EXHIBIT 99.1

PENGROWTH ENERGY CORPORATION

2013 ANNUAL INFORMATION FORM

February 28, 2014

TABLE OF CONTENTS

GLOSSARY OF TERMS AND ABBREVIATIONS	1
CONVERSION	4
PRESENTATION OF OUR FINANCIAL INFORMATION	5
PRESENTATION OF OUR RESERVE AND RESOURCE INFORMATION	5
FORWARD-LOOKING STATEMENTS	5
PENGROWTH ENERGY CORPORATION	7
Introduction	7
General Development of the Business	7
DESCRIPTION OF OUR BUSINESS	8
General	8
Business Strategy	8
OPERATIONAL INFORMATION	9
Principal Producing Properties	9
Statement of Oil and Gas Reserves and Reserves Data	10
Additional Information Relating to Reserves Data	18
Future Development Costs	19
Finding, Development and Acquisition Costs	19
Recycle Ratio	21
Reserve Life Index (RLI)	22
Reserve Replacement	22
Other Oil and Gas Information	22
Forward Contracts	26
Additional Information Concerning Abandonment & Reclamation Costs	26
Tax Horizon	27
Costs Incurred	27
Exploration and Development Activities	27
Production Estimates	27
Production History (Netback)	28
DESCRIPTION OF CAPITAL STRUCTURE	28
DIVIDENDS	29
General	29
Historical Distributions/Dividends	29
Restrictions on Dividends	30
ABCA Solvency Tests	30
Revolving Credit Facility	30
Senior Unsecured Notes	31
INDUSTRY CONDITIONS	32
Pricing and Marketing	32
The North American Free Trade Agreement	32
Royalties and Incentives	33
Land Tenure	37
Environmental Regulation	37
Liability Management Rating Programs	39

(Cover photo: Lindbergh Pilot Project Facility)

Climate Change Regulation	40
General Discussion	41
RISK FACTORS	42
MARKET FOR SECURITIES	53
DIRECTORS AND OFFICERS	54
Corporate Cease Trade Orders, Bankruptcies, Personal Bankruptcies, Penalties or Sanctions	55
AUDIT AND RISK COMMITTEE	56
Principal Accountant Fees and Services	56
Pre-approval Policies and Procedures	57
CONFLICTS OF INTEREST	57
LEGAL PROCEEDINGS	57
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	59
DISCLOSURE PURSUANT TO THE REQUIREMENTS OF THE NEW YORK STOCK EXCHANGE	59
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, 2013.

GLOSSARY OF TERMS AND ABBREVIATIONS

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

Corporate

"6.25% Series A Convertible Debentures" means the $115 million original aggregate principal amount of 6.25 percent convertible unsecured subordinated debentures of the Corporation due December 31, 2014, which are convertible at the option of the holder, at any time, into fully paid Common Shares at a conversion price of $19.186 per Common Share;

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

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

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

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

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

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

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

"2010 Senior Notes" means US$187 million of senior unsecured notes issued under the 2010 Note Purchase Agreements;

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

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

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

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

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

"Common Shares" means our common shares;

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

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

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

"NAL Energy" means NAL Energy Corporation;

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

"Shareholders" means holders of Common Shares;

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

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

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

PENGROWTH ENERGY CORPORATION ANNUAL INFORMATION FORM | 1

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

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

Engineering

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

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

"Contingent Resources" are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. Contingencies may include factors such as economic, legal, environmental, political and regulatory matters or a lack of markets. Contingent Resources do not constitute, and should not be confused with, reserves;

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

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

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

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

"GLJ Report" refers to the report prepared by GLJ, dated February 27, 2014 with an effective date of December 31, 2013;

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Abbreviations

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

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

"API" refers to the American Petroleum Institute;

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

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

"bbl/d" refers to barrels per day;

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

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

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

"Cdn$" refers to Canadian dollars;

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

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

"EIA"refers to Environmental Impact Assessment;

"EOR" refers to enhanced oil recovery;

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

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

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

"GHG" refers to greenhouse gas;

"H₂S" refers to hydrogen sulphide gas;

"IFRS" refers to International Financial Reporting Standards;

"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;

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

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

"NGL" refers to natural gas liquids;

"NYSE" refers to the New York Stock Exchange;

"SAGD" refers to steam assisted gravity drainage;

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

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

"TSX" refers to the Toronto Stock Exchange;

"US$" refers to United States dollars;

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

"WCS" refers to Western Canada Select;

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

"WTI" refers to West Texas Intermediate crude oil.

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

CONVERSION

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

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

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PRESENTATION OF OUR FINANCIAL INFORMATION

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

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

PRESENTATION OF OUR RESERVE AND RESOURCE INFORMATION

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

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

FORWARD-LOOKING STATEMENTS

This Annual Information Form contains forward-looking statements within the meaning of securities laws, including the "safe harbour" provisions of Canadian securities legislation and the United States Private Securities Litigation Reform Act of 1995. Forward-looking information is often, but not always, identified by the use of words such as "anticipate", "believe", "expect", "plan", "intend", "forecast", "target", "project", "guidance", "may", "will", "should", "could", "estimate", "predict" or similar words suggesting future outcomes or language suggesting an outlook. Forward-looking statements in this Annual Information Form include, but are not limited to: business strategy and strengths, goals, focus and the effects thereof, acquisition criteria, capital expenditures, reserves, resources, reserve life indices, estimated production, production additions from our 2014 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, return of bank debt covenants to original levels after December 31, 2015, contribution of expected Lindbergh production to EBITDA and expiring acreage. Statements relating to reserves and resources are forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions that the reserves and resources described exist in the quantities predicted or estimated and can profitably be produced in the future.

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

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

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party operators; unforeseen title defects; fluctuations in foreign currency and exchange rates; inadequate insurance coverage; counterparty risk; compliance with environmental laws and regulations; changes in tax and royalty laws; our ability to access external sources of debt and equity capital; and the implementation of GHG emissions legislation. Further information regarding these factors may be found under the heading "Risk Factors" in this Annual Information Form, under the heading "Business Risks" in our Management's Discussion and Analysis for the year ended December 31, 2013, and in our most recent 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 amalgamated with its wholly-owned subsidiaries NAL Energy, NAL Properties Inc. and NAL Canada West Inc. on January 1, 2013. The Corporation originally acquired NAL Energy on May 31, 2012 and the results and information contained in this Annual Information Form include results and information pertaining to NAL Energy from that date. The Corporation is also the successor to the Trust, following the completion of the conversion of the Trust from an income trust to a corporate structure pursuant to the Arrangement which was completed on January 1, 2011. Pursuant to the Arrangement, on December 31, 2010, Unitholders of the Trust exchanged their Trust Units for Common Shares on a one for one (1:1) basis. At the same time, holders of Exchangeable Shares received 1.02308 Common Shares for each Exchangeable Share held. See "General Development of the Business of the Corporation – Recent Developments".

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

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

GENERAL DEVELOPMENT OF THE BUSINESS

Recent Developments

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

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

Three Year Historical Overview

2013

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

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

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

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

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

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

2012

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

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

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

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

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

2011

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

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

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

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

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

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

DESCRIPTION OF OUR BUSINESS

GENERAL

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

As at December 31, 2013, we had 539 permanent employees.

BUSINESS STRATEGY

Our corporate strategy is to use funds flow from our existing non-thermal operations to sustain our current dividend and to fund a portfolio of thermal oil assets with low declines, strong capital efficiencies and long reserve lives aimed at supporting production growth and long-term stable dividend payout.

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

For 2014, we have established a $700-$730 million capital spending level that retains significant flexibility in an uncertain commodity price environment. Included in this budget is $365 million for expenditures related to the first commercial phase of our Lindbergh project which is anticipated to produce 12,500 bbl/d of bitumen commencing in early 2015. We prioritize our capital investments based on:

• recycle ratio;

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

• rate of return of future cash flows;

• potential for continued, repeatable and scalable development; and

• investments necessary to maintain existing facilities and wells.

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

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OPERATIONAL INFORMATION

PRINCIPAL PRODUCING PROPERTIES

The following table summarizes our principal producing properties as of December 31, 2013 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, 2013. The table also contains our average daily production of oil, natural gas and NGL for the year ended December 31, 2013.

Summary of Company Interest at December 31, 2013⁽¹⁾ (Forecast Prices and Costs)⁽²⁾ 

		Remaining	P+P	P+P Value
	P+P	Reserve	Reserve	Before Tax	2013 Oil	2013 Gas	2013 NGL	2013 Total
	Reserves	Life	Life Index	at 10% DR(4)	Production	Production	Production	Production
Field	Mboe(3)	years	years	$MM	bbl/d	MMcf/d	bbl/d	BOE/d(3)
Lindbergh	142,565	37	246.8	1,020	1,846	-	-	1,846
Swan Hills Area	75,989	50	13.8	1,272	10,475	15.7	3,459	16,543
Greater Olds/Garrington Area	71,549	50	10.6	1,010	4,977	51.7	3,817	17,404
Subtotal	290,103	50	22.5	3,302	17,298	67.3	7,276	35,793
Remainder(5)	187,282	50	12.9	1,846	18,118	164.5	3,199	48,734
Total	477,385	50	17.4	5,148	35,416	231.8	10,476	84,527

Notes:

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

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

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

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

(5) "Remainder" includes our Working Interests and Royalty Interests in approximately 120 other properties.

Lindbergh

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

We began steam injection into the SAGD pilot project in early February 2012 and results have outperformed expectations since that time. The pilot, which consists of two well pairs, has been producing for two years and, as of February 1, 2014, was producing approximately 1,900 bbl/d of bitumen, with an ISOR of approximately 2.0. The two well pair pilot has produced approximately one million bbl of bitumen as of December 31, 2013.

The excellent pilot results and associated reserve potential have provided us with the confidence needed to accelerate and expand the first phase of commercial development. On January 10, 2013, our Board of Directors approved the first phase of Lindbergh commercial development, which is expected to reach 12,500 bbl/d of bitumen in early 2015.

In July of 2013, the project received regulatory approval to proceed under the EPEA application number 1713445. Once surface dispositions were received, civil construction commenced in August preparing leases and roads for the project. SAGD drilling and mechanical construction activities began in September. At December 31, 2013, the commercial project remained on time and on budget with construction and drilling well underway. First steam from the commercial project is anticipated in the fourth quarter of 2014.

Two additional expansion phases are expected to increase total Lindbergh production to 50,000 bbl/d of bitumen by 2018. The EIA application for the first of these expansions to 30,000 bbl/d was submitted in December 2013. Approval for the expansion is anticipated in the first quarter of 2016.

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

Swan Hills Area

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

PENGROWTH ENERGY CORPORATION ANNUAL INFORMATION FORM | 9

The two major operated properties in the area are:

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

• Carson Creek is comprised of two Pengrowth operated units (one oil and one natural gas) covering approximately 46,200 acres. The Carson Creek North Beaverhill Lake Unit No. 1, in which we have an 89.1 percent Working Interest, was discovered in 1958 and the current waterflood was initiated in 1964. The Carson Creek Beaverhill Lake Unit No. 1, in which we have a 95.1 percent Working Interest, was discovered in 1958.

In 2013, $63 million (net) was spent on light oil plays in this area. Key focuses were further miscible flood development and waterflood optimization. Pengrowth drilled a total of six operated wells (4.7 net) at Judy Creek, Deer Mountain, and Virginia Hills. These were split between produced water injectors (2) and oil producers (4). Drilling also occurred in the partner-operated properties where we participated in six oil wells (1.2 net) at House Mountain unit and non-unit.

Greater Olds/Garrington Area

Our Olds property is located 95 kilometres north of Calgary, Alberta. Our interests in this area include a 100 percent ownership in the Olds Gas Field Unit No. 1. In addition, we have a 74 percent average Working Interest in the adjacent non-unit reserves. The Olds unit produces sour natural gas from the Wabamun Formation, with H₂S concentrations ranging from less than one percent to 35 percent. The non-unit reserves are contained within formations from the Wabamun to the Edmonton group, and are predominantly sweet natural gas.

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

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

In 2014, we plan to spend approximately $200 million continuing to develop the Cardium play in the Greater Olds/Garrington Area. We have a large contiguous land base in this area with over 500 gross sections with Cardium rights, averaging approximately 50 percent Working Interest. In addition to the Cardium, other zones of interest in the area include the liquids-rich Mannville and Elkton formations. In 2013, we spent $205.4 million in the Olds/Garrington area on activities targeting the Cardium, Mannville, and Elkton plays, drilling 81 gross wells (47.5 net) during the year.

The bulk of our drilling activity is currently focused on developing Cardium oil production in the Lochend and Garrington areas. Our drilling and completion expertise in these areas continues to deliver results that exceed type curve expectations.

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

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, 2013 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, 2013 and the preparation date is January 21, 2014 when the final information was provided. The information in this section summarizes our oil, liquids and natural gas reserves and the net present values of Future Net Revenue for these reserves using GLJ's forecast prices and costs and constant prices and costs. We engaged GLJ to provide an independent evaluation of Proved Reserves and Proved Plus Probable Reserves and no attempt was made to evaluate Possible Reserves in our non-thermal properties. It is our practice to obtain an engineering report evaluating all of our Proved Reserves and Probable Reserves as at December 31 of each year. Only in respect of the Lindbergh oil sands property and the Groundbirch natural gas property did GLJ evaluate Possible Reserves and Contingent Resources. All of our reserves are in Canada in the provinces of Alberta, British Columbia, Saskatchewan and Nova Scotia. In certain instances in this Annual Information Form, we have presented estimates of reserves, Future Net Revenue and Contingent Resources for individual properties. The estimates of reserves, Future Net Revenue and Contingent Resources for individual properties may not reflect the same confidence level as estimates of reserves, Future Net Revenue and Contingent Resources for all properties, due to the effects of aggregation.

10 | ANNUAL INFORMATION FORM

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, 2013 contained in the GLJ Report. These tables summarize the data contained in the GLJ Report, and, as a result, may contain slightly different numbers than the GLJ Report due to rounding. Columns may not add due to rounding.

Our Future Net Revenues associated with the production and reserves contained in this Annual Information Form reflect the royalty programs in-place on December 31, 2013.

The information set forth below is derived from the GLJ Report, which has been prepared in accordance with the standards contained in the Canadian Oil and Gas Evaluation ("COGE") Handbook and the reserves definitions contained in NI 51-101 and the COGE Handbook. The GLJ Report incorporates estimates of future well abandonment obligations but does not include estimates of remediation costs. The GLJ forecasts of Future Net Revenue are stated prior to any provision for income taxes, interest costs or general and administrative costs and after the deduction of estimated future capital expenditures for wells to which reserves have been assigned. The estimated Future Net Revenue shown below does not represent the fair market value of the properties. There is no assurance that such price and cost assumptions will be attained and variances could be material. The recovery and estimates of crude oil, NGL and natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual crude oil, NGL and natural gas reserves may be greater than or less than the estimates provided herein.

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

• Corporate income tax at the current legislated rate;

• Annual general and administrative expenses at the current rate;

• Interest expense at the current rate;

• Tax pool deductions utilizing our existing $3.7 billion of tax pools and forecasted additions to our tax pools from capital expenditures as forecast by GLJ; and

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

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

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

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

PENGROWTH ENERGY CORPORATION ANNUAL INFORMATION FORM | 11

Reserves Data (Forecast Prices and Costs)

Summary of Oil and Gas Reserves as of December 31, 2013
(Forecast Prices and Costs)⁽¹⁾ 

	Light and Medium Oil			Heavy Oil			Bitumen			Natural Gas Liquids
	Company Interest	Gross Interest	Net Interest	Company Interest	Gross Interest	Net Interest	Company Interest	Gross Interest	Net Interest	Company Interest	Gross Interest	Net Interest
Reserves Category	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)
Proved Reserves
Proved Developed Producing	57,926	57,824	46,508	13,273	13,267	11,426	1,304	1,304	1,214	23,587	23,546	16,953
Proved Developed Non-Producing	596	596	502	83	83	67	-	-	-	449	448	341
Proved Undeveloped	14,771	14,771	11,899	5,955	5,954	4,906	80,423	80,423	65,392	1,306	1,306	1,047
Total Proved Reserves	73,293	73,191	58,908	19,311	19,304	16,399	81,727	81,727	66,606	25,342	25,300	18,341
Probable Reserves	30,180	30,150	23,434	10,884	10,882	8,903	60,838	60,838	45,599	9,749	9,736	7,137
Total Proved Plus Probable Reserves	103,473	103,340	82,342	30,196	30,186	25,301	142,565	142,565	112,205	35,091	35,036	25,478

	Natural Gas			Coal Bed Methane			Total Oil Equivalent Basis(2)
	Company Interest	Gross Interest	Net Interest	Company Interest	Gross Interest	Net Interest		Company Interest	Gross Interest	Net Interest
Reserves Category	(MMcf)	(MMcf)	(MMcf)	(MMcf)	(MMcf)	(MMcf)		(Mboe)	(Mboe)	(Mboe)
Proved Reserves
Proved Developed Producing	516,980	514,949	443,767	20,930	20,653	19,316		185,743	185,208	153,281
Proved Developed Non-Producing	18,006	17,882	14,912	658	658	625		4,238	4,217	3,500
Proved Undeveloped	65,000	64,999	57,486	22,481	22,410	19,307		117,035	117,022	96,042
Total Proved Reserves	599,986	597,830	516,165	44,069	43,720	39,248		307,016	306,446	252,823
Probable Reserves	340,071	339,385	292,276	12,238	12,150	10,961		170,369	170,195	135,612
Total Proved Plus Probable Reserves	940,056	937,215	808,441	56,307	55,870	50,208		477,385	476,642	388,435

Notes:

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

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

Summary of Net Present Value of Future Net Revenue as of December 31, 2013
Before and After Income Taxes (Forecast Prices and Costs)⁽¹⁾ 

	Before Income Taxes Discounted at (%/year) - $MM										Unit Value Before Income Tax Discounted at 10%/year(2) (3)
Reserves Category	0	%	5	%	10	%	15	%	20	%	$/BOE	$/McfGE
Proved Reserves
Proved Developed Producing	4,369		3,358		2,742		2,333		2,043		17.89	2.98
Proved Developed Non-Producing	80		52		38		30		24		10.89	1.82
Proved Undeveloped	2,952		1,719		1,052		661		416		10.95	1.82
Total Proved Reserves	7,401		5,129		3,832		3,024		2,483		15.16	2.53
Probable Reserves	5,372		2,392		1,316		841		593		9.70	1.62
Total Proved Plus Probable Reserves	12,774		7,521		5,148		3,865		3,076		13.25	2.21

	After Income Taxes Discounted at (%/year)(4) - $MM
Reserves Category	0	%	5	%	10	%	15	%	20	%
Proved Reserves
Proved Developed Producing	4,341		3,344		2,734		2,329		2,040
Proved Developed Non-Producing	61		43		34		28		23
Proved Undeveloped	2,131		1,278		799		508		320
Total Proved Reserves	6,533		4,665		3,567		2,864		2,383
Probable Reserves	3,863		1,729		962		624		447
Total Proved Plus Probable Reserves	10,396		6,394		4,529		3,488		2,829

Notes:

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

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

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

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

12 | ANNUAL INFORMATION FORM

Additional Information Concerning Future Net Revenue (undiscounted) as of December 31, 2013(Forecast Prices and Costs)⁽¹⁾ ($MM)

Reserves Category	Revenue	Royalties(2)	Operating Costs	Development Costs	Abandonment Costs(3)	Future Net Revenue Before Income Taxes	Income Tax	Future Net Revenue After Income Taxes
Total Proved	20,918	3,788	7,371	2,001	357	7,401	868	6,533
Total Proved Plus Probable	34,587	6,763	11,254	3,382	415	12,774	2,378	10,396

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.

(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 ConcerningAbandonment & Reclamation Costs".

Net Present Value of Future Net Revenue By Production Group as of December 31, 2013
(Forecast Prices and Costs)⁽¹⁾ 

		Future Net Revenue Before Income Taxes	Unit Value(4)(5)
Reserves Category	Production Group	(discounted at 10%/year) ($MM)	($/BOE)	($/McfGE)
Total Proved	Light and Medium Crude Oil (including solution gas and other by-products)(2)	1,808	23.74	3.96
	Heavy Oil (including solution gas and other by-products)(2)	344	20.19	3.36
	Bitumen	748	11.22	1.87
	Natural Gas (including by-products but excluding solution gas from oil wells)(3)	896	10.37	1.73
	Non-conventional Oil & Gas Activities	36	5.44	0.91
	Total	3,832	15.16	2.53
Total Proved Plus Probable	Light and Medium Crude Oil (including solution gas and other by-products)(2)	2,332	21.89	3.65
	Heavy Oil (including solution gas and other by-products)(2)	501	19.28	3.21
	Bitumen	1,021	9.09	1.52
	Natural Gas (including by-products but excluding solution gas from oil wells)(3)	1,246	9.21	1.53
	Non-conventional Oil & Gas Activities	48	5.72	0.95
	Total	5,148	13.25	2.21

Notes:

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

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

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

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

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

PENGROWTH ENERGY CORPORATION ANNUAL INFORMATION FORM | 13

Reserves Data (Constant Prices and Costs)

Summary of Oil and Gas Reserves as of December 31, 2013
(Constant Prices and Costs)⁽¹⁾ 

	Light and Medium Oil			Heavy Oil			Bitumen			Natural Gas Liquids
	Company Interest	Gross Interest	Net Interest	Company Interest	Gross Interest	Net Interest	Company Interest	Gross Interest	Net Interest	Company Interest	Gross Interest	Net Interest
Reserves Category	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)
Proved Reserves
Proved Developed Producing	58,780	58,678	48,520	13,301	13,294	11,601	1,261	1,261	1,180	22,426	22,387	16,139
Proved Developed Non-Producing	590	590	513	83	83	69	-	-	-	425	424	323
Proved Undeveloped	14,820	14,820	12,142	5,927	5,926	4,930	80,466	80,466	68,135	1,206	1,206	968
Total Proved Reserves	74,189	74,088	61,175	19,311	19,303	16,600	81,727	81,727	69,315	24,057	24,017	17,431
Probable Reserves	30,288	30,257	24,676	10,832	10,831	9,005	60,838	60,838	49,021	9,067	9,055	6,657
Total Proved Plus Probable Reserves	104,477	104,345	85,852	30,143	30,134	25,605	142,565	142,565	118,335	33,124	33,072	24,088

	Natural Gas			Coal Bed Methane			Total Oil Equivalent Basis(2)
	Company Interest	Gross Interest	Net Interest	Company Interest	Gross Interest	Net Interest	Company Interest	Gross Interest	Net Interest
Reserves Category	(MMcf)	(MMcf)	(MMcf)	(MMcf)	(MMcf)	(MMcf)	(Mboe)	(Mboe)	(Mboe)
Proved Reserves
Proved Developed Producing	462,495	460,823	404,183	16,039	15,816	14,811	175,523	175,061	147,273
Proved Developed Non-Producing	12,962	12,891	11,145	602	602	572	3,358	3,345	2,858
Proved Undeveloped	61,793	61,792	55,793	9,655	9,621	8,503	114,326	114,319	96,891
Total Proved Reserves	537,249	535,506	471,120	26,295	26,039	23,886	293,207	292,725	247,022
Probable Reserves	305,429	304,870	269,235	11,514	11,447	10,072	163,849	163,700	135,910
Total Proved Plus Probable Reserves	842,678	840,376	740,356	37,809	37,486	33,958	457,056	456,426	382,932

Notes:

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

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

Summary of Net Present Value of Future Net Revenue as of December 31, 2013Before and After Income Taxes (Constant Prices and Costs)⁽¹⁾ 

	Before Income Taxes Discounted at (%/year) - $MM										Unit Value Before Income Taxes Discounted at 10%/year(2)(3)
Reserves Category	0	%	5	%	10	%	15	%	20	%	$/BOE	$/McfGE
Proved Reserves
Proved Developed Producing	3,482		2,717		2,244		1,926		1,698		15.24	2.54
Proved Developed Non-Producing	48		34		25		20		16		8.87	1.48
Proved Undeveloped	2,235		1,297		779		471		276		8.04	1.34
Total Proved Reserves	5,766		4,047		3,048		2,417		1,990		12.34	2.06
Probable Reserves	3,372		1,609		931		614		441		6.85	1.14
Total Proved Plus Probable Reserves	9,138		5,656		3,979		3,031		2,431		10.39	1.73

	After Income Taxes Discounted at (%/year)(4)  - $MM
Reserves Category	0	%	5	%	10	%	15	%	20	%
Proved Reserves
Proved Developed Producing	3,480		2,714		2,243		1,925		1,697
Proved Developed Non-Producing	48		33		25		20		16
Proved Undeveloped	1,841		1,109		684		421		248
Total Proved Reserves	5,369		3,857		2,952		2,366		1,962
Probable Reserves	2,486		1,214		726		495		367
Total Proved Plus Probable Reserves	7,855		5,071		3,678		2,861		2,329

Notes:

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

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

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

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

14 | ANNUAL INFORMATION FORM

Additional Information Concerning Future Net Revenue (undiscounted) as of December 31, 2013
(Constant Prices and Costs)⁽¹⁾ ($MM)

Reserves Category	Revenue	Royalties(2)	Operating Costs	Development Costs	Abandonment Costs(3)	Future Net Revenue Before Income Taxes	Income Tax	Future Net Revenue After Income Taxes
Total Proved	16,454	2,643	5,993	1,768	284	5,766	397	5,369
Total Proved Plus Probable	25,044	4,214	8,632	2,755	305	9,138	1,283	7,855

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.

(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 ConcerningAbandonment & Reclamation Costs".

Net Present Value of Future Net Revenue By Production Group as of December 31, 2013
(Constant Prices and Costs)⁽¹⁾ 

		Future Net Revenue Before Income Taxes	Unit Value(4)(5)
Reserves Category	Production Group	(discounted at 10%/year) ($MM)	($/BOE)	($/McfGE)
Total Proved	Light and Medium Crude Oil (including solution gas and other by-products)(2)	1,658	21.08	3.51
	Heavy Crude Oil (including solution gas and other by-products)(2)	307	17.82	2.97
	Bitumen	567	8.18	1.36
	Natural Gas (including by-products but excluding solution gas from oil wells)(3)	506	6.50	1.08
	Non-conventional Oil & Gas Activities	10	2.59	0.43
	Total	3,048	12.34	2.06
Total Proved Plus Probable	Light and Medium Crude Oil (including solution gas and other by-products)(2)	2,111	19.14	3.19
	Heavy Crude Oil (including solution gas and other by-products)(2)	439	16.65	2.77
	Bitumen	749	6.32	1.05
	Natural Gas (including by-products but excluding solution gas from oil wells)(3)	668	5.46	0.91
	Non-conventional Oil & Gas Activities	13	2.35	0.39
	Total	3,979	10.39	1.73

Notes:

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

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

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

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

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

PENGROWTH ENERGY CORPORATION ANNUAL INFORMATION FORM | 15

Pricing Assumptions

Forecast Prices used in Estimates

The forecast price and cost assumptions assume the continuance of current laws and regulations and changes in wellhead selling prices, and take into account forecasted two percent annual inflation with respect to future operating and capital costs. The forecast prices are provided in the table below and reflect GLJ's January 1, 2014 price forecast as referred to in the GLJ Report.

	Oil						Natural Gas	Natural Gas Liquids(1)
	WTI Cushing Oklahoma	Edmonton Par Price 40°API	Cromer Medium 29.3°API	WCS Stream Quality	Hardisty Heavy 12°API	Lindbergh Bitumen Wellhead Calculated(5)	AECO Gas Price	Propane	Butane	Pentanes Plus	Inflation Rates(2)	Exchange Rate(3)
Year	(US$/bbl)	(Cdn$/bbl)	(Cdn$/bbl)	(Cdn$/bbl)	(Cdn$/bbl)	(Cdn$/bbl)	(Cdn$/MMBtu)	(Cdn$/bbl)	(Cdn$/bbl)	(Cdn$/bbl)	(%/year)	(US$/Cdn$)
2013(4)	97.88	93.33	88.05	74.91	65.07	68.44	3.24	38.49	68.65	104.40	1.0	0.97
2014	97.50	92.76	86.27	75.60	65.72	64.83	4.03	57.83	73.22	105.20	2.0	0.95
2015	97.50	97.37	90.55	79.36	70.03	65.61	4.26	58.42	75.95	107.11	2.0	0.95
2016	97.50	100.00	93.00	81.50	72.85	68.54	4.50	60.00	78.00	107.00	2.0	0.95
2017	97.50	100.00	93.00	81.50	72.85	68.54	4.74	60.00	78.00	107.00	2.0	0.95
2018	97.50	100.00	93.00	81.50	72.85	68.54	4.97	60.00	78.00	107.00	2.0	0.95
2019	97.50	100.00	93.00	81.50	72.85	68.54	5.21	60.00	78.00	107.00	2.0	0.95
2020	98.54	100.77	93.71	82.13	73.42	69.10	5.33	60.46	78.60	107.82	2.0	0.95
2021	100.51	102.78	95.58	83.76	74.90	70.55	5.44	61.67	80.17	109.97	2.0	0.95
2022	102.52	104.83	97.49	85.44	76.42	72.04	5.55	62.90	81.77	112.17	2.0	0.95
2023	104.57	106.93	99.44	87.14	77.97	73.56	5.66	64.16	83.40	114.41	2.0	0.95
thereafter	+2%/yr	+2%/yr	+2%/yr	+2%/yr	+2%/yr	+2%/yr	+2%/yr	+2%/yr	+2%/yr	+2%/yr	2.0	0.95

Notes:

(1) FOB Edmonton.

(2) Inflation rates for forecasting prices and costs.

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

(4) Actual average historical prices for 2013.

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

Constant Prices used in Estimates

The constant price assumptions assume the continuance of current laws, regulations and operating costs in effect on the date of the GLJ Report. Product prices were determined from the actual prices on the first day of each month during 2013 and were not escalated. In addition to the product prices, operating and capital costs have no inflationary increase. The constant prices are as follows:

Oil

Natural Gas

Natural Gas Liquids(1)

WTI Cushing Oklahoma

Edmonton Par Price 40°API

Cromer Medium 29.3°API

WCS Stream Quality

Hardisty Heavy 12°API

Lindbergh Bitumen Wellhead Calculated(3)

AECO Gas Price

Propane

Butane

Pentanes Plus

Inflation Rates(2)

Exchange Rate(3)

Year

(US$/bbl)

(Cdn$/bbl)

(Cdn$/bbl)

(Cdn$/bbl)

(Cdn$/bbl)

(Cdn$/bbl)

(Cdn$/MMBtu)

(Cdn$/bbl)

(Cdn$/bbl)

(Cdn$/bbl)

(%/year)

(US$/Cdn$)

2014 and thereafter

96.67

93.12

86.10

74.87

64.51

63.62

3.15

36.78

68.34

105.09

0.0

0.9714

Notes:

(1) FOB Edmonton.

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

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

16 | ANNUAL INFORMATION FORM

Reserves Reconciliation

The following tables provide a reconciliation of our gross reserves of crude oil, bitumen, natural gas and NGL for the year ended December 31, 2013, presented using forecast prices and costs. All reserves are located in Canada.

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

	Light and Medium Oil			Heavy Oil			Bitumen			Natural Gas Liquids
	Proved	Probable	Proved Plus Probable	Proved	Probable	Proved Plus Probable	Proved	Probable	Proved Plus Probable	Proved	Probable	Proved Plus Probable
	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)
December 31, 2012	107,598	45,330	152,928	21,676	10,971	32,646	12,789	82,003	94,792	28,378	11,241	39,619
Technical Revisions	242	(2,472)	(2,230)	834	(1,128)	(294)	324	(52)	272	1,351	(384)	967
Economic Factors	(10)	(47)	(57)	(23)	(14)	(37)	-	-	-	(40)	(55)	(95)
Discoveries	-	-	-	-	-	-	-	-	-	-	-	-
Extensions	2,456	424	2,879	632	1,648	2,281	69,288	(21,112)	48,176	672	297	969
Infill Drilling	2,922	754	3,676	-	-	-	-	-	-	306	(19)	286
Improved Recovery	30	39	69	-	-	-	-	-	-	14	9	23
Acquisitions	311	97	409	61	15	76	-	-	-	150	33	183
Dispositions	(30,545)	(13,975)	(44,520)	(1,500)	(610)	(2,110)	-	-	-	(1,718)	(1,386)	(3,104)
Production	(9,812)	-	(9,812)	(2,376)	-	(2,376)	(674)	-	(674)	(3,813)	-	(3,813)
December 31, 2013	73,191	30,150	103,340	19,304	10,882	30,186	81,727	60,838	142,565	25,300	9,736	35,036

	Natural Gas			Coal Bed Methane			Total Oil Equivalent Basis(1)
	Proved	Probable	Proved Plus Probable	Proved	Probable	Proved Plus Probable	Proved	Probable	Proved Plus Probable
	(MMcf)	(MMcf)	(MMcf)	(MMcf)	(MMcf)	(MMcf)	(Mboe)	(Mboe)	(Mboe)
December 31, 2012	726,497	360,126	1,086,623	46,364	12,537	58,901	299,251	211,655	510,906
Technical Revisions	12,257	(3,881)	8,376	309	(409)	(100)	4,845	(4,750)	95
Economic Factors	(2,153)	(1,683)	(3,836)	(255)	22	(233)	(474)	(393)	(867)
Discoveries	-	-	-	-	-	-	-	-	-
Extensions	10,904	30,107	41,012	-	-	-	74,865	(13,725)	61,140
Infill Drilling	4,578	(526)	4,052	-	-	-	3,990	647	4,637
Improved Recovery	237	263	500	-	-	-	83	91	174
Acquisitions	1,759	413	2,172	-	-	-	816	214	1,030
Dispositions	(74,935)	(45,435)	(120,370)	-	-	-	(46,253)	(23,543)	(69,796)
Production	(81,314)	-	(81,314)	(2,698)	-	(2,698)	(30,677)	-	(30,677)
December 31, 2013	597,830	339,385	937,215	43,720	12,150	55,870	306,446	170,196	476,642

Note:

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

At December 31, 2013, Company Interest Total Proved Plus Probable Reserves at forecast prices and costs were 477.4 MMboe as compared to 512.0 MMboe reported at year end 2012. The following additional GLJ reserves reconciliation is presented for year end December 31, 2013.

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

	Proved Developed Producing Reserves	Total Proved Reserves	Total Proved Plus Probable Reserve
December 31, 2012	237,685	300,078	511,960
Technical Revisions	8,545	4,943	181
Economic Factors	(509)	(473)	(870)
Extensions	5,309	74,869	61,144
Infill Drilling	2,993	3,991	4,639
Improved Recovery	75	83	174
Acquisitions	611	816	1,030
Dispositions	(38,114)	(46,439)	(70,020)
Production	(30,852)	(30,852)	(30,852)
December 31, 2013	185,743	307,016	477,385

Note:

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

PENGROWTH ENERGY CORPORATION ANNUAL INFORMATION FORM | 17

Significant factors bearing on the reserves reconciliation were as follows:

• Net reserve additions from drilling activity, improved recovery and technical revisions replaced 270 percent and 211 percent of 2013 production for Proved Reserves and Total Proved Plus Probable Reserves, respectively. Based on all changes, including acquisitions and dispositions, reserve replacement was 122 percent and -12 percent for Proved Reserves and Proved Plus Probable Reserves, respectively.

• New reserve additions for development activity during 2013 amounted to 79 MMboe of Proved Reserves and 66 MMboe of Total Proved Plus Probable Reserves, almost all in our oil and liquids rich gas properties. The most significant resulted from regulatory approval of the first commercial phase of development and ongoing reservoir delineation at our Lindbergh thermal project. Other notable additions and reclassification of Proved or Probable Undeveloped Reserves to producing were for infill drilling and drilling extensions in the Cardium play through the Lochend – Garrington fairway where we hold an extensive land position. Other additions were in the liquids rich multi-zone Olds and Harmattan core areas.

• Minor technical revisions due to performance changes in various properties resulted in a net increase of 4 MMboe of Proved Reserves. The net change due to technical revisions of Total Proved Plus Probable Reserves was essentially neutral.

• Reserve additions from development activities were offset by net dispositions of 46 MMboe and 69 MMboe of Proved Reserves and Total Proved Plus Probable Reserves, respectively, from our planned divestment programs. These were primarily from the disposition of the Weyburn Unit, the former NAL southeast Saskatchewan properties and other minor non-core assets in Alberta and British Columbia.

ADDITIONAL INFORMATION RELATING TO RESERVES DATA

Undeveloped Reserves

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

Proved Undeveloped Reserves and Probable Undeveloped Reserves have been estimated in accordance with procedures and standards contained in the COGE Handbook. In general, Undeveloped Reserves are scheduled to be developed within the next two to three years. Much of the remaining capital scheduled beyond this period is for staged developments such as the Judy Creek and Swan Hills miscible flood projects, and the Lindbergh thermal development. Other longer term capital expenditures are for gas development most of which has been deferred with capital being allocated instead to higher-impact oil opportunities.

Company Gross Reserves First Attributed by Year⁽¹⁾ 

Proved Undeveloped Reserves
	Light & Medium Oil		Heavy Oil		Bitumen		Natural Gas		Coal Bed Methane		Natural Gas Liquids		Total Oil Equivalent
	(Mbbl)		(Mbbl)		(Mbbl)		(MMcf)		(MMcf)		(Mbbl)		(Mboe)(2)
	First Attributed	Total at year end	First Attributed	Total at year end	First Attributed	Total at year end	First Attributed	Total at year end	First Attributed	Total at year end	First Attributed	Total at year end	First Attributed	Total at year end
Prior	15,077	15,077	1,732	1,732	-	-	15,742	15,742	24,955	24,955	878	878	30,470	30,470
2011	2,891	16,447	2,843	3,568	2,756	2,756	18,332	62,830	-	23,241	1,027	1,678	12,572	38,794
2012	6,233	20,019	2,915	6,120	8,380	11,136	28,115	76,111	-	22,200	1,128	1,831	23,342	55,491
2013	2,348	14,771	1,015	5,954	69,293	80,423	9,405	64,999	-	22,410	647	1,306	74,870	117,022

Probable Undeveloped Reserves
	Light & Medium Oil		Heavy Oil		Bitumen		Natural Gas		Coal Bed Methane		Natural Gas Liquids		Total Oil Equivalent
	(Mbbl)		(Mbbl)		(Mbbl)		(MMcf)		(MMcf)		(Mbbl)		(Mboe)(2)
	First Attributed	Total at year end	First Attributed	Total at year end	First Attributed	Total at year end	First Attributed	Total at year end	First Attributed	Total at year end	First Attributed	Total at year end		First Attributed	Total at year end
Prior	10,168	10,168	1,265	1,265	6,348	6,348	145,695	145,695	6,318	6,318	2,879	2,879		45,996	45,996
2011	2,185	12,015	1,767	2,612	-	1,581	44,814	139,429	-	6,077	1,210	2,535		12,630	42,994
2012	8,652	19,144	5,205	7,516	80,038	81,630	50,800	178,755	-	6,674	2,250	3,675		104,612	142,869
2013	2,352	11,774	431	8,196	39,821	60,518	35,878	177,413	-	6,312	654	2,451		49,237	113,559

Notes:

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

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

18 | ANNUAL INFORMATION FORM

Proved Undeveloped Reserves

Our Proved Undeveloped Reserves comprise approximately 38 percent of Company Interest total Proved Reserves on a barrel of oil equivalency basis. Company Interest Proved Undeveloped Reserves of 117 MMboe were assigned by GLJ in accordance with NI 51-101. In general, Proved Undeveloped Reserves were assigned to certain properties because we intend to make the needed capital commitments to convert the Undeveloped Reserves to Proved Developed Producing Reserves in the next few years. Proved Undeveloped Reserves have been primarily assigned for future oil sands development, miscible flood expansion and development drilling.

The Lindbergh thermal project, currently under development and anticipated to come on stream in 2015, accounts for 69 percent of our Proved Undeveloped Reserves. SAGD well pairs are forecast to be drilled until 2030. The pace of development is limited by the capacity of the central processing and steam facility. Harmattan, Garrington and Lochend contain approximately six percent of our Proved Undeveloped Reserves. Development drilling in these fields is primarily focused on the Cardium formation and is forecast to occur over the next three to five years. The Groundbirch Montney gas property amounts to approximately five percent of our Proved Undeveloped Reserves. Drilling is forecast by GLJ to occur over the next five years to develop these reserves. In the Judy Creek and Judy Creek West units, drilling and miscible flood development is forecast to continue until 2021 and accounts for another four percent of Company Interest Proved Undeveloped Reserves. Similarly, the Swan Hills unit miscible flood expansion, as well as some infill drilling, comprises three percent of our Company Interest Proved Undeveloped Reserves. The Swan Hills unit reserves have a 50 year Remaining Reserve Life. The incremental recovery is reflected in the GLJ Report and miscible flood expansion is forecast to continue until 2031. The gradual pace of development is affected by a limited supply of solvent for injection in the miscible floods at both Judy Creek and Swan Hills. Our CBM development requires further drilling at Twining, Huxley and Fenn Big Valley. Because of the extensive land holdings, this is forecast to occur over the next five years and represents another three percent of the Proved Undeveloped Reserves.

Probable Undeveloped Reserves

Probable Undeveloped Reserves were assigned by GLJ in accordance with the requirements and standards of NI 51-101 and the COGE Handbook. Our Probable Undeveloped Reserves amount to 114 MMboe and represent about 24 percent of the Total Proved Plus Probable Reserves. Probable Undeveloped Reserves are assigned for similar reasons and generally to the same properties as Proved Undeveloped Reserves, but also meet the requirements of the reserve classification to which they belong. Our largest Probable Undeveloped Reserves are distributed among certain properties as a percent of the total as follows: Lindbergh (53 percent), Groundbirch (18 percent), Harmattan/Garrington/Lochend (six percent) and Tangleflags (five percent).

FUTURE DEVELOPMENT COSTS

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

Future Development Costs ($MM)

							Total
Reserve Category	2014	2015	2016	2017	2018	Remainder	Undiscounted	Discounted at 10%
Proved Reserves (Constant Prices and Costs)	505	247	140	105	71	700	1,768	1,192
Proved Reserves (Forecast Prices and Costs)	499	269	163	113	78	879	2,001	1,292
Proved & Probable Reserves (Forecast Prices and Costs)	564	420	296	150	123	1,828	3,382	1,775

We expect to fund future development costs with a combination of cash flow and proceeds from non-core asset dispositions. There are no reserves that are expected to be limited in their recovery due to their cost of development. We have established a $715 million capital expenditure program for 2014 to fund our land acquisition, development and exploration activities, including expenditures of $365 million at our Lindbergh thermal project.

FINDING, DEVELOPMENT AND ACQUISITION COSTS

Finding and Development Costs

During 2013, we spent $692 million on development and optimization activities, which added 83.4 MMboe of Proved Reservesand 65.3 MMboe of Total Proved Plus Probable Reserves including revisions. The development and optimization expenditures exclude $5 million in corporate expenditures mainly for information technology projects in the Calgary office. The largest reserve additions were for drilling and improved recovery projects at Lindbergh, Lochend/Harmattan/Garrington and Groundbirch.

In total, we participated in drilling 175 gross wells (115.4 net wells) with a 98 percent success rate.

Extensive development occurred in the mainly Pengrowth-operated Lochend/Harmattan/Garrington Cardium trend during 2013. Within this area, we drilled, or participated in the drilling of, 76 gross (44.7 net) successful horizontal wells resulting in 72 (42.0 net) Cardium oil wells, three (2.0 net) Ellerslie and Elkton liquids rich gas wells and one (0.7 net) Elkton oil well.

PENGROWTH ENERGY CORPORATION ANNUAL INFORMATION FORM | 19

In our 100 percent owned Lindbergh thermal property, we drilled 29 stratigraphic delineation/observation wells during 2013 to better understand the reservoir and delineate the pool. In addition, we commenced construction of the central processing facilities and drilled the first seven SAGD producers in our first commercial phase of development.

In the Swan Hills area, we drilled 12 gross (5.8 net) Beaverhill Lake wells at Deer Mountain, House Mountain and Virginia Hills resulting in eight (2.9 net) oil producers and three (1.9 net) water injectors. Ongoing miscible flood conversions and waterflood optimization occurred in the Judy Creek, Judy Creek West and Swan Hills units.

At Jenner, we drilled 12 (11.2 net) horizontal oil wells in our ongoing development of various Glauconite heavy oil pools.

Various other drilling programs and optimization work were conducted during 2013 to test new concepts, increase production and maximize recoveries.

Acquisitions and Divestitures

Pengrowth experienced a very active year in 2013, completing almost $1 billion of asset dispositions, after interim period adjustments, and approximately $16 millionof asset acquisitions. The most significant asset dispositions in 2013 were the sale of our interest in the Weyburn Unit, which closed on March 11, 2013, with an effective date of January 1, 2013 for proceeds of approximately $316 million net of interim closing adjustments and the disposition of our southeast Saskatchewan interests which closed on September 9, 2013, with an effective date of June 1, 2013 for gross proceeds of $510 million prior to closing adjustments. Various other non-core asset dispositions of note were at Fireweed, Monogram, Twining, Bantry, Deer Mountain, Nipisi and Lake Erie (Ontario).

Future Development Costs

NI 51-101 requires that the calculation of F&D Costs include changes in forecasted FDC relating to the reserves. These forecasts of FDC will change with time due to ongoing development activity, inflationary changes in capital costs and acquisition or disposition of assets. We provide the calculation of FD&A Costs both with and without change in FDC. We include FD&A Costs because we believe that acquisitions and dispositions can have a significant impact on our ongoing reserve replacement costs.

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

Proved Reserves	2013	2012	2011	2011-2013 Weighted Average
Costs Excluding Future Development Costs
Exploration and Development Capital Expenditures - $M	692,436	460,953	603,394	1,756,783
Exploration and Development Reserve Additions including Revisions - Mboe	83,414	21,015	41,042	145,471
Finding and Development Cost - $/BOE	8.30	21.93	14.70	12.08
Net Acquisition (Disposition) Capital - $M	(977,762)	1,654,202	(8,307)	668,133
Net Acquisition (Disposition) Reserve Additions - Mboe	(45,623)	75,863	(160)	30,080
Net Acquisition Cost - $/BOE	21.43	21.81	52.06	22.21
Total Capital Expenditures including Net Acquisitions (Dispositions) - $M	(285,326)	2,115,155	595,087	2,424,916
Reserve Additions including Net Acquisitions (Dispositions) - Mboe	37,791	96,878	40,883	175,551
Finding, Development and Acquisition Cost - $/BOE(1)	(7.55)	21.83	14.56	13.81
Costs Including Future Development Costs
Exploration and Development Capital Expenditures - $M	692,436	460,953	603,394	1,756,783
Exploration and Development Change in FDC - $M	1,031,692	104,601	257,000	1,393,293
Exploration and Development Capital including Change in FDC - $M	1,724,128	565,554	860,394	3,150,076
Exploration and Development Reserve Additions including Revisions - Mboe	83,414	21,015	41,042	145,471
Finding and Development Cost - $/BOE	20.67	26.91	20.96	21.65
Net Acquisition (Disposition) Capital - $M	(977,762)	1,654,202	(8,307)	668,133
Net Acquisition (Disposition) FDC - $M	(224,700)	229,820	-	5,120
Net Acquisition (Disposition) Capital including FDC - $M	(1,202,462)	1,884,022	(8,307)	673,253
Net Acquisition (Disposition) Reserve Additions - Mboe	(45,623)	75,863	(160)	30,080
Net Acquisition Cost - $/BOE	26.36	24.83	52.06	22.38
Total Capital Expenditures including Net Acquisitions (Dispositions) - $M	(285,326)	2,115,155	595,087	2,424,916
Total Change in FDC - $M	806,992	334,421	257,000	1,398,413
Total Capital including Change in FDC - $M	521,666	2,449,576	852,087	3,823,329
Reserve Additions including Net Acquisitions (Dispositions) - Mboe	37,791	96,878	40,883	175,551
Finding, Development and Acquisition Cost including FDC - $/BOE	13.80	25.29	20.84	21.78

20 | ANNUAL INFORMATION FORM

Total Proved Plus Probable Reserves	2013	2012	2011	2011-2013 Weighted Average
Costs Excluding Future Development Costs
Exploration and Development Capital Expenditures - $M	692,436	460,953	603,394	1,756,783
Exploration and Development Reserve Additions including Revisions - Mboe	65,268	103,772	39,335	208,375
Finding and Development Cost - $/BOE	10.61	4.44	15.34	8.43
Net Acquisition (Disposition) Capital - $M	(977,762)	1,654,202	(8,307)	668,133
Net Acquisition (Disposition) Reserve Additions - Mboe	(68,990)	109,388	(253)	40,145
Net Acquisition Cost - $/BOE	14.17	15.12	32.85	16.64
Total Capital Expenditures including Net Acquisitions (Dispositions) - $M	(285,326)	2,115,155	595,087	2,424,916
Reserve Additions including Net Acquisitions (Dispositions) - Mboe	(3,722)	213,160	39,082	248,520
Finding, Development and Acquisition Cost - $/BOE(1)	76.66	9.92	15.23	9.76
Costs Including Future Development Costs
Exploration and Development Capital Expenditures - $M	692,436	460,953	603,394	1,756,783
Exploration and Development Change in FDC - $M	741,154	1,287,994	188,000	2,217,148
Exploration and Development Capital including Change in FDC - $M	1,433,590	1,748,947	791,394	3,973,931
Exploration and Development Reserve Additions including Revisions - Mboe	65,268	103,772	39,335	208,375
Finding and Development Cost - $/BOE	21.96	16.85	20.12	19.07
Net Acquisition (Disposition) Capital - $M	(977,762)	1,654,202	(8,307)	668,133
Net Acquisition (Disposition) FDC - $M	(381,200)	467,242	-	86,042
Net Acquisition (Disposition) Capital including FDC - $M	(1,358,962)	2,121,444	(8,307)	754,175
Net Acquisition (Disposition) Reserve Additions - Mboe	(68,990)	109,388	(253)	40,145
Net Acquisition Cost - $/BOE	19.70	19.39	32.85	18.79
Total Capital Expenditures including Net Acquisitions (Dispositions) - $M	(285,326)	2,115,155	595,087	2,424,916
Total Change in FDC - $M	359,954	1,755,236	188,000	2,303,190
Total Capital including Change in FDC - $M	74,628	3,870,391	783,087	4,728,106
Reserve Additions including Net Acquisitions (Dispositions) – Mboe	(3,722)	213,160	39,082	248,520
Finding Development and Acquisition Cost including FDC - $/BOE(2)	(20.05)	18.16	20.04	19.03

Notes:

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

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

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

RECYCLE RATIO

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

	2013	2012	2011	2011-2013 Weighted Average
Recycle Ratio	1.1	1.4	1.4	1.3
Operating Netback, $/BOE(1)(3)	24.35	23.67	28.99	25.52
P+P F&D, $/BOE(2)	21.96	16.85	20.12	19.07

Notes:

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

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

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

PENGROWTH ENERGY CORPORATION ANNUAL INFORMATION FORM | 21

RESERVE LIFE INDEX (RLI)

The reserve life index provides a comparative measure of the longevity of the resources. We calculate the RLI by dividing 2013 Company Interest year end reserves by GLJ’s 2014 forecasted production.

	Proved Producing Reserves	Total Proved Reserves	Total Proved Plus Probable Reserves
RLI, years	7.4	11.8	17.4
Reserves, Mboe(1)(2)	185,743	307,016	477,385
2014 Forecast Production, BOE/d(1)	69,079	71,422	75,047

Notes:

(1) Both reserves and production are Company Interest.

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

RESERVE REPLACEMENT

We provide reserve replacement data as an indication of the effectiveness of our investments made and the relative impact of that investment. The reserve replacement figures are calculated with and without net acquisitions included.

	2013		2012		2011		Weighted Average/Total 2011-2013
Without Net Acquisitions Proved Plus Probable Replacement	211	%	327	%	146	%	233	%
P+P Additions plus Revisions, MMboe(1)	65.3		103.8		39.3		208.4
With Net Acquisitions Proved Plus Probable Replacement	(12	)%	672	%	145	%	277	%
P+P Additions, Revisions plus net Acquisitions, MMboe(1)	(3.7)		213.2		39.1		248.6
Without Net Acquisitions Total Proved Replacement	270	%	66	%	152	%	162	%
Total Proved Additions plus Revisions, MMboe(1)	83.4		21.0		41.0		145.4
With Net Acquisitions Total Proved Replacement	122	%	306	%	151	%	196	%
Total Proved Additions, Revisions plus net Acquisitions, MMboe(1)	37.8		96.9		40.9		175.6
Current Year Production, MMboe(1)	30.9		31.7		27.0		89.6

Notes:

(1) Both reserves and production are Company Interest.

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

OTHER OIL AND GAS INFORMATION

Oil and Gas Wells

As at December 31, 2013, we had an interest in 8,152 gross (4,423 net) producing oil and natural gas wells and 3,576 gross (2,074 net) non-producing wells. All wells are onshore except for wells in Nova Scotia which are all offshore.

		Producing		Non-Producing		Total
		Gross	Net	Gross	Net	Gross	Net
Crude Oil and Bitumen Wells
	Alberta	2,427	1,513	1,193	680	3,620	2,193
	British Columbia	87	55	193	120	280	175
	Saskatchewan	169	72	204	147	373	219
Natural Gas Wells
	Alberta	5,229	2,633	966	518	6,195	3,151
	British Columbia	183	113	163	88	346	201
	Saskatchewan	38	35	21	14	59	49
	Nova Scotia	19	2	-	-	19	2
Other
	Alberta	-	-	600	370	600	370
	British Columbia	-	-	163	106	163	106
	Saskatchewan	-	-	73	31	73	31
Total		8,152	4,423	3,576	2,074	11,728	6,497

22 | ANNUAL INFORMATION FORM

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, 2013 and the maximum net area of unproved properties for which we expect our rights to explore, develop and exploit to expire during 2014. There are no material work commitments necessary to maintain these properties.

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

Unproved Properties as at December 31, 2013

Location	Gross Acres	Net Acres	Maximum Net Acres Expected to Expire During 2014
Alberta	789,996	507,042	100,062
British Columbia	371,027	155,216	23,679
Saskatchewan	9,299	7,397	640
Nova Scotia	200,650	15,957	-
Total	1,370,972	685,612	124,380

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

Lindbergh Oil Sands Reserves and Contingent Resources

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

The main bitumen resource at Lindbergh is located within the Lloydminster Formation of the Mannville Group, at an approximate depth of 500 metres. Oil quality ranges from 9.5 - 11^o API. The average exploitable reservoir pay thickness is 14.3 metres in the 12,500 bbl/d first phase commercial project area. There appear to be no top water or top gas thief zones within the Lloydminster Formation in the project development area. A competent cap-rock is provided by the General Petroleum shale, which is pervasive and consistent throughout the area.

We own a central processing facility and pad site and drilled and completed two SAGD well pairs in December 2011. The wells were drilled from a single pad with each having an effective horizontal well length of approximately 840 metres within the bitumen-bearing Lloydminster formation.

Both well pairs encountered high quality reservoir throughout with no lean zones or shale barriers in any of the well bores. Steaming operations began at the Lindbergh pilot in early February 2012. Based on favourable pilot results, Pengrowth is developing a commercial project with a first phase design capacity of 12,500 bbl/d of bitumen (including the pilot area) with an expected project life of 37 years. Over the life of the 12,500 bbl/d commercial project, 116 well pairs are expected to be drilled from several central pad sites within the project area, recovering 142.6 MMbbl of bitumen. The production life for each individual well pair is expected to be 8 ‑ 9 years. Under our development plan, as individual well pair production declines, additional well pairs would be drilled throughout the Lindbergh project area to maintain production. The initial phase is expected to reach 12,500 bbl/d production in 2015. In July of 2013, the project received regulatory approval to proceed under the EPEA application number 1713445.

Future expansion of the Lindbergh commercial project, including the Muriel Lake property, is expected to increase the production capacity to 50,000 bbl/d of bitumen.The EIA application for the first of these expansions to 30,000 bbl/d was submitted in December 2013.

Proved, Probable and Possible Reserves have been assigned to the project development area. In addition, there are economic Contingent Resources for the area beyond the reserves. GLJ has updated the evaluation of the reserves and Contingent Resources for Lindbergh as of December 31, 2013. The evaluation was limited to portions of the reservoir amenable to SAGD. The profitability of the commercial project will be sensitive to oil prices and reservoir quality. The project is forecast to be profitable using forecast prices and costs as well as constant prices and costs.

PENGROWTH ENERGY CORPORATION ANNUAL INFORMATION FORM | 23

The tables below summarize the estimated volumes of Company-Interest reserves and economic Contingent Resources attributable to the Lindbergh property based upon forecast prices and costs. The estimates are in accordance with the definitions and guidelines in the COGE Handbook and NI 51-101. Please note that reserves and Contingent Resources involve different risks associated with achieving commerciality. Under the fiscal conditions, including commodity price and cost assumptions, applied in the estimation of reserves, the likelihood that a project will achieve commerciality is assumed to be 100 percent, whereas the likelihood of a Contingent Resource achieving commerciality may be less than 100 percent.

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

Lindbergh Thermal ProjectProved, Proved plus Probable and Proved plus Probable plus Possible Reserves as of December 31, 2013(Forecast Prices and Costs)
	Proved Reserves	Proved plus Probable Reserves	Proved plus Probable plus Possible Reserves(1)
Gross Reserves (MMbbl)	81.7	142.6	195.7

Notes:

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

Contingent Resources have been assigned to the remaining areas of the reservoir within the property that meet certain minimum criteria. Contingent Resources are estimated on the basis of a technically feasible SAGD recovery project having been defined. However, there is no certainty that it will be commercially viable to produce any portion of the Contingent Resources.

All categories of Contingent Resources have decreased from the previous year end as shown below. This is due to a significant volume now being reported as reserves resulting from further pool delineation and receiving regulatory approval for the first commercial phase of development. In 2013, we drilled 29 stratigraphic delineation/observation wells at Lindbergh.

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

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

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

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

• Approval of regulatory application to expand the current development area.

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

	December 31, 2013	December 31, 2012
	Contingent Resources(1)  (Gross MMbbl)	Contingent Resources(1)  (Gross MMbbl)
Low Estimate(2)	124	194
Best Estimate(3)	163	218
High Estimate(4)	276	328

Notes:

(1) Contingent Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. The contingencies may include factors such as economics, legal, environmental, political, regulatory or lack of markets. Contingent Resources are further classified in accordance with the level of certainty associated with the estimates.

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

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

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

24 | ANNUAL INFORMATION FORM

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

Groundbirch Reserves and Contingent Resources

The Groundbirch property is located approximately 40 kilometres southwest of Ft. St. John, British Columbia and covers an area of approximately 13,440 acres. We have an average 90 percent Working Interest in these lands.

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

The tables below summarize the estimated volumes of Company Interest reserves and economic Contingent Resources attributable to the Groundbirch property based upon forecast prices and costs. The estimates are in accordance with the definitions and guidelines in the COGE Handbook and NI 51-101. Please note that reserves and Contingent Resources involve different risks associated with achieving commerciality. Under the fiscal conditions, including commodity price and cost assumptions, applied in the estimation of reserves, the likelihood that a project will achieve commerciality is assumed to be 100 percent, whereas the likelihood of a Contingent Resource achieving commerciality may be less than 100 percent.

Groundbirch Proved, Proved plus Probable and Proved plus Probable plus Possible Reserves as of December 31, 2013(Forecast Prices and Costs)
		Proved Developed Producing Reserves (Gross)	Total Proved Reserves (Gross)	Total Proved Plus Probable Reserves (Gross)	Total Proved Plus Probable Plus Possible Reserves(1)  (Gross)
Reserves
	Gas (Bcf)	25.9	62.0	193.1	232.3
	NGL (MMbbl)	-	-	-	-
	Total (MMboe)(2)	4.3	10.3	32.2	38.7

Note:    

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

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

Contingent Resources have been assigned to the remaining areas of the reservoir within the property that meet certain minimum criteria. GLJ's estimates of economic Contingent Resources as at December 31, 2013 are shown below. Contingent Resources increased based on production performance in the area and recent offsetting development activity. There was no drilling and completion activity on our lands during 2013.

Contingent Resources are assigned on the basis of a technically feasible recovery project having been defined. These Contingent Resources are expected to be economic to develop. The Groundbirch tight gas resource is still in the early stage of evaluation and delineation in the area. Contingent Resources are assigned by GLJ to regions of the field where the zone is delineated to an appropriate level to understand the reservoir, and to reasonably remove reservoir risk.The reclassification of these Contingent Resources as reserves is contingent upon obtaining additional drilling, completion and test data which is required before Pengrowth can commit to further development. However, there is no certainty that it will be commercially viable to produce any portion of the Contingent Resource.

PENGROWTH ENERGY CORPORATION ANNUAL INFORMATION FORM | 25

		December 31, 2013 Contingent Resources(1)(Gross)	December 31, 2012 Contingent Resources(1)(Gross)
Low Estimate(2)
	Gas (Bcf)	215.1	157.0
	NGL (MMbbl)	-	0.2
	Total (MMboe)(5)	35.8	26.3
Best Estimate(3)
	Gas (Bcf)	339.9	274.3
	NGL (MMbbl)	-	0.3
	Total (MMboe)(5)	56.6	46.0
High Estimate(4)
	Gas (Bcf)	600.7	493.9
	NGL (MMbbl)	-	0.5
	Total (MMboe)(5)	100.1	82.8

Notes:

(1) Contingent Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. The contingencies may include factors such as economics, legal, environmental, political, regulatory or lack of markets. Contingent Resources are further classified in accordance with the level of certainty associated with the estimates.

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

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

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

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

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

FORWARD CONTRACTS

We use financial derivatives or fixed price contracts to manage our exposure to fluctuations in commodity prices and foreign currency exchange rates. A description of such instruments is provided in note 18 of our annual audited financial statements and related management's discussion and analysis for the year ended December 31, 2013, which may be found on SEDAR at www.sedar.com.

ADDITIONAL INFORMATION CONCERNING ABANDONMENT & RECLAMATION COSTS

The total future abandonment and reclamation costs are based on management's estimate of costs to remediate, reclaim and abandon wells and facilities having regard to our Working Interest and the estimated timing of the costs to be incurred in future periods. We have developed a process to calculate these estimates, which considers applicable regulations, actual and anticipated costs, type and size of the well or facility and the geographic location.

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

We have estimated the net present value (discounted at ten percent per annum) of our total asset retirement obligations, which are inclusive of those costs estimated by GLJ, to be approximately $145 million as at December 31, 2013, based on a total future liability (inflated at 1.5 percent per annum) of approximately $2,122 million. These costs are anticipated to be paid over 65 years with the majority of the costs incurred in the last 20 years and apply to 7,458 net producing, non-producing, service and abandoned wells.

26 | ANNUAL INFORMATION FORM

The following table summarizes our total current asset retirement obligations as at December 31, 2013:

Asset Retirement Obligations - $MM

	2014	2015	2016	Remainder	Total
Total Abandonment, Reclamation, Remediation & Dismantling	5.8	6.3	6.8	2,103.6	2,122.5
Discounted at ten percent	5.5	5.5	5.4	128.4	144.8

The above table excludes asset retirement obligations associated with future development and, in particular, the development associated with Proved Developed Non-Producing, Proved Undeveloped and Probable Reserves, except where such activity would be coincidental with existing operations. GLJ’s Proved Developed Producing reserve evaluation at forecast prices and costs is the best comparison to our current operation and includes $308 million ($131 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 $308 million, or $131 million when discounted at ten percent, is excluded elsewhere.

TAX HORIZON

We have not paid cash income tax in the past year and based upon current tax legislation, anticipated capital spending and economic conditions, we do not anticipate having to pay corporate income tax until at least 2018, partially as a result of our $3.7 billion of tax pools.

COSTS INCURRED

The following table outlines property acquisition, exploration and development costs that we incurred during the financial year ended December 31, 2013. These costs include only those costs which are cash or cash equivalent.

	Amount
Nature of Cost	($M)
Acquisition Costs
Proved	15,955
Unproved	-
Exploration Costs	4,558
Development Costs	686,499
Total	707,012

EXPLORATION AND DEVELOPMENT ACTIVITIES

The following table summarizes the number of wells drilled during the financial year ended December 31, 2013.

	Development		Exploration		Total
Wells	Gross	Net	Gross	Net	Gross	Net
Gas	6	3.3	-	-	6	3.3
Oil	126	77.1	2	0.3	128	77.4
Service	18	12.4	-	-	18	12.4
Stratigraphic Test	20	19.5	-	-	20	19.5
Dry	3	2.8	-	-	3	2.8
Total	173	115.1	2	0.3	175	115.4

PRODUCTION ESTIMATES

The following tables summarize the 2014 average daily volume of gross production estimated by GLJ for all properties held on December 31, 2013 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 2014 Company Interest production to be between 71,000 and 73,000 BOE/d.

	2014 Estimated Production
	Constant Prices and Costs		Forecast Prices and Costs
	Total Proved	Total Proved Plus Probable	Total Proved	Total Proved Plus Probable
Light and Medium Crude Oil (bbl/d)	21,203	22,604	21,130	22,604
Heavy Crude Oil (bbl/d)	6,850	7,048	6,850	7,048
Bitumen (bbl/d)	1,502	1,583	1,502	1,583
Natural Gas (Mcf/d)	197,602	205,882	197,506	205,965
Natural Gas Liquids (bbl/d)	8,778	9,226	8,769	9,227
Total (BOE/d)	71,267	74,773	71,170	74,789

PENGROWTH ENERGY CORPORATION ANNUAL INFORMATION FORM | 27

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(3)				YEAR ENDED(3)
		Mar 31, 2013	June 30, 2013	Sept 30, 2013	Dec 31, 2013	Dec 31, 2013
Barrels of Oil Equivalent(1)
	Average Daily Oil Production(2) (BOE/d)	89,702	87,909	83,275	77,371	84,527
	Sales price (after commodity risk management) ($/BOE)	47.85	50.15	53.32	45.71	49.32
	Other production income ($/BOE)	0.56	0.52	0.74	0.37	0.54
	Oil & gas sales ($/BOE)	48.41	50.67	54.06	46.08	49.86
	Royalties ($/BOE)	(8.30)	(9.09)	(9.47)	(8.82)	(8.92)
	Operating expenses ($/BOE)	(14.60)	(16.23)	(16.39)	(15.34)	(15.64)
	Transportation costs ($/BOE)	(0.74)	(0.91)	(1.10)	(1.10)	(0.95)
	Operating netback ($/BOE)	24.77	24.44	27.10	20.82	24.35
Light Crude
	Average Daily Oil Production(2) (bbl/d)	30,438	28,302	27,102	22,488	27,061
	Sales price (after commodity risk management) ($/bbl)	82.31	87.09	88.55	74.77	83.56
	Other production income ($/bbl)	0.31	0.48	0.34	0.48	0.39
	Oil & gas sales ($/bbl)	82.62	87.57	88.89	75.25	83.95
	Royalties ($/bbl)	(16.10)	(18.60)	(20.76)	(19.84)	(18.71)
	Operating expenses ($/bbl)	(17.92)	(17.87)	(17.38)	(16.57)	(17.04)
	Transportation costs ($/bbl)	(1.18)	(1.40)	(1.93)	(2.22)	(1.65)
	Operating netback ($/bbl)	47.42	49.70	48.82	36.62	46.55
Heavy Oil
	Average Daily Oil Production(2) (bbl/d)	7,706	8,523	8,812	8,369	8,355
	Oil & gas sales ($/bbl)	50.15	69.24	88.19	61.43	67.98
	Royalties ($/bbl)	(6.80)	(9.23)	(12.79)	(9.90)	(9.79)
	Operating expenses ($/bbl)	(19.17)	(19.49)	(19.91)	(17.36)	(18.97)
	Transportation costs ($/bbl)	(1.02)	(2.10)	(1.93)	(1.36)	(1.62)
	Operating netback ($/bbl)	23.16	38.42	53.56	32.81	37.60
Natural Gas(5)
	Average Daily Natural Gas Production(2) (Mcf/d)	245,019	241,307	225,081	216,231	231,812
	Sales price (after commodity risk management) ($/Mcf)	3.24	3.40	3.11	3.27	3.26
	Other production income ($/Mcf)	0.16	0.13	0.23	0.08	0.15
	Oil & gas sales ($/Mcf)	3.40	3.53	3.34	3.35	3.41
	Royalties ($/Mcf)	(0.12)	(0.15)	0.17	0.04	(0.02)
	Operating expenses ($/Mcf)	(1.87)	(2.40)	(2.51)	(2.39)	(2.35)
	Transportation costs ($/Mcf)	(0.09)	(0.09)	(0.09)	(0.11)	(0.09)
	Operating netback ($/Mcf)	1.32	0.89	0.91	0.89	0.95
NGL
	Average Daily Oil Production(2) (bbl/d)	10,722	10,867	9,847	10,476	10,476
	Oil & gas sales ($/bbl)	56.67	49.15	57.18	60.49	55.81
	Royalties ($/bbl)	(15.99)	(14.46)	(15.43)	(15.47)	(15.33)
	Operating expenses ($/bbl)	(14.76)	(16.14)	(15.79)	(14.30)	(15.03)
	Transportation costs ($/bbl	(0.08)	(0.06)	(0.04)	(0.01)	(0.05)
	Operating netback ($/bbl)	25.84	18.49	25.92	30.71	25.40

Notes:

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

(2) Before the deductions of royalties.

(3) Numbers may not add due to rounding.

DESCRIPTION OF CAPITAL STRUCTURE

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.

28 | ANNUAL INFORMATION FORM

Preferred Shares

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

Debentures

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

Our 6.25% Series A Convertible Debentures have a face value of $1,000, bear interest at the rate of 6.25 percent per annum payable semi-annually in arrears on the last day of June and December of each year and mature on December 31, 2014. The 6.25% Series A Convertible Debentures are convertible at the holder’s option at a conversion price of $19.186 per Common Share, subject to adjustment in certain events. The 6.25% Series A Convertible Debentures are now redeemable at our option.

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

Stock Exchange Listings

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

DIVIDENDS

GENERAL

We currently pay monthly dividends to our Shareholders on the 15^th day of each month or the first business day following the 15^th day. The record date for any dividend is on or about the 22^nd day of the month preceding the dividend date or such other date as may be determined by our Board. In accordance with stock exchange rules, an ex-dividend date occurs two trading days prior to the record date to permit time for settlement of trades of securities and dividends must be declared a minimum of seven trading days before the record date. A list of all anticipated dividend record dates for 2014 can be found at www.pengrowth.com/investors/dividends/.

HISTORICAL DISTRIBUTIONS/DIVIDENDS

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

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The following table sets forth dividends declared by the Corporation in 2013, 2012 and 2011 on the outstanding Common Shares for the periods indicated, with each amount being paid in the following month:

Month	2013 ($/share)	2012 ($/share)	2011 ($/share)
January	0.04	0.07	0.07
February	0.04	0.07	0.07
March	0.04	0.07	0.07
April	0.04	0.07	0.07
May	0.04	0.07	0.07
June	0.04	0.07	0.07
July	0.04	0.04	0.07
August	0.04	0.04	0.07
September	0.04	0.04	0.07
October	0.04	0.04	0.07
November	0.04	0.04	0.07
December	0.04	0.04	0.07
Total	0.48	0.66	0.84

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

RESTRICTIONS ON DIVIDENDS

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

ABCA SOLVENCY TESTS

The payment of dividends by a corporation is governed by the liquidity and insolvency tests described in the ABCA. Pursuant to the ABCA, after the payment of a dividend, we must be able to pay our liabilities as they become due, and the realizable value of our assets must be greater than our liabilities and the legal stated capital of our outstanding securities. As at December 31, 2013, our legal stated capital was approximately $1.528 billion.

REVOLVING CREDIT FACILITY

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

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

In addition to the standard representations, warranties and covenants commonly contained in a credit facility of this nature, the Credit Facility includes the following key financial covenants as at February 28, 2014:

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

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

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

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

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

SENIOR UNSECURED NOTES

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

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

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

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

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

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

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

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

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

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INDUSTRY CONDITIONS

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

PRICING AND MARKETING

Oil

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

Natural Gas

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

Natural Gas Liquids

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.

THE NORTH AMERICAN FREE TRADE AGREEMENT

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

All three signatory countries are prohibited from imposing a minimum or maximum export price requirement in any circumstance where any other form of quantitative restriction is prohibited. The signatory countries are also prohibited from imposing a minimum or maximum import price requirement except as permitted in enforcement of countervailing and anti-dumping orders and undertakings. NAFTA requires energy regulators to ensure the orderly and equitable implementation of any regulatory changes and to ensure that the application of those changes will cause minimal disruption to contractual arrangements and avoid undue interference with pricing, marketing and distribution arrangements, all of which are important for Canadian oil and natural gas exports. NAFTA contemplates the reduction of Mexican restrictive trade practices in the energy sector and prohibits discriminatory border restrictions and export taxes.

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ROYALTIES AND INCENTIVES

General

In addition to federal regulation, each province has legislation and regulations, which govern royalties, production rates and other matters. The royalty regime in a given province is a significant factor in the profitability of oil sands projects, crude oil, natural gas liquids, sulphur and natural gas production. Royalties payable on production from lands other than Crown lands are determined by negotiation between the mineral freehold owner and the lessee, although production from such lands is subject to certain provincial taxes and royalties. Royalties from production on Crown lands are determined by governmental regulation and are generally calculated as a percentage of the value of gross production. The rate of royalties payable generally depends in part on prescribed reference prices, well productivity, geographical location, field discovery date, method of recovery and the type or quality of the petroleum product produced. Other royalties and royalty‑like interests are carved out of the working interest owner's interest, from time to time, through non‑public transactions. These are often referred to as overriding royalties, gross overriding royalties, net profits interests, or net carried interests.

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

Alberta

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

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

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

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

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

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

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

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

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

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

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

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 if it decides to discontinue the program.

British Columbia

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

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

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

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

• Deep Royalty Credit Program providing a royalty credit for natural gas wells defined in terms of a dollar amount applied against royalties, is well specific and applies to drilling and completion costs for vertical wells with a true vertical depth greater than 2,500 metres and horizontal wells with a true vertical depth greater than 1,900 metres (or 2,300 metres if spud before September 1, 2009) and if certain other criteria are met and is intended to reflect the higher drilling and completion costs;

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

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

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

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

• Ultra-Marginal Royalty Reduction Program providing royalty reductions for low productivity, shallow natural gas wells. Vertical wells must be less than 2,500 metres and horizontal wells less than 2,300 metres to be eligible. Production in the first 12 months ending after January 2007 must be less than 17 m³ per metre of depth for exploratory wildcat wells and less than 11 m³ per metre of depth for development wells and exploratory outpost wells. The well must have been spudded or re-entered after December 31, 2005. A reduction is realized in each month that average daily production is less than 60,000 m³; and

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

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

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

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

Saskatchewan

In Saskatchewan, the amount payable as a Crown royalty or a freehold production tax in respect of oil depends on the type and vintage of oil, the quantity of oil produced in a month, the value of the oil produced and specified adjustment factors determined monthly by the provincial government. For Crown royalty and freehold production tax purposes, conventional oil is divided into "types", being "heavy oil", "southwest designated oil" or "non‑heavy oil other than southwest designated oil". The conventional royalty and production tax classifications (“fourth tier oil”, “third tier oil”, “new oil” and “old oil”) depend on the finished drilling date of a well and are applied to each of the three crude oil types slightly differently. Heavy oil is classified as third tier oil (produced from a vertical well having a finished drilling date on or after January 1, 1994 and before October 1, 2002 or incremental oil from new or expanded waterflood projects with a commencement date on or after January 1, 1994 and before October 1, 2002), fourth tier oil (having a finished drilling date on or after October 1, 2002 or incremental oil from new or expanded waterflood projects with a commencement date on or after October 1, 2002) or new oil (conventional oil that is not classified as third tier oil or fourth tier oil). Southwest designated oil uses the same definition of fourth tier oil but third tier oil is defined as conventional oil produced from a vertical well having a finished drilling date on or after February 9, 1998 and before October 1, 2002 or incremental oil from new or expanded waterflood projects with a commencement date on or after February 9, 1998 and before October 1, 2002 and new oil is defined as conventional oil produced from a horizontal well having a finished drilling date on or after February 9, 1998 and before October 1, 2002. For non-heavy oil other than southwest designated oil, the same classification as heavy oil is used but new oil is defined as conventional oil produced from a vertical well completed after 1973 and having a finished drilling date prior to 1994, conventional oil produced from a horizontal well having a finished drilling date on or after April 1, 1991 and before October 1, 2002, or incremental oil from new or expanded waterflood projects with a commencement date on or after January 1, 1974 and before 1994 whereas old oil is defined as conventional oil not classified as third or fourth tier oil or new oil. Production tax rates for freehold production are determined by first determining the Crown royalty rate and then subtracting the "Production Tax Factor" ("PTF") applicable to that classification of oil. Currently the PTF is 6.9 for old oil, 10.0 for new oil and third tier oil and 12.5 for fourth tier oil. The minimum rate for freehold production tax is zero.

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

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oil that is third tier oil or new oil, 35 percent for southwest designated oil that is third tier oil or new oil, 35 percent for non‑heavy oil other than southwest designated oil that is third tier or new oil, and 45 percent for old oil.

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

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

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

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

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

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

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

• Royalty/Tax Incentive Volumes for Horizontal Gas Wells drilled on or after June 1, 2010 and before April 1, 2013 providing for a classification of the well as a qualifying exploratory gas well and resulting in a reduced Crown royalty (a Crown royalty rate of the lesser of fourth tier oil Crown royalty rate and 2.5 percent) and freehold tax rates (a freehold production tax rate of zero percent) on incentive volumes of 25,000,000 m³ for horizontal gas wells and after the incentive volume is produced, the gas produced will be subject to the "fourth tier" royalty tax rate;

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

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

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

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

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

Nova Scotia

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

LAND TENURE

The respective provincial governments predominantly own the rights to crude oil and natural gas located in the western provinces. Provincial governments grant rights to explore for and produce oil and natural gas pursuant to leases, licences, and permits for varying terms, and on conditions set forth in provincial legislation including requirements to perform specific work or make payments. Private ownership of oil and natural gas also exists in such provinces and rights to explore for and produce such oil and natural gas are granted by lease on such terms and conditions as may be negotiated.

Each of the provinces of Alberta, British Columbia, and Saskatchewan has implemented legislation providing for the reversion to the Crown of mineral rights to deep, non-productive geological formations at the conclusion of the primary term of a lease or license. On March 29, 2007, British Columbia expanded its policy of deep rights reversion for new leases to provide for the reversion of both shallow and deep formations that cannot be shown to be capable of production at the end of their primary term.

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

ENVIRONMENTAL REGULATION

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

Federal

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

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Alberta

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

In December 2008, the Government of Alberta released a new land use policy for surface land in Alberta, the Alberta Land Use Framework (the "ALUF"). The ALUF sets out an approach to manage public and private land use and natural resource development in a manner that is consistent with the long-term economic, environmental and social goals of the province. It calls for the development of seven region-specific land use plans in order to manage the combined impacts of existing and future land use within a specific region and the incorporation of a cumulative effects management approach into such plans.

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

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

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

The next regional plan to take effect is the South Saskatchewan Regional Plan ("SSRP") which covers approximately 83,764 square kilometres and includes 45 percent of the provincial population. The SSRP was released in draft form in 2013 and is expected to come into force on April 1, 2014.

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

British Columbia

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

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Saskatchewan

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

LIABILITY MANAGEMENT RATING PROGRAMS

Alberta

In Alberta, the AER implements the Licensee Liability Rating Program (the "AB LLR Program"). The AB LLR Program is a liability management program governing most conventional upstream oil and gas wells, facilities and pipelines. The ABOGCA establishes an orphan fund (the "Orphan Fund") to pay the costs to suspend, abandon, remediate and reclaim a well, facility or pipeline included in the AB LLR Program if a licensee or working interest participant ("WIP") becomes defunct. The Orphan Fund is funded by licensees in the AB LLR Program through a levy administered by the AER. The AB LLR Program is designed to minimize the risk to the Orphan Fund posed by unfunded liability of licences and prevent the taxpayers of Alberta from incurring costs to suspend, abandon, remediate and reclaim wells, facilities or pipelines. The AB LLR Program requires a licensee whose deemed liabilities exceed its deemed assets to provide the AER with a security deposit. The ratio of deemed liabilities to deemed assets is assessed once each month and failure to post the required security deposit may result in the initiation of enforcement action by the AER.

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

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

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

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

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

The changes will be implemented over a three-year period, ending May 2015. The LMR is the ratio of a permit holder's deemed assets to deemed liabilities. Permit holders whose deemed liabilities exceed deemed assets will be considered high risk and reviewed for a security deposit. Permit holders who fail to submit the required security deposit within the allotted timeframe may be in non-compliance with the OGAA.

Saskatchewan

In Saskatchewan, the Ministry of Economy implements the Licensee Liability Rating Program (the "SK LLR Program"). The SK LLR Program is designed to assess and manage the financial risk that a licensee's well and facility abandonment and reclamation liabilities pose to an orphan fund (the "Oil and Gas Orphan Fund") established under the SKOGCA. The Oil and Gas Orphan Fund is responsible for carrying out the abandonment and reclamation of wells and facilities contained within the SK LLR Program when a licensee or WIP is defunct or missing. The SK LLR Program requires a licensee whose deemed liabilities exceed its deemed assets to post a security deposit. The ratio of deemed liabilities to deemed assets is assessed once each month for all licensees of oil, gas and service wells and upstream oil and gas facilities.

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CLIMATE CHANGE REGULATION

Federal

The Government of Canada is a signatory to the United Nations Framework Convention on Climate Change (the "UNFCCC") and a participant to the Copenhagen Accord (a non-binding agreement created by the UNFCCC which represents a broad political consensus and reinforces commitments to reducing greenhouse gas ("GHG") emissions). On January 29, 2010, Canada inscribed in the Copenhagen Accord its 2020 economy-wide target of a 17 percent reduction of GHG emissions from 2005 levels. This target is aligned with the United States target. On April 26, 2007, the Government of Canada released "Turning the Corner: An Action Plan to Reduce Greenhouse Gases and Air Pollution" (the "Action Plan") which sets forth a plan for regulations to address both GHGs and air pollution. An update to the Action Plan, "Turning the Corner: Regulatory Framework for Industrial Greenhouse Gas Emissions" was released on March 10, 2008 (the "Updated Action Plan"). The Updated Action Plan outlines emissions intensity-based targets, which will be applied to regulated sectors on a facility-specific, sector-wide basis or company-by-company basis. Although the intention was for draft regulations aimed at implementing the Updated Action Plan to become binding on January 1, 2010, the only regulations being implemented are in the transportation and electricity sectors. The federal government indicates that it is taking a sector-by-sector regulatory approach to reducing GHG emissions and is working on regulations for other sectors. Representatives of the Government of Canada have indicated that the proposals contained in the Updated Action Plan will be modified to ensure consistency with the direction ultimately taken by the United States with respect to GHG emissions regulation. In June 2012, the second US-Canada Clean Energy Dialogue Action Plan was released. The plan renewed efforts to enhance bilateral collaboration on the development of clean energy technologies to reduce GHG emissions.

Alberta

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

As part of its efforts to reduce GHG emissions, Alberta introduced legislation to address GHG emissions: the Climate Change and Emissions Management Act (the "CCEMA") enacted on December 4, 2003 and amended through the Climate Change and Emissions Management Amendment Act, which received royal assent on November 4, 2008. The CCEMA is based on an emissions intensity approach and aims for a 50 percent reduction from 1990 emissions relative to GDP by 2020. The accompanying regulations include the Specified Gas Emitters Regulation ("SGER"), which imposes GHG limits, and the Specified Gas Reporting Regulation, which imposes GHG emissions reporting requirements. Alberta facilities emitting more than 100,000 tonnes of GHGs a year are subject to compliance with the CCEMA. Alberta is the first jurisdiction in North America to impose regulations requiring large facilities in various sectors to reduce their GHG emissions.

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

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

Alberta is also the first jurisdiction in North America to direct dedicated funding to implement carbon capture and storage technology across industrial sectors. Alberta will invest $2 billion into demonstration projects that will begin commercializing the technology on the scale needed to be successful. On December 2, 2010, the Government of Alberta passed the Carbon Capture and Storage Statutes Amendment Act, 2010. It deemed the pore space underlying all land in Alberta to be, and to have always been, the property of the Crown and provided for the assumption of long-term liability for carbon sequestration projects by the Crown, subject to the satisfaction of certain conditions.

Under the Alberta regulations, based on emissions during 2013, we would be required to purchase "off-setting" credits in 2014 of up to $1,000,000 from Alberta Environment. In 2013, we spent $1,000,665 on purchasing “off-setting” credits (climate change emission management fund contributions) with respect to 2012 emissions from our Quirk Creek Gas Plant. We did not need to purchase “off‑setting” credits in respect of our Olds Gas Plant and Judy Creek Gas Conservation Plant as we had a surplus of carbon credits.

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British Columbia

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

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

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

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

Saskatchewan

On May 11, 2009, the Government of Saskatchewan announced The Management and Reduction of Greenhouse Gases Act (the "MRGGA") to regulate GHG emissions in the province. The MRGGA received Royal Assent on May 20, 2010 and will come into force on proclamation. The MRGGA establishes a framework for achieving the provincial target of a 20 percent reduction in GHG emissions from 2006 levels by 2020. The MRGGA and related regulations have yet to be proclaimed in force.

Nova Scotia

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

GENERAL DISCUSSION

At present, we are not paying any direct costs. However, the direct and indirect costs of the various GHG regulations, existing and proposed, may at some time and under certain conditions adversely affect our business, operations and financial results. Equipment that meets future emission standards may not be available on an economic basis and other compliance methods to reduce our emissions or emissions intensity to future required levels may significantly increase operating costs or reduce the output of the projects. Offset, performance or fund credits may not be available for acquisition or may not be available on an economic basis. Any failure to meet emission reduction compliance obligations requirements may materially adversely affect our business and result in fines, penalties and the suspension of operations. There is also a risk that one or more levels of government could impose additional emissions or emissions intensity reduction requirements or taxes on emissions created by us or by consumers of our products. The imposition of such measures might negatively affect our costs and prices for our products and have an adverse effect on earnings and results of operations.

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RISK FACTORS

If any of the following risks occur, our production, revenues and financial condition could be materially impaired, with a resulting decrease in 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, 2013.

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

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

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

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

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

• geo-political conditions;

• worldwide economic conditions including ongoing credit and liquidity concerns;

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

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

• the level of consumer demand;

• the price and availability of alternative fuels;

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

• the effect of worldwide energy conservation measures; and

• government regulation.

North American crude oil price differentials are expected to continue to be volatile throughout 2014 which will have an impact on crude oil prices for Canadian producers. Overall, supply in excess of current pipeline and refining capacity is expected to exist. Material structural changes are required to reduce these bottlenecks and the resulting steep price discounts. There are numerous projects proposed to alleviate pipeline bottlenecks in the United States, expand refinery capacity and expand or build new pipelines in Canada and the United States to source new markets, many of which are in the regulatory application phase. There can be no assurance that such regulatory approvals will be secured on a timely basis or at all.

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

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

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

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

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

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

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

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

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

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

Those factors and assumptions include:

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

• the assumed effect of government regulation;

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

• initial production rates;

• production decline rates;

• ultimate recovery of reserves and resources;

• marketability of production; and

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

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

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

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

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

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

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

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

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

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

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

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

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

• production falls short of the hedged volumes;

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

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

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

Similarly, from time to time we may enter into agreements to fix the exchange rate of Canadian to United States dollars in order to offset the risk of revenue losses if the Canadian dollar increases in value compared to the United States dollar. However, if the Canadian dollar declines in value compared to the United States dollar, we will not benefit from the fluctuating exchange rate.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Although pipeline expansions are ongoing, the lack of firm pipeline capacity continues to affect the oil industry and limit the ability to produce and market oil production. In addition, the pro-rationing of capacity on inter-provincial pipeline systems continues to affect the ability to export oil. Furthermore, producers are increasingly turning to rail as an alternative means of transportation. In recent years, the volume of crude oil shipped by rail in North America has increased dramatically and it is projected to continue in this upward trend. Any significant change in market factors or other conditions affecting these infrastructure systems and facilities, as well as any delays in constructing new infrastructure systems and facilities could harm our business and, in turn, our financial condition, results of operations and cash flows.

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

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

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

The continuing production from a property, and to some extent the marketing of production, is dependent upon the ability of the operators of our properties. Approximately 37 percent of our properties are operated by third parties, based on daily production. If, in situations where we are not the operator, the operator fails to perform these functions properly or becomes insolvent, revenues may be reduced. Revenues from production generally flow through the operator and, where we are not the operator; there is a risk of delay and additional expense in receiving such revenues.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Various levels of governments impose extensive controls and regulations on oil and natural gas operations (including exploration, development, production, pricing, marketing and transportation). Governments may regulate or intervene with respect to exploration and production activities, prices, taxes and royalties. Amendments to these controls and regulations may occur from time to time in response to economic or political conditions. The implementation of new regulations or the modification of existing regulations affecting the oil and natural gas industry could reduce demand for crude oil and natural gas and increase our costs, either of which may have a material adverse effect on our business, financial condition, results of operations and prospects. In order to conduct oil and natural gas operations, we will require regulatory permits, licenses, registrations, approvals and authorizations from various governmental authorities. There can be no assurance that we will be able to obtain all of the permits, licenses, registrations, approvals and authorizations that may be required to conduct operations that it may wish to undertake. In addition to regulatory requirements pertaining to the production, marketing and sale of oil and natural gas mentioned above, our business and financial condition could be influenced by federal legislation affecting, in particular, foreign investment, through legislation such as the Competition Act (Canada) and the Investment Canada Act (Canada). See “Industry Conditions”.

Hydraulic Fracturing

Hydraulic fracturing involves the injection of water, sand and small amounts of additives under pressure into rock formations to stimulate hydrocarbon (oil and natural gas) production. Specifically, hydraulic fracturing is used to produce commercial quantities of oil and natural gas from reservoirs that were previously unproductive. Any new laws, regulations or permitting requirements regarding hydraulic fracturing could lead to operational delays, increased operating costs, third party or governmental claims, and could increase our costs of compliance and doing business as well as delay the development of oil and natural gas resources from shale formations, which are not commercial without the use of hydraulic fracturing. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we are ultimately able to produce from our reserves.

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

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

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

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

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

Although confidentiality agreements are signed by third parties prior to the disclosure of any confidential information, a breach could put us at competitive risk and may cause significant damage to our business. The harm to our business from a breach of confidentiality cannot presently be quantified, but may be material and may not be compensable in damages. There is no assurance that, in the event of a breach

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of confidentiality, we will be able to obtain equitable remedies, such as injunctive relief, from a court of competent jurisdiction in a timely manner, if at all, in order to prevent or mitigate any damage to its business that such a breach of confidentiality may cause.

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

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

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

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

Wet weather and spring thaw may make the ground unstable. Consequently, municipalities and provincial transportation departments enforce road bans that restrict the movement of rigs and other heavy equipment, thereby reducing activity levels. Also, certain oil and natural gas producing areas are located in areas that are inaccessible other than during the winter months because the ground surrounding the sites in these areas consists of swampy terrain. Seasonal factors and unexpected weather patterns may lead to declines in exploration and production activity and corresponding declines in the demand for our goods and services.

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

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

Delays in business operations could adversely affect dividends to Shareholders and the market price of the Common Shares.

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

• restrictions imposed by lenders;

• accounting delays;

• delays in the sale or delivery of products;

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

• blowouts or other accidents;

• adjustments for prior periods;

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

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

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

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

The market price of our Common Shares is sensitive to a variety of market based factors including, but not limited to, interest rates, foreign exchange rates and the comparability of the Common Shares to other yield-oriented securities. Any changes in these market‑based factors may adversely affect the trading price of the Common Shares.

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

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

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

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

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

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

• the availability of processing capacity;

• the availability and proximity of pipeline capacity;

• the availability of storage capacity;

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

• the availability of alternative fuel sources;

• the effects of inclement weather;

• the availability of drilling and related equipment;

• unexpected cost increases;

• accidental events;

• currency fluctuations;

• changes in regulations;

• the availability and productivity of skilled labour; and

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

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

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

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

Potential conflicts of interest.

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

Asset Concentration

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

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LindberghThermal Project Specific Risks

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

Early Stage of Development

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

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

• breakdown or failure of equipment or processes;

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

• design errors;

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

• labour disputes, disruptions or declines in productivity;

• increases in materials or labour costs;

• conditions imposed by regulatory approvals;

• delays induced by weather;

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

• errors in construction;

• changes in project scope;

• unforeseen site surface or subsurface conditions;

• transportation or construction accidents;

• permit requirement violation;

• availability of water supplies;

• reservoir performance;

• energy supply disruption; and

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

The Lindbergh thermal project is not being constructed on a turn-key basis. Additionally, given the state of development of the Lindbergh thermal project, various changes to the project may be made. Based upon current scheduling, the project is not expected to start commercial SAGD operations until the fourth quarter of 2014 at the earliest. The information contained herein related to the Lindbergh thermal project, including, without limitation, reserve and economic evaluations, assumes receipt of all regulatory approvals and no material changes being made to the project or its scope.

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

PENGROWTH ENERGY CORPORATION ANNUAL INFORMATION FORM | 51

Operating Costs

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

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

• the cost of catalyst and chemicals;

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

• the cost of natural gas and electricity;

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

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

• reliability of the facilities;

• the maintenance cost of the facilities;

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

• the cost of insurance; and

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

Infrastructure for the Lindbergh Thermal Project

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

In-situ Extraction

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

Recovery of Bitumen

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

Access to Diluent Supplies at Favourable Prices

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

Marketing of Production

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

52 | ANNUAL INFORMATION FORM

Regulatory Approvals

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

MARKET FOR SECURITIES

Our outstanding Common Shares are listed and posted for trading on the NYSE under the symbol "PGH" and on the TSX under the symbol "PGF". The following tables set forth certain trading information for the Common Shares in 2013 as reported by the TSX and the NYSE.

	TSX			NYSE
	($) High	($) Low	Volume	(US$) High	(US$) Low	Volume
January	5.06	4.38	24,770,780	5.14	4.36	39,840,933
February	4.78	3.93	17,843,236	4.79	3.82	45,372,192
March	5.79	4.38	23,456,156	5.68	4.24	63,787,784
April	5.29	4.58	14,306,121	5.21	4.46	38,510,400
May	5.38	4.96	11,767,549	5.33	4.92	33,301,947
June	5.49	4.83	10,451,462	5.32	4.58	33,347,634
July	6.25	4.99	18,473,983	6.06	4.72	40,181,678
August	6.10	5.53	10,039,411	5.88	5.31	26,542,086
September	6.21	5.82	15,818,773	6.02	5.53	31,107,714
October	6.73	6.04	18,833,724	6.50	5.86	33,172,099
November	6.82	6.31	16,466,374	6.55	6.02	29,177,513
December	6.84	6.52	14,181,381	6.42	6.12	28,185,324

Our 6.25% Series A Convertible Debentures are listed and posted for trading on the TSX under the symbol "PGF.DB.A". Our 6.25% Series B Convertible Debentures are listed and posted for trading on the TSX under the symbol "PGF.DB.B". The following table sets forth certain trading information for the 6.25% Series A Convertible Debentures and 6.25% Series B Convertible Debentures in 2013 as reported by the TSX.

	6.25% SERIES A CONVERTIBLE DEBENTURES			6.25% SERIES B CONVERTIBLE DEBENTURES
	($) High	($) Low	Volume	($) High	($) Low	Volume
January	103.25	101.32	1,150,000	103.50	100.40	5,735,000
February	102.06	100.11	2,151,500	101.80	99.70	5,604,000
March	102.90	100.65	2,483,000	103.00	99.80	2,549,000
April	103.01	102.07	1,627,000	102.45	101.00	3,554,000
May	102.65	101.41	1,077,000	101.75	101.00	5,029,000
June	102.10	101.51	1,008,000	102.80	101.40	2,234,000
July	102.00	101.02	619,000	102.95	101.50	2,912,000
August	102.32	101.50	874,000	102.76	101.50	1,259,000
September	102.38	101.66	1,748,000	102.50	101.30	2,831,000
October	103.50	101.90	743,000	103.63	101.85	3,652,000
November	103.25	102.00	2,860,000	103.99	102.26	686,000
December	102.75	102.02	2,106,000	103.25	102.00	1,014,000

PENGROWTH ENERGY CORPORATION ANNUAL INFORMATION FORM | 53

DIRECTORS AND OFFICERS

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

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

54 | ANNUAL INFORMATION FORM

Name and Jurisdiction of Residence	Position with Pengrowth(1)	Principal Occupation
Frederic D. Kerr Alberta, Canada	Vice President, Investor Relations	Vice President, Investor Relations of Pengrowth since April 2012 and prior thereto Vice President, Institutional Sales of Acumen Capital Partners (investment banking firm).
Marlon J. McDougall Alberta, Canada	Chief Operating Officer	Chief Operating Officer of Pengrowth since August 2011 and prior thereto, Vice President Operations & Chief Operating Officer of NAL Resources (energy company).
Deric S. Orton(7)  Alberta, Canada	Vice President, Land	Vice President, Land of Pengrowth since June 2012 and prior thereto Director, Land of NAL Resources Corp.
Robert W. Rosine Alberta, Canada	Executive Vice-President, Business Development	Executive Vice President, Business Development of Pengrowth since March 2010 and prior thereto President of Mancal Energy Inc. (energy company).
Christopher G. Webster Alberta, Canada	Chief Financial Officer	Chief Financial Officer of Pengrowth.

Notes:

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

(2) Member of Corporate Governance and Nominating Committee.

(3) Member of Compensation Committee.

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

(5) Member of Audit and Risk Committee.

(6) Mr. 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.

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

As at December 31, 2013, the foregoing directors and officers, as a group, beneficially owned, directly or indirectly, 2,038,321 Common Shares or approximately 0.39 percent of the issued and outstanding Common Shares and held rights and options to acquire a further 3,710,766 Common Shares (assuming 100 percent vesting of all performance-based rights). The information as to shares beneficially owned, not being within our knowledge, has been furnished by the respective individuals.

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

CORPORATE CEASE TRADE ORDERS, BANKRUPTCIES, PERSONAL BANKRUPTCIES, PENALTIES OR SANCTIONS

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

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

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

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

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

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

PENGROWTH ENERGY CORPORATION ANNUAL INFORMATION FORM | 55

AUDIT AND RISK COMMITTEE

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

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

PRINCIPAL ACCOUNTANT FEES AND SERVICES

The following table provides information about the aggregate fees billed to us for professional services rendered by KPMG LLP during fiscal 2013 and 2012:

	2013 ($M)	2012 ($M)
Audit Fees	1,012	1,061
Audit Related Fees	-	-
Tax Fees	49	96
All Other Fees	149	176
Total	1,210	1,333

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.

56 | ANNUAL INFORMATION FORM

Audit-Related Fees

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

Tax Fees

During 2013 and 2012 the services provided in this category included assistance and advice in relation to the preparation of income tax returns for us and our subsidiaries, tax advice and planning and commodity tax consultation.

All Other Fees

During 2013 and 2012 the services provided in this category relate to translation of financial statements, management discussion and analysis and other regulatory filings into French.

PRE-APPROVAL POLICIES AND PROCEDURES

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

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

CONFLICTS OF INTEREST

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

• the issuance of additional Common Shares;

• material acquisitions and dispositions of properties;

• material capital expenditures;

• borrowing; and

• the payment of dividends.

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

LEGAL PROCEEDINGS

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

PENGROWTH ENERGY CORPORATION ANNUAL INFORMATION FORM | 57

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.

58 | ANNUAL INFORMATION FORM

INTERESTS OF EXPERTS

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

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

AUDITORS, TRANSFER AGENT AND REGISTRAR

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

MATERIAL CONTRACTS

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

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

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

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

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

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

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

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

CODE OF ETHICS

Pengrowth has adopted a code of ethics, as that term is defined in Form 40-F under the US Securities Exchange Act of 1934 (the "Code of Ethics") that applies to Pengrowth's management, including its Chief Executive Officer, Chief Financial Officer and principal accounting 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. Requests for copies of the "Code of Ethics" should be made by contacting: Investor Relations, Pengrowth Energy Corporation, Suite 2100, 222 – 3^rd Avenue S.W., Calgary, Alberta, Canada, T2P 0B4.

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

During the year ended December 31, 2013, Pengrowth has not granted any waivers (including implicit waivers) from the Code of Ethics in respect of its Chief Executive Officer, Chief Financial Officer or its principal accounting officers.

OFF-BALANCE SHEET ARRANGEMENTS

Pengrowth has no off-balance sheet arrangements.

DISCLOSURE PURSUANT TO THE REQUIREMENTS
OF THE NEW YORK STOCK EXCHANGE

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

The Board of Directors of the Corporation has adopted and published a Corporate Governance Policy which affirms Pengrowth's commitment to maintaining a high standard of corporate governance. This policy is published on Pengrowth's website at www.pengrowth.com. The Board of Directors of the Corporation has also adopted Terms of Reference for each of an Audit and Risk Committee, a Corporate Governance and Nominating Committee, a Compensation Committee, and a Reserves, Health, Safety and

PENGROWTH ENERGY CORPORATION ANNUAL INFORMATION FORM | 59

Environment Committee, a Code of Business Conduct and Ethics, a Corporate Disclosure Policy and an Insider Trading Policy each of which is published on Pengrowth's website, and is available in print to any Shareholder who requests it. The Audit and Risk Committee's Terms of Reference are attached hereto as Appendix C. From time to time, special committees of the Board of Directors are formed with prescribed mandates.

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

ADDITIONAL INFORMATION

Additional information, including directors' and officers' remuneration, the principal holders of Common Shares and securities authorized for issuance under equity compensation plans, is contained in our Management Information Circular which relates to the Annual Meeting of Shareholders to be held on June 24, 2014. Additional financial information is contained in our comparative financial statements and associated management's discussion and analysis for the years ended December 31, 2013, 2012 and 2011.

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

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

Investor Relations

Pengrowth Energy Corporation

Suite 2100, 222 – 3rd Avenue S.W.

Calgary, Alberta T2P 0B4

Telephone: (403) 233-0224

Toll Free: (855) 336-8814

Facsimile: (403) 265-6251

Website: www.pengrowth.com

E-mail: investorrelations@pengrowth.com

60 | ANNUAL INFORMATION FORM

APPENDIX A

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

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

1. We have evaluated the Company's reserves data as at December 31, 2013. The reserves data are estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2013, estimated using forecast prices and costs.

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

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

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

4. The following table sets forth the estimated future net revenue (before deduction of income taxes) attributed to proved plus probable reserves, estimated using forecast prices and costs and calculated using a discount rate of 10 percent, included in the reserves data of the Company evaluated by us for the year ended December 31, 2013, and identifies the respective portions thereof that we have audited, evaluated and reviewed and reported on to the Company's board of directors:

Independent Qualified Reserves Evaluator	Description and Preparation Date of Evaluation Report	Location of Reserves (Country or Foreign Geographic Area)	Net Present Value of Future Net Revenue (before income taxes, 10% discount rate - $M)
			Audited	Evaluated	Reviewed	Total
GLJ Petroleum Consultants	Corporate Summary January 21, 2014	Canada	-	5,147,810	-	5,147,810

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

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

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

EXECUTED as to our report referred to above:

GLJ Petroleum Consultants Ltd., Calgary, Alberta, Canada, February 27, 2014.

(signed) "Doug Sutton"

Doug R. Sutton, P.Eng.

Vice President

APPENDIX A | PENGROWTH ENERGY CORPORATION ANNUAL INFORMATION FORM

APPENDIX B

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

Management of Pengrowth Energy Corporation (the "Corporation") are responsible for the preparation and disclosure of information with respect to the Corporation’s oil and gas activities in accordance with securities regulatory requirements. This information includes reserves data, which are estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2013, estimated using forecast prices and costs.

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

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

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

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

(c) reviewed the reserves data with management and the independent qualified reserves evaluator.

The Reserves, Health, Safety and Environment Committee of the board of directors has reviewed the Corporation's procedures for assembling and reporting other information associated with oil and gas activities and has reviewed that information with management. The board of directors has, on the recommendation of the Reserves, Health, Safety and Environment Committee, approved:

(a) the content and filing with securities regulatory authorities of Form 51-101F1 containing reserves data and other oil and gas information;

(b) the filing of Form 51-101F2 which is the report of the independent qualified reserves evaluator on the reserves data; and

(c) the content and filing of this report.

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

(signed) "Derek W. Evans"

Derek W. Evans

President and Chief Executive Officer

Pengrowth Energy Corporation

(signed) "Bob Rosine"

Bob Rosine

Executive Vice President, Business Development

Pengrowth Energy Corporation

(signed) "Wayne K. Foo"

Wayne K. Foo

Director

Pengrowth Energy Corporation

(signed) "Kelvin B. Johnston"

Kelvin B. Johnston

Director

Pengrowth Energy Corporation

February 28, 2014

PENGROWTH ENERGY CORPORATION ANNUAL INFORMATION FORM | APPENDIX B

APPENDIX C

AUDIT AND RISK COMMITTEETERMS OF REFERENCE

	PENGROWTH ENERGY CORPORATION Policies and Practices	Page 1 of 11
TERMS OF REFERENCE AUDIT AND RISK COMMITTEE

OBJECTIVES

The Audit and Risk Committee (the "Committee") is appointed by the board of directors (the "Board") of Pengrowth Energy Corporation (the "Corporation") to assist the Board in fulfilling its oversight responsibilities. The Corporation, together with its subsidiaries and affiliates, are collectively referred to herein as "Pengrowth".

The Committee's primary duties and responsibilities are to:

• monitor the performance of Pengrowth's internal audit function and the integrity of Pengrowth's financial reporting process and systems of internal controls regarding finance, accounting, and legal compliance;

• assist Board oversight of: (i) the integrity of Pengrowth's financial statements; (ii) Pengrowth's compliance with legal and regulatory requirements; and (iii) the performance of Pengrowth's internal audit function and independent auditors;

• monitor the independence, qualification and performance of Pengrowth's external auditors;

• provide an avenue of communication among the external auditors, the internal auditors, management and the Board; and

• oversee Pengrowth’s risk management processes.

The Committee will continuously review and modify its terms of reference with regards to, and to reflect changes in, the business environment, industry standards on matters of corporate governance, additional standards which the Committee believes may be applicable to Pengrowth's business, the location of Pengrowth's business and its shareholders and the application of laws and policies.

COMPOSITION

Committee members must meet the requirements of applicable securities laws and each of the stock exchanges on which the shares of Pengrowth trade. The Committee will be comprised of three or more directors as determined by the Board. Each member of the Committee shall be "independent" and "financially literate", as those terms are defined in National Instrument 52-110 Audit Committees ("NI 52-110") of the Canadian Securities Administrators (as set out in Schedule "A" hereto), Rule 10A-3 promulgated under the Securities Exchange Act of 1934 (as set out in Schedule "B" hereto), and Section 303A.02 of the New York Stock Exchange Listed Company Manual (as set out in Schedule "C" hereto), as applicable, and as "financially literate" is interpreted by the Board in its business judgement. In addition, at least one member of the Committee must have accounting or related financial management expertise as defined by paragraph (8) of general instruction B to Form 40‑F and as interpreted by the Board in its business judgement.

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

The chair of the Committee will be appointed by the Board or, if one is not appointed, the members of the Committee may elect a chair by vote of a majority of the membership of such committee.

PENGROWTH ENERGY CORPORATION ANNUAL INFORMATION FORM | APPENDIX C

MEETINGS AND MINUTES

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

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

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

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

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

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

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

SCOPE, DUTIES AND RESPONSIBILITIES

MANDATORY DUTIES

REVIEW PROCEDURES

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

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

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

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

PENGROWTH ENERGY CORPORATION ANNUAL INFORMATION FORM | APPENDIX C

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

EXTERNAL AUDITORS

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

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

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

OTHER COMMITTEE RESPONSIBILITIES

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

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

DISCRETIONARY DUTIES

The Committee's responsibilities may, at the 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 Committee.

APPENDIX C | PENGROWTH ENERGY CORPORATION ANNUAL INFORMATION FORM

INTERNAL AUDITORS

1. Review the annual audit plans of the internal auditors.

2. Review the significant findings prepared by the internal auditors and recommendations issued by any external party relating to internal audit issues, together with management's response.

3. Review the adequacy of the resources of the internal auditors to ensure the objectivity and independence of the internal audit function.

4. Consult with management on management's appointment, replacement, reassignment or dismissal of the internal auditors.

5. Ensure that the internal auditors have access to the Chairman of the Board and the President and CEO.

EXTERNAL AUDITORS

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

2. The Committee shall review the external auditors audit plan – discuss scope, staffing, locations, and reliance upon management and general audit approach.

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

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

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

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

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

RISK MANAGEMENT POLICIES

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

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

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

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

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

RISK MANAGEMENT PROCESSES

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

PENGROWTH ENERGY CORPORATION ANNUAL INFORMATION FORM | APPENDIX C

FINANCIAL RISK MANAGEMENT

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

OTHER COMMITTEE RESPONSIBILITIES

1. On at least an annual basis, review with Pengrowth's legal counsel any legal matters that could have a significant impact on the organization's financial statements, Pengrowth's compliance with applicable laws and regulations, and inquiries received from regulators or governmental agencies.

2. Annually prepare a report to shareholders as required by the United States' Securities and Exchange Commission; the report should be included in Pengrowth's annual information circular.

3. Ensure due compliance with each obligation to certify, on an annual and interim basis, internal control over financial reporting and disclosure controls and procedures in accordance with applicable securities laws and regulations.

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

5. Perform any other activities consistent with this Charter, Pengrowth's by-laws, and other governing law as the Committee or the Board deems necessary or appropriate.

6. Maintain minutes of meetings and periodically report to the Board on significant results of the foregoing activities.

COMMUNICATION, AUTHORITYTOENGAGEADVISORSANDEXPENSES

The Committee shall have direct access to such officers and employees of Pengrowth, to Pengrowth's internal and external auditors and to any other consultants or advisors, as well as to such information respecting Pengrowth it considers necessary to perform its duties and responsibilities.

Any employee may bring before the Committee, on a confidential basis, any concerns relating to matters over which the Committee has oversight responsibilities.

The Committee has the authority to engage the external auditors, independent legal counsel and other advisors as it determines necessary to carry out its duties and to set the compensation for any auditors, counsel and other advisors, such engagement to be at Pengrowth's expense. Pengrowth shall be responsible for all other expenses of the Committee that are deemed necessary or appropriate by the Committee in order to carry out its duties.

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

Last reviewed and approved by the Board of Pengrowth on October 28, 2013.

APPENDIX C | PENGROWTH ENERGY CORPORATION ANNUAL INFORMATION FORM

Schedule "A"

Excerpt from Multilateral Instrument 52-110

Meaning of "Independence"

1. An audit committee member is independent if he or she has no direct or indirect material relationship with Pengrowth.

2. For the purposes of paragraph 1, a "material relationship" is a relationship which could, in the view of the Board, be reasonably expected to interfere with the exercise of a member's independent judgment.

3. Despite paragraph 2, the following individuals are considered to have a material relationship with Pengrowth:

(a) an individual who is, or has been within the last three years, an employee or executive officer of Pengrowth;

(b) an individual whose immediate family member is, or has been within the last three years, an executive officer of Pengrowth;

(c) an individual who:

i. is a partner of a firm that is Pengrowth's internal or external auditor,

ii. is an employee of that firm, or

iii. was within the last three years a partner or employee of that firm and personally worked on Pengrowth's audit within that time;

(d) an individual whose spouse, minor child or stepchild, or child or stepchild who shares a home with the individual:

i. is a partner of a firm that is Pengrowth's internal or external auditor,

ii. is an employee of that firm and participates in its audit, assurance or tax compliance (but not tax planning) practice, or

iii. was within the last three years a partner or employee of that firm and personally worked on Pengrowth's audit within that time;

(e) an individual who, or whose immediate family member, is or has been within the last three years, an executive officer of an entity if any of Pengrowth's current executive officers serves or served at that same time on the entity's compensation committee; and

(f) an individual who received, or whose immediate family member who is employed as an executive officer of Pengrowth received, more than $75,000 in direct compensation from Pengrowth during any 12 month period within the last three years.

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

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

(a) remuneration for acting as a member of the Board or 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

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

(a) has previously acted as an interim chief executive officer of Pengrowth, or

(b) acts, or has previously acted, as a chair or vice-chair of the Board or of any Board committee of Pengrowth on a part-time basis.

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

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

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

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

is considered to have a material relationship with Pengrowth.

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

(a) an individual's spouse, minor child or stepchild, or a child or stepchild who shares the individual's home; or

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

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

Standard of "Financial Literacy"

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

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

Schedule "B"

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

Standard of "Independence"

b.    Required standards.

1.    Independence.

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

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

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

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

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

1.

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

ii.    

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

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

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

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

iii. The following will be deemed to be affiliates:

A.    An executive officer of an affiliate;

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

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

C.    A general partner of an affiliate; and

D.    A managing member of an affiliate.

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

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

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

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

Schedule "C"

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

303A.02 "Independence" Tests

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

PENGROWTH ENERGY CORPORATION2100, 222 Third Avenue S.W., Calgary, AB T2P 0B4 Canada

Phone: 403.233.0224 | Toll free: 800.223.4122 | Fax: 403.265.6251
www.pengrowth.com

Investor Relations

Phone: 403.233.0224 | Toll free: 855.336.8814

E-mail: investorrelations@pengrowth.com

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