40-F

U.S. 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) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended: December 31, 2014 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 2100, 222 Third Avenue S.W.

Calgary, Alberta Canada T2P 0B4

(403) 233-0224

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

Puglisi & Associates

850 Library Avenue, Suite 204

Newark, Delaware 19711

(302) 738-6680

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

of agent for service in the United States)

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

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

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

None

(Title of Class)

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

None

(Title of Class)

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

þ Annual information form þ Audited annual financial statements

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

There were 533,438,177 Common Shares, of no par value, outstanding as of December 31, 2014.

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 and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted 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 and post such files).

Yes o No o

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-3 (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, 2014, 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, 2014, 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 “Auditors’ Report” that accompanies the Registrant’s Consolidated Financial Statements for the fiscal year ended December 31, 2014, 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, 2014, 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: James D. McFarland, Michael S. Parrett, A. Terence Poole and Barry D. Stewart.

AUDIT COMMITTEE FINANCIAL EXPERT

The board of directors of the Registrant has determined that each of Michael S. Parrett and A. Terence Poole, 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. Parrett and Mr. Poole is also independent, as that term is defined in the Corporate Governance Listing Standards of the New York Stock Exchange. The Commission has indicated that the designation of each of Mr. Parrett and Mr. Poole as an audit committee financial expert does not make either of them an “expert” for any purpose, impose any duties, obligations or liabilities on them that are greater than those imposed on members of the audit committee and the board of directors who do not carry this designation or affect the duties, obligations or liabilities of any other member of the audit committee or the board of directors.

ADDITIONAL DISCLOSURE

Code of Ethics.

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

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

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

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

Principal Accountant Fees and Services.

The required disclosure is included under the heading “Principal Accountant Fees and Services” at page 57 of the Registrant’s Annual Information Form for the fiscal year ended December 31, 2014, 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 58 of the Registrant’s Annual Information Form for the fiscal year ended December 31, 2014, 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 59 of the Registrant’s Annual Information Form for the fiscal year ended December 31, 2014, filed as part of this Annual Report on Form 40-F as Exhibit 99.1 hereto.

Tabular Disclosure of Contractual Obligations.

The required disclosure is included under the heading “Commitments and Contractual Obligations” at page 33 of the Registrant’s Management’s Discussion and Analysis for the fiscal year ended December 31, 2014, filed as part of this Annual Report on Form 40-as Exhibit 99.2 hereto.

UNDERTAKING

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

CONSENT TO SERVICE OF PROCESS

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

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

SIGNATURES

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

Date: February 26, 2015	PENGROWTH ENERGY CORPORATION
	By:	/s/ Derek W. Evans
		Name: Derek W. Evans
		Title: President and Chief Executive Officer

EXHIBIT INDEX

Exhibit	Description
99.1	Pengrowth Energy Corporation Annual Information Form for the year ended December 31, 2014
99.2	Management’s Discussion and Analysis
99.3	Consolidated Financial Statements of Pengrowth Energy Corporation, including Management’s Report to Shareholders and the Auditors’ Reports
99.4	Supplemental Unaudited Disclosures about Oil and Gas Producing Activities required under United States Generally Accepted Accounting Principles
99.5	Consent of Independent Registered Public Accounting Firm
99.6	Consent of GLJ Petroleum Consultants Ltd.
99.7	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350
99.8	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350
99.9	Certification of Chief Executive Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934
99.10	Certification of Chief Financial Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934

EX-99.1

nTABLE OF CONTENTS

GLOSSARY OF TERMS AND ABBREVIATIONS	1
CONVERSION	4
PRESENTATION OF OUR FINANCIAL INFORMATION	5
PRESENTATION OF OUR RESERVE AND RESOURCE INFORMATION	5
FORWARD-LOOKING STATEMENTS	5
PENGROWTH ENERGY CORPORATION	7
Introduction	7
General Development of the Business	7
DESCRIPTION OF OUR BUSINESS	8
General	8
Business Strategy	8
OPERATIONAL INFORMATION	9
Principal Producing Properties	9
Statement of Oil and Gas Reserves and Reserves Data	10
Additional Information Relating to Reserves Data	18
Future Development Costs	19
Finding, Development and Acquisition Costs	19
Recycle Ratio	21
Reserve Life Index	22
Reserve Replacement	22
Other Oil and Gas Information	23
Forward Contracts	27
Additional Information Concerning Abandonment & Reclamation Costs	27
Tax Horizon	27
Costs Incurred	27
Exploration and Development Activities	28
Production Estimates	28
Production History (Netback)	29
DESCRIPTION OF CAPITAL STRUCTURE	29
Common Shares	29
Preferred Shares	30
Debentures	30
Stock Exchange Listing	30
DIVIDENDS	30
Historical Dividends	30
Restrictions on Dividends	31
ABCA Solvency Tests	31
Revolving Credit Facility	31
Senior Unsecured Notes	32
INDUSTRY CONDITIONS	33
Pricing and Marketing	33
The North American Free Trade Agreement	33
Royalties and Incentives	34
Land Tenure	38
Production and Operation Regulations	38
Environmental Regulation	39
Liability Management Rating Programs	40
Climate Change Regulation	41
RISK FACTORS	43
MARKET FOR SECURITIES	54
DIRECTORS AND OFFICERS	54
Corporate Cease Trade Orders, Bankruptcies, Personal Bankruptcies, Penalties or Sanctions	56
AUDIT AND RISK COMMITTEE	57
Principal Accountant Fees and Services	57

PENGROWTH ENERGY CORPORATION ANNUAL INFORMATION FORM

Pre-approval Policies and Procedures	58
CONFLICTS OF INTEREST	58
LEGAL PROCEEDINGS	58
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS	59
INTERESTS OF EXPERTS	59
AUDITORS, TRANSFER AGENT AND REGISTRAR	59
MATERIAL CONTRACTS	59
CODE OF ETHICS	59
OFF-BALANCE SHEET ARRANGEMENTS	59
DISCLOSURE PURSUANT TO THE REQUIREMENTS OF THE NEW YORK STOCK EXCHANGE	60
ADDITIONAL INFORMATION	60
APPENDIX A - Report on Reserves Data by Independent Qualified Reserves Evaluator on Form 51-101F2
APPENDIX B - Report of Management and Directors on Oil and Gas Disclosure on Form 51-101F3
APPENDIX C - 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, 2014.

GLOSSARY OF TERMS AND ABBREVIATIONS

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

Corporate

"6.25% Series A Convertible Debentures" means the $115 million original aggregate principal amount of 6.25 percent convertible unsecured subordinated debentures of the Corporation due December 31, 2014, which are convertible at the option of the holder, at any time, into fully paid Common Shares at a conversion price of $19.1860 per Common Share;

"6.25% Series B Convertible Debentures" means the $150 million original aggregate principal amount of 6.25 percent convertible unsecured subordinated debentures of the Corporation due March 31, 2017, which are convertible at the option of the holder, at any time, into fully paid Common Shares at a conversion price of $11.5116 per Common Share;

"2005 Note Purchase Agreements" means, collectively, the separate and several note purchase agreements each dated December 1, 2005 among us and the purchasers listed therein, as amended;

"2007 Note Purchase Agreements" means, collectively, the separate and several note purchase agreements each dated July 26, 2007 among us and the purchasers listed therein, as amended;

"2007 US Senior Notes" means the senior unsecured notes issued under the 2007 Note Purchase Agreement;

"2008 Note Purchase Agreements" means, collectively, the separate and several note purchase agreements dated August 21, 2008 among us and the purchasers listed therein, as amended;

"2008 Senior Notes" means the senior unsecured notes issued under the 2008 Note Purchase Agreements;

"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 US$187 million 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 US$385 million equivalent of senior unsecured notes issued from time to time under the 2012 Note Purchase Agreements;

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

"Arrangement" means the plan of arrangement involving the Trust, Pengrowth Corporation, Esprit Energy Trust, Pengrowth Holding Trust, 1552168 Alberta Ltd., Monterey Exploration Ltd., the Corporation, the Unitholders and the holders of Exchangeable Shares completed on January 1, 2011 under the ABCA pursuant to which, the Trust converted from an income trust to a corporate structure;

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

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

"Common Shares" means our common shares;

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

"Credit Facility" refers to Pengrowth's $1.0 billion extendible revolving term credit facility syndicated among eleven financial institutions;

"Exchangeable Shares" means the series A exchangeable shares of Pengrowth Corporation;

"NAL Energy" means NAL Energy Corporation;

"Pengrowth Trust Indenture" refers to the amended and restated trust indenture of the Trust dated July 1, 2009;

"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;

"Trust" refers to Pengrowth Energy Trust, a trust formed pursuant to the laws of Alberta pursuant to the Pengrowth Trust Indenture which was acquired by the Corporation on December 31, 2010 in connection with the Arrangement and subsequently wound up. All references to the "Trust", unless the context otherwise requires, are references to Pengrowth Energy Trust, its predecessors and subsidiaries;

PENGROWTH ENERGY CORPORATION ANNUAL INFORMATION FORM | 1

"Trust Units" refers to the trust units of the Trust created and issued pursuant to the Pengrowth Trust Indenture;

"UK Senior Notes" means the senior unsecured notes issued under the 2005 Note Purchase Agreements; and

"Unitholders" refers to holders of Trust Units and class A trust units, as the context requires.

Engineering

"Bitumen" refers to a naturally occurring viscous mixture consisting mainly of pentanes and heavier hydrocarbons. Its viscosity is greater than 10,000 mPa-s (cp) measured at original temperature in the reservoir and atmospheric pressure, on a gas-free basis. Crude bitumen may contain sulphur and other non-hydrocarbon compounds;

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

"Contingent Resources" are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. 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;

"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;

"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" refers to the estimated net amount to be received with respect to the development and production of reserves computed by deducting, from estimated future revenues, estimated future royalty obligations, costs related to the development and production of reserves and abandonment and reclamation costs (corporate general and administrative expenses and financing costs are not deducted);

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

"GLJ Report" refers to the reserve report prepared by GLJ, dated February 25, 2015 with an effective date of December 31, 2014;

"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;

"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;

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

"Possible Reserves" are those additional reserves that are less certain to be recovered than Probable Reserves. There is a ten percent probability that the quantities actually recovered will equal or exceed the sum of Proved Plus Probable plus Possible Reserves;

"Probable Reserves" refers to 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;

"Proved Developed Producing Reserves" refers to those reserves 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;

"Proved 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; the developed category may be subdivided into Proved Developed Producing Reserves and Developed Non‑Producing Reserves;

"Proved Reserves" refers to 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;

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

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

2 | ANNUAL INFORMATION FORM

"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);

"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;

"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;

"API" refers to the American Petroleum Institute;

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

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

"bbl/d" refers to barrels per day;

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

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

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

"Cdn$" refers to Canadian dollars;

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

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

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

"EIA"refers to Environmental Impact Assessment;

"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;

PENGROWTH ENERGY CORPORATION ANNUAL INFORMATION FORM | 3

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

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

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

"MMBtu" refers to million British thermal units;

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

"MW" refers to megawatts;

"NGL" refers to natural gas liquids;

"NYSE" refers to the New York Stock Exchange;

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

"RLI" refers to Reserve Life Index;

"SAGD" refers to steam assisted gravity drainage;

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

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

"TSX" refers to the Toronto Stock Exchange;

"US$" refers to United States dollars;

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

"WCS" refers to Western Canada Select;

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

"WTI" refers to West Texas Intermediate crude oil.

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

CONVERSION

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

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

4 | ANNUAL INFORMATION FORM

PRESENTATION OF OUR FINANCIAL INFORMATION

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

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

PRESENTATION OF OUR RESERVE AND RESOURCE INFORMATION

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

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

FORWARD-LOOKING STATEMENTS

This Annual Information Form contains forward-looking statements within the meaning of securities laws, including the "safe harbour" provisions of Canadian securities legislation and the United States Private Securities Litigation Reform Act of 1995. Forward-looking information is often, but not always, identified by the use of words such as "anticipate", "believe", "expect", "plan", "intend", "forecast", "target", "project", "guidance", "may", "will", "should", "could", "estimate", "predict" or similar words suggesting future outcomes or language suggesting an outlook. Forward-looking statements in this Annual Information Form include, but are not limited to: business strategy and strengths, goals, focus and the effects thereof, acquisition criteria, capital expenditures, reserves, resources, reserve life indices, estimated production, production additions from our 2015 development program, remaining producing reserves lives, operating expenses, asset retirement obligations, royalty rates, net present values of Future Net Revenue from reserves, commodity prices and costs, dividend policy, exchange rates, the impact of contracts for commodities, development plans and programs, Future Development Costs and the funding thereof, tax horizon, future income taxes, Lindbergh development plans, Bernadet development plans, abandonment and reclamation costs, return of bank debt covenants to original levels after December 31, 2015, contribution of expected Lindbergh production to EBITDA and expiring acreage. Statements relating to reserves and resources are forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions that the reserves and resources described exist in the quantities predicted or estimated and can profitably be produced in the future.

Forward-looking statements and information are based on our current beliefs as well as assumptions made by, and information currently available to, us concerning anticipated financial performance, business prospects, strategies, regulatory developments, future oil and natural gas commodity prices and differentials between light, medium and heavy oil prices, future oil and natural gas production levels, future exchange rates, the proceeds of anticipated divestitures, the amount of future cash dividends paid by the Corporation, the cost of expanding our property holdings, our ability to obtain equipment in a timely manner to carry out development activities, our ability to market our oil and gas successfully to current and new customers, the impact of increasing competition, our ability to obtain financing on acceptable terms, and our ability to add production and reserves through our acquisition, development and exploration activities. Although management considers these assumptions to be reasonable based on information currently available to it, they may prove to be incorrect.

By their very nature, forward-looking statements involve inherent risks and uncertainties, both general and specific, and risks that predictions, forecasts, projections and other forward-looking statements will not be achieved. We caution readers not to place undue reliance on these statements as a number of important factors could cause the actual results to differ materially from the beliefs, plans, objectives, expectations and anticipations, estimates and intentions expressed in such forward-looking statements. These factors include, but are not limited to: the volatility of oil and gas prices; production and development costs and capital expenditures; the imprecision of reserve estimates and estimates of recoverable quantities of oil, natural gas and liquids; unforeseen operating problems; pipeline or delivery

PENGROWTH ENERGY CORPORATION ANNUAL INFORMATION FORM | 5

constraints; our ability to replace and expand oil and gas reserves; environmental claims and liabilities; incorrect assessments of value when making acquisitions; increases in debt service charges; the loss of key personnel; the marketability of production; defaults by third party operators; unforeseen title defects; fluctuations in foreign currency and exchange rates; inadequate insurance coverage; counterparty risk; compliance with environmental laws and regulations; changes in tax and royalty laws; our ability to access external sources of debt and equity capital; and the implementation of GHG emissions legislation. Further information regarding these factors may be found under the heading "Risk Factors" in this Annual Information Form, under the heading "Business Risks" in our Management's Discussion and Analysis for the year ended December 31, 2014, and in our most recent consolidated financial statements, management information circular, quarterly reports, material change reports and news releases.

Readers are cautioned that the foregoing list of factors that may affect future results is not exhaustive. When relying on our forward‑looking statements to make decisions with respect to Pengrowth, investors and others should carefully consider the foregoing factors and other uncertainties and potential events. Furthermore, the forward-looking statements contained in this Annual Information Form are made as of the date of this document and we do not undertake any obligation to update publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise, except as required by applicable law. The forward-looking statements contained in this Annual Information Form are expressly qualified by this cautionary statement.

6 | ANNUAL INFORMATION FORM

nPENGROWTH ENERGY CORPORATION

INTRODUCTION

The Corporation is engaged in the development, production and acquisition of, and the exploration for, oil and natural gas reserves in the provinces of Alberta, British Columbia, Saskatchewan and Nova Scotia. The Corporation amalgamated with its wholly-owned subsidiaries NAL Energy, NAL Properties Inc. and NAL Canada West Inc. on January 1, 2013. The Corporation originally acquired NAL Energy on May 31, 2012 and the results and information contained in this Annual Information Form include results and information pertaining to NAL Energy from that date. The Corporation is also the successor to the Trust, following the completion of the conversion of the Trust from an income trust to a corporate structure pursuant to the Arrangement which was completed on January 1, 2011.

The Corporation was originally incorporated pursuant to the ABCA on October 4, 2010, as 1562803 Alberta Ltd. and changed its name to Pengrowth Energy Corporation on December 2, 2010.

The head office and registered office of the Corporation is located at 2100, 222 – 3rd Avenue S.W., Calgary, Alberta, Canada, T2P 0B4.

GENERAL DEVELOPMENT OF THE BUSINESS

Recent Developments

On January 21, 2015, we announced our 2015 capital program and provided guidance on 2015 expected production and costs. We also announced a reduction in our monthly dividend from $0.04 per share to $0.02 per share beginning with the dividend payable on March 16, 2015. Our 2015 capital budget reflects our plan to spend between $190 million and $210 million in 2015.

Three Year Historical Overview

2014

On December 31, 2014, our 6.25% Series A Convertible Debentures matured.

On December 15, 2014, we announced the commencement of steam injection at our Lindbergh commercial project.

On December 1, 2014, we announced the appointment of Margaret Byl to our Board.

On November 5, 2014, we acquired a 100 percent interest in 32.6 sections of Montney prospective lands at Bernadet in northeastern British Columbia for $123.6 million.

On June 24, 2014, we announced a reserve evaluation update, effective May 31, 2014, with respect to our Lindbergh property, noting a 24 percent increase in Proved Reserves and a 61 percent increase in Total Proved Plus Probable Reserves from December 31, 2013.

On January 24, 2014, we amended our credit facility by increasing the maximum permitted consolidated senior debt to EBITDA ratio from 3.0 to 3.5 and the consolidated total debt to EBITDA ratio from 3.5 to 4.0 until December 31, 2015. The ratios revert back to their prior permitted levels of 3.0 and 3.5, respectively, after December 31, 2015.

On January 16, 2014, we announced our 2014 capital program and provided guidance on 2014 expected production and costs. Our 2014 capital budget reflected our plan to spend between $700 million and $730 million in 2014 including $365 million at Lindbergh.

2013

On September 9, 2013, we announced the closing of our southeast Saskatchewan asset disposition for proceeds of $510 million prior to closing adjustments.

On July 23, 2013, we renewed our $1 billion credit facility until July 26, 2017.

On July 15, 2013, we announced that we received EPEA approval for the 12,500 bbl/d first commercial phase of our Lindbergh thermal project. We also released a reserve update with respect to our Lindbergh property, noting the reclassification of 69.2 MMbbl of Probable Reserves to Proved Reserves and an increase of 48.1 MMbbl in P+P reserves.

On March 11, 2013, we announced the completion of the sale of the Weyburn Unit disposition for proceeds of approximately $316 million net of interim closing adjustments.

On January 11, 2013, we announced our 2013 capital program as well as the sanctioning of the initial 12,500 bbl/d commercial phase of our Lindbergh thermal project. Our 2013 capital budget reflected our plan to spend up to $770 million in 2013 including $300 million at Lindbergh. The budget also contemplated up to $700 million of asset dispositions in addition to the Weyburn disposition.

PENGROWTH ENERGY CORPORATION ANNUAL INFORMATION FORM | 7

On January 1, 2013, the Corporation amalgamated with its wholly-owned subsidiaries NAL Energy, NAL Properties Inc. and NAL Canada West Inc.

2012

On December 21, 2012, we announced the sale of our 10.01952 percent interest in the Weyburn Unit property to OMERS Energy Inc. and Ontario Teachers’ Pension Plan for total gross proceeds of $315 million. The effective date of the disposition was January 1, 2013.

On October 18, 2012, we issued the 2012 Senior Notes. The notes were issued in five series; US$35 million of 3.49 percent notes due in 2019; US$10.5 million of 4.07 percent notes due in 2022; US$195 million of 4.17 percent notes due in 2024; £15 million of 3.45 percent notes due in 2019; and Cdn$25 million of 4.74 percent notes due in 2022.

On May 31, 2012, we completed the acquisition of NAL Energy for total consideration of approximately $1.6 billion comprised of 131,239,234 Common Shares and $344,744,000 of assumed debt. In connection with this acquisition, Messrs. Kelvin B. Johnston and Barry D. Stewart joined our Board. A business acquisition report (Form 51-102F4) was filed on SEDAR.com in respect of this acquisition on August 10, 2012.

In early February 2012, we commenced the injection of steam at our Lindbergh pilot project.

On January 24, 2012, we released the details of our $625 million 2012 capital expenditure program and provided guidance on production and operating costs for 2012. Our 2012 capital program focused on oil and liquids-rich gas opportunities.

DESCRIPTION OF OUR BUSINESS

GENERAL

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

As at December 31, 2014, we had 569 permanent employees.

BUSINESS STRATEGY

Our corporate strategy is to build a sustainable dividend paying entity through the acquisition and development of large accumulations of oil, bitumen and natural gas with low declines and low cost structures.

Our operational expertise is in the WCSB. We rely on our expertise to partially offset production declines in our mature oil and gas properties as well as develop new production in less mature oil and gas properties. We continue to develop our significant expertise in horizontal well multi-stage fracturing technology, EOR technologies and waterflood optimization. Additionally, we have assembled a highly skilled team experienced in thermal development. Our inventory of undeveloped land and opportunities on our properties provide future drilling opportunities for the short-term and mid-term. In the mid-term, we anticipate continuing to develop our thermal project at Lindbergh, with the potential for 40,000 to 50,000 bbl/d of bitumen, as well as our light oil and liquids-rich gas properties in the Greater Olds/Garrington and Swan Hills areas. See additional details on these properties under “Operational Information – Principal Producing Properties” below.

For 2015, we have established a $190 million to $210 million capital spending level that reflects the current low and volatile commodity price environment. Our 2015 capital budget represents a 74 percent decrease from our 2014 capital budget and is focused on maintenance and integrity of existing assets and optimizing the first commercial phase of our Lindbergh project. In general, we prioritize our capital investments based on:

• Recycle Ratio;

• net present value of future cash flow as compared to the capital invested;

• rate of return of future cash flows;

• potential for continued, repeatable and scalable development; and

• investments necessary to maintain existing facilities and wells.

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.

8 | ANNUAL INFORMATION FORM

OPERATIONAL INFORMATION

PRINCIPAL PRODUCING PROPERTIES

The following table summarizes our principal producing properties as of December 31, 2014 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, 2014. The table also contains our average daily production of oil, natural gas and NGL for the year ended December 31, 2014.

Summary of Company Interest at December 31, 2014⁽¹⁾
(Forecast Prices and Costs)⁽²⁾ 

	P+P	Remaining	P+P Reserve	P+P Value Before Tax	2014 Oil	2014 Gas	2014 NGL	2014 Total
	Reserves	Reserve Life	Life Index	Discounted at 10%(4)	Production	Production	Production	Production
Field	(Mboe(3))	(years)	(years)	($MM)	(bbl/d)	(MMcf/d)	(bbl/d)	(BOE/d(3))
Lindbergh	243,338	30	72.9	2,061	1,685	-	-	1,685
Greater Olds/Garrington Area	72,933	50	15.0	933	9,212	11.8	3,480	14,662
Swan Hills Area	68,746	50	10.8	850	6,307	56.0	3,933	19,573
Subtotal	385,017	50	26.4	3,844	17,204	67.8	7,413	35,920
Remainder(5)	172,333	50	12.7	1,415	12,275	134.3	2,717	37,368
Total	557,350	50	19.8	5,259	29,479	202.1	10,130	73,288

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 approximately 112 other properties.

Lindbergh

Our Lindbergh property is located approximately 420 kilometres north east of Calgary, Alberta and 50 kilometres south of Bonnyville, Alberta. We have a 100 percent Working Interest in the Lindbergh oil sands leases, located in the Cold Lake oil sands district in northeastern Alberta and covering 20,800 net acres (32.5 sections). Our Lindbergh area assets include our 100 percent Working Interest Muriel Lake lands which are about eight kilometres to the north east of the Lindbergh lease and comprise an additional 6,400 net acres (10 sections).

We began steam injection into the SAGD pilot project in early February 2012 and results have outperformed expectations since that time. The pilot, which consists of two well pairs, has been producing for close to three years and, as of January 15, 2015, was producing approximately 1,600 bbl/d of bitumen, with an ISOR of approximately 2.8. The two well pair pilot has produced approximately 1.6 million bbl of bitumen as of December 31, 2014.

The excellent pilot results and associated reserve potential have provided us with the confidence needed to accelerate and expand the first phase of commercial development. On January 10, 2013, our Board of Directors approved the first phase of Lindbergh commercial development, which is anticipated to reach 16,000 bbl/d of bitumen by the end of 2015.

In July 2013, the project received regulatory approval to proceed under the EPEA application number 1713445. Once surface dispositions were received, civil construction commenced in August 2013 preparing leases and roads for the project. SAGD drilling and mechanical construction activities began in September 2013. In December 2014, the commercial project commenced steam injection into the first of three well-pads. Steam injection into the second and third well-pads commenced in January 2015.

The Phase 2 expansion to 30,000 bbl/day of capacity is expected to recover 243.3 MMbbl of Total Proved Plus Probable Reserves from a total of 228 well pairs including the two existing pilot well pairs. Given the strong pilot results, additional productivity is thought to be possible and anticipated from Phase 1 and Phase 2. There is also potential for further expansion to attain 40,000 to 50,000 bbl/d over all the Pengrowth lands in the Lindbergh region. The EIA application for the first of these expansions to 30,000 bbl/d was submitted in December 2013. Approval for the expansion is anticipated in the first quarter of 2016.

For additional information, see “Lindbergh Oil Sands Reserves and Contingent Resources” on page 23 of this Annual Information Form.

Greater Olds/Garrington Area

Our Greater Olds/Garrington area is located approximately 100 kilometres north of Calgary, Alberta. Our interests in this area include a 100 percent ownership of the Olds Gas Field Unit No. 1. In addition, we have an 87 percent average Working Interest in the adjacent non-unit reserves. The Olds Gas Field Unit No. 1 produces sour natural gas from the Wabamun formation, with H₂S concentrations ranging from less than one percent to 35 percent. The non-unit reserves are contained within formations from the Wabamun to the Edmonton group, and are predominantly sweet natural gas.

PENGROWTH ENERGY CORPORATION ANNUAL INFORMATION FORM | 9

The Greater Olds/Garrington area is characterized by stacked reservoirs with multi-zone potential. Pengrowth has been exploiting several development opportunities over the past three years in the Harmattan gas field, including the development of our liquids-rich (50 bbl/MMcf) Elkton gas play and more recently, the liquids-rich (90 bbl/MMcf) Mannville gas play.

We operate and own 100 percent of the sour gas processing plant at Olds, Alberta, which processes both our production and third party volumes. Third party volumes represent approximately 35 percent of the total volumes processed at the plant.

With the significant reduction in oil and gas prices, capital for 2015 has been significantly reduced in the Greater Olds/Garrington area. We have a large contiguous land base in this area with approximately 500 gross sections with Cardium rights, averaging approximately 50 percent Working Interest. In addition to the Cardium, other zones of interest in the area include the liquids-rich Mannville and Elkton formations. In 2014, we spent $170 million in the Greater Olds/Garrington area on activities targeting the Cardium, Mannville, and Elkton plays, drilling 71 gross wells (42.4 net) during the year.

In 2014, the bulk of our drilling activity was focused on developing Cardium oil production in the Lochend and Garrington fields in the Greater Olds/Garrington area. Our drilling and completion expertise in these fields continues to deliver results that exceed type curve expectations.

The Harmattan gas field, within the Greater Olds/Garrington area, is located approximately 90 kilometres northwest of Calgary, Alberta. It is comprised of wells and pools in formations from the Wabamun to the Cardium, as well as two partner-operated Elkton units. The production is predominantly sweet liquids-rich natural gas and sweet oil with Working Interests averaging 65 percent in the non-unit lands (operated) and 25 percent in the partner-operated units.

Swan Hills Area

We have varied Working Interests within the Swan Hills area in all of the key properties throughout this significant regional Beaverhill Lake resource base. These are both operated and non-operated, unit and non-unit properties in Judy Creek, Carson Creek, House Mountain, Deer Mountain, Swan Hills, South Swan Hills and Freeman. The properties are primarily located approximately 200 kilometres northwest of Edmonton, Alberta.

The two major operated properties in the area are:

• The Judy Creek Beaverhill Lake Unit and the Judy Creek West Beaverhill Lake Unit are both oil properties (together referred to as "Judy Creek"), where we have a 100 percent Working Interest in both. Judy Creek covers an area of approximately 38,300 acres, was discovered in 1959, placed on waterflood in 1962 and hydrocarbon miscible flood in 1985. We also have a 54.4 percent Working Interest in and operate the Judy Creek Gas Conservation Plant that services a number of other properties in the area including Swan Hills, Virginia Hills and South Swan Hills.

• Carson Creek is comprised of two Pengrowth operated units (one oil and one natural gas) covering approximately 46,200 acres. The Carson Creek North Beaverhill Lake Unit No. 1, in which we have a 90.6 percent Working Interest, was discovered in 1958 and the current waterflood was initiated in 1964. The Carson Creek Beaverhill Lake Unit No. 1, in which we have a 95.1 percent Working Interest, was discovered in 1958.

In 2014, $42.5 million (net) was spent on light oil plays in this area. Key focuses were further miscible flood development and waterflood optimization. Pengrowth drilled a total of four operated wells (four net) at Judy Creek. These were split between three injectors (two miscible flood and one waterflood) and one oil producer.

STATEMENT OF OIL AND GAS RESERVES AND RESERVES DATA

Disclosure of Reserves Data

The information in this section is based upon an evaluation by GLJ, prepared in accordance with NI 51-101, with an effective date of December 31, 2014 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, 2014 and the preparation date is January 19, 2015 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 and no attempt was made to evaluate Possible Reserves in our non-thermal 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. All of our reserves are in Canada in the provinces of Alberta, British Columbia, Saskatchewan and Nova Scotia. In certain instances in this Annual Information Form, we have presented estimates of reserves, Future Net Revenue and Contingent Resources for individual properties. The estimates of reserves, Future Net Revenue and Contingent Resources for individual properties may not reflect the same confidence level as estimates of reserves, Future Net Revenue and Contingent Resources for all properties, due to the effects of aggregation.

The following tables set forth certain information relating to our oil and natural gas reserves and the net present value of the estimated Future Net Revenue associated with such reserves as at December 31, 2014 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 may not add due to rounding.

10 | ANNUAL INFORMATION FORM

Our Future Net Revenues associated with the production and reserves contained in this Annual Information Form reflect the royalty programs in-place on December 31, 2014.

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 future well abandonment obligations but does not include estimates of remediation costs. 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 $3.98 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 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 by Independent Qualified Reserves Evaluator in Form 51-101F2 and the Report of Management and Directors on Oil and Gas Disclosure in Form 51-101F3 are attached to this Annual Information Form as Appendices A and B, respectively.

PENGROWTH ENERGY CORPORATION ANNUAL INFORMATION FORM | 11

Reserves Data (Forecast Prices and Costs)

Summary of Oil and Gas Reserves as of December 31, 2014
(Forecast Prices and Costs)⁽¹⁾ 

	Light and Medium Oil			Heavy Oil			Bitumen			Natural Gas Liquids
	Company Interest	Gross Interest	Net Interest	Company Interest	Gross Interest	Net Interest	Company Interest	Gross Interest	Net Interest	Company Interest	Gross Interest	Net Interest
Reserves Category	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)
Proved Reserves
Proved Developed Producing	50,395	50,304	40,977	12,627	12,618	10,935	829	829	795	22,873	22,833	16,541
Proved Developed Non-Producing	800	800	679	113	113	79	25,906	25,906	21,849	575	573	444
Proved Undeveloped	13,137	13,137	10,346	5,484	5,483	4,505	77,113	77,113	59,131	832	832	698
Total Proved Reserves	64,331	64,241	52,003	18,224	18,214	15,519	103,848	103,848	81,775	24,279	24,238	17,683
Probable Reserves	27,364	27,332	21,263	11,047	11,045	8,978	139,490	139,490	107,826	9,983	9,968	7,381
Total Proved Plus Probable Reserves	91,695	91,574	73,265	29,272	29,259	24,497	243,338	243,338	189,601	34,261	34,206	25,064

	Natural Gas			Coal Bed Methane			Total Oil Equivalent Basis(2)
	Company Interest	Gross Interest	Net Interest	Company Interest	Gross Interest	Net Interest	Company Interest	Gross Interest	Net Interest
Reserves Category	(MMcf)	(MMcf)	(MMcf)	(MMcf)	(MMcf)	(MMcf)	(Mboe)	(Mboe)	(Mboe)
Proved Reserves
Proved Developed Producing	468,905	467,104	404,859	18,722	18,448	17,265	167,994	167,510	139,603
Proved Developed Non-Producing	17,848	17,749	14,913	1,251	1,251	1,209	30,576	30,558	25,738
Proved Undeveloped	66,687	66,686	59,333	22,800	22,728	19,534	111,480	111,467	87,824
Total Proved Reserves	553,439	551,539	479,105	42,773	42,426	38,008	310,051	309,535	253,165
Probable Reserves	343,775	343,061	296,930	12,712	12,614	11,378	247,299	247,115	196,833
Total Proved Plus Probable Reserves	897,214	894,600	776,035	55,485	55,040	49,386	557,350	556,650	449,998

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.

Summary of Net Present Value of Future Net Revenue as of December 31, 2014
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	3,456		2,511		1,965		1,616		1,376		14.08	2.35
Proved Developed Non-Producing	839		700		598		520		458		23.24	3.87
Proved Undeveloped	3,283		1,636		875		488		276		9.96	1.66
Total Proved Reserves	7,578		4,846		3,438		2,624		2,109		13.58	2.26
Probable Reserves	7,238		3,442		1,820		1,031		607		9.25	1.54
Total Proved Plus Probable Reserves	14,816		8,288		5,259		3,656		2,716		11.69	1.95

	After Income Taxes Discounted at (%/year)(4) - $MM
Reserves Category	0	%	5	%	10	%	15	%	20	%
Proved Reserves
Proved Developed Producing	3,456		2,511		1,965		1,616		1,376
Proved Developed Non-Producing	834		698		597		519		458
Proved Undeveloped	2,368		1,217		668		379		215
Total Proved Reserves	6,658		4,426		3,230		2,515		2,048
Probable Reserves	5,296		2,522		1330		746		429
Total Proved Plus Probable Reserves	11,954		6,948		4,561		3,261		2,477

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

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Additional Information Concerning Future Net Revenue (undiscounted) as of December 31, 2014
(Forecast Prices and Costs)⁽¹⁾ ($MM)

Reserves Category	Revenue	Royalties(2)	Operating Costs	Development Costs	Abandonment Costs(3)	Future Net Revenue Before Income Taxes	Income Tax	Future Net Revenue After Income Taxes
Total Proved	21,524	4,066	7,572	1,944	363	7,578	920	6,658
Total Proved Plus Probable	41,550	8,386	12,937	4,957	455	14,816	2,862	11,954

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 estimate of well abandonment costs and abandonment of Sable Island facilities and subsea pipelines, but does not include abandonment costs for other facilities or any surface reclamation costs. See "Pengrowth – Operational Information – Additional Information Concerning Abandonment & Reclamation Costs".

Net Present Value of Future Net Revenue By Production Group as of December 31, 2014
(Forecast Prices and Costs)⁽¹⁾ 

		Future Net Revenue Before Income Taxes (discounted at 10%/year)	Unit Value(4)(5)
Reserves Category	Production Group	($MM)	($/BOE)	($/McfGE)
Total Proved	Light and Medium Crude Oil (including solution gas and other by-products)(2)	1,308	18.17	3.03
	Heavy Oil (including solution gas and other by-products)(2)	325	20.22	3.37
	Bitumen	1184	14.47	2.41
	Natural Gas (including by-products but excluding solution gas from oil wells)(3)	593	7.71	1.28
	Non-conventional Oil & Gas Activities	28	4.39	0.73
	Total	3,438	13.58	2.26
Total Proved Plus Probable	Light and Medium Crude Oil (including solution gas and other by-products)(2)	1,753	17.14	2.86
	Heavy Oil (including solution gas and other by-products)(2)	512	20.30	3.38
	Bitumen	2,070	10.91	1.82
	Natural Gas (including by-products but excluding solution gas from oil wells)(3)	885	7.10	1.18
	Non-conventional Oil & Gas Activities	40	4.81	0.80
	Total	5,259	11.69	1.95

Notes:

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

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

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

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

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

PENGROWTH ENERGY CORPORATION ANNUAL INFORMATION FORM | 13

Reserves Data (Constant Prices and Costs)

Summary of Oil and Gas Reserves as of December 31, 2014
(Constant Prices and Costs)⁽¹⁾ 

	Light and Medium Oil			Heavy Oil			Bitumen			Natural Gas Liquids
	Company Interest	Gross Interest	Net Interest	Company Interest	Gross Interest	Net Interest	Company Interest	Gross Interest	Net Interest	Company Interest	Gross Interest	Net Interest
Reserves Category	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)
Proved Reserves
Proved Developed Producing	51,252	51,161	42,296	12,870	12,861	11,029	829	829	770	23,077	23,037	16,691
Proved Developed Non-Producing	823	823	706	122	122	88	25,906	25,906	20,779	525	523	395
Proved Undeveloped	13,549	13,549	10,872	5,452	5,451	4,497	77,082	77,082	60,508	899	899	755
Total Proved Reserves	65,625	65,534	53,873	18,444	18,434	15,614	103,817	103,817	82,058	24,500	24,459	17,841
Probable Reserves	27,541	27,509	22,449	11,127	11,125	9,147	139,522	139,522	110,240	10,413	10,398	7,726
Total Proved Plus Probable Reserves	93,165	93,043	76,322	29,571	29,559	24,762	243,338	243,338	192,298	34,913	34,857	25,567

	Natural Gas			Coal Bed Methane			Total Oil Equivalent Basis(2)
	Company Interest	Gross Interest	Net Interest	Company Interest	Gross Interest	Net Interest	Company Interest	Gross Interest	Net Interest
Reserves Category	(MMcf)	(MMcf)	(MMcf)	(MMcf)	(MMcf)	(MMcf)	(Mboe)	(Mboe)	(Mboe)
Proved Reserves
Proved Developed Producing	481,473	479,579	416,130	18,757	18,483	17,300	171,399	170,898	143,024
Proved Developed Non-Producing	16,111	16,026	13,257	1,249	1,249	1,208	30,269	30,253	24,379
Proved Undeveloped	67,182	67,181	59,361	21,085	21,040	18,005	111,693	111,684	89,527
Total Proved Reserves	564,765	562,785	488,748	41,091	40,772	36,513	313,361	312,836	256,930
Probable Reserves	344,500	343,789	298,253	14,129	14,038	12,640	248,374	248,192	201,377
Total Proved Plus Probable Reserves	909,265	906,574	787,001	55,220	54,811	49,153	561,735	561,027	458,307

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, 2014
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	3,902		2,997		2,456		2,097		1,842		17.17	2.86
Proved Developed Non-Producing	960		819		713		630		564		29.23	4.87
Proved Undeveloped	2,721		1,421		797		469		282		8.90	1.48
Total Proved Reserves	7,583		5,236		3,965		3,196		2,687		15.43	2.57
Probable Reserves	5,843		2,953		1,660		1,003		635		8.24	1.37
Total Proved Plus Probable Reserves	13,426		8,189		5,625		4,198		3,322		12.27	2.05

	After Income Taxes Discounted at (%/year)(4)  - $MM
Reserves Category	0	%	5	%	10	%	15	%	20	%
Proved Reserves
Proved Developed Producing	3,902		2,997		2,456		2,097		1,842
Proved Developed Non-Producing	817		754		681		613		554
Proved Undeveloped	1,990		1,039		581		337		197
Total Proved Reserves	6,709		4,790		3,717		3,047		2,594
Probable Reserves	4,331		2,181		1216		723		448
Total Proved Plus Probable Reserves	11,039		6,971		4,933		3,771		3,041

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

14 | ANNUAL INFORMATION FORM

Additional Information Concerning Future Net Revenue (undiscounted) as of December 31, 2014
(Constant Prices and Costs)⁽¹⁾ ($MM)

Reserves Category	Revenue	Royalties(2)	Operating Costs	Development Costs	Abandonment Costs(3)	Future Net Revenue Before Income Taxes	Income Tax	Future Net Revenue After Income Taxes
Total Proved	19,332	3,458	6,334	1,662	295	7,583	874	6,709
Total Proved Plus Probable	34,580	6,416	10,203	4,191	344	13,426	2,387	11,039

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 estimate of well abandonment costs and abandonment of Sable Island facilities and subsea pipelines, but does not include abandonment costs for other facilities or any surface reclamation costs. See "Pengrowth – Operational Information – Additional Information Concerning Abandonment & Reclamation Costs".

Net Present Value of Future Net Revenue By Production Group as of December 31, 2014
(Constant Prices and Costs)⁽¹⁾ 

		Future Net Revenue Before Income Taxes (discounted at 10%/year)	Unit Value(4)(5)
Reserves Category	Production Group	($MM)	($/BOE)	($/McfGE)
Total Proved	Light and Medium Crude Oil (including solution gas and other by-products)(2)	1,547	20.85	3.48
	Heavy Oil (including solution gas and other by-products)(2)	418	25.78	4.30
	Bitumen	1,205	14.67	2.45
	Natural Gas (including by-products but excluding solution gas from oil wells)(3)	763	9.73	1.62
	Non-conventional Oil & Gas Activities	33	5.48	0.91
	Total	3,965	15.43	2.57
Total Proved Plus Probable	Light and Medium Crude Oil (including solution gas and other by-products)(2)	1,994	18.86	3.14
	Heavy Oil (including solution gas and other by-products)(2)	602	23.60	3.93
	Bitumen	1,942	10.10	1.68
	Natural Gas (including by-products but excluding solution gas from oil wells)(3)	1,045	8.26	1.38
	Non-conventional Oil & Gas Activities	42	5.19	0.86
	Total	5,625	12.27	2.05

Notes:

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

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

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

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

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

PENGROWTH ENERGY CORPORATION ANNUAL INFORMATION FORM | 15

Pricing Assumptions

Forecast Prices used in Estimates

The forecast price and cost assumptions assume the continuance of current laws and regulations and changes in wellhead selling prices, and take into account forecasted two percent annual inflation with respect to future operating and capital costs. The forecast prices are provided in the table below and reflect GLJ's January 1, 2015 price forecast as referred to in the GLJ Report.

	Oil						Natural Gas	Natural Gas Liquids(1)
	WTI Cushing Oklahoma	Edmonton Par Price 40°API	Cromer Medium 29°API	WCS Stream Quality	Hardisty Heavy 12°API	Lindbergh Bitumen Wellhead Calculated(5)	AECO Gas Price	Propane	Butane	Pentanes Plus	Inflation Rates(2)	Exchange Rate(3)
Year	(US$/bbl)	(Cdn$/bbl)	(Cdn$/bbl)	(Cdn$/bbl)	(Cdn$/bbl)	(Cdn$/bbl)	(Cdn$/MMBtu)	(Cdn$/bbl)	(Cdn$/bbl)	(Cdn$/bbl)	(%/year)	(US$/Cdn$)
2014(4)	93.06	94.77	89.86	81.62	74.23	73.45	4.52	45.57	69.29	102.92	2.0	0.905
2015	62.50	64.71	61.47	54.35	48.89	45.67	3.31	19.63	52.91	69.24	2.0	0.850
2016	75.00	80.00	76.00	67.20	60.68	56.72	3.77	32.00	60.80	85.60	2.0	0.875
2017	80.00	85.71	81.43	72.00	65.09	61.06	4.02	38.57	65.14	91.71	2.0	0.875
2018	85.00	91.43	86.86	76.80	69.49	65.40	4.27	41.14	69.49	97.83	2.0	0.875
2019	90.00	97.14	92.29	81.60	73.90	69.74	4.53	43.71	73.83	103.94	2.0	0.875
2020	95.00	102.86	97.71	86.40	78.30	74.08	4.78	46.29	78.17	110.06	2.0	0.875
2021	98.54	106.18	100.87	89.19	80.87	76.60	5.03	47.78	80.70	113.62	2.0	0.875
2022	100.51	108.31	102.89	90.98	82.51	78.22	5.28	48.74	82.31	115.89	2.0	0.875
2023	102.52	110.47	104.95	92.79	84.17	79.86	5.53	49.71	83.96	118.20	2.0	0.875
2024	104.57	112.67	107.04	94.65	85.87	81.54	5.71	50.70	85.63	120.56	2.0	0.875
thereafter	+2%/year	+2%/year	+2%/year	+2%/year	+2%/year	+2%/year	+2%/year	+2%/year	+2%/year	+2%/year	2.0	0.875

Notes:

(1) FOB Edmonton.

(2) Inflation rates for forecasting prices and costs.

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

(4) Actual average historical prices for 2014.

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

Constant Prices used in Estimates

The constant price assumptions assume the continuance of current laws, regulations and operating costs in effect on the date of the GLJ Report. Product prices were determined from the actual prices on the first day of each month during 2014 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$/Cdn$)

2015 and thereafter

95.28

94.74

89.56

82.63

75.39

73.95

4.58

48.89

70.49

103.42

0.0

0.9099

Notes:

(1) FOB Edmonton.

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

16 | ANNUAL INFORMATION FORM

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, 2014, presented using forecast prices and costs. All reserves are located in Canada.

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

	Light and Medium Oil			Heavy 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, 2013	73,191	30,150	103,340	19,304	10,882	30,186	81,727	60,838	142,565	25,300	9,736	35,036
Technical Revisions	968	(3,232)	(2,264)	1,399	(472)	927	(1,103)	937	(166)	2,335	(721)	1,615
Economic Factors	(1,795)	554	(1,241)	(473)	178	(295)	-	-	-	(620)	78	(542)
Discoveries	-	-	-	-	-	-	-	-	-	-	-	-
Extensions	2,012	618	2,629	397	530	927	23,839	77,715	101,554	351	715	1,066
Infill Drilling	521	590	1,111	-	-	-	-	-	-	523	220	743
Improved Recovery	35	(35)	-	-	-	-	-	-	-	3	6	9
Acquisitions	594	313	907	4	1	4	-	-	-	108	46	154
Dispositions	(3,559)	(1,625)	(5,184)	(20)	(74)	(95)	-	-	-	(75)	(111)	(186)
Production	(7,725)	-	(7,725)	(2,397)	-	(2,397)	(615)	-	(615)	(3,687)	-	(3,687)
December 31, 2014	64,241	27,332	91,574	18,214	11,045	29,259	103,848	139,491	243,338	24,238	9,968	34,206

	Natural Gas			Coal Bed Methane			Total Oil Equivalent Basis(1)
	Proved	Probable	Proved Plus Probable	Proved	Probable	Proved Plus Probable	Proved	Probable	Proved Plus Probable
	(MMcf)	(MMcf)	(MMcf)	(MMcf)	(MMcf)	(MMcf)	(Mboe)	(Mboe)	(Mboe)
December 31, 2013	597,830	339,385	937,215	43,720	12,150	55,870	306,446	170,196	476,642
Technical Revisions	9,621	(6,506)	3,115	2,674	225	2,899	5,650	(4,536)	1,114
Economic Factors	(20,399)	(1,959)	(22,358)	(770)	240	(530)	(6,416)	523	(5,893)
Discoveries	-	-	-	-	-	-	-	-	-
Extensions	31,627	16,244	47,871	-	-	-	31,870	82,285	114,155
Infill Drilling	4,218	1,901	6,119	-	-	-	1,747	1,127	2,874
Improved Recovery	32	141	173	-	-	-	43	(6)	37
Acquisitions	958	305	1,262	-	-	-	865	411	1,276
Dispositions	(2,209)	(6,449)	(8,657)	-	-	-	(4,023)	(2,885)	(6,908)
Production	(70,139)	-	(70,139)	(3,198)	-	(3,198)	(26,647)	-	(26,647)
December 31, 2014	551,539	343,061	894,600	42,426	12,614	55,040	309,535	247,115	556,650

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.

At December 31, 2014, Company Interest Total Proved Plus Probable Reserves at forecast prices and costs were 557.4 MMboe as compared to 477.4 MMboe reported at year end 2013. The following additional GLJ reserves reconciliation is presented for year end December 31, 2014.

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

	Proved Developed Producing Reserves	Total Proved Reserves	Total Proved Plus Probable Reserve
December 31, 2013	185,743	307,016	477,385
Technical Revisions	6,227	5,724	1,199
Economic Factors	(3,183)	(6,433)	(5,908)
Extensions	5,027	31,870	114,155
Infill Drilling	3,481	1,747	2,874
Improved Recovery	265	43	38
Acquisitions	865	865	1,276
Dispositions	(3,681)	(4,030)	(6,918)
Production	(26,750)	(26,750)	(26,750)
December 31, 2014	167,994	310,051	557,350

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.

PENGROWTH ENERGY CORPORATION ANNUAL INFORMATION FORM | 17

Significant factors bearing on the reserves reconciliation were as follows:

• Net reserve changes from drilling activity, improved recovery, technical revisions and economic factors replaced 123 percent and 420 percent of 2014 production for Proved Reserves and Total Proved Plus Probable Reserves, respectively. Based on all changes, including acquisitions and dispositions, reserve replacement was 111 percent and 399 percent for Proved Reserves and Proved Plus Probable Reserves, respectively.

• New reserve additions for development activity during 2014 amounted to 34 MMboe of Proved Reserves and 117 MMboe of Total Proved Plus Probable Reserves, almost all in our oil and liquids-rich gas properties. The most significant resulted from ongoing reservoir delineation and submission of the regulatory application to expand the development of our Lindbergh thermal project. Other notable additions and reclassification of Proved or Probable Undeveloped Reserves to producing were for infill drilling and drilling extensions in the Cardium play through the Lochend/Garrington fairway where we hold an extensive land position. Other additions were in the liquids-rich multi-zone Harmattan and Caroline core areas and our Groundbirch Montney gas development.

• Technical revisions due to performance changes in various properties resulted in a net increase of 6 MMboe of Proved Reserves and 1 MMboe of Total Proved Plus Probable Reserves. The positive performance changes were offset by reserve decreases due to economic factors relating to lower forecast product prices compared to last year end. The decrease is estimated to be 6 MMboe for both Proved Reserves and Total Proved Plus Probable Reserves.

• Disposition of minor non-core assets in Alberta resulted in a decrease of 4 MMboe and 7 MMboe of Proved Reserves and Total Proved Plus Probable Reserves, respectively. Asset acquisitions accounted for an increase of 1 MMboe in both Proved and Total Proved Plus Probable 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 three years. Much of the remaining capital scheduled beyond this period is for staged developments such as the Judy Creek and Swan Hills miscible flood projects, and the Lindbergh thermal development. Other longer term capital expenditures are for gas development most of which has been deferred with capital being allocated instead to higher-impact oil opportunities.

Company Gross Reserves First Attributed by Year⁽¹⁾ 

Proved Undeveloped Reserves
	Light & Medium Oil		Heavy Oil		Bitumen		Natural Gas		Coal Bed Methane		Natural Gas Liquids		Total Oil Equivalent
	(Mbbl)		(Mbbl)		(Mbbl)		(MMcf)		(MMcf)		(Mbbl)		(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
Prior	16,447	16,447	3,568	3,568	2,756	2,756	62,830	62,830	23,241	23,241	1,678	1,678	38,794	38,794
2012	6,233	20,019	2,915	6,120	8,380	11,136	28,115	76,111	-	22,200	1,128	1,831	23,342	55,491
2013	2,348	14,771	1,015	5,954	69,293	80,423	9,405	64,999	-	22,410	647	1,306	74,870	117,022
2014	1,059	13,137	332	5,483	22,596	77,113	21,818	66,686	-	22,728	137	832	27,760	111,467

Probable Undeveloped Reserves
	Light & Medium Oil		Heavy Oil		Bitumen		Natural Gas		Coal Bed Methane		Natural Gas Liquids		Total Oil Equivalent
	(Mbbl)		(Mbbl)		(Mbbl)		(MMcf)		(MMcf)		(Mbbl)		(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
Prior	12,015	12,015	2,612	2,612	1,581	1,581	139,429	139,429	6,077	6,077	2,535	2,535		42,994	42,994
2012	8,652	19,144	5,205	7,516	80,038	81,630	50,800	178,755	-	6,674	2,250	3,675		104,612	142,869
2013	2,352	11,774	431	8,196	39,821	60,518	35,878	177,413	-	6,312	654	2,451		49,237	113,559
2014	1,443	10,698	356	8,092	78,743	134,485	33,494	179,851	-	6,639	1,122	2,896		87,246	187,253

Notes:

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

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

18 | ANNUAL INFORMATION FORM

Proved Undeveloped Reserves

Our Proved Undeveloped Reserves comprise approximately 36 percent of Company Interest total Proved Reserves on a barrel of oil equivalency basis. Company Interest Proved Undeveloped Reserves of 111 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 needed 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, miscible flood expansion and development drilling.

The Lindbergh thermal project, currently under development and anticipated to come on stream in 2015, accounts for 69 percent of our Proved Undeveloped Reserves. SAGD well pairs are forecast to be drilled until 2043. The pace of development is limited by the initial capacity of the central processing and steam facility. The Groundbirch Montney gas property amounts to approximately seven percent of our Proved Undeveloped Reserves. Drilling is forecast by GLJ to occur over the next five years to develop these reserves. Harmattan, Garrington and Lochend contain approximately four percent of our Proved Undeveloped Reserves. Development drilling in these fields is primarily focused on the Cardium formation and is forecast to occur over the next three to five years. In the Judy Creek and Judy Creek West units, drilling and miscible flood development is forecast to continue until 2021 and accounts for another four percent of Company Interest Proved Undeveloped Reserves. Similarly, the Swan Hills unit miscible flood expansion, as well as some infill drilling, comprises three percent of our Company Interest Proved Undeveloped Reserves. The Swan Hills unit reserves have a 50 year Remaining Reserve Life. The incremental recovery is reflected in the GLJ Report and miscible flood expansion is forecast to continue until 2032. The gradual pace of development is affected by a limited supply of solvent for injection in the miscible floods at both Judy Creek and Swan Hills. Our CBM development requires further drilling at Twining, Huxley and Fenn Big Valley. Because of the extensive land holdings, this is forecast to occur over the next six years and represents another three percent of the Proved Undeveloped Reserves.

Probable Undeveloped Reserves

Probable Undeveloped Reserves were assigned by GLJ in accordance with the requirements and standards of NI 51-101 and the COGE Handbook. Our Probable Undeveloped Reserves amount to 187 MMboe and represent about 34 percent of the Total Proved Plus Probable Reserves. Probable Undeveloped Reserves are assigned for similar reasons and generally to the same properties as Proved Undeveloped Reserves, but also meet the requirements of the reserve classification to which they belong. Our largest Probable Undeveloped Reserves are distributed among certain properties as a percent of the total as follows: Lindbergh (72 percent), Groundbirch (12 percent), Harmattan/Garrington/Lochend (four percent) and Tangleflags (three percent).

FUTURE DEVELOPMENT COSTS

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

Future Development Costs ($MM)

							Total
Reserve Category	2015	2016	2017	2018	2019	Remainder	Undiscounted	Discounted at 10%
Proved Reserves (Constant Prices and Costs)	165	249	101	132	49	966	1,662	894
Proved Reserves (Forecast Prices and Costs)	161	243	96	140	53	1,251	1,944	965
Proved & Probable Reserves (Forecast Prices and Costs)	250	514	444	526	112	3,111	4,957	2,395

We expect to fund future development costs with a combination of cash flow and proceeds from non-core asset dispositions. There are no reserves that are expected to be limited in their recovery due to their cost of development.

FINDING, DEVELOPMENT AND ACQUISITION COSTS

Finding and Development Costs

During 2014, we spent $903 million on development, land and optimization, which added 32.9 MMboe of Proved Reserves and 112.4 MMboe of Total Proved Plus Probable Reserves including revisions. The development and optimization expenditures exclude $3 million in corporate expenditures mainly for information technology projects in the Calgary office. The largest reserve additions were for drilling and improved recovery projects at Lindbergh, Greater Olds/Garrington and Groundbirch.

In total, we participated in drilling 185 gross wells (145.1 net wells) with a 99 percent success rate.

Extensive development occurred in the mainly Pengrowth-operated Lochend/Harmattan/Garrington Cardium trend in the Greater Olds/Garrington area during 2014. Within this area, we drilled, or participated in the drilling of, 71 gross (42.4 net) successful horizontal wells resulting in 60 (33.9 net) Cardium oil wells and eight (6.0 net) oil and three (2.5 net) liquids-rich gas wells in the Ellerslie and Elkton.

PENGROWTH ENERGY CORPORATION ANNUAL INFORMATION FORM | 19

In our 100 percent owned Lindbergh thermal property, during 2014, we drilled 40 stratigraphic test/observation wells to better understand the reservoir and delineate the pool. In addition, we completed construction of the central processing facilities and drilled the final 13 SAGD producers and 20 injectors in our first commercial phase of development.

In the 100 percent owned Judy Creek units, we drilled one oil well and three injectors as part of the ongoing miscible flood conversions and waterflood optimization activities in the Beaverhill Lake formation.

Various other drilling programs and optimization work were conducted during 2014 to test new concepts, increase production and maximize recoveries.

Acquisitions and Divestitures

Relative to 2013, Pengrowth was not very active on the acquisition and disposition front in 2014. During 2014, $85 million of asset dispositions (after interim period adjustments) were completed, and approximately $17 million of asset acquisitions, excluding the $123.6 million land acquisition at Bernadet which was classified as capital spending, were completed. In 2013, we completed almost $1 billion of asset dispositions, and $16 million of asset acquisitions. The 2014 dispositions were comprised of our interestsinseveral non-core assets which included the greater Red Earth area, Virginia Hills North and Provost. Asset acquisitions in 2014 were limited to strategic core consolidating asset acquisitions at Carson Creek North and Deer Mountain Unit No. 1. In November 2014, we acquired 32.6 sections of prospective liquids-rich Montney lands at Bernadet in northeastern British Columbia for $123.6 million.

Future Development Costs

NI 51-101 requires that 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 in capital costs and acquisition or disposition of assets. We provide the calculation of FD&A Costs both with and without change in FDC. We include FD&A Costs because we believe that acquisitions and dispositions can have a significant impact on our ongoing reserve replacement costs.

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

Proved Reserves	2014	2013	2012	2012-2014 Weighted Average
Costs Excluding Future Development Costs
Exploration and Development Capital Expenditures - $MM	902.5	692.4	461.0	2,055.9
Exploration and Development Reserve Additions including Revisions - MMboe	32.9	83.4	21	137.3
Finding and Development Cost - $/BOE	27.43	8.30	21.93	14.97
Net Acquisition (Disposition) Capital - $MM	(67.5)	(977.8)	1,654.2	608.9
Net Acquisition (Disposition) Reserve Additions - MMboe	(3.1)	(45.6)	75.9	30.2
Net Acquisition Cost - $/BOE	21.77	21.43	21.81	20.16
Total Capital Expenditures including Net Acquisitions (Dispositions) - $MM	835.0	(285.3)	2,115.1	2,664.8
Reserve Additions including Net Acquisitions (Dispositions) - MMboe	29.8	37.8	96.9	167.5
Finding, Development and Acquisition Cost - $/BOE(1)	28.02	(7.55)	21.83	15.91
Costs Including Future Development Costs
Exploration and Development Capital Expenditures - $MM	902.5	692.4	461.0	2,055.9
Exploration and Development Change in FDC - $MM	(51.7)	1,031.7	104.6	1,084.6
Exploration and Development Capital including Change in FDC - $MM	850.8	1,724.1	565.6	3,140.5
Exploration and Development Reserve Additions including Revisions - MMboe	32.9	83.4	21.0	137.3
Finding and Development Cost - $/BOE	25.86	20.67	26.91	22.87
Net Acquisition (Disposition) Capital - $MM	(67.5)	(977.8)	1,654.2	608.9
Net Acquisition (Disposition) FDC - $MM	(5.3)	(244.7)	229.8	(0.2)
Net Acquisition (Disposition) Capital including FDC - $MM	(72.8)	(1,202.5)	1,884.0	608.7
Net Acquisition (Disposition) Reserve Additions - MMboe	(3.1)	(45.6)	75.9	30.2
Net Acquisition Cost - $/BOE	23.48	26.36	24.83	20.16
Total Capital Expenditures including Net Acquisitions (Dispositions) - $MM	835.0	(285.3)	2,115.2	2,664.8
Total Change in FDC - $MM	(57.0)	807.0	334.4	1,084.4
Total Capital including Change in FDC - $MM	778.0	521.7	2,449.6	3,749.2
Reserve Additions including Net Acquisitions (Dispositions) - MMboe	29.8	37.8	96.9	167.5
Finding, Development and Acquisition Cost including FDC - $/BOE	26.11	13.80	25.29	22.38

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Total Proved Plus Probable Reserves	2014	2013	2012	2012-2014 Weighted Average
Costs Excluding Future Development Costs
Exploration and Development Capital Expenditures - $MM	902.5	692.4	461.0	2,055.9
Exploration and Development Reserve Additions including Revisions - MMboe	112.4	65.3	103.8	281.5
Finding and Development Cost - $/BOE	8.03	10.61	4.44	7.30
Net Acquisition (Disposition) Capital - $MM	(67.5)	(977.8)	1,654.2	608.9
Net Acquisition (Disposition) Reserve Additions - MMboe	(5.6)	(69.0)	109.4	34.8
Net Acquisition Cost - $/BOE	12.05	14.17	15.12	17.50
Total Capital Expenditures including Net Acquisitions (Dispositions) - $MM	835.0	(285.3)	2,115.2	2,664.8
Reserve Additions including Net Acquisitions (Dispositions) - MMboe	106.7	(3.7)	213.2	316.3
Finding, Development and Acquisition Cost - $/BOE	7.82	76.66	9.92	8.42
Costs Including Future Development Costs
Exploration and Development Capital Expenditures - $MM	902.5	692.4	461.0	2,055.9
Exploration and Development Change in FDC - $MM	1,607.2	741.2	1,288.0	3,636.4
Exploration and Development Capital including Change in FDC - $MM	2,509.7	1,433.6	1,748.9	5,692.3
Exploration and Development Reserve Additions including Revisions - MMboe	112.4	65.3	103.8	281.5
Finding and Development Cost - $/BOE	22.33	21.96	16.85	20.22
Net Acquisition (Disposition) Capital - $MM	(67.5)	(977.8)	1,654.2	608.9
Net Acquisition (Disposition) FDC - $MM	(32.2)	(381.2)	467.2	53.8
Net Acquisition (Disposition) Capital including FDC - $MM	(99.7)	(1,359.0)	2,121.4	662.7
Net Acquisition (Disposition) Reserve Additions - MMboe	(5.6)	(69.0)	109.4	34.8
Net Acquisition Cost - $/BOE	17.80	19.70	19.39	19.04
Total Capital Expenditures including Net Acquisitions (Dispositions) - $MM	835.0	(285.3)	2,115.2	2,664.8
Total Change in FDC - $MM	1,575.0	360.0	1,755.2	3,690.2
Total Capital including Change in FDC - $MM	2,410.0	74.6	3,870.4	6,355.0
Reserve Additions including Net Acquisitions (Dispositions) – MMboe	106.7	(3.7)	213.2	316.3
Finding Development and Acquisition Cost including FDC - $/BOE(2)	22.57	(20.05)	18.16	20.09

Notes:

(1) The negative 2013 FD&A Cost excluding FDC for Proved Reserves is due to the proceeds from dispositions exceeding capital expenditures plus acquisition costs.

(2) The negative 2013 FD&A Cost including FDC for P+P Reserves is due to the reserve decrease from dispositions exceeding the reserve additions, including revisions, from development activity and acquisitions.

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.

RECYCLE RATIO

We calculate the Recycle Ratio to measure our performance. It reflects the amount of cash flow relative to investment and is able to be compared both internally and externally. To calculate the Recycle Ratio, we divide annual operating netback by annual P+P F&D Costs including change in FDC.

	2014	2013	2012	2012-2014 Weighted Average
Recycle Ratio	1.1	1.1	1.4	1.2
Operating Netback, $/BOE(1)(3)	25.64	24.35	23.67	24.50
P+P F&D, $/BOE(2)	22.33	21.96	16.85	20.22

Notes:

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

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

(3) Comparative figures restated to conform to presentation in the current period.

PENGROWTH ENERGY CORPORATION ANNUAL INFORMATION FORM | 21

RESERVE LIFE INDEX

The Reserve Life Index ("RLI") provides a comparative measure of the longevity of the resources. We calculate the RLI by dividing 2014 Company Interest year end reserves by GLJ’s 2015 forecasted production.

	Proved Producing Reserves	Total Proved Reserves	Total Proved Plus Probable Reserves
RLI, years	7.2	11.7	19.8
Reserves, Mboe(1)(2)	167,994	310,051	557,350
2015 Forecast Production, BOE/d(1)	63,485	72,506	77,004

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 production.

	2014	2013	2012	Weighted Average/Total 2012-2014
Without Net Acquisitions Proved Plus Probable Replacement (%)	420	211	327	315
P+P Additions plus Revisions, MMboe(1)	112.4	65.3	103.8	281.5
With Net Acquisitions Proved Plus Probable Replacement (%)	399	(12)	672	354
P+P Additions, Revisions plus net Acquisitions, MMboe(1)	106.7	(3.7)	213.2	316.2
Without Net Acquisitions Total Proved Replacement (%)	123	270	66	154
Total Proved Additions plus Revisions, MMboe(1)	32.9	83.4	21.0	137.4
With Net Acquisitions Total Proved Replacement (%)	111	122	306	184
Total Proved Additions, Revisions plus net Acquisitions, MMboe(1)	29.8	37.8	96.9	164.5
Current Year Production, MMboe(1)	26.8	30.9	31.7	89.4

Note:

(1) Both reserves and production are Company Interest.

22 | ANNUAL INFORMATION FORM

OTHER OIL AND GAS INFORMATION

Oil and Gas Wells

As at December 31, 2014, we had an interest in 7,564 gross (4,047 net) producing oil and natural gas wells and 3,649 gross (2,140 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	2,148	1,324	1,140	618	3,288	1,942
	British Columbia	83	52	176	110	259	162
	Saskatchewan	161	64	209	155	370	219
Bitumen Wells
	Alberta	2	2	20	20	22	22
Natural Gas Wells
	Alberta	4,948	2,467	1,016	587	5,964	3,054
	British Columbia	173	106	198	108	371	214
	Saskatchewan	32	30	35	25	67	55
	Nova Scotia	17	2	2	-	19	2
Other
	Alberta	-	-	590	360	590	360
	British Columbia	-	-	158	104	158	104
	Saskatchewan	-	-	105	53	105	53
Total		7,564	4,047	3,649	2,140	11,213	6,187

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, 2014 and the maximum net area of unproved properties for which we expect our rights to explore, develop and exploit to expire during 2015. 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, 2014

Location	Gross Acres	Net Acres	Maximum Net Acres Expected to Expire During 2015
Alberta	682,909	413,509	83,680
British Columbia	379,753	169,577	20,112
Saskatchewan	8,941	7,166	640
Nova Scotia	200,650	15,957	-
Total	1,272,253	606,208	104,432

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.

Lindbergh Oil Sands Reserves and Contingent Resources

The Lindbergh property, an oil sands lease, is located approximately 420 kilometres north east of Calgary, Alberta and 50 kilometres south of Bonnyville, Alberta. We have a 100 percent Working Interest in the Lindbergh oil sands leases, located in the Cold Lake oil sands district in northeastern Alberta and covering 20,800 net acres (32.5 sections). Our Muriel Lake property is about eight kilometres to the north east of the Lindbergh lease and is comprised of an additional 6,400 net acres (10 sections). There were a total of 116 existing wells that have been used in the geological evaluation including 10 on the Muriel Lake property. The Corporation has drilled and evaluated 82 delineation wells since acquiring the Lindbergh property in 2004. Additionally, 64 square kilometres of three dimensional seismic along with 105 kilometres of two dimensional seismic has been shot and evaluated.

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 degree API. 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.

PENGROWTH ENERGY CORPORATION ANNUAL INFORMATION FORM | 23

The Lindbergh Pilot facility, well pad and two SAGD well pairs were constructed, drilled and completed in December 2011. The wells were drilled from a single pad with each having an effective horizontal well length of approximately 840 metres within the bitumen-bearing Lloydminster formation. Both well pairs encountered high quality reservoir throughout with no lean zones or shale barriers in any of the well bores. Steaming operations began at the Lindbergh pilot in early February 2012.

Based on favorable pilot results, Pengrowth developed a commercial project with a first phase design capacity of 12,500 bbl/d of bitumen (including the pilot area) with an expected project life of 29 years. In July 2013, the project received regulatory approval to proceed under the EPEA application number 1713445. Construction commenced in August 2013 on the commercial project. The project achieved first steam in December 2014. This first commercial phase is comprised of a central processing facility ("CPF"), three additional well pads, surface pipelines, 20 well pairs, a 15 MW cogeneration plant and other associated infrastructure. The drilling of the additional wells went as anticipated and the characteristics of the wells as drilled were similar to those observed for the Pilot well pairs.

Over the life of the 12,500 bbl/d commercial project, a total of 95 well pairs (incremental to the two existing pilot well pairs) are expected to be drilled from several central pad sites within the project area, recovering Proved Reserves of 103.8 MMbbl of bitumen. The production life for each individual well pair is expected to be eight to nine years. Under our development plan, as individual well pair production declines, additional well pairs would be drilled throughout the project area to maintain production. The initial phase is expected to reach 16,000 bbl/d production by the end of 2015.

The Phase 2 expansion to 30,000 bbl/day of capacity is expected to recover 243.3 MMbbl of Total Proved Plus Probable Reserves from a total of 228 well pairs including the two existing pilot well pairs. Given the strong pilot results, additional productivity is thought to be possible and anticipated from Phase 1 and Phase 2. There is also potential for further expansion to attain 40,000 to 50,000 bbl/d over all the Pengrowth lands in the Lindbergh region. The EIA application for the first of these expansions to 30,000 bbl/d was submitted in December 2013. Approval for the expansion is anticipated in the first quarter of 2016.

Proved Reserves, Probable Reserves and Possible Reserves have been assigned within the approved project area. Additional Undeveloped Reserves have been assigned in the Probable Reserves and Possible Reserves categories within the expansion application project area. Furthermore, there are economic 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, 2014. 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 project is forecast to be profitable using forecast prices and costs as well as constant prices and costs.

The tables below summarize the estimated volumes of Company Interest reserves and economic Contingent Resources attributable to the Lindbergh property based upon forecast prices and costs. 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 assumed to be 100 percent, whereas the likelihood of a Contingent Resource achieving commerciality may be less than 100 percent.

Proved Reserves, Probable Reserves and Possible Reserves have been assigned within the region of the proposed commercial development area 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".

Lindbergh Thermal Project
Proved, Proved plus Probable and Proved plus Probable plus Possible Reserves as of December 31, 2014
(Forecast Prices and Costs)

	Proved Reserves	Proved plus Probable Reserves	Proved plus Probable plus Possible Reserves(1)
Gross Reserves (MMbbl)	103.8	243.3	316.6

Note:

(1) Possible Reserves are those additional reserves that are less certain to be recovered than Probable Reserves. There is a ten percent probability that the quantities actually recovered will equal or exceed the sum of Proved Plus Probable plus Possible Reserves.

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 no certainty that it will be commercially viable to produce any portion of the Contingent Resources.

All categories of Contingent Resources have decreased from the previous year end as shown below. This is due to a significant volume now being reported as reserves resulting from further pool delineation (including the drilling of 40 stratigraphic test/observation wells in 2014), receiving regulatory approval for the first commercial phase of development and making the regulatory application for the first expansion phase of the commercial development.

A significant portion of the resource volumes are still classified as a 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.

24 | ANNUAL INFORMATION FORM

• 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. The Lindbergh project is analogous to multiple successful commercial developments within Alberta and Saskatchewan. 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.

	December 31, 2014	December 31, 2013
	Contingent Resources(1)  (Gross MMbbl)	Contingent Resources(1)  (Gross MMbbl)
Low Estimate(2)	50.6	124.1
Best Estimate(3)	100.6	163.0
High Estimate(4)	149.0	275.6

Notes:

(1) 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 further classified in accordance with the level of certainty associated with the estimates.

(2) Low Estimate is a conservative estimate of the quantity of oil that will be recovered from the accumulation, which under probabilistic methodology reflects a ninety percent confidence level.

(3) Best Estimate is a best estimate of the quantity of oil that will be recovered from the accumulation, which under probabilistic methodology reflects a fifty percent confidence level.

(4) High Estimate is an optimistic estimate of the quantity of oil that will be recovered from the accumulation, which under probabilistic methodology reflects a ten percent confidence level.

The accuracy of resource estimates is, in part, a function of the quality and quantity of available data and of engineering and geological interpretation and judgment. The size of the resource estimate could be positively impacted, potentially in a material amount, if additional delineation wells determine that the aerial extent, reservoir quality and/or the thickness of the reservoir is larger than what is currently estimated based on the interpretation of seismic and well control. The size of the resource estimate could be negatively impacted, potentially in a material amount, if additional delineation wells determine that the aerial extent, reservoir quality and/or the thickness of the reservoir are less than what is currently estimated based on the interpretation of the seismic and well control.

Groundbirch Reserves and Contingent Resources

The Groundbirch property is located approximately 40 kilometres southwest of Fort St. John, British Columbia and covers an area of 13,855 gross (12,536 net) acres. We have an average 90 percent Working Interest in these lands. At Groundbirch, we currently have 17 producing wells making approximately 18 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 1 micro-Darcy. As a result of the very low permeability, the reservoir is developed with horizontal wells using multi-stage fracture technology.

We drilled the first wells at Groundbirch in 2010. A central gas processing facility with a capacity of approximately 30 MMcf/d was constructed and six wells were brought on stream in December 2010. Additional drilling occurred in 2011 and we had 15 producing wells by later that year. In 2014, we drilled two additional horizontal wells and increased hydraulic fracture intensity by increasing the number of fracture stages in the completions. This resulted in higher initial rates and is expected to increase ultimate recovery as demonstrated by more recent regional development.

For those areas producing and immediately adjacent, 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 gas processing facility full. Should economic conditions warrant, consideration will be given to expanding our facility capacity and increasing the pace of development in the future. In evaluating reserves and Contingent Resources, the GLJ forecasts are consistent with this development scenario.

The tables below summarize the estimated volumes of Company Interest reserves and economic Contingent Resources attributable to the Groundbirch property based upon forecast prices and costs. 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 assumed to be 100 percent, whereas the likelihood of a Contingent Resource achieving commerciality may be less than 100 percent.

PENGROWTH ENERGY CORPORATION ANNUAL INFORMATION FORM | 25

Groundbirch
Proved, Proved plus Probable and Proved plus Probable plus Possible Reserves as of December 31, 2014
(Forecast Prices and Costs)

		Proved Developed Producing Reserves	Total Proved Reserves	Total Proved Plus Probable Reserves	Total Proved Plus Probable Plus Possible Reserves(1)
Gross Reserves
	Gas (Bcf)	38.0	85.2	228.2	279.6
	NGL (MMbbl)	-	-	-	-
	Total (MMboe)(2)	6.3	14.2	38.0	46.6

Notes:    

(1) Possible Reserves are those additional reserves that are less certain to be recovered than Probable Reserves. There is a ten percent probability that the quantities actually recovered will equal or exceed the sum of Proved Plus Probable plus Possible Reserves.

(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.

Contingent Resources have been assigned to the remaining areas of the reservoir within the property that meet certain minimum criteria. GLJ's estimates of economic Contingent Resources as at December 31, 2014 are shown below. Contingent Resources increased from 2013 year end based on production performance in the area, additional drilling, implementation of new and evolving hydraulic fracturing technology and offsetting development activity. We drilled three wells on our lands during 2014; one stratigraphic test well and two horizontal gas wells.

Contingent Resources are assigned on the basis of a technically feasible recovery project having been defined. These Contingent Resources are expected to be economic to develop. The Groundbirch tight gas resource is in the early stage of evaluation, delineation and development. Contingent Resources are assigned by GLJ to regions of the field where the zone is delineated to an appropriate level to understand the reservoir, and to remove reservoir risk. Additional drilling, completion and test data is required for planning and design purposes with respect to well spacing, pipeline and facility capacity and scheduling. The reclassification of these Contingent Resources as reserves is contingent upon creating a development plan with corporate approval and commitment to proceed within an acceptable time period. However, there is no certainty that it will be commercially viable to produce any portion of the Contingent Resource.

		December 31, 2014 Contingent Resources(1)(Gross)	December 31, 2013 Contingent Resources(1)(Gross)
Low Estimate(2)
	Gas (Bcf)	474.5	215.1
	NGL (MMbbl)	-	-
	Total (MMboe)(5)	79.1	35.8
Best Estimate(3)
	Gas (Bcf)	634.4	339.9
	NGL (MMbbl)	-	-
	Total (MMboe)(5)	105.7	56.6
High Estimate(4)
	Gas (Bcf)	990.9	600.7
	NGL (MMbbl)	-	-
	Total (MMboe)(5)	165.2	100.1

Notes:

(1) 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 further classified in accordance with the level of certainty associated with the estimates.

(2) Low Estimate is a conservative estimate of the quantity of gas that will be recovered from the accumulation, which under probabilistic methodology reflects a ninety percent confidence level.

(3) Best Estimate is a best estimate of the quantity of gas that will be recovered from the accumulation, which under probabilistic methodology reflects a fifty percent confidence level.

(4) High Estimate is an optimistic estimate of the quantity of gas that will be recovered from the accumulation, which under probabilistic methodology reflects a ten percent confidence level.

(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.

The accuracy of resource estimates is, in part, a function of the quality and quantity of available data and of engineering and geological interpretation and judgment. The size of the resource estimate could be positively impacted, potentially in a material amount, if additional development wells determine that the aerial extent, reservoir quality and/or the thickness of the reservoir is larger than what is currently estimated based on the interpretation of seismic and well control. The size of the resource estimate could be negatively impacted, potentially

26 | ANNUAL INFORMATION FORM

in a material amount, if additional development wells determine that the aerial extent, reservoir quality and/or the thickness of the reservoir are less than what is currently estimated based on the interpretation of the seismic and well control.

FORWARD CONTRACTS

We use financial derivatives or fixed price contracts to manage our exposure to fluctuations in commodity prices and foreign currency exchange rates. A description of such instruments is provided in Note 17 of our annual audited consolidated financial statements and related Management's Discussion and Analysis for the year ended December 31, 2014, which may be found on SEDAR at www.sedar.com.

ADDITIONAL INFORMATION CONCERNING ABANDONMENT & RECLAMATION COSTS

The total future abandonment and reclamation costs are based on management's estimate of costs to remediate, reclaim and abandon wells and facilities having regard to our Working Interest and the estimated timing of the costs to be incurred in future periods. 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.

GLJ's estimate of downhole well abandonment costs for all wells with reserves assigned as well as abandonment costs for all Sable Island offshore and onshore facilities and pipelines upstream of the plant gate are included in their report and therefore in their estimate of Future Net Revenue. All other abandonment and reclamation costs are not reflected in GLJ's estimate of Future Net Revenue.

We have estimated the net present value (discounted at ten percent per annum) of our total asset retirement obligations, which are inclusive of those costs estimated by GLJ, to be approximately $145 million as at December 31, 2014, based on a total future liability (inflated at 1.5 percent per annum) of approximately $2,007 million. The majority of these costs are expected to be incurred between 2038 and 2079 and apply to 7,139 net producing, non-producing, service and abandoned wells.

The following table summarizes our total current asset retirement obligations as at December 31, 2014:

Asset Retirement Obligations - $MM

	2015	2016	2017	Remainder	Total
Total Abandonment, Reclamation, Remediation & Dismantling	5	7	7	1,988	2,007
Discounted at ten percent	5	6	6	128	145

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 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 $305 million ($144 million when discounted at ten percent) of the current asset retirement obligations in the above table. Elsewhere, where we describe Future Net Revenue, only the GLJ estimated abandonment obligation is included in the values. For further clarity, the amount beyond the $305 million, or $144 million when discounted at ten percent, is excluded elsewhere.

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 2020, partially as a result of our $3.98 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, 2014. These costs include only those costs which are cash or cash equivalent.

	Amount
Nature of Cost	($M)
Acquisition Costs
Proved	16,889
Unproved	-
Exploration Costs	130,122
Development Costs	770,778
Total	917,789

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EXPLORATION AND DEVELOPMENT ACTIVITIES

The following table summarizes the number of wells drilled during the financial year ended December 31, 2014.

	Development		Exploration		Total
Wells	Gross	Net	Gross	Net	Gross	Net
Gas	8	5.2	-	-	8	5.2
Oil	92	56.8	2	0.5	94	57.3
Bitumen	13	13.0	-	-	13	13.0
Service	30	29.8	-	-	30	29.8
Stratigraphic Test	39	39.0	-	-	39	39.0
Dry	1	0.8	-	-	1	0.8
Total	183	144.6	2	0.5	185	145.1

PRODUCTION ESTIMATES

The following table summarizes the 2015 average daily volume of gross production estimated by GLJ for all properties held on December 31, 2014 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 2015 Company Interest production to be between 73,000 and 75,000 BOE/d.

	2015 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 and Medium Crude Oil (bbl/d)	17,791	1,113	18,904	17,731	1,134	18,865
Heavy Crude Oil (bbl/d)	6,352	271	6,623	6,352	271	6,623
Bitumen (bbl/d)	8,864	279	9,143	8,864	279	9,143
Natural Gas (Mcf/d)	187,748	12,735	200,483	187,144	12,819	199,963
Natural Gas Liquids (bbl/d)	8,183	661	8,844	8,145	670	8,815
Total (BOE/d)	72,482	4,446	76,928	72,284	4,489	76,773

28 | ANNUAL INFORMATION FORM

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, 2014	June 30, 2014	Sept 30, 2014	Dec 31, 2014	Dec 31, 2014
Barrels of Oil Equivalent(1)
Average Daily Oil Production(2) (BOE/d)	75,102	73,823	72,472	71,802	73,288
Oil & gas sales ($/BOE) (includes other income)	63.50	60.60	55.36	44.13	55.96
Royalties ($/BOE)	(10.90)	(11.64)	(9.83)	(7.75)	(10.04)
Operating expenses ($/BOE)	(15.39)	(17.05)	(15.36)	(14.31)	(15.53)
Transportation costs ($/BOE)	(1.24)	(1.07)	(0.97)	(1.32)	(1.15)
Realized commodity risk management	(6.26)	(6.98)	(4.29)	3.29	(3.60)
Operating netback ($/BOE)	29.71	23.86	24.91	24.04	25.64
Light Crude (excluding realized commodity risk management)
Average Daily Oil Production(2) (bbl/d)	22,444	21,780	21,359	19,361	21,228
Sales ($/bbl)	97.03	102.37	94.04	72.93	92.10
Royalties ($/bbl)	(19.79)	(22.22)	(19.91)	(17.71)	(19.96)
Operating expenses ($/bbl)	(16.24)	(15.64)	(15.99)	(15.78)	(15.80)
Transportation costs ($/bbl)	(2.56)	(1.99)	(1.65)	(2.18)	(2.10)
Operating netback ($/bbl)	58.44	62.52	56.49	37.26	54.24
Heavy Oil (excluding realized commodity risk management)
Average Daily Oil Production(2) (bbl/d)	8,255	8,203	8,246	8,299	8,251
Sales ($/bbl)	77.12	84.00	78.43	61.56	75.21
Royalties ($/bbl)	(9.78)	(13.40)	(13.09)	(10.58)	(11.71)
Operating expenses ($/bbl)	(16.98)	(20.65)	(16.80)	(19.97)	(18.58)
Transportation costs ($/bbl)	(1.85)	(1.80)	(1.67)	(1.64)	(1.74)
Operating netback ($/bbl)	48.51	48.15	46.87	29.37	43.18
Natural Gas(5) (excluding realized commodity risk management)
Average Daily Natural Gas Production(2) (Mcf/d)	201,907	196,989	200,786	208,563	202,076
Sales ($/Mcf)	6.35	4.59	4.05	4.02	4.74
Royalties ($/Mcf)	(0.54)	(0.40)	(0.22)	(0.19)	(0.33)
Operating expenses ($/Mcf)	(2.47)	(2.87)	(2.43)	(2.06)	(2.45)
Transportation costs ($/Mcf)	(0.10)	(0.11)	(0.11)	(0.20)	(0.13)
Operating netback ($/Mcf)	3.24	1.21	1.29	1.57	1.83
NGL (excluding realized commodity risk management)
Average Daily Oil Production(2) (bbl/d)	10,751	11,008	9,403	9,381	10,130
Sales ($/bbl)	59.12	55.70	52.94	39.51	52.17
Royalties ($/bbl)	(17.28)	(16.92)	(14.38)	(9.19)	(14.61)
Operating expenses ($/bbl)	(14.09)	(16.69)	(15.53)	(13.40)	(15.28)
Transportation costs ($/bbl	(0.01)	-	-	-	-
Operating netback ($/bbl)	27.74	22.09	23.03	16.92	22.28

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) Numbers may not add due to rounding.

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.

PENGROWTH ENERGY CORPORATION ANNUAL INFORMATION FORM | 29

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.

Debentures

As a result of the acquisition of NAL Energy on May 31, 2012, the Corporation assumed all of NAL Energy’s covenants and obligations with respect to the 6.25% Series A Convertible Debentures and the 6.25% Series B Convertible Debentures. Copies of the relevant indentures can be found under our profile on www.sedar.com.

Our 6.25% Series A Convertible Debentures matured on December 31, 2014.

Our 6.25% Series B Convertible Debentures have a face value of $1,000, bear interest at the rate of 6.25 percent per annum payable semi-annually in arrears on the last day of March and September of each year and mature on March 31, 2017. The 6.25% Series B Convertible Debentures are convertible at the holder’s option at a conversion price of $11.5116 per Common Share, subject to adjustment in certain events.

Stock Exchange Listings

Our Common Shares are listed and posted for trading on the TSX under the symbol "PGF" and on the NYSE under the symbol "PGH". Our 6.25% Series B Convertible Debentures are listed and posted for trading on the TSX under the symbol "PGF.DB.B".

DIVIDENDS

We currently pay monthly dividends to our Shareholders on the 15^th day of each month or the first business day following the 15^th day. The record date for any dividend is on or about the 22^nd day of the month preceding the dividend date or such other date as may be determined by our Board. In accordance with stock exchange rules, an ex-dividend date occurs two trading days prior to the record date to permit time for settlement of trades of securities and dividends must be declared a minimum of seven trading days before the record date. A list of all anticipated dividend record dates for 2015 can be found at www.pengrowth.com/investors/dividends/.

Historical Dividends

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

30 | ANNUAL INFORMATION FORM

The following table sets forth dividends declared by the Corporation in 2014, 2013 and 2012 on the outstanding Common Shares for the periods indicated, with each amount being paid in the following month:

Month	2014 ($/share)	2013 ($/share)	2012 ($/share)
January	0.04	0.04	0.07
February	0.04	0.04	0.07
March	0.04	0.04	0.07
April	0.04	0.04	0.07
May	0.04	0.04	0.07
June	0.04	0.04	0.07
July	0.04	0.04	0.04
August	0.04	0.04	0.04
September	0.04	0.04	0.04
October	0.04	0.04	0.04
November	0.04	0.04	0.04
December	0.04	0.04	0.04
Total	0.48	0.48	0.66

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

Restrictions on Dividends

Our ability to pay cash dividends to Shareholders may be directly or indirectly affected in certain events as a result of certain restrictions, including restrictions set forth in: (i) the credit agreement relating to our Credit Facility; (ii) the note purchase agreements relating to the 2007 US Senior Notes, the 2008 Senior Notes, the 2010 Senior Notes, the 2012 Senior Notes and the UK Senior Notes; and (iii) the solvency tests in the ABCA. In particular, the funds required to satisfy the interest payable on the foregoing obligations, as well as the amounts payable upon the redemption or maturity of such obligations, as applicable, or upon an Event of Default (as defined below), will be deducted and withheld from the amounts that would otherwise be payable as dividends to Shareholders.

ABCA Solvency Tests

The payment of dividends by a corporation is governed by the liquidity and insolvency tests described in the ABCA. Pursuant to the ABCA, after the payment of a dividend, we must be able to pay our liabilities as they become due, and the realizable value of our assets must be greater than our liabilities and the legal stated capital of our outstanding securities. As at December 31, 2014, our legal stated capital was approximately $1.581 billion.

Revolving Credit Facility

The credit agreement relating to the Credit Facility stipulates that we shall not make or agree to make cash dividends or other distributions to Shareholders when a "Default" (subject to certain exceptions) or an "Event of Default" has occurred or is continuing or would reasonably be expected to occur as a result of such dividend or distribution. "Events of Default" are defined in the credit agreements to include those events of default typically referred to in a loan agreement of such type and include, among other things; (i) the failure to repay amounts owing under the Credit Facility; (ii) our voluntary or involuntary insolvency; (iii) the default of obligations owing under other debt arrangements; and (iv) a change in control of us. "Default" is defined in the credit agreement to mean any event or circumstance which, with the giving of notice or lapse of time or otherwise, would constitute an Event of Default.

On January 24, 2014, we amended our credit facility by increasing the maximum permitted Senior Debt to EBITDA ratio from 3.0 to 3.5 and the Total Debt to EBITDA ratio from 3.5 to 4.0 until December 31, 2015. The ratios revert back to their prior permitted levels of 3.0 and 3.5, respectively, after December 31, 2015. The covenant amendments were obtained as a proactive step while Pengrowth completes construction of the first 12,500 bbl/d commercial phase of Lindbergh and until a full year of Lindbergh production can contribute to the EBITDA calculation. Pengrowth’s current forecast does not project violating the covenants.

In addition to the standard representations, warranties and covenants commonly contained in a credit facility of this nature, the Credit Facility includes the following key financial covenants as at February 26, 2015:

• The ratio of Senior Debt (as defined below) to EBITDA (as defined below) at the end of any fiscal quarter shall not exceed 3.5:1 prior to December 31, 2015, after which the covenant is reduced to 3.0:1;

• The ratio of Total Debt (as defined below) to EBITDA (as defined below) at the end of any fiscal quarter shall not exceed 4.0:1 prior to December 31, 2015, after which the covenant is reduced to 3.5:1; and

• The ratio of Senior Debt (as defined below) to Total Capitalization (as defined below) shall not exceed 50 percent, except upon the completion of a Material Acquisition, and for a period extending to the end of the second fiscal quarter thereafter, this limit increases to 55 percent.

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With respect to the financial covenants, the following definitions apply to the Corporation:

Senior Debt:	All obligations, liabilities and indebtedness classified as debt on the balance sheet of the Corporation.
Total Debt:	The aggregate of Senior Debt and Subordinated Debt.
EBITDA:	The aggregate of the last four fiscal quarters’ net income from operations plus the sum of:
	•Income taxes; •Interest expense; •All provisions for federal, provincial or other income and capital taxes; •Depreciation, depletion and amortization expense; and •Other non-cash items.
Material Acquisition:	An acquisition or series of acquisitions which increases the tangible assets of Pengrowth by more than five percent.
Subordinated Debt:	Debt which, by its terms, is subordinated to the lenders under the Credit Facility.
Total Capitalization:	The aggregate of Total Debt and the Shareholders Equity (calculated in accordance with GAAP as shown on the Corporation’s balance sheet).

Senior Unsecured Notes

The terms of the note agreements ensure note holders have priority over our Shareholders with respect to our assets and income.

The holders of the US Senior Notes, UK Senior Notes and the Canadian Senior Notes are entitled to certain remedies upon the occurrence of an "Event of Default", which remedies may restrict our ability to pay dividends to Shareholders. An "Event of Default" is defined in the note purchase agreements to include those events of default which are typically referred to in a note purchase agreement of a similar nature (including failure to pay principal and interest when due, default in compliance with other covenants, inaccuracy of representations and warranties, cross default to other indebtedness, certain events of insolvency or the rendering of judgments against the Corporation in excess of certain threshold amounts). "Default" is defined in the note agreements to mean any event or circumstance which, after the giving of notice or lapse of time or both, would constitute an Event of Default.

In addition to standard representations, warranties and covenants the note agreements contain the following key financial covenants:

• The ratio of EBITDA (as defined below) to interest expense for the four immediately preceding fiscal quarters shall not be less than 4:1;

• With respect to the UK Senior Notes the Total Debt (as defined below) is limited to 60 percent of the Total Established Reserves (as defined below) determined and calculated not later than the last day of the first fiscal quarter of the next succeeding fiscal year of the Corporation;

• With respect to the 2012 Senior Notes, 2010 US Senior Notes, 2008 US Senior Notes, the 2007 US Senior Notes and the CDN Senior Notes the Total Debt (as defined below) to Total Capitalization (as defined below) shall not exceed 55 percent at the end of each fiscal quarter; and

• The ratio of Total Debt to EBITDA for each period of four consecutive fiscal quarters shall not exceed 3.5:1

With respect to these financial covenants, the following definitions apply to the Corporation:

EBITDA:	The sum of the last four fiscal quarters of (i) net income determined in accordance with GAAP; (ii) all provisions for federal, provincial or other income and capital taxes; (iii) all provisions for depletion, depreciation, and amortization, (iv) interest expense; and (v) non-cash items
Total Debt:	Has substantially the same meaning as "Senior Debt" in the definitions relating to the Credit Facility.
Total Established Reserves:	The sum of (i) 100 percent of the present value of Pengrowth’s Proved Reserves; and (ii) 50 percent of the present value of Pengrowth’s Probable Reserves.
Total Capitalization:	Total Debt plus Shareholder equity in the Corporation

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INDUSTRY CONDITIONS

Companies operating in the oil and natural gas industry are subject to extensive regulation and control of operations (including land tenure, exploration, development, production, refining and upgrading, transportation, and marketing) as a result of legislation enacted by various levels of government with respect to the pricing and taxation of oil and natural gas through agreements among the governments of Canada, Alberta, British Columbia, Saskatchewan and Nova Scotia, all of which should be carefully considered by investors in the oil and gas industry. All current legislation is a matter of public record and we are unable to predict what additional legislation or amendments may be enacted. Outlined below are some of the principal aspects of legislation, regulations and agreements governing the oil and gas industry.

Pricing and Marketing

Oil

The producers of oil are entitled to negotiate sales contracts directly with oil purchasers, with the result that the market determines the price of oil. Worldwide supply and demand factors primarily determine oil prices; however, prices are also influenced by regional market and transportation issues. The specific price depends in part on oil quality, prices of competing fuels, distance to market, availability and cost of transportation capacity to various markets, value of refined products, the supply/demand balance, and contractual terms of sale. Oil exporters are also entitled to enter into export contracts with terms not exceeding one year in the case of light crude oil and two years in the case of heavy crude oil, provided that an order approving such export has been obtained from the National Energy Board of Canada (the "NEB"). Any oil export to be made pursuant to a contract of longer duration (to a maximum of 25 years) requires an exporter to obtain an export licence from the NEB. The NEB is currently undergoing a consultation process to update the regulations governing the issuance of export licences. The updating process is necessary to meet the criteria set out in the federal Jobs, Growth and Long-term Prosperity Act (Canada) (the "Prosperity Act") which received Royal Assent on June 29, 2012. In this transitory period, the NEB has issued, and is currently following an "Interim Memorandum of Guidance concerning Oil and Gas Export Applications and Gas Import Applications" under Part VI of the National Energy Board Act (Canada).

Natural Gas

Supply and demand determine the price of natural gas and price is calculated at the sale point, being the wellhead, the outlet of a gas processing plant, on a gas transmission system such as the Alberta "NIT" (Nova Inventory Transfer), at a storage facility, at the inlet to a utility system or at the point of receipt by the consumer. Accordingly, the price for natural gas is dependent upon such producer's own arrangements (whether long or short term contracts and the specific point of sale). As natural gas is also traded on trading platforms such as the Natural Gas Exchange ("NGX"), Intercontinental Exchange or the New York Mercantile Exchange ("NYMEX") in the United States, spot and future prices can also be influenced by supply and demand fundamentals on these platforms. Natural gas exported from Canada is subject to regulation by the NEB and the Government of Canada. Exporters are free to negotiate prices and other terms with purchasers, provided that the export contracts must continue to meet certain other criteria prescribed by the NEB and the Government of Canada. Natural gas (other than propane, butane and ethane) exports for a term of less than two years or for a term of two to 20 years (in quantities of not more than 30,000 m³/day) must be made pursuant to an NEB order. Any natural gas export to be made pursuant to a contract of longer duration (to a maximum of 25 years) or for a larger quantity requires an exporter to obtain an export licence from the NEB.

Natural Gas Liquids

The price of NGL sold in intraprovincial, interprovincial and international trade is determined by negotiation between buyers and sellers. Such price depends, in part, on the quality of the NGL, prices of competing chemical feed stock, distance to market, access to downstream transportation, length of contract term, the supply/demand balance and other contractual terms. NGL exported from Canada are subject to regulation by the NEB and the Government of Canada. Exporters are free to negotiate prices and other terms with purchasers, provided that the export contracts must continue to meet certain criteria prescribed by the NEB and the Government of Canada. NGL may be exported for a term of no more than one year in respect to propane and butane, and no more than two years in respect to ethane, all exports requiring an order of the NEB.

The North American Free Trade Agreement

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

All three signatory countries are prohibited from imposing a minimum or maximum export price requirement in any circumstance where any other form of quantitative restriction is prohibited. The signatory countries are also prohibited from imposing a minimum or maximum import price requirement except as permitted in enforcement of countervailing and anti-dumping orders and undertakings. NAFTA requires energy regulators to ensure the orderly and equitable implementation of any regulatory changes and to ensure that the application of those changes will cause minimal disruption to contractual arrangements and avoid undue interference with pricing, marketing and

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distribution arrangements, all of which are important for Canadian oil and natural gas exports. NAFTA contemplates the reduction of Mexican restrictive trade practices in the energy sector and prohibits discriminatory border restrictions and export taxes.

Royalties and Incentives

General

In addition to federal regulation, each province has legislation and regulations, which govern royalties, production rates and other matters. The royalty regime in a given province is a significant factor in the profitability of oil sands projects, crude oil, natural gas liquids, sulphur and natural gas production. Royalties payable on production from lands other than Crown lands 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 product produced. Other royalties and royalty‑like interests are carved out of the working interest owner's interest, from time to time, through non‑public transactions. These are often referred to as overriding royalties, gross overriding royalties, net profits interests, or net carried interests.

Occasionally the governments of the western Canadian provinces create incentive programs for exploration and development. Such programs often provide for royalty rate reductions, royalty holidays or royalty tax credits and are generally introduced when commodity prices are low to encourage exploration and development activity by improving earnings and cash flow within the industry.

Alberta

Producers of oil and natural gas from Crown lands in Alberta are required to pay annual rental payments, currently at a rate of $3.50 per hectare, and make monthly royalty payments in respect of oil and natural gas produced.

Royalties are currently paid pursuant to "The New Royalty Framework" (implemented by the Mines and Minerals (New Royalty Framework) Amendment Act, 2008) and the "Alberta Royalty Framework", which was implemented in 2010.

Royalty rates for conventional oil are set by a single sliding rate formula, which is applied monthly and incorporates separate variables to account for production rates and market prices. The maximum royalty payable under the royalty regime is 40 percent. Royalty rates for natural gas under the royalty regime are similarly determined using a single sliding rate formula with the maximum royalty payable under the royalty regime set at 36 percent.

Oil sands projects are also subject to Alberta's royalty regime. Prior to payout of an oil sands project, the royalty is payable on gross revenues of an oil sands project. Gross revenue royalty rates range between one percent to nine percent depending on the market price of oil, determined using the average monthly price, expressed in Canadian dollars, for WTI crude oil at Cushing, Oklahoma: rates are one percent when the market price of oil is less than or equal to $55 per barrel and increase for every dollar of market price of oil increase to a maximum of nine percent when 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 one percent to nine percent and the net revenue royalty based on the net revenue royalty rate. Net revenue royalty rates start at 25 percent and increase for every dollar of market price of oil increase above $55 up to 40 percent when oil is priced at $120 or higher. In addition, concurrently with the implementation of The New Royalty Framework, the Government of Alberta renegotiated existing contracts with certain oil sands producers that were not compatible with the new royalty regime.

Producers of oil and natural gas from freehold lands in Alberta are required to pay freehold mineral tax. The freehold mineral tax is a tax levied by the Government of Alberta on the value of oil and natural gas production from non-Crown lands and is derived from the Freehold Mineral Rights Tax Act (Alberta). The freehold mineral tax is levied on an annual basis on calendar year production 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. The basic formula for the assessment of freehold mineral tax is: revenue less allocable costs equals net revenue divided by wellhead production equals the value based upon unit of production. If payors do not wish to file individual unit values, a default price is supplied by the Crown. On average, the tax levied is four percent of revenues reported from fee simple mineral title properties.

The Government of Alberta has from time to time implemented drilling credits, incentives or transitional royalty programs to encourage oil and gas development and new drilling. For example, the Innovative Energy Technologies Program (the "IETP"), which is currently in place, has the stated objectives of increasing recovery from oil and gas deposits, finding technical solutions to the gas over bitumen issue, improving the recovery of bitumen by in-situ and mining techniques and improving the recovery of natural gas from coal seams. The IETP provides royalty adjustments to specific pilot and demonstration projects that utilize new or innovative technologies to increase recovery from existing reserves.

In addition, the Government of Alberta has implemented certain initiatives intended to accelerate technological development and facilitate the development of unconventional resources (the "Emerging Resource and Technologies Initiative"). Specifically:

• Coalbed methane wells will receive a maximum royalty rate of five percent for 36 producing months on up to 750 MMcf of production, retroactive to wells that began producing on or after May 1, 2010;

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• Shale gas wells will receive a maximum royalty rate of five percent for 36 producing months with no limitation on production volume, retroactive to wells that began producing on or after May 1, 2010;

• Horizontal gas wells will receive a maximum royalty rate of five percent for 18 producing months on up to 500 MMcf of production, retroactive to wells that commenced drilling on or after May 1, 2010; and

• Horizontal oil wells and horizontal non-project oil sands wells will receive a maximum royalty rate of five percent with volume and production month limits set according to the depth of the well (including the horizontal distance), retroactive to wells that commenced drilling on or after May 1, 2010.

British Columbia

Producers of oil and natural gas from Crown lands in British Columbia are required to pay annual rental payments, currently at a rate of $3.50 per hectare, and make monthly royalty payments in respect of oil and natural gas produced. The amount payable as a royalty in respect of oil depends on the type and vintage of the oil, the quantity of oil produced in a month and the value of that oil. Generally, oil is classified as either light or heavy and the vintage of oil is based on the determination of whether the oil is produced from a pool discovered before October 31, 1975 ("old oil"), between October 31, 1975 and June 1, 1998 ("new oil"), or after June 1, 1998 or through an enhanced oil recovery ("EOR") scheme ("third tier oil"). The royalty calculation takes into account the production of oil on a well-by-well basis, the specified royalty rate for a given vintage of oil, the average unit selling price of the oil and any applicable royalty exemptions. Royalty rates are reduced on low-productivity wells, reflecting the higher unit costs of extraction, and are the lowest for third tier oil, reflecting the higher unit costs of both exploration and extraction.

The royalty payable in respect of natural gas produced on Crown lands is determined by a sliding scale formula based on a reference price, which is the greater of the average net price obtained by the producer and a prescribed minimum price. For non-conservation gas (not produced in association with oil), the royalty rate depends on the date of acquisition of the oil and natural gas tenure rights and the spud date of the well and may also be impacted by the select price, a parameter used in the royalty rate formula to account for inflation. Royalty rates are fixed for certain classes of non-conservation gas when the reference price is below the select price. Conservation gas is subject to a lower royalty rate than non‑conservation gas. Royalties on natural gas liquids are levied at a flat rate of 20 percent of the sales volume.

Producers of oil and natural gas from freehold lands in British Columbia are required to pay monthly freehold production taxes. For oil, the level of the freehold production tax is based on the volume of monthly production. It 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 freehold production tax is either a flat rate, or, at certain production levels, is determined using a sliding scale formula based on the reference price similar to that applied to natural gas production on Crown land, and depends on whether the natural gas is conservation gas or non-conservation gas. The production tax rate for freehold natural gas liquids is a flat rate of 12.25 percent.

As of January 1, 2017, all liquified natural gas ("LNG") facilities will be subject to a 3.5 percent income tax. This income tax is scheduled to increase to five percent in 2037. During the period in which net operating losses and capital investment are deducted, a tax rate of 1.5 percent will apply to the taxpayer's net income. Once the net operating losses and capital investment have been depleted, the full rate of 3.5 percent is payable. To encourage investment, the British Columbia government has said that it will offer a corporate income tax credit to any LNG taxpayer based on the amount of LNG acquired for an LNG facility.

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, including the following:

• Deep Well Royalty Credit Program providing a royalty credit for natural gas wells defined in terms of a dollar amount applied against royalties, is well specific and applies to drilling and completion costs for vertical wells with a true vertical depth greater than 2,500 metres and horizontal wells with a true vertical depth greater than 1,900 metres (or 2,300 metres if spud before September 1, 2009) and if certain other criteria are met and is intended to reflect the higher drilling and completion costs. Effective April 1, 2014, there are two tiers to the Deep Well Royalty Credit Program, "tier one" and "tier two". The pre-existing Deep Well Royalty Credit Program, as described above, will comprise tier two of the program. Tier one of the Deep Well Royalty Credit Program applies to shallower horizontal wells with a true vertical depth less than or equal to 1,900 metres if spud after March 31, 2014;

• Deep Re-Entry Royalty Credit Program providing a royalty credit for deep re-entry wells with a true vertical depth to the top of pay of the re-entry well event that is greater than 2,300 metres and a re-entry date after November 30, 2003; or if the well was spud on or after January 1, 2009, with a true vertical depth to the completion point of the re-entry well event being greater than 2,300 metres;

• Deep Discovery Royalty Credit Program providing the lesser of a 3-year royalty holiday or 283,000,000 m³ of royalty free gas for deep discovery wells with a true vertical depth greater than 4,000 metres whose surface locations are at least 20 kilometres away from the surface location of any well drilled into a recognized pool within the same formation;

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• Coalbed Gas Royalty Reduction and Credit Program providing a royalty reduction for coalbed gas wells with average daily production less than 17,000 m³ as well as a royalty credit for coalbed gas wells equal to $50,000 for wells drilled on Crown land and a tax credit equal to $30,000 for wells drilled on freehold land;

• Marginal Royalty Reduction Program providing a monthly royalty reduction for low productivity natural gas wells with an average daily rate of production less than 23 m³ for every metre of marginal well depth in the first 12 months of production. To be eligible, wells must have been spudded after May 31, 1998 and the first month of marketable gas production must have occurred between June 2003 and August 2008. Once a well passes the initial eligibility test, a reduction is realized in each month that average daily production is less than 25,000 m³;

• Ultra-Marginal Royalty Reduction Program providing royalty reductions for low productivity, shallow natural gas wells. Vertical wells must be less than 2,500 metres and horizontal wells less than 2,300 metres to be eligible. Production in the first 12 months ending after January 2007 must be less than 17 m³ per metre of depth for exploratory wildcat wells and less than 11 m³ per metre of depth for development wells and exploratory outpost wells. The well must have been spudded or re-entered after December 31, 2005. A reduction is realized in each month that average daily production is less than 60,000 m³. Horizontal wells that are spud on or after April 1, 2014 are not eligible for the Ultra-Marginal Royalty Reduction Program due to the potential for overlap with shallower horizontal wells eligible for a royalty credit under the Deep Well Royalty Credit Program; and

• Net Profit Royalty Reduction Program providing reduced initial royalty rates to facilitate the development and commercialization of technically complex resources such as coalbed gas, tight gas, shale gas and enhanced-recovery projects, with higher royalty rates applied once capital costs have been recovered.

Oil produced from an oil well that is located on either Crown or freehold land and completed in a new pool discovered subsequent to June 30, 1974 may also be exempt from the payment of a royalty for the first 36 months of production or 11,450 m³ of production, whichever comes first.

The Government of British Columbia also maintains an Infrastructure Royalty Credit Program that provides royalty credits for up to 50 percent of the cost of certain approved road construction or pipeline infrastructure projects intended to facilitate increased oil and gas exploration and production in under-developed areas and to extend the drilling season.

The Petroleum and Natural Gas Royalty and Freehold Production Tax Regulation has been amended effective April 1, 2013 to provide for a three percent minimum royalty on affected wells with deep well/deep re-entry credits. The three percent minimum royalty applies to deep wells when the net royalty payable would otherwise be zero for a production month.

Saskatchewan

In Saskatchewan, taxes ("Resources Surcharge") and royalties are applicable to revenue generated by corporations focused on oil and gas operations.

A Resource Surcharge on the value of sales of oil, natural gas, potash, uranium and coal in Saskatchewan is levied under authority of The Corporation Capital Tax Act. For resource corporations, the Resource Surcharge rate is three percent of the value of sales of all potash, uranium and coal produced in Saskatchewan, and oil and natural gas produced from wells drilled in Saskatchewan prior to October 2, 2002. For oil and natural gas produced from wells drilled in Saskatchewan after September 30, 2002, the Resource Surcharge rate is 1.7 percent of the value of sales. The Resource Surcharge applies to resource trusts in addition to resource corporations.

The amount payable as a Crown royalty or a freehold production tax in respect of oil depends on the type and vintage of oil, the quantity of oil produced in a month, the value of the oil produced and specified adjustment factors determined monthly by the provincial government. For Crown royalty and freehold production tax purposes, conventional oil is divided into "types", being "heavy oil", "southwest designated oil" or "non‑heavy oil other than southwest designated oil". The conventional royalty and production tax classifications (“fourth tier oil”, “third tier oil”, “new oil” and “old oil”) depend on the finished drilling date of a well and are applied to each of the three crude oil types slightly differently. Heavy oil is classified as third tier oil (produced from a vertical well having a finished drilling date on or after January 1, 1994 and before October 1, 2002 or incremental oil from new or expanded waterflood projects with a commencement date on or after January 1, 1994 and before October 1, 2002), fourth tier oil (having a finished drilling date on or after October 1, 2002 or incremental oil from new or expanded waterflood projects with a commencement date on or after October 1, 2002) or new oil (conventional oil that is not classified as third tier oil or fourth tier oil). Southwest designated oil uses the same definition of fourth tier oil but third tier oil is defined as conventional oil produced from a vertical well having a finished drilling date on or after February 9, 1998 and before October 1, 2002 or incremental oil from new or expanded waterflood projects with a commencement date on or after February 9, 1998 and before October 1, 2002 and new oil is defined as conventional oil produced from a horizontal well having a finished drilling date on or after February 9, 1998 and before October 1, 2002. For non-heavy oil other than southwest designated oil, the same classification as heavy oil is used but new oil is defined as conventional oil produced from a vertical well completed after 1973 and having a finished drilling date prior to 1994, conventional oil produced from a horizontal well having a finished drilling date on or after April 1, 1991 and before October 1, 2002, or incremental oil from new or expanded waterflood projects with a commencement date on or after January 1, 1974 and before 1994 whereas old oil is defined as conventional oil not classified as third or fourth tier oil or new oil. Production tax rates for freehold production

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are determined by first determining the Crown royalty rate and then subtracting the "Production Tax Factor" ("PTF") applicable to that classification of oil. Currently the PTF is 6.9 for old oil, 10.0 for new oil and third tier oil and 12.5 for fourth tier oil. The minimum rate for freehold production tax is zero.

Base prices are used to establish lower limits in the price-sensitive royalty structure for conventional oil and apply at a reference well production rate of 100 m³ for old oil, new oil and third tier oil, and 250 m³ per month for fourth tier oil. Where average wellhead prices are below the established base prices of $100 per m³ for third and fourth tier oil and $50 per m³ for new oil and old oil, base royalty rates are applied. Base royalty rates are five percent for all fourth tier oil, ten percent for heavy oil that is third tier oil or new oil, 12.5  percent for southwest designated oil that is third tier oil or new oil, 15 percent for non‑heavy oil other than southwest designated oil that is third tier or new oil, and 20 percent for old oil. Where average wellhead prices are above base prices, marginal royalty rates are applied to the proportion of production that is above the base oil price. Marginal royalty rates are 30 percent for all fourth tier oil, 25 percent for heavy oil that is third tier oil or new oil, 35 percent for southwest designated oil that is third tier oil or new oil, 35 percent for non‑heavy oil other than southwest designated oil that is third tier or new oil, and 45 percent for old oil.

The amount payable as a Crown royalty or a freehold production tax in respect of natural gas production is determined by a sliding scale based on the monthly provincial average gas price published by the Saskatchewan government, the quantity produced in a given month, the type of natural gas, and the classification of the natural gas. Like conventional oil, natural gas may be classified as "non‑associated gas" (gas produced from gas wells) or "associated gas" (gas produced from oil wells) and royalty rates are determined according to the finished drilling date of the respective well. Non-associated gas is classified as new gas (having a finished drilling date before February 9, 1998 with a first production date on or after October 1, 1976), third tier gas (having a finished drilling date on or after February 9, 1998 and before October 1, 2002), fourth tier gas (having a finished drilling date on or after October 1, 2002) and old gas (not classified as either third tier, fourth tier or new gas). A similar classification is used for associated gas except that the classification of old gas is not used, the definition of fourth tier gas also includes production from oil wells with a finished drilling date prior to October 1, 2002, where the individual oil well has a gas-oil production ratio in any month of at least 3,500 m³ of gas for every m³ of oil, and new gas is defined as oil produced from a well with a finished drilling date before February 9, 1998 that received special approval, prior to October 1, 2002, to produce oil and gas concurrently without gas-oil ratio penalties. Natural gas liquids and by‑products recovered at gas processing plants are not subject to a royalty. Gas liquids which are produced and measured at the wellhead are treated as crude oil for royalty purposes.

On December 9, 2010, the Government of Saskatchewan enacted the Freehold Oil and Gas Production Tax Act, 2010 with the intention to facilitate the efficient payment of freehold production taxes by industry. Two new regulations with respect to this legislation are: (i) The Freehold Oil and Gas Production Tax Regulations, 2012 which sets out the terms and conditions under which the taxes are calculated and paid; and (ii) The Recovered Crude Oil Tax Regulations, 2012 which sets out the terms and conditions under which taxes on recovered crude oil that was delivered from a crude oil recovery facility on or after March 1, 2012 are to be calculated and paid.

As with conventional oil production, base prices based on a well reference rate of 250 10³ m³/month are used to establish lower limits in the price-sensitive royalty structure for natural gas. Where average field-gate prices are below the established base prices of $1.35 per gigajoulefor third and fourth tier gas and $0.95 per gigajoulefor new gas and old gas, base royalty rates are applied. Base royalty rates are five percent for all fourth tier gas, 15 percent for third tier or new gas, and 20 percent for old gas. Where average well‑head prices are above base prices, marginal royalty rates are applied to the proportion of production that is above the base gas price. Marginal royalty rates are 30 percent for all fourth tier gas, 35 percent for third tier and new gas, and 45 percent for old gas. The current regulatory scheme provides for certain differences with respect to the administration of "fourth tier gas" which is associated gas.

The Government of Saskatchewan currently provides a number of targeted incentive programs. These include both royalty reduction and incentive volume programs, including the following:

• Royalty/Tax Incentive Volumes for Vertical Oil Wells Drilled on or after October 1, 2002 providing reduced Crown royalty (a Crown royalty rate of the lesser of fourth tier oil Crown royalty rate and 2.5 percent) and freehold tax rates (a freehold production tax rate of zero percent) on incentive volumes of 8,000 m³ for deep development vertical oil wells, 4,000 m³ for non-deep exploratory vertical oil wells and 16,000 m³ for deep exploratory vertical oil wells (more than 1,700 metres or within certain formations) and after the incentive volume is produced, the oil produced will be subject to the "fourth tier" royalty tax rate;

• Royalty/Tax Incentive Volumes for Exploratory Gas Wells Drilled on or after October 1, 2002 providing reduced Crown royalty (a Crown royalty rate of the lesser of fourth tier oil Crown royalty rate and 2.5 percent) and freehold tax rates (a freehold production tax rate of zero percent) on incentive volumes of 25,000,000 m³ for qualifying exploratory gas wells;

• Royalty/Tax Incentive Volumes for Horizontal Oil Wells Drilled on or after October 1, 2002 providing reduced Crown royalty (a Crown royalty rate of the lesser of fourth tier oil Crown royalty rate and 2.5 percent) and freehold tax rates (a freehold production tax rate of zero percent) on incentive volumes of 6,000 m³ for non-deep horizontal oil wells and 16,000 m³ for deep horizontal oil wells (more than 1,700 metres total vertical depth or within certain formations) and after the incentive volume is produced, the oil produced will be subject to the "fourth tier" royalty tax rate;

• Royalty/Tax Incentive Volumes for Horizontal Gas Wells drilled on or after June 1, 2010 and before April 1, 2013 providing for a classification of the well as a qualifying exploratory gas well and resulting in a reduced Crown royalty (a Crown royalty

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rate of the lesser of fourth tier oil Crown royalty rate and 2.5 percent) and freehold tax rates (a freehold production tax rate of zero percent) on incentive volumes of 25,000,000 m³ for horizontal gas wells and after the incentive volume is produced, the gas produced will be subject to the "fourth tier" royalty tax rate;

• Royalty/Tax Regime for Incremental Oil Produced from New or Expanded Waterflood Projects Implemented on or after October 1, 2002 whereby incremental production from approved waterflood projects is treated as fourth tier oil for the purposes of Crown royalty and freehold tax calculations;

• Royalty/Tax Regime for Enhanced Oil Recovery Projects (Excluding Waterflood Projects) Commencing prior to April 1, 2005 providing lower Crown royalty and freehold tax determinations based in part on the profitability of EOR projects during and subsequent to the payout of the EOR operations;

• Royalty/Tax Regime for Enhanced Oil Recovery Projects (Excluding Waterflood Projects) Commencing on or after April 1, 2005 providing a Crown royalty of one percent of gross revenues on EOR projects pre-payout and 20 percent of EOR operating income post-payout and a freehold production tax of zero percent pre-payout and eight percent post-payout on operating income from EOR projects; and

• Royalty/Tax Regime for High Water-Cut Oil Wells designed to extend the product lives and improve the recovery rates of high water-cut oil wells and granting third tier oil royalty/tax rates with a Saskatchewan Resource Credit of 2.5 percent for oil produced prior to April 2013 and 2.25 percent for oil produced on or after April 1, 2013 to incremental high water‑cut oil production resulting from qualifying investments made to rejuvenate eligible oil wells and/or associated facilities.

On June 22, 2011, the Government of Saskatchewan released the Upstream Petroleum Industry Associated Gas Conservation Standards, which are designed to reduce emissions resulting from the flaring and venting of associated gas (the "Associated Natural Gas Standards"). The Associated Natural Gas Standards were jointly developed with industry and the implementation of such standards commenced on July 1, 2012 for new wells and facilities licensed on or after such date. The new standards will apply to existing licensed wells and facilities on July 1, 2015.

Nova Scotia

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

Land Tenure

The respective provincial governments predominantly own the rights to crude oil and natural gas located in the western provinces. Provincial governments grant rights to explore for and produce 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. Private ownership of oil and natural gas also exists in such provinces and rights to explore for and produce such oil and natural gas are granted by lease on such terms and conditions as may be negotiated.

Each of the provinces of Alberta, British Columbia, and Saskatchewan has 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 license. On March 29, 2007, British Columbia expanded its policy of deep rights reversion for new leases to provide for the reversion of both shallow and deep formations that cannot be shown to be capable of production at the end of their primary term.

Alberta also has a policy of "shallow rights reversion" which provides for the reversion to the Crown of mineral rights to shallow, non‑productive geological formations for all leases and licenses. For leases and licenses issued subsequent to January 1, 2009, shallow rights reversion will be applied at the conclusion of the primary term of the lease or license.

Production and Operation Regulations

The oil and natural gas industry in Canada is highly regulated and subject to significant control by provincial regulators. Regulatory approval is required for, among other things, the drilling of oil and natural gas wells, construction and operations of facilities, the storage, injection and disposal of substances and the abandonment and reclamation of well-sites. In order to conduct oil and gas operations and remain in good standing with the applicable provincial regulator, we 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 with such legislation, regulations, orders, directives or other directions can be costly and a breach of the same may result in fines or other sanctions.

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Environmental Regulation

The oil and natural gas industry is currently subject to environmental regulations pursuant to a variety of provincial and federal legislation, all of which is subject to governmental review and revision from time to time. Such legislation provides for, among other things, restrictions and prohibitions on the spill, release or emission of various substances produced in association with certain oil and gas industry operations, such as sulphur dioxide and nitrous oxide. 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. Compliance with such legislation can require significant expenditures and a breach of such requirements may result in suspension or revocation of necessary licenses and authorizations, civil liability and the imposition of material fines and penalties.

Federal

Pursuant to the Prosperity Act, the Government of Canada amended or repealed several pieces of federal environmental legislation and in addition, created a new federal environment assessment regime that came in to force on July 6, 2012. The changes to the environmental legislation under the Prosperity Act are intended to provide for more efficient and timely environmental assessments of projects that previously had been subject to overlapping legislative jurisdiction.

Alberta

The regulatory landscape in Alberta has undergone a transformation from multiple regulatory bodies to a single regulator for upstream oil and gas, oil sands and coal development activity. On June 17, 2013, the Alberta Energy Regulator (the "AER") assumed the functions and responsibilities of the former Energy Resources Conservation Board, including those found under the Oil and Gas Conservation Act ("ABOGCA"). On November 30, 2013, the AER assumed the energy related functions and responsibilities of Alberta Environment and Sustainable Resource Development ("AESRD") in respect of the disposition and management of public lands under the Public Lands Act. On March 29, 2014, the AER assumed the energy related functions and responsibilities of AESRD in the areas of environment and water under the Environmental Protection and Enhancement Act and the Water Act, respectively. 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 the transformation to a single regulator is the creation of an enhanced regulatory regime that is efficient, attractive to business and investors, and effective in supporting public safety, environmental management and resource conservation while respecting the rights of landowners.

In December 2008, the Government of Alberta released a new land use policy for surface land in Alberta, the Alberta Land Use Framework (the "ALUF"). The ALUF 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.

The Alberta Land Stewardship Act (the "ALSA") was proclaimed in force in Alberta on October 1, 2009 and provides the legislative authority for the Government of Alberta to implement the policies contained in the ALUF. Regional plans established under the ALSA are deemed to be legislative instruments equivalent to regulations and will be binding on the Government of Alberta and provincial regulators, including those governing the oil and gas industry. In the event of a conflict or inconsistency between a regional plan and another regulation, regulatory instrument or statutory consent, the regional plan will prevail. Further, the ALSA requires local governments, provincial departments, agencies and administrative bodies or tribunals to review their regulatory instruments and make any appropriate changes to ensure that they comply with an adopted regional plan. The ALSA also contemplates the amendment or extinguishment of previously issued statutory consents such as regulatory permits, licenses, registrations, approvals and authorizations for the purpose of achieving or maintaining an objective or policy resulting from the implementation of a regional plan. Among the measures to support the goals of the regional plans contained in the ALSA are conservation easements, which can be granted for the protection, conservation and enhancement of land; and conservation directives, which are explicit declarations contained in a regional plan to set aside specified lands in order to protect, conserve, manage and enhance the environment.

On August 22, 2012, the Government of Alberta approved the Lower Athabasca Regional Plan ("LARP") which came into effect on September 1, 2012. The LARP is the first of seven regional plans developed under the ALUF. LARP covers approximately 93,212 square kilometres and is in the north east corner of Alberta. The region includes a substantial portion of the Athabasca oil sands area, which contains approximately 82 percent of the province's oil sands resources and much of the Cold Lake oil sands area.

LARP establishes six new conservation areas and nine new provincial recreation areas. In conservation and provincial recreation areas, conventional oil and gas companies with pre-existing tenure may continue to operate. Any new petroleum and gas tenure issued in conservation and provincial recreation areas will include a restriction that prohibits surface access. In contrast, oil sands companies' tenure has been (or will be) cancelled in conservation areas and no new oil sands tenure will be issued. While new oil sands tenure will be issued in provincial recreation areas, new and existing oil sands tenure will prohibit surface access.

In July 2014, the Government of Alberta approved the South Saskatchewan Regional Plan ("SSRP") which came into force on September 1, 2014. The SSRP is the second regional plan developed under the ALUF. The SSRP covers approximately 83,764 square kilometres and includes 44 percent of the province's population.

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The SSRP creates four new and four expanded conservation areas, and two new and six expanded provincial parks and recreational areas. Similar to LARP, the SSRP will honour existing petroleum and natural gas tenure in conservation and provincial recreational areas. However, any new petroleum and natural gas tenures sold in conservation areas, provincial parks, and recreational areas will prohibit surface access. However, oil and gas companies must minimize impacts of activities on the natural landscape, historic resources, wildlife, fish and vegetation when exploring, developing and extracting the resources. Freehold mineral rights will not be subject to this restriction.

With the implementation of the new Alberta regulatory structure under the AER, AESRD will remain responsible for development and implementation of regional plans. However, the AER will take on some responsibility for implementing regional plans in respect of energy related activities.

British Columbia

In British Columbia, the Oil and Gas Activities Act (the "OGAA") impacts conventional oil and gas producers, shale gas producers, and other operators of oil and 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 oil and 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 BC Commission to consider these environmental objectives in deciding whether or not to authorize an oil and gas activity. In addition, although not an exclusively environmental statute, the Petroleum and Natural Gas Act, in conjunction with the OGAA, requires proponents to obtain various approvals before undertaking exploration or production work, such as geophysical licences, geophysical exploration project approvals, permits for the exclusive right to do geological work and geophysical exploration work, and well, test hole and water-source well authorizations. Such approvals are given subject to environmental considerations and licences and project approvals can be suspended or cancelled for failure to comply with this legislation or its regulations.

Saskatchewan

In May 2011, Saskatchewan passed changes to The Oil and Gas Conservation Act ("SKOGCA"), the act governing the regulation of resource development operations in the province. Although the associated Bill received Royal Assent on May 18, 2011, it was not proclaimed into force until April 1, 2012, in conjunction with the release of The Oil and Gas Conservation Regulations, 2012 ("OGCR") and The Petroleum Registry and Electronic Documents Regulations ("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, Saskatchewan has implemented a number of operational aspects, including the increased demand for record-keeping, increased testing requirements for injection wells and increased investigation and enforcement powers; and, procedural aspects including those related to Saskatchewan's participation as partner in the Petroleum Registry of Alberta.

Liability Management Rating Programs

Alberta

In Alberta, the AER implements the Licensee Liability Rating Program (the "AB LLR Program"). The AB LLR Program is a liability management program governing most conventional upstream oil and gas wells, facilities and pipelines. The ABOGCA 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 defunct. 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 licencees and 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 liabilities to deemed assets is assessed once each month and failure to post the required security deposit may result in the initiation of enforcement action by the AER.

Effective May 1, 2013, the AER implemented important changes to the AB LLR Program that resulted in a significant increase in the number of oil and gas companies in Alberta that are required to post security. Some of the important changes include:

• a 25 percent increase to the prescribed average reclamation cost for each individual well or facility (which will increase a licensee's deemed liabilities);

• a $7,000 increase to facility abandonment cost parameters for each well equivalent (which will increase a licensee's deemed liabilities);

• a decrease in the industry average netback from a five-year to a three-year average (which will affect the calculation of a licensee's deemed assets, as the reduction from five to three years means the average will be more sensitive to price changes); and

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• a change to the present value and salvage factor, increasing to 1.0 for all active facilities from the current 0.75 for active wells and 0.50 for active facilities (which will increase a licensee's deemed liabilities).

These changes are being implemented over a three-year period, ending May 2015. The first phase was implemented in May 2013, the second phase was implemented in May 2014 and the final phase will be implemented in May 2015. The changes to the AB LLR Program stem from concern that the previous regime significantly underestimated the environmental liabilities of licensees.

On July 4, 2014, the AER introduced 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 will be required to bring 20 percent of its inactive wells into compliance every year, either by reactivating or suspending the wells in accordance with Directive 013 or by abandoning them in accordance with Directive 020: Well Abandonment.

British Columbia

In British Columbia, the Commission implements the Liability Management Rating ("LMR") Program, designed to manage public liability exposure related to oil and gas activities by ensuring that permit holders carry the financial risks and regulatory responsibility of their operations through to regulatory closure. Under the LMR Program, the Commission determines the required security deposits for permit holders under the OGAA. The LMR is the ratio of a permit holder's deemed assets to deemed liabilities. Permit holders whose deemed liabilities exceed deemed assets will be considered high risk and reviewed for a security deposit. Permit holders who fail to submit the required security deposit within the allotted timeframe may be in non-compliance with the OGAA.

Saskatchewan

In Saskatchewan, the Ministry of Economy implements 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 to post a security deposit. The ratio of deemed liabilities to deemed assets is assessed once each month for all licensees of oil, gas and service wells and upstream oil and gas facilities.

Climate Change Regulation

Federal

The Government of Canada is a signatory to the United Nations Framework Convention on Climate Change (the "UNFCCC") and a participant to the Copenhagen Accord (a non-binding agreement created by the UNFCCC which represents a broad political consensus and reinforces commitments to reducing greenhouse gas ("GHG") emissions). On January 29, 2010, Canada inscribed in the Copenhagen Accord its 2020 economy-wide target of a 17 percent reduction of GHG emissions from 2005 levels. This target is aligned with the United States target. In a report dated October 2013, the Government stated that this target represents a significant challenge in light of strong economic growth (Canada's economy is projected to be approximately 31 percent larger in 2010 compared to 2005 levels).

On April 26, 2007, the Government of Canada released "Turning the Corner: An Action Plan to Reduce Greenhouse Gases and Air Pollution" (the "Action Plan") which sets forth a plan for regulations to address both GHGs and air pollution. An update to the Action Plan, "Turning the Corner: Regulatory Framework for Industrial Greenhouse Gas Emissions" was released on March 10, 2008 (the "Updated Action Plan"). The Updated Action Plan outlines emissions intensity-based targets, which will be applied to regulated sectors on a facility-specific, sector-wide basis or company-by-company basis. Although the intention was for draft regulations aimed at implementing the Updated Action Plan to become binding on January 1, 2010, the only regulations being implemented are in the transportation and electricity sectors. The federal government indicates that it is taking a sector-by-sector regulatory approach to reducing GHG emissions and is working on regulations for other sectors. Representatives of the Government of Canada have indicated that the proposals contained in the Updated Action Plan will be modified to ensure consistency with the direction ultimately taken by the United States with respect to GHG emissions regulation. In June 2012, the second US-Canada Clean Energy Dialogue Action Plan was released. The plan renewed efforts to enhance bilateral collaboration on the development of clean energy technologies to reduce GHG emissions.

Alberta

As part of Alberta's 2008 Climate Change Strategy, the province committed to taking action on three themes: (a) conserving and using energy efficiently (reducing GHG emissions); (b) greening energy production; and (c) implementing carbon and capture storage.

As part of its efforts to reduce GHG emissions, Alberta introduced legislation to address GHG emissions: the Climate Change and Emissions Management Act (the "CCEMA") enacted on December 4, 2003 and amended through the Climate Change and Emissions Management Amendment Act, which received royal assent on November 4, 2008. The CCEMA is based on an emissions intensity approach and aims for a 50 percent reduction from 1990 emissions relative to GDP by 2020. The accompanying regulations include the Specified Gas Emitters Regulation ("SGER"), which imposes GHG limits, and the Specified Gas Reporting Regulation, which imposes GHG emissions reporting

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requirements. Alberta facilities emitting more than 100,000 tonnes of GHGs a year are subject to compliance with the CCEMA. Alberta is the first jurisdiction in North America to impose regulations requiring large facilities in various sectors to reduce their GHG emissions.

The SGER, effective July 1, 2007, applies to facilities emitting more than 100,000 tonnes of GHGs in 2003 or any subsequent year, and requires reductions in GHG emissions intensity (e.g. the quantity of GHG emissions per unit of production) from emissions intensity baselines established in accordance with the SGER. The SGER distinguishes between "Established Facilities" and "New Facilities". Established Facilities are defined as facilities that completed their first year of commercial operation prior to January 1, 2000 or that have completed eight or more years of commercial operation. Established Facilities are required to reduce their emissions intensity by 12 percent of their baseline emissions intensity for 2008 and subsequent years. Generally, the baseline for an Established Facility reflects the average of emissions intensity in 2003, 2004 and 2005. New Facilities are defined as facilities that completed their first year of commercial operation on December 31, 2000, or a subsequent year, and have completed less than eight years of commercial operation, or are designated as New Facilities in accordance with the SGER. New Facilities are required to reduce their emissions intensity by two percent from baseline in the fourth year of commercial operation, four percent of their baseline in the fifth year, six  percent of their baseline in the sixth year, eight percent of their baseline in the seventh year and ten percent of their baseline in the eighth year. The CCEMA does not contain any provision for continuous annual improvements in emissions intensity reductions beyond those stated above.

The CCEMA provides that regulated emitters can meet their emissions intensity targets by contributing to the Climate Change and Emissions Management Fund at a rate of $15 per tonne of CO₂ equivalent ("Emission Performance Credits"). The funds contributed by industry to the Climate Change and Emissions Management Fund will be used to drive innovation and test and implement new technologies for green energy production. Emissions credits can also be purchased from regulated emitters that have reduced their emissions below the 100,000 tonne threshold or non-regulated emitters that have generated approved emissions offsets through activities that result in emissions reductions in accordance with established protocols published by the Government of Alberta.

Alberta is also the first jurisdiction in North America to direct dedicated funding to implement carbon capture and storage technology across industrial sectors. Alberta will invest $2 billion into demonstration 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.

Under the Alberta Specified Gas Emitters Regulation ("SGER") and based on 2013 emissions, we purchased Emission Performance Credits in the amount of $700,000, payable to the Climate Change Emission Management Fund for our Quirk Creek Gas Plant. We were not required to purchase Emission Performance Credits for the Olds Gas Plant and Judy Creek Gas Conservation Plant as these facilities met the reduction requirements of the SGER and subsequently received carbon credits for this reduction.

British Columbia

In February 2008, British Columbia announced a revenue-neutral carbon tax that took effect July 1, 2008. The tax is consumption-based and applied at the time of retail sale or consumption of virtually all fossil fuels purchased or used in British Columbia. The current tax level is $30 per tonne of CO₂ equivalent. The final scheduled increase took effect on July 1, 2012. There is no plan for further rate increases or expansions at this time. In order to make the tax revenue-neutral, British Columbia has implemented tax credits and reductions in order to offset the tax revenues that the Government of British Columbia would otherwise receive from the tax.

In the 2012 Budget, British Columbia announced that the government would undertake a comprehensive review of the carbon tax and its impact on British Columbians. The review covered all aspects of the carbon tax, including revenue neutrality, and considered the impact on the competitiveness of British Columbia businesses such as those in the agriculture sector, and in particular, British Columbia's food producers. After the review last year, British Columbia confirmed that it will keep its revenue-neutral carbon tax, the current carbon tax rates and tax base will be maintained and revenues will continue to be returned through tax reductions.

On April 3, 2008, British Columbia introduced the Greenhouse Gas Reduction (Cap and Trade) Act (the "Cap and Trade Act"), which received royal assent on May 29, 2008 and partially came into force by regulation of the Lieutenant Governor in Council. It sets a province-wide target of a 33 percent reduction in the 2007 level of GHG emissions by 2020 and an 80 percent reduction by 2050. Unlike the emissions intensity approach taken by the federal government and the Government of Alberta, the Cap and Trade Act establishes an absolute cap on GHG emissions. The Reporting Regulation, implemented under the authority of the Cap and Trade Act, sets out the requirements for the reporting of the GHG emissions from facilities in British Columbia emitting 10,000 tonnes or more of carbon dioxide equivalent emissions per year beginning on January 1, 2010. Those reporting operations with emissions of 25,000 tonnes or greater are required to have emissions reports verified by a third party. Recent amendments to the Cap and Trade Act repealed past requirements on public-sector organizations, including Crown corporations, to be carbon neutral by 2010, and they are now only required to produce annual carbon reduction plans and reports. Additional regulations that will further enable British Columbia to implement a cap and trade system are currently under development.

We do not currently have any facilities that emit over 10,000 tonnes of CO₂ but we do trigger the Linear Facility definition as we conduct oil and gas extraction and gas processing activities in British Columbia that cumulatively exceed the threshold. As a result, we are required to report our emissions.

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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 received Royal Assent on May 20, 2010 and will come into force on proclamation. The MRGGA establishes a framework for achieving the provincial target of a 20 percent reduction in GHG emissions from 2006 levels by 2020. Although the MRGGA and related regulations have yet to be proclaimed in force, draft versions indicate that Saskatchewan will permit the use of pre-certified investment credits, early action credits and emissions offsets in compliance, similar to the federal climate change initiatives. It remains unclear whether the scheme implemented by the MRGGA will be based on emissions intensity or an absolute cap on emissions.

Nova Scotia

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

General Discussion

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

RISK FACTORS

If any of the following risks occur, our production, revenues and financial condition could be materially impaired, with a resulting decrease in dividends on, and the market price of, our Common Shares. As a result, the trading price of our Common Shares could decline, and you could lose all or part of your investment. Additional risks are described under the heading "Business Risks" in our Management's Discussion and Analysis for the year ended December 31, 2014.

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

Factors unrelated to our performance could include macroeconomic developments nationally, within North America or globally, domestic and global commodity prices or current perceptions of the oil and gas market. Similarly, the market price of our Common Shares could be subject to significant fluctuations in response to variations in our operating results, financial condition, liquidity and other internal factors. Factors that could affect the market price of our Common Shares that are unrelated to our performance include domestic and global commodity prices and market perceptions of the attractiveness of particular industries. The price at which our Common Shares will trade cannot be accurately predicted.

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

The monthly dividends we pay to our Shareholders and the market price of the Common Shares depend, 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 basis in response to a variety of factors that are beyond our control. While oil prices are set in a much broader global market, natural gas prices are largely dependent on North American economies. Additional factors include:

• global energy policy, including the ability of OPEC to set and maintain production levels for oil;

• geo-political conditions;

• worldwide economic conditions including ongoing credit and liquidity concerns;

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

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

• the level of consumer demand;

• the price and availability of alternative fuels;

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

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• the effect of worldwide energy conservation measures; and

• government regulation.

North American crude oil price differentials are expected to continue to be volatile throughout 2015 which will have an impact on crude oil prices for Canadian producers. Overall, supply in excess of current pipeline and refining capacity is expected to exist. Material structural changes are required to reduce these bottlenecks and the resulting steep price discounts. There are numerous projects proposed to alleviate pipeline bottlenecks in the United States, expand refinery capacity and expand or build new pipelines in Canada and the United States to source new markets, many of which are in the regulatory application phase. There can be no assurance that such regulatory approvals will be secured on a timely basis or at all.

Declines in oil or natural gas prices could have a materially adverse effect on our operations, financial condition and proved reserves and ultimately on the market price of the Common Shares and our ability to pay dividends to our Shareholders.

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

The amount of future dividends paid by us, if any, will be subject to the discretion of our Board of Directors and may vary depending on a variety of factors, forecasts and conditions existing from time to time, including fluctuations in commodity prices, production levels, capital expenditure requirements, debt service requirements, operating costs, royalty burdens, foreign exchange rates and the satisfaction of the liquidity and solvency tests imposed by the ABCA for the declaration and payment of dividends. Depending on these and various other factors, many of which will be beyond our control, we may change our dividend policy from time to time and, as a result, future dividends could be reduced or suspended entirely.

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

Dividends may be reduced during periods of lower operating cash flow, which result from lower commodity prices and the decisions by us to otherwise use cash flow.

To the extent that external sources of capital, including the issuance of additional Common Shares, become limited or unavailable, our ability to make the necessary capital investments to maintain or expand petroleum and natural gas reserves and to invest in assets, as the case may be, will be impaired. To the extent that we are required to use funds from operations to finance capital expenditures or property acquisitions, the cash available for dividends may be reduced.

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

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

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

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

Those factors and assumptions include:

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

• the assumed effect of government regulation;

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

• initial production rates;

• production decline rates;

• ultimate recovery of reserves and resources;

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• marketability of production; and

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

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

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

If we are unable to acquire or develop additional reserves, the value of the Common Shares and dividends to our Shareholders 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 participations 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 assure 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-ins of connected wells resulting from extreme weather conditions, insufficient storage or transportation capacity or other geological and mechanical conditions. While diligent well supervision and effective maintenance operations can contribute to maximizing production rates over time, it is not possible to eliminate production delays and declines from normal field operating conditions, which can negatively affect revenue and cash flow levels to varying degrees.

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

Uncertainty in domestic and international credit markets and other financial systems could materially affect our ability to access sufficient capital for our capital expenditures and acquisitions and, as a result, may have a material adverse effect on our ability to execute our business strategy and on our financial condition. There can be no assurance that financing will be available or sufficient to meet these requirements or for other corporate purposes or, if financing is available, that it will be on terms appropriate and acceptable to us. Should the lack of financing and uncertainty in the capital markets adversely impact our ability to refinance debt, additional equity may be issued resulting in a dilutive effect on current and future Shareholders.

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

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

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

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

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• production falls short of the hedged volumes;

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

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

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

Similarly, from time to time we may 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.

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 certain 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.

Compliance with environmental legislation can require significant expenditures and a breach of applicable environmental legislation may result in the imposition of fines and penalties, some of which may be material. Environmental legislation is evolving in a manner expected to result in stricter standards and enforcement, larger fines and liability and potentially increased capital expenditures and operating costs. The discharge of oil, natural gas or other pollutants into the air, soil or water may give rise to liabilities to governments and third parties and may require us to incur costs to remedy such discharge. Although we believe that we will be in material compliance with current applicable environmental regulations, 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.

Our exploration and production facilities and other operations and activities emit greenhouse gases which may require us to comply with greenhouse gas emissions legislation in Alberta and British Columbia or that may be enacted in other provinces.

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 United Nations Framework Convention on Climate Change (the "UNFCCC") and as a participant to the Copenhagen Agreement (a non-binding agreement created by the UNFCCC), the Government of Canada announced on January 29, 2010 that it will seek a 17 percent reduction in GHG emissions from 2005 levels by 2020. These GHG emission reduction targets are not binding, however. Although it is not the case today, some of our significant facilities may ultimately be subject to future regional, provincial and/or federal climate change regulations to manage GHG emissions. The direct or indirect costs of compliance with these regulations may have a material adverse effect on our business, financial condition, results of operations and prospects. Given the evolving nature of the debate related to climate change and the control of greenhouse gases and resulting requirements, it is not possible to predict the impact on us and our operations and financial condition.

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

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

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

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

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

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We cannot predict the impact of changing demand for oil and natural gas products, and any major changes may have a material adverse effect on our business, financial condition, results of operations and cash flows.

Incorrect assessments of value at the time of acquisitions could adversely affect the value of our Common Shares and dividends to our Shareholders.

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.

Our indebtedness may limit the amount of dividends that we are able to pay our Shareholders, and if we default on our debts, the net proceeds of any foreclosure sale would be allocated to the repayment of our lenders, note holders, Convertible Debenture holders and other creditors and only the remainder, if any, would be available for dividend to our Shareholders.

We are indebted under our credit facility, the Convertible Debentures and the Notes. Certain covenants in the agreements with our lenders and with respect to the Notes and the Convertible Debentures may limit the amount of dividends paid to Shareholders. Variations in interest rates, exchange rates and scheduled principal repayments could result in significant changes in the amount we are required to apply to the service of our outstanding indebtedness. If we become unable to pay our debt service charges or otherwise cause an event of default to occur, 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. In any such event, the amount of cash available for dividend may be diluted or adversely impacted and such dilution or impact may be significant.

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 reduce dividends to our Shareholders and 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 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.

Although pipeline expansions are ongoing, the lack of firm pipeline capacity continues to affect the oil industry and limit the ability to produce and market oil production. In addition, the pro-rationing of capacity on inter-provincial pipeline systems continues to affect the ability to export oil. 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 and it is projected to continue in this upward trend. Any significant change in market factors or other conditions affecting these infrastructure systems and facilities, as well as any delays in constructing new infrastructure systems and facilities could harm our business and, in turn, our financial condition, results of operations and cash flows.

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.

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 oil, heavy 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.

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 and dividends to our Shareholders.

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 37 percent of our properties are operated by third parties, based on daily production. If, in situations

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where we are not the operator, the operator fails to perform these functions properly or becomes insolvent, revenues may be reduced. Revenues from production generally flow through the operator and, where we are not the operator; there is a risk of delay and additional expense in receiving such revenues.

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

Our dividends and the market price of the Common Shares could be adversely affected by unforeseen title defects, which could reduce dividends to our Shareholders.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Changes in government regulations that affect the crude oil and natural gas industry could adversely affect us and reduce our dividends to our Shareholders.

Various levels of governments impose extensive controls and regulations on oil and natural gas operations (including exploration, development, production, pricing, marketing and transportation). Governments may regulate or intervene with respect to exploration and production activities, prices, taxes and royalties. Amendments to these controls and regulations may occur from time to time in response to economic or political conditions. The implementation of new regulations or the modification of existing regulations affecting the oil and natural gas industry could reduce demand for crude oil and natural gas and increase our costs, either of which may have a material adverse effect on our business, financial condition, results of operations and prospects. 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 it may wish to undertake. In addition to regulatory requirements pertaining to the production, marketing and sale of oil and natural gas mentioned above, our business and financial condition could be influenced by federal legislation affecting, in particular, foreign investment, through legislation such as the Competition Act (Canada) and the Investment Canada Act (Canada). See “Industry Conditions”.

PENGROWTH ENERGY CORPORATION ANNUAL INFORMATION FORM | 49

Hydraulic Fracturing

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

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

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

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

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

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

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

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

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

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

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

Wet weather and spring thaw may make the ground unstable. Consequently, municipalities and provincial transportation departments enforce road bans that restrict the movement of rigs and other heavy equipment, thereby reducing activity levels. Also, 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. Seasonal factors and unexpected weather patterns may lead to declines in exploration and production activity and corresponding declines in the demand for our goods and services.

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

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

Delays in business operations could adversely affect dividends to Shareholders and 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;

50 | ANNUAL INFORMATION FORM

• 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.

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

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

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

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

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

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

• the availability of processing capacity;

• the availability and proximity of pipeline capacity;

• the availability of storage capacity;

• the supply of and demand for oil and natural gas;

• the availability of alternative fuel sources;

• the effects of inclement weather;

• the availability of drilling and related equipment;

• unexpected cost increases;

• accidental events;

• currency fluctuations;

• changes in regulations;

• the availability and productivity of skilled labour; and

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

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

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

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

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Potential conflicts of interest.

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

Asset Concentration

With the sale of our Weyburn and southeast Saskatchewan assets in 2013, and our decision to invest approximately $2 billion in our Lindbergh Project, our assets have become much less diversified and will become increasingly concentrated in one project, product type (bitumen) and one area/formation. Should this project not be successful, not be completed in the time frame and at the cost estimated, or should the realized sale price of bitumen produced be less than currently anticipated, we may suffer significant financial harm.

LindberghThermal Project Specific Risks

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

Early Stage of Development

There is a risk that design and construction of the facilities and infrastructure to support our Lindbergh thermal project and any future commercial projects will not be completed on time, on budget or at all. Additionally, there is a risk that the Lindbergh thermal project and any future commercial projects may have delays, interruptions of operations or increased costs due to many factors, including, without limitation:

• inability to attract or retain sufficient numbers of qualified workers;

• breakdown or failure of equipment or processes;

• construction performance falling below expected levels of output or efficiency;

• design errors;

• non-performance by, or financial failure of, third-party contractors;

• labour disputes, disruptions or declines in productivity;

• increases in materials or labour costs;

• conditions imposed by regulatory approvals;

• delays induced by weather;

• disruption or delays in availability of pipelines and/or rail transportation services leading to volumes being shut-in or otherwise unable to reach markets;

• errors in construction;

• changes in project scope;

• unforeseen site surface or subsurface conditions;

• transportation or construction accidents;

• permit requirement violation;

• availability of water supplies;

• reservoir performance;

• energy supply disruption; and

• shortages of or delays in accessing drilling rigs and services.

The Lindbergh thermal project is not being 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. Based upon current scheduling, the project is not expected to start commercial SAGD operations until late in the first quarter of 2015. The information contained herein related to the Lindbergh thermal project, including, without limitation, reserve and economic evaluations, assumes receipt of all regulatory approvals and no material changes being made to the project or its scope.

The industry is 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

52 | ANNUAL INFORMATION FORM

us. Cost estimates are provided prior to pilot project results, completion of final scope design and detailed engineering needed to reduce the margin of error. Accordingly, actual costs may vary from estimates and these differences may be material.

Operating Costs

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

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

• the cost of catalyst and chemicals;

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

• the cost of natural gas and electricity;

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

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

• reliability of the facilities;

• the maintenance cost of the facilities;

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

• the cost of insurance; and

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

Infrastructure for the Lindbergh Thermal Project

We will depend, to a large extent, on third party designers, contractors and suppliers to design and construct the necessary facilities and infrastructure for the Lindbergh thermal project. We also anticipate that we will 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 to complete the Lindbergh thermal project on a timely basis and on acceptable commercial terms would negatively impact our operation and financial results.

In-situ Extraction

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

Recovery of Bitumen

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

Access to Diluent Supplies at Favourable Prices

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

Marketing of Production

The market prices for heavy 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 oil. Also, the market for heavy 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 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

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In Alberta, oil sands projects require approvals from AER and AESRD and in some cases require a federal review. The AER and AESRD approvals fall under the EPEA and under the EIA for projects over 2,000 m³/day. These approvals can take 18 months or longer under EPEA or 24 months or longer under EIA. The timing to approval with the regulators represents a risk factor to being allowed to expand the Lindbergh project beyond 12,500 bbl/day. 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, any Statements of Concern submitted by operators, land owners, grazing lease holders, municipalities or Aboriginals in the region as well as any technical or environmental issues identified in the submission itself whether in regard to the surface infrastructure or the subsurface reservoir, cap rock, surface or subsurface water etc. Any of these issues or concerns may take longer to mitigate or eliminate in the view of the regulator and thus could delay approvals. Unresolved Statements of Concern may require a hearing with the regulators which may or may not be resolved in favor of the company and, if resolved via a hearing, will also add delays to the timing of an approval.

MARKET FOR SECURITIES

Our outstanding Common Shares are listed and posted for trading on the NYSE under the symbol "PGH" and on the TSX under the symbol "PGF". The following tables set forth certain trading information for the Common Shares in 2014 as reported by the TSX and the NYSE.

	TSX			NYSE
	($) High	($) Low	Volume	(US$) High	(US$) Low	Volume
January	7.44	6.43	19,119,720	6.70	5.94	33,841,107
February	7.60	6.97	12,309,784	6.88	6.29	21,102,309
March	7.53	6.60	18,433,694	6.80	5.95	32,476,077
April	7.23	6.69	12,744,135	6.60	6.06	19,609,157
May	7.42	6.82	14,059,751	6.80	6.28	23,613,514
June	7.78	6.85	15,087,286	7.21	6.29	27,056,098
July	7.70	6.88	12,386,451	7.22	6.32	24,008,030
August	7.09	6.55	14,146,464	6.51	5.98	25,326,337
September	6.95	5.78	17,301,885	6.38	5.15	34,213,311
October	5.85	4.22	42,314,189	5.23	3.69	70,953,996
November	4.63	3.72	60,501,674	4.09	3.27	64,530,621
December	4.01	2.77	57,765,784	3.45	2.41	98,232,397

Our 6.25% Series A Convertible Debentures were listed and posted for trading on the TSX under the symbol "PGF.DB.A" until their maturity on December 31, 2014. Our 6.25% Series B Convertible Debentures are listed and posted for trading on the TSX under the symbol "PGF.DB.B". The following table sets forth certain trading information for the 6.25% Series A Convertible Debentures and 6.25% Series B Convertible Debentures in 2014 as reported by the TSX.

	6.25% SERIES A CONVERTIBLE DEBENTURES			6.25% SERIES B CONVERTIBLE DEBENTURES
	($) High	($) Low	Volume	($) High	($) Low	Volume
January	102.74	102.21	1,068,000	103.95	102.00	1,690,000
February	102.75	102.21	766,000	104.50	103.50	1,198,000
March	103.33	102.29	1,024,000	104.39	103.79	684,000
April	102.63	101.90	1,153,000	104.50	103.53	838,000
May	102.35	101.80	1,615,000	105.00	104.50	291,000
June	101.95	101.50	2,689,000	105.36	104.55	452,000
July	102.00	101.50	881,000	105.50	104.51	610,000
August	101.57	101.21	960,000	105.00	104.61	313,000
September	101.43	100.50	1,823,000	105.50	104.00	2,657,000
October	101.05	100.21	5,106,000	104.50	101.67	795,000
November	100.64	100.16	9,290,000	103.00	100.00	2,859,333
December	100.20	99.94	2,644,000	100.49	89.95	4,925,000

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:

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Name and Jurisdiction of Residence	Position with Pengrowth	Principal Occupation
John B. Zaozirny(2)(3)  Alberta, Canada	Chairman and Director (Director since 1988)(1)	Vice Chairman of Canaccord Genuity Corp. since May 2010 and prior thereto Vice Chairman of Canaccord Financial Inc.
Derek W. Evans Alberta, Canada	President, Chief Executive Officer and Director (Director since 2009)(1)	President and Chief Executive Officer of Pengrowth.
Margaret L. Byl(4)  Alberta, Canada	Director (Director since 2014)	Executive Coach and Corporate Director since December 2014; prior thereto, Executive Coach, EP Consulting Inc. since 2012; prior thereto, Vice President, ERP Consolidation of Suncor Energy Inc.
Wayne K. Foo(2)(4)  Alberta, Canada	Director (Director since 2006)(1)	President and Chief Executive Officer of Parex Resources Inc. (energy company).
Kelvin B. Johnston(3)(4)  Alberta, Canada	Director (Director since 2012)	President of Wylander Crude Corp. and Vice President, Corporate Development of Lakeview Energy Ltd.
James D. McFarland(4)(5)  Alberta, Canada	Director (Director since 2010)(1)	President, Chief Executive Officer and Director of Valeura Energy Inc. and its predecessor PanWestern Energy Inc. (energy company) since April, 2010 and prior thereto President and Chief Executive Officer of Verenex Energy Inc.
Michael S. Parrett(2)(5)(6)  Ontario, Canada	Director (Director since 2004)(1)	Business Consultant and Corporate Director.
A. Terence Poole(3)(5)  Alberta, Canada	Director (Director since 2005)(1)	Business Consultant and Corporate Director.
Barry D. Stewart(4)(5)  Alberta, Canada	Director (Director since 2012)	Retired Petroleum Industry Executive.
D. Michael G. Stewart(2)(3)  Alberta, Canada	Director (Director since 2006)(1)	Corporate Director.
David P.B. Allen Alberta, Canada	Vice President, Exploration	Vice President, Exploration of Pengrowth since April 2012 and prior thereto Director, Exploration & Development of NAL Energy Corporation from June 2009 to February 2012.
Gillian I. Basford Alberta, Canada	Vice President, Human Resources	Vice President, Human Resources of Pengrowth since January 2011; prior thereto Interim Vice President, Human Resources of Pengrowth Corporation from September 2010 until December 2010; prior thereto independent consultant.
Douglas C. Bowles Alberta, Canada	Vice President and Controller	Vice President and Controller of Pengrowth.
James E.A. Causgrove Alberta, Canada	Senior Vice President, Operations and Engineering	Senior Vice President, Operations and Engineering of Pengrowth since September 8, 2011; prior thereto Vice President, Production and Operations of Pengrowth.
Stephen J. De Maio(7) Alberta Canada	Vice President, In-Situ Development & Operations	Vice President In-Situ Development & Operations of Pengrowth since September 2010; prior thereto Vice-President of Project Development at Connacher Oil and Gas Limited (energy company).
D. Dean Evans Alberta, Canada	Vice President and Treasurer	Vice President and Treasurer of Pengrowth since August 2012 and prior thereto Treasurer of Pengrowth from February 2009 to August 2012.
Andrew D. Grasby Alberta, Canada	Senior Vice President, General Counsel & Corporate Secretary	Senior Vice President, General Counsel & Corporate Secretary of Pengrowth since February 2012; prior thereto Vice President, General Counsel & Corporate Secretary of Pengrowth from September 2010 and prior thereto a partner with McCarthy Tétrault LLP (law firm).
Rebecca D. Greenan Alberta, Canada	Vice President, Marketing	Vice President, Marketing of Pengrowth since August 2012 and prior thereto Director, Marketing of Pengrowth.
Marlon J. McDougall Alberta, Canada	Chief Operating Officer	Chief Operating Officer of Pengrowth since August 2011 and prior thereto, Vice President Operations & Chief Operating Officer of NAL Energy Corporation (energy company).

PENGROWTH ENERGY CORPORATION ANNUAL INFORMATION FORM | 55

Name and Jurisdiction of Residence	Position with Pengrowth	Principal Occupation
Deric S. Orton(8) Alberta, Canada	Vice President, Land	Vice President, Land of Pengrowth since June 2012 and prior thereto Director, Land of NAL Energy Corporation.
Robert W. Rosine Alberta, Canada	Executive Vice-President, Business Development	Executive Vice President, Business Development of Pengrowth since March 2010 and prior thereto President of Mancal Energy Inc. (energy company).
Christopher G. Webster Alberta, Canada	Chief Financial Officer	Chief Financial Officer of Pengrowth.

Notes:

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

(2) Member of Corporate Governance and Nominating Committee.

(3) Member of Compensation Committee.

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

(5) Member of Audit and Risk Committee.

(6) Mr. Parrett was a director of Mongolia Minerals Corporation (a private company involved in mining investments in Mongolia) which filed for protection under the CCAA in June, 2014.

(7) Mr. De Maio was formerly the Chief Executive Officer and a director of Efficient Energy Resources Ltd. (a private electrical generation company) which agreed to the voluntary appointment of a receiver in 2005.

(8) Mr. Orton was formerly an officer of Piper Resources Ltd. (“Piper”) from January 2007 to September 2008. In February 2008, Piper filed for CCAA protection and was declared bankrupt in August 2008.

As at December 31, 2014, the foregoing directors and officers, as a group, beneficially owned, directly or indirectly, 2,679,630 Common Shares or approximately 0.5 percent of the issued and outstanding Common Shares and held rights and options to acquire a further 4,578,948 Common Shares (assuming 100 percent vesting of all performance-based rights). The information as to shares beneficially owned, not being within our knowledge, has been furnished by the respective individuals.

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

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

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

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

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

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

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

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

56 | ANNUAL INFORMATION FORM

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 C. 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
James D. McFarland	Yes	Yes	Mr. McFarland has more than 42 years' experience in the oil and gas industry, most recently as President, Chief Executive Officer, director and co-founder of Valeura Energy Inc., a TSX listed issuer. Prior thereto Mr. McFarland was President, Chief Executive Officer, director and a co-founder of Verenex Energy Inc., a TSX listed issuer. He has served in senior executive roles as Managing Director of Southern Pacific Petroleum N.L. in Australia (an Australian Securities Exchange listed issuer), President and Chief Operating Officer of Husky Oil Limited (a TSX listed issuer) and in a wide range of upstream and corporate functions in an earlier 23-year career with Imperial Oil Limited and other ExxonMobil affiliates in Canada, the US and western Europe. He is also 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.
Michael S. Parrett	Yes	Yes	Mr. Parrett currently serves as a director of Stillwater Mining Company, a NYSE listed company and Centerra Gold Inc., a TSX listed company. He is a director of (Chairman 2010-2013) Mongolia Minerals Corporation and a director of Sunshine Silver Mines Corporation, both private corporations. He was formerly Chairman of Gabriel Resources Limited, President of Rio Algom Limited and prior to that Chief Financial Officer of Rio Algom and Falconbridge Limited. Mr. Parrett has also acted as an independent consultant providing advisory service to various companies in Canada and the United States. Mr. Parrett is a chartered accountant and holds a Bachelor of Arts in Economics from York University.
A. Terence Poole	Yes	Yes	Mr. Poole brings extensive senior financial management, accounting, capital and debt market experience to Pengrowth. He retired from Nova Chemicals Corporation in 2006 where he had held various senior management positions including Executive Vice‑President, Corporate Strategy and Development. Mr. Poole currently serves on the board of directors for Methanex Corporation. Mr. Poole received a Bachelor of Commerce degree from Dalhousie University and holds a Chartered Accountant designation.
Barry D. Stewart	Yes	Yes	Mr. Stewart is a retired petroleum industry executive with over 41 years' experience in the oil and gas industry. Mr. Stewart served as Executive Vice President, In-Situ and International Oil with Suncor Energy Inc. from 2000 to 2001, and Executive Vice President, Exploration & Production with Suncor Energy Inc. from 1991 to 1999. Currently, Mr. Stewart serves as Director and Chairman of Newalta Corporation. Mr. Stewart holds a Bachelor of Science in Engineering Physics from Queen's University.

Principal Accountant Fees and Services

The following table provides information about the aggregate fees billed to us for professional services rendered by KPMG LLP during fiscal 2014 and 2013:

	2014 ($thousands)	2013 ($thousands)
Audit Fees	955	1,012
Audit Related Fees	-	-
Tax Fees	182	49
All Other Fees	143	149
Total	1,280	1,210

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.

PENGROWTH ENERGY CORPORATION ANNUAL INFORMATION FORM | 57

Audit-Related Fees

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

Tax Fees

During 2014 and 2013 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 2014 and 2013 the services provided in this category relate to translation of financial statements, management discussion and analysis and other regulatory filings into French.

Pre-Approval Policies and Procedures

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

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

CONFLICTS OF INTEREST

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

• the issuance of additional Common Shares;

• material acquisitions and dispositions of properties;

• material capital expenditures;

• borrowing; and

• the payment of dividends.

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

LEGAL PROCEEDINGS

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

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

58 | ANNUAL INFORMATION FORM

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 10 percent of our outstanding Common Shares or any known associate or affiliate of such persons, in any transaction within the three most recently completed financial years or during the current financial year that has materially affected or is reasonably expected to materially affect us.

INTERESTS OF EXPERTS

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

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

AUDITORS, TRANSFER AGENT AND REGISTRAR

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

MATERIAL CONTRACTS

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

(i) the Amended and Restated Credit Agreement dated January 1, 2011 between Pengrowth and a syndicate of eleven financial institutions concerning the Credit Facility as amended by amending agreements dated November 29, 2011, July 29, 2013 and January 24, 2014;

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

(iii) the Note Purchase Agreement dated May 11, 2010 concerning the 2010 Senior Notes;

(iv) the Note Purchase Agreement dated August 21, 2008 concerning the 2008 Senior Notes;

(v) the Note Purchase Agreement dated July 26, 2007 concerning the 2007 US Senior Notes; and

(vi) the Note Purchase Agreement dated December 1, 2005 concerning the UK Senior Notes.

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

CODE OF ETHICS

Pengrowth has adopted a code of ethics, as that term is defined in Form 40-F under the US Securities Exchange Act of 1934 (the "Code of Ethics") that applies to Pengrowth's management, including its Chief Executive Officer, Chief Financial Officer and principal accounting officers. The Code of Ethics is available for viewing on our website www.pengrowth.com under the name "Code of Business Conduct and Ethics", and is available in print to any Shareholder who requests it. Requests for copies of the Code of Ethics should be made by contacting: Investor Relations, Pengrowth Energy Corporation, Suite 2100, 222 – 3^rd Avenue S.W., Calgary, Alberta, Canada, T2P 0B4.

The Board adopted an updated Code of Ethics on February 28, 2013. All Directors, officers, employees, consultants and contractors are required to accept the Code of Ethics annually.

During the year ended December 31, 2014, Pengrowth has not granted any waivers (including implicit waivers) from the Code of Ethics in respect of its Chief Executive Officer, Chief Financial Officer or its principal accounting officers.

OFF-BALANCE SHEET ARRANGEMENTS

Pengrowth has no off-balance sheet arrangements.

PENGROWTH ENERGY CORPORATION ANNUAL INFORMATION FORM | 59

DISCLOSURE PURSUANT TO THE REQUIREMENTS
OF THE NEW YORK STOCK EXCHANGE

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

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

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

ADDITIONAL INFORMATION

Additional information, including directors' and officers' remuneration, the principal holders of Common Shares and securities authorized for issuance under equity compensation plans, is contained in our Management Information Circular which relates to the Annual Meeting of Shareholders to be held on June 23, 2015. Additional financial information is contained in our comparative consolidated financial statements and associated management's discussion and analysis for the years ended December 31, 2014, 2013 and 2012.

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

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

Investor Relations

Pengrowth Energy Corporation

Suite 2100, 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

60 | ANNUAL INFORMATION FORM

APPENDIX A

FORM 51-101F2
REPORT ON RESERVES DATA
BY
INDEPENDENT QUALIFIED RESERVES
EVALUATOR OR AUDITOR

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

1. We have evaluated the Company's reserves data as at December 31, 2014. The reserves data are estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2014, estimated using forecast prices and costs.

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

We carried out our evaluation in accordance with standards set out in the Canadian Oil and Gas Evaluation Handbook (the "COGE Handbook") prepared jointly by the Society of Petroleum Evaluation Engineers (Calgary Chapter) and the Canadian Institute of Mining, Metallurgy & Petroleum (Petroleum Society).

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

4. The following table sets forth the estimated 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 Company evaluated by us for the year ended December 31, 2014, and identifies the respective portions thereof that we have audited, evaluated and reviewed and reported on to the Company's board of directors:

Independent Qualified Reserves Evaluator	Description and Preparation 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 - $MM)
			Audited	Evaluated	Reviewed	Total
GLJ Petroleum Consultants	Corporate Summary January 19, 2015	Canada	-	5,259	-	5,259

5. In our opinion, the reserves 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 that we reviewed but did not audit or evaluate.

6. We have no responsibility to update our reports referred to in paragraph 4 for events and circumstances occurring after their respective preparation dates.

7. Because the reserves data are based on judgments 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, 2015.

(signed) "Todd Ikeda"

Todd J. Ikeda, P.Eng.

Vice President

APPENDIX A | PENGROWTH ENERGY CORPORATION ANNUAL INFORMATION FORM

APPENDIX B

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, 2014, estimated using forecast prices and costs.

An independent qualified reserves evaluator has evaluated the Corporation's reserves 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 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 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; and

(c) the content and filing of this report.

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

(signed) "Derek W. Evans"

Derek W. Evans

President and Chief Executive Officer

Pengrowth Energy Corporation

(signed) "Bob Rosine"

Bob Rosine

Executive Vice President, Business Development

Pengrowth Energy Corporation

(signed) "Wayne K. Foo"

Wayne K. Foo

Director

Pengrowth Energy Corporation

(signed) "Kelvin B. Johnston"

Kelvin B. Johnston

Director

Pengrowth Energy Corporation

February 26, 2015

APPENDIX B | PENGROWTH ENERGY CORPORATION ANNUAL INFORMATION FORM

APPENDIX C

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.

APPENDIX C | PENGROWTH ENERGY CORPORATION ANNUAL INFORMATION FORM

MEETINGS AND MINUTES

The Committee shall meet at least four times annually, or more frequently if determined necessary to carry out its responsibilities.

A meeting may be called by any member of the Committee, the Chairman of the Board or the President and Chief Executive Officer ("CEO") of the Corporation. A notice of the time and place of every meeting of the Committee shall be given in writing to each member of the Committee at least two business days prior to the time fixed for such meeting, unless notice of a meeting is waived by all members entitled to attend. Attendance of a member of the Committee at a meeting shall constitute waiver of notice of the meeting except where a member attends a meeting for the express purpose of objecting to the transaction of any business on the grounds that the meeting was not lawfully called.

A quorum for meetings of the Committee shall require a majority of its members present in person or by telephone. If the Chair of the Committee is not present at any meeting of the Committee, one of the other members of the Committee present at the meeting will be chosen to preside by a majority of the members of the Committee present at that meeting.

The President and CEO of the Corporation shall be available to advise the Committee, shall receive notice of meetings and may attend meetings of the Committee at the invitation of the Chair. Other management representatives, as well as Pengrowth's internal and external auditors, shall be invited to attend as necessary. Notwithstanding the foregoing, the Chair of the Committee shall hold in camera sessions, without management present, at every meeting of the Committee.

Decisions of the Committee shall be determined by a majority of the votes cast.

The Committee shall appoint a member of the Committee, the Corporate Secretary or another officer of Pengrowth to act as secretary at each meeting for the purpose of recording the minutes of each meeting.

The Committee shall provide the Board with a summary of all meetings together with a copy of the minutes from such meetings. Where minutes have not yet been prepared, the Chair shall provide the Board with oral reports on the activities of the Committee. All information reviewed and discussed by the Committee at any meeting shall be referred to in the minutes and made available for examination by the Board upon request to the Chair.

SCOPE, DUTIES AND RESPONSIBILITIES

MANDATORY DUTIES

REVIEW PROCEDURES

Pursuant to the requirements of NI 52-110 and other applicable laws, the Committee will:

1. Review and reassess the adequacy of the Committee's terms of reference at least annually, submit the terms of reference to the Board for approval and have the document published annually in Pengrowth's annual information circular and at least every three years in accordance with the regulations of the United States' Securities and Exchange Commission.

2. Prior to filing or public distribution, review, discuss with management and the internal and external auditors and recommend to the Board for approval, Pengrowth's audited annual financial statements, annual earnings press releases, annual information form, all financial statements including the related management's discussion and analysis required in prospectuses and other offering memoranda, financial statements required by regulatory authorities, all prospectuses and all documents which may be incorporated by reference into a prospectus, including without limitation, the annual information circular. Approve, on behalf of the Board, Pengrowth's interim financial statements and related management's discussion and analysis and interim earnings press releases. This review should include discussions with management, the internal auditors and the external auditors of significant issues regarding accounting principles, practices and judgements. Discuss any significant changes to Pengrowth's accounting principles and any items required to be communicated by the external auditors in accordance with Assurance and Related Services Guideline #11 (AuG-11).

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.

APPENDIX C | PENGROWTH ENERGY CORPORATION ANNUAL INFORMATION FORM

4. Be responsible for reviewing the disclosure contained in Pengrowth's annual information form as required by Form 52-110F1 Audit Committee Information Required in an AIF, attached to NI 52-110. If proxies are solicited for the election of directors of Pengrowth, the Committee shall be responsible for ensuring that Pengrowth's information circular includes a cross-reference to the sections in Pengrowth's annual information form that contain the information required by Form 52-110F1.

EXTERNAL AUDITORS

1. The Committee shall advise the external auditors of their accountability to the Committee and the Board as representatives of Pengrowth’s shareholders to whom the external auditors are ultimately responsible. The external auditors shall report directly to the Committee. The Committee is directly responsible for overseeing the work of the external auditors, shall review at least annually the independence and performance of the external auditors and shall annually recommend to the Board the appointment of the external auditors or approve any discharge of auditors when circumstances warrant. The Committee shall, on an annual basis, obtain and review a report by the external auditor describing: (i) the external auditor's internal quality-control procedures; (ii) any material issues raised by the most recent internal quality-control review, or peer review, of the external auditors, or by any inquiry or investigation by governmental or professional authorities, within the preceding five years, respecting one or more independent audits carried out by the external auditors, and any steps taken to deal with any such issues; and (iii) all relationships between the independent auditor and Pengrowth.

2. Approve the fees and other compensation to be paid to the external auditors.

3. Pre-approve all services to be provided to Pengrowth or its subsidiary entities by Pengrowth's external auditors and all related terms of engagement.

OTHER COMMITTEE RESPONSIBILITIES

1. Establish procedures for: (i) the receipt, retention and treatment of complaints received by Pengrowth regarding accounting, internal accounting controls, or auditing matters; and (ii) the confidential and anonymous submission by employees of Pengrowth of concerns regarding questionable accounting or auditing matters.

2. Review and approve Pengrowth's hiring policies regarding partners, employees and former partners and employees of the present and former external auditors of Pengrowth.

DISCRETIONARY DUTIES

The Committee's responsibilities may, at the Board's discretion, also include the following:

REVIEW PROCEDURES

1. In consultation with management, the internal auditors and the external auditors, consider the integrity of Pengrowth's financial reporting processes and controls and the performance of Pengrowth's internal financial accounting staff; discuss significant financial risk exposures and the steps management has taken to monitor, control and report such exposures; and review significant findings prepared by the internal or external auditors together with management's responses.

2. Review, with financial management, the internal auditors and the external auditors, Pengrowth's policies relating to risk management and risk assessment.

3. Meet separately with each of management, the internal auditors and the external auditors to discuss difficulties or concerns, specifically: (i) any difficulties encountered in the course of the audit work, including any restrictions on the scope of activities or access to requested information, and any significant disagreements with management; (ii) any changes required in the planned scope of the audit; and (iii) the responsibilities, budget, and staffing of the internal audit function, and report to the Board on such meetings.

4. Conduct an annual performance evaluation of the Committee.

APPENDIX C | PENGROWTH ENERGY CORPORATION ANNUAL INFORMATION FORM

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.

APPENDIX C | PENGROWTH ENERGY CORPORATION ANNUAL INFORMATION FORM

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.

Adopted by the Board of Pengrowth on November 1, 2012.

Last reviewed and approved by the Board of Pengrowth on October 31, 2014.

APPENDIX C | PENGROWTH ENERGY CORPORATION ANNUAL INFORMATION FORM

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

SCHEDULE A TO APPENDIX C | PENGROWTH ENERGY CORPORATION ANNUAL INFORMATION FORM

(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.

SCHEDULE A TO APPENDIX C | PENGROWTH ENERGY CORPORATION ANNUAL INFORMATION FORM

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;

SCHEDULE B TO APPENDIX C | PENGROWTH ENERGY CORPORATION ANNUAL INFORMATION FORM

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.

SCHEDULE B TO APPENDIX C | PENGROWTH ENERGY CORPORATION ANNUAL INFORMATION FORM

Schedule "C"

Excerpts from Section 303A.00 of the New York Stock Exchange Listed Company Manual

303A.02 "Independence" Tests

The NYSE Listed Company Manual contains the following provisions regarding the independence requirements of members of the audit committee:

(a) (i)    No director qualifies as "independent" unless the board of directors affirmatively determines that the director has no material relationship with the listed company (either directly or as a partner, shareholder or officer of an organization that has a relationship with the company).

(ii) In addition, in affirmatively determining the independence of any director who will serve on the compensation committee of the listed company's board of directors, the board of directors must consider all factors specifically relevant to determining whether a director has a relationship to the listed company which is material to that director's ability to be independent from management in connection with the duties of a compensation committee member, including, but not limited to:

(A) the source of compensation of such director, including any consulting, advisory or other compensatory fee paid by the listed company to such director; and

(B) whether such director is affiliated with the listed company, a subsidiary of the listed company or an affiliate of a subsidiary of the listed company.

(b) In addition, a director is not independent if:

(i) The director is, or has been within the last three years, an employee of the listed company, or an immediate family member is, or has been within the last three years, an executive officer, of the listed company.

(ii) The director has received, or has an immediate family member who has received, during any twelve-month period within the last three years, more than $120,000 in direct compensation from the listed company, other than director and committee fees and pension or other forms of deferred compensation for prior service (provided such compensation is not contingent in any way on continued service).

(iii) (A) The director is a current partner or employee of a firm that is the listed company's internal or external auditor; (B) the director has an immediate family member who is a current partner of such a firm; (C) the director has an immediate family member who is a current employee of such a firm and personally works on the listed company's audit; or (D) the director or an immediate family member was within the last three years a partner or employee of such a firm and personally worked on the listed company's audit within that time.

(iv) The director or an immediate family member is, or has been within the last three years, employed as an executive officer of another company where any of the listed company's present executive officers at the same time serves or served on that company's compensation committee.

(v) The director is a current employee, or an immediate family member is a current executive officer, of a company that has made payments to, or received payments from, the listed company for property or services in an amount which, in any of the last three fiscal years, exceeds the greater of $1 million, or 2% of such other company's consolidated gross revenues.

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General Commentary to Section 303A.02(b):

An "immediate family member" includes a person's spouse, parents, children, siblings, mothers and fathers-in-law, sons and daughters-in-law, brothers and sisters-in-law, and anyone (other than domestic employees) who shares such person's home. When applying the look-back provisions in Section 303A.02(b), listed companies need not consider individuals who are no longer immediate family members as a result of legal separation or divorce, or those who have died or become incapacitated.

In addition, references to the "listed company" or "company" include any parent or subsidiary in a consolidated group with the listed company or such other company as is relevant to any determination under the independent standards set forth in this Section 303A.02(b).

For purposes of Section 303A, the term "executive officer" has the same meaning specified for the term "officer" in Rule 16a-1(f) under the Securities Exchange Act of 1934 as follows:

The term "officer" shall mean an issuer's president, principal financial officer, principal accounting officer (or, if there is no such accounting officer, the controller), any vice-president of the issuer in charge of a principal business unit, division or function (such as sales, administration or finance), any other officer who performs a policy-making function, or any other person who performs similar policy-making functions for the issuer. Officers of the issuer's parent(s) or subsidiaries shall be deemed officers of the issuer if they perform such policy-making functions for the issuer. In addition, when the issuer is a limited partnership, officers or employees of the general partner(s) who perform policy-making functions for the limited partnership are deemed officers of the limited partnership.

SCHEDULE C TO APPENDIX C | PENGROWTH ENERGY CORPORATION ANNUAL INFORMATION FORM

EX-99.2

MANAGEMENT’S DISCUSSION & ANALYSIS

The following Management’s Discussion and Analysis ("MD&A") of financial results should be read in conjunction with the audited Consolidated Financial Statements for the year ended December 31, 2014 of Pengrowth Energy Corporation ("Pengrowth" or the "Corporation"). This MD&A is based on information available to February 26, 2015.

Pengrowth’s fourth quarter and annual results for 2014 are contained within this MD&A.

BUSINESS OF THE CORPORATION

Pengrowth is a Canadian resource company that is engaged in the production, development, exploration and acquisition of oil and natural gas assets. The financial and operating results from property dispositions are included in Pengrowth’s results up to the time of closing for each disposition.

FREQUENTLY RECURRING TERMS

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

ADVISORY REGARDING FORWARD-LOOKING STATEMENTS

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

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

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

PENGROWTH 2014 Management's Discussion and Analysis 1

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

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

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

CRITICAL ACCOUNTING ESTIMATES

The Consolidated Financial Statements are prepared in accordance with IFRS. 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

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. Reserves form the basis for the calculation of depletion charges and assessment of impairment of goodwill and oil and gas assets. Reserves 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.

PENGROWTH 2014 Management's Discussion and Analysis 2

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. During 2014, Pengrowth’s ARO risk free discount rate changed from 3.25 percent to 2.3 percent due to a decrease in the 30 year Canadian Government long term bond rate which drives Pengrowth’s estimate of the ARO discount rate.

Impairment testing

CGUs that have associated goodwill are tested for impairment at least annually and CGUs with or without associated goodwill are tested when there is an indication of impairment. The test is based on estimates of proved plus probable reserves, production rates, oil and natural gas prices, future costs, discount rate and other relevant assumptions. Undeveloped land, contingent resources and infrastructure may also be considered. The impairment assessment of goodwill is based on the estimated recoverable amount of the related CGUs. By their nature, these estimates are subject to measurement uncertainty and may impact the Consolidated Financial Statements of future periods.

Fair value of risk management contracts

Pengrowth records risk management contracts at fair value with changes in fair value recognized in the Consolidated Statements of Income (Loss). The fair values are determined using observable market data and external counterparty information.

Valuation of trade and other receivables, and prepayments to suppliers

Management estimates the likelihood of the collection of trade and other receivables and recovery of prepayments based on an analysis of individual accounts. Factors taken into consideration include the aging of receivables in comparison with the credit terms allowed to customers and the financial position and collection history with the customer. Should actual collections be less than estimates, Pengrowth would be required to record an additional expense.

COMPARATIVE FIGURES

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

ADDITIONAL GAAP MEASURE

Funds Flow from Operations

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

NON-GAAP FINANCIAL MEASURES

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

PENGROWTH 2014 Management's Discussion and Analysis 3

Operating netbacks do not have standardized meanings prescribed by GAAP. Pengrowth’s operating netbacks have been calculated by taking balances directly from the Consolidated Statements of Income (Loss) and dividing by production. See the section of this MD&A entitled Operating Netbacks for a discussion of the calculation.

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

Management believes that, in addition to net income (loss), adjusted net income (loss) is a useful supplemental measure as it reflects the underlying performance of Pengrowth’s business activities by excluding the after tax effect of non-cash commodity, power and interest mark to market gains and losses, non-cash mark to market gains and losses on investments, unrealized foreign exchange gains and losses and gains on acquisitions, as applicable, that may significantly impact net income (loss) from period to period.

Payout ratio and net payout ratio are terms used to evaluate financial flexibility and the capacity to fund dividends. Payout ratio is defined on a percentage basis as dividends declared divided by funds flow from operations. Net payout ratio is calculated as dividends declared net of proceeds from the Dividend Reinvestment Plan ("DRIP") divided by funds flow from operations.

Management believes that segregating G&A expenses into cash and non-cash expenses is useful to the reader, as non-cash expenses only affect net income (loss) but not funds flow from operations.

OPERATIONAL MEASURES

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

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

Pengrowth’s ability to grow both reserves and production can be measured with the following metrics: reserves per share, reserves per debt adjusted share, production per share and production per debt adjusted share. Reserves per share and reserves per debt adjusted share are measured using year end proved plus probable reserves and the number of common shares outstanding at year end. The reserves per debt adjusted share is debt-adjusted by assuming additional shares are issued at the year end share price to replace year end long term debt outstanding.

Production per share and production per debt adjusted share are measured in respect of the average production for the year and the weighted average number of common shares outstanding during the year. The production per debt adjusted share is debt-adjusted by assuming additional shares are issued at the year end share price to replace year end long term debt outstanding.

Recycle ratio is a measure of value creation for each dollar spent. This measure is calculated as operating netback per boe divided by Finding and Development ("F&D") cost per boe and can also be calculated using Finding, Development & Acquisition ("FD&A") cost per boe. Recycle ratio can be calculated including or excluding Future Development Costs ("FDC").

CURRENCY

All amounts are stated in Canadian dollars unless otherwise specified.

PENGROWTH 2014 Management's Discussion and Analysis 4

2014 and 2015 GUIDANCE

The following table provides a summary of Pengrowth's 2014 Guidance and actual results:

	2014 Actual	2014 Guidance (1)
Production (boe/d)	73,288	71,000 - 73,000
Capital expenditures ($ millions)	904.0	740 - 770
Royalty expenses (% of sales)	17.9	16 - 18
Operating expenses ($/boe)	15.53	15.20 - 15.80
Cash G&A expenses ($/boe)	3.15	3.15 - 3.25
Funds flow from operations ($ millions)	505.7	500 - 540
EBITDA ($ millions) (2)	557.4	575 - 625

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

⁽²⁾  Guidance EBITDA calculated as funds flow from operations plus interest and financing charges less expenditures on remediation.

2014 average production of 73,288 boe/d exceeded 2014 Guidance driven by performance of the new Cardium development wells partly offset by third party capacity constraints at Pine Creek, downtime at Sable Island and several minor property divestitures completed in 2014.

2014 capital expenditures amounted to $904.0 million, including $442.3 million invested in all phases at Lindbergh and $338.1 million invested in non-thermal development capital. Pengrowth also acquired 32.6 gross/net sections of prospective liquids-rich Montney lands at Bernadet in north eastern British Columbia for $123.6 million in the fourth quarter which was not contemplated in 2014 Guidance of $740 - $770 million.

2014 royalty, operating and G&A expenses were in line with 2014 Guidance.

2014 funds flow from operations was at the lower end of 2014 Guidance, and 2014 EBITDA was below 2014 Guidance primarily due to unplanned clean up and remediation costs.

The following table provides Pengrowth's previously announced 2015 Guidance:

	2015 Guidance
Production (boe/d)	73,000 - 75,000
Capital expenditures ($ millions)	190 - 210
Royalty expenses (% of sales)	12 - 15
Operating expenses ($/boe) (1)	15.50 - 16.50
Cash G&A expenses ($/boe) (1)	3.20 - 3.30

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

Pengrowth’s 2015 capital program of $200 million represents a 78 percent decrease from 2014 actual capital expenditures of $904.0 million. The program includes $125 million of non-thermal capital focused on optimization and enhancement activities targeting ongoing production and does not contemplate an active drilling program. Thermal capital of $75 million at Lindbergh is allocated to engineering design work on Phase II, the building of the sales pipeline connection to Husky Energy Inc. ("Husky"), installation of downhole pumps on all new wells and the addition of treating capability at the existing facilities to increase throughput capacity. Pengrowth is maintaining spending on its asset integrity and maintenance programs.

Despite the reduction in 2015 capital spending, Pengrowth expects to grow volumes to a range of 73,000 - 75,000 boe/d in 2015 due to the anticipated volumes from the first commercial phase at Lindbergh.

PENGROWTH 2014 Management's Discussion and Analysis 5

FINANCIAL HIGHLIGHTS

	Three months ended					Twelve months ended
($ millions except per boe amounts)	Dec 31, 2014		Sept 30, 2014	Dec 31, 2013		Dec 31, 2014		Dec 31, 2013
Production (boe/d)	71,802		72,472	77,371		73,288		84,527
Capital expenditures	258.8		191.9	239.7		904.0		695.8
Funds flow from operations	115.8		129.0	105.9		505.7		560.9
Operating netback ($/boe)(1)	24.04		24.91	20.82		25.64		24.35
Adjusted net income (loss)	(854.8	)	3.4	(37.3	)	(879.0	)	(183.8	)
Net income (loss)	(506.0	)	52.2	(91.1	)	(578.8	)	(316.9	)

⁽¹⁾  Including realized commodity risk management.

Funds Flow from Operations

($ millions)	Q3/14 vs. Q4/14			% Change		Q4/13 vs. Q4/14			% Change		2013 vs. 2014			% Change
Funds flow from operations for comparative period	Q3/14	129.0				Q4/13	105.9				2013	560.9
Increase (decrease) due to:
Volumes		(14.1	)	(11	)		(32.6	)	(31	)		(235.1	)	(42	)
Prices including differentials		(62.7	)	(49	)		(20.4	)	(19	)		141.0		25
Realized commodity risk management		50.3		39			37.4		35			(41.1	)	(7	)
Other income including sulphur		(0.8	)	(1	)		0.8		1			(2.4	)	—
Royalties		14.3		11			11.6		11			6.5		1
Expenses:
Operating		7.9		6			14.7		14			67.1		12
Cash G&A		(0.6	)	—			0.5		—			3.5		1
Interest & financing		(0.5	)	—			3.6		3			19.5		3
Other expenses including transportation		(7.0	)	(5	)		(5.7	)	(5	)		(14.2	)	(3	)
Net change		(13.2	)	(10	)		9.9		9			(55.2	)	(10	)
Funds flow from operations	Q4/14	115.8				Q4/14	115.8				2014	505.7

Fourth quarter of 2014 funds flow from operations decreased 10 percent compared to the third quarter of 2014 primarily due to lower volumes as a result of minor property dispositions and temporary solution gas restrictions in the Swan Hills area. The impact of lower commodity prices was more than offset by realized commodity risk management gains, along with lower royalties and operating expenses.

Fourth quarter of 2014 funds flow from operations increased 9 percent compared to the same period in 2013 as the impact of lower volumes and commodity prices was more than offset by realized commodity risk management gains, along with lower royalties and operating expenses.

Full year 2014 funds flow from operations decreased 10 percent compared to 2013 mainly due to lower volumes resulting from 2013 and 2014 property dispositions which were mostly offset by an increase in natural gas prices and lower operating and interest expenses year over year.

Net Income (Loss)

Pengrowth recorded a net loss of $506.0 million in the fourth quarter of 2014 compared to net income of $52.2 million in the third quarter of 2014 and a net loss of $91.1 million in the fourth quarter of 2013. The substantial increase in net loss was primarily a result of non-cash impairment charges of approximately $858 million after-tax, recorded in the fourth quarter of 2014, partly offset by an increase in unrealized gain on commodity risk management.

Full year 2014 net loss of $578.8 million increased $261.9 million compared to a net loss of $316.9 million in 2013 mainly due to non-cash impairment charges of approximately $858 million after-tax, recorded in the fourth quarter of 2014, partly offset by an increase in unrealized gain on commodity risk management and the absence of the 2013 loss on disposition of properties.

PENGROWTH 2014 Management's Discussion and Analysis 6

Adjusted Net Income (Loss)

Pengrowth reports adjusted net income (loss) to remove the effect of unrealized gains and losses, however, non-cash impairment charges of approximately $858 million after-tax recorded in the fourth quarter of 2014 are included. The following table provides a reconciliation of net income (loss) to adjusted net income (loss):

	Three months ended						Twelve months ended
($ millions)	Dec 31, 2014		Sept 30, 2014		Dec 31, 2013		Dec 31, 2014		Dec 31, 2013
Net income (loss)	(506.0	)	52.2		(91.1	)	(578.8	)	(316.9	)
Excluded non-cash items in net income (loss):
Unrealized gain (loss) on commodity, power and interest risk management	501.3		121.1		(39.1	)	499.6		(87.0	)
Unrealized foreign exchange loss(1)	(29.8	)	(42.7	)	(28.2	)	(79.0	)	(63.0	)
Unrealized loss on investments	—		(5.0	)	—		(5.0	)	(15.0	)
Tax effect on non-cash items above	(122.7	)	(24.6	)	13.5		(115.4	)	31.9
Total excluded	348.8		48.8		(53.8	)	300.2		(133.1	)
Adjusted net income (loss)	(854.8	)	3.4		(37.3	)	(879.0	)	(183.8	)

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

The following table represents a continuity of adjusted net income (loss):
($ millions)	Q3/14 vs. Q4/14			Q4/13 vs. Q4/14			2013 vs. 2014
Adjusted net income (loss) for comparative period	Q3/14	3.4		Q4/13	(37.3	)	2013	(183.8	)
Funds flow from operations increase (decrease)		(13.2	)		9.9			(55.2	)
DD&A and accretion expense decrease		0.9			3.5			59.3
Impairment charges increase		(994.6	)		(994.6	)		(994.6	)
Loss on property dispositions decrease		1.7			29.4			199.0
Other		1.9			2.3			1.8
Estimated tax on above		145.1			132.0			94.5
Net change		(858.2	)		(817.5	)		(695.2	)
Adjusted net loss	Q4/14	(854.8	)	Q4/14	(854.8	)	2014	(879.0	)

Pengrowth posted an adjusted net loss of $854.8 million in the fourth quarter of 2014 compared to adjusted net income of $3.4 million in the third quarter of 2014 and an adjusted net loss of $37.3 million in the fourth quarter of 2013. The increase in the adjusted net loss was primarily due to non-cash impairment charges Pengrowth recorded given the significant downturn in commodity benchmark prices in late 2014.

Full year 2014 adjusted net loss of $879.0 million increased $695.2 million compared to an adjusted net loss of $183.8 million in 2013 also due to non-cash impairment charges recorded in the fourth quarter of 2014 partly offset by reduced losses on disposition of properties and lower DD&A in 2014.

PENGROWTH 2014 Management's Discussion and Analysis 7

Price Sensitivity

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

						Estimated Impact on 12 Month Funds Flow
COMMODITY PRICE ENVIRONMENT (1)		Assumption		Change		(Cdn$ millions)
West Texas Intermediate Oil (2) (3)	U.S.$/bbl	$	49.87	$	1.00
Light oil						7.2
Heavy oil						7.0
Oil risk management (4)						(11.7	)
NGLs						3.2
Net impact of U.S.$1/bbl increase in WTI						5.7
Oil differentials
Light oil	U.S.$/bbl	$	5.77	$	1.00	(7.2	)
Heavy oil	U.S.$/bbl	$	14.11	$	1.00	(7.0	)
Net impact of U.S.$1/bbl increase in differentials						(14.2	)
AECO Natural Gas (2) (3)	Cdn$/Mcf	$	2.76	$	0.10
Natural gas						6.0
Natural gas risk management (4)						(3.0	)
Net impact of Cdn$0.10/Mcf increase in AECO						3.0

⁽¹⁾  Calculations are performed independently and are not indicative of actual results when multiple variables change at the same time. An exchange rate of $1Cdn = $0.80 U.S. was used.

⁽²⁾  Commodity price is based on an estimation of the 12 month forward price curve at February 1, 2015 and does not include the impact of risk management contracts.

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

⁽⁴⁾  Includes risk management contracts as at February 1, 2015.

PENGROWTH 2014 Management's Discussion and Analysis 8

RESULTS OF OPERATIONS

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

CAPITAL EXPENDITURES

	Three months ended			Twelve months ended
($ millions)	Dec 31, 2014	Sept 30, 2014	Dec 31, 2013	Dec 31, 2014	Dec 31, 2013
Drilling, completions and facilities
Lindbergh	80.4	110.5	136.0	442.3	306.4
Non-thermal	34.9	61.5	72.8	256.5	299.8
Total drilling, completions and facilities	115.3	172.0	208.8	698.8	606.2
Land & seismic acquisitions (1)	123.9	0.3	1.1	129.3	2.9
Maintenance capital	17.8	19.1	26.6	72.8	81.9
Development capital	257.0	191.4	236.5	900.9	691.0
Other capital	1.8	0.5	3.2	3.1	4.8
Capital expenditures	258.8	191.9	239.7	904.0	695.8

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

Fourth quarter of 2014 capital expenditures were $258.8 million following the ongoing strategy of executing on projects that maximize cash flow while taking advantage of significant opportunities to expand Pengrowth's development inventoryand continuing to invest in the first commercial phase of the Lindbergh thermal project. Approximately 48 percent of the fourth quarter of 2014 capital expenditures were invested inthe acquisition of 32.6 gross/net sections of prospective liquids-rich Montney lands at Bernadet in north eastern British Columbia, 31 percent was spent at Lindbergh, and the remaining 21 percent was spent on non-thermal activity including drilling 13 (5.5 net) wells.

2014 capital spending totaled $904.0 million of which approximately 49 percent was invested at Lindbergh, 37 percent was invested in non-thermal activity with the remaining 14 percent invested in the Bernadet land acquisition.

Focus Areas

Lindbergh

Pengrowth’s 100 percent owned and operated Lindbergh thermal project is located in the Cold Lake area of Alberta and encompasses 42.5 sections of land. Cost advantages of the Lindbergh resource include enhanced bitumen quality and flow characteristics resulting in an efficient steam oil ratio which translates into a lower operating cost structure and higher netbacks compared to many thermal projects. A two well pair pilot project at Lindbergh was brought on stream in February 2012 and the results have exceeded type curve and steam oil ratio expectations. The 12,500 bbl/d first commercial phase of Lindbergh was sanctioned by Pengrowth’s Board of Directors in January 2013 and Alberta Environmental Protection and Enhancement Act approval was received for the first commercial phase in July 2013. The Environmental Impact Assessment ("EIA") application for the Lindbergh expansion to 30,000 bbl/d was submitted to the regulators in December 2013.

During the fourth quarter of 2014, $80.4 million was invested at Lindbergh, bringing the year to date spending to $442.3 million. Construction of the initial 12,500 bbl/d commercial phase of Lindbergh was completed on time with steaming operations commencing in December 2014. Steam circulation on the 20 well pairs is following the same time line established for the pilot well pairs. Operations have commenced on all three well pads and production is expected to build through 2015 as downhole pumps are installed.

Pengrowth has entered into a transportation agreement with Husky for delivery of production from the initial commercial phase of Lindbergh to Hardisty, Alberta, with options to nominate additional future volumes as Lindbergh expands. Pengrowth retains maximum flexibility in regards to transportation options at Lindbergh and will be able to utilize both rail and pipeline to move production to markets and maximize netbacks. Construction of the pipeline is underway with an expected on stream date in the third quarter of 2015.

Operations at the pilot project continued to show strong results during the fourth quarter of 2014 with combined field production from the two well pairs averaging 1,689 bbl/d of bitumen. The average Instantaneous Steam Oil Ratio ("ISOR") for the fourth quarter of 2014 was 2.5. Since steaming commenced in February 2012, cumulative production

PENGROWTH 2014 Management's Discussion and Analysis 9

from the two well pairs exceeded 1.6 million bbls of bitumen by December 31, 2014 with a Cumulative Steam Oil Ratio ("CSOR") of 2.1. The pilot well pairs began their natural decline in 2014.

Lindbergh is expected to provide Pengrowth with the potential to ultimately develop annual bitumen production of 40,000 to 50,000 bbl/d. This is expected to be low cost production with low sustaining capital requirements and long reserve life.

Non-Thermal Oil and Gas

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

Development continued during the fourth quarter of 2014 in the Greater Olds/Garrington area with an additional 7 (3.2 net) wells drilled in the Cardium and an additional 2 (0.5 net) wells drilled in the Glauconite formation, all with 100 percent success. Two of the new Cardium wells are on stream, and 2 other wells have been tested, with initial test data and early production results meeting or exceeding expectations. Pengrowth’s fourth quarter of 2014 development program included 3 (0.8 net) wells in the Slave Point formation at Sawn Lake and 1 (1.0 net) injection well at Judy Creek supporting incremental production and reserves in the miscible flood. Pengrowth also completed and tied in 2 Groundbirch Montney horizontal wells in the fourth quarter of 2014 completed with high intensity multi-stage hydraulic fracturing technology. The initial production results from the 2 (2.0 net) Groundbirch wells indicate performance that significantly exceeds Pengrowth's historic Groundbirch production results.

Pengrowth acquired an additional 32.6 gross/net sections of prospective liquids-rich lands in the heart of the Montney fairway at Bernadet in north eastern British Columbia at the November 5, 2014 Crown land sale. This acquisition extends Pengrowth's legacy position in the Bernadet area of 4.0 gross/net sections and is expected to provide significant scalable, low risk development drilling inventory in addition to Pengrowth's existing Montney inventory in Groundbirch. With the addition of the Bernadet lands, Pengrowth is now well positioned with a focused multi-year conventional drilling inventory of light oil and liquids-rich natural gas prospects that complement Pengrowth's thermal opportunities.

2015 Capital Program

Pengrowth’s 2015 capital program of $200 million represents a 78 percent decrease from 2014 actual capital expenditures of $904.0 million. The program includes $125 million of non-thermal capital focused on optimization and enhancement activities targeting ongoing production and does not contemplate an active drilling program. Thermal capital of $75 million at Lindbergh is allocated to engineering design work on Phase II, the building of the sales pipeline connection to Husky, installation of downhole pumps on all new wells and the addition of treating capability at the existing facilities to increase throughput capacity.

PENGROWTH 2014 Management's Discussion and Analysis 10

RESERVES AND PERFORMANCE MEASURES

Reserves - Company Interest at Forecast Prices

Reserves Summary (MMboe except as noted)	2014		2013		2012
Proved Reserves
Additions + revisions for the year	32.9		83.4		21.0
Net acquisitions (dispositions) for the year	(3.2	)	(45.6	)	75.9
Total proved reserves at period end	310.1		307.0		300.1
Proved reserve replacement ratio excluding net acquisitions (dispositions)	123	%	270%		66	%
Proved reserve replacement ratio including net acquisitions (dispositions)	111	%	122%		306	%
Proved plus Probable Reserves (P+P)
Additions + revisions for the year	112.4		65.3		103.8
Net acquisitions (dispositions) for the year	(5.6	)	(69.0	)	109.4
Total proved plus probable reserves at period end	557.4		477.4		512.0
Total production (MMboe) (1)	26.8		30.9		31.7
P+P Reserve replacement ratio excluding net acquisitions (dispositions)	420	%	211%		327	%
P+P Reserve replacement ratio including net acquisitions (dispositions) (2)	399	%	(12	)%	672	%

⁽¹⁾  Includes production from Lindbergh pilot project.

⁽²⁾  2013 negative replacement ratio was a result of net dispositions in the year.

Pengrowth’s 2014 total proved reserves increased 1 percent from 2013, while total proved plus probable reserves increased 17 percent. Pengrowth added 32.9 MMboe of proved reserves and 112.4 MMboe of total proved plus probable reserves in 2014 from development and optimization activities in non-thermal properties, and ongoing reservoir delineation and the submission of a regulatory application to expand the development of the Lindbergh thermal project. The 2014 reserve additions resulted in an organic reserve replacement ratio of 420 percent for total proved plus probable reserves excluding net acquisitions and dispositions.

Further details of Pengrowth’s 2014 year end reserves, F&D and FD&A calculations are provided in the AIF which is filed on SEDAR (www.sedar.com) or the 40-F filed on EDGAR (www.sec.gov).

Performance Measures

Finding & Development Costs & Recycle Ratio	2014		2013		2012		3 year weighted average
Excluding Net Acquisitions (Dispositions) (F&D)
Excluding changes in FDC
F&D costs per boe - (P+P)	$	8.03	$	10.61	$	4.44	$	7.30
Recycle ratio (1) (2)	3.2		2.3		5.3		3.4
Including changes in FDC
F&D costs per boe - (P+P)	$	22.33	$	21.96	$	16.85	$	20.22
Recycle ratio (1)	1.1		1.1		1.4		1.2

⁽¹⁾  Calculated as operating netback per boe divided by F&D costs per boe based on proved plus probable reserves.

⁽²⁾  Prior periods restated to conform to presentation in the current period.

2014 total proved plus probable F&D cost, including changes in FDC, was $22.33/boe, staying relatively flat year over year with a slight increase from 2013.

Recycle ratio is an important performance measure in assessing investment profitability and provides a comparison to our competitors. Pengrowth’s operating results and capital program in 2014 yielded a recycle ratio, excluding net acquisitions (dispositions) and including changes in FDC, of 1.1 on a proved plus probable basis, slightly below the three year average of 1.2.

PENGROWTH 2014 Management's Discussion and Analysis 11

Other Performance Measures	2014	2013	2012
Production per share (boe/share)	0.05	0.06	0.07
Production per debt adjusted share (boe/share) (1)	0.03	0.04	0.04
P+P reserves per share (boe/share)	1.04	0.91	1.00
P+P reserves per debt adjusted share (boe/share) (1)	0.54	0.62	0.60

⁽¹⁾  Debt adjusted shares equals the shares outstanding plus the number of shares needed to retire all of the debt at the year end share price.

Pengrowth’s goal over the longer term is to modestly grow production and reserves per debt adjusted share, while continuing to pay a prudent dividend. On a debt adjusted basis, 2014 production and total proved plus probable reserves per share decreased from 2013, primarily due to increased debt resulting from the weakening of the Canadian dollar and the decrease in Pengrowth’s share price used to convert the debt to shares at December 31, 2014, offsetting the 17 percent increase in proved plus probable reserves.

PRODUCTION

	Three months ended						Twelve months ended
Daily production	Dec 31, 2014	% of total	Sept 30, 2014	% of total	Dec 31, 2013	% of total	Dec 31, 2014	% of total	Dec 31, 2013	% of total
Light oil (bbls)	19,361	27	21,359	30	22,488	29	21,228	29	27,061	32
Heavy oil (bbls)	8,299	12	8,246	11	8,369	11	8,251	11	8,355	10
Natural gas liquids (bbls)	9,381	13	9,403	13	10,476	13	10,130	14	10,476	12
Natural gas (Mcf)	208,563	48	200,786	46	216,231	47	202,076	46	231,812	46
Total boe per day	71,802		72,472		77,371		73,288		84,527

Fourth quarter of 2014 average daily production decreased 1 percent compared to the third quarter of 2014 as the effects of minor property dispositions and solution gas restrictions at Swan Hills were offset by increased Sable Island natural gas production after repairs and maintenance work was completed in the third quarter of 2014. Strong performance from the 2 well Groundbirch development program also contributed to the fourth quarter of 2014 production. Fourth quarter and full year 2014 production decreased 7 percent and 13 percent compared to the same periods last year, respectively, due to significant property dispositions in late 2013 and several minor dispositions in 2014, partly offset by production additions from the Cardium development program.

Light Oil

Fourth quarter of 2014 light oil production decreased 9 percent and 14 percent compared to the third quarter of 2014 and fourth quarter of 2013, respectively, due to several minor 2014 property dispositions coupled with solution gas restrictions in the Swan Hills area during the fourth quarter of 2014. Full year 2014 light oil production decreased 22 percent compared to 2013 due to the late 2013 property dispositions and several minor 2014 dispositions, partly offset by new production from the Cardium development program.

Heavy Oil

Fourth quarter of 2014 heavy oil production increased 1 percent compared to the third quarter of 2014 due to slightly higher production at Lindbergh and Bodo. Fourth quarter and full year 2014 heavy oil production decreased 1 percent compared to the same periods last year due to anticipated declines at the Lindbergh pilot project partly offset by higher production from a development program in the Bodo area.

NGLs

Fourth quarter of 2014 NGL production remained unchanged compared to the third quarter of 2014 but declined 10 percent compared to the fourth quarter of 2013 due to the absence of a Sable Island condensate shipment included in the fourth quarter of 2013. Full year 2014 NGL production decreased 3 percent compared to 2013 largely due to the late 2013 property dispositions partly offset by new Cardium production.

Natural Gas

Fourth quarter of 2014 natural gas production increased 4 percent compared to the third quarter of 2014 due to positive additions from the Groundbirch development program combined with less repair and maintenance downtime at Sable Island. Fourth quarter and full year 2014 natural gas production decreased 4 percent and 13 percent compared to the same periods last year, respectively, mainly as a result of the late 2013 property dispositions, partly offset by new Cardium and Groundbirch production.

PENGROWTH 2014 Management's Discussion and Analysis 12

COMMODITY PRICES

Oil and Liquids Prices Excluding Realized Commodity Risk Management

	Three months ended						Twelve months ended
(Cdn$/bbl)	Dec 31, 2014		Sept 30, 2014		Dec 31, 2013		Dec 31, 2014		Dec 31, 2013
Average Benchmark Prices
WTI oil	83.05		105.83		102.75		102.44		101.07
Edmonton par light oil	75.79		97.20		87.07		94.50		93.47
WCS heavy oil	66.85		83.84		69.07		81.03		75.14
Average Differentials to WTI
Edmonton par	(7.26	)	(8.63	)	(15.68	)	(7.94	)	(7.60	)
WCS heavy oil	(16.20	)	(21.99	)	(33.68	)	(21.41	)	(25.93	)
Average Sales Prices
Light oil	72.93		94.04		83.23		92.10		89.68
Heavy oil	61.56		78.43		61.43		75.21		67.98
Natural gas liquids	39.51		52.94		60.49		52.17		55.81

Fourth quarter of 2014 WTI crude oil price averaged Cdn$83.05/bbl, a decrease of 22 percent and 19 percent compared to the third quarter of 2014 and the fourth quarter of 2013, respectively. The rapid decline in global crude oil prices resulting from an oversupply of crude oil in late 2014 was partially mitigated by a decline in the Canadian dollar versus the U.S. dollar, as Pengrowth reports its revenues in Canadian dollars. Full year 2014 WTI crude oil price averaged Cdn$102.44/bbl, an increase of 1 percent compared to the full year 2013 price.

Fourth quarter of 2014 Edmonton par light oil differentials narrowed by 16 percent and 54 percent compared to the third quarter of 2014 and the fourth quarter of 2013, respectively. Full year 2014 light oil differentials widened by 4 percent compared to full year 2013 differentials.

Fourth quarter of 2014 WCS heavy oil differentials narrowed by 26 percent and 52 percent compared to the third quarter of 2014 and the fourth quarter of 2013, respectively. Full year 2014 heavy oil differentials narrowed by 17 percent compared to full year 2013 differentials.

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

Pengrowth's fourth quarter and full year 2014 average oil and liquids sales prices moved in conjunction with the above described benchmark prices and differentials.

Natural Gas Prices Excluding Realized Commodity Risk Management

	Three months ended						Twelve months ended
(Cdn$)	Dec 31, 2014		Sept 30, 2014		Dec 31, 2013		Dec 31, 2014		Dec 31, 2013
Average Benchmark Prices
NYMEX gas (per MMBtu)	4.36		4.30		4.05		4.71		3.82
AECO monthly gas (per MMBtu)	4.01		4.22		3.15		4.42		3.16
Average Differential to NYMEX
AECO differential (per MMBtu)	(0.35	)	(0.08	)	(0.90	)	(0.29	)	(0.66	)
Average Sales Prices
Natural gas (per Mcf) (1)	4.02		4.05		3.18		4.74		3.19

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

The NYMEX natural gas benchmark price averaged Cdn$4.36/MMBtu in the fourth quarter of 2014 resulting in an increase of 1 percent and 8 percent compared to the third quarter of 2014 and the fourth quarter of 2013, respectively. Full year 2014 NYMEX price increased 23 percent compared the same period last year. The increase in prices resulted from low natural gas storage in the key consuming regions of North America in the first half of 2014 coupled with a decline in the Canadian dollar.

PENGROWTH 2014 Management's Discussion and Analysis 13

Fourth quarter of 2014 AECO gas prices averaged Cdn$4.01/MMBtu, representing a decline of 5 percent compared to the third quarter of 2014. The decline in AECO price resulted from a widening of the differential between NYMEX and AECO. Fourth quarter and full year 2014 AECO prices increased 27 percent and 40 percent compared to the same periods in 2013, respectively. Higher NYMEX and a narrowing of the differential between AECO and NYMEX were the primary drivers behind the higher AECO prices.

Fourth quarter of 2014 realized natural gas sales price of Cdn$4.02/Mcf was essentially unchanged compared to the third quarter of 2014 in spite of the AECO gas price declining 5 percent as Pengrowth also sells its natural gas at several additional sales points which yielded higher prices than AECO. Fourth quarter and full year 2014 realized natural gas sales prices increased 26 percent and 49 percent compared to the same periods in 2013, respectively, mainly due to higher natural gas benchmark prices and a narrowing of the differential between NYMEX and AECO.

Total Average Sales Prices Excluding Realized Commodity Risk Management

	Three months ended			Twelve months ended
($/boe)	Dec 31, 2014	Sept 30, 2014	Dec 31, 2013	Dec 31, 2014	Dec 31, 2013
Average sales prices	43.61	54.73	47.92	55.42	51.10
Other production income including sulphur	0.52	0.63	0.37	0.54	0.54
Total oil and gas sales	44.13	55.36	48.29	55.96	51.64

Fourth quarter of 2014 average sales price of Cdn$43.61/boe decreased 20 percent and 9 percent compared to the third quarter of 2014 and the fourth quarter of 2013, respectively, mostly due to declines in crude oil benchmark prices. Full year 2014 average sales price increased 8 percent compared to full year 2013, as stronger benchmark prices from the first half of 2014 outweighed the rapid decline in prices seen in the fourth quarter of 2014.

Commodity Risk Management Gains (Losses)

	Three months ended						Twelve months ended
($ millions except per unit amounts)	Dec 31, 2014		Sept 30, 2014		Dec 31, 2013		Dec 31, 2014		Dec 31, 2013
Realized
Oil risk management	24.3		(23.9	)	(17.5	)	(66.5	)	(60.5	)
$/bbl (1)	9.55		(8.77	)	(6.16	)	(6.18	)	(4.68	)
Natural gas risk management	(2.6	)	(4.7	)	1.8		(29.6	)	5.5
$/Mcf	(0.14	)	(0.25	)	0.09		(0.40	)	0.07
Total realized gain (loss)	21.7		(28.6	)	(15.7	)	(96.1	)	(55.0	)
$/boe	3.29		(4.29	)	(2.21	)	(3.60	)	(1.78	)
Unrealized
Unrealized commodity risk management assets (liabilities) at period end	421.1		(84.2	)	(80.0	)	421.1		(80.0	)
Less: Unrealized commodity risk management assets (liabilities) at beginning of period	(84.2	)	(205.8	)	(40.9	)	(80.0	)	7.0
Unrealized gain (loss) on commodity risk management contracts for the period	505.3		121.6		(39.1	)	501.1		(87.0	)

⁽¹⁾  Includes light and heavy oil.

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

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

PENGROWTH 2014 Management's Discussion and Analysis 14

management contracted price is higher than the benchmark prices at settlement. Realized gains and losses are settled monthly and directly impact cash flow for the period.

As per the table above, realized commodity risk management gains were recorded in the fourth quarter of 2014 compared to losses in the third quarter of 2014 and the fourth quarter of 2013 primarily resulting from a decline in the oil benchmark price. Full year 2014 realized commodity risk management losses increased compared to the same period last year mainly due to a rise in natural gas benchmark prices year over year.

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

Forward Contracts - Commodity and Power Risk Management

The following table provides a summary of the fixed prices of the commodity and power risk management contracts in place at December 31, 2014 (see Note 17 to the audited Consolidated Financial Statements for more information on Pengrowth's risk management contracts):

Crude Oil Swaps and Puts
Reference point	Yearly average volume (bbl/d)	Year	% of total 2015 oil production Guidance (1)	Price/bbl ($Cdn)
WTI	26,000	2015	75%	93.99
WTI	19,482	2016	56%	90.39
Natural Gas Swaps and Puts
Reference point	Yearly average volume (MMBtu/d)	Year	% of 2015 natural gas production Guidance	Price/MMBtu ($Cdn)
AECO & NGI Chicago Index	86,279	2015	46%	3.84
AECO	37,887	2016	20%	3.79
AECO	21,877	2017	12%	4.01
AECO	4,739	2018	3%	3.89
Power
Reference point	Yearly average volume (MW)	Year	% of estimated power purchases	Price/MWh ($Cdn)
AESO	40	2015	79%	49.53
AESO	10	2016	15%	50.00

⁽¹⁾  Includes light and heavy crude oil. After the successful 2013 divestment program, 2015 oil risk management contracts represent over 65 percent of 2015 production Guidance. Pengrowth's Board of Directors has approved the retention of the risk management contracts already in place.

In addition to the above table, Pengrowth has financial and physical contracts to manage oil price differentials. See Note 17 to the audited Consolidated Financial Statements for more information.

PENGROWTH 2014 Management's Discussion and Analysis 15

Commodity and Power Price Sensitivity on Risk Management Contracts as at December 31, 2014

($ millions)
Oil	Cdn$1/bbl increase in future oil prices		Cdn$1/bbl decrease in future oil prices
Unrealized pre-tax gain (loss) on oil risk management	(16.5	)	16.5
Natural gas	Cdn$0.25/MMBtu increase in future natural gas prices		Cdn$0.25/MMBtu decrease in future natural gas prices
Unrealized pre-tax gain (loss) on natural gas risk management	(13.6	)	13.5
Power	Cdn$1/MWh increase in future power prices		Cdn$1/MWh decrease in future power prices
Unrealized pre-tax gain (loss) on power risk management	0.4		(0.4	)

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

If each commodity risk management contract were to have settled at December 31, 2014, revenue and cash flow would have been $421.1 million higher than if the risk management contracts were not in place based on the estimated fair value of the risk management contracts at period end. The $421.1 million is composed of assets of $292.3 million relating to risk management contracts expiring within one year and assets of $128.8 million relating to risk management contracts expiring beyond one year.

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

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

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

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

As a result of the successful 2013 divestment program, 2015 oil risk management contracts represent over 65 percent of 2015 production Guidance. Pengrowth's Board of Directors approved the retention of the risk management contracts already in place.

PENGROWTH 2014 Management's Discussion and Analysis 16

OIL AND GAS SALES EXCLUDING REALIZED COMMODITY RISK MANAGEMENT

Contribution Analysis

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

	Three months ended						Twelve months ended
($ millions except percentages)	Dec 31, 2014	% of total	Sept 30, 2014	% of total	Dec 31, 2013	% of total	Dec 31, 2014	% of total	Dec 31, 2013	% of total
Light oil	129.9	45	184.8	50	172.2	50	713.6	48	885.8	56
Heavy oil	47.0	16	59.5	16	47.3	14	226.5	15	207.3	13
Natural gas liquids	34.1	12	45.8	13	58.3	17	192.9	13	213.4	13
Natural gas	77.1	26	74.8	20	63.3	18	349.4	23	270.0	17
Other income including sulphur	3.4	1	4.2	1	2.6	1	14.5	1	16.9	1
Total oil and gas sales (1)	291.5		369.1		343.7		1,496.9		1,593.4

⁽¹⁾  Excluding realized commodity risk management.

Price and Volume Analysis

Quarter ended December 31, 2014 versus Quarter ended September 30, 2014

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

($ millions)	Light oil		Heavy oil		NGLs		Natural gas		Other (2)		Total
Quarter ended September 30, 2014 (1)	184.8		59.5		45.8		74.8		4.2		369.1
Effect of change in product prices and differentials	(37.6	)	(12.9	)	(11.6	)	(0.6	)	—		(62.7	)
Effect of change in sales volumes	(17.3	)	0.4		(0.1	)	2.9		—		(14.1	)
Other	—		—		—		—		(0.8	)	(0.8	)
Quarter ended December 31, 2014 (1)	129.9		47.0		34.1		77.1		3.4		291.5

⁽¹⁾  Excluding realized commodity risk management.

⁽²⁾  Primarily sulphur sales.

Light oil sales decreased 30 percent in the fourth quarter of 2014 compared to the third quarter of 2014 resulting from a decrease in the Edmonton par light oil benchmark price combined with lower sales volumes due to minor property dispositions and temporary solution gas restrictions in the Swan Hills area. Heavy oil sales decreased 21 percent in response to a decrease in the WCS benchmark. NGL sales decreased 26 percent driven by lower prices in the fourth quarter of 2014. Natural gas sales increased 3 percent in response to higher sales volumes from the Groundbirch development program combined with less downtime at Sable Island.

Quarter ended December 31, 2014versus Quarter endedDecember 31, 2013

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

($ millions)	Light oil		Heavy oil		NGLs		Natural gas		Other (2)	Total
Quarter ended December 31, 2013 (1)	172.2		47.3		58.3		63.3		2.6	343.7
Effect of change in product prices and differentials	(18.4	)	0.1		(18.1	)	16.0		—	(20.4	)
Effect of change in sales volumes	(23.9	)	(0.4	)	(6.1	)	(2.2	)	—	(32.6	)
Other	—		—		—		—		0.8	0.8
Quarter ended December 31, 2014 (1)	129.9		47.0		34.1		77.1		3.4	291.5

⁽¹⁾  Excluding realized commodity risk management.

⁽²⁾  Primarily sulphur sales.

Light oil sales decreased 25 percent in the fourth quarter of 2014 compared to the same period in 2013 due to lower volumes from several minor 2014 property dispositions and temporary solution gas restrictions in the Swan Hills area coupled with a decrease in the Edmonton par light oil price. Heavy oil sales were essentially unchanged. NGL sales decreased 42 percent driven by lower prices compared to the same period last year. Natural gas sales increased 22 percent due to higher natural gas benchmark prices year over year.

PENGROWTH 2014 Management's Discussion and Analysis 17

Twelve Months ended December 31, 2014versusTwelve Months ended December 31, 2013

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

($ millions)	Light oil		Heavy oil		NGLs		Natural gas		Other (2)		Total
Twelve months ended December 31, 2013 (1)	885.8		207.3		213.4		270.0		16.9		1,593.4
Effect of change in product prices and differentials	18.7		21.8		(13.5	)	114.0		—		141.0
Effect of change in sales volumes	(190.9	)	(2.6	)	(7.0	)	(34.6	)	—		(235.1	)
Other	—		—		—		—		(2.4	)	(2.4	)
Twelve months ended December 31, 2014 (1)	713.6		226.5		192.9		349.4		14.5		1,496.9

⁽¹⁾  Excluding realized commodity risk management.

⁽²⁾  Primarily sulphur sales.

Full year 2014 light oil sales decreased 19 percent compared to 2013 due to lower sales volumes relating to the late 2013 disposition program in addition to several minor 2014 property dispositions partly offset by an increase in the Edmonton par light oil price year over year. Heavy oil sales increased 9 percent resulting from an improvement in the WCS benchmark price. NGL sales decreased 10 percent impacted by lower pentane and butane prices in 2014 coupled with lower volumes. Natural gas sales increased 29 percent due to higher natural gas benchmark prices partly offset by lower sales volumes from the late 2013 property dispositions and natural declines.

ROYALTY EXPENSES

($ millions except per boe amounts and percentages)	Three months ended			Twelve months ended
	Dec 31, 2014	Sept 30, 2014	Dec 31, 2013	Dec 31, 2014	Dec 31, 2013
Royalty expenses	51.2	65.5	62.8	268.6	275.1
$/boe	7.75	9.83	8.82	10.04	8.92
Royalties as a percent of oil and gas sales (%) (1)	17.6	17.7	18.3	17.9	17.3

⁽¹⁾  Excluding realized commodity risk management.

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

Fourth quarter of 2014 royalties as a percentage of sales remained consistent with the third quarter of 2014. Fourth quarter of 2014 royalties as a percentage of sales decreased to 17.6 percent from 18.3 percent in the fourth quarter of 2013 mainly due to lower Sable Island royalties and lower freehold royalties. Full year 2014 royalties as a percentage of sales increased to 17.9 percent from 17.3 percent in 2013 impacted by an increase in natural gas reference prices and unfavourable gas cost allowance adjustments recorded in 2014.

OPERATING EXPENSES

($ millions except per boe amounts)	Three months ended			Twelve months ended
	Dec 31, 2014	Sept 30, 2014	Dec 31, 2013	Dec 31, 2014	Dec 31, 2013
Operating expenses	94.5	102.4	109.2	415.4	482.5
$/boe	14.31	15.36	15.34	15.53	15.64

Fourth quarter of 2014 operating expenses decreased $7.9 million or 8 percent compared to the third quarter of 2014 primarily due to lower power and turnaround costs combined with lower costs as a result of minor asset sales during the third quarter of 2014. On a per boe basis, fourth quarter of 2014 operating expenses decreased $1.05/boe as a result of the lower expenses, as mentioned above.

Fourth quarter of 2014 operating expenses decreased $14.7 million or 13 percent compared to the fourth quarter of 2013 primarily due to lower power, processing and gathering fees and from minor asset sales during the third quarter of 2014. On a per boe basis, fourth quarter of 2014 operating expenses decreased $1.03/boe compared to the fourth quarter of 2013 due to the above mentioned cost decreases partly offset by reduced production.

Full year 2014 operating expenses decreased $67.1 million or 14 percent due to the absence of operating expenses from properties divested throughout 2013 and 2014 as well as lower power costs, partly offset by increased turnaround costs in 2014. On a per boe basis, 2014 operating expenses decreased $0.11/boe compared to 2013 driven by lower costs partly offset by reduced production resulting mainly from the 2013 and 2014 dispositions.

PENGROWTH 2014 Management's Discussion and Analysis 18

TRANSPORTATION EXPENSES

($ millions except per boe amounts)	Three months ended			Twelve months ended
	Dec 31, 2014	Sept 30, 2014	Dec 31, 2013	Dec 31, 2014	Dec 31, 2013
Transportation expenses	8.7	6.5	7.8	30.8	29.4
$/boe	1.32	0.97	1.10	1.15	0.95

Fourth quarter of 2014 transportation expenses increased $2.2 million or 34 percent compared to the third quarter of 2014. During the fourth quarter of 2014, Pengrowth commenced directly marketing and delivering natural gas to the Chicago sales point using Pengrowth's existing Alliance pipeline capacity. Previously, Pengrowth's Alliance pipeline capacity was managed by a third party. Although Pengrowth's transportation expense increased, the realized natural gas price also increased. In addition, higher trucking costs at various locations also contributed to the increase in transportation expenses in the fourth quarter of 2014. On a per boe basis, fourth quarter of 2014 transportation expenses increased $0.35/boe compared to the third quarter of 2014 driven by increased transportation expenses, as described above.

Fourth quarter of 2014 transportation expenses increased $0.9 million or 12 percent compared to the fourth quarter of 2013 also resulting from moving natural gas directly into the Chicago market. On a per boe basis, fourth quarter of 2014 transportation expenses increased $0.22/boe compared to the same period last year due to higher transportation costs and lower production volumes.

Full year 2014 transportation expenses increased $1.4 million or 5 percent compared to 2013 mainly due to higher sales product trucking costs at Lochend. During the second half of 2014, pipeline infrastructure development was completed at Lochend. Also contributing to higher transportation costs in 2014 was the direct use by Pengrowth of its Alliance pipeline capacity as described above; where prior to the fourth quarter of 2014, the Alliance connected gas was sold at the wellhead, thereby not incurring transportation expenses. On a per boe basis, 2014 transportation costs increased $0.20/boe compared to 2013 due to the increase in transportation expenses combined with a decrease in production volumes.

Pengrowth incurs transportation expenses for its natural gas production once the product enters a pipeline at a title transfer point. Pengrowth has the option to sell some of its natural gas directly to markets outside of Alberta by incurring additional transportation costs. Pengrowth also incurs transportation expenses on its oil and NGL production including sales product trucking costs and pipeline costs up to the custody transfer point. Pengrowth has elected to sell approximately 70 percent of its crude oil at market points beyond the wellhead, incurring transportation costs prior to custody transfer points. The transportation expenses are dependent upon third party rates and the distance the product travels prior to changing ownership or custody.

PENGROWTH 2014 Management's Discussion and Analysis 19

OPERATING NETBACKS

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

	Three months ended						Twelve months ended
Combined Netback ($/boe)	Dec 31, 2014		Sept 30, 2014		Dec 31, 2013		Dec 31, 2014		Dec 31, 2013
Oil & gas sales (includes other income)	44.13		55.36		48.29		55.96		51.64
Royalties	(7.75	)	(9.83	)	(8.82	)	(10.04	)	(8.92	)
Operating expenses	(14.31	)	(15.36	)	(15.34	)	(15.53	)	(15.64	)
Transportation expenses	(1.32	)	(0.97	)	(1.10	)	(1.15	)	(0.95	)
Operating netback before realized commodity risk management	20.75		29.20		23.03		29.24		26.13
Realized commodity risk management	3.29		(4.29	)	(2.21	)	(3.60	)	(1.78	)
Operating netback	24.04		24.91		20.82		25.64		24.35
Light Oil Netback Excluding Realized Commodity Risk Management ($/bbl)
Sales	72.93		94.04		83.23		92.10		89.68
Royalties	(17.71	)	(19.91	)	(19.84	)	(19.96	)	(18.71	)
Operating expenses	(15.78	)	(15.99	)	(16.57	)	(15.80	)	(17.04	)
Transportation expenses	(2.18	)	(1.65	)	(2.22	)	(2.10	)	(1.65	)
Light oil operating netback	37.26		56.49		44.60		54.24		52.28
Heavy Oil Netback Excluding Realized Commodity Risk Management ($/bbl)
Sales	61.56		78.43		61.43		75.21		67.98
Royalties	(10.58	)	(13.09	)	(9.90	)	(11.71	)	(9.79	)
Operating expenses	(19.97	)	(16.80	)	(17.36	)	(18.58	)	(18.97	)
Transportation expenses	(1.64	)	(1.67	)	(1.36	)	(1.74	)	(1.62	)
Heavy oil operating netback	29.37		46.87		32.81		43.18		37.60
NGLs Netback Excluding Realized Commodity Risk Management ($/bbl)
Sales	39.51		52.94		60.49		52.17		55.81
Royalties	(9.19	)	(14.38	)	(15.47	)	(14.61	)	(15.33	)
Operating expenses	(13.40	)	(15.53	)	(14.30	)	(15.28	)	(15.03	)
Transportation expenses	—		—		(0.01	)	—		(0.05	)
NGLs operating netback	16.92		23.03		30.71		22.28		25.40
Natural Gas Netback Excluding Realized Commodity Risk Management ($/Mcf)
Sales	4.02		4.05		3.18		4.74		3.19
Royalties (1)	(0.19	)	(0.22	)	0.04		(0.33	)	(0.02	)
Operating expenses	(2.06	)	(2.43	)	(2.39	)	(2.45	)	(2.35	)
Transportation expenses	(0.20	)	(0.11	)	(0.11	)	(0.13	)	(0.09	)
Natural gas operating netback ($/Mcf)	1.57		1.29		0.72		1.83		0.73
Natural gas operating netback ($/boe)	9.42		7.74		4.32		10.98		4.38
CONTRIBUTION BASED ON OPERATING NETBACKS
Light oil	50	%	58	%	57	%	55	%	65	%
Heavy oil	17	%	19	%	16	%	17	%	15	%
Natural gas liquids	11	%	10	%	18	%	11	%	12	%
Natural gas	22	%	13	%	9	%	17	%	8	%

⁽¹⁾  Fourth quarter of 2013 contains a favourable prior period adjustment.

PENGROWTH 2014 Management's Discussion and Analysis 20

Pengrowth realized a weighted average operating netback of $24.04/boe in the fourth quarter of 2014 representing a 3 percent decrease compared to the third quarter of 2014 primarily due to lower benchmark prices partly offset by realized risk management gains instead of losses and lower royalties and operating expenses. When comparing the fourth quarter of 2014 to the same period last year, the operating netback increased 15 percent mainly driven by realized risk management gains instead of losses and lower royalties and operating expenses.

Full year 2014 operating netback increased 5 percent compared to 2013 resulting mainly from higher benchmark prices year over year.

GENERAL AND ADMINISTRATIVE EXPENSES

	Three months ended			Twelve months ended
($ millions except per boe amounts)	Dec 31, 2014	Sept 30, 2014	Dec 31, 2013	Dec 31, 2014	Dec 31, 2013
Cash G&A expenses	21.2	20.6	21.7	84.3	87.8
$/boe	3.21	3.09	3.05	3.15	2.85
Non-cash G&A expenses	2.6	5.0	2.5	16.0	15.0
$/boe	0.39	0.75	0.35	0.60	0.48
Total G&A	23.8	25.6	24.2	100.3	102.8
$/boe	3.60	3.84	3.40	3.75	3.33

Fourth quarter of 2014 cash G&A expenses were $0.6 million or $0.12/boe higher compared to the third quarter of 2014 mainly due to year end reserve reporting fees.

Fourth quarter of 2014 cash G&A expenses decreased $0.5 million compared to the same period last year resulting primarily from lower personnel costs. On a per boe basis, fourth quarter of 2014 cash G&A expenses increased $0.16/boe compared to the same period last year primarily due to the impact of lower production volumes in 2014 partly offset by lower costs.

Full year 2014 cash G&A expenses were $3.5 million lower compared to 2013 due to staffing decreases associated with the 2013 dispositions as well as lower office rent. On a per boe basis, 2014 cash G&A expenses increased $0.30/boe due to lower production volumes partly offset by lower expenses, as discussed above.

The non-cash component of G&A represents the compensation expenses associated with Pengrowth’s Long Term Incentive Plan ("LTIP"). See Note 13 to the audited Consolidated Financial Statements for additional information. The compensation costs associated with this plan are expensed over the applicable vesting periods.

Fourth quarter of 2014 non-cash G&A expenses decreased $2.4 million compared to the third quarter of 2014 resulting from a lower performance multiplier on previously expensed grants. Fourth quarter of 2014 non-cash G&A expenses remained relatively unchanged compared to the same period last year.

Full year 2014 non-cash G&A expenses increased $1.0 million compared to 2013 due to slightly higher long term incentive plan grants in 2014.

During 2014, $14.7 million (2013 - $16.0 million) of directly attributable G&A costs were capitalized to Property, Plant and Equipment ("PP&E").

UNREALIZED LOSS ON INVESTMENTS

Pengrowth owns 1.0 million shares of a private corporation with an estimated fair value of $nil at December 31, 2014. The fair value is based in part on the lack of success of recent private placement equity offerings by the private company.

As the fair value at December 31, 2014 was estimated to be $nil (December 31, 2013 - $5 million) Pengrowth recorded an unrealized loss of $5 million in 2014 (2013 - $15 million loss). See Note 4 to the audited Consolidated Financial Statements for additional information.

PENGROWTH 2014 Management's Discussion and Analysis 21

DEPLETION, DEPRECIATION, AMORTIZATION AND ACCRETION

	Three months ended			Twelve months ended
($ millions except per boe amounts)	Dec 31, 2014	Sept 30, 2014	Dec 31, 2013	Dec 31, 2014	Dec 31, 2013
Depletion, depreciation and amortization	127.7	128.5	130.7	517.0	574.6
$/boe	19.33	19.27	18.36	19.33	18.62
Accretion	4.4	4.5	4.9	18.8	20.5
$/boe	0.67	0.67	0.69	0.70	0.66

Fourth quarter of 2014 DD&A expense decreased $0.8 million and $3.0 million compared to the third quarter of 2014 and fourth quarter of 2013, respectively, mainly due to the decrease in production volumes related to several minor 2014 property dispositions.

Full year 2014 DD&A expense decreased $57.6 million compared to 2013 due to lower production volumes related to the 2013 property dispositions and several minor 2014 property dispositions.

Fourth quarter of 2014 accretion expense remained relatively unchanged compared to the third quarter of 2014. Fourth quarter and full year 2014 accretion expense decreased $0.5 million and $1.7 million compared to the same periods last year, respectively, mainly due to decreases in the ARO liability resulting from property dispositions and discount rate changes.

EXPLORATION AND EVALUATION ASSETS ("E&E")

Pengrowth's E&E assets consist of exploration and development projects which are pending the determination of proved plus probable reserves and production. During the fourth quarter of 2014, Pengrowth acquired 32.6 gross/net sections of prospective liquids-rich Montney lands at Bernadet in north eastern British Columbia. The vast majority of the $490.1 million of E&E assets on the Consolidated Balance Sheets relate to the Groundbirch and Bernadet areas in north eastern British Columbia. See Note 6 of the audited Consolidated Financial Statements for more information.

IMPAIRMENTS

	Three months ended			Twelve months ended
($ millions)	Dec 31, 2014	Sept 30, 2014	Dec 31, 2013	Dec 31, 2014	Dec 31, 2013
PP&E impairment	486.3	—	—	486.3	—
E&E impairment	57.0	—	—	57.0	—
Goodwill impairment	451.3	—	—	451.3	—
Total impairment	994.6	—	—	994.6	—

PP&E Impairments

IFRS requires an impairment test to assess the recoverable value of the PP&E within each CGU whenever there is an indication of impairment. In light of a significant and rapid decline in oil benchmark prices in the fourth quarter of 2014 and continued softening in natural gas prices, impairment tests were carried out on all CGUs at December 31, 2014, resulting in a $486.3 million PP&E impairment on three CGUs at December 31, 2014. The impairment tests carried out were based on reserve values using pre-tax discount rates of 10 - 15 percent - varying from CGU to CGU (December 31, 2013: 8 - 15 percent), January 1, 2015 independent reserves evaluator's forecast pricing and an inflation rate of 2 percent. The recoverable amount of each CGU was determined using fair value less costs to sell.

All CGUs were negatively impacted by a downturn in the forward benchmark prices and those CGUs that previously used a discount rate of 8 percent were further impacted by the move to a discount rate of 10 percent in calculating the present value of the associated reserves. The increase in discount rate reflects the increased market uncertainty facing Western Canadian oil and gas companies.

The impairments noted above were recorded on the Consolidated Statements of Income (Loss) at December 31, 2014 and may be reversed, excluding goodwill, if and when the fair values of the CGUs increase in the future periods. However, the impairment test is sensitive to lower commodity prices, which have been under significant downward pressure recently. Further declines in commodity prices could result in additional impairment charges if the recoverable

PENGROWTH 2014 Management's Discussion and Analysis 22

values are further eroded by price decreases. See Note 5 to the audited Consolidated Financial Statements for additional information.

At December 31, 2013, there were no indications of impairment, however, due to the required annual goodwill impairment test, all of the CGUs that have associated goodwill were tested. No impairment was recognized on any of the CGUs tested at December 31, 2013.

Exploration and Evaluation Impairments

In conjunction with the Montney CGU, Pengrowth evaluated its Groundbirch project for an impairment. This was in accordance with Pengrowth's policy and IFRS which states that the impairment of ongoing E&E projects should be assessed on the cash flow from the applicable CGUs in the operating segment. It was determined that the recoverable amount was below the carrying amount, thus a $57.0 million impairment on the Groundbirch E&E asset was recorded at December 31, 2014.

The recoverable amount is generally computed by reference to the present value of the future cash flows expected to be derived from production of proved plus probable reserves for the operating segment. Undeveloped land and contingent resources were also considered in the recoverable amount. Changes in forward price estimates, production costs or recovery rates may change the economic status of contingent resources and may ultimately result in contingent resources being restated. The Groundbirch E&E impairment test was based on reserve values using a pre-tax discount rate of 10 percent; independent reserves evaluator January 1, 2015 forecast pricing and an inflation rate of 2 percent; and contingent resources using a pre-tax discount rate of 12 percent. See Notes 5 and 6 to the audited Consolidated Financial Statements for more information.

An impairment test was performed on January 1, 2013 upon transfer of the Lindbergh Project to PP&E. The net present value of the proved plus probable reserves, as determined by the external reserve evaluator, supported the carrying value of the Lindbergh Project, and as such, no impairment was required.

Goodwill Impairments

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

At December 31, 2014, impairment tests were performed, which resulted in a $451.3 million impairment of goodwill to both CGU specific and groups of CGUs goodwill. All CGUs were negatively impacted by a downturn in the forward benchmark prices, and several CGUs were impacted by increasing the discount rate from 8 to 10 percent for present valuing the reserves. See Note 7 to the audited Consolidated Financial Statements for more information.

As at December 31, 2014, Pengrowth has remaining goodwill of $202.2 million (December 31, 2013 - $672.7 million) which is not specific to any CGU. In addition to the $451.3 million in impairment charges, several minor 2014 property dispositions resulted in a $19.2 million decrease in goodwill in 2014 (2013 - $28.0 million).

At December 31, 2013, an impairment test was performed with no impairments to goodwill recorded.

INTEREST AND FINANCING CHARGES

	Three months ended						Twelve months ended
($ millions)	Dec 31, 2014		Sept 30, 2014		Dec 31, 2013		Dec 31, 2014		Dec 31, 2013
Interest and financing charges	27.6		26.0		24.6		105.6		100.2
Capitalized interest	(9.9	)	(8.8	)	(3.3	)	(31.0	)	(6.1	)
Total interest and financing charges	17.7		17.2		21.3		74.6		94.1

At December 31, 2014, Pengrowth had approximately $1.8 billion in total long term debt composed of $1.5 billion of fixed rate debt, $0.2 billion in term credit facility and $0.1 billion in convertible debentures. Total long term debt consists primarily of U.S. dollar denominated fixed rate notes at a weighted average interest rate of 5.7 percent. The term credit facility had an average 3.8 percent interest rate and convertible debentures have a 6.25 percent coupon.

Fourth quarter of 2014 interest and financing charges, before capitalized interest, increased $1.6 million and $3.0 million compared to the third quarter of 2014 and fourth quarter of 2013, respectively, from borrowing on the term credit facility in the fourth quarter of 2014 and higher interest expense on U.S. term debt resulting from the weakening of the Canadian Dollar.

PENGROWTH 2014 Management's Discussion and Analysis 23

Full year 2014 interest and financing charges, before capitalized interest, increased $5.4 million compared to 2013 mainly due to higher interest expense on the U.S. and U.K. term debt as a result of the weaker Canadian dollar relative to last year.

In accordance with IFRS, interest is capitalized for qualifying assets in the construction phase based on costs incurred on the project and the average cost of borrowing. During the year ended December 31, 2014, $31.0 million (December 31, 2013 - $6.1 million) of interest was capitalized on the Lindbergh thermal project to PP&E using a capitalization rate of 5.7 percent (December 31, 2013 - 5.7 percent). Pengrowth anticipates to cease capitalizing interest on the first phase of Lindbergh in the first half of 2015.

OTHER (INCOME) EXPENSE

Full year 2014 other expense of $19.3 million includes a $22.6 million provision for clean-up and remediation costs at a northern Alberta oil property incurred in the first quarter of 2014 partly offset by gains on remediation trust funds and interest income.

TAXES

Deferred income tax is a non-cash item relating to temporary differences between the accounting and tax basis of Pengrowth’s assets and liabilities and has no immediate impact on Pengrowth’s cash flows. Pengrowth recorded a deferred tax recovery of $14.4 million in the fourth quarter of 2014 compared to a deferred tax expense of $32.6 million in the third quarter of 2014 and a deferred tax recovery of $18.6 million in the fourth quarter of 2013. Full year 2014 deferred tax recovery amounted to $20.4 million compared to $73.2 million recorded in 2013.

No current income taxes were paid by Pengrowth in 2014 or 2013. See Note 11 to the audited Consolidated Financial Statements for additional information.

PENGROWTH 2014 Management's Discussion and Analysis 24

FOREIGN CURRENCY GAINS (LOSSES)

	Three months ended						Twelve months ended
($ millions)	Dec 31, 2014		Sept 30, 2014		Dec 31, 2013		Dec 31, 2014		Dec 31, 2013
Currency exchange rate ($1Cdn = $U.S.) at period end	0.86		0.89		0.94		0.86		0.94
Unrealized foreign exchange loss on U.S. dollar denominated debt	(47.9	)	(63.9	)	(39.9	)	(114.9	)	(83.4	)
Unrealized foreign exchange gain (loss) on U.K. pound sterling denominated debt	0.5		0.7		(6.1	)	(2.9	)	(9.4	)
Total unrealized foreign exchange loss from translation of foreign denominated debt	(47.4	)	(63.2	)	(46.0	)	(117.8	)	(92.8	)
Unrealized gain on U.S. foreign exchange risk management contracts	17.3		20.8		12.0		34.9		21.0
Unrealized gain (loss) on U.K. foreign exchange risk management contracts	0.3		(0.3	)	5.8		3.9		8.8
Total unrealized gain on foreign exchange risk management contracts	17.6		20.5		17.8		38.8		29.8
Total unrealized foreign exchange loss	(29.8	)	(42.7	)	(28.2	)	(79.0	)	(63.0	)
Total realized foreign exchange gain (loss)	(0.3	)	0.8		(0.2	)	(1.0	)	1.1

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

Pengrowth holds a series of swap contracts which were transacted in order to fix the foreign exchange rate on a portion of Pengrowth’s U.S. dollar denominated term debt. The swaps partially offset foreign exchange gains/losses on U.S. dollar denominated debt. Each swap requires Pengrowth to buy U.S. dollars at a predetermined rate and time, based upon maturity dates of the U.S. dollar term debt. At December 31, 2014, the fair value of these foreign exchange derivative contracts was an asset of $58.0 million included on the Consolidated Balance Sheets with changes in the fair value between Balance Sheet dates reported on the Consolidated Statements of Income (Loss) as an unrealized foreign exchange (gain) loss.

Contract type	Settlement date	Principal amount (U.S.$ millions)	Swapped amount (U.S.$ millions)	% of principal swapped		Fixed rate ($1Cdn = $U.S.)
Swap	May 2015	71.5	50.0	70	%	0.98
Swap	July 2017	400.0	250.0	63	%	0.97
Swap	August 2018	265.0	125.0	47	%	0.96
Swap	October 2019	35.0	15.0	43	%	0.94
Swap	May 2020	115.5	20.0	17	%	0.95
No contracts	October 2022	105.0	—	—		—
No contracts	October 2024	195.0	—	—		—
		1,187.0	460.0	39	%

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

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

PENGROWTH 2014 Management's Discussion and Analysis 25

At December 31, 2014, the fair value of these foreign exchange derivative contracts was a liability of $7.2 million included on the Consolidated Balance Sheets with changes in the fair value between Balance Sheet dates reported on the Consolidated Statements of Income (Loss) as an unrealized foreign exchange (gain) loss.

At December 31, 2014, each Cdn$0.01 exchange rate change would result in approximately a $4.6 million pre-tax change in the fair value of the U.S. risk management contracts and a $0.7 million pre-tax change in the fair value of the U.K. risk management contracts.

ASSET RETIREMENT OBLIGATIONS - NET PRESENT VALUE

($ millions)	Dec 31, 2014		Dec 31, 2013		Change
ARO, opening balance	606.2		868.9		(262.7	)
Revisions due to discount rate changes (1)	211.5		(195.0	)	406.5
Expenditures on remediation	(22.9	)	(29.6	)	6.7
ARO on dispositions	(66.5	)	(84.0	)	17.5
Accretion and other	52.5		45.9		6.6
ARO, closing balance	780.8		606.2		174.6

⁽¹⁾  2014 amount relates to change in the discount rate from 3.25 percent to 2.3 percent. 2013 amount relates to change in the discount rate from 2.5 percent to 3.25 percent. The offset to both revisions is recorded in PP&E.

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.

2014 ARO liability increased $174.6 million mainly due to a change in the risk free discount rate from 3.25 percent at December 31, 2013 to 2.3 percent at December 31, 2014 which increased the liability by $211.5 million. The rate decrease reflects a decrease in the 30 year Canadian Government long term bond rate which drives Pengrowth’s estimate of the ARO discount rate. Partly offsetting this upward revision were several minor 2014 property dispositions which decreased the ARO liability by $66.5 million.

Pengrowth has estimated the net present value of its total ARO to be $780.8 million as at December 31, 2014 (December 31, 2013 – $606.2 million), based on a total escalated future liability of $2.0 billion (December 31, 2013 – $2.1 billion). The majority of the costs are expected to be incurred between 2038 and 2079. A risk free discount rate of 2.3 percent per annum and an ARO specific inflation rate of 1.5 percent were used to calculate the net present value of the ARO at December 31, 2014.

REMEDIATION TRUST FUNDS AND REMEDIATION AND ABANDONMENT EXPENSE

During 2014, Pengrowth contributed $5.0 million (December 31, 2013 - $4.6 million), into trust funds established to fund certain abandonment and reclamation costs associated with Judy Creek and Sable Island. The total balance of the remediation trust funds was $60.4 million at December 31, 2014 (December 31, 2013 - $54.7 million).

Pengrowth has a contractual obligation to make contributions to a remediation trust fund that is used to cover certain ARO on its Judy Creek properties in the Swan Hills area. Pengrowth makes monthly contributions to the fund of $0.10/boe of production from the Judy Creek properties and an annual lump sum contribution of $0.25 million.

Pengrowth has a contractual obligation to make contributions to a remediation trust fund that will be used to fund the ARO of the Sable Island properties and facilities. Since 2007, Pengrowth made a monthly contribution to the fund at a rate of $0.52/MMBtu of its share of natural gas production and $1.04/bbl of its share of natural gas liquids production from Sable Island. Starting in January 2015, the new rates are $4.17/MMBtu of its share of natural gas production and $8.36/bbl of its share of natural gas liquids production.

See Note 4 to the audited Consolidated Financial Statements for additional information.

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. Through December 31, 2014, Pengrowth spent $22.9 million on abandonment and reclamation (December 31, 2013 - $29.6 million). Pengrowth expects to spend approximately $25 million in 2015 on reclamation and abandonment, excluding contributions to remediation trust funds and orphan well levies from the Alberta Energy Regulator.

PENGROWTH 2014 Management's Discussion and Analysis 26

CLIMATE CHANGE PROGRAMS

Effective July 1, 2007, Alberta regulates Greenhouse Gas ("GHG") emissions under the Climate Change and Emissions Management Act of 2007. Under the Act, the Specified Gas Reporting Regulation ("SGRR") imposes annual GHG emissions reporting requirements on all Alberta facilities that emit more than 50,000 tonnes of greenhouse gases per year. Also under the Act, the Specified Gas Emitters Regulation ("SGER") requires Alberta facilities that emit more than 100,000 tonnes of greenhouse gases per year to reduce emissions intensity by 12 percent annually over baseline emission levels for those facilities. The baseline for facilities is an average of 2003, 2004 and 2005 emissions. Facilities can meet these required reductions in three ways: audited emission reductions in their operations; purchased Alberta-based offset carbon credits or contributions to the Alberta Climate Change and Emissions Management Fund. Unused reduction credits from one year may be carried forward to future years.

Pengrowth has three operated facilities that are subject to the annual 12 percent reduction: the Olds Gas Plant, the Judy Creek Gas Conservation Plant and the Quirk Creek Gas Plant. Pengrowth will report 2014 emission reduction information on these facilities by March 31, 2015, as scheduled. It is anticipated that the Olds Gas Plant and the Judy Creek Gas Conservation Plant will achieve the reduction targets for 2014, however the Quirk Creek Gas Plant is not expected to achieve the reduction target. During 2014, Pengrowth purchased approximately $0.7 million of Emission Performance Credits payable to the Alberta Climate Change and Emissions Management Fund relating to the 2013 Quirk Creek Gas Plant emissions reporting.

ACQUISITIONS AND DISPOSITIONS

	Three months ended						Twelve months ended
($ millions)	Dec 31, 2014		Sept 30, 2014		Dec 31, 2013		Dec 31, 2014		Dec 31, 2013
Property acquisitions	1.2		13.7		12.1		17.0		16.0
Proceeds on property dispositions	(21.0	)	(43.0	)	(41.3	)	(84.5	)	(993.7	)
Net cash acquisitions (dispositions)	(19.8	)	(29.3	)	(29.2	)	(67.5	)	(977.7	)

During 2014, Pengrowth successfully closed several minor non-core property dispositions for aggregate net proceeds of $84.5 million resulting in pre-tax gains of $23.3 million. Pengrowth also completed several minor asset acquisitions for $17.0 million, excluding the $123.6 million land acquisition at Bernadet which is reflected in capital spending.

During 2013, Pengrowth successfully closed the disposition of its non-core southeast Saskatchewan assets, non-operated Weyburn property and other minor properties for proceeds of $993.7 million, net of closing adjustments, resulting in pre-tax losses of $175.7 million. The proceeds were used to pay down the term credit facility in 2013 and fund the first commercial phase of Lindbergh.

WORKING CAPITAL

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 and convertible debentures, as applicable.

At December 31, 2014, Pengrowth had a working capital surplus of $22.7 million as current assets exceeded current liabilities. In comparison, Pengrowth had a working capital surplus of $179.3 million at December 31, 2013. The year over year decrease in the working capital surplus was due to a $nil cash balance at December 31, 2014 compared to $448.5 million at December 31, 2013, partly offset by a $299.6 million increase in the current asset fair value of risk management contracts at December 31, 2014. The cash balance of $448.5 million at the start of 2014 was used to fund the Lindbergh capital program.

PENGROWTH 2014 Management's Discussion and Analysis 27

FINANCIAL RESOURCES AND LIQUIDITY

As at:	Dec 31, 2014		Dec 31, 2013		Change
($ millions)
Term credit facilities	191.0		—		191.0
Senior unsecured notes (1)	1,531.0		1,412.7		118.3
Senior debt	1,722.0		1,412.7		309.3
Convertible debentures	137.2		236.0		(98.8	)
Total debt before working capital	1,859.2		1,648.7		210.5
Working capital surplus (2)	(22.7	)	(179.3	)	156.6
Total debt	1,836.5		1,469.4		367.1
Twelve months trailing:	Dec 31, 2014		Dec 31, 2013		Change
($ millions, except ratios and percentages)
Net loss	(578.8	)	(316.9	)	(261.9	)
Add (deduct):
Interest and financing charges	74.6		94.1		(19.5	)
Deferred income tax recovery	(20.4	)	(73.2	)	52.8
Depletion, depreciation, amortization and accretion	535.8		595.1		(59.3	)
EBITDA	11.2		299.1		(287.9	)
Add other items:
Impairment	994.6		—		994.6
(Gain) loss on disposition of properties	(23.3	)	175.7		(199.0	)
Other non-cash items (3)	(402.2	)	180.2		(582.4	)
Adjusted EBITDA	580.3		655.0		(74.7	)
Senior debt before working capital to Adjusted EBITDA (4)	3.0		2.2		0.8
Total debt before working capital to Adjusted EBITDA (5)	3.2		2.5		0.7
Total debt to Adjusted EBITDA (6)	3.2		2.2		1.0
Total capitalization (7)	4,763.3		5,157.7		(394.4	)
Total debt as a percentage of total capitalization	38.6	%	28.5	%

⁽¹⁾  Includes current and long term portions.

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

⁽³⁾  Primarily resulting from the impact of unrealized fair value changes in risk management contracts and unrealized foreign exchange on long term debt.

⁽⁴⁾  Indicative of debt covenant for senior debt before working capital to EBITDA of 3.5 times.

⁽⁵⁾  Indicative of debt covenant for total debt before working capital to EBITDA of 4.0 times.

⁽⁶⁾  Not indicative of the actual debt covenants. See the Financial Covenants section for more information.

⁽⁷⁾  Total capitalization includes total debt plus Shareholders' Equity per the Consolidated Balance Sheets.

At December 31, 2014, total debt increased $367.1 million from December 31, 2013 mainly due to the term credit facility balance increasing to $191.0 million, and a decrease in the working capital surplus which was used to help fund general corporate activities including capital expenditures and dividends. Also, a $118.3 million increase in the U.S. senior unsecured notes due to the weakening of the Canadian dollar contributed to the change. This was partly offset by a decrease in convertible debentures as one of the series matured and was paid off, using the term credit facility, on December 31, 2014.

The trailing twelve months total debt to Adjusted EBITDA ratio increased to 3.2x at December 31, 2014, compared to 2.2x at December 31, 2013 mainly due to the increase in total debt and a decrease in funds flow from operations.

In light of the rapid decline in commodity prices in late 2014, Pengrowth has taken extensive and proactive measures for 2015 to ensure the Corporation's financial health and sustainability in a low commodity price environment. In addition to Pengrowth's extensive risk management program, these new initiatives include:

• A significantly reduced capital program for 2015 of $200 million, representing a 78 percent reduction from actual 2014 capital spending, with no decrease in expected production compared to 2014 due to anticipated volume contribution from the first commercial phase at Lindbergh.

PENGROWTH 2014 Management's Discussion and Analysis 28

• A deferral in the development plan for Lindbergh that is still expected to deliver annual bitumen production of 40,000 to 50,000 bbl/d.

• A 50 percent dividend reduction to $0.02 per share per month, which aims to balance 2015 cash inflows with capital obligations and dividends.

• Enhanced focus on management of all aspects of capital, operating and G&A cost structures.

• Commitment to ongoing risk management efforts to protect future cash flows and capital programs. Pengrowth has extensive oil and natural gas risk management contracts in place through 2015 and 2016 that are expected to provide a significant degree of cash flow certainty notwithstanding the current low commodity price environment.

Term Credit Facilities

Pengrowth maintains a $1 billion revolving credit facility which had a balance of $191.0 million at December 31, 2014 (December 31, 2013 - $nil) and had $25.0 million (December 31, 2013 - $35.8 million) in outstanding letters of credit. The credit facility includes an expansion feature of $250 million providing Pengrowth with up to $1.25 billion of notional credit capacity from a syndicate of seven Canadian and four foreign banks, and can be extended at Pengrowth’s discretion any time prior to maturity, subject to syndicate approval. The facility has a maturity date of July 26, 2017.

Pengrowth also maintains a $50 million demand operating facility with one Canadian bank. At December 31, 2014, this facility had a balance of $9.0 million (December 31, 2013 - $nil) and had $0.9 million (December 31, 2013 - $0.8 million) of outstanding letters of credit. When utilized together with any overdraft amounts, this facility appears on the Consolidated Balance Sheets as a current liability in bank indebtedness, as applicable.

Together, these two facilities provided Pengrowth with approximately $822 million of combined notional credit capacity at December 31, 2014, with the ability to expand the facilities by an additional $250 million. Use of the remaining credit capacity is still subject to complying with all financial covenants.

Financial Covenants

Pengrowth’s senior unsecured notes and credit facilities are subject to a number of covenants, all of which were met at all times during the preceding twelve months, and at December 31, 2014.

On January 24, 2014, Pengrowth amended the credit facility by increasing the maximum permitted senior debt before working capital to EBITDA (as calculated in accordance with the debt agreements) ratio from 3.0 to 3.5 times and the total debt before working capital to EBITDA ratio from 3.5 to 4.0 times until December 31, 2015. As at December 31, 2014, Pengrowth's actual ratios pursuant to these two covenants were at 2.9 times and 3.1 times, respectively. The financial covenants are now substantially similar between the credit facilities and the senior unsecured notes. The ratios on the credit facility will revert back to their prior levels of 3.0 and 3.5 times, respectively, after December 31, 2015. The covenant amendments were obtained as a proactive step while Pengrowth completes construction of the first 12,500 bbl/d commercial phase of Lindbergh and a full year of Lindbergh production can contribute to the EBITDA calculation.

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

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

The key financial covenants as at December 31, 2014 are summarized below:

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

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

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

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

There may be instances, such as when financing an acquisition, where it would be acceptable for total debt to trailing EBITDA to temporarily exceed the 4.0 times noted above. In the event of a significant acquisition, certain credit facility financial covenants are relaxed for two fiscal quarters after the close of the acquisition. Pengrowth may prepare pro

PENGROWTH 2014 Management's Discussion and Analysis 29

forma financial statements for debt covenant purposes and has additional flexibility under its debt covenants for a set period of time. This would be a strategic decision recommended by management and approved by the Board of Directors with steps taken in the subsequent period to restore Pengrowth’s capital structure based on its capital management objectives.

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

If certain financial ratios reach or exceed certain levels, management may consider steps to improve these ratios. These steps may include, but are not limited to property dispositions, reducing capital expenditures or dividends as well as issuing equity. Details of these measures are included in Note 16 to the audited Consolidated Financial Statements.

Dividend Reinvestment Plan

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

During the twelve months ended December 31, 2014, 9.2 million shares were issued under the DRIP program for cash proceeds of $51.8 million compared to 8.6 million shares issued for total proceeds of $44.9 million in 2013.

Off-Balance Sheet Financing

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

FINANCIAL INSTRUMENTS

Pengrowth uses financial instruments to manage its exposure to commodity and power price fluctuations and foreign currency exposure. Pengrowth’s policy is not to utilize financial instruments for trading or speculative purposes. See Note 2 to the audited Consolidated Financial Statements for a description of the accounting policies for financial instruments and Note 17 to the audited Consolidated Financial Statements for additional information regarding the fair value of Pengrowth’s financial instruments.

FUNDS FLOW FROM OPERATIONS AND DIVIDENDS

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

	Three months ended						Twelve months ended
($ millions, except per share amounts)	Dec 31, 2014		Sept 30, 2014		Dec 31, 2013		Dec 31, 2014		Dec 31, 2013
Funds flow from operations	115.8		129.0		105.9		505.7		560.9
Dividends declared	63.9		63.6		62.5		253.6		248.5
Funds flow from operations less dividends declared	51.9		65.4		43.4		252.1		312.4
Per share	0.10		0.12		0.08		0.48		0.60
Payout ratio (1)	55	%	49	%	59	%	50	%	44	%

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

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

Funds flow from operations is derived from producing and selling oil, natural gas and related products and is therefore highly dependent on commodity prices. Pengrowth enters into forward commodity risk management contracts to mitigate price volatility and to provide a measure of stability to monthly cash flow. Details of commodity risk management contracts are contained in Note 17 to the audited Consolidated Financial Statements.

PENGROWTH 2014 Management's Discussion and Analysis 30

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

	Three months ended						Twelve months ended
($ millions, except per share amounts)	Dec 31, 2014		Sept 30, 2014		Dec 31, 2013		Dec 31, 2014		Dec 31, 2013
Proceeds from DRIP	12.3		13.1		11.7		51.8		44.9
Per share	0.02		0.02		0.02		0.10		0.09
Net payout ratio (%) (1)	45	%	39	%	48	%	40	%	36	%

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

DRIP participation was equivalent to approximately 19 percent of the total dividend during the fourth quarter of 2014 and 20 percent for the full year 2014.

DIVIDENDS

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

In January 2015, Pengrowth's Board approved a monthly dividend of $0.02 per share starting with the dividend payable on March 16, 2015. The previous dividend level of $0.04 per share was based on higher commodity prices and, given the current low commodity price environment and the uncertainty over how long it will persist, Pengrowth believes that it was prudent to lower the amount of its monthly dividend to ensure that it balances its 2015 cash inflows with capital obligations and dividends in a lower commodity price environment.

Dividends are generally paid to shareholders on the fifteenth day or next business day of the month. Pengrowth paid $0.04 per share in each of the twelve months January through December 31, 2014 for an aggregate cash dividend of $0.48 per share. For the same period in 2013, Pengrowth also paid $0.04 per share in each of the months January through December for an aggregate cash dividend of $0.48 per share.

PENGROWTH 2014 Management's Discussion and Analysis 31

SUMMARY OF QUARTERLY RESULTS

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

2014	Q1		Q2		Q3		Q4
Oil and gas sales ($ millions) (1)	429.2		407.1		369.1		291.5
Net income (loss) ($ millions)	(116.2	)	(8.8	)	52.2		(506.0	)
Net income (loss) per share ($)	(0.22	)	(0.02	)	0.10		(0.95	)
Net income (loss) per share - diluted ($)	(0.22	)	(0.02	)	0.10		(0.95	)
Adjusted net income (loss) ($ millions)	(2.8	)	(24.8	)	3.4		(854.8	)
Funds flow from operations ($ millions)	139.5		121.4		129.0		115.8
Dividends declared ($ millions)	62.8		63.3		63.6		63.9
Dividends declared per share ($)	0.12		0.12		0.12		0.12
Daily production (boe/d)	75,102		73,823		72,472		71,802
Total production (Mboe)	6,759		6,718		6,667		6,606
Average sales price ($/boe) (1)	63.00		60.08		54.73		43.61
Operating netback ($/boe) (2)	29.71		23.86		24.91		24.04
2013	Q1		Q2		Q3		Q4
Oil and gas sales ($ millions) (1)	393.5		416.6		439.6		343.7
Net loss ($ millions)	(65.1	)	(53.4	)	(107.3	)	(91.1	)
Net loss per share ($)	(0.13	)	(0.10	)	(0.21	)	(0.17	)
Net loss per share - diluted ($)	(0.13	)	(0.10	)	(0.21	)	(0.17	)
Adjusted net loss ($ millions)	(1.1	)	(37.2	)	(108.2	)	(37.3	)
Funds flow from operations ($ millions)	147.5		146.0		161.5		105.9
Dividends declared ($ millions)	61.6		62.1		62.3		62.5
Dividends declared per share ($)	0.12		0.12		0.12		0.12
Daily production (boe/d)	89,702		87,909		83,275		77,371
Total production (Mboe)	8,073		8,000		7,661		7,118
Average sales price ($/boe) (1)	48.18		51.55		56.64		47.92
Operating netback ($/boe) (2)	24.79		24.44		27.10		20.82

⁽¹⁾  Excluding realized commodity risk management.

⁽²⁾  Including realized commodity risk management.

Fourth quarter of 2014 average sales price decreased compared to all of the preceding quarters of 2014 and 2013, as per table above, driven by a rapid decline in the oil benchmark prices seen in late 2014. In contrast, the first and second quarters of 2014 average sales prices were the highest posted average prices since the fourth quarter of 2008 driven by an increase in the benchmark prices at that time.

Quarterly production in 2014 is lower compared to all four quarters in 2013 primarily due to property dispositions, lower natural gas production resulting from natural declines as a result of capital investment being directed mainly to oil development programs, in addition to a few fields with third party capacity constraints.

First quarter of 2014 posted the highest operating netback since the fourth quarter of 2011 resulting from higher benchmark prices in early 2014. The operating netback has decreased to $24.04/boe in the fourth quarter of 2014 as a result of the rapid decline in oil benchmark prices.

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

PENGROWTH 2014 Management's Discussion and Analysis 32

SELECTED ANNUAL INFORMATION

The table below provides a summary of selected annual information for the years ended 2014, 2013 and 2012.

	Twelve months ended December 31
($ millions unless otherwise indicated)	2014		2013		2012
Oil and gas sales (1)	1,496.9		1,593.4		1,458.2
Net income (loss)	(578.8	)	(316.9	)	12.7
Net income (loss) per share ($)	(1.10	)	(0.61	)	0.03
Net income (loss) per share - diluted ($)	(1.10	)	(0.61	)	0.03
Dividends declared per share ($)	0.48		0.48		0.66
Total assets	6,169.8		6,633.2		7,469.9
Long term debt (2)	1,859.2		1,648.7		1,767.7
Shareholders' equity	2,926.8		3,688.3		4,190.3
Number of shares outstanding at year end (thousands)	533,438		522,031		511,804

⁽¹⁾  Excluding realized commodity risk management.

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

COMMITMENTS AND CONTRACTUAL OBLIGATIONS

($ millions)	2015	2016	2017	2018	2019	Thereafter	Total
Convertible debentures (1)	—	—	136.8	—	—	—	136.8
Interest payments on convertible debentures	8.6	8.6	2.1	—	—	—	19.3
Long term debt (2)	173.3	—	655.1	322.4	67.7	507.0	1,725.5
Interest payments on long term debt (3)	90.9	85.3	69.2	40.3	25.4	65.4	376.5
Operating leases (4)	13.1	12.8	12.0	10.9	9.5	51.9	110.2
Pipeline transportation	30.7	16.5	20.7	22.0	19.7	144.8	254.4
Other	17.9	2.9	0.7	0.7	0.3	11.0	33.5
	334.5	126.1	896.6	396.3	122.6	780.1	2,656.2

⁽¹⁾  Assumes no conversion of convertible debentures prior to maturity.

⁽²⁾  The debt repayment includes foreign denominated fixed rate debt translated using the year end exchange rate and excludes related foreign exchange risk management contracts.

⁽³⁾  Interest payments are calculated at period end exchange rates and interest rates except for fixed rate debt which is calculated at the actual interest rate.

⁽⁴⁾  Includes office rent, vehicle leases and other.

BUSINESS RISKS

The following factors should not be considered exhaustive. Additional risks are outlined in the Corporation’s most recent Annual Information Form ("AIF") which is available on SEDAR at www.sedar.com.

The amount of cash flow available for distribution to shareholders as dividends and the value of Pengrowth common shares are 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 our business include, but are not limited to, the following:

Risks associated with Commodity Prices

• The prices of Pengrowth’s products (crude oil, bitumen, natural gas and NGLs) fluctuate due to many factors including local and global market supply and demand, weather patterns, availability of pipeline and rail transportation capacity, availability of refining capacity, discount for Western Canadian light and heavy oil and natural gas, and political and economic stability.

• Production could be shut-in at specific wells or fields in times of low commodity prices.

• Substantial and sustained reductions in commodity prices or equity 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 maintain its current dividend rate, spend capital and meet obligations. The impairment test is sensitive to lower realized commodity prices, which have been under significant downward pressure in recent months, particularly oil prices. Further declines in commodity prices could result in additional impairment charges as the cushions in the CGU impairment tests have been eroded by price decreases and operating cost increases.

PENGROWTH 2014 Management's Discussion and Analysis 33

Risks associated with Liquidity

• Capital markets may restrict Pengrowth’s access to capital and raise its 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 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 certain circumstances, being in default of one loan will result in other loans also being in default. In the event that an event of non-compliance continued, Pengrowth would have to repay the relevant debt, refinance the debt or negotiate new terms with the debt holders and may have to suspend dividends to shareholders.

• Pengrowth’s indebtedness may limit the amount of dividends that we are able to pay our shareholders, and 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.

• Uncertainty in international financial markets could lead to constrained capital markets, increased cost of capital and negative impact on economic activity and commodity prices.

Risks associated with Legislation and Regulatory Changes

• Government royalties, income taxes, commodity taxes and other taxes, levies and fees have a significant economic impact on Pengrowth’s financial results. Changes to federal and provincial legislation governing such royalties, taxes and fees could have a material impact on Pengrowth’s financial results and the value of Pengrowth’s common shares.

• Environmental laws and regulatory initiatives impact Pengrowth financially and operationally. We may incur substantial capital and operating expenses to comply with increasingly complex laws and regulations covering the protection of the environment and human health and safety. In particular, we 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 our financial results, which could negatively impact our business, including increasing the risk of failing a financial covenant contained within our credit facility or term debt.

Risks associated with Operations

• The marketability of our 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 our 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.

• A significant portion 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, we 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.

PENGROWTH 2014 Management's Discussion and Analysis 34

• Geological and operational risks affect the quantity and quality of reserves and the costs of recovering those reserves. Our actual results will vary from our 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 Pengrowth’s ability to pay dividends to shareholders and 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 by individuals 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 and Pengrowth’s ability to pay dividends to shareholders.

• Delays or failure to secure regulatory approvals for projects may result in capital being spent with reduced economics, reduced or no further reserves being booked, and reduced or no associated future production and cash flow.

• The 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 heavy oil 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 our ability to sell our 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 heavy oil and bitumen.

Risks associated with Strategy

• Capital re-investment on our 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. In addition, the dedication of a larger percentage of our cash flow to such opportunities may reduce the funds available for dividend payments to shareholders. In such an event, the market value of the common shares may also be adversely affected.

• Pengrowth’s oil and gas reserves will be depleted over time and the level of cash flow from operations and the value of the 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 and dividends to shareholders.

• Dividends and the market price of the common shares could be adversely affected by unforeseen title defects.

Asset Concentration Risks

• Pengrowth sold almost $1 billion of assets in 2013 to fund, inter alia, the first commercial phase of Lindbergh. These asset sales, combined with the significant investment into Lindbergh substantially increased Pengrowth’s asset concentration and a failure (cost overruns, delays, performance issues, etc.) to execute at Lindbergh could have a significant adverse effect on Pengrowth and its ability to pay dividends.

PENGROWTH 2014 Management's Discussion and Analysis 35

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 may change over time which would affect the availability of capital and the value of Pengrowth common shares.

• Inflation may result in escalating costs, which could impact dividends and the value of Pengrowth common shares.

• Canadian / U.S. exchange rates influence revenues and, to a lesser extent, operating and capital costs. Pengrowth is also exposed to foreign currency fluctuations on the U.S. dollar denominated term debt for both interest and principal payments.

• Failure to receive regulatory approval or the expiry of the rights to explore for E&E assets could lead to the impairment of E&E assets.

These factors should not be considered exhaustive. Additional risks are outlined in the AIF of the Corporation which is available on SEDAR at www.sedar.com.

ACCOUNTING PRONOUNCEMENTS ADOPTED

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

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

ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED

In May 2014, the IASB issued IFRS 15 Revenue from Contracts with Customers ("IFRS 15"). The new standard is effective for annual periods beginning on or after January 1, 2017. Earlier application is permitted. The standard contains a single model that applies to contracts with customers and two approaches to recognising revenue: at a point in time or over time. The model features a contract-based five-step analysis of transactions to determine whether, how much and when revenue is recognized. New estimates and judgmental thresholds have been introduced, which may affect the amount and/or timing of revenue recognized. The new standard applies to contracts with customers. It does not apply to insurance contracts, financial instruments or lease contracts, which fall in the scope of other IFRSs. Pengrowth intends to adopt IFRS 15 in its Consolidated Financial Statements for the annual period beginning on January 1, 2017. The extent of the impact of adoption of the standard has not yet been determined.

In July 2014, the IASB issued the complete IFRS 9 (IFRS 9 (2014)). The mandatory effective date of IFRS 9 is for annual periods beginning on or after January 1, 2018 and must be applied retrospectively with some exemptions. Early adoption is permitted. The restatement of prior periods is not required and is only permitted if information is available without the use of hindsight. IFRS 9 (2014) introduces new requirements for the classification and measurement of financial assets. Under IFRS 9 (2014), financial assets are classified and measured based on the business model in which they are held and the characteristics of their contractual cash flows. The standard introduces additional changes relating to financial liabilities. It also amends the impairment model by introducing a new “expected credit loss” model for calculating impairment. IFRS 9 (2014) also includes a new general hedge accounting standard which aligns hedge accounting more closely with risk management. This new standard does not fundamentally change the types of hedging relationships or the requirement to measure and recognize ineffectiveness, however it will provide more hedging strategies that are used for risk management to qualify for hedge accounting and introduce more judgment to assess the effectiveness of a hedging relationship. Special transitional requirements have been set for the application of the

PENGROWTH 2014 Management's Discussion and Analysis 36

new general hedging model. Pengrowth intends to adopt IFRS 9 (2014) in its Consolidated Financial Statements for the annual period beginning on January 1, 2018. The extent of the impact of adoption of the standard has not yet been determined.

DISCLOSURE AND INTERNAL CONTROLS

As a Canadian reporting issuer with securities listed on both the TSX and the NYSE, Pengrowth is required to comply with Multilateral Instrument 52-109 - Certification of Disclosure in Issuers’ Annual and Interim Filings, as well as the Sarbanes Oxley Act (“SOX”) enacted in the United States. Both the Canadian and U.S. certification rules include similar requirements where both the Chief Executive Officer (“CEO”) and the Chief Financial Officer (“CFO”) must assess and certify as to the effectiveness of the disclosure controls and procedures as defined in Canada by Multilateral Instrument 52-109 - Certification of Disclosure in Issuers’ Annual and Interim Filings and in the United States by Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended.

The CEO, Derek Evans, and the CFO, Christopher Webster, evaluated the effectiveness of Pengrowth’s disclosure controls and procedures for the year ending December 31, 2014. 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, 2014, to ensure that information required to be disclosed by us in reports that we file under Canadian and U.S. securities laws is gathered, recorded, processed, summarized and reported within the time periods specified under Canadian and U.S. securities laws and is accumulated and communicated to the management of Pengrowth Energy Corporation, including the CEO and CFO, to allow timely decisions regarding required disclosure as required under Canadian and U.S. securities laws.

It should be noted that while Pengrowth’s CEO and CFO believe that Pengrowth’s disclosure controls and procedures provide a reasonable level of assurance that they are effective, they do not expect that Pengrowth’s disclosure controls and procedures or internal control over financial reporting will prevent all errors and fraud. A control system, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met.

INTERNAL CONTROL OVER FINANCIAL REPORTING

Pengrowth's management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended and in Canada as defined in Multilateral Instrument 52-109 - Certification of Disclosure in Issuers’ Annual and Interim Filings. Pengrowth's internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of Pengrowth's financial reporting and the preparation of Pengrowth's Consolidated Financial Statements for external purposes in accordance with IFRS for note disclosure purposes. Pengrowth's internal control over financial reporting includes those policies and procedures that: pertain to the maintenance of records that in reasonable detail accurately and fairly reflect Pengrowth's transactions and disposition of the assets; provide reasonable assurance that transactions are recorded as necessary to permit preparation of Pengrowth's Consolidated Financial Statements in accordance with IFRS and that receipts and expenditures of Pengrowth's assets are being made only in accordance with authorizations of Pengrowth's management and directors; and provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of Pengrowth's assets that could have a material effect on Pengrowth's Consolidated Financial Statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Pengrowth's management, with the participation of Pengrowth's principal executive officer and principal financial officer, evaluated the effectiveness of Pengrowth's internal control over financial reporting as of December 31, 2014. In making this evaluation, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) in Internal Control-Integrated Framework (2013).

PENGROWTH 2014 Management's Discussion and Analysis 37

Based on Pengrowth's evaluation, management concluded that Pengrowth's internal control over financial reporting was effective as of December 31, 2014.

The effectiveness of internal control over financial reporting as of December 31, 2014 was audited by KPMG LLP, an independent registered public accounting firm, as stated in their report, which is included with Pengrowth's audited Consolidated Financial Statements for the year ended December 31, 2014. No changes were made to Pengrowth's internal control over financial reporting during the year ending December 31, 2014 that have materially affected, or are reasonably likely to materially affect, the internal controls over financial reporting.

PENGROWTH 2014 Management's Discussion and Analysis 38

EX-99.3

MANAGEMENT'S REPORT TO SHAREHOLDERS

Management’s Responsibility to Shareholders

The Consolidated Financial Statements and the notes to the Consolidated Financial Statements are the responsibility of the management of Pengrowth Energy Corporation. They have been prepared in accordance with International Financial Reporting Standards ("IFRS") as issued by the International Accounting Standards Board which have been adopted in Canada. Financial information that is presented in the Management Discussion and Analysis is consistent with the Consolidated Financial Statements.

In preparation of these statements, estimates are sometimes necessary because a precise determination of certain assets and liabilities is dependant on future events. Management believes such estimates have been based on careful judgments and have been properly reflected in the accompanying Consolidated Financial Statements.

Management is responsible for the reliability and integrity of the Consolidated Financial Statements, the notes to the Consolidated Financial Statements, and other financial information contained in this report. In order to ensure that management fulfills its responsibilities for financial reporting, we have established an organizational structure that provides appropriate delegation of authority, division of responsibilities, and selection and training of properly qualified personnel. Management is also responsible for the development of internal controls over the financial reporting process.

The Board of Directors ("the Board") is assisted in exercising its responsibilities through the Audit and Risk Committee ("the Committee") of the Board, which is composed of four independent directors. The Committee meets regularly with management and the independent auditors to satisfy itself that management’s responsibilities are properly discharged, to review the Consolidated Financial Statements and to recommend approval of the Consolidated Financial Statements to the Board.

KPMG LLP, the independent auditors appointed by the shareholders, have audited Pengrowth Energy Corporation’s Consolidated Financial Statements in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States) and provided an independent professional opinion. The auditors have full and unrestricted access to the Committee to discuss the audit and their related findings as to the integrity of the financial reporting process.

Derek W. Evans	Christopher G. Webster
President and Chief Executive Officer	Chief Financial Officer

February 26, 2015

PENGROWTH 2014 Financial Results 1

INDEPENDENT AUDITORS’ REPORT OF REGISTERED

PUBLIC ACCOUNTING FIRM

To the Shareholders and Directors of Pengrowth Energy Corporation

We have audited the accompanying consolidated financial statements of Pengrowth Energy Corporation, which comprise the consolidated balance sheets as at December 31, 2014 and December 31, 2013, the consolidated statements of loss, cash flow and shareholders’ equity for the years then ended, and notes, comprising a summary of significant accounting policies and other explanatory information.

Management’s Responsibility for the Consolidated Financial Statements

Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board, and for such internal control as management determines is necessary to enable the preparation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.

Auditors’ Responsibility

Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we comply with ethical requirements and plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on our judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, we consider internal control relevant to the entity's preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances.An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements.

We believe that the audit evidence we have obtained in our audits is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the consolidated financial statements present fairly, in all material respects, the consolidated financial position of Pengrowth Energy Corporation as at December 31, 2014 and December 31, 2013, and its consolidated financial performance and its consolidated cash flows for the years then ended in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board.

Other Matter

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Pengrowth Energy Corporation’s internal control over financial reporting as of December 31, 2014, based on the criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 26, 2015 expressed an unmodified (unqualified) opinion on the effectiveness of Pengrowth Energy Corporation’s internal control over financial reporting.

Chartered Accountants

February 26, 2015

Calgary, Canada

PENGROWTH 2014 Financial Results 2

REPORT OF INDEPENDENT REGISTERED

PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of Pengrowth Energy Corporation

We have audited Pengrowth Energy Corporation’s (the "Corporation") internal control over financial reporting as of December 31, 2014, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Corporation’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Corporation’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). 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 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.

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 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.

In our opinion, the Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2014, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

We also have audited, in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of the Corporation as at December 31, 2014 and December 31, 2013, and the related consolidated statements of loss, cash flow and shareholders’ equity for the years then ended, and our report dated February 26, 2015 expressed an unmodified (unqualified) opinion on those consolidated financial statements.

Chartered Accountants

February 26, 2015

Calgary, Canada

PENGROWTH 2014 Financial Results 3

PENGROWTH ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS

(Stated in millions of Canadian dollars)

		As at			As at
	Note	December 31, 2014			December 31, 2013
ASSETS
Current Assets
Cash and cash equivalents		$	—		$	448.5
Accounts receivable	17	148.1			192.3
Fair value of risk management contracts	17	299.6			—
		447.7			640.8
Fair value of risk management contracts	17	182.6			23.1
Other assets	4	60.4			59.7
Property, plant and equipment	5	4,786.8			4,817.6
Exploration and evaluation assets	6	490.1			419.3
Goodwill	7	202.2			672.7
TOTAL ASSETS		$	6,169.8		$	6,633.2
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Bank indebtedness	9	$	10.7		$	—
Accounts payable		352.9			353.2
Dividends payable		21.3			20.9
Fair value of risk management contracts	17	12.8			70.3
Current portion of long term debt	9	173.2			—
Current portion of convertible debentures	8	—			98.7
Current portion of provisions	10	27.3			17.1
		598.2			560.2
Fair value of risk management contracts	17	0.4			22.2
Convertible debentures	8	137.2			137.3
Long term debt	9	1,548.8			1,412.7
Provisions	10	760.7			594.4
Deferred income taxes	11	197.7			218.1
		3,243.0			2,944.9
Shareholders' Equity
Shareholders' capital	12	4,759.7			4,693.1
Contributed surplus		32.3			28.0
Deficit		(1,865.2		)	(1,032.8		)
		2,926.8			3,688.3
Commitments and contingencies	19, 20
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY		$	6,169.8		$	6,633.2

See accompanying notes to the Consolidated Financial Statements.

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

Director	Director

PENGROWTH 2014 Financial Results 4

PENGROWTH ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF LOSS

(Stated in millions of Canadian dollars, except per share amounts)

		Year ended December 31
	Note	2014			2013
REVENUES
Oil and gas sales		$	1,496.9		$	1,593.4
Royalties, net of incentives		(268.6		)	(275.1		)
		1,228.3			1,318.3
Realized loss on commodity risk management	17	(96.1		)	(55.0		)
Unrealized gain (loss) on commodity risk management	17	501.1			(87.0		)
		1,633.3			1,176.3
EXPENSES
Operating		415.4			482.5
Transportation		30.8			29.4
General and administrative		100.3			102.8
Depletion, depreciation and amortization	5	517.0			574.6
Impairment	5, 6, 7	994.6			—
		2,058.1			1,189.3
OPERATING LOSS		(424.8		)	(13.0		)
Other (income) expense items
Unrealized loss on investment	4	5.0			15.0
(Gain) loss on disposition of properties	5	(23.3		)	175.7
Unrealized foreign exchange loss	18	79.0			63.0
Realized foreign exchange (gain) loss	18	1.0			(1.1		)
Interest and financing charges		74.6			94.1
Accretion	10	18.8			20.5
Other expense		19.3			9.9
LOSS BEFORE TAXES		(599.2		)	(390.1		)
Deferred income tax recovery	11	(20.4		)	(73.2		)
NET LOSS AND COMPREHENSIVE LOSS		$	(578.8	)	$	(316.9	)
NET LOSS PER SHARE	15
Basic		$	(1.10	)	$	(0.61	)
Diluted		$	(1.10	)	$	(0.61	)

See accompanying notes to the Consolidated Financial Statements.

PENGROWTH 2014 Financial Results 5

PENGROWTH ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOW

(Stated in millions of Canadian dollars)

		Year ended December 31
	Note	2014			2013
CASH PROVIDED BY (USED FOR):
OPERATING
Net loss and comprehensive loss		$	(578.8	)	$	(316.9	)
Non-cash items
Depletion, depreciation, amortization and accretion		535.8			595.1
Impairment	5, 6, 7	994.6			—
Deferred income tax recovery	11	(20.4		)	(73.2		)
Unrealized foreign exchange loss	18	79.0			63.0
Unrealized (gain) loss on commodity risk management	17	(501.1		)	87.0
Share based compensation	13	16.0			15.0
Unrealized loss on investment	4	5.0			15.0
(Gain) loss on disposition of properties	5	(23.3		)	175.7
Other items		(1.1		)	1.9
Derivative settlement on senior note repayment		—			(1.7		)
Funds flow from operations		505.7			560.9
Interest and financing charges		74.6			94.1
Expenditures on remediation	10	(22.9		)	(29.6		)
Change in non-cash operating working capital	14	98.3			11.4
		655.7			636.8
FINANCING
Dividends paid		(253.2		)	(248.1		)
Bank indebtedness	9	10.7			—
Long term debt (repayment) and related derivative settlement	9	191.0			(209.6		)
Convertible debentures repayment	8	(97.9		)	—
Interest paid		(105.1		)	(99.7		)
Other financing cost		—			(1.1		)
Proceeds from DRIP and stock option exercises		53.4			47.0
		(201.1		)	(511.5		)
INVESTING
Capital expenditures		(904.0		)	(695.8		)
Property acquisitions		(17.0		)	(16.0		)
Proceeds on property dispositions		84.5			993.7
Other items		(10.2		)	(10.0		)
Change in non-cash investing working capital	14	(56.4		)	48.6
		(903.1		)	320.5
CHANGE IN CASH AND CASH EQUIVALENTS		(448.5		)	445.8
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR		448.5			2.7
CASH AND CASH EQUIVALENTS AT END OF YEAR		$	—		$	448.5

See accompanying notes to the Consolidated Financial Statements.

PENGROWTH 2014 Financial Results 6

PENGROWTH ENERGY CORPORATION

STATEMENTS OF CONSOLIDATED SHAREHOLDERS' EQUITY

(Stated in millions of Canadian dollars)

		Year ended December 31
	Note	2014			2013
SHAREHOLDERS' CAPITAL	12
Balance, beginning of year		$	4,693.1		$	4,634.8
Share based compensation		14.8			13.4
Issued under DRIP		51.8			44.9
Balance, end of year		4,759.7			4,693.1
CONTRIBUTED SURPLUS
Balance, beginning of year		28.0			22.9
Share based compensation	13	17.5			16.4
Exercise of share based compensation awards		(13.2		)	(11.3		)
Balance, end of year		32.3			28.0
DEFICIT
Balance, beginning of year		(1,032.8		)	(467.4		)
Net loss		(578.8		)	(316.9		)
Dividends declared		(253.6		)	(248.5		)
Balance, end of year		(1,865.2		)	(1,032.8		)
TOTAL SHAREHOLDERS' EQUITY		$	2,926.8		$	3,688.3

See accompanying notes to the Consolidated Financial Statements.

PENGROWTH 2014 Financial Results 7

PENGROWTH ENERGY CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

AS AT AND FOR THE YEARS ENDED DECEMBER 31, 2014 AND 2013

(Tabular amounts are stated in millions of Canadian dollars except per share amounts and as otherwise stated)

1. BUSINESS OF THE CORPORATION

Pengrowth Energy Corporation ("Pengrowth" or the "Corporation") is a Canadian resource company that is engaged in the production, development, exploration and acquisition of oil and natural gas assets. The Consolidated Financial Statements include the accounts of the Corporation, and its subsidiary, collectively referred to as Pengrowth. All inter-entity transactions have been eliminated.

2. SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

These Consolidated Financial Statements have been prepared in accordance with the International Financial Reporting Standards (“IFRS”) issued by the International Accounting Standards Board (“IASB”) and International Financial Reporting Interpretations Committee (“IFRIC”).

The Consolidated Financial Statements were authorized for release by the Board of Directors on February 26, 2015.

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.

Exploration and Evaluation Assets

Costs of exploring for and evaluating certain oil and natural gas properties are capitalized within E&E assets. These E&E assets include lease acquisition costs, geological and geophysical expenditures, costs of drilling and completion of wells, plant and production equipment costs and related overhead charges. E&E assets do not include costs of general prospecting, or evaluation costs incurred prior to having obtained the legal rights to explore an area, which are expensed as incurred. Interest is not capitalized on E&E assets.

E&E assets are not depleted or depreciated and are carried forward until technical feasibility and commercial viability is considered to be determined. The technical feasibility and commercial viability is generally considered to be determined when proved plus probable reserves are determined to exist and the commercial production of oil and gas has commenced. A review of each exploration license or field is carried out, at least annually, to ascertain whether the project is technically feasible and commercially viable. Upon determination of technical feasibility and commercial viability, E&E assets attributable to those reserves are first tested for impairment and then reclassified from E&E assets to PP&E.

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.

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

PENGROWTH 2014 Financial Results 8

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.

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 property dispositions. The gain or loss is measured as the difference between the fair value of the proceeds received and the carrying value of the assets disposed, including capitalized future asset retirement obligations and associated goodwill.

Depletion and Depreciation

The net carrying value of developed or producing fields or groups of fields is depleted using the unit of production method by reference to the ratio of production in the period to the related proved plus probable reserves, taking into account estimated future development costs necessary to bring those reserves into production. Future development costs are estimated taking into account the level of development required to produce the reserves. These estimates are reviewed by independent reserve engineers at least annually. Pengrowth’s total proved plus probable reserves are estimated by an independent reserve evaluator and represent the "best estimate" of quantities of oil, natural gas and related substances to be commercially recoverable from known accumulations, from a given date forward, based on geological and engineering data. It is equally likely that the actual remaining quantities recovered will be greater than or less than the sum of the estimated proved plus probable reserves. Properties with no remaining production and reserves are fully depleted in the year that production ceases. Assets under construction are not depleted or depreciated until available for their intended use.

For other assets, depreciation is recognized in the Consolidated Statements of Income (Loss) using either a straight line or declining balance basis over the estimated useful lives of each part of an item of PP&E. The estimated useful lives for other assets for the current and comparative periods are as follows:

-	Office equipment	60 months
-	Leasehold improvements and finance leases	Lease term/Useful life
-	Computers	36 months
-	Deferred hydrocarbon injectants	24 months
-	Motor vehicles	36 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, 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.

PENGROWTH 2014 Financial Results 9

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

Goodwill may arise on business combinations. Goodwill is stated at cost less accumulated impairment and divestitures.

Goodwill 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).

In 2014, Pengrowth had goodwill allocated to both specific cash generating units and/or groups of cash generating units resulting from several prior year acquisitions. As Pengrowth disposes of certain properties, associated goodwill is included in the carrying amount of the properties when determining the gain or loss on disposal. Unless specific goodwill can be identified to the properties disposed of, the amount is measured on the basis of the relative value of the properties disposed of and the portion of the cash generating units retained.

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 that have associated goodwill are tested for impairment at least annually, however, CGUs with or without associated goodwill are first 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 recognized in respect of specific CGUs are allocated first to reduce the carrying amount of any goodwill allocated to the units and then to reduce the carrying amounts of the other assets in the unit on a pro-rata basis. Impairment losses recognized in respect of goodwill allocated to a group of CGUs is allocated to the goodwill on a pro-rata basis.

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

PENGROWTH 2014 Financial Results 10

amount or the carrying amount that would have been determined, net of depletion and depreciation or amortization, if no impairment loss had been recognized.

Exploration and Evaluation Assets

E&E assets are tested for impairment when there is an indication that a particular E&E project may be impaired. Examples of indicators of impairment include a significant price decline over an extended period, the decision to delay or no longer pursue the E&E project, an expiry of the rights to explore in an area, or failure to receive regulatory approval. In addition, E&E assets are assessed for impairment upon their reclassification to producing assets (oil and natural gas interests in PP&E). In assessing the impairment of E&E assets, the carrying value of the E&E assets would be compared to their estimated recoverable amount and, in certain circumstances, could be tested in conjunction with PP&E impairment testing of related CGUs. The impairment of E&E assets would be recognized in the Consolidated Statements of Income (Loss).

Goodwill

For goodwill and other intangible assets that have indefinite lives or that are not yet available for use, an impairment test is completed each year at December 31. In assessing the impairment of goodwill, the carrying value of goodwill is compared to the excess of the recoverable amount over the carrying amount of the PP&E and E&E assets, as applicable, within the CGU or groups of CGUs where the acquired properties are grouped. An impairment loss is recognized if the carrying amount of the goodwill exceeds the excess of the recoverable amount above the carrying amount of the CGU or CGUs. An impairment loss in respect of goodwill cannot be reversed.

Financial Assets

A financial asset is assessed at each reporting date to determine whether there is any objective evidence that it is impaired. A financial asset is considered to be impaired if objective evidence, including failure to pay on time, indicates that one or more events have had a negative effect on the estimated future cash flows of that asset.

An impairment loss in respect of a financial asset measured at amortized cost is calculated as the difference between its carrying amount and the present value of the estimated future cash flows discounted at the original effective interest rate. Significant financial assets are tested for impairment on an individual basis. The remaining financial assets are assessed collectively in groups that share similar credit risk characteristics.

Any impairment losses of financial assets are recognized in the Consolidated Statements of Income (Loss). An impairment loss is reversed if the reversal can be related objectively to an event occurring after the impairment loss was recognized. For financial assets measured at amortized cost, the reversal is recognized in the Consolidated Statements of Income (Loss).

Provisions

A provision is recognized if, as a result of a past event, the Corporation has a present legal or constructive obligation that can be estimated reliably and it is probable that an outflow of economic benefits will be required to settle the obligation. Provisions are determined by discounting the expected future cash flows at the appropriate discount rate. Provisions are not permitted for future operating losses.

Asset Retirement Obligations (“ARO”)

Pengrowth initially recognizes the net present value of an ARO in the period in which it is incurred when a reasonable estimate of the net present value can be made. The net present value of the estimated ARO is recorded as a liability, with a corresponding increase in the carrying amount of the related asset. The capitalized asset is depleted on the unit of production method based on proved plus probable reserves. The liability is increased each reporting period due to the passage of time and the amount of such accretion is expensed to income in the period. Actual costs incurred upon the settlement of the ARO are charged against the ARO. Management reviews the ARO estimate and changes, if any, are applied prospectively. Revisions made to the ARO estimate are recorded as an increase or decrease to the ARO liability with a corresponding change made to the carrying amount of the related asset. The carrying amount of both the liability and the capitalized asset, net of accumulated depreciation, are derecognized if the asset is subsequently disposed.

Pengrowth has placed cash in segregated remediation trust fund accounts to fund certain ARO for the Judy Creek and Sable Island properties. These funds are reflected in Other Assets on the Consolidated Balance Sheets.

PENGROWTH 2014 Financial Results 11

Contract & Other Liabilities Provision

Pengrowth assumed firm pipeline commitments in conjunction with certain prior period acquisitions. The fair values of these contracts were estimated on the date of acquisition and the amount recorded is reduced as the contracts settle.

Pengrowth also categorizes any finance lease transactions and cash-settled deferred share unit grants within this grouping.

Deferred 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. 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.

Pengrowth’s policy for income tax uncertainties is that tax benefits will be recognized only when it is more likely than not the position will be sustained on examination.

Share Based Compensation Plans

Pengrowth has share based compensation plans, which are described in Note 13. Compensation expense is based on the estimated fair value of the share based compensation award at the date of grant. Compensation expenses associated with the share based compensation 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.

Commencing in 2014, the independent members of the Board of Directors receive cash-settled Phantom Deferred Share Units ("PhantomDSUs"). 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 including notional dividends. This valuation incorporates the period end share price and the number of Phantom DSUs outstanding at each period end. 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.

Financial Instruments

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

Financial instruments are classified into one of five categories: (i) fair value through profit or loss, (ii) held to maturity investments, (iii) loans and receivables, (iv) available for sale financial assets or (v) other liabilities.

Accounts receivable are classified as loans and receivables which are measured at amortized cost.

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

PENGROWTH 2014 Financial Results 12

Bank indebtedness, accounts payable, dividends payable, convertible debentures and long term debt have been classified as other liabilities which are measured at amortized cost using the effective interest rate method.

Pengrowth has accounted for its physical delivery sales contracts, which were entered into and continue to be held for the purpose of receipt or delivery of non-financial items in accordance with its expected purchase, sale or usage requirements as executory contracts. As such, these contracts are not considered to be derivative financial instruments and have not been recorded at fair value on the Consolidated Balance Sheets. Settlements on these physical delivery sales contracts are recognized in revenue in the period of settlement.

All derivatives must be classified as fair value through profit or loss and measured at fair value with changes in fair value over a reporting period recognized in net income (loss).

The receipts or payments arising from derivative commodity contracts are presented as realized gain (loss) on commodity risk management while the unrealized gains and losses are presented as unrealized gain (loss) on commodity risk management.

The receipts or payments arising from derivative power and interest rate contracts are included in operating expenses and interest expense, respectively. The unrealized gains and losses on derivative power and interest rate contracts are included in other (income) expense and interest expense, respectively.

The receipts or payments arising from derivative foreign exchange contracts are presented as realized foreign exchange (gain) loss while the unrealized gains and losses are presented as unrealized foreign exchange (gain) loss.

Transaction costs incurred in connection with the issuance of term debt instruments with a maturity of greater than one year are deducted against the carrying value of the debt and amortized to net income (loss) using the effective interest rate method over the expected life of the debt.

Pengrowth capitalizes transaction costs incurred in connection with the renewal of the revolving credit facility with a maturity date greater than one year and amortizes the cost to net income (loss) on a straight line basis over the term of the facility.

Fair Value Measurement

All financial assets and liabilities for which fair value is measured or disclosed in the Consolidated Financial Statements are further categorized using a three-level hierarchy that reflects the significance of the lowest level of inputs used in determining fair value:

• Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

• Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1. Prices in Level 2 are either directly or indirectly observable as of the reporting date. Level 2 valuations are based on inputs, including quoted forward prices for commodities, time value and volatility factors, which can be substantially observed or corroborated in the marketplace.

• Level 3 – Valuations in this level are those with inputs for the asset or liability that are not based on observable market data.

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 net income (loss).

Jointly Controlled Operations

A significant proportion of Pengrowth’s petroleum and natural gas development and production activities are conducted through jointly controlled operations that are not conducted through separate vehicles and accordingly, the accounts reflect only Pengrowth’s interest in such activities.

PENGROWTH 2014 Financial Results 13

Related Parties

Related parties are persons or entities that have control or significant influence over Pengrowth, as well as key management personnel. Note 21 provides information on compensation expense related to key management personnel. Pengrowth has no significant transactions with any other related parties.

Revenue Recognition

Revenue from the sale of oil and natural gas is recognized when the product is delivered and collection is reasonably assured. Revenue from processing and other miscellaneous sources is recognized upon completion of the relevant service.

Equity Investment

Pengrowth utilizes the equity method of accounting for investments subject to significant influence, if applicable. Under this method, investments are initially recorded at cost and adjusted thereafter to include Pengrowth’s pro rata share of post-acquisition earnings. Any dividends received or receivable from the investee would reduce the carrying value of the investment.

Estimates

The preparation of Consolidated Financial Statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingencies at the date of the Consolidated Financial Statements and revenues and expenses during the reporting year. Actual results could differ from those estimated.

In particular, information about significant areas of estimation uncertainty and critical judgments in applying accounting policies that have the most significant effect on the amounts recognized in the Consolidated Financial Statements is described below:

Estimating oil and gas reserves

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. Reserves form the basis for the calculation of depletion charges and assessment of impairment of goodwill and oil and gas assets. Reserves 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.

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 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,

PENGROWTH 2014 Financial Results 14

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 that have associated goodwill are tested for impairment at least annually and CGUs with or without associated goodwill are tested when there is an indication of impairment. The test is based on estimates of proved plus probable reserves, production rates, oil and natural gas prices, future costs, discount rate and other relevant assumptions. Undeveloped land, contingent resources and infrastructure may also be considered. The impairment assessment of goodwill is based on the estimated recoverable amount of the related CGUs. By their nature, these estimates are subject to measurement uncertainty and may impact the Consolidated Financial Statements of future periods.

Fair value of risk management contracts

Pengrowth records risk management contracts at fair value with changes in fair value recognized in the Consolidated Statements of Income (Loss). The fair values are determined using observable market data and external counterparty information.

Valuation of trade and other receivables, and prepayments to suppliers

Management estimates the likelihood of the collection of trade and other receivables and recovery of prepayments based on an analysis of individual accounts. Factors taken into consideration include the aging of receivables in comparison with the credit terms allowed to customers and the financial position and collection history with the customer. Should actual collections be less than estimates, Pengrowth would be required to record an additional expense.

Net Income (Loss) per Share

Basic net income (loss) per share is calculated using the weighted average number of shares outstanding for the year. Diluted net income (loss) per share amounts includes the dilutive effect of common share rights and options, deferred entitlement share units and other share units under the long term incentive plan using the treasury stock method. The treasury stock method assumes that any proceeds obtained on the exercise of in-the-money share unit rights and options would be used to purchase common shares at the average trading price during the period.

The dilutive effect of convertible debentures is calculated using net income (loss) for the period, adjusted for the after tax interest on the convertible debentures assuming they were converted at the start of the period; and adding to the diluted number of shares the weighted average shares issuable if the convertible debentures were converted at the start of the period.

Cash and Term Deposits

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

ACCOUNTING PRONOUNCEMENTS ADOPTED

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

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

3. ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED

In May 2014, the IASB issued IFRS 15 Revenue from Contracts with Customers ("IFRS 15"). The new standard is effective for annual periods beginning on or after January 1, 2017. Earlier application is permitted. The standard contains a single model that applies to contracts with customers and two approaches to recognising revenue: at a point in time or over time. The model features a contract-based five-step analysis of transactions to determine whether, how much and when revenue is recognized. New estimates and judgmental thresholds have been introduced, which may affect

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the amount and/or timing of revenue recognized. The new standard applies to contracts with customers. It does not apply to insurance contracts, financial instruments or lease contracts, which fall in the scope of other IFRSs. Pengrowth intends to adopt IFRS 15 in its Consolidated Financial Statements for the annual period beginning on January 1, 2017. The extent of the impact of adoption of the standard has not yet been determined.

In July 2014, the IASB issued the complete IFRS 9 (IFRS 9 (2014)). The mandatory effective date of IFRS 9 is for annual periods beginning on or after January 1, 2018 and must be applied retrospectively with some exemptions. Early adoption is permitted. The restatement of prior periods is not required and is only permitted if information is available without the use of hindsight. IFRS 9 (2014) introduces new requirements for the classification and measurement of financial assets. Under IFRS 9 (2014), financial assets are classified and measured based on the business model in which they are held and the characteristics of their contractual cash flows. The standard introduces additional changes relating to financial liabilities. It also amends the impairment model by introducing a new “expected credit loss” model for calculating impairment. IFRS 9 (2014) also includes a new general hedge accounting standard which aligns hedge accounting more closely with risk management. This new standard does not fundamentally change the types of hedging relationships or the requirement to measure and recognize ineffectiveness, however it will provide more hedging strategies that are used for risk management to qualify for hedge accounting and introduce more judgment to assess the effectiveness of a hedging relationship. Special transitional requirements have been set for the application of the new general hedging model. Pengrowth intends to adopt IFRS 9 (2014) in its Consolidated Financial Statements for the annual period beginning on January 1, 2018. The extent of the impact of adoption of the standard has not yet been determined.

4. OTHER ASSETS

	As at
	December 31, 2014		December 31, 2013
Remediation trust funds	$	60.4	$	54.7
Other investment	—		5.0
	$	60.4	$	59.7

REMEDIATION TRUST FUNDS

Pengrowth has a contractual obligation to make contributions to a remediation trust fund that is used to cover certain ARO on its Judy Creek properties in the Swan Hills area. Pengrowth makes monthly contributions to the fund of $0.10/boe of production from the Judy Creek properties and an annual lump sum contribution of $0.25 million. The investment in the Judy Creek remediation trust fund is classified as fair value through profit or loss. Interest income is recognized when earned and included in other (income) expense. As at December 31, 2014, the carrying value of the Judy Creek remediation trust fund was $7.0 million (December 31, 2013 - $7.0 million).

Pengrowth has a contractual obligation to make contributions to a remediation trust fund that will be used to fund the ARO of the Sable Island properties and facilities. Since 2007, Pengrowth made a monthly contribution to the fund at a rate of $0.52/MMBtu of its share of natural gas production and $1.04/bbl of its share of natural gas liquids production from Sable Island. Starting in January 2015, the new rates are $4.17/MMBtu of its share of natural gas production and $8.36/bbl of its share of natural gas liquids production. The investment in the Sable Island fund is classified as fair value through profit or loss. Investment income is recognized when earned and is recorded in other (income) expense. As at December 31, 2014, the carrying value of the Sable Island remediation trust fund was $53.4 million (December 31, 2013 - $47.7 million).

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The following reconciles Pengrowth’s investment in remediation trust funds for the periods noted below:

	Remediation Trust Funds
Balance, December 31, 2012	$	53.8
Contributions	2.8
Remediation expenditures	(1.3		)
Investment income	1.8
Unrealized loss	(2.4		)
Balance, December 31, 2013	$	54.7
Contributions	2.9
Remediation expenditures	(1.5		)
Investment income	2.1
Unrealized gain	2.2
Balance, December 31, 2014	$	60.4

OTHER INVESTMENT

Pengrowth owns 1.0 million shares of a private corporation with an estimated fair value of $nil. This investment is classified as fair value through profit or loss. The fair value is based in part on the lack of success of recent private placement equity offerings by the private company. Pengrowth owns a minority interest and does not have significant influence over the private corporation.

As the company is private, the estimated fair value is not based on observable market data and there are restrictions on selling the shares. The fair value at December 31, 2014 was $nil (December 31, 2013 - $5 million). An unrealized loss of $5 million was recorded in the third quarter of 2014 (December 31, 2013 - $15 million loss).

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

Cost or deemed cost	Oil and natural gas assets			Other equipment		Total
Balance, December 31, 2012	$	7,349.4		$	74.2	$	7,423.6
Additions to PP&E	705.4			4.6		710.0
Property acquisitions	16.0			—		16.0
Transfer from E&E assets (note 6)	144.3			—		144.3
Change in asset retirement obligations	(169.6		)	—		(169.6		)
Divestitures	(1,457.8		)	—		(1,457.8		)
Balance, December 31, 2013	$	6,587.7		$	78.8	$	6,666.5
Additions to PP&E	812.7			6.1		818.8
Property acquisitions	17.0			—		17.0
Change in asset retirement obligations	245.2			—		245.2
Divestitures	(164.8		)	—		(164.8		)
Balance, December 31, 2014	$	7,497.8		$	84.9	$	7,582.7
Accumulated depletion, amortization and impairment losses	Oil and natural gas assets			Other equipment		Total
Balance, December 31, 2012	$	1,450.9		$	56.5	$	1,507.4
Depletion and amortization for the period	567.6			7.0		574.6
Divestitures	(233.1		)	—		(233.1		)
Balance, December 31, 2013	$	1,785.4		$	63.5	$	1,848.9
Depletion and amortization for the period	510.2			6.8		517.0
Impairment	486.3			—		486.3
Divestitures	(56.3		)	—		(56.3		)
Balance, December 31, 2014	$	2,725.6		$	70.3	$	2,795.9
Net book value	Oil and natural gas assets			Other equipment		Total
As at December 31, 2014	$	4,772.2		$	14.6	$	4,786.8
As at December 31, 2013	$	4,802.3		$	15.3	$	4,817.6

During the year ended December 31, 2014, $14.7 million (December 31, 2013 – $16.0 million) of directly attributable general and administrative costs were capitalized to PP&E.

The calculation of depletion for the year ended December 31, 2014 excluded certain capital from the construction phase of the Lindbergh thermal project ("Lindbergh Project") of $877.3 million (December 31, 2013 – $399.7 million).

Pengrowth capitalizes interest for qualifying assets in the construction phase based on costs incurred on the project and the average cost of borrowing. During the year ended December 31, 2014, $31.0 million (December 31, 2013 – $6.1 million) of interest was capitalized on the Lindbergh Project to PP&E using a capitalization rate of 5.7 percent (December 31, 2013 – 5.7 percent).

During the year ended December 31, 2014, Pengrowth successfully closed several minor non-core property dispositions for aggregate net proceeds of $84.5 million, resulting in pre-tax gains on disposition of properties of $23.3 million.

For the year ended December 31, 2013, Pengrowth successfully closed the disposition of its non-core southeast Saskatchewan assets, non-operated Weyburn property and other minor properties for proceeds of $993.7 million, resulting in pre-tax losses on disposition of properties of $175.7 million.

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IMPAIRMENT TESTING

In light of a significant and rapid decline in oil benchmark prices in the fourth quarter of 2014 and continued softening in natural gas prices, impairment tests were carried out on all CGUs at December 31, 2014, resulting in a $486.3 million PP&E impairment at December 31, 2014. The impairment tests carried out were based on reserve values using pre-tax discount rates of 10 - 15 percent - varying from CGU to CGU (December 31, 2013: 8 - 15 percent), January 1, 2015 independent reserves evaluator's forecast pricing and an inflation rate of 2 percent. The recoverable amount of each CGU was determined using fair value less costs to sell.

Impairments were primarily recorded in the following CGUs:

• Central CGU, located in Central Alberta, composed of primarily oil producing assets and CGU specific goodwill, recorded a $219.7 million PP&E impairment. In addition, the CGU specific goodwill of $129.7 million was also impaired (see Note 7). The Central CGU had a recoverable amount of $1.0 billion at December 31, 2014.

• Olds CGU, located in the Olds region of Alberta, primarily composed of natural gas and liquids producing assets, recorded a $52.6 million impairment. The Olds CGU had a recoverable amount of $447.0 million at December 31, 2014.

• WCU Light Oil CGU, located in the Garrington/Lochend area of Alberta, composed of light oil producing assets, recorded a $214.0 million impairment. The WCU Light Oil CGU had a recoverable amount of $609.3 million at December 31, 2014.

All CGUs were negatively impacted by a downturn in the forward benchmark prices and those CGUs that previously used a discount rate of 8 percent were further impacted by the move to a pre-tax discount rate of 10 percent in calculating the present value of the associated reserves. The increase in discount rate reflects the increased market uncertainty facing Western Canadian oil and gas companies.

The impairments noted above were recorded on the Consolidated Statements of Income (Loss) at December 31, 2014 and may be reversed, excluding goodwill, if and when the fair values of the CGUs increase in the future periods. However, the impairment test is sensitive to lower commodity prices, which have been under significant downward pressure recently. Further declines in commodity prices could result in additional impairment charges if the recoverable values are further eroded by price decreases.

The estimates of the above recoverable amounts were determined based on the following information, as applicable:

(a) 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,

ii. The commodity price forecast of Pengrowth’s independent reserves evaluator as noted below,

iii. Discounted at an estimated market rate.

(b) The fair value of undeveloped land.

(c) The fair value of infrastructure estimated by management.

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.

(d) Undeveloped land. The undeveloped land value is based on Pengrowth’s undeveloped land acreage and the current market prices for undeveloped land.

(e) Infrastructure. Assumptions that are valid at the time of infrastructure estimation may change significantly when new information becomes available.

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Below are the forward commodity price estimates used in the December 31, 2014 impairment test:

	WTI oil (1)	Foreign exchange rate	Edmonton light crude oil (1)	AECO gas (1)
Year	(U.S.$/bbl)	(U.S.$/Cdn$)	(Cdn$/bbl)	(Cdn$/MMBtu)
2015	62.50	0.85	64.71	3.31
2016	75.00	0.88	80.00	3.77
2017	80.00	0.88	85.71	4.02
2018	85.00	0.88	91.43	4.27
2019	90.00	0.88	97.14	4.53
2020	95.00	0.88	102.86	4.78
2021	98.54	0.88	106.18	5.03
2022	100.51	0.88	108.31	5.28
2023	102.52	0.88	110.47	5.53
2024	104.57	0.88	112.67	5.71
Thereafter	+ 2.0 percent/yr	0.88	+ 2.0 percent/yr	+ 2.0 percent/yr

⁽¹⁾  Prices represent forecasted amounts as at January 1, 2015 by Pengrowth's independent reserves evaluator.

At December 31, 2013, there were no indicators of impairment, however, due to the required annual goodwill impairment test all CGUs that have associated goodwill were tested. No impairment was recognized on any of the CGUs tested at December 31, 2013.

6. EXPLORATION AND EVALUATION ASSETS

Cost or deemed cost
Balance, December 31, 2012	$	563.6
Transfer to PP&E	(144.3		)
Balance, December 31, 2013	$	419.3
Additions	127.8
Impairment	(57.0		)
Balance, December 31, 2014	$	490.1

E&E assets consist of Pengrowth’s exploration and development projects which are pending the determination of proved plus probable reserves and production. Additions represent Pengrowth’s share of costs incurred on E&E assets during the period. Upon achievement of commercial viability and technical feasibility, E&E assets are transferred to PP&E, after being tested for impairment.

During the fourth quarter of 2014, Pengrowth acquired 32.6 gross/net sections of prospective liquids-rich Montney lands at Bernadet in north eastern British Columbia, which is included in the E&E balance as at December 31, 2014.

In the first quarter of 2013, the Board of Directors sanctioned the first phase of the Lindbergh Project resulting in $144.3 million of E&E costs being transferred to PP&E. This transfer represented all of the Lindbergh costs that were in E&E.

IMPAIRMENT TESTING

In conjunction with the Montney CGU, Pengrowth evaluated its Groundbirch project for an impairment. This was in accordance with Pengrowth's policy and IFRS which states that the impairment of ongoing E&E projects should be assessed on the cash flow from the applicable CGUs in the operating segment. It was determined that the recoverable amount was below the carrying amount, thus a $57.0 million impairment on the Groundbirch E&E was recorded at December 31, 2014.

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 for the operating segment. Undeveloped land and contingent resources were also considered in the recoverable amount. Changes in forward price estimates, production costs or recovery rates may change the economic status of contingent resources and may ultimately result in contingent resources being restated. The Groundbirch E&E impairment test was based on reserve values using a pre-tax discount

PENGROWTH 2014 Financial Results 20

rate of 10 percent; independent reserves evaluator January 1, 2015 forecast pricing and an inflation rate of 2 percent; and contingent resources using a pre-tax discount rate of 12 percent. See Note 5 for more information.

An impairment test was performed on January 1, 2013 upon transfer of the Lindbergh Project to PP&E. The net present value of the proved plus probable reserves, as determined by the external reserve evaluator, supported the carrying value of the Lindbergh Project, and as such, no impairment was required.

7. GOODWILL

Cost or deemed cost
Balance, December 31, 2012	$	700.7
Divestitures	(28.0		)
Balance, December 31, 2013	$	672.7
Divestitures	(19.2		)
Impairment	(451.3		)
Balance, December 31, 2014	$	202.2

In 2014, Pengrowth had goodwill allocated to specific CGUs and/or groups of CGUs resulting from several prior year acquisitions. As Pengrowth disposes of certain properties, associated goodwill is included in the carrying amount of the properties when determining the gain or loss on disposal. Unless specific goodwill can be identified to the properties disposed of, the amount is measured on the basis of the relative value of the properties disposed of and the portion of the CGUs retained. This resulted in $19.2 million of goodwill removed in 2014 (2013: $28.0 million).

IMPAIRMENT TESTING

Goodwill is stated at cost less accumulated impairment and divestitures. Goodwill is assessed for impairment at each year end, or when there is an indication of impairment, in conjunction with the assessment for impairment of PP&E and E&E. At December 31, 2014, impairment tests were performed, which resulted in a $451.3 million impairment of goodwill to both CGU specific and groups of CGUs goodwill. All CGUs were negatively impacted by a downturn in the forward benchmark prices, and several CGUs were impacted by increasing the discount rate from 8 to 10 percent for present valuing the reserves.

The impairments noted above have been recorded on the Consolidated Statements of Income (Loss) and are not reversible in future periods. The remaining carrying value of goodwill at December 31, 2014 is $202.2 million and is not attributed to any specific CGU, thus this value is supported by the excess recoverable amount over the carrying value of a number of Pengrowth's CGUs.

An increase in the discount rate of two percent would result in approximately an additional $41 million of goodwill impairment. The goodwill impairment testing is classified under level 3 of the fair value measurement hierarchy. See Note 2 for more information on fair value hierarchy classifications.

At December 31, 2013, an impairment test was performed, with no impairments to goodwill recorded.

8. CONVERTIBLE DEBENTURES

These subordinated convertible debentures are unsecured, and pay interest in arrears on a semi-annual basis. Each $1,000 debenture is convertible at the option of the holder at any time into fully paid common shares at a pre-determined conversion price per common share. 

The convertible debentures are classified as both current and non-current liabilities on the Consolidated Balance Sheets as applicable, and the debt premium accretes over time to the principal amount owing on maturity. No value was ascribed to equity (through the conversion feature), as a result of Pengrowth’s ability to borrow at a lower rate than the convertible debenture interest rate.

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On December 31, 2014, $97.9 million of debentures matured and were settled with cash, leaving one series outstanding. The following table summarizes the activity associated with the convertible debentures:

Series	Series A-6.25%			Series B-6.25%			Total
Maturity date	Dec 31, 2014			Mar 31, 2017
Conversion price (per Pengrowth share)	$	19.19		$	11.51
Balance, December 31, 2012	$	99.6		$	137.5		$	237.1
Premium accretion	(0.9		)	(0.2		)	(1.1		)
Balance, December 31, 2013	$	98.7		$	137.3		$	236.0
Premium accretion	(0.8		)	(0.1		)	(0.9		)
Matured	(97.9		)	—			(97.9		)
Balance, December 31, 2014	$	—		$	137.2		$	137.2
Face value, December 31, 2014	$	—		$	136.8		$	136.8

9. LONG TERM DEBT AND BANK INDEBTEDNESS

LONG TERM DEBT

	As at
	December 31, 2014		December 31, 2013
U.S. dollar denominated senior unsecured notes:
71.5 million at 4.67 percent due May 2015	$	82.9	$	75.9
400 million at 6.35 percent due July 2017	463.4		424.6
265 million at 6.98 percent due August 2018	306.8		281.1
35 million at 3.49 percent due October 2019	40.5		37.1
115.5 million at 5.98 percent due May 2020	133.6		122.4
105 million at 4.07 percent due October 2022	121.3		111.1
195 million at 4.17 percent due October 2024	225.3		206.3
	$	1,373.8	$	1,258.5
U.K. pound sterling denominated unsecured notes:
50 million at 5.46 percent due December 2015	$	90.3	$	88.0
15 million at 3.45 percent due October 2019	27.0		26.3
	$	117.3	$	114.3
Canadian dollar senior unsecured notes:
15 million at 6.61 percent due August 2018	$	15.0	$	15.0
25 million at 4.74 percent due October 2022	24.9		24.9
	$	39.9	$	39.9
Canadian dollar revolving credit facility borrowings	$	191.0	$	—
Total long term debt	$	1,722.0	$	1,412.7
Current portion of long term debt	$	173.2	$	—
Non-current portion of long term debt	1,548.8		1,412.7
	$	1,722.0	$	1,412.7

Pengrowth’s unsecured covenant based revolving credit facility includes a committed value of $1 billion and a $250 million expansion feature, providing $1.25 billion of notional credit capacity from a syndicate of seven Canadian and four foreign banks. The facility can be extended at Pengrowth’s discretion any time prior to maturity, subject to syndicate approval. In the event that the lenders do not agree to a renewal, the outstanding balance is due upon maturity which is currently July 26, 2017.

This facility carries floating interest rates that are expected to range between 1.6 percent and 3.25 percent over bankers’ acceptance rates, depending on Pengrowth’s ratio of senior debt to earnings before interest, taxes and non-cash items.

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At December 31, 2014, the available facility was reduced by drawings of $191.0 million (December 31, 2013 – $nil) and letters of credit in the amount of $25.0 million (December 31, 2013 – $35.8 million) were outstanding.

As of December 31, 2014, an unrealized cumulative foreign exchange loss of $159.6 million (December 31, 2013 - $45.0 million loss) has been recognized on the remaining U.S. dollar term notes since the date of issuance. As of December 31, 2014, an unrealized cumulative foreign exchange gain of $20.4 million (December 31, 2013 - $23.3 million gain) has been recognized on the U.K. pound sterling denominated term notes since inception. See Note 17 for additional information about foreign exchange risk management and the impact on the Consolidated Financial Statements.

The five year schedule of long term debt repayment based on current maturity dates and assuming the revolving credit facility is not renewed is as follows: 2015 - $173.2 million, 2016 - $nil, 2017 - $654.4 million, 2018 - $321.8 million, 2019 - $67.5 million.

BANK INDEBTEDNESS

Pengrowth also maintains a $50 million demand operating facility with one Canadian bank. At December 31, 2014, this facility was reduced by drawings of $9.0 million (December 31, 2013 – $nil) and reduced by $0.9 million of outstanding letters of credit (December 31, 2013 – $0.8 million). When utilized together with any overdraft amounts, this facility would appear on the Consolidated Balance Sheets as a current liability in bank indebtedness, as applicable.

FINANCIAL COVENANTS

Pengrowth’s senior unsecured notes and credit facilities are subject to a number of covenants, all of which were met at all times during the preceding twelve months, and at December 31, 2014. On January 24, 2014, certain of the credit facility covenants were amended until December 31, 2015. The financial covenants are now substantially similar between the credit facilities and the senior unsecured notes. The covenant amendments were obtained as a proactive step while Pengrowth completes construction of the first 12,500 bbl/d commercial phase of Lindbergh.

10. PROVISIONS

Provisions are composed of ARO and contract & other liabilities. The following provides a continuity of the balances for the following periods:

	Asset retirement obligations			Contract & Other liabilities			Total
Balance, December 31, 2012	$	868.9		$	6.7		$	875.6
Incurred during the period	4.2			—			4.2
Property acquisitions	3.1			—			3.1
Property dispositions	(84.0		)	—			(84.0		)
Revisions due to discount rate changes (1)	(195.0		)	—			(195.0		)
Provisions settled	(29.6		)	—			(29.6		)
Other revisions	18.1			—			18.1
Accretion (amortization)	20.5			(1.4		)	19.1
Balance, December 31, 2013	$	606.2		$	5.3		$	611.5
Incurred during the period	6.8			4.4			11.2
Property acquisitions	3.5			—			3.5
Property dispositions	(66.5		)	—			(66.5		)
Revisions due to discount rate changes(2)	211.5			—			211.5
Provisions settled	(22.9		)	(0.5		)	(23.4		)
Other revisions	23.4			(0.4		)	23.0
Accretion (amortization)	18.8			(1.6		)	17.2
Balance, December 31, 2014	$	780.8		$	7.2		$	788.0

⁽¹⁾  Relates to the change in the risk free discount rate from 2.5 percent to 3.25 percent. The offset is recorded in PP&E.

⁽²⁾  Relates to the change in the risk free discount rate from 3.25 percent to 2.3 percent. The offset is recorded in PP&E.

PENGROWTH 2014 Financial Results 23

As at December 31, 2014
Current	$	24.9	$	2.4	$	27.3
Long term	755.9		4.8		760.7
	$	780.8	$	7.2	$	788.0
As at December 31, 2013
Current	$	15.0	$	2.1	$	17.1
Long term	591.2		3.2		594.4
	$	606.2	$	5.3	$	611.5

The following assumptions were used to estimate the ARO liability:

	As at
	December 31, 2014		December 31, 2013
Total escalated future costs	2,007.0		2,122.5
Discount rate, per annum	2.3	%	3.25	%
Inflation rate, per annum	1.5	%	1.5	%

The majority of the costs are expected to be incurred between 2038 and 2079.

CONTRACT & OTHER LIABILITIES

Pengrowth assumed firm transportation commitments in conjunction with prior period acquisitions. The fair values of these contracts were estimated on the date of acquisition and the amount recorded is reduced as the contracts settle.

Provisions incurred in 2014 relate to a finance lease transaction and Board of Directors cash-settled deferred share unit grants.

11. DEFERRED INCOME TAXES

A reconciliation of the deferred income tax recovery calculated based on the loss before taxes at the statutory tax rate to the actual provision for deferred income taxes is as follows:

	Year ended December 31
	2014			2013
Loss before taxes	$	(599.2	)	$	(390.1	)
Combined federal and provincial tax rate	25.22		%	25.30		%
Expected income tax recovery	$	(151.1	)	$	(98.7	)
Goodwill impairment and divestitures	118.7			7.1
Foreign exchange loss(1)	9.5			11.7
Loss on investments(2)	0.6			1.9
Effect of change in corporate tax rate	(2.4		)	(0.2		)
Other including share based compensation	4.3			5.0
Deferred income tax recovery	$	(20.4	)	$	(73.2	)

⁽¹⁾  Reflects the 50% non-taxable portion of foreign exchange gains and losses and related risk management contracts.

⁽²⁾  Reflects the 50% non-taxable portion of investment gains and losses.

PENGROWTH 2014 Financial Results 24

The net deferred income tax liability is composed of:

	As at
	December 31, 2014			December 31, 2013
Deferred tax liabilities associated with:
PP&E and E&E assets	$	(590.3	)	$	(635.7	)
Risk management contracts	(105.5		)	17.6
Less deferred tax assets associated with:
Non-capital losses	287.7			242.2
Convertible debentures	0.1			0.3
Share issue costs	0.4			2.1
Provisions	197.4			154.2
Long term debt	12.5			1.2
Net deferred tax liability	$	(197.7	)	$	(218.1	)

In calculating the deferred income tax liability in 2014, Pengrowth included $1,150.7 million (2013 - $967.5 million) of non-capital losses available for carry forward to reduce taxable income in future years. These losses expire between 2026 and 2034.

Deferred tax assets have not been recognized with respect to the following items:

	As at
	December 31, 2014		December 31, 2013
Deductible temporary differences	$	25.5	$	25.5
Tax losses	16.7		16.7
	$	42.2	$	42.2

A continuity of the net deferred income tax liability for 2014 and 2013 is detailed in the following tables:

Movement in temporary differences during the year	Balance Jan 1, 2014			Recognized in profit or loss			Balance Dec 31, 2014
PP&E and E&E assets	$	(635.7	)	$	45.4		$	(590.3	)
Convertible debentures	0.3			(0.2		)	0.1
Long term debt	1.2			11.3			12.5
Share issue costs	2.1			(1.7		)	0.4
Non-capital losses	242.2			45.5			287.7
Provisions	154.2			43.2			197.4
Risk management contracts	17.6			(123.1		)	(105.5		)
	$	(218.1	)	$	20.4		$	(197.7	)

Movement in temporary differences during the year	Balance Jan 1, 2013			Recognized in profit or loss			Balance Dec 31, 2013
PP&E and E&E assets	$	(718.5	)	$	82.8		$	(635.7	)
Convertible debentures	0.6			(0.3		)	0.3
Long term debt	(10.7		)	11.9			1.2
Share issue costs	4.9			(2.8		)	2.1
Non-capital losses	208.3			33.9			242.2
Provisions	221.2			(67.0		)	154.2
Risk management contracts	2.9			14.7			17.6
	$	(291.3	)	$	73.2		$	(218.1	)

PENGROWTH 2014 Financial Results 25

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.

No current income taxes were paid by Pengrowth in 2014 and 2013.

12. SHAREHOLDERS’ CAPITAL

Pengrowth is authorized to issue an unlimited number of common shares and up to 10 million preferred shares. No preferred shares have been issued.

	2014			2013
(Common shares in 000's)	Number of common shares	Amount		Number of common shares	Amount
Balance, beginning of year	522,031	$	4,693.1	511,804	$	4,634.8
Share based compensation (cash exercised)	257	1.6		336	2.1
Share based compensation (non-cash exercised)	1,985	13.2		1,260	11.3
Issued for cash under Dividend Reinvestment Plan ("DRIP")	9,165	51.8		8,631	44.9
Balance, end of year	533,438	$	4,759.7	522,031	$	4,693.1

DIVIDEND REINVESTMENT PLAN

Pengrowth’s Dividend Reinvestment Plan (“DRIP”) entitles shareholders to reinvest cash dividends in additional shares of Pengrowth. Under the DRIP, the shares are issued from treasury at a 5 percent discount to the weighted average closing price as determined by the plan.

13. SHARE BASED COMPENSATION PLANS

Pengrowth’s Long Term Incentive Plan ("LTIP") as described below is used to grant awards of share based compensation. Prior to January 1, 2011, Pengrowth had other long term incentive plans that are being phased out with no new awards to be issued under the previous long term incentive plans.

A rolling and reloading plan with a maximum of 3.2 percent of the issued and outstanding common shares may be reserved for issuance under all share based compensation plans in the aggregate, as approved by shareholders. As at December 31, 2014, the number of shares issuable under the share based compensation plans, in aggregate, represents 2.3 percent of the issued and outstanding common shares, which is within the limit.

Share based compensation expense is composed of the following:

	Year ended December 31
	2014			2013
Share based compensation	$	18.0		$	16.4
Amounts capitalized in the year	(1.5		)	(1.4		)
Share based compensation expense included in net loss	$	16.5		$	15.0

LONG TERM INCENTIVE PLAN ("LTIP")

Pengrowth’s LTIP has the following components:

(a) Performance Share Units ("PSUs")

PSUs entitle the holder to a number of common shares to be issued in the third year after grant. PSUs may be awarded to employees, officers and consultants. PSUs are subject to a performance factor ranging from 50 percent to 150 percent of the number of PSUs granted plus the amount of reinvested notional dividends.

PENGROWTH 2014 Financial Results 26

(b) Restricted Share Units ("RSUs")

RSUs may be awarded to employees, officers and consultants and entitle the holder to a number of common shares plus reinvested notional dividends to be issued at vesting over three years. The RSUs generally vest on the first, second and third anniversary date from the date of grant.

(c) Deferred Share Units ("DSUs")

DSUs are currently only issued to the independent members of the Board of Directors. Each DSU entitles the holder to one common share plus reinvested notional dividends since the grant date of the DSU. The DSUs vest upon grant but can only be converted to common shares upon the holder ceasing to be a Director of Pengrowth. The number of common shares ultimately issued will be equal to the number of DSUs initially granted to the holder plus the amount of reinvested notional dividends accruing during the term of the DSUs. Commencing in 2014, the independent members of the Board of Directors receive cash-settled phantom DSUs in lieu of any new grants of these share-settled DSUs.

The Board of Directors retain discretion with respect to the LTIP.

The following provides a continuity of the share settled LTIP:

(number of share units - 000's)	PSUs		RSUs		DSUs
Outstanding, December 31, 2012	1,724		1,958		136
Granted	2,611		3,299		161
Forfeited	(439	)	(483	)	—
Exercised	(2	)	(689	)	(34	)
Performance adjustment	(163	)	—		—
Deemed DRIP	303		328		21
Outstanding, December 31, 2013	4,034		4,413		284
Granted	1,916		2,361		—
Forfeited	(259	)	(285	)	—
Exercised	(275	)	(1,706	)	—
Performance adjustment	108		—		—
Deemed DRIP	421		385		24
Outstanding, December 31, 2014	5,945		5,168		308

Compensation expense related to PSU, RSU, and DSU share settled plans are based on the fair value of the share units at the date of grant. The fair value of the performance related share units is determined at the date of grant using the closing share price and is adjusted for the estimated performance multiplier. The amount of compensation expense is reduced by an estimated forfeiture rate at the date of grant. For PSU and RSU grants made prior to 2013, the forfeiture rate was estimated at 10 to 25 percent for employees and 3 to 9 percent for officers, depending on the vesting period. For PSU and RSU 2013 and 2014 grants, the estimated forfeiture rates range from 10 to 30 percent for both employees and officers, depending on the vesting period. There is no forfeiture rate applied for DSUs as they vest immediately upon grant. For the performance related share plans, the number of shares awarded at the end of the vesting period is subject to certain performance conditions. Fluctuations in compensation expense may occur due to changes in estimating the outcome of the performance conditions. Compensation expense is recognized in net income (loss) over the vesting period with a corresponding increase or decrease to contributed surplus. Upon the issuance of common shares at the end of the vesting period, shareholders’ capital is increased and contributed surplus is decreased by the amount of compensation expense incurred during the vesting period. The shares are issued from treasury upon vesting.

For the year ended December 31, 2014, Pengrowth recorded $17.5 million of compensation expense related to the LTIP units (December 31, 2013 - $16.6 million), based on the weighted average grant date fair value of $7.04 per share unit (December 31, 2013 - $4.73 per share unit). As at December 31, 2014, the amount of compensation expense to be recognized over the remaining vesting period was $18.4 million or $2.44 per share unit (December 31, 2013 - $18.7 million or $2.73 per share unit) subject to the determination of the performance multiplier. The unrecognized compensation cost will be expensed to net income (loss) over the remaining weighted average vesting period of 1.4 years.

PENGROWTH 2014 Financial Results 27

PREVIOUS LONG TERM INCENTIVE PLANS

(a) Deferred Entitlement Share Units ("DESU") Plan

This compensation plan was used while Pengrowth was a trust. Effective January 1, 2011, no further grants were made under this plan. As at December 31, 2014, all of the grants were fully vested and the total outstanding balance was composed of grants to the independent members of the Board of Directors which are not exercisable and do not expire until they cease to be a Director for any reason. As at December 31, 2014, the number of share units outstanding under the DESU Plan was 295,374 share units (December 31, 2013 - 275,409 share units).

(b) Common Share Rights Incentive Plan

The trust unit rights incentive plan that was effective when Pengrowth was a trust, was renamed on conversion to a corporation to the common share rights incentive plan. This plan consists of two types of awards being share unit options exercisable at a fixed price and share unit rights exercisable at the original grant price or at a reduced price that is calculated in accordance with the plan. During the years ended December 31, 2014 and 2013, there were no exercise price reductions under this plan. As at December 31, 2014, all of the grants were fully vested and the number of share unit options outstanding under the Common Share Rights Incentive Plan was 3,159 share unit options (December 31, 2013 - 496,918 share unit options). The remaining share unit options outstanding have an exercise price of $11.18 per share unit option and expire in 2015.

CASH-SETTLED PHANTOM DEFERRED SHARE UNITS ("PHANTOM DSUs")

Commencing in 2014, the independent members of the Board of Directors receive cash-settled Phantom DSUs in lieu of any new grants of share-settled DSUs. Each Phantom DSU entitles the holder to a cash payment equivalent to the value of a number of Common Shares (including the reinvestment of notional dividends) to be paid upon the individual ceasing to be a Director for any reason. 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. 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, 2014, the number of Phantom DSUs outstanding was 133,621 units (December 31, 2013 - nil) with a corresponding long term liability of $0.5 million (December 31, 2013 - $nil). For the year ended December 31, 2014, Pengrowth recorded $0.5 million of compensation expense related to the Phantom DSUs (December 31, 2013 - $nil).

14. OTHER CASH FLOW DISCLOSURES

CHANGE IN NON-CASH OPERATING WORKING CAPITAL

	Year ended December 31
Cash provided by:	2014		2013
Accounts receivable	$	44.2	$	5.3
Accounts payable	54.1		6.1
	$	98.3	$	11.4

CHANGE IN NON-CASH INVESTING WORKING CAPITAL

	Year ended December 31
Cash provided by (used for):	2014			2013
Accounts payable, including capital accruals	$	(56.4	)	$	48.6

DIVIDENDS PAID

In 2013 and 2014, Pengrowth paid $0.04 per share in dividends in each of the months January through December for an aggregate annual cash dividend of $0.48 per share.

PENGROWTH 2014 Financial Results 28

15. AMOUNTS PER SHARE

The following reconciles the weighted average number of shares used in the basic and diluted net loss per share calculations:

	Year ended December 31
(000's)	2014	2013
Weighted average number of shares – basic and diluted	527,851	517,365

For the year ended December 31, 2014, 8.2 million shares (December 31, 2013 - 5.9 million) that are issuable on exercise of the share based compensation plans were excluded from the diluted net loss per share calculation as their effect is anti-dilutive.

Further, for the year ended December 31, 2014, 23.0 million shares (December 31, 2013 - 23.0 million) that are issuable on potential conversion of the convertible debentures were excluded from the diluted net loss per share calculation as their effect is anti-dilutive.

16. CAPITAL DISCLOSURES

Pengrowth defines its capital as shareholders’ equity, long term debt, convertible debentures, bank indebtedness and working capital.

Pengrowth’s goal over the longer term is to modestly grow production and reserves per debt adjusted share, while continuing to pay a prudent dividend.

Pengrowth must comply with certain financial debt covenants. Compliance with these financial covenants is closely monitored by management as part of Pengrowth’s overall capital management objectives. The covenants are based on specific definitions prescribed in the debt agreements and are different between the credit facility and the term notes. Throughout the period, Pengrowth was in compliance with all financial covenants.

Management monitors Pengrowth's capital structure using non-GAAP financial metrics, primarily total debt to the trailing twelve months Earnings Before Interest, Taxes, Depletion, Depreciation, Amortization, Accretion, and other non-cash items ("AdjustedEBITDA") and total debt to total capitalization. Pengrowth seeks to manage the ratio of total debt to trailing Adjusted EBITDA and total debt to total capitalization ratio with the objective of being able to finance its growth strategy while maintaining sufficient flexibility under the debt covenants. However, there may be instances where it would be acceptable for total debt to trailing Adjusted EBITDA to temporarily fall outside of the normal targets set by management such as financing growth opportunities. This would be a strategic decision recommended by management and approved by the Board of Directors with steps taken in the subsequent period to restore Pengrowth’s capital structure based on its capital management objectives.

In order to maintain its financial condition or adjust its capital structure, Pengrowth may dispose of non-core assets, adjust the level of capital spending, issue new debt, refinance existing debt, issue additional equity, monetize risk management contracts or adjust the level of dividends paid to shareholders to reduce debt levels.

Pengrowth’s objectives, policies and processes for managing capital have remained substantially consistent from the prior year. Management believes that current total debt to trailing Adjusted EBITDA and total debt to total capitalization were within reasonable limits at December 31, 2014. However, with the continued weakening of commodity prices along with the Canadian dollar, Pengrowth was concerned about the ratios into 2015, so it took the proactive steps of reducing capital spending and dividends paid, to ensure these ratios will continue to stay within reasonable limits.

PENGROWTH 2014 Financial Results 29

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

	As at
	December 31, 2014			December 31, 2013
Long term debt (1)	$	1,722.0		$	1,412.7
Convertible debentures (2)	137.2			236.0
Working capital surplus (3)	(22.7		)	(179.3		)
	$	1,836.5		$	1,469.4

⁽¹⁾  Includes current portion of senior unsecured notes.

⁽²⁾  Includes current portion of convertible debentures.

⁽³⁾  Working capital surplus is calculated as current liabilities less current assets per the Consolidated Balance Sheets, excluding the current portions of long term debt and convertible debentures.

17. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

Pengrowth’s financial instruments are composed of accounts receivable, accounts payable, risk management assets and liabilities, remediation trust funds, other investments in another entity, dividends payable to shareholders, bank indebtedness, convertible debentures and long term debt.

Details of Pengrowth’s significant accounting policies for recognition and measurement of financial instruments are disclosed in Note 2.

RISK MANAGEMENT OVERVIEW

Pengrowth has exposure to certain market risks related to volatility in commodity and power prices, interest rates and foreign exchange rates. Derivative instruments are used to manage exposure to these risks. Pengrowth’s policy is not to utilize financial instruments for trading or speculative purposes.

The Board of Directors and management have overall responsibility for the establishment of risk management strategies and objectives. Pengrowth’s risk management policies are established to identify the risks faced by Pengrowth, to set appropriate risk limits, and to monitor adherence to risk limits. Risk management policies are reviewed regularly to reflect changes in market conditions and Pengrowth’s activities.

MARKET RISK

Market risk is the risk that the fair value, or future cash flows of financial assets and liabilities, will fluctuate due to movements in market prices. Market risk is composed of commodity and power price risk, foreign currency risk and interest rate risk.

Commodity Price Risk

Pengrowth is exposed to commodity price risk as prices for oil and gas products fluctuate in response to many factors including local and global supply and demand, weather patterns, pipeline transportation, political stability and economic factors. Commodity price fluctuations are an inherent part of the oil and gas business. While Pengrowth does not consider it prudent to entirely eliminate this risk, it does mitigate some of the exposure to commodity price risk to protect the return on acquisitions and provide a level of stability to operating cash flow which enables Pengrowth to fund its capital development program and dividends. Pengrowth utilizes financial contracts to fix the commodity price associated with a portion of its future production. The use of forward and futures contracts are governed by formal policies and is subject to limits established by the Board of Directors. The Board of Directors and management may re-evaluate these limits as needed in response to specific events such as market activity, additional leverage, acquisitions or other transactions where Pengrowth’s capital structure may be subject to more risk from commodity prices.

PENGROWTH 2014 Financial Results 30

Commodity Price Contracts

As at December 31, 2014, Pengrowth had fixed the price applicable to future production as follows:

Crude Oil:
Swaps
Reference point	Volume  (bbl/d)	Remaining term	Price per bbl				Settlement currency
Financial:
Edmonton Light Sweet	1,500	Jan 1, 2015 - Mar 31, 2015	Cdn WTI less $8.77				Cdn
WTI	13,000	Jan 1, 2015 - Dec 31, 2015	$	92.77			Cdn
WTI	12,500	Jan 1, 2015 - Jun 30, 2015	$	95.76			Cdn
WTI	13,000	Jul 1, 2015 - Dec 31, 2015	$	94.60			Cdn
WTI	4,500	Jan 1, 2016 - Dec 31, 2016	$	75.18			Cdn
WTI	18,500	Jan 1, 2016 - Mar 31, 2016	$	95.56			Cdn
WTI	14,000	Apr 1, 2016 - Jun 30, 2016	$	95.04			Cdn
WTI	12,000	Jul 1, 2016 - Sep 30, 2016	$	95.37			Cdn
WTI	11,500	Oct 1, 2016 - Dec 31, 2016	$	95.20			Cdn
Puts
Reference point	Volume  (bbl/d)	Remaining term	Price per bbl		Premium payable per bbl		Settlement currency
Financial:
WTI	500	Jan 1, 2015 - Mar 31, 2015	$	97.25	$	3.25	Cdn
WTI	500	Apr 1, 2015 - Jun 30, 2015	$	97.25	$	3.18	Cdn
WTI	4,000	Jan 1, 2016 - Mar 31, 2016	$	90.00	$	3.30	Cdn
Natural Gas:
Swaps
Reference point	Volume  (MMBtu/d)	Remaining term	Price per MMBtu				Settlement currency
Financial:
AECO	78,195	Jan 1, 2015 - Dec 31, 2015	$	3.78			Cdn
AECO	2,370	Jan 1, 2015 - Mar 31, 2015	$	3.85			Cdn
NGI Chicago Index	7,500	Jan 1, 2015 - Dec 31, 2015	$	4.50			Cdn
AECO	21,326	Jan 1, 2016 - Dec 31, 2016	$	3.70			Cdn
AECO	23,695	Jan 1, 2016 - Mar 31, 2016	$	4.10			Cdn
AECO	4,739	Apr 1, 2016 - Jun 30, 2016	$	3.72			Cdn
AECO	4,739	Jul 1, 2016 - Sep 30, 2016	$	3.70			Cdn
AECO	18,956	Oct 1, 2016 - Dec 31, 2016	$	3.88			Cdn
AECO	18,956	Jan 1, 2017 - Dec 31, 2017	$	4.00			Cdn
AECO	11,848	Jan 1, 2017 - Mar 31, 2017	$	4.04			Cdn
AECO	4,739	Jan 1, 2018 - Dec 31, 2018	$	3.89			Cdn
Puts
Reference point	Volume  (MMBtu/d)	Remaining term	Price per MMBtu		Premium payable per MMBtu		Settlement currency
Financial:
AECO	4,739	Jan 1, 2016 - Mar 31, 2016	$	3.93	$	0.43	Cdn
AECO	4,739	Jan 1, 2016 - Jun 30, 2016	$	3.59	$	0.25	Cdn

PENGROWTH 2014 Financial Results 31

Commodity Price Sensitivity on Risk Management Contracts as at December 31, 2014

Oil	Cdn$1/bbl increase in future oil prices			Cdn$1/bbl decrease in future oil prices
Unrealized pre-tax gain (loss) on oil risk management	$	(16.5	)	$	16.5
Natural gas	Cdn$0.25/MMBtu increase in future natural gas prices			Cdn$0.25/MMBtu decrease in future natural gas prices
Unrealized pre-tax gain (loss) on natural gas risk management	$	(13.6	)	$	13.5

As at close December 31, 2014, the AECO gas spot price was $2.81/MMBtu (December 31, 2013 – $4.03/MMBtu). The WTI prompt monthly price was Cdn$61.80/bbl (December 31, 2013 – Cdn$104.68/bbl).

Physical Delivery Contracts

As at December 31, 2014, the following physical delivery contracts were held for the purpose of delivery of non-financial items in accordance with Pengrowth's expected sales requirements. Physical delivery contracts are not considered financial instruments and therefore, no asset or liability has been recognized in the Consolidated Financial Statements.

Crude Oil:
Reference point	Volume (bbl/d)	Remaining term	Price per bbl
Edmonton Light Sweet	3,098	Jan 1, 2015 - Mar 31, 2015	Cdn WTI less $8.78

Power Price Contracts

As at December 31, 2014, Pengrowth had fixed the price applicable to future power costs as follows:

Power:
Reference point	Volume (MW)	Remaining term	Price per MWh		Settlement currency
Financial:
AESO	40	Jan 1, 2015 - Dec 31, 2015	$	49.53	Cdn
AESO	10	Jan 1, 2016 - Dec 31, 2016	$	50.00	Cdn

As at close December 31, 2014, the Alberta power pool spot price was $18.78/MWh (December 31, 2013 – $32.93/MWh). The average Alberta power pool price was $30.47/MWh for the three months ended December 31, 2014 (December 31, 2013 – $48.59/MWh). The average Alberta power pool price was $49.42/MWh for the year ended December 31, 2014 (December 31, 2013 – $80.19/MWh).

Power Price Sensitivity on Risk Management Contracts as at December 31, 2014

Each $1/MWh change in future power prices would result in a pre-tax change in the unrealized gain (loss) on power risk management contracts outstanding as at December 31, 2014 of approximately $0.4 million.

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 has mitigated some of this exchange risk by entering into fixed Canadian dollar crude oil and natural gas price swaps as outlined in the commodity price risk section above.

Pengrowth is exposed to foreign currency fluctuation on the U.S. dollar and U.K. pound sterling denominated notes for both interest and principal payments. Pengrowth has mitigated some of this risk by entering into a series of swap contracts and other derivatives in order to fix the foreign exchange rate on a portion of the U.S. dollar and all of the U.K. pound sterling denominated notes.

PENGROWTH 2014 Financial Results 32

Foreign Exchange Contracts

U.K. pound sterling Denominated Term Debt

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

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

U.S. 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. 

Contract type	Settlement date	Principal amount  (U.S.$ millions)	Swapped amount  (U.S.$ millions)	% of principal swapped		Fixed rate ($1Cdn = $U.S.)
Swap	May 2015	71.5	50.0	70	%	0.98
Swap	July 2017	400.0	250.0	63	%	0.97
Swap	August 2018	265.0	125.0	47	%	0.96
Swap	October 2019	35.0	15.0	43	%	0.94
Swap	May 2020	115.5	20.0	17	%	0.95
No contracts	October 2022	105.0	—	—		—
No contracts	October 2024	195.0	—	—		—
		1,187.0	460.0	39	%

Foreign Exchange Rate Sensitivity

Foreign Exchange on Foreign Denominated Term Debt

The following 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, 2014	Cdn - U.S.		Cdn - U.K.
Unrealized foreign exchange gain or loss on foreign denominated debt	$	11.9	$	0.7
Unrealized foreign exchange risk management gain or loss	4.6		0.7
Net pre-tax impact on Consolidated Statements of Loss	$	7.3	$	—
	Cdn$0.01 Exchange rate change
Foreign exchange sensitivity as at December 31, 2013	Cdn - U.S.		Cdn - U.K.
Unrealized foreign exchange gain or loss on foreign denominated debt	$	11.9	$	0.7
Unrealized foreign exchange risk management gain or loss	4.6		0.7
Net pre-tax impact on Consolidated Statements of Loss	$	7.3	$	—

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, 2014, Pengrowth had approximately $1.7 billion of current and non-current long term debt outstanding (December 31, 2013 - $1.4 billion) of which $191.0 million was based on floating interest rates (December 31, 2013 - $nil). A 1 percent increase in interest rates would increase pre-tax interest expense by approximately $1.9

PENGROWTH 2014 Financial Results 33

million for the year ended December 31, 2014 (December 31, 2013 - $nil), assuming the amount was outstanding for the entire year.

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, 2014	Commodity contracts (1)			Power and Interest contracts (2)			Foreign exchange contracts (3)			Total
Current portion of risk management assets	$	292.3		$	—		$	7.3		$	299.6
Non-current portion of risk management assets	128.8			—			53.8			182.6
Current portion of risk management liabilities	—			(2.5		)	(10.3		)	(12.8		)
Non-current portion of risk management liabilities	—			(0.4		)	—			(0.4		)
Risk management assets (liabilities), end of year	$	421.1		$	(2.9	)	$	50.8		$	469.0
Less: Risk management assets (liabilities) at beginning of year	(80.0		)	(1.4		)	12.0			(69.4		)
Unrealized gain (loss) on risk management contracts for the year	$	501.1		$	(1.5	)	$	38.8		$	538.4
Realized loss on risk management contracts for the year	(96.1		)	(3.0		)	(1.5		)	(100.6		)
Total unrealized and realized gain (loss) on risk management contracts for the year	$	405.0		$	(4.5	)	$	37.3		$	437.8
As at and for the year ended December 31, 2013	Commodity contracts(1)			Power and Interest contracts (2)			Foreign exchange contracts (3)			Total
Current portion of risk management assets	$	—		$	—		$	—		$	—
Non-current portion of risk management assets	—			—			23.1			23.1
Current portion of risk management liabilities	(68.1		)	(1.3		)	(0.9		)	(70.3		)
Non-current portion of risk management liabilities	(11.9		)	(0.1		)	(10.2		)	(22.2		)
Risk management assets (liabilities), end of year	$	(80.0	)	$	(1.4	)	$	12.0		$	(69.4	)
Less: Risk management assets (liabilities) at beginning of year	7.0			(0.8		)	(17.8		)	(11.6		)
Unrealized gain (loss) on risk management contracts for the year	$	(87.0	)	$	(0.6	)	$	29.8		$	(57.8	)
Realized gain (loss) on risk management contracts for the year	(55.0		)	3.0			1.2			(50.8		)
Total unrealized and realized gain (loss) on risk management contracts for the year	$	(142.0	)	$	2.4		$	31.0		$	(108.6	)

⁽¹⁾  Unrealized and realized gains and losses are presented as separate line items in the Consolidated Statements of Income (Loss).

⁽²⁾  Unrealized gains and losses are included in other (income) expense and interest expense, respectively. Realized gains and losses are included in operating expense and interest expense, respectively.

⁽³⁾  Unrealized and realized gains and losses are included as part of separate line items in the Consolidated Statements of Income (Loss).

PENGROWTH 2014 Financial Results 34

FAIR VALUE

The fair value of cash and cash equivalents, accounts receivable, accounts payable, bank indebtedness and dividends payable approximate their carrying amount due to the short-term nature of those instruments. The fair value of the Canadian dollar revolving credit facility 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 funds and minority investment in a private company are equal to their carrying amount as these assets are carried at their estimated fair value.

The following tables provide fair value measurement information for financial assets and liabilities:

					Fair value measurements using:
As at December 31, 2014	Carrying amount		Fair value		Quoted prices in active markets (Level 1)		Significant other observable inputs (Level 2)		Significant unobservable inputs (Level 3)
Financial Assets
Remediation trust funds	$	60.4	$	60.4	$	60.4	$	—	$	—
Fair value of risk management contracts	482.2		482.2		—		482.2		—
Financial Liabilities
Convertible debentures	137.2		135.3		135.3		—		—
U.S. dollar denominated senior unsecured notes	1,373.8		1,457.7		—		1,457.7		—
Cdn dollar senior unsecured notes	39.9		41.5		—		41.5		—
U.K. pound sterling denominated unsecured notes	117.3		120.6		—		120.6		—
Fair value of risk management contracts	13.2		13.2		—		13.2		—
					Fair value measurements using:
As at December 31, 2013	Carrying amount		Fair value		Quoted prices in active markets (Level 1)		Significant other observable inputs (Level 2)		Significant unobservable inputs (Level 3)
Financial Assets
Remediation trust funds	$	54.7	$	54.7	$	54.7	$	—	$	—
Fair value of risk management contracts	23.1		23.1		—		23.1		—
Investment in private corporation	5.0		5.0		—		—		5.0
Financial Liabilities
Convertible debentures	236.0		240.0		240.0		—		—
U.S. dollar denominated senior unsecured notes	1,258.5		1,333.2		—		1,333.2		—
Cdn dollar senior unsecured notes	39.9		39.6		—		39.6		—
U.K. pound sterling denominated unsecured notes	114.3		118.6		—		118.6		—
Fair value of risk management contracts	92.5		92.5		—		92.5		—

Level 1 Fair Value Measurements

Financial assets and liabilities are recorded at fair value based on quoted prices in active markets.

Level 2 Fair Value Measurements

Risk management contracts - the fair value of the risk management contracts is based on commodity, power and foreign exchange curves that are readily available or, in their absence, third-party market indications and forecasts priced on the last trading day of the applicable period.

PENGROWTH 2014 Financial Results 35

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 two under the fair value hierarchy.

Term notes - 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.

Level 3 Fair Value Measurements

Investment in Private Corporation - the fair value of the investment in Private Corporation is determined by considering several factors, including the lack of success of recent private placement equity offerings in the Private Corporation. The fair value of the investment has decreased to $nil as at December 31, 2014 (December 31, 2013 - $5 million), resulting in an unrealized loss of $5 million in 2014 (December 31, 2013 - loss of $15 million).

CREDIT RISK

Credit risk is the risk of financial loss to Pengrowth if a counterparty to a financial instrument fails to meet its contractual obligations. A significant portion of Pengrowth’s accounts receivable are with customers in the oil and gas industry and are subject to normal industry credit risks. Uncertainty in the credit markets, should it exist, may restrict the ability of Pengrowth’s normal business counterparties to meet their obligations to Pengrowth. Additional credit risk could exist where little or none previously existed. Pengrowth manages its credit risk by performing a credit review on each marketing counterparty and following a credit practice that limits transactions according to the counterparty’s credit rating as assessed by Pengrowth. In addition, Pengrowth may require letters of credit or parental guarantees from certain counterparties to mitigate some of the credit risk associated with the amounts owing by the counterparty. The use of financial swap agreements involves a degree of credit risk that Pengrowth manages through its credit policies which are designed to limit eligible counterparties to those with investment grade credit ratings or better. The carrying value of accounts receivable and risk management assets represents Pengrowth’s maximum credit exposure.

Pengrowth sells a significant portion of its oil and gas to a limited number of counterparties. In 2014, Pengrowth has two counterparties that individually account for more than ten percent of annual revenue. Both of the counterparties are large trading companies and subject to regular internal credit reviews.

Pengrowth considers amounts over 90 days as past due. As at December 31, 2014, the amount of accounts receivable that were past due was not significant. Pengrowth has not recorded a significant allowance for doubtful accounts during 2014 and 2013 and has no significant bad debt provision at December 31, 2014. Pengrowth’s objectives, processes and policies for managing credit risk have not changed from the previous year.

The components of accounts receivable are as follows:

	As at
	December 31, 2014		December 31, 2013
Trade	$	129.9	$	175.2
Prepaid and other	18.2		17.1
	$	148.1	$	192.3

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 notional committed $1.0 billion term credit facility with an additional $250 million available under an expansion feature subject to lender approval and a $50 million demand operating line of credit. Use of the remaining credit capacity is still subject to complying with all financial covenants. Pengrowth’s long term notes and bank credit facilities are unsecured and equally ranked.

PENGROWTH 2014 Financial Results 36

Pengrowth’s non-current financial liabilities are as follows:

As at December 31, 2014	Carrying amount		Contractual cash flows		Year 1		Year 2		Years 3-5		More than 5 years
Convertible debentures	$	137.2	$	156.1	$	8.6	$	8.6	$	138.9	$	—
Cdn dollar revolving credit facility (1)	191.0		209.5		7.2		7.2		195.1		—
Cdn dollar senior unsecured notes (1)	39.9		52.9		2.2		2.2		20.2		28.3
U.S. dollar denominated senior unsecured notes (1)	1,290.9		1,628.9		74.7		75.0		935.1		544.1
U.K. pound sterling denominated unsecured notes (1)	27.0		31.6		0.9		0.9		29.8		—
Other liabilities	4.8		12.0		—		1.5		2.9		7.6
Remediation trust fund payments	—		12.5		0.3		0.3		0.9		11.0
Power risk management contracts	0.4		0.4		—		0.4		—		—

⁽¹⁾  Contractual cash flows include future interest payments calculated at period end exchange rates and interest rates except for term notes which are calculated at the actual interest rate.

As at December 31, 2013	Carrying amount		Contractual cash flows		Year 1		Year 2		Years 3-5		More than 5 years
Convertible debentures	$	137.3	$	164.6	$	8.6	$	8.6	$	147.4	$	—
Cdn dollar senior unsecured notes (1)	39.9		55.0		2.2		2.2		21.1		29.5
U.S. dollar denominated senior unsecured notes (1)	1,258.5		1,642.8		72.1		145.9		867.2		557.6
U.K. pound sterling denominated unsecured notes (1)	114.3		129.1		5.7		93.5		2.7		27.2
Remediation trust fund payments	—		12.5		0.3		0.3		0.9		11.0
Commodity risk management contracts	11.9		12.1		—		12.1		—		—
Power and interest risk management contracts	0.1		0.1		—		0.1		—		—
Foreign exchange risk management contracts	10.2		1.7		0.3		0.3		0.8		0.3

⁽¹⁾  Contractual cash flows include future interest payments calculated at period end exchange rates and interest rates except for term notes which are calculated at the actual interest rate.

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, 2014			December 31, 2013
Risk management contracts
Current asset	$	299.7		$	0.9
Non-current asset	182.5			25.8
Current liability	(12.9		)	(71.2		)
Non-current liability	(0.3		)	(24.9		)
	$	469.0		$	(69.4	)

PENGROWTH 2014 Financial Results 37

18. FOREIGN EXCHANGE (GAIN) LOSS

	Year ended December 31
	2014			2013
Currency exchange rate ($1Cdn = $U.S.) at year end	$	0.86		$	0.94
Unrealized foreign exchange loss on U.S. dollar denominated debt	$	114.9		$	83.4
Unrealized foreign exchange loss on U.K. pound sterling denominated debt	2.9			9.4
Total unrealized foreign exchange loss from translation of foreign denominated debt	$	117.8		$	92.8
Unrealized gain on U.S. foreign exchange risk management contracts	$	(34.9	)	$	(21.0	)
Unrealized gain on U.K. foreign exchange risk management contracts	(3.9		)	(8.8		)
Total unrealized gain on foreign exchange risk management contracts	$	(38.8	)	$	(29.8	)
Total unrealized foreign exchange loss	$	79.0		$	63.0
Total realized foreign exchange (gain) loss	$	1.0		$	(1.1	)

19. COMMITMENTS

	2015		2016		2017		2018		2019		Thereafter		Total
Convertible debentures (1)	$	—	$	—	$	136.8	$	—	$	—	$	—	$	136.8
Interest payments on convertible debentures	8.6		8.6		2.1		—		—		—		19.3
Long term debt (2)	173.3		—		655.1		322.4		67.7		507.0		1,725.5
Interest payments on long term debt (3)	90.9		85.3		69.2		40.3		25.4		65.4		376.5
Operating leases (4)	13.1		12.8		12.0		10.9		9.5		51.9		110.2
Pipeline transportation	30.7		16.5		20.7		22.0		19.7		144.8		254.4
Other	17.9		2.9		0.7		0.7		0.3		11.0		33.5
	$	334.5	$	126.1	$	896.6	$	396.3	$	122.6	$	780.1	$	2,656.2

⁽¹⁾  Assumes no conversion of convertible debentures prior to maturity.

⁽²⁾  The debt repayment includes foreign denominated fixed rate debt translated using the year end exchange rate and excludes related foreign exchange risk management contracts.

⁽³⁾  Interest payments are calculated at period end exchange rates and interest rates except for fixed rate debt which is calculated at the actual interest rate.

⁽⁴⁾  Includes office rent, vehicle leases and other.

20. CONTINGENCIES

Pengrowth has been named as a defendant in various litigation matters. The nature of these claims is usually related to settlement of normal operational issues and labour issues. The outcome of such claims against Pengrowth is not determinable at this time; however, their ultimate resolution is not expected to have a materially adverse effect on Pengrowth as a whole.

21. SUPPLEMENTARY DISCLOSURES

CONSOLIDATED STATEMENTS OF INCOME (LOSS)

Pengrowth’s Consolidated Statements of Income (Loss) are prepared primarily by the nature of expense, with the exception of employee compensation costs which are included in both operating and general and administrative expense line items.

The following table details the amount of total employee compensation costs (including share based compensation expense) included in the operating and general and administrative expense line items in the Consolidated Statements of Income (Loss).

PENGROWTH 2014 Financial Results 38

	Year ended December 31
	2014		2013
Operating	$	44.7	$	50.5
General and administrative	62.9		66.5
Total employee compensation costs	$	107.6	$	117.0

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. Key management personnel at Pengrowth was composed of up to 9 non-executive directors and 14 officers during the year ended December 31, 2014 (December 31, 2013 - 9 non-executive directors and 14 officers).

Year ended December 31, 2014	Wages & benefits		Bonus and other compensation		Share based compensation expense		Severance		Total
Directors	$	0.7	$	—	$	0.5	$	—	$	1.2
Officers	4.8		3.7		6.5		0.5		15.5
	$	5.5	$	3.7	$	7.0	$	0.5	$	16.7
Year ended December 31, 2013	Wages & benefits		Bonus and other compensation		Share based compensation expense		Severance		Total
Directors	$	0.7	$	—	$	0.8	$	—	$	1.5
Officers	5.0		1.8		5.0		—		11.8
	$	5.7	$	1.8	$	5.8	$	—	$	13.3

PENGROWTH 2014 Financial Results 39

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 2014 and 2013 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, 2014, no major discovery or other favorable or adverse event is believed to have caused a material change in the estimates of proved or proved developed reserves as of that date.

1

COSTS INCURRED IN OIL AND GAS PROPERTY ACQUISITION, EXPLORATION AND DEVELOPMENT ACTIVITIES

Costs incurred in oil and gas producing activities for the years ended December 31 are as follows:

(millions of dollars)	2014		2013
Property acquisition costs
- Proved	$	17.0	$	16.0
- Unproved	—		—
Exploration costs	130.1		4.6
Development costs	980.5		438.9
Injectants costs	6.7		6.7
	$	1,134.3	$	466.2

Acquisition costs include costs incurred to purchase, lease, or otherwise acquire oil and gas properties.

Development and exploration costs include the costs for drilling and equipping development and exploratory wells, constructing facilities to extract, treat, gather and store oil and gas, and land rights purchases. These costs also include capitalized amounts associated with asset retirement obligations and capitalized interest.

Injectants (mostly ethane and methane) are used in miscible flood programs to stimulate incremental oil recovery. The cost of injectants purchased from third parties for miscible flood projects is deferred and amortized over the period of expected future economic benefit which is estimated to be 24 months.

Pengrowth capitalizes a portion of general and administrative costs associated with exploration and development activities.

Approximately $1,367 million (2013 – $819 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)	2014		2013
Oil and natural gas assets	$	4,772.2	$	4,802.3
Add: Exploration and evaluation assets	490.1		419.3
	$	5,262.3	$	5,221.6
Unproved oil and gas properties
Unproven properties included in oil and natural gas assets	$	1,408.3	$	1,123.2
Exploration and evaluation assets	490.1		419.3
	$	1,898.4	$	1,542.5
Proven oil & gas properties	3,363.9		3,679.1
Total capitalized costs	$	5,262.3	$	5,221.6

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 2012	108.7			11.8			18.0		510.2
Revisions of previous estimates (including infill drilling & improved recovery)	4.6			(0.1	)		2.9		107.8		a
Purchase of reserves in place	0.3			—			0.1		1.3
Sale of reserves in place	(28.7	)	b	—			(1.3	)	(60.4	)	b
Discoveries and extensions	2.8			58.1		c	0.5		8.3
Production	(9.8	)		(0.6	)		(2.8	)	(72.2	)
End of Year 2013	77.9			69.2			17.4		495.0
Revisions of previous estimates (including infill drilling & improved recovery)	0.4			(3.2	)		2.9		66.9		d
Purchase of reserves in place	0.5			—			0.1		0.8
Sale of reserves in place	(3.0	)		—			(0.1	)	(2.1	)
Discoveries and extensions	1.9			16.7		e	0.3		26.7		f
Production	(8.2	)		(0.6	)		(2.8	)	(62.0	)
End of Year 2014	69.5			82.1			17.8		525.3
Notes Re Significant Changes:
(a) Primarily due to the higher constant gas price used for reserve evaluation at December 31, 2013.
(b) Due to our non-core asset disposition program as described more fully under “Acquisitions and Divestitures” on page 20 of Exhibit 99.1, Pengrowth’s Annual Information Form, to our Form 40-F dated February 28, 2014.
(c) Entirely due to ongoing work at our Lindbergh oil sands development as described more fully under “Lindbergh Oil Sands Reserves and Contingent Resources” on pages 23 and 24 of Exhibit 99.1, Pengrowth’s Annual Information Form, to our Form 40-F dated February 28, 2014.
(d) Primarily due to the higher constant gas price used for reserve evaluation at December 31, 2014.
(e) Entirely due to ongoing work at our Lindbergh oil sands development as described more fully under “Lindbergh Oil Sands Reserves and Contingent Resources” on pages 23, 24 and 25 of Exhibit 99.1, Pengrowth’s Annual Information Form, to our Form 40-F dated February 26, 2015.
(f) Primarily due to the delineation and drilling in Groundbirch as described more fully under "Groundbirch Reserves and Contingent Resources" on pages 25, 26 and 27 of Exhibit 99.1, Pengrowth’s Annual Information Form, to our Form 40-F dated February 26, 2015.
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 2012	86.9			1.6			16.8		463.1
End of year 2013	60.7			1.2			16.4		430.7
End of year 2014	54.1			21.6			17.0		447.9
Net Proved Undeveloped Reserves After Royalty
End of year 2012	21.8			10.2			1.2		47.1
End of year 2013	17.2			68.0			1.0		64.3
End of year 2014	15.4			60.5			0.8		77.4

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 year ended December 31, 2014 and 2013.

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, 2014 and December 31, 2013. 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, 2014 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 $94.74/bbl (2013 - $93.12/bbl) and AECO natural gas price of $4.58/MMBtu (2013 - $3.15/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)	2014			2013
Future cash inflows	$	19,332		$	16,455
Future costs
- Future production costs	(10,087		)	(8,921		)
- Future developments costs	(1,662		)	(1,768		)
- Future income taxes	(874		)	(397		)
Future net cash flows	$	6,709		$	5,369
Deduct: 10% annual discount factor	(2,992		)	(2,417		)
Standardized measure of discounted future net cash flows	$	3,717		$	2,952

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)	2014			2013
Future discounted net cash flow at beginning of year	$	2,952		$	3,281
Sales & transfer, net of production costs	(680		)	(746		)
Net change in sales & transfer prices	901			436
Development costs incurred during the period	777			692
Change in future development costs	(479		)	(1,232		)
Change due to extensions and discoveries	360			778
Change due to revisions (including infill drilling & improved recovery)	(4		)	113
Accretion of discount	305			332
Sales of reserves in place	(42		)	(600		)
Purchase of reserves in place	11			8
Net change in income taxes	(152		)	(55		)
Changes in timing of future net cash flow and other	(232		)	(55		)
Future discounted net cash flow at end of year	$	3,717		$	2,952

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, 2014 and 2013. 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.

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, 2014.

	Development		Exploration		Total
Wells	Gross	Net	Gross	Net	Gross	Net
Natural Gas	8	5.2	—	—	8	5.2
Crude Oil	92	56.8	2	0.5	94	57.3
Bitumen	13	13.0	—	—	13	13.0
Service	30	29.8	—	—	30	29.8
Stratigraphic Test	39	39.0	—	—	39	39.0
Dry	1	0.8	—	—	1	0.8
Total	183	144.6	2	0.5	185	145.1

The following table summarizes the number of wells drilled during the financial year ended December 31, 2013.

	Development		Exploration		Total
Wells	Gross	Net	Gross	Net	Gross	Net
Natural Gas	6	3.3	—	—	6	3.3
Crude Oil	119	70.1	2	0.3	121	70.4
Bitumen	7	7.0	—	—	7	7.0
Service	18	12.4	—	—	18	12.4
Stratigraphic Test	20	19.5	—	—	20	19.5
Dry	3	2.8	—	—	3	2.8
Total	173	115.1	2	0.3	175	115.4

The following table summarizes the number of wells drilled during the financial year ended December 31, 2012.

	Development		Exploration		Total
Wells	Gross	Net	Gross	Net	Gross	Net
Natural Gas	12	9.6	1	—	13	9.6
Crude Oil	114	48.9	4	2.3	118	51.2
Bitumen	—	—	—	—	—	—
Service	24	7.1	—	—	24	7.1
Stratigraphic Test	22	22.0	1	1.0	23	23.0
Dry	1	1.0	4	1.4	5	2.4
Total	173	88.6	10	4.7	183	93.3

8

Oil and Gas Wells

As at December 31, 2014, we had an interest in 7,564 gross (4,047 net) producing oil and natural gas wells and 3,649 gross (2,140 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	2,148	1,324	1,140	618	3,288	1,942
British Columbia	83	52	176	110	259	162
Saskatchewan	161	64	209	155	370	219
Bitumen Wells
Alberta	2	2	20	20	22	22
Natural Gas Wells
Alberta	4,948	2,467	1,016	587	5,964	3,054
British Columbia	173	106	198	108	371	214
Saskatchewan	32	30	35	25	67	55
Nova Scotia	17	2	2	—	19	2
Other
Alberta	—	—	590	360	590	360
British Columbia	—	—	158	104	158	104
Saskatchewan	—	—	105	53	105	53
Total	7,564	4,047	3,649	2,140	11,213	6,187

9

EX-99.5

KPMGLLP
Chartered Accountants	Telephone (403) 691-8000
3100 205 - 5th Avenue SW	Telefax (403) 691-8008
Calgary AB T2P 4B9	Internet www.kpmg.ca

Consent of Independent Registered Public Accounting Firm

The Board of Directors of Pengrowth Energy Corporation

We consent to the use of our reports, each dated February 26, 2015, 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 Statement (No. 333-180888) on Form F-3 of Pengrowth Energy Corporation.

Chartered Accountants

Calgary, Canada

February 26, 2015

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

GLJ Petroleum Consultants Principal Officers: Keith M. Braaten, P. Eng. President & CEO Jodi L. Anhorn, P. Eng.     Executive Vice President & COO Officers / Vice Presidents: Caralyn P. Bennett, P. Eng. Tim R. Freeborn, P.Eng. Leonard L. Herchen, P. Eng. Myron J. Hladyshevsky, P. Eng. Todd J. Ikeda, P. Eng. Bryan M. Joa, P. Eng. Mark Jobin, P. Geol. John E. Keith, P. Eng.

LETTER OF CONSENT

TO: Pengrowth Energy Corporation

2100, 222-3 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, 2014 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, 2014 and (ii) the Registration Statement on Form F-3 (File No. 333-180888) filed with the United States Securities and Exchange Commission pursuant to the Securities Exchange Act of 1934, as amended, or the Securities Act of 1933, as amended, as applicable.

Yours truly,

GLJ PETROLEUM CONSULTANTS LTD.

/s/ "Todd J. Ikeda"

Todd J. Ikeda, P. Eng

Vice President

Calgary, Alberta

February 26, 2015

4100, 400 - 3rd Avenue S.W., Calgary, Alberta, Canada T2P 4H2 • (403) 266-9500 • Fax (403) 262-1855 • 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, 2014, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Derek W. Evans, President and Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:

1. The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Dated: February 26, 2015

/s/ Derek W. Evans

Name: Derek W. Evans

Title: President and Chief Executive Officer

EX-99.8

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED

PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Pengrowth Energy Corporation (the “Company”) on Form 40-F for the fiscal year ended December 31, 2014, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Christopher G. Webster, Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:

1.	The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
2.	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Dated: February 26, 2015

/s/ Christopher G. Webster

Name: Christopher G. Webster

Title: Chief Financial Officer

EX-99.9

CERTIFICATION PURSUANT TO RULE 13a-14 OR 15d-14 OF THE

SECURITIES EXCHANGE ACT OF 1934, AS ADOPTED PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Derek W. Evans, certify that:

1.	I have reviewed this annual report on Form 40-F of Pengrowth Energy Corporation;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the issuer as of, and for, the periods presented in this report;
4.	The issuer’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the issuer and have:

(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
(c)	Evaluated the effectiveness of the issuer’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d)	Disclosed in this report any change in the issuer’s internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the issuer’s internal control over financial reporting; and

5. The issuer’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the issuer’s auditors and the audit committee of the issuer’s board of directors (or persons performing the equivalent functions):

(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the issuer’s ability to record, process, summarize and report financial information; and
(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the issuer’s internal control over financial reporting.

Dated: February 26, 2015

/s/ Derek W. Evans

Name: Derek W. Evans

Title: President and Chief Executive Officer

EX-99.10

CERTIFICATION PURSUANT TO RULE 13a-14 OR 15d-14 OF THE

SECURITIES EXCHANGE ACT OF 1934, AS ADOPTED PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Christopher G. Webster, certify that:

1.	I have reviewed this annual report on Form 40-F of Pengrowth Energy Corporation;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the issuer as of, and for, the periods presented in this report;
4.	The issuer’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the issuer and have:

	(a)		Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
	(b)		Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
	(c)		Evaluated the effectiveness of the issuer’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
	(d)		Disclosed in this report any change in the issuer’s internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the issuer’s internal control over financial reporting; and
5.		The issuer’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the issuer’s auditors and the audit committee of the issuer’s board of directors (or persons performing the equivalent functions):

(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the issuer’s ability to record, process, summarize and report financial information; and
(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the issuer’s internal control over financial reporting.

Dated: February 26, 2015

/s/ Christopher G. Webster

Name: Christopher G. Webster

Title: Chief Financial Officer