceeds net realizable value, a write-down is recognized. The write-down may be reversed in a subsequent period if circumstances which caused it no longer exist and the inventory is still on hand.

Provisions and other liabilities

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 using a risk free rate 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 estimates are recorded as an increase or decrease to the ARO liability with a corresponding change made to the carrying amount of the related asset. In case of assets with no remaining production or reserves, revisions to ARO liability are recorded in the Consolidated Statements of Income (Loss). 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 Lease Contracts

The onerous lease obligation relates to excess head office space and an unutilized construction camp at Lindbergh which were recognized as the unavoidable costs of the lease contracts over the remaining term exceeded the economic benefits of the leases. The onerous lease provision is calculated as present value of future lease payments Pengrowth is obligated to make under the lease contracts less any recoveries under current or anticipated sublease agreements over the remaining life of the leases.

Other Liabilities

Pengrowth also categorizes certain cash-settled long term incentive plan ("LTIP") grants 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 a number of share-settled and cash-settled share based compensation plans, which are described in Note 12.

Share-settled LTIP

Performance Share Units ("PSUs") and Restricted Share Units ("RSUs")

Compensation expense related to PSU and RSU share-settled plans is based on the estimated 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 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.

Stock option plan

Pengrowth uses the Black-Scholes pricing model to calculate the fair value of stock options granted using an estimated forfeiture rate, volatility, risk free rate and expected life. The fair value is recorded as share-based compensation expense over the vesting period with a corresponding amount reflected in contributed surplus. When stock options are exercised, the cash proceeds along with the amount previously recorded as contributed surplus are recorded as share capital.

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. 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. The revaluation of the cash-settled LTIP continues until settlement. Pengrowth estimates the forfeiture rate for each type of share based award at the date of grant.

Financial Instruments

Financial instruments are utilized by Pengrowth to manage its exposure to commodity price fluctuations and foreign currency exposures. Pengrowth’s policy is not to utilize financial instruments for trading or speculative purposes.

IFRS 9 sets out requirements for recognizing and measuring financial assets, financial liabilities and some contracts to buy or sell non-financial items. The Corporation adopted the standard with a date of initial application of January 1, 2018. This standard replaced IAS 39 Financial Instruments: Recognition and Measurement.

IFRS 9 largely retains the existing requirements in IAS 39 for the classification and measurement of financial liabilities. However, it eliminates the previous IAS 39 categories for financial assets of held to maturity, loans and receivables and available for sale. Under IFRS 9, on initial recognition, a financial asset is classified as measured at:

• Amortized cost;

• Fair value through other comprehensive income ("FVTOCI") - debt investment;

• Fair value through other comprehensive income ("FVTOCI") - equity investment;

• Fair value through profit or loss ("FVTPL").

The classification of financial assets under IFRS 9 is generally based on the business model in which a financial asset is managed and its contractual cash flow characteristics.

IFRS 9 replaces the ‘incurred loss’ model in IAS 39 with an ECL model. The new impairment model applies to financial assets measured at amortized cost, contract assets and debt investments at FVOCI, but not to investments in equity instruments. Under IFRS 9, credit losses are recognized earlier than under IAS 39.

The adoption of IFRS 9 did not result in any changes in the eligibility of existing hedge relationships. Pengrowth currently has no intentions of designating any of its financial instruments as hedges, or using hedge accounting.

The following summarizes Pengrowth's financial assets and financial liabilities as a result of the adoption of IFRS 9:

• Accounts receivable and other assets are measured at amortized cost.

• Investments held in the remediation trust funds and other investments are measured at fair value through profit or loss. Any change in the fair value is recognized in the Consolidated Statements of Income (Loss).

• Bank indebtedness, accounts payable and long term debt have been measured at amortized cost using the effective interest rate method.

• Derivative assets and liabilities must be measured at fair value through profit or loss with changes in fair value over a reporting period recognized in net income (loss).

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.

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 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 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.

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.

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 Owned Assets

A minor proportion of Pengrowth’s petroleum and natural gas development and production activities involve jointly owned assets that are not conducted through separate vehicles and accordingly, the accounts reflect only Pengrowth’s proportionate 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 20 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.

Estimates and Judgments

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 or 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.

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, if applicable.

Identification of impairment indicators

Judgment is required to assess when indicators of impairment or reversals exist and whether calculation of the recoverable amount of an asset is necessary. Management considers internal and external sources of information including petroleum and natural gas prices, expected production volumes, anticipated recoverable quantities of proved and probable reserves and rates used to discount future cash flow estimates. Judgement is required to assess these factors when determining if the carrying amount of an asset is impaired, or in the case of previously impaired asset, whether the carrying amount of the asset has been restored.

Share-based payments

Stock options granted by the Corporation are recorded at fair value using the Black Scholes option pricing model. In assessing the fair value of stock options, estimates have to be made regarding the expected volatility in share price, option life, dividend yield, risk-free rate and estimated forfeitures at the initial grant date.

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 and are subject to changes and volatility in forward prices, foreign exchange rates, and discount rates.

Deferred tax assets

Deferred tax assets (if any) are recognized only to the extent it is considered probable that those assets will be recoverable. This involves an assessment of when those deferred tax assets are likely to reverse and judgment as to whether there will be sufficient taxable profits available to offset the tax assets when they do reverse. This requires assumptions regarding future profitability and is therefore inherently uncertain. To the extent assumptions regarding future profitability change, there can be an increase or decrease in the amounts recognized in respect of deferred tax assets as well as the amounts recognized in profit or loss in the period in which the change occurs.

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 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.

Share capital and warrants

Incremental costs directly attributable to the issue of common shares, warrants and stock options are recognized as a deduction from equity, net of any tax effects.

Cash and Term Deposits

Cash and term deposits include demand deposits and term deposits with original maturities of less than 90 days.

ACCOUNTING PRONOUNCEMENTS ADOPTED

IFRS 9 Financial Instruments

On January 1, 2018, Pengrowth adopted all of the requirements of IFRS 9 (2014), Financial Instruments ("IFRS 9"). This standard replaces IAS 39 - Financial Instruments: recognition and measurement ("IAS 39") and introduces new requirements for the classification and measurement of financial assets and liabilities. It introduces a new general hedge accounting standard, which aligns hedge accounting more closely with risk management. It also modifies the existing impairment model by introducing a new 'expected credit loss' model for calculating impairment. This new standard also increases required disclosures about an entity's risk management strategy, cash flows from hedging activities and the impact of hedge accounting on the consolidated financial statements. Pengrowth has applied IFRS 9 retrospectively in accordance with transition requirements with no impact to opening retained earnings or comparative periods.

IFRS 9 uses a single approach to determine whether a financial asset is measured at amortized cost or fair value, replacing the multiple rules in IAS 39. The approach is based on how an entity manages its financial instruments and the contractual cash flow characteristics of the financial assets. Most of the requirements in IAS 39 for classification and measurement of financial liabilities have been carried forward in IFRS 9.

The adoption of IFRS 9 did not result in any measurement adjustments to Pengrowth's financial assets or financial liabilities. The impact of the change in the impairment model was not significant as the credit-impaired financial assets are not significant.

The adoption of IFRS 9 did not result in any changes in the eligibility of existing hedge relationships. Pengrowth currently has no intentions of designating any of its financial instruments as hedges, or using hedge accounting.

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, 2018

Disclosure of changes in accounting policies, accounting estimates and errors [Abstract]

ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED

3. ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED

IFRS 16 Leases

In January 2016, the IASB issued 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 in the final stages of analyzing identified contracts, developing business and accounting processes, making applicable changes to the Corporation's internal controls and calculating the impact that the adoption of this standard will have on its financial statements. Pengrowth has elected to use the modified retrospective approach upon adoption and elected to apply the optional exemptions for short-term and low-value leases. The actual full impact of adoption will depend on the Corporation's incremental borrowing rate, lease portfolio and practical expedients applied. However, Pengrowth anticipates that the most significant impact of adopting IFRS 16 will be the recognition of the lease liabilities on its leases for head office space and the right of use ("ROU") assets, as applicable.

Upon adoption of IFRS 16, the Corporation will recognize lease liabilities and ROU assets for all leases identified except for optional exemptions taken. The lease liability will be measured at the present value of the remaining lease payments, discounted using Pengrowth's incremental borrowing rate as at January 1, 2019. The ROU asset will be measured at the amount equal to the lease liability on January 1, 2019 with no impact on retained earnings.

Adoption of IFRS 16 will also result in an increase to Depletion, Depreciation and Amortization due to the recognition of the ROU assets, increase in interest and financing charges, and a decrease to G&A and operating expenses, as applicable. Cash flow from operating activities will increase as a result of the decrease in G&A and operating expenses, as applicable. Cash flow from financing activities will decrease due to the deduction of the interest portion of the principal payments for former operating leases.

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OTHER ASSETS

12 Months Ended

Dec. 31, 2018

Disclosure Of Other Assets [Abstract]

OTHER ASSETS

4. OTHER ASSETS

	As at
	December 31, 2018		December 31, 2017
Remediation trust fund - current		$24.0		$24.0
Remediation trust fund - non-current	74.0		87.6
Prepaid tax assessment	12.2		12.2
Prepaids and deposits	4.1		8.2
Inventory	5.7		4.6
		$120.0		$136.6
Current portion of other assets		$33.8		$36.8
Non-current portion of other assets		$86.2		$99.8

REMEDIATION TRUST FUND

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 2018, Pengrowth made a monthly contribution to the fund at a rate of $1.41/MMBtu of its share of natural gas production and $2.42/bbl of its share of natural gas liquids production from SOEP. In 2019, there will no longer be contributions to the remediation trust fund as production has ceased and abandonment and decommissioning spending has begun and will continue for the next 3 to 4 years. 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 2019 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, and as such the $24 million has been classified as a current asset in the Consolidated Balance Sheet at December 31, 2018.

In 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, 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
Contributions	2.9
Remediation expenditures	(17.9		)
Investment income	2.7
Unrealized gain (loss)	(1.3		)
Balance, December 31, 2018		$98.0

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 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 is more likely than not to 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, 2018

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, 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
Additions to PP&E	66.7			0.9			67.6
Property acquisitions	0.2			—			0.2
Transfer from E&E	58.6			—			58.6
Change in asset retirement obligations	21.9			—			21.9
Balance, December 31, 2018		$3,965.1			$88.8			$4,053.9
Accumulated depletion, amortization and impairment losses	Oil and natural gas assets			Other equipment			Total
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
Depletion and amortization for the period	160.4			1.9			162.3
Balance, December 31, 2018		$2,880.7			$83.0			$2,963.7
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, 2018
Assets held for sale		$16.0			$—			$16.0
Long term	1,068.4			5.8			1,074.2
		$1,084.4			$5.8			$1,090.2

For the year ended December 31, 2018, $1.7 million (December 31, 2017 – $2.3 million) of directly attributable general and administrative costs were capitalized to PP&E.

Pengrowth ceased capitalization of interest during the third quarter of 2018 due to the change in the development plan for Lindbergh. During the year ended December 31, 2018, $2.4 million (December 31, 2017 – $3.7 million) of interest was capitalized on the Lindbergh Project to PP&E using Pengrowth's weighted average cost of debt of 6.5 percent (December 31, 2017 – 5.7 percent).

For the year ended December 31, 2017, Pengrowth executed and completed a substantial asset disposition program in order to reduce indebtedness and focus on its key growth assets. As a result of these dispositions, approximately $3.2 billion of costs and $1.9 billion of accumulated depletion were removed from PP&E. Proceeds on disposition of approximately $910.2 million were collected in 2017 and an additional $20.0 million of deferred proceeds were collected in 2018 that had been setup in accounts receivable at December 31, 2017.

At December 31, 2018, there were $4.6 billion (December 31, 2017 - $4.9 billion) of future development costs related to Pengrowth's key growth assets.

ASSETS HELD FOR SALE

At December 31, 2018, Pengrowth presented $16.0 million of certain Southern Alberta conventional assets as assets held for sale, classified as current assets on the Consolidated Balance Sheets. The related ARO of $16.0 million was presented as liabilities associated with assets held for sale and classified as current liabilities on the Consolidated Balance Sheets. The disposition is expected to close in the first quarter of 2019. Cash proceeds on closing of the disposition were nominal.

IMPAIRMENT

At December 31, 2017, PP&E impairment charges of $504.4 million were recorded. 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 Corporation's focus on Lindbergh and Groundbirch properties. At December 31, 2018 and 2017, impairment triggers were assessed to be present for the Montney CGU based on declines in natural gas prices, but no PP&E impairment was identified. Refer to Note 6 for further discussion.

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EXPLORATION AND EVALUATION ASSETS ("E&E")

12 Months Ended

Dec. 31, 2018

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, 2016		$496.3
Divestitures	(134.3		)
Impairment	(130.0		)
Balance, December 31, 2017		$232.0
Additions	0.2
Transfer to PP&E	(58.6		)
Impairment	(91.0		)
Balance, December 31, 2018		$82.6

In 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 and closed the sale of the non producing Devil area, for nominal consideration.

IMPAIRMENT TESTING

For the year ended December 31, 2018, Pengrowth evaluated the Groundbirch gas property for an impairment in conjunction with the Montney CGU due to the negative impact resulting from the significant downturn in the forward natural gas benchmark prices late in 2018. In accordance with Pengrowth's policy, the E&E assets are assessed in conjunction with the cash flow from the applicable PP&E CGU. It was determined that the recoverable amount was below the carrying amount, thus a $91.0 million impairment on the Groundbirch E&E asset was recorded in the fourth quarter of 2018.

The recoverable amount was computed with reference to the present value of the future cash flows expected to be derived from production of proved plus probable reserves and contingent resources. 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, 2019 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 was 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 commodity price estimates used in the December 31, 2018 impairment test:

	AECO gas (1)
Year	(Cdn$/MMBtu)
2019	1.85
2020	2.29
2021	2.67
2022	2.90
2023	3.14
2024	3.23
2025	3.34
2026	3.41
2027	3.48
2028	3.54
Thereafter	+ 2.0 percent/yr

⁽¹⁾  Prices represent forecasted amounts as at January 1, 2019 by Pengrowth's independent reserves evaluator.

At December 31, 2018, the recoverable amount of the Groundbirch E&E gas property was estimated to be approximately $76.3 million.

A sensitivity analysis was performed on impairment based on a 1 percent increase and 1 percent decrease in the discount rates resulting in a $26.6 million increase and $37.4 million decrease in December 31, 2018 impairment, respectively. A sensitivity analysis was also performed on impairment based on a 5 percent increase and 5 percent decrease in the forecast cash flow estimates resulting in a $16.0 million decrease and a $17.3 million increase in impairment. Using a 20 percent discount rate for the contingent resource would have resulted in an increase to impairment by $33.5 million, while a 12 percent rate would have resulted in a decrease to impairment of $45.7 million.

At December 31, 2017, Pengrowth evaluated the Groundbirch gas property in conjunction with the Montney CGU for an impairment. It was determined that the recoverable amount was below the carrying amount, resulting in a $129.0 million impairment on the Groundbirch E&E asset in the fourth quarter of December 31, 2017. In addition, $1.0 million impairment was recognized on other minor E&E projects as no further exploration or evaluation was intended on those projects.

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LONG TERM DEBT AND FINANCIAL COVENANTS

12 Months Ended

Dec. 31, 2018

Disclosure of detailed information about financial instruments [abstract]

LONG TERM DEBT AND FINANCIAL COVENANTS

7. LONG TERM DEBT AND FINANCIAL COVENANTS

LONG TERM DEBT

	As at
	December 31, 2018		December 31, 2017
U.S. dollar denominated term notes:
28.1 million at 5.49 percent due October 18, 2019		$38.3		$35.3
94.1 million at 7.98 percent due May 11, 2020	128.3		118.3
85.2 million at 6.07 percent due October 18, 2022	116.2		107.1
158.9 million at 6.17 percent due October 18, 2024	216.7		199.7
		$499.5		$460.4
U.K. pound sterling denominated term notes:
12.1 million at 5.45 percent due October 18, 2019		$21.1		$20.6
Canadian dollar term notes:
20.5 million at 6.74 percent due October 18, 2022		$20.5		$20.5
Canadian dollar term Credit Facility borrowings		$173.5		$109.0
Total long term debt		$714.6		$610.5
Current portion of long term debt		$232.9		$—
Non-current portion of long term debt		$481.7		$610.5

At December 31, 2018, Pengrowth had in place a secured $330 million revolving committed term Credit Facility supported by a syndicate of 11 domestic and international banks with a maturity date of March 31, 2019.

The Corporation is in discussions with the lending syndicate under its $330 million revolving Credit Facility on arrangements to extend the maturity date of the Credit Facility through September 30, 2019 to support the Strategic Review. The Corporation's objective is to finalize the extension agreement as soon as possible, and in advance of the current March 31, 2019 maturity date, however, there can be no assurance or guarantee that an extension will be obtained by the Corporation or on what terms. Refer to Note 1 for further discussion.

The Credit Facility carried floating interest rates that 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, 2018, the available facility had drawings of $173.5 million (December 31, 2017 – $109.0 million) and letters of credit in the amount of $75.6 million (December 31, 2017 – $69.4 million).

As of December 31, 2018, an unrealized cumulative foreign exchange loss of $135.3 million (December 31, 2017 - $96.2 million) has been recognized on the remaining U.S. dollar term notes since the date of issuance. As of December 31, 2018, an unrealized cumulative foreign exchange loss of $1.9 million (December 31, 2017 - $1.4 million) has been recognized on the remaining U.K. pound sterling denominated term notes since the date of issuance. See Note 16 for additional information about foreign exchange risk management and the impact on the Consolidated Financial Statements.

The five year schedule of long term debt and interest repayments based on current maturity dates and assuming the revolving Credit Facility is not renewed beyond September 30, 2019 is as follows: 2019 - $270.1 million, 2020 - $153.8 million, 2021 - $21.9 million, 2022 - $156.8 million, 2023 - $13.4 million.

During 2017, Pengrowth repaid term notes of approximately $1 billion and $126.6 million of convertible debentures at maturity on March 31, 2017.

FINANCIAL COVENANTS

Pursuant to the debt amending agreements dated October 12, 2017, amendments to the existing financial covenants are effective through to and including the quarter ending September 30, 2019 in the case of the term notes (the "Waiver Period"). The only applicable covenant during the Waiver Period is the trailing 12 month Adjusted EBITDA to Interest and Financing Charges (the "Interest Coverage" ratio). The Interest Coverage ratio changes each quarter until the fourth quarter of 2019 after which it remains at 4.0 times. 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. See Financial Resources and Liquidity section of the December 31, 2018 MD&A for more information.

Pengrowth's Interest Coverage ratio was 1.6 times at December 31, 2018, which was above the fourth quarter of 2018 covenant of 1.01 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.

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CAPITAL DISCLOSURES

12 Months Ended

Dec. 31, 2018

Disclosure of share capital, reserves and other equity interest [Abstract]

CAPITAL DISCLOSURES

8. CAPITAL DISCLOSURES

Pengrowth defines its capital as shareholders’ equity, long term debt, 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. Through 2018, Pengrowth has had discussions with the lead banks in its syndicate regarding a new credit agreement that will permit Pengrowth to access the high yield debt market to refinance substantially all of its existing term notes. Pengrowth is also exploring alternative financing arrangements including third party debt providers to refinance its entire debt portfolio. These discussions, if successful, may result in an offer for replacement debt at a higher cost than the current outstanding debt.

The Corporation is in discussions with the lending syndicate under its $330 million revolving Credit Facility on arrangements to extend the maturity date of the Credit Facility through September 30, 2019 to support the Strategic Review. The Corporation's objective is to finalize the extension agreement as soon as possible, and in advance of the current March 31, 2019 maturity date, however, there can be no assurance or guarantee that an extension will be obtained by the Corporation or on what terms. Refer to Note 1 for further discussion.

The only financial covenant relating to the term notes and Credit Facility is the Interest Coverage ratio. The Interest Coverage ratio changes each quarter until the fourth quarter of 2019 after which it remains at 4.0 times, as noted below. Any new or extended Credit Facility could contain new or different covenants and credit limits.

Year	Q1	Q2	Q3	Q4
2018	-	-	-	1.01 times
2019	1.13 times	1.19 times	1.23 times	4.0 times

Management monitors Pengrowth’s capital structure and covenant compliance using non-GAAP financial metrics. These metrics are trailing twelve months earnings before interest, taxes, DD&A, accretion ("EBITDA"), impairment, gain (loss) on disposition of properties, change in fair value of commodity risk management contracts, unrealized foreign exchange gain (loss), non-cash share based compensation expense, restructuring costs and EBITDA related to material divestments ("Adjusted EBITDA") and Adjusted EBITDA to Interest and Financing Charges ratio (the "Interest Coverage" ratio). Trailing 12 month interest and financing charges can be adjusted for the fees and interest expense related to debt repaid with asset divestment proceeds.

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 ended December 31, 2018, Pengrowth was in compliance with all financial covenants. Due to the return of the Debt to EBITDA covenant and increase of the Interest Coverage ratio to 4.0 times there remains a risk around Pengrowth's ability to stay in compliance with its debt covenants at the end of 2019.

At December 31, 2018, Pengrowth has approximately $81.4 million of capacity on its Credit Facility, net of drawings and outstanding letters of credit.

The following table provides a reconciliation between the opening and closing balances for liabilities arising from financing activities at December 31, 2018:

	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		$—
Increase (decrease) due to:
Foreign exchange impact of the Canadian dollar on U.S. and U.K. denominated debt	39.6			—		—
Credit Facility borrowing	—			64.5		—
Balance, December 31, 2018		$541.1			$173.5		$—

The following is a summary of Pengrowth’s capital structure, excluding shareholders’ equity:

	As at
	December 31, 2018		December 31, 2017
Long term debt (1)		$714.6		$610.5
Working capital (surplus) deficiency (2)	35.9		80.6
		$750.5		$691.1

⁽¹⁾  Includes current portion of long term debt, as applicable.

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

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PROVISIONS AND OTHER LIABILITIES

12 Months Ended

Dec. 31, 2018

Disclosure of other provisions, contingent liabilities and contingent assets [Abstract]

PROVISIONS AND OTHER LIABILITIES

9. PROVISIONS AND OTHER LIABILITIES

Provisions and other liabilities are composed of Asset Retirement Obligations ("ARO"), finance leases, onerous lease contracts and other liabilities. The following table provides a continuity of the balances for the following periods:

	Asset retirement obligations			Finance leases			Onerous lease contracts			Other liabilities			Total
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
Incurred during the period	1.4			—			6.8			(0.4		)	7.8
Property dispositions	(0.9		)	—			—			—			(0.9		)
Expenditures on remediation/provisions settled	(23.2		)	(0.8		)	(5.6		)	(0.2		)	(29.8		)
Revision due to rate changes (1)	24.6			—			—			—			24.6
Other revisions	(4.1		)	—			(3.2		)	—			(7.3		)
Accretion (amortization)	5.4			—			1.6			—			7.0
Balance, December 31, 2018		$239.9			$33.4			$25.8			$1.7			$300.8

⁽¹⁾  Relates to the change in the inflation rate from 1.5 percent to 2.0 percent. The offset is recorded in PP&E.

As at December 31, 2018	Asset retirement obligations		Finance leases		Onerous lease contracts		Other liabilities		Total
Current including assets held for sale (1)		$50.0		$0.7		$4.9		$0.1		$55.7
Long term	189.9		32.7		20.9		1.6		245.1
		$239.9		$33.4		$25.8		$1.7		$300.8
As at December 31, 2017
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

⁽¹⁾  Includes $16.0 million of asset retirement obligation related to assets held for sale at December 31, 2018.

The following assumptions were used to estimate the ARO liability:

	As at
	December 31, 2018			December 31, 2017
Total escalated future costs		$491.7			$420.2
Discount rate, per annum	2.3		%	2.3		%
Inflation rate, per annum	2.0		%	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 majority of the abandonment and reclamation costs on other assets, not covered by a fund, are expected to be incurred between 2035 and 2085.

ONEROUS LEASE CONTRACTS

Pengrowth completed significant asset dispositions which led to a management decision to complete an operational restructuring in 2017. Reduction of staff levels and excess office space resulted in Pengrowth recognizing a $37.0 million restructuring cost in 2017, of which $26.2 million related to onerous office lease contracts at December 31, 2017 as the economic benefits from actual or potential subleases were exceeded by the unavoidable costs of the lease contract over the remaining term. During the third quarter of 2018, Pengrowth recognized an additional onerous lease of $5.4 million related to the construction camp at Lindbergh and is recorded as part of the $6.8 million incurred during the period under onerous lease contracts. As Pengrowth shifted its development methodology away from the previously contemplated large single phase approach to expansion achieved in incremental steps, the camp will likely not be utilized at Lindbergh. Accordingly, the economic benefits of the construction camp were exceeded by the unavoidable costs of the contract over the remaining term. The total onerous lease contract provision amounted to $25.8 million at December 31, 2018.

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DEFERRED INCOME TAXES

12 Months Ended

Dec. 31, 2018

Disclosure of income tax [Abstract]

DEFERRED INCOME TAXES

10. DEFERRED INCOME TAXES

As at December 31, 2018, Pengrowth did not recognize deductible temporary differences of approximately $1.8 billion primarily consisting of approximately $1.6 billion of non capital losses and $0.2 billion in other temporary differences (PP&E and other) resulting in a $342.2 million non-cash deferred tax expense. These losses expire between 2025 and 2038.

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
	2018			2017
Income (loss) before taxes		($217.1	)		($907.6	)
Combined federal and provincial tax rate	27.10		%	27.08		%
Expected income tax expense (recovery)		($58.8	)		($245.8	)
Change in unrecognized deferred tax asset	397.7			22.6
Foreign exchange (gain) loss (1)	2.0			(2.0		)
Other including share based compensation	1.3			1.4
Deferred income tax expense (recovery)		$342.2			($223.8	)

⁽¹⁾ Reflects the 50 percent non-taxable (deductible) 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, 2018		December 31, 2017
Deferred tax liabilities associated with:
PP&E and E&E assets		$—		($132.3	)
Less deferred tax assets associated with:
Non-capital losses and financing charges	—		399.6
Provisions	—		64.1
Risk management contracts	—		10.8
Net deferred tax asset (liability)		$—		$342.2

A continuity of the net deferred income tax asset (liability) for 2018 and 2017 is detailed in the following tables:

Movement in deferred tax asset (liability) during the year	Balance Jan 1, 2018			Recognized in profit or loss			Balance Dec 31, 2018
PP&E and E&E assets		($132.3	)	$	132.3			$—
Non-capital losses and financing charges	399.6			(399.6		)	—
Provisions	64.1			(64.1		)	—
Risk management contracts	10.8			(10.8		)	—
		$342.2		$	(342.2	)		$—

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		)	—
		$118.4			$223.8			$342.2

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, 2018

Share Capital, Reserves And Other Equity Interest [Abstract]

SHAREHOLDERS' CAPITAL

11. 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.

	2018			2017
(Common shares in 000's)	Number of common shares	Amount		Number of common shares	Amount
Balance, beginning of year	552,246		$4,829.7	547,709		$4,815.1
Share based compensation (non-cash exercised)	3,871	8.4		4,537	14.6
Balance, end of year	556,117		$4,838.1	552,246		$4,829.7

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LONG TERM INCENTIVE PLANS ("LTIP")

12 Months Ended

Dec. 31, 2018

Disclosure of share-based payment arrangements [Abstract]

LONG TERM INCENTIVE PLANS (LTIP)

12. LONG TERM INCENTIVE PLANS ("LTIP")

(i) SHARE-SETTLED LTIP

At the June 26, 2018 AGM, shareholders approved a rolling and reloading plan that shall not exceed 10 percent of the issued and outstanding common shares to be reserved for issuance under all share-settled compensation plans in the aggregate.

As at December 31, 2018, the number of shares issuable under the share-settled compensation plans, in aggregate, represents 3.1 percent of the issued and outstanding common shares, which is within the limit.

(a) Performance Share Units ("PSUs") and Restricted Share Units ("RSUs")

Performance Share Units ("PSUs")

PSUs entitle the holder to a number of common shares to be issued in the third year after grant. 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. Prior to 2017, PSUs were awarded to employees, officers and consultants. No PSU grants were made in 2018 as PSUs are no longer granted under current LTIP.

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. RSUs are awarded to employees, excluding officers. The RSUs generally vest on the first, second and third anniversary date from the date of grant.

The following table provides a continuity of the share-settled PSUs and RSUs:

(number of share units - 000's)	PSUs		RSUs
Outstanding, December 31, 2016	6,238		8,436
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
Granted	—		3,006
Forfeited	(1,449	)	(2,444	)
Exercised	(826	)	(3,045	)
Performance adjustment	(138	)	—
Outstanding, December 31, 2018	2,621		4,900

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. As mentioned, no new PSUs will be granted under the current LTIP.

Compensation expense related to PSU and RSU 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 performance multiplier is calculated using the percentile rank of Pengrowth's total shareholder return relative to its peers and can result in cash compensation issued upon vesting of the PSUs ranging from zero to two times the value of the PSUs originally granted. Fluctuations in compensation expense may occur due to changes in estimating the outcome of the performance multiplier conditions. The amount of compensation expense is impacted by an estimated forfeiture rate at the date of grant and as more information becomes available. For PSU and RSU grants in 2016, 2017 and 2018, the estimated forfeiture rates range from 25 to 40 percent depending on the vesting period. 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, 2018, Pengrowth recorded $3.5 million of compensation related to the share-settled PSUs and RSUs (December 31, 2017 - $5.0 million). The weighted average grant date fair value was $0.87 per share unit for the 2018 RSU grants (December 31, 2017 - $1.40 per share for the 2017 RSU and PSU grants). As at December 31, 2018, the amount of compensation expense to be recognized over the remaining vesting period was $2.7 million or $0.32 per share unit (December 31, 2017 - $5.4 million or $0.51 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 1.0 year.

(b) Stock Option Plan

Commencing in June 2018, Pengrowth adopted an Employee Stock Option Plan that provides certain employees with the opportunity to exercise options to purchase common shares of the Corporation. Option exercise prices approximate the market price for the common shares on the date of issuance, vest in three even tranches in the three years following grant and expire after seven years. Compensation expense associated with the options is determined based on the grant date fair value and amortized over the vesting period.

The following table provides a continuity of stock options outstanding at December 31:

	2018
(number of option units - 000's)	Number outstanding		Weighted average price
Outstanding, December 31, 2017	—			$—
Granted	9,468			$0.87
Forfeited	(141	)		$0.87
Exercised	—			$—
Outstanding, December 31, 2018	9,327			$0.87

The range of exercise prices of stock options outstanding and exercisable at December 31, 2018 was as follows:

Range of exercise prices	Number outstanding (thousands)	Weighted average remaining contractual life (years)	Weighted average exercise price		Number exercisable (thousands)	Weighted average exercise price
$0.87 - $1.05	9,327	6.49		$0.87	—		$—

Pengrowth uses the Black-Scholes pricing model to calculate the fair value of stock options granted using an estimated forfeiture rate, volatility, risk free rate and expected life. The fair value is recorded as stock-based compensation expense over the vesting period with a corresponding amount reflected in contributed surplus. When stock options are exercised, the cash proceeds along with the amount previously recorded as contributed surplus are recorded as share capital.

Estimated fair values for the stock options outstanding were calculated using the following weighted average assumptions:

Fair value per option		$0.46
Risk free interest rate	1.93		%
Expected volatility (1)	65.86		%
Expected life (years)	4.4
Expected forfeiture rate	15.0		%

⁽¹⁾ Expected volatility has been based on historical share volatility of the Corporation.

For the year ended December 31, 2018, Pengrowth recorded $1.5 million of compensation expense related to stock options (December 31, 2017 - $nil). The weighted average grant date fair value was $0.46 per stock option for the 2018 stock option grants (December 31, 2017 - $nil per option). As at December 31, 2018, the amount of compensation expense to be recognized over the remaining vesting period was $2.0 million or $0.22 per option (December 31, 2017 - $nil per option). The unrecognized compensation cost will be expensed to net income (loss) over the remaining weighted average vesting period of 1.41 years.

(ii) PREVIOUS LTIP

As at December 31, 2018, 163,867 common shares (December 31, 2017 - 163,867 common shares) were reserved for issuance under the Deferred Entitlement Share Unit ("DESU") Plan. As at December 31, 2018, 198,477 common shares (December 31, 2017 - 198,477 common shares) were reserved for issuance under the Deferred Share Unit ("DSU") plan.

(iii) CASH-SETTLED LTIP    

(a) Cash-Settled Restricted Share Units ("Cash-Settled RSUs")

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. During the year ended December 31, 2018, compensation reduction of $0.5 million (December 31, 2017 - $0.2 million reduction) was recognized in the Consolidated Statements of Income (Loss) with a corresponding increase or decrease in liabilities. As at December 31, 2018, $0.3 million (December 31, 2017 - $1.5 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. No grants were made in 2018 and no new Cash-Settled RSUs will be granted under the current LTIP. The revaluation of the cash-settled RSUs continues until settlement.

(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, 2018, Phantom DSUs awarded to Directors had a corresponding liability of $1.2 million (December 31, 2017 - $1.4 million). For the year ended December 31, 2018, Pengrowth recorded a $0.1 million compensation expense (December 31, 2017 - $0.6 million reduction) related to Phantom DSUs. The revaluation of the cash-settled Phantom DSUs continues until settlement.

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, 2016	4,229		1,346
Granted	3,163		492
Forfeited	(3,148	)	—
Exercised	(1,341	)	(462	)
Outstanding, December 31, 2017	2,903		1,376
Granted	—		847
Forfeited	(1,312	)	—
Exercised	(887	)	(155	)
Outstanding, December 31, 2018	704		2,068

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, 2018			December 31, 2017
Non-cash PSU and RSU expense		$3.5			$5.0
Non-cash stock options expense	1.5			—
Amounts capitalized in the period	(0.2		)	(0.1		)
Non-cash share based compensation expense		$4.8			$4.9
Cash-settled RSUs (reduction) expense		($0.5	)		($0.2	)
Cash-settled Phantom DSUs (reduction) expense		$0.1			($0.6	)
Total share based compensation expense		$4.4			$4.1

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REVENUE

12 Months Ended

Dec. 31, 2018

Disclosure of revenue [Abstract]

REVENUE

13. 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 either be fixed or variable, depending on the contract terms. Under its contracts, Pengrowth is required to deliver fixed and variable volumes of diluted bitumen and variable volumes of light oil, natural gas and natural gas liquids 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. The majority of Pengrowth’s diluted bitumen is currently sold on multi-year contracts expiring at the end of 2019 for a fixed quantity of diluted bitumen at a fixed differential to WTI, with WTI being variable, as detailed in Note 16. Revenues are typically collected on the 25^th day of the month following production. Processing fees charged to third parties are generally under multi-year contracts at fixed fees that vary by volume.

The following table presents Pengrowth’s Oil and gas sales disaggregated by revenue source:

	Year ended December 31
	2018		2017
Bitumen		$264.1		$181.6
Natural gas sold to third party (1)	16.6		98.8
Light oil	14.8		149.3
Natural gas liquids	4.7		56.7
Diluent sold	219.3		147.2
Processing income	2.0		19.1
Sale of other product purchased for resale	10.7		20.7
Total oil and gas sales		$532.2		$673.4

⁽¹⁾  Starting April 1, 2018, a portion of natural gas delivered from Groundbirch to the NGTL system is used in other operations as energy costs. As such, $7.2 million related to natural gas used in internal operations is not included in total oil and gas sales.

Pengrowth had no fixed price physical delivery contracts in 2018.

Pengrowth has variable price physical delivery contracts for the sale of diluted bitumen mainly with 2 credit worthy refiners, with revenue from these customers representing approximately 90 percent of the Corporation's full year 2018 oil and gas sales.

Included in accounts receivable at December 31, 2018 is $22.2 million (December 31, 2017 is $40.2 million) of accrued oil and gas sales related to December 2018 production.

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OTHER CASH FLOW DISCLOSURES

12 Months Ended

Dec. 31, 2018

Cash Flow Statement [Abstract]

OTHER CASH FLOW DISCLOSURES

14. OTHER CASH FLOW DISCLOSURES

CHANGE IN NON-CASH OPERATING WORKING CAPITAL AND OTHER ASSETS

	Year ended December 31
Cash provided by (used for):	2018			2017
Accounts receivable and other current assets (1)		$28.5			$40.9
Accounts payable	(54.0		)	(22.7		)
		($25.5	)		$18.2

⁽¹⁾  Includes accounts receivable, inventory and prepaids.

CHANGE IN NON-CASH INVESTING WORKING CAPITAL 

	Year ended December 31
Cash used for:	2018			2017
Accounts payable, including capital accruals		($10.5	)		($7.5	)

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AMOUNTS PER SHARE

12 Months Ended

Dec. 31, 2018

Earnings per share [abstract]

AMOUNTS PER SHARE

15. 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)	2018	2017
Weighted average number of shares - basic and diluted	555,279	551,193

For the years ended December 31, 2018 and 2017, there were no dilutive effects of stock options, RSUs, PSUs, DSUs or DEUs due to the Corporation incurring net losses during these periods.

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FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

12 Months Ended

Dec. 31, 2018

Disclosure of detailed information about financial instruments [abstract]

FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

16. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

Pengrowth’s financial instruments are composed of accounts receivable, other assets, accounts payable, risk management assets and liabilities, remediation trust fund, finance lease obligation, bank indebtedness 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, 2018 audited Consolidated Financial Statements.

RISK MANAGEMENT OVERVIEW

Pengrowth has exposure to certain market risks related to volatility in commodity, differential and power prices, interest rates and foreign exchange rates. Derivative instruments are used to manage exposure to these risks, as applicable. 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, differential 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 and the impact on differentials, 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 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, divestments or other transactions where Pengrowth’s capital structure may be subject to more risk from commodity prices.

Commodity Price Contracts

As at December 31, 2018, Pengrowth had the following financial contracts outstanding:

Financial Crude Oil Contracts:
Swaps
Differentials
Reference point	Term	Volume of dilbit (bbl/d)	Price per bbl (U.S.$)
Western Canada Select	2019	5,000	WTI less $20.88

Financial Risk Management Contracts Sensitivity to Commodity Prices as at December 31, 2018

Oil differentials	Cdn$1 decrease in future oil differential			Cdn$1 increase in future oil differential
Increase (decrease) to fair value of financial differential risk management contracts		($1.3	)		$1.3

Physical Delivery Contracts

As at December 31, 2018, 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 dilbit (bbl/d)	Term	Price per bbl (U.S.$)
Western Canada Select	2,500	2019	WTI less $17.95
Western Canada Select	2,500	2019	WTI less $23.60 - $26.35
Western Canada Select	5,000	2019	WTI less $17.70 - $20.45
Western Canada Select	2,500	Feb. 1, 2019 - Feb. 1, 2020	WTI less $20.40 - $23.40

Pengrowth has also entered into a secured term sale agreement at Hardisty for an additional 5,000 bbl/d of dilbit for 2019 that are 100 percent apportionment protected. Pengrowth will settle at the monthly WCS Index less an apportionment protection fee of U.S.$2.00/bbl.

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 a portion of the principal amount of term note was early repaid in 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, 2018	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, 2018, Pengrowth had $714.6 million of current and non-current long term debt (December 31, 2017 - $610.5 million) of which $173.5 million was based on floating interest rates (December 31, 2017 - $109.0 million). An increase of 1 percent in interest rates would increase pre-tax interest expense by approximately $1.7 million for the year ended December 31, 2018 (December 31, 2017 - $1.1 million), 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, 2018	Commodity contracts (1)			Foreign exchange contracts (2)			Total
Current portion of risk management assets		$—			$3.5			$3.5
Non-current portion of risk management assets	—			4.5			4.5
Current portion of risk management liabilities	(4.2		)	—			(4.2		)
Risk management assets (liabilities), end of year		($4.2	)		$8.0			$3.8
Less: Risk management assets (liabilities) at beginning of year	(39.8		)	(16.9		)	(56.7		)
Unrealized gain (loss) on risk management contracts for the year		$35.6			$24.9			$60.5
Realized gain (loss) on risk management contracts for the year	(67.5		)	—			(67.5		)
Total unrealized and realized gain (loss) on risk management contracts for the year		($31.9	)		$24.9			($7.0	)
As at and for the year ended December 31, 2017	Commodity contracts (1)			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	)

⁽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 under Foreign exchange (gain) loss in the Consolidated Statements of Income (Loss). See Note 17.

Fair Value

The fair value of cash and cash equivalents, accounts receivable, remediation trust fund, 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 value of the remediation trust fund is equal to its carrying amount as this asset is carried at its 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, 2018	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 fund		$98.0		$98.0		$98.0		$—		$—
Fair value of risk management contracts	8.0		8.0		—		8.0		—
Financial Liabilities
U.S. dollar denominated term notes	499.5		533.2		—		533.2		—
Cdn dollar term notes	20.5		22.3		—		22.3		—
U.K. pound sterling denominated term notes	21.1		21.4		—		21.4		—
Fair value of risk management contracts	4.2		4.2		—		4.2		—
					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 fund		$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		—

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 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 cash, accounts receivable, remediation trust fund, 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 2018, 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.

The combined carrying amount of accounts receivable and fair value of derivative assets as at December 31, 2018 was $50.8 million (December 31, 2017 - $94.8 million), representing Pengrowth's maximum credit exposure. The Corporation’s credit provisions are represented by its loss allowance based on lifetime expected credit losses as at December 31, 2018 of $1.2 million (December 31, 2017 - $0.5 million). The amount of the loss allowance was determined based on historical credit loss experience, adjusted for forward-looking factors specific to the debtors and the economic environment. The total amount of accounts receivables 90 days past due amounted to $5.9 million as at December 31, 2018 (December 31, 2017 - $17.5 million).

The accounts receivable is as follows:

	As at
	December 31, 2018		December 31, 2017
Trade		$42.8		$92.9

At December 31, 2018, $25.9 million of trade receivables was related to revenue and the remaining $16.9 million primarily comprise joint venture receivables and deferred proceeds from property dispositions.

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 with a maturity date of March 31, 2019. Use of the remaining credit capacity is still subject to complying with the financial covenant as discussed in Note 7. Pengrowth’s term notes and term Credit Facilities are secured and equally ranked.

Pengrowth engaged Perella Weinberg Partners LP and Tudor, Pickering, Holt & Co ("PWP/TPH") as advisers to assist in exploring financing alternatives. On March 5, 2019, the Board of Directors commenced a formal process with PWP/TPH to explore and develop strategic alternatives (the “Strategic Review”) with a view to strengthening the Corporation's balance sheet and maximizing enterprise value. The Strategic Review is intended to explore a comprehensive range of strategic and transaction alternatives, including a sale, merger or other business combination; a disposition of all or certain assets of the Corporation; recapitalization and refinancing opportunities; sourcing new financing and equity capital; and other alternatives to improve the Corporation's financial position and maximize value. In addition to Pengrowth’s long-life, low-decline assets, the Corporation also has potentially attractive tax attributes that complement its strong base operations. Pengrowth and its advisers expect to actively explore market interest in potential transactions and strategic initiatives with a range of interested parties and capital market participants. There can be no guarantees as to whether the Strategic Review will result in a transaction or the terms or timing of any resulting transaction. Various industry risk factors, including a prolonged or significant decrease in WTI or WCS pricing, could impact the outcome of the Strategic Review Process, Pengrowth’s cash flow, and its ability to address its upcoming debt maturities. Refer to Note 1 for further discussion.

Pengrowth’s current and non-current financial liabilities are as follows:

As at December 31, 2018	Carrying amount		Contractual cash flows		Year 1		Year 2		Years 3-5		More than 5 years
Accounts payable		$72.7		$72.7		$72.7		$—		$—		$—
Commodity risk management contracts	4.2		4.2		4.2		—		—		—
Cdn dollar senior unsecured notes (1)	20.5		25.7		1.4		1.4		22.9		—
U.S. dollar denominated term notes (2)	499.5		619.5		70.7		152.5		169.0		227.3
U.K. pound sterling denominated term notes (2)	21.1		22.0		22.0		—		—		—
Cdn dollar term Credit Facility borrowings (1)	173.5		176.1		176.1		—		—		—
Finance leases	33.4		72.3		4.2		4.2		12.6		51.3
Other liabilities	1.7		1.7		0.1		0.1		—		1.5

⁽¹⁾  Contractual cash flows include future interest payments.

⁽²⁾  Contractual cash flows include future interest payments and term notes calculated at December 31, 2018 period end exchange rate.

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 (1)	20.5		27.1		1.4		1.4		24.3		—
U.S. dollar denominated term notes (2)	460.4		601.3		30.2		65.2		284.0		221.9
U.K. pound sterling denominated term notes (2)	20.6		22.6		1.1		21.5		—		—
Cdn dollar term Credit Facility borrowings (1)	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.

⁽²⁾  Contractual cash flows include future interest payments and term notes calculated at December 31, 2017 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, 2018			December 31, 2017
Risk management contracts
Current asset		$3.5			$—
Non-current asset	4.5			1.9
Current liability	(4.2		)	(40.0		)
Non-current liability	—			(18.6		)
		$3.8			($56.7	)

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FOREIGN EXCHANGE (GAIN) LOSS

12 Months Ended

Dec. 31, 2018

Effects Of Changes In Foreign Exchange Rates [Abstract]

FOREIGN EXCHANGE (GAIN) LOSS

17. FOREIGN EXCHANGE (GAIN) LOSS

	Year ended December 31
	2018			2017
Currency exchange rate (Cdn$1 = U.S.$) at beginning of year		$0.80			$0.74
Currency exchange rate (Cdn$1 = U.S.$) at year end		$0.73			$0.80
Unrealized foreign exchange (gain) loss from translation of foreign denominated debt		$39.8			($65.6	)
Unrealized (gain) loss on foreign exchange risk management contracts	(24.9		)	14.2
Net unrealized foreign exchange (gain) loss		$14.9			($51.4	)
Net realized foreign exchange (gain) loss		($0.8	)		$38.4

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COMMITMENTS

12 Months Ended

Dec. 31, 2018

Disclosure Of Commitments [Abstract]

COMMITMENTS

18. COMMITMENTS

	2019		2020		2021		2022		2023		Thereafter		Total
Operating leases	1.5		1.5		1.5		1.8		1.8		2.1		10.2
Onerous leases	5.1		5.3		5.2		6.0		4.9		5.8		32.3
Pipeline transportation	27.0		33.8		35.1		35.2		35.5		152.4		319.0
Power infrastructure and other	13.6		0.2		0.2		0.2		0.2		3.9		18.3
	$	47.2	$	40.8	$	42.0	$	43.2	$	42.4	$	164.2	$	379.8

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CONTINGENCIES

12 Months Ended

Dec. 31, 2018

Disclosure Of Contingencies [Abstract]

CONTINGENCIES

19. 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, 2018

Disclosure Of Supplementary Disclosures [Abstract]

SUPPLEMENTARY DISCLOSURES

20. 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
	2018		2017
Operating		$12.3		$30.1
General and administrative	20.0		35.5
Total employee compensation costs		$32.3		$65.6

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 2018, Pengrowth had 7 non-executive directors and 7 officers (2017 - 6 non-executive directors and 7 officers). Pengrowth had 6 non-executive directors and 4 officers at the end of 2018.

Year ended December 31, 2018	Wages & benefits paid		Bonus and other compensation paid		Share based compensation expense			Severance paid		Total
Directors		$0.5		$—		$0.1			$—		$0.6
Officers	2.0		3.7		2.9			2.4		11.0
		$2.5		$3.7		$3.0			$2.4		$11.6
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

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SIGNIFICANT ACCOUNTING POLICIES (Policies)

12 Months Ended

Dec. 31, 2018

Disclosure of changes in accounting policies, accounting estimates and errors [Abstract]

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”).

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 March 5, 2019.

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 Corporation 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 Corporation 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.

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

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 on the license or field. 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 with the related PP&E CGU 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 and gross overriding royalty. 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. 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
-	Motor vehicles	60 months

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 and Business Combinations

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 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 and on transfer of E&E to PP&E. 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 including at the time of transfer, 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

The Corporation has elected to measure loss allowances for trade receivables and contract assets at an amount equal to lifetime expected credit losses (“ECLs”). The Corporation measures loss allowances for the amount due from affiliates at an amount equal to the 12-month ECLs. The maximum period considered when estimating ECLs is the maximum contractual period over which the Corporation is exposed to credit risk.

ECLs are a probability-weighted estimate of credit losses. Credit losses are measured as the present value of all cash shortfalls (i.e. the difference between the cash flows due to the entity in accordance with the contract and the cash flows that the Corporation expects to receive). ECLs are discounted at the effective interest rate of the financial asset.

Loss allowances for financial assets are deducted from the gross carrying amount of the assets. Impairment losses on financial assets are presented under “other expenses” in the statement of loss and comprehensive loss.

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.

Impairment losses on financial assets carried at amortized cost are reversed in the statement of loss and comprehensive loss in subsequent periods if the amount of the loss decreases.

Inventory

Product inventories are valued at the lower of cost and net realizable value on a first-in, first-out weighted average cost basis. The cost of inventory includes all costs incurred in the normal course of business to bring each product to its present location and condition. Net realizable value is the estimated selling price in the ordinary course of business less any expected selling costs. If the carrying amount exceeds net realizable value, a write-down is recognized. The write-down may be reversed in a subsequent period if circumstances which caused it no longer exist and the inventory is still on hand.

Provisions and Other Liabilities

Provisions and other liabilities

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 using a risk free rate 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 estimates are recorded as an increase or decrease to the ARO liability with a corresponding change made to the carrying amount of the related asset. In case of assets with no remaining production or reserves, revisions to ARO liability are recorded in the Consolidated Statements of Income (Loss). 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 Lease Contracts

The onerous lease obligation relates to excess head office space and an unutilized construction camp at Lindbergh which were recognized as the unavoidable costs of the lease contracts over the remaining term exceeded the economic benefits of the leases. The onerous lease provision is calculated as present value of future lease payments Pengrowth is obligated to make under the lease contracts less any recoveries under current or anticipated sublease agreements over the remaining life of the leases.

Other Liabilities

Pengrowth also categorizes certain cash-settled long term incentive plan ("LTIP") grants 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 a number of share-settled and cash-settled share based compensation plans, which are described in Note 12.

Share-settled LTIP

Performance Share Units ("PSUs") and Restricted Share Units ("RSUs")

Compensation expense related to PSU and RSU share-settled plans is based on the estimated 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 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.

Stock option plan

Pengrowth uses the Black-Scholes pricing model to calculate the fair value of stock options granted using an estimated forfeiture rate, volatility, risk free rate and expected life. The fair value is recorded as share-based compensation expense over the vesting period with a corresponding amount reflected in contributed surplus. When stock options are exercised, the cash proceeds along with the amount previously recorded as contributed surplus are recorded as share capital.

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. 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. The revaluation of the cash-settled LTIP continues until settlement. Pengrowth estimates the forfeiture rate for each type of share based award at the date of grant.

Financial Instruments

Financial Instruments

Financial instruments are utilized by Pengrowth to manage its exposure to commodity price fluctuations and foreign currency exposures. Pengrowth’s policy is not to utilize financial instruments for trading or speculative purposes.

IFRS 9 sets out requirements for recognizing and measuring financial assets, financial liabilities and some contracts to buy or sell non-financial items. The Corporation adopted the standard with a date of initial application of January 1, 2018. This standard replaced IAS 39 Financial Instruments: Recognition and Measurement.

IFRS 9 largely retains the existing requirements in IAS 39 for the classification and measurement of financial liabilities. However, it eliminates the previous IAS 39 categories for financial assets of held to maturity, loans and receivables and available for sale. Under IFRS 9, on initial recognition, a financial asset is classified as measured at:

• Amortized cost;

• Fair value through other comprehensive income ("FVTOCI") - debt investment;

• Fair value through other comprehensive income ("FVTOCI") - equity investment;

• Fair value through profit or loss ("FVTPL").

The classification of financial assets under IFRS 9 is generally based on the business model in which a financial asset is managed and its contractual cash flow characteristics.

IFRS 9 replaces the ‘incurred loss’ model in IAS 39 with an ECL model. The new impairment model applies to financial assets measured at amortized cost, contract assets and debt investments at FVOCI, but not to investments in equity instruments. Under IFRS 9, credit losses are recognized earlier than under IAS 39.

The adoption of IFRS 9 did not result in any changes in the eligibility of existing hedge relationships. Pengrowth currently has no intentions of designating any of its financial instruments as hedges, or using hedge accounting.

The following summarizes Pengrowth's financial assets and financial liabilities as a result of the adoption of IFRS 9:

• Accounts receivable and other assets are measured at amortized cost.

• Investments held in the remediation trust funds and other investments are measured at fair value through profit or loss. Any change in the fair value is recognized in the Consolidated Statements of Income (Loss).

• Bank indebtedness, accounts payable and long term debt have been measured at amortized cost using the effective interest rate method.

• Derivative assets and liabilities must be measured at fair value through profit or loss with changes in fair value over a reporting period recognized in net income (loss).

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.

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 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 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.

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.

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 Owned Assets

A minor proportion of Pengrowth’s petroleum and natural gas development and production activities involve jointly owned assets that are not conducted through separate vehicles and accordingly, the accounts reflect only Pengrowth’s proportionate 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 20 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.

Estimates

Estimates and Judgments

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 or 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.

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, if applicable.

Identification of impairment indicators

Judgment is required to assess when indicators of impairment or reversals exist and whether calculation of the recoverable amount of an asset is necessary. Management considers internal and external sources of information including petroleum and natural gas prices, expected production volumes, anticipated recoverable quantities of proved and probable reserves and rates used to discount future cash flow estimates. Judgement is required to assess these factors when determining if the carrying amount of an asset is impaired, or in the case of previously impaired asset, whether the carrying amount of the asset has been restored.

Share-based payments

Stock options granted by the Corporation are recorded at fair value using the Black Scholes option pricing model. In assessing the fair value of stock options, estimates have to be made regarding the expected volatility in share price, option life, dividend yield, risk-free rate and estimated forfeitures at the initial grant date.

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 and are subject to changes and volatility in forward prices, foreign exchange rates, and discount rates.

Deferred tax assets

Deferred tax assets (if any) are recognized only to the extent it is considered probable that those assets will be recoverable. This involves an assessment of when those deferred tax assets are likely to reverse and judgment as to whether there will be sufficient taxable profits available to offset the tax assets when they do reverse. This requires assumptions regarding future profitability and is therefore inherently uncertain. To the extent assumptions regarding future profitability change, there can be an increase or decrease in the amounts recognized in respect of deferred tax assets as well as the amounts recognized in profit or loss in the period in which the change occurs.

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 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.

Share capital and warrants

Incremental costs directly attributable to the issue of common shares, warrants and stock options are recognized as a deduction from equity, net of any tax effects.

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.

Accounting Pronouncements, Adopted And Not Yet Adopted

ACCOUNTING PRONOUNCEMENTS ADOPTED

IFRS 9 Financial Instruments

On January 1, 2018, Pengrowth adopted all of the requirements of IFRS 9 (2014), Financial Instruments ("IFRS 9"). This standard replaces IAS 39 - Financial Instruments: recognition and measurement ("IAS 39") and introduces new requirements for the classification and measurement of financial assets and liabilities. It introduces a new general hedge accounting standard, which aligns hedge accounting more closely with risk management. It also modifies the existing impairment model by introducing a new 'expected credit loss' model for calculating impairment. This new standard also increases required disclosures about an entity's risk management strategy, cash flows from hedging activities and the impact of hedge accounting on the consolidated financial statements. Pengrowth has applied IFRS 9 retrospectively in accordance with transition requirements with no impact to opening retained earnings or comparative periods.

IFRS 9 uses a single approach to determine whether a financial asset is measured at amortized cost or fair value, replacing the multiple rules in IAS 39. The approach is based on how an entity manages its financial instruments and the contractual cash flow characteristics of the financial assets. Most of the requirements in IAS 39 for classification and measurement of financial liabilities have been carried forward in IFRS 9.

The adoption of IFRS 9 did not result in any measurement adjustments to Pengrowth's financial assets or financial liabilities. The impact of the change in the impairment model was not significant as the credit-impaired financial assets are not significant.

The adoption of IFRS 9 did not result in any changes in the eligibility of existing hedge relationships. Pengrowth currently has no intentions of designating any of its financial instruments as hedges, or using hedge accounting.

IFRS 16 Leases

In January 2016, the IASB issued 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 in the final stages of analyzing identified contracts, developing business and accounting processes, making applicable changes to the Corporation's internal controls and calculating the impact that the adoption of this standard will have on its financial statements. Pengrowth has elected to use the modified retrospective approach upon adoption and elected to apply the optional exemptions for short-term and low-value leases. The actual full impact of adoption will depend on the Corporation's incremental borrowing rate, lease portfolio and practical expedients applied. However, Pengrowth anticipates that the most significant impact of adopting IFRS 16 will be the recognition of the lease liabilities on its leases for head office space and the right of use ("ROU") assets, as applicable.

Upon adoption of IFRS 16, the Corporation will recognize lease liabilities and ROU assets for all leases identified except for optional exemptions taken. The lease liability will be measured at the present value of the remaining lease payments, discounted using Pengrowth's incremental borrowing rate as at January 1, 2019. The ROU asset will be measured at the amount equal to the lease liability on January 1, 2019 with no impact on retained earnings.

Adoption of IFRS 16 will also result in an increase to Depletion, Depreciation and Amortization due to the recognition of the ROU assets, increase in interest and financing charges, and a decrease to G&A and operating expenses, as applicable. Cash flow from operating activities will increase as a result of the decrease in G&A and operating expenses, as applicable. Cash flow from financing activities will decrease due to the deduction of the interest portion of the principal payments for former operating leases.

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, 2018

Disclosure of changes in accounting policies, accounting estimates and errors [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
-	Motor vehicles	60 months

Cost or deemed cost	Oil and natural gas assets			Other equipment			Total
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
Additions to PP&E	66.7			0.9			67.6
Property acquisitions	0.2			—			0.2
Transfer from E&E	58.6			—			58.6
Change in asset retirement obligations	21.9			—			21.9
Balance, December 31, 2018		$3,965.1			$88.8			$4,053.9
Accumulated depletion, amortization and impairment losses	Oil and natural gas assets			Other equipment			Total
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
Depletion and amortization for the period	160.4			1.9			162.3
Balance, December 31, 2018		$2,880.7			$83.0			$2,963.7
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, 2018
Assets held for sale		$16.0			$—			$16.0
Long term	1,068.4			5.8			1,074.2
		$1,084.4			$5.8			$1,090.2

Cost or deemed cost
Balance, December 31, 2016		$496.3
Divestitures	(134.3		)
Impairment	(130.0		)
Balance, December 31, 2017		$232.0
Additions	0.2
Transfer to PP&E	(58.6		)
Impairment	(91.0		)
Balance, December 31, 2018		$82.6

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OTHER ASSETS (Tables)

12 Months Ended

Dec. 31, 2018

Disclosure Of Other Assets [Abstract]

Components of Other Assets

	As at
	December 31, 2018		December 31, 2017
Remediation trust fund - current		$24.0		$24.0
Remediation trust fund - non-current	74.0		87.6
Prepaid tax assessment	12.2		12.2
Prepaids and deposits	4.1		8.2
Inventory	5.7		4.6
		$120.0		$136.6
Current portion of other assets		$33.8		$36.8
Non-current portion of other assets		$86.2		$99.8

The following table reconciles Pengrowth’s investment in remediation trust funds for the periods noted below:

	Remediation Trust Funds
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
Contributions	2.9
Remediation expenditures	(17.9		)
Investment income	2.7
Unrealized gain (loss)	(1.3		)
Balance, December 31, 2018		$98.0

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PROPERTY, PLANT AND EQUIPMENT ("PP&E") (Tables)

12 Months Ended

Dec. 31, 2018

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
-	Motor vehicles	60 months

Cost or deemed cost	Oil and natural gas assets			Other equipment			Total
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
Additions to PP&E	66.7			0.9			67.6
Property acquisitions	0.2			—			0.2
Transfer from E&E	58.6			—			58.6
Change in asset retirement obligations	21.9			—			21.9
Balance, December 31, 2018		$3,965.1			$88.8			$4,053.9
Accumulated depletion, amortization and impairment losses	Oil and natural gas assets			Other equipment			Total
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
Depletion and amortization for the period	160.4			1.9			162.3
Balance, December 31, 2018		$2,880.7			$83.0			$2,963.7
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, 2018
Assets held for sale		$16.0			$—			$16.0
Long term	1,068.4			5.8			1,074.2
		$1,084.4			$5.8			$1,090.2

Cost or deemed cost
Balance, December 31, 2016		$496.3
Divestitures	(134.3		)
Impairment	(130.0		)
Balance, December 31, 2017		$232.0
Additions	0.2
Transfer to PP&E	(58.6		)
Impairment	(91.0		)
Balance, December 31, 2018		$82.6

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EXPLORATION AND EVALUATION ASSETS ("E&E") (Tables)

12 Months Ended

Dec. 31, 2018

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
-	Motor vehicles	60 months

Cost or deemed cost	Oil and natural gas assets			Other equipment			Total
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
Additions to PP&E	66.7			0.9			67.6
Property acquisitions	0.2			—			0.2
Transfer from E&E	58.6			—			58.6
Change in asset retirement obligations	21.9			—			21.9
Balance, December 31, 2018		$3,965.1			$88.8			$4,053.9
Accumulated depletion, amortization and impairment losses	Oil and natural gas assets			Other equipment			Total
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
Depletion and amortization for the period	160.4			1.9			162.3
Balance, December 31, 2018		$2,880.7			$83.0			$2,963.7
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, 2018
Assets held for sale		$16.0			$—			$16.0
Long term	1,068.4			5.8			1,074.2
		$1,084.4			$5.8			$1,090.2

Cost or deemed cost
Balance, December 31, 2016		$496.3
Divestitures	(134.3		)
Impairment	(130.0		)
Balance, December 31, 2017		$232.0
Additions	0.2
Transfer to PP&E	(58.6		)
Impairment	(91.0		)
Balance, December 31, 2018		$82.6

Estimated Forward Natural Gas Prices for Impairment Testing

Below are the forward commodity price estimates used in the December 31, 2018 impairment test:

	AECO gas (1)
Year	(Cdn$/MMBtu)
2019	1.85
2020	2.29
2021	2.67
2022	2.90
2023	3.14
2024	3.23
2025	3.34
2026	3.41
2027	3.48
2028	3.54
Thereafter	+ 2.0 percent/yr

⁽¹⁾  Prices represent forecasted amounts as at January 1, 2019 by Pengrowth's independent reserves evaluator.

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LONG TERM DEBT AND FINANCIAL COVENANTS (Tables)

12 Months Ended

Dec. 31, 2018

Disclosure of detailed information about financial instruments [abstract]

Summary of Long Term Debt

	As at
	December 31, 2018		December 31, 2017
U.S. dollar denominated term notes:
28.1 million at 5.49 percent due October 18, 2019		$38.3		$35.3
94.1 million at 7.98 percent due May 11, 2020	128.3		118.3
85.2 million at 6.07 percent due October 18, 2022	116.2		107.1
158.9 million at 6.17 percent due October 18, 2024	216.7		199.7
		$499.5		$460.4
U.K. pound sterling denominated term notes:
12.1 million at 5.45 percent due October 18, 2019		$21.1		$20.6
Canadian dollar term notes:
20.5 million at 6.74 percent due October 18, 2022		$20.5		$20.5
Canadian dollar term Credit Facility borrowings		$173.5		$109.0
Total long term debt		$714.6		$610.5
Current portion of long term debt		$232.9		$—
Non-current portion of long term debt		$481.7		$610.5

The only financial covenant relating to the term notes and Credit Facility is the Interest Coverage ratio. The Interest Coverage ratio changes each quarter until the fourth quarter of 2019 after which it remains at 4.0 times, as noted below. Any new or extended Credit Facility could contain new or different covenants and credit limits.

Year	Q1	Q2	Q3	Q4
2018	-	-	-	1.01 times
2019	1.13 times	1.19 times	1.23 times	4.0 times

The following table provides a reconciliation between the opening and closing balances for liabilities arising from financing activities at December 31, 2018:

	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		$—
Increase (decrease) due to:
Foreign exchange impact of the Canadian dollar on U.S. and U.K. denominated debt	39.6			—		—
Credit Facility borrowing	—			64.5		—
Balance, December 31, 2018		$541.1			$173.5		$—

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CAPITAL DISCLOSURES (Tables)

12 Months Ended

Dec. 31, 2018

Disclosure of share capital, reserves and other equity interest [Abstract]

Summary of Long Term Debt

	As at
	December 31, 2018		December 31, 2017
U.S. dollar denominated term notes:
28.1 million at 5.49 percent due October 18, 2019		$38.3		$35.3
94.1 million at 7.98 percent due May 11, 2020	128.3		118.3
85.2 million at 6.07 percent due October 18, 2022	116.2		107.1
158.9 million at 6.17 percent due October 18, 2024	216.7		199.7
		$499.5		$460.4
U.K. pound sterling denominated term notes:
12.1 million at 5.45 percent due October 18, 2019		$21.1		$20.6
Canadian dollar term notes:
20.5 million at 6.74 percent due October 18, 2022		$20.5		$20.5
Canadian dollar term Credit Facility borrowings		$173.5		$109.0
Total long term debt		$714.6		$610.5
Current portion of long term debt		$232.9		$—
Non-current portion of long term debt		$481.7		$610.5

The only financial covenant relating to the term notes and Credit Facility is the Interest Coverage ratio. The Interest Coverage ratio changes each quarter until the fourth quarter of 2019 after which it remains at 4.0 times, as noted below. Any new or extended Credit Facility could contain new or different covenants and credit limits.

Year	Q1	Q2	Q3	Q4
2018	-	-	-	1.01 times
2019	1.13 times	1.19 times	1.23 times	4.0 times

The following table provides a reconciliation between the opening and closing balances for liabilities arising from financing activities at December 31, 2018:

	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		$—
Increase (decrease) due to:
Foreign exchange impact of the Canadian dollar on U.S. and U.K. denominated debt	39.6			—		—
Credit Facility borrowing	—			64.5		—
Balance, December 31, 2018		$541.1			$173.5		$—

Disclosure of capital structure

The following is a summary of Pengrowth’s capital structure, excluding shareholders’ equity:

	As at
	December 31, 2018		December 31, 2017
Long term debt (1)		$714.6		$610.5
Working capital (surplus) deficiency (2)	35.9		80.6
		$750.5		$691.1

⁽¹⁾  Includes current portion of long term debt, as applicable.

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

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PROVISIONS AND OTHER LIABILITIES (Tables)

12 Months Ended

Dec. 31, 2018

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			Onerous lease contracts			Other liabilities			Total
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
Incurred during the period	1.4			—			6.8			(0.4		)	7.8
Property dispositions	(0.9		)	—			—			—			(0.9		)
Expenditures on remediation/provisions settled	(23.2		)	(0.8		)	(5.6		)	(0.2		)	(29.8		)
Revision due to rate changes (1)	24.6			—			—			—			24.6
Other revisions	(4.1		)	—			(3.2		)	—			(7.3		)
Accretion (amortization)	5.4			—			1.6			—			7.0
Balance, December 31, 2018		$239.9			$33.4			$25.8			$1.7			$300.8

⁽¹⁾  Relates to the change in the inflation rate from 1.5 percent to 2.0 percent. The offset is recorded in PP&E.

As at December 31, 2018	Asset retirement obligations		Finance leases		Onerous lease contracts		Other liabilities		Total
Current including assets held for sale (1)		$50.0		$0.7		$4.9		$0.1		$55.7
Long term	189.9		32.7		20.9		1.6		245.1
		$239.9		$33.4		$25.8		$1.7		$300.8
As at December 31, 2017
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

⁽¹⁾  Includes $16.0 million of asset retirement obligation related to assets held for sale at December 31, 2018.

Assumptions used to estimate asset retirement obligations

The following assumptions were used to estimate the ARO liability:

	As at
	December 31, 2018			December 31, 2017
Total escalated future costs		$491.7			$420.2
Discount rate, per annum	2.3		%	2.3		%
Inflation rate, per annum	2.0		%	1.5		%

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DEFERRED INCOME TAXES (Tables)

12 Months Ended

Dec. 31, 2018

Disclosure of income tax [Abstract]

Dislcosure of temporary difference, unused tax losses and unused tax credits

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
	2018			2017
Income (loss) before taxes		($217.1	)		($907.6	)
Combined federal and provincial tax rate	27.10		%	27.08		%
Expected income tax expense (recovery)		($58.8	)		($245.8	)
Change in unrecognized deferred tax asset	397.7			22.6
Foreign exchange (gain) loss (1)	2.0			(2.0		)
Other including share based compensation	1.3			1.4
Deferred income tax expense (recovery)		$342.2			($223.8	)

⁽¹⁾ Reflects the 50 percent non-taxable (deductible) 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, 2018		December 31, 2017
Deferred tax liabilities associated with:
PP&E and E&E assets		$—		($132.3	)
Less deferred tax assets associated with:
Non-capital losses and financing charges	—		399.6
Provisions	—		64.1
Risk management contracts	—		10.8
Net deferred tax asset (liability)		$—		$342.2

A continuity of the net deferred income tax asset (liability) for 2018 and 2017 is detailed in the following tables:

Movement in deferred tax asset (liability) during the year	Balance Jan 1, 2018			Recognized in profit or loss			Balance Dec 31, 2018
PP&E and E&E assets		($132.3	)	$	132.3			$—
Non-capital losses and financing charges	399.6			(399.6		)	—
Provisions	64.1			(64.1		)	—
Risk management contracts	10.8			(10.8		)	—
		$342.2		$	(342.2	)		$—

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		)	—
		$118.4			$223.8			$342.2

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SHAREHOLDERS' CAPITAL (Tables)

12 Months Ended

Dec. 31, 2018

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.

	2018			2017
(Common shares in 000's)	Number of common shares	Amount		Number of common shares	Amount
Balance, beginning of year	552,246		$4,829.7	547,709		$4,815.1
Share based compensation (non-cash exercised)	3,871	8.4		4,537	14.6
Balance, end of year	556,117		$4,838.1	552,246		$4,829.7

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LONG TERM INCENTIVE PLANS ("LTIP") (Tables)

12 Months Ended

Dec. 31, 2018

Disclosure of share-based payment arrangements [Abstract]

Disclosure of other award share activity

The following table provides a continuity of the share-settled PSUs and RSUs:

(number of share units - 000's)	PSUs		RSUs
Outstanding, December 31, 2016	6,238		8,436
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
Granted	—		3,006
Forfeited	(1,449	)	(2,444	)
Exercised	(826	)	(3,045	)
Performance adjustment	(138	)	—
Outstanding, December 31, 2018	2,621		4,900

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, 2016	4,229		1,346
Granted	3,163		492
Forfeited	(3,148	)	—
Exercised	(1,341	)	(462	)
Outstanding, December 31, 2017	2,903		1,376
Granted	—		847
Forfeited	(1,312	)	—
Exercised	(887	)	(155	)
Outstanding, December 31, 2018	704		2,068

Disclosure of option award activity

The following table provides a continuity of stock options outstanding at December 31:

	2018
(number of option units - 000's)	Number outstanding		Weighted average price
Outstanding, December 31, 2017	—			$—
Granted	9,468			$0.87
Forfeited	(141	)		$0.87
Exercised	—			$—
Outstanding, December 31, 2018	9,327			$0.87

Disclosure of range of exercise prices of outstanding options

The range of exercise prices of stock options outstanding and exercisable at December 31, 2018 was as follows:

Range of exercise prices	Number outstanding (thousands)	Weighted average remaining contractual life (years)	Weighted average exercise price		Number exercisable (thousands)	Weighted average exercise price
$0.87 - $1.05	9,327	6.49		$0.87	—		$—

Summary of share based compensation

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, 2018			December 31, 2017
Non-cash PSU and RSU expense		$3.5			$5.0
Non-cash stock options expense	1.5			—
Amounts capitalized in the period	(0.2		)	(0.1		)
Non-cash share based compensation expense		$4.8			$4.9
Cash-settled RSUs (reduction) expense		($0.5	)		($0.2	)
Cash-settled Phantom DSUs (reduction) expense		$0.1			($0.6	)
Total share based compensation expense		$4.4			$4.1

Estimated fair values for the stock options outstanding were calculated using the following weighted average assumptions:

Fair value per option		$0.46
Risk free interest rate	1.93		%
Expected volatility (1)	65.86		%
Expected life (years)	4.4
Expected forfeiture rate	15.0		%

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REVENUE (Tables)

12 Months Ended

Dec. 31, 2018

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
	2018		2017
Bitumen		$264.1		$181.6
Natural gas sold to third party (1)	16.6		98.8
Light oil	14.8		149.3
Natural gas liquids	4.7		56.7
Diluent sold	219.3		147.2
Processing income	2.0		19.1
Sale of other product purchased for resale	10.7		20.7
Total oil and gas sales		$532.2		$673.4

⁽¹⁾  Starting April 1, 2018, a portion of natural gas delivered from Groundbirch to the NGTL system is used in other operations as energy costs. As such, $7.2 million related to natural gas used in internal operations is not included in total oil and gas sales.

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OTHER CASH FLOW DISCLOSURES (Tables)

12 Months Ended

Dec. 31, 2018

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):	2018			2017
Accounts receivable and other current assets (1)		$28.5			$40.9
Accounts payable	(54.0		)	(22.7		)
		($25.5	)		$18.2

⁽¹⁾  Includes accounts receivable, inventory and prepaids.

CHANGE IN NON-CASH INVESTING WORKING CAPITAL 

	Year ended December 31
Cash used for:	2018			2017
Accounts payable, including capital accruals		($10.5	)		($7.5	)

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AMOUNTS PER SHARE (Tables)

12 Months Ended

Dec. 31, 2018

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)	2018	2017
Weighted average number of shares - basic and diluted	555,279	551,193

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FINANCIAL INSTRUMENTS AND RISK MANAGEMENT (Tables)

12 Months Ended

Dec. 31, 2018

Disclosure of detailed information about financial instruments [abstract]

Disclosure of detailed information about risk management instruments

Oil differentials	Cdn$1 decrease in future oil differential			Cdn$1 increase in future oil differential
Increase (decrease) to fair value of financial differential risk management contracts		($1.3	)		$1.3

As at December 31, 2018, 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 dilbit (bbl/d)	Term	Price per bbl (U.S.$)
Western Canada Select	2,500	2019	WTI less $17.95
Western Canada Select	2,500	2019	WTI less $23.60 - $26.35
Western Canada Select	5,000	2019	WTI less $17.70 - $20.45
Western Canada Select	2,500	Feb. 1, 2019 - Feb. 1, 2020	WTI less $20.40 - $23.40

As at December 31, 2018, Pengrowth had the following financial contracts outstanding:

Financial Crude Oil Contracts:
Swaps
Differentials
Reference point	Term	Volume of dilbit (bbl/d)	Price per bbl (U.S.$)
Western Canada Select	2019	5,000	WTI less $20.88

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

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 a portion of the principal amount of term note was early repaid in 2017.

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, 2018	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			$—

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, 2018			December 31, 2017
Risk management contracts
Current asset		$3.5			$—
Non-current asset	4.5			1.9
Current liability	(4.2		)	(40.0		)
Non-current liability	—			(18.6		)
		$3.8			($56.7	)

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, 2018	Commodity contracts (1)			Foreign exchange contracts (2)			Total
Current portion of risk management assets		$—			$3.5			$3.5
Non-current portion of risk management assets	—			4.5			4.5
Current portion of risk management liabilities	(4.2		)	—			(4.2		)
Risk management assets (liabilities), end of year		($4.2	)		$8.0			$3.8
Less: Risk management assets (liabilities) at beginning of year	(39.8		)	(16.9		)	(56.7		)
Unrealized gain (loss) on risk management contracts for the year		$35.6			$24.9			$60.5
Realized gain (loss) on risk management contracts for the year	(67.5		)	—			(67.5		)
Total unrealized and realized gain (loss) on risk management contracts for the year		($31.9	)		$24.9			($7.0	)
As at and for the year ended December 31, 2017	Commodity contracts (1)			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	)

⁽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 under Foreign exchange (gain) loss in the Consolidated Statements of Income (Loss). See Note 17.

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, 2018	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 fund		$98.0		$98.0		$98.0		$—		$—
Fair value of risk management contracts	8.0		8.0		—		8.0		—
Financial Liabilities
U.S. dollar denominated term notes	499.5		533.2		—		533.2		—
Cdn dollar term notes	20.5		22.3		—		22.3		—
U.K. pound sterling denominated term notes	21.1		21.4		—		21.4		—
Fair value of risk management contracts	4.2		4.2		—		4.2		—
					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 fund		$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		—

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, 2018	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 fund		$98.0		$98.0		$98.0		$—		$—
Fair value of risk management contracts	8.0		8.0		—		8.0		—
Financial Liabilities
U.S. dollar denominated term notes	499.5		533.2		—		533.2		—
Cdn dollar term notes	20.5		22.3		—		22.3		—
U.K. pound sterling denominated term notes	21.1		21.4		—		21.4		—
Fair value of risk management contracts	4.2		4.2		—		4.2		—
					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 fund		$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		—

Disclosure of how entity manages liquidity risk

Pengrowth’s current and non-current financial liabilities are as follows:

As at December 31, 2018	Carrying amount		Contractual cash flows		Year 1		Year 2		Years 3-5		More than 5 years
Accounts payable		$72.7		$72.7		$72.7		$—		$—		$—
Commodity risk management contracts	4.2		4.2		4.2		—		—		—
Cdn dollar senior unsecured notes (1)	20.5		25.7		1.4		1.4		22.9		—
U.S. dollar denominated term notes (2)	499.5		619.5		70.7		152.5		169.0		227.3
U.K. pound sterling denominated term notes (2)	21.1		22.0		22.0		—		—		—
Cdn dollar term Credit Facility borrowings (1)	173.5		176.1		176.1		—		—		—
Finance leases	33.4		72.3		4.2		4.2		12.6		51.3
Other liabilities	1.7		1.7		0.1		0.1		—		1.5

⁽¹⁾  Contractual cash flows include future interest payments.

⁽²⁾  Contractual cash flows include future interest payments and term notes calculated at December 31, 2018 period end exchange rate.

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 (1)	20.5		27.1		1.4		1.4		24.3		—
U.S. dollar denominated term notes (2)	460.4		601.3		30.2		65.2		284.0		221.9
U.K. pound sterling denominated term notes (2)	20.6		22.6		1.1		21.5		—		—
Cdn dollar term Credit Facility borrowings (1)	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.

⁽²⁾  Contractual cash flows include future interest payments and term notes calculated at December 31, 2017 period end exchange rate.

The accounts receivable is as follows:

	As at
	December 31, 2018		December 31, 2017
Trade		$42.8		$92.9

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FOREIGN EXCHANGE (GAIN) LOSS (Tables)

12 Months Ended

Dec. 31, 2018

Effects Of Changes In Foreign Exchange Rates [Abstract]

Summary of Foreign Exchange (Gain) Loss

	Year ended December 31
	2018			2017
Currency exchange rate (Cdn$1 = U.S.$) at beginning of year		$0.80			$0.74
Currency exchange rate (Cdn$1 = U.S.$) at year end		$0.73			$0.80
Unrealized foreign exchange (gain) loss from translation of foreign denominated debt		$39.8			($65.6	)
Unrealized (gain) loss on foreign exchange risk management contracts	(24.9		)	14.2
Net unrealized foreign exchange (gain) loss		$14.9			($51.4	)
Net realized foreign exchange (gain) loss		($0.8	)		$38.4

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COMMITMENTS (Tables)

12 Months Ended

Dec. 31, 2018

Disclosure Of Commitments [Abstract]

Disclosure of maturity analysis for commitments

	2019		2020		2021		2022		2023		Thereafter		Total
Operating leases	1.5		1.5		1.5		1.8		1.8		2.1		10.2
Onerous leases	5.1		5.3		5.2		6.0		4.9		5.8		32.3
Pipeline transportation	27.0		33.8		35.1		35.2		35.5		152.4		319.0
Power infrastructure and other	13.6		0.2		0.2		0.2		0.2		3.9		18.3
	$	47.2	$	40.8	$	42.0	$	43.2	$	42.4	$	164.2	$	379.8

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SUPPLEMENTARY DISCLOSURES (Tables)

12 Months Ended

Dec. 31, 2018

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
	2018		2017
Operating		$12.3		$30.1
General and administrative	20.0		35.5
Total employee compensation costs		$32.3		$65.6

Compensation expense related to officers and directors

The following table provides information on compensation expense related to officers and directors. During 2018, Pengrowth had 7 non-executive directors and 7 officers (2017 - 6 non-executive directors and 7 officers). Pengrowth had 6 non-executive directors and 4 officers at the end of 2018.

Year ended December 31, 2018	Wages & benefits paid		Bonus and other compensation paid		Share based compensation expense			Severance paid		Total
Directors		$0.5		$—		$0.1			$—		$0.6
Officers	2.0		3.7		2.9			2.4		11.0
		$2.5		$3.7		$3.0			$2.4		$11.6
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

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SIGNIFICANT ACCOUNTING POLICIES - Estimated Useful Lives of PP&E (Details)	12 Months Ended
	Dec. 31, 2018
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
Motor vehicles
Disclosure of detailed information about property, plant and equipment [line items]
Useful lives	60 months

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OTHER ASSETS - Components of Other Assets (Details) - CAD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Disclosure Of Other Assets [Abstract]
Remediation trust funds - current	$ 24.0	$ 24.0
Remediation trust funds - non-current	74.0	87.6
Prepaid tax assessment	12.2	12.2
Prepaids and deposits	4.1	8.2
Inventory	5.7	4.6
Other assets	120.0	136.6
Current portion of other assets	33.8	36.8
Non-current portion of other assets	$ 86.2	$ 99.8

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OTHER ASSETS - Remediation Trust Funds Narrative (Details) $ in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2017 CAD ($)	Dec. 31, 2018 CAD ($)	Dec. 31, 2018 CAD ($)	Dec. 31, 2018 CAD ($) $ / MMBTU	Dec. 31, 2018 CAD ($) $ / bbl	Dec. 31, 2017 CAD ($)	Dec. 31, 2016 CAD ($)
Disclosure of detailed information about property, plant and equipment [line items]
Expected remediation payments for 2018			$ 24.0
Remediation trust funds - current	$ 24.0	$ 24.0	24.0	$ 24.0	$ 24.0	$ 24.0
Lump sum contribution			2.9			14.0
Remediation trust funds - current and non-current	111.6	$ 98.0	$ 98.0	$ 98.0	$ 98.0	111.6	$ 106.5
Dispositions						$ 4.8
Judy Creek assets
Disclosure of detailed information about property, plant and equipment [line items]
Dispositions	$ 4.8
SOEP properties
Disclosure of detailed information about property, plant and equipment [line items]
Monthly contribution rate				1.41	2.42
Minimum
Disclosure of detailed information about property, plant and equipment [line items]
Decommissioning period		3 years
Maximum
Disclosure of detailed information about property, plant and equipment [line items]
Decommissioning period		4 years

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OTHER ASSETS - Rollforward of Remediation Trust Funds (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Disclosure Of Other Assets [Abstract]
Beginning balance	$ 111.6	$ 106.5
Contributions	2.9	14.0
Remediation expenditures	17.9	(6.6)
Investment income	2.7	3.1
Unrealized gain (loss)	(1.3)	(0.6)
Dispositions		(4.8)
Ending balance	$ 98.0	$ 111.6

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OTHER ASSETS - Prepaid Tax Assessment Narrative (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Income Tax Contingency [Line Items]
Prepaid tax assessment	$ 12.2	$ 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	$ 2.7

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PROPERTY, PLANT AND EQUIPMENT ("PP&E") - Summary of Property, Plant and Equipment (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2018	Dec. 31, 2017
Reconciliation of changes in property, plant and equipment [abstract]
Beginning balance	$ 1,104.2
Ending balance	1,074.2	$ 1,104.2
Assets held for sale			$ 16.0	$ 0.0
Long term	1,104.2	1,104.2	1,074.2	1,104.2
Property, plant and equipment and assets held for sale			1,090.2	1,104.2
Cost or deemed cost
Reconciliation of changes in property, plant and equipment [abstract]
Beginning balance	3,905.6	6,929.6
Additions to PP&E	67.6	121.5
Property acquisitions	0.2	0.1
Transfer from E&E	58.6
Change in asset retirement obligations	21.9	9.3
Divestitures		(3,154.9)
Ending balance	4,053.9	3,905.6
Long term	3,905.6	6,929.6	4,053.9	3,905.6
Accumulated depletion, amortization and impairment losses
Reconciliation of changes in property, plant and equipment [abstract]
Beginning balance	2,801.4	3,963.1
Depletion and amortization for the period	162.3	207.6
Impairment		504.4
Divestitures		(1,873.7)
Ending balance	2,963.7	2,801.4
Long term	2,801.4	3,963.1	2,963.7	2,801.4
Oil and natural gas assets
Reconciliation of changes in property, plant and equipment [abstract]
Beginning balance	1,097.4
Ending balance	1,068.4	1,097.4
Long term	1,097.4	1,097.4	1,068.4	1,097.4
Property, plant and equipment and assets held for sale			1,084.4	1,097.4
Oil and natural gas assets | Cost or deemed cost
Reconciliation of changes in property, plant and equipment [abstract]
Beginning balance	3,817.7	6,838.8
Additions to PP&E	66.7	120.7
Property acquisitions	0.2	0.1
Transfer from E&E	58.6
Change in asset retirement obligations	21.9	9.3
Divestitures		(3,151.2)
Ending balance	3,965.1	3,817.7
Long term	3,817.7	6,838.8	3,965.1	3,817.7
Oil and natural gas assets | Accumulated depletion, amortization and impairment losses
Reconciliation of changes in property, plant and equipment [abstract]
Beginning balance	2,720.3	3,882.7
Depletion and amortization for the period	160.4	204.4
Impairment		504.4
Divestitures		(1,871.2)
Ending balance	2,880.7	2,720.3
Long term	2,720.3	3,882.7	2,880.7	2,720.3
Other equipment
Reconciliation of changes in property, plant and equipment [abstract]
Beginning balance	6.8
Ending balance	5.8	6.8
Long term	6.8	6.8	5.8	6.8
Property, plant and equipment and assets held for sale			5.8	6.8
Other equipment | Cost or deemed cost
Reconciliation of changes in property, plant and equipment [abstract]
Beginning balance	87.9	90.8
Additions to PP&E	0.9	0.8
Property acquisitions	0.0	0.0
Transfer from E&E	0.0
Change in asset retirement obligations	0.0	0.0
Divestitures		(3.7)
Ending balance	88.8	87.9
Long term	87.9	90.8	88.8	87.9
Other equipment | Accumulated depletion, amortization and impairment losses
Reconciliation of changes in property, plant and equipment [abstract]
Beginning balance	81.1	80.4
Depletion and amortization for the period	1.9	3.2
Impairment		0.0
Divestitures		(2.5)
Ending balance	83.0	81.1
Long term	$ 81.1	$ 80.4	83.0	81.1
Assets held for sale
Reconciliation of changes in property, plant and equipment [abstract]
Assets held for sale			16.0	0.0
Assets held for sale | Oil and natural gas assets
Reconciliation of changes in property, plant and equipment [abstract]
Assets held for sale			16.0	0.0
Assets held for sale | Other equipment
Reconciliation of changes in property, plant and equipment [abstract]
Assets held for sale			$ 0.0	$ 0.0

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PROPERTY, PLANT AND EQUIPMENT ("PP&E") - Narrative (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018		Dec. 31, 2017	Dec. 31, 2016
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment	$ 1,074.2		$ 1,104.2
Proceeds on property dispositions	23.0		910.2
Deferred proceeds collected	20.0
Impairment loss	91.0	[1]	634.4
Assets held for sale	16.0		0.0
Liabilities associated with assets held for sale	16.0		0.0
Cost or deemed cost
Disclosure of detailed information about property, plant and equipment [line items]
Costs capitalized to PP&E	67.6		121.5
Property, plant and equipment	4,053.9		3,905.6	$ 6,929.6
Disposals, property, plant and equipment			3,154.9
Accumulated depletion, amortization and impairment losses
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment	$ 2,963.7		2,801.4	3,963.1
Disposals, property, plant and equipment			1,873.7
Impairment			$ 504.4
Lindbergh project
Disclosure of detailed information about property, plant and equipment [line items]
Weighted average cost of debt	6.50%		5.70%
Future development costs
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment	$ 4,600.0		$ 4,900.0
Northern and Southern GCUs
Disclosure of detailed information about property, plant and equipment [line items]
Assets held for sale	0.0
Oil and natural gas assets
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment	1,068.4		1,097.4
Oil and natural gas assets | Cost or deemed cost
Disclosure of detailed information about property, plant and equipment [line items]
Costs capitalized to PP&E	66.7		120.7
Property, plant and equipment	3,965.1		3,817.7	6,838.8
Disposals, property, plant and equipment			3,151.2
Oil and natural gas assets | Accumulated depletion, amortization and impairment losses
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment	2,880.7		2,720.3	$ 3,882.7
Disposals, property, plant and equipment			1,871.2
Impairment			504.4
Southern Alberta
Disclosure of detailed information about property, plant and equipment [line items]
Assets held for sale	16.0
Liabilities associated with assets held for sale	16.0
General and administrative
Disclosure of detailed information about property, plant and equipment [line items]
Costs capitalized to PP&E	1.7		2.3
Interest expense | Lindbergh project
Disclosure of detailed information about property, plant and equipment [line items]
Costs capitalized to PP&E	$ 2.4		$ 3.7

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EXPLORATION AND EVALUATION ASSETS ("E&E") - Summary of Exploration and Evaluation Assets (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Reconciliation of changes in property, plant and equipment [abstract]
Beginning balance	$ 1,104.2
Ending balance	1,074.2	$ 1,104.2
Exploration and Evaluation Assets
Reconciliation of changes in property, plant and equipment [abstract]
Beginning balance	232.0	496.3
Additions	0.2
Transfer to PP&E	(58.6)
Divestitures		(134.3)
Impairment	(91.0)	(130.0)
Ending balance	$ 82.6	$ 232.0

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EXPLORATION AND EVALUATION ASSETS ("E&E") - Narrative (Details) - CAD ($) $ in Millions		12 Months Ended
	Apr. 11, 2017	Dec. 31, 2018	Dec. 31, 2017
Disclosure of detailed information about property, plant and equipment [line items]
Proceeds on property dispositions		$ 23.0	$ 910.2
Exploration and Evaluation Assets
Disclosure of detailed information about property, plant and equipment [line items]
Proceeds on property dispositions	$ 92.0

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EXPLORATION AND EVALUATION ASSETS ("E&E") - Impairment Testing Narrative (Details) - CAD ($) $ in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2018		Dec. 31, 2017
Disclosure of impairment loss and reversal of impairment loss [line items]
Impairment loss		$ 91.0	[1]	$ 634.4
Groundbirch E&E
Disclosure of impairment loss and reversal of impairment loss [line items]
Inflation rate		2.00%
Impairment loss	$ 129.0	$ 91.0
Recoverable amount		$ 76.3
Other minor E&E
Disclosure of impairment loss and reversal of impairment loss [line items]
Impairment loss	$ 1.0
Proved reserves | Groundbirch E&E
Disclosure of impairment loss and reversal of impairment loss [line items]
Pre-tax discount rate		10.00%
Probable reserves | Groundbirch E&E
Disclosure of impairment loss and reversal of impairment loss [line items]
Pre-tax discount rate		12.00%
Contingent Resources | Groundbirch E&E
Disclosure of impairment loss and reversal of impairment loss [line items]
Pre-tax discount rate		15.00%
One percent increase | Groundbirch E&E
Disclosure of impairment loss and reversal of impairment loss [line items]
Impairment loss		$ 26.6
Sensitivity analysis, percentage		1.00%
One percent decrease | Groundbirch E&E
Disclosure of impairment loss and reversal of impairment loss [line items]
Impairment loss		$ (37.4)
Sensitivity analysis, percentage		(1.00%)
Five percent increase | Groundbirch E&E
Disclosure of impairment loss and reversal of impairment loss [line items]
Impairment loss		$ (16.0)
Sensitivity analysis, percentage		5.00%
Five percent decrease | Groundbirch E&E
Disclosure of impairment loss and reversal of impairment loss [line items]
Impairment loss		$ 17.3
Sensitivity analysis, percentage		(5.00%)
Twenty percent discount | Contingent Resources
Disclosure of impairment loss and reversal of impairment loss [line items]
Impairment loss		$ 33.5
Sensitivity analysis, percentage		20.00%
Twelve percent discount | Contingent Resources
Disclosure of impairment loss and reversal of impairment loss [line items]
Impairment loss		$ (45.7)
Sensitivity analysis, percentage		12.00%

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EXPLORATION AND EVALUATION ASSETS ("E&E") - Forward Natural Gas Prices (Details) - Groundbirch E&E	Dec. 31, 2018 $ / MMBTU
Disclosure of impairment loss and reversal of impairment loss [line items]
Inflation rate	2.00%
Exploration and Evaluation reserves | 2019
Disclosure of impairment loss and reversal of impairment loss [line items]
AECO gas prices (in CDN per MMBtu)	1.85
Exploration and Evaluation reserves | 2020
Disclosure of impairment loss and reversal of impairment loss [line items]
AECO gas prices (in CDN per MMBtu)	2.29
Exploration and Evaluation reserves | 2021
Disclosure of impairment loss and reversal of impairment loss [line items]
AECO gas prices (in CDN per MMBtu)	2.67
Exploration and Evaluation reserves | 2022
Disclosure of impairment loss and reversal of impairment loss [line items]
AECO gas prices (in CDN per MMBtu)	2.90
Exploration and Evaluation reserves | 2023
Disclosure of impairment loss and reversal of impairment loss [line items]
AECO gas prices (in CDN per MMBtu)	3.14
Exploration and Evaluation reserves | 2024
Disclosure of impairment loss and reversal of impairment loss [line items]
AECO gas prices (in CDN per MMBtu)	3.23
Exploration and Evaluation reserves | 2025
Disclosure of impairment loss and reversal of impairment loss [line items]
AECO gas prices (in CDN per MMBtu)	3.34
Exploration and Evaluation reserves | 2026
Disclosure of impairment loss and reversal of impairment loss [line items]
AECO gas prices (in CDN per MMBtu)	3.41
Exploration and Evaluation reserves | 2027
Disclosure of impairment loss and reversal of impairment loss [line items]
AECO gas prices (in CDN per MMBtu)	3.48
Exploration and Evaluation reserves | 2028
Disclosure of impairment loss and reversal of impairment loss [line items]
AECO gas prices (in CDN per MMBtu)	3.54
Exploration and Evaluation reserves | Thereafter
Disclosure of impairment loss and reversal of impairment loss [line items]
Inflation rate	2.00%

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LONG TERM DEBT AND FINANCIAL COVENANTS - Summary of Long Term Debt (Details) $ in Millions	12 Months Ended
	Dec. 31, 2018 CAD ($)	Dec. 31, 2017 CAD ($)	Dec. 31, 2018 GBP (£)	Dec. 31, 2018 CAD ($)	Dec. 31, 2018 USD ($)	Mar. 31, 2017 USD ($)	Dec. 31, 2016 CAD ($)
Disclosure of detailed information about borrowings [line items]
Current portion of long term debt		$ 0.0		$ 232.9
Non-current portion of long term debt		610.5		481.7
Total long term debt		610.5		714.6
Early repayment of borrowings	$ (64.5)	937.2
U.S. dollar denominated term notes
Disclosure of detailed information about borrowings [line items]
Total long term debt		460.4		499.5
400 million at 6.35 percent due July 26, 2017
Disclosure of detailed information about borrowings [line items]
Face value						$ 400,000,000
35 million at 5.49 percent due October 18, 2019
Disclosure of detailed information about borrowings [line items]
Face value					$ 28,100,000.0
Total long term debt		35.3		38.3
115.5 million at 7.98 percent due May 11, 2020
Disclosure of detailed information about borrowings [line items]
Face value					94,100,000.0
Total long term debt		118.3		128.3
105 million at 6.07 percent due October 18, 2022
Disclosure of detailed information about borrowings [line items]
Face value					85,200,000.0
Total long term debt		107.1		116.2
195 million at 6.17 percent due October 18, 2024
Disclosure of detailed information about borrowings [line items]
Face value					158,900,000.0
Total long term debt		199.7		216.7
15 million at 5.45 percent due October 18, 2019
Disclosure of detailed information about borrowings [line items]
Face value | £			£ 12,100,000.0
Total long term debt		20.6		21.1
Cdn dollar term notes
Disclosure of detailed information about borrowings [line items]
Total long term debt		20.5		20.5
25 million at 6.74 percent due October 18, 2022
Disclosure of detailed information about borrowings [line items]
Face value					$ 20,500,000.0
Total long term debt		20.5		20.5
Canadian dollar term Credit Facility borrowings
Disclosure of detailed information about borrowings [line items]
Total long term debt		$ 109.0		$ 173.5			$ 0.0
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 | 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%

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LONG TERM DEBT AND FINANCIAL COVENANTS - Narrative (Details) $ in Millions		3 Months Ended					12 Months Ended
	Oct. 01, 2017 USD ($)	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018 CAD ($)	Dec. 31, 2018 CAD ($)	Dec. 31, 2017 CAD ($)	Mar. 31, 2017 USD ($)	Dec. 31, 2016 CAD ($)
Disclosure of detailed information about borrowings [line items]
Amount outstanding						$ 714,600,000	$ 714,600,000	$ 610,500,000
Early repayment of borrowings							$ (64,500,000)	937,200,000
Interest ratio coverage		4.0	1.23	1.19	1.13	1.01	1.01
Senior debt to adjusted EBITDA ratio						3.5	3.5
Debt to book capitalization ratio							55.00%
Interest coverage ratio, actual						1.6	1.6
Credit Facility
Disclosure of detailed information about borrowings [line items]
Credit facility, maximum borrowing capacity						$ 330,000,000	$ 330,000,000
Amount outstanding						173,500,000	173,500,000	109,000,000
Letters Of Credit - Credit Facility
Disclosure of detailed information about borrowings [line items]
Amount outstanding						75,600,000	75,600,000	69,400,000
400 million at 6.35 percent due July 26, 2017
Disclosure of detailed information about borrowings [line items]
Face value									$ 400
Early redemption penalty	$ 265
U.S. dollar denominated term notes
Disclosure of detailed information about borrowings [line items]
Amount outstanding						499,500,000	499,500,000	460,400,000
Unrealized cumulative foreign exchange loss						135,300,000	135,300,000	96,200,000
U.K. pound sterling denominated term notes
Disclosure of detailed information about borrowings [line items]
Amount outstanding						21,100,000	21,100,000	20,600,000
Unrealized cumulative foreign exchange loss						1,900,000	1,900,000	1,400,000
Term Notes
Disclosure of detailed information about borrowings [line items]
Amount outstanding						541,100,000	541,100,000	501,500,000		$ 1,560,700,000
Early repayment of borrowings								1,000,000,000
Convertible debentures
Disclosure of detailed information about borrowings [line items]
Amount outstanding						0	0	0		$ 126,600,000
Early repayment of borrowings								126,600,000
Floating interest rate
Disclosure of detailed information about borrowings [line items]
Amount outstanding						$ 173,500,000	$ 173,500,000	$ 109,000,000
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%
2019
Disclosure of detailed information about borrowings [line items]
Amount outstanding						$ 270,100,000	$ 270,100,000
2020
Disclosure of detailed information about borrowings [line items]
Amount outstanding						153,800,000	153,800,000
2021
Disclosure of detailed information about borrowings [line items]
Amount outstanding						21,900,000	21,900,000
2022
Disclosure of detailed information about borrowings [line items]
Amount outstanding						156,800,000	156,800,000
2023
Disclosure of detailed information about borrowings [line items]
Amount outstanding						$ 13,400,000	$ 13,400,000

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CAPITAL DISCLOSURES - Narrative (Details) - CAD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Disclosure of detailed information about borrowings [line items]
Long-term debt	$ 714.6	$ 610.5
Credit Facility
Disclosure of detailed information about borrowings [line items]
Long-term debt	$ 81.4

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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	Dec. 31, 2018
Disclosure of share capital, reserves and other equity interest [Abstract]
Interest ratio coverage	4.0	1.23	1.19	1.13	1.01	1.01

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CAPITAL DISCLOSURES - Rollforward of Financial Liabilities (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Disclosure of detailed information about borrowings [line items]
Beginning balance	$ 610.5
Increase (decrease) due to:
Foreign exchange impact of the Canadian dollar on U.S. and U.K. denominated debt	0.0
Credit facility borrowing	0.0
Ending balance	714.6	$ 610.5
Term Notes
Disclosure of detailed information about borrowings [line items]
Beginning balance	501.5	1,560.7
Increase (decrease) due to:
Foreign exchange impact of the Canadian dollar on U.S. and U.K. denominated debt	39.6	(65.1)
Credit facility borrowing	0.0	0.0
Repayment		(996.0)
Issue cost amortization		1.9
Ending balance	541.1	501.5
Canadian dollar Term Credit Facility
Disclosure of detailed information about borrowings [line items]
Beginning balance	109.0	0.0
Increase (decrease) due to:
Foreign exchange impact of the Canadian dollar on U.S. and U.K. denominated debt	0.0	0.0
Credit facility borrowing	64.5	109.0
Repayment		0.0
Issue cost amortization		0.0
Ending balance	173.5	109.0
Convertible debentures
Disclosure of detailed information about borrowings [line items]
Beginning balance	0.0	126.6
Increase (decrease) due to:
Foreign exchange impact of the Canadian dollar on U.S. and U.K. denominated debt		0.0
Credit facility borrowing		0.0
Repayment		(126.6)
Issue cost amortization		0.0
Ending balance	$ 0.0	$ 0.0

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CAPITAL DISCLOSURES - Capital Structure (Excluding Shareholders' Equity) (Details) - CAD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Disclosure of share capital, reserves and other equity interest [Abstract]
Long-term debt	$ 714.6	$ 610.5
Working capital (surplus) deficiency	35.9	80.6
Capital structure	$ 750.5	$ 691.1

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PROVISIONS AND OTHER LIABILITIES - Rollforward of Provisions (Details) - CAD ($) $ in Millions	3 Months Ended	12 Months Ended
	Sep. 30, 2018	Dec. 31, 2018	Dec. 31, 2017
Disclosure of other provisions [line items]
Beginning balance		$ 299.4	$ 694.6
Incurred during the period		7.8	30.4
Property dispositions		(0.9)	(422.4)
Expenditures on remediation/provisions settled		(29.8)	(18.5)
Revision due to discount rate changes		24.6
Other revisions		(7.3)	3.9
Accretion (amortization)		7.0	11.4
Ending balance		300.8	299.4
Asset retirement obligations
Disclosure of other provisions [line items]
Beginning balance		236.7	652.3
Incurred during the period		1.4	5.4
Property dispositions		(0.9)	(420.4)
Expenditures on remediation/provisions settled		(23.2)	(15.9)
Revision due to discount rate changes		24.6
Other revisions		(4.1)	3.9
Accretion (amortization)		5.4	11.4
Ending balance		$ 239.9	$ 236.7
Inflation rate		2.00%	1.50%
Finance leases
Disclosure of other provisions [line items]
Beginning balance		$ 34.2	$ 37.9
Incurred during the period		0.0	0.0
Property dispositions		0.0	(2.0)
Expenditures on remediation/provisions settled		(0.8)	(1.7)
Revision due to discount rate changes		0.0
Other revisions		0.0	0.0
Ending balance		33.4	34.2
Onerous lease contracts
Disclosure of other provisions [line items]
Beginning balance		26.2	0.0
Incurred during the period	$ 6.8	6.8	26.5
Property dispositions		0.0	0.0
Expenditures on remediation/provisions settled		(5.6)	(0.3)
Revision due to discount rate changes		0.0
Other revisions		(3.2)	0.0
Accretion (amortization)		1.6
Ending balance		25.8	26.2
Other liabilities
Disclosure of other provisions [line items]
Beginning balance		2.3	4.4
Incurred during the period		(0.4)	(1.5)
Property dispositions		0.0	0.0
Expenditures on remediation/provisions settled		(0.2)	(0.6)
Revision due to discount rate changes		0.0
Other revisions		0.0	0.0
Ending balance		$ 1.7	$ 2.3

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PROVISIONS AND OTHER LIABILITIES - Components of Provisions (Details) - CAD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Disclosure of other provisions [line items]
Current including assets held for sale	$ 55.7	$ 35.2
Long term	245.1	264.2
Total	300.8	299.4	$ 694.6
Asset retirement obligations
Disclosure of other provisions [line items]
Current including assets held for sale	50.0	29.9
Long term	189.9	206.8
Total	239.9	236.7	652.3
Finance leases
Disclosure of other provisions [line items]
Current including assets held for sale	0.7	0.9
Long term	32.7	33.3
Total	33.4	34.2	37.9
Onerous lease contracts
Disclosure of other provisions [line items]
Current including assets held for sale	4.9	4.4
Long term	20.9	21.8
Total	25.8	26.2	0.0
Other liabilities
Disclosure of other provisions [line items]
Current including assets held for sale	0.1	0.0
Long term	1.6	2.3
Total	1.7	$ 2.3	$ 4.4
Assets held for sale | Asset retirement obligations
Disclosure of other provisions [line items]
Current including assets held for sale	$ 16.0

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PROVISIONS AND OTHER LIABILITIES - Narrative (Details) - CAD ($) $ in Millions	3 Months Ended	12 Months Ended
	Sep. 30, 2018	Dec. 31, 2018		Dec. 31, 2017	Dec. 31, 2016
Disclosure of other provisions [line items]
Property dispositions		$ 0.9		$ 422.4
Restructuring costs		0.4	[1]	37.0
Incurred during the period		7.8		30.4
Provisions		300.8		299.4	$ 694.6
Onerous lease contracts
Disclosure of other provisions [line items]
Property dispositions		0.0		0.0
Onerous office lease contracts				26.2
Incurred during the period	$ 6.8	6.8		26.5
Provisions		$ 25.8		$ 26.2	$ 0.0
Construction Camp - Lindbergh | Onerous lease contracts
Disclosure of other provisions [line items]
Incurred during the period	$ 5.4
Minimum
Disclosure of other provisions [line items]
Expected period		3 years
Maximum
Disclosure of other provisions [line items]
Expected period		4 years

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PROVISIONS AND OTHER LIABILITIES - Assumptions in Calculation of ARO (Details) - Asset retirement obligations - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Disclosure of other provisions [line items]
Total escalated future costs	$ 491.7	$ 420.2
Discount rate, per annum	2.30%	2.30%
Inflation rate, per annum	2.00%	1.50%

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DEFERRED INCOME TAXES - Reconciliation of Deferred Income Tax Recovery (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018		Dec. 31, 2017
Disclosure of income tax [Abstract]
Income (loss) before taxes	$ (217.1)	[1]	$ (907.6)
Combined federal and provincial tax rate	27.10%		27.08%
Expected income tax expense (recovery)	$ (58.8)		$ (245.8)
Change in unrecognized deferred tax asset	397.7		22.6
Foreign exchange (gain) loss	2.0		(2.0)
Other including share based compensation	1.3		1.4
Deferred income tax expense (recovery)	$ 342.2		$ (223.8)
Tax rate effect of expense not deductible in determining taxable profit (tax loss)	50.00%

[1] {F|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOjJmY2RlZjAzOGRkOTRlOWE5NjlkYTc5MWVjNWQ3ZWRhfFRleHRTZWxlY3Rpb246RTdGNjdEMTk4QzhCMzA5MTVCODczRkVEMTY1NDc4ODkM}

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DEFERRED INCOME TAXES - Components of Deferred Tax Assets and Liabilities (Details) - CAD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Deferred tax liabilities associated with:
PP&E and E&E assets	$ 0.0	$ (132.3)
Less deferred tax assets associated with:
Non-capital losses and financing charges	0.0	399.6
Provisions	0.0	64.1
Risk management contracts	0.0	10.8
Net deferred tax asset (liability)	$ 0.0	$ 342.2	$ 118.4

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DEFERRED INCOME TAXES - Narrative (Details) $ in Billions	Dec. 31, 2018 CAD ($)
Disclosure of income tax [Abstract]
Unrecognized deductible temporary differences	$ 1.8
Non capital losses	1.6
Other temporary differences (PP&E and other)	$ 0.2

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DEFERRED INCOME TAXES - Continuity of the Net Deferred Income Tax Asset (Liability) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Reconciliation of changes in deferred tax liability (asset) [abstract]
Beginning balance	$ 342.2	$ 118.4
Recognized in profit or loss	(342.2)	223.8
Ending balance	0.0	342.2
PP&E and E&E assets
Reconciliation of changes in deferred tax liability (asset) [abstract]
Beginning balance	(132.3)	(411.0)
Recognized in profit or loss	132.3	278.7
Ending balance		(132.3)
Non-capital losses and financing charges
Reconciliation of changes in deferred tax liability (asset) [abstract]
Beginning balance	399.6	325.9
Recognized in profit or loss	(399.6)	73.7
Ending balance		399.6
Provisions
Reconciliation of changes in deferred tax liability (asset) [abstract]
Beginning balance	64.1	176.6
Recognized in profit or loss	(64.1)	(112.5)
Ending balance		64.1
Risk management contracts
Reconciliation of changes in deferred tax liability (asset) [abstract]
Beginning balance	10.8	14.6
Recognized in profit or loss	(10.8)	(3.8)
Ending balance		10.8
Long term debt
Reconciliation of changes in deferred tax liability (asset) [abstract]
Beginning balance	0.0	12.1
Recognized in profit or loss		(12.1)
Ending balance		0.0
Convertible debentures
Reconciliation of changes in deferred tax liability (asset) [abstract]
Beginning balance	$ 0.0	0.2
Recognized in profit or loss		(0.2)
Ending balance		$ 0.0

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SHAREHOLDERS' CAPITAL - Summary of Shareholders' Capital (Details) - CAD ($) shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Reconciliation of number of shares outstanding [abstract]
Balance, beginning of year	$ 4,829.7
Balance, end of year	$ 4,838.1	$ 4,829.7
Common Shares
Reconciliation of number of shares outstanding [abstract]
Balance, beginning of period (in shares)	552,246	547,709
Share based compensation (non-cash exercised) (in shares)	3,871	4,537
Balance, end of period (in shares)	556,117	552,246
Balance, beginning of year	$ 4,829.7	$ 4,815.1
Share based compensation (non-cash exercised)	8.4	14.6
Balance, end of year	$ 4,838.1	$ 4,829.7

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SHAREHOLDERS' CAPITAL - Narrative (Details)	Dec. 31, 2018 shares
Preferred Shares
Disclosure of classes of share capital [line items]
Shares authorized (in shares)	10,000,000

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LONG TERM INCENTIVE PLANS ("LTIP") - Continuity of Share-settled LTIP (Details) - shares shares in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Disclosure of terms and conditions of share-based payment arrangement [line items]
Granted	9,468
Forfeited	(141)
Exercised	0
PSUs
Disclosure of terms and conditions of share-based payment arrangement [line items]
Beginning shares	5,034	6,238
Granted	0	2,124
Forfeited	(1,449)	(486)
Exercised	(826)	(1,104)
Performance adjustment	(138)	(1,738)
Ending shares	2,621	5,034
RSUs
Disclosure of terms and conditions of share-based payment arrangement [line items]
Beginning shares	7,383	8,436
Granted	3,006	4,578
Forfeited	(2,444)	(2,195)
Exercised	(3,045)	(3,436)
Performance adjustment	0	0
Ending shares	4,900	7,383

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LONG TERM INCENTIVE PLANS ("LTIP") - Stock Option Activity (Details) shares in Thousands	12 Months Ended
	Dec. 31, 2018 CAD ($) shares
Disclosure of terms and conditions of share-based payment arrangement [line items]
Granted (in shares) | shares	9,468
Forfeited (in shares) | shares	(141)
Exercised (in shares) | shares	0
Beginning weighted average exercise price (in CAD per share) | $	$ 0.00
Weighted average exercise price, granted (in CAD per share) | $	0.87
Weighted average exercise price, forfeited (in CAD per share) | $	0.87
Weighted average exercise price, exercised (in CAD per share) | $	0.00
Ending weighted average exercise price (in CAD per share) | $	$ 0.87
Stock options
Disclosure of terms and conditions of share-based payment arrangement [line items]
Beginning shares | shares	0
Ending shares | shares	9,327

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LONG TERM INCENTIVE PLANS ("LTIP") - Range of Exercise Prices of Options Outstanding and Exercisable (Details) shares in Thousands	Dec. 31, 2018 CAD ($) shares year	Dec. 31, 2017 CAD ($) shares
Disclosure of range of exercise prices of outstanding share options [line items]
Weighted average remaining contractual life of outstanding share options | year	6.49
Number exercisable (in shares) | shares	0
Weighted average exercise price of share options exercisable (in CAD per share)	$ 0.87	$ 0.00
Minimum
Disclosure of range of exercise prices of outstanding share options [line items]
Range of exercise price (in CAD per share)	0.87
Maximum
Disclosure of range of exercise prices of outstanding share options [line items]
Range of exercise price (in CAD per share)	$ 1.05
Stock options
Disclosure of range of exercise prices of outstanding share options [line items]
Number outstanding (in shares) | shares	9,327	0

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LONG TERM INCENTIVE PLANS ("LTIP") - Fair Value Assumptions (Details)	12 Months Ended
	Dec. 31, 2018 CAD ($) year
Disclosure of share-based payment arrangements [Abstract]
Fair value per option | $	$ 0.46
Risk free interest rate	1.93%
Expected volatility	65.86%
Expected life (years) | year	4.4
Expected forfeiture rate	15.00%

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LONG TERM INCENTIVE PLANS ("LTIP") - Narrative (Details)	12 Months Ended
	Dec. 31, 2018 CAD ($) tranche $ / shares shares	Dec. 31, 2017 CAD ($) $ / shares shares
Disclosure of terms and conditions of share-based payment arrangement [line items]
Actual percent of LTIP shares of outstanding and issued shares	3.10%
Expense (reduction) for share-based compensation	$ 4,400,000	$ 4,100,000
Share-settled LTIP units
Disclosure of terms and conditions of share-based payment arrangement [line items]
Expense (reduction) for share-based compensation	3,500,000	5,000,000
Weighted average grant date fair value (in CAD per share)	0.87	1.40
Unrecognized compensation expense	$ 2,700,000	$ 5,400,000
Unrecognized compensation expense (in CAD per share) | $ / shares	$ 0.32	$ 0.51
Period for recognition	1 year
Stock options
Disclosure of terms and conditions of share-based payment arrangement [line items]
Expense (reduction) for share-based compensation	$ 1,500,000	$ 0
Weighted average grant date fair value (in CAD per share)	0.46	0
Unrecognized compensation expense	$ 2,000,000	$ 0
Unrecognized compensation expense (in CAD per share) | $ / shares	$ 0.22
Period for recognition	1 year 4 months 28 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
DSUs
Disclosure of terms and conditions of share-based payment arrangement [line items]
Shares reserved for future issuance (in shares) | shares	198,477	198,477
Cash-settled RSUs
Disclosure of terms and conditions of share-based payment arrangement [line items]
Expense (reduction) for share-based compensation	$ (500,000)	$ (200,000)
Number of tranches | tranche	3
Vesting period	3 years
Liabilities from share-based payment transactions	$ 300,000	1,500,000
Phantom DSUs
Disclosure of terms and conditions of share-based payment arrangement [line items]
Expense (reduction) for share-based compensation	100,000	(600,000)
Liabilities from share-based payment transactions	$ 1,200,000	$ 1,400,000
Minimum | PSUs
Disclosure of terms and conditions of share-based payment arrangement [line items]
Performance factor	0.00%
Maximum | PSUs
Disclosure of terms and conditions of share-based payment arrangement [line items]
Performance factor	200.00%

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LONG TERM INCENTIVE PLANS ("LTIP") - Continuity of Cash-settled LTIP (Details) - shares shares in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Disclosure of terms and conditions of share-based payment arrangement [line items]
Granted	9,468
Forfeited	(141)
Exercised	0
Cash-settled RSUs
Disclosure of terms and conditions of share-based payment arrangement [line items]
Beginning shares	2,903	4,229
Granted	0	3,163
Forfeited	(1,312)	(3,148)
Exercised	(887)	(1,341)
Ending shares	704	2,903
Phantom DSUs
Disclosure of terms and conditions of share-based payment arrangement [line items]
Beginning shares	1,376	1,346
Granted	847	492
Forfeited	0	0
Exercised	(155)	(462)
Ending shares	2,068	1,376

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LONG TERM INCENTIVE PLANS ("LTIP") - Share Based Compensation Expense (Details) - CAD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Disclosure of terms and conditions of share-based payment arrangement [line items]
Amounts capitalized in the period	$ (200,000)	$ (100,000)
Non-cash share based compensation expense	4,800,000	4,900,000
Expense (reduction) for share-based compensation	4,400,000	4,100,000
PSU and RSUs
Disclosure of terms and conditions of share-based payment arrangement [line items]
Non-cash PSU and RSU expense	3,500,000	5,000,000
Stock options
Disclosure of terms and conditions of share-based payment arrangement [line items]
Non-cash PSU and RSU expense	1,500,000	0
Expense (reduction) for share-based compensation	1,500,000	0
Cash-settled RSUs
Disclosure of terms and conditions of share-based payment arrangement [line items]
Expense (reduction) for share-based compensation	(500,000)	(200,000)
Phantom DSUs
Disclosure of terms and conditions of share-based payment arrangement [line items]
Expense (reduction) for share-based compensation	$ 100,000	$ (600,000)

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REVENUE - Disaggregation of Revenue (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018		Dec. 31, 2017
Disclosure of disaggregation of revenue from contracts with customers [line items]
Oil and gas sales	$ 532.2	[1]	$ 673.4
Bitumen
Disclosure of disaggregation of revenue from contracts with customers [line items]
Oil and gas sales			181.6
Natural gas
Disclosure of disaggregation of revenue from contracts with customers [line items]
Oil and gas sales			98.8
Light oil
Disclosure of disaggregation of revenue from contracts with customers [line items]
Oil and gas sales			149.3
Natural gas liquids
Disclosure of disaggregation of revenue from contracts with customers [line items]
Oil and gas sales			56.7
Diluent sold
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
Sale of other product purchased for resale
Disclosure of disaggregation of revenue from contracts with customers [line items]
Oil and gas sales			$ 20.7
Previously reported
Disclosure of disaggregation of revenue from contracts with customers [line items]
Oil and gas sales	532.2
Previously reported | Bitumen
Disclosure of disaggregation of revenue from contracts with customers [line items]
Oil and gas sales	264.1
Previously reported | Natural gas
Disclosure of disaggregation of revenue from contracts with customers [line items]
Oil and gas sales	16.6
Previously reported | Light oil
Disclosure of disaggregation of revenue from contracts with customers [line items]
Oil and gas sales	14.8
Previously reported | Natural gas liquids
Disclosure of disaggregation of revenue from contracts with customers [line items]
Oil and gas sales	4.7
Previously reported | Diluent sold
Disclosure of disaggregation of revenue from contracts with customers [line items]
Oil and gas sales	219.3
Previously reported | Processing income
Disclosure of disaggregation of revenue from contracts with customers [line items]
Oil and gas sales	2.0
Previously reported | Sale of other product purchased for resale
Disclosure of disaggregation of revenue from contracts with customers [line items]
Oil and gas sales	10.7
Previously reported | Natural Gas Used in Internal Operations
Disclosure of disaggregation of revenue from contracts with customers [line items]
Oil and gas sales	$ 7.2

[1] {F|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOjJmY2RlZjAzOGRkOTRlOWE5NjlkYTc5MWVjNWQ3ZWRhfFRleHRTZWxlY3Rpb246RTdGNjdEMTk4QzhCMzA5MTVCODczRkVEMTY1NDc4ODkM}

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REVENUE - Narrative (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018		Dec. 31, 2017
Disclosure of disaggregation of revenue from contracts with customers [line items]
Oil and gas sales	$ 532.2	[1]	$ 673.4
Operating expenses	(619.7)	[1]	(1,311.6)
Diluent and other product purchases	(229.5)	[1]	(163.5)
Accounts receivable	$ 42.8		92.9
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	90.00%
Oil and gas sales
Disclosure of disaggregation of revenue from contracts with customers [line items]
Accounts receivable	$ 22.2		$ 40.2

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OTHER CASH FLOW DISCLOSURES - Change in Non-cash Operating Working Capital and Other Assets (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Cash Flow Statement [Abstract]
Accounts receivable and other current assets (1)	$ 28.5	$ 40.9
Accounts payable	(54.0)	(22.7)
Change in non-cash operating working capital	$ (25.5)	$ 18.2

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OTHER CASH FLOW DISCLOSURES - Change in Non-cash Investing Working Capital (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Cash Flow Statement [Abstract]
Accounts payable, including capital accruals	$ (10.5)	$ (7.5)

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AMOUNTS PER SHARE - Summary of Weighted Average Shares Used in Calculating Amounts Per Share (Details) - shares shares in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Earnings per share [abstract]
Weighted average number of shares - basic and diluted (in shares)	555,279	551,193

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FINANCIAL INSTRUMENTS AND RISK MANAGEMENT - Summary of Commodity Price Contracts (Details) $ in Millions	12 Months Ended
	Dec. 31, 2018 CAD ($) $ / bbl bbl $ / bbl
Commodity price risk | Financial Crude Oil Contracts: | 2019
Disclosure of detailed information about hedging instruments [line items]
Nominal volume (in bbl/d) | bbl	5,000
Price per unit (in usd per bbl)	20.88
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 | $	$ (1.3)
Benchmark for sensitivity analysis	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 | $	$ 1.3
Benchmark for sensitivity analysis	1
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 $23.60 - $26.35 | 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 $23.60 - $26.35 | Commodity price risk | Physical Delivery Contracts | 2019 | Maximum
Disclosure of detailed information about hedging instruments [line items]
Price per unit (in usd per bbl)	26.35
WTI less $23.60 - $26.35 | Commodity price risk | Physical Delivery Contracts | 2019 | Minimum
Disclosure of detailed information about hedging instruments [line items]
Price per unit (in usd per bbl)	23.60
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
WTI less $20.40 - $23.40 | Commodity price risk | Physical Delivery Contracts | 2020
Disclosure of detailed information about hedging instruments [line items]
Nominal volume (in bbl/d) | bbl	2,500
WTI less $20.40 - $23.40 | Commodity price risk | Physical Delivery Contracts | 2020 | Maximum
Disclosure of detailed information about hedging instruments [line items]
Price per unit (in usd per bbl)	23.40
WTI less $20.40 - $23.40 | Commodity price risk | Physical Delivery Contracts | 2020 | Minimum
Disclosure of detailed information about hedging instruments [line items]
Price per unit (in usd per bbl)	20.40

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FOREIGN EXCHANGE (GAIN) LOSS - Summary of Foreign Exchange (Gain) Loss (Details) $ in Millions	12 Months Ended
	Dec. 31, 2018 CAD ($) $ / $		Dec. 31, 2017 CAD ($) $ / $
Effects Of Changes In Foreign Exchange Rates [Abstract]
Currency exchange rate (Cdn$1 U.S.$) at beginning of year | $ / $	0.80		0.74
Currency exchange rate (Cdn$1 U.S.$) at year end | $ / $	0.73		0.80
Disclosure Of Foreign Currency Gains (Losses) [Line Items]
Net unrealized foreign exchange (gain) loss	$ 14.9	[1]	$ (51.4)
Net realized foreign exchange (gain) loss	(0.8)	[1]	38.4
Foreign exchange risk management contracts
Disclosure Of Foreign Currency Gains (Losses) [Line Items]
Net unrealized foreign exchange (gain) loss	(24.9)		14.2
Foreign denominated debt
Disclosure Of Foreign Currency Gains (Losses) [Line Items]
Net unrealized foreign exchange (gain) loss	$ 39.8		$ (65.6)

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FINANCIAL INSTRUMENTS AND RISK MANAGEMENT - Narrative (Details) $ in Millions		3 Months Ended	12 Months Ended
	Oct. 01, 2017 USD ($)	Dec. 31, 2017 CAD ($)	Dec. 31, 2018 CAD ($) bbl $ / bbl $ / $		Dec. 31, 2017 CAD ($)	Dec. 31, 2018 USD ($) bbl $ / bbl $ / $	Mar. 31, 2017 USD ($)	Dec. 31, 2016 CAD ($)
Disclosure of information about terms and conditions of hedging instruments and how they affect future cash flows [line items]
Accounts receivable and derivative assets, gross		$ 94,800,000	$ 50,800,000		$ 94,800,000
Loss allowance		500,000	1,200,000		500,000
Current trade receivables		92,900,000	42,800,000		92,900,000
Realized foreign exchange (gain) loss			(800,000)	[1]	38,400,000
Long-term debt		610,500,000	714,600,000		610,500,000
Early repayment of borrowings			$ (64,500,000)		937,200,000
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						$ 366.3
Price per unit | $ / $			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							$ 400.0
Early redemption penalty	$ 265.0
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	$ 365.0						$ 300.0
Realized foreign exchange (gain) loss		34,800,000			2,800,000
Convertible debentures
Disclosure of information about terms and conditions of hedging instruments and how they affect future cash flows [line items]
Long-term debt		0	$ 0		0			$ 126,600,000
Early repayment of borrowings					126,600,000
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
Long-term debt		109,000,000	173,500,000		109,000,000
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	173,500,000		109,000,000
Interest rate risk		1,100,000	1,700,000		1,100,000
Trade receivables, revenue
Disclosure of information about terms and conditions of hedging instruments and how they affect future cash flows [line items]
Current trade receivables			25,900,000
Join venture receivables and deferred proceeds from dispositions
Disclosure of information about terms and conditions of hedging instruments and how they affect future cash flows [line items]
Current trade receivables			16,900,000
90 days past due
Disclosure of information about terms and conditions of hedging instruments and how they affect future cash flows [line items]
Current trade receivables		$ 17,500,000	$ 5,900,000		$ 17,500,000
2019 | Commodity price risk | Financial Crude Oil Contracts:
Disclosure of information about terms and conditions of hedging instruments and how they affect future cash flows [line items]
Nominal volume (in bbl/d) | bbl			5,000			5,000
Price per unit | $ / bbl			20.88			20.88
2019 | Commodity price risk | Secured Term Sale Agreement - Hardisty | Physical Delivery Contracts
Disclosure of information about terms and conditions of hedging instruments and how they affect future cash flows [line items]
Nominal volume (in bbl/d) | bbl			5,000			5,000
Appointment protected			100.00%			100.00%
Price per unit | $ / bbl			2.00			2.00

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FINANCIAL INSTRUMENTS AND RISK MANAGEMENT - Foreign Exchange Contracts Associated with the Borrowing Obligations (Details) - Dec. 31, 2018 - Currency risk - Foreign currency swap contract £ in Millions, $ in Millions	GBP (£) $ / £ $ / $	USD ($) $ / £ $ / $
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) | $ / £	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) | $ / $	0.75	0.75

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FINANCIAL INSTRUMENTS AND RISK MANAGEMENT - Summary of Balance Sheet and Income Statement Locations of Risk Management Instruments (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Disclosure of detailed information about hedging instruments [line items]
Current portion of risk management assets	$ 3.5	$ 0.0
Non-current portion of risk management assets	4.5	1.9
Current portion of risk management liabilities	(4.2)	(40.0)
Non-current portion of risk management liabilities	0.0	(18.6)
Risk management assets (liabilities)	3.8	(56.7)	$ (56.7)
Unrealized gain (loss) on risk management contracts for the year	60.5	0.0
Realized gain (loss) on risk management contracts for the year	(67.5)	(57.4)
Total unrealized and realized gain (loss) on risk management contracts for the year	(7.0)	(57.4)
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	(4.2)	(39.8)
Non-current portion of risk management liabilities		0.0
Risk management assets (liabilities)	(4.2)	(39.8)	(54.0)
Unrealized gain (loss) on risk management contracts for the year	35.6	14.2
Realized gain (loss) on risk management contracts for the year	(67.5)	(19.8)
Total unrealized and realized gain (loss) on risk management contracts for the year	(31.9)	(5.6)
Foreign exchange contract
Disclosure of detailed information about hedging instruments [line items]
Current portion of risk management assets	3.5
Non-current portion of risk management assets	4.5	1.9
Current portion of risk management liabilities	0.0	(0.2)
Non-current portion of risk management liabilities		(18.6)
Risk management assets (liabilities)	8.0	(16.9)	$ (2.7)
Unrealized gain (loss) on risk management contracts for the year	24.9	(14.2)
Realized gain (loss) on risk management contracts for the year	0.0	(37.6)
Total unrealized and realized gain (loss) on risk management contracts for the year	$ 24.9	$ (51.8)

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FINANCIAL INSTRUMENTS AND RISK MANAGEMENT - Foreign Denominated Term Debt Sensitivity to Foreign Exchange Rate (Details) $ in Millions	Dec. 31, 2018 CAD ($)
Cdn - U.S.
Disclosure of detailed information about hedging instruments [line items]
Net pre-tax impact on Consolidated Statements of Income (Loss)	$ 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)	$ (0.1)

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FINANCIAL INSTRUMENTS AND RISK MANAGEMENT - Summary of Non-current Financial Liabilities & Maturities (Details) - CAD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Disclosure of maturity analysis for financial assets held for managing liquidity risk [line items]
Amount outstanding	$ 714.6	$ 610.5
Year 2
Disclosure of maturity analysis for financial assets held for managing liquidity risk [line items]
Amount outstanding	153.8
Accounts payable
Disclosure of maturity analysis for financial assets held for managing liquidity risk [line items]
Amount outstanding	72.7	136.2
Contractual cash flows	72.7	136.2
Accounts payable | Year 1
Disclosure of maturity analysis for financial assets held for managing liquidity risk [line items]
Contractual cash flows	72.7	136.2
Accounts payable | Year 2
Disclosure of maturity analysis for financial assets held for managing liquidity risk [line items]
Contractual cash flows	0.0	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	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	0.0
Convertible debentures
Disclosure of maturity analysis for financial assets held for managing liquidity risk [line items]
Amount outstanding	0.0	0.0	$ 126.6
Cdn dollar term notes
Disclosure of maturity analysis for financial assets held for managing liquidity risk [line items]
Amount outstanding	20.5	20.5
Contractual cash flows	25.7	27.1
Cdn dollar term notes | Year 1
Disclosure of maturity analysis for financial assets held for managing liquidity risk [line items]
Contractual cash flows	1.4	1.4
Cdn dollar term notes | Year 2
Disclosure of maturity analysis for financial assets held for managing liquidity risk [line items]
Contractual cash flows	1.4	1.4
Cdn dollar term notes | Years 3-5
Disclosure of maturity analysis for financial assets held for managing liquidity risk [line items]
Contractual cash flows	22.9	24.3
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	0.0	0.0
U.S. dollar denominated term notes
Disclosure of maturity analysis for financial assets held for managing liquidity risk [line items]
Amount outstanding	499.5	460.4
Contractual cash flows	619.5	601.3
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	70.7	30.2
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	152.5	65.2
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	169.0	284.0
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	227.3	221.9
U.K. pound sterling denominated term notes
Disclosure of maturity analysis for financial assets held for managing liquidity risk [line items]
Amount outstanding	21.1	20.6
Contractual cash flows	22.0	22.6
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	22.0	1.1
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	0.0	21.5
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	0.0	0.0
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	0.0
Canadian dollar term Credit Facility borrowings
Disclosure of maturity analysis for financial assets held for managing liquidity risk [line items]
Amount outstanding	173.5	109.0	$ 0.0
Contractual cash flows	176.1	117.6
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	176.1	6.9
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	0.0	110.7
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	0.0	0.0
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	0.0	0.0
Finance leases
Disclosure of maturity analysis for financial assets held for managing liquidity risk [line items]
Amount outstanding	33.4	34.2
Contractual cash flows	72.3	76.8
Finance leases | Year 1
Disclosure of maturity analysis for financial assets held for managing liquidity risk [line items]
Contractual cash flows	4.2	4.4
Finance leases | Year 2
Disclosure of maturity analysis for financial assets held for managing liquidity risk [line items]
Contractual cash flows	4.2	4.2
Finance leases | Years 3-5
Disclosure of maturity analysis for financial assets held for managing liquidity risk [line items]
Contractual cash flows	12.6	12.6
Finance leases | More than 5 years
Disclosure of maturity analysis for financial assets held for managing liquidity risk [line items]
Contractual cash flows	51.3	55.6
Foreign exchange risk management contracts
Disclosure of maturity analysis for financial assets held for managing liquidity risk [line items]
Amount outstanding		18.8
Contractual cash flows		20.8
Foreign exchange risk management contracts | Year 1
Disclosure of maturity analysis for financial assets held for managing liquidity risk [line items]
Contractual cash flows		0.2
Foreign exchange risk management contracts | Year 2
Disclosure of maturity analysis for financial assets held for managing liquidity risk [line items]
Contractual cash flows		4.3
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		16.3
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		0.0
Other liabilities
Disclosure of maturity analysis for financial assets held for managing liquidity risk [line items]
Amount outstanding	1.7	2.3
Contractual cash flows	1.7	3.2
Other liabilities | Year 1
Disclosure of maturity analysis for financial assets held for managing liquidity risk [line items]
Contractual cash flows	0.1	0.0
Other liabilities | Year 2
Disclosure of maturity analysis for financial assets held for managing liquidity risk [line items]
Contractual cash flows	0.1	1.4
Other liabilities | Years 3-5
Disclosure of maturity analysis for financial assets held for managing liquidity risk [line items]
Contractual cash flows	0.0	0.3
Other liabilities | More than 5 years
Disclosure of maturity analysis for financial assets held for managing liquidity risk [line items]
Contractual cash flows	1.5	1.5
Commodity risk management contracts
Disclosure of maturity analysis for financial assets held for managing liquidity risk [line items]
Amount outstanding	4.2	39.8
Contractual cash flows	4.2	39.8
Commodity risk management contracts | Year 1
Disclosure of maturity analysis for financial assets held for managing liquidity risk [line items]
Contractual cash flows	4.2	39.8
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	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	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	$ 0.0	$ 0.0

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FINANCIAL INSTRUMENTS AND RISK MANAGEMENT - Summary of Fair Value Amounts (Details) - CAD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial Assets	$ 1,344.2	$ 1,910.9
Financial Liabilities	1,092.3	1,104.7
Carrying amount | U.S. dollar denominated term notes
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial Liabilities	499.5	460.4
Carrying amount | Cdn dollar term notes
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial Liabilities	20.5	20.5
Carrying amount | U.K. pound sterling denominated term notes
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial Liabilities	21.1	20.6
Carrying amount | Fair value of risk management contracts
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial Liabilities	4.2	58.6
Carrying amount | Remediation trust fund
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial Assets	98.0	111.6
Carrying amount | Fair value of risk management contracts
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial Assets	8.0	1.9
Fair value | U.S. dollar denominated term notes
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial Liabilities	533.2	509.5
Fair value | Cdn dollar term notes
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial Liabilities	22.3	22.8
Fair value | U.K. pound sterling denominated term notes
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial Liabilities	21.4	21.7
Fair value | Fair value of risk management contracts
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial Liabilities	4.2	58.6
Fair value | Remediation trust fund
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial Assets	98.0	111.6
Fair value | Fair value of risk management contracts
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial Assets	8.0	1.9
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 fund
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial Assets	98.0	111.6
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) | U.S. dollar denominated term notes
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial Liabilities	533.2	509.5
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	22.3	22.8
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	21.4	21.7
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	4.2	58.6
Fair value | Significant other observable inputs (Level 2) | Remediation trust fund
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	8.0	1.9
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 fund
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	$ 0.0	$ 0.0

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FINANCIAL INSTRUMENTS AND RISK MANAGEMENT - Components of Accounts Receivable (Details) - CAD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Disclosure of detailed information about financial instruments [abstract]
Trade	$ 42.8	$ 92.9

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FINANCIAL INSTRUMENTS AND RISK MANAGEMENT - Risk Management Contracts on the Consolidated Balance Sheets (Details) - CAD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Disclosure of detailed information about hedging instruments [line items]
Current asset	$ 3.5	$ 0.0
Non-current asset	4.5	1.9
Current liability	(4.2)	(40.0)
Non-current liability	0.0	(18.6)
Risk management contracts
Disclosure of detailed information about hedging instruments [line items]
Current asset	3.5	0.0
Non-current asset	4.5	1.9
Current liability	(4.2)	(40.0)
Non-current liability	0.0	(18.6)
Gross derivative amounts	$ 3.8	$ (56.7)

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COMMITMENTS - Summary of Commitments Maturities (Details)	Dec. 31, 2018 CAD ($)
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Operating leases	$ 10.2
Onerous leases	32.3
Pipeline transportation	319.0
Other	18.3
Commitments	379.8
2019
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Operating leases	1.5
Onerous leases	5.1
Pipeline transportation	27.0
Other	13.6
Commitments	47.2
2020
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Operating leases	1.5
Onerous leases	5.3
Pipeline transportation	33.8
Other	0.2
Commitments	40.8
2021
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Operating leases	1.5
Onerous leases	5.2
Pipeline transportation	35.1
Other	0.2
Commitments	42.0
2022
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Operating leases	1.8
Onerous leases	6.0
Pipeline transportation	35.2
Other	0.2
Commitments	43.2
2023
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Operating leases	1.8
Onerous leases	4.9
Pipeline transportation	35.5
Other	0.2
Commitments	42.4
Thereafter
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Operating leases	2.1
Onerous leases	5.8
Pipeline transportation	152.4
Other	3.9
Commitments	$ 164.2

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SUPPLEMENTARY DISCLOSURES - Total Employee Compensation Costs (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Disclosure Of Employee Compensation Expenses [Line Items]
Total employee compensation costs	$ 32.3	$ 65.6
Operating
Disclosure Of Employee Compensation Expenses [Line Items]
Total employee compensation costs	12.3	30.1
General and administrative
Disclosure Of Employee Compensation Expenses [Line Items]
Total employee compensation costs	$ 20.0	$ 35.5

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SUPPLEMENTARY DISCLOSURES - Key Management Personnel Costs (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Disclosure of amounts incurred by entity for provision of key management personnel services provided by separate management entities [line items]
Wages & benefits paid	$ 2.5	$ 2.8
Bonus and other compensation paid	3.7	2.7
Share based compensation expense	3.0	1.3
Severance paid	2.4	0.0
Total	11.6	6.8
Directors
Disclosure of amounts incurred by entity for provision of key management personnel services provided by separate management entities [line items]
Wages & benefits paid	0.5	0.6
Bonus and other compensation paid	0.0	0.0
Share based compensation expense	0.1	(0.6)
Severance paid	0.0	0.0
Total	0.6	0.0
Officers
Disclosure of amounts incurred by entity for provision of key management personnel services provided by separate management entities [line items]
Wages & benefits paid	2.0	2.2
Bonus and other compensation paid	3.7	2.7
Share based compensation expense	2.9	1.9
Severance paid	2.4	0.0
Total	$ 11.0	$ 6.8