Exhibit 99.1







ANNUAL INFORMATION
FORM



FOR THE YEAR ENDED



DECEMBER 31, 2011



March 12,
2012











TABLE OF
CONTENTS



|CONVENTIONS                                                                       |  | 1 
|--------------------------------------------------------------------------------- |  | --
|ABBREVIATIONS                                                                     |  | 1 
|CONVERSIONs                                                                       |  | 2 
|SPECIAL NOTE REGARDING FORWARD-LOOKING INFORMATION AND STATEMENTS                 |  | 2 
|CORPORATE STRUCTURE                                                               |  | 4 
|GENERAL DEVELOPMENT OF THE BUSINESS                                               |  | 5 
|OTHER BUSINESS INFORMATION                                                        |  | 8 
|STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION                      |  | 10
|INDUSTRY CONDITIONS                                                               |  | 30
|RISK FACTORS                                                                      |  | 39
|MARKET FOR SECURITIES                                                             |  | 51
|DESCRIPTION OF CAPITAL STRUCTURE                                                  |  | 53
|ESCROWED SECURITIES AND SECURITIES SUBJECT TO CONTRACTUAL RESTRICTION ON TRANSFER |  | 55
|DIRECTORS AND OFFICERS                                                            |  | 55
|AUDIT COMMITTEE INFORMATION                                                       |  | 60
|LEGAL PROCEEDINGS AND REGULATORY ACTIONS                                          |  | 62
|INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS                        |  | 63
|TRANSFER AGENT AND REGISTRAR                                                      |  | 63
|MATERIAL CONTRACTS                                                                |  | 63
|INTEREST OF EXPERTS                                                               |  | 63
|ADDITIONAL INFORMATION                                                            |  | 63



APPENDICES



|APPENDIX A | – | REPORT OF MANAGEMENT AND DIRECTORS ON OIL AND GAS DISCLOSURE IN ACCORDANCE WITH FORM 51-101F3     
|---------- | - | --------------------------------------------------------------------------------------------------
|APPENDIX B | – | REPORT ON RESERVES DATA BY MCDANIEL & ASSOCIATES CONSULTANTS LTD. IN ACCORDANCE WITH FORM 51-101F2
|APPENDIX C | – | AUDIT COMMITTEE CHARTER                                                                           











CONVENTIONS



A reference in this Annual Information
Form to "Perpetual" or the "Corporation" means Perpetual Energy Inc. Perpetual is an oil and
natural gas exploration and production company headquartered in Calgary, Alberta. The Corporation has been actively transitioning
its asset base from primarily shallow gas production to a diversified, resource-style growth-oriented platform for growth. Perpetual
currently has liquids-rich natural gas assets in the Deep Basin of west central Alberta, heavy oil production in eastern Alberta,
a natural gas storage facility and oilsands leases in northern Alberta to complement its shallow gas production base.



On June 30, 2010, Perpetual announced that
the Corporation had completed the previously announced plan of arrangement (the “Arrangement”) involving Perpetual,
Paramount Energy Trust (the “Trust”) and Paramount Energy Operating Corp. pursuant to which the Trust converted
into the Corporation. Unitholders of the Trust voted in favor of the Arrangement at the Annual General and Special Meeting of Trust
Unitholders held on June 17, 2010. Former Unitholders of the Trust received common shares of Perpetual in consideration for the
cancellation of their Trust Units on a one-for-one basis. In addition, as part of the Arrangement, the Trust was dissolved and
the Corporation assumed all of the existing liabilities of the Trust, including the Trust's outstanding convertible debentures
which are now convertible debentures of the Corporation.



References to “Common Shares”
and “Shareholders” are references to the securities of the Corporation and the holders thereof following the
conversion date, and references to “dividends” are references to dividends paid by Perpetual following the conversion
date and to distributions paid by the Trust prior to the conversion date, as the context may require.



Certain other terms
used but not defined herein are defined in National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities
("NI 51-101") and in the Canadian Oil and Gas Evaluation Handbook Volume I (the "COGE Handbook").
Unless otherwise specified, information in this Annual Information Form is as at the end of the Corporation's most recently completed
financial year, being December 31, 2011. All dollar amounts herein are in Canadian dollars, unless otherwise stated. Words importing
the singular also include the plural, and vice versa, and words importing one gender include all genders.



ABBREVIATIONS



|Natural Gas |                                        | Oil and Liquids
|----------- | -------------------------------------- | ---------------
|Mcf         | thousand cubic feet                    |                
|Mcfe        | thousand cubic feet equivalent         |                
|MMcf        | million cubic feet                     |                
|MMcfe       | million cubic feet equivalent          |                
|Bcf         | billion cubic feet                     |                
|Bcfe        | billion cubic feet equivalent          |                
|Mcf/d       | thousand cubic feet per day            |                
|MMcf/d      | million cubic feet per day             |                
|Mcfe/d      | thousand cubic feet equivalent per day |                
|m3          | cubic metres                           |                
|MMbtu       | million British Thermal Units          |                
|GJ          | Gigajoule                              |                



Approximately 93% of the Corporation's
annual production volumes and 90% of its proved and probable reserves are related to natural gas and, as such, the Corporation
reports production and reserves in Mcf equivalent (Mcfe). Mcfe and BOE may be misleading, particularly if used in isolation. In
accordance with NI 51-101, an Mcfe and BOE conversion ratio for crude oil and natural gas of 1 Bbl: 6 Mcf has been used, which
is based on an energy equivalency conversion method primarily applicable at the burner tip and does not necessarily represent a
value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil as compared to natural gas
is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication
of value.



1







CONVERSIONs



The following table sets forth certain
conversions between Standard Imperial Units and the International System of Units (or metric units).



|To
        Convert From |  | To           |  | Multiply By
|----------------------- |  | ------------ |  | -----------
|Mcf                     |  | cubic metres |  | 28.174     
|cubic metres            |  | cubic feet   |  | 35.494     
|bbls                    |  | cubic metres |  | 0.159      
|cubic metres            |  | bbls         |  | 6.293      
|feet                    |  | metres       |  | 0.305      
|metres                  |  | feet         |  | 3.281      
|miles                   |  | kilometres   |  | 1.609      
|kilometres              |  | miles        |  | 0.621      
|acres                   |  | hectares     |  | 0.405      
|hectares                |  | acres        |  | 2.471      
|gigajoules              |  | MMbtu        |  | 0.950      



SPECIAL
NOTE REGARDING FORWARD-LOOKING INFORMATION AND STATEMENTS



Certain statements contained in this Annual
Information Form constitute forward-looking information and statements within the meaning of applicable securities laws. This information
and these statements relate to future events or to Perpetual's future performance. All statements other than statements of historical
fact may be forward-looking statements. The use of any of the words "anticipate", "continue", "estimate",
"expect", “forecast”, "may", "will", "project", "should", "believe",
"outlook", "guidance", "objective", "plans", "intends", "targeting",
"could", "potential", "outlook", "strategy" and any similar expressions are intended to
identify forward-looking information and statements.



In particular, but without limiting the
foregoing, this Annual Information Form contains forward-looking information and statements pertaining to the following:



| | · | the quantity and recoverability of the Corporation's reserves and resources;
| | - | ----------------------------------------------------------------------------

| | · | the timing and amount of future production;
| | - | -------------------------------------------

| | · | future prices as well as supply and demand for natural gas and oil;
| | - | -------------------------------------------------------------------

| | · | the existence, operations and strategy of the commodity price risk management program;
| | - | --------------------------------------------------------------------------------------

| | · | the approximate amount of forward sales and hedging to be employed, and the value of financial
forward natural gas contracts;
| | - | -----------------------------------------------------------------------------------------------------------------------------

| | · | funds flow sensitivities to commodity price, production, foreign exchange and interest rate changes;
| | - | ----------------------------------------------------------------------------------------------------

| | · | operating, general and administrative, and other expenses;
| | - | ----------------------------------------------------------

| | · | amount of future abandonment and reclamation costs, decommissioning and environmental obligations;
| | - | --------------------------------------------------------------------------------------------------

| | · | the use of exploration and development activity, prudent asset management, and acquisitions to
sustain, replace or add to reserves and production or expand the Corporation's asset base;
| | - | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | · | the Corporation's acquisition strategy and the existence of acquisition opportunities, the criteria
to be considered in connection therewith and the benefits to be derived there from;
| | - | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | · | the Corporation’s divestiture strategy;
| | - | ---------------------------------------

| | · | the Corporation’s commodity diversification and asset base transformation strategy;
| | - | -----------------------------------------------------------------------------------

| | · | the Corporation’s business plan;
| | - | --------------------------------

| | · | future growth in the Corporation’s funds flow;
| | - | ----------------------------------------------

| | · | the Corporation's ability to benefit from the combination of growth opportunities and the ability
to grow through the capital markets;
| | - | --------------------------------------------------------------------------------------------------------------------------------------

| | · | expected book value and related tax value of the Corporation's assets and prospect inventory and
estimates of net asset value;
| | - | ------------------------------------------------------------------------------------------------------------------------------

| | · | ability to fund exploration and development;
| | - | --------------------------------------------

2







| | · | expectations regarding the Corporation's access to capital to fund its acquisition, exploration
and development activities;
| | - | ---------------------------------------------------------------------------------------------------------------------------

| | · | expected realization of gas over bitumen royalty adjustments;
| | - | -------------------------------------------------------------

| | · | deferred income tax and its effect on funds flow;
| | - | -------------------------------------------------

| | · | intentions with respect to preservation of tax pools of and taxes payable by the Corporation;
| | - | ---------------------------------------------------------------------------------------------

| | · | funding of and anticipated results from capital expenditure programs;
| | - | ---------------------------------------------------------------------

| | · | renewal of and borrowing costs associated with the credit facility;
| | - | -------------------------------------------------------------------

| | · | future debt levels, financial capacity, liquidity and capital resources;
| | - | ------------------------------------------------------------------------

| | · | future contractual commitments;
| | - | -------------------------------

| | · | drilling, completion, facilities and construction plans;
| | - | --------------------------------------------------------

| | · | future drilling, workovers and recompletions estimated in Perpetual’s prospect inventory;
| | - | -----------------------------------------------------------------------------------------

| | · | the impact of Canadian federal and provincial governmental regulation on the Corporation relative
to other issuers;
| | - | -------------------------------------------------------------------------------------------------------------------

| | · | Crown royalty rates;
| | - | --------------------

| | · | working gas capacity and other operating and marketing parameters related to Warwick Gas Storage
Inc.;
| | - | ------------------------------------------------------------------------------------------------------

| | · | the Corporation's treatment under governmental regulatory regimes;
| | - | ------------------------------------------------------------------

| | · | business strategies and plans of management, including future changes in the structure of business
operations;
| | - | --------------------------------------------------------------------------------------------------------------

| | · | the dividend policy; and
| | - | ------------------------



| | · | the reliance on third parties in the industry to develop and expand the Corporation's assets and
operations.
| | - | ------------------------------------------------------------------------------------------------------------



The forward-looking information and statements
contained in this Annual Information Form reflect several material factors and expectations and assumptions of the Corporation
including, without limitation, that Perpetual will conduct its operations in a manner consistent with its expectations and, where
applicable, consistent with past practice; the general continuance of current or, where applicable, assumed industry conditions;
the continuance of existing, and in certain circumstances, the implementation of proposed tax, royalty and regulatory regimes;
the ability of Perpetual to obtain equipment, services, and supplies in a timely manner to carry out its activities; the accuracy
of the estimates of Perpetual's reserve and resource volumes; the timely receipt of required regulatory approvals; certain commodity
price and other cost assumptions; the timing and costs of storage facility and pipeline construction and expansion and the ability
to secure adequate product transportation; the continued availability of adequate debt and/or equity financing and funds flow to
fund the Corporation's capital and operating requirements as needed; and the extent of Perpetual's liabilities.



Perpetual believes the material factors,
expectations and assumptions reflected in the forward-looking information and statements are reasonable but no assurance can be
given that these factors, expectations and assumptions will prove to be correct. The forward-looking information and statements
included in this Annual Information Form are not guarantees of future performance and should not be unduly relied upon. Such information
and statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ
materially from those anticipated in such forward-looking information or statements including, without limitation:



| | · | volatility in market prices for oil, natural gas, natural gas liquids, power and other products;
| | - | ------------------------------------------------------------------------------------------------

| | · | supply and demand regarding Perpetual's products;
| | - | -------------------------------------------------

| | · | risks inherent in Perpetual's operations, such as production declines, unexpected results, geological,
technical, or drilling and process problems;
| | - | ---------------------------------------------------------------------------------------------------------------------------------------------------

| | · | unanticipated operating events that can reduce production or cause production to be shut-in or
delayed;
| | - | -------------------------------------------------------------------------------------------------------

| | · | unanticipated well or facility operating performance that impacts storage operations or working
gas capacity;
| | - | -------------------------------------------------------------------------------------------------------------

| | · | changes in exploration or development plans by Perpetual or by third party operators of Perpetual's
properties;
| | - | ---------------------------------------------------------------------------------------------------------------

| | · | reliance on industry partners;
| | - | ------------------------------

| | · | uncertainties or inaccuracies associated with estimating reserves and resource volumes;
| | - | ---------------------------------------------------------------------------------------

| | · | competition for, among other things; capital, acquisitions of reserves, undeveloped lands, skilled
personnel, equipment for drilling, completions, facilities and pipeline construction and maintenance;
| | - | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



3







| | · | increased service and operational costs;
| | - | ----------------------------------------

| | · | incorrect assessments of the value of acquisitions;
| | - | ---------------------------------------------------

| | · | increased debt levels or debt service requirements;
| | - | ---------------------------------------------------

| | · | industry conditions including fluctuations in the price of natural gas and related commodities;
| | - | -----------------------------------------------------------------------------------------------

| | · | royalties payable in respect of Perpetual's production;
| | - | -------------------------------------------------------

| | · | governmental regulation of the oil and gas industry, including environmental regulation;
| | - | ----------------------------------------------------------------------------------------

| | · | fluctuation in foreign exchange or interest rates;
| | - | --------------------------------------------------

| | · | the need to obtain required approvals from regulatory authorities;
| | - | ------------------------------------------------------------------

| | · | changes in laws applicable to the Corporation, royalty rates, or other regulatory matters;
| | - | ------------------------------------------------------------------------------------------

| | · | general economic conditions in Canada, the United States and globally;
| | - | ----------------------------------------------------------------------

| | · | stock market volatility and market valuations;
| | - | ----------------------------------------------

| | · | limited, unfavourable, or a lack of access to capital markets; and
| | - | ------------------------------------------------------------------



certain other risks detailed from time
to time in Perpetual's public disclosure documents including, without limitation, those risks and contingencies described above
and under ''Risk Factors" in this Annual Information Form and under ''Risk Factors" in the Corporation's
management's discussion and analysis for the year ended December 31, 2011, which will be available on the Corporation's website
at www.perpetualenergyinc.com as well as at www.sedar.com and at www.sec.gov. The foregoing list of risk factors should not be
considered exhaustive.



The forward-looking information and statements
contained in this Annual Information Form speak only as of the date of this Annual Information Form, and none of the Corporation
or its subsidiaries assumes any obligation to publicly update or revise them to reflect new events or circumstances, unless expressly
required to do so by applicable securities laws.



CORPORATE
STRUCTURE



Name, Address and
Incorporation



Perpetual was incorporated under the Business
Corporations Act (Alberta) (the "ABCA") under the name "Perpetual Energy Inc."on April 26, 2010. Perpetual amalgamated with its wholly-owned subsidiaries 1143046 Alberta
Ltd., POT Acquisition Company Ltd., Profound Energy Inc. (“Profound”) and Starboard Gas (W3) Ltd. on June 30,
2010 and continued as Perpetual Energy Inc.



Perpetual's head office and registered
office is located at Suite 3200, 605 – 5th Avenue S.W., Calgary, Alberta T2P 3H5.



Intercorporate Relationships



The following diagram illustrates the intercorporate
relationship between Perpetual and its material subsidiaries, the percentage of votes attached to all voting securities of the
subsidiaries beneficially owned, or controlled or directed, directly or indirectly, by Perpetual and the jurisdiction of incorporation
or formation of the subsidiaries.



4











GENERAL
DEVELOPMENT OF THE BUSINESS



Three Year History



The general development of Perpetual's
business over the last three completed financial years that include events, such as acquisitions or dispositions, or conditions
that have had an influence on that development, are described below.



2011



During 2011, the Corporation disposed of
assets for proceeds of approximately $41.7 million which included a number of non-core oil and gas properties and undeveloped Cardium
lands in west central Alberta.



On October 19, 2011, the Corporation announced
that future dividend payments would be suspended until further notice. Continued payment of a dividend was deemed to be unsustainable
given the continued weakness in natural gas prices. The continued execution of the strategies to diversify commodity mix and create
value, capitalizing on Perpetual’s substantial inventory of economic opportunities, is expected to grow funds flow. Combined
with ongoing debt reduction initiatives, including asset sales, stronger diversified funds flows will strengthen the Corporation’s
balance sheet. The suspension of the dividend was necessary to drive Perpetual’s commitment to maximize Shareholder value.
Reinstatement of a dividend in the future will be evaluated at such time as Perpetual’s balance sheet has regained strength
and commodity prices and costs support a sustainable model where excess free funds flow, over and above capital investments, is
once again being generated for distribution to holders (“Shareholders”) of the Corporation’s common shares
(“Common Shares”).



In May 2011, Perpetual announced the reduction
of its dividend from $0.03 per share to $0.015 per share. With the strong economic potential of the Wilrich play in west central
Alberta well understood and the horizontal development of the Corporation’s growing inventory of conventional heavy oil prospects
in eastern Alberta showing significant promise, the reduction in the dividend enabled an increased capital spending program in
the second half of 2011 to accelerate the commodity diversification strategy and increase future funds flow.



In April 2011 the Corporation set the working
gas capacity for the second cycle of its Warwick gas storage facility at 17 Bcf.



On March 15, 2011, the Corporation issued
$150 million aggregate principal amount of 8.75% senior unsecured notes due March 15, 2018 (the "Notes").



5







2010



During 2010, the Corporation disposed of
assets for proceeds of approximately $91.3 million including the receipt of 1.6 million common shares of Trioil Resources Ltd.,
a junior oil company focused on the exploration and development of Cardium oil plays in southern Alberta.



Included in the 2010 dispositions, in November
2010, the Corporation sold natural gas assets for gross proceeds of approximately $40.0 million. The disposed assets had proved
plus probable natural gas reserves of 33.4 Bcf. Production of these assets had previously been shut-in by an order from the Energy
Resources Conservation Board ("ERCB") in an effort to protect potential future bitumen production from comingling
with natural gas reserves. As such, the economic benefit to Perpetual was derived from the royalty deductions management could
realize from the shut-in production. Under the terms of the transaction, Perpetual retained the right to the royalty deductions.
See "Risk Factors – Gas Over Bitumen Matters".



On November 8, 2010, Perpetual reduced
its dividend from $0.05/share per month to $0.03/share per month in order to provide Perpetual with additional capital to direct
towards economic new venture development opportunities in the Cardium and Wilrich, the continued evaluation of other new ventures
in the Montney play at Elmworthand the Viking and Colorado shale plays and the further delineation and development of its liquids-rich
gas and light and heavy oil and bitumen resource prospects.



On June 30, 2010, Perpetual completed a
plan of arrangement pursuant to which former Unitholders of the Trust received Common Shares in consideration for the cancellation
of their trust units on a one-for-one basis, the Trust was dissolved and Perpetual assumed all of the existing liabilities of the
Trust, including the Trust's outstanding convertible debentures which are now convertible debentures of the Corporation.



In May 2010, Perpetual began injection
in its gas storage operation which was built using one of its depleted gas reservoirs. The facility is located near three major
pipelines in the Warwick area east of Edmonton.



On April 1, 2010, the Corporation acquired
oil and natural gas assets in the Edson area of west central Alberta for approximately $126 million (the "Edson Acquisition").
The assets acquired pursuant to the Edson Acquisition consisted of 10.1 MMcfe/d of natural gas and liquids production (80% natural
gas) as well as extensive gathering and processing infrastructure and 13,393 net acres of undeveloped prospective lands in a desirable
multi-zone part of the Alberta deep basin.



As part of the Edson Acquisition, Perpetual
agreed to farm-in on 37 gross (31 net) sections of undeveloped Cardium rights in the area of which 22 net sections are believed
to be prospective for light oil. The farm-in included a two well horizontal drilling and completion commitment, each earning 50
percent of the vendor's net interest in four sections followed by a rolling option to earn the additional lands on the same basis.
The Edson Acquisition was funded through a combination of bank debt, the early termination of gas price hedging contracts and an
issue of 12.1 million subscription receipts at a price of $4.75 per subscription receipt for total proceeds of $57.5 million, which
were subsequently converted into 12.1 million trust units of the Trust.



2009



On August 13, 2009, pursuant to a takeover
offer, the conversion of previously issued special warrants, open market purchases and a second stage transaction, the Trust acquired
all of the outstanding common shares of Profound. Cash consideration paid for Profound consisted of $6.9 million for the special
warrants, $3.1 million for the open market share purchases and $14.2 million for the tendered shares, and $3.3 million of acquisition
costs for a total of $27.5 million. In addition, the Trust issued 10 million trust units of the Trust to Profound shareholders
valued at $32.2 million. Through the acquisition of Profound, Perpetual established production in west central Alberta, and secured
deep basin resource-style play opportunities and exposure to development of the Pembina area tight Cardium oil play.



6







Significant Acquisitions



Perpetual did not complete any significant
acquisitions during its most recently completed financial year for which disclosure is required under Part 8 of National Instrument
51-102 – Continuous Disclosure Obligations.



Recent Developments



Perpetual is continuing to pursue additional
asset dispositions to reach the previously announced targeted proceeds of $75 to $150 million in 2012. Since the end of 2011, Perpetual
has closed multiple oil and gas asset dispositions for net proceeds of $64 million.
Included in the dispositions is the sale of 656,000 shares of TriOoil Resources Ltd. The disposed assets are primarily non-core
properties located in eastern and west central Alberta and include approximately 8 MMcf/d of gas production and oil and NGL production
of 390 bbl/d.



The Corporation has $75 million of 6.50%
convertible unsecured subordinated debentures (“6.50% Debentures”) maturing on June 30, 2012. While Perpetual may settle
all or a portion of the outstanding 6.50% Debentures through the issuance of Common Shares by giving notice of such intent to Debentureholders
not more than 30 and not less than 15 days prior to the maturity date, it is the intention of the Corporation to settle the 6.50%
Debentures in cash.



To date in 2012, Perpetual has disposed
of non-core oil and gas assets for total proceeds of approximately $61 million. In addition, as described in note 23 to the annual
consolidated financial statements, the Corporation has identified the WGSI Facility as an asset held for sale subsequent to the
balance sheet date. Perpetual anticipates that cash flows including cash flow from operating activities, proceeds from closed and
future asset dispositions and available credit facilities will provide the required funds to discharge the Corporation’s
existing obligations, carry out exploration and development programs and fund ongoing operations for the foreseeable future, including
the cash settlement of the 6.50% Debentures on the maturity date. Perpetual expects a downward adjustment to the borrowing base
under the Credit Facility pursuant to the semi-annual redetermination of the borrowing base in April 2012, which relates principally
to lower natural gas prices. If available liquidity is not sufficient to meet the Corporation’s operating and debt servicing
obligations as they come due, management’s plans include reducing expenditures as necessary or pursuing alternative financing
arrangements for the foreseeable future.



DESCRIPTION OF THE BUSINESS



General



Perpetual is engaged in finding, exploiting,
producing and marketing oil and gas based energy. Perpetual's business primarily consists of operations in Alberta focused on:
(i)  the development and production of shallow natural gas from mature producing regions in eastern Alberta where the Corporation
has an established gathering, processing and transportation infrastructure; (ii) the exploration and extraction of heavy oil
from properties geographically synergistic with the eastern Alberta gas assets; (iii) exploring and developing the Corporation's
natural gas, natural gas liquids and tight oil resource growth opportunities in the deep basin in west central Alberta; (iv) bitumen
opportunities in northeast Alberta; and (v) the gas storage facility business where the Corporation has a gas storage facility
at Warwick in east central Alberta.



Business Plan



Perpetual's business plan is based upon
an entrepreneurial approach to value creation focused around several key priorities:



| | · | Base Asset Optimization
| | - | -----------------------



| | o | Maximize value of its base shallow gas assets by minimizing
costs; pursuing low cost production and reserve additions through uphole recompletions and low exposure, concentric exploration
of its undeveloped shallow gas land base; and making accretive acquisitions to complement and enhance the value of the shallow
gas opportunity inventory. Excess funds generated are used to fund the diversification and growth strategies.
| | - | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | · | Cash Flow Diversification and Asset Base Transformation
| | - | -------------------------------------------------------



7







| | o | Commodity diversification through exploration and
development of conventional heavy and light oil opportunities, generally synergistic with our base operations; and
| | - | --------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | o | Short term growth and commodity diversification through
exploration and development of resource-style liquids-rich gas in the Alberta Deep Basin, particularly the Wilrich formation in
the greater Edson area and the Montney at Elmworth;
| | - | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | o | Cash flow diversification by pursuing creative energy
business opportunities leveraging our assets and expertise, such as maximizing value from our non-depleting commercial natural
gas storage business at Warwick.
| | - | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | · | High Impact, Long Term Growth
| | - | -----------------------------



| | o | Long term value creation from new venture activities
for resources-style oil and liquid-rich gas plays; and
| | - | -----------------------------------------------------------------------------------------------------------



| | o | Long term growth and value creation through subsurface
bitumen resource definition, evaluation and extraction activities.
| | - | -------------------------------------------------------------------------------------------------------------------------



In recent years, the Corporation has had
significant success in repositioning its asset base to enhance and diversify its production and reserve base and prospect inventory,
adding higher impact, growth oriented, resource-style opportunities to its asset portfolio. These high impact opportunities include
horizontal development of heavy oil at Mannville in east central Alberta, and horizontal development utilizing multi-stage fracture
technology for liquids-rich gas in the Wilrich at Edson and the Montney at Elmworth. Longer term opportunities that have been captured,
resource is being assessed and technologies are being evaluated for gas development potential in the shallow Viking and Colorado
shale in east central Alberta, several bitumen prospects in northeast Alberta and other oil and liquids-rich resource plays in
the Alberta deep basin. Geographic diversity into other regions in North America is within the scope of Perpetual's business plan.



OTHER
BUSINESS INFORMATION



Specialized Skill
and Knowledge



Perpetual employs individuals with various
professional skills in the course of pursuing its business plan. These professional skills include, but are not limited to, geology,
geophysics, engineering, financial and business skills. Drawing on significant experience in the oil and gas business, Perpetual
believes its management team has a demonstrated track record of bringing together all of the key components to a successful exploration
and production company: strong technical and leadership skills; operational and capital project execution expertise; an entrepreneurial
spirit that allows Perpetual to effectively identify, evaluate and execute on value added initiatives; expertise in planning and
financial controls; ability to execute on business development opportunities and capital markets expertise.



Competitive Conditions



The oil and natural gas industry is very
competitive. The Canadian Association of Petroleum Producers estimates that there are over 1,000 exploration and production companies
in Canada. Perpetual controls less than one percent of the business in western Canada, but where it is active, Perpetual believes
it has a strong competitive position to optimize value by minimizing costs and maximizing production and capture of new opportunities.



Companies operating in the petroleum industry
must manage risks which are beyond the direct control of company personnel. Among these risks are those associated with exploration,
reservoir management, commodity prices and markets, foreign exchange rates and interest rates.



The oil and natural gas industry is intensely
competitive and Perpetual competes with a substantial number of other entities, many of which have greater technical or financial
resources. With the maturing nature of the Western Canadian Sedimentary Basin, the access to new prospects is becoming more competitive
and complex.



8







Perpetual attempts to enhance its competitive
position by operating in areas where it believes its technical personnel are able to reduce some of the risks associated with exploration,
production and marketing because we have established core competencies in these areas of operation. Management believes that Perpetual
will be able to explore for and develop new production and reserves with the objective of increasing its funds flow and reserve
base. See "Risk Factors – Competition".



Commodity Price
Cycles



The Company’s operational results
and financial condition will be dependent on commodity prices, specifically the prices of oil, natural gas, natural gas liquids
and seasonal gas price spreads. Commodity prices have fluctuated widely during recent years and are determined by supply and demand
factors including general economic conditions weather, environmental regulations and policies, geopolitical risks, oil and gas
resource extraction technologies, oil fields equipment and services, local and regional access to markets, refining capacity, as
well as operating results and conditions in other oil and natural gas producing regions. The exploration for and the development
of oil and natural gas reserves is dependent on access to areas where drilling is to be conducted. Seasonal weather variation,
including "freeze-up" and "break-up", affect access in certain circumstances. See "Risk Factors –
Seasonality".



Environmental Protection



The oil and natural gas industry is currently
subject to environmental regulations pursuant to a variety of provincial and federal legislation. Compliance with such legislation
may require significant expenditures or result in operational restrictions. Breach of such requirements may result in suspension
or revocation of necessary licenses and authorizations, civil liability for pollution damage and the imposition of material fines
and penalties, all of which might have a significant negative impact on earnings and overall competitiveness of the Corporation.
For a description of the financial and operational effects of environmental protection requirements on the capital expenditures,
earnings and competitive position of Perpetual, see "Industry Conditions – Environmental Regulation" and
"Risk Factors – Environmental".



Employees



At December 31, 2011, Perpetual had 132
permanent employees and 18 consultants located in its Calgary office and 20 permanent employees in its field offices. The Corporation
also had 66 field employees and 39 field hourly consultants at December 31, 2011 in various field locations. Perpetual currently
has 128 permanent employees and 18 consultants located in its Calgary office and 20 permanent employees in its field offices. The
Corporation also has 63 field employees and 38 field hourly consultants.



Reorganizations



Other than disclosed under "General
Development of the Business", Perpetual has not completed any material reorganization within the three most recently completed
financial years or during the current financial year. No material reorganization is currently proposed for the current financial
year. See "General Development of the Business".



Environmental, Health
and Safety Policies



The Corporation supports environmental
protection and worker health and safety through the implementation and communication of the Corporation's environmental management
and health and safety policies, practices and procedures. Committees focused on environment, health and safety ("EH&S")
issues are established in the Corporation's operations which are designed to drive continuous improvement in policies and programs
which target accountability for EH&S by the Corporation, and its employees.  Practices for continuous improvement of EH&S
performance management includes providing employees with job orientation, training, instruction and supervision to build competency,
skill and accountability in conducting daily activities in ahealthy, environmentally responsible
and safe manner.



9







The Corporation develops emergency response
practices, procedures and readiness plans in conjunction with local authorities, emergency services and the communities in which
it operates in order to effectively respond to an environmental or safety incident should it arise. The effectiveness of these
plans are evaluated on a regular basis to ensure preparedness for emergency situations. Environmental and risk assessments are
undertaken for new projects, or when acquiring new properties or facilities in order to identify, assess and minimize environmental
risks, loss and operational exposures. The Corporation conducts audits of operations to measure compliance with internal and industry
standards, and for continuous improvement in practices and procedures. Documentation is maintained to support internal accountability
and measure operational performance against recognized industry indicators to assist in achieving the objectives of the described
policies and programs.



Perpetual’s culture of safety has
been acknowledged through the results of an independent audit for the Certificate of Recognition (COR) program under the Alberta
governments “Partnership in Injury Reduction” initiative. The Corporation was awarded the COR accreditation as the
independent evaluation found we exceeded the Alberta Employment and Immigration Workplace Partnerships standard, an accomplishment
shared amongst a select few in the oil and gas industry.



The Corporation also faces environmental,
health and safety risks in the normal course of its operations due to the handling and storage of hazardous substances. The Corporation's
environmental and health and safety management systems are designed to manage such risks in the Corporation's business and allow
action to be taken to control the risk of environmental, health or safety impacts from such operations. A key aspect of these systems
is the conducting of internal and external inspection and audits of worksites and offices. See “Risk Factors”.



STATEMENT
OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION



Date of Statement



The statement of reserves data and other
oil and gas information set forth below is dated February 6, 2012, has a preparation date of February 6, 2012 and an effective
date of December 31, 2011.



Disclosure of Reserves
Data



The reserves data set forth below is based
upon the figures contained in the report of McDaniel & Associates Consultants Ltd. ("McDaniel") dated effective
December 31, 2011, with a preparation date of February 6, 2012 (the "McDaniel Report") evaluating substantially
all of Perpetual's crude oil, natural gas liquid ("NGL") and natural gas reserves. McDaniel evaluated in the McDaniel
Report 100% of the assigned total proved plus probable reserves and 100% of the total proved plus probable future net revenue discounted
at 10%. McDaniel prepared their reserve report using their own technical assumptions and interpretations, methodologies and pricing
and cost assumptions. Due to rounding, certain columns set forth below in this section may not add.



The McDaniel Report has been prepared in
accordance with the standards contained in the COGE Handbook and the reserve definitions contained in NI 51-101 and the
COGE Handbook. Additional information not required by NI 51-101 has been presented to provide continuity and additional
information which Perpetual believes is important to readers of this Annual Information Form. McDaniel was engaged to provide evaluations
of proved and proved and probable reserves and no attempt was made to evaluate possible reserves.



All of the Corporation's reserves are in
Canada and, more specifically, in the province of Alberta.



The Report on Reserves Data by McDaniel
in Form 51-101F2 is attached as Appendix B to this Annual Information Form and the Report of Management and Directors on Oil and
Gas Disclosure in Form 51-101F3 is attached as Appendix A to this Annual Information Form.



There are numerous uncertainties inherent
in estimating quantities of crude oil, NGL and natural gas reserves and the future cash flows attributed to such reserves. The
reserve and associated cash flow information set forth in this Annual Information Form are estimates only. In general, estimates
of economically recoverable oil, NGL and natural gas reserves and the future net cash flows there from are based upon a number
of variable factors and assumptions, such as historical production from the properties, production rates, ultimate reserve recovery,
timing and amount of capital expenditures, marketability of oil and natural gas, royalty rates, the assumed effects of regulation
by governmental agencies and future operating costs, all of which may vary materially from actual results. For those reasons, estimates
of the economically recoverable crude oil, NGL and natural gas reserves attributable to any particular group of properties, classification
of such reserves based on risk of recovery and estimates of future net revenues associated with reserves prepared by different
engineers, or by the same engineers at different times, may vary. The Corporation's actual production, revenues, taxes and development
and operating expenditures with respect to its reserves will vary from estimates thereof and such variations could be material.



10









The information relating to the Corporation's
crude oil, NGL and natural gas reserves contains forward-looking statements relating to future net revenues, forecast capital expenditures,
future development plans and costs related thereto, forecast operating costs, anticipated production and abandonment costs. See
"Special Note Regarding Forward-Looking Information and Statements" and "Risk Factors – Reserves
Estimates".



It should not be assumed that the estimates
of future net revenues presented in the tables below represent the fair market value of the reserves. There is no assurance that
the forecast prices and costs assumptions will be attained and variances could be material. Actual reserves may be greater than
or less than the estimates provided in this Statement of Reserves and Other Oil and Gas Information.



SUMMARY OF RESERVES

TOTAL RESERVES

as at December 31, 2011

FORECAST PRICES AND COSTS



|                     |  | Light and    |     |  |               |  |     |                 |  |  |             |  |  |             |      
|-------------------- |  | ------------ | --- |  | ------------- |  | --- | --------------- |  |  | ----------- |  |  | ----------- | -----
|                     |  | Medium Crude |     |  |               |  |     |                 |  |  | Natural Gas |  |  | Natural Gas |      
|                     |  | Oil          |     |  | Heavy
    Oil |  |     | Natural
    Gas |  |  | Liquids     |  |  | Equivalent  |      
|RESERVES             |  | Gross        |     |  | Net           |  |     | Gross           |  |  | Net         |  |  | Gross       |      
|CATEGORIES           |  | (Mbbl)       |     |  | (Mbbl)        |  |     | (Mbbl)          |  |  | (Mbbl)      |  |  | (MMcf)      |      
|Proved Producing     |  |              | 408 |  |               |  | 387 |                 |  |  | 893         |  |  |             | 831  
|Proved Non Producing |  |              | 0   |  |               |  | 0   |                 |  |  | 89          |  |  |             | 83   
|Proved Undeveloped   |  |              | 19  |  |               |  | 17  |                 |  |  | 354         |  |  |             | 330  
|Total Proved         |  |              | 427 |  |               |  | 404 |                 |  |  | 1,336       |  |  |             | 1,244
|Total Probable       |  |              | 276 |  |               |  | 253 |                 |  |  | 1,095       |  |  |             | 948  
|Proved and Probable  |  |              | 703 |  |               |  | 658 |                 |  |  | 2,431       |  |  |             | 2,192



Notes:

| | (1) | ”Gross” refers to company interest volumes before royalties
| | --- | -----------------------------------------------------------

| | (2) | ”Net”refers to company interest volumes after royalties
| | --- | -------------------------------------------------------



NET PRESENT VALUE OF FUTURE NET REVENUE

BEFORE TAX

as at December 31, 2011

FORECAST PRICES AND COSTS ($millions)



|                     |  |                                           |       |  |                |  |     |     |  |  |     |  |  |     |     |  | Unit Value    | 
|-------------------- |  | ----------------------------------------- | ----- |  | -------------- |  | --- | --- |  |  | --- |  |  | --- | --- |  | ------------- | 
|                     |  |                                           |       |  |                |  |     |     |  |  |     |  |  |     |     |  | Before Income | 
|                     |  | Before Income Taxes Discounted
    at (%) |       |  | Tax Discounted | 
|RESERVES             |  |                                           |       |  |                |  |     |     |  |  |     |  |  |     |     |  | At 10%/Year   | 
|CATEGORIES           |  | 0%                                        |       |  | 5%             |  |     | 10% |  |  | 15% |  |  | 20% |     |  | ($/Mcfe)      | 
|Proved Producing     |  |                                           | 547   |  |                |  | 448 |     |  |  | 383 |  |  |     | 337 |  |               | 
|Proved Non Producing |  |                                           | 80    |  |                |  | 38  |     |  |  | 24  |  |  |     | 18  |  |               | 
|Proved Undeveloped   |  |                                           | 77    |  |                |  | 42  |     |  |  | 25  |  |  |     | 370 |  |               | 
|Total Proved         |  |                                           | 704   |  |                |  | 528 |     |  |  | 432 |  |  |     | 370 |  |               | 
|Total Probable       |  |                                           | 640   |  |                |  | 408 |     |  |  | 291 |  |  |     | 220 |  |               | 
|Proved and Probable  |  |                                           | 1,344 |  |                |  | 936 |     |  |  | 722 |  |  |     | 589 |  |               | 



11







NET PRESENT VALUE OF FUTURE NET REVENUE

AFTER TAX

as at December 31, 2011

FORECAST PRICES AND COSTS ($millions)



|                     |  |                                          |       |  |               |  |     |     |  |  |     |  |  |     |     |  | Unit Value          | 
|-------------------- |  | ---------------------------------------- | ----- |  | ------------- |  | --- | --- |  |  | --- |  |  | --- | --- |  | ------------------- | 
|                     |  |                                          |       |  |               |  |     |     |  |  |     |  |  |     |     |  | After Income        | 
|                     |  |                                          |       |  |               |  |     |     |  |  |     |  |  |     |     |  | Tax                 | 
|                     |  | After Income Taxes Discounted
    at (%) |       |  | Discounted At | 
|RESERVES             |  |                                          |       |  |               |  |     |     |  |  |     |  |  |     |     |  | 10%/Year            | 
|CATEGORIES           |  | 0%                                       |       |  | 5%            |  |     | 10% |  |  | 15% |  |  | 20% |     |  | ($/Mcfe)
    (1)(2) | 
|Proved Producing     |  |                                          | 547   |  |               |  | 448 |     |  |  | 383 |  |  |     | 337 |  |                     | 
|Proved Non Producing |  |                                          | 80    |  |               |  | 38  |     |  |  | 24  |  |  |     | 18  |  |                     | 
|Proved Undeveloped   |  |                                          | 77    |  |               |  | 42  |     |  |  | 25  |  |  |     | 370 |  |                     | 
|Total Proved         |  |                                          | 704   |  |               |  | 528 |     |  |  | 432 |  |  |     | 370 |  |                     | 
|Total Probable       |  |                                          | 507   |  |               |  | 333 |     |  |  | 240 |  |  |     | 184 |  |                     | 
|Proved and Probable  |  |                                          | 1,211 |  |               |  | 860 |     |  |  | 672 |  |  |     | 554 |  |                     | 



Notes:

| | (1) | The after-tax net present value of the Corporation's oil and gas properties reflects the tax burden
on the properties on a stand-alone basis and utilizes the Corporation’s tax pools.
| | --- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | (2) | The after tax net present value of the Corporation’s oil and gas does not consider the corporate
tax situation, or tax planning. It does not provide an estimate of the value at the level of the corporation, which may be significantly
different. The Corporation's financial statements and the management's discussion and analysis should be consulted for information
at the level of the corporation.
| | --- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



FUTURE NET REVENUE

TOTAL RESERVES (UNDISCOUNTED)

as at December 31, 2011

FORECAST PRICES AND COSTS ($ millions)



|                             |  |         |       |  |           |  |      |              |  |  |           |  |  |             |        |   |             |  |      | Future  |  |  |        |   |  | Future                                                                                                         |      
|---------------------------- |  | ------- | ----- |  | --------- |  | ---- | ------------ |  |  | --------- |  |  | ----------- | ------ | - | ----------- |  | ---- | ------- |  |  | ------ | - |  | -------------------------------------------------------------------------------------------------------------- | -----
|                             |  |         |       |  |           |  |      |              |  |  |           |  |  |             |        |   |             |  |      | Net     |  |  |        |   |  | Net                                                                                                            |      
|                             |  |         |       |  |           |  |      | Gas
    over |  |  |           |  |  |             |        |   | Abandonment |  |      | Revenue |  |  |        |   |  | Revenue                                                                                                        |      
|                             |  |         |       |  |           |  |      | Bitumen      |  |  |           |  |  |             |        |   | and         |  |      | Before  |  |  |        |   |  | After                                                                                                          |      
|RESERVES                     |  |         |       |  |           |  |      | Royalty      |  |  | Operating |  |  | Development |        |   | Reclamation |  |      | Income  |  |  | Income |   |  | Income                                                                                                         |      
|CATEGORIES                   |  | Revenue |       |  | Royalties |  |      | Adjustments  |  |  | Costs     |  |  | Costs       |        |   | Costs       |  |      | Taxes   |  |  | Taxes  |   |  | Taxes
                                                                                                  (1)(2) |      
|Proved Reserves              |  |         | 1,468 |  |           |  | (154 | )            |  |  | 65        |  |  |             | (540   | ) |             |  | (90  | )       |  |  | (46    | ) |  |                                                                                                                | 704  
|Proved and Probable Reserves |  |         | 3,196 |  |           |  | (354 | )            |  |  | 65        |  |  |             | (1,165 | ) |             |  | (318 | )       |  |  | (81    | ) |  |                                                                                                                | 1,344



Notes:

| | (1) | The after-tax net present value of the Corporation's oil and gas properties reflects the tax burden
on the properties on a stand-alone basis and utilizes the Corporation’s tax pools.
| | --- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | (2) | The after tax net present value of the Corporation’s oil and gas does not consider the corporate
tax situation, or tax planning. It does not provide an estimate of the value at the level of the corporation, which may be significantly
different. The Corporation's financial statements and the management's discussion and analysis should be consulted for information
at the level of the corporation.
| | --- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



12









FUTURE NET REVENUE

TOTAL RESERVES

by production group

as at December 31, 2011





|                                     |  |                                                                                   |  |  | Future Net Revenue       |     |  | Unit     |  
|------------------------------------ |  | --------------------------------------------------------------------------------- |  |  | ------------------------ | --- |  | -------- | -
|                                     |  |                                                                                   |  |  | Before Income Taxes      |     |  | Value    |  
|                                     |  |                                                                                   |  |  | (discounted at 10%/year) |     |  | ($/Mcfe) |  
|RESERVES CATEGORIES                  |  | Production
        Group                                                          |  |  | ($millions)              |     |  | ($/bbl)  |  
|Proved Reserves                      |  | Natural Gas and NGL (including by products but excluding solution gas from wells) |  |  | $                        | 363 |  |          | $
|Proved Reserves                      |  | Light and Medium Crude Oil (including solution gas and other by products)         |  |  |                          | 20  |  |          |  
|Proved Reserves                      |  | Heavy Oil (including solution gas and other by products)                          |  |  |                          | 48  |  |          |  
|Proved Reserves – Total              |  |                                                                                   |  |  | $                        | 432 |  |          | $
|                                     |  |                                                                                   |  |  |                          |     |  |          |  
|Proved and Probable Reserves         |  | Natural Gas and NGL (including by products but excluding solution gas from wells) |  |  | $                        | 611 |  |          | $
|Proved and Probable Reserves         |  | Light and Medium Crude Oil (including solution gas and other by products)         |  |  |                          | 30  |  |          |  
|Proved and Probable Reserves         |  | Heavy Oil (including solution gas and other by products)                          |  |  |                          | 81  |  |          |  
|Proved and Probable Reserves – Total |  |                                                                                   |  |  | $                        | 722 |  |          | $



Forecast Prices
and Costs



Pricing Assumptions
(Forecast Prices and Costs)



SUMMARY OF PRICING ASSUMPTIONS

AS AT DECEMBER 31, 2011

FORECAST PRICES AND COSTS



|           |  | West Texas   |        |   | Edmonton    |  |        |                |  |  |               |  
|---------- |  | ------------ | ------ | - | ----------- |  | ------ | -------------- |  |  | ------------- | -
|           |  | Intermediate |        |   | Light Crude |  |        | Natural Gas at |  |  | Foreign       |  
|           |  | Crude Oil    |        |   | Oil         |  |        | AECO           |  |  | Exchange      |  
|Year       |  | ($US/bbl)    |        |   | ($Cdn/bbl)  |  |        | ($Cdn/GJ)      |  |  | ($US/$Cdn)(1) |  
|2012       |  |              | 97.50  |   |             |  | 99.00  |                |  |  | 3.32          |  
|2013       |  |              | 97.50  |   |             |  | 99.00  |                |  |  | 3.98          |  
|2014       |  |              | 100.00 |   |             |  | 101.50 |                |  |  | 4.45          |  
|2015       |  |              | 100.80 |   |             |  | 102.30 |                |  |  | 4.83          |  
|2016       |  |              | 101.70 |   |             |  | 103.20 |                |  |  | 5.26          |  
|2017       |  |              | 102.70 |   |             |  | 104.20 |                |  |  | 5.59          |  
|2018       |  |              | 103.60 |   |             |  | 105.10 |                |  |  | 5.92          |  
|2019       |  |              | 104.50 |   |             |  | 106.00 |                |  |  | 6.11          |  
|2020       |  |              | 105.40 |   |             |  | 106.90 |                |  |  | 6.35          |  
|2021       |  |              | 107.60 |   |             |  | 109.20 |                |  |  | 6.49          |  
|2022       |  |              | 109.70 |   |             |  | 111.30 |                |  |  | 6.59          |  
|2023       |  |              | 111.90 |   |             |  | 113.50 |                |  |  | 6.68          |  
|2024       |  |              | 114.10 |   |             |  | 115.80 |                |  |  | 6.82          |  
|2025       |  |              | 116.40 |   |             |  | 118.10 |                |  |  | 7.01          |  
|Thereafter |  |              | 2      | % |             |  | 2      | %              |  |  | 2             | %



Note:



| | (1) | Exchange rates used to generate the benchmark reference prices in this table.
| | --- | -----------------------------------------------------------------------------



13







For comparison purposes, the Corporation
realized a weighted average gas price for the year ended December 31, 2011 of $3.82/Mcf, including $0.05/Mcf of realized hedging
gains for natural gas. The weighted average AECO daily gas price for the same 12 month period was $3.67/Mcf.



Reconciliations
of Changes in Reserves and Future Net Revenue



RECONCILIATION OF GROSS RESERVES
TOTAL RESERVES(1)
FORECAST PRICES AND COSTS



|                                                   |  | Gross
    Proved |       |   | Gross
    Probable |  |         | Gross
    Proved + Probable | 
|-------------------------------------------------- |  | ---------------- | ----- | - | ------------------ |  | ------- | --------------------------- | 
|                                                   |  |                  |       |   |                    |  |         |                             | 
|                                                   |  | Oil              |       |   | Gas                |  |         | Liquids                     | 
|FACTORS                                            |  | Mbbl             |       |   | MMcf               |  |         | Mbbl                        | 
|December 31, 2010(2)                               |  |                  | 1,152 |   |                    |  | 229,445 |                             | 
|Improved Recoveries, Extensions and Discoveries(3) |  |                  | 1,216 |   |                    |  | 29,362  |                             | 
|Technical Revisions                                |  |                  | (174  | ) |                    |  | 20,929  |                             | 
|Acquisitions                                       |  |                  | 0     |   |                    |  | 806     |                             | 
|Dispositions                                       |  |                  | (83   | ) |                    |  | (8,217  | )                           | 
|Production                                         |  |                  | (351  | ) |                    |  | (46,889 | )                           | 
|Economic Factors                                   |  |                  | 2     |   |                    |  | (19,500 | )                           | 
|December 31, 2011                                  |  |                  | 1,763 |   |                    |  | 205,926 |                             | 



Notes:

| | (1) | Includes reserves from zones not affected by gas over bitumen issue and reserves shut-in pursuant
to AEUB decisions and orders. See "Risk Factors – Gas Over Bitumen Matters".
| | --- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | (2) | The opening balance on December 31, 2010 includes all of Perpetual's reserves, including reserves
that were shut-in or identified for shut-in as a result of the gas over bitumen issue. At December 31, 2010 and 2011 all reserves
shut-in as a result of the gas over bitumen issue were categorized as probable reserves.
| | --- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | (3) | The Corporation includes all reserve additions resulting from capital expenditures in Improved
Recoveries, Extensions and Discoveries.
| | --- | --------------------------------------------------------------------------------------------------------------------------------------



Additional Information
Relating to Reserves Data



Proved Undeveloped
Reserves



The following table discloses, for each
product type, the volumes of proved undeveloped reserves that were first attributed in each of the most recent three financial
years and, in the aggregate, before that time.



|              |  | Light and Medium Oil |     |  | Heavy Oil       |  |    | Natural Gas |  |  | NGLs            | 
|------------- |  | -------------------- | --- |  | --------------- |  | -- | ----------- |  |  | --------------- | 
|              |  | (Mbbl)               |     |  | (Mbbl)          |  |    | (MMcf)      |  |  | (Mbbl)          | 
|              |  | First                |     |  | Cumulative      |  |    | First       |  |  | Cumulative      | 
|Year          |  | Attributed           |     |  | at
    Year End |  |    | Attributed  |  |  | at
    Year End | 
|Prior thereto |  |                      | 137 |  |                 |  | 20 |             |  |  | -               | 
|2009          |  |                      | 78  |  |                 |  | 78 |             |  |  | -               | 
|2010          |  |                      | 92  |  |                 |  | 92 |             |  |  | 128             | 
|2011          |  |                      | 19  |  |                 |  | 19 |             |  |  | 354             | 



The Corporation has a large inventory of
proved undeveloped reserves. Poor gas prices in 2011, 2010 and 2009 deferred activity on previously booked reserves associated
with the Viking unconventional resource play in eastern Alberta, moving the reserves to the probable undeveloped category. Perpetual
added proved undeveloped reserves associated with its successful Mannville heavy oil program in eastern Alberta, the liquids rich
Wilrich gas program in west central Alberta and the liquids rich Montney gas play at Elmworth. These reserves are booked as per
the COGE Handbook to company land immediately adjacent to existing producing wells. The Corporation plans to develop these reserves
over the next four to five years as part of larger drilling programs subject to commodity prices. The Corporation uses many factors
to determine its annual budgets and all projects, whether booked as undeveloped reserves or unbooked and residing in Perpetual’s
prospect inventory, compete based on these factors with funds balanced to maximize returns from capital investments as well as
drive strategic initiatives.



14







Probable
Undeveloped Reserves



The following table discloses, for each
product type, the volumes of probable undeveloped reserves that were first attributed in each of the most recent three financial
years and, in the aggregate, before that time.



|              |  | Light
    and Medium Oil |    |  | Heavy
    Oil   |  |    | Natural
    Gas |  |  | NGLs            | 
|------------- |  | ------------------------ | -- |  | --------------- |  | -- | --------------- |  |  | --------------- | 
|              |  | (Mbbl)                   |    |  | (Mbbl)          |  |    | (MMcf)          |  |  | (Mbbl)          | 
|              |  | First                    |    |  | Cumulative      |  |    | First           |  |  | Cumulative      | 
|Year          |  | Attributed               |    |  | at
    Year End |  |    | Attributed      |  |  | at
    Year End | 
|Prior thereto |  |                          | 35 |  |                 |  | 90 |                 |  |  | -               | 
|2009          |  |                          | 29 |  |                 |  | 54 |                 |  |  | -               | 
|2010          |  |                          | 46 |  |                 |  | 46 |                 |  |  | 86              | 
|2011          |  |                          | 93 |  |                 |  | 93 |                 |  |  | 480             | 



The Corporation has a large inventory of
probable undeveloped reserves primarily on its Viking resource play in east central Alberta. New wells typically experience rapid
production declines within the first 12 months of production and therefore a significant percent of the well's revenue is generated
very early in its productive life. Poor gas prices in 2011, 2010 and 2009 deferred activity on these Viking reserves. Perpetual
added probable undeveloped reserves associated with its successful Mannville heavy oil program in eastern Alberta, the liquids
rich Wilrich gas program in west central Alberta and the liquids rich Montney gas play at Elmworth. These reserves are booked as
per the COGE handbook to company lands. The Corporation plans to develop these reserves over the next eight to nine years as part
of larger drilling programs subject to commodity prices. As stated above, the Corporation uses many factors to determine its annual
budgets and all projects, whether booked as probable undeveloped reserves or unbooked and residing on Perpetual’s prospect
inventory, compete based on these factors with funds balanced to maximize returns from capital investment as well as drive strategic
initiatives.



Significant
Factors or Uncertainties



The process of estimating reserves is complex.
It requires significant judgments and decisions based on available geological, geophysical, engineering, and economic data. These
estimates may change substantially as additional data from ongoing development activities and production performance becomes available
and as economic conditions impacting oil and gas prices and costs change. The reserves estimates contained herein are based on
current production forecasts, prices and economic conditions.



As circumstances change and additional
data become available, reserve estimates also change. Estimates made are reviewed and revised, either upward or downward, as warranted
by the new information. Revisions are often required due to changes in well performance, prices, economic conditions and governmental
restrictions.



Although every reasonable effort is made
to ensure that reserve estimates are accurate, reserve estimation is an inferential science. As a result, the subjective decisions,
new geological, geophysical or production information and a changing environment may impact these estimates. Revisions to reserve
estimates can arise from changes in year-end oil and gas prices, and reservoir performance. Such revisions can be either positive
or negative.



Future Development
Costs



The following table sets forth development
costs deducted in the estimation of Perpetual's future net revenue attributable to the reserve categories noted below.



15







|           |  | FUTURE DEVELOPMENT COSTS              |     
|---------- |  | ------------------------------------- | ----
|           |  | FORECAST PRICES AND COSTS ($millions) |     
|Year       |  | Proved Reserves                       |     
|           |  | 0                                     | %   
|2012       |  |                                       | 29.2
|2013       |  |                                       | 56.1
|2014       |  |                                       | 4.0 
|2015       |  |                                       | 0.0 
|2016       |  |                                       | 0.0 
|Thereafter |  |                                       | 0.3 
|Total      |  |                                       | 89.6



The Corporation expects to fund future
development costs from internally-generated funds flow, debt or equity financing through the capital markets and the Corporation
does not expect such costs to make development of any properties uneconomic.



The McDaniel Report estimates that future
capital costs of $317.7 million will be required over the life of the Corporation's proved and probable reserves for the drilling,
completion, equipping and tie-in of four conventional wells and up to 824 unconventional wells, 772 targeting the Cretaceous Viking
formation, 12 targeting the Wilrich, 16 targeting the Montney formation, 12 targeting other west central zones, 12 targeting Mannville
heavy oil and recompletion of up to 87 conventional wells, and 131 resource wells included in Perpetual's proved and probable reserves.
As the Corporation's technical staff continue to analyze and evaluate the asset base and expand the facilities and pipeline infrastructure,
development of the Corporation's undeveloped reserves will be undertaken over the next several years. In addition to opportunities
on Perpetual's asset base recognized in the McDaniel Report, many of Perpetual's current assets include significant incremental
exploration, exploitation and development opportunities. The Corporation has identified in its prospect inventory additional drilling
recompletion and facility related opportunities beyond those included in the McDaniel Report. See "Statement of Reserves
Data and Other Oil and Gas Information - Other Oil and Gas Information – Prospect Inventory".



Elmworth Contingent
Resource



A preliminary resource assessment was conducted
in 2010 for the Montney Formation in the Elmworth area. These numbers have been mechanically updated to reflect increased reserve
bookings by McDaniel as at year end 2011, the results of which are summarized below.



December 31, 2011 Elmworth Contingent
Resource(1,3,4)

|        |  | Gross
    Lease |         |  | Working
    Interest | 
|------- |  | --------------- | ------- |  | -------------------- | 
|        |  |                 |         |  |                      | 
|        |  |                 |         |  |                      | 
|        |  | Original        |         |  | Raw                  | 
|        |  | Gas in          |         |  | Recoverable          | 
|        |  | Place           |         |  | Gas (3)              | 
|        |  | (MMcf)          |         |  | (MMcf)               | 
|Low(2)  |  |                 | 757,590 |  |                      | 
|Best(2) |  |                 | 757,590 |  |                      | 
|High(2) |  |                 | 757,590 |  |                      | 



Notes:

| | (1) | Contingent resources have been evaluated by McDaniel using the definitions defined in the COGE
Handbook, Volume 1. All volumes are reported before the deduction of royalties payable to others. Contingent resource assignments
are in addition to any reserve assignments associated with these assets. This is a mechanical update to the December 31, 2010 Resource
assessment to account for 41.5 Bcfe of Proved and Probable reserves that have been booked to this asset.
| | --- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | (2) | A Low estimate (90% chance the ultimate recoverable resource will be equal or greater than the
stated value), means higher certainty, a Best estimate (50% chance that the ultimate recoverable resource will be greater than
or equal to the stated value) means most likely and a High estimate means lower than a 50% chance that the ultimate recoverable
resource will be greater than or equal to the stated value.
| | --- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------





16











| | (3) | McDaniel has assigned recovery factors of 20% (Low), 35% (Best) and 50% (High) in their assessment
of recoverable resource.
| | --- | ---------------------------------------------------------------------------------------------------------------------------

| | (4) | Contingent resources can be sub-classified into economic and uneconomic portions based on a number
of assumptions on capital costs, timing, price forecast, etc. Currently sub-classification of these estimates has not been completed
pending a discussion of the above parameters.
| | --- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



The primary contingencies identified for
the Montney resource were infrastructure and access to market. To date, 41.5 Bcfe of reserves have been booked as proved and probable
subject to standard booking practice for undeveloped reserves. The total of the contingent resource plus the reserve booking to
date matches the original best case net resource booking of 178 Bcfe for this area.



Bitumen Contingent Resource



Bluesky Contingent Resource in Panny
Area



Perpetual holds over 41,400 hectares (162
net sections) of oil sands leases in the Panny Area of northern Alberta. Throughout 2011, the Corporation worked with McDaniel
to provide estimates of volumes of discovered bitumen initially in place ("DBIIP"), undiscovered bitumen initially
in place (“UDBIIP”), contingent resources and prospective resources for a portion of the Company’s assets
in this area. Three vertical wells and a horizontal well were drilled in the area in the first quarter of 2011, and one existing
well was deepened in the fourth quarter to evaluate the reservoir quality and bitumen characteristics of the Bluesky formation
and to further define the extent of the bitumen resource and extraction potential. The assignments of DBIIP, UDBIIP, recoverable
contingent resource and recoverable prospective resource in the McDaniel Report “Perpetual Energy Inc. Clastic Oil Sands
Resource Assessment Evaluation of Bitumen and Heavy Oil Resources as of June 30, 2011” and the subsequent update “Evaluation
of Discovered Bitumen Initially-in-Place and Contingent Bitumen Resources – Panny Area” effective December 31,
2011 are based on approximately 59 wells in the pools, and on the potential application of cyclic steam stimulation to the Bluesky
formation as a “technology under development” in carbonate reservoirs. These reports were prepared pursuant to NI 51-101.



Given the extent of the bitumen resource
now confirmed across the Panny acreage, the high quality of the Bluesky formation reservoir recovered in core, and that the viscosity
of the bitumen discovered is capable of flowing at low rates without any thermal or solvent assistance, the Corporation is encouraged
by the results to date at Panny. Perpetual has plans to further quantify the resource through additional drilling, has initiated
a detailed review of applicable technologies, and has applied for a pilot test on its lands.



Hoole and Marten Hills Areas



Perpetual holds over 41,000 hectares (161
net sections) of oil sands leases in the Hoole and Marten Hills areas of northern Alberta. Throughout 2011, the company has
worked with McDaniel to provide estimates of volumes of UDBIIP, DBIIP, contingent resources and prospective resources for a portion
of the Company’s assets in these areas. Three vertical wells were drilled in the area and 13 km of 2D seismic were acquired
in the first quarter of 2011, to evaluate the reservoir quality and bitumen characteristics of the Clearwater and Grand Rapids
formations and to further define the extent of the bitumen resource and extraction potential. The assignments of DBIIP, UDBIIP,
recoverable contingent resource and recoverable prospective resource in the McDaniel Report “Perpetual Energy Inc. Clastic
Oil Sands Resource Assessment Evaluation of Bitumen and Heavy Oil Resources as of June 30, 2011” are based on 57 wells
in the pools, and on the potential application of cyclic steam stimulation to the Clearwater formation and Steam Assisted Gravity
Drainage (“SAGD”) to the Grand Rapids formation. The Report was prepared pursuant to NI 51-101.



Liege Area



Perpetual holds 30,720 hectares (120 net
sections) of oil sands leases in the Liege area. During the first quarter of 2011, the Company acquired 42 km of 2D seismic and
drilled three wells which encountered bitumen-saturated reservoir in the Wabiskaw as well as in the Grosmont A, B and C and Leduc
carbonate formations. Each of the three wells encountered three or more stacked zones, with at least one zone having greater than
ten meters of continuous bitumen-saturated reservoir. The assignments of DBIIP, UDBIIP, recoverable contingent resource and recoverable
prospective resource in the McDaniel Report “Perpetual Energy Inc. Evaluation of Contingent and Prospective Resources
of Grosmont and Leduc Bitumen as of October 31, 2011” are based on 55 wells in the pools and on the potential application
of SAGD. The Report was prepared pursuant to NI 51-101.



17







Net Present Value of Resource



All of Perpetual’s contingent resources
currently have an "undetermined" economic status as sub-classification into economic and uneconomic categories has not
been evaluated. Contingencies affecting the classification of the resources referred to in the McDaniel reports referenced
in the sections above as reserves include corporate development plans, the need for regulatory approval, and the need to perform
an economic study regarding production. There is no certainty that it will be commercially viable to produce any portion of
the resources. Please see "Notes Pertaining to the Reporting of Bitumen Contingent Resource" below for applicable
definitions and risk factors.



The bitumen in place and recoverable resource
estimates, prepared in accordance with the COGE Handbook, are as follows:



|                  |  | Discovered(1)             |       |  | Undiscovered(1) | 
|----------------- |  | ------------------------- | ----- |  | --------------- | 
|Resource Category |  | Gross
    Area (hectares) |       |  | Company
    WI  | 
|Panny Clastics    |  |                           |       |  |                 | 
|Low Estimate(1)   |  |                           |       |  |                 | 
|Best Estimate(1)  |  |                           | 5,184 |  |                 | 
|High Estimate(1)  |  |                           |       |  |                 | 
|Other Clastics    |  |                           |       |  |                 | 
|Low Estimate(1)   |  |                           |       |  |                 | 
|Best Estimate(1)  |  |                           | 610   |  |                 | 
|High Estimate(1)  |  |                           |       |  |                 | 
|Liege Carbonates  |  |                           |       |  |                 | 
|Low Estimate(1)   |  |                           |       |  |                 | 
|Best Estimate(1)  |  |                           | 2,717 |  |                 | 
|High Estimate(1)  |  |                           |       |  |                 | 
|Total All Areas   |  |                           |       |  |                 | 
|Low Estimate(1)   |  |                           |       |  |                 | 
|Best Estimate(1)  |  |                           | 8,511 |  |                 | 
|High Estimate(1)  |  |                           |       |  |                 | 



Note:

| | (1) | Contingent and prospective resources have been evaluated by McDaniel using the definitions is as
defined in section five of the COGE Handbook. All volumes are reported before the deduction of royalties payable to others. Contingent
resource assignments are in addition to any reserve assignments associated with these assets. Please refer to the detailed definitions
contained under the heading “Notes Pertaining to the Reporting of Bitumen Contingent Resources” below.
| | --- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



Notes Pertaining
to the Reporting of Bitumen Contingent Resources



The following are excerpts from the definitions
of resources and reserves, contained in Section 5 of the COGE Handbook, which is referenced by the Canadian Securities Administrators
in NI 51-101.



Definitions



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.
It is also appropriate to classify as contingent resources the estimated discovered recoverable quantities associated with a project
in the early evaluation stage. Contingent Resources are further classified in accordance with the level of certainty associated
with the estimates and may be sub-classified based on project maturity and/or characterized by their economic status. [Criteria
for determining commerciality are further detailed in the COGE Handbook Section 5.3.4].



18







Discovered Petroleum Initially-In-Place
(DPIIP) (equivalent to discovered resources) is that quantity of petroleum that is estimated, as of a given date, to be contained
in known accumulations prior to production. The recoverable portion of discovered petroleum initially in place includes production,
reserves, and contingent resources; the remainder is unrecoverable.



Economic Contingent Resources are
those contingent resources which are currently economically recoverable.



Prospective Resources are those
quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application
of future development projects.



Undiscovered Petroleum Initially-In-Place
(UDPIIP) (equivalent to undiscovered resources) is that quantity of petroleum that is estimated, as of a given date, to be
contained in known accumulations yet to be discovered. The recoverable portion of undiscovered petroleum initially in place is
referred to as "prospective resources"; the remainder as unrecoverable.



Total Petroleum Initially-In-Place (PIIP)
is that quantity of petroleum that is estimated to exist originally in naturally occurring accumulations. It includes that quantity
of petroleum that is estimated, as of a given date, to be contained in known accumulations, prior to production, plus those estimated
quantities in accumulations yet to be discovered (equivalent to "total resources").



Uncertainty
Categories for Resource Estimates



The range of uncertainty of estimated recoverable
volumes may be represented by either deterministic scenarios or by a probability distribution. Resources should be provided as
low, best, and high estimates as follows:



Low Estimate: This is considered
to be a conservative estimate of the quantity that will actually be recovered. It is likely that the actual remaining quantities
recovered will exceed the low estimate. If probabilistic methods are used, there should be at least a 90 percent probability (P90)
that the quantities actually recovered will equal or exceed the low estimate.



Best Estimate: This is considered
to be the best estimate of the quantity that will actually be recovered. It is equally likely that the actual remaining quantities
recovered will be greater or less than the best estimate. If probabilistic methods are used, there should be at least a 50 percent
probability (P50) that the quantities actually recovered will equal or exceed the best estimate.



High Estimate: This is considered
to be an optimistic estimate of the quantity that will actually be recovered. It is unlikely that the actual remaining quantities
recovered will exceed the high estimate. If probabilistic methods are used, there should be at least a 10 percent probability (P10)
that the quantities actually recovered will equal or exceed the high estimate.



This approach to describing uncertainty
may be applied to reserves, contingent resources, and prospective resources. There may be significant risk that sub-commercial
and undiscovered accumulations will not achieve commercial production. However, it is useful to consider and identify the range
of potentially recoverable quantities independently of such risk.



Levels of
Certainty for Reported Reserves



With respect to contingent resources, not
all technically feasible development plans will be commercial. The commercial viability of a development project is dependent on
the forecast of fiscal conditions over the life of the project. For contingent resources the risk component relating to the likelihood
that an accumulation will be commercially developed is referred to as the "chance of development." For contingent resources
the chance of commerciality is equal to the chance of development.



Risk Factors



In general, estimates of gross original
resources and recoverable resources are based upon a number of factors and assumptions made as of the date on which the estimates
were determined, such as geological, technological and engineering estimates and are subject to a variety of risks and uncertainties
and other factors that could cause actual events or results to differ materially from those anticipated in forward-looking estimates.



19







These risks and uncertainties include but
are not limited to: (1) the fact that there is no certainty that the zones of interest will exist to the extent estimated or that
the zones will be found to have oil with characteristics that meet or exceed the minimum criteria in terms of net pay thickness,
porosity or oil saturation, or that the oil will be commercially recoverable to the extent estimated; (2) risks inherent in the
heavy oil and oil sands industry; (3) the lack of additional financing to fund the Corporation's exploration activities and continued
operations; (4) fluctuations in foreign exchange and interest rates; (5) the number of competitors in the oil and gas industry
with greater technical, financial and operations resources and staff; (6) fluctuations in world prices and markets for oil and
gas due to domestic, international, political, social, economic and environmental factors beyond the Corporation's control; (7)
changes in government regulations affecting oil and gas operations and the high compliance cost with respect to governmental regulations;
(8) potential liabilities for pollution or hazards against which the Corporation cannot adequately insure or which the Corporation
may elect not to insure; (9) the Corporation's ability to hire and retain qualified employees and consultants; (10) contingencies
affecting the classification as reserves versus resources which relate to the following issues as detailed in the COGE Handbook:
ownership considerations, drilling requirements, testing requirements, regulatory considerations, infrastructure and market considerations,
timing of production and development, and economic requirements; (11) the fact that there is no certainty that any portion of contingent
resources will be commercially viable to produce; (12) the fact that there is no certainty that any portion of the prospective
resources will be discovered and if discovered, there is no certainty that it will be commercially viable to produce any portion
of the resources; and (13) other factors beyond the Corporation's control. Any reference in this Annual Information Form to DPIIP,
UDPIIP, contingent resources and prospective resources are not, and should not be confused with oil and gas reserves.



Other Oil and Gas
Information



Oil and Gas
Properties



The following is a description of the Corporation's
important oil and natural gas properties as at December 31, 2011. Production stated is the Corporation's working and royalty interest
share of production volumes and, unless otherwise stated, is average production for 2011. Reserve amounts stated include corporation
gross reserves plus royalty interest reserves as at December 31, 2011 based on forecast costs and prices as evaluated in the McDaniel
Report. See "Disclosure of Reserves Data". 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. Unless otherwise specified, gross acres, net acres and well count information are as at December 31,
2011.



Northern District



Athabasca



The Athabasca area is located in northeast
Alberta and is comprised of 630,610 net acres (48.7% undeveloped) with an average 72.5% working interest in 537 gross (389.2 net)
producing natural gas wells. This area represented approximately 20.9% of the production from Perpetual’s assets for the
year 2011. Perpetual operates the majority of this area which produced 29.8 MMcfe/d in 2011, including 12 bbls/d of oil and NGL
production.



Approximately 50% of Perpetual’s
production from this property is processed through six operated facilities in which the Corporation holds an average of 90% working
interest.



Northeast



The Northeast area is located in northeast
Alberta and is comprised of 1,132,494 net acres (52.7% undeveloped) with an average 84.1% working interest in 566 gross (475.8
net) producing natural gas wells. This area represented approximately 22.0% of the production from Perpetual’s assets for
the year 2011. Perpetual operates the majority of this area which produced 31.2 MMcfe/d in 2011, including 1 bbl/d of oil and NGL
production.



Approximately 70% of Perpetual’s
production from this property is processed through seven Perpetual operated facilities in which the Corporation holds an average
of 95% working interest.



20







Bitumen



The Bitumen area is located in northeast
Alberta and comprised of 335,979 net acres (99.5% undeveloped) with a 100.0% working interest in northeast Alberta across seven
districts: Panny, Liege, Wabasca, Hoole, Ells, Calling Lake and Marten Hills.



Southern District



Birchwavy East



The Birchwavy East area is located in east
central Alberta east of Edmonton Alberta and is comprised of 386,019 net acres (51.9% undeveloped) with an average 86.2% working
interest in 429 gross (369.7 net) producing natural gas wells. This area represented 17.6% of the production from Perpetual’s
assets for the year 2011. Perpetual operates the majority of this area which produced 25.0 MMcfe/d in 2011, including 82 bbls/d
of oil and NGL production.



Approximately 82 % of Perpetual’s
production from this property is processed through four Perpetual operated facilities.



Birchwavy West



The Birchwavy West area is located in east
central Alberta, east of Edmonton and is comprised of 470,866 net acres (51.9% undeveloped) with an average 69.2% working interest
in 500 gross (346.2 net) producing natural gas wells. This area represented approximately 12.2% of the production from Perpetual’s
assets for 2011. Perpetual operates the majority of this area which produced 17.3 MMcfe/d in 2011, including 22 bbls/d of oil and
NGL production.



Approximately 76% of Perpetual’s
production from this property is processed through six operated facilities.



Mannville Heavy Oil



The Mannville Heavy Oil area is located
within Bichwavy East, in the Mannville area and is comprised of 136,878 net acres (26.6% undeveloped) with an average 80.9% working
interest in 54 gross (43.7 net) producing oil wells. This area represented approximately 2.9% of the total production from Perpetual’s
assets for the year 2011 and 29.4% of Perpetual’s oil and NGL production. Perpetual operates this area which produced 631
bbls/d in 2011.



Current production in the Mannville Heavy
Oil area is 100% operated and processed through third party facilities.



West Central District



Carrot Creek



The Carrot Creek area is located in west
central Alberta, west of Edmonton, and is comprised of 24,795 net acres (24.1% undeveloped) with an average 66.6 % working interest
in 50 gross (33.3 net) producing natural gas wells. This area represented approximately 6.6% of the production from Perpetual’s
assets for the year 2011. Perpetual operates the majority of this area which produced 9.4 MMcfe/d in 2011, which includes 449 bbls/d
of crude oil and NGL production.



Approximately 75% of Perpetual’s
production from this property is processed through a 60% working interest operated field compressor and processed through a 30%
Perpetual owned non-operated facility. The remaining 25% of production was compressed through a 100% owned and operated facility
then processed through a third party deep cut plant at Edson.



Edson



The Edson area is located in west central
Alberta, west of Edmonton and is comprised of 56,192 net acres (60.7% undeveloped) with an average 87.3% working interest in 64
gross (55.9 net) producing natural gas wells. This area represented approximately 14.8% of the production from Perpetual’s
assets for the year 2011. Perpetual operates the majority of this area which produced 20.9 MMcfe/d in 2011, which includes 636
bbls/d of crude oil and NGL production.



21







Close to 100% of PET’s production
from this property was processed through 100% operated compressor in 2011, then processed through a third party deep cut plant
at Edson.



Elmworth



The Elmworth area is located in west central
Alberta, south of Grande Prairie, and is comprised of 29,856 net acres including an average 50.0% working interest in 1 gross (0.5
net) producing wells. One well was on test for 45 days through a third party facility at an average daily net production rate of
1.8 MMcf/d of natural gas and 58 bbls/d of oil and liquids. The contribution to the average annual daily production was 0.2 MMcfe/d
in 2011, including 7 bbls of oil and NGL production.



Gold Creek/Karr



The Gold Creek/Karr area is located northwest
of Edmonton and is comprised of 11,488 net acres (73.8% undeveloped) with an average 95.0% working interest in 6 gross (5.7 net)
producing natural gas wells. This area represents approximately 1.0% of the production from Perpetual’s assets for the year
2011. Perpetual produced 1.1 MMcfe/d in 2011 including 40 bbls/d of crude oil and NGL production.



The Gold Creek/Karr area was divested in
February 2012.



Pembina



The Pembina area is located west of Edmonton
Alberta and comprised of 21,967 net acres (68.8% undeveloped) with an average 72.8 % working interest in 18 gross (13.1 net) producing
natural gas wells. This area represents approximately 1.0% of the production from Perpetual’s assets for the year 2011. Perpetual
operates the majority of this area which produced 1.3 MMcfe/d in 2011, including 110 bbls/d of crude oil and NGL production.



Certain properties in the Pembina area were sold effective May
26, 2011.



West Central Other



Other non-core assets in the West Central
area comprised of 56,048 net acres (89.6% undeveloped) with an average 83.3% working interest in 3 gross (2.5 net) producing natural
gas wells. This area represents approximately 1.3% of the production from Perpetual’s assets for the year 2011. Perpetual
produced 1.9 MMcfe/d in 2011, including 28 Bbls/d of crude oil and NGL production.



Current production in the West Central
Other area is processed through a combination of operated and third party facilities.



New Ventures



At year-end 2011, Perpetual had a 100%
working interest in 20,230 net acres (100% undeveloped) of land targeting new oil and gas exploration concepts.



22







Oil and Gas Wells



The following table sets forth the number
and status of wells in which the Corporation had a working interest as at December 31, 2011.



|                          |  | Producing
    Gas Wells |       |  | Producing
    Oil Wells |  |         | Non
                                              Producing Gas Wells(3)(4) |  |  | Non
                                              Producing Oil Wells(3)(4) | 
|------------------------- |  | ----------------------- | ----- |  | ----------------------- |  | ------- | --------------------------------------------------------------------------- |  |  | --------------------------------------------------------------------------- | 
|Property                  |  | Gross(1)                |       |  | Net(2)                  |  |         | Gross(1)                                                                    |  |  | Net(2)                                                                      | 
|                          |  |                         |       |  |                         |  |         |                                                                             |  |  |                                                                             | 
|Northern District         |  |                         |       |  |                         |  |         |                                                                             |  |  |                                                                             | 
|Athabasca                 |  |                         | 537   |  |                         |  | 389.2   |                                                                             |  |  | -                                                                           | 
|Northeast                 |  |                         | 566   |  |                         |  | 475.8   |                                                                             |  |  | -                                                                           | 
|Bitumen                   |  |                         | -     |  |                         |  | -       |                                                                             |  |  | 7                                                                           | 
|Northern
    Subtotal     |  |                         | 1,103 |  |                         |  | 865.0   |                                                                             |  |  | 7                                                                           | 
|                          |  |                         |       |  |                         |  |         |                                                                             |  |  |                                                                             | 
|Southern District         |  |                         |       |  |                         |  |         |                                                                             |  |  |                                                                             | 
|Birchwavy East            |  |                         | 429   |  |                         |  | 369.7   |                                                                             |  |  | -                                                                           | 
|Birchwavy West            |  |                         | 497   |  |                         |  | 345.0   |                                                                             |  |  | 3                                                                           | 
|Mannville Heavy Oil       |  |                         | -     |  |                         |  | -       |                                                                             |  |  | 54                                                                          | 
|Southern
    Subtotal     |  |                         | 926   |  |                         |  | 714.7   |                                                                             |  |  | 57                                                                          | 
|                          |  |                         |       |  |                         |  |         |                                                                             |  |  |                                                                             | 
|West Central District     |  |                         |       |  |                         |  |         |                                                                             |  |  |                                                                             | 
|Carrot Creek              |  |                         | 35    |  |                         |  | 22.5    |                                                                             |  |  | 15                                                                          | 
|Edson                     |  |                         | 60    |  |                         |  | 52.8    |                                                                             |  |  | 4                                                                           | 
|Elmworth                  |  |                         | 1     |  |                         |  | 0.5     |                                                                             |  |  | -                                                                           | 
|Gold Creek/Karr           |  |                         | 6     |  |                         |  | 5.7     |                                                                             |  |  | -                                                                           | 
|Pembina                   |  |                         | 6     |  |                         |  | 4.0     |                                                                             |  |  | 12                                                                          | 
|West
    Central Other    |  |                         | 2     |  |                         |  | 1.5     |                                                                             |  |  | 1                                                                           | 
|West
    Central Subtotal |  |                         | 110   |  |                         |  | 87.0    |                                                                             |  |  | 32                                                                          | 
|                          |  |                         |       |  |                         |  |         |                                                                             |  |  |                                                                             | 
|Warwick
    Gas Storage   |  |                         | 14    |  |                         |  | 14.0    |                                                                             |  |  | -                                                                           | 
|                          |  |                         |       |  |                         |  |         |                                                                             |  |  |                                                                             | 
|TOTAL                     |  |                         | 2,153 |  |                         |  | 1,680.7 |                                                                             |  |  | 96                                                                          | 



Notes:

| | (1) | "Gross" refers to the number of wells, respectively, in which a working interest
is held by the Corporation. In addition the Corporation held royalty interests in 349 producing wells at December 31, 2011.
| | --- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | (2) | "Net" refers to the aggregate of the numbers obtained by multiplying each gross
well by the percentage working interest therein.
| | --- | --------------------------------------------------------------------------------------------------------------------------------

| | (3) | "Non-Producing" refers to wells which are not currently producing either due to
lack of facilities, markets or regulatory approval. This includes 94 gross (83 net) wells shut-in as a result of gas over bitumen
regulatory rulings.
| | --- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | (4) | Allowance for the abandonment costs associated with the well bores was made in the McDaniel Report.
There are 48 gross (48 net) wells that are classified as service wells not included in the gross/net well count.
| | --- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



Acreage Information



The following table sets out Perpetual's
developed and undeveloped land holdings as at December 31, 2011. The Corporation does not have any material work commitments on
any of Perpetual's properties.



23







|                      |  | Developed Acres |           |  | Undeveloped Acres | 
|--------------------- |  | --------------- | --------- |  | ----------------- | 
|Property              |  | Gross(1)        |           |  | Net(2)            | 
|                      |  |                 |           |  |                   | 
|Northern District     |  |                 |           |  |                   | 
|Athabasca             |  |                 | 550,292   |  |                   | 
|Northeast             |  |                 | 673,054   |  |                   | 
|Bitumen               |  |                 | 1,920     |  |                   | 
|Northern Subtotal     |  |                 | 1,225,265 |  |                   | 
|                      |  |                 |           |  |                   | 
|Southern District     |  |                 |           |  |                   | 
|Birchwavy East        |  |                 | 289,961   |  |                   | 
|Birchwavy West        |  |                 | 422,881   |  |                   | 
|Mannville Heavy Oil   |  |                 | 111,419   |  |                   | 
|Southern Subtotal     |  |                 | 844,261   |  |                   | 
|                      |  |                 |           |  |                   | 
|West Central District |  |                 |           |  |                   | 
|Carrot Creek          |  |                 | 32,479    |  |                   | 
|Edson                 |  |                 | 42,080    |  |                   | 
|Elmworth              |  |                 | -         |  |                   | 
|Gold Creek/Karr       |  |                 | 3,200     |  |                   | 
|Pembina               |  |                 | 13,760    |  |                   | 
|West Central Other    |  |                 | 12,000    |  |                   | 
|West Central Subtotal |  |                 | 103,519   |  |                   | 
|                      |  |                 |           |  |                   | 
|New Ventures          |  |                 | -         |  |                   | 
|                      |  |                 |           |  |                   | 
|TOTAL                 |  |                 | 2,173,045 |  |                   | 



Notes:

| | (1) | "Gross" means the total number of acres in which the Corporation has an interest
in respect of Perpetual's current assets.
| | --- | --------------------------------------------------------------------------------------------------------------------------

| | (2) | "Net" means the aggregate of the numbers obtained by multiplying each gross acre
by the actual percentage interest therein.
| | --- | ---------------------------------------------------------------------------------------------------------------------------

| | (3) | During 2012, 176,186net acres are set to expire. A total of129,456net acres expired in 2011. The Corporation intends to assess all expiring lands and, where appropriate, seek continuation
through mapping, development activity or, in the case of higher risk areas, farm outs, where third parties provide exploration
funding in exchange for an earned working interest.
| | --- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | (4) | "Undeveloped Acres" refers to land where there are not any existing wells within
the rights associated with those lands.
| | --- | ------------------------------------------------------------------------------------------------------------------------



Production Estimates



The following table sets out the volume
of Perpetual's production estimated by McDaniel on a proved and probable basis for the year ended December 31, 2012, which is reflected
in the estimate of future net revenue disclosed in the tables.



|2012 McDaniel Forecast Production |  | Natural Gas (MMcf/d) |       |  | Crude Oil (Mbbl/d) |  |     | Natural Gas Liquids  (Mbbl/d) | 
|--------------------------------- |  | -------------------- | ----- |  | ------------------ |  | --- | ----------------------------- | 
|Proved                            |  |                      | 104.1 |  |                    |  | 1.6 |                               | 
|Probable                          |  |                      | 12.3  |  |                    |  | 0.4 |                               | 
|Total Proved and Probable         |  |                      | 116.4 |  |                    |  | 2.1 |                               | 



24







Production History



The following tables summarize certain
information in respect of production, product prices received, royalties paid, operating expenses and resulting netback for the
periods indicated below:









|                                              |  | 2011 Quarter Ended |      
|--------------------------------------------- |  | ------------------ | -----
|                                              |  | Dec 31             |      
|Average Daily Natural Gas Production (MMcf/d) |  |                    | 126.8
|Average Daily Oil & NGL Production (bbl/d)    |  |                    | 2,685
|Total (MMcfe/d)                               |  |                    | 142.9
|Average Realized Price ($/Mcfe)               |  |                    | 4.66 
|Royalties ($/Mcfe)                            |  |                    | (0.32
|Operating Costs ($/Mcfe)                      |  |                    | (1.93
|Transportation Costs ($/Mcfe)                 |  |                    | (0.17
|Operating Netback ($/Mcfe)                    |  |                    | 2.24 



The following table indicates Perpetual's
average daily production from each of the Corporation's core areas for the year ended December 31, 2011:





|Property              |  | Average Annual Daily Production (MMcfe/d) |      
|--------------------- |  | ----------------------------------------- | -----
|                      |  |                                           |      
|Northern District     |  |                                           |      
|Athabasca             |  |                                           | 29.8 
|Northeast             |  |                                           | 31.2 
|Northern Subtotal     |  |                                           | 61.0 
|                      |  |                                           |      
|Southern District     |  |                                           |      
|Birchwavy East        |  |                                           | 25.0 
|Birchwavy West        |  |                                           | 17.3 
|Mannville Heavy Oil   |  |                                           | 4.2  
|Southern Subtotal     |  |                                           | 46.5 
|                      |  |                                           |      
|West Central District |  |                                           |      
|Carrot Creek          |  |                                           | 9.4  
|Edson                 |  |                                           | 20.9 
|Elmworth              |  |                                           | 0.2  
|Gold Creek/Karr       |  |                                           | 1.1  
|Pembina               |  |                                           | 1.3  
|West Central Other    |  |                                           | 1.9  
|West Central Subtotal |  |                                           | 34.8 
|                      |  |                                           |      
|TOTAL                 |  |                                           | 142.3



25







Prospect Inventory



The Corporation has identified numerous
exploitation development and low exposure exploration opportunities which are not recorded in the McDaniel Report as these opportunities
do not meet the criteria to be booked as proved or probable reserves under NI 51-101. These prospects are at various degrees of
technical refinement and risk and will be pursued during 2012 and beyond through drilling, completion and tie-in activities or
evaluated further with additional seismic. These will be pursued as they are technically refined and as economic factors such as
commodity prices, proximity to infrastructure, operating costs, and gas production rates permit. The spending of additional capital
beyond the estimates contained in the McDaniel Report is expected to increase value to the Shareholders through the addition of
production and reserves from new pools or acceleration of production in existing pools and through development of captured resource.
Facility optimization projects target production and reserves additions through improved recovery and by reducing operating costs
to extend the economic life of producing assets with a corresponding increase in recoverable reserves.



Mannville
Heavy Oil



Through the successful application of horizontal
drilling technology, Perpetual has established a highly economic inventory of Mannville heavy oil exploration and development opportunities
that are a key component of Perpetual’s commodity diversification strategy. Reserves have been booked by McDaniel for 16
drilling locations at year end 2011. Perpetual has recognized an additional 230 drilling prospects in its prospect invetory at
various levels of delineation and drill readiness.



Conventional
Shallow Gas Opportunities



In 2012, Perpetual is focusing its capital
budget on its two key investment priorities, Mannville heavy oil and West Central liquids rich natural gas projects. As a result,
the Corporation does not plan to pursue any significant conventional shallow gas opportunities in 2012. The McDaniel Report books
one conventional gas drill and 112 recompletion opportunities in Perpetual’s current conventional shallow natural gas inventory.
Further, the Corporation's prospect inventory has recorded more than 380additional conventional
drilling opportunities on the Company lands targeting cretaceous Mannville and Devonian shallow gas including pool extensions,
down spacing for new pools on developed lands and low exposure exploration on undeveloped lands. Additional drilling prospects
are at varying levels of technical analysis and economic evaluation. In addition, over 580 workovers and secondary zone completions
have been identified that are not identified in the McDaniel Report.



Bitumen



Perpetual has positioned itself with 335,403
gross (334,379 net) acres of undeveloped oil sands leases throughout many of its shallow gas operating areas in northeast Alberta
including Panny, Liege, Marten Hills, Ells, Wabasca, Hoole and Calling Lake as well as a small project area on the Peace River
Arch. The bitumen resource potential on these leases will likely be developed over the long term using a variety of recovery techniques
ranging from near cold production technologies to in-situ thermal techniques such as SAGD technology. In 2012, Perpetual has applied
for an experimental project approval to test a novel recovery technology in its Panny Bluesky bitumen property and is currently
awaiting regulatory approval. Independent contingent resource assessment reports were prepared by McDaniel in 2011, resulting in
the assignment of 1.156 billion barrels of discovered bitumen initially in place (best estimate) and 2.079 billion barrels of undiscovered
bitumen initially in place (best estimate) on 67,000 acres of Perpetual’s oil sands leases, primarily in the Panny sandstone
and Liege carbonate reservoirs. McDaniel assessed that this represented 212 million barrels of recoverable contingent resource
(best estimate) and 417 million barrels of prospective resource (best estimate).



West Central
Deep Basin



The Corporation has accumulated 212,043
gross (143,751 net) acres of undeveloped land in west central Alberta with significant liquids rich natural gas resource potential,
as well as light oil play. Activity on these lands to develop the liquids rich gas resource in the Wilrich formation at Edson and
Ansell are planned throughout the next several years subject to commodity prices. Development of the liquids rich Montney resource
is also planned over the next several years. The McDaniel report does classify some of the resource as undeveloped reserves but
over 140 locations are carried in Perpetual’s prospect inventory for future Montney development. Development of these resource
plays will warrant significant capital for future development activities. Perpetual has recorded 80 Wilrich horizontal development
locations in its prospect inventory. As Wilrich drilling progresses, additional horizontal drilling locations are expected to be
confirmed in other prospective horizons including the Notikewin and Fahler. An independent contingent resource assessment report
prepared by McDaniel in 2011 for the Montney at Elmworth and has been adjusted for those lands that have currently recognized reserves
associated with them. As a result, Perpetual has restated its remaining contingent resource for this area see “Montney Contigent
Resource”.



26







Unconventional
Viking and Colorado Shale



Perpetual
has identified an extensive inventory of unconventional Viking formation tight gas opportunities in east central Alberta including
903 drilling locations and recompletions itemized in the McDaniel Report covering 379 sections of land. The Corporation also has
in excess of 475 additional sections of undeveloped land where unconventional Viking potential has been identified. Perpetual has
also identified the potential to develop the shallow Colorado shale gas resource overlying the Viking formation throughout this
east central land base. No undeveloped Colorado reserves were booked by McDaniel at year end 2011. The Corporation has been conducting
a series of technical studies to assist in the understanding of the economic viability of development of the Colorado group. The
results of these tests will allow Perpetual to pursue the orderly development of this material resource with both recompletions
following the depletion of the underlying Mannville reservoirs and multi-well drilling programs initiated as economic and technical
conditions dictate.



Capital Expenditures



The following tables summarize capital
expenditures related to Perpetual's activities for the year ended December 31, 2011:



|                                  |  | ($millions) |      
|--------------------------------- |  | ----------- | -----
|                                  |  |             |      
|Exploration and development       |  | $           | 139.2
|Gas storage                       |  |             | 11.2 
|Dispositions net of, Acquisitions |  |             | (33.4
|Total                             |  | $           | 117.1



Exploration and development expenditures
for 2011 include approximately $3.9 million in exploration and evaluation costs which have been expensed directly on the Corporation's
statement of earnings. Exploration and evaluation costs include seismic expenditures and dry hole costs and are considered by the
Corporation to be more closely related to investing activities than operating activities; As a result they are included with capital
expenditures.



Exploration and
Development Activities



The following table sets forth the gross
and net exploratory and development wells in which the Corporation participated during the year ended December 31, 2011:





|                             |  | Gross |     |   | Net | 
|---------------------------- |  | ----- | --- | - | --- | 
|Exploratory Wells            |  |       |     |   |     | 
|Light and Medium Oil         |  |       | 6   |   |     | 
|Natural Gas                  |  |       | 8   |   |     | 
|Dry                          |  |       | -   |   |     | 
|Evaluation (Oil Sands)       |  |       | 7   |   |     | 
|Total                        |  |       | 21  |   |     | 
|                             |  |       |     |   |     | 
|Success Rate (%)             |  |       | 100 | % |     | 
|                             |  |       |     |   |     | 
|Development Wells            |  |       |     |   |     | 
|Light and Medium Oil         |  |       | 30  |   |     | 
|Natural Gas                  |  |       | 7   |   |     | 
|Dry                          |  |       | -   |   |     | 
|Evaluation and Service Wells |  |       | -   |   |     | 
|Total                        |  |       | 41  |   |     | 
|                             |  |       |     |   |     | 
|Service                      |  |       | 4   |   |     | 
|                             |  |       |     |   |     | 
|Success Rate (%)             |  |       | 100 | % |     | 



27







Additional Information
Concerning Abandonment and Reclamation Costs



In addition to the abandonment cost estimates
provided by McDaniel inclusive in their reserve assessment, Perpetual compiles annually a detailed internal estimate of the Corporation’s
total future asset retirement obligation based on net ownership interest in all wells, facilities and pipelines, including estimated
costs to abandon the wells, facilities and pipelines and reclaim the sites, and the estimated timing of the costs to be incurred
in future periods. Pursuant to this evaluation, the estimated value of Perpetual’s future asset retirement obligations,
net of the estimated salvage value of facilities and equipment and discounted at eight percent is $76 million as at December 31,
2011. The McDaniel Report includes an undiscounted amount of $81 million with respect to expected future well abandonment costs
related specifically to proved and probable reserves and such amount is included in the values captioned “Total Proved
and Probable Reserves” in the NPV of Funds Flow table (see “Net Present Value (“NPV”)
of Reserves Summary”). Of the total future well abandonment costs included in the McDaniel Report an undiscounted amount
of $55 million relates to Perpetual’s developed reserves. The following table presents the estimated future asset retirement
obligations and estimated net salvage values at various discount rates:



|($millions, net to Perpetual)                                                             |  | Undiscounted |      |   | 5% |   |     | 8% |  |   | Discounted at 10% |  
|----------------------------------------------------------------------------------------- |  | ------------ | ---- | - | -- | - | --- | -- |  | - | ----------------- | -
|Well abandonment costs for developed reserves included in McDaniel Report                 |  | $            | 55   |   |    | $ | 32  |    |  | $ | 25                |  
|Well abandonment costs for undeveloped reserves included in McDaniel Report               |  |              | 26   |   |    |   | 14  |    |  |   | 10                |  
|Well abandonment costs for total proved and probable reserves included in McDaniel Report |  |              | 81   |   |    |   | 46  |    |  |   | 35                |  
|Estimate of other abandonment and reclamation costs not included in McDaniel Report       |  |              | 246  |   |    |   | 141 |    |  |   | 107               |  
|Total estimated future abandonment and reclamation costs                                  |  |              | 326  |   |    |   | 188 |    |  |   | 142               |  
|Salvage value                                                                             |  |              | (151 | ) |    |   | (87 | )  |  |   | (66               | )
|Abandonment and reclamation costs, net of salvage                                         |  |              | 175  |   |    |   | 101 |    |  |   | 76                |  
|Well abandonment costs for developed reserves included in McDaniel Report                 |  |              | (55  | ) |    |   | (32 | )  |  |   | (25               | )
|Estimate of additional future abandonment and reclamation costs, net of salvage (1)       |  | $            | 121  |   |    | $ | 69  |    |  | $ | 52                |  



Note:



| | (1) | Future abandonment and reclamation costs not included in the McDaniel Report, net of salvage value.
| | --- | ---------------------------------------------------------------------------------------------------



Risk management



Perpetual’s
commodity price risk management strategy is focused on using derivative instruments to mitigate the effect of commodity price volatility
on funds flow, to lock in attractive economics on capital programs and acquisitions and to take advantage of perceived anomalies
in commodity markets.The Corporation uses both financial arrangements and physical forward sales to economically hedge
up to a maximum of 60 percent of the trailing quarter’s production including gas over bitumen
deemed volumes in accordance with the limits under the Corporation’s credit facility and Hedging and Risk Management Policy.
Perpetual will also enter into foreign exchange swaps and physical or financial swaps related to the differential between natural
gas prices at the AECO and NYMEX trading hubs in order to mitigate the effects of fluctuations in foreign exchange rates and basis
differentials on the Corporation’s realized prices. The term “derivatives” includes all financial and
physical risk management contracts. Although Perpetual considers the majority of these risk management contracts to be effective
economic hedges against potential commodity price volatility, the Corporation does not follow hedge accounting for its derivatives.



28







Perpetual’s
risk management activities are conducted by an internal Risk Management Committee under guidelines approved by the Corporation’s
Board of Directors. Perpetual’s risk management strategy, though designed primarily to protect funds flow, capital programs
and debt management, is opportunistic in nature. Depending on management’s perceived position in the commodity price cycle
the Corporation may elect to reduce or increase its risk management position within the approved guidelines. The Corporation mitigates
credit risk by entering into derivative contracts with financially sound, credit-worthy counterparties.



For a complete list of Perpetual’s
outstanding derivatives as at December 31, 2011, please see note 17 to the annual consolidated financial statements as at and for
the year ended December 31, 2011. Financial and physical forward natural gas sales arrangements
at the AECO trading hub as at March 7, 2012 are as follows:





|Type of contract     |  | Term                    |  | Volumes at
    AECO (GJ/d)(1) |  |  | Price
    ($/GJ)(1) |  |  | Futures
    market
    ($/GJ)(4) |  |  | % of 2012 gas
    production(2) | 
|-------------------- |  | ----------------------- |  | ----------------------------- |  |  | ------------------- |  |  | -------------------------------- |  |  | ------------------------------- | 
|Financial – AECO (3) |  | January - December 2012 |  | 45,250                        |  |  | 3.72                |  |  | 2.09                             |  |  | 35                              | 
|Financial - NYMEX    |  | March 2012              |  | 50,000                        |  |  | 2.52                |  |  | 2.45                             |  |  | 3                               | 
|Financial - AECO     |  | March 2012              |  | 40,000                        |  |  | 2.20                |  |  | 1.97                             |  |  | 3                               | 
|Financial - AECO     |  | April - October 2012    |  | 10,000                        |  |  | 2.85                |  |  | 1.84                             |  |  | 4                               | 
|Financial - AECO     |  | April - December 2012   |  | 19,000                        |  |  | 2.60                |  |  | 1.99                             |  |  | 11                              | 
|Physical - AECO      |  | April - December 2012   |  | 25,000                        |  |  | 2.59                |  |  | 1.99                             |  |  | 14                              | 
|Financial - AECO     |  | January - December 2013 |  | 25,000                        |  |  | 3.23                |  |  | 2.82                             |  |  | 19                              | 





Notes:

| | (1) | Average price calculated using weighted average price for net open sell contracts. NYMEX prices
in $US/MMBtu.
| | --- | -------------------------------------------------------------------------------------------------------------

| | (2) | Calculated using 2012 estimated gas production of 130,000 GJ/d including gas over bitumen deemed
production.
| | --- | ------------------------------------------------------------------------------------------------------------

| | (3) | These derivative transactions are part of paired transactions in which the proceeds from the sale
of crude oil call options which were used to fund the 2012 natural gas contracts at the price indicated.
| | --- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | (4) | Futures market price incorporates settled AECO Monthly Index and NYMEX prices for January to March
2013 and forward AECO prices as of March 7, 2012.
| | --- | ----------------------------------------------------------------------------------------------------------------------------------------------------



Perpetual also has in place the
following costless collar oil sales arrangements, to reduce exposure to fluctuations in the WTI index:





|Type of
    contract |  | Term                    |  | Volumes
    at WTI
    (bbl/d) |  | Floor price
    ($US/bbl)(1) |  | Ceiling price
    ($US/bbl)(1) |  | Futures
    market
    ($US/bbl)(3) |  | % of 2012 oil
    production(2) | 
|-------------------- |  | ----------------------- |  | ------------------------------ |  | ---------------------------- |  | ------------------------------ |  | ----------------------------------- |  | ------------------------------- | 
|Collar               |  | January – December 2012 |  | 500                            |  | 82.00                        |  | 91.00                          |  |                                     |  | 14                              | 
|Collar               |  | January - December 2012 |  | 500                            |  | 80.00                        |  | 89.00                          |  |                                     |  | 14                              | 
|Collar               |  | January - December 2012 |  | 500                            |  | 85.00                        |  | 97.00                          |  |                                     |  | 14                              | 
|Collar               |  | January – December 2012 |  | 500                            |  | 90.00                        |  | 109.25                         |  |                                     |  | 14                              | 
|Period total         |  | January - December 2012 |  | 2,000                          |  | 84.25                        |  | 96.50                          |  | 106.46                              |  | 56                              | 





Notes:



| | (1) | Average price calculated using weighted average price for net open sell contracts.
| | --- | ----------------------------------------------------------------------------------

| | (2) | Calculated using 2012 estimated oil and NGL production of 3,600 bbl/d including gas over bitumen
deemed production.
| | --- | -------------------------------------------------------------------------------------------------------------------

| | (3) | Futures market price incorporates settled and forward WTI oil prices as of March 7, 2012
| | --- | ----------------------------------------------------------------------------------------



The Company has entered into two contracts
to fix the WTI to oil price differential (WCS differential) on 400 bbl/d at $US17.35 per bbl and on 500 bbl/d at $28.75 per bbl,
both for the 2012 calendar year.

In addition, the Corporation has
sold oil call options exercisable and expiring as follows. A premium of $3.1 million was received in the fourth quarter of 2011
for the 2013 call option priced at $105 per bbl, which was included in funds flows for the period.





|Type of
    contract |  | Term                    |  | Expiry       |  | Volumes at
    WTI (bbl/d) |  | Strike price
    ($US WTI) |  | Futures market
    ($US WTI) | 
|-------------------- |  | ----------------------- |  | ------------ |  | -------------------------- |  | -------------------------- |  | ---------------------------- | 
|Call                 |  | January - December 2013 |  | Dec 31, 2012 |  | 1,000                      |  | 95.00                      |  | 105.55                       | 
|Call                 |  | January - December 2013 |  | monthly      |  | 1,000                      |  | 105.00                     |  | 105.55                       | 
|Call                 |  | January - December 2014 |  | monthly      |  | 2,000                      |  | 105.00                     |  | 99.65                        | 





29







Perpetual has entered into the following
U.S. dollar forward sales arrangements to limit the Corporation’s exposure to the effects of strength in the Canadian dollar
on natural gas prices.





|Type
    of contract |  | Term                          |  | Perpetual
    sold/bought |  | Notional
    $USD/month |            | Exchange
    rate
    ($CAD/$USD) |  
|-------------------- |  | ----------------------------- |  | ------------------------- |  | ----------------------- | ---------- | --------------------------------- | -
|Financial            |  | January  2012 – December 2012 |  | bought                    |  | $                       | (1,000,000 | )                                 | $
|Financial            |  | January  2012 – December 2012 |  | bought                    |  | $                       | (1,000,000 | )                                 | $
|Financial            |  | January  2012 – December 2012 |  | bought                    |  | $                       | (1,000,000 | )                                 | $
|Financial            |  | January  2012 – December 2012 |  | bought                    |  | $                       | (2,000,000 | )                                 | $





Perpetual entered into forward financial
power contracts to mitigate the risk to operating costs associated with fluctuations in power prices at the WGSI facility. Contracts
outstanding at March 7, 2012 are as follows:





|Type of contract |  | Term                 |  | Perpetual
    sold/bought |  |  | Volume
    (MWh) |   | Price ($CAD/MWh) |  
|---------------- |  | -------------------- |  | ------------------------- |  |  | ---------------- | - | ---------------- | -
|Financial        |  | January 2012         |  | bought                    |  |  | (7,261.44        | ) |                  | $
|Financial        |  | February 2012        |  | bought                    |  |  | (5,950.80        | ) |                  | $
|Financial        |  | March 2012           |  | bought                    |  |  | (5,133.60        | ) |                  | $
|Financial        |  | January – March 2013 |  | bought                    |  |  | (6,480.00        | ) |                  | $





INDUSTRY
CONDITIONS



Companies operating in the oil and natural
gas industry are subject to extensive regulation and control of operations (including land tenure, exploration, development, production,
refining and upgrading, transportation, and marketing) as a result of legislation enacted by various levels of government and with
respect to the pricing and taxation of oil and natural gas through agreements among the governments of Canada, Alberta and British
all of which should be carefully considered by investors in the oil and gas industry. It is not expected that any of these regulations
or controls will affect the Corporation's operations in a manner materially different than they will affect other oil and natural
gas companies of similar size. All current legislation is a matter of public record and the Corporation is 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 in western Canada.



Pricing and Marketing



Crude Oil
and Natural Gas Liquids

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. Oil prices are primarily
based on worldwide supply and demand. The specific price depends in part on oil quality, prices of competing fuels, distance to
market, 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.



Perpetual’s crude oil is sold under
contracts of varying terms up to one year based on market sensitive pricing terms, while natural gas liquids are sold under annual
arrangements. Industry pricing benchmarks for crude oil and natural gas liquids are continuously monitored to ensure optimal netbacks.



Canadian Natural Resources Limited, Cenovus
Energy, Suncor and Talisman Energy Inc., have implemented a new heavy oil stream named Western Canadian Select (WCS).



30







WCS — produced out of Western Canada
— is made up of existing Canadian heavy conventional and bitumen crude oils blended with sweet synthetic and condensate diluents.
It is a consistent high quality crude blend that was launched in December 2004 with volumes of approximately 250,000 barrels per
day, and is well-positioned to become a North American benchmark.



Natural Gas



The price of the vast majority of natural
gas produced in western Canada is now determined through highly liquid market hubs such as the Alberta "NIT" (Nova Inventory
Transfer) hub rather than through direct negotiation between buyers and sellers. Natural gas exported from Canada is subject to
regulation by the NEB and the Government of Canada. Exporters are free to negotiate prices and other terms with purchasers, provided
that the export contracts must continue to meet certain other criteria prescribed by the NEB and the Government of Canada. Natural
gas (other than propane, butane and ethane) exports for a term of less than two years or for a term of two to 20 years (in quantities
of not more than 30,000 m3/day) must be made pursuant to an NEB order. Any natural gas export to be made pursuant to
a contract of longer duration (to a maximum of 25 years) or for a larger quantity requires an exporter to obtain an export licence
from the NEB. The governments of Alberta and British Columbia also regulate the volume of natural gas that may be removed from
those provinces for consumption elsewhere based on such factors as reserve availability, transportation arrangements, and market
considerations.



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.



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, from time to time, carved out of the working interest owner's interest through non-public
transactions. These are often referred to as overriding royalties, gross overriding royalties, net profits interests, or net carried
interests.



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



31







Alberta



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



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



Royalty rates for conventional oil are
set by a single sliding rate formula which is applied monthly and incorporates separate variables to account for production rates
and market prices. Effective January 1, 2011, the maximum royalty payable under the royalty regime was set at 40%. The royalty
curve for conventional oil announced on May 27, 2010 amends the price component of the conventional oil royalty formula to moderate
the increase in the royalty rate at prices higher than $535/m3compared to the previous royalty curve.



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



Oil sands projects are also subject to
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 from 1 to 9% 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 1% when the market price of oil is less
than or equal to $55 per barrel and increase for every dollar of market price of oil increase to a maximum of 9% when oil is priced
at $120 or higher. After payout, the royalty payable is the greater of the gross revenue royalty based on the gross revenue royalty
rate of 1-9% and the net revenue royalty based on the net revenue royalty rate. Net revenue royalty rates start at 25% and increase
for every dollar of market price of oil increase above $55 up to 40% when oil is priced at $120 or higher. In addition, concurrently
with the implementation of the New Royalty Framework, the Government of Alberta renegotiated existing contracts with certain oil
sands producers that were not compatible with the current royalty regime.



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



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



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



32







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



On March 3, 2009, the Government of Alberta
announced a three-point incentive program in order to stimulate new and continued economic activity in Alberta. One aspect of the
program was a drilling royalty credit program which provided up to a $200 per metre royalty credit for new wells. The drilling
credit program applied to wells that were drilled between April 1, 2009 and March 31, 2011. Another aspect of the program was a
new well royalty program which provided for a maximum 5% royalty rate for eligible new wells for the first twelve (12) productive
months regulated “volume cap” was reached. The New Well RoyaltyRegulation, providing for the permanent implementation
of this incentive program, was approved by an Order-in-Council on March 17, 2011.



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



| | · | Coalbed methane wells will receive a maximum royalty rate of 5% for 36 producing months on up to
750 MMcf of production, retroactive to wells that began producing on or after May 1, 2010;
| | - | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | · | Shale gas wells will receive a maximum royalty rate of 5% for 36 producing months with no limitation
on production volume, retroactive to wells that began producing on or after May 1, 2010;
| | - | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | · | Horizontalgaswells will receive a maximum royalty rate of 5% for 18 producing months
on up to 500 MMcf of production, retroactive to wells that commenced drilling on or after May 1, 2010; and
| | - | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | · | Horizontal oil wells and horizontal non-project oil sands wells will receive a maximum royalty
rate of 5% with volume and production month limits set according to the depth of the well (including the horizontal distance),
retroactive to wells that commenced drilling on or after May 1, 2010.
| | - | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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



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
("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 as an incentive for the production and marketing of natural gas which might otherwise
have been flared.



33







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



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



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



| | · | Deep Royalty Credit Program providing a royalty credit equal to approximately 23% of drilling
and completion costs for vertical wells with a true vertical depth greater than 2,500 metres and horizontal wells with a true vertical
depth greater than 2,300 metres;
| | - | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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



| | · | Deep Discovery Royalty Credit Programproviding the lesser of a 3-year royalty holiday or
283,000,000 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 with a spud date after November 30, 2003;
| | - | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | · | Coalbed Gas Royalty Reduction and Credit Programproviding a royalty reduction for coalbed
gas wells with average daily production less than 17,000 m3as well as a royalty credit for coalbed gas wells equal
to $50,000 for wells drilled on Crown land and a tax credit equal to $30,000 for wells drilled on freehold land;
| | - | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | · | Marginal Royalty Reduction Program providing royalty reductions for low productivity natural
gas wells with average monthly production under 25,000 m3 during the first 12 production months and average daily production
less than 23 m3 for every metre of marginal well depth;
| | - | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | · | Ultra-Marginal Royalty Reduction Program providing additional royalty reductions for low
productivity shallow natural gas wells with a true vertical depth of less than 2,500 metres in the case of vertical wells, and
a total vertical depth of less than 2,300 metres in the case of a horizontal well, average monthly production under 60,000 m3
during the first 12 production months and average daily production less than 11.5 m3(development wells) or 17 m3
(exploratory wildcat wells) for every 100 metres of marginal well depth; and
| | - | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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



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



The Government of British Columbia also
maintains an Infrastructure Royalty Credit Program (the "Infrastructure Royalty Credit Program") which provides
royalty credits for up to 50% of the cost of certain approved road construction or pipeline infrastructure projects intended to
improve, or make possible, the access to new and underdeveloped oil and gas areas. In 2009, 2010 and 2011, the Government of British
Columbia awarded $120 million in royalty credits to oil and gas companies under the Infrastructure Royalty Credit Program.



34













On August 6, 2009, the Government of British
Columbia announced an oil and gas stimulus package designed to attract investment in and create economic benefits for British Columbia.
The stimulus package includes four royalty initiatives related primarily to natural gas drilling and infrastructure development.
British Columbia's existing Deep Royalty Credit Program was permanently amended for wells spudded after August 31, 2009 by increasing
the royalty deduction on deep drilling for natural gas by 15% and extending the program to include horizontal wells drilled to
depths of between 1,900 and 2,300 metres. An additional $50 million was also allocated to be distributed through the Infrastructure
Royalty Credit Program to stimulate investment in oilfield-related road and pipeline construction.



Land Tenure



Crude oil and natural gas located in the
western provinces is owned predominantly by the respective provincial governments. Provincial governments grant rights to explore
for and produce oil and natural gas pursuant to leases, licences, and permits for varying terms, and on conditions set forth in
provincial legislation including requirements to perform specific work or make payments. Oil and natural gas located in such provinces
can also be privately owned and rights to explore for and produce such oil and natural gas are granted by lease on such terms and
conditions as may be negotiated.



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



Alberta also has a policy of "shallow
rights reversion" which provides for the reversion to the Crown of mineral rights to shallow, non-productive geological formations
for all leases and licenses. For leases and licenses issued subsequent to January 1, 2009, shallow rights reversion will be applied
at the conclusion of the primary term of the lease or license. Holders of leases or licences that have been continued indefinitely
prior to January 1, 2009 will receive a notice regarding the reversion of the shallow rights, which will be implemented three years
from the date of the notice. Leases and licences that were granted prior to January 1, 2009 but continued after that date are not
subject to shallow rights reversion until they reach the end of their primary term and are continued (at which time deep rights
reversion will be applied); thereafter, the holders of such agreements will be served with shallow rights reversion notices based
on vintage and location similar to leases and licences that were already continued as of January 1, 2009. The order in
which these agreements will receive reversion notices will depend on their vintage and location, and the Government of Alberta
had anticipated that the receipt of reversion notices for older leases and licenses would commence in April 2011. However, on April
14, 2011, the Government of Alberta announced it was deferring serving shallow rights reversion notices and will revisit the decision
in spring 2012.



Environmental Regulation



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



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



35







The Alberta Land Stewardship Act
(the "ALSA") was proclaimed in force in Alberta on October 1, 2009, and provides the legislative authority for
the Government of Alberta to implement the policies contained in the ALUF. Regional plans established pursuant to the ALSA will
be deemed to be legislative instruments equivalent to regulations and will be binding on the Government of Alberta and provincial
regulators, including those governing the oil and gas industry. In the event of a conflict or inconsistency between a regional
plan and another regulation, regulatory instrument or statutory consent, the regional plan will prevail. Further, the ALSA requires
local governments, provincial departments, agencies and administrative bodies or tribunals to review their regulatory instruments
and make any appropriate changes to ensure that they comply with an adopted regional plan. The ALSA also contemplates the amendment
or extinguishment of previously issued statutory consents such as regulatory permits, leases, licenses, approvals and authorizations
for the purpose of achieving or maintaining an objective or policy resulting from the implementation of a regional plan. Among
the 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 29,
2011 the Government of Alberta released a revised draft of the Lower Athabasca Regional Plan (the "Revised LARP")
updating its prior draft of April 5, 2011 (the "Draft LARP"). The Revised LARP, while establishing several conservation
areas of the Athabasca region, has changed the boundaries of certain conservation areas outlined in the Draft LARP with the result
that fewer oil sands leases appear to be impacted. Consistent with the Draft LARP, as the intention of the Revised LARP is to manage
the areas to minimize or prevent new land disturbance, activities associated with oil sands development are considered incompatible
with the intent to manage such conservation areas. However, references to the cancellation of existing tenures have been removed
from the Revised LARP and the Revised LARP now contemplates that the conservation areas will be created pursuant to existing legislation
rather than the previously contemplated regulations. Existing conventional petroleum and natural gas rights will not be affected,
although the Revised LARP raises some question as to whether new conventional leases and licenses will be granted in the conservation
areas in the future. The planning process is also underway for a regional plan for the South Saskatchewan Region.



Climate Change Regulation



Federal



In December 2002, the Government of Canada
ratified the Kyoto Protocol ("Kyoto Protocol"), which requires a reduction in greenhouse gas ("GHG")
emissions by signatory countries between 2008 and 2012. The Kyoto Protocol officially came into force on February 16, 2005 although
on December 12, 2011 Canada formally withdrew from the Kyoto Protocol. On April 26, 2007, the Government of Canada released "Turning
the Corner: An Action Plan to Reduce Greenhouse Gases and Air Pollution" (the "Action Plan") which set forth
a plan for regulations to address both GHGs and air pollution. An update to the Action Plan, "Turning the Corner: Regulatory
Framework for Industrial Greenhouse Gas Emissions" was released on March 10, 2008 (the "Updated Action Plan").
The Updated Action Plan outlines emissions intensity-based targets which will be applied to regulated sectors on either a facility-specific,
sector-wide or company-by-company basis. Facility-specific targets apply to the upstream oil and gas, oil sands, petroleum refining
and natural gas pipelines sectors. Unless a minimum regulatory threshold applies, all facilities within a regulated sector will
be subject to the emissions intensity targets.



The Updated Action Plan makes a distinction
between "Existing Facilities" and "New Facilities". For Existing Facilities, the Updated Action Plan requires
an emissions intensity reduction of 18% below 2006 levels by 2010 followed by a continuous annual emissions intensity improvement
of 2%. "New Facilities" are defined as facilities beginning operations in 2004 and include both greenfield facilities
and major facility expansions that (i) result in a 25% or greater increase in a facility's physical capacity, or (ii) involve significant
changes to the processes of the facility. New Facilities will be given a 3-year grace period during which no emissions intensity
reductions will be required. Targets requiring an annual 2% emissions intensity reduction will begin to apply in the fourth year
of commercial operation of a New Facility. Further, emissions intensity targets for New Facilities will be based on a cleaner fuel
standard to encourage continuous emissions intensity reductions over time. The method of applying this cleaner fuel standard has
not yet been determined. In addition, the Updated Action Plan indicates that targets for the adoption of carbon capture and storage
("CCS") technologies will be developed for oil sands in-situ facilities, upgraders and coal-fired power generators
that begin operations in 2012 or later. These targets will become operational in 2018, although the exact nature of the targets
has not yet been determined.



36







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



Four separate compliance mechanisms are
provided for in the Updated Action Plan in respect of the above targets:



Regulated entities
will be able to use Technology Fund contributions to meet their emissions intensity targets. The contribution rate for Technology
Fund contributions will increase over time, beginning at $15 per tonne of CO2 equivalent for the 2010 to 2012 period,
rising to $20 in 2013, and thereafter increasing at the nominal rate of GDPgrowth. Maximum contribution limits will also
decline from 70% in 2010 to 0% in 2018. Monies raised through contributions to the Technology Fund will be used to invest in technology
to reduce GHG emissions. Alternatively, regulated entities may be able to receive credits for investing in large-scale and transformative
projects at the same contribution rate and under similar requirements as described above.



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



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



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



From December 7 to 18, 2009, government
leaders and representatives met in Copenhagen, Denmark and agreed to the Copenhagen Accord, which reinforces the commitment to
reducing GHG emissions contained in the Kyoto Protocol and promises funding to help developing countries mitigate and adapt to
climate change. Another meeting of government leaders and representatives in 2010 resulted in the Cancun Agreements developed countries
committed to additional measures to help developing countries deal with climate change. Neither the Copenhagen Accord nor the Cancun
Agreements establish binding GHG emissions reduction targets. In response to the Copenhagen Accord, the Government of Canada indicated
that it will seek to achieve a 17% reduction in GHG emissions from 2005 levels by 2020.



Although draft
regulations for the implementation of the Updated Action Plan were intended to become binding on January 1, 2010, only draft regulations
pertaining to carbon dioxide emissions from coal-fired generation of electricity have been proposed to date. Further, representatives
of the Government of Canada have indicated that the proposals contained in the Updated Action Plan will be modified to ensure consistency
with the direction ultimately taken by the United States with respect toGHG emissions regulation.
As a result,it is unclear to what extent, if any, the proposals contained in the Updated Action Plan will be implemented.



37







The United States
Environmental Protection Agency (the “EPA”) has indicated its intention to imposeGHG emissions
standards for fossil fuel-fired power plants by specifying that it will issue final regulations by May 26, 2012, and with respect
to refineries, specifying that it will issue proposed regulations by December 10, 2011 and finalize regulations by November 10,
2012. The EPA did not meet the December, 2011 deadline and it is unclear whether the EPA will also miss the finalized regulations
deadline.



Alberta



Alberta enacted the Climate Change and
Emissions Management Act(the "CCEMA") on December 4, 2003, amending it through the Climate Change and
Emissions Management Amendment Actwhich received royal assent on November 4, 2008. The CCEMA is based on an emissions intensity
approach similar to the Updated Action Plan and aims for a 50% reduction from 1990 emissions relative to GDP by 2020.



Alberta facilities emitting more than 100,000
tonnes of GHGs a year are subject to compliance with the CCEMA.Similar to the Updated Action Plan, the CCEMA and the associated
Specified Gas Emitters Regulation make a distinction between "Established Facilities" and "New Facilities".
Established Facilities are defined as facilities that completed their first year of commercial operation
prior to January 1, 2000 or that have completed eight or more years of commercial operation.Established Facilities are
required to reduce their emissions intensity to 88% of their baseline for 2008 and subsequent years, with their baseline being
established by the average of the ratio of the total annual emissions to production for the years 2003 to 2005. New Facilities
are defined as facilities that completed their first year of commercial operation on December 31, 2000, or a subsequent year, and
have completed less than eight years of commercial operation, or are designated as New Facilities in accordance with theSpecified
Gas Emitters Regulation. New Facilities are required to reduce their emissions intensity by 2% from
baseline in the fourth year of commercial operation, 4% of baseline in the fifth year, 6% of baseline in the sixth year, 8% of
baseline in the seventh year, and 10% of baseline in the eighth year. Unlike the Updated Action Plan, the CCEMA does not contain
any provision for continuous annual improvements in emissions intensity reductions beyond those stated above.



The CCEMA contains compliance mechanisms
that are similar to the Updated Action Plan. Regulated emitters can meet their emissions intensity targets by contributing to the
Climate Change and Emissions Management Fund (the "Fund") at a rate of $15 per tonne of CO2 equivalent.
Unlike the Updated Action Plan, CCEMA contains no provisions for an increase to this contribution rate. Emissions credits can be
purchased from regulated emitters that have reduced their emissions below the 100,000 tonne threshold or non-regulated emitters
that have generated emissions offsets through activities that result in emissions reductions in accordance with established protocols
published by the Government of Alberta. On December 2, 2010, the Government of Alberta passed theCarbon Capture and Storage
Statutes Amendment Act, 2010, which deemed the pore space underlying all land in Alberta to be, and to have always been, the
property of the Crown and provided for the assumption of long-term liability for carbon sequestration projects by the Crown, subject
to the satisfaction of certain conditions.



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 $25 per
tonne of CO2 equivalent. It is scheduled to increase to $30 per tonne of CO2 equivalent onJuly 31,
2012. In order to make the tax revenue-neutral, British Columbia has implemented tax credits and reductions in order to offset
the tax revenues that the Government of British Columbia would otherwise receive from the tax.



On April 3, 2008, British Columbia introduced
the Greenhouse Gas Reduction (Cap and Trade) Act (the "Cap and Trade Act") which received royal assent
on May 29, 2008 and partially came into force by regulation of the Lieutenant Governor in Council. Unlike the emissions intensity
approach taken by the federal government and the Government of Alberta, the Cap and Trade Act establishes an absolute cap on GHG
emissions. Although more specific details of British Columbia's cap and trade plan have not yet been
finalized, on January 1, 2010, new reporting regulations came into force requiring all British Columbia facilities emitting over
10,000 tonnes of CO2 equivalents per year to begin reporting their emissions. Facilities reporting emissions greater
than 25,000 tonnes of CO2 equivalents per year are required to have their emissions reports verified by a third party.
Regulations pertaining to proposed offsets and emissions trading are currently in the consultation stage.



38







RISK
FACTORS



Investors should carefully consider
the risk factors set out below and consider all other information contained herein and in the Corporation's other public filings
before making an investment decision.



Gas Over Bitumen
Matters



The ERCB has established a process to identify
gas production in Alberta that may pose an unacceptable risk to the stability and viability of co-located bitumen resources and
has ordered the shut-in of certain natural gas production in northeast Alberta. These "shut-in orders" have called into
question the ability to produce natural gas when the production of natural gas interferes with ultimate bitumen recovery. In particular,
the ERCB, as part of its broad bitumen conservation strategy, has ordered the shut-in of natural gas production in the Wabiskaw
and McMurray formations in certain parts of the Athabasca Oil Sands Area in northeast Alberta. Certain of the Corporation's assets
are directly affected by such shut-in orders. The Corporation cannot ensure that additional production will not be shut-in in the
future or that it will be able to negotiate adequate compensation for having to shut-in any such production. This could have a
material adverse effect on our business, financial condition and operations.



The Government of Alberta has presently
prescribed a financial solution in the form of reduction in the royalty calculated for operators of gas wells which have been affected
by shut-in orders. The Corporation is currently receiving these royalty reductions and there is no assurance that such reductions
will continue to be received by the Corporation or that the Corporation will have sufficient gas crown royalties against which
to apply the royalty reductions.



Solution Gas Ownership



A portion of the Corporation's natural
gas production is from properties where third parties hold bitumen rights. Certain of these third parties have suggested that "solution
gas" exists within the bitumen and that therefore this solution gas is the property of the bitumen rights holder. If this
is proven to be correct, and if it is demonstrated that this solution gas has been or may continue to be produced in association
with the recovery of Perpetual's conventional natural gas rights, these facts may give rise to a third party claim for compensation
and impact future production and reserves. A successful claim in this regard may have a material adverse effect on our business,
financial condition and operations.



Exploration, Development
and Production Risks



Oil and natural gas operations involve
many risks that even a combination of experience, knowledge and careful evaluation may not be able to overcome. The long-term commercial
success of the Corporation depends on its ability to find, acquire, develop and commercially produce oil and natural gas reserves.
Without the continual addition of new reserves, any existing reserves the Corporation may have at any particular time, and the
production therefrom will decline over time as such existing reserves are exploited. A future increase in the Corporation's reserves
will depend not only on its ability to explore and develop any properties it may have from time to time, but also on its ability
to select and acquire suitable producing properties or prospects. No assurance can be given that the Corporation will be able to
continue to locate satisfactory properties for acquisition or participation therein. Moreover, if such acquisitions or participations
are identified, management of the Corporation may determine that current markets, terms of acquisition and participation or pricing
conditions make such acquisitions or participations uneconomic. There is no assurance that further commercial quantities of oil
and natural gas will be discovered or acquired by the Corporation.



39







Future oil and natural gas exploration
may involve unprofitable efforts, not only from dry wells, but also 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 or environmental damage could greatly increase the cost of operations, and various field operating conditions may adversely
affect the production from successful wells. These conditions include delays in obtaining governmental approvals or consents, shut-ins
of connected wells resulting from extreme weather conditions, insufficient storage or transportation capacity or other geological
and mechanical conditions. While diligent well supervision and effective maintenance operations can contribute to maximizing production
rates over time, production delays and declines from normal field operating conditions cannot be eliminated and can be expected
to adversely affect revenue and cash flow levels to varying degrees.



Oil and natural gas exploration, development
and production operations are subject to all the risks and hazards typically associated with such operations, including fire, explosion,
blowouts, cratering, sour gas releases spills, or other environmental hazards, each of which could result in substantial damage
to oil and natural gas wells, production facilities, other property and the environment or personal injury. In particular, the
Corporation 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 the Corporation. 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 the Corporation's business, financial condition, results of operations and prospects. In accordance with industry practice,
the Corporation is not fully insured against all of these risks, nor are all such risks insurable. Although the Corporation maintains
liability insurance in an amount that it considers consistent with industry practice, the nature of these risks is such that liabilities
could exceed policy limits, in which event the Corporation could incur significant costs.



Global Financial
Crisis



Recent market events and conditions, including
disruptions in the international credit markets and other financial systems and the American and European sovereign debt levels
have caused significant volatility in commodity prices. These conditions have caused a decrease in confidence in the global credit
and financial markets and have created a climate of greater volatility, less liquidity, widening of credit spreads, a lack of price
transparency, increased credit losses and tighter credit conditions. Notwithstanding various actions by governments, concerns about
the general condition of the capital markets, financial instruments, banks, investment banks, insurers and other financial institutions
caused the broader credit markets to further deteriorate and stock markets to decline substantially. This volatility may in the
future affect the Corporation’s ability to obtain equity or debt financing on acceptable terms.



Prices, Markets
and Marketing



The marketability and price of oil and
natural gas that may be acquired or discovered by the Corporation is and will continue to be affected by numerous factors beyond
its control. The Corporation's ability to market its oil and natural gas may depend upon its ability to acquire space on pipelines
that deliver natural gas to commercial markets. The Corporation may also be affected by deliverability uncertainties related to
the proximity of its reserves to pipelines and processing and storage facilities and operational problems affecting such pipelines
and facilities as well as extensive government regulation relating to price, taxes, royalties, land tenure, allowable production,
the export of oil and natural gas and many other aspects of the oil and natural gas business.



The prices of oil and natural gas prices
may be volatile and subject to fluctuation. Any material decline in prices could result in a reduction of the Corporation's net
production revenue. The economics of producing from some wells may change as a result of lower prices, which could result in reduced
production of oil or natural gas and a reduction in the volumes of the Corporation's reserves. The Corporation might also elect
not to produce from certain wells at lower prices. All of these factors could result in a material decrease in the Corporation's
expected net production revenue and a reduction in its oil and natural gas acquisition, development and exploration activities.
Prices for oil and natural gas are subject to large fluctuations in response to relatively minor changes in the supply of and demand
for oil and natural gas, market uncertainty and a variety of additional factors beyond the control of the Corporation. These factors
include economic conditions, in the United States, Canada and Europe, the actions of OPEC, governmental regulation, political stability
in the Middle East, Northern Africa and elsewhere, the foreign supply of oil and natural gas, risks of supply disruption, regional
product pipeline takeaway capacity affecting market hub pricing, refinery capacity, the price of foreign imports and the availability
of alternative fuel sources. Any substantial and extended decline in the price of oil and natural gas would have an adverse effect
on the Corporation's carrying value of its reserves, borrowing capacity, revenues, profitability and cash flows from operations
and may have a material adverse effect on the Corporation's business, financial condition, results of operations and prospects.



40







Oil and natural gas prices are expected
to remain volatile for the near future as a result of market uncertainties over the supply and the demand of these commodities
due to the current state of the world economies, OPEC actions, and sanctions imposed on certain oil producing nations by other
countries and the ongoing credit and liquidity concerns. Volatile oil and natural gas prices make it difficult to estimate the
value of producing properties for acquisitions and often cause disruption in the market for oil and natural gas producing properties,
as buyers and sellers have difficulty agreeing on such value. Price volatility also makes it difficult to budget for and project
the return on acquisitions and development and exploitation projects.



Market Price of
Common Shares



The
trading price of securities of oil and natural gas issuers is subject to substantial volatility. This volatility is often based
on factors both related and unrelated to the financial performance or prospects of the issuers involved. The market price of the
common shares of the Corporation could be subject to significant fluctuations in response to variations in the Corporation's operating
results, future cash flow predictions, financial condition, liquidity and other internal factors. Factors that could affect the
market price of the common shares of the Corporation that are unrelated to the Corporation's performance include domestic and global
commodity prices and market perceptions of the attractiveness of particular industries. The price at which the common shares of
the Corporation will trade cannot be accurately predicted.



Failure to Realize
Anticipated Benefits of Acquisitions and Dispositions



The Corporation considers acquisitions
and dispositions of businesses and assets in the ordinary course of business. Achieving the benefits of acquisitions depends in
part on successfully consolidating functions and integrating operations and procedures in a timely and efficient manner as well
as the Corporation's ability to realize the anticipated growth opportunities and synergies from combining the acquired businesses
and operations with those of the Corporation. The integration of acquired businesses may require substantial management effort,
time and resources and may divert management's focus from other strategic opportunities and operational matters. Management continually
assesses the value and contribution of services provided and assets required to provide such services. In this regard, non-core
assets may be periodically disposed of, so that the Corporation can focus its efforts and resources more efficiently. Depending
on the state of the market for such non-core assets, certain non-core assets of the Corporation, if disposed of, could be expected
to realize less than their carrying value on the financial statements of the Corporation.



Operational Dependence



Other companies operate some of the assets
in which the Corporation has an interest. As a result, the Corporation has limited ability to exercise influence over the operation
of those assets or their associated costs, which could adversely affect the Corporation's financial performance. The Corporation's
return on assets operated by others therefore depends upon a number of factors that may be outside of the Corporation's control,
including the timing and amount of capital expenditures, the operator's expertise and financial resources, the approval of other
participants, the selection of technology and risk management practices.



Project Risks



The Corporation manages a variety of small
and large projects in the conduct of its business. Project delays may delay expected revenues from operations. Significant project
cost over-runs could make a project uneconomic. The Corporation's ability to execute projects and market oil and natural gas depends
upon numerous factors beyond the Corporation's control, including:



41







| | · | The availability of fracture stimulation equipment and services;
| | - | ----------------------------------------------------------------

| | · | 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, and the ability to acquire, water supplies needed for drilling and hydraulic
fracturing, or the Corporation's ability to dispose of water used or removed from strata at a reasonable cost and within applicable
environmental regulations;
| | - | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | · | 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, the Corporation
could be unable to execute projects on time, on budget or at all, and may not be able to effectively market the oil and natural
gas that it produces.



Gathering and Processing
Facilities and Pipeline Systems



The
Corporation delivers its products through gathering, processing and pipeline systems some of which it does not own. The amount
of oil and natural gas that the Corporation can produce and sell is subject to the accessibility, availability, proximity and capacity
of these gathering, processing and pipeline systems. The lack of availability of capacity in any of the gathering, processing and
pipeline systems, and in particular the processing facilities, could result in the Corporation’s inability to realize the
full economic potential of its production or in a reduction of the price offered for the Corporation’s production. 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 the Corporation's business and, in turn, the Corporation’s financial
condition, results of operations and cash flows.



A
portion of the Corporation's production may, from time to time, be processed through facilities owned by third parties and over
which the Corporation does not have control. From time to time these facilities may discontinue or decrease operations either as
a result of normal servicing requirements or as a result of unexpected events. A discontinuation or decrease of operations could
materially adversely affect the Corporation's ability to process its production and to deliver the same for sale.



Competition



The petroleum industry is competitive in
all its phases. The Corporation competes 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. The Corporation's competitors include oil and natural gas companies
that have substantially greater financial resources, staff and facilities than those of the Corporation. The Corporation's ability
to increase its reserves in the future will depend not only on its ability to explore and develop its present properties, but also
on its 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 and methods and reliability of delivery and storage. Competition
may also be presented by alternate fuel sources.



42







Regulatory



Oil and natural gas operations (exploration,
production, pricing, marketing and transportation) are subject to extensive controls and regulations imposed by various levels
of government, which may be amended from time to time. See "Industry Conditions". Governments may regulate or
intervene with respect to exploration and production activities, price, taxes, royalties and the exportation of oil and natural
gas. Such regulations may be changed 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 crude oil and increase the Corporation's costs, any of which may have a material adverse effect on the
Corporation's business, financial condition, results of operations and prospects. In order to conduct oil and natural gas operations,
the Corporation will require licenses from various governmental authorities. There can be no assurance that the Corporation will
be able to obtain all of the licenses and permits that may be required to conduct operations that it may wish to undertake.



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. The use of hydraulic fracturing is being 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 or third party or governmental claims, and could
increase the Corporation's costs of compliance and doing business as well as delay the development of oil and natural gas resources
from tight sand and 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 the Corporation is ultimately able to produce from its reserves
and resource base.



Environmental



All phases of the oil and natural gas business
present environmental risks and hazards and are subject to environmental regulation pursuant to a variety of federal, provincial
and local laws and regulations. Environmental legislation provides for, among other things, restrictions and prohibitions on spills,
releases or emissions of various substances produced in association with oil and natural gas operations. The legislation also requires
that wells and facility sites be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities.
Compliance with such 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 the Corporation to incur costs to remedy such discharge. Although the Corporation
believes that it 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 the Corporation's business, financial condition, results
of operations and prospects.



Climate Change



The Corporation's exploration and production
facilities and other operations and activities emit greenhouse gases and require the Corporation to comply with greenhouse gas
emissions legislation in Alberta and British Columbia or that may be enacted in other provinces. The Corporation may also be required
to comply with the regulatory scheme for greenhouse gas emissions ultimately adopted by the federal government, which regulations
are expected to be consistent with the regulatory scheme for greenhouse gas emissions adopted by the United States. The direct
or indirect costs of these regulations may have a material adverse effect on the Corporation's business, financial condition, results
of operations and prospects. The future implementation or modification of greenhouse gases regulations, whether to meet the limits
regulated by the Copenhagen Accord or as otherwise determined, could have a material impact on the nature of oil and natural gas
operations, including those of the Corporation. 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 the Corporation and its operations
and financial condition. See "Industry Conditions – Climate Change Regulation".



43







Variations in Foreign
Exchange Rates and Interest Rates



World oil and natural gas prices are quoted
in United States dollars and the price received by Canadian producers is therefore affected by the Canadian/U.S. dollar exchange
rate, which will fluctuate over time. In recent years, the Canadian dollar has increased materially in value against the United
States dollar. Material increases in the value of the Canadian dollar negatively impact the Corporation's production revenues.
Future Canadian/United States exchange rates could accordingly impact the future value of the Corporation's reserves as determined
by independent evaluators.



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



An increase in interest rates could result
in a significant increase in the amount the Corporation pays to service debt, which could negatively impact the market price of
the common shares of the Corporation.



Substantial Capital
Requirements



The Corporation anticipates making substantial
capital expenditures for the acquisition, exploration, development and production of oil and natural gas reserves in the future.
As future capital expenditures will be financed out of cash generated from operations, borrowings and possible future equity sales,
the Corporation's ability to do so is dependent on, among other factors, the overall state of the capital markets, the Corporation’s
credit rating (if applicable), interest rates, tax burden due to new tax laws and investor appetite for investments in the energy
industry and the Corporation's securities in particular. Further, if the Corporation's revenues or reserves decline, it may not
have access to the capital necessary to undertake or complete future drilling programs. There can be no assurance that debt or
equity financing, or cash generated by operations will be available or sufficient to meet these requirements or for other corporate
purposes or, if debt or equity financing is available, that it will be on terms acceptable to the Corporation. The inability of
the Corporation to access sufficient capital for its operations could have a material adverse effect on the Corporation's business
financial condition, results of operations and prospects.



Additional Funding
Requirements



The Corporation's cash flow from its reserves
may not be sufficient to fund its ongoing activities at all times and from time to time, the Corporation may require additional
financing in order to carry out its oil and natural gas acquisition, exploration and development activities. As a result of the
global economic volatility, the Corporation, along with many other oil and natural gas entities, may, from time to time, have restricted
access to capital and increased borrowing costs. Failure to obtain such financing on a timely basis could cause the Corporation
to forfeit its interest in certain properties, miss certain acquisition opportunities and reduce or terminate its operations. If
the Corporation's revenues from its reserves decrease as a result of lower oil and natural gas prices or otherwise, it will affect
the Corporation's ability to expend the necessary capital to replace its reserves or to maintain its production. To the extent
that external sources of capital become limited or unavailable or available on terms the Corporation's ability to make capital
investments and maintain existing assets may be impaired, and its assets, liabilities, business, financial condition and results
of operations may be materially and adversely affected as a result. In addition, the future development of the Corporation's petroleum
properties may require additional financing and there are no assurances that such financing will be available or, if available,
will be available upon acceptable terms. Failure to obtain any financing necessary for the Corporation's capital expenditure plans
may result in a delay in development or production on the Corporation’s properties.

44







Credit Facility Arrangements



The Corporation currently has a credit
facility and the amount authorized thereunder is dependent on the borrowing base determined by its lenders. The Corporation is
required to comply with covenants under its credit facility which may, in certain cases, include certain financial ratio tests,
which from time to time either affect the availability, or price, of additional funding and in the event that the Corporation does
not comply therewith the Corporation's access to capital could be restricted or repayment could be required. The failure of the
Corporation to comply with such covenants, which may be affected by events beyond the Corporation's control, could result in the
default under the Corporation's credit facility which could result in the Corporation being required to repay amounts owing thereunder.
Even if the Corporation is able to obtain new financing, it may not be on commercially reasonable terms or terms that are acceptable
to the Corporation. If the Corporation is unable to repay amounts owing, the lenders under the credit facility could proceed to
foreclose or otherwise realize upon the collateral granted to them to secure the indebtedness. The acceleration of the Corporation's
indebtedness under one agreement may permit acceleration of indebtedness under other agreements that contain cross default or cross-acceleration
provisions. In addition, the Corporation's credit facility may, from time to time, impose operating and financial restrictions
on the Corporation that could include restrictions on, the payment of dividends, repurchase or making of other distributions with
respect to the Corporation's securities, incurring of additional indebtedness, provision of guarantees, the assumption of loans,
making of capital expenditures, entering into of amalgamations, mergers, take-over bids or disposition of assets, among others.



The Corporation's borrowing base is determined
and re-determined by the Corporation's lenders based on the Corporation's reserves, commodity prices, applicable discount rate
and other factors as determined by the Corporation's lenders. A material decline in commodity prices could reduce the Corporation's
borrowing base, therefore reducing the funds available to the Corporation under the credit facility, the result of which could
be that a portion, or all, of the Corporation's bank indebtedness be required to be repaid.



Issuance of Debt



From time to time the Corporation may enter
into transactions to acquire assets or shares of other organizations. These transactions may be financed in whole or in part with
debt, which may increase the Corporation's debt levels above industry standards for oil and natural gas companies of similar size.
Depending on future exploration and development plans, the Corporation may require additional debt financing that may not be available
or, if available, may not be available on favourable terms. Neither the Corporation's articles nor its by-laws limit the amount
of indebtedness that the Corporation may incur. The level of the Corporation's indebtedness from time to time, could impair the
Corporation's ability to obtain additional financing on a timely basis to take advantage of business opportunities that may arise.



Hedging



From time to time the Corporation may enter
into agreements to receive fixed prices, floors or ceilings, on its oil and natural gas production to offset the risk of revenue
losses if commodity prices decline. However, to the extent that the Corporation engages in price risk management activities to
protect itself from commodity price declines, it 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, the Corporation’s hedging arrangements may
expose it 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 the Corporation
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, the Corporation will not benefit from the fluctuating exchange rate.



Availability of
Drilling and Completion Equipment and Access



Oil and natural gas exploration and development
activities are dependent on the availability of drilling and completion and related equipment (typically leased from third parties)
in the particular areas where such activities will be conducted. Demand for such limited equipment or access restrictions may affect
the availability of such equipment to the Corporation and may delay exploration and development activities.



45







Title to Assets



Although title reviews may be conducted
prior to the purchase of oil and natural gas producing properties or the commencement of drilling wells, such reviews do not guarantee
or certify that an unforeseen defect in the chain of title will not arise to defeat the Corporation's claim which may have a material
adverse effect on the Corporation's business, financial condition, results of operations and prospects. There may be valid challenges
to title, or proposed legislative changes which affect title, to the oil and natural gas properties the Corporation controls that,
if successful or made into law, could impair the Corporation’s activities on them and result in a reduction of the revenue
received by the Corporation.



Reserve Estimates



There are numerous uncertainties inherent
in estimating quantities of oil, natural gas and natural gas liquids reserves and the future cash flows attributed to such reserves.
The reserve and associated cash flow information set forth herein are estimates only. In general, estimates of economically recoverable
oil and natural gas reserves and the future net cash flows therefrom are based upon a number of variable factors and assumptions,
such as historical production from the properties, production rates, ultimate reserve recovery, timing and amount of capital expenditures,
marketability of oil and natural gas, royalty rates, the assumed effects of regulation by governmental agencies and future operating
costs, all of which may vary materially from actual results. For those reasons, estimates of the economically recoverable oil and
natural gas reserves attributable to any particular group of properties, classification of such reserves based on risk of recovery
and estimates of future net revenues associated with reserves prepared by different engineers, or by the same engineers at different
times, may vary. The Corporation's actual production, revenues, taxes and development and operating expenditures with respect to
its reserves will vary from estimates thereof and such variations could be material.



Estimates of proved reserves that may be
developed and produced in the future can be based upon volumetric calculations and upon analogy to similar types of reserves rather
than actual production history. Recovery factors and drainage areas are estimated by experience and analogy to similar producing
pools. Estimates based on these methods are generally less reliable than those based on actual production history. Subsequent evaluation
of the same reserves based upon production history and production practices can result in variations in the estimated reserves
and such variations could be material.



In accordance with applicable securities
laws, the Corporation's independent reserves evaluator has used forecast prices and costs in estimating the reserves and future
net cash flows as summarized herein. Actual future net cash flows will be affected by other factors, such as actual production
levels, supply and demand for oil and natural gas, pipeline restrictions leading to market aberrations, curtailments or increases
in consumption by oil and natural gas purchasers, changes in governmental regulation or taxation and the impact of inflation on
costs.



Actual production and cash flows derived
from the Corporation's oil and natural gas reserves will vary from the estimates contained in the reserve evaluation, and such
variations could be material. The reserve evaluation is based in part on the assumed success of activities the Corporation intends
to undertake in future years. The reserves and estimated cash flows to be derived therefrom contained in the reserve evaluation
will be reduced to the extent that such activities do not achieve the level of success assumed in the reserve evaluation. The reserve
evaluation is effective as of a specific effective date and has not been updated and thus does not reflect changes in the Corporation's
reserves since that date.



Insurance



The Corporation's involvement in the exploration
for and development of oil and natural gas properties may result in the Corporation becoming subject to liability for pollution,
blow outs, leaks of sour natural gas, property damage, personal injury or other hazards. Although the Corporation maintains insurance
in accordance with industry standards to address certain of these risks, such insurance has limitations on liability and may not
be sufficient to cover the full extent of such liabilities. In addition, certain risks are not, in all circumstances, insurable
or, in certain circumstances, the Corporation may elect not to obtain insurance to deal with specific risks due to the high premiums
associated with such insurance or other reasons. The payment of any uninsured liabilities would reduce the funds available to the
Corporation. The occurrence of a significant event that the Corporation is not fully insured against, or the insolvency of the
insurer of such event, may have a material adverse effect on the Corporation's business, financial condition, results of operations
and prospects.



46







GeoPolitical Risks



The marketability and price of oil and
natural gas that may be acquired or discovered by the Corporation is and will continue to be affected by political events throughout
the world that cause disruptions in the supply of oil. Conflicts, or conversely peaceful developments, arising in the Middle East,
North Africa and other areas of the world have a significant impact on the price of oil and natural gas. Any particular event could
result in a material decline in prices and therefore result in a reduction of the Corporation's net production revenue.



In addition, the Corporation's oil and
natural gas properties, wells and facilities could be subject to a terrorist attack. If any of the Corporation's properties, wells
or facilities are the subject of terrorist attack it may have a material adverse effect on the Corporation's business, financial
condition, results of operations and prospects. The Corporation does not have insurance to protect against the risk from terrorism.



Dilution



The Corporation may make future acquisitions
or enter into financings or other transactions involving the issuance of securities of the Corporation which may be dilutive.



Management of Growth



The Corporation may be subject to growth
related risks including capacity constraints and pressure on its internal systems and controls. The ability of the Corporation
to manage growth effectively will require it to continue to implement and improve its operational and financial systems and to
expand, train and manage its employee base. The inability of the Corporation to deal with this growth may have a material adverse
effect on the Corporation's business, financial condition, results of operations and prospects.



Expiration of Licences
and Leases



The Corporation's properties are held in
the form of licences and leases and working interests in licences and leases. If the Corporation or the holder of the licence or
lease fails to meet the specific requirement of a licence or lease, the licence or lease may terminate or expire. There can be
no assurance that any of the obligations required to maintain each licence or lease will be met. The termination or expiration
of the Corporation's licences or leases or the working interests relating to a licence or lease may have a material adverse effect
on the Corporation's business, financial condition, results of operations and prospects.



Dividends



The Corporation does not presently pay
any dividends on its outstanding shares. Payment of dividends in the future will be dependent on, among other things, the cash
flow, results of operations and financial condition of the Corporation, the need for funds to finance ongoing operations and other
considerations as the board of directors of the Corporation considers relevant.



Aboriginal Claims



Aboriginal peoples have claimed aboriginal
title and rights to portions of western Canada. The Corporation is not aware that any claims have been made in respect of its properties
and assets; however, if a claim arose and was successful such claim may have a material adverse effect on the Corporation's business,
financial condition, results of operations and prospects.



47







Seasonality



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 the goods and services of the Corporation.



Third Party Credit
Risk



The Corporation may be exposed to third
party credit risk through its contractual arrangements with its current or future joint venture partners, marketers of its petroleum
and natural gas production and other parties. In the event such entities fail to meet their contractual obligations to the Corporation,
such failures may have a material adverse effect on the Corporation's 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 the Corporation's ongoing capital program, potentially delaying the program and the results of such
program until the Corporation finds a suitable alternative partner.



Conflicts of Interest



Certain directors of the Corporation are
also directors of other oil and natural 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. See "Directors
and Officers – Conflicts of Interest".



Reliance on Key
Personnel



The Corporation's success depends in large
measure on certain key personnel. The loss of the services of such key personnel may have a material adverse effect on the Corporation's
business, financial condition, results of operations and prospects. The Corporation does not have any key person insurance in effect
for the Corporation. The contributions of the existing management team to the immediate and near term operations of the Corporation
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 the Corporation will be able to continue to attract and retain all personnel necessary
for the development and operation of its business. Investors must rely upon the ability, expertise, judgment, discretion, integrity
and good faith of the management of the Corporation.



Certain Forward-Looking
Information May Prove Inaccurate



Investors are cautioned not to place undue
reliance on forward-looking information. By its nature, forward-looking information involves numerous assumptions, known and unknown
risks and uncertainties, of both a general and specific nature, that could cause actual results to differ materially from those
suggested by the forward-looking information or contribute to the possibility that predictions, forecasts or projections will prove
to be materially inaccurate.



Share Price Volatility



The market price for Common Shares may
be volatile and subject to wide fluctuations in response to numerous factors, many of which are beyond the Corporation's control,
including the following: (i) actual or anticipated fluctuations in the Corporation's quarterly results of operations; (ii) actual
or anticipated changes in oil and natural gas prices; (iii) recommendations by securities research analysts; (iv) changes in the
economic performance or market valuations of other companies that investors deem comparable to the Corporation; (v) addition or
departure of the Corporation's executive officers and other key personnel; (vi) sales or perceived sales of additional Common Shares;
(vii) significant acquisitions or business combinations, strategic partnerships, joint ventures or capital commitments by or involving
the Corporation or its competitors; and (viii) news reports relating to trends, concerns, technological or competitive developments,
regulatory changes and other related issues in the Corporation's industry or target markets.



48







Financial markets have experienced significant
price and volume fluctuations in the last several years that have particularly affected the market prices of equity securities
of companies and that have, in many cases, been unrelated to the operating performance, underlying asset values or prospects of
such companies. Accordingly, the market price of the Common Shares may decline even if the Corporation's operating results, underlying
asset values or prospects have not changed. Additionally, these factors, as well as other related factors, may cause decreases
in asset values that are deemed to be other than temporary, which may result in impairment losses. As well, certain institutional
investors may base their investment decisions on consideration of the Corporation's environmental, governance and social practices
and performance against such institutions' respective investment guidelines and criteria, and failure to meet such criteria may
result in a limited or no investment in the Common Shares by those institutions, which could adversely affect the trading price
of the Common Shares. There can be no assurance that continuing fluctuations in the price and volume of publicly traded equity
securities will not occur. If such increased levels of volatility and market turmoil continue, the Corporation's operations could
be adversely impacted and the trading price of the Common Shares may be adversely affected.



Future Acquisition
Activities May Have Adverse Effects



The acquisition of oil and natural gas
companies and assets is subject to substantial risks, including the failure to identify material problems during due diligence,
the risk of over-paying for assets and the inability to arrange financing for an acquisition as may be required or desired. Further,
the integration and consolidation of acquisitions requires substantial human, financial and other resources and, ultimately, the
Corporation's acquisitions may not be successfully integrated. There can be no assurances that any future acquisitions will perform
as expected or that the returns from such acquisitions will support the indebtedness incurred to acquire them or the capital expenditures
needed to develop them.



Internal Controls



Effective internal controls are necessary
for the Corporation to provide reliable financial reports and to help prevent fraud. Although the Corporation undertakes a number
of procedures in order to help ensure the reliability of its financial reports, including those imposed on it under Canadian securities
laws, the Corporation cannot be certain that such measures will ensure that the Corporation will maintain adequate control over
financial processes and reporting. Failure to implement required new or improved controls, or difficulties encountered in their
implementation, could harm the Corporation's results of operations or cause it to fail to meet its reporting obligations. If the
Corporation or its independent auditors discover a material weakness, the disclosure of that fact, even if quickly remedied, could
reduce the market's confidence in the Corporation's consolidated financial statements and adversely affect the trading price of
the Common Shares.



Litigation Risks



In the normal course of the Corporation's
operations, it may become involved in, named as a party to, or be the subject of, various legal proceedings, including regulatory
proceedings, tax proceedings and legal actions, relating to personal injuries, property damage, property taxes, 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 the Corporation and as a result, could have a material adverse effect on the Corporation's assets,
liabilities, business, financial condition and results of operations. Even if the Corporation prevails in any such legal proceeding,
the proceedings could be costly and time-consuming and may divert the attention of management and key personnel from the Corporation's
business operations, which could adversely affect its financial condition.



DIVIDENDS



On October 19, 2011 after having reduced
its monthly dividend from $0.03 per Share to $0.015 in May, the Corporation announced that future dividend payments would be suspended
until further notice. Continued payment of a dividend is not sustainable given the continued weakness in natural gas prices, and
will inhibit Perpetual's continuing efforts to implement its strategy of commodity and asset base diversification. The continued
execution of the strategies to diversify commodity mix and create value, capitalizing on Perpetual’s substantial inventory
of economic opportunities, is expected to grow funds flow. Combined with ongoing debt reduction initiatives, including asset sales,
stronger diversified funds flows will strengthen the Corporation’s balance sheet. The suspension of the dividend was necessary
to drive Perpetual’s commitment to maximize Shareholder value. Reinstatement of a dividend in the future will be evaluated
at such time as Perpetual’s balance sheet has regained strength and commodity prices and costs support a sustainable model
where excess free funds flow, over and above capital investments, is once again being generated for distribution to Shareholders.



49







The credit facilities and the terms of
the Notes contain provisions which restrict the ability of the Corporation to pay dividends to Shareholders in the event of the
occurrence of certain events of default, and Section 43 of the ABCA also imposes certain restrictions on the ability of a corporation
to pay dividends.



The historical dividends described below
may not be reflective of future dividends, which will be subject to review by the board of directors of the Corporation taking
into account the prevailing circumstances at the relevant time. See "Risk Factors".



The accompanying table summarizes cash
dividends to shareholders for each of the last three years:



|For the Period Ended |  | Payment Date |                    |  | Dividend per Common Share(1) | 
|-------------------- |  | ------------ | ------------------ |  | ---------------------------- | 
|2009                 |  |              |                    |  |                              | 
|January 31, 2009     |  |              | February 17, 2009  |  |                              | 
|February 28, 2009    |  |              | March 16, 2009     |  |                              | 
|March 31, 2009       |  |              | April 15, 2009     |  |                              | 
|April 30, 2009       |  |              | May 15, 2009       |  |                              | 
|May 31, 2009         |  |              | June 15, 2009      |  |                              | 
|June 30, 2009        |  |              | July 15, 2009      |  |                              | 
|July 31, 2009        |  |              | August 17, 2009    |  |                              | 
|August 31, 2009      |  |              | September 15, 2009 |  |                              | 
|September 30, 2009   |  |              | October 15, 2009   |  |                              | 
|October 31, 2009     |  |              | November 16, 2009  |  |                              | 
|November 30, 2009    |  |              | December 15, 2009  |  |                              | 
|December 31, 2009    |  |              | January 15, 2010   |  |                              | 
|2010                 |  |              |                    |  |                              | 
|January 31, 2010     |  |              | February 16, 2010  |  |                              | 
|February 28, 2010    |  |              | March 15, 2010     |  |                              | 
|March 31, 2010       |  |              | April 15, 2010     |  |                              | 
|April 30, 2010       |  |              | May 17, 2010       |  |                              | 
|May 31, 2010         |  |              | June 15, 2010      |  |                              | 
|June 30, 2010        |  |              | July 15, 2010      |  |                              | 
|July 31, 2010        |  |              | August 16, 2010    |  |                              | 
|August 31, 2010      |  |              | September 15, 2010 |  |                              | 
|September 30, 2010   |  |              | October 15, 2010   |  |                              | 
|October 31, 2010     |  |              | November 15, 2010  |  |                              | 
|November 30, 2010    |  |              | December 15, 2010  |  |                              | 
|December 31, 2010    |  |              | January 17, 2011   |  |                              | 
|2011                 |  |              |                    |  |                              | 
|January 31, 2011     |  |              | February 15, 2011  |  |                              | 
|February 28, 2011    |  |              | March 15, 2011     |  |                              | 
|March 31, 2011       |  |              | April 11, 2011     |  |                              | 
|April 30, 2011       |  |              | May 16, 2011       |  |                              | 
|May 31, 2011         |  |              | June 15, 2011      |  |                              | 
|June 30, 2011        |  |              | July 15, 2011      |  |                              | 
|July 31, 2011        |  |              | August 15, 2011    |  |                              | 
|August 31, 2011      |  |              | September 15, 2011 |  |                              | 
|September 30, 2011   |  |              | October 17, 2011   |  |                              | 



Note:

| | (1) | Prior to the payment made on August 16, 2010, amounts represented distributions on the Trust Units
of Paramount Energy Trust (the Corporation’s predecessor).
| | --- | -------------------------------------------------------------------------------------------------------------------------------------------------------------



50







MARKET
FOR SECURITIES



Trading Price and
Volume



The outstanding Common Shares, 6.50% Convertible
Debentures, 7.00% Convertible Debentures and 7.25% Convertible Debentures are listed and posted for trading on the TSX under the
trading symbols "PMT", "PMT.DB.C", "PMT.DB.E" and "PMT.DB.D", respectively. Prior to July
6, 2010 the Common Shares traded as Trust Units under the symbol "PMT.UN", and the Debentures traded as securities convertible
into Trust Units.



The following tables set forth the closing
price range and trading volume of each of these securities as reported by the TSX for the periods indicated:



Common Shares

|          |  | Price Range |      |  |         | 
|--------- |  | ----------- | ---- |  | ------- | 
|          |  | High ($)    |      |  | Low ($) | 
|2011      |  |             |      |  |         | 
|January   |  |             | 4.12 |  |         | 
|February  |  |             | 4.33 |  |         | 
|March     |  |             | 4.38 |  |         | 
|April     |  |             | 4.19 |  |         | 
|May       |  |             | 4.20 |  |         | 
|June      |  |             | 3.74 |  |         | 
|July      |  |             | 3.38 |  |         | 
|August    |  |             | 3.30 |  |         | 
|September |  |             | 2.77 |  |         | 
|October   |  |             | 2.36 |  |         | 
|November  |  |             | 1.65 |  |         | 
|December  |  |             | 1.35 |  |         | 



6.50% Convertible
Debentures (PMT.DB.C)



|          |  | Price Range |        |  |         | 
|--------- |  | ----------- | ------ |  | ------- | 
|          |  | High ($)    |        |  | Low ($) | 
|2011      |  |             |        |  |         | 
|January   |  |             | 102.49 |  |         | 
|February  |  |             | 103.00 |  |         | 
|March     |  |             | 102.25 |  |         | 
|April     |  |             | 102.25 |  |         | 
|May       |  |             | 101.65 |  |         | 
|June      |  |             | 102.00 |  |         | 
|July      |  |             | 101.00 |  |         | 
|August    |  |             | 100.75 |  |         | 
|September |  |             | 98.99  |  |         | 
|October   |  |             | 96.00  |  |         | 
|November  |  |             | 96.26  |  |         | 
|December  |  |             | 97.50  |  |         | 



51









7.25% Convertible
Debentures (PMT.DB.D)



|          |  | Price Range |        |  |         | 
|--------- |  | ----------- | ------ |  | ------- | 
|          |  | High ($)    |        |  | Low ($) | 
|2011      |  |             |        |  |         | 
|January   |  |             | 104.00 |  |         | 
|February  |  |             | 104.05 |  |         | 
|March     |  |             | 103.00 |  |         | 
|April     |  |             | 103.25 |  |         | 
|May       |  |             | 103.25 |  |         | 
|June      |  |             | 103.50 |  |         | 
|July      |  |             | 98.00  |  |         | 
|August    |  |             | 98.00  |  |         | 
|September |  |             | 92.25  |  |         | 
|October   |  |             | 90.00  |  |         | 
|November  |  |             | 83.50  |  |         | 
|December  |  |             | 80.50  |  |         | 



7.00% Convertible
Debentures (PMT.DB.E)



|          |  | Price Range |        |  |         | 
|--------- |  | ----------- | ------ |  | ------- | 
|          |  | High ($)    |        |  | Low ($) | 
|2011      |  |             |        |  |         | 
|January   |  |             | 103.00 |  |         | 
|February  |  |             | 103.75 |  |         | 
|March     |  |             | 102.25 |  |         | 
|April     |  |             | 102.77 |  |         | 
|May       |  |             | 102.50 |  |         | 
|June      |  |             | 102.97 |  |         | 
|July      |  |             | 97.00  |  |         | 
|August    |  |             | 94.26  |  |         | 
|September |  |             | 88.70  |  |         | 
|October   |  |             | 83.00  |  |         | 
|November  |  |             | 82.00  |  |         | 
|December  |  |             | 79.99  |  |         | 



Prior Sales



Other than Share Options and Restricted
Rights to acquire Common Shares and the Notes, there is no class of securities of Perpetual that is outstanding and not listed
or quoted on a marketplace.



Set forth below are the exercise prices
at which Share Options and Restricted Rights were issued during the most recently completed financial year by Perpetual, the number
of Share Options and Restricted Rights issued at such exercise prices and the date on which the securities were issued.



|Date of Grant     |  | Number of Share Options Granted |           |  | Exercise Price | 
|----------------- |  | ------------------------------- | --------- |  | -------------- | 
|May 27, 2011      |  |                                 | 173,500   |  |                | 
|June 27, 2011     |  |                                 | 352,500   |  |                | 
|July 4, 2011      |  |                                 | 31,000    |  |                | 
|July 6, 2011      |  |                                 | 20,900    |  |                | 
|August 18, 2011   |  |                                 | 798,700   |  |                | 
|December 9, 2011  |  |                                 | 11,500    |  |                | 
|December 15, 2011 |  |                                 | 1,466,000 |  |                | 
|December 22, 2011 |  |                                 | 4,200     |  |                | 



52











|Date of Grant     |  | Number of Restricted Rights Granted |         |  | Exercise Price | 
|----------------- |  | ----------------------------------- | ------- |  | -------------- | 
|May 27, 2011      |  |                                     | 297,848 |  |                | 
|May 31, 2011      |  |                                     | 381,600 |  |                | 
|June 27, 2011     |  |                                     | 3,700   |  |                | 
|July 4, 2011      |  |                                     | 5,000   |  |                | 
|July 6, 2011      |  |                                     | 3,400   |  |                | 
|August 18, 2011   |  |                                     | 9,200   |  |                | 
|December 9, 2011  |  |                                     | 5,800   |  |                | 
|December 15, 2011 |  |                                     | 676,500 |  |                | 
|December 22, 2011 |  |                                     | 6,300   |  |                | 



DESCRIPTION
OF CAPITAL STRUCTURE



The authorized share capital of Perpetual
consists of an unlimited number of Common Shares and an unlimited number of preferred shares. As at the date hereof, there is one
Common Share and no preferred shares issued and outstanding. Each Common Share entitles the holder thereof to receive notice of
and to attend all meetings of shareholders of Perpetual and to one vote per share at such meetings (other than meetings of another
class of shares of Perpetual). The Common Shares entitle the holders thereof to receive dividends as and when declared by the board
of directors of Perpetual on the Common Shares as a class, subject to prior satisfaction of all preferential rights to dividends
attached to all shares of other classes of shares of Perpetual ranking in priority to the Common Shares in respect of dividends.
Holders of Common Shares will be entitled in the event of any liquidation, dissolution or winding-up of Perpetual, whether voluntary
or involuntary, or any other distribution of the assets of Perpetual among its shareholders for the purposes of winding-up its
affairs, and subject to prior satisfaction of all preferential rights to return of capital on dissolution attached to all shares
of other classes of shares of Perpetual 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 shares of Perpetual ranking equally with the Common
Shares in respect of return of capital, in such assets of Perpetual as are available for distribution.



The preferred shares may be issuable in
one or more series, each series to consist of such number of shares as may, before the issuance thereof, be determined by the board
of directors of Perpetual. The board of directors may from time to time fix, before issuance, the designation, rights, privileges,
restrictions and conditions attaching to each series of preferred shares including, without limiting the generality of the foregoing,
the amount, if any, specified as being payable preferentially to such series on a distribution, the extent, if any, of further
participation on a distribution, voting rights, if any, and dividend rights (including whether such dividends be preferential,
or cumulative or non-cumulative), if any.



The holders of each series of preferred
shares are entitled to receive any dividends declared by the board of directors of Perpetual in priority to the Common Shares and
to be paid rateably with holders of each other series of preferred shares, and are entitled to participate in any distribution
of the assets of Perpetual upon the liquidation, dissolution, bankruptcy or winding-up of Perpetual or other distribution of its
assets among its shareholders for the purpose of winding-up its affairs in priority to the holders of the Common Shares and to
share rateably in the distribution with holders of each other series of preferred shares.



Constraints



There are currently no constraints imposed
on the ownership of securities of the Corporation to ensure that Perpetual has a required level of Canadian ownership.



53







Ratings



The following information relating to our
credit ratings is provided as it relates to our financing costs and liquidity. Credit ratings affect our ability to obtain short-term
and long-term financing and the cost of such financing. A negative change in our ratings outlook or any downgrade in our current
credit ratings by our ratings agencies could adversely affect our cost of borrowing and/or access to sources of liquidity and capital.
We believe that our credit ratings will allow us to continue to have access to the capital markets, as and when needed, at a reasonable
cost of funds.



Other than as set forth below, Perpetual
has not asked for and received a stability rating, or to the knowledge of Perpetual, has received any other kind of rating, including,
a provisional rating, from one or more approved rating organizations for securities of Perpetual that are outstanding and which
continue in effect.



The Notes have been assigned ratings of
B- by Standard and Poor's Rating Services, a division of McGraw-Hill Companies (Canada) Corporation ("S&P")
and Caa1/LGD 4-52%% by Moody's Investors Service, Inc. ("Moody's").



S&P and Moody's provide credit ratings
of debt securities for commercial entities. A credit rating generally provides an indication of the risk that the borrower will
not fulfill its full obligations in a timely manner with respect to both interest and principal commitments.



S&P's credit ratings are on a long-term
debt rating scale that ranges from AAA to D, which represents the range from highest to lowest quality of such securities rated.
S&P has assigned Perpetual a corporate credit rating of B, stable outlook, and a credit rating of B- on the Notes. An obligation
rated "B" is more vulnerable to non-payment than those rated BB, but the obligor currently has the capacity to meet its
financial commitments on the obligation. Adverse business, financial, or economic conditions will likely impair the obligor's capacity
or willingness to meet its financial commitment on the obligation. The ratings from AA to CCC may be modified by the addition of
a plus (+) or a minus (-) sign to show relative standing within the major rating categories. In addition, S&P may add a rating
outlook of "positive", "negative" or "stable" which assesses the potential direction of a long-term
credit rating over the intermediate term (typically six months to two years).



Moody's credit ratings are on a long-term
debt rating scale that ranges from AAA to C, which represents the range from highest to lowest quality of such securities rated.
Moody's has assigned Perpetual a corporate family credit rating of Caa1, negative outlook, and a credit rating of Caa1/LGD 4-52%,
negative outlook on the Notes. According to the Moody's rating system, securities rated ''B'' are considered speculative and are
subject to high credit risk. Moody's appends numerical modifiers 1, 2 and 3 to each generic rating classification from AA through
C. The modifier 1 indicates that the security ranks in the higher end of its generic rating category, the modifier 2 indicates
a mid-range ranking and the modifier 3 indicates a ranking in the lower end of its generic rating category. In addition, Moody's
may add a rating outlook of ''positive'', ''negative'' or ''stable'', which assess the likely direction of an issuer's rating over
the medium term.



Credit ratings are intended to provide
investors with an independent measure of credit quality of an issue of securities. Credit ratings are not recommendations to purchase,
hold or sell securities and do not address the market price or suitability of a specific security for a particular investor. There
is no assurance that any rating will remain in effect for any given period of time or that any rating will not be revised or withdrawn
entirely by a rating agency in the future if, in its judgment, circumstances so warrant. A rating can be revised, suspended or
withdrawn at any time by the rating agency. Potential investors should consult the rating agency should they require more information
with respect to the interpretation and implications of the foregoing ratings. A revision or withdrawal of a credit rating could
have a material adverse effect on the pricing and liquidity of the Notes in the secondary market.



54







ESCROWED
SECURITIES AND SECURITIES SUBJECT TO CONTRACTUAL RESTRICTION ON TRANSFER



To the knowledge of the Corporation, none
of Perpetual's securities are held in escrow or subject to a contractual restriction on transfer.



DIRECTORS
AND OFFICERS



Name, Occupation
and Security Holding



The names, province or state, and country
of residence, positions and offices held with the Corporation, and principal occupation of the directors and executive officers
of the Corporation are set out below and, in the case of directors, the period each has served as a director of the Corporation.





|Name and Province and Country of Residence       |  | Position held with the Corporation and Period
    Served as a Director |  | Principal Occupations
    During the Past Five Years                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    
|------------------------------------------------ |  | ---------------------------------------------------------------------- |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|Clayton H. Riddell
        Alberta, Canada       |  | Chairman of the Board and Director since June 28, 2002                 |  | Mr. Riddell has been the Chairman of the Board and Chief Executive Officer of Paramount since 1978. Until June 2002 he was also the President. He is currently Chairman of the Board of the Company and prior thereto was the Chairman and Chief Executive Officer of the Company (and formerly Paramount Energy Operating Corp. ("PEOC")). He graduated from the University of Manitoba with a Bachelor of Science (Honours) Degree in Geology and is currently a member of the Association of Professional Engineers, Geologists and Geophysicists of Alberta, the Canadian Association of Petroleum Producers, the Canadian Society of Petroleum Geologists, and the American Association of Petroleum Geologists.                                                                                                                                                                                                                                                                   
|                                                 |  |                                                                        |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                         
|Susan L. Riddell Rose(4)
        Alberta, Canada |  | President, Chief Executive Officer and Director since June 28, 2002    |  | Ms. Riddell Rose is President and Chief Executive Officer of Perpetual Energy Inc through the corporate conversion of Paramount Energy Trust. Ms. Riddell Rose graduated from Queen's University, Kingston, Ontario with a Bachelor of Science in Geological Engineering (1986) and has over 25 years of experience in the Canadian oil and natural gas industry. She began her career as a geological engineer with Shell Canada. From 1990 until 2002 Sue was employed by Paramount Resources Ltd. in various capacities culminating in the position of Corporate Operating Officer. She has been a director of Paramount Resources Ltd. since 2000. Sue is also on the board of directors of Newalta Inc. She is a member of the Association of Professional Engineers, Geologists and Geophysicists of Alberta, the Canadian Society of Petroleum Geologists, the American Association of Petroleum Geologists and is a Governor of the Canadian Association of Petroleum Producers.







55









|Name and Province and Country of Residence             |  | Position
    held with the Corporation and Period Served as a Director |  | Principal
    Occupations During the Past Five Years                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                            
|------------------------------------------------------ |  | ---------------------------------------------------------------------- |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|                                                       |  |                                                                        |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 
|Karen A. Genoway(2)(3)(5)(7)Alberta, Canada            |  | Director since June 28, 2002                                           |  | Ms. Genoway is a professional landman with over 28 years experience in the oil and natural gas industry. Currently, she is the Vice President, Land with Rimfire Energy Inc., a private company. From February 2001 she was Vice President of Request Management Inc., manager of Request Income Trust until its acquisition by Pulse Data Inc. in January 2002. Ms. Genoway was with Enerplus Resources Fund where she held the positions of Senior Vice President (1997 to 2000), Vice President Land (1989 to 1997) and Land Manager (1987 to 1989). Ms. Genoway is a graduate of the ICD Corporate Governance College, Directors Education Program, February 2006 and received her accreditation from the Institute of Corporate Directors, Institute-Certified Director, ICD.D, April 2006.
|                                                       |  |                                                                        |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 
|Randall E. Johnson(1)(3)(5)(7)
        Alberta, Canada |  | Director since June 20, 2006                                           |  | Mr. Johnson has been an independent businessman since 2005. Prior to that he was Managing Director of the Bank of Montreal’s Corporate Banking group from 1996 to 2005, having been with the Bank of Montreal since 1984. Mr. Johnson has served on the Board of Directors of Atlas Energy Ltd. (May 2005 to December 2006) and Dual Exploration Inc. (June 2005 to November 2006). Since January 2007 Mr. Johnson has also been a director of Magellan Resources Ltd., a privately held oil and gas company.                                                                                                                                                                                                                                                                                   
|                                                       |  |                                                                        |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 
|Robert A. Maitland(1)(3)(5)(7)
        Alberta, Canada |  | Director since February 7, 2008                                        |  | Mr. Maitland is a Chartered Accountant with over 30 years of senior business experience, primarily in the oil and gas industry. Mr. Maitland was most recently the Vice President Finance and Chief Financial Officer of Fairquest Energy Ltd. (June 2005 to June 2007) and Fairborne Energy Ltd. (May 2002 to May 2005). He has also been the Vice President and Chief Financial Officer for Canadian Midstream Services Ltd. (April 1999 to May 2001), Summit Resources Ltd., Omega Hydrocarbons Ltd., Shiningbank Energy Income Fund, Post Energy Ltd. and Pan East Petroleum Corp. He presently serves on the board of directors of Gasfrac Energy Services Inc. And the Developmental Disabilities Resources Centre and several other private companies.                                   





56









|Name and Province and Country of Residence              |  | Position
    held with the Corporation and Period Served as a Director |  | Principal
    Occupations During the Past Five Years                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    
|------------------------------------------------------- |  | ---------------------------------------------------------------------- |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|Geoffrey C. Merritt(1)(2)(4)(7)
        Alberta, Canada |  | Director since June 17, 2010                                           |  | Geoff Merritt has over 30 years of experience in the upstream oil and gas sector. He was the founder and Chief Executive Officer of Masters Energy Inc., a public exploration and production company, incorporated in 2003 and acquired by Zargon Oil & Gas Ltd. in April 2009.  From 1998 to 2003, Mr. Merritt was the President and CEO of Sunfire Energy, a public exploration and production company.  Prior to 1998, Geoff was the Vice President and General Manager of the oil and gas division of Pembina Corporation.  Mr. Merritt is on the board of Zargon Oil and Gas Ltd.  Mr. Merritt received a B.Sc. in Chemical Engineering from the University of Alberta in 1978 and is a graduate of the Harvard Business School.                   
|                                                        |  |                                                                        |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                         
|Donald J. Nelson(2)(4)(7)
        Alberta, Canada       |  | Director since June 28, 2002                                           |  | Mr. Nelson is President of Fairway Resources Inc., an oil and gas consulting firm. Prior to his current occupation, Mr. Nelson held the consecutive positions of Vice President, Operations and President and Director with Summit Resources Limited from July 1996 to June 2002. Mr. Nelson is a director of Keyera Corp., a publicly traded issuer and also sits on the boards of a number of private oil and gas companies. He is a professional engineer and is an active member of the Association of Professional Engineers, Geologists and Geophysicists of Alberta and of the Society of Petroleum Engineers.                                                                                                                                   
|                                                        |  |                                                                        |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                         
|Howard R. Ward(3)(4)(5)(7)
        Alberta, Canada      |  | Director since June 28, 2002                                           |  | Mr. Ward has been a partner with International Energy Counsel LLP, a law firm, since December 2002. Prior thereto, Mr. Ward was counsel with the law firm McCarthy Tétrault LLP from June 2002 to December 2002. Prior to that, he was counsel with Donahue and Partners LLP and, for more than 22 years, partner with Burstall Ward (now Burstall Winger LLP), Barristers and Solicitors. He has been a member of the Law Society of Alberta since 1975. He also has served as a director of the following publicly traded entities: Blue Sky Resources Ltd. (July 1999 to July 2000); Cabre Exploration Ltd. (June 1981 to December 2000); Jet Energy Corp. (August 1995 to November 1999); and Tuscany Resources Ltd. (October 1997 to October 2001).





57









|Name and Province and Country of Residence   |  | Position
    held with the Corporation and Period Served as a Director |  | Principal
    Occupations During the Past Five Years                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 
|-------------------------------------------- |  | ---------------------------------------------------------------------- |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|Jeffrey R. Green
        Alberta, Canada     |  | Vice President, Corporate and Engineering
        Services             |  | Mr. Green has over 25 years of experience in the Canadian oil and natural gas industry. His previous industry experience includes Vice President of Production Operations & Administration, Manager, Acquisitions and Divestitures with Paramount Energy Trust and Exploitation Manager and Production Manager at Anadarko Canada Corp. Mr. Green has held additional technical and supervisory positions in other organizations including Norcen and Union Pacific Resources.                                                                                                                                                                                                                                                                                                                                                       
|                                             |  |                                                                        |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      
|Gary C. Jackson
        Alberta, Canada      |  | Vice President, Land and Acquisitions                                  |  | Mr. Jackson has over 30 years of experience in the Canadian oil and natural gas industry. He was Vice President, Land of Summit Resources Limited from 2000 to 2002. His career has included the position of Manager of Acquisitions and Divestitures, Joint Venture Midstream and Land Services at Petro-Canada Oil and Gas as well as various positions related to land and contracts with Amerada Hess Canada and Placer Cego Petroleum.                                                                                                                                                                                                                                                                                                                                                                                          
|                                             |  |                                                                        |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      
|Marcello M. Rapini
        Alberta, Canada   |  | Vice President, Marketing                                              |  | Mr. Rapini joined Perpetual Energy Inc. in December 2005 and has over 20 years of gas marketing and trading experience in the natural gas industry. His previous positions include Vice President of Trade at Sempra Energy Trading, Senior Trader at Mirant Energy Marketing Ltd. and Senior Trader at Duke Energy Marketing.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                       
|                                             |  |                                                                        |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      
|Cameron R. Sebastian
        Alberta, Canada |  | Vice President, Finance and Chief Financial Officer                    |  | Mr. Sebastian has over 22 years of experience in the North American energy industry. He was Vice President, Finance of Summit Resources Ltd. from 2000 to 2002 and the company's controller from 1994 to 1997. Prior thereto he was Vice President, Finance of Pursuit Resources Corp. and controller of Coho Energy Inc. in Dallas, Texas.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          
|                                             |  |                                                                        |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      
|William R. ThorntonAlberta, Canada           |  | Vice President, Enhanced Recovery and North Business Unit              |  | Mr. Thornton has over 30 years of extensive experience in all aspects of oil and gas development and in particular the enhanced recovery of heavy oil. Mr. Thornton has held positions that include President and Chief Executive Officer of MegaWest Energy Corp., General Manager, Petroleum Engineering with Western Oil Sands, Vice-President, Engineering with Petrovera Resources and Director of Primary Heavy Oil with Gulf Canada. Prior to these positions, he was with Murphy Oil for 17 years on their various enhanced oil recovery projects and technology developments throughout Western Canada andthe United States. Mr. Thornton also has international experience, having worked in drilling operations in the interior of Peru and as part of a team negotiating a production sharing agreement in northern Iraq.





58









|Name and Province and Country of Residence |  | Position
    held with the Corporation and Period Served as a Director |  | Principal
    Occupations During the Past Five Years                                                                                                                                                                                                                                                                                                                                                                                                                                
|------------------------------------------ |  | ---------------------------------------------------------------------- |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|Vicki L. Benoit
        Alberta, Canada    |  | Vice President, Production Operations                                  |  | Ms Benoit has over 25 years of oil and gas experience leading operations, production and asset teams for Devon Energy Corp., Southward Energy Corp., Staboard Energy Ltd. And consulting in an engineering capacity for various energy companies including Resolute Energy Corp., Omers Energy and Viking Energy Corp.                                                                                                                                                              
|                                           |  |                                                                        |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                     
|Linda L. McKean
        Alberta, Canada    |  | Vice President, South/West Business Unit                               |  | Ms. McKean has 23 years of experience in the Canadian oil and natural gas industry. Ms. McKean has been with Perpetual and the predecessor Paramount Energy Trust since 2004 in the positions of Eastern District Manager and consulting engineer.  Her previous industry technical experience includes reservoir engineering positions at Berkeley Petroleum and Anadarko Canada Corp, and 10 years at Shell Canada working as a development geologist and as a reservoir engineer.





Notes:



| | (1) | Member of the Audit Committee.
| | --- | ------------------------------

| | (2) | Member of the Reserves Committee.
| | --- | ---------------------------------

| | (3) | Member of the Corporate Governance Committee.
| | --- | ---------------------------------------------

| | (4) | Member of the Environmental, Health and Safety Committee.
| | --- | ---------------------------------------------------------

| | (5) | Member of the Compensation Committee.
| | --- | -------------------------------------

| | (6) | The terms of office of all directors of the Company will expire on the date of the next annual
shareholders' meeting.
| | --- | ---------------------------------------------------------------------------------------------------------------------

| | (7) | Ms. Genoway, Mr. Johnson, Mr. Maitland, Mr. Nelson, Mr. Merritt and Mr. Ward are independent, non-employee
directors.
| | --- | ---------------------------------------------------------------------------------------------------------------------



The directors and officers of Perpetual,
as a group, beneficially own or control or direct, directly or indirectly an aggregate of 36,977,376 voting securities as of March
1, 2012 representing approximately 25.16% of the outstanding Common Shares.



Cease Trade Orders,
Bankruptcies, Penalties or Sanctions



Cease Trade
Orders



To the knowledge of the Corporation, except
as described below, no director or executive officer of the Corporation (nor any personal holding company of any of such persons)
is, as of the date of this Annual Information Form, or was within 10 years before the date of this Annual Information Form, a director,
chief executive officer or chief financial officer of any company (including the Corporation), that: (a) was subject to a cease
trade order (including a management cease trade order), an order similar to a cease trade order or an order that denied the relevant
company access to any exemption under securities legislation, in each case that was in effect for a period of more than 30 consecutive
days (collectively, an "Order"), that was issued while the director or executive officer was acting in the capacity
as director, chief executive officer or chief financial officer; or (b) was subject to an Order that was issued 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.



59







Mr. Clayton Riddell is a director and executive
officer of Paramount Resources Ltd. ("Paramount"). From 1992 to 2008, Paramount was the general partner of T.T.Y.
Paramount Partnership No. 5 ("TTY"), a limited partnership, which was an unlisted reporting issuer in certain
provinces of Canada. TTY was established in 1980 to conduct oil and gas exploration and development but had not carried on active
operations since 1984 and had only nominal assets. A cease trade order against TTY was issued by the Autorité des marches
financiers in 1999 for failing to file the June 30, 1998 interim financial statements in Québec. The cease trade order was
revoked on April 9, 2008. TTY was dissolved on July 21, 2008.



From 1997 to 2003, Mr. Maitland was a director
of Military International Ltd. which was cease traded for failure to file financial statements, which cease trade order is still
in effect.



Bankruptcies



To the knowledge of the Corporation, no
director or executive officer of the Corporation (nor any personal holding company of any of such persons), or shareholder holding
a sufficient number of securities of the Corporation to affect materially the control of the Corporation: (a) is, as of the date
of this Annual Information Form, or has been within the 10 years before the date of this Annual Information Form, a director or
executive officer of any company (including the Corporation) that, while that 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; or (b) has, within the 10 years before the date of this Annual Information Form,
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, executive officer or shareholder.



Penalties
or Sanctions



To the knowledge of the Corporation, no
director or executive officer of the Corporation (nor any personal holding company of any of such persons), or shareholder holding
a sufficient number of securities of the Corporation to affect materially the control of the Corporation, has been subject to:
(a) 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 (b) 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.



Conflicts
of Interest



Certain officers and directors of the Corporation
are also officers and/or directors of other entities engaged in the oil and gas business generally. As a result, situations may
arise where the interest of such directors and officers conflict with their interests as directors and officers of other companies.
The resolution of such conflicts is governed by applicable corporate laws, which require that directors act honestly, in good faith
and with a view to the best interests of the Corporation. Conflicts, if any, will be handled in a manner consistent with the procedures
and remedies set forth in the ABCA. The ABCA provides that in the event that a director has an interest in a contract or proposed
contract or agreement, the director shall disclose his interest in such contract or agreement and shall refrain from voting on
any matter in respect of such contract or agreement unless otherwise provided by the ABCA.



AUDIT
COMMITTEE INFORMATION



Audit Committee
Charter



The mandate and responsibilities of Perpetual's
audit committee (the "Audit Committee") are set out in the Audit Committee Charter which is part of the
Corporation's Corporate Governance Directors' Manual. The Audit Committee Charter is set out in Appendix "C" to this
Annual Information Form.



60







Audit Committee



The Audit Committee reviews and recommends
to the Board the approval of the annual and interim financial statements, the associated management's discussion and analysis and
related financial disclosure to the public and regulatory authorities. It is responsible for the engagement of Perpetual's external
auditors, upon approval by Shareholders, including fees paid for the annual audit and interim financial reviews, and pre-approves
non-audit services. The Audit Committee communicates directly with the auditors and reviews programs and policies regarding the
effectiveness of internal controls over the Corporation's accounting and financial reporting systems. It also reviews insurance
coverage and directors' and officers' liability insurance. The Audit Committee must liaise with the Reserves Committee on matters
relating to reserves valuations which impact Perpetual's financial statements.



Composition of the
Audit Committee



The Audit Committee consists of three members:
Robert A. Maitland, Geoffrey C. Merritt and Randall E. Johnson. Mr. Maitland is Chair of the Audit Committee. Each of the members
of the Audit Committee is independent and financially literate in accordance with the meanings set out in National Instrument 52
110 Audit Committees.



Relevant Education
and Experience



Robert A. Maitland



Mr. Maitland is a Chartered Accountant.
He has completed the Institute of Corporate Directors - Director Education Program and has received his accreditation as Institute-Certified
Director, ICD.D. He has over 30 years of senior business experience, primarily in the oil and gas industry and has been the Vice
President and Chief Financial Officer of Summit Resources Ltd., Omega Hydrocarbons Ltd., Shiningbank Energy Income Fund, Post Energy
Ltd., Pan East Petroleum Corp., Fairborne Energy Ltd. and Fairquest Energy Ltd. He presently serves on the board of directors of
GASFRAC Energy Services Inc. (a publicly traded oil and gas service company) and the Developmental Disabilities Resources Centre
and several other private companies.



Randall E. Johnson



Mr. Johnson graduated with a Bachelor of
Science degree in Mathematics (1980) and a Masters of Business Administration degree (1982) from Brigham Young University in Provo,
Utah. His 22 year career in Corporate Banking commenced with CIBC in 1982 in Calgary. In 1984, he moved to Bank of Montreal's Corporate
Banking group where he worked as an Associate from 1984 to 1987, Account Manager from 1987 to 1990, Director from 1990 to 1996,
and then as Managing Director from 1996 to 2005. After retiring from Bank of Montreal in January 2005, Mr. Johnson joined the Board
of Directors of three publicly traded oil and gas companies: Atlas Energy Ltd. (May 2005 to December 2006), Dual Exploration Inc.
(June 2005 to November 2006), and Perpetual (June 2006 to present). During 2005 and 2006, Mr. Johnson was a part-time faculty member
of the Bissett School of Business at Mount Royal University.



Geoffrey C. Merritt



Geoff Merritt has over 30 years of experience
in the upstream oil and gas sector. He was the founder and Chief Executive Officer of Masters Energy Inc., a public exploration
and production company, incorporated in 2003 and acquired by Zargon Oil & Gas Ltd. in April 2009. From 1998 to 2003, Mr. Merritt
was the President and CEO of Sunfire Energy, a public exploration and production company. Prior to 1998, Geoff was the Vice President
and General Manager of the oil and gas division of Pembina Corporation. Mr. Merritt is on the board of Zargon Oil and Gas Ltd.
Mr. Merritt received a B.Sc. in Chemical Engineering from the University of Alberta in 1978 and is a graduate of the Harvard Business
School.



Pre-Approval of
Policies and Procedures



Perpetual has adopted policies and procedures
with respect to the pre-approval of audit and permitted non-audit services to be provided by KPMG LLP. The Audit Committee establishes
a budget for the provision of a specified list of audit and permitted non-audit services that the audit committee believes to be
typical, recurring or otherwise likely to be provided by KPMG LLP. The budget generally covers the period between the adoption
of the budget and the next meeting of the Audit Committee, but at the option of the Audit Committee it may cover a longer or shorter
period. The list of services is sufficiently detailed as to the particular services to be provided to ensure that (i) the Audit
Committee knows precisely what services it is being asked to pre-approve and (ii) it is not necessary for any member of management
to make a judgment as to whether a proposed service fits within the pre-approved services.



61







The Audit Committee must pre-approve the
provision of permitted services by KPMG LLP which are not otherwise pre-approved by the Audit Committee, including the fees and
terms of the proposed services. Prohibited services may not be pre-approved by the Audit Committee.



External Auditor
Service Fees



Audit Fees



The aggregate fees billed by Perpetual's
external auditor in each of the last two fiscal years for audit services were $930,000 in 2011 and $965,500 in 2010, which includes
fees related to offering documents, IFRS conversion work (in 2010) and the Corporation's year-end audit and quarterly reviews.



Audit-Related
Fees



The aggregate fees billed in each of the
last two fiscal years for assurance related services by Perpetual's external auditor that are reasonably related to the performance
of the audit or review of the financial statements that are not reported under Audit Fees above were $0 in 2011 and $0 in 2010.



Tax Fees



The aggregate fees billed in each of the
last two fiscal years for professional services rendered by Perpetual's external auditor for tax compliance, tax advice and tax
planning were $0 in 2011 and $9,705 in 2010.



These services relate to the determination
and reporting of taxability of security dividends for each of Canada and the United States, the preparation and filing of Canadian
trust and corporate income tax returns, and services with respect to discussions on tax compliance in various foreign jurisdictions.



All Other
Fees



The aggregate fees billed in the 2011 fiscal
year by Perpetual’s external auditor for services other than those services reported above were $0. For the 2010 fiscal year
those fees totalled $126,000 and were related to valuation services and French translation.



LEGAL
PROCEEDINGS AND REGULATORY ACTIONS



Legal Proceedings



There are no legal proceedings Perpetual
is or was a party to, or that any of its property is or was the subject of, during Perpetual's financial year, nor are any such
legal proceedings known to Perpetual to be contemplated, that involves a claim for damages, exclusive of interest and costs, exceeding
10% of the current assets of Perpetual.



Regulatory Actions



There are no:



| | (a) | penalties or sanctions imposed against Perpetual by a court relating to securities legislation
or by a securities regulatory authority during Perpetual's financial year;
| | --- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | (b) | other penalties or sanctions imposed by a court or regulatory body against Perpetual that would
likely be considered important to a reasonable investor in making an investment decision; and
| | --- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | (c) | settlement agreements Perpetual entered into before a court relating to securities legislation
or with a securities regulatory authority during Perpetual's financial year.
| | --- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------



62









INTEREST
OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS



There is no material interest, direct or
indirect, of any: (a) director or executive officer of Perpetual; (b) person or company that beneficially owns, or controls or
directs, directly or indirectly, more than 10% of any class or series of Perpetual's voting securities; and (c) associate or affiliate
of any of the persons or companies referred to in (a) or (b) above 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
Perpetual.



TRANSFER
AGENT AND REGISTRAR



Computershare Trust Company of Canada at
its offices in Calgary, Alberta and Toronto, Ontario acts as the transfer agent and registrar for the Common Shares and the Convertible
Debentures.



MATERIAL
CONTRACTS



Except for contracts entered into in the
ordinary course of business, the Corporation has not entered into any material contracts within the most recently completed financial
year, or before the most recently completed financial year which are still in effect.



INTEREST
OF EXPERTS



Names of Experts



The
only persons or companies who are named as having prepared or certified a report, valuation, statement or opinion described or
included in a filing, or referred to in a filing, made under National Instrument 51-102 by the Corporation during, or relating
to, the Corporation's most recently completed financial year, and whose profession or business gives authority to the report, valuation,
statement or opinion made by the person or company, are KPMG LLP, the Corporation's independent auditors, and McDaniel the Corporation's
independent reserve evaluators. Interests of Experts



To the Corporation's knowledge, no registered
or beneficial interests, direct or indirect, in any securities or other property of the Corporation or of one of the Corporation's
associates or affiliates (i) were held by the McDaniel or by the "designated professionals" (as defined in Form 51-102F2)
of McDaniel, when McDaniel prepared its reports, valuations, statements or opinions referred to herein as having been prepared
by McDaniel, (ii) were received by McDaniel or the designated professionals of McDaniel after McDaniel prepared the reports, valuations,
statements or opinions in question, or (iii) is to be received by McDaniel or the designated professionals of McDaniel.



Neither McDaniel nor any director, officer
or employee of McDaniel is or is expected to be elected, appointed or employed as a director, officer or employee of the Corporation
or of any associate or affiliate of the Corporation.



KPMG LLP are the auditors of the Company
and have confirmed that they are independent with respect to the Company within the meaning of the Rules of Professional Conduct
of Institute of Chartered Accountants of Alberta and within the meaning of the U.S. Securities Act of 1933 and the applicable rules
and regulations thereunder adopted by the Securities and Exchange Commission and the Public Company Accounting Oversight Board
(United States).



ADDITIONAL
INFORMATION



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



Additional information, including directors'
and officers' remuneration and indebtedness, principal holders of the Corporation's securities and securities authorized for issuance
under equity compensation plans is contained in the Corporation's information circular for the Corporation's most recent annual
meeting of securityholders that involved the election of directors.



Additional financial information is contained
in the Corporation's financial statements and the related management's discussion and analysis for the Corporation's most recently
completed financial year.



63







APPENDIX A



report of
management and directors on oil and gas disclosure
in accordance with form 51-101F3



Management of Perpetual Energy Inc. (the
"Corporation") is 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, 2011, estimated using forecast
prices and costs.



McDaniel & Associates Consultants Ltd.,
an independent qualified reserves evaluator, has evaluated the Corporation's reserves data. The report of the independent qualified
reserves evaluator is presented below.



The Reserves 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 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
Committee, approved



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



| | (e) | the filing of Form 51-102F2 which is the report of the independent qualified reserves evaluator
on the reserves data; and
| | --- | -------------------------------------------------------------------------------------------------------------------------



| | (f) | 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.



DATED as of this 12th day of
March, 2012.



|"Susan L. Riddell Rose"               |  | "Cameron R. Sebastian"                             
|------------------------------------- |  | ---------------------------------------------------
|Susan L. Riddell Rose                 |  | Cameron R. Sebastian                               
|President and Chief Executive Officer |  | Vice President, Finance and Chief Financial Officer
|                                      |  |                                                    
|"Robert A. Maitland"                  |  | "Donald J. Nelson"                                 
|Robert A. Maitland                    |  | Donald J. Nelson                                   
|Director                              |  | Director, Chairman of the Reserves Committee       











APPENDIX B



REPORT ON
RESERVES DATA BY MCDANIEL & ASSOCIATES CONSULTANTS LTD.
IN ACCORDANCE WITH FORM 51-101F2



MCDANIEL & ASSOCIATES Consultants Ltd.

To the Board of Directors of Perpetual
Energy Inc. (the “Company”):



| | 1. | We have evaluated the Company’s reserves data as at December 31, 2011. The reserves data
are estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2011 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, 2011, and identifies
the respective portions thereof that we have evaluated and reported on to the Company’s management:
| | -- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|                    |  |                      |        |  | Net Present Value of Future
    Net Revenue $M (before income taxes, 10% discount rate) | 
|------------------- |  | -------------------- | ------ |  | --------------------------------------------------------------------------------------- | 
|Preparation Date of |  |                      |        |  |                                                                                         | 
|Evaluation Report   |  | Location of Reserves |        |  | Audited                                                                                 | 
|                    |  |                      |        |  |                                                                                         | 
|February 6, 2012    |  |                      | Canada |  |                                                                                         | 



| | 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 report referred to in paragraph 4 for events and circumstances
occurring after the preparation date.
| | -- | --------------------------------------------------------------------------------------------------------------------------------------------



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



D-2







Executed as to our report referred to above:



MCDANIEL & ASSOCIATES CONSULTANTS
LTD.



|“signed by B. J. Wurster” | 
|------------------------- | 
|                          | 
|B. J. Wurster, P. Eng.    | 
|Vice President            | 
|                          | 
|Calgary, Alberta          | 
|February 6, 2012          | 



D-3







APPENDIX C



AUDIT COMMITTEE
CHARTER

The Audit Committee:



| | § | must review and, if appropriate, recommend to the Board the approval of the financial statements,
MD&A and annual and interim earnings press releases prior to this information being publicly disclosed;
| | - | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | § | must annually review this written charter (setting out the Audit Committee’s mandate and
responsibilities) and recommend any changes to the Corporate Governance Committee;
| | - | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | § | supply for the purposes of this Manual, in consultation with Corporate Counsel, a list of the laws,
rules and regulations that pertain to the operation of the Audit Committee;
| | - | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | § | must recommend to the Board the nomination, appointment, retention and compensation of external
auditors (“Auditors”);
| | - | ----------------------------------------------------------------------------------------------------------------------



| | § | must oversee the work of Auditors, which oversight may include approval of the Auditor’s
integrated audit plan, planning report, annual engagement letter, or services related thereto, subject to ratification by the Board
| | - | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | § | must review and approve all non-audit services provided by the Auditors prior to the performance
of those services;
| | - | -------------------------------------------------------------------------------------------------------------------



| | § | communicates directly with the Auditors who must report directly to the Audit Committee;
| | - | ----------------------------------------------------------------------------------------



| | § | must be satisfied that adequate procedures are in place for the review of Perpetual’s public
disclosure of financial information extracted or derived from the financial statements, and must periodically assess the adequacies
of those procedures;
| | - | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | § | must establish procedures for the receipt, retention and treatment of complaints regarding accounting,
internal accounting controls, or auditing matters, and for the confidential, anonymous submission by employees of concerns regarding
questionable accounting or auditing matters;
| | - | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | § | must review and approve Perpetual’s hiring policies regarding former and existing partners
and employees of past or present Auditors;
| | - | -------------------------------------------------------------------------------------------------------------------------------------



| | § | reviews programs and policies regarding the maintenance and effectiveness of disclosure controls
and internal controls over the Corporation’s accounting and financial reporting systems;
| | - | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | § | reviews insurance coverage and Directors’ and Officers’ liability insurance; and,
| | - | ---------------------------------------------------------------------------------



| | § | liaises with the reserves committee (“Reserves Committee”) on matters relating to reserves
valuations which impact the financial statements of the Corporation.
| | - | ---------------------------------------------------------------------------------------------------------------------------------------------------------------



Purpose



The Audit Committee’s purpose is
to provide assistance to the Board in fulfilling its legal, regulatory and fiduciary obligations with respect to financial accounting,
internal control processes, continuous public disclosure, the independent audit function, non-audit services provided by Auditors
and such other related matters as may be delegated by the Board of Directors.



D-4







Composition, Procedures and Organization



| | 1. | The Audit Committee will be comprised of three or more Directors as determined from time to time
by resolution of the Board.
| | -- | ----------------------------------------------------------------------------------------------------------------------------



| | 2. | Each member of the Audit Committee must be independent as defined in NI 52-110 and as such must
be free from any material relationship that may interfere with the exercise of his or her independent judgment as a member of the
Audit Committee.
| | -- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | 3. | Consistent with the appointment of other Board committees, the members of the Audit Committee will
be appointed by the Board at the first meeting of the Board following each AGM or at such other time as may be determined by the
Board.
| | -- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | 4. | The Committee will designate the Chairman of the Audit Committee by majority vote. The presence
in person or by telephone of a majority of the Audit Committee’s members constitutes a quorum for any meeting.
| | -- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | 5. | All actions of the Audit Committee will require a vote of the majority of its members present at
a meeting of such committee at which a quorum is present.
| | -- | ----------------------------------------------------------------------------------------------------------------------------------------------------------



| | 6. | All members of the Audit Committee must be financially literate at the time of their appointment
or have become financially literate within a reasonable period of time after such appointment. NI 52-110 sets out that 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 Perpetual's financial statements.
| | -- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | 7. | The Board shall designate at least one Audit Committee member as the financial expert, and the
member so designated must have accounting or related financial management expertise, as such qualification may be determined in
the business judgment of the Board in accordance with the requirements of applicable regulatory bodies.
| | -- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



Accountability and Reporting



The Audit Committee is accountable to the
Board. The Audit Committee must provide the Board with a summary of all meetings and its recommendations together with a copy of
the minutes of each such meeting. If applicable, the Chairman will provide oral reports as requested.



All information reviewed and discussed
by the Audit Committee at any meeting must be retained and made available for examination by the Board. The Audit Committee will
review its mandate annually, and will forward to the Corporate Governance Committee any recommended alterations to that mandate.



Meetings



The Committee will meet with such frequency
and at such intervals as it determines is necessary to carry out its duties and responsibilities.



D-5







The Audit Committee will meet to review
the interim and year-end financial statements and MD&A; related financial public disclosure and regulatory filings including
the Annual Information Form, Management Information Circular; other continuous disclosure documentation (“Continuous Disclosure
Documents”) as described in NI 52-101 (which is incorporated herein by reference); the Auditor’s Report with respect
to annual attestation of Internal Controls over Financial Reporting (“ICOFR”), and to report to the Board on
same. In conjunction with the review of the year-end financial statements and MD&A, the Audit Committee will consider the annual
independent evaluation of the oil and gas reserves of the Corporation. In addition to these scheduled quarterly meetings as contained
in “Planning Documents For Board and Committees” (Section 4 of the Manual), the Audit Committee may meet on other occasions
with the Auditors in order to be advised of current practices in the industry and to discuss and review other matters including
the annual work plans, processes and procedures. The Audit Committee must meet at least quarterly with the Auditors in the absence
of Perpetual’s Officers and employees to discuss any matters that the Committee or a committee member believes should be
discussed privately.



The Chairman of the Audit Committee will
appoint a Director, Officer or employee of Perpetual to act as secretary for the purposes of recording the minutes of each meeting.



Responsibilities



The Audit Committee must:



| | · | review and approve the Audit Committee Mandate annually;
| | - | --------------------------------------------------------



| | · | review and recommend to the Board the appointment, termination and retention of, and the compensation
to be paid to, the Auditors;
| | - | ----------------------------------------------------------------------------------------------------------------------------------



| | · | evaluate the performance of the Auditors;
| | - | -----------------------------------------



| | · | review and consider the Auditors’ integrated audit plan and annual engagement letter including
the proposed fees and the proposed work plan;
| | - | --------------------------------------------------------------------------------------------------------------------------------------------



| | · | consider and make recommendations to the Board or otherwise pre-approve, all non-audit services
provided by the Auditors to Perpetual or its subsidiaries;
| | - | ----------------------------------------------------------------------------------------------------------------------------------------------------------



| | · | oversee the work and the performance of the Auditors, review the independence of the Auditors and
report to the Board on these matters;
| | - | ---------------------------------------------------------------------------------------------------------------------------------------



| | · | review the annual and quarterly financial statements, MD&A and financial press releases, Annual
Information Form, Management Information Circular and other related Continuous Disclosure Documents as appropriate, prior to their
public disclosure;
| | - | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | · | oversee management’s establishment and maintenance of ICOFR to provide reasonable assurance
with regard to reliability of financial reporting;
| | - | ----------------------------------------------------------------------------------------------------------------------------------------------



| | · | review the Auditors’ report on the annual audited financial statements and related assessment
of ICOFR and the Auditor’s review letters on interim financial statements;
| | - | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | · | provide oral or written reports to the Board when necessary;
| | - | ------------------------------------------------------------



| | · | resolve disagreements between management and the Auditors regarding financial reporting;
| | - | ----------------------------------------------------------------------------------------



| | · | receive periodic certificates and reports from management with respect to compliance with financial,
regulatory, taxation and continuous disclosure requirements, and satisfy itself (a) that adequate procedures are in place to ensure
timely and full public disclosure of Continuous Disclosure Documents; and, (b) that a system of internal controls over financial
reporting has been implemented and is being maintained, in accordance with both the Disclosure Policy and the Management Responsibility
For Internal Control Policy; and additionally, must consider whether any identified deficiencies in internal controls are significant
or are material weaknesses;
| | - | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



D-6







| | · | meet with the Auditors, without management being present, at each time the interim and financial
statements are being considered, to ensure that no management restrictions have been placed on the scope of the Auditors’
work and to discuss the working relationship between the Auditors and management and other matters that the Audit Committee or
the Auditors may wish to raise;
| | - | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | · | review and monitor the implementation and adequacy of disclosure policies;
| | - | --------------------------------------------------------------------------



| | · | review insurance coverage including Directors’ and Officers’ liability insurance;
| | - | ---------------------------------------------------------------------------------



| | · | be notified in writing within three business days of any fraud, litigation or regulatory investigation
which, in the opinion of the Corporation’s management, is material. Confirmation of receipt of such notification by each
member of the Audit Committee will additionally be required. Any fraud, material litigation or regulatory investigation not reported
as outlined above will be reported quarterly to the Board of Directors at the March, May, August, and November meetings immediately
following the discovery of such occurrence;
| | - | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | · | review and monitor the implementation and adequacy of hedging policies and controls, with reference
to the Corporation’s Hedging and Risk Management Policy, which is attached to this Manual in Section 7;
| | - | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | · | review compliance with applicable laws, regulations and policies;
| | - | -----------------------------------------------------------------



| | · | be advised of and review the results of any internal audits of Perpetual and report on same to
the Board;
| | - | ---------------------------------------------------------------------------------------------------------



| | · | establish procedures for:
| | - | -------------------------



| | (a) | the receipt, retention and treatment of complaints received by the Corporation regarding accounting,
internal accounting controls, or auditing matters; and
| | --- | -----------------------------------------------------------------------------------------------------------------------------------------------------------



| | (b) | the confidential, anonymous submission by employees of the issuer of concerns regarding questionable
accounting or auditing matters; (together with (a), a “Whistleblower Process”)
| | --- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | · | ensure that the Corporation’s management regularly advises employees of the existence of
a Whistleblower Process;
| | - | -----------------------------------------------------------------------------------------------------------------

| | · | receive regular reports respecting complaints made under the Whistleblower Process;
| | - | -----------------------------------------------------------------------------------

| | · | inform the Auditors of whether the Audit Committee has knowledge of any actual, suspected or alleged
fraud affecting the Corporation, including complaints regarding financial reporting and confidential submissions by employees;
| | - | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | · | review and validate Perpetual management’s annual review of fraud risk assessment;
| | - | ----------------------------------------------------------------------------------



| | · | review and approve Perpetual’s hiring policies regarding partners, employees and former partners
and employees of the present and former Auditor of the issuer; and
| | - | -------------------------------------------------------------------------------------------------------------------------------------------------------------------





| | · | monitor the selection and application of proper accounting principles and practices and to review
the status of all relevant financial and related fiduciary aspects of the Corporation.
| | - | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------









D-7