Edgar Filing: PENGROWTH ENERGY Corp

Date: February 28, 2013

PENGROWTH ENERGY CORPORATION

/s/ Derek W. Evans

Derek W. Evans

President and Chief Executive Officer

Form 40-F

U.S. SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 40-F

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

x	ANNUAL REPORT PURSUANT TO SECTION 13(a) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended: December 31, 2012 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:

x Annual information form x 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 511,804,194 Common Shares, of no par value, outstanding as of December 31, 2012.

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 x No ¨

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 ¨ No ¨

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.

DOCUMENTS FILED AS PART OF THIS ANNUAL REPORT

The following documents have been filed as part of this Annual Report on Form 40-F as Appendices hereto:


Appendix		Documents

A		Pengrowth Energy Corporation Annual Information Form for the year ended December 31, 2012.

B		Management’s Discussion and Analysis.

C		Financial Statements of Pengrowth Energy Corporation, including Management’s Report to Shareholders and the Auditors’ Reports.

D		Supplemental Unaudited Disclosures about Oil and Gas Producing Activities required under United States Generally Accepted Accounting Principles.

E		Pengrowth Energy Corporation Code of Business Conduct and Ethics dated November 1, 2012.

CERTIFICATIONS AND DISCLOSURE REGARDING CONTROLS AND PROCEDURES

Certifications. See Exhibits 99.3, 99.4, 99.5 and 99.6 to this Annual Report on Form 40-F.

Disclosure Controls and Procedures. The required disclosure is included in the section entitled “Disclosure Controls and Procedures” contained in the Registrant’s Management’s Discussion and Analysis for the fiscal year ended December 31, 2012, 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, 2012, 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, 2012, 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, 2012, 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: Thomas A. Cumming, James D. McFarland, Michael S. Parrett and A. Terence Poole.

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.

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 60 of the Registrant’s Annual Information Form for the fiscal year ended December 31, 2012, filed as part of this Annual Report on Form 40-F in Appendix A.

Pre-Approval Policies and Procedures.

The required disclosure is included under the heading “Pre-approval Policies and Procedures” at page 61 of the Registrant’s Annual Information Form for the fiscal year ended December 31, 2012, filed as part of this Annual Report on Form 40-F in Appendix A.

Off-Balance Sheet Arrangements.

The required disclosure is included under the heading “Off-Balance Sheet Arrangements” at page 63 of the Registrant’s Annual Information Form for the fiscal year ended December 31, 2012, filed as part of this Annual Report on Form 40-F in Appendix A.

Tabular Disclosure of Contractual Obligations.

The required disclosure is included under the heading [“Contractual Obligations and Contingencies”] at page 32 of the Registrant’s Management’s Discussion and Analysis for the fiscal year ended December 31, 2012, filed as part of this Annual Report on Form 40-F in Appendix B.

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.

APPENDIX A

PENGROWTH ENERGY CORPORATION ANNUAL INFORMATION FORM FOR THE YEAR

ENDED DECEMBER 31, 2012

LOGO

PENGROWTH ENERGY CORPORATION

ANNUAL INFORMATION FORM

For the year ended December 31, 2012

February 28, 2013

TABLE OF CONTENTS


GLOSSARY OF TERMS AND ABBREVIATIONS			1
CONVERSION			4
PRESENTATION OF OUR FINANCIAL INFORMATION			5
PRESENTATION OF OUR RESERVE 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			11
Additional Information Relating to Reserves Data			20
Future Development Costs			21
Finding, Development and Acquisition Costs			22
Recycle Ratio			24
Reserve Life Index (RLI)			24
Reserve Replacement			25
Other Oil and Gas Information			25
Forward Contracts			29
Additional Information Concerning Abandonment & Reclamation Costs			29
Tax Horizon			29
Costs Incurred			30
Exploration and Development Activities			30
Production Estimates			30
Production History (Netback)			30
DESCRIPTION OF CAPITAL STRUCTURE			31
General			31
DIVIDENDS			32
General			32
Historical Distributions/Dividends			32
Restrictions on Dividends			33
ABCA Solvency Tests			33
Revolving Credit Facility			33
Senior Unsecured Notes			34
INDUSTRY CONDITIONS			35
General Discussion			44
RISK FACTORS			44
MARKET FOR SECURITIES			56
DIRECTORS AND OFFICERS			57
Corporate Cease Trade Orders, Bankruptcies, Personal Bankruptcies, Penalties or Sanctions			59
AUDIT AND RISK COMMITTEE			60
Principal Accountant Fees and Services			60
Pre-approval Policies and Procedures			61


CONFLICTS OF INTEREST			61
LEGAL PROCEEDINGS			61
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS			62
INTERESTS OF EXPERTS			62
AUDITORS, TRANSFER AGENT AND REGISTRAR			62
MATERIAL CONTRACTS			62
CODE OF ETHICS			62
OFF-BALANCE SHEET ARRANGEMENTS			63
DISCLOSURE PURSUANT TO THE REQUIREMENTS OF THE NEW YORK STOCK EXCHANGE			63
ADDITIONAL INFORMATION			63

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, 2012.

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 $19.186 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;

“2003 Note Purchase Agreements” means, collectively, the separate and several note purchase agreements each dated April 23, 2003 among us and the purchasers listed therein, as amended;

“2003 US Senior Notes” means the senior unsecured notes issued under the 2003 Note Purchase Agreements;

“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, 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;

“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 ten financial institutions;

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

“NAL Acquisition” means the acquisition of all of the issued and outstanding shares of NAL Energy by the Corporation which was completed on May 31, 2012;

“NAL Energy” means NAL Energy Corporation;

PENGROWTH ENERGY CORPORATION ANNUAL INFORMATION FORM | 1

“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;

“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

“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 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 report prepared by GLJ, dated February 27, 2013 with an effective date of December 31, 2012;

“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. It is unlikely that the actual remaining quantities recovered will exceed the sum of the estimated 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;

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“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;

“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;

“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;

“EOR” refers to enhanced oil recovery;

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

“F&D Costs” refers to finding and development costs;

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

“GHG” refers to greenhouse gas;

“IFRS” refers to International Financial Reporting Standards;

PENGROWTH ENERGY CORPORATION ANNUAL INFORMATION FORM | 3

“MMBtu” refers to million British thermal units;

“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;

“NGL” refers to natural gas liquids;

“NYSE” refers to the New York Stock Exchange;

“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;

“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 conversation 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

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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 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: benefits and synergies resulting from our corporate and asset acquisitions, 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 2013 development program, dispositions and rationalization plans, 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, the impact of proposed changes to Canadian tax legislation or US tax legislation, abandonment and reclamation costs, government royalty rates (including estimated increase in royalties paid and estimated decline in net present value of reserves and 2013 cash flows) 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,

PENGROWTH ENERGY CORPORATION ANNUAL INFORMATION FORM | 5

objectives, expectations and anticipations, estimates and intentions expressed in such forward-looking statements. These factors include, but are not limited to: the volatility of oil and gas prices; production and development costs and capital expenditures; the imprecision of reserve estimates and estimates of recoverable quantities of oil, natural gas and liquids; unforeseen operating problems; pipeline or delivery constraints; our ability to replace and expand oil and gas reserves; environmental claims and liabilities; incorrect assessments of value when making acquisitions; increases in debt service charges; the loss of key personnel; the marketability of production; defaults by third party operators; unforeseen title defects; fluctuations in foreign currency and exchange rates; inadequate insurance coverage; counterparty risk; compliance with environmental laws and regulations; changes in tax and royalty laws; our ability to access external sources of debt and equity capital; and the implementation of GHG emissions legislation. Further information regarding these factors may be found under the heading “Risk Factors” in this Annual Information Form, under the heading “Business Risks” in our Management’s Discussion and Analysis for the year ended December 31, 2012, and in our most recent consolidated financial statements, management information circular, quarterly reports, material change reports and news releases.

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

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PENGROWTH 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, Ontario 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. Pursuant to the Arrangement, on December 31, 2010, Unitholders of the Trust exchanged their Trust Units for Common Shares on a one for one (1:1) basis. At the same time, holders of Exchangeable Shares received 1.02308 Common Shares for each Exchangeable Share held. See “General Development of the Business of the Corporation – Recent Developments”.

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 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 reflects plans to spend up to $770 million in 2013 including $300 million at Lindbergh. The budget also contemplates up to $700 million of asset dispositions in addition to the Weyburn disposition.

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

Three Year Historical Overview

2012

On December 21, 2012, we announced the sale of our 10.01952 percent interest in the Weyburn property to OMERS Energy Inc. and Ontario Teachers’ Pension Plan for total gross proceeds of $315 million. This sale is expected to close in early March 2013 and the effective date of the disposition is 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 August 2, 2012, we released a reserve update with respect to our Lindbergh property reflecting a significant increase in P+P reserves.

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 will focus on oil and liquids-rich gas opportunities.

2011

On November 29, 2011, we amended our Credit Facility and extended the term to November 29, 2015.

On November 16, 2011, we completed a bought deal public offering of Common Shares at $10.60 per share for total gross proceeds of approximately $300 million.

PENGROWTH ENERGY CORPORATION ANNUAL INFORMATION FORM | 7

On November 3, 2011, we announced a $60 million increase in our 2011 capital program to $610 million.

On August 8, 2011, Marlon McDougall was appointed Chief Operating Officer of the Corporation.

On May 5, 2011, we announced the expansion of our capital program to $550 million for 2011.

On January 1, 2011, the Corporation completed the Arrangement, pursuant to which the Trust converted into a corporate structure.

2010

On November 9, 2010, we released the details of our $400 million 2011 capital expenditure program and provided guidance on production and operating costs for 2011.

On September 15, 2010, the Trust completed the acquisition of Monterey Exploration Ltd. (“Monterey”) for total consideration of approximately $445 million (including $82 million for shares already owned), comprised of 27,967,959 Trust Units, 4,994,426 Exchangeable Shares and $41.8 million of assumed debt. No business acquisition report (Form 51-102F4) was required or filed in respect of this acquisition.

On May 11, 2010, Pengrowth Corporation issued the 2010 Senior Notes. The notes were issued in two series; US$71.5 million of 4.67 percent notes due in 2015 and US$115.5 million of 5.98 percent notes due in 2020.

On January 14, 2010, certain outstanding debentures were redeemed at a cash redemption price of $1,025 per $1,000 principal value for a total cost of $76,609,525, plus accrued and unpaid interest to the redemption date. The cash redemption amount was funded with incremental borrowings from the Credit Facility.

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, Ontario 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, 2012, we had 641 permanent employees.

Business Strategy

Our corporate strategy is to use funds flow from our existing conventional operations to sustain our current dividend and to fund a portfolio of oil assets with low declines and long reserve lives aimed at supporting production growth and long-term stable dividend payout. Our plan is to rationalize our asset base over the coming year and to dispose of up to $700 million of non-core assets (in addition to the disposition of our Weyburn interest which is expected to be sold in early March 2013 for gross proceeds of $315 million).

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 a 50,000 bbl/d of bitumen commercial project as well as our light oil and liquids-rich gas properties at Swan Hills and in the Greater Olds/Garrington area. See additional details on these properties under “Operational Information – Principal Producing Properties” below.

For 2013, we have established a $770 million capital spending level that retains significant flexibility in an uncertain commodity price environment. Included in this budget is $300 million for expenditures related to the first commercial phase of our Lindbergh project which is anticipated to produce 12,500 bbl/d of bitumen commencing in early 2015. 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.

8 | ANNUAL INFORMATION FORM

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 clean-up, abandonment and site reclamation activities.

OPERATIONAL INFORMATION

Principal Producing Properties

The following table summarizes our principal producing properties as of December 31, 2012 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, 2012. The table also contains our average daily production of oil, natural gas and NGL for the year ended December 31, 2012.

Summary of Company Interest

at December 31, 2012⁽¹⁾

(Forecast Prices and Costs)⁽²⁾


Field	P+P Reserves Mboe⁽³⁾		Remaining Reserve Life years		P+P Reserve Life Index years		P+P Value Before Tax at 10% DR⁽⁴⁾ $MM		2012 Oil Production bbl/d		2012 Gas Production MMcf/d		2012 NGL Production bbl/d		2012 Total Production BOE/d⁽³⁾
Lindbergh⁽⁵⁾		94,791		27		209.4		646		891		—		—		891
Swan Hills Area		86,513		50		12.6		1,528		12,229		19.4		4,421		19,881
Greater Olds/Garrington Area⁽⁶⁾		63,665		50		10.0		783		2,432		40.8		2,782		12,022
Southeast Saskatchewan⁽⁶⁾⁽⁷⁾		43,636		50		13.5		862		6,041		1.7		82		6,404

Subtotal		288,605		50		17.1		3,818		21,593		61.9		7,285		39,198
Remainder⁽⁸⁾		223,354		50		12.4		2,270		13,817		181.1		3,446		47,442

Total		511,960		50		14.7		6,088		35,410		243.0		10,731		86,640

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)

The Lindbergh pilot project commenced production on June 1, 2012. From June 1, 2012 to December 31, 2012, Lindbergh pilot production averaged 1,330 bbl/d of bitumen. This production is not included in corporate production numbers but is utilized in all reserve reporting in this Annual Information Form. As of January 1, 2013, Lindbergh production will be reflected in corporate production volumes.

(6)

Includes properties acquired in connection with the NAL Acquisition on May 31, 2012. For Greater Olds/Garrington, annualized NAL production of 3,740 BOE/d is included in the total. For Southeast Saskatchewan, annualized NAL production of 3,642 BOE/d is included in the total. For these properties, 2012 production was based on seven months average production of 6,430 BOE/d (in Greater Olds/Garrington) and 6,265 BOE/d (in Southeast Saskatchewan) averaged over the year.

(7)	Includes our ownership in the Weyburn Unit which is expected to be sold in early March 2013 and contributed 2,533 BOE/d to the 2012 production.

(8)	“Remainder” includes our Working Interests and Royalty Interests in approximately 150 other properties.

Lindbergh

The Lindbergh property is located approximately 420 kilometres northeast of Calgary and 50 kilometres south of Bonnyville. We have a 100% Working Interest in the Lindbergh oil sands leases, located in the Cold Lake oil sands district in north-eastern Alberta and covering 27,200 net acres (42.5 sections). Our Lindbergh thermal project includes our Muriel Lake lands which are about eight kilometers to the northeast of the Lindbergh lease.

We began steam injection into the pilot project in early February 2012 and results outperformed expectations during the year. The pilot, which consists of two well pairs, has been producing for over 10 months and is currently producing in excess of 1,600 bbl/d of bitumen, with an ISOR of 1.7. The well pairs had each produced approximately 163,000 bbls of bitumen as of December 31, 2012.

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 expected to reach 12,500 bbl/d of bitumen by early 2015. Two additional expansion phases are expected to increase total Lindbergh production to 50,000 bbl/d of bitumen by 2018.

PENGROWTH ENERGY CORPORATION ANNUAL INFORMATION FORM | 9

For additional information, see “Lindbergh Oil Sands Reserves and Contingent Resources” on page 26 of this annual information form.

Swan Hills Area

We have varied Working Interests within the Swan Hills area in all of the key properties throughout this significant regional 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, Virginia Hills and Freeman. The properties are primarily located approximately 160 – 240 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 an 89.1 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 2012, $171 million (net) was spent on light oil and liquids-rich gas plays in this area. In addition to ongoing miscible flood development and waterflood optimization, we drilled a total of 24 operated horizontal wells (22.7 net) at Judy Creek, Deer Mountain, Virginia Hills and Carson Creek, primarily in the tighter platform and R5 shoal. Multi-stage fracture treatments were used in the completion of these wells. Drilling also occurred in the partner-operated properties where we participated in 9 oil wells (1.6 net) at House Mountain and Freeman.

After very high levels of drilling activity in the area over the past several years, we will now shift to a more balanced mix of drilling, waterflood, miscible flood, and well optimization (re-entries, recompletions, workovers) across the properties.

Greater Olds/Garrington Area

Our Olds property is located 95 kilometres north of Calgary, Alberta. Our interests in this area include a 100 percent ownership in the Olds Gas Field Unit No. 1. In addition, we have a 74 percent average Working Interest in the adjacent non-unit reserves. The Olds unit 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.

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

The Harmattan gas field, within the Olds area, is located approximately 90 kilometres northwest of Calgary, Alberta. It is comprised of wells and pools in formations from the Cardium to the Wabumun, 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.

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

On May 31, 2012, Pengrowth acquired 149.5 net sections of land with multi-zone potential in the Cochrane to Sylvan Lake corridor pursuant to the NAL Acquisition. The primary target on these lands is the Cardium formation which produces light oil and Pengrowth estimates that there are more than 195 net drilling locations on these lands. Other zones of interest include the liquids-rich Mannville and Elkton formations.

In 2012, we spent $95 million in the Olds/Garrington area on activities targeting the Elkton, Mannville and Cardium plays, drilling 35 gross wells (17.8 net) during the year.

10 | ANNUAL INFORMATION FORM

Southeast Saskatchewan

Our southeast Saskatchewan area is located 200 kilometres southeast of Regina, Saskatchewan. Our interests include primarily 50 percent ownership in various non-operated fields which include Alida, Nottingham, Rosebank, Star Valley, Midale, Elswick, Steelman and Hoffer. Pengrowth also has 100 percent ownership in the operated Willmar field. The southeast Saskatchewan area produces sour medium/light oil (28° to 40° API) primarily from the Mississippian formations (Frobisher, Midale, Ratcliffe, and Oungre zones) with H₂S concentrations ranging from 1.5 percent to 8 percent. Solution gas is conserved in most fields.

Although Mississippian production is considered to be relatively mature, there are plans for further infill drilling in the Frobisher, Midale and Oungre zones and waterflood optimization potential in the Midale zone in various fields.

Approximately $19 million of capital has been allocated to the southeast Saskatchewan area in 2013 to drill up to 21 wells (13 net) targeting the Mississippian formations.

The Weyburn Unit is located in southeastern Saskatchewan. At December 31, 2012, we held a 10.01952 percent Working Interest in this unit which is operated by a senior producer. We expect to dispose of our interest in Weyburn in early March 2013 with an effective date of January 1, 2013. The unit produces medium sour crude oil (25° to 34° API) from the Midale carbonate reservoir under waterflood and CO₂ EOR miscible flood. The field consists of approximately 600 production wells and 330 injection wells currently producing approximately 2,500 BOE/d (net) to Pengrowth. The reserves data below includes reserves attributed to Weyburn.

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, 2012 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, 2012 and the preparation date is January 18, 2013 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 conventional 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, Ontario 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, 2012 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.

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, 2012.

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;

PENGROWTH ENERGY CORPORATION ANNUAL INFORMATION FORM | 11

•

Interest expense at the current rate;

•

Tax pool deductions utilizing our existing $4.5 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.

Reserves Data (Forecast Prices and Costs)

Summary of Oil and Gas Reserves

as of December 31, 2012

(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		85,484		85,249		70,130		15,486		15,477		13,483		1,653		1,653		1,557		25,749		25,709		18,743
Proved Developed Non-Producing		2,333		2,331		1,805		78		78		62		—		—		—		845		838		638
Proved Undeveloped		20,025		20,019		16,588		6,122		6,120		5,132		11,136		11,136		9,389		1,831		1,831		1,490

Total Proved Reserves		107,841		107,598		88,522		21,687		21,676		18,676		12,789		12,789		10,946		28,425		28,378		20,871
Probable Reserves		45,388		45,330		36,623		10,975		10,971		9,329		82,003		82,003		64,326		11,256		11,241		8,398

Total Proved Plus Probable Reserves		153,229		152,928		125,145		32,662		32,646		28,005		94,792		94,792		75,272		39,681		39,619		29,269


	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		632,064		629,478		545,098		23,808		23,522		22,020		237,685		236,922		198,432
Proved Developed Non-Producing		21,127		20,908		16,766		642		642		610		6,883		6,838		5,401
Proved Undeveloped		76,112		76,111		67,765		22,269		22,200		19,143		55,510		55,491		47,083

Total Proved Reserves		729,303		726,497		629,629		46,719		46,364		41,773		300,078		299,251		250,916
Probable Reserves		360,932		360,126		312,631		12,627		12,537		11,257		211,882		211,655		172,657

Total Proved Plus Probable Reserves		1,090,235		1,086,623		942,260		59,346		58,901		53,030		511,960		510,906		423,573

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.

12 | ANNUAL INFORMATION FORM

Summary of Net Present Value

of Future Net Revenue

as of December 31, 2012

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		6,143		4,610		3,704		3,110		2,693		18.66		3.11
Proved Developed Non-Producing		208		125		86		64		50		15.87		2.65
Proved Undeveloped		1,521		793		465		284		172		9.88		1.65

Total Proved Reserves		7,872		5,528		4,255		3,458		2,916		16.96		2.83
Probable Reserves		6,059		3,175		1,834		1,127		717		10.62		1.77

Total Proved Plus Probable Reserves		13,931		8,703		6,088		4,586		3,632		14.37		2.40


	After Income Taxes Discounted at (%/year)⁽⁴⁾- $MM
Reserves Category	0%		5%		10%		15%		20%
Proved Reserves
Proved Developed Producing		5,792		4,436		3,610		3,057		2,662
Proved Developed Non-Producing		153		95		67		52		42
Proved Undeveloped		1,103		574		334		199		115

Total Proved Reserves		7,047		5,104		4,012		3,309		2,819
Probable Reserves		4,471		2,326		1,326		798		489

Total Proved Plus Probable Reserves		11,519		7,430		5,337		4,107		3,308

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 has been converted to thousand cubic feet of natural gas equivalent on the basis of one barrel of oil 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.

PENGROWTH ENERGY CORPORATION ANNUAL INFORMATION FORM | 13

Additional Information Concerning Future Net Revenue

(undiscounted)

as of December 31, 2012

(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		19,950		3,473		7,032		1,194		379		7,872		825		7,047
Total Proved Plus Probable		35,253		6,505		11,344		3,022		451		13,931		2,412		11,519

Notes:

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

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

(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, 2012

(Forecast Prices and Costs)⁽¹⁾


		Future Net Revenue Before Income Taxes		Unit Value⁽⁴⁾⁽⁵⁾
Reserves Category	Production Group	(discounted at 10%/year) ($MM)		($/BOE)		($/McfGE)
Total Proved	Light and Medium Crude Oil (including solution gas and other by-products)⁽²⁾		2,545		23.09		3.85
	Heavy Oil (including solution gas and other by-products)⁽²⁾		449		24.27		4.05
	Natural Gas (including by-products but excluding solution gas from oil wells)⁽³⁾		1,106		10.77		1.80
	Non-conventional Oil & Gas Activities		154		7.90		1.32

	Total		4,255		16.96		2.83
Total Proved Plus Probable	Light and Medium Crude Oil (including solution gas and other by-products)⁽²⁾		3,289		21.33		3.56
	Heavy Oil (including solution gas and other by-products)⁽²⁾		568		23.69		3.95
	Natural Gas (including by-products but excluding solution gas from oil wells)⁽³⁾		1,448		9.32		1.55
	Non-conventional Oil & Gas Activities		783		8.70		1.45

	Total		6,088		14.37		2.40

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 has been converted to thousand cubic feet of natural gas equivalent on the basis of one barrel of oil being equal to six (6) Mcf of natural gas.

14 | ANNUAL INFORMATION FORM

Reserves Data (Constant Prices and Costs)

Summary of Oil And Gas Reserves

as of December 31, 2012

(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		85,304		85,073		71,417		15,469		15,460		13,582		1,653		1,653		1,556		21,863		21,830		16,219
Proved Developed Non-Producing		2,330		2,328		1,820		78		78		63		—		—		—		798		792		613
Proved Undeveloped		20,049		20,043		16,884		6,122		6,120		5,173		11,136		11,136		10,102		1,413		1,413		1,157

Total Proved Reserves		107,683		107,444		90,121		21,669		21,658		18,818		12,789		12,789		11,658		24,074		24,035		17,990
Probable Reserves		45,601		45,545		38,146		11,003		10,999		9,487		82,003		82,003		67,144		9,086		9,074		6,837

Total Proved Plus Probable Reserves		153,284		152,989		128,267		32,672		32,657		28,306		94,792		94,792		78,801		33,160		33,110		24,827


	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		489,544		487,856		438,284		12,991		12,838		12,024		208,045		207,466		177,825
Proved Developed Non-Producing		15,414		15,256		12,577		261		261		248		5,818		5,784		4,634
Proved Undeveloped		48,096		48,095		45,802		1,350		1,350		1,282		46,961		46,953		41,163

Total Proved Reserves		553,053		551,207		496,662		14,601		14,449		13,554		260,824		260,203		223,623
Probable Reserves		222,963		222,457		203,490		4,901		4,853		4,584		185,670		185,506		156,292

Total Proved Plus Probable Reserves		776,016		773,664		700,152		19,502		19,302		18,138		446,494		445,709		379,916

Notes:

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

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

PENGROWTH ENERGY CORPORATION ANNUAL INFORMATION FORM | 15

Summary of Net Present Value

of Future Net Revenue

as of December 31, 2012

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		4,586		3,554		2,920		2,495		2,189		16.42		2.74
Proved Developed Non-Producing		144		90		63		48		38		13.67		2.28
Proved Undeveloped		1,054		573		338		204		119		8.22		1.37

Total Proved Reserves		5,784		4,217		3,322		2,746		2,346		14.86		2.48
Probable Reserves		4,100		2,201		1,282		783		485		8.21		1.37

Total Proved Plus Probable Reserves		9,884		6,418		4,604		3,529		2,831		12.12		2.02


	After Income Taxes Discounted At (%/year)⁽⁴⁾- $MM
Reserves Category	0%		5%		10%		15%		20%
Proved Reserves
Proved Developed Producing		4,586		3,554		2,920		2,495		2,189
Proved Developed Non-Producing		33		37		35		31		28
Proved Undeveloped		974		542		325		198		116

Total Proved Reserves		5,593		4,133		3,281		2,724		2,333
Probable Reserves		3,027		1,707		995		594		353

Total Proved Plus Probable Reserves		8,620		5,840		4,276		3,318		2,686

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 has been converted to thousand cubic feet of natural gas equivalent on the basis of one barrel of oil being equal to six (6) Mcf of natural gas.

(4)

16 | ANNUAL INFORMATION FORM

Additional Information Concerning

Future Net Revenue

(undiscounted)

as of December 31, 2012

(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		14,527		2,327		5,191		936		289		5,784		191		5,593
Total Proved Plus Probable		24,953		4,125		8,204		2,422		318		9,884		1,264		8,620

Notes:

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

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

(3)

Net Present Value of Future Net Revenue

By Production Group

as of December 31, 2012

(Constant Prices and Costs)⁽¹⁾


		Future Net Revenue Before Income Taxes		Unit Value⁽⁴⁾⁽⁵⁾
Reserves Category	Production Group	(discounted at 10%/year) ($MM)		($/BOE)		($/McfGE)
Total Proved	Light and Medium Crude Oil (including solution gas and other by-products)⁽²⁾		2,280		20.53		3.42
	Heavy Crude Oil (including solution gas and other by-products)⁽²⁾		419		22.54		3.76
	Natural Gas (including by-products but excluding solution gas from oil wells)⁽³⁾		520		6.63		1.10
	Non-conventional Oil & Gas Activities		103		6.63		1.11

	Total		3,322		14.86		2.48
Total Proved Plus Probable	Light and Medium Crude Oil (including solution gas and other by-products)⁽²⁾		2,900		18.56		3.09
	Heavy Crude Oil (including solution gas and other by-products)⁽²⁾		523		21.63		3.60
	Natural Gas (including by-products but excluding solution gas from oil wells)⁽³⁾		645		5.77		0.96
	Non-conventional Oil & Gas Activities		537		6.11		1.02

	Total		4,604		12.12		2.02

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 has been converted to thousand cubic feet of natural gas equivalent on the basis of one barrel of oil being equal to six (6) Mcf of natural gas.

PENGROWTH ENERGY CORPORATION ANNUAL INFORMATION FORM | 17

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, 2013 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 29.3° 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$/Cdn$)
2012⁽⁴⁾		94.10		86.86		81.56		73.29		63.80		58.68		2.45		28.97		66.23		101.06		1.6		1.00
2013		90.00		85.00		79.90		70.13		60.92		59.97		3.38		34.06		65.45		96.63		2.0		1.00
2014		92.50		91.50		84.18		76.15		68.36		64.70		3.83		45.75		70.46		97.91		2.0		1.00
2015		95.00		94.00		86.48		78.22		71.10		64.74		4.28		56.40		72.38		97.76		2.0		1.00
2016		97.50		96.50		88.78		80.29		73.02		66.62		4.72		57.90		74.31		100.36		2.0		1.00
2017		97.50		96.50		88.78		80.29		73.02		66.62		4.95		57.90		74.31		100.36		2.0		1.00
2018		97.50		96.50		88.78		80.29		73.02		66.62		5.22		57.90		74.31		100.36		2.0		1.00
2019		98.54		97.54		89.74		81.16		73.81		67.42		5.32		58.52		75.11		101.44		2.0		1.00
2020		100.51		99.51		91.55		82.79		75.32		68.90		5.43		59.71		76.62		103.49		2.0		1.00
2021		102.52		101.52		93.40		84.46		76.87		70.42		5.54		60.91		78.17		105.58		2.0		1.00
2022		104.57		103.57		95.28		86.16		78.44		71.97		5.64		62.14		79.75		107.71		2.0		1.00
thereafter		+2%/yr		+2%/yr		+2%/yr		+2%/yr		+2%/yr		+2%/yr		+2%/yr		+2%/yr		+2%/yr		+2%/yr		2.0		1.00

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 2012.

(5)	Lindberg 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 2012 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
29.3° API

WCS
Stream
Quality

Hardisty
Heavy
12° API

AECO Gas
Price

Propane

Butane

Pentanes
Plus

Inflation
Rate

Exchange
Rate⁽²⁾

Year

(US$/bbl)

(Cdn$/bbl)

(Cdn$/MMBtu)

(Cdn$/bbl)

(%/year)

(US$/Cdn$)

2013 and thereafter

94.57

87.85

83.76

74.27

65.18

2.33

30.29

65.96

101.09

0.0

1.0002

Notes:

(1)	FOB Edmonton.

(2)	The exchange rate used to generate the benchmark reference prices in this table.

18 | ANNUAL INFORMATION FORM

Reserves Reconciliation

The following tables provide a reconciliation of our gross reserves of crude oil, natural gas and NGL for the year ended December 31, 2012, 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, 2011		85,291			31,331			116,622			19,672			5,872			25,544			4,436			1,912		6,348			22,479			8,225			30,704

Technical Revisions		1,659			(594	)		1,064			728			(131	)		597			1			—		1			761			(1,194	)		(432	)
Discoveries		—			—			—			—			—			—			—			—		—			—			—			—
Extensions		2,608			1,682			4,290			3,163			4,893			8,056			8,678			80,091		88,769			174			362			536
Infill Drilling		304			166			470			—			—			—			—			—		—			531			—			530
Improved Recovery		1,008			397			1,405			267			(19	)		248			—			—		—			148			(115	)		34
Acquisitions		27,956			12,255			40,212			514			443			957			—			—		—			8,784			3,940			12,724
Dispositions		(92	)		(52	)		(145	)		(155	)		(49	)		(205	)		—			—		—			(66	)		(36	)		(102	)
Economic Factors		(936	)		146			(790	)		(129	)		(38	)		(167	)		—			—		—			(515	)		58			(457	)
Production		(10,200	)		—			(10,200	)		(2,384	)		—			(2,384	)		(326	)		—		(326	)		(3,917	)		—			(3,917	)

December 31, 2012		107,598			45,330			152,928			21,676			10,971			32,646			12,789			82,003		94,792			28,378			11,241			39,619


	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, 2011		566,757			276,304			843,061			47,582			12,191			59,773			234,268			95,423			329,691

Technical Revisions		24,903			(13,335	)		11,568			2,048			186			2,234			7,640			(4,110	)		3,530
Discoveries		—			—			—			—			—			—			—			—			—
Extensions		4,093			4,478			8,571			—			—			—			15,305			87,774			103,079
Infill Drilling		11,270			(3,702	)		7,569			—			—			—			2,713			(451	)		2,262
Improved Recovery		215			(28	)		187			—			—			—			1,460			258			1,718
Acquisitions		232,905			102,941			335,846			2,934			728			3,662			76,560			33,917			110,477
Dispositions		(3,215	)		(1,775	)		(4,990	)		(605	)		(139	)		(744	)		(951	)		(457	)		(1,407	)
Economic Factors		(25,331	)		(4,758	)		(30,089	)		(2,178	)		(428	)		(2,606	)		(6,165	)		(698	)		(6,863	)
Production		(85,100	)		—			(85,100	)		(3,417	)		—			(3,417	)		(31,580	)		—			(31,580	)

December 31, 2012		726,497			360,126			1,086,623			46,364			12,537			58,901			299,251			211,655			510,906

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 | 19

At December 31 2012, Company Interest Total Proved Plus Probable Reserves at forecast prices and costs were 512.0 MMboe as compared to 330.5 MMboe reported at year end 2011. The following additional GLJ reserves reconciliation is presented for year end December 31, 2012.

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, 2011		188,038			234,910			330,511

Technical Revisions		7,889			7,735			3,615
Discoveries		—			—			—
Extensions		8,080			15,316			103,094
Infill Drilling		2,735			2,713			2,262
Improved Recovery		1,859			1,461			1,719
Acquisitions		65,939			76,826			110,814
Dispositions		(711	)		(963	)		(1,426	)
Economic Factors		(4,434	)		(6,211	)		(6,919	)
Production		(31,710	)		(31,710	)		(31,710	)

December 31, 2012		237,685			300,079			511,960

Note:

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

Significant factors bearing on the reserves reconciliation were as follows:

•

Net reserve additions from drilling activity, improved recovery, technical revisions and change due to economic factors replaced 66 percent and 327 percent of 2012 production for Proved Reserves and Total Proved Plus Probable Reserves, respectively. Based on all changes, including acquisitions and dispositions, reserve replacement was 306 percent and 672 percent for Proved Reserves and Proved Plus Probable Reserves, respectively.

•

An increase of 109 MMboe from acquisitions, net of minor dispositions, accounted for approximately 51 percent of the Total Proved Plus Probable Reserves added in 2012. This was almost entirely from the NAL Acquisition, as well as some asset acquisitions primarily at Quirk Creek, Lone Pine Creek, Lochend, Weyburn Unit and Sawn Lake.

•

New reserve additions for development activity during 2012 amounted to 107 MMboe of Total Proved Plus Probable Reserves, almost all in our oil and liquids rich gas properties. The most significant resulted from anticipated sanctioning of the phase one commercial development at our Lindbergh thermal project. Other notable additions were for drilling extensions at Tangleflags, Harmattan, Jenner and Swan Hills. Reserve increases in the Proved Developed Producing category also resulted from the reclassification of Proved or Probable Undeveloped Reserves to producing primarily for drilling extensions and improved recovery projects at Harmattan, Weyburn, Jenner and Judy Creek.

•

Minor technical revisions due to improved performance in various properties resulted in a net increase of 4 MMboe of Total Proved Plus Probable Reserves. This was offset by an estimated 7 MMboe negative change in Total Proved Plus Probable Reserves due to adverse economic factors associated with lower forecasted commodity prices.

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, Swan Hills and Weyburn 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.

20 | ANNUAL INFORMATION FORM

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		16,351		16,351		1,846		1,846		—		—		30,359		30,359		19,184		19,184		1,190		1,190		27,644		27,644
2010		1,386		15,077		30		1,732		—		—		30,017		51,742		10,435		24,955		516		878		8,674		30,470
2011		2,891		16,447		2,843		3,568		2,756		2,756		18,332		62,830		—		23,241		1,027		1,678		12,572		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

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		11,514		11,514		1,505		1,505		6,348		6,348		37,134		37,134		5,178		5,178		2,510		2,510		28,929		28,929
2010		708		10,168		50		1,265		—		6,348		99,381		145,695		2,809		6,318		1,284		2,879		19,073		45,996
2011		2,185		12,015		1,767		2,612		—		1,581		44,814		139,429		—		6,077		1,210		2,535		12,630		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

Notes:

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

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

Proved Undeveloped Reserves

Our Proved Undeveloped Reserves comprise approximately 18 percent of Company Interest total Proved Reserves on a barrel of oil equivalency basis. Company Interest Proved Undeveloped Reserves of 55.5 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 20 percent of our Proved Undeveloped Reserves. The Groundbirch Montney gas property amounts to approximately 11 percent of our Proved Undeveloped Reserves. Drilling is forecast by GLJ to occur over the next three years to develop these reserves. In the Judy Creek and Judy Creek West units, drilling and miscible flood development is forecast to continue until 2017 and accounts for another nine percent of Company Interest Proved Undeveloped Reserves. Similarly, in the Swan Hills unit miscible flood expansion, as well as some infill drilling, comprises seven 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 forecasted to continue until 2031. The Cardium formation at Harmattan, Garrington and Lochend contains approximately eight percent of our Proved Undeveloped Reserves. Development drilling in these fields is forecast to occur over the next four years. In the Weyburn Unit, the Proved Undeveloped Reserves amount to six percent of the total, and reflect the capital allocated to infill drilling, waterflood realignment and CO₂ miscible flood expansion, forecast to continue until 2018. As mentioned earlier, we sold our ownership in the Weyburn Unit in a transaction which is expected to close in early March 2013. Our CBM development requires further drilling at Twining, Huxley and Fenn Big Valley. Because of the extensive land holdings and slower pace of development, this is forecast to occur over the next five years and represents another six 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 143 MMboe and represent about 28 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 (57 percent), Groundbirch (11 percent), Weyburn Unit (three 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.

PENGROWTH ENERGY CORPORATION ANNUAL INFORMATION FORM | 21

Future Development Costs

($MM)


													Total
Reserve Category	2013		2014		2015		2016		2017		Remainder		Undiscounted		Discounted at 10%
Proved Reserves (Constant Prices and Costs)		213		244		114		81		37		247		936		652
Proved Reserves (Forecast Prices and Costs)		214		295		141		115		44		385		1,194		772
Proved & Probable Reserves (Forecast Prices and Costs)		702		514		363		240		145		1,058		3,022		2,002

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. We have established a $770 million capital expenditure program for 2013 to fund our land acquisition, development and exploration activities, including expenditures of $300 million at our Lindbergh thermal project.

Finding, Development and Acquisition Costs

Finding and Development Costs

During 2012, we spent $461.0 million on development and optimization activities, which added 21.0 MMboe of Proved Reserves and 103.8 MMboe of Total Proved Plus Probable Reserves including revisions. The development and optimization activities exclude $6.8 million in expenditures mainly for information technology projects in the Calgary office. The largest reserve additions were for drilling and improved recovery projects at Lindbergh, Tangleflags, Harmattan and Jenner.

In total, we participated in drilling 183 gross wells (93.3 net wells) with a 97 percent success rate.

Extensive development occurred in the Pengrowth-operated Swan Hills Beaverhill Lake trend during 2012. In addition to ongoing miscible flood development and waterflood optimization, we also drilled a total of 15 (14.8 net) horizontal oil wells at Judy Creek, primarily in the tighter platform and reef margin. In addition, we drilled two (1.9 net) liquids-rich gas wells at Carson Creek and four (2.1 net) oil wells in Deer Mountain and Virginia Hills. Multi-stage acid fracture treatments were used in the completion of these wells. We also participated in drilling eight (1.5 net) partner operated wells in the House Mountain area.

At Lindbergh, we drilled 23 (23.0 net) stratigraphic test/observation wells during 2012 to better understand the reservoir and delineate the pool. In addition, steam facilities were completed for our SAGD pilot, which commenced injection in early February 2012, and ongoing expenditures were made in preparation for commercial development.

In the Olds area, we drilled, or participated in the drilling of, 15 (10.0 net) successful horizontal wells resulting in seven (3.0 net) Cardium oil wells and six (5.0 net) Elkton and two (2.0 net) Mannville liquids rich gas wells.

In the lands acquired in connection with the NAL Acquisition, we drilled eight (4.4 net) horizontal Cardium oil wells in Lochend and 12 (3.7 net) in Garrington.

Further development and optimization occurred in the CO₂ miscible flood and waterflood areas of the Weyburn Unit in southeast Saskatchewan. During 2012, 23 (2.3 net) wells were drilled in the unit, consisting of 17 (1.7 net) water and CO₂ injection wells and six (0.6 net) oil producers.

Various other drilling programs and optimization work were conducted during 2012 to test new concepts, increase production and maximize recoveries.

Acquisitions and Divestitures

Pengrowth experienced a very active year in 2012 making significant strategic corporate and asset acquisitions. We spent $1.7 billion on acquisitions adding 76.8 MMboe of Proved Reserves and 110.8 MMboe of Proved Plus Probable Reserves. We also made some minor dispositions, selling 1.0 MMboe of Proved Reserves and 1.4 MMboe of Proved Plus Probable for net proceeds of $27 million.

On May 31, 2012 we completed the NAL Acquisition which added to our inventory of high quality light oil drilling opportunities and increased our cash flow base which funds our development activity. This also added 96.2 MMboe of Proved Plus Probable Reserves as of the closing date. Other asset acquisitions throughout the year added another 14.6 MMboe of Proved Plus Probable Reserves. These included Quirk Creek and Weyburn where we increased our existing ownership and Sawn Lake and Lochend which provided additional light oil drilling locations.

22 | ANNUAL INFORMATION FORM

Future Development Capital

NI 51-101 requires that the calculation of F&D Costs include changes in forecasted future development capital (“FDC”) relating to the reserves. FDC reflects the amount of capital estimated by the independent evaluator that will be required to bring non-producing, undeveloped or probable reserves on stream. 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)


								2010-2012 Weighted Average
Proved Reserves	2012		2011			2010		2010-2012 Weighted Average
Costs Excluding Future Development Capital
Exploration and Development Capital Expenditures—$M		460,953		603,394			329,470		1,393,817
Exploration and Development Reserve Additions including Revisions—Mboe		21,015		41,042			20,505		82,562

Finding and Development Cost—$/BOE		21.93		14.70			16.07		16.88

Net Acquisition Capital—$M		1,654,202		(8,307	)		400,600		2,046,495
Net Acquisition Reserve Additions—Mboe		75,863		(160	)		11,232		86,935

Net Acquisition Cost—$/BOE		21.81		52.06			35.67		23.54

Total Capital Expenditures including Net Acquisitions—$M		2,115,155		595,087			730,070		3,440,312
Reserve Additions including Net Acquisitions—Mboe		96,878		40,883			31,737		169,497

Finding Development and Acquisition Cost—$/BOE		21.83		14.56			23.00		20.30

Costs Including Future Development Capital
Exploration and Development Capital Expenditures—$M		460,953		603,394			329,470		1,393,817
Exploration and Development Change in FDC—$M		104,601		257,000			32,000		393,601

Exploration and Development Capital including Change in FDC—$M		565,554		860,394			361,470		1,787,418
Exploration and Development Reserve Additions including Revisions—Mboe		21,015		41,042			20,505		82,562

Finding and Development Cost—$/BOE		26.91		20.96			17.63		21.65

Net Acquisition Capital—$M		1,654,202		(8,307	)		400,600		2,046,495
Net Acquisition FDC—$M		229,820		0			34,000		263,820

Net Acquisition Capital including FDC—$M		1,884,022		(8,307	)		434,600		2,310,315
Net Acquisition Reserve Additions—Mboe		75,863		(160	)		11,232		86,935

Net Acquisition Cost—$/BOE		24.83		52.06			38.69		26.58

Total Capital Expenditures including Net Acquisitions—$M		2,115,155		595,087			730,070		3,440,312
Total Change in FDC—$M		334,421		257,000			66,000		657,421

Total Capital including Change in FDC—$M		2,449,576		852,087			796,070		4,097,733
Reserve Additions including Net Acquisitions—Mboe		96,878		40,883			31,737		169,497

Finding Development and Acquisition Cost including FDC—$/BOE		25.29		20.84			25.08		24.18

PENGROWTH ENERGY CORPORATION ANNUAL INFORMATION FORM | 23


Total Proved Plus Probable Reserves	2012		2011			2010		2010-2012 Weighted Average
Costs Excluding Future Development Capital
Exploration and Development Capital Expenditures—$M		460,953		603,394			329,470		1,393,817
Exploration and Development Reserve Additions including Revisions—Mboe		103,772		39,335			27,127		170,234

Finding and Development Cost—$/BOE		4.44		15.34			12.15		8.19

Net Acquisition Capital—$M		1,654,202		(8,307	)		400,600		2,046,495
Net Acquisition Reserve Additions—Mboe		109,388		(253	)		22,832		131,967

Net Acquisition Cost—$/BOE		15.12		32.85			17.55		15.51

Total Capital Expenditures including Net Acquisitions—$M		2,115,155		595,087			730,070		3,440,312
Reserve Additions including Net Acquisitions—Mboe		213,160		39,082			49,959		302,201

Finding Development and Acquisition Cost—$/BOE		9.92		15.23			14.61		11.38

Costs Including Future Development Capital
Exploration and Development Capital Expenditures—$M		460,953		603,394			329,470		1,393,817
Exploration and Development Change in FDC—$M		1,287,994		188,000			86,000		1,561,994

Exploration and Development Capital including Change in FDC—$M		1,748,947		791,394			415,470		2,955,811
Exploration and Development Reserve Additions including Revisions—Mboe		103,772		39,335			27,127		170,234

Finding and Development Cost—$/BOE		16.85		20.12			15.32		17.36

Net Acquisition Capital—$M		1,654,202		(8,307	)		400,600		2,046,495
Net Acquisition FDC—$M		467,242		0			106,000		573,242

Net Acquisition Capital including FDC—$M		2,121,444		(8,307	)		506,600		2,619,737
Net Acquisition Reserve Additions—Mboe		109,388		(253	)		22,832		131,967

Net Acquisition Cost—$/BOE		19.39		32.85			22.19		19.85

Total Capital Expenditures including Net Acquisitions—$M		2,115,155		595,087			730,070		3,440,312
Total Change in FDC—$M		1,755,236		188,000			192,000		2,135,236

Total Capital including Change in FDC—$M		3,870,391		783,087			922,070		5,575,548
Reserve Additions including Net Acquisitions—Mboe		213,160		39,082			49,959		302,201

Finding Development and Acquisition Cost including FDC—$/BOE		18.16		20.04			18.46		18.45

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.


	2012		2011		2010		2010-2012 Weighted Average
Recycle Ratio		1.4		1.4		1.8		1.5
Operating Netback, $/BOE⁽¹⁾		22.93		28.45		26.92		25.94
P+P F&D, $/BOE⁽²⁾		16.85		20.12		15.32		17.36

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.

Reserve Life Index (RLI)

The reserve life index provides a comparative measure of the longevity of the resources. We calculate the RLI by dividing 2012 Company Interest year end reserves by GLJ’s 2013 forecasted production.


	Proved Producing Reserves		Total Proved Reserves		Total Proved Plus Probable Reserves
RLI, years		7.6		9.2		14.7
Reserves, Mboe⁽¹⁾⁽²⁾		237,685		300,078		511,960
2013 Forecast Production, BOE/d⁽¹⁾		85,730		89,710		95,593

Notes:

(1)	Both reserves and production are Company Interest.

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

24 | ANNUAL INFORMATION FORM

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.


	2012			2011			2010			Weighted Average/ Total 2010-2012
Without Net Acquisitions Proved Plus Probable Replacement		327	%		146	%		99	%		198	%
P+P Additions plus Revisions, MMboe⁽¹⁾		103.8			39.3			27.1			170.2

With Net Acquisitions Proved Plus Probable Replacement		672	%		145	%		183	%		352	%
P+P Additions, Revisions plus net Acquisitions, MMboe⁽¹⁾		213.2			39.1			50.0			302.3

Without Net Acquisitions Total Proved Replacement		66	%		152	%		75	%		96	%
Total Proved Additions plus Revisions, MMboe⁽¹⁾		21.0			41.0			20.5			82.5

With Net Acquisitions Total Proved Replacement		306	%		151	%		116	%		197	%
Total Proved Additions, Revisions plus net Acquisitions, MMboe⁽¹⁾		96.9			40.9			31.7			169.5

Current Year Production, MMboe⁽¹⁾		31.7			27.0			27.3			86.0

Note:

(1)	Both reserves and production are Company Interest.

(2)	Note that 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.

Other Oil and Gas Information

Oil and Gas Wells

As at December 31, 2012, we had an interest in 11,709 gross (5,570 net) producing oil and natural gas wells and 4,242 gross (2,157 net) non-producing oil and natural gas wells.


	Producing				Non-Producing				Total
	Gross		Net		Gross		Net		Gross		Net
Crude Oil and Bitumen Wells
Alberta		2,623		1,565		1,197		653		3,820		2,218
British Columbia		97		59		179		107		276		166
Saskatchewan		1,671		534		777		330		2,448		864
Natural Gas Wells
Alberta		6,513		3,126		1,027		528		7,540		3,654
British Columbia		233		142		240		117		473		259
Saskatchewan		68		45		66		31		134		76
Ontario		485		97		85		17		570		114
Nova Scotia		19		2		—		—		19		2
Other⁽¹⁾
Alberta		—		—		480		278		480		278
British Columbia		—		—		90		50		90		50
Saskatchewan						101		46		101		46

Total		11,709		5,570		4,242		2,157		15,951		7,727

Note:

(1)	We cannot classify these wells as either oil or gas.

(2)	All wells are onshore except for wells in Nova Scotia and Ontario which are all offshore.

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, 2012 and the maximum net area of unproved properties for which we expect our rights to explore, develop and exploit to expire during 2012. 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.

PENGROWTH ENERGY CORPORATION ANNUAL INFORMATION FORM | 25

Unproved Properties

as at December 31, 2012


Location	Gross Acres		Net Acres		Maximum Net Acres That May Expire During 2013
Alberta		936,264		618,247		106,202
British Columbia		422,357		188,565		29,345
Ontario		472,071		94,314		1,129
Saskatchewan		240,916		125,247		14,448
Nova Scotia		200,650		15,957		—

Total		2,272,258		1,027,251		151,124

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 northeast of Calgary and 50 kilometres south of Bonnyville. We have a 100% Working Interest in the Lindbergh oil sands leases, located in the Cold Lake oil sands district in north-eastern Alberta and covering 20,800 net acres (32.5 sections). Our Muriel Lake property, which is included in our Lindbergh thermal project, is about eight kilometers to the northeast 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 59 delineation wells since acquiring the Lindbergh property in 2004. Additionally, 59 square kilometres of three dimensional seismic along with 55 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 quality ranges from 9.5-11^oAPI. The average exploitable reservoir pay thickness is 14.3 metres in the 12,500 bbl/d first phase commercial project area. There appear 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.

We own a central processing facility and pad site and drilled and completed two SAGD well pairs 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 favourable pilot results, Pengrowth plans 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 25 years. Over the life of the 12,500 bbl/d commercial project, 60-65 well pairs are expected to be drilled from eight or nine well pads within the project area, recovering in excess of 107 MMbbls of bitumen. The production life for each individual well pair is expected to be 8 – 12 years. Under our development plan, as individual well pair production declines, additional well pairs would be drilled throughout the Lindbergh project area to maintain production. The initial phase is expected to reach peak production by the second quarter of 2015. Future expansion of the Lindbergh commercial project, including the Muriel Lake property, is expected to increase the production capacity to 30,000—50,000 bbl/d of bitumen.

The Corporation submitted an application for a 12,500 bbl/d first phase commercial project to the ERCB and Alberta Environment on December 23, 2011. Regulatory approval of this application is expected in the second quarter of 2013, with construction to commence in the third quarter 2013.

Proved, Probable and Possible Reserves have been assigned to the project development area. In addition, there are economic Contingent Resources for the area beyond the reserves. GLJ has updated the evaluation of the reserves and Contingent Resources for Lindbergh as of December 31, 2012. 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, Probable 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”.

26 | ANNUAL INFORMATION FORM

Lindbergh Thermal Project

Proved, Proved plus Probable and Proved plus Probable plus Possible Reserves

as of December 31, 2012

(Forecast Prices and Costs)


	Proved Reserves		Proved plus Probable Reserves		Proved plus Probable plus Possible Reserves
Gross Reserves (MMbbl)		12.8		94.8		154.9

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.

Best Estimate and High Estimate 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 and our commitment to develop the Phase 1 commercial project. In 2012, we drilled 18 stratigraphic test/observation wells. 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.

•

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

•

High quality project design and cost estimates for any phases of potential future expansion projects, needed to confirm positive project economics.

•

Submission of regulatory application to expand the currently proposed Phase 1 development area.

We anticipate these contingencies will be satisfied over time which should allow us to book some portion of the Contingent Resources as Proved, Probable and Possible Reserves each year going forward.


	December 31, 2012		December 31, 2011
	Contingent Resources⁽¹⁾ (Gross MMbbl)		Contingent Resources⁽¹⁾ (Gross MMbbl)
Low Estimate⁽²⁾		194		193
Best Estimate⁽³⁾		218		296
High Estimate⁽⁴⁾		328		476

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.

PENGROWTH ENERGY CORPORATION ANNUAL INFORMATION FORM | 27

Groundbirch Reserves and Contingent Resources

The Groundbirch property is located approximately 40 kilometres southwest of Ft. St. John, British Columbia and covers an area of approximately 13,440 acres. We have an average 90 percent Working Interest in the lands that we acquired with Monterey in September 2010.

Production from the Montney formation began on this property in December 2010. For those areas producing and immediately adjacent, GLJ has assigned proven, probable and possible reserves. For areas outside of this, GLJ has completed a Contingent Resource assessment.

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.

Groundbirch

Proved, Proved plus Probable and Proved plus Probable plus Possible Reserves

as of December 31, 2012

(Forecast Prices and Costs)


	Proved Developed Producing Reserves (Gross)		Total Proved Reserves (Gross)		Total Proved Plus Probable Reserves (Gross)		Total Proved Plus Probable Plus Possible Reserves (Gross)
Reserves
Gas (Bcf)		26.5		63.1		165.1		193.9
NGL (MMbbl)		—		0.1		0.2		0.2
Total (MMboe)⁽¹⁾		4.4		10.6		27.7		32.5

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.

Contingent Resources have been assigned to the remaining areas of the reservoir within the property that meet certain minimum criteria. GLJ’s estimate of economic 2012 Contingent Resources are the same as 2011 year end as shown below. Production performance through the year was as predicted and ultimate recoveries remain unchanged when compared to the 2011 reserve report. There was no drilling and completion activity on the lands during 2012.

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 still in the early stage of evaluation and delineation in the area. The reclassification of these Contingent Resources as reserves is contingent upon obtaining additional drilling, completion and test data which is required before Pengrowth can commit to further development. However, there is no certainty that it will be commercially viable to produce any portion of the Contingent Resource.


	December 31, 2012 Contingent Resources⁽¹⁾ (Gross)		December 31, 2011 Contingent Resources⁽¹⁾ (Gross)
Low Estimate⁽²⁾
Gas, MMcf		157.0		155.3
NGL, MMbbl		0.2		0.3
Total, MMboe⁽⁵⁾		26.3		26.2
Best Estimate⁽³⁾
Gas, MMcf		274.3		271.5
NGL, MMbbl		0.3		0.6
Total, MMboe⁽⁵⁾		46.0		45.8
High Estimate⁽⁴⁾
Gas, MMcf		493.9		488.6
NGL,s MMbbl		0.5		1.0
Total, MMboe⁽⁵⁾		82.8		82.5

Notes:

(1)

(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.

28 | ANNUAL INFORMATION FORM

(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 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 18 of our annual audited consolidated financial statements and related management’s discussion and analysis for the year ended December 31, 2012, 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 properties 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 $138 million as at December 31, 2012, based on a total future liability (inflated at 1.5 percent per annum) of approximately $2,414 million. These costs are anticipated to be paid over 65 years with the majority of the costs incurred in the last 20 years and applies to 12,721 net wells.

The following table summarizes our total current asset retirement obligations as at December 31, 2012:

Asset Retirement Obligations—$MM


	2013		2014		2015		Remainder		Total
Total Abandonment, Reclamation, Remediation & Dismantling		4.8		9.6		5.8		2,394.0		2,414.2
Discounted at ten percent		4.6		8.3		4.6		120.8		138.3

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 $350 million ($129 million when discounted at ten percent) of the current asset retirement obligations in the above table. Elsewhere, where we describe Future Net Revenue, only the GLJ estimated abandonment obligation is included in the values. For further clarity, the amount beyond the $350 million, or $129 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 2017.

PENGROWTH ENERGY CORPORATION ANNUAL INFORMATION FORM | 29

Costs Incurred

The following table outlines property acquisition, exploration and development costs that we incurred during the financial year ended December 31, 2012. These costs include only those costs which are cash or cash equivalent.


Nature of Cost	Amount ($M)
Acquisition Costs⁽¹⁾
Proved		1,156,200
Unproved		705,051
Exploration Costs		72,102
Development Costs		388,485

Total		2,321,838

Note:

(1)	Based on the values assigned to property, plant and equipment in the purchase price allocation for the NAL Acquisition in the December 31, 2012 financial statements, and cash paid for other properties acquired.

Exploration and Development Activities

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
Gas		12		9.6		1		—		13		9.6
Oil		114		48.9		4		2.3		118		51.2
Service		24		7.1		—		—		24		7.1
Stratigraphic Test		22		22.0		1		1.0		23		23
Dry		1		1.0		4		1.4		5		2.4

Total		173		88.6		10		4.7		183		93.3

Production Estimates

The following tables summarize the 2013 average daily volume of gross production estimated by GLJ for all properties held on December 31, 2012 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 2013 Company Interest production to be between 85,000 and 87,000 BOE/d.


	2013 Estimated Production
	Constant Prices and Costs				Forecast Prices and Costs
	Total Proved		Total Proved Plus Probable		Total Proved		Total Proved Plus Probable
Light and Medium Crude Oil (bbl/d)		30,573		33,308		30,576		33,311
Heavy Crude Oil (bbl/d)		7,822		8,111		7,821		8,111
Natural Gas (Mcf/d)		245,469		257,110		245,530		257,989
Natural Gas Liquids (bbl/d)		10,054		10,770		10,056		10,828

Total (BOE/d)		89,360		95,041		89,375		95,248

Note:

(1)	The above numbers include approximately 2,500 BOE/d (net) of production associated with the Weyburn properties which are expected to be sold in early March 2013 with an effective date of January 1, 2013.

Production History (Netback)

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


	QUARTER ENDED												YEAR ENDED
	Mar 31, 2012⁽²⁾			June 30, 2012⁽³⁾			Sept 30, 2012			Dec 31, 2012			Dec 31, 2012
Barrels of Oil Equivalent ⁽¹⁾
Average Daily Oil Production⁽⁴⁾(BOE/d)		75,618			78,870			94,284			94,039			85,748
Sales price (after commodity risk management) ($/BOE)		47.14			45.00			44.73			49.36			46.60
Other production income ($/BOE)		0.59			0.75			0.45			0.52			0.57

Oil & gas sales ($/BOE)		47.73			45.75			45.18			49.88			47.17
Royalties ($/BOE)		(11.32	)		(8.72	)		(7.79	)		(8.03	)		(8.84	)

30 | ANNUAL INFORMATION FORM


	QUARTER ENDED												YEAR ENDED
	Mar 31, 2012⁽²⁾			June 30, 2012⁽³⁾			Sept 30, 2012			Dec 31, 2012			Dec 31, 2012
Operating expenses ($/BOE)		(13.88	)		(15.29	)		(15.22	)		(14.01	)		(14.61	)
Transportation costs ($/BOE)		(0.84	)		(0.95	)		(0.66	)		(0.75	)		(0.79	)

Operating netback ($/BOE)		21.69			20.79			21.51			27.09			22.93

Light Crude
Average Daily Oil Production ⁽⁴⁾ (bbl/d)		22,431			26,504			31,110			31,898			28,005
Sales price (after commodity risk management) ($/bbl)		82.79			82.09			83.09			85.82			83.57
Other production income ($/bbl)		0.63			0.74			0.35			0.35			0.50

Oil & gas sales ($/bbl)		83.42			82.83			83.44			86.17			84.07
Royalties ($/bbl)		(20.70	)		(18.54	)		(15.73	)		(16.24	)		(17.52	)
Operating expenses ($/bbl)		(16.60	)		(17.05	)		(18.68	)		(15.78	)		(16.66	)
Transportation costs ($/bbl)		(1.59	)		(1.63	)		(0.93	)		(1.24	)		(1.32	)

Operating netback ($/bbl)		44.53			45.61			48.10			52.91			48.57

Heavy Oil
Average Daily Oil Production ⁽⁴⁾ (bbl/d)		6,576			6,446			6,502			6,532			6,514
Oil & gas sales ($/bbl)		71.37			64.57			63.98			63.74			65.92
Royalties ($/bbl)		(14.82	)		(10.46	)		(13.62	)		(9.19	)		(12.03	)
Operating expenses ($/bbl)		(15.98	)		(16.96	)		(19.36	)		(15.96	)		(17.15	)
Transportation costs ($/bbl)		(1.17	)		(1.13	)		(0.74	)		(0.91	)		(1.01	)

Operating netback ($/bbl)		39.40			36.02			30.26			37.68			35.73

Natural Gas⁽⁵⁾
Average Daily Natural Gas Production ⁽⁴⁾ (Mcf/d)		213,639			218,403			275,357			263,983			242,992
Sales price (after commodity risk management) ($/Mcf)		2.33			1.94			2.40			3.15			2.49
Other production income ($/Mcf)		0.14			0.18			0.12			0.14			0.14

Oil & gas sales ($/Mcf)		2.47			2.12			2.52			3.29			2.63
Royalties ($/Mcf)		(0.24	)		0.09			(0.05	)		(0.03	)		(0.05	)
Operating expenses ($/Mcf)		(2.01	)		(2.25	)		(2.14	)		(2.10	)		(2.18	)
Transportation costs ($/Mcf)		(0.09	)		(0.10	)		(0.09	)		(0.09	)		(0.09	)

Operating netback ($/Mcf)		0.13			(0.14	)		0.24			1.07			0.31

NGLs
Average Daily Oil Production ⁽⁴⁾ (bbl/d)		11,004			9,519			10,779			11,611			10,731
Oil & gas sales ($/bbl)		67.31			56.02			51.45			56.64			57.91
Royalties ($/bbl)		(22.10	)		(15.54	)		(13.30	)		(14.63	)		(16.40	)
Operating expenses ($/bbl)		(12.95	)		(16.21	)		(12.81	)		(13.50	)		(13.56	)
Transportation costs ($/bbl		(0.13	)		(0.22	)		(0.31	)		(0.22	)		(0.20	)

Operating netback ($/bbl)		32.13			24.05			25.03			28.29			27.75

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 BOE.

(2)	Does not include NAL Energy results as it was acquired effective May 31, 2012.

(3)	Includes only one month of NAL Energy results as it was acquired effective May 31, 2012.

(4)	Before the deductions of royalties.

(5)	Includes CBM production.

DESCRIPTION OF CAPITAL STRUCTURE

General

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 | 31

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 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 June and December of each year and mature on December 31, 2014. The 6.25% Series A Convertible Debentures are convertible at the holder’s option at a conversion price of $19.186 per Common Share, subject to adjustment in certain events. The 6.25% Series A Convertible Debentures are now redeemable at our own option.

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 A Convertible Debentures and our 6.25% Series B Convertible Debentures are listed and posted for trading on the TSX under the symbols “PGF.DB.A” and “PGF.DB.B”, respectively.

DIVIDENDS

General

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 2013 can be found at www.pengrowth.com/investors/dividends/.

Historical Distributions/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 “Risk Factors”.

32 | ANNUAL INFORMATION FORM

The following table sets forth dividends declared by the Corporation in 2012 and 2011 and distributions declared by the Trust in respect of 2010 on the outstanding Common Shares and Trust Units, respectively, for the periods indicated, with each amount being paid in the following month:


Month	2012 ($/share)		2011 ($/share)		2010 ($/share)
January		0.07		0.07		0.07
February		0.07		0.07		0.07
March		0.07		0.07		0.07
April		0.07		0.07		0.07
May		0.07		0.07		0.07
June		0.07		0.07		0.07
July		0.04		0.07		0.07
August		0.04		0.07		0.07
September		0.04		0.07		0.07
October		0.04		0.07		0.07
November		0.04		0.07		0.07
December		0.04		0.07		0.07

Total		0.66		0.84		0.84

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 and (ii) the note purchase agreements relating to the 2003 US Senior Notes, 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, 2012, our legal stated capital was approximately $1.481 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.

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:

•

The ratio of Consolidated Senior Debt (as defined below) to Consolidated EBITDA (as defined below) at the end of any fiscal quarter shall not exceed 3:1, except upon the completion of a Material Acquisition (as defined below), and for a period extending to the end of the second full fiscal quarter thereafter this limit increases to 3.5:1;

•

The ratio of Consolidated Total Debt (as defined below) to Consolidated EBITDA at the end of any fiscal quarter shall not exceed 3.5:1; except upon the completion of a Material Acquisition, and for a period extending to the end of the second full fiscal quarter thereafter, this limit increases to 4:1; and

•

The ratio of Consolidated 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.

PENGROWTH ENERGY CORPORATION ANNUAL INFORMATION FORM | 33

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


Consolidated Senior Debt:		All obligations, liabilities and indebtedness classified as debt on the consolidated balance sheet of the Corporation.

Consolidated Total Debt:		The aggregate of Consolidated Senior Debt and Subordinated Debt.

Consolidated 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 consolidated 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 Consolidated Total Debt and the Shareholders Equity (calculated in accordance with GAAP as shown on the Corporation’s consolidated 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 Consolidated 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 2003 US Senior Notes and the UK Senior Notes the Consolidated Total Debt (as defined below) is limited to 60 percent of the Consolidated 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 Consolidated 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 Consolidated Total Debt to Consolidated 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:


Consolidated 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

34 | ANNUAL INFORMATION FORM


Consolidated Total Debt:		Has substantially the same meaning as “Consolidated Senior Debt” in the definitions relating to the Credit Facility.

Consolidated 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:		Consolidated Total Debt plus Shareholder equity in the Corporation

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 and with respect to the pricing and taxation of oil and natural gas through agreements among the governments of Canada, Alberta, British Columbia, Saskatchewan, Ontario and Nova Scotia, all of which should be carefully considered by investors in the oil and gas industry. It is not expected that any of these regulations or controls will affect our operations in a manner materially different than they will affect other oil and natural gas companies of similar size. 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 primarily determines oil prices. 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, the 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 current 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 which received Royal Assent on June 29, 2012 (the “Prosperity Act”). 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”.

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) or the New York Mercantile Exchange (NYMEX) in the United States, spot and future prices can be set by such supply and demand. 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

In Canada, 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.

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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 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. Effective January 1, 2011, the maximum royalty payable under the royalty regime was set at 40%. The royalty curve for conventional oil announced on May 27, 2010 amends the price component of the conventional oil royalty formula to moderate the increase in the royalty rate at prices higher than $535/m³compared to the previous royalty curve.

Royalty rates for natural gas under the royalty regime are similarly determined using a single sliding rate formula incorporating separate variables to account for production rates and market prices. Effective January 1, 2011, the maximum royalty payable under the royalty regime was set at 36%. The royalty curve for natural gas announced on May 27, 2010 amends the price component of the natural gas royalty formula to moderate the increase in the royalty rate at prices higher than $5.25/GJ compared to the previous royalty curve.

Oil sands projects are also subject to the 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 1-9% depending on the market price of oil, determined using the average monthly price, expressed in Canadian dollars, for WTI crude oil and Cushing, Oklahoma: rates are 1% 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 9% 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 1-9% and the net revenue royalty based on the net revenue royalty rate. Net revenue royalty rates start at 25% and increase for every dollar of market price of oil increase above $55 up to 40% 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 current royalty regime.

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Producers of oil and natural gas from freehold lands in Alberta are required to pay annual freehold production taxes. The level of the freehold production tax is based on the volume of monthly production and a specified rate of tax for both oil and gas.

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.

The Government of Alberta currently has in place two royalty programs, both of which commenced in 2008 with the intention to encourage the development of deeper, higher cost oil and gas reserves. A five-year program for conventional oil exploration wells over 2,000 metres provides qualifying wells with up to a $1 million or 12 months of royalty relief, whichever comes first, and a five-year program for natural gas wells deeper than 2,500 metres provides a sliding scale royalty credit based on depth of up to $3,750 per metre. On May 27, 2010, the natural gas deep drilling program was amended, retroactive to May 1, 2010, by reducing the minimum qualifying depth to 2,000 metres, removing a supplemental benefit of $875,000 for wells exceeding 4,000 metres that are spudded subsequent to that date, and including wells drilled into pools drilled prior to 1985, among other changes.

On November 19, 2008, the Government of Alberta announced the introduction of a five-year program of transitional royalty rates with the intent of promoting new drilling. The five-year transition option is designed to provide lower royalties at certain price levels in the initial years of a well’s life when production rates are expected to be the highest. Under this program, companies drilling new natural gas or conventional deep oil wells between 1,000 and 3,500 m receive a one-time option, on a well-by-well basis, to adopt either the new transitional royalty rates or those outlined in the royalty regime. These options expired on February 15, 2011 and on January 1, 2014, all producers operating under the transitional royalty rates will automatically become subject to the royalty regime. Production from wells operating under the transitional royalty rates will not be subject to the royalty curves for conventional oil and natural gas.

On March 17, 2011, the Government of Alberta approved the New Well Royalty Regulation providing for the permanent implementation of a formerly temporary royalty program which provides for a maximum 5% royalty rate for eligible new wells for the first twelve (12) productive months or until the regulated “volume cap” is reached.

In addition to the foregoing, 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 5% for 36 producing months on up to 750 MMcf of production, retroactive to wells that began producing on or after May 1, 2010;

•

Shale gas wells will receive a maximum royalty rate of 5% 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 5% 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 5% 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.

The Emerging Resource and Technologies Initiative will be reviewed in 2014, and the Government of Alberta has committed to providing industry with three years notice at that time if it decides to discontinue the program.

Approximately 77 percent of our Company Interest production forecast for 2012 is in the Province of Alberta on Crown lands.

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.

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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% 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, at certain production levels, is determined using a sliding scale formula based on the reference price similar to that applied to oil production on Crown land. 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 freehold production tax rate for natural gas liquids is a flat 12.25%.

British Columbia maintains a number of targeted royalty programs for key resource areas intended to increase the competitiveness of British Columbia’s natural gas low productivity wells. These include both royalty credit and royalty reduction programs, including the following:

•

Summer Royalty Credit Program providing a royalty credit equal to 10% of the goods and services costs up to $100,000 for wells drilled between April 1 and November 30 of each year;

•

Deep Royalty Credit Program providing a royalty credit 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 2,300 metres (or 1,900 metres if spud after August 1, 2009) and if certain other criteria are met and is intended to reflect the higher drilling and completion costs that relate to locations specific factors;

•

Deep Re-Entry Royalty Credit Program providing 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 subsequent to December 1, 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;

•

Natural Gas Royalty Reduction providing a reduced royalty on wells drilled on land rights acquired after June 1, 1998 and completed within 5 years of the date the rights are issued;

•

Coalbed Gas Royalty Reduction and Credit Program providing a royalty reduction for coalbed gas wells with average daily production less than 17,000 m³as 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 monthly royalty reductions for low productivity non-conservation natural gas wells with average monthly production under 25,000 m³ during the first 12 production months and average daily production less than 23 m³ for every metre of marginal well depth;

•

Ultra-Marginal Royalty Reduction Program providing additional royalty reductions for low productivity shallow non-conservation natural gas wells with a true vertical depth of less than 2,500 metres in the case of vertical wells, and a total vertical depth of less than 2,300 metres in the case of a horizontal well, average monthly production under 60,000 m³ during the first 12 production months and average daily production less than 11.0 m³(development wells) or 17 m³ (exploratory wildcat wells) for every 100 metres of marginal well depth; 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 m³of production, whichever comes first.

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The Government of British Columbia also maintains an Infrastructure Royalty Credit Program (the “Infrastructure Royalty Credit Program”) which provides royalty credits for up to 50% 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.

In August 2012, the Government of British Columbia announced that it is bringing in a nominal 2% royalty on both oil and natural gas on the revenue for the first year of production for wells drilled from September 2012 through to June 2013.

Approximately ten percent of our Company Interest production forecast for 2012 is in the Province of British Columbia on Crown lands.

Saskatchewan

In Saskatchewan, the amount payable as Crown royalty or 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 (having a finished drilling date on or after January 1, 1994 and before October 1, 2004), fourth tier oil (having a finished drilling date on or after October 1, 2002 or incremental oil from new or expanded waterflood projects) or new oil (oil from wells drilled on or after January 1, 1994 ). Southwest designated oil uses the same definitions of third and fourth tier oil but 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 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, 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 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 m³for “old oil”, “new oil” and “third tier oil”, and 250 m³per 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 m³for new oil and old oil, base royalty rates are applied. Base royalty rates are 5% for all fourth tier oil, 10% for heavy oil that is third tier oil or new oil, 12.5% for southwest designated oil that is third tier oil or new oil, 15% for non-heavy oil other than southwest designated oil that is third tier or new oil, and 20% 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% for all fourth tier oil, 25% for heavy oil that is third tier oil or new oil, 35% for southwest designated oil that is third tier oil or new oil, 35% for non-heavy oil other than southwest designated oil that is third tier or new oil, and 45% for old oil.

The amount payable as Crown royalty or freehold production tax in respect of natural gas production is determined by a sliding scale based on the actual price received, 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 more than 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 $50 per thousand m³for third and fourth tier gas and $35 per thousand m³for new gas and old gas, base royalty rates are applied. Base royalty rates are 5% for all fourth tier gas, 15% for third tier or new gas, and 20% 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% for all fourth tier gas, 35% for third tier and new gas, and 45% for old gas. The current regulatory scheme provides for certain differences with respect to the administration of “forth tier gas” which is associated gas.

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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%) and freehold tax rates (a freehold production tax rate of 0%) on incentive volumes of 8,000 m³for deep development vertical oil wells, 4,000 m³for non-deep exploratory vertical oil wells and 16,000 m³for 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%) and freehold tax rates (a freehold production tax rate of 0%) 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%) and freehold tax rates 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 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 rate of the lesser of “fourth tier oil” Crown royalty rate and 2.5%) and freehold tax rates (a freehold production tax rate of 0%) on incentive volumes of 25,000,000 m³for 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 1% of gross revenues on enhanced oil recovery projects pre-payout and 20% of EOR operating income post-payout and a freehold production tax of 0% pre-payout and 8% 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 to incremental high water-cut oil production resulting from qualifying investments made to rejuvenate eligible oil wells and/or associated facilities.

In 1975, the Government of Saskatchewan introduced a Royalty Tax Rebate (“RTR”) as a response to the Government of Canada disallowing Crown royalties and similar taxes as a deductible business expense for income tax purposes. As of January 1, 2007, the remaining balance of any unused RTR is limited in its carry forward to seven years because of the Government of Canada’s initiative to reintroduce the full deduction of provincial resource royalties from federal and provincial taxable income.

On June 22, 2011, the Government of Saskatchewan released the Upstream Petroleum Industry Associated Gas Conservation Standards, which are designed to reduce emissions resulting for 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. These will apply to existing licensed wells and facilities on July 1, 2015.

Approximately seven percent of our Company Interest production forecast for 2012 is in the Province of Saskatchewan.

Ontario

In Ontario, the Crown royalty rate for oil and gas is 12.5%, based on monthly production and full sale price of the oil or gas received at the point of sale.

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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.

Approximately five percent of our Company Interest production forecast for 2012 is in the Province of Nova Scotia.

Land Tenure

The respective provincial governments predominantly own 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. Holders of leases or licences that have been continued indefinitely prior to January 1, 2009 will receive a notice regarding the reversion of the shallow rights, which will be implemented three years from the date of the notice. Leases and licences granted prior to January 1, 2009, but continued after that date, are not subject to shallow rights reversion until they continue past their primary term (at which time the application of deep rights reversion occurs). Afterwards, the holders of such agreements will be served with shallow rights reversion notices based on vintage and location similar to leases and licences that were already continued as of January 1, 2009. The order in which these agreements will receive reversion notices will depend on their vintage and location.

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 restrictions and prohibitions on the 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 for the satisfactory 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 for pollution damage, and the imposition of material fines and penalties.

On a Federal level and pursuant the Prosperity Act, in June 2012, the Government of Canada amended or appealed several pieces of federal environmental legislation and in addition, created a new federal environment assessment regime. 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.

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 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 pursuant to the ALSA will be 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, leases, licenses, approvals and authorizations for the purpose of achieving or maintaining an objective or policy resulting from the implementation of a regional plan. Among the

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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 covers approximately 93,212 square kilometres and is in the northeast corner of Alberta. The region includes a substantial portion of the Athabasca oilsands area, which contains approximately 82% of the provinces oilsands resource and much of the Cold Lake oilsands area. LARP establishes six new conservation areas, bringing the total conserved land in the region to two million hectares, or 22%—an area three times the size of Banff National Park. The Alberta government plans to pay $30 million to producers whose leases will be cancelled in areas set aside for conservation. Oil and gas companies will be allowed to continue to operate in conservation and recreation areas while oilsands companies’ tenures will be cancelled. New petroleum and gas tenure sold in conservation areas will include a restriction that prohibits surface access. Application procedures for activities and facilities in the LARP, regulated by the Energy Resources Conservation Board and the Alberta Utilities Commission, respectively, have been changed to accommodate the new restrictions set out in the LARP. The LARP is the first of seven regions to get a land use plan. The next will be the South Saskatchewan region.

In British Columbia, the Oil and Gas Activities Act (the “OGCA”) impacts conventional oil and gas producers, shale gas producers, and other operators of oil and gas facilities in B.C. Under the OGCA, the B.C. Oil and Gas 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 OGCA requires the 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 requires proponents to obtain various approvals before undertaking exploration or production work, such as geophysical licences, geophysical exploration project approvals, and 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.

In May of 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 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.

Climate Change Regulation

Federal

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 set 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 or a company-by-company basis. Facility-specific targets apply to the upstream oil and gas, oil sands, petroleum refining and natural gas pipelines sectors. Unless a minimum regulatory threshold applies, all facilities within a regulated sector will be subject to the emissions intensity targets. Although the intention was for draft regulations for the implementation of the Updated Action Plan to become binding on January 1, 2010, the only regulations announced pertain to carbon dioxide emissions from coal-fired generation of electricity (finalized in summer 2012). Further, 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. As a result, it is unclear to what extent implementation of the proposals contained in the Updated Action Plan will occur.

The United States Environmental Protection Agency (the “EPA”) has indicated its intention to impose GHG emissions standards for fossil fuel-fired power plants by specifying that it would issue final regulations by May 26, 2012, and with respect to refineries, specifying that it will issue proposed regulations by December 10, 2011 and finalized regulations by November 10, 2012. The EPA did not meet the December 10, 2011 deadline and it is unclear whether the EPA will also miss the finalized regulations deadline. However, in March 2012, the EPA proposed a strict GHG standard on new power plants only. While it is expected that this rule could encourage building new natural gas power plants rather than coal plants, the actual effect of the new rule will not be able to be quantified for some time.

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Alberta

Alberta enacted the Climate Change and Emissions Management Act (the “CCEMA”) on December 4, 2003, amending it 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 similar to the Updated Action Plan and aims for a 50% reduction from 1990 emissions relative to GDP by 2020.

Alberta facilities emitting more than 100,000 tonnes of GHGs a year are subject to compliance with the CCEMA. Similar to the Updated Action Plan, the CCEMA and the associated Specified Gas Emitters Regulation make a distinction 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 to 88% of their baseline for 2008 and subsequent years, with their baseline being established by the average of the ratio of the total annual emissions to production for the years 2003 to 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 Specified Gas Emitters Regulation. New Facilities are required to reduce their emissions intensity by 2% from baseline in the fourth year of commercial operation, 4% of baseline in the fifth year, 6% of baseline in the sixth year, 8% of baseline in the seventh year, and 10% of baseline in the eighth year. Unlike the Updated Action Plan, the CCEMA does not contain any provision for continuous annual improvements in emissions intensity reductions beyond those stated above.

The CCEMA contains compliance mechanisms that are similar to the Updated Action Plan. 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. Unlike the Updated Action Plan, CCEMA contains no provisions for an increase to this contribution rate. Emissions credits can be purchased from regulated emitters that have reduced their emissions below the 100,000 tonne threshold or non-regulated emitters that have generated emissions offsets through activities that result in emissions reductions in accordance with established protocols published by the Government of Alberta.

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 regulations, if the emissions remain at current levels, we would be required to purchase “off-setting” credits in 2013 of up to $500,000 from Alberta Environment. In 2011 our Olds Gas Plant and Judy Creek Gas Conservation Plant did not need to purchase “off-setting” credits as we had a surplus of carbon credits.

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 their 2012 Budget, British Columbia announced the government will undertake a comprehensive review of the carbon tax and its impact on British Columbians. The review will cover all aspects of the carbon tax, including revenue neutrality, and will consider the impact on the competitiveness of B.C. businesses such as those in the agriculture sector, and in particular, B.C.’s food producers. Under this comprehensive review, British Columbians can make written submissions to B.C.’s Minister of Finance, and these will be considered as part of the 2013 Budget process.

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% reduction in the 2007 level of GHG emissions by 2020 and an 80% 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 Cap and Trade Act sets out the requirements for the reporting of the greenhouse gas 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 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 further development.

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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.

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. Regulations under the MRGGA have also yet to be proclaimed, but draft versions indicate that Saskatchewan will adopt the goal of a 20% reduction in GHG emissions from 2006 levels by 2020.

Ontario

The Province of Ontario has not implemented GHG emission reduction legislation applicable to the oil and gas industry at this time. Ontario’s Climate Change Action Plan calls for a 6% reduction by 2014 and a 15% reduction by 2020 from 1990 levels. Ontario plans to achieve these reductions with the implementation of a cap and trade system and by phasing out coal-fired electrical power plants, among other measures.

The Environmental Protection Act has been amended to include provisions to enable a cap and trade system and as of January 1, 2010 emitters of more than 25,000 tonnes of CO_2eper year must report their emissions to the government pursuant to Ontario Regulation 452/09 (Ontario Greenhouse Gas Emissions Reporting).

Nova Scotia

The Province of Nova Scotia has set a goal of lowering greenhouse gas emissions by 10 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

As present, we are not paying any direct costs. 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 methods to reduce our emissions or emissions intensity to future required levels may significantly increase operating costs or reduce the output of the projects. 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 result in fines, penalties and the suspension of operations. 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, 2012.

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:

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

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geo-political conditions;

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worldwide economic conditions including ongoing credit and liquidity concerns;

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

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

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the level of consumer demand;

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the price and availability of alternative fuels;

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the proximity to, and capacity of, transportation facilities;

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the effect of worldwide energy conservation measures; and

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government regulation.

North American crude oil price differentials are expected to continue to be volatile throughout 2013 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.

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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:

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

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the assumed effect of government regulation;

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

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initial production rates;

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production decline rates;

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ultimate recovery of reserves and resources;

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marketability of production; and

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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.

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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;

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

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

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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 spills, releases or emissions of various substances produced in association with oil and natural gas operations. The legislation also requires that wells and facility sites be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities.

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.

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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% 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.

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.

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A decline in our ability to market our oil and natural gas production could have a material adverse effect on production levels or on the price received for production, which, in turn, could 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 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 and natural gas industry and limit the ability to produce and to market oil and natural gas production. In addition, the pro-rationing of capacity on inter-provincial pipeline systems also continues to affect the ability to export oil and natural gas. 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.

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 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 to defeat our claim. Our actual interest in properties may, therefore, 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 proposed legislative changes which affect title, to the oil and natural gas properties we control that, if successful or made into law, 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. Recently, the Canadian dollar has increased materially in value against the United States dollar. Material increases in the value of the Canadian dollar negatively affects our production revenues. Future Canadian/United States exchange rates could, accordingly, affect the future value of our reserves as determined by independent evaluators.

PENGROWTH ENERGY CORPORATION ANNUAL INFORMATION FORM | 49

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 proven reserves only. Accordingly, we would have more risk of a ceiling test write-down in a declining price environment if we reported under United States generally accepted accounting principles. While these write-downs would not affect cash flow, the charge to earnings could be viewed unfavourably in the market or could limit our ability to borrow funds or comply with covenants contained in our current or future credit agreements or other debt instruments.

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

We are an Alberta corporation. We have our principal places of business in Canada. All of our directors and officers are residents of Canada and all or a substantial portion of our assets and the assets of such persons are located outside of the United States. Consequently, it may be difficult for United States investors to affect service of process within the United States upon us or such persons or to realize in the United States upon judgments of courts of the United States predicated upon civil remedies under the United States Securities Act of 1933, 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.

50 | ANNUAL INFORMATION FORM

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 (exploration, 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 licenses from various governmental authorities. There can be no assurance that we will be able to obtain all of the licenses and permits 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”.

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.

PENGROWTH ENERGY CORPORATION ANNUAL INFORMATION FORM | 51

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 as the demand for natural gas rises during cold winter months and hot summer months.

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;

•

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 and spills or 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.

52 | ANNUAL INFORMATION FORM

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.

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.

Lindbergh Thermal 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:

PENGROWTH ENERGY CORPORATION ANNUAL INFORMATION FORM | 53

•

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 2014 at the earliest. 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 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;

54 | ANNUAL INFORMATION FORM

•

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.

PENGROWTH ENERGY CORPORATION ANNUAL INFORMATION FORM | 55

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 2012 as reported by the TSX and the NYSE.


	TSX
2012	($) High		($) Low		Volume
January		11.36		9.96		16,811,417
February		10.14		9.81		15,738,212
March		10.15		9.35		19,983,760
April		9.47		8.43		14,433,885
May		9.14		7.10		18,379,022
June		7.88		5.97		33,676,747
July		6.69		5.92		24,077,828
August		7.39		5.93		26,440,978
September		7.15		6.44		12,644,491
October		6.72		5.76		16,556,041
November		6.20		4.98		20,848,445
December		5.23		4.66		21,440,464

	NYSE
2012	(US$) High		(US$) Low		Volume
January		11.17		9.95		22,853,909
February		10.25		9.86		25,046,401
March		10.30		9.40		22,801,248
April		9.55		8.46		24,579,746
May		9.26		6.87		29,905,269
June		7.69		5.80		42,241,267
July		6.60		5.79		29,422,763
August		7.49		5.90		38,019,099
September		7.40		6.51		23,386,877
October		6.85		5.88		22,363,245
November		6.25		5.00		34,975,397
December		5.30		4.68		40,010,291

Our 6.25% Series A Convertible Debentures are listed and posted for trading on the TSX under the symbol “PGF.DB.A”. These debentures were assumed with the NAL Acquisition on May 31, 2012 and first traded as Pengrowth debentures on June 6, 2012. The following table sets forth certain trading information for the 6.25% Series A Convertible Debentures in 2012 as reported by the TSX.


	TSX
2012	($) High		($) Low		Volume
June 6 to June 30		102.75		100.85		27,490
July		104.97		101.70		15,620
August		104.98		103.39		6,690
September		105.05		104.26		2,750
October		104.80		104.07		8,560
November		104.25		102.30		11,200
December		102.75		101.36		10,130

56 | ANNUAL INFORMATION FORM

Our 6.25% Series B Convertible Debentures are listed and posted for trading on the TSX under the symbol “PGF.DB.B”. These debentures were assumed with the NAL Acquisition on May 31, 2012 and first traded as Pengrowth debentures on June 6, 2012. The following table sets forth certain trading information for the 6.25% Series B Convertible Debentures in 2012 as reported by the TSX.


	TSX
2012	($) High		($) Low		Volume
June 6 to June 30		102.81		97.50		51,300
July		104.20		101.25		33,890
August		105.00		103.00		15,400
September		105.40		104.00		14,710
October		104.75		103.26		27,445
November		104.00		102.50		11,580
December		102.75		100.00		14,980

DIRECTORS AND OFFICERS

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


Name and Jurisdiction of Residence	Position with Pengrowth⁽¹⁾	Principal Occupation
John B. Zaozirny⁽²⁾⁽³⁾ Alberta, Canada	Chairman and Director (Director since 1988)	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)	President and Chief Executive Officer of Pengrowth since September 2009; prior thereto President and Chief Operating Officer of Pengrowth since May 2009; and prior thereto, the President and Chief Executive Officer of Focus Energy Trust (energy trust) until 2008.

Thomas A. Cumming⁽³⁾⁽⁵⁾ Alberta, Canada	Director (Director since 2000)	Business Consultant and Corporate Director.

Wayne K. Foo⁽²⁾⁽⁴⁾ Alberta, Canada	Director (Director since 2006)	President and Chief Executive Officer of Parex Resources Inc. (energy company) since 2009; prior thereto President and Chief Executive Officer of Petro Andina Resources Inc. (energy company).

Kelvin B. Johnston⁽³⁾⁽⁴⁾ Alberta, Canada	Director (Director since 2012)	President of Wylander Crude Corp. since July 2006 and Vice President, Corporate Development of Lakeview Energy Ltd. since June 2009.

James D. McFarland^(4)(5)(6) Alberta, Canada	Director (Director since 2010)	President, Chief Executive Officer and Director of Valeura Energy Inc. and its predecessor PanWestern Energy Inc. (energy company) since April, 2010; prior thereto President and Chief Executive Officer of Verenex Energy Inc. from March 2004 to December 2009.

Michael S. Parrett⁽²⁾⁽⁵⁾ Ontario, Canada	Director (Director since 2004)	Business Consultant and Corporate Director.

A. Terence Poole⁽²⁾⁽⁵⁾ Alberta, Canada	Director (Director since 2005)	Business Consultant and Corporate Director.

Barry D. Stewart⁽²⁾⁽⁴⁾ Alberta, Canada	Director (Director since 2012)	Retired petroleum industry executive.

D. Michael G. Stewart⁽³⁾⁽⁴⁾ Alberta, Canada	Director (Director since 2006)	Corporate Director.

David P. Allen Alberta, Canada	Vice President, Exploration	Vice President, Exploration of Pengrowth since April 2012; prior thereto Director, Exploration & Development of NAL Resources from June 2009 to February 2012; prior thereto Vice President, Exploration of Alberta Clipper Energy Inc. (energy company).

PENGROWTH ENERGY CORPORATION ANNUAL INFORMATION FORM | 57


Name and Jurisdiction of Residence	Position with Pengrowth⁽¹⁾	Principal Occupation
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.

Steve 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).

Dean Evans Alberta, Canada	Vice President and Treasurer	Vice President and Treasurer of Pengrowth since August 2012; prior thereto Treasurer of Pengrowth from February 2009 to August 2012; prior thereto Treasury Manager at ARC Resources Ltd. (energy company).

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 Greenan Alberta, Canada	Vice President, Marketing	Vice President, Marketing of Pengrowth since August 2012; prior thereto Director, Marketing of Pengrowth from January 2009 to August 2012; prior thereto Manager, Marketing of Pengrowth.

Frederic (Fred) D. Kerr Alberta, Canada	Vice President, Investor Relations	Vice President, Investor Relations of Pengrowth since April 2012; prior thereto Vice President, Institutional Sales of Acumen Capital Partners (investment banking firm).

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 Resources (energy company).

Deric S. Orton⁽⁸⁾ Alberta, Canada	Vice President, Land	Vice President, Land of Pengrowth since June 2012; prior thereto Director, Land of NAL Resources Corp. from December 2008 to June 2012 and prior thereto, Vice President, Land of Piper Resources Ltd. (“Piper”) (energy company).

Robert W. Rosine Alberta, Canada	Executive Vice-President, Business Development	Executive Vice President, Business Development of Pengrowth since March 2010; prior thereto President of Mancal Energy Inc. (energy company) from July 2008 to February 2010; prior thereto, Executive Vice President, Corporate Development of Highpine Oil & Gas Limited (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. McFarland was the Managing Director and a director of Southern Pacific Petroleum NL (“SPP”), which was listed on the Australian Stock Exchange. In December 2003, a secured creditor of SPP appointed a receiver-manager. Mr. McFarland ceased to be the Managing Director and a director of SPP in February 2004.

58 | ANNUAL INFORMATION FORM

(7)	Mr. De Maio was formerly an 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 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, 2012, the foregoing directors and officers, as a group, beneficially owned, directly or indirectly, 1,449,890 Common Shares or approximately 0.28 percent of the issued and outstanding Common Shares and held rights and options to acquire a further 2,263,060 Common Shares (assuming 100% vesting of all performance-based rights). The information as to shares beneficially owned, not being within our knowledge, has been furnished by the respective individuals.

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

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

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

(a)

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

(b)

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

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

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

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

PENGROWTH ENERGY CORPORATION ANNUAL INFORMATION FORM | 59

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
Thomas A. Cumming	Yes	Yes	Mr. Cumming was President and Chief Executive Officer of the Alberta Stock Exchange from 1988 to 1999. His career also includes 25 years with a major Canadian bank both nationally and internationally. He served as Chairman of Alberta’s Electricity Balancing Pool from 2003 to 2012. He is also a past president of the Calgary Chamber of Commerce. Mr. Cumming is a professional engineer and holds a Bachelor of Applied Science degree in Engineering and Business from the University of Toronto.

James D. McFarland	Yes	Yes	Mr. McFarland has more than 40 years’ experience in the oil and gas industry, most recently as President, Chief Executive Officer, director and co-founder of Valeura Energy Inc., a TSX listed issuer. Prior thereto Mr. McFarland was President, Chief Executive Officer, director and a co-founder of Verenex Energy Inc., a TSX listed issuer. He has served in senior executive roles as Managing Director of Southern Pacific Petroleum N.L. in Australia (an Australian Securities Exchange listed issuer), President and Chief Operating Officer of Husky Oil Limited (a TSX listed issuer) and in a wide range of upstream and corporate functions in an earlier 23-year career with Imperial Oil Limited and other ExxonMobil affiliates in Canada, the US and western Europe. Mr. McFarland 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 is a director of Stillwater Mining Company, a NYSE listed company. He is Chairman of 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.

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 2012 and 2011:


	2012 ($M)		2011 ($M)
Audit Fees		1,061		1,024
Audit Related Fees		—		—
Tax Fees		96		35
All Other Fees		176		214

Total		1,333		1,273

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.

60 | ANNUAL INFORMATION FORM

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 2012 and 2011 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 2012 and 2011 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 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.

PENGROWTH ENERGY CORPORATION ANNUAL INFORMATION FORM | 61

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.

Prior to July 2009, the Trust was managed by Pengrowth Management Limited. Pursuant to a Management Agreement between Pengrowth Corporation and Pengrowth Management Limited, Pengrowth Management Limited had the right to appoint two directors to the board of directors of Pengrowth Corporation, the administrator of the Trust. Messrs. James Kinnear and Nicholas Villiers were the designated appointees in 2009 and 2010. Following termination of the Management Agreement in July 2009, Messrs. Kinnear and Villiers remained as directors of Pengrowth Corporation until December 31, 2011.

Mr. Chris Webster, our Chief Financial Officer, served as a director of Monterey. Mr. Webster did not hold any options in Monterey and abstained from all Monterey board discussions concerning the proposed acquisition of Monterey by Pengrowth.

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 Rules of Professional Conduct of the Alberta Institute of Chartered Accountants.

AUDITORS, TRANSFER AGENT AND REGISTRAR

The transfer agent and registrar for the Common Shares is Olympia Trust Company at its principal offices in the cities of Calgary, Alberta and 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 First Amending Agreement to the Amended and Restated Credit Agreement dated November 29, 2011 concerning our Credit Facility;

(ii)

the Amended and Restated Credit Agreement dated January 1, 2011 between Pengrowth and a syndicate of ten financial institutions concerning the Credit Facility;

(iii)

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

(iv)

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

(v)

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

(vi)

the Note Purchase Agreement dated July 26, 2007 concerning the 2007 US Senior Notes;

(vii)

the Note Purchase Agreement dated December 1, 2005 concerning the UK Senior Notes; and

(viii)

the Note Purchase Agreement dated April 23, 2003 concerning the 2003 US 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 officer. The Code of Ethics is available for viewing on our website www.pengrowth.com under the name “Code of Business Conduct “, 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 November 1, 2012. All Directors, officers, employees, consultants and contractors are required to accept the Code of Ethics annually.

62 | ANNUAL INFORMATION FORM

During the year ended December 31, 2012, 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.

DISCLOSURE PURSUANT TO THE REQUIREMENTS

OF THE NEW YORK STOCK EXCHANGE

As a Canadian reporting issuer with securities listed on the TSX, Pengrowth has in place a system of corporate governance practices which complies with Canadian securities laws and the TSX corporate governance guidelines as well as the corporate governance rules of the NYSE applicable to foreign private issuers. In the context of its listing on the New York Stock Exchange, Pengrowth is classified as a foreign private issuer 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 25, 2013. Additional financial information is contained in our comparative consolidated financial statements and associated management’s discussion and analysis for the years ended December 31, 2012, 2011 and 2010.

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

(888) 744-1111

Fax: (866) 341-3586

Website: www.pengrowth.com

E-mail: investorrelations@pengrowth.com

PENGROWTH ENERGY CORPORATION ANNUAL INFORMATION FORM | 63

APPENDIX A

FORM 51-101F2

REPORT ON RESERVES DATA

INDEPENDENT QUALIFIED RESERVES

EVALUATOR OR AUDITOR

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

We have evaluated the Company’s reserves data as at December 31, 2012. The reserves data are estimates of proved reserves and probable reserves and related Future Net Revenue as at December 31, 2012, estimated using forecast prices and costs.

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).

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.

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, 2012, 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 - $M)

Audited

Evaluated

Reviewed

Total

GLJ Petroleum Consultants

January 18, 2013

Canada

—

6,088,469

—

6,088,469

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

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 27, 2013.

(signed) “Doug R. Sutton”

Doug R. Sutton, P.Eng.

Vice-President

APPENDIX A | PENGROWTH ENERGY CORPORATION ANNUAL INFORMATION FORM

APPENDIX B

FORM 51-101F3

REPORT OF

MANAGEMENT AND DIRECTORS

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, 2012, 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 Foo”

Wayne Foo

Director

Pengrowth Energy Corporation

(signed) “Kelvin B. Johnston”

Kelvin B. Johnston

Director

Pengrowth Energy Corporation

February 28, 2013

APPENDIX B | PENGROWTH ENERGY CORPORATION ANNUAL INFORMATION FORM

APPENDIX C

AUDIT AND RISK COMMITTEE

TERMS OF REFERENCE

PENGROWTH ENERGY CORPORATION

Policies and Practices

Page

1 of 12

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 regards 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 will be comprised of three or more directors as determined by the Board. Each member of the Committee 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.

APPENDIX C | PENGROWTH ENERGY CORPORATION ANNUAL INFORMATION FORM

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 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.

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 Pengrowth. A notice of 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 Chairman of the Board and the CEO 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, may 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.

PENGROWTH ENERGY CORPORATION ANNUAL INFORMATION FORM | 67

SCOPE, DUTIES AND RESPONSIBILITIES

MANDATORY DUTIES

REVIEW PROCEDURES

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

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.

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).

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.

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

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

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.

APPENDIX C | PENGROWTH ENERGY CORPORATION ANNUAL INFORMATION FORM

Discretionary Duties

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

REVIEW PROCEDURES

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.

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.

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.

PENGROWTH ENERGY CORPORATION ANNUAL INFORMATION FORM | 69

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.

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.

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.

APPENDIX C | PENGROWTH ENERGY CORPORATION ANNUAL INFORMATION FORM

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, AUTHORITY TO ENGAGE ADVISORS AND EXPENSES

The Committee shall have direct access to such officers and employees of Pengrowth, to Pengrowth’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 Pengrowth’s expense. Pengrowth 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.

PENGROWTH ENERGY CORPORATION ANNUAL INFORMATION FORM | 71

Schedule “A”

Excerpt from Multilateral Instrument 52-110

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.

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.

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

5.	For the purposes of paragraph 3(f), direct compensation does not include

(a)

remuneration for acting as a member of the Board or any Board committee of Pengrowth, 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

(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 Board committee of Pengrowth on a part-time basis.

7.	For the purpose of paragraph 3, “Pengrowth” includes all of its subsidiary entities.

8.	Despite any determination made under paragraphs 3 through 7 above, an individual who

(a)

accepts, directly or indirectly, any consulting, advisory or other compensatory fee from Pengrowth or any subsidiary entity of Pengrowth, other than as remuneration for acting in his or her capacity as a member of the Board or any Board committee, or as a part-time chair or vice-chair of the Board or any Board committee; or

(b)

is an affiliated entity of Pengrowth or any of its subsidiary entities,

is considered to have a material relationship with Pengrowth.

9.	For the purposes of paragraph 8, the indirect acceptance by an individual of any consulting, advisory or other compensatory fee includes acceptance of a fee by

(a)

an individual’s spouse, minor child or stepchild, or a child or stepchild who shares the individual’s home; or

(b)

an entity in which such individual is a partner, member, an officer such as a managing director occupying a comparable position or executive officer, or occupies a similar position (except limited partners, non-managing members and those occupying similar positions who, in each case, have no active role in providing services to the entity) and which provides accounting, consulting, legal, investment banking or financial advisory services to Pengrowth or any subsidiary entity of Pengrowth.

10.	For the purposes of paragraph 8, compensatory fees do not include the receipt of fixed amounts of compensation under a retirement plan (including deferred compensation) for prior service with Pengrowth if the compensation is not contingent in any way on continued service.

Standard of “Financial Literacy”

An individual is financially literate if he or she has the ability to read and understand a set of financial statements that present a breadth and level of complexity of accounting issues that are generally comparable to the breadth and complexity of the issues that can reasonably be expected to be raised by Pengrowth’s financial statements.

PENGROWTH ENERGY CORPORATION ANNUAL INFORMATION FORM | 73

Schedule “B”

Excerpts from Rule 10A-3 of the Securities and Exchange Act of 1934

Standard of “Independence”

b.	Required standards.

1.	Independence.

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:

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

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:

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 person will be deemed not to be in control of a specified person for purposes of this section if the person:

Is not the beneficial owner, directly or indirectly, of more than 10% of any class of voting equity securities of the specified person; and

Is not an executive officer of the specified person.

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.

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

iii.

The following will be deemed to be affiliates:

An executive officer of an affiliate;

A director who also is an employee of an affiliate;

A general partner of an affiliate; and

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).

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.

The term indirect acceptance by a member of an audit committee of any consulting, advisory or other compensatory fee includes acceptance of such a fee by a spouse, a minor child or stepchild or a child or stepchild sharing a home with the member or by an entity in which such member is a partner, member, an officer such as a managing director occupying a comparable position or executive officer, or occupies a similar position (except limited partners, non-managing members and those occupying similar positions who, in each case, have no active role in providing services to the entity) and which provides accounting, consulting, legal, investment banking or financial advisory services to the issuer or any subsidiary of the issuer.

PENGROWTH ENERGY CORPORATION ANNUAL INFORMATION FORM | 75

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)

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).

(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.

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.

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

C-2

to Appendix C

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

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

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

PENGROWTH ENERGY CORPORATION ANNUAL INFORMATION FORM | 77

LOGO

PENGROWTH ENERGY CORPORATION

2100, 222 Third Avenue S.W., Calgary, AB T2P 0B4 Canada

Phone: 403.233.0224 | Toll free: 800.223.4122 | Fax: 403.265.6251

www.pengrowth.com

Investor Relations

Phone: 403.233.0224 | Toll free: 888.744.1111

E-mail: investorrelations@pengrowth.com

Stock Exchange Listings

Toronto Stock Exchange: PGF | New York Stock Exchange: PGH

APPENDIX B

MANAGEMENT’S DISCUSSION AND ANALYSIS

SUMMARY OF FINANCIAL & OPERATING RESULTS


(monetary amounts in millions, except per share and per boe amounts or as otherwise stated)	Three months ended									Twelve months ended
	Dec 31, 2012			Dec 31, 2011			% Change			Dec 31, 2012			Dec 31, 2011		% Change
PRODUCTION
Average daily production (boe/d)		94,039			76,691			23			85,748			73,973		16
CASH FLOW
Funds flow from operations ⁽¹⁾	$	189.7		$	171.1			11		$	538.8		$	620.0		(13	)
Funds flow from operations per share	$	0.37		$	0.50			(26	)	$	1.20		$	1.87		(36	)

Oil and gas sales ⁽³⁾	$	431.5		$	389.2			11		$	1,480.3		$	1,453.7		2
Oil and gas sales per boe	$	49.88		$	55.17			(10	)	$	47.17		$	53.84		(12	)

Operating expense	$	121.2		$	99.7			22		$	458.6		$	382.0		20
Operating expense per boe	$	14.01		$	14.13			(1	)	$	14.61		$	14.15		3

Royalty expense	$	69.5		$	72.3			(4	)	$	277.5		$	277.9		–
Royalty expense per boe	$	8.03		$	10.25			(22	)	$	8.84		$	10.29		(14	)
Royalty expense as a percent of sales		16.1%			18.6%						18.7%			19.1%

Operating netback per boe	$	27.09		$	29.99			(10	)	$	22.93		$	28.45		(19	)

Cash G&A expense	$	18.1		$	16.3			11		$	66.5		$	64.3		3
Cash G&A expense per boe	$	2.09		$	2.31			(10	)	$	2.12		$	2.38		(11	)

Capital expenditures ⁽²⁾	$	93.9		$	142.0			(34	)	$	467.4		$	608.5		(23	)
Capital expenditures per share	$	0.18		$	0.41			(56	)	$	1.05		$	1.83		(43	)

Capital expenditures including net cash acquisitions ⁽²⁾	$	150.1		$	132.4			13		$	554.0		$	600.2		(8	)
Capital expenditures including net cash acquisitions per share	$	0.29		$	0.38			(24	)	$	1.24		$	1.81		(31	)

Dividends paid	$	61.1		$	71.4			(14	)	$	289.1		$	277.5		4
Dividends paid per share	$	0.12		$	0.21			(43	)	$	0.69		$	0.84		(18	)

Number of shares outstanding at period end (000’s)		511,804			360,282			42			511,804			360,282		42
Weighted average number of shares outstanding (000’s)		509,960			345,163			48			447,232			332,182		35
STATEMENT OF INCOME (LOSS)
Adjusted net income (loss) ⁽⁴⁾	$	24.1		$	22.3			8		$	(89.7	)	$	110.9		(181	)
Net income (loss)	$	(1.1	)	$	(9.0	)		(88	)	$	12.7		$	84.5		(85	)
Net income (loss) per share	$	–		$	(0.03	)		–		$	0.03		$	0.25		(88	)
LONG TERM DEBT
Long term debt ⁽⁵⁾	$	1,530.6		$	1,007.7			52		$	1,530.6		$	1,007.7		52
Convertible debentures	$	237.1		$	–			–		$	237.1		$	–		–
Total long term debt including convertible debentures	$	1,767.7		$	1,007.7			75		$	1,767.7		$	1,007.7		75
CONTRIBUTION BASED ON OPERATING NETBACKS ⁽⁴⁾
Light oil		66%			54%						69%			53%
Heavy oil		10%			14%						12%			12%
Natural gas liquids		13%			20%						15%			17%
Natural gas		11%			12%						4%			18%
PROVED PLUS PROBABLE RESERVES
Light oil (Mbbls)											153,229			116,823		31
Heavy oil (Mbbls)											127,454			31,898		300
Natural gas liquids (Mbbls)											39,681			30,746		29
Natural gas (Bcf)											1,150			906		27
Total oil equivalent (Mboe)											511,960			330,511		55
CAPITAL PERFORMANCE
Finding & Development Cost (F&D) (per boe) ⁽⁶⁾										$	16.85		$	20.12		(16	)
Finding, Development & Acquisition Cost (FD&A) (per boe) ⁽⁶⁾										$	18.16		$	20.04		(9	)
Recycle ratio ⁽⁷⁾											1.4			1.4		–

⁽¹⁾	See definition under section “Additional GAAP Measures”.

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

⁽³⁾	Includes the impact of realized commodity risk management contracts.

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

⁽⁵⁾	Long term debt includes the current and long term portion.

⁽⁶⁾	Includes changes in Future Development Capital (“FDC”) and based on Proved plus Probable Reserves.

⁽⁷⁾	Recycle ratio is calculated as operating netback per boe divided by F&D costs per boe based on Proved plus Probable Reserves.

Note regarding currency: all figures contained within this report are quoted in Canadian dollars unless otherwise indicated.

Note regarding oil production: references to light oil contained within this report include light and medium oil.


PENGROWTH 2012 Summary of Financial & Operating Results			3

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, 2012 of Pengrowth Energy Corporation. This MD&A is based on information available to February 28, 2013.

Pengrowth’s fourth quarter and annual results for 2012 are contained within this MD&A.

BUSINESS OF THE CORPORATION

This MD&A contains the results of Pengrowth and seven months of results from its subsidiary, NAL Energy Corporation (“NAL”) which was acquired by Pengrowth on May 31, 2012 and which was amalgamated with Pengrowth on January 1, 2013.

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 and “MWh” refers to megawatt hour. 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, deferred income taxes, goodwill, asset retirement obligations, taxability of dividends, remediation, reclamation and abandonment expenses, capital expenditures, development activities, general and administration expenses, 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 proceeds of anticipated divestitures, 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, our ability to add production and reserves through our development, exploitation and exploration activities, our ability to complete divestments to generate cash to repay debt and fund capital projects. Although management considers these assumptions to be reasonable based on information currently available to it, they may prove to be incorrect.


4			PENGROWTH 2012 Management’s Discussion & Analysis

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; 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 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 Consolidated Financial Statements, management information circular, quarterly reports, material change reports and news releases. Copies of Pengrowth’s Canadian public filings are available on SEDAR at www.sedar.com. Pengrowth’s U.S. public filings, including the most recent annual report form 40-F as supplemented by its filings on form 6-K, are available at www.sec.gov.

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

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

CRITICAL ACCOUNTING ESTIMATES

The audited Consolidated Financial Statements are prepared in accordance with IFRS. Management is required to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the Consolidated Financial Statements and revenues and expenses for the period ended. Certain of these estimates may change from period to period resulting in a material impact on Pengrowth’s results of operations, financial position, and change in financial position.

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 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 Cash Generating Units (“CGUs”)

CGUs are the smallest group of assets that generate cash inflows largely independent from other assets or group of assets. 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. The recoverability of development and production asset carrying values are assessed at the CGU level. 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 Obligation


PENGROWTH 2012 Management’s Discussion & Analysis			5

wells is estimated to take place far in the future. Therefore, changes in estimated timing of future expenses, estimated logistics of performing abandonment work 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

Impairment testing of property, plant and equipment is completed for each of Pengrowth’s CGUs. Impairment testing is based primarily on estimates of proved plus probable reserves, production rates, oil and natural gas prices, future costs, discount rates and other relevant assumptions including undeveloped land and contingent resources. The impairment assessment of goodwill is based on the estimated fair value of Pengrowth’s CGUs. By their nature, these estimates are subject to measurement uncertainty and may impact the financial statements of future periods.

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.

NAL Acquisition

In connection with the NAL Acquisition completed on May 31, 2012, fair values assigned to the various assets and liabilities of NAL were based on internal and third party estimates.

COMPARATIVE FIGURES

Certain changes to the presentation of transportation costs by product type were made in 2012 and, as such, comparative periods have been restated with no impact to net income. In 2012, the MD&A disclosures for the capital expenditures are presented net of capitalized stock based compensation as presented on the Consolidated Statements of Cash Flow. Management believes that these presentation changes better reflect Pengrowth’s operating results. As required under IFRS, changes in the accounting for the NAL Acquisition that arose in the fourth quarter of 2012 were adjusted retrospective to the second quarter of 2012.

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. Measures such as operating netbacks do not have standardized meanings prescribed by GAAP. See the section of this MD&A entitled Operating Netbacks for a discussion of the calculation.

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

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

Payout Ratio is a term used to evaluate financial flexibility and the capacity to fund dividends. Payout Ratio is defined on a percentage basis as dividends declared divided by Funds Flow from Operations. Management believes that, 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 mark to market gains and losses, non-cash


6			PENGROWTH 2012 Management’s Discussion & Analysis

mark to market gains and losses on investments, gains on acquisitions (negative goodwill) and unrealized foreign exchange gains and losses that may significantly impact net income (loss) from period to period. Management believes that segregating General and Administrative (“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 year end share prices 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 year end share prices 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 Capital (“FDC”).

CURRENCY

All amounts are stated in Canadian dollars unless otherwise specified.

2012 AND 2013 GUIDANCE AND 2012 FINANCIAL HIGHLIGHTS

The following table provides a summary of the 2012 and 2013 Guidance and a review of 2012 actual results.


	2012		2012		2012			2013
	Guidance		Actual		Variance			Guidance⁽¹⁾⁽⁴⁾
Annual average production (boe/d)		86,000 - 89,000		85,748		–			85,000 - 87,000
Fourth quarter production		93,000 - 96,000		94,039		–			N/A
Royalty expense (% of sales) ⁽²⁾		20.0		18.7		(1.3	)		17.0
Operating expense ($/boe)		14.60		14.61		0.01			14.00 - 14.50
G&A expense (cash & non-cash) ($/boe)		2.68		2.51		(0.17	)		3.30
Capital expenditures ($ millions) ⁽³⁾		525.0		467.4		(57.6	)		770

⁽¹⁾	Based on guidance levels provided on January 11, 2013, after considering the disposition of Weyburn.

⁽²⁾	Royalty expense as a % of sales includes the impact of commodity risk management contracts.

⁽³⁾	Excludes the portion of capital spent by NAL prior to acquisition, but includes capitalized net operating results of Lindbergh pilot project.

⁽⁴⁾	Starting in 2013, Pengrowth will reclassify approximately $20 million relating primarily to technical support costs to G&A from operating expenses.

Full year and fourth quarter production were at the low end of Guidance primarily due to the ongoing outage at Sable Offshore Energy Project (“SOEP”) and third party pipeline capacity and sales restrictions at Pine Creek. The impact of the SOEP outage was 640 boe/d for the full year 2012 and 1,850 boe/d for the fourth quarter 2012.

Royalty expense was lower than Guidance primarily due to the impact of lower NAL royalty rates, an increase in Gas Cost Allowance (“GCA”) credits and lower commodity prices.

Operating expenses were essentially on target with Guidance.


PENGROWTH 2012 Management’s Discussion & Analysis			7

G&A expenses were lower than Guidance due to additional NAL production with little incremental G&A added.

Capital expenditures amounted to $467.4 million in 2012 which was below the $525.0 million Guidance as Pengrowth moderated spending in a weak commodity price environment.

Production and related operating and other expenses from the Lindbergh pilot are excluded from these items in the table above. Pengrowth included production revenue and costs associated with the Lindbergh pilot project in capital expenditures prior to project sanctioning in January 2013. See Note 7 to the audited Consolidated Financial Statements for additional information. Pengrowth will record revenue, operating and other expenses from Lindbergh in its results, starting in 2013.

FINANCIAL HIGHLIGHTS


	Three months ended									Twelve months ended
	Dec 31, 2012			Sept 30, 2012			Dec 31, 2011			Dec 31, 2012			Dec 31, 2011
Production (boe/d)		94,039			94,284			76,691			85,748			73,973
Capital expenditures ($ millions) ⁽¹⁾		93.9			110.6			142.0			467.4			608.5
Funds flow from operations ($ millions)		189.7			141.1			171.1			538.8			620.0
Operating netback ($/boe)⁽²⁾		27.09			21.51			29.99			22.93			28.45
Adjusted net income (loss) ($ millions) ⁽³⁾		24.1			(18.7	)		22.3			(89.7	)		110.9
Net income (loss) ($ millions)		(1.1	)		(23.7	)		(9.0	)		12.7			84.5

⁽¹⁾	Prior periods restated to conform to presentation in the current period.

⁽²⁾	Includes the impact of realized commodity risk management contracts.

⁽³⁾	See definition under section “Non-GAAP Financial Measures”.

Funds Flow from Operations


($ millions)	Q3/12 vs. Q4/12				% Change			Q4/11 vs. Q4/12				% Change			2011 vs. 2012				% Change
Funds flow from operations for comparative period		Q3/12	141.1						Q4/11	171.1						2011	620.0
Change due to:
Volume			7.7			5				99.0			58				286.5			46
Price			24.3			17				(69.6	)		(41	)			(264.0	)		(43	)
Realized gains on risk management contracts			7.2			5				14.8			9				5.2			1
Other income			0.4			–				(1.9	)		(1	)			(1.1	)		–
Royalty expense			(2.0	)		(1	)			2.8			2				0.4			–
Expenses:
Operating			10.9			8				(21.5	)		(13	)			(76.6	)		(12	)
Cash G&A			(2.5	)		(2	)			(1.8	)		(1	)			(2.2	)		–
Interest & financing			(2.1	)		(1	)			(4.6	)		(3	)			(10.5	)		(2	)
Other expenses including transportation and NAL acquisition costs			4.7			3				1.4			1				(18.9	)		(3	)
Funds flow from operations		Q4/12	189.7			34			Q4/12	189.7			11			2012	538.8			(13	)

The 34 percent increase in Funds Flow from Operations in the fourth quarter compared to the third quarter of 2012, was primarily due to higher natural gas prices in the quarter, increased oil production and commodity risk management gains, as well as lower operating expenses. Higher natural gas revenue, net of volume and risk management impacts, contributed $20.2 million to the Funds Flow from Operations when comparing the fourth quarter to the third quarter of 2012.


8			PENGROWTH 2012 Management’s Discussion & Analysis

The 11 percent increase in Funds Flow from Operations in the fourth quarter compared to the fourth quarter of 2011, was primarily due to higher production volumes as a result of the NAL Acquisition partly offset by significantly lower average realized prices and higher operating costs. Higher discounts of the Canadian light oil versus WTI benchmark during the fourth quarter had an unfavourable financial impact on oil sales of approximately $14 million compared to the same period last year.

The 13 percent decrease in Funds Flow from Operations for the full year of 2012 compared to 2011, was primarily due to significantly lower average realized prices and higher operating and other expenses, partly offset by higher oil and natural gas production volumes from the NAL Acquisition. Other expenses for 2012 included approximately $22 million in one-time NAL Acquisition costs. Higher discounts of the Canadian light oil versus WTI benchmark during 2012 had an unfavourable financial impact on oil sales of approximately $93 million compared to 2011.

Net Income (Loss)

Pengrowth recorded a net loss of $1.1 million in the fourth quarter compared to a net loss of $23.7 million in the third quarter of 2012, representing a $22.6 million improvement. The decrease in net loss was primarily driven by the increase in Funds Flow from Operations and lower unrealized losses on commodity risk management partly offset by higher unrealized foreign exchange losses and an unrealized loss on an investment.

The fourth quarter net loss decreased by $7.9 million from a net loss of $9.0 million in the same period last year. The change was also driven by the increase in Funds Flow from Operations and a lower unrealized loss on commodity risk management partly offset by increases in Depletion, Depreciation and Amortization (“DD&A”) coupled with unrealized foreign exchange and investment losses.

For the full year 2012, Pengrowth recorded net income of $12.7 million compared to net income of $84.5 million for 2011. The $71.8 million decrease in net income was primarily driven by higher DD&A and impairment charges, a decrease in Funds Flow from Operations partly offset by a gain on commodity risk management, a gain on acquisition and a tax recovery.

Adjusted Net Income (Loss)

The following table provides a reconciliation of net income (loss) to Adjusted Net Income (Loss):


	Three months ended									Twelve months ended
($ millions)	Dec 31, 2012			Sept 30, 2012			Dec 31, 2011			Dec 31, 2012			Dec 31, 2011
Net income (loss)		(1.1	)		(23.7	)		(9.0	)		12.7			84.5
Less non-cash items included in net income (loss):
Unrealized gain (loss) on commodity risk management		(0.6	)		(45.4	)		(102.9	)		30.6			(40.0	)
Unrealized foreign exchange gain (loss)		(13.3	)		33.1			29.2			21.9			(19.1	)
Non-cash mark to market gain (loss) on investments		(15.0	)		–			23.0			(15.0	)		23.0
Gain on acquisition		–			–			–			73.5			–
Tax effect on non-cash items above		3.7			7.3			19.4			(8.6	)		9.7
		(25.2	)		(5.0	)		(31.3	)		102.4			(26.4	)
Adjusted net income (loss)		24.1			(18.7	)		22.3			(89.7	)		110.9


PENGROWTH 2012 Management’s Discussion & Analysis			9

The following table represents a continuity of Adjusted Net Income (Loss):


($ millions)	Q3/12 vs. Q4/12				Q4/11 vs. Q4/12				2011 vs. 2012
Adjusted net income (loss) for comparative period		Q3/12	(18.7	)		Q4/11	22.3			2011	110.9
Funds flow from operations increase (decrease)			48.6				18.6				(81.2	)
DD&A and accretion expense increase			(3.1	)			(49.2	)			(134.1	)
Impairment charges (increase) decrease			–				27.4				(50.9	)
Gain on disposition decrease			(8.1	)			(9.9	)			(2.7	)
Other			1.8				(2.6	)			(4.4	)
			39.2				(15.7	)			(273.3	)
Estimated tax reduction (increase) on above			(9.9	)			4.0				69.2
Tax adjustments			13.5				13.5				3.5
Adjusted net income (loss)		Q4/12	24.1			Q4/12	24.1			2012	(89.7	)

Pengrowth recorded Adjusted Net Income of $24.1 million in the fourth quarter of 2012 compared to an Adjusted Net Loss of $18.7 million in the prior quarter. This change was driven by the positive impact of an increase in Funds Flow from Operations and a deferred tax adjustment, partly offset by slightly higher DD&A and an absence of the prior quarter gain on disposition.

In comparison to the same period last year, Pengrowth recorded an increase in Adjusted Net Income of $1.8 million in the fourth quarter of 2012. An increase in Funds Flow from Operations, a deferred tax adjustment and the absence of impairment charges in the current quarter, partly offset by the increase in DD&A were the primary reasons for the change.

For the full year 2012, Pengrowth recorded an Adjusted Net Loss of $89.7 million compared to Adjusted Net Income of $110.9 million in 2011. The decrease in Funds Flow from Operations coupled with increases in DD&A and impairment charges were the primary drivers of the year over year change.

Price Sensitivity

The following table illustrates the sensitivity of Funds Flow from Operations to changes in commodity prices:


							Estimated Impact on 12 Month Funds Flow
COMMODITY PRICE ENVIRONMENT ⁽¹⁾			Assumption		Change		($ millions)			$ Per Share
West Texas Intermediate Oil^{(2) (4)}	U.S.$	/bbl	$	90.00	$	1.00
Light oil ⁽³⁾								8.6			0.016
Light oil risk management⁽⁵⁾								(6.6	)		(0.013	)
Heavy oil ⁽³⁾								2.3			0.004
NGLs								3.0			0.006
Net impact of $1/bbl change in WTI								7.3			0.013
AECO Natural Gas ⁽²⁾⁽⁴⁾	Cdn$	/Mcf		$3.50	$	0.10
Natural gas								7.4			0.014
Natural gas risk management⁽⁵⁾								(4.7	)		(0.009	)
Net impact of $0.10/Mcf change in AECO								2.7			0.005

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

⁽²⁾	Commodity price is based on the assumptions inside Pengrowth’s 2013 budget.

⁽³⁾	Includes an average Cdn$ WTI to Edmonton light oil differential of Cdn$8.00/bbl and a heavy oil differential of Cdn$21.00/bbl.

⁽⁴⁾	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,

⁽⁵⁾	Includes risk management contracts as at February 13, 2013.

NAL ACQUISITION

On May 31, 2012, Pengrowth acquired all issued and outstanding common shares of NAL in exchange for 0.86 of a Pengrowth share per NAL share (the “NAL Acquisition”). The NAL Acquisition resulted in the issuance of 131.2 million Pengrowth common shares to former NAL shareholders, as well as the assumption by Pengrowth of NAL’s convertible debentures and long term debt. The TSX closing share price of Pengrowth on the acquisition date of May 31, 2012, was $7.36 per share.


10			PENGROWTH 2012 Management’s Discussion & Analysis

The transaction was accounted for using the acquisition method based on fair values as follows:


Acquired net assets:	($ millions)
Property, plant and equipment		1,748.0
Derivative instruments		16.2
Inventory		2.5
Convertible debentures		(349.0	)
Bank debt		(219.1	)
Working capital deficiency		(46.9	)
Asset retirement obligations		(47.0	)
Deferred tax liability		(65.5	)
Gain on acquisition		(73.5	)
		965.7

The estimated fair value of property, plant and equipment was determined using both internal estimates and an independent reserve evaluation. The deferred tax liability was determined based on applying Pengrowth’s effective deferred income tax rate of approximately 25 percent to the difference between the book and tax basis of the net assets acquired. The asset retirement obligation was determined using Pengrowth’s estimated timing and costs to remediate, reclaim and abandon the wells and facilities. An inflation rate of 2 percent and a discount rate of 8 percent were used. As part of finalizing of certain balances Pengrowth decreased the previously recorded working capital deficiency by $5.7 million resulting in an adjustment to the gain on acquisition which will be reflected in the second quarter of 2012 comparative quarterly figures.

The gain on acquisition amounted to $73.5 million and is recorded as a separate line item on the Consolidated Statements of Income. This gain has no basis for tax purposes.

RESULTS OF OPERATIONS

(All volumes, wells and spending amounts stated below reflect Pengrowth’s net working interest unless otherwise stated.)

CAPITAL EXPENDITURES

For the full year 2012, Pengrowth spent $467.4 million on capital expenditures excluding property acquisitions and dispositions. Approximately 79 percent of capital expenditures were invested in drilling, completions and facilities, with the remaining 21 percent spent on land, seismic, maintenance and other capital.


	Three months ended									Twelve months ended
($ millions)	Dec 31, 2012			Sept 30, 2012			Dec 31, 2011			Dec 31, 2012			Dec 31, 2011
Drilling, completions and facilities⁽¹⁾		71.0			88.2			124.4			367.9			532.9
Land & seismic acquisitions⁽²⁾		1.5			1.8			6.9			18.2			20.6
Maintenance capital		18.8			18.1			12.2			74.4			51.7
Development capital		91.3			108.1			143.5			460.5			605.2
Other capital ⁽³⁾		2.6			2.5			(0.8	)		6.9			5.7
Drilling royalty credits		–			–			(0.8	)		–			(2.4	)
Capital expenditures		93.9			110.6			141.9			467.4			608.5
Property acquisitions		65.3			5.5			–			113.2			8.6
Proceeds on property dispositions		(9.1	)		(15.2	)		(9.5	)		(26.6	)		(16.9	)
Capital expenditures including net cash acquisitions		150.1			100.9			132.4			554.0			600.2

⁽¹⁾	Prior periods restated to conform to presentation in the current period.

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

⁽³⁾	Other capital includes equipment inventory and material transfers.


PENGROWTH 2012 Management’s Discussion & Analysis			11

DRILLING ACTIVITY

Pengrowth participated in the drilling of 183 gross wells (93.3 net) in 2012.


	Three months ended						Twelve months ended
	Dec 31, 2012			Sept 30, 2012			Dec 31, 2012
		Gross	Net		Gross	Net		Gross	Net
Focus Areas ⁽¹⁾
Swan Hills		6	3.5		7	5.5		36	25.2
Greater Olds/Garrington		10	3.4		18	9.6		41	19.0
Lindbergh ⁽²⁾		6	6.0		1	1.0		24	24.0
Other Areas ⁽¹⁾		21	4.9		20	8.3		82	25.1
Total wells drilled		43	17.8		46	24.4		183	93.3

⁽¹⁾	Drilling activity reflects both operated and non-operated properties.

⁽²⁾	Wells drilled relate to the core hole assessment program.

DRILLING AND COMPLETIONS CAPITAL ACTIVITIES

Pengrowth’s capital spending breakdown by area is as follows:


	Three months ended				Twelve months ended
($ millions)	Dec 31, 2012		Sept 30, 2012		Dec 31, 2012
Focus Areas ⁽¹⁾
Swan Hills		22.7		38.3		170.7
Greater Olds/Garrington		23.5		30.8		94.8
Lindbergh ⁽²⁾		9.7		2.1		35.5
		55.9		71.2		301.0
Other Areas ⁽¹⁾		15.1		17.0		66.9
Drilling, completions and facilities		71.0		88.2		367.9

⁽¹⁾	Spending amounts reflect the activity for both operated and non-operated properties.

⁽²⁾	Pengrowth included production revenue and costs associated with the Lindbergh pilot project in capital expenditures until the first phase of the project was sanctioned in January 2013.

Focus Areas

(Pengrowth references average well test results for certain properties. These results are not necessarily representative of long term well performance or ultimate recoveries.)

Swan Hills Trend

With a net estimated 2.3 billion barrels of 42° API original oil in place in the Beaverhill Lake formation (Energy Resources Conservation Board estimate), the Swan Hills Trend is a significant conventional oil resource for Pengrowth. This extensive carbonate oil reservoir provides Pengrowth with significant opportunities to put its expertise in horizontal drilling and multi-stage acid fracturing of carbonate reservoirs to work on its operated interests in Judy Creek, Carson Creek, Deer Mountain, Virginia Hills and Sawn Lake.

During the fourth quarter, Pengrowth drilled 3 operated wells (3.0 net) in the Swan Hills area (2 oil wells and 1 produced water injector), and participated in the drilling of 3 non-operated oil wells (0.5 net).

During 2012, Pengrowth spent $170.7 million on development activities targeting light oil and liquids-rich opportunities at Judy Creek, Carson Creek, Deer Mountain and Virginia Hills. Pengrowth drilled a total of 24 operated wells (22.7 net), primarily targeting the tighter platform and R5 shoal. In addition, 12 partner-operated oil wells (2.5 net) were drilled targeting the House Mountain, Freeman and Sawn Lake plays.

Greater Olds/Garrington Area

Pengrowth holds a large, contiguous land base in the greater Olds/Garrington area of over 500 gross sections of Cardium rights, extensive infrastructure and significant operatorship.


12			PENGROWTH 2012 Management’s Discussion & Analysis

Activity in the Cardium continued in the fourth quarter with 2 operated (1.3 net) wells being drilled at Lochend. Both wells were completed and brought on production in January 2013. Non operated Cardium drilling accounted for 7 (1.2 net) wells during the fourth quarter of 2012 all of which are expected to be on production in the first quarter of 2013.

During the fourth quarter, Pengrowth acquired additional assets in the Lochend area to complement the large position associated with the NAL Acquisition adding approximately 530 boe/d with more optimization of this production expected in early 2013. This acquisition also added 32 net drilling locations. In total, Pengrowth has identified more than 80 drillable locations (55 net) in the Lochend area. Pengrowth also increased its natural gas handling capacity at the Lochend battery with additional compression being added which has significantly reduced incineration in the area.

In the fourth quarter, Pengrowth continued with the liquids-rich gas program in the Elkton formation, drilling 1 operated (0.9 net) well for which completion and testing was done before year end with the final tie-in expected in early January 2013. The five day average IP rate for this well was approximately 250 boe/d of liquids rich natural gas.

Full year 2012, Pengrowth spent $94.8 million on development activities in the greater Olds/Garrington area, participating in the drilling of 41 wells (19.0 net).

Lindbergh

The Lindbergh property, located in the Cold Lake area of Alberta and encompassing 42.5 gross sections of land, is 100 percent owned and operated by Pengrowth. The Lindbergh thermal project targets the Lloydminster formation, where the bitumen has better flow characteristics and oil quality, which will translate into higher netbacks than originally anticipated. Based on very positive pilot project results during 2012, an initial 12,500 bbl/d commercial development was sanctioned by the Board of Directors in January 2013 and will be constructed during 2013 and 2014. The engineering phase of the 12,500 bbl/d project is ongoing, with capital investment in critical path and long lead items being completed. Subject to permitting, field construction is slated to begin by mid 2013 with drilling activities to commence in the fourth quarter of 2013. Lindbergh is expected to provide Pengrowth with the potential to develop production of up to 50,000 bbl/d of bitumen over three phases of development. This is expected to be low operating and sustaining capital cost, low decline, stable oil production, with a twenty-five year reserve life.

Pengrowth drilled 6 (6.0 net) core holes at Lindbergh in the fourth quarter with results as anticipated. The wells were drilled in support of the commercial application currently being compiled for the second phase which will increase the facility to 30,000 bbl/d. The application is anticipated to be submitted by the end of 2013.

2013 Capital Program

Pengrowth anticipates a 2013 capital program, excluding acquisitions, of $770 million. This is a 65 percent increase from 2012 capital expenditures of $467.4 million and is focused on both thermal and conventional programs. Pengrowth’s $470 million conventional capital program is focused on oil and liquids rich plays at Swan Hills and the greater Olds/Garrington area, while the thermal capital program of $300 million is focused on the Lindbergh 12,500 bbl/d project.

RESERVES AND PERFORMANCE MEASURES

Reserves – Company Interest at Forecast Prices


Reserves Summary (MMboe except as noted)	2012		2011			2010
Proved Reserves
Additions + Revisions for the year		21.0		41.0			20.5
Net Acquisitions (Dispositions) for the year		75.9		(0.2	)		11.2
Total Proved Reserves at period end		300.1		234.9			221.0
Proved Reserve replacement ratio excluding net acquisitions		66%		152%			75%
Proved Reserve replacement ratio including net acquisitions		306%		151%			116%
Proved plus Probable Reserves (P+P)
Additions + Revisions for the year		103.8		39.3			27.1
Net Acquisitions (Dispositions) for the year		109.4		(0.3	)		22.8
Total Proved plus Probable Reserves at period end		512.0		330.5			318.4
Total Production (MMboe) ⁽¹⁾		31.7		27.0			27.3
P+P Reserve replacement ratio excluding net acquisitions		327%		146%			99%
P+P Reserve replacement ratio including net acquisitions		672%		145%			183%

⁽¹⁾	2012 includes production from Lindbergh pilot project.


PENGROWTH 2012 Management’s Discussion & Analysis			13

Pengrowth reported year end Proved Reserves of 300.1 MMboe and Total Proved plus Probable reserves of 512.0 MMboe for 2012, representing increases of 28 percent and 55 percent, respectively, from year end 2011. During 2012, Pengrowth’s development and optimization activities as well as the sanctioning of the Lindbergh thermal project resulted in the addition of 21.0 MMboe of Proved Reserves and 103.8 MMboe of Total Proved plus Probable Reserves including revisions. The NAL Acquisition along with some strategic asset acquisitions in 2012, offset by minor dispositions, resulted in overall increases of 75.9 MMboe in Proved Reserves and 109.4 MMboe in Total Proved Plus Probable Reserves. The reserve additions in 2012 resulted in a reserve replacement ratio of 327 percent for Total Proved Plus Probable Reserves excluding net acquisitions, and 672 percent including net acquisitions.

Further details of Pengrowth’s 2012 year end reserves, Finding and Development (“F&D”) and Finding, Development & Acquisition (“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	2012		2011		2010		3 year weighted average
Excluding Net Acquisitions (F&D)
Excluding Changes in FDC
F&D costs per boe – (P+P)	$	4.44	$	15.34	$	12.15		$ 8.19
Recycle Ratio⁽¹⁾		5.2		1.9		2.2		3.2
Including Changes in FDC
F&D costs per boe – (P+P)	$	16.85	$	20.12	$	15.32		$17.36
Recycle Ratio⁽¹⁾		1.4		1.4		1.8		1.5

Including Net Acquisitions (FD&A)
Excluding Changes in FDC
FD&A costs per boe – (P+P)	$	9.92	$	15.23	$	14.61		$11.38
Recycle Ratio⁽²⁾		2.3		1.9		1.8		2.3
Including Changes in FDC
FD&A costs per boe – (P+P)	$	18.16	$	20.04	$	18.46		$18.45
Recycle Ratio⁽²⁾		1.3		1.4		1.5		1.4

⁽¹⁾	Recycle Ratio is calculated as operating netback per boe ($22.93/boe for 2012) divided by F&D costs per boe based on proved plus probable reserves.

⁽²⁾	Recycle Ratio is calculated as operating netback per boe divided by FD&A costs per boe based on proved plus probable reserves.

The 2012 total proved plus probable F&D cost, including changes in Future Development Capital (“FDC”), was $16.85/boe, a 16 percent decrease from the 2011 F&D cost. The decrease from 2011 is primarily due to the addition of 88.8 MMboe for the Lindbergh thermal project.

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 2012 yielded a recycle ratio, excluding net acquisitions and including changes in FDC, of 1.4 on a proved plus probable basis, in line with the three year average of 1.5. Despite an improvement in the F&D cost, the recycle ratio remained unchanged from 2011 as the netback was negatively impacted by lower realized oil prices and depressed natural gas prices.


Other Performance Measures	2012		2011		2010
Production per share (boe/share)		0.07		0.08		0.09
Production per debt adjusted share (boe/share)⁽¹⁾		0.04		0.06		0.07
Reserves per share – (P+P) (boe/share)		1.00		0.92		0.98
Reserves per debt adjusted share – (P+P) (boe/share)⁽¹⁾		0.60		0.73		0.78

⁽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.


14			PENGROWTH 2012 Management’s Discussion & Analysis

Pengrowth’s goal over longer periods is to modestly grow production and reserves per debt adjusted share, while continuing to pay a prudent dividend. On a debt adjusted basis, production and total proved plus probable reserves per share decreased in 2012, primarily due to the reduction in Pengrowth’s share price used to value the debt at December 31, 2012. However, overall production growth was 16 percent and the reserve replacement ratio was 327 percent for the year which positively impacted reserves per share.

PRODUCTION


	Three months ended												Twelve months ended
Daily production	Dec 31, 2012		% of total		Sept 30, 2012		% of total		Dec 31, 2011		% of total		Dec 31, 2012		% of total		Dec 31, 2011		% of total
Light oil (bbls)		31,898		34		31,110		33		22,935		30		28,005		33		21,455		29
Heavy oil (bbls)		6,532		7		6,502		7		6,448		8		6,514		8		6,425		9
Natural gas liquids (bbls)		11,611		12		10,779		11		10,478		14		10,731		12		9,659		13
Natural gas (Mcf)		263,983		47		275,357		49		220,977		48		242,992		47		218,601		49
Total boe per day		94,039				94,284				76,691				85,748				73,973

The above table includes seven months of NAL production and excludes production from the Lindbergh thermal project.

Fourth quarter average daily production remained relatively unchanged when compared to the prior quarter. The incremental production from new drills and from the November acquisition of assets at Lochend was partially offset by an ongoing outage at SOEP, where the Venture offshore platforms remained shut-in for the entire fourth quarter reducing production by 1,850 boe/d. The addition of the NAL production is the primary driver of the 23 percent increase when comparing fourth quarter production to the same period last year and was in part offset by the SOEP operational outage and natural declines. Full year average daily production increased 16 percent when compared to 2011 and was positively impacted by both the addition of NAL volumes and production from new wells at Lochend and Judy Creek, partially offset by the 640 boe/d production loss from the SOEP outage, and by natural declines.

Light Oil

Fourth quarter light oil average daily production increased 3 percent compared to the third quarter. The increase can be primarily attributed to the Lochend property acquisition and new wells drilled in the area. A 39 percent increase in light oil production in the current quarter compared to the same period in 2011 was due to added NAL production, while a 31 percent increase year over year is primarily due to added NAL production and production from the development program.

Heavy Oil

Heavy oil production, excluding Lindbergh, remained virtually unchanged in the fourth quarter compared to the third quarter as optimization efforts offset natural declines. Heavy oil volumes increased by 1 percent for the current quarter and the full year of 2012 compared to the same periods in 2011, as additional production and optimization efforts more than offset natural declines.

NGLs

NGL production increased 8 percent in the fourth quarter compared to the prior quarter due to a condensate shipment at SOEP as well as added production from new liquids-rich gas wells at Harmattan. Fourth quarter NGL production and full year production both increased 11 percent compared to the same periods last year, driven by additional NAL production but partly offset by the outage at SOEP and declines at Carson Creek.

Natural Gas

Natural gas production for the fourth quarter decreased 4 percent compared to the third quarter due to the extended outage at SOEP, capacity and sales restrictions at Pine Creek, as well as freeze-ups in several properties due to cold weather in December. Natural gas production increased 19 percent from the same quarter last year as the positive impact of the NAL Acquisition was partially offset by the extended outage at SOEP and natural declines. The 11 percent increase in natural gas production for the full year of 2012 compared to 2011 was also predominantly influenced by added production from the NAL Acquisition, partially offset by the SOEP outage, the Olds gas plant turnaround in the second quarter and the shut-in of dry gas production due to low natural gas prices during 2012.

As natural gas prices improved during the fourth quarter, approximately 500 boe/d of previously shut-in gas production has been brought back on stream. Approximately 500 boe/d of dry natural gas still remained shut-in for the fourth quarter of 2012.


PENGROWTH 2012 Management’s Discussion & Analysis			15

COMMODITY PRICES

Oil and Liquids Prices


	Three months ended								Twelve months ended
(Cdn$/bbl)	Dec 31, 2012			Sept 30, 2012			Dec 31, 2011		Dec 31, 2012			Dec 31, 2011
Average Benchmark Prices
WTI oil		87.36			91.78			95.98		94.15			94.17
Edmonton differential		(2.77	)		(8.48	)		1.93		(7.86	)		1.19
Edmonton par light oil		84.59			83.30			97.91		86.29			95.36
Average Realized Prices
Light oil ⁽¹⁾		80.44			80.89			94.77		82.61			92.10
after realized commodity risk management ⁽¹⁾		85.82			83.09			91.16		83.58			89.49
Heavy oil ⁽¹⁾		63.74			63.98			77.60		65.92			69.76
Natural gas liquids		56.64			51.45			70.54		57.91			69.31

⁽¹⁾	Prior periods restated to conform to presentation in the current period.

WTI benchmark average oil prices decreased 9 percent to Cdn$87.36/bbl in the fourth quarter of 2012 from an average price of Cdn$95.98/bbl in the fourth quarter of 2011, while the Canadian benchmark Edmonton par average light oil prices declined 14 percent compared to an average price of Cdn$97.91/bbl during the same period last year. For the full year, WTI averaged Cdn$94.15/bbl in 2012, essentially unchanged from the same period in 2011.

The price/bbl differential between Canadian light oil and WTI narrowed substantially in the fourth quarter compared to wider discounts throughout much of 2012. Canadian light oil traded at an average discount of Cdn$2.77/bbl to WTI in the fourth quarter, compared to a premium of Cdn$1.93/bbl in the same period of 2011. Full year, Canadian light oil prices traded at an average discount of Cdn$7.86/bbl to WTI in 2012, compared to a premium of Cdn$1.19/bbl to WTI in 2011. Pipeline constraints into the major U.S. refining hubs and increased light oil production from the U.S. Bakken fields were the primary reasons for the substantial discount. We expect the differentials to remain volatile until the pipeline constraints are resolved.

Pengrowth’s average realized price for light oil, after risk management activities, was $85.82/bbl in the fourth quarter, a decline of 6 percent from the fourth quarter of 2011. Full year 2012, light oil realized prices averaged $83.58/bbl, a 7 percent decline from the same period in 2011. Contributing to the lower realized prices in 2012 was the decline in Canadian benchmark light oil prices, primarily a result of the widening differential between Canadian light oil and the benchmark WTI oil prices, offset by gains from Pengrowth’s risk management activities.

Pengrowth’s average realized prices for heavy oil and natural gas liquids were down 18 and 20 percent, respectively, in the fourth quarter compared to the fourth quarter of 2011. Full year, prices declined 6 and 16 percent, respectively, primarily due to lower benchmark Canadian light oil pricing and widening price differentials to WTI benchmark prices.

Natural Gas Prices


	Three months ended									Twelve months ended
(Cdn$)	Dec 31, 2012			Sept 30, 2012			Dec 31, 2011			Dec 31, 2012			Dec 31, 2011
Average Benchmark Prices
NYMEX gas (per MMBtu)		3.50			2.88			3.55			2.83			3.99
AECO differential		(0.31	)		(0.58	)		(0.36	)		(0.45	)		(0.36	)
AECO spot gas (per MMBtu)		3.19			2.30			3.19			2.38			3.63
Average Realized Prices
Natural gas (per Mcf)		3.07			2.24			3.26			2.35			3.61
after realized commodity risk management		3.14			2.40			3.77			2.49			4.08

NYMEX gas in the fourth quarter showed a 21 percent improvement from the third quarter, but remained essentially flat compared to the same period of 2011. The full year 2012, NYMEX price of $2.83/MMBtu was approximately 29 percent below 2011. An abundant supply of natural gas, largely attributable to increased production from various North American shale gas plays, has resulted in record storage volumes of natural gas and weak prices.


16			PENGROWTH 2012 Management’s Discussion & Analysis

AECO spot gas price was $3.19/MMBtu in the fourth quarter as it continued to trade at a discount to the NYMEX gas benchmark with the differential averaging $0.31/MMBtu. This compares to $2.30/MMBtu in the third quarter and $3.19/MMBtu in the same period last year. The full year 2012 AECO spot price was $2.38/MMBtu which was down 34 percent from full year 2011. Higher transportation costs to major delivery points in the U.S. and an increase in domestic U.S. natural gas production, resulted in decreased demand and contributed to the lower pricing of Canadian natural gas.

Pengrowth’s average realized natural gas price, after risk management activities, was $3.14/Mcf during the fourth quarter of 2012, a 31 percent increase from the third quarter price of $2.40/Mcf, and a 17 percent decline compared to the fourth quarter of 2011 average price of $3.77/Mcf. Full year 2012, average realized natural gas prices were $2.49/Mcf, a 39 percent decline compared to an average price of $4.08/Mcf in the same period of 2011.

Pengrowth’s lower average realized prices in 2012 were attributable to a lower benchmark price for natural gas when compared to the same periods in 2011, coupled with a lower contribution from realized natural gas commodity risk management activities, as lower volumes were under risk management and at a lower average price.

Total Average Realized Prices


	Three months ended						Twelve months ended
($/boe)	Dec 31, 2012		Sept 30, 2012		Dec 31, 2011		Dec 31, 2012		Dec 31, 2011
Average realized price		47.33		43.53		53.88		45.89		52.50
after realized commodity risk management		49.36		44.73		54.28		46.60		53.13
Other production income		0.52		0.45		0.89		0.57		0.71
Total oil and gas sales		49.88		45.18		55.17		47.17		53.84

Pengrowth’s total average realized price, after risk management activities, during the fourth quarter of 2012 was $49.36/boe, a 9 percent decrease from the fourth quarter of 2011 average price of $54.28/boe. Full year average realized prices were $46.60/boe, a 12 percent decrease from $53.13/boe in the same period of 2011. The decrease in realized prices is primarily a result of lower Canadian benchmark prices for oil and liquids due to the substantial discounting of Canadian light oil versus the WTI benchmark oil prices, decreased Canadian natural gas prices as well as lower natural gas volumes being under risk management.

Commodity Risk Management Gains (Losses)


	Three months ended									Twelve months ended
	Dec 31, 2012			Sept 30, 2012			Dec 31, 2011			Dec 31, 2012			Dec 31, 2011
Realized
Light oil ($ millions)		15.8			6.3			(7.6	)		9.9			(20.4	)
Light oil ($/bbl)		5.38			2.20			(3.61	)		0.97			(2.61	)
Natural gas ($ millions)		1.8			4.1			10.4			12.2			37.3
Natural gas ($/Mcf)		0.07			0.16			0.51			0.14			0.47
Combined ($ millions)		17.6			10.4			2.8			22.1			16.9
Combined ($/boe)		2.03			1.20			0.40			0.71			0.63
Unrealized
Total unrealized risk management assets (liabilities) at period end ($ millions)		7.0			7.5			(42.0	)		7.0			(42.0	)
Less: Unrealized risk management assets (liabilities) at beginning of period ($ millions)		7.5			52.9			60.8			(42.0	)		(2.1	)
		(0.5	)		(45.4	)		(102.8	)		49.0			(39.9	)
Less: Risk management assets, acquired with NAL – May 31, 2012 ($ millions)		–			–			–			18.4			–
Total unrealized gain (loss) on risk management contracts ($millions)		(0.5	)		(45.4	)		(102.8	)		30.6			(39.9	)


PENGROWTH 2012 Management’s Discussion & Analysis			17

Pengrowth has an active risk management program which primarily uses forward price swaps to manage the exposure to commodity price fluctuations and provide a measure of stability to cash flow. During the second quarter of 2012, Pengrowth also acquired swaps, options and collars with the NAL Acquisition.

Fourth quarter realized gains from oil risk management increased $9.5 million compared to the prior quarter as Pengrowth’s average fixed risk management contracted price exceeded the benchmark oil prices more than it had in the prior quarter. For the full year 2012 Pengrowth recorded a $9.9 million realized gain, compared to a $20.4 million loss in 2011, as the average fixed risk management contracted price exceeded the benchmark oil prices in 2012, contrary to the same period last year.

Realized gains from natural gas commodity risk management activities decreased 56 percent in the fourth quarter compared to the third quarter, due to narrowing of the gap between the benchmark prices relative to the risk management contracted prices in the current quarter. Realized risk management gains were also reduced by 67 percent for the full year of 2012 compared to 2011 due to decreased natural gas volumes under risk management and decreased risk management contracted prices. This resulted in narrowing of the gap between the benchmark natural gas price and Pengrowth’s average natural gas risk management contracted prices in 2012 and consequently resulting in lower realized risk management gains in 2012.

The change in fair value of the forward contracts between periods affects net income (loss) through the unrealized amounts recorded during the period. The fair value of forward contracts is determined by comparing the risk management contracted fixed price to the forward price curve at each period end. The value of the options in place is confirmed with external agencies at period end. Pengrowth recognized a $0.5 million unrealized loss in the fourth quarter compared to a $45.4 million unrealized loss in the third quarter of 2012. The primary reason for the lower unrealized loss in the current quarter is a reduction in the WTI forward curve. The $30.6 million unrealized gain for the full year compared to a $39.9 loss in 2011 is due to a decrease in the forward price curve relative to Pengrowth’s risk management contracted fixed price. Unrealized gains (losses) 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 curve pricing for the commodities under risk management contracts. 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.

Forward Contracts

The following table provides a summary of the minimum prices of our commodity risk management contracts in place at December 31, 2012 (see Note 18 to the audited Consolidated Financial Statements for more information on Pengrowth’s commodity risk management contracts):


Crude Oil ⁽¹⁾
Reference Point	Volume (bbl/d)	Remaining Term	% of 2013 Total Oil Production Guidance⁽²⁾	Price/bbl ($)
WTI	18,500	Jan 1, 2013 - Dec 31, 2013	52%	93.87
WTI	3,500	Jan 1, 2014 - Dec 31, 2014	10%	92.14


Natural Gas
Reference Point	Volume (MMBtu/d)	Remaining Term	% of 2013 Total Natural Gas Production Guidance	Price/MMBtu ($)
AECO & NGI Chicago Index	133,788	Jan 1, 2013 - Dec 31, 2013	55%	3.30
AECO & NGI Chicago Index	45,282	Jan 1, 2014 - Dec 31, 2014	19%	3.82
AECO & NGI Chicago Index	14,348	Jan 1, 2015 - Dec 31, 2015	6%	4.06


Power
Reference Point	Volume (MW)	Remaining Term	% of 2013 Total Power Consumption	Price/MWh ($)
AESO	5	Jan 1, 2013 - Dec 31, 2013	5%	74.50
AESO	5	Jan 1, 2014 - Dec 31, 2014	5%	46.85

⁽¹⁾	U.S. denominated contracts have been converted to Canadian dollars at the December 31, 2012 closing exchange rate.

⁽²⁾	Includes light and heavy crude oil.


18			PENGROWTH 2012 Management’s Discussion & Analysis

Pengrowth has entered into additional commodity risk management contracts subsequent to December 31, 2012 for the years 2013, 2014 and 2015. See Note 23 to the audited Consolidated Financial Statements for details. For 2013, Pengrowth now has 65% of its oil production under risk management at $93.81/bbl.

At December 31, 2012, each Cdn$1/bbl change in future WTI oil prices results in approximately $6.5 million pre-tax change in the value of the crude risk management contracts, while each Cdn$0.25/MMBtu change in future natural gas prices results in approximately $17.3 million pre-tax change in the value of the natural gas risk management contracts. The changes in the 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 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 the risk management contract price in effect at December 31, 2012, future revenue and cash flow would have been $7.0 million higher than if the risk management contracts were not in place based on the estimated fair value of the risk management assets at period end. The $7.0 million is composed of net assets of $5.9 million relating to risk management contracts expiring within one year and net assets of $1.1 million relating to risk management contracts expiring beyond one year.

Each Cdn$1/MWh change in future power prices would result in approximately $0.1 million pre-tax change in the fair value of the risk management contracts.

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 as unrealized commodity risk management gains (losses). The volatility in net income (loss) will continue to the extent that the fair value of commodity risk management contracts fluctuates. However, these non-cash amounts do not affect Pengrowth’s operating cash flow until realized.

Realized commodity risk management gains (losses) are recorded in oil and gas sales on the Consolidated Statements of Income and impact cash flow at that time.

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


Percent of Monthly Company Interest Production or Estimated Power Consumption	Forward Period
Up to 65%		1 - 24 Months
Up to 30%		25 - 36 Months
Up to 25%		37 - 60 Months

Each commodity risk management transaction for natural gas or crude oil shall not exceed 20,000 MMBtu/d or 2,500 bbl/d, respectively. Each power consumption risk management transaction shall not exceed 25 MW.

OIL AND GAS SALES

Contribution Analysis

The following table shows the contribution of each product category to the overall sales inclusive of realized commodity risk management activities:


Oil and Gas Sales	Three months ended												Twelve months ended
($ millions except percentages)	Dec 31, 2012		% of total		Sept 30, 2012		% of total		Dec 31, 2011		% of total		Dec 31, 2012		% of total		Dec 31, 2011		% of total
Light oil ⁽¹⁾		251.8		58		237.8		61		192.4		49		856.6		58		700.8		49
Heavy oil ⁽¹⁾		38.3		9		38.3		10		46.0		12		157.2		11		163.5		11
Natural gas liquids		60.5		14		51.0		13		68.0		17		227.5		15		244.4		17
Natural gas		76.4		18		60.9		16		76.5		20		221.1		15		325.9		22
Brokered sales/sulphur		4.5		1		3.9		–		6.3		2		17.9		1		19.1		1
Total oil and gas sales		431.5				391.9				389.2				1,480.3				1,453.7

⁽¹⁾	Prior period restated to conform to presentation in the current period.


PENGROWTH 2012 Management’s Discussion & Analysis			19

Price and Volume Analysis

Quarter ended December 31 – 2012 versus 2011

The following table illustrates the effect of changes in prices and volumes on the components of oil and gas sales including the impact of realized commodity risk management activities, for the fourth quarter of 2012 compared to the same period in 2011:


($ millions)	Light oil ⁽¹⁾			Natural gas			NGLs			Heavy oil ⁽¹⁾			Other ⁽²⁾			Total
Quarter ended December 31, 2011		192.4			76.5			68.0			46.0			6.3			389.2
Effect of change in product prices and differentials		(42.1	)		(4.4	)		(14.8	)		(8.3	)		–			(69.6	)
Effect of change in realized commodity risk management activities		23.4			(8.6	)		–			–			–			14.8
Effect of change in sales volumes		78.1			12.9			7.4			0.6			–			99.0
Other		–			–			(0.1	)		–			(1.8	)		(1.9	)
Quarter ended December 31, 2012		251.8			76.4			60.5			38.3			4.5			431.5

⁽¹⁾	Prior period restated to conform to presentation in the current period.

⁽²⁾	Primarily sulphur sales.

Light oil sales increased 31 percent in the fourth quarter compared to the same period in 2011, primarily due to increased production as a result of the NAL Acquisition, partly offset by a 15 percent realized price decline. Natural gas sales remained relatively unchanged as a decrease in commodity risk management gains and a 6 percent price decline were offset by sales from increased production. Natural gas liquids sales decreased by 11 percent primarily impacted by a 20 percent decrease in prices partly offset by an 11 percent increase in production volumes, while heavy oil sales decreased 17 percent due to price declines.

Higher discounts of the Canadian light oil versus WTI benchmark during the fourth quarter had an unfavourable financial impact on oil sales of approximately $14 million compared to the same period last year.

Full year 2012 versus 2011


($ millions)	Light oil ⁽¹⁾			Natural gas			NGLs			Heavy oil ⁽¹⁾			Other⁽²⁾			Total
Twelve months ended December 31, 2011		700.8			325.9			244.4			163.5			19.1			1,453.7
Effect of change in product prices and differentials		(97.3	)		(112.7	)		(44.8	)		(9.2	)		–			(264.0	)
Effect of change in realized commodity risk management activities		30.3			(25.1	)		–			–			–			5.2
Effect of change in sales volumes		222.8			33.1			27.9			2.7			–			286.5
Other		–			(0.1	)		–			0.2			(1.2	)		(1.1	)
Twelve months ended December 31, 2012		856.6			221.1			227.5			157.2			17.9			1,480.3

⁽¹⁾	Prior period restated to conform to presentation in the current period.

⁽²⁾	Primarily sulphur sales.

Light oil sales increased 22 percent in the full year of 2012 compared to 2011, primarily due to a 31 percent increase in light oil production as a result of the NAL Acquisition and growth programs, partly offset by a 10 percent price decline. Natural gas sales decreased 32 percent, primarily due to a 35 percent price decline, partly offset by increased production. Similarly natural gas liquids and heavy oil sales in 2012 were also negatively impacted by lower prices.

Higher discounts of the Canadian light oil versus WTI benchmark during 2012 had an unfavourable financial impact on oil sales of approximately $93 million compared to 2011.


20			PENGROWTH 2012 Management’s Discussion & Analysis

ROYALTY EXPENSE


	Three months ended						Twelve months ended
($ millions except per boe amounts and percentages)	Dec 31, 2012		Sept 30, 2012		Dec 31, 2011		Dec 31, 2012		Dec 31, 2011
Royalty expense		69.5		67.5		72.3		277.5		277.9
$/boe		8.03		7.79		10.25		8.84		10.29
Royalties as a percent of sales (%)		16.1		17.2		18.6		18.7		19.1
Royalties as a percent of sales excluding realized risk management contracts (%)		16.8		17.7		18.7		19.0		19.3

Royalties include Crown, freehold, overriding royalties and mineral taxes. Royalty payments are based on sales before commodity risk management activities; however, gains or losses from realized commodity risk management activities are reported as part of sales and therefore affect royalty rates as a percentage of sales.

Royalty rates, as a percentage of sales excluding realized risk management activities, decreased from 17.7 percent in the third quarter of 2012 to 16.8 percent in the current quarter. This was due to several factors including higher gross overriding and other income recorded in the quarter, which is not subject to royalties, and an increase in royalty relief and credits including GCA.

Royalty rates, as a percentage of sales excluding risk management, decreased from 18.7 percent in the fourth quarter of 2011 to 16.8 percent in the current quarter. The primary reason for the decrease is the added impact of NAL royalty rates which have historically been lower than Pengrowth’s due to a higher weighting of freehold royalties which are generally lower than Crown royalties. Increases in GCA and gross overriding income have also contributed to the royalty rate decrease.

On a year over year basis royalty rates, as a percentage of sales excluding the impact of realized risk management contracts, decreased from 19.3 percent in 2011 to 19 percent in 2012. The decrease is primarily driven by the impact of lower NAL royalty rates and commodity price declines.

2013 royalty rates, as a percentage of sales, are forecast to be 17 percent.

OPERATING EXPENSES


	Three months ended						Twelve months ended
($ millions except per boe amounts)	Dec 31, 2012		Sept 30, 2012		Dec 31, 2011		Dec 31, 2012		Dec 31, 2011
Operating expenses		121.2		132.1		99.7		458.6		382.0
$/boe		14.01		15.22		14.13		14.61		14.15

Operating expenses in the fourth quarter decreased $10.9 million or $1.21 on a per boe basis compared to the third quarter due to reduced maintenance, turnaround and chemical costs, partially offset by slightly higher power costs.

Fourth quarter operating expenses increased $21.5 million or 22 percent compared to the same period last year primarily due to the additional NAL operating costs associated with a 23 percent production increase. On a per boe basis, operating expenses decreased $0.12/boe to $14.01/boe.

For the full year of 2012 compared to 2011, operating expenses increased by $76.6 million or 20 percent. The increase is primarily attributable to an increase in production volumes of 16 percent related to NAL and additional costs from the Olds turnaround during the second quarter of 2012. On a per boe basis, operating expenses increased $0.46/boe to $14.61/boe.

2013 operating expenses are forecast to be $14.00 to $14.50 per boe. Starting in 2013, Pengrowth will reclassify approximately $20 million relating primarily to technical support costs to G&A from operating expenses.

TRANSPORTATION COSTS


	Three months ended						Twelve months ended
($ millions except per boe amounts)	Dec 31, 2012		Sept 30, 2012		Dec 31, 2011		Dec 31, 2012		Dec 31, 2011
Transportation costs		6.5		5.7		5.6		24.8		25.7
$/boe		0.75		0.66		0.80		0.79		0.95


PENGROWTH 2012 Management’s Discussion & Analysis			21

In the fourth quarter of 2012, total transportation costs increased 14 percent compared to the third quarter and 16 percent compared to the fourth quarter of 2011, due to delays in pipeline connections and new production at Lochend.

Year over year transportation costs decreased 4 percent due to lower clean oil transportation costs as 2011 costs were negatively affected by the Rainbow Pipeline interruption from May to September of 2011.

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

OPERATING NETBACKS

Pengrowth’s operating netbacks have been calculated by taking balances directly from the Consolidated Statements of Income and dividing by production. Certain assumptions have been made in allocating operating expenses, other income and royalty injection credits between light oil, heavy oil, natural gas and NGL production. Operating netbacks as presented below may not be comparable to similar measures presented by other companies, as there are no standardized measures. The sales price used in the calculation of operating netbacks is after realized commodity risk management gains (losses).


	Three months ended									Twelve months ended
Combined Netbacks ($/boe)	Dec 31, 2012			Sept 30, 2012			Dec 31, 2011			Dec 31, 2012			Dec 31, 2011
Oil & gas sales		49.88			45.18			55.17			47.17			53.84
Royalties		(8.03	)		(7.79	)		(10.25	)		(8.84	)		(10.29	)
Operating expenses		(14.01	)		(15.22	)		(14.13	)		(14.61	)		(14.15	)
Transportation costs		(0.75	)		(0.66	)		(0.80	)		(0.79	)		(0.95	)
Operating netback		27.09			21.51			29.99			22.93			28.45

	Three months ended									Twelve months ended
Light Oil Netbacks ($/bbl)	Dec 31, 2012			Sept 30, 2012			Dec 31, 2011			Dec 31, 2012			Dec 31, 2011
Sales ⁽¹⁾		86.17			83.44			92.08			84.07			90.29
Royalties		(16.24	)		(15.73	)		(21.29	)		(17.52	)		(20.37	)
Operating expenses		(15.78	)		(18.68	)		(15.40	)		(16.66	)		(16.26	)
Transportation costs ⁽¹⁾		(1.24	)		(0.93	)		(1.34	)		(1.32	)		(1.90	)
Operating netback		52.91			48.10			54.05			48.57			51.76

	Three months ended									Twelve months ended
Heavy Oil Netbacks ($/bbl)	Dec 31, 2012			Sept 30, 2012			Dec 31, 2011			Dec 31, 2012			Dec 31, 2011
Sales ⁽¹⁾		63.74			63.98			77.60			65.92			69.76
Royalties		(9.19	)		(13.62	)		(13.65	)		(12.03	)		(13.81	)
Operating expenses		(15.96	)		(19.36	)		(13.91	)		(17.15	)		(14.45	)
Transportation costs ⁽¹⁾		(0.91	)		(0.74	)		(1.47	)		(1.01	)		(1.52	)
Operating netback		37.68			30.26			48.57			35.73			39.98

	Three months ended									Twelve months ended
NGLs Netbacks ($/bbl)	Dec 31, 2012			Sept 30, 2012			Dec 31, 2011			Dec 31, 2012			Dec 31, 2011
Sales		56.64			51.45			70.54			57.91			69.31
Royalties		(14.63	)		(13.30	)		(14.51	)		(16.40	)		(16.92	)
Operating expenses		(13.50	)		(12.81	)		(12.34	)		(13.56	)		(14.65	)
Transportation costs		(0.22	)		(0.31	)		(0.20	)		(0.20	)		(0.05	)
Operating netback		28.29			25.03			43.49			27.75			37.69

	Three months ended									Twelve months ended
Natural Gas Netbacks ($/Mcf)	Dec 31, 2012			Sept 30, 2012			Dec 31, 2011			Dec 31, 2012			Dec 31, 2011
Sales		3.29			2.52			3.98			2.63			4.24
Royalties		(0.03	)		(0.05	)		(0.26	)		(0.05	)		(0.33	)
Operating expenses		(2.10	)		(2.14	)		(2.31	)		(2.18	)		(2.11	)
Transportation costs		(0.09	)		(0.09	)		(0.09	)		(0.09	)		(0.09	)
Operating netback		1.07			0.24			1.32			0.31			1.71

⁽¹⁾	Prior period restated to conform to presentation in the current period.


22			PENGROWTH 2012 Management’s Discussion & Analysis

Pengrowth realized an average operating netback of $27.09/boe in the fourth quarter, a 26 percent increase compared to the third quarter of 2012, primarily due to higher oil and gas sales and lower operating expenses. For the full year of 2012, Pengrowth realized an average operating netback of $22.93/boe, compared to $28.45/boe in 2011. The 19 percent decrease is primarily caused by lower average realized prices.

The natural gas netback for the fourth quarter was $1.07/Mcf compared to $0.24/Mcf in the prior quarter due to a 31 percent increase in the realized natural gas price, including risk management, in the fourth quarter. The natural gas netback declined significantly for the full year of 2012 compared to 2011. This was due to a 39 percent decline in the average realized natural gas price, including risk management, year over year. Pengrowth also shut-in approximately 1,000 boe/d of primarily dry natural gas production during the second and third quarters, and approximately 500 boe/d during the fourth quarter.

Pengrowth’s natural gas netbacks should be viewed in conjunction with the NGLs netbacks, which were $28.29/bbl in the fourth quarter and $27.75/bbl for the full year of 2012, since virtually all of our current active natural gas production yields NGLs.

GENERAL AND ADMINISTRATIVE EXPENSES


	Three months ended						Twelve months ended
($ millions except per boe amounts)	Dec 31, 2012		Sept 30, 2012		Dec 31, 2011		Dec 31, 2012		Dec 31, 2011
Cash G&A expense		18.1		15.6		16.3		66.5		64.3
$/boe		2.09		1.80		2.31		2.12		2.38
Non-cash G&A expense		1.4		3.8		2.0		12.3		11.0
$/boe		0.16		0.43		0.28		0.39		0.41
Total G&A		19.5		19.4		18.3		78.8		75.3
$/boe		2.26		2.23		2.60		2.51		2.79

Fourth quarter cash G&A expenses were $2.5 million and $1.8 million higher compared to the prior quarter and the fourth quarter of 2011, respectively. Both increases were primarily due to added personnel costs from the NAL Acquisition and increased professional services. On a per boe basis, however, cash G&A has decreased to $2.09/boe in the fourth quarter compared to $2.31/boe in the same period last year. For the full year of 2012, cash G&A per boe also decreased to $2.12/boe from $2.38/boe in 2011. As anticipated, this decrease reflects the benefit of the increased production resulting from the NAL Acquisition.

The non-cash component of G&A represents the compensation expense associated with Pengrowth’s Long Term Incentive Plans (“LTIP”). See Note 14 to the audited Consolidated Financial Statements for additional information. The compensation costs associated with these plans are expensed over the applicable vesting period. Non-cash G&A expense decreased $2.4 million in the fourth quarter compared to the third quarter primarily due to a lower performance multiplier on previously expensed grants. The higher non-cash G&A expenses in 2012 compared to the prior year were primarily due to additional grants issued in 2012.

2013 G&A expenses are expected to be $3.30/boe including non-cash G&A of approximately $0.46/boe. Starting in 2013, Pengrowth will reclassify approximately $20 million relating primarily to technical support costs to G&A from operating expenses.

OTHER EXPENSES

For the full year of 2012, other expenses of $27.6 million included approximately $22 million in one time transaction costs related to the NAL Acquisition.

GAIN (LOSS) ON INVESTMENTS

Pengrowth owns 1.0 million shares of a private corporation with an estimated fair value of $20.0 million at December 31, 2012 compared to $35.0 million at December 31, 2011. The fair value of these shares has decreased since December 31, 2011 resulting in an unrealized loss of $15.0 million compared to an unrealized gain of $23.0 million recognized in 2011. See Note 5 to the audited Consolidated Financial Statements for additional information.

DEPLETION, DEPRECIATION, AMORTIZATION AND ACCRETION


	Three months ended						Twelve months ended
($ millions except per boe amounts)	Dec 31, 2012		Sept 30, 2012		Dec 31, 2011		Dec 31, 2012		Dec 31, 2011
Depletion, depreciation and amortization		165.1		162.0		117.6		567.3		437.9
$/boe		19.08		18.67		16.67		18.08		16.22
Accretion		5.7		5.7		4.0		20.4		15.6
$/boe		0.66		0.66		0.57		0.65		0.58


PENGROWTH 2012 Management’s Discussion & Analysis			23

The 2 percent increase in depletion expense in the fourth quarter of 2012 compared to the third quarter of 2012 was primarily due to an increase in the Unit of Production (“UOP”) rate from higher capital spending on property acquisitions. Comparing the fourth quarter and the full year of 2012 to the same periods last year, depletion increased 40 percent and 30 percent, respectively, primarily due to additional depletion recorded on property, plant and equipment from the NAL Acquisition.

Accretion expense also increased in the fourth quarter and full year 2012 due to the ARO increase from the NAL Acquisition.

IMPAIRMENTS

Impairment tests were performed at December 31, 2011, June 30, 2012 and December 31, 2012. The recoverable amounts of each CGU were based on the higher of value in use or fair value less costs to sell. Based on the impairment tests carried out, there were no impairments at December 31, 2012, but impairments were recorded at June 30, 2012 and December 31, 2011. The impairment test is sensitive to lower commodity prices, which have been under significant downward pressure in recent periods, particularly natural gas prices. Further declines in commodity prices in 2013 could result in additional impairment charges as the cushions in the CGU impairment tests have been eroded by price decreases.

At June 30, 2012, Pengrowth tested its predominantly natural gas CGUs for impairments as a result of declining forward price estimates for natural gas. Of the CGUs tested, only one was impaired. Pengrowth recognized a $30 million pre-tax impairment charge on the producing portion of the Groundbirch CGU, as the carrying value exceeded the fair value at June 30, 2012. Fair value was determined based on the total proved plus probable reserves, estimated by Pengrowth’s independent reserves evaluator, using the July 1, 2012 commodity price forecast of Pengrowth’s independent reserves evaluator discounted at a market rate. See Note 6 to the audited Consolidated Financial Statements for additional information.

At June 30, 2012, Pengrowth also recognized a $48.3 million pre-tax impairment of the Horn River Exploration and Evaluation (“E&E”) assets. It was determined that there would be no additional capital spending at Horn River, which will result in the expiry of the majority of Pengrowth’s existing leases in the area. As a result, the carrying value of the Horn River E&E assets was written down to nil at June 30, 2012. See Note 7 to the audited Consolidated Financial Statements for additional information.

At December 31, 2011, Pengrowth recognized a $27.4 million pre-tax impairment charge on the producing portion of the Groundbirch CGU as the carrying value exceeded the fair value on December 31, 2011. Fair value was determined based on the total proved plus probable reserves estimated by Pengrowth’s independent reserves evaluator using the period end commodity price forecast of Pengrowth’s independent reserves evaluator and discounted at a market rate. This impairment charge resulted from a low natural gas price forecast by Pengrowth’s independent reserves evaluator and allocation of 2012 capital to properties with better economic returns. As a result, goodwill attributed to the Groundbirch CGU was reduced by $16.3 million to nil and the PP&E was reduced by $11.1 million. See Note 6 to the audited Consolidated Financial Statements for detailed disclosure of the assumptions used to determine the fair value.

INTEREST AND FINANCING CHARGES

Three months ended

Twelve months ended

($ millions)

Dec 31, 2012

Sept 30, 2012

Dec 31, 2011

Dec 31, 2012

Dec 31, 2011

Interest and financing charges

25.7

23.6

21.1

86.4

75.9

At December 31, 2012, Pengrowth had approximately $1.8 billion in total debt, composed of $1.6 billion in long term debt and $0.2 billion in convertible debentures. Total debt consists primarily of U.S. dollar denominated fixed rate notes at a weighted average interest rate of 5.7 percent, drawings from Pengrowth’s syndicated bank facility which is subject to prevailing market rates, and convertible debentures with a 6.25 percent coupon. At December 31, 2012, the bank facility and the demand operating facility cost of funds was approximately 3 percent. On October 18, 2012 Pengrowth issued $385 million U.S. equivalent of senior unsecured term notes, proceeds of which were used to pay down Pengrowth’s current credit facilities.

Interest and financing charges were $2.1 million or 9 percent higher in the fourth quarter compared to the third quarter primarily due to interest expense on the newly issued term notes which replaced shorter term bank debt. Comparing the fourth quarter to the same period last year, interest and financing charges increased $4.6 million or 22 percent. This increase is due to convertible debentures assumed with the NAL Acquisition and additional interest on the newly issued term notes. The convertible debentures contributed $3.4 million of net interest expense to interest and financing charges in the fourth quarter compared to the same quarter last year.

The $10.5 million or 14 percent increase in interest expense and financing charges year over year reflects the higher debt levels outstanding in the current year, particularly the increased expense of $8.3 million relating to the convertible debentures assumed with the NAL Acquisition.


24			PENGROWTH 2012 Management’s Discussion & Analysis

Pengrowth has various floating to fixed interest rate swap contracts which were acquired with NAL. Under these contracts, Pengrowth pays a fixed rate and receives a floating rate, the Canadian three months Bankers Acceptance CDOR (“Canadian Depository Offered Rate”), on the notional amounts. The fair value of the interest rate derivative contracts has been included on the Consolidated Balance Sheets with changes in the fair value reported separately on the Consolidated Statements of Income as part of interest and financing charges. See Note 18 to the audited Consolidated Financial Statements for additional information.

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 reduction of $32.0 million during the year ended December 31, 2012 compared to a deferred tax expense of $22.3 million during the year ended December 31, 2011. The decrease in deferred income tax expense primarily relates to the decrease in pre-tax income from 2011 to 2012. Also contributing to the decrease in 2012 is the recognition of previously uncertain tax benefits.

No current income taxes were paid by Pengrowth in 2012 or 2011. See Note 12 to the audited Consolidated Financial Statements for additional information.

FOREIGN CURRENCY GAINS (LOSSES)


	Three months ended								Twelve months ended
($ millions)	Dec 31, 2012			Sept 30, 2012		Dec 31, 2011			Dec 31, 2012			Dec 31, 2011
Currency exchange rate ($1Cdn = $U.S.) at period end		1.01			1.02		0.98			1.01			0.98
Unrealized foreign exchange gain (loss) on U.S. dollar denominated debt		(14.2	)		31.8		28.8			16.4			(19.5	)
Unrealized foreign exchange gain (loss) on U.K. pound sterling denominated debt		(2.0	)		0.4		2.8			(2.4	)		(1.4	)
		(16.2	)		32.2		31.6			14.0			(20.9	)
Unrealized gain (loss) on foreign exchange risk management contracts		2.9			0.9		(2.4	)		7.9			1.8
Total unrealized foreign exchange gain (loss)		(13.3	)		33.1		29.2			21.9			(19.1	)
Total realized foreign exchange loss		(0.6	)		–		(0.6	)		(1.0	)		(1.6	)

Pengrowth’s unrealized foreign exchange gains and losses are primarily attributable to the translation of the foreign denominated long term debt. The gains or losses are calculated by comparing the translated Canadian dollar balance of foreign denominated long term debt from one period to another. In the fourth quarter Pengrowth recorded an unrealized foreign exchange loss of $16.2 million compared to gains of $32.2 million and $31.6 million in the prior quarter and the fourth quarter of 2011, respectively, primarily as a result of a weaker Canadian dollar relative to the U.S. dollar and U.K. Pound. The additional U.S. term debt issued in October contributed $3.3 million to the unrealized foreign exchange loss in the current quarter.

In contrast, Pengrowth recorded a $14.0 million unrealized foreign exchange gain for the full year of 2012 compared to a $20.9 million loss for 2011 primarily due to a stronger Canadian dollar at year end relative to the U.S. dollar on December 31, 2011.

Pengrowth acquired various foreign exchange contracts with the NAL Acquisition. The swaps and various types of options require Pengrowth to sell the notional U.S. dollar monthly amount pursuant to the terms of each contract. See Note 18 to the audited Consolidated Financial Statements for additional information. Pengrowth does not use hedge accounting for any foreign exchange risk management contracts.

During 2012, 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 maturity dates of the U.S. dollar term debt. The fair value of foreign exchange derivative contracts has been included on the Consolidated Balance Sheets with changes in the fair value reported on the Consolidated Statements of Income as an unrealized foreign exchange (gain) loss.


PENGROWTH 2012 Management’s Discussion & Analysis			25


Swaps-Buy U.S. dollars
Contract Type	Settlement Date	Amount (U.S. $ millions)	% of Principal hedged	Fixed Rate ($1Cdn = $U.S.)
Swap	April 2013	50	100%	1.01
Swap	May 2015	50	70%	0.98
Swap	July 2017	240	60%	0.97
Swap	August 2018	75	28%	0.96
Swap	October 2019	15	43%	0.94
Swap	May 2020	15	13%	0.95
		445	36%

To mitigate the fluctuations in our U.K. 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. Pengrowth has two U.K. Pound Sterling note issuances outstanding. The first was issued in 2005 and the second in 2012. The exchange rate is fixed at approximately $0.4976 and $0.63 U.K. Pound Sterling per Canadian dollar, respectively.

ASSET RETIREMENT OBLIGATIONS (“ARO”)


($ millions)	Dec 31, 2012			Dec 31, 2011			Change
ARO, opening balance		660.9			447.1			213.8
Assumed in business combinations		47.3			–			47.3
Revisions due to discount rate changes ⁽¹⁾		178.1			206.6			(28.5	)
Expenditures on remediation		(27.6	)		(21.9	)		(5.7	)
Accretion and other		10.2			29.1			(18.9	)
ARO, closing balance		868.9			660.9			208.0

⁽¹⁾	2012 amount relates to the change in the discount rate from 8 percent to 2.5 percent on the ARO balances assumed in the business combinations. 2011 amount relates to reductions in the risk free rate during the year. The offset to the revisions is recorded in property, plant and equipment.

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.

For the year ended December 31, 2012, Pengrowth’s ARO liability increased by $208.0 million mainly due to the additional ARO liabilities assumed in the NAL Acquisition, and the associated impact of the discount rate reduction.

Pengrowth has estimated the net present value of its total ARO to be $868.9 million as at December 31, 2012 (December 31, 2011 – $660.9 million), based on a total escalated future liability of $2.4 billion (December 31, 2011 – $1.8 billion). These costs are expected to be incurred over 65 years with the majority of the costs incurred between 2036 and 2077. A risk free discount rate of 2.5 percent per annum and an inflation rate of 1.5 percent were used to calculate the net present value of the ARO.

REMEDIATION TRUST FUNDS AND REMEDIATION AND ABANDONMENT EXPENSE

During 2012, Pengrowth’s contributions were $6.3 million (December 31, 2011 – $7.1 million), into trust funds established to fund certain abandonment and reclamation costs associated with Judy Creek and SOEP. The total balance of the remediation trust funds was $53.8 million at December 31, 2012 (December 31, 2011 – $49.7 million).

As a working interest holder in SOEP, Pengrowth is under a contractual obligation to contribute to a remediation trust fund. The funding levels are based on the raw production delivered and processed at the various facilities. Funding levels for this fund may change each year pending a review by the owners.

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, 2012, Pengrowth spent $27.6 million on


26			PENGROWTH 2012 Management’s Discussion & Analysis

abandonment and reclamation (December 31, 2011 – $21.9 million). Pengrowth expects to spend approximately $21 million in 2013 on reclamation and abandonment, excluding contributions to remediation trust funds and orphan well levies from the Alberta Energy Resources Conservation Board.

CLIMATE CHANGE PROGRAMS

Since becoming effective July 1, 2007, Alberta regulates Greenhouse Gas (“GHG”) emissions under the Climate Change and Emissions Management Act. Under the Act the Specified Gas Reporting Regulation (the “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 (the “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. Unutilized reduction credits from one year may be carried forward to future years.

During 2012, Pengrowth submitted GHG information on two facilities, the Olds Gas Plant and the Judy Creek Gas Conservation Plant, which had reduced emissions by approximately 42 percent during 2011, well ahead of the 12 percent annual reduction target. During 2012, Pengrowth also acquired additional interest in the Quirk Creek Gas Plant and became the operator of that facility. Quirk Creek is a Specified Gas Emitter facility therefore Pengrowth now has three operated facilities that are subject to the annual 12 percent reduction and will be reporting emission reduction information on the three facilities in 2013.

For further information on Greenhouse Gas emissions, see Pengrowth’s AIF.

GOODWILL

In accordance with IFRS, goodwill is tested for impairment at each year end, or when there is an indication of impairment, in conjunction with the assessment of impairment of property, plant and equipment. Management has assessed the goodwill and determined that there is no impairment at December 31, 2012. As at December 31, 2012, Pengrowth has goodwill of $700.7 million which was unchanged from December 31, 2011. See Note 8 to the audited Consolidated Financial Statements for details.

ACQUISITIONS AND DISPOSITIONS

In the fourth quarter Pengrowth acquired properties in the Lochend area for $61.4 million and disposed of its Kakwa property and a portion of its Dawson area property for proceeds of $9.1 million. During the fourth quarter, Pengrowth has also entered into an agreement to sell its non-operated Weyburn property for proceeds of $315 million (prior to closing adjustments) which is expected to close in early March 2013. We do not expect a material gain or loss on this transaction.

During the third quarter of 2012, Pengrowth acquired properties in the Lone Pine Creek area for $5.4 million and disposed of various wells in the Cactus Lake, Plover, Twining and Swalwell areas for proceeds of $15 million, resulting in a gain on disposition of $8.1 million.

In the second quarter of 2012, Pengrowth completed the NAL Acquisition for $965.7 million and additional producing properties in the Sawn Lake area for $15.5 million.

In the first quarter of 2012, Pengrowth exercised rights of first refusal in the Quirk Creek Field and the Weyburn Unit, increasing its working interest in each. The purchase prices were $13.5 million and $12.3 million net of adjustments, respectively.

WORKING CAPITAL

At December 31, 2012, Pengrowth had a working capital surplus as current assets exceeded current liabilities by $128.8 million. In contrast, on December 31, 2011, Pengrowth had a working capital deficiency of $137.3 million. The change in the working capital was due to the inclusion of $317.3 million of Weyburn assets held for sale partly offset by the current liabilities associated with these assets and the inclusion of the current portion of long term debt, U.S. $50 million, maturing in April of 2013.


PENGROWTH 2012 Management’s Discussion & Analysis			27

FINANCIAL RESOURCES AND LIQUIDITY


As at:	Dec 31, 2012			Dec 31, 2011			Change
($ millions, except ratios and percentages) Term credit facilities		160.0			–			160.0
Senior unsecured notes		1,320.9			1,007.7			313.2
Long term debt		1,480.9			1,007.7			473.2
Working capital (surplus) deficiency including current portion of debt		(128.8	)		137.3			(266.1	)
Total debt excluding long term portion of convertible debentures		1,352.1			1,145.0			207.1
Convertible debentures		237.1			–			237.1
Total debt ⁽¹⁾		1,589.2			1,145.0			444.2

Twelve months trailing:	Dec 31, 2012			Dec 31, 2011			Change
Net income		12.7			84.5			(71.8	)
Add (deduct):
Interest and financing charges		86.4			75.9			10.5
Deferred tax (recovery) expense		(32.0	)		22.3			(54.3	)
Depletion, depreciation, amortization and accretion		587.7			453.5			134.2
Impairment of assets		78.3			27.4			50.9
Other non-cash (income) expenses		(107.9	)		34.8			(142.7	)
Adjusted EBITDA		625.2			698.4			(73.2	)
Total debt excluding convertible debentures to adjusted EBITDA		2.2			1.6
Total debt to adjusted EBITDA ⁽³⁾		2.5			1.6
Total capitalization excluding convertible debentures ⁽²⁾		5,542.4			4,492.3			1,050.1
Total capitalization ⁽²⁾		5,779.5			4,492.3			1,287.2
Total debt excluding convertible debentures as a percentage of total capitalization ⁽²⁾		24.4	%		25.5	%
Total debt as a percentage of total capitalization		27.5	%		25.5	%

⁽¹⁾	Total debt includes working capital (surplus) deficiency and convertible debentures.

⁽²⁾	Total capitalization includes total outstanding debt plus Shareholders’ Equity.

⁽³⁾	The ratio in the table only includes seven months of Adjusted EBITDA from the NAL acquisition. Including the prior five months of NAL Adjusted EBITDA would result in a debt to Adjusted EBITDA ratio of approximately 2.2x.

At December 31, 2012, total debt increased $444.2 million from December 31, 2011. In October 2012, Pengrowth issued U.S. $385 million equivalent in long term notes where the proceeds were used to pay down indebtedness under Pengrowth’s current credit facilities. The expansion of total debt year over year also included convertible debentures assumed with the NAL Acquisition and increased borrowing in the term credit facility due to net acquisitions in 2012.

The increase in total debt was partly mitigated by the strengthening Canadian dollar which drove down the Canadian equivalent of the U.S. denominated senior unsecured notes by $16.6 million from December 31, 2011. In contrast, the U.K. pound sterling denominated debt increased by $2.4 million due to a weaker Canadian dollar relative to the U.K. pound sterling year over year. The increase in total debt resulted in a trailing twelve months total debt to Adjusted EBITDA ratio at December 31, 2012 of 2.5x (including seven months of NAL Adjusted EBITDA). Including the prior five months of NAL Adjusted EBITDA would result in a debt to Adjusted EBITDA ratio of approximately 2.2x.

Term Credit Facilities

Pengrowth maintains a $1 billion revolving credit facility which was drawn by $160 million in borrowings and approximately $27.5 million in outstanding letters of credit at December 31, 2012. The credit facility includes an expansion feature of $250 million providing Pengrowth with up to $1.25 billion of credit capacity from a syndicate of seven Canadian and three foreign banks. The revolving credit facility matures on November 29, 2015 and can be extended at Pengrowth’s discretion any time prior to maturity, subject to syndicate approval.


28			PENGROWTH 2012 Management’s Discussion & Analysis

Pengrowth also maintains a $50 million demand operating facility with one Canadian bank. At December 31, 2012, this facility was undrawn and had approximately $0.9 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.

Together, these two facilities and the cash balance provided Pengrowth with approximately $864.9 million of available credit capacity at December 31, 2012, with the ability to expand the facilities by an additional $250 million.

Financial Covenants

Pengrowth’s senior unsecured notes and credit facilities are subject to a number of covenants, all of which were met at all times during the preceding twelve months, and at December 31, 2012. There were no changes to Pengrowth’s covenants in the twelve months ended December 31, 2012. All loan agreements can be found on SEDAR (www.sedar.com) filed under “Other” or “Material Document”.

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 financial covenants are substantially similar between the credit facilities and the senior unsecured notes.

Key financial covenants are summarized below:

Total senior debt before working capital must not exceed 3.0 times EBITDA for the last four fiscal quarters;

Total debt before working capital must not exceed 3.5 times EBITDA for the last four fiscal quarters;

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

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

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

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

If certain financial ratios reach or exceed certain levels, management may consider steps to improve these ratios. These steps may include, but are not limited to property dispositions, reducing capital expenditures or dividends as well as raising equity. Details of these measures are included in Note 17 to the audited Consolidated Financial Statements.

Convertible Debentures

As a result of the NAL Acquisition, Pengrowth assumed $349.0 million of subordinated convertible debentures at June 1, 2012. On June 22, 2012, approximately $50.5 million of the debentures were redeemed as a result of the change in control pursuant to the debenture indentures.

On August 31, 2012, $59.5 million of principal, on one series of the convertible debentures, matured and was repaid in cash. Convertible debentures with an aggregate amount of $237.1 million were outstanding at December 31, 2012. See Note 9 to the audited Consolidated Financial Statements.

Dividend Reinvestment Plan

Pengrowth’s Dividend Reinvestment Plan (“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.

On January 3, 2012, Pengrowth announced that it had introduced a Premium Dividend™ program. This program was suspended effective December 17, 2012.


PENGROWTH 2012 Management’s Discussion & Analysis			29

During the year ended December 31, 2012, 19.3 million shares were issued for cash proceeds of $135.9 million under the DRIP (including the Premium Dividend™) program, compared to 5.0 million shares issued for cash proceeds of $54.7 million in 2011.

Property Divestments

In addition to the $315 million Weyburn disposition which is expected to close in early March 2013, Pengrowth has also announced its intention to raise up to $700 million from additional property divestments in 2013. These proceeds will be used for debt repayment and capital expenditures, including Lindbergh.

Pengrowth does not have any off balance sheet financing arrangements.

FINANCIAL INSTRUMENTS

Pengrowth uses financial instruments to manage its exposure to commodity price fluctuations, foreign currency and interest rate exposures. 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 18 to the audited Consolidated Financial Statements for additional information regarding market risk, credit risk, liquidity risk and 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, 2012		Sept 30, 2012		Dec 31, 2011		Dec 31, 2012		Dec 31, 2011
Funds flow from operations		189.7		141.1		171.1		538.8		620.0
Dividends declared		61.3		60.6		73.5		284.4		280.2
Excess of funds flow from operations less dividends declared		128.4		80.5		97.6		254.4		339.8
Per share		0.25		0.16		0.28		0.57		1.02
Payout ratio ⁽¹⁾		32%		43%		43%		53%		45%

⁽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 18 to the audited Consolidated Financial Statements.

The following table provides the Net Payout Ratio when the proceeds of the Dividend Reinvestment and Premium Dividend^TMplans are accounted for to reflect Pengrowth’s net cash outlay:


	Three months ended						Twelve months ended
($ millions, except per share amounts)	Dec 31, 2012		Sept 30, 2012		Dec 31, 2011		Dec 31, 2012		Dec 31, 2011
Proceeds from Dividend Reinvestment and Premium Dividend^TM plans		26.3		41.0		17.6		135.9		54.7
Per share		0.05		0.08		0.05		0.30		0.16
Net payout ratio (%) ⁽¹⁾		18%		14%		33%		28%		36%

⁽¹⁾	Net Payout Ratio is calculated as dividends declared net of proceeds from the Dividend Reinvestment and Premium Dividend^TM plans divided by Funds Flow from Operations.


30			PENGROWTH 2012 Management’s Discussion & Analysis

DIVIDENDS

Pengrowth recognizes the importance of its dividend to shareholders. 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. As a result of the volatility in commodity prices, changes in production levels and capital expenditure requirements, 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. Pengrowth has no restrictions on the payment of its dividends other than maintaining its financial covenants in its borrowings and restrictions in the Alberta Business Corporations Act.

Dividends are generally paid to shareholders on or about the fifteenth day of the month. Pengrowth paid $0.07 per share in each of the months January through July 2012 and $0.04 per share in each of the months August through December 2012, for an aggregate annual cash dividend of $0.69 per share for the full year 2012. In 2011, Pengrowth paid a monthly dividend of $0.07 per share for an aggregate annual cash dividend of $0.84 per share.

SUMMARY OF QUARTERLY RESULTS

The following table is a summary of quarterly information for 2012 and 2011.


2012	Q1			Q2			Q3			Q4
Oil and gas sales ($ millions)		328.5			328.4			391.9			431.5
Net income (loss) ($ millions)		0.7			31.1			(23.7	)		(1.1	)
Net income (loss) per share ($)		–			0.08			(0.05	)		–
Net income (loss) per share - diluted ($)		–			0.07			(0.05	)		–
Adjusted net income (loss) ($ millions)		(5.4	)		(89.6	)		(18.7	)		24.1
Funds flow from operations ($ millions)		113.6			94.4			141.1			189.7
Dividends declared ($ millions)		76.1			86.3			60.6			61.3
Dividends declared per share ($)		0.21			0.21			0.12			0.12
Daily production (boe/d)		75,618			78,870			94,284			94,039
Total production (Mboe)		6,881			7,177			8,674			8,652
Average realized price ($/boe)		47.14			45.00			44.73			49.36
Operating netback ($/boe)		21.69			20.79			21.51			27.09

2011	Q1			Q2			Q3			Q4
Oil and gas sales ($ millions)		340.9			356.7			366.9			389.2
Net income (loss) ($ millions)		5.4			88.5			(0.5	)		(9.0	)
Net income (loss) per share ($)		0.02			0.27			–			(0.03	)
Net income (loss) per share - diluted ($)		0.02			0.27			–			(0.03	)
Adjusted net income ($ millions)		35.9			30.0			22.9			22.3
Funds flow from operations ($ millions)		146.8			151.7			150.4			171.1
Dividends declared ($ millions)		68.6			68.9			69.2			73.5
Dividends declared per share ($)		0.21			0.21			0.21			0.21
Daily production (boe/d)		73,634			70,958			74,568			76,691
Total production (Mboe)		6,627			6,457			6,860			7,056
Average realized price ($/boe)		51.15			54.41			52.68			54.28
Operating netback ($/boe)		27.64			28.97			27.15			29.99

Oil and gas sales for the third and fourth quarters of 2012 have exceeded prior quarters due to the additional volumes from the NAL Acquisition. Changes in commodity prices have also affected oil and gas sales throughout 2012 and have been partially muted by risk management activity to mitigate price volatility and to provide a measure of stability to monthly cash flow.


PENGROWTH 2012 Management’s Discussion & Analysis			31

Production increased in the second, third and fourth quarters of 2012, primarily as a result of the NAL Acquisition on May 31, 2012. In addition to natural declines, production changes over these quarters were a result of production limitations due to a SOEP Venture platform outage in the third and fourth quarters of 2012, first quarter of 2011 unscheduled pipeline outage, second quarter 2011 scheduled maintenance shutdowns and restrictions due to flooding and forest fires.

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

SELECTED ANNUAL INFORMATION

The table below provides a summary of selected annual financial information for the years ended 2012, 2011, and 2010.


	Twelve months ended December 31
($ millions unless otherwise indicated)	2012		2011		2010
Oil and gas sales		1,480.3		1,453.7		1,368.7
Net income		12.7		84.5		149.8
Net income per share ($) ⁽¹⁾		0.03		0.25		0.50
Net income per share – diluted ($)⁽¹⁾		0.03		0.25		0.49
Dividends declared per share ($) ⁽²⁾		0.66		0.84		0.77
Total assets		7,469.9		5,644.7		5,226.6
Long term debt ⁽³⁾		1,767.7		1,007.7		1,024.4
Shareholders’ equity ⁽¹⁾		4,190.3		3,347.3		3,182.3
Number of shares outstanding at year end (thousands)		511,804		360,282		326,024

⁽¹⁾	Comparative 2010 amounts are Trust units and Trust Unitholders’ equity.

⁽²⁾	2010 reflects one fewer month of distribution declared as a result of the corporate conversion.

⁽³⁾	Includes long term debt (including the current portion of long term debt) and convertible debentures, as applicable.

COMMITMENTS AND CONTRACTUAL OBLIGATIONS


($ millions)	2013		2014		2015		2016		2017		Thereafter		Total
Convertible debentures ⁽¹⁾		–		97.9		–		–		136.8		–		234.7
Interest payments on convertible debentures		14.7		14.7		8.6		8.6		2.1		–		48.7
Long term debt ⁽²⁾		49.7		–		312.0		–		398.0		776.1		1,535.8
Interest payments on long term debt⁽³⁾		81.0		80.1		77.2		67.1		56.4		113.4		475.2
Operating leases ⁽⁴⁾		15.3		15.1		14.8		14.5		12.0		1.9		73.6
Pipeline transportation		28.2		25.6		22.8		6.5		3.4		6.8		93.3
Lindbergh		3.4		3.9		–		–		–		–		7.3
Remediation trust fund payments		0.3		0.3		0.3		0.3		0.3		11.0		12.5
		192.6		237.6		435.7		97.0		609.0		909.2		2,481.1

⁽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.

⁽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 and vehicle leases.


32			PENGROWTH 2012 Management’s Discussion & Analysis

SUMMARY OF COMMON SHARE TRADING DATA


		High		Low		Close		Volume (000s)		Value ($ millions)
TSX - PGF (Cdn $)
2012	1st quarter	$	11.36	$	9.35	$	9.35		52,533		530.4
	2nd quarter	$	9.47	$	5.97	$	6.46		66,490		508.1
	3rd quarter	$	7.39	$	5.92	$	6.63		63,163		413.9
	4th quarter	$	6.72	$	4.66	$	4.95		58,845		322.5
	Year	$	11.36	$	4.66	$	4.95		241,031		1,774.9

2011	1st quarter	$	13.80	$	11.98	$	13.41		61,957		795.7
	2nd quarter	$	13.96	$	11.56	$	12.15		39,337		500.2
	3rd quarter	$	12.84	$	9.33	$	9.47		39,079		431.7
	4th quarter	$	11.18	$	8.48	$	10.76		58,503		610.7
	Year	$	13.96	$	8.48	$	10.76		198,876		2,338.4

NYSE - PGH (U.S. $)
2012	1st quarter	$	11.17	$	9.40	$	9.40		19,845		200.6
	2nd quarter	$	9.55	$	5.80	$	6.37		23,493		178.9
	3rd quarter	$	7.49	$	5.79	$	6.74		24,284		161.0
	4th quarter	$	6.85	$	4.69	$	4.97		23,467		128.3
	Year	$	11.17	$	4.69	$	4.97		91,089		668.8

2011	1st quarter	$	14.14	$	12.09	$	13.83		21,853		284.8
	2nd quarter	$	14.60	$	11.81	$	12.58		25,342		332.4
	3rd quarter	$	13.60	$	8.94	$	8.99		31,966		357.3
	4th quarter	$	11.00	$	7.99	$	10.53		25,754		258.1
	Year	$	14.60	$	7.99	$	10.53		104,916		1,232.6

SUBSEQUENT EVENTS

Weyburn Divestment

During the fourth quarter of 2012, Pengrowth announced that it had an agreement in place to sell its 10.01952 percent working interest in its non-operated Weyburn property for proceeds of $315 million, prior to closing adjustments. The sale is expected to close in early March 2013.

Commodity Price Contracts

Pengrowth entered into additional commodity and power risk management contracts subsequent to December 31, 2012 as outlined in the tables below.

Crude Oil:

Swaps

Reference Point

Volume (bbl/d)

Remaining Term

Price per bbl

Settlement
Currency

Financial:

WTI

5,000

Feb 1, 2013 - Dec 31, 2013

93.53

Cdn

WTI

19,500

Jan 1, 2014 - Dec 31, 2014

94.94

Cdn

WTI

5,000

Jan 1, 2015 - Dec 31, 2015

92.33

Cdn


PENGROWTH 2012 Management’s Discussion & Analysis			33

Natural Gas:

Swaps

Reference Point

Volume (MMBtu/d)

Remaining Term

Price per MMBtu

Settlement

Currency

Financial:

AECO

9,478

Jan 1, 2014 - Dec 31, 2014

3.74

Cdn

Power:

Reference Point

Volume (MW)

Remaining Term

Price per MWh

Settlement
Currency

Financial:

AESO

Feb 1, 2013 - Dec 31, 2013

57.08

Cdn

BUSINESS RISKS

The following 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.

The amount of dividends available to shareholders 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, 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, 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 light 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 affecting the ability to maintain the current dividends, spend capital and meet obligations. The impairment test is sensitive to lower commodity prices, which have been under significant downward pressure in recent periods, particularly natural gas prices. Further declines in commodity prices in 2013 could result in additional impairment charges as the cushions in the CGU impairment tests have been eroded by price decreases.

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 of these 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 non-compliance continued, Pengrowth would have to repay the 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.


34			PENGROWTH 2012 Management’s Discussion & Analysis

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.

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.

•

Increased 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.

•

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.

•

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 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.

•

During times of increased activity it may be more difficult to hire and retain staff and the cost for skilled labour may increase substantially.

•

Attacks by individuals against facilities and any such attacks, 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 dividends to our shareholders.

•

Delays or failure to secure regulatory approvals for thermal projects may result in capital being spent with reduced economics, reduced or no further reserves being booked, and reduced or no associated future production and cash flow.


PENGROWTH 2012 Management’s Discussion & Analysis			35

•

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 payment to shareholders. In such an event, the market value of the common shares may be adversely affected.

•

Pengrowth’s oil and gas reserves will be depleted over time and our level of cash flow from operations and the value of our common shares could be reduced 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 our common shares and dividends to our shareholders.

•

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.

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 notes 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.

FUTURE CHANGES IN ACCOUNTING POLICIES

Accounting Policies adopted January 1, 2013

Pengrowth adopted IFRS 10 Consolidated Financial Statements, IFRS 11 Joint Arrangements, IFRS 12 Disclosures of Interests in Other Entities, as well as the consequential amendments to IAS 28 Investments in Associates and Joint Ventures (2011) and IFRS 13 Fair Value Measurement, with a date of initial application of January 1, 2013.

The adoption of these standards on January 1, 2013 will have no impact on the amounts recorded in the Corporation’s Consolidated Financial Statements.

IFRS 10: Consolidated Financial Statements (“IFRS 10”)

IFRS 10 introduces a new control model that is applicable to all investees; among other things, it requires the consolidation of an investee if the Corporation controls the investee on the basis of de facto circumstances. Subsidiaries are entities controlled by the Corporation. The Corporation controls an entity when it is exposed to, or has rights to, variable returns from its involvement with the entity and has the ability to affect those returns through its power over the entity. The financial statements of subsidiaries are included in the Consolidated Financial Statements from the date that control commences until the date that control ceases.


36			PENGROWTH 2012 Management’s Discussion & Analysis

significant restrictions on the ability of the Corporation to access or use the assets, and settle the liabilities of the Corporation and its subsidiaries except for customary limitations in the Corporation’s credit facility (i.e. notification of significant dispositions).

IFRS 11: Joint Arrangements (“IFRS 11”)

Joint arrangements are arrangements of which the Corporation has joint control, established by contracts requiring unanimous consent for decisions about the activities that significantly affect the arrangements’ returns. Under IFRS 11, joint arrangements are classified as either joint operations or joint ventures depending on the Corporation’s rights to the assets and obligations for the liabilities of the arrangements. When making this assessment, the Corporation considers the structure of the arrangements, the legal form of any separate vehicles, the contractual terms of the arrangement and other facts and circumstances. Previously, the structure of the arrangement was the sole focus of classification.

The Corporation has no joint arrangements under IFRS 11. A significant portion of the Corporation’s oil and gas activities are conducted with others, however, these are considered jointly controlled assets and are outside the scope of IFRS 11. These Consolidated Financial Statements reflect only the Corporation’s proportionate share of the related assets, obligations, revenue and expenses of jointly controlled assets.

IFRS 12: Disclosures of Interests in Other Entities (“IFRS 12”)

IFRS 12 sets out certain disclosures that are required relating to interests in subsidiaries, associates, joint arrangements and unconsolidated structured entities. The Corporation does not have any investments that are not consolidated nor has it entered into any joint arrangements or structured entities.

IFRS 13: Fair Value Measurement (“IFRS 13”)

IFRS 13 defines fair value, sets out a single standard framework for measuring fair value and the required disclosures about fair value measurements. Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date.

IFRS 13 is applied prospectively to fair value measurements occurring on or after January 1, 2013. The additional disclosure requirements of IFRS 13 are also applied prospectively and will be presented, as relevant, in the 2013 interim and annual financial statements.

Accounting policies not yet adopted

IFRS 9: Financial Instruments (“IFRS 9”)

IFRS 9 is expected to be published in three parts. The first part, Phase 1—classification and measurement of financial instruments (“IFRS 9, Phase 1”), was published in October 2010.

IFRS 9, Phase 1, sets out the requirements for recognizing and measuring financial assets, financial liabilities and some contracts to buy or sell non-financial items. IFRS 9, Phase 1 simplifies measurement of financial assets by classifying all financial assets as those being recorded at amortized cost or being recorded at fair value. For financial assets recorded at fair value, any change in the fair value would be recognized in net income. IFRS 9, Phase 1, is required to be adopted for years beginning on or after January 1, 2015 although earlier adoption is allowed. Pengrowth has not made any decision as to early adoption and based on a preliminary assessment this standard should not have a material impact on Pengrowth.

Amendments to IAS 32 Financial Instruments: Presentation (“IAS 32”) and IFRS 7: Financial Instruments: Disclosures (“IFRS 7”)

Offsetting Financial Assets and Financial Liabilities: Amendments to IAS 32 and IFRS 7, was published in December 2011. The amendments to IAS 32 clarify the requirements for offsetting financial instruments. The amendments to IFRS 7 introduce new disclosure requirements for financial assets and financial liabilities that are offset in the Consolidated Balance Sheets, or are subject to enforceable master netting arrangements or similar agreements.

The amendment to IFRS 7 is applied retrospectively for annual periods beginning on or after January 1, 2013, while amendments to IAS 32 is applied retrospectively for annual periods beginning on or after January 1, 2014. Pengrowth has not made any decision as to early adoption of IAS 32 and it is expected that these standards will not have a material impact on Pengrowth.

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


PENGROWTH 2012 Management’s Discussion & Analysis			37

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, 2012. 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 our disclosure controls and procedures were effective at the reasonable assurance level as at December 31, 2012, 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

Our 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. Our internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of our Consolidated Financial Statements for external purposes in accordance with IFRS for note disclosure purposes. Our 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 our transactions and disposition of the assets; provide reasonable assurance that transactions are recorded as necessary to permit preparation of our Consolidated Financial Statements in accordance with IFRS and that receipts and expenditures of our assets are being made only in accordance with authorizations of our management and directors; and provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on our 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.

Our management, with the participation of our principal executive officer and principal financial officer, evaluated the effectiveness of our internal control over financial reporting as of December 31, 2012. 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.

Based on our evaluation, management concluded that our internal control over financial reporting was effective as of December 31, 2012.

The effectiveness of internal control over financial reporting as of December 31, 2012 was audited by KPMG LLP, an independent registered public accounting firm, as stated in their report, which is included with our audited Consolidated Financial Statements for the year ended December 31, 2012. No changes were made to our internal control over financial reporting during the year ending December 31, 2012 that have materially affected, or are reasonably likely to materially affect, the internal controls over financial reporting.

Pengrowth’s audited Consolidated Financial Statements contain financial information from the acquisition date of NAL to August 31, 2012 that was generated using a third party manager’s internal controls over financial reporting. The net revenue generated during this period was $86 million.


38			PENGROWTH 2012 Management’s Discussion & Analysis

APPENDIX C

FINANCIAL STATEMENTS OF PENGROWTH ENERGY CORPORATION, INCLUDING MANAGEMENT’S REPORT TO SHAREHOLDERS AND THE AUDITORS’ REPORTS

MANAGEMENT’S REPORT TO SHAREHOLDERS

Management’s Responsibility to Shareholders

The Consolidated Financial Statements and the notes to the Consolidated Financial Statements are the responsibility of the management of Pengrowth Energy Corporation. They have been prepared in accordance with International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board which have been adopted in Canada. Financial information that is presented in the Management Discussion and Analysis is consistent with the Consolidated Financial Statements.

In preparation of these statements, estimates are sometimes necessary because a precise determination of certain assets and liabilities is dependant on future events. Management believes such estimates have been based on careful judgments and have been properly reflected in the accompanying Consolidated Financial Statements.

Management is responsible for the reliability and integrity of the Consolidated Financial Statements, the notes to the Consolidated Financial Statements, and other financial information contained in this report. In order to ensure that management fulfills its responsibilities for financial reporting we have established an organizational structure that provides appropriate delegation of authority, division of responsibilities, and selection and training of properly qualified personnel. Management is also responsible for the development of internal controls over the financial reporting process.

The Board of Directors (”the Board”) is assisted in exercising its responsibilities through the Audit and Risk Committee (“the Committee”) of the Board, which is composed of four independent directors. The Committee meets regularly with management and the independent auditors to satisfy itself that management’s responsibilities are properly discharged, to review the Consolidated Financial Statements and to recommend approval of the Consolidated Financial Statements to the Board.

KPMG LLP, the independent auditors appointed by the shareholders, have audited Pengrowth Energy Corporation’s Consolidated Financial Statements in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States) and provided an independent professional opinion. The auditors have full and unrestricted access to the Committee to discuss the audit and their related findings as to the integrity of the financial reporting process.



Derek W. Evans		Christopher G. Webster
President and Chief Executive Officer		Chief Financial Officer

February 28, 2013


PENGROWTH 2012 Financial Results			39

INDEPENDENT AUDITORS’ REPORT OF REGISTERED

PUBLIC ACCOUNTING FIRM

TO THE SHAREHOLDERS AND BOARD OF DIRECTORS OF PENGROWTH ENERGY CORPORATION

We have audited the accompanying consolidated financial statements of Pengrowth Energy Corporation (the “Corporation”), which comprise the consolidated balance sheets as at December 31, 2012 and December 31, 2011, the consolidated statements of income, shareholders’ equity and cash flow 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 the Corporation as at December 31, 2012 and December 31, 2011, 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), the Corporation’s internal control over financial reporting as of December 31, 2012, based on the criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 28, 2013 expressed an unqualified opinion on the effectiveness of the Corporation’s internal control over financial reporting.

Chartered Accountants

Calgary, Canada

February 28, 2013


40			PENGROWTH 2012 Financial Results

REPORT OF INDEPENDENT REGISTERED

PUBLIC ACCOUNTING FIRM

TO THE SHAREHOLDERS AND BOARD OF DIRECTORS OF PENGROWTH ENERGY CORPORATION

We have audited Pengrowth Energy Corporation’s (the “Corporation”) internal control over financial reporting as of December 31, 2012, based on the criteria established in Internal Control – Integrated Framework 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 to the Shareholders. 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.

An entity’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. An entity’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 entity; (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 entity are being made only in accordance with authorizations of management and directors of the entity; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the entity’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, 2012, based on the criteria established in Internal Control – Integrated Framework 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 of December 31, 2012 and December 31, 2011, and the related consolidated statements of income, shareholders’ equity and cash flow for the years then ended, and our report dated February 28, 2013 expressed an unqualified opinion on those consolidated financial statements.

LOGO

Chartered Accountants

Calgary, Canada

February 28, 2013


PENGROWTH 2012 Financial Results			41

CONSOLIDATED BALANCE SHEETS

(Stated in thousands of dollars)


			As at			As at
	Note		December 31, 2012			December 31, 2011
ASSETS
Current Assets
Cash and cash equivalents			$	2,659		$	36,722
Accounts receivable				197,507			183,814
Fair value of risk management contracts		18		12,918			643
Assets held for sale		6		317,268			–
				530,352			221,179
Fair value of risk management contracts		18		2,561			–
Other assets		5		73,806			84,712
Property, plant and equipment		6		5,598,874			4,074,434
Exploration and evaluation assets		7		563,663			563,751
Goodwill		8		700,652			700,652
TOTAL ASSETS			$	7,469,908		$	5,644,728

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Accounts payable			$	297,496		$	273,344
Dividends payable				20,471			25,220
Fair value of risk management contracts		18		7,814			39,753
Current portion of long term debt		10		49,735			–
Current portion of provisions		11		22,635			20,149
Liabilities associated with assets held for sale		11		3,449			–
				401,600			358,466
Fair value of risk management contracts		18		19,233			26,487
Convertible debentures		9		237,050			–
Long term debt		10		1,480,898			1,007,686
Provisions		11		849,519			646,998
Deferred income taxes		12		291,274			257,838
				3,279,574			2,297,475
Shareholders’ Equity
Shareholders’ capital		13		4,634,781			3,525,222
Contributed surplus				22,935			17,697
Deficit				(467,382	)		(195,666	)
				4,190,334			3,347,253
Commitments		20
Contingencies		21
Subsequent events		23
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY			$	7,469,908		$	5,644,728

See accompanying notes to the Consolidated Financial Statements.

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



Director		Director


42			PENGROWTH 2012 Financial Results

CONSOLIDATED STATEMENTS OF INCOME

(Stated in thousands of dollars, except per share amounts)


			Year ended December 31
	Note		2012			2011
REVENUES
Oil and gas sales			$	1,480,267		$	1,453,735
Royalties, net of incentives				(277,476	)		(277,945	)
				1,202,791			1,175,790
Unrealized gain (loss) on commodity risk management		18		30,576			(39,951	)
				1,233,367			1,135,839
EXPENSES
Operating				458,552			382,024
Transportation				24,825			25,716
General and administrative				78,760			75,312
Depletion, depreciation and amortization		6		567,315			437,923
Impairment of assets		6,7,8		78,304			27,360
				1,207,756			948,335
OPERATING INCOME				25,611			187,504

Other (income) expense items
(Gain) loss on investments		5		15,000			(23,000	)
Gain on acquisition		4		(73,538	)		–
Gain on disposition of properties		6		(9,940	)		(12,647	)
Unrealized foreign exchange (gain) loss		19		(21,933	)		19,098
Realized foreign exchange loss		19		968			1,583
Interest and financing charges				86,406			75,924
Accretion		11		20,366			15,618
Other expense				27,581			4,068
INCOME (LOSS) BEFORE TAXES				(19,299	)		106,860
Deferred income tax (reduction) expense		12		(31,983	)		22,328
NET INCOME AND COMPREHENSIVE INCOME			$	12,684		$	84,532
NET INCOME PER SHARE		16
Basic			$	0.03		$	0.25
Diluted			$	0.03		$	0.25

See accompanying notes to the Consolidated Financial Statements.


PENGROWTH 2012 Financial Results			43

CONSOLIDATED STATEMENTS OF CASH FLOW

(Stated in thousands of dollars)


			Year ended December 31
	Note		2012			2011
CASH PROVIDED BY (USED FOR):
OPERATING
Net income and comprehensive income			$	12,684		$	84,532
Depletion, depreciation and accretion				587,681			453,541
Impairment of assets		6,7,8		78,304			27,360
Deferred income tax (reduction) expense		12		(31,983	)		22,328
Contract liability amortization		11		(1,648	)		(1,677	)
Unrealized foreign exchange (gain) loss		19		(21,933	)		19,098
Unrealized (gain) loss on commodity risk management		18		(30,576	)		39,951
Share based compensation		14		12,266			11,024
Non-cash (gain) loss on investments		5		15,000			(23,000	)
Non-cash gain on acquisition		4		(73,538	)		–
Gain on disposition of properties		6		(9,940	)		(12,647	)
Other items				2,441			(547	)
Funds flow from operations				538,758			619,963
Interest and financing charges				86,406			75,924
Expenditures on remediation		11		(27,575	)		(21,939	)
Changes in non-cash operating working capital		15		(43,500	)		19,135
				554,089			693,083
FINANCING
Dividends paid				(289,149	)		(277,512	)
Bank indebtedness repayment		10		(220,717	)		(22,000	)
Long term debt (repayment)		10		536,374			(39,000	)
Convertible debentures repayment		9		(110,038	)		–
Interest paid				(91,106	)		(72,612	)
Other financing cost				–			(1,605	)
Proceeds from equity issues, including DRIP				136,220			345,774
				(38,416	)		(66,955	)
INVESTING
Capital expenditures				(467,421	)		(608,463	)
Property acquisitions				(113,219	)		(8,628	)
Proceeds on property dispositions				26,631			16,935
Purchase of injectants				(4,433	)		(4,126	)
Contributions to remediation trust funds				(4,803	)		(6,030	)
Change in non-cash investing working capital		15		13,509			18,057
				(549,736	)		(592,255	)
CHANGE IN CASH AND CASH EQUIVALENTS				(34,063	)		33,873
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR				36,722			2,849
CASH AND CASH EQUIVALENTS AT END OF YEAR			$	2,659		$	36,722

See accompanying notes to the Consolidated Financial Statements.


44			PENGROWTH 2012 Financial Results

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

(Stated in thousands of dollars)


			Year ended December 31
	Note		2012			2011
SHAREHOLDERS’ CAPITAL		13
Balance, beginning of year			$	3,525,222		$	3,171,719
Share based compensation				7,979			8,086
Issued under Dividend Reinvestment Plan				60,170			54,698
Issued for cash under Premium Dividend Plan ™				75,777			–
Issued on business combination		4		965,921			–
Share issue costs, net of tax				(288	)		(9,367	)
Issued for cash on equity issue				–			300,086
Balance, end of year				4,634,781			3,525,222

CONTRIBUTED SURPLUS
Balance, beginning of year				17,697			10,626
Share based compensation		14		12,759			11,617
Exercise of share based compensation awards				(7,521	)		(4,546	)
Balance, end of year				22,935			17,697

DEFICIT
Balance, beginning of year				(195,666	)		–
Net income				12,684			84,532
Dividends declared				(284,400	)		(280,198	)
Balance, end of year				(467,382	)		(195,666	)

TOTAL SHAREHOLDERS’ EQUITY			$	4,190,334		$	3,347,253

See accompanying notes to the Consolidated Financial Statements.


PENGROWTH 2012 Financial Results			45

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

AS AT AND FOR THE YEARS ENDED DECEMBER 31, 2012 and 2011

(Tabular amounts are stated in thousands of 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 all of its subsidiaries, 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 28, 2013.

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 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 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 derecognized. The costs of the day-to-day servicing of PP&E are expensed as incurred.


46			PENGROWTH 2012 Financial Results

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.

Dispositions

Gains or losses are recognized in the Consolidated Statements of Income 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.

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 capital necessary to bring those reserves into production. Future development capital is 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.

For other assets, depreciation is recognized in the Consolidated Statements of Income 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

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 is the capital spent, or estimated to be spent, by the farmee in order to earn the interest. The difference between the estimated capital and the carrying value of the disposed interest would be recorded as a gain or loss on disposition on the Consolidated Statements of Income. When the agreed upon work commitment has been completed, the farmee has earned their interest. It is at this stage that Pengrowth would record a gain or loss on disposition.

If the farm-out results in a Gross Overriding Royalty (“GOR”) being retained by Pengrowth, rather than a working interest, a value is assigned to the GOR which then represents the deemed proceeds.

LEASED ASSETS

Assets held by Pengrowth under leases which transfer to the Corporation substantially all of the risks and rewards of ownership are classified as finance leases. On initial recognition, the leased asset is measured at an amount equal to the lower of its fair value and the present value of the minimum lease payments. Subsequent to initial recognition, the asset is accounted for in accordance with the accounting policy applicable to that asset. Minimum lease payments made under finance leases are apportioned between the finance expense and the reduction of the outstanding liability. The finance expense is allocated to each period during the lease term so as to produce a constant periodic rate of interest on the remaining balance of the liability.

Assets held under other leases are classified as operating leases and are not recognized in the Consolidated Balance Sheets. Payments made under operating leases are recognized in the Consolidated Statements of Income 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.


PENGROWTH 2012 Financial Results			47

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.

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.

IMPAIRMENT

Non-Financial Assets

Property, Plant and Equipment

For the purpose of impairment testing, PP&E is grouped together into the smallest group of assets that generate cash inflows from continuing use that are largely independent of the cash inflows of other assets or groups of assets – cash generating unit (the “CGU”).

CGUs are tested for impairment at least annually or when there is an indication of impairment, such as decreased commodity prices or 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.

The recoverable amount of a CGU is the higher of its value in use and the fair value less costs to sell. However, for properties such as Pengrowth’s, these amounts are generally the same. 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 and contingent resources are also considered in the recoverable amount.

Impairment losses recognized in respect of 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 in respect of PP&E recognized in prior periods are assessed at each reporting date for any indications that the loss has decreased or no longer exists. In such circumstances, the recoverable amount is determined and to the extent the loss is reduced, it is reversed. An impairment loss is reversed only to the lesser of the revised recoverable amount or the carrying amount that would have been determined, net of depletion and depreciation or amortization, if no impairment loss had been recognized.

Exploration and Evaluation Assets

E&E assets are tested for impairment where there is an indication that a particular E&E project may be impaired. Examples of indicators of impairment include the decision to 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 include any surplus from PP&E impairment testing of related CGUs. The impairment of E&E assets and any eventual impairment thereof would be recognized in the Consolidated Statements of Income.

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.


48			PENGROWTH 2012 Financial Results

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.

All impairment losses are recognized in the Consolidated Statements of Income. 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.

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 a pre-tax rate that reflects current market assessments of the time value of money and the risks specific to the liability. 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 properties and the Sable Offshore Energy Project (“SOEP”). These funds are reflected in Other Assets on the Consolidated Balance Sheets.

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 within this grouping.

DEFERRED INCOME TAXES

Income tax expense is comprised of current and deferred tax. Income tax expense is recognized in the Consolidated Statements of Income 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.


PENGROWTH 2012 Financial Results			49

SHARE BASED COMPENSATION PLANS

Pengrowth has share based compensation plans, which are described in Note 14. 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 over the vesting period of the plan with a corresponding increase to contributed surplus. Pengrowth estimates the forfeiture rate for each type of share based award at the date of grant. Any consideration received upon the exercise of the awards together with the amount of non-cash compensation expense recognized in contributed surplus is recorded as an increase in shareholders’ capital at the time of exercise.

Pengrowth does not have any outstanding share based compensation plans that call for settlement in cash or other assets. Grants of such items, if any, will be recorded as liabilities, with changes in the liabilities charged to net income, based on the estimated fair value.

FINANCIAL INSTRUMENTS

Financial instruments are utilized by Pengrowth to manage its exposure to commodity 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 as other (income) expense.

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.

All derivatives must be classified as held for trading and measured at fair value with changes in fair value over a reporting period recognized in net income.

The receipts or payments arising from derivative commodity contracts are included in oil and gas sales, while unrealized gains and losses are presented as a separate caption under revenues.

The receipts or payments arising from derivative power and interest rate contracts are included in operating expenses and interest expense. The unrealized gains and losses on derivative power and interest rate contracts are included in other (income) expense and interest expense.

The receipts or payments arising from derivative foreign exchange contracts are presented as realized foreign exchange (gain) loss while the unrealized gains and losses are presented as unrealized foreign exchange (gain) loss.

Transaction costs incurred in connection with the issuance of term debt instruments with a maturity of greater than one year are deducted against the carrying value of the debt and amortized to net income 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 on a straight line basis over the term of the facility.

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 balance sheet date. Foreign exchange gains and losses are recognized in net income.

JOINTLY CONTROLLED OPERATIONS

A significant proportion of Pengrowth’s petroleum and natural gas development and production activities are conducted through jointly controlled operations with others and accordingly, the accounts reflect only Pengrowth’s interest in such activities.


50			PENGROWTH 2012 Financial Results

RELATED PARTIES

Related parties are persons or entities that have control or significant influence over Pengrowth, as well as key management personnel. Note 22 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 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 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 financial statements are 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”).

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 judgement. 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 future expenses, estimated logistics of performing abandonment work and the discount rate used to calculate the present value of future expenses would have a significant effect on the carrying amount of the decommissioning provision.

Impairment testing

The impairment testing of PP&E is completed at least annually for each CGU, and 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 and contingent resources are also considered. The impairment assessment of goodwill is based on the estimated fair value of Pengrowth’s CGUs. By their nature, these estimates are subject to measurement uncertainty and may impact the financial statements of future periods.


PENGROWTH 2012 Financial Results			51

Valuation of trade and other receivables, and prepayments to suppliers

NET INCOME PER SHARE

Basic net income per share is calculated using the weighted average number of shares outstanding for the year. Diluted net income per share amounts includes the dilutive effect of common share rights and options, deferred entitlement share units and other share units under the new long term incentive plans 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 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.

COMPARATIVE FIGURES

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

3.	RECENT ACCOUNTING PRONOUNCEMENTS

Accounting Policies adopted January 1, 2013

The adoption of these standards on January 1, 2013 will have no impact on the amounts recorded in the Corporation’s Consolidated Financial Statements.

IFRS 10: Consolidated Financial Statements (“IFRS 10”)

On January 1, 2013, the Corporation had wholly owned subsidiaries, none of which hold any significant assets (holding companies). The determination of whether to consolidate these entities does not involve any significant judgments or assumptions. There are no significant restrictions on the ability of the Corporation to access or use the assets, and settle the liabilities of the Corporation and its subsidiaries except for customary limitations in the Corporation’s credit facility (i.e. notification of significant dispositions).

IFRS 11: Joint Arrangements (“IFRS 11”)


52			PENGROWTH 2012 Financial Results

IFRS 12: Disclosures of Interests in Other Entities (“IFRS 12”)

IFRS 13: Fair Value Measurement (“IFRS 13”)

Accounting policies not yet adopted

IFRS 9: Financial Instruments (“IFRS 9”)

IFRS 9 is expected to be published in three parts. The first part, Phase 1 – classification and measurement of financial instruments (“IFRS 9, Phase 1”), was published in October 2010.

Amendments to IAS 32 Financial Instruments: Presentation (“IAS 32”) and IFRS 7: Financial Instruments: Disclosures (“IFRS 7”)

4.	BUSINESS COMBINATIONS

NAL ENERGY CORPORATION

Pengrowth and NAL Energy Corporation (“NAL”) completed a business combination on May 31, 2012 (the “Combination”) where Pengrowth acquired all of the outstanding common shares of NAL in exchange for 0.86 of a Pengrowth share per NAL share. The Combination resulted in the issuance of 131.2 million common shares of Pengrowth to former NAL shareholders, as well as the assumption by Pengrowth of NAL’s convertible debentures and long term debt. Pengrowth’s share price on the date that the transaction was announced on March 22, 2012, was $9.95 per share. The share price on the closing date, which is the price Pengrowth is required to use to value the shares issued in the Combination, was $7.36 per Pengrowth share.

NAL was a publicly traded petroleum and natural gas company with operations in Alberta, British Columbia, Saskatchewan and Ontario. Pengrowth acquired NAL to enable growth opportunities that result from a larger, stronger and more diverse company through enhanced exposure to light oil plays.


PENGROWTH 2012 Financial Results			53

The transaction was accounted for using the acquisition method based on fair values as follows:


Acquired net assets:
Property, plant and equipment	$	1,748,032
Derivative instruments		16,209
Inventory		2,487
Convertible debentures		(348,975	)
Bank debt		(219,061	)
Working capital deficiency		(46,936	)
Asset retirement obligations		(46,981	)
Deferred tax liability		(65,516	)
Gain on acquisition		(73,538	)
	$	965,721

The gain on acquisition amounted to $73.5 million and is recorded as a separate line item on the Consolidated Statements of Income. The gain is due in large part to a decline in Pengrowth’s share price from the date the transaction was announced to the closing date, and has no basis for tax purposes. As part of finalizing certain balances, Pengrowth decreased the previously recorded working capital deficiency by $5.7 million resulting in an adjustment to the gain on acquisition which will be reflected in the second quarter of 2012 comparative figures. The fair value of receivables included in the working capital deficiency was $44.2 million.

The Consolidated Financial Statements include the results of operations and cash flows from NAL subsequent to the closing date of May 31, 2012. Proforma revenues net of royalties and net income for the combined entity for the period January 1, 2012 to December 31, 2012 would have been approximately $1.4 billion and $13.0 million, respectively.

Revenue net of royalties contributed by NAL since the acquisition for the period June 1, 2012 to December 31, 2012 was $201.9 million. Net income contributed by NAL in this period is not determinable, as the results of NAL’s operations were combined effective June 1, 2012. Transaction costs relating to the business combination in the amount of $21.5 million were incurred by Pengrowth to December 31, 2012, and are included in the other (income) expense line in the Consolidated Statements of Income.

For the period from closing on May 31, 2012 to August 31, 2012, certain administrative functions affecting the acquired NAL properties were transferred from the former administrating management company (the “Manager”) to Pengrowth. In this transition period, Pengrowth paid its portion of the Manager’s general and administrative costs, as determined by NAL’s share of production under management.

LOCHEND CARDIUM

Pengrowth purchased properties in the Lochend Cardium area of Alberta on November 2, 2012 for $61.4 million adding approximately 530 boe/d with more optimization of this production expected in early 2013. The assets acquired complement and consolidate Pengrowth’s position in this light oil resource play.

The transaction was accounted for by the acquisition method based on fair values as follows:


Acquired net assets:
Property, plant and equipment	$	61,805
Asset retirement obligation		(366	)
	$	61,439

The estimated fair value of property, plant and equipment was determined using internal estimates. The asset retirement obligation was determined using Pengrowth’s estimated timing and costs to remediate, reclaim and abandon the wells and facilities. An inflation rate of 1.5 percent and a discount rate of 8 percent were used.


54			PENGROWTH 2012 Financial Results

5.	OTHER ASSETS


	As at
	December 31, 2012		December 31, 2011
Remediation trust funds	$	53,806	$	49,712
Other investment		20,000		35,000
	$	73,806	$	84,712

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 $250,000. 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, 2012 the carrying value of the Judy Creek remediation trust fund was $7.5 million (December 31, 2011 – $8.2 million).

Pengrowth has a contractual obligation to make contributions to a remediation trust fund that will be used to fund the ARO of the SOEP properties and facilities. Pengrowth currently makes a monthly contribution to the fund of $0.52/MMBtu of its share of natural gas production and $1.04/bbl of its share of natural gas liquids production from SOEP. The investment in the SOEP fund is classified as fair value through profit or loss. Investment income is recognized when earned and is recorded in other (income) expense. As at December 31, 2012 the carrying value of the SOEP remediation trust fund was $46.3 million (December 31, 2011 – $41.5 million).

The following reconciles Pengrowth’s investment in remediation trust funds for the periods noted below:


	Remediation Trust Funds
Balance, January 1, 2011	$	42,115
Contributions		5,136
Remediation expenditures from funds		(1,095	)
Investment income		1,989
Unrealized gain		1,567
Balance, December 31, 2011	$	49,712
Contributions		3,933
Remediation expenditures from funds		(1,480	)
Investment income		2,350
Unrealized loss		(709	)
Balance, December 31, 2012	$	53,806

OTHER INVESTMENT

Pengrowth owns 1.0 million shares of a private corporation with an estimated fair value of $20 million. This investment is classified as fair value through profit or loss. The fair value is based in part on recent trading activity in the private company. Pengrowth owns a minority interest in 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. Therefore, it is uncertain if Pengrowth could realize this value in an open market and, as such, the fair value is subject to revision. The fair value has decreased to $20 million as at December 31, 2012 (December 31, 2011 – $35 million), resulting in an unrealized loss of $15 million for the year ended December 31, 2012 (December 31, 2011 – $23 million gain).


PENGROWTH 2012 Financial Results			55

6.	PROPERTY, PLANT AND EQUIPMENT


Cost or Deemed Cost	Oil and natural gas assets			Other equipment		Total
Balance, January 1, 2011	$	4,138,502		$	64,686	$	4,203,188
Expenditures on property, plant and equipment		534,297			5,152		539,449
Property acquisitions		10,623			–		10,623
Transfers from exploration and evaluation assets		26,313			–		26,313
Change in asset retirement obligations		215,360			–		215,360
Divestitures		(7,340	)		–		(7,340	)
Balance, December 31, 2011	$	4,917,755		$	69,838	$	4,987,593
Expenditures on property, plant and equipment		421,755			4,382		426,137
Acquisitions through business combinations		1,809,837			–		1,809,837
Property acquisitions		51,780			–		51,780
Change in asset retirement obligations		167,936			–		167,936
Divestitures		(19,764	)		–		(19,764	)
Balance, December 31, 2012	$	7,349,299		$	74,220	$	7,423,519

Accumulated depletion, amortization and impairment losses	Oil and natural gas assets			Other equipment		Total
Balance, January 1, 2011	$	423,661		$	41,511	$	465,172
Depletion and amortization for the period		430,053			7,870		437,923
Impairment loss		11,121			–		11,121
Divestitures		(1,057	)		–		(1,057	)
Balance, December 31, 2011	$	863,778		$	49,381	$	913,159
Depletion and amortization for the period		560,240			7,075		567,315
Impairment loss		29,976			–		29,976
Divestitures		(3,073	)		–		(3,073	)
Balance, December 31, 2012	$	1,450,921		$	56,456	$	1,507,377

Carrying Amount	Oil and natural gas assets			Other equipment		Total
As at December 31, 2012
Current	$	317,268		$	–	$	317,268
Long term		5,581,110			17,764		5,598,874
	$	5,898,378		$	17,764	$	5,916,142
As at December 31, 2011
Long term	$	4,053,977		$	20,457	$	4,074,434

During the year ended December 31, 2012, approximately $10.1 million (December 31, 2011 – $15.8 million) of directly attributable general and administrative costs were capitalized to PP&E.

During the year ended December 31, 2012, $9.9 million of gains were recorded on divestitures (December 31, 2011 – $12.6 million).

ASSETS HELD FOR SALE

During the fourth quarter of 2012, Pengrowth announced that it had an agreement in place to sell its 10.01952 percent working interest in its non-operated Weyburn property. Total proceeds, prior to closing adjustments, will be $315 million. The sale is expected to close in early March 2013.


56			PENGROWTH 2012 Financial Results

The $317.3 million carrying value of the Weyburn properties is presented as assets held for sale and classified as current assets on the Consolidated Balance Sheets. The related ARO liability of $3.4 million is presented as liabilities associated with assets held for sale and classified as current liabilities on the Consolidated Balance Sheets.

IMPAIRMENT TESTING

IFRS requires an impairment test to assess the recoverable value of the PP&E within each CGU whenever there is an indication of impairment. Impairment tests were performed at December 31, 2011, June 30, 2012 and December 31, 2012. The recoverable amounts of each CGU was based on the higher of value in use or fair value less costs to sell.

The estimates of the recoverable amounts were determined based on the following information:

(a)	The net present value of the CGU’s oil and gas reserves using;

Proved plus probable reserves as estimated by Pengrowth’s independent reserves evaluator,

ii.

The commodity price forecast of Pengrowth’s independent reserves evaluator,

iii.

Discounted at an estimated market rate.

(b)	The fair value of undeveloped land.

(c)	The fair value of contingent resources estimated by Management and Pengrowth’s independent reserves evaluator.

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)

Contingent resources. Assumptions that are valid at the time of contingent resource 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 contingent resources and may ultimately result in contingent resources being restated.

The impairment tests carried out were based on a discount rate of 8 percent, and an inflation rate of 2 percent.

Below are the forward commodity price estimates used in the December 31, 2012 impairment test:


Year	WTI oil ⁽¹⁾(U.S.$/bbl)		Foreign exchange rate (U.S.$/Cdn$)		Edmonton light crude oil ⁽¹⁾ (Cdn$/bbl)		AECO gas ⁽¹⁾(Cdn$/MMBtu)
2013		90.00		1.00		85.00		3.38
2014		92.50		1.00		91.50		3.83
2015		95.00		1.00		94.00		4.28
2016		97.50		1.00		96.50		4.72
2017		97.50		1.00		96.50		4.95
2018		97.50		1.00		96.50		5.22
2019		98.54		1.00		97.54		5.32
2020		100.51		1.00		99.51		5.43
2021		102.52		1.00		101.52		5.54
2022		104.57		1.00		103.57		5.64
Thereafter		+ 2.0 percent/yr		1.00		+ 2.0 percent/yr		+ 2.0 percent/yr

⁽¹⁾	Prices represent forecasted amounts as at January 1, 2013 by Pengrowth’s independent reserves evaluator.


PENGROWTH 2012 Financial Results			57

Based on the impairment tests carried out, there were no additional impairments to record at December 31, 2012. The impairment test is sensitive to lower commodity prices, which have been under significant downward pressure in recent periods, particularly natural gas prices. Further declines in commodity prices in 2013 could result in additional impairment charges as the cushions in the CGU impairment tests have been eroded by price decreases.

At June 30 2012, the carrying value of the producing Groundbirch CGU exceeded the fair value less costs to sell and an impairment of $30.0 million on PP&E was recognized.

At December 31, 2011, the carrying value of the producing Groundbirch CGU exceeded the fair value less costs to sell and an impairment was recognized for $27.4 million. As a result, the full amount of goodwill attributed to the producing Groundbirch CGU was eliminated, thereby reducing goodwill by $16.2 million. The related PP&E was reduced by $11.1 million.

The impairments noted above may be reversed if the fair value of the producing Groundbirch CGU increases in future periods; however the impairment of goodwill attributed to the producing Groundbirch CGU cannot be reversed.

7.	EXPLORATION AND EVALUATION ASSETS


Cost or Deemed Cost
Balance, January 1, 2011	$	511,569
Additions		78,495
Transfers to property, plant and equipment		(26,313	)
Balance, December 31, 2011	$	563,751
Additions		48,240
Impairment loss		(48,328	)
Balance, December 31, 2012	$	563,663

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. E&E assets consist mainly of costs associated with the Lindbergh project and the undeveloped portion of Groundbirch.

Upon achievement of commercial viability and technical feasibility, E&E assets are transferred to property, plant and equipment.

There were no amounts transferred to property, plant and equipment during the year ended December 31, 2012. During 2011, the amounts transferred related to the producing sections of the Grounbirch property. During 2012, the Lindbergh project remained in E&E as Pengrowth worked on achieving technical feasibility and demonstrating commercial viability, including receiving all of the necessary environmental and regulatory approvals. Thus, all production from the Lindbergh pilot project was not included in production volumes and any net revenue received from production was not recognized in income while the project remained classified as an E&E Asset. During the year ended December 31, 2012, the revenues, net of royalties and production costs, capitalized to the Lindbergh pilot project were $4.9 million (December 31, 2011 – nil).

Subsequent to December 31, 2012, the Board of Directors sanctioned the first 12,500 bbl/d of the Lindbergh project.

During the year ended December 31, 2012, $1.5 million (December 31, 2011 – $1.6 million) of directly attributable general and administrative costs related to exploration and evaluation activities were capitalized.

IMPAIRMENT OF E&E ASSETS

During the second quarter of 2012, it was determined that there will be no future drilling in the Horn River area due to low natural gas prices and a lack of infrastructure. Accordingly, there will be no additional capital spent to hold Pengrowth’s existing leases in the area, the majority which will now be left to expire. As a result, the carrying value of the Horn River assets was written down to nil, resulting in an impairment of $48.3 million on E&E assets at June 30, 2012.

Subsequent to June 30, 2012 there have been no indications of impairment requiring Pengrowth to perform an impairment test.


58			PENGROWTH 2012 Financial Results

8.	GOODWILL

The following table reconciles Pengrowth’s Goodwill:


Cost or Deemed Cost
Balance, January 1, 2011	$	716,891
Impairment		(16,239	)
Balance, December 31, 2011	$	700,652
Balance, December 31, 2012	$	700,652

Goodwill is stated at cost less accumulated impairment. 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. At December 31, 2012 an impairment test was performed, with no impairments to goodwill recorded. At December 31, 2011 the carrying value of the Groundbirch CGU exceeded the fair value less costs to sell, and an impairment was recognized for $27.4 million. As a result, goodwill attributed to the Groundbirch CGU was reduced by $16.2 million to NIL and the corresponding PP&E was reduced by $11.1 million. The impairment of goodwill attributed to Groundbirch cannot be reversed.

The carrying value of goodwill at December 31, 2012 is $701 million. Approximately $130 million is attributable to the Swan Hills area CGU as it relates directly to the purchase of the Carson Creek property in 2006. The remaining goodwill is not attributed to any specific CGU thus this value is supported by the excess recoverable amount over the carrying value of certain of Pengrowth’s CGUs.

9.	CONVERTIBLE DEBENTURES

In connection with the business combination with NAL, Pengrowth assumed $349 million of subordinated convertible debentures, which were issued in three different series. These 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.

Pengrowth was required to make offers to purchase all of the outstanding NAL 6.75 percent Debentures and NAL 6.25 percent Series A Debentures at a price equal to 101 percent of the respective principal amounts plus accrued and unpaid interest, and all of the outstanding NAL 6.25 percent Series B Debentures at a price equal to 100 percent of the principal amount thereof plus accrued and unpaid interest. As a result, on June 22, 2012, Pengrowth purchased $50.5 million of debenture principal for $52.1 million, which included accrued interest of $0.9 million and a premium of $0.7 million.

The convertible debentures are classified as a non-current liability on the Consolidated Balance Sheets and the debt premium accretes over time to the principal amount owing on maturity. No value has been 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.

On August 31, 2012, $59.5 million of debentures matured and were settled in cash, leaving two series outstanding at December 31, 2012. The following table summarizes each series as well as the activity associated with the convertible debentures from the date of acquisition to December 31, 2012:


Series		6.75%			Series A-6.25%			Series B-6.25%
Maturity date		Aug 31, 2012			Dec 31, 2014			Mar 31, 2017
Conversion price (per Pengrowth share)	$	16.28		$	19.19		$	11.51			Total
Balance, June 1, 2012	$	80,565		$	117,645		$	150,765		$	348,975
Redeemed		(20,221	)		(17,137	)		(13,157	)		(50,515	)
Premium released upon redemption		(208	)		(394	)		(67	)		(669	)
Premium accretion		(613	)		(520	)		(85	)		(1,218	)
Matured		(59,523	)		–			–			(59,523	)
Balance, December 31, 2012	$	–		$	99,594		$	137,456		$	237,050
Face value, December 31, 2012	$	–		$	97,863		$	136,843		$	234,706


PENGROWTH 2012 Financial Results			59

10.

LONG TERM DEBT AND BANK INDEBTEDNESS


	As at
	December 31, 2012		December 31, 2011
U.S. dollar denominated senior unsecured notes:
50 million at 5.47 percent due April 2013	$	49,735	$	50,799
71.5 million at 4.67 percent due May 2015		70,933		72,423
400 million at 6.35 percent due July 2017		396,838		405,429
265 million at 6.98 percent due August 2018		262,757		268,452
35 million at 3.49 percent due October 2019		34,619		–
115.5 million at 5.98 percent due May 2020		114,385		116,865
105 million at 4.07 percent due October 2022		103,849		–
195 million at 4.17 percent due October 2024		192,858		–
	$	1,225,974	$	913,968
U.K. pound sterling denominated 50 million unsecured notes at 5.46 percent due December 2015		80,682		78,718
U.K. pound sterling denominated 15 million unsecured notes at 3.45 percent due October 2019		24,126		–
Canadian dollar 15 million senior unsecured notes at 6.61 percent due August 2018		15,000		15,000
Canadian dollar 25 million senior unsecured notes at 4.74 percent due October 2022		24,851		–
Canadian dollar revolving credit facility borrowings		160,000		–
Total long term debt	$	1,530,633	$	1,007,686
Current	$	49,735	$	–
Long term		1,480,898		1,007,686
	$	1,530,633	$	1,007,686

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 credit capacity from a syndicate of seven Canadian and three foreign banks. The facility matures on November 29, 2015 and can be renewed at Pengrowth’s discretion any time prior to its maturity, subject to syndicate approval. In the event that the lenders do not agree to a renewal, the outstanding balance is due upon maturity.

This facility carries floating interest rates that are expected to range between 2.0 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. At December 31, 2012, the available facility was reduced by drawings of $160 million (December 31, 2011 - nil) and letters of credit in the amount of approximately $28 million (December 31, 2011- $24 million) were outstanding.

Pengrowth also maintains a $50 million demand operating facility with one Canadian bank. At December 31, 2012, this facility was undrawn (December 31, 2011 - nil) and reduced by approximately $0.9 million of outstanding letters of credit (December 31, 2011 – $1.5 million). When utilized together with any overdraft amounts, this facility appears on the Consolidated Balance Sheets as a current liability in bank indebtedness.

As of December 31, 2012, an unrealized cumulative foreign exchange gain of $59.3 million (December 31, 2011 – $42.8 million gain) has been recognized on the U.S. dollar term notes since the date of issuance. As of December 31, 2012, an unrealized cumulative foreign exchange gain of $32.7 million (December 31, 2011 - $35.1 million gain) has been recognized on the U.K. pound sterling denominated term notes since inception. See Note 18 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: 2013 - $49.7 million, 2014 - NIL, 2015 - $311.6 million, 2016 - NIL, 2017- $396.8 million.


60			PENGROWTH 2012 Financial Results

11.

PROVISIONS

Provisions are composed of ARO and contract liabilities. The following provides a continuity of the ARO and contract liabilities for the following periods:


	Asset retirement obligations			Contract & Other liabilities			Total
Balance, January 1, 2011	$	447,068		$	7,952		$	455,020
Provisions made during the period		7,789			–			7,789
Provisions on dispositions		(1,151	)		–			(1,151	)
Provisions settled		(21,939	)		–			(21,939	)
Revisions due to discount rate changes		206,554			–			206,554
Other revisions		6,932			–			6,932
Accretion (amortization)		15,618			(1,676	)		13,942
Balance, December 31, 2011	$	660,871		$	6,276		$	667,147
Assumed in business combinations		47,347			–			47,347
Provisions made during the period		4,802			2,030			6,832
Provisions on acquisitions		30,893			–			30,893
Provisions on dispositions		(5,511	)		–			(5,511	)
Revisions due to discount rate changes ⁽¹⁾		178,134			–			178,134
Provisions settled		(27,575	)		–			(27,575	)
Other revisions		(40,382	)		–			(40,382	)
Accretion (amortization)		20,366			(1,648	)		18,718
Balance, December 31, 2012	$	868,945		$	6,658		$	875,603

⁽¹⁾	Relates to the change in the discount rate from 8 percent to 2.5 percent on the ARO balances assumed in the NAL and Lochend business combinations. The offset is recorded in property plant and equipment.


As at December 31, 2012
Current ⁽¹⁾	$	24,050	$	2,034	$	26,084
Long term		844,895		4,624		849,519
	$	868,945	$	6,658	$	875,603

⁽¹⁾	Includes current liability related to ARO for Weyburn assets held for sale of $3.4 million.


As at December 31, 2011
Current	$	18,500	$	1,649	$	20,149
Long term		642,371		4,627		646,998
	$	660,871	$	6,276	$	667,147

The following assumptions were used to estimate the ARO liability:


	As at
	December 31, 2012		December 31, 2011
Total escalated future costs ($ millions)		2,414		1,845
Discount rate, per annum		2.5%		2.5%
Inflation rate, per annum		1.5%		1.5%

These costs are expected to be incurred over 65 years with the majority of the costs incurred between 2036 and 2077.

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 made during the period relate to a finance lease transaction.


PENGROWTH 2012 Financial Results			61

12.

DEFERRED INCOME TAXES

A reconciliation of the deferred income tax (reduction) expense calculated based on the Income (Loss) before taxes at the statutory tax rate to the actual provision for deferred income taxes is as follows:


	Year ended December 31
	2012			2011
Income (loss) before taxes	$	(19,299	)	$	106,860
Combined federal and provincial tax rate		25.32%			26.86%
Expected income tax (reduction) expense	$	(4,887	)	$	28,703
Foreign exchange (gain) loss ⁽¹⁾		(1,647	)		2,781
Effect of change in corporate tax rate		(415	)		(10,026	)
(Gain) loss on investments		1,899			(3,089	)
Gain on acquisition ⁽²⁾		(18,620	)		–
Reduction in prior periods unrecognized tax benefits		(13,460	)		–
Impairment on goodwill		–			4,362
Other non-deductible including stock based compensation and NAL acquisition costs		5,147			(403	)
Deferred income tax (reduction) expense	$	(31,983	)	$	22,328

⁽¹⁾	Reflects the 50% non-taxable portion of foreign exchange gains and losses.

⁽²⁾	Reflects the gain on acquisition relating to the business combination with NAL.

The deferred income tax rate applied to the temporary differences in 2012 and 2011 was 25.3 and 25.4 percent respectively, compared to the combined federal and provincial statutory rates of 25.3 percent and 26.9 percent for the 2012 and 2011 taxation years. The general combined federal and provincial tax rate decreased due to a reduction in the federal rate from 16.5 percent in 2011 to 15.0 percent in 2012.

The net deferred income tax liability is comprised of:


	As at
	December 31, 2012			December 31, 2011
Deferred tax liabilities associated with:
Property, plant and equipment and E&E assets	$	(718,479	)	$	(544,273	)
Long term debt		(10,661	)		(8,699	)
	$	(729,140	)	$	(552,972	)
Less deferred tax assets associated with:
Non-capital losses		208,295			104,194
Convertible debentures		593			–
Share issue costs		4,888			5,106
Provisions		221,162			169,198
Risk management contracts		2,928			16,636
Net deferred tax liability	$	(291,274	)	$	(257,838	)

In calculating the deferred income tax liability in 2012, Pengrowth included $832.8 million (2011 – $420.9 million) of non-capital losses available for carry forward to reduce taxable income in future years. These losses expire between 2025 and 2031.

Deferred tax assets have not been recognized with respect to the following items:


	As at
	December 31, 2012		December 31, 2011
Deductible temporary differences	$	25,510	$	25,510
Tax losses		16,711		16,711
	$	42,221	$	42,221


62			PENGROWTH 2012 Financial Results

A continuity of the net deferred income tax asset (liability) for 2012 and 2011 is detailed in the following tables:


Movement in temporary differences during the year	Balance Jan 1, 2012			Recognized in profit or loss			Recognized directly in equity		Acquired in business combinations			Balance Dec 31, 2012
Property, plant and equipment and E&E assets	$	(544,273	)	$	(17,520	)	$	–	$	(156,686	)	$	(718,479	)
Convertible debentures		–			(478	)		–		1,071			593
Long term debt		(8,699	)		(1,962	)		–		–			(10,661	)
Share issue costs		5,106			(2,191	)		97		1,876			4,888
Non-capital losses		104,194			23,669			–		80,432			208,295
Provisions		169,198			40,069			–		11,895			221,162
Risk management contracts		16,636			(9,604	)		–		(4,104	)		2,928
	$	(257,838	)	$	31,983		$	97	$	(65,516	)	$	(291,274	)

Movement in temporary differences during the year	Balance Jan 1, 2011			Recognized in profit or loss			Recognized directly in equity					Balance Dec 31, 2011
Property, plant and equipment and E&E assets	$	(470,796	)	$	(73,477	)	$	–				$	(544,273	)
Long term debt		(19,820	)		11,121			–					(8,699	)
Share issue costs		5,163			(3,241	)		3,184					5,106
Non-capital losses		131,222			(27,028	)		–					104,194
Provisions		107,892			61,306			–					169,198
Risk management contracts		7,645			8,991			–					16,636
	$	(238,694	)	$	(22,328	)	$	3,184				$	(257,838	)

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 2012 and 2011.

13.

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.


	2012					2011
	Number of common shares		Amount			Number of common shares		Amount
Balance, beginning of year		360,282,162	$	3,525,222			326,024,040	$	3,171,719
Share based compensation (cash exercised)		71,890		450			542,083		3,540
Share based compensation (non-cash exercised)		895,357		7,529			368,994		4,546
Issued for cash under Dividend Reinvestment Plan (DRIP)		8,289,603		60,170			5,037,045		54,698
Issued for cash under Premium Dividend Plan ™		11,025,949		75,777			–		–
Issued on NAL business combination		131,239,234		965,921			–		–
Issued for cash on equity issue		–		–			28,310,000		300,086
Share issue costs, net of tax of $97 (2011 – $3,184)		–		(288	)		–		(9,367	)
Balance, end of year		511,804,195	$	4,634,781			360,282,162	$	3,525,222

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.

On January 3, 2012, Pengrowth announced that it had introduced a Premium Dividend™ program. The Premium Dividend™ program was suspended effective December 17, 2012.


PENGROWTH 2012 Financial Results			63

14.

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 maximum of 4.5 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, 2012, the number of shares issuable under the share based compensation plans, in aggregate, represents 1.2 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
	2012			2011
Long term incentive plan	$	13,043		$	7,661
Previous long term incentive plan ⁽¹⁾
Deferred entitlement share unit plan		(284	)		3,709
Common share rights incentive plan		–			247
Total share based compensation	$	12,759		$	11,617
Amounts capitalized in the year		(493	)		(593	)
Share based compensation expense included in net income	$	12,266		$	11,024

⁽¹⁾	These compensation plans were used while Pengrowth was a trust. Effective January 1, 2011, no further grants were made under these plans.

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. Shares issued in 2011 will be subject to a performance factor ranging from 50 percent to 200 percent of the number of shares granted plus the amount of reinvested notional dividends, while shares issued in 2012 will be subject to a performance factor ranging from 50 percent to 150 percent of the number of shares granted plus the amount of reinvested notional dividends.

(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 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.

The Board of Directors retain discretion with respect to the LTIP.


64			PENGROWTH 2012 Financial Results

The following provides a continuity of the LTIP:


	2012
	PSUs					RSUs					DSUs
	Number of share units			Weighted average price		Number of share units			Weighted average price		Number of share units		Weighted average price
Outstanding, beginning of year		573,274		$	12.42		686,134		$	12.45		50,159	$	12.64
Granted		1,157,256			8.81		1,581,100			8.77		75,997		9.47
Forfeited		(117,469	)		11.26		(128,144	)		10.95		–		–
Exercised		(174	)		12.64		(303,579	)		11.77		–		–
Deemed DRIP ⁽¹⁾		110,928			10.91		122,532			10.71		9,637		11.11
Outstanding, end of year		1,723,815		$	9.98		1,958,043		$	9.57		135,793	$	10.76

⁽¹⁾	Weighted average deemed DRIP price for accounting purposes is based on the average of the original grant prices.


	2011
	PSUs					RSUs					DSUs
	Number of share units			Weighted average price		Number of share units			Weighted average price		Number of share units		Weighted average price
Outstanding, beginning of year		–		$	–		–		$	–		–	$	–
Granted		637,000			12.44		882,267			12.49		47,468		12.64
Forfeited		(94,249	)		12.57		(117,527	)		12.58		–		–
Exercised		–			–		(119,487	)		12.64		–		–
Deemed DRIP ⁽¹⁾		30,523			12.56		40,881			12.58		2,691		12.64
Outstanding, end of year		573,274		$	12.42		686,134		$	12.45		50,159	$	12.64

⁽¹⁾	Weighted average deemed DRIP price for accounting purposes is based on the average of the original grant prices.

Compensation expense related to PSU, RSU, and DSU 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, which has been estimated at 10 to 25 percent for employees and 3 to 15 percent for 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 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, 2012, Pengrowth recorded $13.0 million of compensation expense related to the LTIP units (December 31, 2011 – $7.7 million), based on the weighted average grant date fair value of $8.80 per share unit (December 31, 2011 – $12.46 per share unit). As at December 31, 2012, the amount of compensation expense to be recognized over the remaining vesting period was $15.4 million or $4.46 per share unit (December 31, 2011 – $8.8 million or $4.86 per share unit) subject to the determination of the performance multiplier. The unrecognized compensation cost will be expensed to net income over the remaining weighted average vesting period of 1.5 years.


PENGROWTH 2012 Financial Results			65

PREVIOUS LONG TERM INCENTIVE PLANS

(a)	Deferred Entitlement Share Units (“DESU”) Plan

The DESU plan comprises of two types of awards being performance and non-performance related share units. The performance related share units issued to each participant at the end of the three year vesting period will be subject to a performance test which compares Pengrowth’s three year average total return to the three year average total return of a peer group of other energy corporations such that upon vesting, the number of shares issued from treasury may range from 0.5 to 2.0 times the total of the number of shares granted plus accrued shares through the deemed reinvestment of notional dividends. The non-performance related share units generally vest equally over three years and entitle the holder in each vesting year to one third of the number of common shares initially granted plus the amount of any reinvested notional dividends.

The following provides a continuity of the DESUs:


	2012					2011
DESUs ⁽¹⁾	Number of DESUs			Weighted average price		Number of DESUs			Weighted average price
Outstanding, beginning of year		2,024,142		$	9.78		2,948,588		$	10.95
Forfeited		(102,313	)		10.54		(363,889	)		9.34
Exercised		(602,367	)		8.22		(249,504	)		11.14
Vested, no shares issued ⁽²⁾		(392,448	)		6.63		(472,308	)		16.81
Deemed DRIP ⁽³⁾		106,277			11.38		161,255			9.99
Outstanding, end of year		1,033,291		$	11.97		2,024,142		$	9.78

Composed of:
Performance related DESUs		501,711		$	11.22		1,307,474		$	8.44
Non-Performance related DESUs		531,580			12.67		716,668			12.21
Outstanding, end of year		1,033,291		$	11.97		2,024,142		$	9.78

⁽¹⁾	These compensation plans were used while Pengrowth was a trust. Effective January 1, 2011, no further grants were made under these plans.

⁽²⁾	2009 DEU grant vested in March 2012 with a performance multiplier of fifty percent.

⁽³⁾	Weighted average deemed DRIP price for accounting purposes is based on the average of the original grant prices.

Pengrowth recorded a recovery of compensation expense of ($0.3) million for the year ended December 31, 2012 related to the DESUs (December 31, 2011 – $3.7 million expense). The recovery in 2012 related to a change in the performance multiplier for DESUs. As at December 31, 2012, the amount of compensation expense to be recognized over the remaining vesting period was approximately $0.3 million (December 31, 2011 – $3.7 million) or $0.37 per DESU (December 31, 2011 – $2.21 per DESU), subject to the determination of the performance multiplier. The unrecognized compensation cost will be expensed to net income over the remaining weighted average vesting period of 0.2 of a year (December 31, 2011 – 1.0 year).

(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 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. The common share rights incentive plan provides the holder the right to purchase common shares over a five year period. During the years ended December 31, 2012 and 2011 there were no exercise price reductions under this plan.


66			PENGROWTH 2012 Financial Results

The following provides a continuity of the common share rights:


	2012					2011
Share unit options and rights ⁽¹⁾	Number outstanding			Weighted average price		Number outstanding			Weighted average price
Outstanding, beginning of year		2,217,274		$	12.96		3,583,766		$	12.70
Expired		(543,475	)		17.65		(319,174	)		19.40
Forfeited		(131,258	)		16.32		(505,235	)		14.27
Exercised		(71,890	)		6.26		(542,083	)		6.53
Outstanding, end of year		1,470,651		$	11.27		2,217,274		$	12.96

Composed of:
Share unit options		855,995		$	7.05		932,994		$	6.98
Share unit rights		614,656			17.13		1,284,280			17.30
Outstanding, end of year		1,470,651		$	11.27		2,217,274		$	12.96

⁽¹⁾	These compensation plans were used while Pengrowth was a trust. Effective January 1, 2011, no further grants were made under these plans. The final tranche of share unit options and rights will expire in 2015.

The following table summarizes information about share unit rights and options outstanding and exercisable at December 31, 2012:


Options Range of exercise prices	Number outstanding		Weighted average remaining contractual life (years)		Weighted average exercise price		Number exercisable		Weighted average exercise price
$6.00 to $8.99		621,793		1.2	$	6.80		621,793	$	6.80
$9.00 to $11.99		234,202		1.5		9.51		234,202		9.51
		855,995		1.3	$	7.05		855,995	$	7.05


Rights Range of exercise prices	Number outstanding		Weighted average remaining contractual life (years)		Weighted average exercise price		Number exercisable		Weighted average exercise price
$13.00 to $17.99		599,782		0.2	$	17.08		599,782	$	17.08
$18.00 to $25.99		14,874		0.3		19.37		14,874		19.37
		614,656		0.2	$	17.13		614,656	$	17.13

There was no compensation expense related to the common share rights incentive plan recognized during the year ended December 31, 2012, as the plan was fully expensed in 2011 (December 31, 2011 – $0.2 million). Common share options were exercised regularly over the year, the weighted average share price over the year ended December 31, 2012 was $7.58 (December 31, 2011 – $11.76).

15.

OTHER CASH FLOW DISCLOSURES

CHANGE IN NON-CASH OPERATING WORKING CAPITAL


	Year ended December 31
Cash provided by (used for):	2012			2011
Accounts receivable	$	27,516		$	8,431
Accounts payable		(71,016	)		10,704
	$	(43,500	)	$	19,135


PENGROWTH 2012 Financial Results			67

CHANGE IN NON-CASH INVESTING WORKING CAPITAL


	Year ended December 31
Cash provided by (used for):	2012		2011
Accounts receivable	$	3,183	$	(3,183	)
Accounts payable, including capital accruals		10,326		21,240
	$	13,509	$	18,057

DIVIDENDS PAID

Pengrowth paid $0.07 per share per month in dividends in each of January through July 2012, and $0.04 per share for the remaining months of the year for an aggregate annual cash dividend of $0.69 per share (December 31, 2011 – $0.07 per share per month, aggregate annual dividend of $0.84 per share).

16.

AMOUNTS PER SHARE

The following reconciles the weighted average number of shares used in the basic and diluted net income per share calculations:


	Year ended December 31
	2012		2011
Weighted average number of shares – basic		447,231,785		332,181,500
Dilutive effect of share based compensation plans		2,276,750		2,655,804
Weighted average number of shares – diluted		449,508,535		334,837,304

For the year ended December 31, 2012, 1.5 million shares (December 31, 2011 – 1.3 million) that are issuable on exercise of the share based compensation plans were excluded from the diluted net income per share calculation as their effect is anti-dilutive.

Further, for the year ended December 31, 2012, 16.2 million (December 31, 2011 – nil) that are issuable on potential conversion of the convertible debentures were excluded from the diluted net income per share calculation as their effect is anti-dilutive.

17.

CAPITAL DISCLOSURES

Pengrowth defines its capital as shareholders’ equity, long term debt, convertible debentures, bank indebtedness and working capital.

Pengrowth’s goal over longer periods is to modestly grow production and reserves on a debt adjusted per share basis. Pengrowth seeks to retain sufficient flexibility with its capital to take advantage of acquisition opportunities that may arise.

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 capital 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 (“Adjusted EBITDA”) 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, or adjust the level of dividends paid to shareholders to reduce debt levels.


68			PENGROWTH 2012 Financial Results

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 are within reasonable limits.

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


	As at
	December 31, 2012			December 31, 2011
Long term debt	$	1,480,898		$	1,007,686
Convertible debentures		237,050			–
Working capital (surplus) deficiency ⁽¹⁾		(128,752	)		137,287
	$	1,589,196		$	1,144,973

⁽¹⁾	Includes assets and liabilities held for sale.

18.

FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

Pengrowth’s financial instruments are composed of accounts receivable, accounts payable, fair value of 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 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 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 2012 Financial Results			69

Commodity Price Contracts

As at December 31, 2012, 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:

WTI

14,000

Jan 1, 2013 - Dec 31, 2013

94.41

Cdn

WTI

500

Jan 1, 2013 - Dec 31, 2013

100.95

WTI

3,500

Jan 1, 2014 - Dec 31, 2014

92.14

Cdn

Options

Reference Point

Volume (bbl/d)

Remaining Term

Price per bbl

Premium
(Payable) Received

Settlement
Currency

Financial:

WTI bought puts

4,000

Jan 1, 2013 - Dec 31, 2013

91.13

$ (9.34

)

Cdn

WTI sold calls

2,500

Jan 1, 2013 - Dec 31, 2013

110.00

$ 10.46

Natural Gas:

Swaps

Reference Point

Volume (MMBtu/d)

Remaining Term

Price per MMBtu

Settlement Currency

Financial:

AECO

118,003

Jan 1, 2013 - Dec 31, 2013

$ 3.26

Cdn

AECO

2,370

Apr 1, 2013 - Oct 31, 2013

$ 3.11

Cdn

NGI Chicago Index

12,500

Jan 1, 2013 - Dec 31, 2013

$ 3.83

Cdn

AECO

40,282

Jan 1, 2014 - Dec 31, 2014

$ 3.77

Cdn

NGI Chicago Index

5,000

Jan 1, 2014 - Dec 31, 2014

$ 4.27

Cdn

AECO

11,848

Jan 1, 2015 - Dec 31, 2015

$ 3.98

Cdn

NGI Chicago Index

2,500

Jan 1, 2015 - Dec 31, 2015

$ 4.45

Cdn

Collars

Price per MMBtu

Reference Point

Volume (MMBtu/d)

Remaining Term

Bought Puts

Sold Calls

Settlement
Currency

Financial:

AECO

1,896

Jan 1, 2013 - Dec 31, 2013

2.64

3.22

Cdn

Commodity Price Sensitivity

Each Cdn $1/barrel change in future oil prices would result in approximately Cdn $6.5 million pre-tax change in the unrealized gain (loss) on commodity risk management contracts as at December 31, 2012 (December 31, 2011 – Cdn $7.5 million). Similarly, each Cdn $0.25 /MMBtu change in future natural gas prices would result in approximately Cdn $17.3 million pre-tax change in the unrealized gain (loss) on commodity risk management contracts (December 31, 2011 – Cdn $1.3 million).

As at close December 31, 2012, the AECO gas spot price was $3.04/MMBtu (December 31, 2011 – $2.61/MMBtu), the WTI prompt monthly price was U.S. $91.82/barrel (December 31, 2011 – U.S. $98.83 /barrel).


70			PENGROWTH 2012 Financial Results

Power Price Contracts

As at December 31, 2012, 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

Jan 1, 2013 - Dec 31, 2013

74.50

Cdn

AESO

Jan 1, 2014 - Dec 31, 2014

46.85

Cdn

As at close December 31, 2012, the Alberta power pool spot price was $17.23/MWh (December 31, 2011 – $45.44/MWh). The average Alberta power pool price was $57.62/MWh for the month ended December 31, 2012 (December 31, 2011 – $51.26/MWh). The average Alberta power pool price was $64.32/MWh for the year ended December 31, 2012 (December 31, 2011 – $76.21/MWh).

Power Price Sensitivity

Each Cdn $1/MWh change in future power prices would result in approximately Cdn $0.1 million pre-tax change in the unrealized gain (loss) on power risk management contracts as at December 31, 2012 (December 31, 2011 – Cdn $0.2 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.

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. Pengrowth has two U.K. pound sterling note issuances outstanding. The 50 million U.K. pound sterling debt was issued in 2005 and is due December 2015. The 15 million U.K. pound sterling debt was issued in 2012 and is due October 2019. The exchange rate per Canadian dollar is fixed at 0.4976 on the 50 million U.K. pound sterling debt, and 0.63 on the 15 million U.K. pound sterling debt.

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.


Swaps-Buy U.S. dollars
Contract Type	Settlement Date		Amount (U.S. $ 000’s)		Fixed Rate ($1 Cdn = $ U.S.)
Swap		April 2013		50,000		1.01
Swap		May 2015		50,000		0.98
Swap		July 2017		240,000		0.97
Swap		August 2018		75,000		0.96
Swap		October 2019		15,000		0.94
Swap		May 2020		15,000		0.95
				445,000


PENGROWTH 2012 Financial Results			71

Other Foreign Exchange Contracts

The following foreign exchange risk management contracts were outstanding at December 31, 2012. Unless stated otherwise, all transactions reference the Cdn/U.S. foreign exchange rates and settle against the Bank of Canada monthly average noon rate. Each transaction requires Pengrowth to sell the notional U.S. dollars per the terms of each contract.

Options

Contract Type

Remaining Term

Notional Monthly
Amount (U.S. $ 000’s)

Option Payout Range
($1 Cdn = $ U.S.)

Daily Premium
(Cdn $ 000’s)

Option

Jan 1, 2013 - Sept 30, 2013

1,000

0.87 - 1.11

2.0

For each business day that the Bank of Canada noon rate settles outside of the option payout range, Pengrowth foregoes the premium for that day. When the Bank of Canada monthly average noon rate falls below the lower payout range, Pengrowth is obligated to sell the notional monthly amount at the lower rate.

Contract Type

Remaining Term

Notional Monthly
Amount (U.S. $ 000’s)

Fade In Price
($1 Cdn = $ U.S.)

Average Strike Price
($1 Cdn = $ U.S.)

Participation Price
($1 Cdn = $ U.S.)

Option

Jan 1, 2013 - Sept 30, 2013

1,000

1.11

0.93

0.87

If the Bank of Canada monthly average noon rate is below the participation price, or between the strike and fade in price, Pengrowth sells the notional amount at the strike price for that month. Alternatively, if the Bank of Canada monthly average noon rate rises above the fade in price, or between the strike and participating price, no transaction exists for that month.

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, 2012	Cdn - U.S.		Cdn - U.K.
Unrealized foreign exchange gain or loss on foreign denominated debt	$	12,370	$	650
Unrealized foreign exchange risk management gain or loss	$	4,570	$	747

	Cdn $0.01 Exchange Rate Change
Foreign Exchange Sensitivity as at December 31, 2011	Cdn - U.S.		Cdn - U.K.
Unrealized foreign exchange gain or loss on foreign denominated debt	$	9,020	$	500
Unrealized foreign exchange risk management gain or loss	$	—	$	593

Interest Rate Risk

Pengrowth is exposed to interest rate risk on the Canadian dollar revolving credit facility, as well as the interest rate derivative contracts, as the interest is based on floating interest rates.


72			PENGROWTH 2012 Financial Results

Interest Rate Contracts

The following interest rate swap contracts were outstanding at December 31, 2012. These contracts reduce exposure to rising interest rates by fixing the interest rate on floating rate debt. Under the contracts, Pengrowth pays the fixed interest rate, and receives the floating interest rate on the notional amounts. The floating interest rate received is the three-month Bankers Acceptance CDOR (“Canadian Depository Offered Rate”).


Remaining Term	Notional Monthly Amount (Cdn $ millions)		Fixed Interest Rate (%)
Jan 2013 - Jan 2013		22		1.4%
Jan 2013 - Mar 2013		28		1.9%
Jan 2013 - Jan 2014		22		1.5%
Jan 2013 - Mar 2014		28		2.0%

Interest Rate Sensitivity

Interest Rate Contracts

As at December 31, 2012, if interest rates had been 1 percent lower, with all other variables held constant, net income for the year would have been $0.3 million lower pre-tax (2011 – nil), due to the change in fair value of the derivatives contracts. An equal and opposite effect would have occurred to net income had interest rates been 1 percent higher.

Bank Interest Cost

As at December 31, 2012, Pengrowth had approximately $1.5 billion of current and non-current long term debt outstanding (December 31, 2011 – $1.0 billion) of which $160 million was based on floating interest rates (December 31, 2011 – nil). A 1 percent increase in interest rates would increase pre-tax interest expense by approximately $1.6 million for the year ended December 31, 2012 (2011 – nil).

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 bases. Realized and unrealized gains and losses are included in the Consolidated Statements of Income.

The following tables provide details of the fair value of risk management contracts and the unrealized and realized gains and losses on risk management recorded in the Consolidated Statements of Income:


As at and for the year ended December 31, 2012	Commodity contracts ⁽¹⁾			Power and Interest contracts ⁽²⁾			Foreign exchange contracts ⁽³⁾			Total
Current portion of risk management assets	$	11,674		$	–		$	1,244		$	12,918
Non-current portion of risk management assets		1,432			210			919			2,561
Current portion of risk management liabilities		(5,785	)		(710	)		(1,319	)		(7,814	)
Non-current portion of risk management liabilities		(349	)		(259	)		(18,625	)		(19,233	)
Risk management assets (liabilities), end of year		6,972			(759	)		(17,781	)		(11,568	)
Less: Risk management assets (liabilities) at beginning of year		(42,036	)		536			(24,097	)		(65,597	)
		49,008			(1,295)			6,316			54,029
Less: Risk management assets (liabilities) acquired from NAL		18,432			(652	)		(1,571	)		16,209
Unrealized gain (loss) on risk management contracts for the year		30,576			(643	)		7,887			37,820
Realized gain (loss) on risk management contracts for the year		22,149			(1,413	)		(1,045	)		19,691
Total unrealized and realized gain (loss) on risk management contracts for the year	$	52,725		$	(2,056	)	$	6,842		$	57,511


PENGROWTH 2012 Financial Results			73


As at and for the year ended December 31, 2011	Commodity contracts ⁽¹⁾			Power and Interest contracts ⁽²⁾			Foreign exchange contracts ⁽³⁾			Total
Current portion of risk management assets	$	–			$ 643			$ –		$	643
Current portion of risk management liabilities		(38,574	)		–			(1,179	)		(39,753	)
Non-current portion of risk management liabilities		(3,462	)		(107	)		(22,918	)		(26,487	)
Risk management assets (liabilities), end of year		(42,036	)		536			(24,097	)		(65,597	)
Less: Risk management assets (liabilities) at beginning of year		(2,085	)		870			(25,929	)		(27,144	)
Unrealized gain (loss) on risk management contracts for the year		(39,951	)		(334	)		1,832			(38,453	)
Realized gain (loss) on risk management contracts for the year		16,843			6,543			(593	)		22,793
Total unrealized and realized gain (loss) on risk management contracts for the year	$	(23,108	)		$ 6,209			$ 1,239		$	(15,660	)

⁽¹⁾	Unrealized gains and losses are presented as a separate caption in revenue. Realized gains and losses are included in oil and gas sales.

⁽²⁾	Unrealized gains and losses are included in other (income) expenses and interest expense. Realized gains and losses are included in operating expenses and interest expense.

⁽³⁾	Unrealized and realized gains and losses are included as part of separate captions in expenses.

FAIR VALUE

The fair value of 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 as of December 31, 2012 and 2011.


					Fair value measurements using:
As at December 31, 2012	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	$	53,806	$	53,806	$	53,806	$	–	$	–
Fair value of risk management contracts		15,479		15,479		–		15,479		–
Investment in private corporation		20,000		20,000		–		–		20,000
Financial Liabilities
Convertible debentures		237,050		237,361		237,361		–		–
U.S. dollar denominated senior unsecured notes		1,225,974		1,424,756		–		1,424,756		–
Cdn dollar senior unsecured notes		39,851		45,221		–		45,221		–
U.K. pound sterling denominated unsecured notes		104,808		116,458		–		116,458		–
Fair value of risk management contracts		27,047		27,047		–		27,047		–


74			PENGROWTH 2012 Financial Results


					Fair value measurements using:
As at December 31, 2011	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	$	49,712	$	49,712	$	49,712	$	–	$	–
Fair value of risk management contracts		643		643		–		643		–
Investment in private corporation		35,000		35,000		–		–		35,000
Financial Liabilities
U.S. dollar denominated senior unsecured notes		913,968		1,075,196		–		1,075,196		–
Cdn dollar senior unsecured notes		15,000		16,836		–		16,836		–
U.K. pound sterling denominated unsecured notes		78,718		89,786		–		89,786		–
Fair value of risk management contracts		66,240		66,240		–		66,240		–

Level 1 Fair Value Measurements

Financial assets and liabilities are recorded at fair value based on quoted prices in active markets.

Level 2 Fair Value Measurements

Risk management contracts – the fair value of the risk management contracts is based on commodity and foreign exchange curves that are readily available or, in their absence, third-party market indications and forecasts priced on the last trading day of the applicable period.

Derivative contracts are recorded at fair value on the Consolidated Balance Sheets as current or long-term assets or liabilities, based on their values on a contract-by-contract basis. 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 recent trading activity in the Private Corporation. The fair value of the investment has decreased to $20 million as at December 31, 2012 (December 31, 2011 – $35 million), resulting in an unrealized loss of $15 million in 2012 (December 31, 2011 – gain of $23 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. Pengrowth has three counterparties that individually account for more than ten percent of annual revenue. All of these counterparties are large, well-established companies supported by investment grade credit ratings.


PENGROWTH 2012 Financial Results			75

Pengrowth considers amounts over 90 days as past due. As at December 31, 2012, the amount of accounts receivable that were past due was not significant. Pengrowth has not recorded a significant allowance for doubtful accounts during 2012 and 2011 and has no significant bad debt provision at December 31, 2012. 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, 2012		December 31, 2011
Trade	$	178,895	$	163,977
Prepaid and other		18,612		19,837
	$	197,507	$	183,814

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 committed $1 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. Pengrowth’s long term notes and bank credit facilities are unsecured and equally ranked.

All of Pengrowth’s financial liabilities are current and due within one year, except as follows:


As at December 31, 2012	Carrying amount		Contractual cash flows		Year 1		Year 2		Years 3-5		More than 5 years
Convertible debentures	$	237,050	$	283,258	$	14,669	$	112,532	$	156,057	$	–
Cdn dollar revolving credit facility ⁽¹⁾		160,000		175,316		5,264		5,264		164,788		–
Cdn dollar senior unsecured notes ⁽¹⁾		39,851		57,210		2,177		2,177		6,535		46,321
U.S. dollar denominated senior unsecured notes⁽¹⁾		1,176,239		1,604,131		67,426		67,426		651,831		817,448
U.K. pound sterling denominated unsecured notes⁽¹⁾		104,808		123,740		5,255		5,255		87,458		25,772
Remediation trust fund payments		–		12,500		250		250		750		11,250
Commodity risk management contracts		349		354		–		354		–		–
Power and interest risk management contracts		259		222		210		12		–		–
Foreign exchange risk management contracts		18,625		1,987		301		301		843		542

⁽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, 2011	Carrying amount		Contractual cash flows		Year 1		Year 2		Years 3-5		More than 5 years
Cdn dollar senior unsecured notes ⁽¹⁾	$	15,000	$	21,585	$	992	$	992	$	2,977	$	16,624
U.S. dollar denominated senior unsecured notes⁽¹⁾		913,968		1,259,950		57,844		106,774		232,500		862,832
U.K. pound sterling denominated unsecured notes⁽¹⁾		78,718		95,893		4,313		4,313		87,267		–
Remediation trust fund payments		–		12,500		250		250		750		11,250
Commodity risk management contracts		3,462		3,511		–		3,511		–		–
Power risk management contracts		107		110		–		110		–		–
Foreign exchange risk management contracts		22,918		135		30		30		75		–

⁽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.


76			PENGROWTH 2012 Financial Results

19.

FOREIGN EXCHANGE (GAIN) LOSS


	Year ended December 31
	2012			2011
Currency exchange rate ($1 Cdn = $ U.S.) at period end	$	1.01		$	0.98
Unrealized foreign exchange (gain) loss on U.S. dollar denominated debt		(16,470	)		19,553
Unrealized foreign exchange loss on U.K. pound sterling denominated debt		2,424			1,377
	$	(14,046	)	$	20,930
Unrealized gain on foreign exchange risk management contracts		(7,887	)		(1,832	)
Unrealized foreign exchange (gain) loss	$	(21,933	)	$	19,098
Realized foreign exchange loss	$	968		$	1,583

20.

COMMITMENTS


($ thousands)	2013		2014		2015		2016		2017		Thereafter		Total
Convertible debentures ⁽¹⁾	$	–	$	97,863	$	–	$	–	$	136,843	$	–	$	234,706
Interest payments on convertible debentures		14,669		14,669		8,553		8,553		2,108		–		48,552
Long term debt ⁽²⁾		49,745		–		312,025		–		397,960		776,118		1,535,848
Interest payments on long term debt⁽³⁾		80,965		80,122		77,152		67,118		56,356		113,424		475,137
Operating leases ⁽⁴⁾		15,330		15,082		14,818		14,482		12,004		1,896		73,612
Pipeline transportation		28,182		25,629		22,811		6,450		3,379		6,813		93,264
Lindbergh		3,441		3,931		–		–		–		–		7,372
Remediation trust fund payments		250		250		250		250		250		11,250		12,500
	$	192,582	$	237,546	$	435,609	$	96,853	$	608,900	$	909,501	$	2,480,991

⁽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.

⁽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 and vehicle leases.

Weyburn CO₂ purchase commitments have been excluded from the table above, as the Weyburn assets are committed to be sold. Refer to Note 6 for more information.

21.

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.

22.

SUPPLEMENTARY DISCLOSURES

INCOME STATEMENT PRESENTATION

Pengrowth’s Consolidated Statements of Income 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.


	Year ended December 31
	2012		2011
Operating	$	68,621	$	54,382
General and administrative		42,293		38,908
Total employee compensation costs	$	110,914	$	93,290


PENGROWTH 2012 Financial Results			77

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. Fourteen officers and nine non-executive directors comprised the key management personnel at Pengrowth during the course of the year ended December 31, 2012 (2011 – Thirteen officers and seven non-executive directors).


Year ended December 31, 2012	Wages & benefits		Bonus and other compensation		Share based compensation expense		Severance		Total
Directors	$	730	$	–	$	720	$	–	$	1,450
Officers		4,675		1,507		4,062		532		10,776
	$	5,405	$	1,507	$	4,782	$	532	$	12,226


Year ended December 31, 2011	Wages & benefits		Bonus and other compensation		Share based compensation expense		Severance		Total
Directors	$	615	$	–	$	600	$	–	$	1,215
Officers		4,170		1,378		2,615		1,102		9,265
	$	4,785	$	1,378	$	3,215	$	1,102	$	10,480

23.

SUBSEQUENT EVENTS

Assets Held for Sale

Commodity Price Contracts

Pengrowth entered into additional commodity and power risk management contracts subsequent to December 31, 2012 as outlined in the tables below.

Crude Oil:

Swaps

Reference Point

Volume (bbl/d)

Remaining Term

Price per bbl

Settlement
Currency

Financial:

WTI

5,000

Feb 1, 2013 - Dec 31, 2013

93.53

Cdn

WTI

19,500

Jan 1, 2014 - Dec 31, 2014

94.94

Cdn

WTI

5,000

Jan 1, 2015 - Dec 31, 2015

92.33

Cdn

Natural Gas:

Swaps

Reference Point

Volume (MMBtu/d)

Remaining Term

Price per MMBtu

Settlement
Currency

Financial:

AECO

9,478

Jan 1, 2014 - Dec 31, 2014

$ 3.74

Cdn


78			PENGROWTH 2012 Financial Results

Power:

Reference Point

Volume (MW)

Remaining Term

Price per MWh

Settlement
Currency

Financial:

AESO

Feb 1, 2013 - Dec 31, 2013

57.08

Cdn


PENGROWTH 2012 Financial Results			79

APPENDIX D

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 being a SEC registrant. All amounts pertain to Pengrowth’s audited annual financial statements prepared in accordance with International Financial Reporting Standards (“IFRS”). All amounts are in thousands 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 2012 and 2011 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 the Corporation’s share of future production from Canadian reserves to be materially different from that presented.

Subsequent to December 31, 2012, 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.

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:


(thousands of dollars)
	2012		2011
Property acquisition costs
Proved	$	1,156,200	$	3,139
Unproved		705,051		5,489
Exploration costs		72,102		88,183
Development costs		556,421		735,335
Injectants costs		4,433		4,126

	$	2,494,207	$	836,272

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. Development costs also include capitalized costs associated with additions to asset retirement obligations.

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 $564 million (2011 – $564 million) of capitalized costs to acquire and evaluate unproven and development properties has been excluded from depletion.

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:


	2012		2011
Oil and natural gas assets		5,898,378		4,053,977
Add: Exploration and evaluation assets		563,663		563,751

		6,462,041		4,617,728

Unproved oil and gas properties
Unproven properties included in oil and natural gas assets		1,642,835		807,651
Exploration and evaluation assets		563,663		563,751

		2,206,498		1,371,402


Proven oil & gas properties		4,255,543		3,246,326

Total capitalized costs		6,462,041		4,617,728

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, Nova Scotia and Ontario. Pengrowth’s proved developed and undeveloped reserves after deductions of royalties are summarized below:

Net Proved Developed and Undeveloped Reserves After Royalties


	Crude Oil			Natural
	and NGLs			Gas
	MMbbls			Bcf
End of year 2010		95.8			504.6
Revisions of previous estimates (including infill drilling & improved recovery)		10.6			26.3
Purchase of reserves in place		—			0.1
Sale of reserves in place		(0.2	)		(0.4	)
Discoveries and extensions		10.1			41.0
Production		(10.7	)		(70.2	)

End of Year 2011		105.6			501.4
Revisions of previous estimates (including infill drilling & improved recovery)		2.6			(69.8	)
Purchase of reserves in place		30.7			156.7
Sale of reserves in place		(0.3	)		(2.4	)
Discoveries and extensions		13.0			3.1
Production		(13.1	)		(78.8	)

End of Year 2012		138.5			510.2

Net Proved Developed Reserves After Royalty


	Crude Oil		Natural
	and NGLs		Gas
	MMbbls		Bcf
End of year 2009		81.7		394.0
End of year 2010		81.3		439.4
End of year 2011		85.9		436.1
End of year 2012		105.3		463.1

Notes:

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.

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, 2012 and 2011.

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.

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.

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, 2012 and December 31, 2011. 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, 2012 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 $87.85/bbl (2011 - $97.03/bbl) and AECO natural gas price of $2.33/MMBtu (2011 - $3.78/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 from projected production of Pengrowth’s crude oil and natural gas reserves at December 31, for the years presented.


($ millions)	2012			2011
Future cash inflows	$	14,528		$	13,677
Future costs
Future production and development costs		(8,744	)		(7,826	)
Future income taxes		(191	)		(655	)

Future net cash flows		5,593			5,196
Deduct: 10% annual discount factor		(2,312	)		(2,152	)

Standardized measure of discounted future net cash flows	$	3,281		$	3,044

CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE CASH FLOW RELATING TO PROVED OIL AND GAS RESERVES

The following table sets forth the changes in the standardized measure of discounted future net cash flows at December 31, for the years presented.


	2012			2011
	$MM			$MM
Future discounted net cash flow at beginning of year		3,044			2,549

Sales & transfer, net of production costs		(738	)		(759	)
Net change in sales & transfer prices		(747	)		599
Development costs incurred during the period		452			581
Change in future development costs		(527	)		(752	)
Change due to extensions and discoveries		201			297
Change due to revisions (including infill drilling & improved recovery)		113			363
Accretion of discount		332			262
Sales of reserves in place		(12	)		(4	)
Purchase of reserves in place		845			1
Net change in Income Taxes		239			(212	)
Changes in timing of future net cash flow and other		79			119

Future discounted net cash flow at end of year		3,281			3,044

Note:

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, 2012 and 2011. 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.

APPENDIX E

PENGROWTH ENERGY CORPORATION CODE OF BUSINESS CONDUCT AND ETHICS DATED NOVEMBER 1, 2012

Pengrowth Energy Corporation

CODE OF BUSINESS CONDUCT AND ETHICS

Last Reviewed and Approved by the Board of Directors on November 1, 2012

TABLE OF CONTENTS



Application			1

Purpose			1

Policy			1

Compliance with Code			1

Compliance with the Law			1

Health, Safety and the Environment			1

Maintaining Records			1

Accounting and Financial Reporting			2

Assistance to Auditors			2

Public Reporting			2

Conflict of Interest			2

Private Business Interest			2

Involvement with Not-for-Profit Organizations			3

Outside Employment			3

Directorships			3

Related Party Transaction			3

Corporate Property and Opportunities			3

Disclosure of Conflict of Interest			3

Gifts and Entertainment			4

Fair Dealings			4

Political Activities and Contributions			4

Confidential Information			4

Use of Confidential Information			4

Disclosure of Confidential Information			5

Inside Information			5

Protection and Use of Assets			5

Intellectual Property - Patents, Inventions, Discoveries and Copyrights			5

Employee Relations and Reporting			5

Compliance with Policies, Procedures and Internal Controls and Exception Reporting			6

Reporting Violation or Suspected Violation of this Code or Law			6

No Retaliation for Raising Concern			6

Consequence of Non-Compliance with Code or Law			6

Questions Regarding this Code or Law			6

Acknowledgement			6

Exceptions			7

Appendix “A” Complaint Procedures for Accounting, Financial Reporting and Auditing Matters and Violations of the Code of Business Conduct and Ethics			8

Appendix “B” Awareness Statement on Code of Business Conduct and Ethics			11


	PENGROWTH ENERGY CORPORATION Policies and Practices	Page 1 of 11

CODE OF BUSINESS CONDUCT AND ETHICS

APPLICATION

Unless expressly provided herein to the contrary, this Code of Business Conduct and Ethics (the “Code”) applies to all directors, officers, employees, consultants and contractors (each a “Member”) of Pengrowth Energy Corporation and its respective subsidiaries and affiliates (collectively, referred to herein as “Pengrowth”).

PURPOSE

This Code summarizes appropriate behaviour for maintaining Pengrowth’s reputation for honesty and integrity earned by maintaining the highest standards of business ethics and compliance with applicable laws, rules and regulations in all our interactions with our fellow Members, governments, local communities, securityholders, customers, suppliers, competitors and the public.

POLICY

Pengrowth and all of its Members will adhere to the highest ethical standards and compliance with laws, rules and regulations in all our business activities. Any situation, decision or response should first consider what is right and how it reflects on Pengrowth. Although the various matters described in this Code do not cover the full spectrum of employee and contractor activities, they are indicative of the type of behaviour expected from employees and contractors in all circumstances.

COMPLIANCE WITH CODE

Members are expected to comply with all aspects of this Code. This Code does not specifically address every potential form of unacceptable conduct, and it is expected that Members will exercise good judgment in compliance with the principles set out in this Code. Each Member has a duty to avoid any circumstance that would violate the letter or spirit of this Code.

COMPLIANCE WITH THE LAW

Each Member must ensure that his or her dealings and actions on behalf of Pengrowth comply with the spirit and intent of all relevant legislation, rules and regulations including those set by a self regulatory body or professional organization of all the countries in which Pengrowth operates or where Pengrowth’s securities are listed on the exchanges.

HEALTH, SAFETY AND THE ENVIRONMENT

Pengrowth is committed to safe and healthful working conditions for all Members and third parties, and to conducting its activities in an environmentally responsible manner consistent with the principles of sustainable development.

Members are expected to read, understand and adhere to Pengrowth’s Environmental, Health and Safety Policies and Procedures and participate fully in this effort by improving operations to avoid injury or sickness to persons, and damage to property and the environment and by giving due regard to all applicable safety standards, regulatory requirements, technical and conventional standards and restraints.

MAINTAINING RECORDS

Accurate, timely and reliable books of account and records are essential for effective management to ensure

CODE OF BUSINESS CONDUCT AND ETHICS | 1

Pengrowth meets its business, legal and financial obligations. Members are to safeguard Pengrowth’s records and adhere to retention guidelines.

ACCOUNTING AND FINANCIAL REPORTING

Pengrowth is committed to achieving compliance with all applicable securities laws and regulations, accounting standards, accounting controls and audit practices. Every Member is required to follow prescribed accounting and financial reporting procedures. All accounting records should accurately reflect and describe corporate transactions and that all transactions are fairly, completely, accurately, timely and understandably accounted for and recorded in accordance with Pengrowth’s policies and procedures. The recording of such data must not be falsified or altered in any way to conceal or distort assets, liabilities, revenues, expenses or the nature of the activity.

Any suspected violation relating to accounting or financial reporting matters should be reported pursuant to procedures described in Appendix A – “Complaint Procedures for Accounting, Financial Reporting and Auditing Matters and Violations of the Code of Business Conduct and Ethics” to this document.

It is essential that all Members follow established policies, procedures and internal controls. Any exception to established policies, procedures and internal controls (excluding to this Code) is prohibited, unless appropriately authorized in advance by any officer of Pengrowth who shall report all such approved exceptions to the Audit and Risk Committee. Exceptions to this Code are dealt with below under “Exceptions”.

ASSISTANCE TO AUDITORS

No information should be concealed from the internal or external, independent auditors.

PUBLIC REPORTING

Persons responsible for the preparation of documents and reports and other public communications that Pengrowth files with, or submits to, the securities commissions and in its other public communications to comply with its obligations under the securities laws and to meet the expectations of its securityholders and other members of the investment community, are to exercise the highest standard of care in their preparation in accordance with the applicable laws and must include full fair, accurate, timely and understandable disclosure.

Enquiries from members of the community related to matters of a sensitive nature should be directed to a member of senior management. Any member of senior management receiving such an enquiry is then required to refer the matter to either the President and Chief Executive Officer (the “CEO”), Chief Financial Officer or General Counsel whereby such senior officers will respond on behalf of Pengrowth.

All Members responsible for disclosure are expected to read, understand, adhere to and must act according to Pengrowth’s Corporate Disclosure Policy.

CONFLICT OF INTEREST

Members must avoid interests or relationships where their personal interests may affect, or appear to affect, their judgment in acting in the best interests of Pengrowth. This requires that each Member act in such a manner that his or her conduct will bear the closest scrutiny should circumstances demand that it be examined. Where a conflict of interest situation may exist, or be perceived to exist, the Member may be put in a compromising position or his or her judgement may be questioned. Pengrowth wants to ensure that all Members are, and are perceived to be, free to act in the best interests of Pengrowth.

There are many situations which can be classified as conflicts of interest, but the following examples illustrate those that are most common.

Private Business Interest

Unless otherwise consented to by the General Counsel, a Member, either directly or indirectly through his or her immediate family or by any other means, must not have a personal financial interest in, or place himself or

CODE OF BUSINESS CONDUCT AND ETHICS | 2

herself in a position where he or she could derive a benefit or interest from, a business transaction with Pengrowth, which financial interest or benefit is of such a nature that it would reasonably be expected to create a conflict of interest for the Member.

This, however, does not prevent a Member and his or her family from having ownership in publicly traded shares or equity in companies which may do business with Pengrowth. Nor does it prevent a consultant or contractor from providing his or her services to Pengrowth through a third party corporation.

Involvement with Not-for-Profit Organizations

As a responsible community citizen, Pengrowth encourages and supports Member participation in charitable, educational, cultural, political and not-for-profit organizations. Members are reminded that such participation should not be of a nature or extent that it adversely affects a Member’s job performance or puts the Member in a conflict of interest position.

Outside Employment

Pengrowth recognizes that some employees may, from time to time, hold additional part-time employment outside their employment relationship with Pengrowth. Employees are reminded that any such outside employment should not be of a nature or extent that it adversely affects the employee’s job performance at Pengrowth or put the employee in a conflict of interest position. All employees who hold management positions with Pengrowth shall obtain the approval of the General Counsel before accepting any such outside employment.

Directorships

Any officer or employee shall obtain the approval of the CEO prior to accepting a position as a director of a for-profit company or any business organization. The CEO shall obtain the approval of the Board of Directors prior to accepting a position as a director of a for-profit company or any business organization. A director shall advise the Chairman of the Board prior to accepting a position as a director of a for-profit company or any business organization.

Related Party Transaction

In addition to the consent requirement set out under “Private Business Interest” above, each director and officer who is a party to a material contract or proposed material contract with Pengrowth or is a director or an officer of or has a material interest in any entity which is a party to a material contract or proposed material contract with Pengrowth of which he has knowledge is required to disclose in writing to the Chairman of the Board the nature and extent of the director’s or officer’s interest. The Chairman of the Board shall make any such disclosure concerning himself to the Chair of the Corporate Governance and Nominating Committee.

Corporate Property and Opportunities

Members are prohibited from taking for themselves, opportunities that arise through the use of corporate property, information or position and from using corporate property, information or position for personal gain.

DISCLOSURE OF CONFLICT OF INTEREST

Disclosure of areas of potential conflict of interest will allow appropriate steps to be taken to protect the individual from these situations.

Officers, employees, consultants and contractors are required to disclose to the appropriate Vice President in writing all business, commercial or financial interests and activities which might reasonably be regarded as creating an actual or potential conflict with their duties of employment. Senior management will determine whether a conflict of interest does or could exist and, if necessary, advise the person as to what steps should be taken. Directors are required to

CODE OF BUSINESS CONDUCT AND ETHICS | 3

disclose to the Chair of the Corporate Governance and Nominating Committee (or, in the case of the Chair of the Corporate Governance and Nominating Committee, to the other members of the Committee) all business, commercial or financial interests and activities which might reasonably be regarded as creating an actual or potential conflict with their duties as directors.

GIFTS AND ENTERTAINMENT

The exchange of gifts and entertainment is a common practice in most business communities and is designed to develop and foster goodwill among business partners. Accepting gifts and entertainment can cause problems when they compromise, or appear to compromise, our ability to make fair and objective business decisions. No gift or entertainment should be accepted, or offered, if it will unfairly influence a business relationship.

There are many factors that influence whether a gift or entertainment is normal and customary. Gifts or entertainment should be moderate, reasonable and in good taste, be of a style or value commonly accepted for business occasions and should not be unusual for the recipient’s job or community. The exchange must create no obligation or sense of obligation and should occur infrequently.

Business entertainment can present situations where discretion is required since some commonly accepted business invitations can include recreational opportunities or event tickets that are of significant value. In these cases, the recipient should ensure that there is a valid business development reason for attending. If the invitation is for an event where the value being received may be significant, prior approval by an officer of Pengrowth is required, or in the case of the CEO, approval by the Chair of the Corporate Governance and Nominating Committee. As transportation costs for events can also be significant, payment of these costs by another party is not acceptable and will be covered by Pengrowth if there is a valid business reason to accept the invitation.

FAIR DEALINGS

It is Pengrowth’s policy to deal fairly and lawfully with all securityholders, customers, suppliers, competitors and Members. All goods and services shall be obtained on a competitive basis at the best value considering price, quality, reliability, availability and delivery.

POLITICAL ACTIVITIES AND CONTRIBUTIONS

Pengrowth respects and supports the right of its employees to participate in political activities. However, these activities should not be conducted on Pengrowth time or involve the use of any Pengrowth resources. Employees will not be reimbursed for personal political contributions.

Pengrowth may occasionally express its views on local and national issues that affect its operations. In such cases, Pengrowth funds and resources may be used, but only when permitted by law and by Pengrowth’s strict guidelines. On very limited occasions, Pengrowth may also make limited contributions to political parties or candidates in jurisdictions where it is legal and customary to do so. Pengrowth may pay related administrative and solicitation costs for political action committees formed in accordance with the political laws and regulations. No employee may make or commit to political contributions on behalf of Pengrowth without the approval of the Chief Executive Officer.

CONFIDENTIAL INFORMATION

In the course of their work, Members may have access to information that is confidential, privileged, of value to competitors of Pengrowth or might be damaging to Pengrowth if improperly disclosed. Pengrowth respects privileged business and employee related information, and therefore all Members must protect the confidentiality of such information.

USE OF CONFIDENTIAL INFORMATION

The use or disclosure of confidential information must be for Pengrowth’s purposes only and not for personal benefit or the benefit of others. This applies to disclosure of confidential information concerning Pengrowth or its business activities as well as information with respect to companies having business dealings with Pengrowth. To preserve confidentiality, disclosure and discussion of confidential information should be limited to those individuals who need to

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know the information. Members are expected to read, understand and adhere to Pengrowth’s Corporate Disclosure Policy and Confidentiality Agreements.

DISCLOSURE OF CONFIDENTIAL INFORMATION

Members must guard against improper disclosure of information that may be of competitive value to Pengrowth. Pengrowth is in a competitive environment with other companies. Certain records, reports, papers, devices, processes, plans, methods and apparatus of Pengrowth, including methods of doing business, strategies and information on costs, prices, sales, profits, markets and opportunities are the property of Pengrowth and are considered to be confidential and proprietary. Members must not reveal such confidential information without consent of the General Counsel.

Confidential information does not include information which is already in the public domain. Certain information may be released by Pengrowth (to comply with securities regulations, for example) however, the release of such information is a decision of the Board of Directors and senior management. If there is any doubt as to what can or cannot be discussed outside of Pengrowth, Members should err on the side of discretion and not communicate any information. For more specific advice, your immediate manager, the CEO, the Chief Financial Officer or General Counsel should be consulted.

These obligations regarding confidential information continue to apply to all Members following cessation of their employment or contractual relations with Pengrowth. Members are expected to read, understand and adhere to Pengrowth’s Corporate Disclosure Policy and Confidentiality Agreements.

INSIDE INFORMATION

Certain information, which Pengrowth treats as confidential, may influence the price or trading of Pengrowth’s common shares or other securities if it is disclosed to members of the public. Inside information would include information concerning material exploration well results, major contracts, proposed acquisitions or mergers, and earnings figures. Members shall not use such inside information for their own financial gain or for that of their associates.

If in doubt as to the propriety of actions, the Member should seek the advice of the CEO, Chief Financial Officer or General Counsel. Members are expected to read, understand and adhere to Pengrowth’s Policy on Trading in Securities.

PROTECTION AND USE OF ASSETS

All Members are responsible for protecting Pengrowth’s assets and their efficient use for legitimate business purposes only. Pengrowth provides Members with computer and Internet access for work purposes. Members are expected to read, understand, acknowledge and adhere to Pengrowth’s Acceptable Use Policy for Information System Assets.

INTELLECTUAL PROPERTY - PATENTS, INVENTIONS, DISCOVERIES AND COPYRIGHTS

All intellectual property including inventions, discoveries and copyrights made by Members during or as a result of their employment or contractual relations with Pengrowth (where company time, equipment, resources or pertinent information has been used for personal gain) are the property of Pengrowth unless a written release is obtained from the CEO.

Pengrowth and its Members honour the proprietary rights of others as expressed in patents, copyrights, trademarks and industrial design.

EMPLOYEE RELATIONS AND REPORTING

Pengrowth values the diversity of its Members and is committed to providing equal opportunity in all aspect of employment. In working together, Members must ensure they treat each other with respect, dignity, honesty, fairness and provide a healthy environment that is free of harassment, offensive behaviour and discrimination.

All Members are encouraged to report any behaviour of other Members which they reasonably believe is illegal or

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unethical and any suspected violation relating conduct matters should be reported pursuant to procedures described in Appendix A – “Complaint Procedures for Accounting, Financial Reporting and Auditing Matters and Violations of the Code of Business Conduct and Ethics” to this document or to the Vice President, Human Resources or the General Counsel.

COMPLIANCE WITH POLICIES, PROCEDURES AND INTERNAL CONTROLS AND EXCEPTION REPORTING

Members should ensure all transactions with which they are involved are authorized and executed in accordance with Pengrowth’s policies and procedures and conform to all legal and accounting requirements Members are expected to read, understand and adhere to Pengrowth’s Delegation of Authorities guideline.

Whenever a Member is in doubt about the application or interpretation of any legal requirement or has questions about whether particular circumstances may involve illegal conduct, the individual should immediately seek the advice of his or her manager or consult Pengrowth’s General Counsel.

REPORTING VIOLATION OR SUSPECTED VIOLATION OF THIS CODE OR LAW

It is important that Pengrowth be made aware of circumstances that may indicate possible violations of law or this Code. Any violations of this Code must be promptly reported pursuant to procedures described in Appendix A – “Complaint Procedures for Accounting, Financial Reporting and Auditing Matters and Violations of the Code of Business Conduct and Ethics” to this document.

NO RETALIATION FOR RAISING CONCERN

Any Member may submit a complaint regarding a suspected violation of the Code without fear of dismissal or retaliation. Pengrowth and applicable law prohibit any form of retaliation for raising concerns or reporting possible misconduct in good faith or for assisting in the investigation of possible misconduct. No adverse action will be taken against any individual for making a complaint or disclosing information in good faith. Any Member who retaliates in any way against an individual who, in good faith, reports any violation, or suspected violation, of this Code, will be subject to disciplinary action.

CONSEQUENCE OF NON-COMPLIANCE WITH CODE OR LAW

Non-compliance with this Code or the law or other dishonest or unethical business practices are forbidden and may result in disciplinary action, including termination from employment or termination of contractual relations.

Pengrowth is required to cooperate with investigations by regulatory authoritative bodies and quasi-judicial tribunals to the extent that a policy violation breaks a law or regulation.

QUESTIONS REGARDING THIS CODE OR LAW

If a Member has any question of appropriateness in a particular situation, areas of conflict or disagreement with any aspect of this Code or any applicable laws, the matter should be discussed with the CEO, Chief Financial Officer, General Counsel or Chairman of the Board of Pengrowth.

This Code is not intended to address all of the situations you may encounter. There will be occasions where Members are confronted by circumstances not covered by this Code or procedure and where Members must make a judgment as to the appropriate course of action. In those circumstances, Members are encouraged to use common sense and to contact their respective supervisor, manager or other appropriate person for guidance.

ACKNOWLEDGEMENT

It is essential that all Members understand and adhere to this Code.

All Members will be asked to acknowledge, in writing, their review of and agreement to be bound by this Code as a condition of their new or continuing employment or contractual relations, as the case may be. This acknowledgment must be made: (i) in the case of directors, upon election to the Board of Directors of Pengrowth and annually thereafter; (ii) in the case of officers and employees, upon the commencement of employment and annually thereafter,

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(iii) in the case of consultants and contractors, upon commencement of this contractual relation and annually thereafter, and such acknowledgement may be provided in electronic format.

The form of certification attached as Appendix “B” is to be used by each Member to disclose any personal facts or dealings that are non-compliant with this Code.

EXCEPTIONS

No provision of this Code will be waived in respect of a director or executive officer unless expressly approved by the Board of Directors. Any waiver of this Code in respect of a director or officer shall be disclosed to Pengrowth’s shareholders by posting such waiver to Pengrowth’s website promptly after Board approval and as otherwise required by law, regulation or stock exchange requirement. For greater certainty, the exercise of discretion by an executive officer or the Board of Directors, in compliance with this Code, shall not be considered a “waiver” of this Code.

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

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APPENDIX “A”

COMPLAINT PROCEDURES FOR ACCOUNTING, FINANCIAL REPORTING

AND AUDITING MATTERS AND VIOLATIONS OF THE CODE OF BUSINESS CONDUCT AND ETHICS

In order to facilitate the reporting of complaints, the Board of Directors of Pengrowth has established the following procedures for (i) the receipt, retention and treatment of complaints regarding accounting, internal accounting controls, financial reporting or auditing matters (“Accounting Matters”); (ii) the receipt, retention and treatment of complaints regarding suspected violations of the Code of Business Conduct and Ethics and any other conduct concerns (“Conduct Matters”); and (iii) the confidential, anonymous submission by directors, officers and employees of Pengrowth (collectively, “Members”) of concerns regarding questionable Accounting Matters and Conduct Matters.

RECEIPT OF COMPLAINTS

1.	Through Management

Any Member may submit a complaint regarding Accounting Matters or Conduct Matters to the management of Pengrowth without fear of dismissal or retaliation of any kind.

2.	Through Appropriate Committee Chair

Any Member with concerns regarding an Accounting Matter may report their concerns to the Chair of the Audit and Risk Committee. Pengrowth is committed to achieving compliance with all applicable securities laws and regulations, accounting standards, accounting controls and audit practices. The Audit and Risk Committee of Pengrowth will oversee and be responsible for the investigation of the treatment of Member concerns relating to Accounting Matters.

Any Member with concerns regarding a Conduct Matter may report their concerns to the Chair of the Corporate Governance and Nominating Committee. The Corporate Governance and Nominating Committee of Pengrowth will oversee treatment of Member concerns in Conduct Matters.

All such concerns will be set forth in writing and forwarded in a sealed envelope to the General Counsel of Pengrowth or, if the submitter so desires, directly to the Chair of the Audit and Risk Committee or Corporate Governance and Nominating Committee, in care of the General Counsel in an envelope labelled with a legend such as: “To be opened by the Audit and Risk Committee only” or “To be opened by the Corporate Governance and Nominating Committee only.”

If a Member would like to discuss any matter with the Audit and Risk Committee, the Member should indicate this in the submission and include a telephone number at which he or she can be reached, should the Audit and Risk Committee deem such communication is appropriate. Any such envelopes received by the General Counsel that are directed to the Audit and Risk Committee will be forwarded promptly and unopened to the Chair of the Audit and Risk Committee.

3.	Through Anonymous Confidential Submission

Any Member may report concerns regarding an Accounting Matter or a Conduct Matter on a confidential or anonymous basis to Grant Thornton LLP, at 1-888-747-7171 or usecare@GrantThornton.ca.

Any Member who makes an anonymous submission must be sure to provide sufficient detail to identify the concern being raised. Given that the submission is made anonymously, the Audit and Risk Committee or the Corporate Governance and Nominating Committee, as the case may be, will be unable to follow up if there are additional questions. The submission should, at a minimum, contain dates, places, persons involved and witnesses or other information sufficient for recipient to investigate and determine whether the submission is valid or made in good faith such that a reasonable investigation or assessment can be conducted.

SCOPE OF ACCOUNTING MATTERS COVERED BY THESE PROCEDURES

These procedures relate to Members’ complaints relating to any questionable Accounting Matters, including, without limitation, the following:

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•

fraud or deliberate error in the preparation, evaluation, review or audit of any financial statement of Pengrowth;

•

fraud or deliberate error in the recording and maintaining of financial records of Pengrowth;

•

deficiencies in or non-compliance with Pengrowth’s internal accounting controls;

•

misrepresentation or false statement to or by a director, officer, employee or external accountant regarding a matter contained in the financial records, financial reports or audit reports of Pengrowth; or

•

deviation from full and fair reporting of Pengrowth’s financial condition.

TREATMENT OF COMPLAINTS

Grant Thornton LLP and Pengrowth shall inform (i) the Chair of the Audit and Risk Committee of all complaints and concerns provided to it in respect of Accounting Matters; and (ii) the Chair of the Corporate Governance and Nominating Committee of all complaints provided to it in respect of Conduct Matters.

Upon receipt of a complaint or concern, the Chair of the Audit and Risk Committee or Chair of the Corporate Governance and Nominating Committee, as the case may be, will (i) determine whether or not the complaint actually pertains to an Accounting Matter or a Conduct Matter and (ii) when possible, acknowledge receipt of the complaint to the sender.

Complaints relating to an Accounting Matter will be reviewed by the Audit and Risk Committee, outside legal counsel or such other person(s) as the Audit and Risk Committee determines to be appropriate. Complaints relating to a Conduct Matter will be reviewed by the Corporate Governance and Nominating Committee, outside legal counsel or such other person(s) as the Corporate Governance and Nominating Committee determines to be appropriate. In any case, confidentiality will be maintained to the fullest extent possible, consistent with the need to conduct an adequate review. If on preliminary examination the allegation is judged to be wholly without substance or merit, or not made in good faith, the allegation may be dismissed.

Prompt and appropriate investigation and corrective action will be taken when and as warranted in the judgment of the Audit and Risk Committee or the Corporate Governance and Nominating Committee, as the case may be.

If the identity of the Member making the complaint, or assisting in investigation of the complaint, is known by anyone within Pengrowth, the Audit and Risk Committee will monitor any disciplinary action against the Member to determine whether it could subject Pengrowth to anti-retaliation liability pursuant to Sections 806 or 1107 of the Sarbanes-Oxley Act. Pengrowth will not discharge, demote, suspend, threaten, harass or in any manner discriminate against any individual in the terms and conditions of employment based upon any lawful actions of such individual with respect to reporting of complaints in good faith regarding any Accounting Matter or any Conduct Matter or as otherwise specified in Section 806 of the Sarbanes-Oxley Act. In addition, Pengrowth will observe the anti-retaliation requirements of Section 1107 of the Sarbanes-Oxley Act, which establishes penalties for retaliation against any person who provides truthful information to a law enforcement officer regarding any offense.

Pengrowth will regard the making of any deliberately false or malicious allegations by an employee as a serious offence which may result in recommendations to the Board of Directors or to senior management of Pengrowth for disciplinary action including dismissal for cause and, if warranted, legal proceedings.

REPORTING AND RETENTION OF COMPLAINTS AND INVESTIGATIONS

The Chair of the Audit and Risk Committee and the Chair of the Corporate Governance and Nominating Committee will maintain a log of all complaints, tracking their receipt, investigation and resolution and shall prepare a periodic summary report thereof for the Audit and Risk Committee or the Corporate Governance and Nominating Committee, as the case may be.

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RECORD RETENTION

The chairs of the Audit and Risk Committee and the Corporate Governance and Nominating Committee, will work with the Corporate Secretary to ensure that, as part of each committee’s respective records, any such complaints or concerns are retained in a manner which preserves their confidentiality, for a period of at least seven years.

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APPENDIX “B”

AWARENESS STATEMENT ON CODE OF BUSINESS CONDUCT AND ETHICS

To be completed by all directors, officers, employees, consultants and contractors of Pengrowth Energy Corporation and its subsidiaries (“Pengrowth”)

I have recently read the Code of Business Conduct and Ethics of Pengrowth (the “Code”), and I can certify that, except as specifically noted below:

1.	I understand the content and consequences of contravening the Code and agree to abide by the Code.

2.	I am in compliance with the Code.

3.	All facts and dealings which I believe to be non-compliant with the Code have been communicated to the appropriate representative of Pengrowth and are detailed below.

4.	(If applicable) After due inquiry and to my best knowledge and belief, no employee, consultant or contractor under my direct supervision is in violation of the Code.

5.	I have and will continue to exercise my best efforts to assure full compliance with the Code by myself and (if applicable) all employees, consultants and contractors under my direct supervision.


Print or type name:

Signature:

Title and location:

Date:

Facts and dealings that I believe to be non-compliant with the Code

(Including potential conflict of interest situations)

(If required, provide additional details on separate sheet).

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EXHIBIT INDEX


Exhibit		Description

99.1		Consent of Independent Registered Public Accounting Firm.

99.2		Consent of GLJ Petroleum Consultants Ltd.

99.3		Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350

99.4		Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350

99.5		Certification of Chief Executive Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934

99.6		Certification of Chief Financial Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934