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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.
| | - | -------------------------------------------------------------------------------------



| | þ | ANNUAL REPORT PURSUANT TO SECTION 13(a) OF THE SECURITIES EXCHANGE ACT OF 1934
| | - | ------------------------------------------------------------------------------



|                                             |  |                                
|-------------------------------------------- |  | -------------------------------
|For the fiscal year ended: December 31, 2010 |  | Commission File Number: 1-31253

PENGROWTH ENERGY CORPORATION

(Exact name of Registrant as specified in
its charter)

Alberta, Canada

(Province or other jurisdiction of incorporation or organization)



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

Suite 2100, 222 Third Avenue
S.W.

Calgary, Alberta Canada T2P 0B4

(403) 233-0224

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

Puglisi & Associates

850 Library Avenue, Suite 204

Newark, Delaware 19711

(302) 738-6680

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

of agent for service in the United States)

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



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

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

None

(Title of Class)

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

None

(Title of Class)

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

þ Annual information
form            þ Audited annual financial statements

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

There were 326,024,040 Common Shares, of no par value, outstanding as of December 31, 2010.

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

Yes
 ̈            No  þ

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

Yes
þ            No   ̈

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 Statements on Form F-10 and F-3 (File Nos. 333-171682 and 333-171672, respectively) under the Securities Act of 1933, as amended.









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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, 2010.                                                                                                                                                                                                     
|B        |  | Managements Discussion and Analysis.                                                                                                                                                                                                                                                          
|C        |  | Consolidated Financial Statements of Pengrowth Energy Corporation, including Managements Report to Shareholders, the Auditors Reports and note 24 thereof which
includes a reconciliation of the Consolidated Financial Statements to United States generally accepted accounting principles.
|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 December 16, 2010                                                                                                                                                                                                       

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, 2010, 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, 2010, 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, 2010, 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, 2010, 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.



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ADDITIONAL DISCLOSURE

Certain disclosure regarding the corporate governance practices of the Registrant, including disclosure of the Registrants code of ethics, principal accountant fees and services, pre-approval
policies and procedures and off-balance sheet arrangements, is included on pages 59, 57, 58 and 60, respectively, of the Annual Information Form contained in Appendix A. Disclosure regarding the Registrants contractual obligations is included
on page 29 of Managements Discussion and Analysis contained 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

Form F-X signed by the Registrant and its agent for service of process has been filed with the Commission together with Form F-10 (333-171682) in connection with its securities registered on such form.

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.



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SIGNATURES

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



|                    |  |  |  |                              |  |     |  |                       |  |                                      
|------------------- |  |  |  | ---------------------------- |  | --- |  | --------------------- |  | -------------------------------------
|Date: March 8, 2011 |  |  |  | PENGROWTH ENERGY CORPORATION
|                    |  |  |  |                             
|                    |  |  |  |                              |  | By: |  | /s/    DEREK W.
EVANS
|                    |  |  |  |                              |  |     |  | Name:                 |  | Derek W. Evans                       
|                    |  |  |  |                              |  |     |  | Title:                |  | President and Chief Executive Officer



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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



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APPENDIX A

PENGROWTH ENERGY CORPORATION ANNUAL INFORMATION FORM FOR THE YEAR

ENDED
DECEMBER 31, 2010



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LOGO

PENGROWTH ENERGY CORPORATION

ANNUAL INFORMATION FORM

For the year ended December 31, 2010

March 8, 2011



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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  | 
|PENGROWTH  OPERATIONAL INFORMATION                                                       |  |  | 9  | 
|Principal Properties                                                                      |  |  | 9  | 
|Statement of Oil and Gas Reserves and Reserves Data                                       |  |  | 13 | 
|Additional Information Relating to Reserves Data                                          |  |  | 22 | 
|Future Development Costs                                                                  |  |  | 24 | 
|Finding, Development and Acquisition Costs                                                |  |  | 24 | 
|Future Development Capital                                                                |  |  | 25 | 
|Recycle Ratio                                                                             |  |  | 26 | 
|Reserve Life Index (RLI)                                                                  |  |  | 26 | 
|Reserve Replacement                                                                       |  |  | 27 | 
|Other Oil and Gas Information                                                             |  |  | 27 | 
|Forward Contracts                                                                         |  |  | 30 | 
|Additional Information Concerning Abandonment & Reclamation Costs                         |  |  | 30 | 
|Costs Incurred                                                                            |  |  | 31 | 
|Exploration and Development Activities                                                    |  |  | 31 | 
|Production Estimates                                                                      |  |  | 31 | 
|Production History (Netback)                                                              |  |  | 32 | 
|DESCRIPTION OF CAPITAL STRUCTURE                                                          |  |  | 33 | 
|General                                                                                   |  |  | 33 | 
|Stock Exchange Listings                                                                   |  |  | 34 | 
|DIVIDENDS                                                                                 |  |  | 34 | 
|General                                                                                   |  |  | 34 | 
|Historical Distributions/Dividends                                                        |  |  | 34 | 
|Restrictions on Dividends                                                                 |  |  | 34 | 
|ABCA Solvency Tests                                                                       |  |  | 35 | 
|Revolving Credit Facility                                                                 |  |  | 35 | 
|Senior Unsecured Notes                                                                    |  |  | 35 | 
|INDUSTRY CONDITIONS                                                                       |  |  | 36 | 
|Pricing and Marketing                                                                     |  |  | 36 | 
|Pipeline Capacity                                                                         |  |  | 37 | 
|The North American Free Trade Agreement                                                   |  |  | 37 | 
|Royalties and Incentives                                                                  |  |  | 37 | 
|Land Tenure                                                                               |  |  | 42 | 
|Environmental Regulation                                                                  |  |  | 43 | 
|Climate Change Regulation                                                                 |  |  | 43 | 
|General Discussion                                                                        |  |  | 46 | 
|RISK FACTORS                                                                              |  |  | 46 | 
|MARKET FOR SECURITIES                                                                     |  |  | 54 | 
|DIRECTORS AND OFFICERS                                                                    |  |  | 54 | 
|Corporate Cease Trade Orders, Bankruptcies, Personal Bankruptcies, Penalties or
Sanctions |  |  | 56 | 
|AUDIT AND RISK COMMITTEE                                                                  |  |  | 57 | 
|Principal Accountant Fees and Services                                                    |  |  | 57 | 



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|                                                                       |  |  |    | 
|---------------------------------------------------------------------- |  |  | -- | 
|Pre-approval Policies and Procedures                                   |  |  | 58 | 
|CONFLICTS OF INTEREST                                                  |  |  | 58 | 
|LEGAL PROCEEDINGS                                                      |  |  | 58 | 
|INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS             |  |  | 58 | 
|INTERESTS OF EXPERTS                                                   |  |  | 59 | 
|AUDITORS, TRANSFER AGENT AND REGISTRAR                                 |  |  | 59 | 
|MATERIAL CONTRACTS                                                     |  |  | 59 | 
|CODE OF ETHICS                                                         |  |  | 59 | 
|OFF-BALANCE SHEET ARRANGEMENTS                                         |  |  | 60 | 
|DISCLOSURE PURSUANT TO THE REQUIREMENTS OF THE NEW YORK STOCK EXCHANGE |  |  | 60 | 
|ADDITIONAL INFORMATION                                                 |  |  | 60 | 

APPENDIX A - Report on
Reserves Data by Independent Qualified Reserves Evaluator on Form 51-101F2

APPENDIX B - Report of Management and Directors on Oil and
Gas Disclosure on Form 51-101F3

APPENDIX C - Audit and Risk Committee Terms of Reference

Unless otherwise indicated, all of the information provided in this Annual Information Form is as at December 31, 2010.



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GLOSSARY OF TERMS AND ABBREVIATIONS

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

Corporate

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

2003 US Senior Notes means the senior unsecured notes issued from time to time 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 Pengrowth, the Trust 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, Pengrowth and the purchasers listed therein, as amended;

2007 US Senior Notes means the senior unsecured notes issued from time to time 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, Pengrowth and the purchasers listed therein, as
amended ;

2008 Senior Notes means the senior unsecured notes issued from time to time 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, Pengrowth and the purchasers listed therein, as amended;

2010 Senior Notes means the
senior unsecured notes issued from time to time under the 2010 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;

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

Shareholders means holders of Common Shares;

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 from time to time 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;



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Contingent Resources are those quantities of petroleum estimated, on 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
March 7, 2011 with an effective date of December 31, 2010;

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;

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 or PDP 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 to put the reserves on production; the developed category may be subdivided into Proved Developed Producing Reserves and Developed Non-Producing
Reserves;

Proved Reserves or TP 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 the Company Interest
Reserves of a property by the 2011 Company Interest estimated production for the corresponding reserve category from such property. The reserves and the 2011 estimated 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 recovered from known
accumulations, from a given date forward, 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 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;



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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 interest, held by
Pengrowth in an oil and gas property.

Abbreviations

Cdn$ refers to Canadian dollars;

US$ refers to United
States dollars;

API refers to the American Petroleum Institute;

°API 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;

bblpd 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;

boepd refers to
barrels of oil equivalent per day;

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

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;

GAAP or Canadian GAAP refers to generally accepted accounting principles in Canada;

F&D Costs refers to finding and development costs;

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

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

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;

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

Mcfpd and MMcfpd 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;

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

TSX refers to the Toronto Stock Exchange;

WCSB refers to the Western Canadian Sedimentary Basin; and



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WTI refers to West Texas Intermediate.

Disclosure provided herein in respect of a boe and a Mcfe may be misleading, particularly if used in isolation. A boe conversation ratio of six Mcf of
natural gas to one barrel of oil and a Mcfe conversion ratio of one barrel of oil to six 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.

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 Canadian GAAP. Canadian GAAP differs in some significant
respects from United States generally accepted accounting principles and thus our financial statements may not be comparable to the financial statements of US companies. The principal differences as they apply to us are summarized in note 24 to
our audited annual consolidated financial statements for the year ended December 31, 2010, which are available on the SEDAR website at www.sedar.com and in our current Form 40-F, which is available through EDGAR at the SECs
website at www.sec.gov.

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 reserves 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 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 2011 development program, remaining producing reserves lives, operating expenses, asset retirement obligations, royalty rates, net present values of future net revenue from reserves, commodity prices and
costs, dividend policy, exchange rates, the impact of contracts for commodities, development plans and programs, future development costs and the funding thereof, tax horizon, future income taxes, 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 2011 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.



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By their very nature, forward-looking statements involve inherent risks and uncertainties, both general and
specific, and risks that predictions, forecasts, projections and other forward-looking statements will not be achieved. We caution readers not to place undue reliance on these statements as a number of important factors could cause the actual
results to differ materially from the beliefs, plans, objectives, expectations and anticipations, estimates and intentions expressed in such forward-looking statements. These factors include, but are not limited to: the volatility of oil and gas
prices; production and development costs and capital expenditures; the imprecision of reserve estimates and estimates of recoverable quantities of oil, natural gas and liquids; unforeseen operating problems; pipeline or delivery constraints; our
ability to replace and expand oil and gas reserves; environmental claims and liabilities; incorrect assessments of value when making acquisitions; increases in debt service charges; the loss of key personnel; the marketability of production;
defaults by third party operators; unforeseen title defects; fluctuations in foreign currency and exchange rates; inadequate insurance coverage; counterparty risk; compliance with environmental laws and regulations; changes in tax and royalty laws;
our ability to access external sources of debt and equity capital, the implementation of International Financial Reporting Standards (IFRS); and the implementation of greenhouse gas (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, 2010, 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 and Nova Scotia. The Corporation is the successor to the Trust, following the completion of the conversion of the Trust from an income trust to a corporate structure by way of a Court approved plan of
arrangement under the ABCA 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 of the Corporation 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. Unless otherwise
indicated, all information presented for the pre-Arrangement period in this Annual Information Form is that of the Trust.

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

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

Three Year Historical Overview

2010

On November 9, 2010, we released the details of our 2011 capital expenditure
program and provided guidance on production and operating costs for 2011. Our 2011 development capital expenditure program is expected to be $400 million. We will continue to monitor and adjust capital investment levels in order to ensure that we
optimize value, operate within our cash flow and have the flexibility to take advantage of acquisition opportunities.

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 closed a US$187 million offering of 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 (together, the 2010 Senior Notes).

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.

2009

On November 11, 2009, we announced the appointment of John B. Zaozirny as Chairman of the Board of Pengrowth Corporation.

On October 23, 2009, Pengrowth Corporation completed a bought deal public offering of 28,847,000 Trust Units at $10.40 per Trust Unit for total
gross proceeds of approximately $300 million.

On September 13, 2009 Derek W. Evans was appointed President and Chief Executive Officer
of Pengrowth Corporation. Mr. Evans appointment as Chief Executive Officer followed the retirement of James S. Kinnear as Chairman and Chief Executive Officer.

Prior to June 30, 2009, the Trust and Pengrowth Corporation were managed by Pengrowth Management Limited pursuant to a third party management agreement (the Management Agreement).
On June 30, 2009, the Management Agreement expired and management of the Trust and Pengrowth Corporation was internalized.

On
May 25, 2009 Derek W. Evans was appointed as the President and Chief Operating Officer and as a director of Pengrowth Corporation.



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2008

On September 30, 2008, we closed the acquisition of Accrete Energy Inc. for total consideration of $120 million paid by the issuance of 4,973,325 Trust Units and the assumption of $22 million of
Accretes net liabilities. Pursuant to the acquisition, we acquired 1,900 boepd of production in the Harmattan gas field and 8.4 MMboe of P+P Company Interest reserves as of the closing date of September 30, 2008.

On August 21, 2008, we completed a US$265 million private placement of 6.98 percent senior unsecured ten year notes to a group of US
investors, and a $15 million private placement of 6.61 percent senior unsecured ten year notes to a group of Canadian investors (together, the 2008 Senior Notes). Interest on these notes is payable semi-annually.

DESCRIPTION OF OUR BUSINESS

General

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

Over the long term, we target a balance of capital spending that can maintain or modestly grow production and reserves on a debt adjusted
share basis. This will be achieved through a combination of:



| |  |  | focusing capital expenditures on existing low cost, low risk plays (Carson Creek, Swan Hills, Groundbirch, Olds Garrington) as well as to identify,
test and develop other resource plays where repeatable, predictable and scalable results can be achieved;
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | investing capital to advance the long term value of our resource plays (Lindbergh and EOR opportunities);
| | - |  | ---------------------------------------------------------------------------------------------------------



| |  |  | acquiring other assets in the WCSB with low cost, low risk, repeatable, predictable and scalable drilling opportunities;
| | - |  | ------------------------------------------------------------------------------------------------------------------------



| |  |  | maintaining appropriate debt levels; and
| | - |  | ----------------------------------------



| |  |  | ensuring a high level of capital efficiency and cost discipline.
| | - |  | ----------------------------------------------------------------

As at December 31, 2010, we had 582 permanent employees.

Business Strategy

Our goal is to maximize value creation for Shareholders through reinvesting a portion of our cash flow on our oil and gas properties while continuing to pay dividends. In October 2009, the Trusts
business model was changed to increase the emphasis on capital reinvestment following a review of the best opportunities for value creation on the Trusts existing asset base. This value creation strategy has been implemented and further
developed throughout 2010.

Our capital program focuses on our short and medium term inventory of low cost, low risk, repeatable and scalable
resource plays that have the ability to enhance reserves and production.We aim to continue acquiring companies and assets and anticipate financing those acquisitions with a prudent combination of debt and equity.

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 have an advantage through our expertise in horizontal well carbonate reef multi-stage fracturing technology, EOR technologies and waterflood optimization. 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 the Montney reservoir at the Groundbirch property and, receiving
regulatory approval for a pilot project at our Lindbergh SAGD project with potential for a commercial project providing long term development potential. The development of CO2 EOR at a number of fields with the initial development at Judy Creek and
the Horn River shale gas property also factor into our medium term plans.

For 2011, we have established a prudent capital spending level that
is higher than the previous year, but flexible in an uncertain commodity price environment. We prioritize our capital investments based on:



| |  |  | recycle ratio;
| | - |  | --------------



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##### Table of Contents

| |  |  | 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.
| | - |  | ----------------------------------------------------------------

PENGROWTH  OPERATIONAL INFORMATION

Principal Properties

The portfolio of properties acquired
and held by us reflects a mix of conventional and unconventional assets. While traditionally the Trust acquired properties and developed them, our shift in strategy as announced in October 2009 to become a low cost, low risk, repeatable and scalable
resource play developer has begun to return results as demonstrated by our improved 2010 F&D Costs.

The following table summarizes our
principal producing properties as of December 31, 2010 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, 2010. The table also contains our average daily production of oil, natural gas and NGL for the year ended December 31, 2010.

Summary of Company Interest

at December 31,
2010(1)

(Forecast Prices and Costs)(2)



|                |  |                 |         |  |                           |  |    |                          |  |  |                                    |  |  |                         |         |  |                         |  |        |                         |  |  |                              |  |  |  |       |  |  |  |        | 
|--------------- |  | --------------- | ------- |  | ------------------------- |  | -- | ------------------------ |  |  | ---------------------------------- |  |  | ----------------------- | ------- |  | ----------------------- |  | ------ | ----------------------- |  |  | ---------------------------- |  |  |  | ----- |  |  |  | ------ | 
|Field           |  | P+PReservesMboe |         |  | RemainingReserveLifeyears |  |    | P+PReserveLifeIndexyears |  |  | P+P ValueBefore Taxat 10% DR(4)$MM |  |  | 2010 OilProductionbblpd |         |  | 2010 GasProductionMMcfd |  |        | 2010 NGLProductionbblpd |  |  | 2010
TotalProductionboepd(5) | 
|Judy Creek      |  |                 | 32,579  |  |                           |  | 50 |                          |  |  | 11.9                               |  |  |                         | 729.1   |  |                         |  | 5,939  |                         |  |  | 5.3                          |  |  |  | 1,444 |  |  |  | 8,258  | 
|Groundbirch     |  |                 | 27,158  |  |                           |  | 46 |                          |  |  | 18.5                               |  |  |                         | 187.2   |  |                         |  |       |                         |  |  | 0.7                          |  |  |  |      |  |  |  | 122    | 
|Carson Creek    |  |                 | 23,990  |  |                           |  | 44 |                          |  |  | 8.0                                |  |  |                         | 454.5   |  |                         |  | 1,880  |                         |  |  | 13.7                         |  |  |  | 2,246 |  |  |  | 6,413  | 
|Weyburn Unit    |  |                 | 21,261  |  |                           |  | 47 |                          |  |  | 21.8                               |  |  |                         | 438.7   |  |                         |  | 2,550  |                         |  |  | 0.3                          |  |  |  |      |  |  |  | 2,604  | 
|Harmattan       |  |                 | 16,718  |  |                           |  | 50 |                          |  |  | 7.6                                |  |  |                         | 195.8   |  |                         |  | 412    |                         |  |  | 18.4                         |  |  |  | 1,642 |  |  |  | 5,117  | 
|Swan Hills Unit |  |                 | 16,157  |  |                           |  | 50 |                          |  |  | 17.8                               |  |  |                         | 234.2   |  |                         |  | 1,814  |                         |  |  | 1.7                          |  |  |  | 243   |  |  |  | 2,343  | 
|Olds            |  |                 | 16,014  |  |                           |  | 50 |                          |  |  | 12.6                               |  |  |                         | 161.8   |  |                         |  | 13     |                         |  |  | 17.2                         |  |  |  | 708   |  |  |  | 3,587  | 
|Twining         |  |                 | 11,635  |  |                           |  | 50 |                          |  |  | 11.2                               |  |  |                         | 171.9   |  |                         |  | 592    |                         |  |  | 13.4                         |  |  |  | 400   |  |  |  | 3,228  | 
|CBM             |  |                 | 11,065  |  |                           |  | 47 |                          |  |  | 16.8                               |  |  |                         | 85.9    |  |                         |  |       |                         |  |  | 11.4                         |  |  |  | 2     |  |  |  | 1,898  | 
|                |  |                 |         |  |                           |  |    |                          |  |  |                                    |  |  |                         |         |  |                         |  |        |                         |  |  |                              |  |  |  |       |  |  |  |        | 
|Subtotal        |  |                 | 176,577 |  |                           |  | 50 |                          |  |  | 12.4                               |  |  |                         | 2,659.1 |  |                         |  | 13,200 |                         |  |  | 82.1                         |  |  |  | 6,685 |  |  |  | 33,570 | 
|Remainder(3)    |  |                 | 141,852 |  |                           |  | 50 |                          |  |  | 9.8                                |  |  |                         | 1,977.3 |  |                         |  | 15,331 |                         |  |  | 137.2                        |  |  |  | 2,926 |  |  |  | 41,125 | 
|                |  |                 |         |  |                           |  |    |                          |  |  |                                    |  |  |                         |         |  |                         |  |        |                         |  |  |                              |  |  |  |       |  |  |  |        | 
|Total           |  |                 | 318,429 |  |                           |  | 50 |                          |  |  | 11.1                               |  |  |                         | 4,636.4 |  |                         |  | 28,531 |                         |  |  | 219.3                        |  |  |  | 9,611 |  |  |  | 74,695 | 

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) | Remainder includes our Working Interests and Royalty Interests in approximately 125 other properties.
|--- | -------------------------------------------------------------------------------------------------------

|(4) | Estimated future net revenues disclosed do not represent fair market value.
|--- | ---------------------------------------------------------------------------

|(5) | Natural gas has been converted to barrels of oil equivalent on the basis of six Mcf of natural gas being equal to one barrel of oil.
|--- | ------------------------------------------------------------------------------------------------------------------------------------

Judy Creek

We have a 100 percent
Working Interest in both the Judy Creek Beaverhill Lake Unit and the Judy Creek West Beaverhill Lake Unit (oil properties together referred to as Judy Creek). 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. Judy Creek is located approximately 200 kilometres northwest of Edmonton, Alberta and covers an area of
approximately 38,300 acres. Judy Creek was discovered in 1959, placed on waterflood in 1962 and hydrocarbon miscible flood in 1985. Remaining Company Interest Total Proved Plus Probable Reserves at December 31, 2010 are estimated to be
32.6 MMboe. The Remaining Reserve Life is 50 years and the P+P Reserve Life Index is 11.9 years. Our Company Interest production for Judy Creek averaged 8,258 boepd in 2010.



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2010 Development Activity

Two horizontal multi-stage acid fractured wells were drilled to test two play concepts: the underlying platform and the capping shoal of the Beaverhill Lake (BHL) formation. Combined
rate at year-end from the two wells was 360 boepd. Two vertical producers were reactivated and a vertical well was acid fractured resulting in a combined rate at year-end from those three wells of 100 boepd. A new horizontal miscible flood injector
was drilled and placed in service and a new vertical producer was drilled as part of the new injection pattern.

2011
Development Activity

The 2011 capital program includes the drilling and multi-staged acid fracture completion of approximately ten BHL
horizontal wells. Most of this activity is expected to occur in the first half of 2011. Six of the wells are planned to be drilled in the BHL Platform in the northeast area of the Judy Creek BHL Unit. Three wells are planned to be drilled at the
southern end of the Judy Creek West BHL Pool targeting the uppermost reef stage. One well will be drilled in the reef interior.

Carbon
Dioxide (CO2) EOR Pilot

The intent of the Judy Creek CO2 EOR pilot project is to evaluate the potential of a commercial sized CO2
miscible flood that would increase oil recovery and recover hydrocarbons left behind from the hydrocarbon miscible flood. CO2 injection into the first pilot commenced in February of 2007 and ended June 2009.

Since February 2007, 1.2 Bcf of CO2 has been injected into the 80 acre pilot pattern resulting in an additional 59 Mbbl of oil and 224 MMcf of natural
gas being recovered. The results of the pilot are in-line or better than our internal estimates and can be used to extrapolate the additional recoveries across our whole field. Although CO2 injection has ended, the increased production is expected
to continue and monitoring recovery will be maintained into 2011.

Groundbirch

We have an average 90 percent Working Interest in the Groundbirch properties we acquired in September 2010 from Monterey Exploration Ltd. The Montney
formation, one of the most economic gas resource plays in North America, is present across our Groundbirch property which is located approximately 40 kilometres southwest of Ft. St. John, British Columbia and covers an area of approximately
13,440 acres. Remaining Company Interest Total Proved Plus Probable Reserves at December 31, 2010 are estimated to be 27.2 MMboe. The Remaining Reserve Life is 46 years and the P+P Reserve Life Index is 18.5 years.
Our Company Interest production for Groundbirch averaged only 122 boepd in 2010 as the gas plant was only placed in operation on December 18, 2010.

2010 Development Activity

Since acquiring Monterey on September 15, 2010 and before
December 31, 2010, three horizontal Montney gas wells have been drilled, five horizontal Montney wells have been multi-stage fractured, a 28 MMcfpd gas plant was constructed and commissioned, and approximately 15 km of pipe was installed. By
the end of December 2010, the gas plant was operating with gas being supplied from five wells on our Groundbirch lands.

2011 Development Activity

The 2011 capital program includes further development of the Montney gas resource through three more horizontal drills, and a total of eight Montney horizontal wells being multi-stage fractured. A
vertical well will test the Doig production formation and, if warranted, a horizontal well will be drilled and completed in the Doig later in 2011. The 2011 development plan is designed to keep the gas plant operating near design capacity.

Carson Creek

Carson
Creek is located 160 kilometres northwest of Edmonton, Alberta and is comprised of two Pengrowth-operated units (one oil unit and one natural gas and gas condensate unit) covering approximately 46,200 acres.

The Carson Creek North Beaverhill Lake Unit No. 1 (oil), in which we have an 88.6 percent Working Interest, was discovered in 1958 and the current
waterflood was initiated in 1964.

The Carson Creek Beaverhill Lake Unit No. 1 (gas and gas condensate), in which we have a
95.1 percent Working Interest, was discovered in 1958. From 1962 to 1985, a re-cycling program was operated in which NGL were stripped from the liquid-rich natural gas and the remaining lean gas re-injected. Gas re-injection now only occurs
during plant disruption.

Remaining Company Interest Total Proved Plus Probable Reserves at December 31, 2010 are estimated to be
24.0 MMboe. The Remaining Reserve Life is 44 years and the P+P Reserve Life Index is 8 years. Our Company Interest production for Carson Creek averaged 6,413 boepd in 2010.



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We have a 95.1 percent Working Interest in the Carson Creek gas plant, which processes the gas production.

2010 Development Activity

Our 2010 activity consisted of drilling seven horizontal wells in the Carson Creek Beaverhill Lake Unit No. 1. This activity built on the successful horizontal well developmental program in the new
C pool that started in 2009. All wells were multi-staged acid fractured. A total of 16 horizontal wells are currently producing from the C pool and have an average liquid yield of over 200 bbl of NGL per MMcf. Note that the
original wells that had undergone re-cycling have a yield near 35 bbl of NGL per MMcf.

Our 2010 activities in the Carson Creek North Unit
included waterflood optimization and well workovers to increase production and improve recovery.

2011 Development Activity

We will continue with waterflood optimization, injector stimulations and a water injector conversion in 2011. One new horizontal well is
planned to be drilled.

In the Carson Creek Beaverhill Lake Unit No. 1 and surrounding areas, more drilling is planned for 2011. Six new
horizontal drills have been budgeted for a program starting in the first half of the year.

Weyburn Unit

The Weyburn Unit is located in southeastern Saskatchewan. We hold a 9.76 percent Working Interest in this unit which is operated by a senior producer. 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 700 production wells and 300 injection wells. Remaining Company
Interest Total Proved Plus Probable Reserves at December 31, 2010 are estimated to be 21.3 MMboe. The Remaining Reserve Life is 47 years and the P+P Reserve Life Index is 21.8 years. Our Company Interest production for Weyburn
averaged 2,604 boepd in 2010.

2010 Development Activity

In 2010, an average of 10.2 MMcfpd of CO2 was purchased for EOR injection to supplement the CO2 that is separated from oil production. Total injection rates reached 24 MMcfpd on peak days. In 2010, 32
gross wells were drilled: two were production wells, 28 were injectors and two were observation wells. The replacement of the low pressure gas compressor that was initiated in 2010 is to be completed in 2011.

2011 Development Activity

The 2011 program includes purchasing an average 11.6 MMcfpd of CO2 for EOR injection. Current plans are to drill eleven new wells as part of expanding the CO2 EOR and waterflood patterns.

Harmattan

The Harmattan gas
field 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 55 percent in the non-unit lands (operated) and 25 percent in the partner-operated units. The Remaining Company Interest Total Proved Plus Probable Reserves at
December 31, 2010 are estimated to be 16.7 MMboe. The Remaining Reserve Life is 50 years and the P+P Reserve Life Index is 7.6 years. Our Company Interest production for Harmattan averaged 5,117 boepd in 2010.

2010 Development Activity

We drilled two successful Elkton wells early in the year. These wells are liquid-rich gas wells, producing approximately 75 bbl of NGL per MMcf. The success of these two original wells led to two more
wells being drilled in the fourth quarter. One started production in November and the other well will begin production in the first quarter of 2011.

We drilled four Cardium formation wells in 2010 to test the Cardium potential on our lands. We had varied success with the most recent wells initial production rate was over 350 boepd while others
had lower rates.

Three Viking formation proof of concept wells were drilled in 2010. A fourth well was junked and abandoned earlier in the
year due to hole conditions. Initial indications from the program are quite positive and the results will be evaluated to define future development.



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2011 Development Activity

At least two more Elkton formation wells are expected to be drilled as a continuation of the 2010 program. One or two wells are planned to be drilled into the Cardium formation targeting areas with good
off-setting production. The performance of the three 2010 Viking formation wells will help to determine Viking formation drilling plans later in 2011.

Swan Hills Unit

The Swan Hills Unit No. 1 is located near the Judy Creek field
in north central Alberta. We hold a 24.01 percent Working Interest in this unit which is operated by our partner. Light sweet crude oil is produced from the Beaverhill Lake reservoir which has a waterflood and a hydrocarbon miscible flood EOR
program. The remaining Company Interest Total Proved Plus Probable Reserves at December 31, 2010 are estimated to be 16.2 MMboe. The Remaining Reserve Life is 50 years and the P+P Reserve Life Index is 17.8 years. Our Company
Interest production for Swan Hills averaged 2,343 boepd in 2010.

2010 Development Activity

In 2010, four new producing wells were drilled with initial rates ranging from 20 to 260 bblpd of oil.

2011 Development Activity

The 2011 capital program for production development includes drilling four gross producing wells as well as conducting eight workovers on existing wells to stimulate new production and to add recoverable
reserves.

Olds

The Olds property is located 95 kilometres north of Calgary, Alberta. Our interests include 100 percent ownership in the Olds Gas Field Unit No. 1. In addition, we have a 75 percent
average Working Interest in non-unit reserves. The Olds unit produces sour natural gas from the Wabamun Formation, with
H2S concentrations ranging from less than one to
35 percent. The non-unit reserves are contained within formations from the Wabamun to the Edmonton group, and are predominantly sweet natural gas. Remaining Company Interest Total Proved Plus Probable Reserves at December 31, 2010 are
estimated to be 16.0 MMboe. The Remaining Reserve Life is 50 years and the P+P Reserve Life Index is 12.6 years. Our Company Interest production for Olds averaged 3,587 boepd in 2010.

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.

2010 Development Activity

In 2010, we multi-stage fractured one existing Wabamun gas well. The production increased four-fold immediately following the operation. The well now
produces at 1.5 times pre-fracture rates. Further projects have been delayed due to the current low gas price environment.

2011 Development Activity

We anticipate continued well optimization work as well as up to three recompletions using the multi-stage fracturing techniques in existing wellbores.

Twining

The Twining property is
located approximately 130 kilometres northeast of Calgary, Alberta. Although production is mainly gas, there is also oil production from this area. We operate the majority of the production within this property. Oil is produced from the
Pekisko formation. Remaining Company Interest Total Proved Plus Probable Reserves at December 31, 2010 are estimated to be 11.6 MMboe. The Remaining Reserve Life is 50 years and the P+P Reserve Life Index is 11.2 years.
Our Company Interest production for Twining averaged 3,228 boepd in 2010.

2010 Development Activity

Our 2010 activity included drilling two horizontal Pekisko oil wells, and recompleting an existing horizontal oil well using multi-stage fracturing
technology.

2011 Development Activity

Plans for 2011 development activity include multi-stage fracturing one of the 2010 Pekisko horizontal drills, drilling two additional horizontal Pekisko oil wells, along with multi-stage fracturing an
existing producing Pekisko oil well.



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Coal Bed Methane (CBM)

Our CBM activity is focused in the Elnora, Fenn Big Valley and Twining areas which are 100 to 160 kilometres northeast of Calgary, Alberta. Remaining Company Interest Total Proved Plus Probable
Reserves at December 31, 2010 are estimated to be 11.1 MMboe. The Remaining Reserve Life is 50 years and the P+P Reserve Life Index is 11.2 years. Our Company Interest CBM production averaged 1,898 boepd in 2010.

2010 Development Activity

Our 2010 activity included drilling 19 gross (13.1 net) wells. These wells were drilled to hold expiring lands and to evaluate the viability of higher well densities in our core areas.

Partners also drilled nine gross (one net) wells in 2010.

2011 Development Activity

In 2011, we anticipate completing three wells that were drilled
late in 2010 on expiring lands. Low gas price forecasts will limit our 2011 investment in CBM development activities.

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, 2010 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, 2010 and the preparation date is January 19, 2011 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 Total Proved Plus Probable Reserves and no attempt was made to
evaluate Possible Reserves in the 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 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, 2010 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.

For the purposes of this Annual Information Form, the Probable Reserves reported for the Lindbergh oil sands property in the GLJ Report are
included with the Heavy Oil reserves. See  Lindbergh Oil Sands Reserves and Contingent Resources.

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, 2010.

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 Canadian Oil and Gas Evaluation 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;
| | - |  | ----------------------------------------------------



- 13 -



---

##### Table of Contents

| |  |  | Annual general and administrative expenses at the current rate;
| | - |  | ---------------------------------------------------------------



| |  |  | Interest expense at the current rate;
| | - |  | -------------------------------------



| |  |  | Tax pool deductions utilizing our existing $3.0 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 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.

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 paying income tax until after 2014.

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, 2010

(Forecast Prices and Costs)(1)



|                                    |  |                      |         |  |                  |  |         |                               |  |  |                 |  |  |               |        |  |              |  |        |                 |  |  |               |  |  |              |         |  |  |  |         |  |  |  |         | 
|----------------------------------- |  | -------------------- | ------- |  | ---------------- |  | ------- | ----------------------------- |  |  | --------------- |  |  | ------------- | ------ |  | ------------ |  | ------ | --------------- |  |  | ------------- |  |  | ------------ | ------- |  |  |  | ------- |  |  |  | ------- | 
|                                    |  | Light and Medium Oil |         |  | Heavy Oil(2)     |  |         | Natural Gas Liquids           | 
|                                    |  | CompanyInterest      |         |  | GrossInterest    |  |         | NetInterest                   |  |  | CompanyInterest |  |  | GrossInterest |        |  | NetInterest  |  |        | CompanyInterest |  |  | GrossInterest |  |  | NetInterest  |        
|Reserves Category                   |  | (Mbbl)               |         |  | (Mbbl)           |  |         | (Mbbl)                        |  |  | (Mbbl)          |  |  | (Mbbl)        |        |  | (Mbbl)       |  |        | (Mbbl)          |  |  | (Mbbl)        |  |  | (Mbbl)       |        
|Proved Reserves                     |  |                      |         |  |                  |  |         |                               |  |  |                 |  |  |               |        |  |              |  |        |                 |  |  |               |  |  |              |         |  |  |  |         |  |  |  |         | 
|Proved Developed Producing          |  |                      | 63,893  |  |                  |  | 63,750  |                               |  |  | 50,755          |  |  |               | 13,505 |  |              |  | 13,499 |                 |  |  | 11,658        |  |  |              | 19,655  |  |  |  | 19,618  |  |  |  | 14,089  | 
|Proved Developed Non-Producing      |  |                      | 2,251   |  |                  |  | 2,250   |                               |  |  | 1,699           |  |  |               |       |  |              |  |       |                 |  |  |              |  |  |              | 721     |  |  |  | 721     |  |  |  | 539     | 
|Proved Undeveloped                  |  |                      | 15,085  |  |                  |  | 15,077  |                               |  |  | 11,631          |  |  |               | 1,732  |  |              |  | 1,732  |                 |  |  | 1,457         |  |  |              | 878     |  |  |  | 878     |  |  |  | 662     | 
|                                    |  |                      |         |  |                  |  |         |                               |  |  |                 |  |  |               |        |  |              |  |        |                 |  |  |               |  |  |              |         |  |  |  |         |  |  |  |         | 
|Total Proved Reserves               |  |                      | 81,228  |  |                  |  | 81,077  |                               |  |  | 64,085          |  |  |               | 15,238 |  |              |  | 15,232 |                 |  |  | 13,114        |  |  |              | 21,254  |  |  |  | 21,216  |  |  |  | 15,290  | 
|Probable Reserves                   |  |                      | 29,069  |  |                  |  | 29,024  |                               |  |  | 22,345          |  |  |               | 11,234 |  |              |  | 11,233 |                 |  |  | 9,780         |  |  |              | 8,227   |  |  |  | 8,216   |  |  |  | 6,130   | 
|                                    |  |                      |         |  |                  |  |         |                               |  |  |                 |  |  |               |        |  |              |  |        |                 |  |  |               |  |  |              |         |  |  |  |         |  |  |  |         | 
|Total Proved Plus Probable Reserves |  |                      | 110,297 |  |                  |  | 110,101 |                               |  |  | 86,430          |  |  |               | 26,472 |  |              |  | 26,465 |                 |  |  | 22,894        |  |  |              | 29,481  |  |  |  | 29,432  |  |  |  | 21,420  | 
|                                    |  |                      |         |  |                  |  |         |                               |  |  |                 |  |  |               |        |  |              |  |        |                 |  |  |               |  |  |              |         |  |  |  |         |  |  |  |         | 
|                                    |  |                      |        
|                                    |  | Natural Gas          |         |  | Coal Bed Methane |  |         | Total Oil Equivalent
Basis(3) | 
|                                    |  | CompanyInterest      |         |  | GrossInterest    |  |         | Net Interest                  |  |  | CompanyInterest |  |  | GrossInterest |        |  | Net Interest |  |        | CompanyInterest |  |  | GrossInterest |  |  | Net Interest |        
|Reserves Category                   |  | (MMcf)               |         |  | (MMcf)           |  |         | (MMcf)                        |  |  | (MMcf)          |  |  | (MMcf)        |        |  | (MMcf)       |  |        | (Mboe)          |  |  | (Mboe)        |  |  | (Mboe)       |        
|Proved Reserves                     |  |                      |         |  |                  |  |         |                               |  |  |                 |  |  |               |        |  |              |  |        |                 |  |  |               |  |  |              |         |  |  |  |         |  |  |  |         | 
|Proved Developed Producing          |  |                      | 493,650 |  |                  |  | 491,062 |                               |  |  | 421,501         |  |  |               | 26,012 |  |              |  | 25,699 |                 |  |  | 24,124        |  |  |              | 183,664 |  |  |  | 182,995 |  |  |  | 150,772 | 
|Proved Developed Non-Producing      |  |                      | 21,374  |  |                  |  | 21,258  |                               |  |  | 17,274          |  |  |               | 2,039  |  |              |  | 2,026  |                 |  |  | 1,724         |  |  |              | 6,874   |  |  |  | 6,851   |  |  |  | 5,405   | 
|Proved Undeveloped                  |  |                      | 51,742  |  |                  |  | 51,742  |                               |  |  | 45,128          |  |  |               | 25,026 |  |              |  | 24,955 |                 |  |  | 21,413        |  |  |              | 30,489  |  |  |  | 30,470  |  |  |  | 24,839  | 
|                                    |  |                      |         |  |                  |  |         |                               |  |  |                 |  |  |               |        |  |              |  |        |                 |  |  |               |  |  |              |         |  |  |  |         |  |  |  |         | 
|Total Proved Reserves               |  |                      | 566,767 |  |                  |  | 564,062 |                               |  |  | 483,903         |  |  |               | 53,077 |  |              |  | 52,680 |                 |  |  | 47,261        |  |  |              | 221,028 |  |  |  | 220,316 |  |  |  | 181,016 | 
|Probable Reserves                   |  |                      | 280,262 |  |                  |  | 279,489 |                               |  |  | 238,563         |  |  |               | 12,966 |  |              |  | 12,866 |                 |  |  | 11,639        |  |  |              | 97,402  |  |  |  | 97,199  |  |  |  | 79,956  | 
|                                    |  |                      |         |  |                  |  |         |                               |  |  |                 |  |  |               |        |  |              |  |        |                 |  |  |               |  |  |              |         |  |  |  |         |  |  |  |         | 
|Total Proved Plus Probable Reserves |  |                      | 847,029 |  |                  |  | 843,551 |                               |  |  | 722,466         |  |  |               | 66,043 |  |              |  | 65,547 |                 |  |  | 58,900        |  |  |              | 318,429 |  |  |  | 317,514 |  |  |  | 260,972 | 
|                                    |  |                      |         |  |                  |  |         |                               |  |  |                 |  |  |               |        |  |              |  |        |                 |  |  |               |  |  |              |         |  |  |  |         |  |  |  |         | 

Notes:



|(1) | Forecast prices are shown under the heading Pricing Assumptions.
|--- | ------------------------------------------------------------------

|(2) | Includes 6,348 Mbbl of Company Interest heavy oil Probable Reserves for the Lindbergh oil sands property in the GLJ Report.
|--- | ---------------------------------------------------------------------------------------------------------------------------

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



- 14 -



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##### Table of Contents

Summary of Net Present Value

of Future Net Revenue

as of December 31, 2010

Before and After Income Taxes

(Forecast Prices and Costs)(1)



|                                    |  |                                            |       |  |                                                         |  |       |          |  |  |          |  |  |          |       |  |       |  |       |        |  |  |       |  |  |  |      | 
|----------------------------------- |  | ------------------------------------------ | ----- |  | ------------------------------------------------------- |  | ----- | -------- |  |  | -------- |  |  | -------- | ----- |  | ----- |  | ----- | ------ |  |  | ----- |  |  |  | ---- | 
|                                    |  | Before Income Taxes Discounted at (%/Year) |       |  | Unit Value Before IncomeTax Discounted at10%/Year(2)(3) | 
|Reserves Category                   |  | 0%($MM)                                    |       |  | 5%($MM)                                                 |  |       | 10%($MM) |  |  | 15%($MM) |  |  | 20%($MM) |       |  | $/boe |  |       | $/Mcfe | 
|Proved Reserves                     |  |                                            |       |  |                                                         |  |       |          |  |  |          |  |  |          |       |  |       |  |       |        |  |  |       |  |  |  |      | 
|Proved Developed Producing          |  |                                            | 5,338 |  |                                                         |  | 3,945 |          |  |  | 3,143    |  |  |          | 2,626 |  |       |  | 2,267 |        |  |  | 20.84 |  |  |  | 3.47 | 
|Proved Developed Non-Producing      |  |                                            | 197   |  |                                                         |  | 123   |          |  |  | 86       |  |  |          | 64    |  |       |  | 50    |        |  |  | 15.83 |  |  |  | 2.64 | 
|Proved Undeveloped                  |  |                                            | 994   |  |                                                         |  | 551   |          |  |  | 325      |  |  |          | 198   |  |       |  | 120   |        |  |  | 13.07 |  |  |  | 2.18 | 
|                                    |  |                                            |       |  |                                                         |  |       |          |  |  |          |  |  |          |       |  |       |  |       |        |  |  |       |  |  |  |      | 
|Total Proved Reserves               |  |                                            | 6,530 |  |                                                         |  | 4,618 |          |  |  | 3,553    |  |  |          | 2,887 |  |       |  | 2,437 |        |  |  | 19.63 |  |  |  | 3.27 | 
|Probable Reserves                   |  |                                            | 3,396 |  |                                                         |  | 1,769 |          |  |  | 1,084    |  |  |          | 732   |  |       |  | 526   |        |  |  | 13.55 |  |  |  | 2.26 | 
|                                    |  |                                            |       |  |                                                         |  |       |          |  |  |          |  |  |          |       |  |       |  |       |        |  |  |       |  |  |  |      | 
|Total Proved Plus Probable Reserves |  |                                            | 9,926 |  |                                                         |  | 6,387 |          |  |  | 4,636    |  |  |          | 3,620 |  |       |  | 2,963 |        |  |  | 17.77 |  |  |  | 2.96 | 
|                                    |  |                                            |       |  |                                                         |  |       |          |  |  |          |  |  |          |       |  |       |  |       |        |  |  |       |  |  |  |      | 



|                                    |  |                                              |       |  |         |  |       |          |  |  |          |  |  |          |       |  |  |  |       | 
|----------------------------------- |  | -------------------------------------------- | ----- |  | ------- |  | ----- | -------- |  |  | -------- |  |  | -------- | ----- |  |  |  | ----- | 
|                                    |  | After Income Taxes Discounted at
(%/Year)(4) |      
|Reserves Category                   |  | 0%($MM)                                      |       |  | 5%($MM) |  |       | 10%($MM) |  |  | 15%($MM) |  |  | 20%($MM) |      
|Proved Reserves                     |  |                                              |       |  |         |  |       |          |  |  |          |  |  |          |       |  |  |  |       | 
|Proved Developed Producing          |  |                                              | 4,813 |  |         |  | 3,680 |          |  |  | 2,931    |  |  |          | 2,414 |  |  |  | 2,043 | 
|Proved Developed Non-Producing      |  |                                              | 139   |  |         |  | 90    |          |  |  | 62       |  |  |          | 45    |  |  |  | 33    | 
|Proved Undeveloped                  |  |                                              | 730   |  |         |  | 402   |          |  |  | 226      |  |  |          | 126   |  |  |  | 67    | 
|                                    |  |                                              |       |  |         |  |       |          |  |  |          |  |  |          |       |  |  |  |       | 
|Total Proved Reserves               |  |                                              | 5,681 |  |         |  | 4,172 |          |  |  | 3,218    |  |  |          | 2,584 |  |  |  | 2,143 | 
|Probable Reserves                   |  |                                              | 2,559 |  |         |  | 1,384 |          |  |  | 810      |  |  |          | 510   |  |  |  | 343   | 
|                                    |  |                                              |       |  |         |  |       |          |  |  |          |  |  |          |       |  |  |  |       | 
|Total Proved Plus Probable Reserves |  |                                              | 8,240 |  |         |  | 5,556 |          |  |  | 4,028    |  |  |          | 3,094 |  |  |  | 2,486 | 
|                                    |  |                                              |       |  |         |  |       |          |  |  |          |  |  |          |       |  |  |  |       | 

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 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 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.
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



- 15 -



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##### Table of Contents

Additional Information Concerning Future Net Revenue

(undiscounted)

as of December 31, 2010

(Forecast Prices
and Costs)(1)



|                                    |  |              |        |  |                   |  |       |                     |  |  |                       |  |  |                          |       |  |                                           |  |     |                 |  |  |                                         |  |  |  |       |  |  |  |       | 
|----------------------------------- |  | ------------ | ------ |  | ----------------- |  | ----- | ------------------- |  |  | --------------------- |  |  | ------------------------ | ----- |  | ----------------------------------------- |  | --- | --------------- |  |  | --------------------------------------- |  |  |  | ----- |  |  |  | ----- | 
|Reserves Category                   |  | Revenue($MM) |        |  | Royalties(2)($MM) |  |       | OperatingCosts($MM) |  |  | DevelopmentCosts($MM) |  |  | AbandonmentCosts(3)($MM) |       |  | Future NetRevenue BeforeIncome Taxes($MM) |  |     | Income Tax($MM) |  |  | Future NetRevenueAfter IncomeTaxes($MM) | 
|Proved Reserves                     |  |              | 15,054 |  |                   |  | 2,908 |                     |  |  | 4,768                 |  |  |                          | 603   |  |                                           |  | 246 |                 |  |  | 6,530                                   |  |  |  | 849   |  |  |  | 5,681 | 
|Total Proved Plus Probable Reserves |  |              | 22,413 |  |                   |  | 4,344 |                     |  |  | 6,788                 |  |  |                          | 1,079 |  |                                           |  | 277 |                 |  |  | 9,926                                   |  |  |  | 1,686 |  |  |  | 8,240 | 

Notes:



|(1) | Forecast prices are shown under the heading Pricing Assumptions.
|--- | ------------------------------------------------------------------

|(2) | Crown royalties payable to the provinces of Alberta, British Columbia, Saskatchewan and Nova Scotia and any freehold and over-riding royalties payable. This includes
the impact of the New Royalty Framework implemented by the Government of Alberta on January 1, 2009, the optional Transitional Royalty and any drilling incentive programs currently in effect.
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|(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, 2010

(Forecast Prices and Costs)(1)



|                      |  |                                                                                  |         |                                                                   |       |          |                  |  |       |  |  |  |      | 
|--------------------- |  | -------------------------------------------------------------------------------- | ------- | ----------------------------------------------------------------- | ----- | -------- | ---------------- |  | ----- |  |  |  | ---- | 
|Reserves Category     |  | Production Group                                                                 |         | Future Net RevenueBefore Income Taxes(discounted at 
10%/yr)($MM) |       |          | Unit Value(4)(5) | 
|                      |  |                                                                                  | ($/boe) |                                                                   |       | ($/Mcfe) |                 
|Total Proved Reserves |  | Light and Medium Crude Oil (including solution gas and other by-products)(2)     |         |                                                                   | 2,017 |          |                  |  | 25.50 |  |  |  | 4.25 | 
|                      |  | Heavy Oil (including solution gas and other by-products)(2)                      |         |                                                                   | 380   |          |                  |  | 25.92 |  |  |  | 4.32 | 
|                      |  | Natural Gas (including by-products but excluding solution gas from oil wells)(3) |         |                                                                   | 1,087 |          |                  |  | 13.70 |  |  |  | 2.28 | 
|                      |  | Non-conventional Oil & Gas Activities                                            |         |                                                                   | 68    |          |                  |  | 8.61  |  |  |  | 1.43 | 
|                      |  |                                                                                  |         |                                                                   |       |          |                  |  |       |  |  |  |      | 
|                      |  | Total                                                                            |         |                                                                   | 3,553 |          |                  |  | 19.63 |  |  |  | 3.27 | 
|                      |  |                                                                                  |         |                                                                   |       |          |                  |  |       |  |  |  |      | 
|Total Proved Plus     |  | Light and Medium Crude Oil (including solution gas and other by-products)(2)     |         |                                                                   | 2,540 |          |                  |  | 23.83 |  |  |  | 3.97 | 
|Probable Reserves     |  | Heavy Oil (including solution gas and other by-products)(2)                      |         |                                                                   | 492   |          |                  |  | 19.72 |  |  |  | 3.29 | 
|                      |  | Natural Gas (including by-products but excluding solution gas from oil wells)(3) |         |                                                                   | 1,517 |          |                  |  | 12.69 |  |  |  | 2.11 | 
|                      |  | Non-conventional Oil & Gas Activities                                            |         |                                                                   | 87    |          |                  |  | 8.84  |  |  |  | 1.47 | 
|                      |  |                                                                                  |         |                                                                   |       |          |                  |  |       |  |  |  |      | 
|                      |  | Total                                                                            |         |                                                                   | 4,636 |          |                  |  | 17.77 |  |  |  | 2.96 | 
|                      |  |                                                                                  |         |                                                                   |       |          |                  |  |       |  |  |  |      | 

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 Mcfe are based on our net reserves.
|--- | --------------------------------------------------------------------------------------

|(5) | Natural gas has been converted to barrels of oil equivalent on the basis of six 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 Mcf of natural gas.
|--- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



- 16 -



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##### Table of Contents

Reserves Data (Constant Prices and Costs)

Summary of Oil And Gas Reserves

as of December 31, 2010

(Constant Prices
and Costs)(1)



|                                    |  |                      |         |  |                  |  |         |                               |  |  |                 |  |  |               |        |  |             |  |        |                 |  |  |               |  |  |              |         |  |  |  |         |  |  |  |         | 
|----------------------------------- |  | -------------------- | ------- |  | ---------------- |  | ------- | ----------------------------- |  |  | --------------- |  |  | ------------- | ------ |  | ----------- |  | ------ | --------------- |  |  | ------------- |  |  | ------------ | ------- |  |  |  | ------- |  |  |  | ------- | 
|                                    |  | Light and Medium Oil |         |  | Heavy Oil(2)     |  |         | Natural Gas Liquids           | 
|                                    |  | CompanyInterest      |         |  | GrossInterest    |  |         | Net Interest                  |  |  | CompanyInterest |  |  | GrossInterest |        |  | NetInterest |  |        | CompanyInterest |  |  | GrossInterest |  |  | NetInterest  |        
|Reserves Category                   |  | (Mbbl)               |         |  | (Mbbl)           |  |         | (Mbbl)                        |  |  | (Mbbl)          |  |  | (Mbbl)        |        |  | (Mbbl)      |  |        | (Mbbl)          |  |  | (Mbbl)        |  |  | (Mbbl)       |        
|Proved Reserves                     |  |                      |         |  |                  |  |         |                               |  |  |                 |  |  |               |        |  |             |  |        |                 |  |  |               |  |  |              |         |  |  |  |         |  |  |  |         | 
|Proved Developed Producing          |  |                      | 63,559  |  |                  |  | 63,421  |                               |  |  | 53,513          |  |  |               | 13,413 |  |             |  | 13,408 |                 |  |  | 11,785        |  |  |              | 19,121  |  |  |  | 19,087  |  |  |  | 13,702  | 
|Proved Developed Non-Producing      |  |                      | 2,250   |  |                  |  | 2,248   |                               |  |  | 1,760           |  |  |               |       |  |             |  |       |                 |  |  |              |  |  |              | 767     |  |  |  | 766     |  |  |  | 579     | 
|Proved Undeveloped                  |  |                      | 15,085  |  |                  |  | 15,077  |                               |  |  | 12,255          |  |  |               | 1,730  |  |             |  | 1,730  |                 |  |  | 1,498         |  |  |              | 872     |  |  |  | 872     |  |  |  | 660     | 
|                                    |  |                      |         |  |                  |  |         |                               |  |  |                 |  |  |               |        |  |             |  |        |                 |  |  |               |  |  |              |         |  |  |  |         |  |  |  |         | 
|Total Proved Reserves               |  |                      | 80,893  |  |                  |  | 80,746  |                               |  |  | 67,527          |  |  |               | 15,143 |  |             |  | 15,138 |                 |  |  | 13,283        |  |  |              | 20,761  |  |  |  | 20,726  |  |  |  | 14,941  | 
|Probable Reserves                   |  |                      | 28,918  |  |                  |  | 28,873  |                               |  |  | 24,015          |  |  |               | 11,206 |  |             |  | 11,205 |                 |  |  | 10,336        |  |  |              | 8,067   |  |  |  | 8,057   |  |  |  | 6,043   | 
|                                    |  |                      |         |  |                  |  |         |                               |  |  |                 |  |  |               |        |  |             |  |        |                 |  |  |               |  |  |              |         |  |  |  |         |  |  |  |         | 
|Total Proved Plus Probable Reserves |  |                      | 109,811 |  |                  |  | 109,620 |                               |  |  | 91,542          |  |  |               | 26,349 |  |             |  | 26,343 |                 |  |  | 23,619        |  |  |              | 28,827  |  |  |  | 28,783  |  |  |  | 20,983  | 
|                                    |  |                      |         |  |                  |  |         |                               |  |  |                 |  |  |               |        |  |             |  |        |                 |  |  |               |  |  |              |         |  |  |  |         |  |  |  |         | 
|                                    |  |                      |        
|                                    |  | Natural Gas          |         |  | Coal Bed Methane |  |         | Total Oil Equivalent
Basis(3) | 
|                                    |  | CompanyInterest      |         |  | GrossInterest    |  |         | Net Interest                  |  |  | CompanyInterest |  |  | GrossInterest |        |  | NetInterest |  |        | CompanyInterest |  |  | GrossInterest |  |  | Net Interest |        
|Reserves Category                   |  | (MMcf)               |         |  | (MMcf)           |  |         | (MMcf)                        |  |  | (MMcf)          |  |  | (MMcf)        |        |  | (MMcf)      |  |        | (Mboe)          |  |  | (Mboe)        |  |  | (Mboe)       |        
|Proved Reserves                     |  |                      |         |  |                  |  |         |                               |  |  |                 |  |  |               |        |  |             |  |        |                 |  |  |               |  |  |              |         |  |  |  |         |  |  |  |         | 
|Proved Developed Producing          |  |                      | 462,175 |  |                  |  | 459,940 |                               |  |  | 399,088         |  |  |               | 23,102 |  |             |  | 22,810 |                 |  |  | 21,419        |  |  |              | 176,972 |  |  |  | 176,374 |  |  |  | 149,084 | 
|Proved Developed Non-Producing      |  |                      | 20,922  |  |                  |  | 20,832  |                               |  |  | 17,268          |  |  |               | 1,905  |  |             |  | 1,894  |                 |  |  | 1,608         |  |  |              | 6,821   |  |  |  | 6,803   |  |  |  | 5,485   | 
|Proved Undeveloped                  |  |                      | 50,602  |  |                  |  | 50,602  |                               |  |  | 44,926          |  |  |               | 23,626 |  |             |  | 23,559 |                 |  |  | 20,242        |  |  |              | 30,058  |  |  |  | 30,040  |  |  |  | 25,274  | 
|                                    |  |                      |         |  |                  |  |         |                               |  |  |                 |  |  |               |        |  |             |  |        |                 |  |  |               |  |  |              |         |  |  |  |         |  |  |  |         | 
|Total Proved Reserves               |  |                      | 533,699 |  |                  |  | 531,374 |                               |  |  | 461,281         |  |  |               | 48,633 |  |             |  | 48,262 |                 |  |  | 43,269        |  |  |              | 213,852 |  |  |  | 213,216 |  |  |  | 179,843 | 
|Probable Reserves                   |  |                      | 268,528 |  |                  |  | 267,871 |                               |  |  | 233,465         |  |  |               | 11,740 |  |             |  | 11,648 |                 |  |  | 10,575        |  |  |              | 94,903  |  |  |  | 94,722  |  |  |  | 81,067  | 
|                                    |  |                      |         |  |                  |  |         |                               |  |  |                 |  |  |               |        |  |             |  |        |                 |  |  |               |  |  |              |         |  |  |  |         |  |  |  |         | 
|Total Proved Plus Probable Reserves |  |                      | 802,227 |  |                  |  | 799,245 |                               |  |  | 694,746         |  |  |               | 60,373 |  |             |  | 59,911 |                 |  |  | 53,844        |  |  |              | 308,754 |  |  |  | 307,938 |  |  |  | 260,910 | 
|                                    |  |                      |         |  |                  |  |         |                               |  |  |                 |  |  |               |        |  |             |  |        |                 |  |  |               |  |  |              |         |  |  |  |         |  |  |  |         | 

Notes:



|(1) | Constant prices are shown under the heading Pricing Assumptions.
|--- | ------------------------------------------------------------------

|(2) | Includes 6,348 Mbbl of Company Interest heavy oil Probable Reserves for the Lindbergh oil sands property in the GLJ Report.
|--- | ---------------------------------------------------------------------------------------------------------------------------

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



- 17 -



---

##### Table of Contents

Summary of Net Present Value

of Future Net Revenue

as of December 31, 2010

Before and After Income Tax

(Constant Prices and Costs)(1)



|                                    |  |                                           |       |  |                                                           |  |       |       |  |  |       |  |  |       |       |  |       |  |       |        |  |  |       |  |  |  |      | 
|----------------------------------- |  | ----------------------------------------- | ----- |  | --------------------------------------------------------- |  | ----- | ----- |  |  | ----- |  |  | ----- | ----- |  | ----- |  | ----- | ------ |  |  | ----- |  |  |  | ---- | 
|                                    |  | Before Income TaxesDiscounted At (%/Year) |       |  | Unit ValueBefore Income TaxesDiscounted at 10%/Year(2)(3) | 
|                                    |  | 0%                                        |       |  | 5%                                                        |  |       | 10%   |  |  | 15%   |  |  | 20%   |       |  |       |  |       |        | 
|Reserves Category                   |  | ($MM)                                     |       |  | ($MM)                                                     |  |       | ($MM) |  |  | ($MM) |  |  | ($MM) |       |  | $/boe |  |       | $/Mcfe | 
|Proved Reserves                     |  |                                           |       |  |                                                           |  |       |       |  |  |       |  |  |       |       |  |       |  |       |        |  |  |       |  |  |  |      | 
|Proved Developed Producing          |  |                                           | 3,733 |  |                                                           |  | 2,893 |       |  |  | 2,382 |  |  |       | 2,039 |  |       |  | 1,793 |        |  |  | 15.98 |  |  |  | 2.66 | 
|Proved Developed Non-Producing      |  |                                           | 114   |  |                                                           |  | 74    |       |  |  | 52    |  |  |       | 39    |  |       |  | 31    |        |  |  | 9.55  |  |  |  | 1.59 | 
|Proved Undeveloped                  |  |                                           | 612   |  |                                                           |  | 331   |       |  |  | 183   |  |  |       | 99    |  |       |  | 47    |        |  |  | 7.25  |  |  |  | 1.21 | 
|                                    |  |                                           |       |  |                                                           |  |       |       |  |  |       |  |  |       |       |  |       |  |       |        |  |  |       |  |  |  |      | 
|Total Proved Reserves               |  |                                           | 4,459 |  |                                                           |  | 3,297 |       |  |  | 2,618 |  |  |       | 2,177 |  |       |  | 1,871 |        |  |  | 14.56 |  |  |  | 2.43 | 
|Probable Reserves                   |  |                                           | 1,971 |  |                                                           |  | 1,089 |       |  |  | 687   |  |  |       | 469   |  |       |  | 337   |        |  |  | 8.47  |  |  |  | 1.41 | 
|                                    |  |                                           |       |  |                                                           |  |       |       |  |  |       |  |  |       |       |  |       |  |       |        |  |  |       |  |  |  |      | 
|Total Proved Plus Probable Reserves |  |                                           | 6,431 |  |                                                           |  | 4,386 |       |  |  | 3,304 |  |  |       | 2,646 |  |       |  | 2,208 |        |  |  | 12.66 |  |  |  | 2.11 | 
|                                    |  |                                           |       |  |                                                           |  |       |       |  |  |       |  |  |       |       |  |       |  |       |        |  |  |       |  |  |  |      | 



|                                    |  |                                             |       |  |       |  |       |       |  |  |       |  |  |       |       |  |  |  |       | 
|----------------------------------- |  | ------------------------------------------- | ----- |  | ----- |  | ----- | ----- |  |  | ----- |  |  | ----- | ----- |  |  |  | ----- | 
|                                    |  | After Income TaxesDiscounted At
(%/Year)(4) |      
|                                    |  | 0%                                          |       |  | 5%    |  |       | 10%   |  |  | 15%   |  |  | 20%   |      
|Reserves Category                   |  | ($MM)                                       |       |  | ($MM) |  |       | ($MM) |  |  | ($MM) |  |  | ($MM) |      
|Proved Reserves                     |  |                                             |       |  |       |  |       |       |  |  |       |  |  |       |       |  |  |  |       | 
|Proved Developed Producing          |  |                                             | 3,638 |  |       |  | 2,895 |       |  |  | 2,374 |  |  |       | 1,996 |  |  |  | 1,713 | 
|Proved Developed Non-Producing      |  |                                             | 89    |  |       |  | 59    |       |  |  | 41    |  |  |       | 29    |  |  |  | 21    | 
|Proved Undeveloped                  |  |                                             | 471   |  |       |  | 259   |       |  |  | 134   |  |  |       | 60    |  |  |  | 15    | 
|                                    |  |                                             |       |  |       |  |       |       |  |  |       |  |  |       |       |  |  |  |       | 
|Total Proved Reserves               |  |                                             | 4,198 |  |       |  | 3,213 |       |  |  | 2,549 |  |  |       | 2,085 |  |  |  | 1,749 | 
|Probable Reserves                   |  |                                             | 1,459 |  |       |  | 834   |       |  |  | 503   |  |  |       | 320   |  |  |  | 214   | 
|                                    |  |                                             |       |  |       |  |       |       |  |  |       |  |  |       |       |  |  |  |       | 
|Total Proved Plus Probable Reserves |  |                                             | 5,657 |  |       |  | 4,047 |       |  |  | 3,052 |  |  |       | 2,405 |  |  |  | 1,963 | 
|                                    |  |                                             |       |  |       |  |       |       |  |  |       |  |  |       |       |  |  |  |       | 

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 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 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.
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



- 18 -



---

##### Table of Contents

Additional Information Concerning

Future Net Revenue

(undiscounted)

as of December 31, 2010

(Constant Prices and Costs)(1)



|                                    |  |         |        |  |              |  |       |                |  |  |                  |  |  |                     |     |  |                                       |  |     |            |  |  |                                     |  |  |  |     |  |  |  |       | 
|----------------------------------- |  | ------- | ------ |  | ------------ |  | ----- | -------------- |  |  | ---------------- |  |  | ------------------- | --- |  | ------------------------------------- |  | --- | ---------- |  |  | ----------------------------------- |  |  |  | --- |  |  |  | ----- | 
|                                    |  | Revenue |        |  | Royalties(2) |  |       | OperatingCosts |  |  | DevelopmentCosts |  |  | AbandonmentCosts(3) |     |  | Future NetRevenue
Before
Income Taxes |  |     | Income Tax |  |  | Future netRevenue AfterIncome Taxes | 
|Reserves Category                   |  | ($MM)   |        |  | ($MM)        |  |       | ($MM)          |  |  | ($MM)            |  |  | ($MM)               |     |  | ($MM)                                 |  |     | ($MM)      |  |  | ($MM)                               | 
|Proved Reserves                     |  |         | 10,759 |  |              |  | 1,778 |                |  |  | 3,778            |  |  |                     | 553 |  |                                       |  | 191 |            |  |  | 4,459                               |  |  |  | 261 |  |  |  | 4,198 | 
|Total Proved Plus Probable Reserves |  |         | 15,197 |  |              |  | 2,469 |                |  |  | 5,111            |  |  |                     | 988 |  |                                       |  | 198 |            |  |  | 6,431                               |  |  |  | 774 |  |  |  | 5,657 | 

Notes:



|(1) | Constant prices are shown under the heading Pricing Assumptions.
|--- | ------------------------------------------------------------------

|(2) | Crown royalties payable to the provinces of Alberta, British Columbia, Saskatchewan and Nova Scotia and any freehold and over-riding royalties payable. This includes
the impact of the New Royalty Framework implemented by the Government of Alberta on January 1, 2009, the optional Transitional Royalty and any drilling incentive programs still in effect.
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|(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, 2010

(Constant Prices and Costs)(1)



|                      |  |                                                                                  |         |                                                                 |       |          |                  |  |       |  |  |  |      | 
|--------------------- |  | -------------------------------------------------------------------------------- | ------- | --------------------------------------------------------------- | ----- | -------- | ---------------- |  | ----- |  |  |  | ---- | 
|Reserves Category     |  | Production Group                                                                 |         | Future NetRevenue Before IncomeTaxes(discounted at 10%/yr)($MM) |       |          | Unit Value(4)(5) | 
|                      |  |                                                                                  | ($/boe) |                                                                 |       | ($/Mcfe) |                 
|Total Proved Reserves |  | Light and Medium Crude Oil (including solution gas and other by-products)(2)     |         |                                                                 | 1,581 |          |                  |  | 19.29 |  |  |  | 3.22 | 
|                      |  | Heavy Crude Oil (including solution gas and other by-products)(2)                |         |                                                                 | 321   |          |                  |  | 21.66 |  |  |  | 3.61 | 
|                      |  | Natural Gas (including by-products but excluding solution gas from oil wells)(3) |         |                                                                 | 689   |          |                  |  | 9.08  |  |  |  | 1.51 | 
|                      |  | Non-conventional Oil & Gas Activities                                            |         |                                                                 | 27    |          |                  |  | 3.69  |  |  |  | 0.62 | 
|                      |  |                                                                                  |         |                                                                 |       |          |                  |  |       |  |  |  |      | 
|                      |  | Total                                                                            |         |                                                                 | 2,618 |          |                  |  | 14.56 |  |  |  | 2.43 | 
|Total Proved Plus     |  | Light and Medium Crude Oil (including solution gas and other by-products)(2)     |         |                                                                 | 1,963 |          |                  |  | 17.72 |  |  |  | 2.95 | 
|Probable Reserves     |  | Heavy Crude Oil (including solution gas and other by-products)(2)                |         |                                                                 | 397   |          |                  |  | 15.46 |  |  |  | 2.58 | 
|                      |  | Natural Gas (including by-products but excluding solution gas from oil wells)(3) |         |                                                                 | 909   |          |                  |  | 7.87  |  |  |  | 1.31 | 
|                      |  | Non-conventional Oil & Gas Activities                                            |         |                                                                 | 36    |          |                  |  | 4.00  |  |  |  | 0.67 | 
|                      |  |                                                                                  |         |                                                                 |       |          |                  |  |       |  |  |  |      | 
|                      |  | Total                                                                            |         |                                                                 | 3,304 |          |                  |  | 12.66 |  |  |  | 2.11 | 

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 Mcfe are based on our net reserves.
|--- | --------------------------------------------------------------------------------------

|(5) | Natural gas has been converted to barrels of oil equivalent on the basis of six 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 Mcf of natural gas.
|--- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



- 19 -



---

##### Table of Contents

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, 2011 price forecast as referred to in the GLJ Report.



|           |  |                    |        |  |                          |  |        |                        |  |  |                       |  |  |                |        |  |            |  |        |            |  |  |              |  |  |                   |        |  |                 |  |        |  |  |  |     |  |  |  |      | 
|---------- |  | ------------------ | ------ |  | ------------------------ |  | ------ | ---------------------- |  |  | --------------------- |  |  | -------------- | ------ |  | ---------- |  | ------ | ---------- |  |  | ------------ |  |  | ----------------- | ------ |  | --------------- |  | ------ |  |  |  | --- |  |  |  | ---- | 
|           |  | Oil                |        |  | Natural Gas              |  |        | Natural Gas
Liquids(1) |  |  |                       |  |  |                |       
|           |  | WTICushingOklahoma |        |  | EdmontonPar Price
40°API |  |        | CromerMedium29.3°API   |  |  | HardistyHeavy 12° API |  |  | AECO Gas Price |        |  | Propane    |  |        | Butane     |  |  | PentanesPlus |  |  | InflationRates(2) |        |  | ExchangeRate(3) | 
|Year       |  | (US$/bbl)          |        |  | (Cdn$/bbl)               |  |        | (Cdn$/bbl)             |  |  | (Cdn$/bbl)            |  |  | (Cdn$/MMBtu)   |        |  | (Cdn$/bbl) |  |        | (Cdn$/bbl) |  |  | (Cdn$/bbl)   |  |  | (%/Year)          |        |  | (US$/Cdn$)      | 
|2010(4)    |  |                    | 79.42  |  |                          |  | 78.02  |                        |  |  | 73.81                 |  |  |                | 60.62  |  |            |  | 4.17   |            |  |  | 46.87        |  |  |                   | 65.59  |  |                 |  | 84.04  |  |  |  |    |  |  |  |     | 
|2011       |  |                    | 88.00  |  |                          |  | 86.22  |                        |  |  | 82.78                 |  |  |                | 68.79  |  |            |  | 4.16   |            |  |  | 54.32        |  |  |                   | 67.26  |  |                 |  | 90.54  |  |  |  | 2.0 |  |  |  | 0.98 | 
|2012       |  |                    | 89.00  |  |                          |  | 89.29  |                        |  |  | 83.04                 |  |  |                | 68.33  |  |            |  | 4.74   |            |  |  | 56.25        |  |  |                   | 68.75  |  |                 |  | 91.96  |  |  |  | 2.0 |  |  |  | 0.98 | 
|2013       |  |                    | 90.00  |  |                          |  | 90.92  |                        |  |  | 83.64                 |  |  |                | 67.03  |  |            |  | 5.31   |            |  |  | 57.28        |  |  |                   | 70.01  |  |                 |  | 92.74  |  |  |  | 2.0 |  |  |  | 0.98 | 
|2014       |  |                    | 92.00  |  |                          |  | 92.96  |                        |  |  | 84.59                 |  |  |                | 67.84  |  |            |  | 5.77   |            |  |  | 58.56        |  |  |                   | 71.58  |  |                 |  | 94.82  |  |  |  | 2.0 |  |  |  | 0.98 | 
|2015       |  |                    | 95.17  |  |                          |  | 96.19  |                        |  |  | 87.54                 |  |  |                | 70.23  |  |            |  | 6.22   |            |  |  | 60.60        |  |  |                   | 74.07  |  |                 |  | 98.12  |  |  |  | 2.0 |  |  |  | 0.98 | 
|2016       |  |                    | 97.55  |  |                          |  | 98.62  |                        |  |  | 89.75                 |  |  |                | 72.03  |  |            |  | 6.53   |            |  |  | 62.13        |  |  |                   | 75.94  |  |                 |  | 100.59 |  |  |  | 2.0 |  |  |  | 0.98 | 
|2017       |  |                    | 100.26 |  |                          |  | 101.39 |                        |  |  | 92.26                 |  |  |                | 74.08  |  |            |  | 6.76   |            |  |  | 63.87        |  |  |                   | 78.07  |  |                 |  | 103.42 |  |  |  | 2.0 |  |  |  | 0.98 | 
|2018       |  |                    | 102.74 |  |                          |  | 103.92 |                        |  |  | 94.57                 |  |  |                | 75.95  |  |            |  | 6.90   |            |  |  | 65.47        |  |  |                   | 80.02  |  |                 |  | 106.00 |  |  |  | 2.0 |  |  |  | 0.98 | 
|2019       |  |                    | 105.45 |  |                          |  | 106.68 |                        |  |  | 97.08                 |  |  |                | 78.00  |  |            |  | 7.06   |            |  |  | 67.21        |  |  |                   | 82.15  |  |                 |  | 108.82 |  |  |  | 2.0 |  |  |  | 0.98 | 
|2020       |  |                    | 107.56 |  |                          |  | 108.84 |                        |  |  | 99.04                 |  |  |                | 79.59  |  |            |  | 7.21   |            |  |  | 68.57        |  |  |                   | 83.80  |  |                 |  | 111.01 |  |  |  | 2.0 |  |  |  | 0.98 | 
|Thereafter |  |                    | +2%/yr |  |                          |  | +2%/yr |                        |  |  | +2%/yr                |  |  |                | +2%/yr |  |            |  | +2%/yr |            |  |  | +2%/yr       |  |  |                   | +2%/yr |  |                 |  | +2%/yr |  |  |  | 2.0 |  |  |  | 0.98 | 

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 weighted average historical prices for 2010.
|--- | ---------------------------------------------------

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 2010 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) |  |  |                       |  |  |                |      
|                    |  | WTICushingOklahoma |       |  | EdmontonPar Price40° API |  |       | CromerMedium29.3° API  |  |  | HardistyHeavy 12° API |  |  | AECO Gas Price |       |  | Propane    |  |      | Butane     |  |  | PentanesPlus |  |  | InflationRate |       |  | ExchangeRate(2) | 
|Year                |  | (US$/bbl)          |       |  | (Cdn$/bbl)               |  |       | (Cdn$/bbl)             |  |  | (Cdn$/bbl)            |  |  | (Cdn$/MMBtu)   |       |  | (Cdn$/bbl) |  |      | (Cdn$/bbl) |  |  | (Cdn$/bbl)   |  |  | (%/Year)      |       |  | (US$/Cdn$)      | 
|2011 and thereafter |  |                    | 79.40 |  |                          |  | 78.23 |                        |  |  | 74.21                 |  |  |                | 61.72 |  |            |  | 4.06 |            |  |  | 45.10        |  |  |               | 66.10 |  |                 |  | 84.57 |  |  |  | 0.0 | % |  |  | 0.9672 | 

Notes:



|(1) | FOB Edmonton.
|--- | -------------

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



- 20 -



---

##### Table of Contents

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, 2010, presented using forecast prices and costs. All
reserves are located in Canada.

Reserves Reconciliation

By Principal Product Type

(Forecast Prices and Costs)



|                    |  |                      |         |   |                  |  |         |                               |  |  |             |   |  |               |        |   |                           |  |        |             |  |  |               |   |  |                           |         |   |  |  |        |   |  |  |         |  
|------------------- |  | -------------------- | ------- | - | ---------------- |  | ------- | ----------------------------- |  |  | ----------- | - |  | ------------- | ------ | - | ------------------------- |  | ------ | ----------- |  |  | ------------- | - |  | ------------------------- | ------- | - |  |  | ------ | - |  |  | ------- | -
|                    |  | Light and Medium Oil |         |   | Heavy Oil        |  |         | Natural Gas Liquids           | 
|                    |  | GrossProved          |         |   | GrossProbable    |  |         | Gross ProvedPlus Probable     |  |  | GrossProved |   |  | GrossProbable |        |   | Gross ProvedPlus Probable |  |        | GrossProved |  |  | GrossProbable |   |  | Gross ProvedPlus Probable |        
|                    |  | (Mbbl)               |         |   | (Mbbl)           |  |         | (Mbbl)                        |  |  | (Mbbl)      |   |  | (Mbbl)        |        |   | (Mbbl)                    |  |        | (Mbbl)      |  |  | (Mbbl)        |   |  | (Mbbl)                    |        
|December 31, 2009   |  |                      | 82,659  |   |                  |  | 29,400  |                               |  |  | 112,059     |   |  |               | 16,347 |   |                           |  | 11,367 |             |  |  | 27,713        |   |  |                           | 21,384  |   |  |  | 8,091  |   |  |  | 29,475  |  
|                    |  |                      |         |   |                  |  |         |                               |  |  |             |   |  |               |        |   |                           |  |        |             |  |  |               |   |  |                           |         |   |  |  |        |   |  |  |         |  
|Technical Revisions |  |                      | 2,582   |   |                  |  | (459    | )                             |  |  | 2,124       |   |  |               | 918    |   |                           |  | (199   | )           |  |  | 719           |   |  |                           | 912     |   |  |  | (509   | ) |  |  | 403     |  
|Discoveries         |  |                      | 88      |   |                  |  | 29      |                               |  |  | 117         |   |  |               |       |   |                           |  | 18     |             |  |  | 18            |   |  |                           | 21      |   |  |  | 7      |   |  |  | 28      |  
|Extensions          |  |                      | 1,957   |   |                  |  | 444     |                               |  |  | 2,401       |   |  |               | 53     |   |                           |  | 26     |             |  |  | 79            |   |  |                           | 1,794   |   |  |  | 241    |   |  |  | 2,035   |  
|Infill Drilling     |  |                      | 727     |   |                  |  | 133     |                               |  |  | 860         |   |  |               | 30     |   |                           |  | 32     |             |  |  | 62            |   |  |                           | 64      |   |  |  | 11     |   |  |  | 75      |  
|Improved Recovery   |  |                      | 779     |   |                  |  | (555    | )                             |  |  | 225         |   |  |               | 363    |   |                           |  | (10    | )           |  |  | 353           |   |  |                           | 17      |   |  |  | 2      |   |  |  | 19      |  
|Acquisitions        |  |                      | 274     |   |                  |  | 60      |                               |  |  | 334         |   |  |               |       |   |                           |  |       |             |  |  |              |   |  |                           | 505     |   |  |  | 374    |   |  |  | 878     |  
|Dispositions        |  |                      | (83     | ) |                  |  | (29     | )                             |  |  | (112        | ) |  |               |       |   |                           |  |       |             |  |  |              |   |  |                           | (3      | ) |  |  | (1     | ) |  |  | (4      | )
|Economic Factors    |  |                      |        |   |                  |  |        |                               |  |  |            |   |  |               |       |   |                           |  |       |             |  |  |              |   |  |                           |        |   |  |  |       |   |  |  |        |  
|Production          |  |                      | (7,907  | ) |                  |  |        |                               |  |  | (7,907      | ) |  |               | (2,478 | ) |                           |  |       |             |  |  | (2,478        | ) |  |                           | (3,476  | ) |  |  |       |   |  |  | (3,476  | )
|                    |  |                      |         |   |                  |  |         |                               |  |  |             |   |  |               |        |   |                           |  |        |             |  |  |               |   |  |                           |         |   |  |  |        |   |  |  |         |  
|December 31, 2010   |  |                      | 81,077  |   |                  |  | 29,024  |                               |  |  | 110,101     |   |  |               | 15,232 |   |                           |  | 11,233 |             |  |  | 26,465        |   |  |                           | 21,216  |   |  |  | 8,216  |   |  |  | 29,432  |  
|                    |  |                      |         |   |                  |  |         |                               |  |  |             |   |  |               |        |   |                           |  |        |             |  |  |               |   |  |                           |         |   |  |  |        |   |  |  |         |  
|                    |  |                      |        
|                    |  | Natural Gas          |         |   | Coal Bed Methane |  |         | Total Oil Equivalent
Basis(1) | 
|                    |  | GrossProved          |         |   | GrossProbable    |  |         | Gross ProvedPlus Probable     |  |  | GrossProved |   |  | GrossProbable |        |   | Gross ProvedPlus Probable |  |        | GrossProved |  |  | GrossProbable |   |  | Gross ProvedPlus Probable |        
|                    |  | (MMcf)               |         |   | (MMcf)           |  |         | (MMcf)                        |  |  | (MMcf)      |   |  | (MMcf)        |        |   | (MMcf)                    |  |        | (Mboe)      |  |  | (Mboe)        |   |  | (Mboe)                    |        
|December 31, 2009   |  |                      | 529,897 |   |                  |  | 169,278 |                               |  |  | 699,175     |   |  |               | 41,090 |   |                           |  | 11,037 |             |  |  | 52,127        |   |  |                           | 215,554 |   |  |  | 78,911 |   |  |  | 294,465 |  
|                    |  |                      |         |   |                  |  |         |                               |  |  |             |   |  |               |        |   |                           |  |        |             |  |  |               |   |  |                           |         |   |  |  |        |   |  |  |         |  
|Technical Revisions |  |                      | 21,671  |   |                  |  | (16,808 | )                             |  |  | 4,864       |   |  |               | 2,841  |   |                           |  | (1,432 | )           |  |  | 1,408         |   |  |                           | 8,497   |   |  |  | (4,208 | ) |  |  | 4,289   |  
|Discoveries         |  |                      | 231     |   |                  |  | 77      |                               |  |  | 308         |   |  |               |       |   |                           |  |       |             |  |  |              |   |  |                           | 148     |   |  |  | 66     |   |  |  | 214     |  
|Extensions          |  |                      | 20,668  |   |                  |  | 54,462  |                               |  |  | 75,130      |   |  |               | 2,105  |   |                           |  | 1,256  |             |  |  | 3,361         |   |  |                           | 7,599   |   |  |  | 9,997  |   |  |  | 17,596  |  
|Infill Drilling     |  |                      | 2,013   |   |                  |  | 5,047   |                               |  |  | 7,060       |   |  |               | 10,752 |   |                           |  | 2,036  |             |  |  | 12,787        |   |  |                           | 2,949   |   |  |  | 1,356  |   |  |  | 4,305   |  
|Improved Recovery   |  |                      | 366     |   |                  |  | 42      |                               |  |  | 408         |   |  |               |       |   |                           |  |       |             |  |  |              |   |  |                           | 1,219   |   |  |  | (556   | ) |  |  | 664     |  
|Acquisitions        |  |                      | 64,401  |   |                  |  | 67,448  |                               |  |  | 131,849     |   |  |               |       |   |                           |  |       |             |  |  |              |   |  |                           | 11,512  |   |  |  | 11,675 |   |  |  | 23,187  |  
|Dispositions        |  |                      | (222    | ) |                  |  | (58     | )                             |  |  | (280        | ) |  |               | (56    | ) |                           |  | (29    | )           |  |  | (85           | ) |  |                           | (132    | ) |  |  | (45    | ) |  |  | (177    | )
|Economic Factors    |  |                      |        |   |                  |  |        |                               |  |  |            |   |  |               |       |   |                           |  |       |             |  |  |              |   |  |                           |        |   |  |  |       |   |  |  |        |  
|Production          |  |                      | (74,962 | ) |                  |  |        |                               |  |  | (74,962     | ) |  |               | (4,051 | ) |                           |  |       |             |  |  | (4,051        | ) |  |                           | (27,029 | ) |  |  |       |   |  |  | (27,029 | )
|                    |  |                      |         |   |                  |  |         |                               |  |  |             |   |  |               |        |   |                           |  |        |             |  |  |               |   |  |                           |         |   |  |  |        |   |  |  |         |  
|December 31, 2010   |  |                      | 564,062 |   |                  |  | 279,489 |                               |  |  | 843,551     |   |  |               | 52,680 |   |                           |  | 12,866 |             |  |  | 65,547        |   |  |                           | 220,316 |   |  |  | 97,198 |   |  |  | 317,514 |  
|                    |  |                      |         |   |                  |  |         |                               |  |  |             |   |  |               |        |   |                           |  |        |             |  |  |               |   |  |                           |         |   |  |  |        |   |  |  |         |  

Note:



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



- 21 -



---

##### Table of Contents

At December 31 2010, Company Interest Total Proved Plus Probable Reserves at forecast prices and costs
were 318.4 MMboe as compared to 295.7 MMboe reported at year end 2009. The following additional GLJ reserves reconciliation is presented for year end December 31, 2010.

Company Interest Reserves Reconciliation

on Total Oil Equivalent Basis

(Forecast Prices and Costs)



|                    |  |                                    |         |   |                 |  |         |                             |  |  |         |  
|------------------- |  | ---------------------------------- | ------- | - | --------------- |  | ------- | --------------------------- |  |  | ------- | -
|                    |  | Proved DevelopedProducing Reserves |         |   | Proved Reserves |  |         | Proved PlusProbable Reserve | 
|                    |  | (Mboe)(1)                          |         |   | (Mboe)(1)       |  |         | (Mboe)(1)                   | 
|December 31, 2009   |  |                                    | 183,834 |   |                 |  | 216,554 |                             |  |  | 295,734 |  
|                    |  |                                    |         |   |                 |  |         |                             |  |  |         |  
|Technical Revisions |  |                                    | 11,121  |   |                 |  | 8,574   |                             |  |  | 4,328   |  
|Discoveries         |  |                                    |        |   |                 |  | 148     |                             |  |  | 214     |  
|Extensions          |  |                                    | 9,197   |   |                 |  | 7,607   |                             |  |  | 17,606  |  
|Infill Drilling     |  |                                    | 1,467   |   |                 |  | 2,957   |                             |  |  | 4,315   |  
|Improved Recovery   |  |                                    | 2,438   |   |                 |  | 1,221   |                             |  |  | 664     |  
|Acquisitions        |  |                                    | 3,115   |   |                 |  | 11,534  |                             |  |  | 23,214  |  
|Dispositions        |  |                                    | (244    | ) |                 |  | (302    | )                           |  |  | (383    | )
|Economic Factors    |  |                                    |        |   |                 |  |        |                             |  |  |        |  
|Production          |  |                                    | (27,264 | ) |                 |  | (27,264 | )                           |  |  | (27,264 | )
|                    |  |                                    |         |   |                 |  |         |                             |  |  |         |  
|December 31, 2010   |  |                                    | 183,664 |   |                 |  | 221,028 |                             |  |  | 318,429 |  
|                    |  |                                    |         |   |                 |  |         |                             |  |  |         |  

Note:



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

Significant factors bearing on the reserves reconciliation were as follows:



| |  |  | Reserve additions from drilling activity, improved recovery and technical revisions replaced 75 percent and 99 percent of 2010 production for
Total Proved and Total Proved Plus Probable Reserves, respectively. Based on all changes, including acquisitions and dispositions, reserve replacement was 116 percent and 183 percent for Total Proved and Proved Plus Probable Reserves,
respectively.
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | New reserve additions for development activity during 2010 amounted to 22.8 MMboe of Total Proved Plus Probable Reserves. Most significant were
drilling extensions in our resource plays at Groundbirch, Carson Creek and Harmattan. 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 at Carson Creek, Harmattan and Deer Mountain.
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Acquisitions net of some minor dispositions, resulted in an increase of 22.8 MMboe to Proved Plus Probable Reserves. This was almost entirely from
the acquisition of Monterey Exploration Ltd. with the large majority of the reserves associated with the Groundbirch Montney resource play.
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

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 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 related to the Weyburn, Judy Creek and Swan Hills EOR projects, which have staged development plans, and the Groundbirch gas and Lindbergh oil sands
projects which will be drilled up over time to keep the respective facilities full.



- 22 -



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##### Table of Contents

Company Gross Reserves

First Attributed by Year(1)

Proved Undeveloped Reserves



|                              |  |                          |        |  |                  |  |        |                   |  |  |                        |  |  |                           |       |  |                               |  |        |                 |  |  |                  |  |  |                 |        |  |                  |  |        |                 |  |  |                  |  |  |  |       |  |  |  |        |  |  |  |        | 
|----------------------------- |  | ------------------------ | ------ |  | ---------------- |  | ------ | ----------------- |  |  | ---------------------- |  |  | ------------------------- | ----- |  | ----------------------------- |  | ------ | --------------- |  |  | ---------------- |  |  | --------------- | ------ |  | ---------------- |  | ------ | --------------- |  |  | ---------------- |  |  |  | ----- |  |  |  | ------ |  |  |  | ------ | 
|                              |  | Light & Medium Oil(Mbbl) |        |  | Heavy Oil(Mbbl)  |  |        | Natural
Gas(MMcf) |  |  | Coal Bed Methane(MMcf) |  |  | Natural Gas Liquids(Mbbl) |       |  | Total Oil
Equivalent(Mboe)(2) | 
|                              |  | FirstAttributed          |        |  | Total atyear-end |  |        | FirstAttributed   |  |  | Total atyear-end       |  |  | FirstAttributed           |       |  | Total atyear-end              |  |        | FirstAttributed |  |  | Total atyear-end |  |  | FirstAttributed |        |  | Total atyear-end |  |        | FirstAttributed |  |  | Total atyear-end | 
|Prior                         |  |                          | 18,985 |  |                  |  | 18,985 |                   |  |  | 2,194                  |  |  |                           | 2,194 |  |                               |  | 50,224 |                 |  |  | 50,224           |  |  |                 | 13,911 |  |                  |  | 13,911 |                 |  |  | 1,361            |  |  |  | 1,361 |  |  |  | 33,229 |  |  |  | 33,229 | 
|2008                          |  |                          | 1,000  |  |                  |  | 17,029 |                   |  |  | 382                    |  |  |                           | 1,676 |  |                               |  | 3,513  |                 |  |  | 48,311           |  |  |                 | 1,858  |  |                  |  | 10,372 |                 |  |  | 125              |  |  |  | 1,120 |  |  |  | 2,402  |  |  |  | 29,606 | 
|2009                          |  |                          | 1,347  |  |                  |  | 16,351 |                   |  |  | 130                    |  |  |                           | 1,846 |  |                               |  | 2,778  |                 |  |  | 30,359           |  |  |                 | 10,140 |  |                  |  | 19,184 |                 |  |  | 209              |  |  |  | 1,190 |  |  |  | 3,840  |  |  |  | 27,644 | 
|2010                          |  |                          | 1,386  |  |                  |  | 15,077 |                   |  |  | 30                     |  |  |                           | 1,732 |  |                               |  | 30,017 |                 |  |  | 51,742           |  |  |                 | 10,435 |  |                  |  | 24,955 |                 |  |  | 516              |  |  |  | 878   |  |  |  | 8,674  |  |  |  | 30,470 | 
|                             
|Probable Undeveloped Reserves | 
|                              |  |                          |        |  |                  | 
|                              |  | Light & Medium Oil(Mbbl) |        |  | Heavy Oil(Mbbl)  |  |        | Natural
Gas(MMcf) |  |  | Coal Bed Methane(MMcf) |  |  | Natural Gas Liquids(Mbbl) |       |  | Total Oil
Equivalent(Mboe)(2) | 
|                              |  | FirstAttributed          |        |  | Total atyear-end |  |        | FirstAttributed   |  |  | Total atyear-end       |  |  | FirstAttributed           |       |  | Total atyear-end              |  |        | FirstAttributed |  |  | Total atyear-end |  |  | FirstAttributed |        |  | Total atyear-end |  |        | FirstAttributed |  |  | Total atyear-end | 
|Prior                         |  |                          | 13,497 |  |                  |  | 13,497 |                   |  |  | 2,269                  |  |  |                           | 2,269 |  |                               |  | 64,986 |                 |  |  | 64,986           |  |  |                 | 10,155 |  |                  |  | 10,155 |                 |  |  | 2,716            |  |  |  | 2,716 |  |  |  | 31,006 |  |  |  | 31,006 | 
|2008                          |  |                          | 1,850  |  |                  |  | 12,372 |                   |  |  | 6,997                  |  |  |                           | 7,857 |  |                               |  | 17,686 |                 |  |  | 68,222           |  |  |                 | 4,514  |  |                  |  | 7,948  |                 |  |  | 782              |  |  |  | 3,478 |  |  |  | 13,329 |  |  |  | 36,502 | 
|2009                          |  |                          | 1,565  |  |                  |  | 11,514 |                   |  |  | 68                     |  |  |                           | 7,853 |  |                               |  | 9,450  |                 |  |  | 37,134           |  |  |                 | 2,177  |  |                  |  | 5,178  |                 |  |  | 934              |  |  |  | 2,510 |  |  |  | 4,505  |  |  |  | 28,929 | 
|2010                          |  |                          | 708    |  |                  |  | 10,168 |                   |  |  | 50                     |  |  |                           | 7,613 |  |                               |  | 99,381 |                 |  |  | 145,695          |  |  |                 | 2,809  |  |                  |  | 6,318  |                 |  |  | 1,284            |  |  |  | 2,879 |  |  |  | 19,073 |  |  |  | 45,996 | 

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 Mcf of natural gas being equal to one barrel of oil.
|--- | ------------------------------------------------------------------------------------------------------------------------------------

Proved Undeveloped Reserves

Our Proved
Undeveloped Reserves comprise approximately 14 percent of the Company Interest Total Proved Reserves on a barrel of oil equivalency basis. Company Interest Proved Undeveloped Reserves of 30.5 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 miscible flood expansion and development drilling.

The Groundbirch
property, acquired in 2010, accounts for approximately 18 percent of our Proved Undeveloped Reserves. Drilling is forecast by GLJ to occur over the next five years to develop these reserves. Swan Hills miscible flood expansion, as well as some
infill drilling, comprises 14 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 2027. Similarly at Judy Creek, miscible flood development is forecast to continue until 2014 and accounts for another 14 percent of the Company Interest Proved Undeveloped Reserves. In the Weyburn Unit,
the Proved Undeveloped Reserves also amounts to 14 percent of the total, reflects the capital allocated to infill drilling and the CO2 miscible flood. Working interest partners have committed to a CO2 supply until 2016. Further development of
the flood area in the Weyburn Unit, from the existing 58 patterns to full development with 76 patterns in the proved case, is forecast to occur by 2014. Development of all 92 patterns in the probable case continues until 2016. Given
that CO2 injection is still in the early planning and pilot stages, no full scale CO2 miscible flood is being forecast at Judy Creek.

Our
ongoing CBM development requires further infill drilling and drilling extensions at Twining, Huxley and Fenn Big Valley. Because of the extensive land holdings, this is forecast to occur over the next five years and represents approximately 13
percent of the Proved Undeveloped Reserves. Multi-well shallow gas infill drilling programs are scheduled for 2011 and beyond at Monogram, Patricia and Dinosaur, which together contain four percent of the Company Interest Total Proved
Undeveloped Reserves. Ongoing development is scheduled in heavy oil properties where approximately four percent of Pengrowths Company Interest Proved Undeveloped Reserves are assigned to the waterflood expansion in East Bodo that is
forecast to occur in 2011. At Deer Mountain, waterflood optimization, drilling extensions and infill drilling scheduled over the next two years account for about three percent of the Company Interest 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 46.0 MMboe and represent about 14 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: Groundbirch (38 percent), Lindbergh (14 percent), Weyburn Unit (eight percent), Swan Hills Unit (five percent), Judy
Creek (four percent), Carson Creek



- 23 -



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##### Table of Contents

(three percent), and shallow gas (three percent). Probable Undeveloped Reserves are assigned at Groundbirch for the Montney gas play. Production commenced in December 2010 and drilling
extensions are forecast to occur over the next five years to keep the facility running at full capacity. At Lindbergh, Probable Undeveloped Reserves are assigned to a proposed oil sands SAGD pilot project. Facility design and procurement,
delineation drilling and other development work is underway with initial production planned for 2012.

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.



|                                                       |       |      |     |       |      |  |       |      |  |       |      |  |       |      |    |       |           |  |       |              |  |       |                  |  |  |  |       |  |  |  |     | 
|------------------------------------------------------ | ----- | ---- | --- | ----- | ---- |  | ----- | ---- |  | ----- | ---- |  | ----- | ---- | -- | ----- | --------- |  | ----- | ------------ |  | ----- | ---------------- |  |  |  | ----- |  |  |  | --- | 
|                                                       |       |      |     |       |      |  |       |      |  |       |      |  |       |      |    |       |           |  |       | Total        | 
|Reserve Category                                       |       | 2011 |     |       | 2012 |  |       | 2013 |  |       | 2014 |  |       | 2015 |    |       | Remainder |  |       | Undiscounted |  |       | Discountedat 10% | 
|                                                       | ($MM) |      |     | ($MM) |      |  | ($MM) |      |  | ($MM) |      |  | ($MM) |      |    | ($MM) |           |  | ($MM) |              |  | ($MM) |                 
|Proved Reserves (Constant Prices and Costs)            |       |      | 164 |       |      |  | 124   |      |  |       | 57   |  |       |      | 42 |       |           |  | 26    |              |  |       | 139              |  |  |  | 553   |  |  |  | 406 | 
|Proved Reserves (Forecast Prices and Costs)            |       |      | 164 |       |      |  | 126   |      |  |       | 59   |  |       |      | 45 |       |           |  | 28    |              |  |       | 180              |  |  |  | 603   |  |  |  | 424 | 
|Proved & Probable Reserves (Forecast Prices and Costs) |       |      | 281 |       |      |  | 225   |      |  |       | 146  |  |       |      | 82 |       |           |  | 42    |              |  |       | 303              |  |  |  | 1,079 |  |  |  | 760 | 

We expect to fund future development
costs with a combination of cash flow, debt and equity. There are no reserves that are expected to be limited in their recovery due to their cost of development. We have established a $400 million capital expenditure program for 2011 to fund
our land acquisition, development and exploration activities, including expenditures at our proposed Lindbergh oil sands SAGD pilot project.

Finding, Development and Acquisition Costs

Finding and Development Costs

During 2010, we spent $329.5 million, net of Alberta
drilling royalty credits, on development and optimization activities, which added 20.5 MMboe of Proved Reserves and 27.1 MMboe of Total Proved Plus Probable Reserves including revisions. The development and optimization activities exclude
$4.4 million in expenditures mainly for information technology projects in the Calgary office. The largest reserve additions were for drilling extensions at Groundbirch, Carson Creek and Harmattan.

In total, we participated in drilling 214 gross wells (128 net wells) with a 96 percent success rate.

Extensive development occurred in the Carson Creek Beaverhill Lake Unit during 2010. Following a nine well horizontal program in 2009, another seven
horizontal wells that were multi-stage fractured were drilled in 2010 in this liquids-rich gas reservoir. A successful well was also drilled off the main pool just outside the unit which will lead to further delineation and development drilling in
2011.

In the Harmattan area, we drilled 12 successful horizontal wells resulting in five Cardium oil wells, three Viking oil wells and four
Elkton gas wells.

In the Deer Mountain area we drilled six unit and four non-unit horizontal wells in the Beaverhill Lake oil pool. Eight
wells were multi-stage fractured and began producing in 2010. Two unit wells were being completed in early 2011. In addition, we continue to optimize injection patterns and waterflood performance in the unit.

Following the acquisition of Monterey in September 2010, we drilled four Montney horizontal gas wells at Groundbirch and completed three wells that were
multi-stage fractured. In addition, gas plant construction and tie-ins were completed with five wells beginning production before year-end.

At Judy Creek, ongoing development drilling and optimization of the waterflood and hydrocarbon miscible flood projects continue to be a focus for us.
Similar miscible flood development as well as infill drilling occurred in the Swan Hills Unit No. 1.

Further development and
optimization occurred in the CO2 miscible flood and waterflood areas of the Weyburn Unit in southeast Saskatchewan. During 2010, 32 wells were drilled in the unit, consisting of 28 water and CO2 injection wells, two producers and two observation
wells.

Various other drilling programs and optimization work were conducted during 2010 to test new concepts, increase production and
maximize recoveries. In the Princess and Jenner areas 52 infill shallow gas wells were drilled. Ongoing development in the East Bodo waterflood occurred with seven new vertical producers and three injectors drilled in 2010. Proof of concept
horizontal drilling and recompletion operations were initiated in 2010 in an effort to increase recovery in the Pekisko formation at Twining. In the partner operated Dunvegan Gas Unit, eight successful vertical Middle Debolt wells and 1 horizontal
Upper Debolt well were drilled.



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##### Table of Contents

Acquisitions and Divestitures

We made one large acquisition during 2010 that created a new core area. The acquisition of Monterey represented a significant step forward in our value creation strategy by providing multiple operated,
low risk drilling opportunities in the early stages of a Montney resource play development in the Groundbirch area of Northeast British Columbia. In 2010, we had spent an aggregate of $461.3 million to acquire 11.5 MMboe of Proved Reserves
and 23.2 MMboe of Total Proved Plus Probable Reserves (reserve values effective as of the acquisition dates). Minor asset acquisitions were made at Judy Creek and Swalwell to increase interests in existing core areas. In addition, we
consolidated our ownership in Twining/Fenn Big Valley CBM lands through a series of land swaps.

In early 2010, we sold gross overriding
royalties on a number of our non-core properties. The proceeds from this sale totaled $38.4 million. Total proceeds from minor dispositions of small, isolated properties and undeveloped acreage during 2010 were $22.3 million, resulting in
a decrease of 0.3 MMboe Proved Reserves and 0.4 MMboe Total Proved Plus Probable Reserves.

Future
Development Capital

NI 51-101 requires that the calculation of finding and development 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 finding, development and acquisition costs both with and
without change in FDC.

Finding, Development and Acquisition Costs

Company Interest Reserves

(Forecast Prices and Costs)



|                                                                         |  |            |         |  |            |  |         |            |  |  |                                |  |  |  |           | 
|------------------------------------------------------------------------ |  | ---------- | ------- |  | ---------- |  | ------- | ---------- |  |  | ------------------------------ |  |  |  | --------- | 
|                                                                         |  | 2010Proved |         |  | 2009Proved |  |         | 2008Proved |  |  | 2008-2010WeightedAverageProved | 
|Costs Excluding Future Development Capital                               |  |            |         |  |            |  |         |            |  |  |                                |  |  |  |           | 
|Exploration and Development Capital Expenditures - $M                    |  |            | 329,470 |  |            |  | 202,200 |            |  |  | 388,300                        |  |  |  | 919,970   | 
|Exploration and Development Reserve Additions including Revisions -Mboe  |  |            | 20,505  |  |            |  | 11,291  |            |  |  | 17,677                         |  |  |  | 49,473    | 
|                                                                         |  |            |         |  |            |  |         |            |  |  |                                |  |  |  |           | 
|Finding and Development Cost - $/boe                                     |  |            | 16.07   |  |            |  | 17.91   |            |  |  | 21.97                          |  |  |  | 18.60     | 
|                                                                         |  |            |         |  |            |  |         |            |  |  |                                |  |  |  |           | 
|Net Acquisition Capital - $M                                             |  |            | 400,600 |  |            |  | (6,230  | )          |  |  | 130,795                        |  |  |  | 525,165   | 
|Net Acquisition Reserve Additions - Mboe                                 |  |            | 11,232  |  |            |  | (937    | )          |  |  | 6,437                          |  |  |  | 16,732    | 
|                                                                         |  |            |         |  |            |  |         |            |  |  |                                |  |  |  |           | 
|Net Acquisition Cost - $/boe                                             |  |            | 35.67   |  |            |  | 6.65    |            |  |  | 20.32                          |  |  |  | 31.39     | 
|                                                                         |  |            |         |  |            |  |         |            |  |  |                                |  |  |  |           | 
|Total Capital Expenditures including Net Acquisitions - $M               |  |            | 730,070 |  |            |  | 195,970 |            |  |  | 519,095                        |  |  |  | 1,445,135 | 
|Reserve Additions including Net Acquisitions - Mboe                      |  |            | 31,737  |  |            |  | 10,354  |            |  |  | 24,114                         |  |  |  | 66,205    | 
|                                                                         |  |            |         |  |            |  |         |            |  |  |                                |  |  |  |           | 
|Finding Development and Acquisition Cost - $/boe                         |  |            | 23.00   |  |            |  | 18.93   |            |  |  | 21.53                          |  |  |  | 21.83     | 
|                                                                         |  |            |         |  |            |  |         |            |  |  |                                |  |  |  |           | 
|Costs Including Future Development Capital                               |  |            |         |  |            |  |         |            |  |  |                                |  |  |  |           | 
|Exploration and Development Capital Expenditures - $M                    |  |            | 329,470 |  |            |  | 202,200 |            |  |  | 388,300                        |  |  |  | 919,970   | 
|Exploration and Development Change in FDC - $M                           |  |            | 32,000  |  |            |  | (42,800 | )          |  |  | 12,000                         |  |  |  | 1,200     | 
|                                                                         |  |            |         |  |            |  |         |            |  |  |                                |  |  |  |           | 
|Exploration and Development Capital including Change in FDC - $M         |  |            | 361,470 |  |            |  | 159,400 |            |  |  | 400,300                        |  |  |  | 921,170   | 
|Exploration and Development Reserve Additions including Revisions - Mboe |  |            | 20,505  |  |            |  | 11,291  |            |  |  | 17,677                         |  |  |  | 49,473    | 
|                                                                         |  |            |         |  |            |  |         |            |  |  |                                |  |  |  |           | 
|Finding and Development Cost - $/boe                                     |  |            | 17.63   |  |            |  | 14.12   |            |  |  | 22.65                          |  |  |  | 18.62     | 
|                                                                         |  |            |         |  |            |  |         |            |  |  |                                |  |  |  |           | 
|Net Acquisition Capital - $M                                             |  |            | 400,600 |  |            |  | (6,230  | )          |  |  | 130,795                        |  |  |  | 525,165   | 
|Net Acquisition FDC - $M                                                 |  |            | 34,000  |  |            |  | 800     |            |  |  | 1,000                          |  |  |  | 35,800    | 
|                                                                         |  |            |         |  |            |  |         |            |  |  |                                |  |  |  |           | 
|Net Acquisition Capital including FDC - $M                               |  |            | 434,600 |  |            |  | (5,430  | )          |  |  | 131,795                        |  |  |  | 560,965   | 
|Net Acquisition Reserve Additions - Mboe                                 |  |            | 11,232  |  |            |  | (937    | )          |  |  | 6,437                          |  |  |  | 16,732    | 
|                                                                         |  |            |         |  |            |  |         |            |  |  |                                |  |  |  |           | 
|Net Acquisition Cost - $/boe                                             |  |            | 38.69   |  |            |  | 5.80    |            |  |  | 20.47                          |  |  |  | 33.53     | 
|                                                                         |  |            |         |  |            |  |         |            |  |  |                                |  |  |  |           | 
|Total Capital Expenditures including Net Acquisitions - $M               |  |            | 730,070 |  |            |  | 195,970 |            |  |  | 519,095                        |  |  |  | 1,445,135 | 
|Total Change in FDC - $M                                                 |  |            | 66,000  |  |            |  | (42,000 | )          |  |  | 13,000                         |  |  |  | 37,000    | 
|                                                                         |  |            |         |  |            |  |         |            |  |  |                                |  |  |  |           | 
|Total Capital including Change in FDC - $M                               |  |            | 796,070 |  |            |  | 153,970 |            |  |  | 532,095                        |  |  |  | 1,482,135 | 
|Reserve Additions including Net Acquisitions - Mboe                      |  |            | 31,737  |  |            |  | 10,354  |            |  |  | 24,114                         |  |  |  | 66,205    | 
|                                                                         |  |            |         |  |            |  |         |            |  |  |                                |  |  |  |           | 
|Finding Development and Acquisition Cost including FDC - $/boe           |  |            | 25.08   |  |            |  | 14.87   |            |  |  | 22.07                          |  |  |  | 22.39     | 
|                                                                         |  |            |         |  |            |  |         |            |  |  |                                |  |  |  |           | 



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##### Table of Contents

|                                                                         |  |                         |         |  |                         |  |          |                         |  |  |                                             |  |  |  |           | 
|------------------------------------------------------------------------ |  | ----------------------- | ------- |  | ----------------------- |  | -------- | ----------------------- |  |  | ------------------------------------------- |  |  |  | --------- | 
|                                                                         |  | 2010Proved plusProbable |         |  | 2009Proved plusProbable |  |          | 2008Proved plusProbable |  |  | 2008-2010WeightedAverageProved plusProbable | 
|Costs Excluding Future Development Capital                               |  |                         |         |  |                         |  |          |                         |  |  |                                             |  |  |  |           | 
|Exploration and Development Capital Expenditures - $M                    |  |                         | 329,470 |  |                         |  | 202,200  |                         |  |  | 388,300                                     |  |  |  | 919,970   | 
|Exploration and Development Reserve Additions including Revisions - Mboe |  |                         | 27,127  |  |                         |  | 2,577    |                         |  |  | 23,863                                      |  |  |  | 53,567    | 
|                                                                         |  |                         |         |  |                         |  |          |                         |  |  |                                             |  |  |  |           | 
|Finding and Development Cost - $/boe                                     |  |                         | 12.15   |  |                         |  | 78.46    |                         |  |  | 16.27                                       |  |  |  | 17.17     | 
|                                                                         |  |                         |         |  |                         |  |          |                         |  |  |                                             |  |  |  |           | 
|Net Acquisition Capital - $M                                             |  |                         | 400,600 |  |                         |  | (6,230   | )                       |  |  | 130,795                                     |  |  |  | 525,165   | 
|Net Acquisition Reserve Additions - Mboe                                 |  |                         | 22,832  |  |                         |  | (1,283   | )                       |  |  | 9,688                                       |  |  |  | 31,237    | 
|                                                                         |  |                         |         |  |                         |  |          |                         |  |  |                                             |  |  |  |           | 
|Net Acquisition Cost - $/boe                                             |  |                         | 17.55   |  |                         |  | 4.86     |                         |  |  | 13.50                                       |  |  |  | 16.81     | 
|                                                                         |  |                         |         |  |                         |  |          |                         |  |  |                                             |  |  |  |           | 
|Total Capital Expenditures including Net Acquisitions - $M               |  |                         | 730,070 |  |                         |  | 195,970  |                         |  |  | 519,095                                     |  |  |  | 1,445,135 | 
|Reserve Additions including Net Acquisitions - Mboe                      |  |                         | 49,959  |  |                         |  | 1,294    |                         |  |  | 33,551                                      |  |  |  | 84,804    | 
|                                                                         |  |                         |         |  |                         |  |          |                         |  |  |                                             |  |  |  |           | 
|Finding Development and Acquisition Cost - $/boe                         |  |                         | 14.61   |  |                         |  | 151.45   |                         |  |  | 15.47                                       |  |  |  | 17.04     | 
|                                                                         |  |                         |         |  |                         |  |          |                         |  |  |                                             |  |  |  |           | 
|Costs Including Future Development Capital                               |  |                         |         |  |                         |  |          |                         |  |  |                                             |  |  |  |           | 
|Exploration and Development Capital Expenditures - $M                    |  |                         | 329,470 |  |                         |  | 202,200  |                         |  |  | 388,300                                     |  |  |  | 919,970   | 
|Exploration and Development Change in FDC - $M                           |  |                         | 86,000  |  |                         |  | (122,800 | )                       |  |  | 180,000                                     |  |  |  | 143,200   | 
|                                                                         |  |                         |         |  |                         |  |          |                         |  |  |                                             |  |  |  |           | 
|Exploration and Development Capital including Change in FDC - $M         |  |                         | 415,470 |  |                         |  | 79,400   |                         |  |  | 568,300                                     |  |  |  | 1,063,170 | 
|Exploration and Development Reserve Additions including Revisions - Mboe |  |                         | 27,127  |  |                         |  | 2,577    |                         |  |  | 23,863                                      |  |  |  | 53,567    | 
|                                                                         |  |                         |         |  |                         |  |          |                         |  |  |                                             |  |  |  |           | 
|Finding and Development Cost - $/boe                                     |  |                         | 15.32   |  |                         |  | 30.81    |                         |  |  | 23.82                                       |  |  |  | 19.85     | 
|                                                                         |  |                         |         |  |                         |  |          |                         |  |  |                                             |  |  |  |           | 
|Net Acquisition Capital - $M                                             |  |                         | 400,600 |  |                         |  | (6,230   | )                       |  |  | 130,795                                     |  |  |  | 525,165   | 
|Net Acquisition FDC - $M                                                 |  |                         | 106,000 |  |                         |  | 800      |                         |  |  | 10,000                                      |  |  |  | 116,800   | 
|                                                                         |  |                         |         |  |                         |  |          |                         |  |  |                                             |  |  |  |           | 
|Net Acquisition Capital including FDC - $M                               |  |                         | 506,600 |  |                         |  | (5,430   | )                       |  |  | 140,795                                     |  |  |  | 641,965   | 
|Net Acquisition Reserve Additions - Mboe                                 |  |                         | 22,832  |  |                         |  | (1,283   | )                       |  |  | 9,688                                       |  |  |  | 31,237    | 
|                                                                         |  |                         |         |  |                         |  |          |                         |  |  |                                             |  |  |  |           | 
|Net Acquisition Cost - $/boe                                             |  |                         | 22.19   |  |                         |  | 4.23     |                         |  |  | 14.53                                       |  |  |  | 20.55     | 
|                                                                         |  |                         |         |  |                         |  |          |                         |  |  |                                             |  |  |  |           | 
|Total Capital Expenditures including Net Acquisitions - $M               |  |                         | 730,070 |  |                         |  | 195,970  |                         |  |  | 519,095                                     |  |  |  | 1,445,135 | 
|Total Change in FDC - $M                                                 |  |                         | 192,000 |  |                         |  | (122,000 | )                       |  |  | 190,000                                     |  |  |  | 260,000   | 
|                                                                         |  |                         |         |  |                         |  |          |                         |  |  |                                             |  |  |  |           | 
|Total Capital including Change in FDC - $M                               |  |                         | 922,070 |  |                         |  | 73,970   |                         |  |  | 709,095                                     |  |  |  | 1,705,135 | 
|Reserve Additions including Net Acquisitions - Mboe                      |  |                         | 49,959  |  |                         |  | 1,294    |                         |  |  | 33,551                                      |  |  |  | 84,804    | 
|                                                                         |  |                         |         |  |                         |  |          |                         |  |  |                                             |  |  |  |           | 
|Finding Development and Acquisition Cost including FDC -$/boe            |  |                         | 18.46   |  |                         |  | 57.16    |                         |  |  | 21.13                                       |  |  |  | 20.11     | 
|                                                                         |  |                         |         |  |                         |  |          |                         |  |  |                                             |  |  |  |           | 

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.



|                            |  |      |       |  |      |  |       |      |  |  |                            |  |  |  |       | 
|--------------------------- |  | ---- | ----- |  | ---- |  | ----- | ---- |  |  | -------------------------- |  |  |  | ----- | 
|                            |  | 2010 |       |  | 2009 |  |       | 2008 |  |  | 2008-2010Weighted 
Average | 
|Recycle Ratio, $/$          |  |      | 1.72  |  |      |  | 0.82  |      |  |  | 1.46                       |  |  |  | 1.46  | 
|Operating Netback, $/boe(1) |  |      | 26.37 |  |      |  | 25.38 |      |  |  | 34.78                      |  |  |  | 28.96 | 
|P+P F&D, $/boe(2)           |  |      | 15.32 |  |      |  | 30.81 |      |  |  | 23.82                      |  |  |  | 19.85 | 

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 2010 Company Interest year-end reserves by GLJs 2011 forecasted production.





|                                   |  |     |         |  |    |  |         |     |  |  |         | 
|---------------------------------- |  | --- | ------- |  | -- |  | ------- | --- |  |  | ------- | 
|                                   |  | PDP |         |  | TP |  |         | P+P | 
|RLI, years                         |  |     | 7.2     |  |    |  | 8.2     |     |  |  | 11.1    | 
|Reserves, Mboe(1)(2)               |  |     | 183,664 |  |    |  | 221,028 |     |  |  | 318,429 | 
|2011 Forecast Production, Boe/d(1) |  |     | 70,204  |  |    |  | 74,061  |     |  |  | 78,820  | 

Notes:



|(1) | Both reserves and production are Company Interest.
|--- | --------------------------------------------------

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



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##### Table of Contents

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.



|                                                             |  |      |      |   |      |  |      |      |  |  |                          |   |  |  |      |  
|------------------------------------------------------------ |  | ---- | ---- | - | ---- |  | ---- | ---- |  |  | ------------------------ | - |  |  | ---- | -
|                                                             |  | 2010 |      |   | 2009 |  |      | 2008 |  |  | WeightedAverage2008-2010 |  
|Without Net Acquisitions Proven Plus Probable Replacement %  |  |      | 99   | % |      |  | 9    | %    |  |  | 80                       | % |  |  | 62   | %
|P+P Drill Adds plus Revisions, MMboe(1)                      |  |      | 27.1 |   |      |  | 2.6  |      |  |  | 23.9                     |   |  |  | 53.6 |  
|With Net Acquisitions Proven Plus Probable Replacement %     |  |      | 183  | % |      |  | 4    | %    |  |  | 112                      | % |  |  | 98   | %
|P+P Adds, Revisions plus net Acquisitions, MMboe(1)          |  |      | 50.0 |   |      |  | 1.3  |      |  |  | 33.6                     |   |  |  | 84.8 |  
|Without Net Acquisitions Total Proved Replacement %          |  |      | 75   | % |      |  | 39   | %    |  |  | 59                       | % |  |  | 57   | %
|Total Proved Drill Adds plus Revisions, MMBoe(1)             |  |      | 20.5 |   |      |  | 11.3 |      |  |  | 17.7                     |   |  |  | 49.2 |  
|With Net Acquisitions Total Proved Replacement, %            |  |      | 116  | % |      |  | 36   | %    |  |  | 80                       | % |  |  | 77   | %
|Total Proved Adds, Revisions plus net Acquisitions, MMboe(1) |  |      | 31.7 |   |      |  | 10.4 |      |  |  | 24.1                     |   |  |  | 66.2 |  
|Current Year Production, MMboe(1)                            |  |      | 27.3 |   |      |  | 29.0 |      |  |  | 30.0                     |   |  |  | 86.3 |  

Note:



|(1) | Both reserves and production are Company Interest. Note that natural gas has been converted to barrels of oil equivalent on the basis of six Mcf of natural gas being
equal to one barrel of oil.
|--- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

Other Oil and Gas Information

Oil and Gas Wells

As at
December 31, 2010, we had an interest in 8,277 gross (4,138 net) producing oil and natural gas wells and 2,463 gross (1,366 net) non-producing oil and natural gas wells.



|                  |  |           |       |  |               |  |       |       |  |  |       |  |  |  |       | 
|----------------- |  | --------- | ----- |  | ------------- |  | ----- | ----- |  |  | ----- |  |  |  | ----- | 
|                  |  | Producing |       |  | Non-Producing | 
|                  |  | Gross     |       |  | Net           |  |       | Gross |  |  | Net   | 
|Crude Oil Wells   |  |           |       |  |               |  |       |       |  |  |       |  |  |  |       | 
|Alberta           |  |           | 1,757 |  |               |  | 1,124 |       |  |  | 797   |  |  |  | 472   | 
|British Columbia  |  |           | 91    |  |               |  | 58    |       |  |  | 157   |  |  |  | 100   | 
|Saskatchewan      |  |           | 909   |  |               |  | 192   |       |  |  | 462   |  |  |  | 178   | 
|Nova Scotia       |  |           |      |  |               |  |      |       |  |  |      |  |  |  |      | 
|Natural Gas Wells |  |           |       |  |               |  |       |       |  |  |       |  |  |  |       | 
|Alberta           |  |           | 5,181 |  |               |  | 2,569 |       |  |  | 514   |  |  |  | 271   | 
|British Columbia  |  |           | 278   |  |               |  | 162   |       |  |  | 125   |  |  |  | 73    | 
|Saskatchewan      |  |           | 42    |  |               |  | 31    |       |  |  | 39    |  |  |  | 24    | 
|Nova Scotia       |  |           | 19    |  |               |  | 2     |       |  |  |      |  |  |  |      | 
|Other(1)          |  |           |       |  |               |  |       |       |  |  |       |  |  |  |       | 
|Alberta           |  |           |      |  |               |  |      |       |  |  | 247   |  |  |  | 163   | 
|British Columbia  |  |           |      |  |               |  |      |       |  |  | 70    |  |  |  | 54    | 
|Saskatchewan      |  |           |      |  |               |  |      |       |  |  | 52    |  |  |  | 31    | 
|                  |  |           |       |  |               |  |       |       |  |  |       |  |  |  |       | 
|Total             |  |           | 8,277 |  |               |  | 4,138 |       |  |  | 2,463 |  |  |  | 1,366 | 
|                  |  |           |       |  |               |  |       |       |  |  |       |  |  |  |       | 

Note:



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

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, 2010 and the maximum net area of unproved properties for which we expect our rights to explore, develop and exploit to expire during 2011. There are no material work commitments
necessary to maintain these properties.

Unproved Properties

as at December 31, 2010



|                 |  |             |           |  |           |  |         |                                              |  |  |         | 
|---------------- |  | ----------- | --------- |  | --------- |  | ------- | -------------------------------------------- |  |  | ------- | 
|Location         |  | Gross Acres |           |  | Net Acres |  |         | Maximum Net Acres ThatMay Expire During 2011 | 
|Alberta          |  |             | 861,332   |  |           |  | 606,134 |                                              |  |  | 90,569  | 
|British Columbia |  |             | 455,118   |  |           |  | 240,875 |                                              |  |  | 45,827  | 
|Ontario          |  |             | 4,776     |  |           |  |        |                                              |  |  |        | 
|Saskatchewan     |  |             | 61,011    |  |           |  | 41,432  |                                              |  |  | 1,999   | 
|Nova Scotia      |  |             | 200,650   |  |           |  | 15,957  |                                              |  |  |        | 
|                 |  |             |           |  |           |  |         |                                              |  |  |         | 
|Total            |  |             | 1,552,887 |  |           |  | 904,398 |                                              |  |  | 138,395 | 
|                 |  |             |           |  |           |  |         |                                              |  |  |         | 



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##### Table of Contents

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 oil sands property is located approximately 420 kilometres northeast of Calgary and 65 kilometres southwest of
Cold Lake. We hold a 100 percent Working Interest in this oil sands asset where oil quality averages 11°API. The Upper Lloydminster and Lower Rex are the targeted formations. These formations contain bitumen-saturated sands up to 23 metres thick
at approximately 500 metres depth.

We are planning a pilot that is the basis for the Probable Reserves and Probable plus Possible Reserves
currently assigned to this property. In addition, there are Contingent Resources for the area surrounding the pilot. GLJ has updated the evaluation of the reserves and Contingent Resources for Lindbergh as of December 31, 2010. The
evaluation was limited to portions of the reservoir amenable to steam assisted gravity drainage (SAGD). The pilots profitability will be sensitive to oil prices and reservoir quality. The pilot 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
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.

Probable
Reserves have been assigned within the region of the proposed pilot development area. Probable plus Possible Reserves have been assigned to this same pilot area as well as a previously delineated region offsetting the pilot. There is no change in
the estimate of Probable Reserves and minor changes in the net present values due to slightly higher forecasted oil prices and a revised development plan for the pilot. The Probable Reserves attributed to the Lindbergh property have been included in
the reserves disclosed under -Statement of Oil and Gas Reserves and Reserves Data. The estimate of Probable Plus Possible Reserves has decreased due to the reporting limitation of a 50 year forecast life at a lower peak
production rate now planned for the pilot stage. The high estimate of Contingent Resources summarized below has been increased by the amount the Probable Plus Possible Reserves have been decreased, as the 50 year life does not limit recovery at the
current expected peak rate for the commercial phase.

Lindberg Oil Sands Pilot Project Probable and

Probable plus Possible Reserves and Net Present Value of Future Net Revenue

as of December 31, 2010

(Forecast Prices and Costs)



|                                                   |  |                       |       |   |                                |  |       |  
|-------------------------------------------------- |  | --------------------- | ----- | - | ------------------------------ |  | ----- | -
|                                                   |  | Probable 
Reserves(1) |       |   | Probable plusPossible Reserves | 
|Gross Reserves (MMbbl)                             |  |                       | 6.3   |   |                                |  | 18.5  |  
|Before tax net present value of future net revenue |  |                       |       |   |                                |  |       |  
|0% discount rate ($MM)                             |  |                       | 118.7 |   |                                |  | 627.6 |  
|5% discount rate ($MM)                             |  |                       | 54.8  |   |                                |  | 161.2 |  
|10% discount rate ($MM)                            |  |                       | 21.3  |   |                                |  | 54.1  |  
|15% discount rate ($MM)                            |  |                       | 2.2   |   |                                |  | 16.5  |  
|20% discount rate ($MM)                            |  |                       | (9.4  | ) |                                |  | (1.5  | )

Note:



|(1) | GLJ has estimated our undiscounted pilot capital to be $112 million and the ten percent discounted pilot capital amount to be $75 million to develop the Probable
Reserves.
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------

Contingent Resources have been assigned to the remaining areas of the reservoir within the property that meet certain
minimum criteria. In order to be classified as a Contingent Resource, a technically feasible recovery project must be defined. These Contingent Resources are expected to be economic to develop. The reclassification of these Contingent Resources as
reserves is contingent upon further reservoir studies, delineation drilling, facility design, preparation of firm development plans, regulatory application approval and corporate approvals. However, there is no certainty that it will be commercially
viable to produce any portion of the Contingent Resource.



|                 |  |                                                        |       |  |                                                        |  |       | 
|---------------- |  | ------------------------------------------------------ | ----- |  | ------------------------------------------------------ |  | ----- | 
|                 |  | December 31,
2009Contingent Resources(1)(Gross)(MMbbl) |       |  | December 31,
2010Contingent Resources(1)(Gross)(MMbbl) | 
|Low estimate(2)  |  |                                                        | 148.5 |  |                                                        |  | 148.5 | 
|Best estimate(3) |  |                                                        | 193.4 |  |                                                        |  | 193.4 | 
|High Estimate(4) |  |                                                        | 241.1 |  |                                                        |  | 257.9 | 



- 28 -



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##### Table of Contents

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) | A 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) | A 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) | A 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. These resource volumes are classified as a resource rather than a reserve because they are contingent upon further reservoir studies, delineation drilling and facility
design, preparation of firm development plans, regulatory application approval and company approvals. The size of the resource estimate could be positively impacted, potentially in a material amount, if additional delineation wells determine that
the aerial extent, reservoir quality and/or the thickness of the reservoir is larger than what is currently estimated based on the interpretation of seismic and well control. The size of the resource estimate could be negatively impacted,
potentially in a material amount, if additional delineation wells determine that the aerial extent, reservoir quality and/or the thickness of the reservoir are less than what is currently estimated based on the interpretation of the seismic and well
control.

Groundbirch Reserves and Contingent Resources

The Groundbirch property is located approximately 40 kilometres southwest of 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 from Monterey Exploration Ltd. 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 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

and Net Present Value of Future Net Revenue

as of
December 31, 2010

(Forecast Prices and Costs)



|                                                   |  |                                           |      |  |                             |  |       |                                          |  |  |                                                       |  |  |  |       | 
|-------------------------------------------------- |  | ----------------------------------------- | ---- |  | --------------------------- |  | ----- | ---------------------------------------- |  |  | ----------------------------------------------------- |  |  |  | ----- | 
|                                                   |  | Proved
DevelopedProducing Reserves(Gross) |      |  | Total ProvedReserves(Gross) |  |       | Total
ProvedPlus ProbableReserves(Gross) |  |  | Total Proved PlusProbable andPossible Reserves(Gross) | 
|Reserves                                           |  |                                           |      |  |                             |  |       |                                          |  |  |                                                       |  |  |  |       | 
|Gas (Bcf)                                          |  |                                           | 21.5 |  |                             |  | 53.1  |                                          |  |  | 160.9                                                 |  |  |  | 184.8 | 
|NGL (MMbbl)                                        |  |                                           | 0.0  |  |                             |  | 0.1   |                                          |  |  | 0.3                                                   |  |  |  | 0.4   | 
|Total (MMboe)(1)                                   |  |                                           | 3.6  |  |                             |  | 9.0   |                                          |  |  | 27.2                                                  |  |  |  | 31.2  | 
|                                                   |  |                                           |      |  |                             |  |       |                                          |  |  |                                                       |  |  |  |       | 
|Before tax net present value of future net revenue |  |                                           |      |  |                             |  |       |                                          |  |  |                                                       |  |  |  |       | 
|0% discount rate ($MM)                             |  |                                           | 88.4 |  |                             |  | 182.5 |                                          |  |  | 622.3                                                 |  |  |  | 806.4 | 
|5% discount rate ($MM)                             |  |                                           | 60.9 |  |                             |  | 111.7 |                                          |  |  | 313.4                                                 |  |  |  | 351.7 | 
|10% discount rate ($MM)                            |  |                                           | 46.7 |  |                             |  | 76.3  |                                          |  |  | 187.3                                                 |  |  |  | 199.3 | 
|15% discount rate ($MM)                            |  |                                           | 38.4 |  |                             |  | 56.2  |                                          |  |  | 123.4                                                 |  |  |  | 128.9 | 
|20% discount rate ($MM)                            |  |                                           | 33.0 |  |                             |  | 43.4  |                                          |  |  | 86.1                                                  |  |  |  | 89.4  | 

Note:



|(1) | Natural gas has been converted to barrels of oil equivalent on the basis of six 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. In order to be
classified as a Contingent Resource, a technically feasible recovery project must be defined. These Contingent



- 29 -



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##### Table of Contents

Resources are expected to be economic to develop. The reclassification of these Contingent Resources as reserves is contingent upon further reservoir studies, delineation drilling, facility
design and preparation of firm development plans, regulatory application approval and company approvals. However, there is no certainty that it will be commercially viable to produce any portion of the Contingent Resource.



|                 |  |                                                  |       | 
|---------------- |  | ------------------------------------------------ | ----- | 
|                 |  | December 31, 2010Contingent 
Resources(1)(Gross) |      
|Low estimate(2)  |  |                                                  |       | 
|Gas, MMcf        |  |                                                  | 249.9 | 
|NGL, MMbbl       |  |                                                  | 0.5   | 
|Total, MMboe(5)  |  |                                                  | 42.1  | 
|Best estimate(3) |  |                                                  |       | 
|Gas, MMcf        |  |                                                  | 424.4 | 
|NGL, MMbbl       |  |                                                  | 0.9   | 
|Total, MMboe(5)  |  |                                                  | 71.6  | 
|High estimate(4) |  |                                                  |       | 
|Gas, MMcf        |  |                                                  | 630.7 | 
|NGL,s MMbbl      |  |                                                  | 1.3   | 
|Total, MMboe(5)  |  |                                                  | 106.4 | 

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) | A low estimate is a conservative estimate of the quantity of gas that will be recovered from the accumulation, which under probabilistic methodology reflects a
ninety percent confidence level.
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|(3) | A 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) | A 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 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. These resource volumes are classified as a resource rather than a reserve because they are contingent upon further reservoir studies, delineation drilling and facility design, preparation of firm development plans, regulatory
application approval and company approvals. 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.

Forward Contracts

We may 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
notes 20 and 23 of our annual audited consolidated financial statements and related managements discussion and analysis for the year ended December 31, 2010, 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 to be approximately $196 million
as at December 31, 2010, based on a total future liability (inflated at 1.5 percent per annum) of approximately $1,790 million. These costs are anticipated to be paid over 50 years with the majority of the costs incurred in the
last 20 years and applies to 7,451 net wells (13,723 gross wells).

The following table summarizes our total current asset retirement
obligations as at December 31, 2010:



- 30 -



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##### Table of Contents

Asset Retirement Obligations



|                                                          |  |       |      |  |       |  |     |       |  |  |           |  |  |       |         |  |  |  |         | 
|--------------------------------------------------------- |  | ----- | ---- |  | ----- |  | --- | ----- |  |  | --------- |  |  | ----- | ------- |  |  |  | ------- | 
|                                                          |  | 2011  |      |  | 2012  |  |     | 2013  |  |  | Remainder |  |  | Total |        
|                                                          |  | ($MM) |      |  | ($MM) |  |     | ($MM) |  |  | ($MM)     |  |  | ($MM) |        
|Total Abandonment, Reclamation, Remediation & Dismantling |  |       | 10.9 |  |       |  | 8.4 |       |  |  | 8.3       |  |  |       | 1,762.8 |  |  |  | 1,790.4 | 
|Discounted at ten percent                                 |  |       | 10.4 |  |       |  | 7.3 |       |  |  | 6.5       |  |  |       | 171.4   |  |  |  | 195.6   | 

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 is the best comparison to our current operation and includes $230 million ($82 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 $230 million or $82 million when discounted at ten percent, is excluded
elsewhere.

Costs Incurred

The following table outlines property acquisition, exploration and development costs that we incurred during the financial year ended December 31, 2010. These costs include only those costs
which are cash or cash equivalent.



|                     |  |            |         | 
|-------------------- |  | ---------- | ------- | 
|Nature of Cost       |  | Amount($M) |        
|Acquisition Costs(1) |  |            |         | 
|Proved               |  |            | 125,946 | 
|Unproved             |  |            | 464,593 | 
|Exploration Costs    |  |            | 34,058  | 
|Development Costs    |  |            | 295,412 | 
|                     |  |            |         | 
|Total                |  |            | 920,009 | 
|                     |  |            |         | 

Note:



|(1) | Based on the values assigned to property, plant and equipment in the purchase price allocation for the Monterey acquisition in the December 31, 2010 financial
statements, and cash paid for other properties acquired.
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

Exploration and Development
Activities

The following table summarizes the number of wells completed or determined to be dry during the financial year ended
December 31, 2010.



|                   |  |             |     |  |             |  |       |       |  |  |     |  |  |       |     |  |     |  |     |  |  |  |       | 
|------------------ |  | ----------- | --- |  | ----------- |  | ----- | ----- |  |  | --- |  |  | ----- | --- |  | --- |  | --- |  |  |  | ----- | 
|                   |  | Development |     |  | Exploration |  |       | Total | 
|Wells              |  | Gross       |     |  | Net         |  |       | Gross |  |  | Net |  |  | Gross |     |  | Net | 
|Gas                |  |             | 105 |  |             |  | 77.1  |       |  |  | 3   |  |  |       | 2.1 |  |     |  | 108 |  |  |  | 79.2  | 
|Oil                |  |             | 53  |  |             |  | 28.3  |       |  |  | 6   |  |  |       | 4.4 |  |     |  | 59  |  |  |  | 32.7  | 
|Service            |  |             | 39  |  |             |  | 12.0  |       |  |  | 0   |  |  |       | 0.0 |  |     |  | 39  |  |  |  | 12.0  | 
|Stratigraphic Test |  |             | 0   |  |             |  | 0.0   |       |  |  | 0   |  |  |       | 0.0 |  |     |  | 0   |  |  |  | 0.0   | 
|Dry                |  |             | 6   |  |             |  | 2.7   |       |  |  | 2   |  |  |       | 1.5 |  |     |  | 8   |  |  |  | 4.2   | 
|                   |  |             |     |  |             |  |       |       |  |  |     |  |  |       |     |  |     |  |     |  |  |  |       | 
|Total              |  |             | 203 |  |             |  | 120.1 |       |  |  | 11  |  |  |       | 8.0 |  |     |  | 214 |  |  |  | 128.1 | 
|                   |  |             |     |  |             |  |       |       |  |  |     |  |  |       |     |  |     |  |     |  |  |  |       | 

Production Estimates

The following tables summarize the 2011 average daily volume of gross production estimated by GLJ for all properties held on December 31, 2010 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 2011 Company Interest production to be between 74,000 and
76,000 boepd.



|                                   |  |                           |         |  |                            |  |         |              |  |  |                            |  |  |  |         | 
|---------------------------------- |  | ------------------------- | ------- |  | -------------------------- |  | ------- | ------------ |  |  | -------------------------- |  |  |  | ------- | 
|                                   |  | 2011 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 (bblpd) |  |                           | 20,766  |  |                            |  | 21,538  |              |  |  | 20,766                     |  |  |  | 21,538  | 
|Heavy Oil (bblpd)                  |  |                           | 6,375   |  |                            |  | 6,600   |              |  |  | 6,375                      |  |  |  | 6,600   | 
|Natural Gas (Mcfpd)                |  |                           | 220,667 |  |                            |  | 235,897 |              |  |  | 220,667                    |  |  |  | 235,897 | 
|Natural Gas Liquids (bblpd)        |  |                           | 9,846   |  |                            |  | 11,061  |              |  |  | 9,846                      |  |  |  | 11,061  | 
|                                   |  |                           |         |  |                            |  |         |              |  |  |                            |  |  |  |         | 
|Total (boepd)                      |  |                           | 73,765  |  |                            |  | 78,516  |              |  |  | 73,765                     |  |  |  | 78,516  | 



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##### Table of Contents

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, 2010  |         |   | June 30, 2010 |  |         | Sept 30, 2010 |  |  | Dec 31, 2010 |   |  | Dec 31, 2010 |        
|Barrels of Oil Equivalent Basis(1)                    |  |               |         |   |               |  |         |               |  |  |              |   |  |              |         |   |  |  |         |  
|Average Daily Oil Production (boepd)                  |  |               | 75,627  |   |               |  | 75,517  |               |  |  | 72,704       |   |  |              | 74,953  |   |  |  | 74,693  |  
|Sales price (after commodity risk management) ($/boe) |  |               | 52.49   |   |               |  | 48.75   |               |  |  | 47.07        |   |  |              | 49.01   |   |  |  | 49.34   |  
|Other production income ($/boe)                       |  |               | 0.13    |   |               |  | 0.28    |               |  |  | 0.40         |   |  |              | 0.39    |   |  |  | 0.30    |  
|                                                      |  |               |         |   |               |  |         |               |  |  |              |   |  |              |         |   |  |  |         |  
|Oil & gas sales ($/boe)                               |  |               | 52.62   |   |               |  | 49.03   |               |  |  | 47.47        |   |  |              | 49.40   |   |  |  | 49.64   |  
|Processing and other income ($/boe)                   |  |               | 1.06    |   |               |  | 0.47    |               |  |  | 0.65         |   |  |              | 0.84    |   |  |  | 0.76    |  
|Royalties ($/boe)                                     |  |               | (11.45  | ) |               |  | (8.53   | )             |  |  | (8.26        | ) |  |              | (8.83   | ) |  |  | (9.27   | )
|Operating expenses ($/boe)                            |  |               | (13.50  | ) |               |  | (12.55  | )             |  |  | (12.69       | ) |  |              | (15.77  | ) |  |  | (13.63  | )
|Transportation costs ($/boe)                          |  |               | (0.48   | ) |               |  | (0.68   | )             |  |  | (0.53        | ) |  |              | (0.62   | ) |  |  | (0.58   | )
|Amortization of injectants ($/boe)                    |  |               | (0.67   | ) |               |  | (0.58   | )             |  |  | (0.52        | ) |  |              | (0.44   | ) |  |  | (0.55   | )
|                                                      |  |               |         |   |               |  |         |               |  |  |              |   |  |              |         |   |  |  |         |  
|Operating netback ($/boe)                             |  |               | 27.58   |   |               |  | 27.16   |               |  |  | 26.12        |   |  |              | 24.58   |   |  |  | 26.37   |  
|                                                      |  |               |         |   |               |  |         |               |  |  |              |   |  |              |         |   |  |  |         |  
|Light and Medium Crude Oil                            |  |               |         |   |               |  |         |               |  |  |              |   |  |              |         |   |  |  |         |  
|Average Daily Oil Production (bblpd)                  |  |               | 22,400  |   |               |  | 21,858  |               |  |  | 20,967       |   |  |              | 21,762  |   |  |  | 21,743  |  
|Sales price (after commodity risk management) ($/bbl) |  |               | 77.35   |   |               |  | 73.84   |               |  |  | 73.93        |   |  |              | 74.98   |   |  |  | 75.04   |  
|Other production income ($/bbl)                       |  |               | 0.33    |   |               |  | 0.46    |               |  |  | 0.94         |   |  |              | 0.71    |   |  |  | 0.61    |  
|                                                      |  |               |         |   |               |  |         |               |  |  |              |   |  |              |         |   |  |  |         |  
|Oil & gas sales ($/bbl)                               |  |               | 77.68   |   |               |  | 74.30   |               |  |  | 74.87        |   |  |              | 75.69   |   |  |  | 75.65   |  
|Processing and other income ($/bbl)                   |  |               | 0.58    |   |               |  | 0.37    |               |  |  | 0.34         |   |  |              | 0.60    |   |  |  | 0.47    |  
|Royalties ($/bbl)                                     |  |               | (18.02  | ) |               |  | (18.81  | )             |  |  | (15.04       | ) |  |              | (17.32  | ) |  |  | (17.32  | )
|Operating expenses ($/bbl)                            |  |               | (16.62  | ) |               |  | (16.01  | )             |  |  | (14.01       | ) |  |              | (18.81  | ) |  |  | (16.39  | )
|Transportation costs ($/bbl)                          |  |               | (0.67   | ) |               |  | (1.02   | )             |  |  | (1.05        | ) |  |              | (0.92   | ) |  |  | (0.92   | )
|Amortization of injectants ($/bbl)                    |  |               | (2.25   | ) |               |  | (1.81   | )             |  |  | (1.81        | ) |  |              | (1.52   | ) |  |  | (1.90   | )
|                                                      |  |               |         |   |               |  |         |               |  |  |              |   |  |              |         |   |  |  |         |  
|Operating netback ($/bbl)                             |  |               | 40.70   |   |               |  | 37.02   |               |  |  | 43.30        |   |  |              | 37.72   |   |  |  | 39.59   |  
|                                                      |  |               |         |   |               |  |         |               |  |  |              |   |  |              |         |   |  |  |         |  
|Heavy Crude Oil                                       |  |               |         |   |               |  |         |               |  |  |              |   |  |              |         |   |  |  |         |  
|Average Daily Oil Production (bblpd)                  |  |               | 7,113   |   |               |  | 6,791   |               |  |  | 6,585        |   |  |              | 6,673   |   |  |  | 6,789   |  
|Oil & gas sales ($/bbl)                               |  |               | 65.91   |   |               |  | 56.49   |               |  |  | 57.80        |   |  |              | 60.42   |   |  |  | 60.22   |  
|Processing and other income ($/bbl)                   |  |               | 1.67    |   |               |  | (2.78   | )             |  |  | 1.20         |   |  |              | 0.63    |   |  |  | 0.19    |  
|Royalties ($/bbl)                                     |  |               | (12.82  | ) |               |  | (13.31  | )             |  |  | (9.89        | ) |  |              | (11.25  | ) |  |  | (11.84  | )
|Operating expenses ($/bbl)                            |  |               | (16.78  | ) |               |  | (12.94  | )             |  |  | (17.22       | ) |  |              | (16.86  | ) |  |  | (15.95  | )
|                                                      |  |               |         |   |               |  |         |               |  |  |              |   |  |              |         |   |  |  |         |  
|Operating netback ($/bbl)                             |  |               | 37.98   |   |               |  | 27.46   |               |  |  | 31.89        |   |  |              | 32.94   |   |  |  | 32.62   |  
|                                                      |  |               |         |   |               |  |         |               |  |  |              |   |  |              |         |   |  |  |         |  
|Natural Gas                                           |  |               |         |   |               |  |         |               |  |  |              |   |  |              |         |   |  |  |         |  
|Average Daily Natural Gas Production (Mcfpd)          |  |               | 220,641 |   |               |  | 220,856 |               |  |  | 217,711      |   |  |              | 218,044 |   |  |  | 219,301 |  
|Sales price (after commodity risk management) ($/Mcf) |  |               | 5.62    |   |               |  | 4.86    |               |  |  | 4.67         |   |  |              | 4.87    |   |  |  | 5.00    |  
|Other production income ($/Mcf)                       |  |               | 0.01    |   |               |  | 0.05    |               |  |  | 0.04         |   |  |              | 0.06    |   |  |  | 0.04    |  
|                                                      |  |               |         |   |               |  |         |               |  |  |              |   |  |              |         |   |  |  |         |  
|Oil & gas sales ($/Mcf)                               |  |               | 5.63    |   |               |  | 4.91    |               |  |  | 4.71         |   |  |              | 4.93    |   |  |  | 5.04    |  
|Processing and other income ($/Mcf)                   |  |               | 0.25    |   |               |  | 0.21    |               |  |  | 0.15         |   |  |              | 0.21    |   |  |  | 0.20    |  
|Royalties ($/Mcf)                                     |  |               | (0.87   | ) |               |  | (0.07   | )             |  |  | (0.45        | ) |  |              | (0.31   | ) |  |  | (0.42   | )
|Operating expenses ($/Mcf)                            |  |               | (1.85   | ) |               |  | (1.84   | )             |  |  | (1.88        | ) |  |              | (2.39   | ) |  |  | (2.01   | )
|Transportation costs ($/Mcf)                          |  |               | (0.10   | ) |               |  | (0.13   | )             |  |  | (0.08        | ) |  |              | (0.12   | ) |  |  | (0.11   | )
|                                                      |  |               |         |   |               |  |         |               |  |  |              |   |  |              |         |   |  |  |         |  
|Operating netback ($/Mcf)                             |  |               | 3.06    |   |               |  | 3.08    |               |  |  | 2.45         |   |  |              | 2.32    |   |  |  | 2.70    |  
|                                                      |  |               |         |   |               |  |         |               |  |  |              |   |  |              |         |   |  |  |         |  
|NGL                                                   |  |               |         |   |               |  |         |               |  |  |              |   |  |              |         |   |  |  |         |  
|Average Daily Oil Production (bblpd)                  |  |               | 9,341   |   |               |  | 10,058  |               |  |  | 8,867        |   |  |              | 10,177  |   |  |  | 9,611   |  
|Oil & gas sales ($/bbl)                               |  |               | 56.57   |   |               |  | 60.70   |               |  |  | 53.55        |   |  |              | 56.74   |   |  |  | 56.99   |  
|Royalties ($/bbl)                                     |  |               | (19.15  | ) |               |  | (12.57  | )             |  |  | (13.77       | ) |  |              | (13.97  | ) |  |  | (14.80  | )
|Operating expenses ($/bbl)                            |  |               | (12.94  | ) |               |  | (10.17  | )             |  |  | (12.02       | ) |  |              | (13.56  | ) |  |  | (12.17  | )
|                                                      |  |               |         |   |               |  |         |               |  |  |              |   |  |              |         |   |  |  |         |  
|Operating netback ($/bbl)                             |  |               | 24.48   |   |               |  | 37.96   |               |  |  | 27.76        |   |  |              | 29.21   |   |  |  | 30.02   |  
|                                                      |  |               |         |   |               |  |         |               |  |  |              |   |  |              |         |   |  |  |         |  

Note:



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



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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.

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.



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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.

DIVIDENDS

General

We currently pay monthly
dividends to our Shareholders on the 15thday of each
month or the first business day following the 15thday.
The record date for any dividend is the last business 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.

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.

The following table sets forth distributions declared by the Trust in respect of the preceding three fiscal years on the outstanding Trust Units for the periods indicated, with each amount being paid in
the following month:



|          |  |         |        |  |         |  |        |         |  |  |        | 
|--------- |  | ------- | ------ |  | ------- |  | ------ | ------- |  |  | ------ | 
|Month     |  | 2010($) |        |  | 2009($) |  |        | 2008($) | 
|January   |  |         | 0.0700 |  |         |  | 0.1000 |         |  |  | 0.2250 | 
|February  |  |         | 0.0700 |  |         |  | 0.1000 |         |  |  | 0.2250 | 
|March     |  |         | 0.0700 |  |         |  | 0.1000 |         |  |  | 0.2250 | 
|April     |  |         | 0.0700 |  |         |  | 0.1000 |         |  |  | 0.2250 | 
|May       |  |         | 0.0700 |  |         |  | 0.1000 |         |  |  | 0.2250 | 
|June      |  |         | 0.0700 |  |         |  | 0.1000 |         |  |  | 0.2250 | 
|July      |  |         | 0.0700 |  |         |  | 0.1000 |         |  |  | 0.2250 | 
|August    |  |         | 0.0700 |  |         |  | 0.1000 |         |  |  | 0.2250 | 
|September |  |         | 0.0700 |  |         |  | 0.0700 |         |  |  | 0.2250 | 
|October   |  |         | 0.0700 |  |         |  | 0.0700 |         |  |  | 0.2250 | 
|November  |  |         | 0.0700 |  |         |  | 0.0700 |         |  |  | 0.1700 | 
|December  |  |         | 0.0700 |  |         |  | 0.0700 |         |  |  | 0.1700 | 
|          |  |         |        |  |         |  |        |         |  |  |        | 
|Total     |  |         | 0.8400 |  |         |  | 1.0800 |         |  |  | 2.5900 | 

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 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.



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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, 2010, our legal
stated capital was approximately $1 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.
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

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



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##### Table of Contents

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 then the last day of the first fiscal quarter of the next succeeding fiscal year of the Corporation;
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | With respect to the 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
|                                         | 
|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, 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 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 conditions, legislation, regulations and agreements governing the oil and gas
industry.

Pricing and Marketing

Oil

In Canada, oil producers are entitled to negotiate sales contracts directly with oil
purchasers, with the result that the market determines the price of oil. Oil prices are primarily based on worldwide supply and demand. The specific price depends in part on oil quality, prices of competing fuels, distance to market, 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 and the issuance of such a licence requires a public hearing and the approval of the Governor in Council.



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Natural Gas

The price of the vast majority of natural gas produced in western Canada is now determined through the liquid market established at the Alberta NIT hub rather than through direct negotiation
between buyers and sellers. 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 and the issuance of such a licence requires a public hearing and the
approval of the Governor in Council.

The governments of Alberta, British Columbia and Saskatchewan also regulate the volume of natural gas
that may be removed from those provinces for consumption elsewhere based on such factors as reserve availability, transportation arrangements, and market considerations.

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.

Pipeline Capacity

As a result of pipeline expansions over the past several years, there is ample pipeline capacity to accommodate current production levels of oil and
natural gas in western Canada and pipeline capacity does not generally limit the ability to produce and market such production. However, from time to time, pipeline operators will limit the amount of product shipped. A typical reason may be limited
ability for purchasers to accept product or there have been limitations imposed due to a pipeline taken out of service for planned or unplanned outages.

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. NAFTA carries forward most of the material energy terms that are contained in the Canada United
States Free Trade Agreement. 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 prohibits discriminatory border restrictions and
export taxes. NAFTA also 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.

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 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



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royalties and royalty-like interests are, from time to time, separated from the working interest owners interest 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.

On October 25, 2007, the Government of Alberta released a
report entitled The New Royalty Framework (NRF) containing the Governments proposals for Albertas new royalty regime which were subsequently implemented by the Mines and Minerals (New Royalty Framework)
Amendment Act, 2008. The NRF took effect on January 1, 2009. On March 11, 2010, the Government of Alberta announced changes to Albertas royalty system intended to increase Albertas competitiveness in the upstream oil and
natural gas sectors, which changes included a decrease in the maximum royalty rates for conventional oil and natural gas production effective for the January 2011 production month. Royalty curves incorporating the changes announced on March 11,
2010 were released on May 27, 2010.

With respect to conventional oil, the NRF eliminated the classification system
used by the previous royalty structure which classified oil based on the date of discovery of the pool. Under the NRF, 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. Royalty rates for conventional oil under the NRF ranged from 0-50%, an increase from the previous maximum rates of 30-35% depending on the vintage of the oil, and rate caps were set at
$120 per barrel. Effective January 1, 2011, the maximum royalty payable under the NRF was reduced to 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 NRF are
similarly determined using a single sliding rate formula incorporating separate variables to account for production rates and market prices. Royalty rates for natural gas under the NRF ranged from 5-50%, an increase from the previous maximum rates
of 5-35%, and rate caps were set at $16.59/GJ. Effective January 1, 2011, the maximum royalty payable under the NRF was reduced to 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 NRF. Prior to payout, 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: 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. An oil sands project reaches payout when its cumulative revenue exceeds its cumulative costs. Costs include specified allowed capital and operating costs related to the project plus a specified return allowance. As part of the
implementation of the NRF, the Government of Alberta renegotiated existing contracts with certain oil sands producers that were not compatible with the NRF.

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.

In April 2005, the Government of Alberta implemented the Innovative Energy Technologies
Program (the IETP), which 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 is backed by a $200 million funding commitment over a five-year period beginning April 1, 2005 and provides royalty adjustments to specific pilot and demonstration projects
that utilize new or innovative technologies to increase recovery from existing reserves.

On April 10, 2008, the Government of Alberta
introduced two new royalty programs to be implemented along with the NRF and intended 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 $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
spud subsequent to that date, and including wells drilled into pools drilled prior to 1985, among other changes.



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On November 19, 2008, in response to the drop in commodity prices experienced during the second half of
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 5-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 new program, companies drilling new natural gas or conventional oil deep wells (between 1,000 and 3,500 m) are given a one-time option, on a
well-by-well basis, to adopt either the new transitional royalty rates or those outlined in the NRF. Pursuant to the changes made to Albertas royalty structure announced on March 11, 2010, producers were only able to elect to adopt the
transitional royalty rates prior to January 1, 2011 and producers that had already elected to adopt such rates as of that date were permitted to switch to Albertas conventional royalty structure prior to February 15, 2011. On
January 1, 2014, all producers operating under the transitional royalty rates will automatically become subject to Albertas conventional royalty structure. The revised royalty curves for conventional oil and natural gas will not be
applied to production from wells operating under the transitional royalty rates.

On March 3, 2009, the Government of Alberta announced a
three-point incentive program in order to stimulate new and continued economic activity in Alberta. The program introduced a drilling royalty credit for new conventional oil and natural gas wells and a new well royalty incentive program, both
applying to conventional oil or natural gas wells drilled between April 1, 2009 and March 31, 2010. The drilling royalty credit provides an up to $200 per metre royalty credit for new wells and is primarily expected to benefit smaller
producers since the maximum credit available will be determined using the companys production level in 2008 and its drilling activity between April 1, 2009 and March 31, 2010, favouring smaller producers with lower activity levels.
The new well incentive program initially applied to wells that began producing conventional oil or natural gas between April 1, 2009 and March 31, 2010 and provided for a maximum 5% royalty rate for the first 12 months of production on a
maximum of 50,000 barrels of oil or 500 MMcf of natural gas. In June, 2009, the Government of Alberta announced the extension of these two incentive programs for one year to March 31, 2011. On March 11, 2010, the Government of Alberta
announced that the incentive program rate of 5% for the first 12 months of production would be made permanent, with the same volume limitations.

In addition to the foregoing, on May 27, 2010, in conjunction with the release of the new royalty curves, the Government of Alberta announced a number of new initiatives intended to accelerate
technological development and facilitate the development of unconventional resources (the Emerging Resources 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 when producing exclusively from
coal seams, 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 when producing exclusively
from shale seams, 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;
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | 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, 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.

In addition to the foregoing, Alberta currently maintains a royalty reduction program for low productivity oil and oil sands wells, a royalty adjustment
program for deep marginal gas wells and a royalty exemption for re-entry wells, among others.

Approximately 67 percent of our Company
Interest production forecast for 2011 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 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 (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 as an incentive for the production and marketing of natural gas which might otherwise have been
flared.

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. For natural gas, the freehold production tax 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.

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



| |  |  | Summer Royalty Credit Program providing a royalty credit of 10% of drilling and completion costs up to $100,000 for wells drilled between
April 1 and November 30 of each year, intended to increase summer drilling activity, employment and business opportunities in northeastern British Columbia;
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Deep Royalty Credit Program providing a royalty credit equal to approximately 23% of 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 spud between December 1, 2003 and September 1, 2009;
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Deep Re-Entry Royalty Credit Program providing royalty credits for deep re-entry wells with a true vertical depth greater than 2,300 metres and
a re-entry date subsequent to December 1, 2003;
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Deep Discovery Royalty Credit Programproviding the lesser of a 3-year royalty holiday or 283,000,000 m3of 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;
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Coalbed Gas Royalty Reduction and Credit Programproviding 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 royalty breaks for low productivity natural gas wells with average monthly production under 25,000
m3during the first 12 production months and average daily
production less than 23 m3for every metre of marginal
well depth;
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Ultra-Marginal Royalty Reduction Program providing additional royalty breaks for low productivity shallow natural gas wells with a true vertical
depth of less than 2,300 metres, average monthly production under 60,000 m3during the first 12 production months and average daily production less than 11.5 m3(development wells) or 17 m3(exploratory wildcat wells) for every 100 metres of marginal well depth;
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | 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 event on either Crown or freehold land and completed in a new pool discovery 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.

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 improve, or make possible, the access to new and underdeveloped oil and gas areas. In both 2009 and 2010,
the Government of British Columbia allocated $120 million in royalty credits for oil and gas companies under the Infrastructure Royalty Credit Program.

On August 6, 2009, the Government of British Columbia announced an oil and gas stimulus package designed to attract investment in and create economic benefits for British Columbia. The stimulus
package includes four royalty initiatives related primarily to natural gas drilling and infrastructure development. Natural gas wells spudded within the 10-month period from September 1, 2009 to June 30, 2010 and brought on production
by December 31, 2010 qualify for a 2% royalty rate for the first 12 months of production,



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beginning from the first month of production for the well (the Royalty Relief Program). British Columbias existing Deep Royalty Credit Program was permanently amended for
wells spudded after August 31, 2009 by increasing the royalty deduction on deep drilling for natural gas by 15% and extending the program to include horizontal wells drilled to depths of between 1,900 and 2,300 metres. Wells spud between
September 1, 2009 and June 30, 2010 may qualify for both the Royalty Relief Program and the Deep Royalty Credit Program but will only receive the benefits of one program at a time. An additional $50 million was also allocated to be
distributed through the Infrastructure Royalty Credit Program to stimulate investment in oilfield-related road and pipeline construction.

Approximately ten percent of our Company Interest production forecast for 2011 is in the Province of British Columbia on Crown lands.

Saskatchewan

In Saskatchewan, the
amount payable as a royalty 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 classified as 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 new oil (not classified as
either third tier oil or fourth tier oil). 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.

Base prices are used to establish lower limits in the price-sensitive royalty structure for conventional oil. Where average wellhead prices are below the established base prices of $100 per m3for 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 a royalty in respect of natural gas production is determined by a sliding scale based on a reference price
(which is the greater of the amount obtained by the producer and a prescribed minimum price), the quantity produced in a given month, the type of natural gas, and the vintage of the natural gas. Like conventional oil, natural gas may be classified
as non-associated gas or associated gas and royalty rates are determined according to the finished drilling date of the respective well. As an incentive for the production and marketing of natural gas which may have been
flared, the royalty rate on natural gas produced in association with oil is less than on non-associated natural gas. 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 m3of gas for every m3of 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.

On
December 9, 2010, the Government of Saskatchewan enacted the Freehold Oil and Gas Production Tax Act, 2010 which replaces the existing Freehold Oil and Gas Production Tax Act and is intended to facilitate more efficient payment of
freehold production taxes by industry. No regulations have been passed with respect to the calculation of freehold production taxes under the new Act.

As with conventional oil production, base prices 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 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, 2002providing reduced Crown royalty and freehold tax
rates on incentive volumes of 8,000 m3for deep
development vertical oil wells, 4,000 m3
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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| | for non-deep exploratory vertical oil wells and 16,000 m3for deep exploratory vertical oil wells (more than 1,700 metres or within certain formations);
| | -------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Royalty/Tax Incentive Volumes for Exploratory Gas Wells Drilled on or after October 1, 2002providing reduced Crown royalty and freehold
tax rates on incentive volumes of 25,000,000 m3for
qualifying exploratory gas wells;
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Royalty/Tax Incentive Volumes for Horizontal Oil Wells Drilled on or after October 1, 2002providing reduced Crown royalty and freehold tax
rates on incentive volumes of 6,000 m3for non-deep
horizontal oil wells and 16,000 m3for deep horizontal oil
wells (more than 1,700 metres or within certain formations);
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Royalty/Tax Regime for Incremental Oil Produced from New or Expanded Waterflood Projects Implemented on or after October 1, 2002 treating
incremental production from waterflood projects as fourth tier oil for the purposes of royalty calculation;
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Royalty/Tax Regime for Enhanced Oil Recovery Projects (Excluding Waterflood Projects) Commencing prior to April 1, 2005 providing Crown
royalty and freehold tax determinations based in part on the profitability of enhanced recovery projects pre- and post-payout; and
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | 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% post-payout and a freehold production tax of 0% on operating income from enhanced oil recovery projects pre-payout and 8% post-payout.
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

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 will be limited in its carry forward to seven years
since the Government of Canadas initiative to reintroduce the full deduction of provincial resource royalties from federal and provincial taxable income. Saskatchewans RTR will be wound down as a result of the Government of Canadas
plan to reintroduce full deductibility of provincial resource royalties for corporate income tax purposes.

Approximately seven percent of our
Company Interest production forecast for 2011 is in the Province of Saskatchewan.

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 2011 is in the Province of Nova Scotia.

Land Tenure

Crude oil and natural gas located in the western provinces is owned predominantly by the respective provincial governments. 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. Oil and natural
gas located in such provinces can also be privately owned 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s policy of deep rights reversion was expanded 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.

In Alberta,
the NRF includes 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. The order in which these agreements will receive the reversion notice will depend on their vintage and location, with the older leases
and licenses receiving reversion notices first beginning in January 2011. Leases and licences that were granted prior to January 1, 2009 but continued after that date will not be subject to shallow rights reversion until they reach the end
of their primary term and are continued (at which time deep rights reversion will be applied);



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thereafter, 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.

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 government 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 requires that well and facility sites be abandoned and reclaimed to the satisfaction of provincial authorities. 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.

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, providing the legislative authority for the Government of Alberta to implement the policies contained in the ALUF. Regional plans established pursuant to the ALSA are deemed to be legislative
instruments equivalent to regulations and are binding on the Government of Alberta and provincial regulators, including those governing the oil and gas industry. In the event of a conflict or inconsistency between a regional plan and another
regulation, regulatory instrument or statutory consent, the regional plan will prevail. Further, the ALSA requires local governments, provincial departments, agencies and administrative bodies or tribunals to review their regulatory instruments and
make any appropriate changes to ensure that they comply with an adopted regional plan. The ALSA also contemplates the amendment or extinguishment of previously issued statutory consents such as regulatory permits, licenses, approvals and
authorizations in order for the purpose of achieving or maintaining an objective or policy resulting from the implementation of a regional plan. Among the measures to support the goals of the regional plans contained in the ALSA are conservation
easements, which can be granted for the protection, conservation and enhancement of land; and conservation directives, which are explicit declarations contained in a regional plan to set aside specified lands in order to protect, conserve, manage
and enhance the environment. Although no regional plans have been established under the ALSA, the planning process is underway for the Lower Athabasca Region (which contains the majority of oil sands development) and the South Saskatchewan Region.
While the potential impact of the regional plans established under the ALSA cannot yet be determined, it is clear that such regional plans may have a significant impact on land use in Alberta and may affect the oil and gas industry.

Climate Change Regulation

Federal

In December 2002, the Government of Canada ratified the Kyoto Protocol
(Kyoto Protocol), which requires a reduction in greenhouse gas (GHG) emissions by signatory countries between 2008 and 2012. The Kyoto Protocol officially came into force on February 16, 2005 and
commits Canada to reduce its greenhouse gas emissions levels to 6% below 1990 business-as-usual levels by 2012.

On
February 14, 2007, the House of Commons passed Bill C-288, An Act to ensure Canada meets its global climate change obligations under the Kyoto Protocol. The resulting Kyoto Protocol Implementation Act came into force on
June 22, 2007. Its stated purpose is to ensure that Canada takes effective and timely action to meet its obligations under the Kyoto Protocol and help address the problem of global climate change. It requires the federal Minister of
the Environment to, among other things, produce an annual climate change plan detailing the measures to be taken to ensure Canada meets its obligations under the Kyoto Protocol. It also authorizes the establishment of regulations respecting matters
such as emissions limits, monitoring, trading and enforcement.

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 greenhouse gases 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 either a facility-specific, sector-wide or 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.

The Updated Action Plan makes
a distinction between Existing Facilities and New Facilities. For Existing Facilities, the Updated Action Plan requires an emissions intensity reduction of 18% below 2006 levels by 2010 followed by a continuous annual
emissions intensity improvement of 2%. New Facilities are defined as facilities beginning operations in 2004 or later and include both greenfield facilities and major facility expansions that (i) result in a 25% or greater increase
in a facilitys physical capacity, or (ii) involve significant changes to the processes of the facility. New Facilities will be given a 3-year grace period during which no emissions intensity



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reductions will be required. Targets requiring an annual 2% emissions intensity reduction will begin to apply in the fourth year of commercial operation of a New Facility. Further, emissions
intensity targets for New Facilities will be based on a cleaner fuel standard to encourage continuous emissions intensity reductions over time. The method of applying this cleaner fuel standard has not yet been determined. In addition, the Updated
Action Plan indicates that targets for the adoption of carbon capture and storage (CCS) technologies will be developed for oil sands in-situ facilities, upgraders and coal-fired power generators that begin operations in 2012 or
later. These targets will become operational in 2018, although the exact nature of the targets has not yet been determined.

Given the large
number of small facilities within the upstream oil and gas and natural gas pipeline sectors, facilities within these sectors will only be subject to emissions intensity targets if they meet certain minimum emissions thresholds. That threshold will
be (i) 50,000 tonnes of CO2 equivalent per facility per year for natural gas pipelines; (ii) 3,000 tonnes of CO2 equivalent per facility per year for the upstream oil and gas facility; and (iii) 10,000 boepd per company. These
regulatory thresholds are significantly lower than the regulatory threshold in force in Alberta, discussed below. In all other sectors governed by the Updated Action Plan, all facilities will be subject to regulation.

Four separate compliance mechanisms are provided for in the Updated Action Plan in respect of the above targets: Regulated entities will be able to use
Technology Fund contributions to meet their emissions intensity targets. The contribution rate for Technology Fund contributions will increase over time, beginning at $15 tonnes per CO2 equivalent for the 2010-12 period, rising to $20 in 2013, and
thereafter increasing at the nominal rate of GDP growth. Maximum contribution limits will also decline from 70% in 2010 to 0% in 2018. Monies raised through contributions to the Technology Fund will be used to invest in technology to reduce
greenhouse gas emissions. Alternatively, regulated entities may be able to receive credits for investing in large-scale and transformative projects at the same contribution rate and under similar requirements as described above.

The offset system is intended to encourage emissions reductions from activities outside of the regulated sphere, allowing non-regulated entities to
participate in and benefit from emissions reduction activities. In order to generate offset credits, project proponents must propose and receive approval for emissions reduction activities that will be verified before offset credits will be issued
to the project proponent. Those credits can then be sold to regulated entities for use in compliance or non-regulated purchasers that wish to either purchase the offset credits for cancellation or banking for future use or sale.

Under the Updated Action Plan, regulated entities will also be able to purchase credits created through the Clean Development Mechanism of the Kyoto
Protocol which facilitates investment by developed nations in emissions-reduction projects in developing countries. The purchase of such Emissions Reduction Credits will be restricted to 10% of each firms regulatory obligation, with the added
restriction that credits generated through forest sink projects will not be available for use in complying with the Canadian regulations.

Finally, a one-time credit of up to 15 million tonnes worth of emissions credits will be awarded to regulated entities for emissions reduction
activities undertaken between 1992 and 2006. These credits will be both tradable and bankable.

The United Nations Framework Convention on
Climate Change is working towards establishing a successor to the Kyoto Protocol. From December 7 to 18, 2009, a meeting between government leaders and representatives from approximately 170 countries in Copenhagen, Denmark (the
Copenhagen Conference) resulted in the Copenhagen Accord, which reinforces the commitment to reducing GHG emissions contained in the Kyoto Protocol and promises funding to help developing countries mitigate and adapt to climate
change. From November 29 to December 10, 2010, a meeting between representatives from approximately 190 countries in Cancun, Mexico resulted in the Cancun Agreements, in which developed countries committed to additional measures to help
developing countries deal with climate change. Unlike the Kyoto Protocol, however, neither the Copenhagen Accord nor the Cancun Agreements establish binding GHG emissions reduction targets.

In response to the Copenhagen Accord, the Government of Canada indicated on January 29, 2010 that it will seek to achieve a 17% reduction in greenhouse gas emissions from 2005 levels by 2020. This
goal is similar to the goal expressed in previous policy documents which were discussed above.

Although draft regulations for the
implementation of the Updated Action Plan were intended to be published in the fall of 2008 and become binding on January 1, 2010, no such regulations have been proposed to date. Further, representatives 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 greenhouse gas emissions regulation. As a result, it is unclear to what extent,
if any, the proposals contained in the Updated Action Plan will be implemented.

On December 23, 2010, the United States Environmental
Protection Agency indicated its intention to impose greenhouse gas emissions standards for fossil fuel-fired power plants by July, 2011 and for refineries by December, 2011.

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 Actwhich received royal assent on November 4, 2008. The CCEMA is based



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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 greenhouse gases a year are subject to compliance with the CCEMA. Similarly 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.

Under CCEMA, greenhouse gas emission limits apply once a facility has direct greenhouse gas emissions in a year of 100,000 tonnes CO2 equivalent or more. We currently have two facilities that meet this
threshold. Under CCEMA, any facility coming into commercial production after 2000 will be considered a new facility and will be required to reduce its emission intensity (e.g. tonnes of greenhouse gas emitted per unit of production) by 2 percent per
year beginning in its fourth year of commercial operation, up to an aggregate 12 percent reduction from the emissions intensity level of its third year of commercial operation.

The CCEMA contains similar compliance mechanisms to those in the Updated Action Plan. Regulated emitters can meet their emissions intensity targets by contributing to the Climate Change and Emissions
Management Fund (the 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. Unlike the Updated Action Plan, the CCEMA does not contemplate a linkage to external compliance mechanisms such as the Kyoto Protocols Clean Development Mechanism.

On December 2, 2010, the Government of Alberta passed theCarbon Capture and Storage Statutes Amendment Act, 2010, which 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.

The Alberta government is expected to raise the price of fund credits and increase the required reductions in greenhouse gas emissions
intensity to unspecified levels. In addition, Alberta facilities must currently report emissions of industrial air pollutants and comply with obligations imposed in permits and under environmental regulations. Under the Alberta regulations, if the
emissions remain at current levels, we would be required to purchase off-setting credits in 2010 of up to $300,000 from Alberta Environment. In 2010, 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 initial level of the tax was set at $10 per tonne of CO2 equivalent and rose to $15 per tonne of CO2 equivalent on July 1, 2009
and $20 per tonne of CO2 equivalent on July 1, 2010. It is scheduled to further increase at a rate of $5 per tonne of CO2 equivalent on July 1 of every year until it reaches $30 per tonne of CO2 equivalent on July 31, 2012. 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.

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 will come into force by regulation of the Lieutenant Governor in Council. 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 greenhouse gas emissions. It is expected that greenhouse gas emissions restrictions will be applied to facilities emitting more than 25,000 tonnes of CO2 equivalent per year, which will be required to meet
established targets through a combination of emissions allowances issued by the Government of British Columbia and the purchase of emissions offsets generated through activities that result in a reduction in greenhouse gas emissions. Although more
specific details of British Columbias cap and trade plan have not yet been finalized, on January 1, 2010, new reporting regulations came into force requiring all British Columbia facilities emitting over 10,000 tonnes of CO2 equivalent
per year to begin reporting their emissions. Facilities reporting emissions greater than 25,000 tonnes of CO2 equivalent per year are required to have their emissions reports verified by a third party.



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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; however, there are no reduction targets proposed
for the 2010 reporting year.

Saskatchewan

On May 11, 2009, the Government of Saskatchewan announced The Management and Reduction of Greenhouse Gases Act(the MRGGA) to regulate greenhouse gas emissions in the
province. The MRGGA received Royal Assent on May 20, 2010 and will come into force upon proclamation. Regulations under MRGGA have also yet to be proclaimed, but draft versions indicate that Saskatchewan will adopt the goal of a 20% reduction
in greenhouse gas emissions from 2006 levels by 2020 and permit the use of pre-certified investment credits, early action credits and emissions offsets in compliance similar to both the federal and Alberta climate change initiatives. It remains
unclear whether the scheme implemented by the MRGGA will be based on emissions intensity or an absolute cap on emissions. At this time this proposed regulation is not expected to have any significant impacts on us or our operations.

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 greenhouse
gas regulations, existing and proposed, may 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, 2010.

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.

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

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



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



| |  |  | geo-political conditions;
| | - |  | -------------------------



| |  |  | worldwide economic conditions;
| | - |  | ------------------------------



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



| |  |  | the supply and price of foreign oil and natural gas;
| | - |  | ----------------------------------------------------



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| |  |  | the level of consumer demand;
| | - |  | -----------------------------



| |  |  | the price and availability of alternative fuels;
| | - |  | ------------------------------------------------



| |  |  | the proximity to, and capacity of, transportation facilities;
| | - |  | -------------------------------------------------------------



| |  |  | the effect of worldwide energy conservation measures; and
| | - |  | ---------------------------------------------------------



| |  |  | government regulation.
| | - |  | ----------------------

Declines in oil or natural gas prices could have an 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 cash dividends, 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 the control of our board of directors and
management team, we will change our dividend policy from time to time as circumstances warrant and as a result, future cash dividends could be reduced or suspended entirely. The market value of the Common Shares may deteriorate if we reduce or
suspend the amount of the cash dividends that we pay in the future and such deterioration may be material. Furthermore, the future treatment of dividends for tax purposes will be subject to the nature and composition of our dividends and potential
legislative and regulatory changes.

Dividends may be reduced during periods of lower operating cash flow, which result from lower
commodity prices and the decision by us to make capital expenditures using cash flow. A reduction in dividends could also negatively affect the market price of the Common Shares.

Production and development costs incurred with respect to properties, including power costs and the costs of injection fluids associated with tertiary recovery operations, reduce the income that we
receive and, consequently, the amounts we can distribute to our Shareholders.

The timing and amount of capital expenditures will directly
affect the amount of income available for dividends to our Shareholders. Dividends may be reduced, or even eliminated, at times when significant capital or other expenditures are planned. 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 oil and gas reserves and to invest in assets, as the case may be, will be impaired. To the extent that
we are required to use cash flow to finance capital expenditures or property acquisitions, the cash we receive will be reduced, resulting in reductions to the amount of cash we are able to distribute to our Shareholders. A reduction in the amount of
cash distributed to Shareholders may negatively affect the market price of the Common Shares.

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.

The value of the Common Shares will depend upon, among other things, our reserves. In making strategic decisions, we rely upon reports prepared by our independent reserve engineers and our own internal
estimates. Estimating future production and reserves 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 reserve and cash flow information contained herein represent estimates
only. Petroleum engineers consider many factors and make assumptions in estimating reserves.

Those factors and assumptions include:



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



| |  |  | the assumed effect of government regulation;
| | - |  | --------------------------------------------



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



| |  |  | initial production rates;
| | - |  | -------------------------



| |  |  | production decline rates;
| | - |  | -------------------------



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| |  |  | ultimate recovery of reserves;
| | - |  | ------------------------------



| |  |  | marketability of production; and
| | - |  | --------------------------------



| |  |  | other government levies that may be imposed over the producing life of reserves.
| | - |  | --------------------------------------------------------------------------------

If any of these factors and assumptions prove to be inaccurate, our actual results may vary materially from our reserve 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 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.

Our future oil and
natural gas reserves and production, and therefore our cash flow, will depend upon our success in acquiring and/or developing additional reserves. If we fail to add reserves by acquiring or developing them, our reserves and production will decline
over time as current reserves are produced. When oil and gas from our properties can no longer be economically produced and marketed, our Common Shares will have no value unless additional reserves have been acquired or developed. If we are not able
to raise capital on favourable terms, we may not be able to add to or maintain our reserves. If we use our cash flow to acquire or develop reserves, we will reduce our cash available to be distributed to Shareholders. There is strong competition in
all aspects of the oil and gas industry, including reserve acquisitions. We will actively compete for reserve acquisitions and skilled industry personnel with other oil and gas companies and organizations. However, we cannot assure you that we will
be successful in acquiring additional reserves on terms that meet our objectives.

Future oil and natural gas exploration may involve
unprofitable efforts, not only from unsuccessful wells, but also from wells that are productive but do not produce sufficient petroleum substances to return a profit after drilling, operating and other costs. Completion of a well does not assure a
profit on the investment or recovery of drilling, completion and operating costs. In addition, drilling hazards or environmental damage could greatly increase the cost of operations, and various field operating conditions may adversely affect the
production from successful wells. These conditions include delays in obtaining governmental approvals or consents, 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, production delays and declines from normal field operating conditions cannot be
eliminated and can be expected to adversely affect revenue and cash flow levels to varying degrees.

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

Uncertainty in domestic and
international credit markets 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 us and our cash flow
from operations. 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.



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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.

The
oil and natural gas industry is subject to extensive environmental regulation, which imposes restrictions and prohibitions on releases or emissions of various substances produced in association with certain oil and gas industry operations. In
addition, Canadian legislation requires that well and facility sites be abandoned and reclaimed to the satisfaction of provincial authorities. A breach of this or other legislation may result in fines or the issuance of a clean-up order. Ongoing
environmental obligations will be funded out of our cash flow and could therefore reduce the cash available to be distributed to our Shareholders.

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.

There is strong competition in all aspects of the oil and gas industry. We will actively compete for capital, skilled personnel, undeveloped lands,
reserve acquisitions, access to drilling rigs, service rigs and other equipment, access to processing facilities and pipeline and refining capacity and in all other aspects of its operations with a substantial number of other organizations. Some of
those organizations not only explore for, develop and produce oil and natural gas but also carry on refining operations and market oil and other products on a world-wide basis and, as such, have greater technical, financial and operational resources
than us.

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 and other creditors and only the remainder, if any, would be available for dividend to our
Shareholders.

We are indebted under our credit facility and the Notes. Certain covenants in the agreements with our lenders and with
respect to the Notes may limit the amount of dividends paid to Shareholders. Variations in interest rates, exchange rates and scheduled principal repayments could result in significant changes in the amount we are required to apply to the service of
our outstanding indebtedness. If we become unable to pay our debt service charges or otherwise cause an event of default to occur, our lenders may foreclose on, or sell, our properties. The net proceeds of any such sale will be allocated firstly to
the repayment of our lenders and other creditors and only the remainder, if any, would be payable to Shareholders. In addition, we may not be able to refinance some or all of these debt obligations through the issuance of new debt obligations on the
same terms, and we may be required to refinance through the issuance of new debt obligations on less favourable terms or through the issuance of additional securities or through other means. In any such event, the amount of cash available for
dividend may be diluted or adversely impacted and such dilution or impact may be significant.

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

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

The 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.



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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 are conducted prior to any purchase of significant resource assets, such reviews cannot guarantee
that an unforeseen defect in the chain of title will not arise to defeat our title to certain assets. Such defects could reduce the amount of cash flow, possibly resulting in lower dividends to our Shareholders which could result in a lower market
price of the Common Shares.

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

World oil prices are quoted in United States dollars and the price received by Canadian
producers is therefore affected by the Canadian/United States dollar exchange rate which fluctuates over time. A material increase in the value of the Canadian dollar may negatively impact our net production revenue and cash flow. To the extent that
we have engaged, or in the future engage, in risk management activities related to commodity prices and foreign exchange rates, through entry into oil or natural gas price commodity contracts and foreign exchange contracts or otherwise, we may be
subject to unfavourable price changes and credit risks associated with the counterparties with which we contract.

A decline in the value of
the Canadian dollar relative to the United States dollar provides a competitive advantage to United States companies in acquiring Canadian oil and gas properties and may make it more difficult for us to replace reserves through acquisitions.

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.

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 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.

Changes to accounting policies, including the implementation of IFRS, 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.

In
January 2006, the CICA Accounting Standards Board (AcSB) adopted a strategic plan for the direction of accounting standards in Canada. As part of that plan, the AcSB confirmed in February 2008 that IFRS will replace Canadian GAAP
in 2011 for Canadian publicly accountable enterprises. While IFRS uses a conceptual framework similar to Canadian GAAP, there are significant differences that must be evaluated. The implementation of IFRS 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. At this time, we cannot reasonably quantify the full impact that adopting IFRS will
have on our financial position and future results. For information regarding



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the impact that IFRS will have on our accounting policies and financial statements, see International Financial Reporting Standards (IFRS) in the Annual MD&A and the Third
Quarter MD&A, which documents are incorporated by reference herein.

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 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.

The documents incorporated by reference 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.

Shareholders who are United States persons face certain income tax risks.

The United States federal income tax risks related to owning and disposing of our Common Shares include the following:



| |  |  | A non-United States entity treated as a corporation for United States federal income tax purposes will be a passive foreign investment company
(PFIC) if it generates primarily passive income or the greater part of its assets generate, or are held for the production of, passive income. We are currently not a PFIC although no assurance can be given that we will not be a
PFIC in 2011 or thereafter. If we were classified as a PFIC, for any year during which a United States Shareholder owns Common Shares, such United States Shareholder would generally be subject to special adverse rules including taxation at maximum
ordinary income rates plus an interest charge on both gains on sale and certain dividends. Certain elections may be available to a United States Shareholders if we were classified as a PFIC to alleviate these adverse tax consequences.
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

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

The oil and gas industry in Canada is subject to federal, provincial and municipal legislation
and regulation governing such matters as land tenure, prices, royalties, production rates, environmental protection controls, the exportation of crude oil, natural gas and other products, as well as other matters. The industry is also subject to
regulation by governments in such matters as the awarding or acquisition of exploration and production rights, oil sands or other interests, the imposition of specific drilling obligations, environmental protection controls, control over the
development and abandonment of fields and mine sites (including restrictions on production) and possibly expropriation or cancellation of contract rights.



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Government regulations may change from time to time in response to economic or political conditions. The
exercise of discretion by governmental authorities under existing regulations, the implementation of new regulations or the modification of existing regulations affecting the crude oil and natural gas industry could reduce demand for crude oil and
natural gas or increase our costs, either of which would have a material adverse impact on us.

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 hazards such as fire, explosion,
blowouts, sour gas releases and spills, each of which could result in substantial damage to oil and natural gas wells, production facilities, other property and the environment or personal injury. In particular, 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. In
accordance with industry practice, we are not fully insured against all of these risks, nor are all such risks insurable. Although we maintain liability insurance in an amount that we consider consistent with industry practice, the nature of these
risks is such that liabilities could exceed policy limits, in which event we could incur significant costs. 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. While we have both safety and environmental policies in place to protect our operators and employees and to meet regulatory requirements in areas where we operate, any costs incurred to repair damages
or pay liabilities would reduce the funds available for dividend to the Shareholders.

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:



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| |  |  | 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 not be able to effectively market the oil and
natural gas that we produce.

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.

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.

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.

Our success depends in large measure on certain key 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.



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MARKET FOR SECURITIES

Prior to January 3, 2011 the Trust Units were listed on the NYSE under the symbol and PGH and prior to January 10, 2011 the Trust
Units were listed on the TSX under the symbol PGF.UN. Our outstanding Common Shares have been listed and posted for trading on the NYSE under the symbol PGH since January 3, 2011 and on the TSX under the symbol
PGF since January 10, 2011. The following tables set forth certain trading information for the Trust Units in 2010 as reported by the TSX and the NYSE.



|                |  |         |       |  |        |  |       |        |  |  |            | 
|--------------- |  | ------- | ----- |  | ------ |  | ----- | ------ |  |  | ---------- | 
|                |  | TSX     |      
|Trust Units2010 |  | ($)High |       |  | ($)Low |  |       | Volume | 
|January         |  |         | 11.30 |  |        |  | 10.15 |        |  |  | 10,678,116 | 
|February        |  |         | 11.32 |  |        |  | 10.62 |        |  |  | 7,302,202  | 
|March           |  |         | 11.96 |  |        |  | 11.02 |        |  |  | 15,393,052 | 
|April           |  |         | 12.00 |  |        |  | 11.14 |        |  |  | 10,886,992 | 
|May             |  |         | 11.72 |  |        |  | 8.50  |        |  |  | 11,436,919 | 
|June            |  |         | 10.42 |  |        |  | 8.73  |        |  |  | 11,713,736 | 
|July            |  |         | 10.43 |  |        |  | 9.40  |        |  |  | 19,638,174 | 
|August          |  |         | 10.36 |  |        |  | 9.86  |        |  |  | 11,806,987 | 
|September       |  |         | 11.44 |  |        |  | 10.32 |        |  |  | 18,338,028 | 
|October         |  |         | 12.28 |  |        |  | 11.29 |        |  |  | 13,490,790 | 
|November        |  |         | 13.33 |  |        |  | 11.84 |        |  |  | 41,295,117 | 
|December        |  |         | 13.38 |  |        |  | 12.76 |        |  |  | 15,683,440 | 



|                |  |           |       |  |          |  |       |        |  |  |            | 
|--------------- |  | --------- | ----- |  | -------- |  | ----- | ------ |  |  | ---------- | 
|                |  | NYSE      |      
|Trust Units2010 |  | (US$)High |       |  | (US$)Low |  |       | Volume | 
|January         |  |           | 10.92 |  |          |  | 9.72  |        |  |  | 7,355,078  | 
|February        |  |           | 10.73 |  |          |  | 10.04 |        |  |  | 5,869,870  | 
|March           |  |           | 11.78 |  |          |  | 10.51 |        |  |  | 6,912,854  | 
|April           |  |           | 11.97 |  |          |  | 10.97 |        |  |  | 7,986,861  | 
|May             |  |           | 11.60 |  |          |  | 8.61  |        |  |  | 11,451,681 | 
|June            |  |           | 10.27 |  |          |  | 8.97  |        |  |  | 6,620,949  | 
|July            |  |           | 10.03 |  |          |  | 8.85  |        |  |  | 6,969,592  | 
|August          |  |           | 9.98  |  |          |  | 9.25  |        |  |  | 5,349,184  | 
|September       |  |           | 11.10 |  |          |  | 9.82  |        |  |  | 7,834,570  | 
|October         |  |           | 11.99 |  |          |  | 11.02 |        |  |  | 6,057,204  | 
|November        |  |           | 10.92 |  |          |  | 9.72  |        |  |  | 7,355,078  | 
|December        |  |           | 10.73 |  |          |  | 10.04 |        |  |  | 5,869,870  | 

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 ofResidence          |  | Position with Pengrowth(1)                                            |  | Principal Occupation                                                                                                                                                                                                                                                    |  | Common SharesControlled orBeneficially Owned(2)
|John B. Zaozirny(3)(4) 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.                                                                                                                                                     |  | 35,100                                         
|                                           |  |                                                                       | 
|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. |  | 167,501                                        
|                                           |  |                                                                       | 
|Thomas A. 
Cumming(4)(5)(6)Alberta, Canada |  | Director (Director since
2000)                                        |  | Business Consultant and Corporate Director.                                                                                                                                                                                                                             |  | 8,678                                          
|                                           |  |                                                                       | 
|Wayne K.
Foo(3)(5)
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.                                                                                           |  | 5,273                                          



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|                                            |  |                                                               |  |                                                                                                                                                                                                                                                                                                                                                                                                                                         |  |                                                
|------------------------------------------- |  | ------------------------------------------------------------- |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------- |  | -----------------------------------------------
|Name and Jurisdiction ofResidence           |  | Position with Pengrowth(1)                                    |  | Principal Occupation                                                                                                                                                                                                                                                                                                                                                                                                                    |  | Common SharesControlled orBeneficially Owned(2)
|James D. McFarland(5)(6)(7)
Alberta, Canada |  | Director (Director since
2010)                                |  | President and Chief Executive Officer of Valeura Energy Inc. (energy company) and its predecessor PanWestern Energy Inc. since April, 2010; prior thereto President and Chief
Executive Officer of Verenex Energy Inc. from March, 2004 to December, 2009.                                                                                                                                                                              |  | 15,791                                         
|                                            |  |                                                               | 
|Michael S. Parrett(3)(4)(6)
Ontario, Canada |  | Director (Director since
2004)                                |  | Business Consultant and Corporate Director.                                                                                                                                                                                                                                                                                                                                                                                             |  | 4,000                                          
|                                            |  |                                                               | 
|A. Terence Poole(3)(6) Alberta,
Canada      |  | Director (Director since
2005)                                |  | Business Consultant since 2006; prior thereto Executive Vice President, Corporate Strategy and Development at Nova Chemicals Corporation.                                                                                                                                                                                                                                                                                               |  | 50,000                                         
|                                            |  |                                                               | 
|D. Michael G. Stewart(4)(5) Alberta,
Canada |  | Director (Director since
2006)                                |  | Corporate Director.                                                                                                                                                                                                                                                                                                                                                                                                                     |  | 23,005                                         
|                                            |  |                                                               | 
|Gillian 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.                                                                                                                                                                                                          |  | nil                                            
|                                            |  |                                                               | 
|Douglas C. Bowles Alberta,
Canada           |  | Vice President and Controller                                 |  | Vice President and Controller of Pengrowth since March 2006.                                                                                                                                                                                                                                                                                                                                                                            |  | 41,780                                         
|                                            |  |                                                               | 
|James E.A. Causgrove Alberta,
Canada        |  | Vice President, Production and Operations                     |  | Vice President, Production and Operations of Pengrowth.                                                                                                                                                                                                                                                                                                                                                                                 |  | 85,532                                         
|                                            |  |                                                               | 
|William G. Christensen
Alberta, Canada      |  | Vice President, Strategic Planning and Reservoir Exploitation |  | Vice President, Strategic Planning and Reservoir Exploitation of Pengrowth.                                                                                                                                                                                                                                                                                                                                                             |  | 67,855                                         
|                                            |  |                                                               | 
|Steve J. De Maio(8) 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) from November 2006 until September 2010; prior thereto President of De Maio Consulting (consulting company).                                                                                                                                   |  | 28,207                                         
|                                            |  |                                                               | 
|Brent D. Defosse Alberta,
Canada            |  | Vice President, Drilling and Completions                      |  | Vice President, Drilling and Completions of Pengrowth since May 2010; prior thereto President of Brennex Resources Ltd. (engineering company).                                                                                                                                                                                                                                                                                          |  | 6,143                                          
|                                            |  |                                                               | 
|David Dean Evans Alberta,
Canada            |  | Treasurer                                                     |  | Treasurer of Pengrowth since February 2009; prior thereto Treasury Manager at ARC Resources Ltd.                                                                                                                                                                                                                                                                                                                                        |  | 2,060                                          
|                                            |  |                                                               | 
|Andrew D. Grasby Alberta,
Canada            |  | Vice President, General Counsel & Corporate Secretary         |  | Vice President, General Counsel & Corporate Secretary of Pengrowth since September 2010; prior thereto a partner with McCarthy Tétrault LLP (law firm).                                                                                                                                                                                                                                                                                 |  | 4,444                                          
|                                            |  |                                                               | 
|Robert W. Rosine Alberta,
Canada            |  | Executive Vice-President, Business Development                |  | Executive Vice President, Business Development of Pengrowth since March 1, 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) from February 2006 to February 2008; and prior thereto President and Chief Executive Officer of White Fire Energy Ltd.
(energy company). |  | 14,901                                         
|                                            |  |                                                               | 
|Diane J. Shirra Alberta,
Canada             |  | Vice President, Montney Gas Development                       |  | Vice President, Montney Gas Development of Pengrowth since September, 2010; prior thereto Manager Olds Growth Team with Pengrowth since January 2010; prior thereto Manager
Exploitation Engineering, Southern with Pengrowth since 2008; prior thereto Director Rocky Business Unit and Director, Exploration with Canetic Resources Trust (energy trust).                                                                             |  | 9,209                                          



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|                                       |  |                            |  |                                       |  |                                                
|-------------------------------------- |  | -------------------------- |  | ------------------------------------- |  | -----------------------------------------------
|Name and Jurisdiction ofResidence      |  | Position with Pengrowth(1) |  | Principal Occupation                  |  | Common SharesControlled orBeneficially Owned(2)
|Christopher G. Webster
Alberta, Canada |  | Chief Financial Officer    |  | Chief Financial Officer of Pengrowth. |  | 204,847                                        

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) | As at December 31, 2010 and excluding Common Shares issuable upon the exercise of outstanding rights or deferred entitlement units.
|--- | -----------------------------------------------------------------------------------------------------------------------------------

|(3) | Member of Corporate Governance and Nominating Committee.
|--- | --------------------------------------------------------

|(4) | Member of Compensation Committee.
|--- | ---------------------------------

|(5) | Member of Reserves, Operations and Environmental, Health and Safety Committee.
|--- | ------------------------------------------------------------------------------

|(6) | Member of Audit and Risk Committee.
|--- | -----------------------------------

|(7) | 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.
|--- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|(8) | 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.
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

As at December 31, 2010, the foregoing directors and officers, as a group,
beneficially owned, directly or indirectly, 774,326 Common Shares or approximately 0.24 percent of the issued and outstanding Common Shares and held rights and deferred entitlement units to acquire a further 1,803,318 Common Shares. The information
as to shares beneficially owned, not being within our knowledge, has been furnished by the respective individuals.

The term of 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 10 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.



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AUDIT AND RISK COMMITTEE

The Audit and Risk Committee is appointed annually by our Board of Directors. The responsibilities and duties of the Audit and Risk Committee are set
forth in the Audit and Risk Committee Terms of Reference attached hereto as Appendix 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 |  | FinanciallyLiterate |  | 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 is currently Chairman of Albertas Electricity Balancing Pool. 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 38 years of experience in the oil and gas industry, most recently as President, Chief Executive Officer, director and co-founder of Valeura Energy Inc.,
a Toronto Stock Exchange listed issuer. Prior thereto Mr. McFarland was President, Chief Executive Officer, director and a co-founder of Verenex Energy Inc. He has served in senior executive roles as Managing Director of Southern Pacific Petroleum
N.L. in Australia, President and Chief Operating Officer of Husky Oil Limited and in a wide range of upstream and corporate functions in an earlier 23-year career with Imperial Oil Limited and other Exxon affiliates in Canada, the US and western
Europe. Mr. McFarland is a member of the Association of Professional Engineers, Geologists and Geophysicists of Alberta, and the Society of Petroleum Engineers International. 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 currently an independent consultant providing advisory service to various companies in Canada and the United States. Mr. Parrett is a director of Stillwater Mining
Company, a NYSE listed company. 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 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 2010 and 2009:



|                   |  |          |       |  |          |  |       | 
|------------------ |  | -------- | ----- |  | -------- |  | ----- | 
|                   |  | 2010($M) |       |  | 2009($M) | 
|Audit Fees         |  |          | 923   |  |          |  | 1,314 | 
|Audit Related Fees |  |          |      |  |          |  |      | 
|Tax Fees           |  |          | 80    |  |          |  | 208   | 
|All Other Fees     |  |          |      |  |          |  |      | 
|                   |  |          |       |  |          |  |       | 
|Total              |  |          | 1,003 |  |          |  | 1,522 | 

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.



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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 2010 and 2009 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.

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.

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.

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



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the designated appointees in 2008, 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, 2010.

Mr. John Zaozirny, the Chairman of the Board of Directors, is the Vice Chair of Canaccord Genuity Corporation.
Canaccord Genuity Corporation participated as a member of the syndicate of underwriters in connection with the October 23, 2009 equity offering by the Trust of 28,847,000 Trust Units and received a portion of the underwriters fee
from the offering.

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 Computershare Trust Company of Canada at its principal offices in the cities of Montreal, Toronto, Calgary and Vancouver in Canada and
Computershare Trust Company, Inc. at its principal office in the City of Golden, Colorado in the United States. 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 Arrangement Agreement dated November 5, 2010 among the Trust, Pengrowth Corporation, Esprit Energy Trust, Pengrowth Holding Trust, 1552168 Alberta Ltd.,
Monterey and the Corporation providing for the implementation of the Arrangement, as from time to time amended, supplemented or restated;
| | --- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | (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 May 11, 2010 concerning the 2010 Senior Notes;
| | ----- | --------------------------------------------------------------------------------



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



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



| | (vi) | the Note Purchase Agreement dated December 1, 2005 concerning the UK Senior Notes; and
| | ---- | --------------------------------------------------------------------------------------



| | (vii) | 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 Ethics, and is available in print to any Shareholder who requests it.

The Board adopted the Code of Ethics on December 16, 2010. The Code of Ethics is substantially similar to the Code of Ethics that was in place for
Pengrowth Corporation. All Directors, officers, employees, consultants and contractors are required to accept the Code of Ethics annually.

During the year ended December 31, 2010, 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.



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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, Operations and Environmental, Health and Safety Committee, a Code of
Business Conduct and Ethics, a Corporate Disclosure Policy, an Insider Trading Policy and a Whistleblower 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 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. If the 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. As a matter of practice, Pengrowth has obtained the approval of its Shareholders
to all of its equity compensation plans, regardless of whether the Common Shares to be delivered under such plans are newly issued or purchased on the open market, with the exception of the Trust Unit Awards Plan which has been used as an employee
retention and hiring mechanism when required by the tight employment market in the Canadian oil and gas industry.

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 dated March 8, 2011, which relates to the Annual Meeting of Shareholders to be held on May 5, 2011.
Additional financial information is contained in our comparative consolidated financial statements and associated managements discussion and analysis for the years ended December 31, 2010 and 2009.

Additional information relating to us may be found on SEDAR at www.sedar.com.

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



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APPENDIX A

FORM 51-101F2

REPORT ON RESERVES DATA

BY

INDEPENDENT QUALIFIED RESERVES

EVALUATOR OR AUDITOR

To the board of directors of Pengrowth Energy Corporation (the
Corporation):



|1. | We have prepared an evaluation of the Corporations reserves data as at December 31, 2010. The reserves data are estimates of proved reserves and probable
reserves and related future net revenue as at December 31, 2010, estimated using forecast prices and costs.
|-- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|2. | The reserves data are the responsibility of the Corporations management. Our responsibility is to express an opinion on the reserves data based on our evaluation.
|-- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------

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



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



|4. | The following table sets forth the estimated future net revenue (before deduction of income taxes) attributed to proved plus probable reserves, estimated using forecast
prices and costs and calculated using a discount rate of 10 percent, included in the reserves data of the Corporation evaluated by us for the year ended December 31, 2010, and identifies the respective portions thereof that we have evaluated
and reported on to the Corporations board of directors:
|-- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|                                         |  |                                                     |         |                                                        |  |                                                                                             |   |  |          |  |           |       |  |  |   |  |  |  |           | 
|---------------------------------------- |  | --------------------------------------------------- | ------- | ------------------------------------------------------ |  | ------------------------------------------------------------------------------------------- | - |  | -------- |  | --------- | ----- |  |  | - |  |  |  | --------- | 
|Independent Qualified Reserves
Evaluator |  | Description andPreparation Date ofEvaluation Report |         | Location ofReserves (Countryor ForeignGeographic Area) |  | Net Present Value of Future Net
Revenue(before income taxes, 10 percent discount rate - $M) |  
|                                         |  |                                                     | Audited |                                                        |  | Evaluated                                                                                   |   |  | Reviewed |  |           | Total | 
|GLJ Petroleum Consultants                |  | January 19, 2011                                    |         | Canada                                                 |  |                                                                                             |  |  |          |  | 4,636,444 |       |  |  |  |  |  |  | 4,636,444 | 



|5. | In our opinion, the reserves data respectively evaluated by us have, in all material respects, been determined and are in accordance with the COGE Handbook,
consistently applied. We express no opinion on the reserves data that we reviewed but did not audit or evaluate.
|-- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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



|7. | Because the reserves data are based on judgments regarding future events, actual results will vary and the variations may be material.
|-- | --------------------------------------------------------------------------------------------------------------------------------------



|                                                                        
|------------------------------------------------------------------------
|EXECUTED as to our report referred to above:                            
|                                                                        
|GLJ Petroleum Consultants Ltd., Calgary, Alberta, Canada, March 7, 2011.
|                                                                        
|(signed) Doug R. Sutton                                               
|Doug R. Sutton, P.Eng.                                                  
|                                                                        
|Vice President                                                          



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##### Table of Contents

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, 2010, 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, Operations and Environmental, Health and Safety 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, Operations and Environmental, Health and Safety 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, Operations and Environmental, Health and Safety 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) William G. Christensen                            
|William G. Christensen                                       
|Vice President, Strategic Planning and Reservoir Exploitation
|Pengrowth Energy Corporation                                 
|                                                             
|(signed) Wayne Foo                                         
|Wayne Foo                                                    
|Director                                                     
|Pengrowth Energy Corporation                                 
|                                                             
|(signed) D. Michael G. Stewart                             
|D. Michael G. Stewart                                        
|Director                                                     
|Pengrowth Energy Corporation                                 
|                                                             
|March 8, 2011                                                



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APPENDIX C

AUDIT AND RISK COMMITTEE

TERMS OF REFERENCE



|                                            |  |                                                               |  |            
|------------------------------------------- |  | ------------------------------------------------------------- |  | -----------
|LOGO                                        |  | PENGROWTH ENERGY CORPORATION
Executive Policies and Practices |  | Page1 of 14
|                                           
|TERMS OF REFERENCE
AUDIT AND RISK COMMITTEE

OBJECTIVES

The Audit and
Risk 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 Audit and Risk
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 Audit and Risk 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 Audit and Risk 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

Audit and
Risk Committee members must meet the requirements of applicable securities laws and each of the stock exchanges on which the shares of Pengrowth trade. The Audit and Risk Committee will be comprised of three or more directors as determined by the
Board. Each member of the Audit and Risk 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



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##### Table of Contents

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 Audit and Risk Committee must have accounting or related
financial management expertise as defined by paragraph (8) of general instruction B to Form 40-F and as interpreted by the Board in its business judgement.

The members of the Committee shall be appointed by the Board as members of the Committee and shall continue as such until their successors are appointed or until they cease to be directors of the
Corporation. At any time, the Board may fill any vacancy in the membership of the Committee.

The chair of the Audit and Risk Committee shall
be appointed by the Board. If an Audit and Risk Committee chair is not designated or present at a meeting of the Audit and Risk Committee, the members of the Audit and Risk Committee may designate a chair by majority vote of the Audit and Risk
Committee membership.

MEETINGS AND MINUTES

The Audit and Risk 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 Audit and Risk Committee, the Board Chairman or the President and Chief Executive Officer
(CEO) of Pengrowth. A notice of time and place of every meeting of the Audit and Risk Committee shall be given in writing to each member of the Audit and Risk 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 Audit and Risk 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 Audit and Risk Committee shall require a majority of its members present in person or by telephone. If the chair of the Audit and Risk Committee is not present at any meeting of the Audit and Risk Committee, one of the other members
of the Audit and Risk Committee present at the meeting will be chosen to preside by a majority of the members of the Audit and Risk Committee present at that meeting.

The Board Chairman and the CEO shall be available to advise the Audit and Risk Committee, shall receive notice of meetings and may attend meetings of the Audit and Risk 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 Audit and Risk Committee shall hold in camera
sessions, without management present, at every meeting of the Committee.

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

The Audit and Risk Committee shall appoint a member of the Audit and Risk 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 Audit and Risk
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 Audit and
Risk Committee. All information reviewed and discussed by the Audit and Risk Committee at any meeting shall be referred to in the minutes and made available for examination by the Board upon request to the chair.



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SCOPE, DUTIES AND RESPONSIBILITIES

MANDATORY DUTIES

REVIEW PROCEDURES

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



|1. | Review and reassess the adequacy of the Audit and Risk Committees Terms of Reference at least annually, submit the Terms of Reference to the Board for approval
and have the document published annually in Pengrowths annual information circular and at least every three years in accordance with the regulations of the United States Securities and Exchange Commission.
|-- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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



|3. | Ensure that adequate procedures are in place for the review of Pengrowths public disclosure of financial information extracted or derived from Pengrowths
financial statements, other than the public disclosure referred to in paragraph 2 above and periodically assess the adequacy of those procedures.
|-- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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

EXTERNAL AUDITORS



|1. | The Audit and Risk Committee shall advise the external auditors of their accountability to the Audit and Risk 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 Audit and Risk Committee. The Audit and Risk 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 Audit and Risk 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.
|-- | ----------------------------------------------------------------------------



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|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 AUDIT AND RISK COMMITTEE
RESPONSIBILITIES



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



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

DISCRETIONARY DUTIES

The Audit and Risk Committees responsibilities may, at the Audit and Risk Committees discretion, also include the following:

REVIEW PROCEDURES



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



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



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



|4. | Conduct an annual performance evaluation of the Audit and Risk 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 Board Chairman and the President and CEO.
|-- | ----------------------------------------------------------------------------------------------

EXTERNAL AUDITORS



|1. | On an annual basis, the Audit and Risk Committee should review and discuss with the external auditors all significant relationships they have with Pengrowth that could
impair the auditors independence.
|-- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



-C4-



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##### Table of Contents

|2. | The Audit and Risk Committee shall review the external auditors audit plan  discuss scope, staffing, locations, and reliance upon management and general audit
approach.
|-- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|3. | Consider the external auditors judgments about the quality and appropriateness of Pengrowths accounting principles as applied in its financial reporting.
|-- | -----------------------------------------------------------------------------------------------------------------------------------------------------------



|4. | Be responsible for the resolution of disagreements between management and the external auditors regarding financial performance.
|-- | --------------------------------------------------------------------------------------------------------------------------------



|5. | Ensure compliance by the external auditors with the requirements set forth in National Instrument 52-108 Auditor Oversight.
|-- | ---------------------------------------------------------------------------------------------------------------------------



|6. | Ensure that the external auditors are participants in good standing with the Canadian Public Accountability Board (CPAB) and participate in the
oversight programs established by the CPAB from time to time and that the external auditors have complied with any restrictions or sanctions imposed by the CPAB as of the date of the applicable auditors report relating to Pengrowths
annual audited financial statements.
|-- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|7. | Monitor compliance with the lead auditor rotation requirements of Regulation S-X.
|-- | ---------------------------------------------------------------------------------

RISK MANAGEMENT POLICIES

Review and recommend
for approval by the Board changes considered advisable, after consultation with officers of the Corporation, to the Corporations policies relating to:



| | (a) | The risks inherent in the Corporations businesses, facilities, strategic direction;
| | --- | ------------------------------------------------------------------------------------



| | (b) | The overall risk management strategies (including insurance coverage);
| | --- | ----------------------------------------------------------------------



| | (c) | The risk retention philosophy and the resulting uninsured exposure of the Corporation; and
| | --- | ------------------------------------------------------------------------------------------



| | (d) | The loss prevention policies, risk management and hedging programs, and standard and accountabilities of the Corporation in the context of competitive and operational
considerations.
| | --- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

RISK MANAGEMENT PROCESSES

Review with management at least annually the Corporations processes to identify, monitor, evaluate and address important enterprise-wide business
risks.

FINANCIAL RISK MANAGEMENT



|Review | with management activity related to management of financial risks to the Corporation.
|------ | -------------------------------------------------------------------------------------

OTHER AUDIT AND RISK 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.
|-- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



-C5-



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##### Table of Contents

|4. | Review all exceptions to established policies, procedures and internal controls of Pengrowth, which have been approved by any two officers of Pengrowth.
|-- | --------------------------------------------------------------------------------------------------------------------------------------------------------



|5. | Perform any other activities consistent with this Charter, Pengrowths by-laws, and other governing law as the Audit and Risk 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 Audit and Risk 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 Audit and Risk Committee, on a confidential basis, any concerns relating to matters over which the Audit and Risk
Committee has oversight responsibilities.

The Audit and Risk 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 Audit and Risk Committee that are deemed necessary or appropriate by the Audit and Risk Committee in order to carry out its duties.

Adopted by the Board of Pengrowth on March 8, 2011.



-C6-



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##### Table of Contents

Schedule A

Excerpt from Multilateral Instrument 52-110

Standard 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
| | --- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



---

##### Table of Contents

| | (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 the issuer during any 12 month period within the last three years.
| | --- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|4. | For the purposes of paragraphs 3(c) and 3(d), a partner does not include a fixed income partner whose interest in the firm that is the internal or external auditor is
limited to the receipt of fixed compensation (including deferred compensation) for prior service with that firm if the compensation is not contingent in any way on continued service.
|-- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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



| | (a) | remuneration for acting as a member of the Board or 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. | Despite any determination made under paragraphs 1 through 6, 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.



|8. | For the purposes of paragraph 7, 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.
| | --- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



A-2

to Appendix C



---

##### Table of Contents

|9. | For the purposes of paragraph 7, 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.



A-3

to Appendix C



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##### Table of Contents

Schedule B

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

Standard of Independence



|b. | Required standards.
|-- | -------------------



|1. | Independence.
|-- | -------------



| | i. | Each member of the audit committee must be a member of the board of directors of the listed issuer, and must otherwise be independent; provided that, where a listed
issuer is one of two dual holding companies, those companies may designate one audit committee for both companies so long as each member of the audit committee is a member of the board of directors of at least one of such dual holding companies.
| | -- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | ii. | Independence requirements for non-investment company issuers. In order to be considered to be independent for purposes of this paragraph (b)(1), a member of an
audit committee of a listed issuer that is not an investment company may not, other than in his or her capacity as a member of the audit committee, the board of directors, or any other board committee:
| | --- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | A. | Accept directly or indirectly any consulting, advisory, or other compensatory fee from the issuer or any subsidiary thereof, provided that, unless the rules of the
national securities exchange or national securities association provide otherwise, compensatory fees do not include the receipt of fixed amounts of compensation under a retirement plan (including deferred compensation) for prior service with the
listed issuer (provided that such compensation is not contingent in any way on continued service); or
| | -- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | B. | Be an affiliated person of the issuer or any subsidiary thereof.
| | -- | ----------------------------------------------------------------



|e. | Definitions. Unless the context otherwise requires, all terms used in this section have the same meaning as in the Act. In addition, unless the context otherwise
requires, the following definitions apply for purposes of this section:
|-- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

1.



| | i. | The term affiliate of, or a person affiliated with, a specified person, means a person that directly, or indirectly through one or more intermediaries,
controls, or is controlled by, or is under common control with, the person specified.
| | -- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

ii.

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



| | 1. | Is not the beneficial owner, directly or indirectly, of more than 10% of any class of voting equity securities of the specified person; and
| | -- | -------------------------------------------------------------------------------------------------------------------------------------------



| | 2. | Is not an executive officer of the specified person.
| | -- | ----------------------------------------------------



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##### Table of Contents

| | B. | Paragraph (e)(1)(ii)(A) of this section only creates a safe harbor position that a person does not control a specified person. The existence of the safe harbor does not
create a presumption in any way that a person exceeding the ownership requirement in paragraph (e)(1)(ii)(A)(1) of this section controls or is otherwise an affiliate of a specified person.
| | -- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | iii. | The following will be deemed to be affiliates:
| | ---- | ----------------------------------------------



| | A. | An executive officer of an affiliate;
| | -- | -------------------------------------



| | B. | A director who also is an employee of an affiliate;
| | -- | ---------------------------------------------------



| | C. | A general partner of an affiliate; and
| | -- | --------------------------------------



| | D. | A managing member of an affiliate.
| | -- | ----------------------------------



| | iv. | For purposes of paragraph (e)(1)(i) of this section, dual holding companies will not be deemed to be affiliates of or persons affiliated with each other by virtue of
their dual holding company arrangements with each other, including where directors of one dual holding company are also directors of the other dual holding company, or where directors of one or both dual holding companies are also directors of the
businesses jointly controlled, directly or indirectly, by the dual holding companies (and, in each case, receive only ordinary-course compensation for serving as a member of the board of directors, audit committee or any other board committee of the
dual holding companies or any entity that is jointly controlled, directly or indirectly, by the dual holding companies).
| | --- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|4. | The term control (including the terms controlling, controlled by and under common control with) means the possession, direct or indirect, of the power to direct or
cause the direction of the management and policies of a person, whether through the ownership of voting securities, by contract, or otherwise.
|-- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|8. | The term indirect acceptance by a member of an audit committee of any consulting, advisory or other compensatory fee includes acceptance of such a fee by a spouse, a
minor child or stepchild or a child or stepchild sharing a home with the member or by an entity in which such member is a partner, member, an officer such as a managing director occupying a comparable position or executive officer, or occupies a
similar position (except limited partners, non-managing members and those occupying similar positions who, in each case, have no active role in providing services to the entity) and which provides accounting, consulting, legal, investment banking or
financial advisory services to the issuer or any subsidiary of the issuer.
|-- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



B-2

to Appendix C



---

##### Table of Contents

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). Companies must identify which directors are independent and disclose the basis for that determination.
| | --- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | (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 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.
| | --- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



---

##### Table of Contents

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.

For the
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.



C-2

to Appendix C



---

##### Table of Contents

APPENDIX B

MANAGEMENTS DISCUSSION AND ANALYSIS



---

##### Table of Contents

SUMMARY OF FINANCIAL & OPERATING RESULTS  (monetary amounts in thousands, except
per share amounts or as otherwise stated)

Three Months ended December 31


Twelve Months ended December 312010


2009


% Change


2010


2009


% ChangeSTATEMENT OF INCOMEOil and gas sales

$
340,690


$
359,296



(5
)

$
1,353,283


$
1,343,167



1Net income

$
1,937


$
50,523



(96
)

$
230,257


$
84,853



171Net income per share
(1)

$
0.01


$
0.18



(94
)

$
0.76


$
0.32



138CASH FLOWCash flow from operating activities

$
137,783


$
149,933



(8
)

$
605,995


$
551,350



10Cash flow from operating activities per share (1)

$
0.42


$
0.53



(21
)

$
2.01


$
2.09



(4
)Total capital expenditures
(2)

$
134,296


$
51,331



162


$
357,704


$
216,778



65Total capital expenditures per share (1)

$
0.41


$
0.18



128


$
1.19


$
0.82



45Distributions paid

$
67,413


$
66,548



1


$
250,640


$
334,405



(25
)Distribution paid per unit
(1)

$
0.21


$
0.24



(13
)

$
0.84


$
1.28



(34
)Weighted average number of shares outstanding (000's) (1)


325,515



282,298



15



301,026



264,121



14BALANCE SHEETWorking capital (deficiency)













$
(91,629
)

$
(217,007
)(3)


(58
)Property, plant and equipment













$
4,076,976


$
3,789,369



8Long term debt













$
1,024,367


$
907,599



13Shareholders' equity













$
3,186,976


$
2,795,201



14Shareholders' equity per share
(1)













$
9.78


$
9.64



1Currency (U.S.$/Cdn$) (closing rate at period end)













$
1.0054


$
0.9515Number of shares outstanding at period end (000's)(1)














326,024



289,835



12AVERAGE DAILY PRODUCTIONCrude oil (bbls)


21,762



21,948



(1
)


21,743



22,841



(5
)Heavy oil (bbls)


6,673



7,235



(8
)


6,789



7,551



(10
)Natural gas (mcf)


218,044



232,682



(6
)


219,302



237,217



(8
)Natural gas liquids (bbls)


10,177



9,564



6



9,611



9,590



0Total production (boe)


74,953



77,529



(3
)


74,693



79,518



(6
)TOTAL PRODUCTION (mboe)


6,896



7,133



(3
)


27,263



29,024



(6
)PRODUCTION PROFILECrude oil


29%



28%







29%



29%Heavy oil


9%



9%







9%



9%Natural gas


48%



50%







49%



50%Natural gas liquids


14%



13%







13%



12%AVERAGE REALIZED PRICES (after commodity risk management)Crude oil (per bbl)

$
74.98


$
75.79



(1
)

$
75.04


$
72.36



4Heavy oil (per bbl)

$
60.42


$
62.16



(3
)

$
60.22


$
52.72



14Natural gas (per mcf)

$
4.87


$
5.45



(11
)

$
5.00


$
5.14



(3
)Natural gas liquids (per bbl)

$
56.74


$
54.52



4


$
56.99


$
42.12



35Average realized price per boe

$
49.01


$
50.35



(3
)

$
49.34


$
46.19



7PROVED PLUS PROBABLE RESERVESCrude oil (mbbls)














110,297



112,249



(2
)Heavy oil (mbbls)














26,472



27,724



(5
)Natural gas (bcf)














913



757



21Natural gas liquids (mbbls)














29,481



29,587



0Total oil equivalent (mboe)














318,429



295,734



8CAPITAL PERFORMANCEFinding & Development Cost (F&D) (per boe) (4)













$
15.32


$
30.81



(50
)Finding, Development & Acquisition Cost (FD&A) (per boe) (4)













$
18.46


$
57.16



(68
)Recycle Ratio
(5)














1.72



0.82



110SUMMARY OF COMMON SHARE TRADINGNYSE PGH ($U.S.)High

$
13.25


$
10.52



26


$
13.25


$
10.54



26Low

$
11.02


$
8.81



25


$
7.67


$
4.51



70Close

$
12.86


$
9.63



34


$
12.86


$
9.63



34TSX PGF ($Cdn)High

$
13.38


$
11.39



17


$
13.38


$
12.33



9Low

$
11.29


$
9.40



20


$
8.50


$
5.84



46Close

$
12.78


$
10.15



26


$
12.78


$
10.15



26  (1)
Pengrowth Energy Corporation is the entity resulting from the conversion of Pengrowth Energy Trust see note regarding conversion below.  (2)
Total capital expenditures excludes Drilling Royalty Credits ("DRCs")  (3)
Includes $157.5 million current portion of long term debt.  (4)
Includes the changes in Future Development Capital ("FDC") and based on Proved plus Probable Reserves.  (5)
Recycle Ratio is calculated as operating netback per boe divided by F&D costs per boe based on proved plus probable reserves. Note regarding corporate conversion: Pengrowth Energy Corporation is the entity resulting from the conversion of Pengrowth Energy Trust to a dividend
paying corporation effective December 31, 2010. References to shares, shareholder and dividends should be read as references to trust units, trust unitholder and
distributions respectively for periods prior to December 31, 2010. Note regarding currency: all figures contained within
this report are quoted in Canadian dollars unless otherwise indicated.




|                                                        |  |  |          | 
|------------------------------------------------------- |  |  | -------- | 
|PENGROWTH 2010 Summary of Financial & Operating Results |  |  | 3 

LOGO | 



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##### Table of Contents

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, 2010 of Pengrowth Energy Corporation and the consolidated financial
statements and MD&A of Pengrowth Energy Trust for the year ended December 31, 2009. The MD&A is based on information available to March 8, 2011. STRUCTURE OF THE CORPORATION Pengrowth Energy Corporation (the Corporation) is a Canadian resource company that is engaged in the production, development, exploration and acquisition of oil and natural gas assets. The
Corporation was formed through a reorganization involving Pengrowth Energy Trust (the Trust), Pengrowth Corporation, its subsidiaries and the
security holders of the Trust and Pengrowth Corporation pursuant to a Plan of Arrangement (the Arrangement) under the Business Corporations Act (Alberta). On December 31, 2010 (the Date of Conversion), the Trust completed its conversion from an open-end
investment trust to a corporation through a business combination resulting in the unitholders of the Trust and the exchangeable shareholders of Pengrowth Corporation owning all the common shares of the Corporation. Unitholders of the Trust received
common shares in the Corporation on a one-for-one basis. Exchangeable shareholders of Pengrowth Corporation received 1.02308 common shares of the Corporation for each exchangeable share held. Pursuant to the Arrangement agreement,
shareholders capital was reduced by the amount of the deficit of the Trust on December 31, 2010. The management team and Board of Directors of the Corporation are comprised of the former management team and elected members of the Board of
Directors of the Trust. The Corporation effected an internal reorganization subsequent to the Date of Conversion whereby, among other things, the
Trust and its subsidiaries were dissolved and the Corporation received all the assets and assumed all the liabilities of the Trust. The Arrangement has
been accounted for on a continuity of interest basis and accordingly, the consolidated financial statements for periods prior to the date of conversion reflect the financial position, results of operations and cash flows as if the Corporation had
always carried on the business formerly carried on by the Trust. This MD&A may at times refer to common shares, shareholders, shareholders capital and dividends which prior to the Arrangement were referred to as trust units, trust
unitholders, trust unitholders capital and distributions, respectively. References made to trust units are those issued by the Trust. Comparative amounts in this MD&A will also reflect the history of the Trust and its subsidiaries. This MD&A will refer to Pengrowth which collectively includes the Corporation, the Trust and its subsidiaries. FREQUENTLY RECURRING TERMS Pengrowth uses the
following frequently recurring industry terms in this MD&A: bbls refers to barrels,
mbbls refers to thousands of barrels,
boe refers to barrels of oil equivalent, mboe refers to a thousand barrels of oil equivalent, mcf refers to thousand cubic feet, bcf refers to billion cubic feet, gj refers to
gigajoule, mmbtu refers to million British thermal units and MW refers to megawatt. 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 StatesPrivate 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, 2011 production, the proportion of 2011 production of each product type, production additions from
Pengrowth's 2011 development program, royalty expenses, 2011 operating expenses, future 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.




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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, 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. Although management considers these assumptions to be reasonable based on information currently available to it, they may prove to be incorrect. By their very nature, forward-looking statements involve inherent risks and uncertainties, both general and specific, and risks that predictions, forecasts,
projections and other forward-looking statements will not be achieved. We caution readers not to place undue reliance on these statements as a number of important factors could cause the actual results to differ materially from the beliefs, plans,
objectives, expectations and anticipations, estimates and intentions expressed in such forward-looking statements. These factors include, but are not limited to: the volatility of oil and gas prices; production and development costs and capital
expenditures; the imprecision of reserve estimates and estimates of recoverable quantities of oil, natural gas and liquids; Pengrowth's 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; Pengrowth's ability to access external sources of debt and equity capital; the implementation of International
Financial Reporting Standards; 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 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 financial
statements are prepared in accordance with Canadian Generally Accepted Accounting Principles (GAAP). Management is required to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the 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. The amounts recorded for depletion and depreciation of property, plant and equipment, amortization of injectants, share based compensation, goodwill
and future taxes are based on estimates. The ceiling test calculation is based on estimates of proved reserves, production rates, oil and natural gas prices, future costs and other relevant assumptions. Values assigned to the various assets and
liabilities of the Monterey Exploration Ltd. (Monterey) business combination were based on internal and third party estimates. The amounts recorded for the fair value of risk management contracts and the unrealized gains or losses on the change in
fair value are based on estimates. The provision for asset retirement obligations is based on estimates affected by assumptions around timing and cost estimates for the related work activity. These estimates can change significantly from period to
period. As required by National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities, Pengrowth uses independent qualified reserve evaluators in the preparation of the annual reserve evaluations. By their nature, these estimates are
subject to measurement uncertainty and changes in these estimates may impact the consolidated financial statements of future periods.




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##### Table of Contents

NON-GAAP FINANCIAL MEASURES This MD&A refers to certain financial measures that are not determined in accordance with GAAP in Canada or the United States. 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, as compared to debt or equity, can be determined when it is compared to the
difference in cash flow from operating activities and dividends paid in the financing section of the Statement of Cash Flow. 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 cash flow from operations. 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 (EBITDA) and Total Debt to Total Capitalization. Total Debt is the sum of working capital
deficit and long term debt as shown on the balance sheet, and Total Capitalization is the sum of Total Debt and Shareholders equity. NON-GAAP 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. Company
interest is more fully described in the Corporation's 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. Production volumes, revenues and reserves are reported on a company interest gross basis (before royalties) in accordance with Canadian practice. Pengrowths ability to grow both reserves and production can be measured with the following metrics: Reserves per debt adjusted share and production per debt
adjusted share. Reserves per debt adjusted share is measured using year-end Proved plus Probable reserves and the number of common shares outstanding at year-end. The measurements are debt-adjusted by assuming additional shares are issued at
year-end share prices to replace year-end long-term debt outstanding. Production per debt adjusted share is measured in respect of the average
production for the year and the weighted average number of common shares outstanding during the year. The measurements are 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.




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##### Table of Contents

Pengrowths fourth quarter and annual results for 2010 are contained within this MD&A. 2010 GUIDANCE AND FINANCIAL HIGHLIGHTS The
following table provides a summary of the 2010 and 2011 Guidance and a review of 2010 actual results.  2010


2010


2010


2011Actual


Guidance


Variance


GuidanceProduction (boe/d)


74,693



74,000 - 75,000







74,000 - 76,000Royalty Expense (% of Sales)(1)


19.8



20.0



(0.2
)


20.0Operating Expense ($/boe)


13.63



13.60



0.03



13.54G&A Expense (cash & non-cash) ($/boe)


1.87



2.23



(0.36
)


2.69Total capital expenditures ($ millions)(2)


357.7



350.0



7.7



400.0  (1)
Royalty expense as a % of sales excludes the impact of commodity risk management contracts.  (2)
Total capital expenditures excludes Drilling Royalty Credits.  

Operating expenses for the full year were essentially in line with guidance.  

Increased capital spending on oil focused drilling in the fourth quarter resulted in Pengrowth exceeding spending targets. FINANCIAL HIGHLIGHTS  (monetary amounts in thousands, except
per boe amounts or as otherwise stated)

Three months ended


Twelve months endedDec 31, 2010


Sept 30, 2010


Dec 31, 2009


Dec 31, 2010


Dec 31, 2009Production (boe/d)


74,953



72,704



77,529



74,693



79,518Net capital expenditures(1)

$
130,874


$
87,677


$
46,215


$
333,842


$
207,451Cash flow from operating activities

$
137,783


$
159,926


$
149,933


$
605,995


$
551,350Netback ($/boe)(2)

$
24.58


$
26.12


$
26.63


$
26.37


$
25.38Net income

$
1,937


$
125,632


$
50,523


$
230,257


$
84,853Included in net income:Gain on equity investment

$



$
73,756


$



$
73,756


$
Realized gain on commodityrisk management(3)

$
19,102


$
25,689


$
27,855


$
75,065


$
171,147Unrealized (loss) gain on commodity risk management(3)

$
(52,529
)

$
(898
)

$
(40,101
)

$
6,949


$
(173,726
)Unrealized foreign exchange gain(3)

$
29,742


$
30,579


$
18,124


$
49,918


$
149,233Future tax reduction

$
24,388


$
11,884


$
67,806


$
44,829


$
142,945  (1)
Net capital expenditures includes Drilling Royalty Credits  (2)
Includes the impact of realized commodity risk management contracts  (3)
Pre-tax amount




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Cash flow from operations The following table provides a reconciliation of the change in cash flow from operations from period end 2009 to period end 2010.  ($ thousands)

Q4


% Change


Full Year


% Change2009 Cash flow from Operating Activities


149,933







551,350Volume variance


(7,200
)


(5
)


(65,938
)


(12
)Price variance


(5,387
)


(4
)


165,822



30Processing income variance


1,652



1



1,840



Lower cash gains on risk management contracts


(8,753
)


(6
)


(96,082
)


(17
)Royalty expense


10,087



7



(45,136
)


(8
)Expenses:Transportation


(156
)






(2,272
)


Operating


(14,769
)


(10
)


12,696



2Cash G&A and management fee


2,562



2



10,534



2Interest and financing expense


(1,378
)


(1
)


9,810



2Drilling Credits acquired










16,727



3Realized foreign exchange loss


127







(2,550
)


Non-cash working capital and other items


11,065



7



49,194



92010 Cash flow from Operating Activities


137,783



(8
)


605,995



10 Cash flow from
operating activities decreased eight percent from the fourth quarter of 2009 to 2010. The decrease was driven by a combination of lower production volumes, lower average realized commodity prices and higher operating costs. The decrease in cash flow
was partly offset by lower royalties and G&A expenses. Cash flow from operating activities increased 10 percent on a year over year basis. Higher
liquids commodity prices in 2010 compared to 2009 combined with lower operating expense and G&A expenses in the current year contributed to higher cash flows in 2010 but were partially mitigated by lower production volumes and higher royalty
expenses. Price Sensitivity The following table
illustrates the sensitivity of cash flow from operating activities to changes in commodity prices:  Impact on 2011 AnnualCommodity Price
Environment(1)



Assumption


Change


Cash Flow ($'000s)(2)West Texas Intermediate Oil Price(3)

US$/bbl


79.40


$
1.00



10,832Heavy Oil

US$/bbl


79.40


$
1.00



1,865Light Oil

US$/bbl


79.40


$
1.00



6,084NGL

US$/bbl


79.40


$
1.00



2,883AECO Natural Gas Price(3)




4.06


$
0.10



6,491Natural Gas

C$/mcf


4.06


$
0.10



6,491  (1)
Calculations are performed independently and are not indicative of actual results when multiple variables change at the same time.  (2)
The calculated impact on revenue/cash flow is only applicable within a limited range of the change indicated.  (3)
Does not include the impact of risk management contracts. For 2011, risk management contracts represent approximately 32% of forecasted total liquids production and 22% of
forecasted natural gas production. Net Income or Loss For the fourth quarter of 2010, net income of $1.9 million was recorded, a $48.6 million decrease from the same period last year. The decrease is largely attributable to changes in certain non-cash items including:  

An unrealized loss on commodity risk management contracts of $52.5 million ($37.7 million, net of tax) compared to $40.1 million
($28.8 million, net of tax) in the fourth quarter of 2009.




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

Future income tax reductions decreased $43.4 million in the fourth quarter 2010 primarily from changes in non-cash items affecting net income.  

Partially offsetting these decreases was a higher unrealized foreign exchange gain of $29.7 million ($25.9 million, net of tax) compared to
$18.1 million ($15.8 million, net of tax) in the fourth quarter of 2009. On a year-over-year basis, net income was $230.3
million, an increase of $145.4 million from the same period last year. Contributing to the increase was a 10 percent increase in cash flow from operating activities and changes to certain non-cash items including:  

A non-cash gain of $73.8 million ($73.8 million, net of tax) arising from the difference between the fair value and the book value of the investment in Monterey
prior to the acquisition as described in Note 4 to the financial statements.  

An unrealized commodity risk management gain of $6.9 million ($5.0 million, net of tax) for the full year of 2010 compared to an unrealized commodity risk
management loss of $173.7 million ($126.3 million, net of tax) in the prior year.  

Lower depletion, depreciation and amortization in 2010 of $529.4 million compared to $591.4 million in 2009.  

Partly offsetting the increase was the impact of the change in the U.S. to Canadian dollar exchange rate which primarily caused a smaller unrealized foreign
exchange gain of $49.9 million in 2010 ($43.5 million, net of tax) compared to an unrealized gain of $149.2 million ($130.1 million, net of tax) in the same period last year.  

Also partially offsetting the increase to net income were lower 2010 future income tax reductions compared to the same period last year by $98.1 million as a
result of lower unitholder distributions and the impact of changes to non-cash items. 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 of 2010,
capital expenditures totaled $357.7 million, $333.8 million after drilling royalty credits, with approximately 85 percent spent on drilling, completions and facilities. Included in the capital expenditures are land acquisition costs of
$5.6 million, maintenance capital of $41.0 million and reductions from drilling credits of $23.9 million.  Three months ended


Twelve months ended($ millions)

Dec 31, 2010


Sept 30, 2010


Dec 31, 2009


Dec 31, 2010


Dec 31, 2009Drilling, completions and facilities


120.4



78.7



40.2



300.8



146.2Seismic acquisitions(1)& Reservoir Studies(2)


4.2



1.0



0.5



5.9



13.9Maintenance capital


7.5



12.5



8.8



41.0



48.5Land purchases


0.3



1.0



0.5



5.6



2.9Development capital


132.4



93.2



50.0



353.3



211.5Other capital


1.9



0.9



1.3



4.4



5.2Drilling Royalty Credits


(3.4
)


(6.3
)


(5.1
)


(23.9
)


(9.3
)Total net capital expenditures


130.9



87.7



46.2



333.8



207.4Business acquisitions(3)






570.4







570.4



Property acquisitions


0.1



17.3



25.3



20.2



35.7Proceeds on property dispositions


(12.4
)


(0.3
)


(34.2
)


(60.7
)


(41.9
)Net capital expenditures and acquisitions


118.6



675.1



37.3



863.7



201.2  (1)
Seismic acquisitions are net of seismic sales revenue.  (2)
Reservoir Studies includes capital spending on the Lindbergh Steam Assisted Gravity Drainage ("SAGD") Project.  (3)
Business acquisitions includes the increase to Property, Plant & Equipment as a result of the acquisition of Monterey.




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##### Table of Contents

DRILLING ACTIVITY Pengrowth participated in the drilling of 214 wells (128.1 net wells) in 2010.  Q4 2010


Q3 2010


Q2 2010


Q1 2010


Full Year 2010Gross


Net


Gross


Net


Gross


Net


Gross


Net


Gross


NetFocus AreasSwan Hills


16



7.9



13



8.3



6



5.1



24



4.6



59



25.9Groundbirch


3



3.0



1



1.0



















4



4.0Lindbergh


3



3.0



























3



3.0Olds/Garrington


5



3.7



5



2.7



2



1.6



2



1.7



14



9.71Other Resource PlaysShallow Gas & CBM


5



3.2



11



5.1











66



54.0



82



62.3Heavy Oil


























12



12.0



12



12.0Horn River


























2



2.0



2



2.0Weyburn Unit


12



1.2



8



0.8



6



0.6



5



0.5



31



3.1Conventional


1



0.7



3



3.0



1



1.0



2



1.4



7



6.1Total wells drilled


45



22.7



41



20.9



15



8.3



113



76.2



214



128.1 DEVELOPMENT CAPITAL ACTIVITIES Pengrowths
capital spending breakdown by area, excluding drilling credits is as follows:  ($ millions)

Q4 2010


Full Year 2010


% of Full Year2010 Spending


Full Year 2009Focus Areas(1)Swan Hills


50.7



136.4



38%



59.1Groundbirch


32.7



37.3



10%



Lindbergh


3.0



3.6



1%



9.4Olds/Garrington


21.2



44.3



12%



11.9107.6



221.6



62%



80.4Other Resource PlaysShallow Gas & Coalbed Methane


2.8



16.0



5%



23.9Heavy Oil


2.8



11.5



3%



13.6Horn River


(0.5
)


12.5



3%



4.9Weyburn Unit


3.3



14.0



4%



6.1Conventional Resource Plays


7.4



28.8



8%



26.715.8



82.8



23%



75.2Drilling, Completions & Facilities


123.4



304.4



85%



155.6Maintenance


7.5



41.0



11%



48.5Land & Seismic Acquisitions


1.5



7.9



2%



7.4Other


1.9



4.4



1%



5.2Total Capital Expenditures


134.3



357.7



100%



216.7  (1)
Spending amounts reflect the activity for both operated and partner operated properties.




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##### Table of Contents

Focus Areas Swan Hills Trend The Swan Hills Trend is a significant oil
resource area where Pengrowth is a legacy landholder with an estimated 2.3 billion barrels of original oil in place. It is an extensive carbonate oil reservoir that is providing Pengrowth with many opportunities to put its expertise in horizontal
drilling and multi-stage fracturing of carbonate reservoirs to work on its operated interests in Judy Creek, Carson Creek, House Mountain, and Deer Mountain. Pengrowths operated Carson Creek production comes from two units: Carson Creek North Beaverhill Lake (BHL) Unit 1, which primarily produces oil, and the Carson Creek BHL Unit 1, which primarily produces
liquids-rich gas. Pengrowth has been developing a new BHL gas pool, the Carson C Pool, where production averaged approximately 2,900 boe per day during the fourth quarter. Seven horizontal wells (6.6 net wells) drilled in the Carson C Pool in 2010 were successfully multi-stage acid fractured and tested in the third and fourth quarters of 2010, adding on average
approximately 750 boe per day of initial production per well. All seven wells were on production in early 2011 and total projected cost for this project is estimated at $30 million. At House Mountain two BHL platform horizontal wells (2.0 net wells) were drilled during 2010 at an estimated drilling and completion cost of $10 million. Both wells were multi-stage acid fractured and tested in the
third quarter at a five day initial rate of 350 boe per day and placed on production early in the fourth quarter. At Deer Mountain Unit No
1, six horizontal wells (5.1 net wells) were drilled by the end of the fourth quarter; four of these wells were multi-stage acid fractured and tested, averaging 360 barrels of oil per day; the last two wells were completed in February
2011. Total capital spent in 2010 at Deer Mountain Unit No.1 was approximately $18 million. Groundbirch Pengrowths Groundbirch asset is our major Montney gas property which was acquired through the acquisition of Monterey Exploration Ltd. in 2010. This property
provides Pengrowth access to a large resource with a long reserve life index with the potential of approximately 124 gross (107 net) additional drilling locations. During the fourth quarter, construction was completed on a 28 mmcf per day gas plant. The plant went on production on December 18, 2010 and five wells were tied in. By achieving production before
December 30, 2010, four wells qualify for a reduced royalty rate of two percent for the next twelve months. An additional five wells have been drilled and will be fractured in the first quarter of 2011. Approximately $37 million has been spent
on the operations in the Groundbirch area, subsequent to September 15, 2010, of this approximately $7 million was spent on the construction of the gas plant. Lindbergh Steam Assisted Gravity Drainage (SAGD) Project Pengrowth's entry into operated SAGD
operations resulted from the 2004 acquisition of our Lindbergh property. In 2010, a new leader was assigned to the Lindbergh Project and a team, sourced both internally and externally, was in place by the end of the fourth quarter. A detailed review
and update on the Lindbergh project was completed, an amendment to the existing Lindbergh regulatory application and responses to outstanding Supplemental Information Requests by the regulators was completed and submitted to both the Energy
Resources Conservation Board and Alberta Environment. Late in 2010, three observation wells were drilled for the SAGD pilot. Subject to regulatory approvals, it is anticipated that construction will begin in the third quarter of 2011 followed by
first steam at the SAGD pilot in the first quarter of 2012. Olds/Garrington During 2010 two proof of concept programs were tested in order to define the resources in the Cardium and Viking formations. Nine wells (5.8 net wells) were drilled in this program, one of which was junked and
abandoned. Six wells were on production by the end of 2010 and with their results being evaluated to define future development. Total spending on these two programs was approximately $25 million. During 2010 four Elkton wells (3.3 net wells) were drilled in the Harmattan area for approximately $9 million. Initial production from the wells drilled early in
the year was 800 boe per day. Results from this program are positive with additional locations scheduled for the first quarter of 2011. 2011 Capital
Program Pengrowth currently anticipates the 2011 capital program, excluding acquisitions, to be $400 million, an increase of 12 percent from 2010
total capital spending of $358 million. It is designed to be flexible, scalable and responsive to uncertain commodity prices and market conditions. Management believes that the capital guidance is an appropriate level of capital spending to replace
a significant portion of production.




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##### Table of Contents

RESERVES AND PERFORMANCE MEASURES Reserves  Company Interest  Reserves Summary

2010


2009


2008Proved ReservesDrill + Revisions (mmboe) for the year


20.5



11.3



17.6Net Acquisitions (mmboe) for the year


11.2



(0.9
)


6.4Total Proved Reserves at period end


221.0



216.6



235.2Proved Reserve replacement ratio excluding acquisitions


75%



39%



59%Proved Reserve replacement ratio including acquisitions


116%



36%



80%Proved plus Probable Reserves (P+P)Drill + Revisions (mmboe) for the year


27.1



2.6



23.9Net Acquisitions (mmboe) for the year


22.8



(1.3
)


9.7Total Proved plus Probable Reserves at period end


318.4



295.7



323.5P+P Reserve replacement ratio excluding acquisitions


99%



9%



80%P+P Reserve replacement ratio including acquisitions


183%



4%



112% Pengrowth
reported year-end proved reserves of 221.0 mmboe and proved plus probable reserves of 318.4 mmboe for 2010 compared to 216.6 mmboe and 295.7 mmboe, respectively at year end 2009. During 2010, Pengrowths development and optimization activities
resulted in the addition of 20.5 mmboe of Proved Reserves and 27.1 mmboe of Total Proved plus Probable Reserves including revisions. Acquisitions net of some minor dispositions in 2010 also added 11.2 mmboe of Proved Reserves and 22.8 mmboe of
total proved plus probable reserves. The reserve additions in 2010 resulted in a reserve replacement ratio of 99 percent for total proved plus probable reserves excluding acquisitions, and 183 percent including acquisitions. Further details of Pengrowths 2010 year-end reserves, F&D and FD&A calculations are provided in the AIF which is filed on SEDAR (www.sedar.com) or
the 40-F filed on Edgar (www.sec.gov). Performance Measures  Finding & Development Costs & Recycle Ratio

2010


2009


2008


3 yr averageExcluding Acquisitions (F&D)Excluding Changes in FDCRecycle Ratio(1)


2.17



0.32



2.14



1.69F&D costs per boe

$
12.15


$
78.46


$
16.27


$
17.17Including Changes in FDCRecycle Ratio(1)


1.72



0.82



1.46



1.46F&D costs per boe

$
15.32


$
30.81


$
23.82


$
19.85Including Acquisitions (FD&A)Excluding Changes in FDCRecycle Ratio(2)


1.80



0.17



2.25



1.70FD&A costs per boe  proved plus probable

$
14.61


$
151.45


$
15.47


$
17.04Including Changes in FDCRecycle Ratio(2)


1.43



0.44



1.65



1.44FD&A costs per boe  proved plus probable

$
18.46


$
57.16


$
21.13


$
20.11  (1)
Recycle Ratio is calculated as operating netback per boe 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 2010 total proved plus probable finding and development cost (F&D), including changes in future development capital, were $15.32 per boe, a 50 percent
decrease from the 2009 F&D cost per boe. The improvement year over year illustrates Pengrowths ability to create efficiencies through the drill bit by focusing on the development of repeatable resource plays in such areas as the Swan Hills
Trend and at the newly acquired Groundbirch area. In addition, the 2009 F&D cost per boe was higher than Pengrowths historic average largely due to the impact of the 2009 reserve revisions.




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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 2010 yielded a recycle ratio, excluding acquisition and including changes in FDC, of 1.72 and on a three year average was 1.46. The three year average recycle ratio was
impacted by the 2009 reserve revisions while the 2010 recycle ratio reflects the lower F&D cost per boe. Pengrowths goal over longer periods
is to maintain or modestly grow production and reserves per debt adjusted share. The trend over the last three years for production per debt adjusted share has been relatively flat while reserves per debt adjusted share has improved in 2010,
demonstrating Pengrowths ability to replace production with reserve adds from development activities.  Performance Measures

2010


2009


2008Production per debt adjusted share (boe/share)(1)


0.07



0.08



0.07Reserves per debt adjusted share (boe/share)(1)


0.78



0.74



0.76  (1)
Debt adjusted shares equals the shares outstanding plus the number of shares needed to retire all total long term debt at the year-end share price. ACQUISITIONS & DISPOSITIONS On
September 15, 2010, Pengrowth successfully completed the acquisition of Monterey for total consideration of $445 million (see Note 4 to the financial statements for additional details of this transaction). This acquisition has provided
Pengrowth with 21.0 gross (19.0 net) sections at Groundbirch in northeast British Columbia, a highly prospective Montney focused resource asset. During
the first quarter of 2010, Pengrowth completed the disposition of various gross overriding royalty interests. Proceeds of the disposition were approximately $38.4 million net of adjustments. Proceeds from this disposition were used for debt
repayment. PRODUCTION  Three months ended


Twelve months endedDaily production

Dec 31,2010


% oftotal


Sept 30,2010


% oftotal


Dec 31,2009


% oftotal


Dec 31,2010


% oftotal


Dec 31,2009


% oftotalLight crude oil (bbls)


21,762



29



20,967



29



21,948



28



21,743



29



22,841



29Heavy oil (bbls)


6,673



9



6,585



9



7,235



9



6,789



9



7,551



9Natural gas (mcf)


218,044



48



217,712



50



232,682



50



219,302



49



237,217



50Natural gas liquids (bbls)


10,177



14



8,867



12



9,564



13



9,611



13



9,590



12Total boe per day


74,953







72,704







77,529







74,693







79,518 Average daily production increased three percent in the
fourth quarter of 2010 compared to the third quarter of 2010. Fourth quarter volumes were positively affected by production from the Monterey assets acquired in mid-September and the start-up of Groundbirch production in mid-December. Also
positively impacting the fourth quarter was production from development activities, particularly Swan Hills trend production at Deer Mountain, House Mountain, and new production at Olds/Garrington. Optimization work completed at various field sites
also had a positive impact. Also impacting the quarter were unplanned production outages in Quirk Creek, Sable Offshore Energy Project (SOEP)
and Olds. Both fourth quarter and full year production decreased as a result of minor property dispositions, unscheduled production outages and production declines. Pengrowths 2011 capital program should allow us to maintain average daily production volumes of between 74,000 and 76,000 boe per day. The capital program is expected to deliver new production that is split
80 percent crude oil and liquids and 20 percent natural gas and is designed to be flexible, scalable and responsive to uncertain commodity prices and market conditions. Overall, Pengrowths production is projected to remain balanced at
approximately 50 percent natural gas and 50 percent crude oil and liquids. The 2011 estimate excludes production from any potential future acquisitions and dispositions. Light Crude Oil Fourth quarter light crude oil production increased approximately four percent from the third
quarter of 2010. This increase is mainly attributable to new Swan Hills trend production starting from new wells at Deer Mountain, House Mountain and new production at Olds/Garrington. Optimization and the resumption of production following third
quarter turnaround activity also impacted production.




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The one percent decrease in light crude oil in the current quarter compared to the fourth quarter of 2009, is a
result of production declines, partially offset by the development work mentioned above, the late 2009 acquisition of an additional working interest in House Mountain Unit #1, and additional production from well optimizations, particularly in the
Jenner and Bantry areas. The year-over-year decrease of approximately five percent is a result of increased planned maintenance shutdown work in 2010, particularly the Judy Creek turnaround. Heavy Oil Heavy oil production increased approximately one percent in the fourth quarter of 2010 compared to
the third quarter of 2010. This increase is attributable to volumes back on production after third quarter planned maintenance shutdowns at Bodo and Tangleflags, offset by production declines. The eight percent decrease between the fourth quarters of 2010 and 2009 and the ten percent decrease year-over-year is attributable to production declines due to
reduced capital investment during 2009, second quarter power outages in 2010 and increased downtime from surface and sub-surface maintenance work at partner operated Tangleflags. Natural Gas Natural gas production increased marginally in the fourth quarter compared to the third quarter of
2010. Included in the fourth quarter are a full three months of production from the Monterey acquisition, successful optimization work in the Princess area and approximately two weeks of initial production from Groundbirch. These additional volumes
were partially offset by production declines and unscheduled maintenance at Olds, SOEP and Quirk Creek. Production volumes were lower by approximately
six percent comparing the fourth quarter of 2010 with the same quarter in 2009. The decrease is attributable to non-core gas focused asset dispositions in late 2009, scheduled and unscheduled downtime previously mentioned and natural declines.
Partially offsetting these declines were production from the acquisition of Monterey, liquid rich gas development in the Harmattan area and the start-up of Groundbirch. Production volumes decreased approximately eight percent comparing the full year of 2010 to the same period of 2009. These decreases are a result of the previously mentioned property divestitures and production
declines. Partially offsetting the decreases are additional production volumes from development and optimization activity in Carson Creek, the previously mentioned development program at Harmattan and the volumes added from the acquisition of
Monterey. NGLs NGL production increased
approximately 15 percent in the fourth quarter of 2010 compared to the third quarter of 2010 and six percent comparing fourth quarter 2010 with the same period of 2009. The increase in both time periods is a result of lower miscible flood demand
resulting in higher sales at Judy Creek and additional production from new liquids rich horizontal gas wells in Carson Creek C pool which came on stream mid-way through the third quarter 2010. NGL volumes remained relatively flat comparing full year 2010 with full year 2009 with the increased NGL production at Carson Creek and Harmattan offset by lower
sales volumes at Judy Creek resulting from the previously mentioned turnaround and reduced third party demand for miscible flood injectants plus production declines.




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##### Table of Contents

COMMODITY PRICE Average Realized Prices  Three months ended


Twelve months ended(Cdn$)

Dec 31, 2010


Sept 30, 2010


Dec 31, 2009


Dec 31, 2010


Dec 31, 2009Light crude oil (per bbl)


77.37



72.18



74.37



74.89



63.94after realized commodity risk management


74.98



73.93



75.79



75.04



72.36Heavy oil (per bbl)


60.42



57.80



62.16



60.22



52.72Natural gas (per mcf)


3.68



3.56



4.28



4.08



3.97after realized commodity risk management


4.87



4.67



5.45



5.00



5.14Natural gas liquids (per bbl)


56.74



53.55



54.52



56.99



42.12Total per boe


46.25



43.24



46.44



46.59



40.29after realized commodity risk management


49.01



47.07



50.35



49.34



46.19Other production income


0.39



0.40



0.02



0.30



0.08Total oil and gas sales per boe


49.40



47.47



50.37



49.64



46.27Benchmark pricesWTI oil (U.S.$ per bbl)


85.24



76.21



76.13



79.61



62.09AECO spot gas (Cdn$ per mmbtu)


3.61



3.54



4.61



3.99



3.99NYMEX gas (U.S.$ per mmbtu)


3.98



4.23



4.93



4.38



4.16Currency (U.S.$/Cdn$)


0.99



0.96



0.95



0.97



0.88 The WTI benchmark
crude oil prices increased significantly in 2010, averaging U.S. $79.61 per bbl compared to an average price of $62.09 per bbl in 2009. On a year over year basis, Pengrowths average realized price, after risk management activities increased
approximately seven percent from last year mainly as a result of higher benchmark crude prices in 2010. U.S. based NYMEX natural gas benchmark prices
started 2010 on a strong note with prices rallying above U.S. $5.00 per mmbtu as below normal temperatures across much of the consuming eastern U.S. and improved demand help support the early price rally. However, prices weakened as the year
progressed and continued to experience downward pressure for much of the year. NYMEX gas prices averaged U.S. $4.38 per mmbtu in 2010, a slight improvement from 2009 average prices of U.S. $4.16 per mmbtu. In Canada, the AECO spot market continued to trade at a discount to the NYMEX benchmark. The strengthening Canadian dollar together with U.S. production growth, an
abundance of natural gas in Canadian storage and reduced Canadian exports to the U.S. have contributed to a wider basis for AECO compared to the NYMEX natural gas price. Our corporate realized natural gas price after risk management activities was
$5.00 per mmbtu in 2010, an approximate three percent decrease over 2009 realized prices of $5.14 per mmbtu due to a lower hedged gas price in 2010. Pengrowths average realized price was $49.01 per boe in the fourth quarter 2010, a four percent increase from the third quarter 2010 and a three percent decrease over the fourth quarter of 2009. Benchmark
prices increased in the fourth quarter compared to the third quarter contributing to higher average prices for oil and natural gas. The Canadian dollar
strengthened significantly versus its U.S. counterpart in 2010 averaging $0.97 (U.S.$/Cdn$) compared to $0.88 (U.S.$/Cdn$) in 2009. A stronger outlook on the Canadian economy coupled with improved pricing for major commodities were the
primary contributors to the surge in the Canadian dollar.




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##### Table of Contents

Commodity Risk Management Gains (Losses)  Three months ended


Twelve months endedDec 31, 2010


Sept 30, 2010


Dec 31, 2009


Dec 31, 2010


Dec 31, 2009RealizedLight crude oil ($ millions)


(4.8
)


3.4



2.9



1.2



70.2Light crude oil ($ per bbl)


(2.39
)


1.75



1.42



0.15



8.42Natural gas ($ millions)


23.9



22.3



25.0



73.9



101.0Natural gas ($ per mcf)


1.19



1.11



1.17



0.92



1.17Combined ($ millions)


19.1



25.7



27.9



75.1



171.2Combined ($ per boe)


2.76



3.83



3.91



2.75



5.90UnrealizedTotal unrealized risk management (liabilities) assets at period end ($ millions)


(2.1
)


50.4



(9.0
)


(2.1
)


(9.0
)Less: Unrealized risk management assets (liabilities) at beginning of period ($
millions)


50.4



51.3



31.1



(9.0
)


164.7Unrealized (loss) gain on risk management contracts


(52.5
)


(0.9
)


(40.1
)


6.9



(173.7
) As part of the risk
management strategy, Pengrowth uses forward price swaps to manage exposure to commodity price fluctuations and provide a measure of stability to cash flow. Despite liquid commodity prices remaining strong through 2010, natural gas prices remained lower than the average price achieved through our commodity risk management activities, resulting in a combined realized
commodity risk management gain of $19.1 million compared to gains of $25.7 million and $27.9 million in the third quarter of 2010 and fourth quarter of 2009, respectively. On a year over year basis, average realized prices increased approximately seven percent from the same period last year as a result of higher crude oil prices. The risk management activities resulted in a realized
gain of $73.9 million compared to $101.0 million in 2009, for natural gas, whereas the realized gains for light crude were much lower at $1.2 million versus $70.2 million last year. The change in fair value of the forward contracts between periods affects net income through the unrealized amounts recorded during the period. The fair value of forward contracts is determined by comparing
the contracted fixed price to the forward price curve at each period end. The change in the forward price curve at the end of the fourth quarter
compared to the third quarter of 2010 plus fourth quarter settlements resulted in an unrealized commodity risk management loss of approximately $52.5 million.For the same period last year, the change in the forward price curve resulted
in an unrealized risk management loss of $40.1 million. For the full year of 2010, the unrealized commodity risk management gain of $6.9 million
primarily reflects a weaker natural gas forward price curve from year end 2009. In contrast, through 2009 an unrealized commodity risk management loss of $173.7 million was recorded as a result of an increase in the crude oil forward price curve.




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##### Table of Contents

As of December 31, 2010, the following commodity risk management contracts were in place:  Crude Oil:Reference Point

Volume (bbl/d)


Remaining Term


Price per bbl(2)Financial:WTI(1)


12,000



Jan 1, 2011 - Dec 31, 2011


$
87.87WTI(1)


5,000



Jan 1, 2012 - Dec 31, 2012


$
91.04Natural Gas:Reference Point

Volume (mmbtu/d)


Remaining Term


Price per mmbtu(2)Financial:AECO


45,021



Jan 1, 2011 - Dec 31, 2011


$
5.60Chicago MI(1)


5,000



Jan 1, 2011 - Dec 31, 2011


$
6.78Power:Reference Point

Volume (MW)


Remaining Term


Price per MW(2)Financial:AESO


25



Jan 1, 2011 - Dec 31, 2011


$
46.34  (1)
Associated Cdn $/U.S. $ foreign exchange rate has been fixed.  (2)
All prices are referenced in Canadian dollars Based on our 2011
production forecast the above contracts represent approximately 32 percent of total liquids volumes at an average price of $87.87 per bbl and 22 percent of natural gas volumes at $5.71 per mmbtu. The power contract represents approximately 25
percent of estimated 2011 consumption. Each $1 per barrel change in future oil prices results in approximately $6.2 million pre-tax change in the value
of the crude contracts, while each $0.25 per mmbtu change in future natural gas prices results in approximately $4.6 million pre-tax change in the value of the natural gas contracts. The changes in the fair value of the forward contracts directly
affects reported net income through the unrealized amounts recorded in the statement of income during the period. The effect on cash flow will be recognized separately only upon settlement of the contracts, which could vary significantly from the
unrealized amount recorded due to timing and prices when each contract is settled. However, if each contract were to settle at the contract price in effect at December 31, 2010, future revenue and cash flow would be $2.1 million lower than that
otherwise achievable if the contracts were not in place based on the estimated fair value of the risk management asset at period end. The $2.1 million net liability is composed of a net asset of $4.6 million relating to contracts expiring within one
year and a liability of $6.7 million relating to contracts expiring beyond one year. Pengrowth fixes the Canadian dollar exchange rate at the same time it swaps U.S. dollar denominated commodity in order to protect against changes in the foreign
exchange rate. Each $1 per MW change in future power prices would result in approximately $0.2 million pre-tax change in the fair value of the risk
management contracts. Pengrowth has not designated any outstanding commodity contracts as hedges for accounting purposes and therefore records these
contracts on the balance sheet at their fair value and recognizes changes in fair value in the income statement as unrealized commodity risk management gains or losses. There will continue to be volatility in earnings to the extent that the fair
value of commodity contracts fluctuate, however these non-cash amounts do not impact Pengrowths operating cash flow. Realized commodity risk management gains or losses are recorded in oil and gas sales on the income statement and impacts cash
flow at that time. In accordance with policies approved by the Board of Directors, Pengrowth may sell forward its production by product volume or power
consumption as follows:  Percent of Monthly Company Interest Production

Forward PeriodUp to 65%


1 - 12 MonthsUp to 45%


13 - 24 MonthsUp to 30%


25 - 36 Months




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Each commodity risk management transaction for natural gas or crude oil shall not exceed 20,000 mmbtu per day and
2,500 bbls per day 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 to the overall sales revenue inclusive of realized commodity risk management activity.  Three months ended


Twelve months endedSales Revenue ($ millions except percentages)

Dec 31,
2010


% of
total


Sept 30,
2010


% of
total


Dec 31,
2009


% oftotal


Dec 31,
2010


% oftotal


Dec 31,
2009


% of
totalLight crude oil


150.1



44



142.6



45



153.0



43



595.5



44



603.2



45Natural gas


97.6



29



93.5



29



116.8



33



400.4



30



444.8



33Natural gas liquids


53.1



16



43.7



14



47.9



13



199.9



15



147.4



11Heavy oil


37.1



11



35.0



11



41.4



11



149.2



11



145.3



11Brokered sales/sulphur


2.8







2.7



1



0.2







8.3







2.5



Total oil and gas sales


340.7







317.5







359.3







1,353.3







1,343.2 Price and Volume Analysis 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 activity, for the fourth quarter of 2010 compared to the fourth quarter of 2009.  ($ millions)

Light oil


Natural gas


NGLs


Heavy oil


Other(1)


TotalQuarter ended December 31, 2009


153.0



116.8



47.9



41.4



0.2



359.3Effect of change in product prices


6.0



(12.4
)


2.1



(1.1
)






(5.4
)Effect of change in sales volumes


(1.3
)


(5.8
)


3.1



(3.2
)






(7.2
)Effect of change in realized commodity risk management activities


(7.7
)


(1.1
)














(8.8
)Other


0.1



0.1











2.6



2.8Quarter ended December 31, 2010


150.1



97.6



53.1



37.1



2.8



340.7  (1)
Primarily sulphur sales 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 activity, for the full year of 2010 compared to same period of 2009.  ($ millions)

Light oil


Natural gas


NGLs


Heavy oil


Other(1)


TotalYear ended December 31, 2009


603.2



444.8



147.4



145.3



2.5



1,343.2Effect of change in product prices


86.9



9.0



52.2



18.6







166.7Effect of change in sales volumes


(25.6
)


(26.0
)


0.3



(14.7
)






(66.0
)Effect of change in realized commodity risk management activities


(68.9
)


(27.1
)














(96.0
)Other


(0.1
)


(0.3
)










5.8



5.4Year ended December 31, 2010


595.5



400.4



199.9



149.2



8.3



1,353.3  (1)
Primarily sulphur sales




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ROYALTY EXPENSE  Three months ended


Twelve months ended($ millions)

Dec 31, 2010


Sept 30, 2010


Dec 31, 2009


Dec 31, 2010


Dec 31, 2009Royalty expense


60.9



55.3



71.0



252.7



207.6$ per boe


8.83



8.26



9.95



9.27



7.15Royalties as a percent of sales


17.9%



17.4%



19.7%



18.7%



15.5%Royalties as a percent of sales excluding realized risk management contracts


18.9%



18.9%



21.4%



19.8%



17.7% Royalties include
Crown, freehold, overriding royalties and mineral taxes. Royalty payments are based on revenue before commodity risk management activities; however gains or losses from realized commodity risk management activities are reported as part of revenue
and therefore affect royalty rates as a percentage of sales. Fourth quarter royalty rates remained steady compared to the third quarter of 2010. Royalty incentives for new wells at Carson Creek positively affected the royalty rate comparing the
fourth quarters of 2010 and 2009. Higher liquid commodity prices through 2010 is the main factor impacting the royalty rate compared to 2009 where liquids commodity prices were lower and therefore benefited from changes to the Alberta royalty regime
that became effective January 1, 2009. Royalty expense for 2011 is forecasted to be approximately 20 percent of Pengrowths sales excluding
the impact of risk management contracts. OPERATING EXPENSES  Three months ended


Twelve months ended($ millions)

Dec 31, 2010


Sept 30, 2010


Dec 31, 2009


Dec 31, 2010


Dec 31, 2009Operating expenses(1)


108.8



84.9



94.0



371.7



384.4$ per boe


15.77



12.69



13.18



13.63



13.24  (1)
Prior period restated to conform to presentation in the current period. Operating expenses in the fourth quarter of 2010 were approximately 28 percent higher than the third quarter of 2010 (24 percent on a per boe basis). During the fourth quarter, operations teams increased
maintenance activities in areas with winter only access (approximately $5 million) and were able to accelerate one time proactive maintenance work (approximately $4 million). In addition, fourth quarter operating expenses were impacted by continued
subsurface and optimization activity particularly at Judy Creek (approximately $4 million), higher power costs (approximately $3 million), a prior period operating expense settlement in Fenn Big Valley (approximately $3 million), and additional
operating costs from the conventional properties acquired with Monterey (approximately $2 million). Fourth quarter 2010 operating costs compared to the
fourth quarter of 2009 increased 16 percent (20 percent on a per boe basis) primarily attributable to higher power costs in the current quarter and unfavourable prior period adjustments stemming from previous property acquisitions. Continued effort
in overall expense reduction coupled with the absence of unfavourable prior period adjustments experienced in 2009, resulted in lower operating expenses on a year-over-year basis. 2011 operating expenses are forecast to be $370 million or $13.54 per boe. Power costs are approximately 40 percent of Pengrowths operating costs. Pengrowth expects that power costs will remain essentially
flat when compared to 2010 and will continue to actively manage these costs through its power shedding and risk management programs. PROCESSING AND OTHER INCOME  Three months ended


Twelve months ended($ millions)

Dec 31, 2010


Sept 30, 2010


Dec 31, 2009


Dec 31, 2010


Dec 31, 2009Processing & other income(1)


5.8



4.4



4.1



20.6



18.8$ per boe


0.84



0.65



0.58



0.76



0.65  (1)
Prior period restated to conform to presentation in the current period.




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Processing and other income is derived from sales of casinghead gas, fees charged for processing and gathering
third party gas, road use, and oil and water processing. Income increased in the fourth quarter of 2010 due to higher road use income and casinghead sales being recorded. Casinghead sales increased during the fourth quarter and for the full year of
2010 from additional development activity at Carson Creek. This income primarily represents the partial recovery of operating expenses reported
separately. NET OPERATING EXPENSES  Three months ended


Twelve months ended($ millions)

Dec 31, 2010


Sept 30, 2010


Dec 31, 2009


Dec 31, 2010


Dec 31, 2009Net operating expenses(1)


103.0



80.5



89.9



351.1



365.6$ per boe


14.93



12.04



12.60



12.87



12.59  (1)
Prior period restated to conform to presentation in the current period. Included in the table above are operating expenses net of processing and other income. TRANSPORTATION COSTS  Three months ended


Twelve months ended($ millions)

Dec 31, 2010


Sept 30, 2010


Dec 31, 2009


Dec 31, 2010


Dec 31, 2009Light oil transportation


1.9



2.0



1.2



7.3



4.7$ per bbl


0.92



1.05



0.58



0.92



0.56Natural gas transportation


2.4



1.5



2.9



8.5



8.8$ per mcf


0.12



0.08



0.14



0.11



0.10 The increase in
light oil transportation comparing the fourth quarters and full years of 2010 and 2009 is mainly attributable to trucking of sales quality NGLs from Carson Creek to the sales point at Whitecourt. Impacting natural gas transportation in the fourth
quarter are additional costs incurred from volumes associated with the Monterey acquisition and the non-recurrence of a favorable third quarter adjustment. Pengrowth incurs transportation costs for its natural gas production once the product enters a pipeline at a title transfer point. Pengrowth also incurs transportation costs on its oil production that includes
clean oil trucking charges and pipeline costs up to the custody transfer point. The transportation cost is dependent upon third party rates and distance the product travels on the pipeline prior to changing ownership or custody. 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. Similarly, Pengrowth
has elected to sell approximately 75 percent of its crude oil at market points beyond the wellhead but at the first major trading point, requiring minimal transportation costs. AMORTIZATION OF INJECTANTS FOR MISCIBLE FLOODS  Three months ended


Twelve months ended($ millions)

Dec 31, 2010


Sept 30, 2010


Dec 31, 2009


Dec 31, 2010


Dec 31, 2009Purchased and capitalized


0.3



2.1



4.9



9.3



13.3Amortization


3.0



3.5



4.4



15.1



20.0 The cost of
injectants (primarily natural gas and ethane) purchased for injection in the miscible flood program at Judy Creek and Swan Hills is amortized equally over the period of expected future economic benefit. The costs of purchased injectants are
amortized over a 24 month period. As of December 31, 2010, the balance of unamortized injectant costs was $ 10.0 million. The amount of
injectants purchased and capitalized in the fourth quarter of 2010 was lower than the third quarter of 2010 and fourth quarter of 2009 due to timing and the requirements of this program. The value of Pengrowths proprietary injectants is not
recorded as an asset or a sale; the cost of producing these injectants is included in operating expenses.




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OPERATING NETBACKS There is no standardized measure of operating netbacks and therefore operating netbacks, as presented below, may not be comparable to similar measures presented by other companies. Pengrowths operating
netbacks have been calculated by taking GAAP balances directly from the income statement and dividing by production. Certain assumptions have been made in allocating operating expenses, processing and other income and royalty injection credits
between light crude, heavy oil, natural gas and NGL production. Pengrowth recorded an average operating netback of $24.58 per boe in the fourth
quarter of 2010 compared to $26.12 per boe in the third quarter of 2010 and $26.63 per boe for the fourth quarter of 2009. The decrease in the netback in the fourth quarter of 2010 compared to the third quarter of 2010 and the fourth quarter of 2009
is primarily due to higher operating costs. For the full year of 2010, operating netbacks were higher than in 2009 as a result of higher net revenues. The sales price used in the calculation of operating netbacks is after realized commodity risk management gains or losses.  Three months ended


Twelve months endedCombined Netbacks ($ per boe)

Dec 31, 2010


Sept 30, 2010


Dec 31, 2009


Dec 31, 2010


Dec 31, 2009Oil & gas sales (after commodity risk management)


49.40



47.47



50.37



49.64



46.27Processing and other income  (1)


0.84



0.65



0.58



0.76



0.65Royalties


(8.83
)


(8.26
)


(9.95
)


(9.27
)


(7.15
)Operating expenses(1)


(15.77
)


(12.69
)


(13.18
)


(13.63
)


(13.24
)Transportation costs


(0.62
)


(0.53
)


(0.57
)


(0.58
)


(0.46
)Amortization of injectants


(0.44
)


(0.52
)


(0.62
)


(0.55
)


(0.69
)Operating
netback(1)


24.58



26.12



26.63



26.37



25.38Three months ended


Twelve months endedLight Crude Netbacks ($ per bbl)

Dec 31, 2010


Sept 30, 2010


Dec 31, 2009


Dec 31, 2010


Dec 31, 2009Sales price (after commodity risk management)


74.98



73.93



75.79



75.04



72.36Other production income


0.71



0.94



0.23



0.61



0.32Oil & gas sales


75.69



74.87



76.02



75.65



72.68Processing and other income


0.60



0.34



0.46



0.47



0.71Royalties


(17.32
)


(15.04
)


(17.35
)


(17.32
)


(13.65
)Operating expenses(1)


(18.81
)


(14.01
)


(17.86
)


(16.39
)


(16.38
)Transportation costs


(0.92
)


(1.05
)


(0.58
)


(0.92
)


(0.56
)Amortization of injectants


(1.52
)


(1.81
)


(2.19
)


(1.90
)


(2.40
)Operating netback(1)


37.72



43.30



38.50



39.59



40.40Three months ended


Twelve months endedHeavy Oil Netbacks ($ per bbl)

Dec 31, 2010


Sept 30, 2010


Dec 31, 2009


Dec 31, 2010


Dec 31, 2009Oil & gas sales


60.42



57.80



62.16



60.22



52.72Processing and other income(2)


0.63



1.20



(0.84
)


0.19



0.53Royalties


(11.25
)


(9.89
)


(12.81
)


(11.84
)


(8.91
)Operating expenses(1)


(16.86
)


(17.22
)


(12.01
)


(15.95
)


(14.35
)Operating netback(1)


32.94



31.89



36.50



32.62



29.99Three months ended


Twelve months endedNatural Gas Netbacks ($ per mcf)

Dec 31, 2010


Sept 30, 2010


Dec 31, 2009


Dec 31, 2010


Dec 31, 2009Sales price (after commodity risk management)


4.87



4.67



5.45



5.00



5.14Other production income


0.06



0.04



(0.01
)


0.04



Oil & gas sales


4.93



4.71



5.44



5.04



5.14Processing and other income
(1)


0.21



0.15



0.18



0.20



0.13Royalties


(0.31
)


(0.45
)


(0.58
)


(0.42
)


(0.31
)Operating expenses(1)


(2.39
)


(1.88
)


(1.85
)


(2.01
)


(1.91
)Transportation costs


(0.12
)


(0.08
)


(0.14
)


(0.11
)


(0.10
)Operating netback(1)


2.32



2.45



3.05



2.70



2.95Three months ended


Twelve months endedNGLs Netbacks ($ per bbl)

Dec 31, 2010


Sept 30, 2010


Dec 31, 2009


Dec 31, 2010


Dec 31, 2009Oil & gas sales


56.74



53.55



54.52



56.99



42.12Royalties


(13.97
)


(13.77
)


(17.06
)


(14.80
)


(12.08
)Operating expenses(1)


(13.56
)


(12.02
)


(11.78
)


(12.17
)


(12.23
)Operating netback(1)


29.21



27.76



25.68



30.02



17.81  (1)
Prior period restated to conform to presentation in the current period.  (2)
Heavy oil processing and other income includes a prior period adjustment for processing income at Tangleflags.




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INTEREST AND FINANCING CHARGES  Three months ended


Twelve months ended($ millions)

Dec 31, 2010


Sept 30, 2010


Dec 31, 2009


Dec 31, 2010


Dec 31, 2009Interest and Financing charges


19.6



17.0



18.3



70.5



80.3 At
December 31, 2010, Pengrowth had long term debt outstanding of $1,024.4 million the majority of which is denominated in foreign currency and $22.0 million in bank indebtedness. Of this, 94 percent is fixed at a weighted average interest rate of
6.2 percent, with the remaining six percent subject to floating rates which are presently three percent. The reduction in interest expense in 2010 compared to 2009 reflects the significant strengthening of the Canadian dollar and the decrease
in outstanding indebtedness achieved over the past year and the redemption of the Convertible Unsecured Debentures. Relative to the third quarter 2010,
interest and financing charges increased $2.6 million due to fees related to the renewal of the credit facility and the resulting adjustment of its fee structure to current market rates. GENERAL AND ADMINISTRATIVE EXPENSES  Three months ended


Twelve months ended($ millions)

Dec 31, 2010


Sept 30, 2010


Dec 31, 2009


Dec 31, 2010


Dec 31, 2009Cash G&A expense


12.1



10.7



14.7



46.3



54.1$ per boe


1.76



1.60



2.06



1.70



1.86Non-cash G&A expense


(1.0
)


0.3



(0.6
)


4.6



8.1$ per boe


(0.16
)


0.04



(0.08
)


0.17



0.28Total G&A


11.1



11.0



14.1



50.9



62.2$ per boe


1.61



1.63



1.98



1.87



2.14 The cash
component of general and administrative (G&A) expenses increased $1.4 million in the fourth quarter of 2010 compared to the third quarter of 2010 mainly attributable to legal fees, the special trust unitholders meeting and other costs
incurred related to the corporate conversion. In comparing to the same periods of 2009, a shift in focus for the corporation in 2010 coupled with cost control initiatives led to expense savings in a number of areas including third party consulting
fees and legal fees related to business development activities. The non-cash component of G&A represents the compensation expense associated with
Pengrowths Long Term Incentive Plans (LTIP) see Note 13 to the financial statements. The compensation costs associated with these plans are expensed over the applicable vesting period. The decrease in the fourth quarter and for the full year
of 2010 was primarily due to a change in the estimated performance multiplier on the 2008 Deferred Entitlement Unit grant vesting in the first quarter of 2011 (this change in estimate impacted non-cash G&A approximately $5.3 million
year-over-year). Total G&A costs are expected to increase for 2011 to $2.69 per boe when compared to full year 2010 of $1.87 per boe. Included in
Pengrowth's 2011 G&A forecast, are non-cash G&A costs of approximately $0.47 per boe compared to $0.17 per boe in 2010. RELATED
PARTY TRANSACTIONS The management agreement with Pengrowth Management Limited (the Manager) expired on June 30, 2009. No fees to the Manager have been incurred subsequent to the second quarter of 2009, where the total amount paid was $2.8 million. A senior officer of the Corporation was a member of the Board of Directors of Monterey, a company that Pengrowth acquired in September 2010 (see Note 4 to the
financial statements). OTHER EXPENSE (INCOME) Included in other income and expenses for the full year of 2010 is a $16.7 million gain composed of a $5.4 million gain realized on purchasing drilling credits from a third party, and an $11.3 million gain
resulting from a property disposition where the proceeds received consisted of $17.0 million of drilling credits.




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GAIN ON EQUITY INVESTMENT Pengrowth completed an acquisition of Monterey on September 15, 2010 as described in Note 4 of the consolidated financial statements. Under the new accounting guidance for business combinations,
Pengrowth was required to fair value its previously held equity investment in Monterey and as a result, a non-cash gain of $73.8 million arising from the difference between the fair value and the book value of this investment prior to the
acquisition was recorded in the consolidated statements of income. The fair value of Pengrowths previously held equity investment in Monterey was included in the purchase consideration. TAXES Future Income Taxes Future 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. During the year ended December 31, 2010, Pengrowth recorded a future tax reduction of $44.8 million. The future income tax reduction includes approximately $77.6 million related to taxable income earned by the Trust where both
the income tax and future tax liabilities are the responsibility of the trust unitholders, offset by temporary differences relating to unrealized risk management gains. See Note 11 to the financial statements for additional information. FOREIGN CURRENCY GAINS & LOSSES  Three months ended


Twelve months ended($ millions)

Dec 31, 2010


Sept 30, 2010


Dec 31, 2009


Dec 31, 2010


Dec 31, 2009Unrealized foreign exchange gain (loss) on translation of U.S. dollar denominated
debt


31.0



32.1



17.1



50.7



144.5Unrealized foreign exchange gain (loss) on translation of U.K. pound sterling denominated
debt


3.3



(1.3
)


0.6



7.4



3.834.3



30.8



17.7



58.1



148.3Unrealized (loss) gain on foreign exchange risk management contract on U.K. pound sterling
denominated debt


(4.5
)


(0.2
)


0.4



(8.1
)


0.9Total Unrealized foreign exchange gain


29.7



30.6



18.1



49.9



149.2Realized foreign exchange gain (loss)






0.5



(0.1
)


(2.1
)


0.5 The total
unrealized foreign exchange gain in the fourth quarter was $29.7 million compared to an unrealized foreign exchange gain of $30.6 million and $18.1 million in the third quarter 2010 and fourth quarter 2009, respectively. The primary source of
Pengrowths unrealized foreign exchange gains and losses is attributed 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 quarter end to another. The unrealized foreign exchange gain this quarter was mainly the result of an increase in the closing exchange rate of the Canadian dollar to U.S. dollar since September 30, 2010. As some realized commodity prices are derived from U.S. denominated benchmarks, a weaker U.S. dollar negatively impacts oil and gas revenues. To mitigate this,
Pengrowth elects to hold a portion of its long term debt in U.S. dollars as a natural hedge. Therefore, a decline in revenues as a result of foreign exchange fluctuations will be partially offset by a reduction in U.S. dollar interest expense. DEPLETION, DEPRECIATION AND ACCRETION  Three months ended


Twelve months ended($ millions)

Dec 31, 2010


Sept 30, 2010


Dec 31, 2009


Dec 31, 2010


Dec 31, 2009Depletion and depreciation


132.4



128.8



144.3



529.4



591.4$ per boe


19.20



19.25



20.23



19.42



20.38Accretion


5.7



5.8



7.1



23.0



27.7$ per boe


0.83



0.87



1.00



0.84



0.95




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Depletion and depreciation of property, plant and equipment is calculated using the unit of production method
based on total proved reserves. Depletion and depreciation expense decreased ten percent year over year as a result of lower production volumes and lower cost reserve additions in 2010. On a per boe basis, the depletion cost was relatively flat in
the fourth quarter of 2010 compared to the third quarter of 2010, however higher production volumes yielded a slightly higher depletion and depreciation expense in the fourth quarter. The prior year depletion and depreciation also reflects the
impact of 2009 reserve negative revisions which increased the depletion rate per boe. Pengrowths Asset Retirement Obligations (ARO) liability is
increased for the passage of time (unwinding of the discount) through a charge to earnings that is referred to as accretion. Accretion is charged to net income over the lifetime of the producing oil and gas assets. Accretion expense decreased year
over year and in the fourth quarter of 2010 compared to the same period last year as a result of reductions to the ARO liability at the end of 2009 and in the latter part of this year. The reduction to the ARO liability in 2010 were due to changes
in the inflation rate assumption used in the calculation from two percent per annum to one and one half percent per annum and changes to the estimated timing of abandonment and reclamation. Management reviews the cost estimates and timing
assumptions related to the ARO liability at least annually which may result in a revision to the ARO liability. CEILING TEST Under Canadian GAAP, a ceiling test is applied to the carrying value of the property, plant and equipment and other assets. The carrying value is
assessed to be recoverable when the sum of the undiscounted cash flow expected from the production of proved reserves, the lower of cost and market of unproved properties, and the cost of major development projects exceeds the carrying value. When
the carrying value is not assessed to be recoverable, an impairment loss is recognized to the extent that the carrying value of assets exceeds the sum of the discounted cash flow expected from the production of proved and probable reserves, the
lower of cost and market of unproved properties, and the cost of major development projects. The cash flow is estimated using expected future product prices and costs and are discounted using a risk-free interest rate, when required. There was a
significant surplus in the Canadian GAAP ceiling test at December 31, 2010 and 2009. ASSET RETIREMENT OBLIGATIONS 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, 2010 Pengrowths ARO liability decreased $29.3 million,
including a revision of approximately $42 million. The revision was primarily a result of changes to the inflation rate from two percent per annum to one and one half percent per annum and changes to the timing of future abandonment,
reclamation and remediation work. The inflation rate is based on current expectations and experience. The change in estimate was made on a prospective basis; a corresponding adjustment was made to the related asset. Pengrowth has estimated the net
present value of its total ARO to be $260 million as at December 31, 2010 (December 31, 2009  $289 million), based on a total escalated future liability of $1.8 billion (December 31, 2009  $2.0
billion). These costs are expected to be incurred over 50 years with the majority of the costs incurred between 2041 and 2061. A credit adjusted risk free rate of eight percent was used to calculate the net present value of the ARO. REMEDIATION TRUST FUNDS AND REMEDIATION AND ABANDONMENT EXPENSE During 2010, Pengrowth contributed $7.6 million into trust funds established to fund certain abandonment and reclamation costs associated with Judy Creek and SOEP. The balance in these remediation trust funds was
$42.1 million at December 31, 2010. Every five years Pengrowth must evaluate the value of the assets in the Judy Creek remediation trust fund and
the outstanding ARO, and make recommendations to the former owner of the Judy Creek properties as to whether contribution levels should be changed. The next evaluation is anticipated to occur in 2012. Contributions to the Judy Creek remediation
trust fund may change based on future evaluations of the fund. 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 feedstock handled and delivered to 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, 2010, Pengrowth spent $20.9 million on abandonment and reclamation (December 31, 2009  $18.0 million). Pengrowth expects to spend approximately $19 million in 2011 on reclamation and
abandonment, excluding contributions to remediation trust funds and orphan well levies from the Alberta Energy Resources Conservation Board.




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CLIMATE CHANGE PROGRAMS Since becoming effective July 1, 2007, Alberta regulates GHG emissions under the Climate Change and Emissions Management Act, the Specified Gas Reporting Regulation (the SGRR), which imposes GHG emissions reporting requirements, and the Specified Gas Emitters Regulation (the SGER) which imposes GHG emissions limits. These regulations require Alberta facilities that emit more than 100,000 tonnes of greenhouse gases a year to reduce
emissions intensity by 12 percent over the average emission levels of 2003, 2004 and 2005. Companies can make their reductions through improvements to their operations; by purchasing Alberta-based offset credits or by contributing to the Climate
Change and Emissions Management Fund. Pengrowth currently operates two facilities that are subject to the Alberta climate change regulations. Collectively, these facilities have reduced emissions by approximately 29 percent from the base line
emissions (2009 data). This reduction exceeds current-day requirements. Pengrowth is assessing options for meeting future greenhouse gas emission requirements. However, if the emissions remain at the current levels, Pengrowth may experience
additional annual costs of as much as $0.5 million for the acquisition of credits relating to the facilities to meet future baseline requirements. For further information, see Pengrowths AIF. Pengrowth is waiting on additional information from
other jurisdictions to assess the impact it will have on its operations. GOODWILL As at December 31, 2010, Pengrowth had a recorded goodwill amount of $712.7 million. The $51 million increase in goodwill in the current period is due to the
acquisition of Monterey. In accordance with GAAP, the goodwill balance must be assessed for impairment at least annually or more frequently if events
or changes in circumstances indicate that the balance might be impaired. If such impairment exists, it would be charged to income in the period in which the impairment occurs. Management has assessed goodwill for impairment and determined there is
no impairment at December 31, 2010. WORKING CAPITAL The working capital deficiency decreased at December 31, 2010 by $125.4 million compared to December 31, 2009. The change in working capital is primarily attributable to the maturity of the U.S. $150
million term notes on April 23, 2010. The repayment of the U.S. term notes was financed with the issuance of new U.S. dollar term notes in May 2010. FINANCIAL RESOURCES AND LIQUIDITY  As at ($ thousands) :

Dec 31, 2010


Dec 31, 2009


ChangeTerm credit facilities

$
39,000


$
60,000


$
(21,000
)Senior unsecured notes(1)


985,367



847,599



137,768Current portion of long term debt






157,546



(157,546
)Convertible debentures






74,828



(74,828
)Total outstanding debt


1,024,367



1,139,973



(115,606
)Working capital deficiency excluding current portion of long term debt


91,629



59,461



32,168Total debt including convertible debentures

$
1,115,996


$
1,199,434


$
(83,438
)Total debt excluding convertible debentures

$
1,115,996


$
1,124,606


$
(8,610
)Years Ended

Dec 31, 2010


Dec 31, 2009


ChangeNet income

$
230,257


$
84,853


$
145,404Add:Interest and financing charges


70,464



80,274



(9,810
)Future tax reduction


(44,829
)


(142,945
)


98,116Depletion, depreciation, amortization and accretion


552,356



619,032



(66,676
)Other non-cash (income) expenses


(115,566
)


44,482



(160,048
)EBITDA

$
692,682


$
685,696


$
6,986Total debt including convertible debentures to EBITDA


1.6



1.7



(0.1
)Total debt excluding convertible debentures to EBITDA


1.6



1.6



Total Capitalization including convertible debentures(2) (3)

$
4,211,343


$
3,935,174


$
276,169Total Capitalization excluding convertible
debentures(2) (3)

$
4,211,343


$
3,860,346


$
350,997Total debt including convertible debentures as a percentage of total capitalization(2)


26.5%



30.5%



(4.0%
)Total debt excluding convertible debentures as a percentage of total capitalization(2)


26.5%



29.1%



(2.6%
)  (1)
Non-current portion of long term debt.  (2)
Prior period restated to conform to presentation in the current period.  (3)
Total capitalization includes total outstanding debt plus Shareholders Equity. (Total outstanding debt excludes working capital deficit (excess) but includes current portion of long term debt.)




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Term Credit Facilities At December 31, 2010, Pengrowth had a $1.0 billion revolving credit facility which was renewed during the fourth quarter of 2010. The credit facility was reduced by $39 million in borrowings and $18 million in
outstanding letters of credit. The credit facility also includes a $250 million expansion feature. In total, the credit facility provides Pengrowth with up to $1.25 billion of credit capacity from a syndicate of seven Canadian and three foreign
banks and expires on October 29, 2013. Pengrowth also maintains a $50 million demand operating facility with one Canadian bank which is reduced by borrowings of $22 million and $5 million in outstanding letters of credit. Together these
two facilities provide Pengrowth with up to $1.2 billion of available credit at December 31, 2010. Senior Unsecured Notes On April 23, 2010, U.S $150 million in senior unsecured notes matured resulting in the realization of a cumulative $66 million foreign exchange gain
previously recognized. The maturity was temporarily funded with borrowings from the revolving credit facility until a new issue of U.S. $187 million senior unsecured notes closed on May 11, 2010. The new notes were issued in two tranches, U.S.
$71.5 million due May 2015 and U.S $115.5 million due May 2020 bearing interest at 4.67 and 5.98 percent respectively. Convertible Debentures On January 14, 2010, Pengrowth redeemed all of the outstanding Convertible Unsecured Subordinated Debentures. 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, 2010. All loan agreements are filed on SEDAR (www.sedar.com) as Other or
Material Document. The calculation for each financial covenant is based on specific definitions, is not in accordance with GAAP and cannot
be readily replicated by referring to Pengrowths financial statements. The financial covenants are substantially similar between the credit facilities and the senior unsecured notes. Key financial covenants are summarized below:  1.
Total senior debt must not exceed 3.0 times EBITDA for the last four fiscal quarters;  2.
Total debt must not exceed 3.5 times EBITDA for the last four fiscal quarters;  3.
Total senior debt must be less than 50 percent of total book capitalization; and  4.
EBITDA must not be less than four times interest expense. 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 the debt, refinance the debt or negotiate new terms with the debt holders 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, raising equity, property dispositions, reducing capital expenditures or dividends. Details of these measures are included in Note 19 to the December 31, 2010, audited consolidated financial statements. Dividend Reinvestment Plan In conjunction with
the conversion of the Trust into a corporation, Pengrowth revised its Dividend Reinvestment Plan (DRIP). DRIP entitles shareholders to reinvest cash dividends in additional shares of the Corporation. Under the revised DRIP, the shares
are issued from treasury at a five percent discount to the weighted average closing price of all shares traded on the TSX for the five trading days preceding a dividend payment date.




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Previously, the Trust had a similar program where unitholders were entitled to reinvest cash distributions in
additional trust units of the Trust. The trust units under this plan were issued from treasury at a five percent discount to the weighted average closing price of all trust units traded on the TSX for the 20 trading days preceding a distribution
payment date. For the year ended December 31, 2010, 2.3 million trust units were issued for cash proceeds of $24.1 million under the
reinvestment plan compared to 3.0 million trust units for cash proceeds of $26.3 million at December 31, 2009. Pengrowth does not have any
off balance sheet financing arrangements. 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. Please see Note 2 to the financial statements for a description of the accounting policies for financial instruments and Note 20 to the financial statements for additional information regarding market risk,
credit risk, liquidity risk and fair value of Pengrowths financial instruments. CASH FLOW AND DISTRIBUTIONS/DIVIDENDS The following table provides cash flow from operating activities, net income and distributions declared with the excess (shortfall) over distributions and payout
ratio:  Three months ended


Twelve months ended($ thousands, except per trust unit amounts)

Dec 31, 2010


Sept 30, 2010


Dec 31, 2009


Dec 31, 2010


Dec 31, 2009Cash flow from operating activities


137,783



159,926



149,933



605,995



551,350Net income


1,937



125,632



50,523



230,257



84,853Distributions declared


45,118
(1)


65,254



60,880



232,584
(1)


287,853Distributions declared per trust unit


0.14
(1)


0.21



0.21



0.77
(1)


1.08Excess of cash flow from operating activities over distributions declared


92,665



94,672



89,053



373,411



263,497Per trust unit


0.28



0.32



0.32



1.24



1.00(Shortfall) Surplus of net income (loss) over distributions declared


(43,181
)


60,378



(10,357
)


(2,327
)


(203,000
)Per trust unit


(0.13
)


0.20



(0.04
)


(0.01
)


(0.77
)Payout Ratio


33%



41%



41%



38%



52%  (1)
Reflects one month less of distribution declared as a result of the corporate conversion. 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 cash flow from operating activities over distributions declared, through additional debt or the issuance of equity. Pengrowth does
not deduct capital expenditures when calculating cash flow from operating activities. However, Pengrowth does deduct costs associated with environmental activities when calculating cash flow from operating activities. Cash flow from operating activities is derived from producing and selling oil, natural gas and related products. As such, cash flow from operating activities is
highly dependent on commodity prices. Pengrowth entered into forward commodity contracts to mitigate price volatility and to provide a measure of stability to monthly cash flow. Details of commodity contracts are contained in Note 20 to the
financial statements. DIVIDENDS The
board of directors and management regularly review the level of dividends. The board considers a number of factors, including expectations of future commodity prices, capital expenditure requirements, and the availability of debt and equity capital.
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.




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Cash dividends are generally paid to shareholders on or about the 15thday of the month. Pengrowth paid $0.21 per trust unit as cash distributions in each of
the quarters of 2010. SUMMARY OF QUARTERLY RESULTS The following table is a summary of quarterly information for 2010 and 2009.  2010

Q1


Q2


Q3


Q4Oil and gas sales ($000's)


358,131



336,957



317,505



340,690Net income/(loss) ($000's)


108,816



(6,128
)


125,632



1,937Net income/(loss) per share ($)


0.37



(0.02
)


0.42



0.01Net income/(loss) per share  diluted ($)


0.37



(0.02
)


0.42



0.01Cash flow from operating activities ($000's)


146,736



161,550



159,926



137,783Distributions declared ($000's)


61,037



61,175



65,254



45,118
(1)Distributions declared per unit ($)


0.21



0.21



0.21



0.14
(1)Daily production (boe)


75,627



75,517



72,704



74,953Total production (mboe)


6,806



6,872



6,689



6,896Average realized price ($ per boe)


52.49



48.75



47.07



49.01Operating netback ($ per boe)


27.58



27.16



26.12



24.582009

Q1


Q2


Q3


Q4Oil and gas sales ($000's)


322,973



335,634



325,264



359,296Net income/(loss) ($000's)


(54,232
)


10,272



78,290



50,523Net income/(loss) per share ($)


(0.21
)


0.04



0.30



0.18Net income/(loss) per share  diluted ($)


(0.21
)


0.04



0.30



0.18Cash flow from operating activities ($000's)


94,386



144,116



162,915



149,933Distributions declared ($000's)


77,212



77,526



72,235



60,880Distributions declared per unit ($)


0.30



0.30



0.27



0.21Daily production (boe)


80,284



82,171



78,135



77,529Total production (mboe)


7,226



7,478



7,188



7,133Average realized price ($ per boe)


44.57



44.74



45.22



50.35Operating netback ($ per boe)(2)


26.63



24.71



26.28



23.87  (1)
Reflects one month less of distribution declared as a result of the corporate conversion.  (2)
Prior period restated to conform to presentation in the current period. In addition to natural decline, production changes over these quarters was a result of non-core property dispositions in the fourth quarter of 2009 and production limitations due to plant turnarounds and
unscheduled maintenance in the third quarter of 2010 and the second and third quarters of 2009, partly offset by the Monterey acquisition in the third quarter of 2010. Changes in commodity prices have affected oil and gas sales, which have been
partially muted by risk management activity to mitigate price volatility and to provide a measure of stability to monthly cash flow. Quarterly net income (loss) in 2010 and 2009 has also been impacted by non-cash charges, in particular depletion,
depreciation and amortization, accretion of ARO, unrealized mark-to-market gains and losses, unrealized foreign exchange gains and losses, and future taxes. Cash flow was impacted by changes in operating and general and administrative costs.




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SELECTED ANNUAL INFORMATION The table below provides a summary of selected annual financial information for the years ended 2010, 2009, and 2008.  Twelve months ended December 31($ thousands)

2010


2009


2008Oil and gas sales


1,353,283



1,343,167



1,919,049Net income


230,257



84,853



395,850Net income per share(1)($)


0.76



0.32



1.58Net income per share(1) diluted ($)


0.76



0.32



1.58Distributions declared per trust unit ($)


0.77
(2)


1.08



2.59Total assets


5,042,766



4,693,604



5,317,341Long term debt(3)


1,024,367



982,427



1,599,418Shareholders' equity(1)


3,186,976



2,795,201



2,663,805Number of shares outstanding at year end
(thousands)(1)


326,024



289,835



256,076  (1)
Comparative amounts are Trust units and Trust Unitholders' Equity.  (2)
Reflects one month less of distribution declared as a result of the corporate conversion.  (3)
Includes long term debt and convertible debentures. Oil and gas
sales for 2010 increased as a result of higher liquids prices through the year partly offset by lower production volumes primarily due to natural decline. Higher realized commodity prices for the first three quarters of 2008 were the main
contributor to higher oil and gas sales values compared to 2009 and 2010. Net income and dividends declared are strongly linked to oil and gas sales. Long term debt is lower at December 31, 2010 and 2009 than in 2008 due mainly to $285 million
of net proceeds from an equity issue being applied to the credit facility, and the repayment of the convertible debentures early in 2010. COMMITMENTS AND CONTRACTUAL OBLIGATIONS  ($ thousands)

2011


2012


2013


2014


2015


thereafter


TotalLong term debt(1)(2)










88,730







148,679



791,285



1,028,694Interest payments on long term debt(3)


63,087



63,087



60,985



59,078



56,600



120,848



423,685Other(4)


13,571



13,430



13,335



12,840



12,153



23,268



88,59776,658



76,517



163,050



71,918



217,432



935,401



1,540,976Purchase obligationsPipeline transportation


28,477



27,286



17,489



15,862



14,469



393



103,976CO2purchases(5)


3,114



2,811



2,828



2,843



2,860



818



15,27431,591



30,097



20,317



18,705



17,329



1,211



119,250Remediation trust fund payments


250



250



250



250



250



11,250



12,500108,499



106,864



183,617



90,873



235,011



947,862



1,672,726  (1)
The debt repayment includes the principal owing at maturity on foreign denominated fixed rate debt translated using the year end exchange rate. (see Note 9 of the financial
statements)  (2)
The revolving credit facility matures in 2013. (see Note 9 of the financial statements)  (3)
Interest payments are calculated at period end exchange rates and interest rates except for foreign denominated fixed rate debt which is calculated at the actual interest rate.  (4)
Includes office rent and vehicle leases.  (5)
For the Weyburn CO2 project, prices are denominated in U.S. dollars and have been
translated at the year-end exchange rate.




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SUMMARY OF COMMON SHARE TRADING DATA  High


Low


Close


Volume (000s)


Value ($ millions)TSX - PGF ($ Cdn)2010

1st quarter


11.96



10.15



11.75



33,376



372.72nd quarter


12.00



8.50



9.73



34,038



361.03rd quarter


11.44



9.40



11.34



47,522



488.84th quarter


13.38



11.29



12.78



70,469



896.9Year


13.38



8.50



12.78



185,405



2,119.42009

1st quarter


12.33



5.84



7.10



30,564



252.62nd quarter


9.81



6.71



9.18



26,934



233.83rd quarter


11.33



7.49



11.33



28,766



269.04th quarter


11.39



9.40



10.15



42,483



439.2Year


12.33



5.84



10.15



128,747



1,194.6NYSE - PGH ($ U.S.)2010

1st quarter


11.78



9.78



11.66



20,473



218.82nd quarter


11.97



7.67



9.16



26,059



268.73rd quarter


11.10



8.85



11.06



20,153



200.04th quarter


13.25



11.02



12.86



19,810



245.0Year


13.25



7.67



12.86



86,493



932.52009

1st quarter


10.11



4.51



5.58



28,538



195.82nd quarter


9.00



5.30



7.90



27,305



205.83rd quarter


10.54



6.43



10.51



23,914



203.14th quarter


10.52



8.81



9.63



29,823



290.7Year


10.54



4.51



9.63



109,580



895.4 BUSINESS RISKS The amount of dividends available
to shareholders and the value of Pengrowth common shares are subject to numerous risk factors. As the common shares allow investors to participate in the net cash flow from Pengrowths portfolio of producing oil and natural gas properties, the
principal risk factors that are associated with the oil and gas business include, but are not limited to, the following influences: 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, pipeline transportation and political and economic stability.  

Production could be shut-in at specific wells or fields in 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 reducing the recorded book value of some of its assets. 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. In response, Pengrowth has established a credit policy designed to mitigate this risk and monitors its counterparties on a regular basis.




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

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 dividend to our shareholders. 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.  

Changes to accounting policies, including the implementation of IFRS, 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 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 are having a direct impact on cycle times.  

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 and it may be more
difficult to hire and retain professional staff.  

Attacks by individuals against facilities and the threat of such attacks 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. 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




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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 effected.  

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.  

The ability of investors resident in the United States to enforce civil remedies may be negatively affected for a number of reasons. These factors should not be considered exhaustive. Additional risks are outlined in the AIF of the Corporation available on SEDAR at
www.sedar.com. SUBSEQUENT EVENTS Subsequent to December 31, 2010, Pengrowth has entered into additional fixed price commodity sales contracts with third parties (see Note 23 to the financial
statements). On January 1, 2011, Pengrowth experienced a pipeline incident at the Swan Hills gas gathering pipeline system in North Central
Alberta. The incident resulted in the shut-in of approximately 1,500 barrels of oil equivalent per day of production, net to Pengrowth. On March 2, 2011, the line was placed back in service. OUTLOOK At this time, Pengrowth anticipates
spending $400 million on its capital program in 2011. The 2011 capital program is designed to be flexible, scalable and responsive to uncertain commodity prices and market conditions. The capital program of $400 million represents a 12 percent
increase compared with the $358 million 2010 program. Pengrowth's 2011 production volumes are projected to be flat year-over-year and to deliver
average daily production volumes of between 74,000 and 76,000 boe per day. 2011 operating costs are forecast to be $370 million or $13.54 per boe,
essentially flat to 2010. Total G&A costs are expected to increase for 2011 to $2.69 per boe when compared to full year 2010 of $1.87 per boe.
Included in Pengrowth's 2011 G&A forecast, are non-cash G&A costs of approximately $0.47 per boe compared to $0.17 per boe in 2010. INTERNATIONAL FINANCIAL REPORTING STANDARDS (IFRS) What is IFRS? International Financial Reporting Standards (IFRS) are a set of accounting standards developed by the International Accounting Standards Board. The goal
of IFRS is to provide a global framework for how public companies prepare and disclose their financial statements. IFRS provides general guidance for the preparation of financial statements rather than setting rules for industry specific reporting.
IFRS is now required or permitted in over 100 countries, including the European Union and much of the Pacific Rim. Canadian publicly accountable enterprises are required to adopt IFRS, in full, and without modification, in place of Canadian GAAP for
interim and annual periods beginning on or after January 1, 2011. In the United States there is no current plan for the adoption of IFRS, although the Securities and Exchange Commission has eliminated the IFRS/U.S. GAAP reconciliation requirement
for foreign-filers, like Pengrowth, when fully implemented and audited.




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IFRS Project Plan Pengrowth commenced its IFRS conversion project in 2008 and has established a formal governance structure. This structure includes a full time IFRS Project Coordinator, a steering committee consisting of senior
members of the finance team on an ongoing basis and includes information technology, treasury and operations personnel as required. Pengrowth has also engaged an external expert advisory firm. Regular IFRS project reporting is provided to senior
management and to the Audit Committee of the Board of Directors. Senior management and the Board of Directors have participated in IFRS sessions to gain an understanding of the relevant aspects of IFRS. Pengrowths project consists of four phases: diagnostic; design and planning; solution development; and implementation.  

Diagnostic  This phase involves performing a high-level review of the major differences between Canadian GAAP and IFRS and to identify
information technology and business processes that may be impacted by the transition to IFRS. Status
 The diagnostic analysis was completed in mid-2008.  

Design and planning  The results of the diagnostic were ranked according to complexity, time to complete and potential impact on the
financial position and results of operations. A detailed plan was developed in order to address the issues identified and ranked in the diagnostic phase. The planning is updated and progress is reported to the Audit Committee on a regular basis. Status  Pengrowth completed the initial design and planning in mid-2009. The planning is
updated and progress is reported to the Audit Committee of the Board of Directors on a regular basis.  

Solution development  In this phase, items identified in the diagnostic phase are addressed according to the priority assigned. This phase
involves detailed analysis of the applicable IFRS standard in relation to current practice and development of alternative policy choices. In addition, certain potential differences are further investigated to assess whether there may be broader
impact to Pengrowths debt agreements, compensation arrangements or management reporting systems. The conclusion of the solution development phase will require the Audit Committee of the Board of Directors to review and approve significant
accounting policy choices as recommended by the IFRS Steering Committee. Status  Solution development began in late 2008 for classification of exploration and evaluation expenditures,
depletion, cash generating units and impairment of capital assets, share based payments, business combinations, financial instruments, trust unit holders equity and shareholders equity, risk sharing arrangements (farm-outs, assets swaps,
etc) and the initial adoption of IFRS. Pengrowth has completed its analysis but not finalized its position regarding provisions (including ARO) and income taxes.  

Implementation  Involves implementing all of the changes approved in the solution development phase and may include changes to accounting
policies, information systems, business processes, modification to agreements and training of staff impacted by the conversion. Status  Implementation of information technology changes began in 2009. Training for the IFRS Steering Committee members commenced in 2008. Internal education of the Audit Committee,
Board of Directors and key financial and accounting personnel began in the fourth quarter of 2009. Detailed implementation meetings involving internal personnel directly affected by IFRS also began in the fourth quarter of 2009. Continued training
and implementation meetings occurred throughout 2010. We are currently in the implementation phase, including making systems and procedural changes necessary to produce 2010 IFRS comparative financial statements. The review of the expected changes
in the 2010 IFRS financial statements, both internally and by our external auditors, began in the second quarter of 2010 and is ongoing. The implementation phase is expected to conclude upon issuance of 2011 audited annual financial statements in
March 2012. First  Time Adoption of IFRS The IFRS adoption date of January 1, 2011 for Canadian publicly accountable enterprises will require the restatement, for comparative purposes, of amounts reported by Pengrowth for the year ended
December 31, 2010, including the opening IFRS balance sheet as of January 1, 2010. IFRS 1, First-Adoption of International Financial
Reporting Standards (IFRS 1), sets out the procedures that an entity must follow when it adopts IFRS for the first time as the basis for preparing its general purpose financial statements. In addition, IFRS 1 provides entities
adopting IFRS for the first time with a number of optional exemptions and mandatory exceptions in certain areas to the general requirement of full retrospective application of IFRS. Pengrowth continues to review the potential adjustments to the
January 1, 2010 opening IFRS balance sheet and the effects of transition to IFRS are subject to change. The most significant accounting policies that have been identified and the key differences that may impact the January 1, 2010 IFRS
opening balance sheet are as follows: Deemed Cost Exemption  Under Canadian full cost accounting, Pengrowth has historically
accounted for exploration and development costs of oil and gas properties in the development and production phases in a single Canada wide full cost accounting




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pool. Under IFRS, exploration and evaluation expenditures will be reclassified as intangible exploration assets. IFRS 1 contains an exemption that would allow Pengrowth to measure oil and gas
assets at the date of transition as follows:  (i)
exploration and evaluation assets are reclassified from the full cost pool to intangible exploration assets at the amount that was recorded under Canadian GAAP; and  (ii)
the remaining full cost pool is allocated to the producing/development assets and components pro rata using reserve values or reserve volumes. Pengrowth intends to make use of this exemption. The reclassification of exploration and evaluation assets is expected to result in a $68 million increase in
intangible exploration assets with a corresponding decrease in property, plant and equipment at January 1, 2010. The remaining full cost pool will be allocated on the basis of total proved plus probable using reserve values and
January 1, 2010 forecast pricing. The total value of exploration and producing oil and gas assets will remain unchanged. Impairment of
Property, Plant & Equipment (PP&E) assets  Pengrowth is required to assess the PP&E assets for impairment upon transition to IFRS. Currently, impairment of PP&E is assessed at a consolidated level
under Canadian GAAP. Under IFRS, impairment of PP&E must be assessed at a more detailed level. Impairment calculations will be performed at the Cash Generating Unit (CGU) level, using the greater of fair value less costs to sell or
the value in use. We do not currently expect to record any impairment of oil and gas assets on transition to IFRS. Impairment of
Goodwill  Pengrowth is required to assess goodwill for impairment upon transition to IFRS. Currently impairment of goodwill is assessed at a consolidated level under Canadian GAAP. Under IFRS, goodwill is identified with specific
CGUs or group of CGUs and consequently impairment must be assessed at a more detailed level. Impairment testing of goodwill will be performed in relation to the individual CGU or groups of CGUs that the goodwill relates to. We do not currently
expect to record any impairment of goodwill on transition to IFRS. Business Combinations  IFRS 1 would allow Pengrowth to adopt
the IFRS policies for business combinations on a prospective basis rather than retrospectively restating all prior business combinations. Pengrowth is expecting to use this IFRS 1 exemption and not restate any business combinations prior to the IFRS
transition date of January 1, 2010. The IFRS policies for business combinations are converged with the new CICA Handbook section 1582 that are effective for business combinations completed on or after January 1, 2011; however, early
adoption under Canadian GAAP is permitted. Early adoption would eliminate the majority of differences between Canadian GAAP, U. S. GAAP and IFRS for business combinations completed prior to December 31, 2010. Pengrowth has early adopted CICA
1582, effective January 1, 2010. The acquisition of Monterey in the third quarter of 2010 is the first transaction affected by this change. Provisions  Under IFRS, contract liabilities and decommissioning obligations are classified as provisions. Accounting for contract
liabilities remains unchanged under IFRS. Decommissioning obligations, disclosed as asset retirement obligations under Canadian GAAP, are anticipated to be calculated using a risk free discount rate under IFRS, which is currently estimated to be
four percent. In addition, the timing and cost estimates are being revised to reflect the best estimate of what Pengrowth would rationally pay to settle the obligation, as permitted under IFRS. The net effect of using a risk free discount rate,
partly offset by revised timing and cost estimates is expected to result in approximately $162 million or 56% increase to decommissioning liabilities as presented on the January 1, 2010 opening IFRS Balance Sheet. Under Canadian GAAP, Pengrowth
used a credit adjusted risk free rate of 8%. Due to the use of the aforementioned IFRS 1 election for full cost oil and gas entities, the increase to the decommissioning liabilities is required to be recognized directly in opening equity, resulting
in a corresponding increase to the opening deficit estimated to be approximately $99 million, after tax. The International Accounting Standards Board and its Interpretations Committee continue to debate the inclusion of an entitys own credit
risk in the discount rate used for long-term provisions. It is unclear if clarification of the requirement to use a risk free discount rate will be forthcoming before the filing of the Q1 2011 interim financial statements prepared in accordance with
IFRS. Income Tax  Any changes to income tax reporting are expected to be predominantly caused by changes in the book value of
assets and changes in tax rates applied, not due to the change in income tax accounting methodology. IFRS requires that all future taxes be disclosed as non-current assets or liabilities and designated as deferred taxes. In addition, as the Trust
was classified as a mutual fund trust on the transition date, for Canadian tax purposes, the income tax assets and liabilities of the Trust must be tax effected using the top marginal rate of 39% upon transition to IFRS which is expected to result
in a reduction to the future tax liability of $164 million. This adjustment, in addition to the tax affect of other IFRS opening balance sheet adjustments, is expected to result in a total reduction to future income taxes of approximately $226
million and a decrease to the deficit of approximately $219 million and an increase to equity of approximately $7 million upon transition. It is also anticipated that a significant portion of this transition adjustment will reverse through deferred
tax expense in the fourth quarter 2010 IFRS comparative income statement as a result of Pengrowths conversion to a dividend paying corporation on December 31, 2010.




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Financial Instruments  IFRS allows a one-time opportunity to re-examine the designation of financial
instruments. Pengrowth expects to re-designate the Judy Creek Remediation Trust Fund from held-to-maturity to fair-value-through-profit-or-loss and the Private Company investment from available-for-sale to fair-value-through-profit-or-loss upon
transition to IFRS and therefore record these assets at fair value. This would result in a $7 million increase to other assets at January 1, 2010 with a corresponding decrease to opening deficit upon transition to IFRS. Future changes in the
fair value would be recognized in income. Trust Unit-Holders Equity  If unable to qualify for classification as equity, Pengrowth trust
units would be classified as liabilities on the balance sheet prior to December 31, 2010. After a detailed review of Pengrowths trust indenture, we believe that Pengrowths trust unit holders equity will continue to be
classified in equity. The significance of this issue is minimized as Pengrowth converted to a dividend paying corporation on December 31, 2010 and the common shares of Pengrowth Energy Corporation are classified as equity under IFRS. Pengrowth has completed its initial assessment of the adoption of IFRS and anticipates changes to the January 1, 2010 opening balance sheet as
noted below. Management has not yet finalized its accounting policies and as such the expected opening balance sheet may change. In addition, due to potential changes to IFRS prior to Pengrowths adoption of IFRS, managements plan and
accounting policy decisions are subject to change based on new facts and circumstances that arise after the date of this MD&A. The effects of transition to IFRS on Provisions and Deferred Income Taxes, in particular, may be subject to change due
to uncertainty over discount rates, future expected costs and treatment of temporary tax differences within the Trust. Preliminary
Reconciliation of the Opening Balance Sheet items impacted by IFRS, as of January 1, 2010   ($ thousands)

Cdn GAAP


Reclassificationupon transitionto IFRS


Effect oftransitionto IFRS


IFRSFuture income tax assets(d)


969



(969
)






Other assets(c)


46,027







6,984



53,011Deferred income taxes(d)






(180,671
)


225,991



45,320Property, plant and equipment(a)


3,789,369



(67,597
)






3,721,772Intangible exploration assets(a)






67,597







67,597Current portion of contract liabilities(b)


1,728



(1,728
)






Current portion of provisions(b)






21,227







21,227Contract liabilities(b)


7,952



(7,952
)






Provisions(b)






277,249



161,815



439,064Asset retirement obligations(b)


288,796



(288,796
)






Future income taxes(d)


181,640



(181,640
)






Trust unitholders equity(e)


4,920,945







6,379



4,927,324Deficit(e)


(2,144,521
)






64,781



(2,079,740
)  (a)
IFRS 1 election for full cost oil and gas entities Pengrowth
expects to elect an IFRS 1 exemption whereby the Canadian GAAP full cost pool will be measured upon transition to IFRS as follows:  (i)
exploration and evaluation assets are reclassified from the full cost pool to intangible exploration assets at the amount that was recorded under Canadian GAAP; and  (ii)
the remaining full cost pool is allocated to the producing/development assets and components pro rata using total proved plus probable reserve values and January 1, 2010
forecasted prices. This would result in a $68 million increase in intangible exploration assets with a corresponding decrease in
property, plant and equipment.  (b)
Provisions Under IFRS, contract liabilities and decommissioning
obligations are classified as provisions.




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Accounting for contract liabilities remains unchanged under IFRS. Decommissioning obligations, disclosed as asset retirement obligations under Canadian GAAP, are anticipated to be calculated using a risk free discount rate under
IFRS, which is currently estimated to be four percent. In addition, the timing and cost estimates are being revised to reflect the best estimate of what Pengrowth would rationally pay to settle the obligation, as permitted under IFRS. The net
effect of using a risk free discount rate, partly offset by revised timing and cost estimates is expected to result in an approximately $162 million or 56% increase to decommissioning liabilities as presented on the Balance Sheet. Due to the use of
the aforementioned IFRS 1 election for full cost oil and gas entities, the offset to the increase to the decommissioning liabilities is required to be recognized directly in opening equity, resulting in a corresponding increase to the opening
deficit. In the absence of the use of this IFRS 1 election for full cost oil and gas entities, the offset to the increase in the decommissioning liability would be recognized as an increase to the net book value of the related assets, resulting in
an increase to property, plant and equipment of $162 million. In addition, $19 million of these expenditures are expected to be made in 2010 and are thus classified as current liabilities. The International Accounting Standards Board and its Interpretations Committee continue to debate the inclusion of an entitys own credit risk in the discount
rate used for long-term provisions. It is unclear if clarification of the requirement to use a risk free discount rate will be forthcoming before the filing of the Q1 2011 interim financial statements prepared in accordance with IFRS. The estimated effect on Provisions of the implementation of IFRS, assuming the use of a four percent discount rate, can be quantified as follows:  Increase in Decommissioning Liabilities

$
161,815Tax Effect


(63,108
)Increase to opening deficit

$
98,707  (c)
Other assets Pengrowth expects to re-designate the Judy Creek
Remediation Trust Fund from held-to-maturity to fair-value-through-profit-or-loss and the Private Company Investment from available-for-sale to fair-value-through-profit-or-loss upon transition to IFRS and recorded these assets at fair value. This
would result in a $7.0 million increase to other assets at January 1, 2010 with a corresponding decrease to opening deficit upon transition to IFRS. Future changes in the fair value would be recognized in income. The estimated effect on Other Assets of the implementation of IFRS can be quantified as follows:  Increase in Other Assets

$
6,984Tax Effect


(891
)Decrease to opening deficit

$
6,093  (d)
Deferred income taxes Under IFRS, all deferred income taxes are
reported as non-current, resulting in a reclassification of the $1.0 million deferred tax asset to long term deferred tax liabilities at January 1, 2010. The change in the net present value of the decommissioning liability is expected to result in a $63 million decrease in the deferred tax liability. The change in the carrying value of the Judy Creek remediation
fund and Private Company investment is expected to result in a $1 million increase in the deferred tax liability. At January 1, 2010, the Trust was a flow-through entity that paid a significant portion of its taxable income to the unit-holders.
The temporary tax difference of the Trust under IFRS must be tax affected at the top marginal tax rate in Canada resulting in a reduction of the deferred tax liability of $164 million and a resulting decrease in the opening deficit of $157 million
and an increase to trust unit-holders capital of $7 million. A significant portion of this tax recovery is expected to reverse through the IFRS comparative income statement as deferred tax expenses in the fourth quarter of 2010 as Pengrowth
converted to a dividend paying corporation on December 31, 2010.




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The estimated effect on Deferred Income Taxes of the implementation of IFRS can be quantified as follows:  Decrease in tax liability due to increase in provisions

$
63,108Increase in tax liability due to increase in other assets


(891
)Decrease in tax liability due to changes to book value of net assets

$
62,217Decrease in tax liability due to changes in effective tax rate


163,774Decrease in opening deferred tax liability

$
225,991Cdn GAAP Future Tax Liability

$
(180,671
)Decrease in opening deferred tax liability


225,991IFRS Deferred Tax Asset

$
45,320  (e)
Opening Deficit Under IFRS 1  First Time Adoption of
International Financial Reporting Standards (IFRS 1) most changes to the January 1, 2010 opening balance sheet are applied retrospectively through opening deficit. This includes changes to Provisions, Other Assets and Deferred Taxes
as described above. The estimated effect on the Opening Deficit of the implementation of IFRS can be quantified as follows:  Increase due to increase to provisions

$
(98,707
)Decrease due to change to other assets


6,093Decrease in tax liability due to changes in effective tax rates


157,395Decrease to opening deficit

$
64,781Increase to trust unitholders capital to change in effective tax rate

$
6,379 Ongoing IFRS
differences post first time adoption In addition to the IFRS differences affecting the January 1, 2010 opening balance sheet, Pengrowth
continues to review the potential adjustments to ongoing application of IFRS after the initial transition. Due to potential changes to IFRS prior to Pengrowths adoption of IFRS, managements plan and accounting policy decisions are
subject to change based on new facts and circumstances that arise after the date of this MD&A. The most significant ongoing accounting policies that have been identified and the key differences that may impact the financial statements are as
follows:  

Accounting for Exploration and Evaluations (E&E) expenditures  Upon transition to IFRS, Pengrowth will reclassify E&E
expenditures that are currently included in the PP&E balance on the Consolidated Balance Sheet. This will be comprised of the book value of Pengrowths unproven properties of approximately $68 million that was excluded from Depletion at
December 31, 2009 (see note 6 to the 2009 audited annual financial statements) and is expected to increase through 2010 due to expenditures on exploration and evaluation activities and the acquisition of additional exploration and evaluation
properties. E&E assets will not be depleted but must be assessed for impairment when there are indicators for possible impairment, such as allowing the mineral rights lease to expire or a decision to no longer pursue exploration and evaluation
of a specific E&E asset. The majority of the property, plant and equipment acquired in the Monterey acquisition was allocated to unproven and development properties, which significantly increased the net book value of E&E assets as of
December 31, 2010.  

Impairment of PP&E assets  Impairment of PP&E is currently assessed at a single consolidated level using an annual ceiling test.
Under IFRS, impairment of PP&E must be assessed at a more detailed level whenever there is an indication of impairment such as changes in commodity prices or operational performance. Under IFRS, impairment calculations will be performed at the
Cash Generating Unit (CGU) level, using the greater of fair value less costs to sell or the value in use. This may result in more frequent impairments of assets under IFRS given the smaller size of the entity or CGU being evaluated.  

Calculation of Depletion Expense  Pengrowth currently calculates depletion of production and development assets on a consolidated basis
based on total production and total proved reserves. Under IFRS, depletion will be calculated at a more detailed level and at least at the level of cash generating units. In addition, under IFRS Pengrowth has chosen to use total proven plus probable
reserves for its depletion calculation. The use of total proven plus probable reserve base for calculating depletion would be expected to result in a decrease to the consolidated depletion expense of approximately $4.25 to $4.75 per boe of
production or $28 million to $33 million per quarter.  

Risk Sharing Arrangements and Dispositions  Risk sharing arrangements where Pengrowth cedes a portion of its working interest to a partner
are generally considered disposals of property, plant and equipment under IFRS. Canadian full cost




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accounting guidelines require that no gain or loss be recorded on these or other dispositions where the change in consolidated depletion is less than 20 percent. No such guidance exists under
IFRS. As a result, it is expected that Pengrowth will record gains or losses on these transactions under IFRS. The significance of these gains or losses will be dependant on the details of specific transactions and cannot be reasonably quantified.
The first transaction identified, the previously disclosed GORR sale in Q1 2010, is expected to result in a gain of approximately $8 million as compared to no gain under current GAAP.  

Financial Covenants  Pengrowth has analyzed the impact of IFRS on financial covenants and financing relationships. The primary impact will
be an increase in the debt-to-equity ratio as a result of the IFRS opening balance sheet adjustments to the deficit. Pengrowth nonetheless expects to be fully compliant with all financial debt covenants upon transition to IFRS.  

Compensation Arrangements  Pengrowth does not expect any material changes to compensation arrangements, including all share based
compensation plans, due to the transition to IFRS. Pengrowth has reviewed internal compensation arrangements and determined that the anticipated changes to financial measures as a result of IFRS will not directly affect any of these compensation
arrangements. In addition to the accounting policy differences, Pengrowths transition to IFRS will impact the internal controls
over financial reporting, the disclosure controls and procedures and IT systems as follows:  

Internal controls over financial reporting  As the review of Pengrowths accounting policies is completed, an assessment has been
made to determine changes required for internal controls over financial reporting. For example, additional controls will be implemented for the IFRS 1 changes and preparation of comparative information. This will be an ongoing process to ensure that
changes in accounting policies include the appropriate additional controls and procedures for future IFRS reporting requirements.  

Disclosure controls and procedures  Throughout the transition process, Pengrowth will be assessing stakeholders information
requirements and will ensure that adequate and timely information is provided so that stakeholders are kept apprised.  

IT Systems  Pengrowth has completed the system modifications required for IFRS reporting. Pengrowths IT systems did not require
significant modifications to track PP&E and E&E at a more detailed level within the financial reporting systems. Pengrowths IFRS staff has worked with IT and operational staff to ensure all costs are captured and recorded in a manner
consistent with IFRS depletion, impairment cost center groupings and accounting for asset retirement obligations. Insignificant changes to procedures and systems outside the accounting and finance department have been made. Changes were also made to
allow Pengrowth to account for certain transactions and prepare Canadian GAAP and IFRS financial statements in 2010. Additional systems modifications may be required. Pengrowth continues to make progress on its IFRS convergence plan and management believes that Pengrowth will be in a position to prepare IFRS financial statements in the first quarter of 2011. Pengrowth has not
made any final determination as to what options it may select upon conversion to IFRS. Changes in financial reporting under some options may be significantly different. The final decisions are subject to the approval of Pengrowths Audit
Committee and Board of Directors and the concurrence of Pengrowths auditors. Pengrowth continues to monitor the IFRS adoption efforts of many of its peers and participates in related processes, as appropriate. Pengrowth is currently involved
in an IFRS working group composed of intermediate to large oil and gas producers and an IFRS and Financial Reporting group consisting of a peer group of former income trusts. Recent Accounting Pronouncements As of January 1, 2010, Pengrowth early adopted the following
new Canadian standards: CICA 1582 Business Combinations, which replaces the previous business combinations standard. The standard requires
assets and liabilities acquired in a business combination, consideration paid, contingent consideration and certain acquired contingencies to be measured at fair value on the date of acquisition. In addition, acquisition related and restructuring
costs are recognized separately from the business combination and are included in the statement of income. The adoption of this standard impacts the accounting treatment of business combinations entered on or after January 1, 2010. With respect
to the Monterey acquisition in 2010 (Note 4), the most significant impact of the new standards was the recognition of a $73.8 million gain on existing equity investment in Monterey. In addition, the share consideration paid for Monterey was valued
using the closing date trust unit price versus the announcement date trust unit price which increased the consideration paid by $40.0 million. CICA
1601 "Consolidated Financial Statements", which together with Section 1602 below replace the former consolidated financial statements standard. Section 1601 establishes the requirements for the preparation of consolidated financial
statements. The adoption of this standard had no material impact on Pengrowths financial statements. CICA 1602 "Non-controlling Interests
establishes the accounting for a non-controlling interest in a subsidiary in consolidated financial statements subsequent to a business combination. The standard requires a non-controlling interest in a subsidiary to be classified as a separate
component of equity. In addition, net earnings and components of other comprehensive income are




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attributed to both the parent and non-controlling interest. The adoption of this standard had no impact on the consolidated financial statements. DISCLOSURE CONTROLS AND PROCEDURES As a Canadian
reporting issuer with securities listed on both the TSX and the NYSE, Pengrowth is required to comply with Multilateral Instrument 52-109  Certification of Disclosure in Issuers Annual and Interim Filings, as well as the
Sarbanes Oxley Act (SOX) enacted in the United States. Both the Canadian and U.S. certification rules include similar requirements where both the Chief Executive Officer (CEO) and the Chief Financial Officer (CFO) must assess
and certify as to the effectiveness of the disclosure controls and procedures as defined in Canada by Multilateral Instrument 52-109  Certification of Disclosure in Issuers Annual and Interim Filings and in the United States by Rules
13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended. The CEO, Derek Evans, and the CFO, Christopher Webster, evaluated the
effectiveness of Pengrowths disclosure controls and procedures for the year ending December 31, 2010. 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, 2010, 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 financial statements for external purposes in accordance with accounting principles generally accepted in
Canada and reconciling to accounting principles generally accepted in the U.S. 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 financial statements in accordance with generally
accepted accounting principles 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 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, 2010. 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, 2010. The effectiveness of internal control over financial reporting as of December 31, 2010 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, 2010. No changes were made to our internal control over financial
reporting during the year ending December 31, 2010 that have materially affected, or are reasonably likely to materially affect, the internal controls over financial reporting.




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APPENDIX C

CONSOLIDATED FINANCIAL STATEMENTS OF PENGROWTH ENERGY CORPORATION, INCLUDING MANAGEMENTS REPORT TO SHAREHOLDERS, THE AUDITORS REPORTS AND NOTE 24 THEREOF WHICH INCLUDES A RECONCILIATION OF
THE CONSOLIDATED FINANCIAL STATEMENTS TO UNITED STATES GENERALLY ACCEPTED ACCOUNTING PRINCIPLES



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MANAGEMENTS REPORT TO SHAREHOLDERS MANAGEMENTS RESPONSIBILITY TO SHAREHOLDERS The
financial statements are the responsibility of the management of Pengrowth Energy Corporation. They have been prepared in accordance with generally accepted accounting principles, using managements best estimates and judgments, where
appropriate. Management is responsible for the reliability and integrity of the financial statements, the notes to the financial statements, and other
financial information contained in this report. 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 financial statements. Management is also responsible for
ensuring that management fulfills its responsibilities for financial reporting and internal control, including managements requirement to assess the effectiveness of internal control over financial reporting as at December 31, 2010. The
Board is assisted in exercising its responsibilities through the Audit Committee of the Board, which is composed of four non-management directors. The Committee meets periodically with management and the auditors to satisfy itself that
managements responsibilities are properly discharged, to review the financial statements and to recommend approval of the 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 generally accepted auditing standards and
provided an independent professional opinion. The auditors have full and unrestricted access to the Audit Committee to discuss the audit and their related findings as to the integrity of the financial reporting process.  LOGO

LOGODerek W. Evans

Christopher G. WebsterPresident and Chief Executive Officer

Chief Financial Officer March 8, 2011




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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, which comprise the consolidated balance sheets as at December 31, 2010 and 2009, the consolidated statements of income and deficit, and cash flow for 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 Canadian generally
accepted accounting principles, 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 opinions. OPINION In our opinion, the consolidated financial statements present fairly, in all material
respects, the consolidated financial position of the Pengrowth Energy Corporation as at December 31, 2010 and 2009 and its consolidated results of operations and consolidated cash flow for the years then ended in accordance with Canadian
generally accepted accounting principles. EMPHASIS OF MATTER We draw your attention to Note 3 to the consolidated financial statements which describes the early adoption of Canadian Institute of Chartered Accountants (CICA) Handbook Section 1582
Business Combinations. Our opinion is not qualified in respect of this matter. OTHER MATTER We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Pengrowth Energy Corporations
internal control over financial reporting as of December 31, 2010, 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 March 8, 2011 expressed an unmodified opinion on the effectiveness of the Pengrowth Energy Corporations internal control over financial reporting.  LOGOChartered AccountantsCalgary, CanadaMarch 8, 2011




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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 internal control over financial reporting as of December 31, 2010, based on
the criteria established in Internal Control  Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Pengrowth Energy 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 Pengrowth Energy 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, Pengrowth Energy Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31,
2010, 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
Pengrowth Energy Corporation as of December 31, 2010 and 2009, and the related consolidated statements of income and deficit and cash flow for the years then ended, and our report dated March 8, 2011 expressed an unqualified opinion on
those consolidated financial statements.  LOGOChartered AccountantsCalgary, CanadaMarch 8, 2011




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CONSOLIDATED BALANCE SHEETS (Stated in thousands of dollars)  As atDecember 31 2010


As atDecember 31 2009ASSETSCurrent AssetsCash and term deposits

$
2,849


$
Accounts receivable


189,616



182,342Fair value of risk management contracts (Note 20)


13,550



14,001Future income taxes (Note 11)






969206,015



197,312Other Assets (Note 5)


47,114



46,027Property, Plant And Equipment (Note 6)


4,076,976



3,789,369Goodwill (Note 4)


712,661



660,896TOTAL ASSETS

$5,042,766



$
4,693,604LIABILITIES AND SHAREHOLDERS EQUITYCurrent LiabilitiesBank indebtedness (Note 9)

$
22,000


$
11,563Accounts payable


240,952



185,337Distributions payable (Note 14)


22,534



40,590Fair value of risk management contracts (Note 20)


9,278



17,555Future income taxes (Note 11)


1,203



Contract liabilities (Note 7)


1,677



1,728Current portion of long-term debt (Note 9)






157,546297,644



414,319Fair Value of Risk Management Contracts (Note
20)


31,416



23,269Contract Liabilities (Note 7)


6,275



7,952Convertible Debentures (Note 8)






74,828Long Term Debt (Note 9)


1,024,367



907,599Asset Retirement Obligations (Note 10)


259,538



288,796Future Income Taxes (Note 11)


236,550



181,640Shareholders EquityShareholders capital (Notes 1 and 12)


3,167,383



Trust unitholders capital (Note 12)






4,920,945Equity portion of convertible debentures (Note 8)






160Contributed surplus (Note 12)


19,593



18,617Deficit (Note 14)






(2,144,521
)3,186,976



2,795,201Commitments (Note 21)Contingencies (Note 22)Subsequent Event (Note 23)TOTAL LIABILITIES AND SHAREHOLDERS EQUITY

$
5,042,766


$
4,693,604 See accompanying
notes to the consolidated financial statements. Approved on behalf of the Board of Directors of Pengrowth Energy Corporation.  LOGO

LOGODirector

Director




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CONSOLIDATED STATEMENTS OF INCOME AND DEFICIT (Stated in thousands of dollars, except per share amounts)  Year Ended December 312010


2009REVENUESOil and gas sales

$
1,353,283


$
1,343,167Unrealized gain (loss) on commodity risk management (Note 20)


6,949



(173,726
)Processing and other income


20,598



18,758Royalties, net of incentives


(252,699
)


(207,563
)1,128,131



980,636EXPENSESOperating


371,716



384,412Transportation


15,739



13,467Amortization of injectants for miscible floods


15,056



19,989Interest and financing charges


70,464



80,274General and administrative


50,894



62,195Management fee (Note 17)






2,793Realized foreign exchange loss (gain) (Note 15)


2,061



(489
)Unrealized foreign exchange gain (Note 15)


(49,918
)


(149,233
)Depletion, depreciation and amortization


529,396



591,355Accretion (Note 10)


22,960



27,677Gain on equity investment (Note 4)


(73,756
)


Other (income) expenses


(11,909
)


6,288942,703



1,038,728Income (loss) before taxes


185,428



(58,092
)Future income tax reduction (Note 11)


(44,829
)


(142,945
)NET INCOME AND COMPREHENSIVE INCOME

$
230,257


$
84,853Deficit, beginning of year


(2,144,521
)


(1,941,521
)Distributions declared (Notes 1 and 14)


(232,584
)


(287,853
)Elimination of deficit (Notes 1 and 14)


2,146,848



DEFICIT, END OF YEAR (Note 14)

$



$
(2,144,521
)Net income per share (Notes 1 and 18)Basic and Diluted

$
0.76


$
0.32 See accompanying
notes to the consolidated financial statements.




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CONSOLIDATED STATEMENTS OF CASH FLOW (Stated in thousands of dollars)  Year Ended December 312010


2009CASH PROVIDED BY (USED FOR):OPERATINGNet income and comprehensive income

$
230,257


$
84,853Depletion, depreciation and accretion


552,356



619,032Future income tax reduction (Note 11)


(44,829
)


(142,945
)Contract liability amortization


(1,728
)


(2,483
)Amortization of injectants


15,056



19,989Purchase of injectants


(9,324
)


(13,298
)Expenditures on remediation (Note 10)


(20,926
)


(18,042
)Unrealized foreign exchange gain (Note 15)


(49,918
)


(149,233
)Unrealized (gain) loss on commodity risk management (Note 20)


(6,949
)


173,726Trust unit based compensation (Note 12)


4,565



8,125Non-cash gain on equity investment (Note 4)


(73,756
)


Other items


1,192



4,248Changes in non-cash operating working capital (Note 16)


9,999



(32,622
)605,995



551,350FINANCINGDistributions paid (Notes 1 and 14)


(250,640
)


(334,405
)Bank indebtedness


10,437



8,932Repayment of Monterey bank debt (Note 4)


(41,883
)


Repayment of long term debt (Note 9)


(172,600
)


(312,000
)Private placement of term notes, net of costs (Note 9)


189,902



Redemption of convertible debentures (Note 8)


(76,610
)


Other financing costs


(3,110
)


Proceeds from equity issues


26,980



321,605(317,524
)


(315,868
)INVESTINGExpenditures on property, plant and equipment


(333,842
)


(207,451
)Other property acquisitions


(20,171
)


(35,655
)Proceeds on property dispositions


60,721



41,885Other investments


(2,906
)


852Change in remediation trust funds (Note 5)


(6,952
)


(7,656
)Change in non-cash investing working capital (Note 16)


17,528



(27,457
)(285,622
)


(235,482
)CHANGE IN CASH AND TERM DEPOSITS


2,849



CASH AND TERM DEPOSITS AT BEGINNING OF YEAR






CASH AND TERM DEPOSITS AT END OF YEAR

$
2,849


$
 See accompanying
notes to the consolidated financial statements.




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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS YEARS ENDED DECEMBER 31, 2010 AND 2009 (Tabular amounts are stated
in thousands of dollars except per share amounts and as otherwise stated)  1.
CORPORATE STRUCTURE Pengrowth Energy Corporation (the
Corporation) is a Canadian resource company that is engaged in the production, development, exploration and acquisition of oil and natural gas assets. The Corporation was formed through a unitholder and Court approved reorganization
involving Pengrowth Energy Trust (the Trust), Pengrowth Corporation, its subsidiaries and the security holders of the Trust and Pengrowth Corporation pursuant to a Plan of Arrangement (the Arrangement) under the Business
Corporations Act (Alberta). On December 31, 2010 (the Date of Conversion), the Trust completed its conversion from an open-end
investment trust to a corporation through a business combination resulting in the unitholders of the Trust and the exchangeable shareholders of Pengrowth Corporation owning all the common shares of the Corporation. Unitholders of the Trust received
common shares in the Corporation on a one-for-one basis. Exchangeable shareholders of Pengrowth Corporation received 1.02308 common shares of the Corporation for each exchangeable share held. Pursuant to the Arrangement agreement, shareholders
capital was reduced by the amount of the consolidated deficit of the Trust on December 31, 2010. The management team and Board of Directors of the Corporation are comprised of the former management team and elected members of the Board of
Directors of the Trust. The Corporation effected an internal reorganization subsequent to the date of conversion whereby, among other things, the
Trust and its subsidiaries were dissolved and the Corporation received all the assets and assumed all the liabilities of the Trust. The Arrangement has
been accounted for on a continuity of interest basis and accordingly, the consolidated financial statements for periods prior to the date of conversion reflect the financial position, results of operations and cash flows as if the Corporation had
always carried on the business formerly carried on by the Trust. These financial statements may at times refer to common shares, shareholders, shareholders capital and dividends which, prior to the Arrangement, were referred to as trust units,
trust unitholders, trust unitholders capital and distributions, respectively. References made to trust units are those issued by the Trust. Comparative amounts in these financial statements will also reflect the history of the Trust and its
subsidiaries.  2.
SIGNIFICANT ACCOUNTING POLICIES BASIS OF
PRESENTATION These financial statements have been prepared in accordance with Generally Accepted Accounting Principles (GAAP) in Canada
on a consolidated basis and include the accounts of the Corporation, the Trust and its subsidiaries, collectively referred to as Pengrowth. All inter-entity transactions have been eliminated. Effective January 1, 2011, Pengrowth will be required to prepare financial statements in accordance with International Financial Reporting Standards
(IFRS). JOINT INTEREST OPERATIONS A significant proportion of Pengrowths petroleum and natural gas development and production activities are conducted with others and accordingly, the accounts reflect only Pengrowths interest in such
activities. PROPERTY, PLANT AND EQUIPMENT Pengrowth follows the full cost method of accounting for oil and gas properties and facilities whereby all costs of developing and acquiring oil and gas properties are capitalized. 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 associated
with exploration and development activities. Pengrowth excludes the cost of acquiring and evaluating certain unproved properties and costs associated
with major development projects from the cost base subject to depletion as quantified in Note 6. Capitalized costs, including future development costs and excluding the cost of unproven properties and major development projects, are depleted on a
unit of production method based on total proved reserves before royalties as estimated by independent engineers. The fair value of future estimated asset retirement obligations associated with properties and facilities are capitalized and included
in the depletion calculation. The associated asset retirement obligations on future development capital costs are also included in the cost base subject to depletion. Costs of




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unproven properties are subject to depletion as proven reserves are established or if an impairment of these costs has occurred. Capitalized costs associated with major development projects are
subject to depletion when the property begins producing or when development of the property ceases. If impairment occurs for a major development project, the associated costs with the project are also subject to depletion. The amount of major
development costs transferred to the depletable cost pool is on a proportionate basis of the land developed and producing at the end of the period. Natural gas production and reserves are converted to equivalent units of crude oil using their
relative energy content of 6:1, as per industry standards. Repairs and maintenance costs are expensed as incurred. Proceeds from disposals of oil and gas properties and equipment are credited against capitalized costs unless the disposal would alter the rate of depletion and
depreciation by more than 20 percent, in which case a gain or loss on disposal is recorded. There is a limit on the carrying value of property, plant
and equipment and other assets, which may be depleted against revenues of future periods (the ceiling test). Initially, the carrying value is assessed to be recoverable when the sum of the undiscounted cash flows expected from the
production of proved reserves, and the lower of cost and recoverable amount of unproved properties and major development projects exceeds the carrying value. If the carrying value is not assessed to be recoverable, an impairment loss is recognized
to the extent that the carrying value of assets exceeds the sum of the discounted cash flows expected from the production of proved and probable reserves including the lower of cost and recoverable amount of unproved properties and the cost of major
development projects. The cash flows are estimated using expected future product prices and costs and are discounted using a risk-free interest rate. The carrying value of property, plant and equipment and other assets subject to the ceiling test
includes asset retirement costs. Pengrowth performs a separate recoverability test for capitalized costs associated with unproven properties and major
development projects. Indicators are used to assess whether capitalized costs may be impaired which include, but are not limited to, the following: the Corporations plans to actively pursue exploration, evaluation or development of the
property, the timing of leases expiring on the undeveloped land and the economic outlook for commodity prices and costs. If impairment has been assessed, Pengrowth will determine the amount of capitalized costs to transfer to the depletable cost
base on a property specific basis or based on specific factors related to the group of capitalized costs determined to be impaired. The amount transferred may be based on the excess of the capitalized costs over the expected cash flows for the
property or if the entire property or project is impaired, the total accumulated capitalized costs for the property or project would be depleted. GOODWILL Goodwill, which represents the excess of the total purchase price over the estimated fair
value of the net identifiable assets and liabilities acquired, is not amortized but instead is assessed for impairment annually or as events occur that could suggest impairment exists. Impairment is assessed by determining the fair value of the
reporting entity and comparing this fair value to the book value of the reporting entity. If the fair value of the reporting entity is less than the book value, impairment is measured by allocating the fair value of the reporting entity to the
identifiable assets and liabilities of the reporting entity as if the reporting entity had been acquired in a business combination for a purchase price equal to its fair value. Any excess of the fair value of the reporting entity over the assigned
values of the identifiable assets and liabilities is the fair value of the goodwill. Any excess of the book value of goodwill over this implied fair value is the impairment amount. Impairment is charged to earnings in the period in which it occurs.
Goodwill is stated at cost less impairment. INJECTANT COSTS Injectants (mostly natural gas and ethane) are used in miscible flood programs to stimulate incremental oil recovery. The cost of hydrocarbon injectants purchased from third parties for miscible flood projects is
deferred and amortized over the period of expected future economic benefit which is currently estimated as 24 months. ASSET RETIREMENT
OBLIGATIONS Pengrowth initially recognizes the fair value of an Asset Retirement Obligation (ARO) in the period in which it is incurred when
a reasonable estimate of the fair value can be made. The fair value of the estimated ARO is recorded as a liability, with a corresponding increase in the carrying amount of the related asset. The capitalized amount is depleted on the unit of
production method based on proved reserves. The liability amount is increased each reporting period due to the passage of time and the amount of 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 entry made to the
carrying amount of the related asset.




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Pengrowth has placed cash in segregated remediation trust accounts to fund certain ARO for the Judy Creek
properties and the Sable Offshore Energy Project (SOEP). INCOME TAXES Pengrowth follows 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 financial statements and their respective tax bases, using substantively enacted income tax rates. The effect of a change in income tax rates on future income
tax liabilities and assets is recognized in income in the period the change occurs. Pengrowths policy for income tax uncertainties is to recognize tax benefits only when it is more likely than not the position will be sustained on examination. SHARE BASED COMPENSATION PLANS Pengrowth has share based compensation plans, which are described in Note 13. Compensation expense is based on the estimated fair value of the share based
compensation award at the date of grant. Compensation expense associated with the share based compensation plans are recognized in 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 share unit rights and options together with the amount of non-cash compensation expense recognized in contributed surplus is
recorded as an increase in shareholders capital. 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 intrinsic 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: held for trading, held to maturity investments, loans and receivables, available for sale financial assets or other liabilities. Pengrowth has
designated cash and term deposits as held for trading which are measured at fair value. Accounts receivable are classified as loans and receivables which are measured at amortized cost. Investments held in the remediation trust funds have been
designated as held to maturity and held for trading based on the type of investments in the fund. Other investments included in other assets have been designated as held for trading and available for sale based on the type of investment. Changes in
fair value of held for trading investments are recorded as unrealized gains (losses) and are included in other expenses (income) in the consolidated statements of income and deficit. The available for sale securities included in other assets is
recorded at cost as the investment is in a private entity whose shares are not quoted in an active market. Held to maturity investments are measured at amortized cost. Bank indebtedness, accounts payable, dividends payable and long term debt have
been classified as other liabilities which are measured at amortized cost using the effective interest rate method. All derivatives are classified as
held for trading which are measured at fair value with changes in fair value over a reporting period recognized in net income. Changes in the fair value of derivatives used in certain hedging transactions for which cash flow hedge accounting is
permitted would be recorded in other comprehensive income. Pengrowth does not have any risk management contracts outstanding for which hedge accounting is being applied. Comprehensive income includes net income and transactions and other events from non-owner sources such as unrealized gains and losses on effective cash flow hedges. There are no amounts that Pengrowth would include
in other comprehensive income except for net income. 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 U.S. dollar and U.K. Pound Sterling denominated debt are translated into Canadian dollars at the exchange rate in effect on the balance sheet date. Foreign exchange gains and losses on the U.S. dollar and
U.K. Pound Sterling denominated debt are included in income.




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EQUITY INVESTMENT Pengrowth utilizes the equity method of accounting for investments subject to significant influence. 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. MEASUREMENT UNCERTAINTY The preparation of financial statements in conformity with Canadian GAAP
requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and revenues and expenses for the period then ended. The amounts recorded for depletion, depreciation, amortization of injectants, goodwill, future income taxes, fair value of risk management contracts and ARO are
based on estimates. Management reviews the cost estimates and timing assumptions related to the ARO liability on an annual basis which may result in a revision to the ARO liability. The ceiling test calculation is based on estimates
of proved and probable reserves, production rates, oil and natural gas prices, future costs and other relevant assumptions. The impairment assessment of goodwill is based on the estimated fair value of Pengrowth which is referenced to
Pengrowths common share price and an estimate of the premium that an arms length party would pay to acquire all of the outstanding common shares. By their nature, these estimates are subject to measurement uncertainty and may impact the
consolidated financial statements of future periods. 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 share unit rights and options and
deferred entitlement share units 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. Diluted net income per share amounts also include the dilutive effect of convertible debentures using the if-converted method which assumes that the convertible debentures were converted at the beginning
of the period. 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. CASH AND TERM DEPOSITS Cash and term deposits include demand deposits and term deposits with original maturities of less than 90 days. COMPARATIVE FIGURES Certain comparative figures
have been reclassified to conform to the presentation adopted in the current year.  3.
CHANGE IN ACCOUNTING POLICIES As of January 1, 2010,
Pengrowth early adopted the following new Canadian standards: CICA 1582 Business Combinations, which replaces the previous business
combinations standard. The standard requires assets and liabilities acquired in a business combination, consideration paid, contingent consideration and certain acquired contingencies to be measured at fair value on the date of acquisition. In
addition, acquisition related and restructuring costs are recognized separately from the business combination and are included in the statement of income. The adoption of this standard impacts the accounting treatment of business combinations
entered on or after January 1, 2010. With respect to the Monterey acquisition in 2010 (Note 4), the most significant impact of the new standards was the recognition of a $73.8 million gain on Pengrowths existing equity investment in
Monterey. In addition, the share consideration paid for Monterey was valued using the closing date trust unit price versus the announcement date trust unit price which increased the consideration paid by $40.0 million. CICA 1601 Consolidated Financial Statements, which together with Section 1602 below replace the former consolidated financial statements standard.
Section 1601 establishes the requirements for the preparation of consolidated financial statements. The adoption of this standard had no material impact on Pengrowths financial statements.




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CICA 1602 Non-controlling Interests establishes the accounting for a non-controlling interest in a
subsidiary in consolidated financial statements subsequent to a business combination. The standard requires a non-controlling interest in a subsidiary to be classified as a separate component of equity. In addition, net earnings and components of
other comprehensive income are attributed to both the parent and non-controlling interest. The adoption of this standard had no impact on the consolidated financial statements.  4.
MONTEREY ACQUISITION Pengrowth and Monterey Exploration Ltd.
(Monterey) completed a business combination (the Combination) whereby each Monterey securityholder elected to receive either: (i) 0.8298 of a trust unit or (ii) 0.8298 of an exchangeable share of Pengrowth
Corporation with each exchangeable share being exchangeable to a trust unit. The Combination closed on September 15, 2010 with Pengrowth acquiring 100% of the voting interest in Monterey and resulted in the issuance of 28 million trust
units and 5 million exchangeable shares of Pengrowth Corporation to the former Monterey securityholders. The trust units and exchangeable shares
issued in the Combination were valued at $11.00 per trust unit/exchangeable share based on the closing trading price of the trust units on the date of the Combination. Prior to the Combination, Pengrowth held approximately nine million common shares
or approximately 20 percent of the outstanding common shares of Monterey. Under the new Canadian accounting standards for business combinations early adopted on January 1, 2010, Pengrowth was required to fair value its previously held equity
investment in Monterey and, as a result, recorded a gain of $73.8 million arising from the difference between the fair value on closing date and the book value of the investment prior to the Combination. The fair value of Pengrowths previously
held equity investment in Monterey was included in the purchase consideration. The Combination was accounted for as an acquisition of Monterey by
Pengrowth as follows:  Acquired net assets:Property, plant and equipment

$
570,367Goodwill


51,765Bank debt


(41,883
)Asset retirement obligations


(7,888
)Working capital deficit


(25,667
)Future income taxes


(102,043
)$
444,651Consideration:Trust units

$
307,648Exchangeable shares


54,939Fair value of previous equity investment


82,064$
444,651 The estimated
fair value of property, plant and equipment was determined using both internal estimates and an independent reserve evaluation. Property, plant and equipment acquired in the Combination included approximately $49 million of producing assets and $521
million of unproven and development properties. The amount of the unproven and development properties was initially excluded from the depletion calculation in accordance with Pengrowths accounting policy. The future income tax
liability was determined based on applying Pengrowths effective future income tax rate of approximately 26 percent to the difference between the book and tax basis of the assets acquired. The asset retirement obligations were determined using
Pengrowths estimated costs to remediate, reclaim and abandon the wells and facilities, the estimated timing of the costs to be incurred in future periods, an inflation rate of two percent, and a discount rate of eight percent. Transaction
costs relating to legal and advisory fees incurred in the Combination of approximately $1.4 million were expensed in the period and included in other expenses (income). The acquisition of Monterey is consistent with Pengrowths strategic focus of acquiring and developing operated unconventional resource plays in the Western Canadian Sedimentary Basin. Pengrowth recognized
goodwill of approximately $52 million in the Combination representing, in part, the value of establishing a new core area with resource assets in the Montney play. Pengrowths ability to increase this value beyond what Monterey could realize is
partially a result of Pengrowths ability to fund the development of the necessary capital infrastructure with a lower cost of capital. Goodwill is also impacted by recognizing a future tax liability on the acquisition at an undiscounted amount
as required under Canadian accounting standards. Goodwill is not deductible for tax purposes.




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The consolidated financial statements include the results of operations and cash flows from Monterey subsequent
to the closing date of September 15, 2010. The impact of the Combination on revenue and net income is not material for pro-forma disclosures.  5.
OTHER ASSETS  2010


2009Remediation trust funds

$
42,114


$
34,837Equity investment in Monterey Exploration Ltd.






5,039Other investments


5,000



6,151$
47,114


$
46,027 REMEDIATION TRUST FUNDS Pengrowth has a
contractual obligation to make contributions to a remediation trust fund that is used to cover certain ARO of the Judy Creek properties. Pengrowth makes monthly contributions to the fund of $0.10 per boe of production from the Judy Creek properties
and an annual lump sum contribution of $250,000. Every five years, Pengrowth must evaluate the assets in the trust fund and the outstanding ARO, and make recommendations to the former owner of the Judy Creek properties as to whether contribution
levels should be changed. The next evaluation is anticipated to occur in 2012. Contributions to the Judy Creek remediation trust fund may change based on future evaluations of the fund. The investment in the Judy Creek remediation trust fund is
classified as held to maturity and is measured at amortized cost. Interest income is recognized when earned and included in other expenses (income). As at December 31, 2010, the carrying value of the Judy Creek remediation trust fund was $8.7
million (December 31, 2009  $8.8 million). Pengrowth has a contractual obligation to make contributions to a remediation trust fund that will be
used to fund the ARO of the SOEP properties and facilities. Pengrowth currently makes a monthly contribution to the fund of $0.52 per mmbtu of natural gas production and $1.04 per bbl of natural gas liquids production from SOEP. The SOEP remediation
trust fund as at December 31, 2010 was $33.4 million (December 31, 2009  $26.0 million). Investment income is recognized when earned and is recorded as other expense (income). The investments in the fund have been designated as held for
trading and are recorded at fair value. The following reconciles Pengrowths remediation trust funds for 2010 and 2009:  Remediation Trust Funds

2010


2009Opening balance

$
34,837


$
27,122Contributions to Judy Creek Remediation Trust Fund


537



635Contributions to SOEP Environmental Restoration Fund


7,111



7,579Remediation funded by Judy Creek Remediation Trust Fund


(696
)


(558
)Change in remediation trust funds


6,952



7,656Unrealized gain on held for trading investment


325



59Closing balance

$
42,114


$
34,837 EQUITY INVESTMENT IN MONTEREY On
September 15, 2010, Pengrowth completed a business combination with Monterey described in Note 4. Prior to the business combination, Pengrowth held an equity interest in Monterey. As of December 31, 2009, Pengrowth held approximately 20
percent of the outstanding common shares of Monterey. Pengrowth recorded a pre-tax loss of $3.7 million in 2009 to reflect Pengrowths proportionate share of Montereys net loss in the period. In addition, Pengrowth recorded a pre-tax loss
of $1.1 million in 2009 as a result of decreases in its ownership in Monterey. The decrease in ownership was due to Pengrowth not participating in the share issuances completed by Monterey. The equity income (loss) and ownership adjustments are
included in other expenses (income) in the consolidated statements of income and deficit. OTHER INVESTMENTS Pengrowth sold the remaining shares it held of a public corporation in January 2010 for proceeds of $1.1 million. Pengrowth holds an investment in a private company with a carrying value of $5 million (December 31, 2009  $5 million). The investment has been designated as
available for sale and is recorded at cost as the shares are not quoted in an active market.




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6.
PROPERTY, PLANT AND EQUIPMENT  2010


2009Property, plant and equipment, at cost

$
8,095,143


$
7,272,408Accumulated depletion, depreciation and amortization


(4,028,160
)


(3,498,764
)Net book value of property, plant and equipment


4,066,983



3,773,644Net book value of deferred injectant costs


9,993



15,725Net book value of property, plant and equipment and deferred injectants

$
4,076,976


$
3,789,369 In 2010,
approximately $12.9 million (2009  $9.2 million) of general and administrative costs were capitalized. As at December 31, 2010,
approximately $512 million (December 31, 2009  $68 million) of capitalized costs to acquire and evaluate unproven and development properties has been excluded from depletion. Pengrowth performed a ceiling test calculation at December 31, 2010 to assess the recoverable value of property, plant and equipment. The oil and gas future prices and costs are based on the January 1,
2011 commodity price forecast of our independent reserve evaluators. These prices have been adjusted for commodity price differentials specific to Pengrowth. The following table summarizes the benchmark prices which are provided by an independent
recognized valuation firm used in the ceiling test calculation. Based on these assumptions, the undiscounted value of future net revenues from Pengrowths proved reserves exceeded the carrying value of property, plant and equipment at
December 31, 2010.  Year

WTI Oil(U.S.$/bbl)


ForeignExchange Rate(U.S.$/Cdn$)


Edmonton LightCrude Oil(Cdn$/bbl)


AECO Gas(Cdn$/mmbtu)2011

$
88.00



0.980


$
86.22


$
4.162012

$
89.00



0.980


$
89.29


$
4.742013

$
90.00



0.980


$
90.92


$
5.312014

$
92.00



0.980


$
92.96


$
5.772015

$
95.17



0.980


$
96.19


$
6.222016

$
97.55



0.980


$
98.62


$
6.532017

$
100.26



0.980


$
101.39


$
6.762018

$
102.74



0.980


$
103.92


$
6.902019

$
105.45



0.980


$
106.68


$
7.062020

$
107.56



0.980


$
108.84


$
7.21Thereafter


+ 2.0 percent/yr



0.980



+ 2.0 percent/yr



+ 2.0 percent/yr At
December 31, 2010, Pengrowth has assessed that no impairment exists for capitalized costs associated with unproven and development properties.  7.
CONTRACT LIABILITIES Contract liabilities are composed of
the following amounts:  2010


2009Current portion of firm transportation contracts

$
1,677


$
1,728Non-current portion of firm transportation contracts


6,275



7,952$
7,952


$
9,680 Pengrowth assumed
firm transportation commitments in conjunction with certain acquisitions. The fair values of these contracts were estimated on the date of acquisition and the amount recorded is reduced as the contracts settle.




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8.
CONVERTIBLE DEBENTURES On January 14, 2010, Pengrowth
redeemed all of the outstanding Convertible Unsecured Subordinated Debentures. The cash redemption amount was approximately $76.8 million, including accrued interest to the redemption date. The debentures bore interest at 6.5% per annum and
were convertible at $25.54 per share.  9.
LONG TERM DEBT  2010


2009U.S. dollar denominated senior unsecured notes:150 million at 4.93 percent due April 2010

$



$
157,54650 million at 5.47 percent due April 2013


49,638



52,41771.5 million at 4.67 percent due May 2015


70,731



400 million at 6.35 percent due July 2017


396,219



418,530265 million at 6.98 percent due August 2018


262,354



277,138115.5 million at 5.98 percent due May 2020


114,206



$
893,148


$
905,631U.K. Pound Sterling denominated 50 million unsecured notes at 5.46 percent due December
2015


77,219



84,514Canadian dollar 15 million senior unsecured notes at 6.61 percent due August
2018


15,000



15,000Canadian dollar revolving credit facility borrowings


39,000



60,000Total long term debt

$
1,024,367


$
1,065,145Current portion of long term debt due April 2010






(157,546
)Non-current portion of long term debt

$
1,024,367


$
907,599 SENIOR UNSECURED NOTES On April 23, 2010,
U.S. $150 million in senior unsecured notes matured resulting in the realization of a cumulative $66 million foreign exchange gain. On May 11,
2010, Pengrowth closed a U.S. $187 million private placement of senior unsecured notes. The notes were offered in two tranches of U.S. $71.5 million at 4.67 percent due May 2015 and U.S. $115.5 million at 5.98 percent due May 2020. Similar to other
outstanding series, these notes contain certain financial maintenance covenants and interest is paid semi-annually. Costs incurred in connection with issuing the notes, in the amount of $1.2 million, were deducted from the carrying amount of the
debt and are amortized to income over the expected term of the notes. As of December 31, 2010, an unrealized cumulative foreign exchange gain of
$63.0 million (December 31, 2009  gain of $77.6 million) has been recognized on the U.S. dollar term notes since the date of issuance. As of December 31, 2010, an unrealized cumulative foreign exchange gain of $36.5 million (December
31, 2009  gain of $29.2 million) has been recognized on the U.K. Pound Sterling denominated term notes since Pengrowth ceased to designate existing foreign exchange swaps as a hedge on January 1, 2007. 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: 2011
 nil, 2012  nil, 2013  $89 million, 2014  nil, 2015  $149 million. CREDIT FACILITIES Pengrowth has a committed unsecured $1.0 billion syndicated extendible revolving credit facility. The facility may be renewed at any time prior to its maturity
subject to lender approval. In the event Lenders do not agree to a renewal, the outstanding balance is due upon maturity. During the fourth quarter, Pengrowth elected to extend the maturity date of the facility by three years to October 29,
2013. In conjunction with the renewal of the credit facility, Pengrowth incurred fees of $3.1 million which will be amortized to income over the term of the facility. The credit facility provides up to $1.25 billion of credit capacity from a syndicate of seven Canadian and three foreign banks. Of this capacity, $1.0 billion is committed while the remaining $250 million is
available under an expansion feature subject to lender participation. This facility carries floating interest rates that are expected to range between 2.00 percent and 3.25 percent over




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bankers acceptance rates, depending on Pengrowths consolidated ratio of senior debt to earnings before interest, taxes and non-cash items. The facility was reduced by drawings of $39
million and outstanding letters of credit in the amount of approximately $18 million at December 31, 2010. Pengrowth also maintains a $50 million
demand operating facility. This facility was reduced by borrowings of $22 million and outstanding letters of credit of approximately $5 million at December 31, 2010. All borrowings under this facility are included in bank indebtedness on the
balance sheet.  10.
ASSET RETIREMENT OBLIGATIONS The ARO was estimated by
management based on Pengrowths working interest in wells and facilities, estimated costs to remediate, reclaim and abandon the wells and facilities and the estimated timing of the costs to be incurred, considering various factors including the
annual reserves evaluation of Pengrowths properties from the independent reserve evaluators. Pengrowth has estimated the net present value of its ARO to be $260 million as at December 31, 2010 (December 31, 2009  $289 million),
based on a total escalated future liability of $1,790 million (December 31, 2009  $2,016 million). These costs are expected to be made over 50 years with the majority of the costs incurred between 2041 and 2061. Pengrowths credit
adjusted risk free rate of eight percent (2009  eight percent) and an inflation rate of one and one half percent per annum (2009  two percent per annum) were used to calculate the net present value of the ARO. The following reconciles Pengrowths ARO:  2010


2009ARO, beginning of year

$
288,796


$
344,345Increase (decrease) in liabilities during the year related to:Acquisitions


10,309



365Dispositions


(1,145
)


(2,195
)Additions


1,510



3,146Revisions(1)


(41,966
)


(66,500
)Accretion expense


22,960



27,677Liabilities settled in the year


(20,926
)


(18,042
)ARO, end of year

$
259,538


$
288,796  (1)
A corresponding adjustment was made to the related asset. In 2010,
Pengrowth recorded a reduction to the ARO liability of $42.0 million (2009  $66.5 million reduction) as a result of changes to the inflation rate from two percent per annum to one and one half percent per annum and changes to the estimated
timing of abandonment and reclamation. The change in estimate was made on a prospective basis and a corresponding adjustment was made to the related asset. The following summarizes Pengrowths expenditures on ARO for 2010 and 2009:  Expenditures on ARO

2010


2009Expenditures on ARO not covered by the trust funds

$
20,230


$
17,484Expenditures on ARO covered by the trust funds (Note 5)


696



558$
20,926


$
18,042




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11.
INCOME TAXES A reconciliation of tax expense calculated
based on the income (loss) before taxes at the statutory tax rate to the actual provision for income taxes is as follows:  2010


2009Income (loss) before taxes

$
185,428


$
(58,092
)Combined federal and provincial tax rate


28.40%



29.50%Expected income tax expense (reduction)


52,668



(17,137
)Net income of the Trust(1)


(77,590
)


(98,851
)Foreign exchange gain(2)


(8,320
)


(21,956
)Effect of change in corporate tax rate


7,666



5,968Gain on equity investment


(20,949
)


Change in valuation allowance


(273
)


(6,170
)Other including stock based compensation(3)


1,969



(4,799
)Future income tax reduction

$
(44,829
)

$
(142,945
)  (1)
Relates to distributions of taxable income in the Trust for the year ended December 31, 2010 of $273.2 million x 28.40% (December 31, 2009 $334.4 million x
29.56%) where the income tax liability was the responsibility of the trust unitholder.  (2)
Reflects the 50% non-taxable portion of foreign exchange gains and losses.  (3)
Primarily income that is not taxable and other adjustments. The
future income tax rates in 2010 and 2009 were approximately 25 percent and were applied to the temporary differences compared to the federal and provincial statutory rate of approximately 28 percent for the 2010 taxation year and 29 percent for the
2009 taxation year. The net future income tax liability is composed of:  2010


2009Future income tax assets:Asset retirement obligation

$
66,750


$
68,890Non-capital losses


131,222



135,263Unrealized commodity loss


7,645



7,312Other


2,271



2,824207,888



214,289Less: Valuation allowance






(273
)207,888



214,016Future income tax liabilities:Property, plant and equipment and other assets


(425,821
)


(382,285
)Foreign exchange gain


(19,820
)


(12,402
)Net future tax liability

$
(237,753
)

$
(180,671
) In calculating the
future income tax liability in 2010, Pengrowth included $514.4 million (2009  $539.4 million) related to non-capital losses available for carryforward to reduce taxable income in future years. These losses expire between 2012 and 2030.  12.
SHAREHOLDERS EQUITY 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.




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The following provides the number of common shares issued under the Arrangement (Note 1) and the total number of
common shares outstanding as at December 31, 2010:  Number ofCommon Shares


AmountIssued to trust unitholders


321,910,802


$
5,270,006Issued to exchangeable shareholders(1)


4,113,238



44,225Elimination of the deficit (Notes 1 and 14)






(2,146,848
)Balance at December 31, 2010


326,024,040


$
3,167,383  (1)
Common shares issued after applying the exchange ratio of 1.02308 per exchangeable share held. TRUST UNITHOLDERS CAPITAL As a result of the conversion from an income trust to a corporation
described in Note 1, all outstanding trust units of the Trust were exchanged on a one-for-one basis for common shares of the Corporation on December 31, 2010. The following provides a continuity of trust unitholders capital for the years ended 2010 and 2009:  2010


2009Trust Units Issued

Number ofTrust Units


Amount


Number ofTrust Units


AmountBalance, beginning of year


289,834,790


$
4,920,945



256,075,997


$
4,588,587Issued on redemption of Deferred Entitlement Trust Units (DEUs) (non-cash)


257,607



2,966



416,043



5,741Issued for cash on exercise of trust unit rights


587,314



3,661



299,684



1,918Issued for cash under Distribution Reinvestment Plan (DRIP)


2,282,912



24,072



3,026,166



26,319Issued for the Monterey business combination (Note 4)


27,967,959



307,648







Issued on redemption of Exchangeable shares(1)


980,220



10,714







Issued for cash under At The Market (ATM) Plan










1,169,900



10,723Issued for cash on equity issue










28,847,000



300,009Trust unit rights incentive plan (non-cash exercised)






623







346Issue costs net of tax






(623
)






(12,698
)Trust units exchanged for common shares under the Arrangement (Note 1)


(321,910,802
)


(5,270,006
)






Balance, end of year





$




289,834,790


$
4,920,945  (1)
Trust units issued based on the exchange ratio in effect at the time of redemption. EXCHANGEABLE SHARES Pengrowth issued exchangeable shares in the Monterey acquisition described in
Note 4. These exchangeable shares were included in equity based on Canadian accounting standards that permit the inclusion of certain exchangeable shares in equity as the exchangeable shares were exchangeable into trust units based on the exchange
ratio in effect at the time of redemption. The exchange ratio increased with each cash distribution and was calculated by multiplying the distribution per trust unit by the opening exchange ratio and dividing by the ten day weighted average trading
price of the trust units on the Toronto Stock Exchange prior to the distribution record date. On December 31, 2010, all outstanding exchangeable
shares were exchanged into 1.02308 common shares of the Corporation for each exchangeable share held.




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The following provides a continuity of the exchangeable shares from the date of issue to December 31, 2010:  Number ofShares


AmountIssued for the Monterey business combination (Note 4)


4,994,426


$
54,939Redeemed for trust units


(973,980
)


(10,714
)Exchanged for common shares under the Arrangement (Note 1)


(4,020,446
)


(44,225
)Balance at December 31, 2010





$
 DIVIDEND REINVESTMENT PLAN In conjunction with the
conversion, Pengrowth revised its Dividend Reinvestment Plan (DRIP). DRIP entitles the shareholder to reinvest cash dividends in additional shares of Pengrowth. Under the revised DRIP, the shares are issued from treasury at a five percent discount
to the weighted average closing price of all shares traded on the TSX for the five trading days preceding a dividend payment date. Previously, the
Trust had a similar program where unitholders were entitled to reinvest cash distributions in additional trust units of the Trust. The trust units under this plan were issued from treasury at a five percent discount to the weighted average closing
price of all trust units traded on the TSX for the twenty trading days preceding a distribution payment date. AT THE MARKET
DISTRIBUTION The Equity Distribution Program permitted the Trust to distribute up to 25 million trust units from time to time at prevailing market
rates through either the New York or Toronto Stock Exchanges. The program expired in January 2010 and was not reinstated subsequent to the Arrangement. No trust units were issued under the program in 2010 (2009  1.2 million units). CONTRIBUTED SURPLUS  2010


2009Balance, beginning of year

$
18,617


$
16,579Trust unit rights incentive plan (non-cash expensed)


1,172



2,953Deferred entitlement units plan (non-cash expensed)


3,393



5,172Trust unit rights incentive plan (non-cash exercised)


(623
)


(346
)Deferred entitlement units plans (non-cash exercised)


(2,966
)


(5,741
)Balance, end of year

$
19,593


$
18,617  13.
SHARE BASED COMPENSATION PLANS Pengrowth has several share
based compensation plans. The new Long Term Incentive Plan (LTIP) as described below will be used to grant awards of share based compensation on or after January 1, 2011. The long term incentive plan that was used by the Trust is currently
being phased out with no new awards to be issued under the previous incentive plans. Up to four and one half percent of the issued and outstanding common shares, in aggregate, may be reserved for issuance under the share based compensation plans. NEW LONG TERM INCENTIVE PLAN (LTIP) Effective January 1, 2011, the following plans under the new LTIP were implemented:  (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 are awarded to employees, officers and special consultants. The number of shares issued will be subject to a performance factor ranging from zero to two times
the number of shares granted plus the amount of reinvested notional dividends.  (b)
Restricted Share Units (RSUs) RSUs are
awarded to employees, officers and special 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 will vest on the first, second and third anniversary
date from the date of grant.




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(c)
Deferred Share Units (DSUs) The DSU plan is
currently intended for members of the Board of Directors. Each DSU entitles the holder to a number of 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
retains certain discretion with respect to performance criteria and other aspects of the LTIP. PREVIOUS LONG TERM INCENTIVE PLAN  (a)
Deferred Entitlement Share Units Plan (formerly the DEU Plan) The DEU Plan that was effective under the Trust was renamed on conversion to the Deferred Entitlement Share Units Plan (DESU). 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 zero to two 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 entitles 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 DESUs for the years ended 2010 and 2009:  2010


2009DESUs

Numberof DESUs


Weightedaverage price


Numberof DESUs


Weightedaverage priceOutstanding, beginning of year


2,291,469


$
12.38



1,270,750


$
19.38Granted


1,469,536



11.21



1,174,601



6.55Forfeited


(548,323
)


11.12



(120,637
)


12.63Exercised


(459,074
)


18.82



(297,184
)


20.57Deemed DRIP(1)


194,980



11.20



263,939



14.05Outstanding, end of year


2,948,588


$
10.95



2,291,469


$
12.38Comprised of:Performance related DESUs


1,957,660


$
10.47



2,104,400


$
12.18Non-Performance related DESUs


990,928



11.91



187,069



14.61Outstanding, end of year


2,948,588


$
10.95



2,291,469


$
12.38  (1)
Weighted average deemed DRIP price is based on the average of the original grant prices. Compensation expense related to the DESU plan is 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 25 percent for officers and employees. 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. Pengrowth recorded compensation expense of approximately $3.4 million in 2010 (2009  $5.2 million) related to the DESU plan. Compensation expense associated
with the DESUs granted in 2010 was based on the weighted average grant date fair value of $11.21 per DESU (2009  $6.55 per DESU). As at December 31, 2010, the amount of compensation expense to be recognized over the remaining vesting
period was $10.0 million (December 31, 2009  $6.6 million) or $4.26 per DESU (2009  $4.34 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 1.6 years (2009  1.6 years).  (b)
Common Share Rights Incentive Plan (formerly the Trust Unit Rights Incentive Plan) The Trust Unit Rights Incentive Plan that was effective under the Trust was renamed as 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. In 2010 there were no exercise price reductions under this plan (2009  $0.03 per share unit right).




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The following provides a continuity of share unit rights and options for the years ended 2010 and 2009:  2010


2009Numberoutstanding


Weightedaverage price


Numberoutstanding


Weightedaverage priceOutstanding, beginning of year


5,455,598


$
12.23



3,292,622


$
16.78Granted(1)


30,144



11.22



2,958,378



6.63Forfeited


(1,314,662
)


13.59



(495,718
)


12.25Exercised


(587,314
)


6.23



(299,684
)


6.40Outstanding, end of year


3,583,766


$
12.70



5,455,598


$
12.23Comprised of:Share Unit Options


1,646,445


$
7.02






$
Share Unit Rights


1,937,321



17.53



5,455,598



12.23Outstanding, end of year


3,583,766


$
12.70



5,455,598


$
12.23  (1)
Weighted average exercise price of rights granted is based on the exercise price at the date of grant. The following table summarizes information about share unit rights and options outstanding and exercisable at December 31, 2010:  Range of exercise prices

Numberoutstanding


Weighted averageremainingcontractual life(years)


Weightedaverageexercise price


Numberexercisable


Weightedaverageexercise priceOptions outstanding$6.00 to $8.99


1,198,152



3.2


$
6.10



798,768


$
6.10$9.00 to $12.99


448,293



3.5



9.49



292,771



9.46Total options outstanding


1,646,445



3.3


$
7.02



1,091,539


$
7.00Rights outstanding$13.00 to $18.99


1,647,601



1.8


$
17.20



1,647,601


$
17.20$19.00 to $22.99


289,720



0.3



19.43



289,720



19.43Total rights outstanding


1,937,321



1.6


$
17.53



1,937,321


$
17.53 Compensation
expense associated with the share unit rights granted during 2010 was based on the estimated fair value of $1.67 per share unit right (2009  $1.13). The fair value of share unit rights granted in the period was estimated at 15 percent of the
exercise price (2009  17 percent) at the date of grant using a binomial lattice option pricing model with the following assumptions: risk-free rate of 2.8 percent (2009  1.7 percent), volatility of 47 percent (2009  43 percent),
expected dividend yield of 19 percent per share (2009  20 percent) and reductions in the exercise price over the life of the share unit right. The amount of compensation expense is reduced by the estimated forfeitures at the date of grant
which has been estimated at five percent for directors and officers (2009  five percent) and ten percent for employees (2009  ten percent). Compensation expense related to the share unit rights and option plan in 2010 was $1.2 million (2009  $3.0 million). As at December 31, 2010, the amount
of compensation expense to be recognized over the remaining vesting period was $0.2 million (December 31, 2009  $1.4 million) or $0.04 per share unit option (December 31, 2009  $0.23 per share unit). The unrecognized compensation
cost will be recognized over the weighted average remaining vesting period of 0.4 years (2009  1.1 years). EMPLOYEE SAVINGS PLANS Pengrowth has savings plans whereby it will match contributions by qualifying employees of one to 12 percent of their annual base salary, less any of
Pengrowths contributions to the Group Registered Retirement Savings Plan (Group RRSP), to purchase shares in the open market. Participants in the Group RRSP can make contributions from one to 12 percent and Pengrowth will match
contributions to a maximum of six percent of their annual basic salary. Pengrowths share of contributions to the Share Purchase Plan and Group RRSP in 2010 were $4.2 million and $1.2 million, respectively (2009  $4.6 million and $1.1
million, respectively).




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14.
DEFICIT  2010


2009Accumulated earnings

$
2,386,298


$
2,156,041Accumulated distributions declared


(4,533,146
)


(4,300,562
)Elimination of deficit (Note 1)


2,146,848



$



$
(2,144,521
) Pursuant to the
Arrangement described in Note 1, shareholders capital was reduced by the amount of the consolidated deficit of the Trust on December 31, 2010. The Trust historically under its Royalty and Trust Indentures and NPI agreement distributed to
unitholders a significant portion of its cash flow from operations. Cash flow from operations typically exceeds net income or loss as a result of non-cash expenses such as unrealized gains (losses) on commodity contracts, unrealized foreign exchange
gains (losses), depletion, depreciation and accretion. Actual cash distributions paid in 2010 were cash distributions of the Trust of $251 million
(2009  $334 million). The final distribution payment to the Trust unitholders of record on December 31, 2010 was paid on January 17, 2011. Distributions payable to the unitholders of the Trust at year end represents this final
distribution payment.  15.
FOREIGN EXCHANGE (GAIN) LOSS  2010


2009Unrealized foreign exchange gain on translation of U.S. dollar denominated debt

$
(50,692
)

$
(144,455
)Unrealized foreign exchange gain on translation of U.K. Pound Sterling denominated
debt


(7,366
)


(3,840
)(58,058
)


(148,295
)Unrealized loss (gain) on foreign exchange risk management contracts on U.K. Pound Sterling
denominated debt


8,140



(938
)Unrealized foreign exchange gain

$
(49,918
)

$
(149,233
)Realized foreign exchange loss (gain)


2,061



(489
)$
(47,857
)

$
(149,722
)  16.
OTHER CASH FLOW DISCLOSURES CHANGE IN
NON-CASH OPERATING WORKING CAPITAL  Cash provided by (used for):

2010


2009Accounts receivable

$
3,590


$
15,284Accounts payable


6,409



(48,529
)Due from Pengrowth Management Limited






623$
9,999



$      (32,622
) CHANGE
IN NON-CASH INVESTING WORKING CAPITAL  Cash provided by (used for):

2010


2009Accounts receivable

$
495


$
(495
)Accounts payable and capital accruals


17,033



(26,962
)$
17,528



$      (27,457
) CASH
INTEREST PAYMENTS  2010


2009Interest and financing charges

$
71,529


$
85,566




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17.
RELATED PARTY TRANSACTIONS Pengrowth Management Limited
the Manager provided certain services pursuant to a management agreement which expired on June 30, 2009. There were no charges to Pengrowth in 2010 for management fees (2009  $2.8 million) nor for reimbursement of general and
administrative expenses incurred by the Manager (2009  $2.1 million). A senior officer of Pengrowth was a member of the Board of Directors of
Monterey, a company that was acquired in September 2010 (Note 4).  18.
AMOUNTS PER SHARE The following reconciles the weighted
average number of shares used in the basic and diluted net income per share calculations:  2010


2009Weighted average number of shares  basic


301,026,164



264,121,262Dilutive effect of share unit rights, options and DESUs


2,200,484



1,779,172Weighted average number of shares  diluted


303,226,648



265,900,434 In 2010,
2.4 million shares (2009  5.8 million) from share unit rights, options and DESUs were excluded from the diluted net income per share calculation as their effect is anti-dilutive. The weighted average number of exchangeable shares has been
included in the basic weighted average number of shares outstanding using the if converted method.  19.
CAPITAL DISCLOSURES Pengrowth defines its capital as
shareholders equity, long term debt, bank indebtedness and working capital. Pengrowths goal over longer periods is to maintain or
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 (EBITDA) and total debt to total capitalization. Pengrowth seeks to manage the ratio of total debt to trailing 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
EBITDA to temporarily fall outside of the normal targets set by management such as in financing an acquisition to take advantage of 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 issue new debt, refinance existing debt, issue additional equity, adjust the level of dividends paid to shareholders, adjust the level of capital spending or dispose
of non-core assets to reduce debt levels. Pengrowths objectives, policies and processes for managing capital have remained substantially
consistent from the prior year. Management believes that current total debt to trailing EBITDA and total debt to total capitalization are within reasonable limits.




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The following is a summary of Pengrowths capital structure, excluding shareholders equity:  As at December 31:

2010


2009Term credit facilities

$
39,000


$
60,000Senior unsecured notes(1)


985,367



847,599Working capital deficiency


91,629



217,007Convertible debentures






74,828Total debt including convertible debentures

$
1,115,996


$
1,199,434  (1)
Non-current portion of long term debt.  20.
FINANCIAL INSTRUMENTS 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 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. As at December 31, 2010, Pengrowth had fixed the price applicable to future production as follows:  Crude Oil:Reference Point

Volume (bbl/d)


Term


Price per bblFinancial:WTI(1)


12,000



Jan 1, 2011  Dec 31, 2011


$
87.87 CdnWTI(1)


5,000



Jan 1, 2012  Dec 31, 2012


$
91.04 Cdn  (1)
Associated Cdn $/U.S. $ foreign exchange rate has been fixed.




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Natural Gas:Reference Point

Volume (mmbtu/d)


Term


Price per mmbtuFinancial:AECO


45,021



Jan 1, 2011  Dec 31, 2011


$
5.60 CdnChicago MI(1)


5,000



Jan 1, 2011  Dec 31, 2011


$
6.78 Cdn  (1)
Associated Cdn $/U.S. $ foreign exchange rate has been fixed. Commodity Price Sensitivity Each Cdn $1 per barrel change
in future oil prices would result in approximately Cdn $6.2 million pre-tax change in the unrealized gain (loss) on commodity risk management contracts as at December 31, 2010 (December 31, 2009  $4.7 million). Similarly, each Cdn $0.25
per mmbtu change in future natural gas prices would result in approximately Cdn $4.6 million pre-tax change in the unrealized gain (loss) on commodity risk management contracts (December 31, 2009  $12.8 million). As at close December 31, 2010, the AECO spot gas price was approximately $4.05 per mmbtu (December 31, 2009  $5.81 per mmbtu) and the WTI prompt month
price was US $91.38 per barrel (December 31, 2009  $79.36 per barrel). Power Price Risk As at December 31, 2010, Pengrowth had fixed the price applicable to future power costs as follows:  Power:Reference Point

Volume (MW)


Term


Price per MWFinancial:AESO


25



Jan 1, 2011  Dec 31, 2011


$
46.34 Cdn Power Price
Sensitivity Each Cdn $1 per MW change in future power prices would result in approximately Cdn $0.2 million (2009 $0.2 million) pre-tax change
in the unrealized gain (loss) on power risk management contracts. As at close December 31, 2010, the Alberta average power pool spot price was
approximately Cdn $26.99/MW (December 31, 2009  $43.79 per MW). 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 denominated notes for both interest and principal payments. Pengrowth has not entered into any contracts to mitigate the foreign exchange risk
associated with the U.S. dollar denominated term notes as the U.S. dollar denominated interest payments partially offset U.S. dollar denominated revenues. Pengrowth entered into foreign exchange risk management contracts in conjunction with issuing U.K. Pounds Sterling 50 million ten year term notes which fixed the Canadian dollar to U.K. Pound Sterling
exchange rate on the interest and principal of the U.K. Pound Sterling denominated debt at approximately 0.4976 U.K. Pounds Sterling per Canadian dollar. Foreign Exchange Rate Sensitivity The following summarizes the sensitivity on a pre-tax basis of a change in
the foreign exchange rate on unrealized foreign exchange gains (losses) related to the translation of the foreign denominated term debt and on unrealized gains (losses) related to the change in the fair value of the foreign exchange risk management
contracts, holding all other variables constant:  Cdn $0.01 Exchange Rate ChangeForeign Exchange Sensitivity as at December 31, 2010

Cdn - U.S.


Cdn - U.K.Unrealized foreign exchange gain or loss on foreign denominated debt

$
9,020


$
500Unrealized foreign exchange risk management gain or loss






578




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Cdn $0.01 Exchange Rate ChangeForeign Exchange Sensitivity as at December 31, 2009

Cdn - U.S.


Cdn - U.K.Unrealized foreign exchange gain or loss on foreign denominated debt

$
8,650


$
500Unrealized foreign exchange risk management gain or loss






572 Interest Rate Risk Pengrowth is exposed to
interest rate risk on the Canadian dollar revolving credit facility as the interest is based on floating interest rates. Interest Rate Sensitivity As at December 31, 2010, Pengrowth has approximately $1.0 billion of long term debt (December 31, 2009  $1.1 billion) of which $39
million (December 31, 2009  $60 million) is based on floating interest rates. A one percent increase in interest rates would increase pre-tax interest expense by approximately $0.4 million for 2010 (2009  $0.6 million). Summary of Risk Management Contracts Pengrowths risk management contracts are recorded on the balance sheet at their estimated fair value and realized and unrealized gains and losses are included
in the income statement. 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 income statement:  As at and for the year ended December 31, 2010

Commodity riskmanagementcontracts(1)


Power riskmanagementcontracts(2)


Foreign exchangerisk managementcontracts(3)


TotalCurrent portion of risk management assets

$
12,680


$
870


$



$
13,550Current portion of risk management liabilities


(8,029
)






(1,249
)


(9,278
)Non-current portion of risk management liabilities


(6,736
)






(24,680
)


(31,416
)Risk management (liabilities) assets, end of year


(2,085
)


870



(25,929
)


(27,144
)Risk management (liabilities) assets at beginning of year


(9,034
)






(17,789
)


(26,823
)Unrealized gain (loss) on risk management contracts for the year


6,949



870



(8,140
)


(321
)Realized gain (loss) on risk management contracts for the year


75,065



565



(586
)


75,044Total unrealized and realized gain (loss) on risk management contracts for the year


$
82,014


$
1,435


$
(8,726
)

$
74,723As at and for the year ended December 31, 2009

Commodity riskmanagementcontracts(1)


Power riskmanagementcontracts(2)


Foreign exchangerisk managementcontracts(3)


TotalCurrent portion of risk management assets

$
14,001


$



$



$
14,001Current portion of risk management liabilities


(16,661
)






(894
)


(17,555
)Non-current portion of risk management liabilities


(6,374
)






(16,895
)


(23,269
)Risk management (liabilities) assets, end of year


(9,034
)






(17,789
)


(26,823
)Risk management assets (liabilities) at beginning of year


164,692







(18,727
)


145,965Unrealized (loss) gain on risk management contracts for the year


(173,726
)






938



(172,788
)Realized gain (loss) on risk management contracts for the year


171,147







(328
)


170,819Total unrealized and realized (loss) gain on risk management contracts for the year


$
(2,579
)

$



$
610


$
(1,969
)  (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 expenses (income). Realized gains and losses are included in operating expenses.  (3)
Unrealized gains and losses are presented as a separate caption in expenses. Realized gains and losses are included in interest expense.




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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 following tables provide fair value measurement information for financial assets and liabilities as of December 31, 2010 and 2009.  Fair Value Measurements Using:As at December 31, 2010

Carrying Amount


Fair Value


(Level 1)Quoted Prices inActive Markets


(Level
2)Significant OtherObservable InputsFinancial AssetsRemediation trust funds

$
42,114


$
42,115


$
42,115


$
Fair value of risk management contracts


13,550



13,550







13,550Financial LiabilitiesU.S. dollar denominated senior unsecured notes


893,148



988,949







988,949Cdn dollar senior unsecured notes


15,000



15,735







15,735U.K. Pound Sterling denominated unsecured notes


77,219



84,599







84,599Fair value of risk management contracts


40,694



40,694







40,694Fair Value Measurements Using:As at December 31, 2009

Carrying Amount


Fair Value


(Level 1)
Quoted Prices inActive Markets


(Level 2)
Significant OtherObservable InputsFinancial AssetsRemediation trust funds

$
34,837


$
34,821


$
34,821


$
Fair value of risk management contracts


14,001



14,001







14,001Other Assets  investment in public company


1,151



1,151



1,151



Financial LiabilitiesU.S. dollar denominated senior unsecured notes


905,631



963,136







963,136Cdn dollar senior unsecured notes


15,000



15,164







15,164U.K. Pound Sterling denominated unsecured notes


84,514



89,724







89,724Convertible debentures


74,828



76,423



76,423



Fair value of risk management contracts


40,824



40,824







40,824 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. 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. 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




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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 considers amounts over 90 days as past due. As at December 31, 2010 and 2009, the amount of accounts
receivable that were past due was not significant. Pengrowth has not recorded a significant allowance for doubtful accounts during 2010 and 2009 and has no significant bad debt provision at December 31, 2010 and 2009. Pengrowths
objectives, processes and policies for managing credit risk have not changed from the previous year. 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 $1.0 billion term credit facility with an additional $250 million available under an expansion feature subject to lender
approval and a $50 million demand operating line of credit. 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, 2010

CarryingAmount


ContractualCash Flows


Within 1 year


1-2 years


2-5 years


More than 5yearsCdn dollar revolving credit facility(1)

$
39,000


$
42,644


$
1,289


$
1,289


$
40,066


$
Cdn dollar senior unsecured notes(1)


15,000



22,578



992



992



2,975



17,619U.S. dollar denominated senior unsecured notes(1)


893,148



1,288,764



56,571



56,571



281,108



894,514U.K. Pound Sterling denominated unsecured
notes(1)


77,219



98,393



4,235



4,235



89,923



Remediation trust fund payments






12,500



250



250



750



11,250Commodity risk management contracts


6,736



6,911







6,911







Foreign exchange risk management contracts


24,680



150



30



30



90



  (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.




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As at December 31, 2009

CarryingAmount


Contractual
Cash Flows


Within 1 year


1-2 years


2-5 years


More than 5yearsCdn dollar revolving credit facility(1)

$
60,000


$
60,892


$
613


$
60,279


$



$
Cdn dollar senior unsecured notes(1)


15,000



23,571



992



992



2,977



18,610U.S. dollar denominated senior unsecured notes(1)


748,085



1,131,180



49,009



49,009



194,858



838,304U.K. Pound Sterling denominated unsecured
notes(1)


84,514



112,384



4,637



4,637



13,923



89,187Convertible debentures(1)(2)


74,828



79,599







79,599







Remediation trust fund payments






12,500



250



250



750



11,250Commodity risk management contracts


6,374



6,517







6,517







Foreign exchange risk management contracts


16,895



180



30



30



90



30  (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.  (2)
Convertible debentures were redeemed on January 14, 2010 using proceeds from the revolving credit facility. The repayment of the convertible debentures has been shown in the
above table as due in 1-2 years with the revolving credit facility.  21.
COMMITMENTS  2011


2012


2013


2014


2015


Thereafter


TotalOperating leases

$
13,571


$
13,430


$
13,335


$
12,840


$
12,153


$
23,268


$
88,597 Operating leases
include office rent and vehicle leases.  22.
CONTINGENCIES Pengrowth is sometimes named as a defendant in
litigation. 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.  23.
SUBSEQUENT EVENT Subsequent to December 31, 2010 and prior
to March 8, 2011, Pengrowth has entered into fixed price commodity sales contracts with third parties as follows:  Crude Oil:Reference

Volume (bbl/d)


Term


Price per bblFinancial:WTI(1)


1,500



Mar 1, 2011 - Dec 31, 2011


$
100.68 CdnWTI(1)


2,500



Apr 1, 2011 - Dec 31, 2011


$
100.01 CdnWTI(1)


5,000



Jan 1, 2012 - Dec 31, 2012


$
99.20 Cdn  (1)
Associated Cdn $/U.S. $ foreign exchange rate has been fixed.  24.
RECONCILIATION OF FINANCIAL STATEMENTS TO UNITED STATES GENERALLY ACCEPTED ACCOUNTING PRINCIPLES The significant differences between Canadian generally accepted accounting principles (Canadian GAAP) which, in most respects, conforms to United States generally accepted accounting principles (U.S. GAAP) as they
apply to Pengrowth, are as follows:  (a)
Under U.S. GAAP, the carrying value of petroleum and natural gas properties and related facilities, net of future income taxes, is limited to the present value of after tax
future net revenue from proven reserves, discounted at ten percent based on the average of the prices on the first day of each month for the prior twelve-month period plus the lower of cost and fair value of unproven properties. At December 31,
2010 and 2009, the application of the full cost ceiling test under U.S. GAAP did not result in a write-down of capitalized costs. Where the amount of a ceiling test write-down under Canadian GAAP differs from the amount of the write-down under U.S. GAAP, the charge for depletion will differ in subsequent years. In addition, under U.S.
GAAP depletion is calculated based




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on the reserve assignments in accordance with SEC requirements (based on the average of the prices on the first day of each month for the prior twelve month period) as opposed to escalated dollar
reserves required under Canadian GAAP. As such, the depletion rate under U.S. GAAP differs from Canadian GAAP. The effect of ceiling test impairments in prior years and a different depletion rate under U.S. GAAP has reduced the 2010 depletion charge
by $155.7 million (2009  $189.4 million). Depletion and depreciation on a per unit of production under U.S. GAAP was $13.42 per BOE (2009  $13.53).  (b)
Other comprehensive income under U.S. GAAP differs from that presented under Canadian GAAP as a result of designating a cash flow hedge at different dates under U.S. GAAP as
compared to Canadian GAAP. Effective January 1, 2007, Pengrowth ceased to designate its foreign exchange swaps as a cash flow hedge of the U.K. term debt. The amount deferred in accumulated other comprehensive income pertaining to this hedging
relationship when the hedge was de-designated of $2.4 million is being amortized to income over the life of the foreign exchange swap under U.S. GAAP.  (c)
Under U.S. GAAP, the exchangeable shares were classified as a non-controlling interest. The conversion of the exchangeable shares into trust units or common shares would be
measured under U.S. GAAP at the fair value of the trust units or common shares issued and any gain or loss would be recorded as an addition or reduction of trust unitholders capital or shareholders capital, respectively. Under Canadian
GAAP, the exchangeable shares were recognized as another form of equity and there was no gain or loss on redemption. There is no Canadian to U.S. GAAP difference to total shareholders equity as a result of the differing treatment of
exchangeable shares. Prior to December 31, 2010, the trust units were redeemable at the option of the holder at a
redemption price equal to the lesser of 95% of the average closing price of the trust units for the 10 trading days after the trust units have been surrendered for redemption and the closing price on the date the trust units have been surrendered
for redemption. However, the total amount payable by the Trust in cash in any one calendar month was limited to a maximum of $25,000. Redemptions in excess of the cash limit had to be satisfied by way of a distribution in specie of a pro rata share
of royalty units and other assets, excluding facilities, pipelines or other assets associated with oil and gas production, which were held by the Trust at the time the trust units were to be redeemed. As a result of the significant limitation on the
cash amount payable by the Trust in respect of redemptions, and that any royalty units issued would have similar characteristics of the trust units and be convertible back into trust units, the trust units were not classified as redeemable equity
for the purposes of U.S. GAAP. The common shares outstanding as of December 31, 2010 are not redeemable.  (d)
Under U.S. GAAP, an entity that is subject to income tax in multiple jurisdictions is required to disclose income tax expense in each jurisdiction. Pengrowth is subject to tax at
the federal and provincial level. The portion of the income tax reduction at the federal level for the year ended December 31, 2010 is $1.7 million (2009  $42.0 million). The portion of income tax reduction at the provincial level is $1.0
million (2009  $23.4 million).  (e)
Additional disclosures required under U.S. GAAP with respect to Pengrowths equity incentive plans is provided below. The intrinsic value of the DESUs and Share Unit Rights and Options exercised was as follows:  2010


2009NumberExercised


IntrinsicValue


NumberExercised


IntrinsicValueDESUs


459,074


$
2,874



297,184


$
3,121Share Unit Rights and Options


587,314



3,037



299,684



867Total


1,046,388


$
5,911



596,868


$
3,988 The following table summarizes information about DESUs and Share Unit Rights and Options vested and expected to vest:  At December 31, 2010

DESUs


Share Unit Rightsand OptionsNumber vested and expected to vest


2,000,547



3,528,275Weighted average exercise price per unit(1)

$



$
12.79Aggregate intrinsic value(2)

$
25,567


$
9,160Weighted average remaining life (years)


1.6



2.3




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At December 31, 2009

DESUs


Share Unit Rightsand OptionsNumber vested and expected to vest


1,570,348



5,218,787Weighted average exercise price per unit(1)

$



$
12.39Aggregate intrinsic value(2)

$
15,939


$
8,238Weighted average remaining life (years)


1.4



3.3  (1)
No proceeds are received upon exercise of DESUs.  (2)
Based on December 31 closing common share price. The following table summarizes information about DESUs and Share Unit Rights and Options outstanding:  At December 31, 2010

DESUs


Share Unit Rightsand OptionsNumber exercisable(1)


249,839



3,028,860Weighted average exercise price per unit(2)

$



$
13.74Aggregate intrinsic value(3)

$
3,193


$
6,309Weighted average remaining life (years)






2.2At December 31, 2009

DESUs


Share Unit Rightsand OptionsNumber exercisable(1)


158,981



3,087,494Weighted average exercise price per unit(2)

$



$
14.95Aggregate intrinsic value(3)

$
1,614


$
2,217Weighted average remaining life (years)






2.7  (1)
DESUs exercisable at December 31, 2010 and 2009 were granted to directors, vest immediately and are only exercisable upon retirement.  (2)
No proceeds are received upon exercise of DESUs.  (3)
Based on December 31 closing common share price.  (f)
Under Canadian GAAP, the convertible debentures are classified as debt with a portion, representing the estimated fair value of the conversion feature at the date of issue, being
allocated to equity. In addition, under Canadian GAAP a non-cash interest expense or income representing the effective yield of the debt component is recorded in the consolidated statements of income with a corresponding credit or debit to the
convertible debenture liability balance to accrete the balance to the principal due on maturity as a result of the portion allocated to equity. Under U.S. GAAP, the convertible debentures, in their entirety, are classified as debt. The non-cash interest expense recorded under Canadian GAAP related to the equity portion of the debenture would not be
recorded under U.S. GAAP. On January 14, 2010, Pengrowth redeemed all of the outstanding Convertible Unsecured Subordinated
Debentures. The cash redemption amount was approximately $76.8 million, including accrued interest to the redemption date. Non-cash interest of $0.1 million was recognized upon redemption.  (g)
The following table summarizes the unrecognized tax benefits under U.S. GAAP:  2010


2009Balance, January 1

$
19,288


$
21,239Additions (decreases) based on tax positions in the year






(1,260
)Decrease due to change in tax rates


(292
)


(691
)Balance, December 31

$
18,996


$
19,288




|                                 |  |  |           | 
|-------------------------------- |  |  | --------- | 
|PENGROWTH 2010 Financial Results |  |  | 69 

LOGO | 



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##### Table of Contents

The following table summarizes open taxation years at December 31, 2010 by jurisdiction:  Jurisdiction

YearsFederal


2004 - 2009Alberta, British Columbia, Saskatchewan, and Nova Scotia


2004 - 2009 The 2004 tax examination by federal authorities is currently in progress. Interest and penalties related to uncertain tax positions, which are included in income tax expense, were not material for the years ended December 31, 2010 and 2009. Unrecognized tax benefits are classified as current or long-term liabilities under U.S. GAAP as opposed to future income tax liabilities. It is
anticipated that no amount of the current or prior year unrecognized tax benefit will be realized in the next year. The unrecognized tax benefit, if recognized, would have a favourable impact on Pengrowths effective income tax rate in future
periods.  (h)
Fair Value Measurements The framework for measuring
fair value when an entity is required to use a fair value measure for recognition or disclosure purposes under U.S. GAAP is consistent with the framework under Canadian GAAP, except that Canadian GAAP only requires disclosure of the fair value
hierarchy for items normally measured at fair value. In addition, under Canadian GAAP the framework only applies to financial assets and liabilities measured at fair value as at December 31, 2010 and 2009 while under U.S. GAAP the framework
applies to all financial assets and liabilities and non-financial assets and liabilities measured at fair value or for which fair value is disclosed for December 31, 2010 and 2009. Pengrowths disclosure under Canadian GAAP includes assets
and liabilities measured at fair value and for which fair value is disclosed, consistent with U.S. GAAP. The estimated fair value of property, plant and equipment and asset retirement obligations for the business combination described in Note 4,
would have a Level 3 classification as the valuations in this level are primarily those with inputs that are not based on observable market data. The fair value of Pengrowths equity investment in Monterey at the time of the acquisition was a
Level 1 fair value.  (i)
Under U.S. GAAP, unrealized gains or losses on commodity risk management would be included with oil and gas sales.  (j)
Effective January 1, 2009, Pengrowth adopted new disclosure standards under U.S. GAAP with respect to derivatives and hedging. These new disclosure standards are similar to
Canadian GAAP (see note 20). The following are additional disclosures required under U.S. GAAP with respect to Pengrowths derivatives. Pengrowth has not designated any outstanding risk management contracts as hedges for accounting purposes and therefore records these contracts on the balance sheet at their fair value and recognizes changes in fair
value on the statement of income (loss) as unrealized commodity risk management contracts. The effect on cash flows will be recognized separately only upon realization of the contracts, which could vary significantly from the unrealized amount
recorded due to timing and prices when each contract is settled. The use of commodity contracts 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 total of all risk management assets is $30.9 million (2009  $38.2 million). The total of all risk management liabilities is $58.1 million (2009  $65.0 million). Under Canadian and U.S. GAAP,
the risk management assets and risk management liabilities are netted by individual counterparty, thus the maximum amount of potential loss due to credit risk is the carrying amount of the risk management assets recorded on the balance sheet. There
are no contingent features of these contracts related to Pengrowths credit risk.  (k)
Upon conversion to a corporation on December 31, 2010, Pengrowth eliminated the accumulated deficit under Canadian GAAP by reducing the shareholders capital. This
would not normally be permitted under U.S. GAAP. The total shareholders equity under U. S. GAAP remains unchanged.




|        |  |  |                                  | 
|------- |  |  | -------------------------------- | 
|LOGO 70 |  |  | PENGROWTH 2010 Financial Results | 



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CONSOLIDATED STATEMENTS OF INCOME The application of U.S. GAAP would have the following effect on net income as reported: (Stated in thousands of
Canadian Dollars, except per share amounts)  Year endedDecember 31, 2010


Year ended
December 31, 2009Net income for the year, as reported

$
230,257


$
84,853Adjustments:Depletion and depreciation (a)


155,686



189,371Amortization of discontinued hedge (b)


272



272Non-cash interest on convertible debentures (f)


(120
)


40Future tax adjustments


(47,522
)


(77,553
)Net income  U.S. GAAP

$
338,573


$
196,983Other comprehensive income (loss):Amortization of discontinued hedge (b)


(272
)


(272
)Comprehensive income  U.S. GAAP

$
338,301


$
196,711Net Income per share  U.S. GAAPBasic

$
1.12


$
0.74Diluted

$
1.12


$
0.74 CONSOLIDATED BALANCE SHEETS The application of
U.S. GAAP would have the following effect on the balance sheets as reported: (Stated in thousands of Canadian Dollars)  As at December 31, 2010

As Reported


Increase(Decrease)


U.S. GAAPAssetsProperty, plant and equipment (a)

$
4,076,976



$      (1,406,816
)

$
2,670,160Future income taxes (g)






146,577



146,577$
(1,260,239
)LiabilitiesFuture income taxes (g)

$
237,753


$
(237,753
)

$
Other long term liabilities (g)






18,996



18,996Shareholders equity:Accumulated other comprehensive income (b)

$



$
1,358


$
1,358Shareholders equity (c)


3,186,976



(1,042,840
)


2,144,136$
(1,260,239
)




|                                 |  |  |           | 
|-------------------------------- |  |  | --------- | 
|PENGROWTH 2010 Financial Results |  |  | 71 

LOGO | 



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##### Table of Contents

As at December 31, 2009

As Reported


Increase(Decrease)


U.S. GAAPAssetsProperty, plant and equipment (a)

$
3,789,369



$      (1,562,502
)

$
2,226,867Future income taxes (g)






251,473



251,473$
(1,568,507
)LiabilitiesConvertible debentures

$
74,828


$
40


$
74,868Future income taxes (g)


180,671



(180,671
)


Other long term liabilities (g)






19,288



19,288Shareholders equity:Accumulated other comprehensive income (b)

$



$
1,630


$
1,630Shareholders equity (c)


2,795,201



(1,151,316
)


1,643,885$
(1,568,507
) ADDITIONAL DISCLOSURES REQUIRED UNDER
U.S. GAAP The components of accounts receivable are as follows:  As atDecember 31, 2010


As atDecember 31, 2009Trade

$
170,702


$
159,309Prepaid


18,914



23,033$
189,616


$
182,342 The components of
accounts payable are as follows:  As atDecember 31, 2010


As atDecember 31, 2009Accounts payable

$
65,072


$
50,998Accrued liabilities


175,880



134,339$
240,952


$
185,337




|        |  |  |                                  | 
|------- |  |  | -------------------------------- | 
|LOGO 72 |  |  | PENGROWTH 2010 Financial Results | 



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##### Table of Contents

APPENDIX D

SUPPLEMENTAL UNAUDITED DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES

REQUIRED UNDER UNITED STATES GENERALLY ACCEPTED ACCOUNTING PRINCIPLES



---

##### Table of Contents

SUPPLEMENTAL INFORMATION  OIL AND GAS PRODUCING ACTIVITIES

(unaudited)

The following are
supplementary oil and gas disclosures required under U. S. generally accepted accounting principles. All amounts in thousands, 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 (prior to December 31, 2009, pricing was based on the year end price). 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 2010 and 2009 has been presented in accordance with the SEC
Modernization of Oil and Gas Reporting reserve estimation and disclosure rules, which may not be applied retrospectively for reporting periods before December 31, 2009. The 2008 data are presented in accordance with FASB oil and gas disclosure
requirements effective during that period. 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.



---

##### Table of Contents

Subsequent to December 31, 2010 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.

The impact of Pengrowths equity
accounted investments on the supplemental oil and gas disclosures is not material.

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:



|                           |  |      |         |  |      |   |         | 
|-------------------------- |  | ---- | ------- |  | ---- | - | ------- | 
|                           |  | 2010 |         |  | 2009 |  
|Property acquisition costs |  |      |         |  |      |   |         | 
|Proved                     |  | $    | 125,946 |  |      | $ | 24,653  | 
|Unproved                   |  |      | 464,593 |  |      |   | 11,002  | 
|Exploration costs          |  |      | 34,058  |  |      |   | 13,915  | 
|Development costs          |  |      | 256,232 |  |      |   | 123,104 | 
|Injectants costs           |  |      | 9,324   |  |      |   | 13,298  | 
|                           |  |      |         |  |      |   |         | 
|                           |  | $    | 890,153 |  |      | $ | 185,972 | 
|                           |  |      |         |  |      |   |         | 

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 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 $512 million (2009  $68 million) of capitalized costs to acquire and evaluate unproven and development properties has been excluded from depletion.



---

##### Table of Contents

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:



|                                                          |  |      |            |   |      |   |            |  
|--------------------------------------------------------- |  | ---- | ---------- | - | ---- | - | ---------- | -
|                                                          |  | 2010 |            |   | 2009 |  
|Oil and gas properties                                    |  | $    | 8,030,457  |   |      | $ | 7,211,347  |  
|Less accumulated depletion, depreciation and amortization |  |      | (5,393,465 | ) |      |   | (5,027,476 | )
|                                                          |  |      |            |   |      |   |            |  
|Net capitalized costs                                     |  | $    | 2,636,992  |   |      | $ | 2,183,871  |  
|                                                          |  |      |            |   |      |   |            |  
|                                                          |  |     
|Unproved oil and gas properties                           |  | $    | 953,263    |   |      | $ | 474,940    |  
|Proven oil and gas properties                             |  |      | 1,683,729  |   |      |   | 1,708,931  |  
|                                                          |  |      |            |   |      |   |            |  
|Net capitalized costs                                     |  | $    | 2,636,992  |   |      | $ | 2,183,871  |  
|                                                          |  |      |            |   |      |   |            |  



---

##### Table of Contents

OIL AND GAS RESERVE INFORMATION

All of Pengrowths proved oil, natural gas liquids, and natural gas reserves are located in Canada, in the provinces of Alberta, British Columbia, Saskatchewan and Nova Scotia. Pengrowths
proved developed and undeveloped reserves after deductions of royalties are summarized below:



|                                                                                |  |                     |       |   |            |  |       |  
|------------------------------------------------------------------------------- |  | ------------------- | ----- | - | ---------- |  | ----- | -
|Net Proved Developed and Undeveloped Reserves After Royalties                   |  | Crude Oiland 
NGL's |       |   | NaturalGas | 
|                                                                                |  | MMbbl               |       |   | Bcf        | 
|End of year 2008                                                                |  |                     | 106.7 |   |            |  | 524.9 |  
|Revisions of previous estimates (including infill drilling & improved recovery) |  |                     | 0.4   |   |            |  | (36.6 | )
|Purchase of reserves in place                                                   |  |                     | 0.8   |   |            |  | 1.1   |  
|Sale of reserves in place                                                       |  |                     | (0.5  | ) |            |  | (7.8  | )
|Discoveries and extensions                                                      |  |                     | 1.3   |   |            |  | 6.7   |  
|Production                                                                      |  |                     | (11.2 | ) |            |  | (72.9 | )
|                                                                                |  |                    
|End of year 2009                                                                |  |                     | 97.5  |   |            |  | 415.4 |  
|Revisions of previous estimates (including infill drilling & improved recovery) |  |                     | 5.2   |   |            |  | 87.3  |  
|Purchase of reserves in place                                                   |  |                     | 0.6   |   |            |  | 52.2  |  
|Sale of reserves in place                                                       |  |                     | (0.1  | ) |            |  | (1.2  | )
|Discoveries and extensions                                                      |  |                     | 3.2   |   |            |  | 19.5  |  
|Production                                                                      |  |                     | (10.6 | ) |            |  | (68.6 | )
|                                                                                |  |                    
|End of year 2010                                                                |  |                     | 95.8  |   |            |  | 504.6 |  



|                                            |  |                     |      |  |            |  |       | 
|------------------------------------------- |  | ------------------- | ---- |  | ---------- |  | ----- | 
|Net Proved Developed Reserves After Royalty |  | Crude Oiland 
NGL's |      |  | NaturalGas | 
|                                            |  | MMbbl               |      |  | Bcf        | 
|End of year 2008                            |  |                     | 87.9 |  |            |  | 474.4 | 
|End of year 2009                            |  |                     | 81.7 |  |            |  | 394.0 | 
|End of year 2010                            |  |                     | 81.3 |  |            |  | 439.4 | 

Notes:



|1. | Net after royalty reserves are Pengrowths lessor royalty, overriding royalty, and working interest share of the gross remaining reserves, after deduction of any
crown, freehold and overriding royalties. Crown royalties are subject to change by legislation or regulation and vary depending on production rates, selling prices and potentially timing of initial production.
|-- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|2. | Reserves are the estimated quantities of crude oil, natural gas and related substances anticipated from geological and engineering data to be recoverable from known
accumulations, from a given date forward, by known technology, under existing operating conditions and the average of the commodity prices on the first day of each month for the year ended December 31, 2010 and 2009. Prior to December 31,
2009 reserves were based on the commodity prices in effect on the last day of the year.
|-- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|3. | Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.
|-- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|4. | Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved
undeveloped reserves are reserves that are expected to be recovered from known accumulations where a significant expenditure is required.
|-- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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##### Table of Contents

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 the 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, 2010 and December 31, 2009. 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, 2010 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 $78.23/bbl (2009  $63.59/bbl) and AECO natural gas price of $4.06/MMbtu (2009  $3.84/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 the Pengrowths crude oil
and natural gas reserves at December 31, for the years presented.



|                                                         |  |      |        |   |      |   |        |  
|-------------------------------------------------------- |  | ---- | ------ | - | ---- | - | ------ | -
|                                                         |  | 2010 |        |   | 2009 |  
|Future cash inflows                                      |  | $    | 10,761 |   |      | $ | 8,561  |  
|Future costs                                             |  |      |        |   |      |   |        |  
|Future production and development costs                  |  |      | (6,302 | ) |      |   | (5,164 | )
|Future income taxes                                      |  |      | (261   | ) |      |   | (623   | )
|                                                         |  |      |        |   |      |   |        |  
|Future net cash flows                                    |  |      | 4,198  |   |      |   | 2,774  |  
|Deduct: 10% annual discount factor                       |  |      | (1,649 | ) |      |   | (1,039 | )
|                                                         |  |      |        |   |      |   |        |  
|Standardized measure of discounted future net cash flows |  | $    | 2,549  |   |      | $ | 1,735  |  
|                                                         |  |      |        |   |      |   |        |  



---

##### Table of Contents

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.



|                                                                        |  |      |      |   |      |  |      |  
|----------------------------------------------------------------------- |  | ---- | ---- | - | ---- |  | ---- | -
|Changes in Standardized Measure of Discounted Future Cash Flow          |  | 2010 |      |   | 2009 | 
|                                                                        |  | $MM  |      |   | $MM  | 
|Future discounted net cash flow at beginning of year                    |  |      | 1735 |   |      |  | 1787 |  
|Sales & transfer, net of production costs                               |  |      | (719 | ) |      |  | (737 | )
|Net change in sales & transfer prices                                   |  |      | 706  |   |      |  | 233  |  
|Development costs incurred during the period.                           |  |      | 324  |   |      |  | 199  |  
|Change in future development costs                                      |  |      | (448 | ) |      |  | (79  | )
|Change due to extensions and discoveries                                |  |      | 94   |   |      |  | 30   |  
|Change due to revisions (including infill drilling & improved recovery) |  |      | 198  |   |      |  | (36  | )
|Accretion of discount                                                   |  |      | 203  |   |      |  | 207  |  
|Sales of reserves in place                                              |  |      | (3   | ) |      |  | (19  | )
|Purchase of reserves in place                                           |  |      | 136  |   |      |  | 12   |  
|Net change in Income Taxes                                              |  |      | 228  |   |      |  | (18  | )
|Changes in timing of future net cash flow and other                     |  |      | 95   |   |      |  | 155  |  
|                                                                        |  |      |      |   |      |  |      |  
|Future discounted net cash flow at end of year                          |  |      | 2549 |   |      |  | 1735 |  
|                                                                        |  |      |      |   |      |  |      |  

Note:



|1. | The schedules above are calculated using year-end costs, statutory tax rates and proved oil and gas reserves and the average of the commodity prices on the first day of
each month for the years ended December 31, 2010 and 2009. 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.
|-- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



---

##### Table of Contents

APPENDIX E

PENGROWTH ENERGY CORPORATION CODE OF BUSINESS CONDUCT AND ETHICS DATED DECEMBER 16, 2010



---

##### Table of Contents





Pengrowth Energy Corporation



CODE OF BUSINESS CONDUCT

AND ETHICS









Approved by the Board of Directors on December 16, 2010



---

##### Table of Contents

TABLE OF CONTENTS



|                                                                                                                                                     |  |      |    | 
|---------------------------------------------------------------------------------------------------------------------------------------------------- |  | ---- | -- | 
|                                                                                                                                                     |  | Page |   
|Application                                                                                                                                          |  |      | 1  | 
|Purpose                                                                                                                                              |  |      | 1  | 
|Policy                                                                                                                                               |  |      | 1  | 
|Compliance with the Law                                                                                                                              |  |      | 2  | 
|Health, Safety and the Environment                                                                                                                   |  |      | 3  | 
|Public Reporting                                                                                                                                     |  |      | 4  | 
|Conflict of Interest                                                                                                                                 |  |      | 4  | 
|Private Business                                                                                                                                     |  |      | 5  | 
|Payments                                                                                                                                             |  |      | 5  | 
|Political Contributions                                                                                                                              |  |      | 6  | 
|Involvement with Not-for-Profit Organizations                                                                                                        |  |      | 6  | 
|Outside Employment                                                                                                                                   |  |      | 6  | 
|Directorships                                                                                                                                        |  |      | 7  | 
|Government Relations                                                                                                                                 |  |      | 7  | 
|Confidential Information                                                                                                                             |  |      | 7  | 
|Company Information                                                                                                                                  |  |      | 7  | 
|Inside Information                                                                                                                                   |  |      | 8  | 
|Books of Account                                                                                                                                     |  |      | 9  | 
|Patents and Inventions                                                                                                                               |  |      | 9  | 
|Community Relations                                                                                                                                  |  |      | 9  | 
|Company Property and Opportunities                                                                                                                   |  |      | 10 | 
|Accounting and Financial Reporting                                                                                                                   |  |      | 10 | 
|Employee Relations and Reporting                                                                                                                     |  |      | 10 | 
|Policies, Procedures and Internal Controls                                                                                                           |  |      | 11 | 
|Acknowledgement                                                                                                                                      |  |      | 11 | 
|Exceptions and Changes                                                                                                                               |  |      | 11 | 
|Appendix A Complaint Procedures For Accounting, Financial Reporting and Auditing Matters and Violations of the Code
of Business Conduct and Ethics |  |      | 12 | 
|Appendix B Awareness Statement on Code of Business Conduct and Ethics                                                                              |  |      | 15 | 



---

##### Table of Contents

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

Pengrowths reputation for honesty and integrity has been earned by
maintaining the highest standards of business ethics in all our interactions with our co-workers, governments, local communities, shareholders, customers, suppliers, competitors and the public. The commitment of every Member to preserve and
perpetuate the letter and spirit of this Code is essential to our continued success.

This Code affirms the policy of Pengrowth and is a
guideline to:



| |  |  | assure compliance with laws and regulations that govern the business activities of Pengrowth;
| | - |  | ---------------------------------------------------------------------------------------------



| |  |  | maintain a corporate climate in which the integrity and dignity of each individual is valued;
| | - |  | ---------------------------------------------------------------------------------------------



| |  |  | foster a standard of conduct that reflects positively on Pengrowth; and
| | - |  | -----------------------------------------------------------------------



| |  |  | protect Pengrowth from unnecessary exposure to financial loss.
| | - |  | --------------------------------------------------------------

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. Unscrupulous dealings, 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.

It is important that Pengrowth be made aware of circumstances that may indicate possible violations of law or this Code. 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. Any violations of this Code must be promptly reported to an appropriate person as outlined in Appendix A. Any Member may submit
a complaint regarding a suspected violation of the Code without fear of dismissal or retaliation.

Policy

Pengrowth and all of its Members will adhere to the highest ethical standards in all our business



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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.

Members are expected to comply with all aspects of this Code.

If a director or officer has any
question of appropriateness in a particular situation, areas of conflict or disagreement with any aspect of this policy, the matter should be discussed with the President and Chief Executive Officer, Chief Financial Officer, General Counsel or Board
Chairman of Pengrowth Energy Corporation.

If an employee has any question of appropriateness in a particular situation, areas of conflict or
disagreement with any aspect of this policy, the matter should be discussed with the employees manager. It is recognized that there may be situations in which it is impractical or inappropriate for an employee to bring the matter to his or her
manager. In these instances, employees should seek the advice of the Director, Human Resources or Pengrowths General Counsel.

If a
consultant or contractor has any question of appropriateness in a particular situation, areas of conflict or disagreement with any aspect of this policy, the matter should be discussed with the consultants or contractors supervisor.

Compliance with the Law

A
concern for what is right underlies all business decisions. An issuer may be held liable for the wrongful actions of its directors, officers, employees, consultants or contractors. Accordingly, 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 and regulations including those set by a self regulatory body or professional organization. Particular attention is directed to the laws and regulations
relating to discrimination, privacy, securities, labour, safety and the environment.

In addition to the laws imposed by statute, the law also
imposes a duty upon a company to honour agreements, whether in writing or not, and to act reasonably and in a manner that will not cause harm to others. Members must diligently ensure that their conduct is not and cannot be interpreted as being a
contravention of laws governing the affairs of Pengrowth in any jurisdiction where it carries on business.

Ignorance of the law will not
usually excuse a party who contravenes a law. Members are responsible to keep informed of laws which may affect those affairs of Pengrowth which are under his or her control.

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.

Pengrowth is subject to legislation in Canada,
the United States and other jurisdictions that prohibits



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corrupt practices in dealing with foreign governments. These laws make it an offence to make or offer a payment, gift or other benefit to a foreign public official in order to induce favourable
business treatment, such as obtaining or retaining business or some other advantage in the course of business. Violation of this legislation may result in substantial penalties to Pengrowth and to individuals. Foreign public officials include all
people who perform public duties or functions for a foreign state. This can include anyone acting in an official capacity or under a delegation of authority from the government to carry out government ownership or control, such as
national oil companies, regardless of whether the government in question has majority ownership or control.

Pengrowth, as well as each
Member, must take all responsible steps to ensure that the requirements of this legislation are strictly met. No payments, gifts or other benefits are to be given, directly or indirectly, to foreign public officials, political parties or political
candidates for the purpose of influencing government decisions in Pengrowths favour or for securing other improper advantages. Furthermore, no such payments are to be made to agents or other third parties in circumstances where it is likely
that part or all of the payment will be passed on to a foreign public official, political party or political candidate.

There are certain
types of payments to foreign public officials that are allowed under both the Canadian and U.S. legislation called facilitation or facilitating payments. These are small payments or tips requested in the context of having
routine administrative actions performed by foreign public officials. Members should be aware that such payments are permissible only under very limited circumstances. Advice should be sought from Pengrowths legal counsel with respect to the
amount and advisability of making a facilitation payment. Moreover, we must ensure that any such payments are properly recorded in accordance with Pengrowths accounting procedures.

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 and to understand Pengrowths Environment, 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.

All conditions, situations or accidents which give rise to health, safety or environmental concerns must be immediately reported to the Manager, Safety
and Training or the Manager, Environment.

Pengrowth authorizes each of its Members to take any emergency actions that are necessary or
desirable to minimize any critical health, safety or environmental problems provided those actions are consistent with Pengrowths philosophy and practices regarding health, safety and environmental protection.



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Public Reporting

Full, fair, accurate, timely and understandable disclosure in the reports and other documents that Pengrowth files with, or submits to, the securities commissions and in its other public communications is
critical for Pengrowth to maintain its good reputation, to comply with its obligations under the securities laws and to meet the expectations of its securityholders and other members of the investment community.

Persons responsible for the preparation of such documents and reports and other public communications are to exercise the highest standard of care in
their preparation in accordance with the following guidelines:



| |  |  | all accounting records, and the reports produced from such records, must be in accordance with all applicable laws;
| | - |  | -------------------------------------------------------------------------------------------------------------------



| |  |  | all accounting records must fairly and accurately reflect the transactions or occurrences to which they relate;
| | - |  | ---------------------------------------------------------------------------------------------------------------



| |  |  | all accounting records must fairly and accurately reflect in reasonable detail Pengrowths assets, liabilities, revenues and expenses;
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------



| |  |  | no accounting records should contain any false or intentionally misleading entries;
| | - |  | -----------------------------------------------------------------------------------



| |  |  | no transactions should be intentionally misclassified as to accounts, departments or accounting periods;
| | - |  | --------------------------------------------------------------------------------------------------------



| |  |  | all transactions must be supported by accurate documentation in reasonable detail and recorded in the proper account and in the proper accounting
period;
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | no information should be concealed from the internal auditors or the independent auditors; and
| | - |  | ----------------------------------------------------------------------------------------------



| |  |  | compliance with Pengrowths system of internal controls is required.
| | - |  | --------------------------------------------------------------------

Conflict of Interest

Members must avoid interests or relationships where their personal
interests may affect their judgement 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. Disclosure of areas of potential conflict of interest will allow appropriate steps to be taken to
protect the individual from these situations.



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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 person who 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 Board Chairman the
nature and extent of the directors or officers interest. The Board Chairman shall make any such disclosure concerning himself to the Chairman of the Governance and Nominating Committee.

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 of what steps should be taken. Directors are required to disclose to the chairman of the Corporate Governance and Nominating Committee (or, in the case of the chairman of the Corporate Governance and Nominating Committee, to
another member 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.

There are many situations which can be classified as conflicts of interest, but the following examples illustrate those that are most common.

Private Business

Unless otherwise consented to by his or her immediate superior, a Member, either directly or indirectly through his or her immediate family or by any
other means, must not have a personal financial interest in, or place himself or herself in a position where he or she could derive a benefit or interest from, a business transaction with Pengrowth, which financial interest or benefit is of such a
nature that it would reasonably be expected to create a conflict of interest for the Member.

This, however, does not prevent a Member and his
or her family from having ownership in publicly traded shares or equity in companies which may do business with Pengrowth or prevent a consultant or contractor from providing his or her services to Pengrowth through a third party corporation.

Payments

It is Pengrowths policy to deal fairly and lawfully with all customers, suppliers and independent contractors purchasing or furnishing goods or
services. All goods and services shall be obtained on a competitive basis at the best value considering price, quality, reliability, availability and delivery.

Members shall not accept gratuities or favours of any sort having more than a nominal value from any person, organization or group that does, or is seeking to do, business with Pengrowth or any of its
affiliates or from a competitor of Pengrowth or any of its affiliates. Members should neither seek nor accept gifts, payments, services, fees, trips or accommodations, special privileges of value or loans from any person, organization or group that
does, or is seeking to do, business with Pengrowth or any of its affiliates (unless they are in the business of lending, and then only on conventional terms) or from a competitor of Pengrowth or any of its affiliates. Gifts of nominal value
(advertising mementos, desk calendars or pens), acceptance of hospitality or entertainment (lunch, dinner or



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tickets to a local sporting event) and attendance at transaction closing celebrations are acceptable, provided that acceptance of such gifts, hospitality or entertainment and closing celebrations
would not reasonably be expected to create a conflict of interest. Directors should report gifts of a questionable nature to the President & CEO or Board Chairman and officers, employees, consultants and contractors should report gifts of a
questionable nature to their superior.

Except as contemplated herein, no Member shall offer or provide, either personally or on behalf of
Pengrowth, any expensive gifts, excessive entertainment or payments of any amount of money to any supplier, customer, sub-contractor, or competitor of Pengrowths, or to any public official or their representatives, nor pay to them, either
directly or indirectly, any commissions or fees which are excessive in relation to the services rendered. Modest gifts, favours and entertainment may be furnished by Members whose duties permit them to do so, provided all of the following tests are
met:



| | Ø |  | they are not in cash or securities and are of nominal value;
| | - |  | ------------------------------------------------------------



| | Ø |  | they do not contravene any law and are made as a matter of general and accepted practice or in accordance with corporate policy; and
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------



| | Ø |  | if subsequently disclosed to the public, they would not in any way embarrass Pengrowth or their recipients.
| | - |  | -----------------------------------------------------------------------------------------------------------

Political Contributions

Any political contribution made on behalf of Pengrowth shall comply with the following requirements:



| | (a) | any such contribution may only be made to a political party and not to an individual candidate for election to public office;
| | --- | -----------------------------------------------------------------------------------------------------------------------------



| | (b) | any such contribution requires the approval of the Chief Executive Officer; and
| | --- | -------------------------------------------------------------------------------



| | (c) | any such contribution must be within the approved operating budget of Pengrowth.
| | --- | --------------------------------------------------------------------------------

Contributions are deemed to include money, anything of value (e.g., loans, services or the use of Pengrowth facilities or assets) and time spent by employees during normal work hours away from work
responsibilities. Individual Members are free to make political contributions in their personal capacities.

Involvement
with Not-for-Profit Organizations

As a responsible community citizen, Pengrowth encourages and supports employee participation in
charitable, educational, cultural, political and not-for-profit organizations. Employees are reminded that such participation should not be of a nature or extent that it adversely affects an employees job performance or puts the employee in a
conflict of interest position (see Conflict of Interest above).

Outside Employment

Pengrowth recognizes that some employees may, from time to time, hold additional part-time



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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 puts the employee in a conflict of interest position (see Conflict of Interest above). All employees who hold management positions with Pengrowth shall obtain the approval of their
supervisor before accepting any such outside employment.

Directorships

Any officer or employee shall obtain the approval of the President and Chief Executive Officer prior to accepting a position as a director of a
for-profit company or business organization. The President and Chief Executive Officer shall obtain the approval of the Board of Directors prior to accepting a position as a director of a for-profit company or business organization. A director shall
advise the Board Chairman prior to accepting a position as a director of a for-profit company or business organization.

Government Relations

Pengrowth, as a company operating under federal and provincial regulations, must be sensitive to the interaction with public officials. All interaction
and communications between Members and public officials are to be conducted in the highest ethical manner and must not compromise the integrity or reputation of any public official, Pengrowth, its affiliates or its employees.

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.

The use or disclosure of confidential
information must be for company purposes only and not for personal benefit or the benefit of others. This applies to disclosure of confidential information concerning Pengrowth or its business activities as well as information with respect to
companies having business dealings with Pengrowth. To preserve confidentiality, disclosure and discussion of confidential information should be limited to those individuals who need to know the information.

Company 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 from their superiors.



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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 President and Chief Executive Officer, 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.

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 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.

Inside information is information which (1) has not been publicly released,
(2) is intended for use solely by Pengrowth and not for personal use, or (3) is the type usually not disclosed by Pengrowth. All individuals who come into possession of material inside information, before it is publicly disclosed, are
considered to be in a special relationship with Pengrowth for the purposes of securities laws. The husbands, wives, immediate families and those under control of insiders may also be regarded as being in a special relationship with Pengrowth.
Included in the concept of insider trading is tipping or revealing inside information to individuals to enable such individuals to trade in a companys securities on the basis of undisclosed information.

Members are responsible for being familiar with and abiding by all laws, regulations and rules respecting insiders and insider
trading. The various provincial securities legislation and business corporations acts impose certain liabilities upon every Member of Pengrowth, and any associate of such person, from using for their own benefit in connection with a trade in
securities of Pengrowth or any corporation in which it has an interest or business relationship, any inside information, including that which, if generally known, might reasonably be expected to affect materially the market price of shares or other
securities.

Pengrowths policy parallels the law in that all Members who receive inside information about Pengrowth, its associates,
affiliated companies and other companies in which it has an interest or business relationship, are in a position of trust and they must not trade in common shares or other securities on the basis of the information they possess, or otherwise make
use of the information for their own benefit or advantage until at such time as the information has been fully disclosed and a reasonable period of time has passed for the information to be disseminated.

Pengrowth has adopted the following rule in respect of trading in securities of Pengrowth by its Members:



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If you have knowledge of a material fact, pending change of fact, or
material change related to the affairs of Pengrowth or any public issuer involved in a transaction with Pengrowth which is not generally known, no purchase or sale may be made until the knowledge has been made public. In addition, this knowledge
must not be conveyed to any other person for the purpose of assisting that person in trading securities.

For purposes of this rule,
public issuer includes any issuer, whether a corporation or otherwise, whose securities are traded in a public market, whether on a stock exchange or over the counter. Material change or material fact is one which would be expected to
have a significant effect on the market price or value of any securities of a public issuer.

Pengrowth encourages Members to be
securityholders in Pengrowth as one way to more tangibly link shareholder interests with those of the Members. However, Members possessing inside information are expected to show integrity and use proper judgement in timing their investments. If in
doubt as to the propriety of actions, the Member should seek the advice of the President and Chief Executive Officer, Chief Financial Officer or General Counsel. Reference should be made to the Policy on Trading in Securitiesof Pengrowth
Energy Corporation.

Books of Account

Accurate, timely and reliable books of account and records are essential for effective management to ensure Pengrowth meets its business, legal and financial obligations. As a result, Members should
ensure all transactions with which they are involved are authorized and executed in accordance with Pengrowths procedures and that all transactions are completely and accurately accounted for and recorded.

Patents and Inventions

All 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 Chief Executive Officer.

Pengrowth and its Members honour the proprietary rights of others as expressed in patents, copyrights, trademarks and industrial design.

Community Relations

In
its business, Pengrowth and its Members come in contact with many members of the business and investment community, including individuals, community groups, public officials and members of the media. Pengrowth strives to maintain its good reputation
in the community and therefore needs to ensure that individuals speaking on behalf of Pengrowth recognize and deal with sensitive issues in an appropriate manner. 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



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management receiving such an enquiry is then required to refer the matter to either the President and Chief Executive Officer, Chief Financial Officer or General Counsel whereby such senior
officers will respond on behalf of Pengrowth. Reference should also be made to the Corporate Disclosure Policyof Pengrowth Energy Corporation.

Company Property and Opportunities

All Members are responsible for protecting
Pengrowths assets. Personal use of Pengrowths property, including investment and other business opportunities, is not permitted without specific authorization.

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. 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 directly to Grant Thornton LLP pursuant to
Appendix A to this document.

Employee Relations and Reporting

The continued success of Pengrowth is dependent on our employees, the work they perform, the ideas they contribute, and the ability, creativity and
initiative they bring to the organization.

In working together, Pengrowth Members must ensure they treat each other with respect, dignity,
honesty and fairness. Pengrowth is committed to providing opportunity for employees to be fully challenged, to develop their skills and abilities, and to reach their career goals.

In all matters related to the supervision and development of Members, including hiring, supervision, compensation, promotion and termination, no person will be discriminated against because of race,
religious beliefs, gender (including sexual harassment and pregnancy), sexual orientation, physical or mental disability, ancestry or place of origin.

All Members are encouraged to report any behaviour of other Members which they reasonably believe is illegal or unethical to the Director, Human Resources. Any suspected violation of this Code should be
reported directly to the chairman of the Corporate Governance and Nominating Committee or to Grant Thornton LLP pursuant to Appendix A. Reporting can be done on an anonymous basis if the person wishes to do so. No adverse action will be
taken against any individual for making a complaint or disclosing information in good faith, and 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.



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Policies, Procedures and Internal Controls

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 Committee. Exceptions to this Code are dealt with below under Exceptions and Changes.

Acknowledgement

It is
essential that all Members of Pengrowth understand and adhere to this Code.

All Members of Pengrowth 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 the Corporation and annually thereafter; (ii) in the case of officers and employees, upon the commencement of employment and annually thereafter, (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 and Changes

In very limited circumstances, exceptions may be made by Pengrowth
under this Code. Any exception proposed to be made under this Code shall be presented by the President and Chief Executive Officer to the Corporate Governance and Nominating Committee for its approval.

Any substantive change to this Code must be in writing, approved by the Board of Directors and signed by the President and Chief Executive Officer and
will be disclosed as required by applicable laws and regulations and listing standards.

Adopted by the Board of Directors of Pengrowth Energy
Corporation on December 16, 2010.



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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

Any director, officer or employee of Pengrowth Energy Corporation and its subsidiaries
(collectively, referred to herein as Pengrowth) may submit a complaint regarding accounting or auditing matters to the management of Pengrowth without fear of dismissal or retaliation of any kind. Pengrowth is committed to
achieving compliance with all applicable securities laws and regulations, accounting standards, accounting controls and audit practices. The Audit Committee of Pengrowth will oversee treatment of employee concerns in this area.

Any director, officer, employee, consultant or contractor of Pengrowth may submit a complaint regarding a suspected violation of the Code of Business
Conduct and Ethics to the management of Pengrowth without fear of dismissal or retaliation of any kind. The Governance Committee of Pengrowth will oversee treatment of employee concerns in this area.

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 (Conduct Matters); and (iii) the confidential, anonymous submission by directors, officers and employees of concerns regarding questionable Accounting
Matters and Conduct Matters.

Receipt of Complaints



| |  |  | Directors, officers and employees with concerns regarding an Accounting Matter may report their concerns to the chairman of the Audit Committee.
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Directors, officers, employees, consultants or contractors with concerns regarding a Conduct Matter may report their concerns to the chairman of the
Corporate Governance and Nominating Committee.
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Directors, officers and employees 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.
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | A director, officer or employee who makes an anonymous submission must be sure to provide sufficient detail to identify the concern being raised.
Because the submission is made anonymously, the Audit 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 complaint should, at a minimum, contain
dates, places, persons involved and witnesses such that a reasonable investigation or assessment can be conducted.
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

Scope
of Accounting Matters Covered by These Procedures

These procedures relate to director, officer or employee 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 shall inform (i) the chairman of the Audit Committee of all complaints and concerns provided to it in respect of Accounting
Matters; and (ii) the chairman 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 chairman of the Audit Committee or chairman 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 Committee, outside legal counsel or such other persons as the Audit 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 persons 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.
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Prompt and appropriate corrective action will be taken when and as warranted in the judgment of the Audit Committee or the Corporate Governance and
Nominating Committee, as the case may be.
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Pengrowth will not discharge, demote, suspend, threaten, harass or in any manner discriminate against any individual in the terms and conditions of
employment based upon any lawful actions of such individual with respect to reporting of complaints in good faith regarding any Accounting Matter or any Conduct Matter.
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Pengrowth will regard the making of any deliberately false or malicious allegations by an employee as a serious offence which may result in
recommendations to the Board of Directors or to senior management of Pengrowth for disciplinary action including dismissal for cause and, if warranted, legal proceedings.
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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Reporting and Retention of Complaints and Investigations



| |  |  | The chairman of the Audit Committee and the chairman 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 Committee or the Corporate Governance and Nominating Committee, as the case may be.
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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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)

1.

2.

(If required, provide additional details on separate sheet).



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