Pine Cliff Energy Ltd. — Annual Report 2020

Mar 10, 2021

ANNUAL INFORMATION FORM

For the Year Ended December 31, 2020

March 9, 2021

GLOSSARY OF ABBREVIATIONS AND ADVISORIES 2
FORWARD-LOOKING STATEMENTS 3
CORPORATE STRUCTURE 5Name, Address and Incorporation 5Intercorporate Relationships 5
GENERAL DEVELOPMENT OF THE BUSINESS 5Overview 5Material Activities in 2018,2019, and 2020 6Description of Oil and Gas Properties 8
STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION 10Presentation of Oil and Gas Information 10Definitions and Notes to Reserve Data Tables 11Reserves Data in Respect of Pine Cliff 12PART 1 – DATE OF STATEMENT 13PART 2 – DISCLOSURE OF RESERVE DATA 14PART 3 – PRICING ASSUMPTIONS 16PART 4 – RECONCILIATION OF CHANGES IN RESERVES 17PART 5 – ADDITIONAL INFORMATION RELATED TO RESERVE DATA 18PART 6 – OTHER OIL AND GAS INFORMATION 20
MINING ASSETS 24
DESCRIPTION OF THE BUSINESS 24Competition 24Seasonality and Climate 24Environmental Regulation 24Personnel 25Specialized Skills and Knowledge 25Bankruptcies and Reorganizations 25
INDUSTRY CONDITIONS 25
RISK FACTORS 40
DIVIDENDS 54
DESCRIPTION OF SHARE CAPITAL 54General Description of Share Capital 54Common Shares 54Preferred Shares 54
MARKET FOR SECURITIES 55
OPTIONS AND WARRANTS 55
DIRECTORS AND OFFICERS 56
CONFLICTS OF INTEREST 57
LEGAL PROCEEDINGS AND REGULATORY ACTIONS 57
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS 58
MATERIAL CONTRACTS 58
INTERESTS OF EXPERTS 58
AUDIT COMMITTEE INFORMATION 58
ADDITIONAL INFORMATION 60
APPENDIX "A" 61
APPENDIX "B" 63
APPENDIX "C" 64

GLOSSARY OF ABBREVIATIONS AND ADVISORIES

Oil and Gas Abbreviations

Bbl	barrel	Mcf	thousand cubic feet
Bbl/d	barrels per day	Mcf/d	thousand cubic feet per day
Boe	barrel of oil equivalent	Mcfe	thousand cubic feet of naturalgas equivalent
Boe/d	barrels of oil equivalent per day	MMBtu	million British thermal units
CBM	coal bed methane	MMcf	million cubic feet
GJ	gigajoule	M$	thousands of dollars
MBbl	thousand barrels	NGLs	Natural gas liquids, includingcondensate, propane, butaneand ethane
MBoe	thousand barrels of oil equivalent
Other Abbreviations
AECO	Physical storage and trading hub for natural gas on the TransCanada Alberta transmission system which isthe delivery point for various benchmark Alberta index prices
WTI		West Texas Intermediate oil at Cushing, Oklahoma, the benchmark for North American crude oil pricing

Conversion and Units

The following table sets forth certain standard 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
GJ	Mcf	1.05
MMBtu	Mcf	0.95
MMBtu	GJ	1.054
Bbl	Cubic metres	0.159
Cubic metres	Bbl	6.290
Feet	Metres	0.305
Metres	Feet	3.281
Miles	Kilometres	1.609
Kilometres	Miles	0.621
Acres	Hectares	0.405
Hectares	Acres	2.471

In this annual information form ("Annual Information Form") where amounts are expressed on a Boe basis, natural gas volumes have been converted to oil equivalence at six Mcf per one Bbl. The term Boe may be misleading, particularly if used in isolation. Natural gas liquids and oil volumes are recorded in Bbl and are converted to Mcfe using a ratio of six (6) thousand cubic feet to one Bbl of oil. The term Mcfe may be misleading, particularly if used in isolation. These conversion ratios are based on an energy equivalency conversion method primarily applicable at the burner tip and do not represent a value equivalency at the wellhead. Unless otherwise specified, references to oil include NGLs.

Where any disclosure of reserves data is made in this Annual Information Form that does not reflect all of the reserves of Pine Cliff Energy Ltd. ("Pine Cliff" or the "Company") the reader should note that the estimates of reserves and future net revenue for individual properties or groups of properties may not reflect the same confidence level as estimates of the reserves and future net revenue for all properties, due to the effects of aggregation.

Non-GAAP Measures

This Annual Information Form uses the term "operating netback" which is not recognized under Generally Accepted Accounting Principles ("GAAP") and may not be comparable to similar measures presented by other companies. The Company considers operating netback to be a key indicator of profitability relative to current commodity prices. Operating netback and operating netback per Boe and per Mcfe are calculated as oil and gas sales, processing and gathering income, less royalties, operating and transportation expenses on an absolute and a per Boe or per Mcfe basis, respectively. Management uses operating netback on a per Boe basis in operational and capital allocation decisions.

Currency

In this Annual Information Form, unless otherwise noted, all dollar amounts are expressed in Canadian dollars.

FORWARD-LOOKING STATEMENTS

This Annual Information Form contains forward-looking statements. These statements relate to future events or Pine Cliff's future performance. All statements other than statements of historical fact may be forward-looking statements. In some cases, forward-looking statements can be identified by terminology such as "may", "will", "should", "expect", "plan", "anticipate", "believe", "estimate", "predict", "potential", "continue", or the negative of these terms or other comparable terminology. These statements are only predictions. Actual events or results may differ materially. In addition, this Annual Information Form may contain forward-looking statements attributed to third party industry sources. Undue reliance should not be placed on these forward-looking statements, as there can be no assurance that the plans, intentions or expectations upon which they are based will occur. By its nature, forward-looking information involves numerous assumptions, known and unknown risks and uncertainties, both general and specific, that contribute to the possibility that the predictions, forecasts, projections and other forwardlooking statements will not occur. Forward-looking statements in this Annual Information Form include, but are not limited to, statements with respect to:

• the quantity and quality of the oil and natural gas reserves;
• the performance and characteristics of Pine Cliff's oil and natural gas properties;
• future development and exploration activities and the timing thereof;
• future land expiries;
• results of various projects of Pine Cliff;
• timing of receipt of regulatory approvals;
• timing of development of undeveloped reserves;
• the tax horizon and taxability of Pine Cliff;
• supply and demand for oil, NGLs, natural gas and minerals (including precious metals);
• expectations regarding the Company's ability to raise capital and to continually add to reserves through acquisitions and development;
• the timing and amount of abandonment and reclamation costs;
• the impact of Canadian federal and provincial governmental regulation on Pine Cliff relative to other natural resource issuers of similar size;
• realization of the anticipated benefits of acquisitions and dispositions;
• weighting of production between different commodities;
• projections of commodity prices and costs;
• expected levels of royalty rates, operating costs, transportation costs, general and administrative costs, costs of services and other costs and expenses;
• capital expenditure programs and the timing and method of financing thereof; and
• treatment under government regulation and taxation regimes.

Although Pine Cliff believes that the expectations reflected in the forward-looking statements are reasonable, there can be no assurance that such expectations will prove to be correct. Pine Cliff cannot guarantee future results, levels of activity, performance, or achievements. Moreover, neither Pine Cliff nor any other person assumes responsibility for the outcome of the forward-looking statements. Many of the risks and other factors are beyond Pine Cliff's control, which could cause results to differ materially from those expressed in the forward-looking statements contained in this Annual Information Form. The risks and other factors include, but are not limited to:

• general economic conditions in Canada, the United States and globally, including reduced availability of debt and equity financing generally;
• industry conditions, including fluctuations in the price of oil, NGLs and natural gas;
• liabilities inherent in oil, natural gas and mineral operations;
• governmental regulation of the oil and gas, and mining industries, including environmental regulation;
• fluctuation in foreign exchange or interest rates;
• geological, technical, drilling and processing problems and other difficulties in producing reserves;
• unanticipated operating events which can reduce production or cause production to be shut in or delayed;
• failure to realize anticipated benefits of acquisitions;
• failure to obtain industry partner and other third party consents and approvals, when required;
• stock market volatility and market valuations;
• competition for, among other things, capital, acquisitions or reserves, undeveloped land and skilled personnel;
• competition for and inability to retain drilling rigs, production equipment and other services;
• rights to surface access;
• the need to obtain required approvals from regulatory authorities; and
• the other factors considered under "Risk Factors" in this Annual Information Form.

These factors should not be considered as exhaustive. Statements relating to "reserves" or "resources" are by their nature forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions that the resources and reserves described can be profitably produced in the future. With respect to forward-looking statements contained in this Annual Information Form, Pine Cliff has made assumptions regarding: future exchange rates; the impact of increasing competition; conditions in general economic and financial markets; availability of drilling and related equipment; availability of skilled labour; current technology; cash flow; production rates; timing and amount of capital expenditures; the prices and marketability of oil, NGLs, natural gas; royalty rates; effects of regulation by governmental agencies; future operating costs; future transportation costs; and the Company's ability to obtain financing on acceptable terms. Readers are cautioned that the foregoing list of factors is not exhaustive.

The above summary of assumptions and risks related to forward-looking information has been provided in this Annual Information Form in order to provide readers with a more complete perspective on Pine Cliff's future operations. Readers are cautioned that this information may not be appropriate for other purposes.

The forward-looking statements contained in this Annual Information Form are expressly qualified by this cautionary statement. Pine Cliff is not under any duty to update or revise any of the forward-looking statements and does not intend to do so except as expressly required by applicable securities laws.

CORPORATE STRUCTURE

Name, Address and Incorporation

Pine Cliff was incorporated under the Business Corporations Act (Alberta) (the "ABCA") on November 10, 2004, by Certificate of Incorporation issued pursuant to the provisions of the ABCA, under the name "Pine Cliff Energy Ltd." Effective January 1, 2011, Pine Cliff amalgamated with its wholly-owned subsidiary, CanAmericas Energy Ltd., and its indirect wholly-owned subsidiary, CanAmericas (Chile) Energy Ltd., pursuant to the provisions of the ABCA. On October 1, 2013, Pine Cliff amalgamated with its wholly-owned subsidiary Skope Energy Inc. ("Skope Energy") pursuant to the provisions of the ABCA and, immediately prior to such amalgamation, Skope Energy amalgamated with its wholly-owned subsidiary Skope Energy International Inc. Where applicable, references to the "Company" and "Pine Cliff" in this Annual Information Form shall mean Pine Cliff, together with its direct and indirect subsidiaries.

Pine Cliff is a "reporting issuer" in the provinces of British Columbia, Alberta, Saskatchewan, Manitoba, Ontario and New Brunswick.

On March 3, 2016, Pine Cliff was listed on the Toronto Stock Exchange ("TSX") and de-listed from the TSX Venture Exchange ("TSXV"). The common shares of the Company ("Common Shares") are listed on the TSX under the symbol "PNE".

Pine Cliff's registered and head office is located at Suite 850, 1015 - 4th Street S.W., Calgary, Alberta T2R 1J4.

Transfer Agent and Registrar

The Registrar and Transfer Agent for Common shares is Odyssey Trust Company at 350, 300 5th Ave SW Calgary, Alberta T2P 3C4.

Intercorporate Relationships

The following diagram sets forth the organizational structure of Pine Cliff, which does not have any material subsidiaries as of the date hereof:

GENERAL DEVELOPMENT OF THE BUSINESS

Overview

Pine Cliff is an Alberta-based corporation primarily engaged in the business of exploration for, and acquisition, development and production of oil, natural gas and NGLs in the Western Canadian Sedimentary Basin (the "WCSB"). In order to create value for the holders of Common Shares ("Shareholders"), Pine Cliff is pursuing an integrated growth strategy that includes both development and exploration drilling as well as acquisitions.

Through its nonmaterial wholly-owned subsidiary, Geomark Exploration Ltd. ("Geomark"), Pine Cliff also owns interests in lands that are prospective for the exploration of precious metals located in Ontario, the Northwest Territories and Nunavut, all in Canada and Utah, United States.

Material Activities in 2018, 2019 and 2020

Year ended December 31, 2018

On July 13, 2018, Pine Cliff completed a private placement of an aggregate of 19,000 units to the Alberta Investment Management Corporation (the "2018 Private Placement"), on behalf of certain of its clients, at a price of $1,000 per unit ("2018 Unit") for aggregate gross proceeds of $19 million. Each 2018 Unit was comprised of: (i) one promissory note with a par value of $1,000 per Note and bearing interest at 7.05% per annum (collectively the "$19 Million 2022 Notes"), which was payable semi-annually; and (ii) 150 Common Share purchase warrants ("2021 Warrants"). The proceeds from the 2018 Private Placement were used to reduce bank indebtedness.

The $19 Million 2020 Notes matured on July 31, 2022 and all or a portion of the principal amount outstanding thereunder could be repaid without penalty after three years. Pine Cliff issued 2.85 million 2021 Warrants in connection with the 2018 Private Placement, with each 2021 Warrant entitling the holder to purchase one Common Share for $0.51 until July 13, 2021, which reflected a 45% premium to the 10-day weighted average trading price of the Common Shares prior to, and including, the date of closing of the 2018 Private Placement.

On July 13, 2018, the Company entered into a restated credit agreement with its banking syndicate for an $11 million revolving credit facility, consisting of a $6 million revolving credit facility and a $5 million revolving operating facility (collectively, the "2018 Credit Facility") and reduced the banking syndicate from four to three Canadian financial institutions. The 2018 Credit Facility had a 364 day revolving period maturing July 27, 2019 and if it was not renewed it would have converted to a one day term loan due on July 28, 2019.

On July 29, 2016, the Company issued $5.0 million in promissory notes maturing on July 29, 2018. On July 13 2018, these notes were amended to mature on September 30, 2020 and increased to $6.0 million ("$6 Million 2020 Related Party Note"). The $6 Million 2020 Related Party Note bore interest at 0.25% less than the monthly average effective interest rate paid on the 2018 Credit Facility, payable monthly. The $6 Million 2020 Note was issued to the Company's Chairman of the Board. The $6 Million 2020 Note was secured by a $6.0 million floating charge debenture over all of the Company's assets and was subordinated to any and all claims in favor of the 2018 Credit Facility and the $30 Million 2020 Note and $19 Million 2022 Note holders.

On July 29, 2016, the Company issued $6.0 million in promissory notes maturing on July 29, 2018. On July 13 2018, these notes were amended to mature on September 30, 2020 ("$6 Million 2020 Notes"). The $6 Million 2020 Notes bore interest at 0.25% less than the monthly average effective interest rate paid on the 2018 Credit Facility, payable monthly. The $6 Million 2020 Notes were issued to a shareholder and a relative of that shareholder, owning directly or by discretion and control, greater than 10% of the Common Shares. The $6 Million 2020 Notes were secured by a $6.0 million floating charge debenture over all of the Company's assets and were subordinated to any and all claims in favor of the 2018 Credit Facility and the $30 Million 2020 Note and $19 Million 2022 Note holders.

Year ended December 31, 2019

On May 31, 2019, the Company closed the acquisition of certain mainly natural gas weighted assets (the "Acquired Assets") in the Ghost Pine area of Central Alberta for net cash consideration of $8.8 million, after estimated closing adjustments.

The Acquired Assets added growth opportunities in the Pekisko oil play, where Pine Cliff drilled its first Pekisko oil well in late 2018. Based on Pine Cliff's internal estimates, the Acquired Assets increased Pine Cliff's development inventory to an estimated 30 gross (28 net) Pekisko oil well locations, of which 21 gross (19.0 net) are unbooked and nine gross (9.0 net) are booked locations recognized in the Pine Cliff Reserve Report, as defined herein.

On May 31, 2019, Pine Cliff issued 14,492,754 "flow-through" Common Shares (the "Flow-Through Shares") at a price of $0.276 per Flow-Through Share, resulting in gross proceeds of $4.0 million. The proceeds from the Flow-Through Shares were used to incur eligible Canadian Development Expenses ((within the meaning of the Income Tax Act (Canada) ("CDE") and Pine Cliff incurred all eligible CDE prior to December 31, 2019.

On May 31, 2019, Pine Cliff also issued by way of a non-brokered private placement ("2019 Private Placement"), 6,215,652 Common Shares, at a price of $0.23 per Common Share, resulting in gross proceeds of $1.4 million. Insiders, including directors and officers, subscribed for a total of 2,608,695 Common Shares in this 2019 Private Placement.

On July 28, 2019, the 2018 Credit Facility expired and was not renewed.

On October 1, 2019, Pine Cliff amended and restated its $6.0 million subordinated promissory note to the Company's Chairman of the Board. This amended and restated promissory note matures on December 31, 2024 ("Related Party Note"), bears interest at 6.5% per annum and is payable monthly. The Related Party Note is secured by a $6.0 million floating charge debenture over all of the Company's assets and is subordinated to any and all claims in favor of the holder of the Term Debt, as defined herein.

On October 1, 2019, Pine Cliff amended and restated its $6.0 million subordinated promissory notes. These amended and restated subordinated promissory notes mature on December 31, 2024 ("$6 Million Notes"), bear interest at 6.5% per annum and are payable monthly. The $6 Million Notes are issued to a shareholder and a relative of that shareholder, owning directly or by discretion and control, greater than 10% of the Common Shares. The $6 Million Notes are secured by a $6.0 million floating charge debenture over all of the Company's Assets and are subordinated to any and all claims in favor of the holder of the Term Debt.

On October 1, 2019, Pine Cliff entered into a credit facility with Alberta Investment Management Corporation ("AIMCo"), acting on behalf of its clients, to repay its $30 million promissory notes maturing September 30, 2020 ("2020 Notes") and its $19 million promissory notes maturing July 31, 2022 ("2022 Notes") and replace them with a non-revolving term credit facility ("Term Debt"). The Term Debt consists of a first tranche with a principal amount of $30 million that matures on December 31, 2024 (the "2024 Tranche") and a second tranche with a principal amount of $19 million that matures on July 31, 2022 (the "2022 Tranche"), (collectively the "Refinancing"). Interest on the 2024 Tranche is payable at a rate of 8.75% per annum until September 30, 2020 and thereafter such interest rate will increase by 1% per annum up to 12.75% and interest is payable on the 2022 Tranche at a rate of 7.05% per annum. All or a portion of the principal amount outstanding can be repaid at any time, but without any penalty or premium after September 30, 2022 with respect to the 2024 Tranche and, July 13, 2021 with respect to the 2022 Tranche. A total of 7.5 million Common Share purchase warrants (the "Warrants") were issued in connection with the Refinancing, with each Warrant entitling the holder to purchase one Common Share of Pine Cliff for $0.20565, until September 30, 2022. The Refinancing security consists of floating demand debentures totaling $150.0 million and a general security agreement with first ranking over all current and acquired properties.

Year ended December 31, 2020

On August 5, 2020, the Company the Company entered into an agreement to establish a $4.0 million borrowing facility (the "Facility") with the Company's Chairman of the Board (the "Lender"), whereby the Lender provided up to $4.0 million of borrowings at an interest rate of 6.5% per annum, payable monthly. The term (the "Term") of the Facility will expire on the later of: (i) March 31, 2021; or (ii) the date of full repayment of any outstanding borrowings. Amounts can be drawn, repaid and redrawn by the Company at any time during the Term and borrowings under the Facility are payable on demand to the Lender on 60 days written notice. The Facility can be cancelled at any time by the Lender on 60 days written notice, while the Term may also be extended by mutual consent of the Company and the Lender. As of the date hereof, no amounts are drawn on this facility.

On September 1, 2020, AIMCo exercised its right and purchased 7.5 million Common Shares of Pine Cliff in return for a cash payment of $1.5 million.

DESCRIPTION OF OIL AND GAS PROPERTIES

Pine Cliff's oil and gas properties as at December 31, 2020 are located in Alberta and Saskatchewan where the Company operates or has ownership in facilities and other installations necessary to produce, transport and sell oil, natural gas and NGLs. A description of Pine Cliff's oil and gas properties and infrastructure is set out below.

The following map outlines the location of Pine Cliff's assets:

Central Alberta Assets

Pine Cliff owns high working interest, low-cost production with a long reserve life in the Ghost Pine and Viking areas of Central Alberta (the "Central Alberta Assets"). Pine Cliff has an average 71% working interest by wells in its Central Alberta Assets and operates 96% of the production.

Greater Ghost Pine

Pine Cliff's Ghost Pine assets are located near the town of Drumheller, Alberta and produce 81% natural gas. Ghost Pine production is from the Late Cretaceous Edmonton Group to the liquids-rich, Early Cretaceous Mannville Group and Mississippian Rundle Group. Within the Ghost Pine asset there are up to 12 separate gas or oil charged reservoir formations. Pine Cliff owns and operates a majority of the infrastructure in this area including three licensed gas plants, numerous large nodal compressor stations and extensive gathering and sales pipeline networks.

Drilling and recompletion development in the Ghost Pine area is primarily focused on exploitation of many different productive intervals from surface to the base of the Mississippian Group. Pine Cliff owns, or has license rights to, 420 square kilometers of 3D and 813 kilometers of 2D seismic on its Central Alberta assets. Pine Cliff has identified 64 gross (48.5 net) horizontal Pekisko oil locations and 11 gross (9.4 net) horizontal Basal Quartz oil locations. Of these locations, 17 gross (12.8 net) Pekisko and one gross (1.0 net) Basal Quartz drilling locations are recognized in the Pine Cliff Reserve Report. Additionally, Pine Cliff has identified several development prospects in the Mannville Group for both liquids-rich gas and oil.

Viking

Pine Cliff's Viking assets are located near the town of Viking, Alberta and produce 99% natural gas. The majority of this production comes from the Viking shore face sands composed of fine to coarse grained sandstone with inter-beds of conglomerate and cherty conglomeratic sandstone. There is upside potential in the Colorado shale which is a deep water siltstone equivalent to the Cardium shore face found in Western Alberta.

Southern Alberta and Southern Saskatchewan (The Southern Assets)

Pine Cliff owns long-term, low decline producing shallow gas assets in Southern Alberta and Saskatchewan referred to as the Southern Assets. Excluding the Tilley unit in this area, Pine Cliff has a 95% working interest by well in the Southern Assets and is the operator of 98% of the Company's production in the area, excluding the Tilley unit in this area. Pine Cliff also has a 10% interest in the Tilley unit.

The majority of the producing zones in these properties are from the upper Cretaceous Milk River, Medicine Hat and Second White Specks sands. These fields are characterized by their shallow depths and low-permeability clay-rich sands. The formations occur in broad sheet-like sands that are laterally extensive and have been regarded by many as offshore sands. Underlying structures create fracturing which enhances permeability in these shallow horizons.

Hatton

Pine Cliff's Hatton assets are located near the Town of Maple Creek, Saskatchewan and produce natural gas. Development and production activities in the Hatton area at this time are primarily directed toward exploitation and maintaining production. Pine Cliff controls most of the infrastructure in this area, which includes a gas gathering system and a major compressor station that delivers to a TransGas Limited pipeline.

Many Islands/Long Valley

The Many Islands/Long Valley area is located east of the City of Medicine Hat, Alberta and produce natural gas. Development and production activities in the Many Islands/Long Valley area at this time are primarily directed toward exploitation and maintaining production. Pine Cliff controls most of the infrastructure in this area, which includes a gas gathering system, two field compressors and a 100% interest in a compression station that delivers to two TC Energy Corporation ("TC Energy") pipelines. In 2017, Pine Cliff purchased 100% interest in two Canadian Energy Regulator ("CER") regulated inter-provincial natural gas export pipelines that permit Pine Cliff to transport produced natural gas to either Alberta or Saskatchewan.

Pendor/Black Butte

The Pendor/Black Butte area is located approximately 80 kilometers southwest of the City of Medicine Hat, Alberta and produces natural gas. Development and production activities in the Pendor/Black Butte area at this time are primarily directed toward exploitation and maintaining production. Pine Cliff controls most of the infrastructure in this area which includes a gas gathering system, two gas processing facilities and a 100% interest in a CER regulated sales gas export pipeline terminating in Montana, United States.

Tilley/Monogram

The Tilley/Monogram area is located approximately 40 kilometers northwest of the City of Medicine Hat, Alberta and produces natural gas. Development and production activities in the Tilley/Monogram area are currently directed toward

exploitation and maintaining production. Pine Cliff controls most of the infrastructure in the Monogram area, which includes a gas gathering system, one field compressor and a 90% interest in a gas plant that delivers to TC Energy meter station or to a third party pipeline that transports gas to Alberta, Saskatchewan or the Empress market. The Tilley asset is a 10% working interest unit not operated by Pine Cliff.

Eagle Butte

The Eagle Butte area is located approximately 24 kilometers southeast of the City of Medicine Hat, Alberta and produces natural gas. Development and production activities in the Eagle Butte area are currently directed towards exploitation and maintaining production. Pine Cliff controls most of the infrastructure in this area, which includes a gas gathering system, two field compressors and a 100% interest in a gas plant that delivers to a TC Energy pipeline.

Edson

Pine Cliff owns assets located near the town of Edson in Western Central Alberta, which produce liquids rich natural gas as well as a small amount of oil (the "Edson Assets"). Pine Cliff has a 51% average working interest by wells in the Edson Assets and is the operator of approximately 46% of the Company's production in the area. The Edson Assets have multi-zone potential which can be further exploited.

Pine Cliff's acreage in the area is productive primarily from sands belonging to the Middle Jurassic Rock Creek Formation and the early cretaceous Ellerslie formation. Secondary zones of interest in the area include sands belonging to the Viking, Wilrich, Bluesky, Gething and Notikewin formations. Pine Cliff has identified a total of 51 gross (13.3 net) potential drilling locations including seven gross (1.8 net) booked locations in the liquids-rich Ellerslie (Gething) formation and six gross (2.2 net) booked locations in the Bluesky formation, and three gross (0.5 net) booked locations in the WIlrich formation.

The Rock Creek sands are interpreted to have been deposited in a shallow marine shelf environment where lateral thickness variations may be the result of paleotopographic variability or changes in depositional environment. The reservoir sands are comprised of fine to medium grained sands and siltstones, average approximately six metres in thickness and are encountered at an average drill depth of 2,425 metres.

Unconformable overlying the Fernie Shale are the Lower Manville (basal quartz) equivalent sands. Derived from the Rocky Mountains to the west, these chert-rich sands were deposited by the northerly flowing Spirit River Channel system. The trapping mechanism for all the reservoirs in the Edson Assets is largely stratigraphic.

Non-core Areas

At December 31, 2020, Pine Cliff also has working interests in non-operated properties in the Carstairs, Garrington and Harmattan areas of Alberta and the Cadillac area of Southern Saskatchewan, but does not consider any of these assets to be core areas of the Company at this time.

STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION

Presentation of Oil and Gas Information

All oil and gas information contained in this Annual Information Form has been prepared and presented in accordance with National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities ("NI 51-101"). The actual oil and gas reserves and future production will be greater than or less than the estimates provided herein. The estimated value of future net revenue from the production of the disclosed oil and gas reserves does not represent the fair market value of these reserves. There is no assurance that the forecast prices and costs or other assumptions made in connection with the reserves disclosed herein will be attained and variances could be material.

Definitions and Notes to Reserve Data Tables

Certain terms used herein are defined in NI 51-101 or the Canadian Oil and Gas Evaluation Handbook ("COGE Handbook") and, unless the context otherwise requires, shall have the same meanings in this Annual Information Form as in NI 51-101 or the COGE Handbook.

The following definitions form the basis of the classification of reserves and values presented in the Pine Cliff Reserve Report, as defined herein. They have been jointly prepared by the Canadian Institute of Mining, Metallurgy and Petroleum and the Society of Petroleum Evaluation Engineers and incorporated into the COGE Handbook and specified by NI 51-101. Reserve data tables may not add due to rounding.

Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be recovered from known accumulations, from a given date forward, based on:

• analysis of drilling, geological, geophysical and engineering data;
• the use of established technology;
• specified economic conditions, which are generally accepted as being reasonable, and shall be disclosed; and
• a remaining reserve life of 50 years.

Reserves are classified according to the degree of certainty associated with the estimates.

1. Proved Reserves

Proved reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.

2. Probable Reserves

Probable reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves.

3. Possible Reserves

Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. It is unlikely that the actual remaining quantities recovered will exceed the sum of the estimated proved plus probable plus possible reserves. Possible reserves have not been considered in this Annual Information Form.

Other criteria that must also be met for categorization of reserves are provided in Section 5.5 of the COGE Handbook.

Each of the reserves categories (proved, probable and possible) may be divided into developed or undeveloped categories.

4. Developed Reserves

Developed reserves are those reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure (e.g., when compared to the cost of drilling a well) to put the reserves on production. The developed category may be subdivided into producing and non-producing.

5. Developed Producing Reserves

Developed producing reserves are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty.

6. Developed Non-Producing Reserves

Developed non-producing reserves are those reserves that either have not been on production, or have previously been on production, but are shut in, and the date of resumption of production is unknown.

7. Undeveloped Reserves

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

In multi-well pools, it may be appropriate to allocate total pool reserves between the developed and undeveloped categories or to subdivide the developed reserves for the pool between developed producing and developed non-producing. This allocation is typically based on the estimator's assessment as to the reserves that will be recovered from specific wells, facilities and completion intervals in the pool and their respective development and production status.

8. Levels of Certainty for Reported Reserves

The qualitative certainty levels contained in the definitions in Sections 1, 2 and 3 above are applicable to individual reserves entities, which refers to the lowest level at which reserves estimates are made, and to reported reserves, which refers to the highest level sum of individual entity estimates for which reserve estimates are made.

Reported total reserves estimated by deterministic or probabilistic methods, whether comprised of a single reserves entity or an aggregate estimate for multiple entities, should target the following levels of certainty under a specific set of economic conditions:

• (a) there is a 90% probability that at least the estimated proved reserves will be recovered;
• (b) there is a 50% probability that at least the sum of the estimated proved reserves plus probable reserves will be recovered; and
• (c) there is a 10% probability that at least the sum of the estimated proved reserves plus probable reserves plus possible reserves will be recovered.

A quantitative measure of the probability associated with a reserves estimate is generated only when a probabilistic estimate is conducted. The majority of reserves estimates will be performed using deterministic methods that do not provide a quantitative measure of probability. In principle, there should be no difference between estimates prepared using probabilistic or deterministic methods.

Additional clarification of certainty levels associated with reserves estimates and the effect of aggregation is provided in Section 5.5.3 of the COGE Handbook. Whether deterministic or probabilistic methods are used, evaluators are expressing their professional judgement as to what are reasonable estimates.

Reserves Data in Respect of Pine Cliff

All of Pine Cliff's oil and gas reserves are located in Canada. Pine Cliff conducts an annual independent evaluation of all of the Company's reserves. Pine Cliff engaged independent petroleum consultants McDaniel & Associates Consultants Ltd. ("McDaniel") to evaluate reserves for all of Pine Cliff's oil and gas properties effective December 31, 2020 (the "Pine Cliff Reserve Report"). The Pine Cliff Reserve Report has been prepared in accordance with the standards contained in the COGE Handbook and the reserve definitions contained in NI 51-101. McDaniel has reviewed and consented to the information contained herein.

The reserves data summarizes the oil, natural gas and NGLs reserves of Pine Cliff and the net present values of future net revenue for these reserves using forecast prices and costs. The reserves data conforms to the requirements of NI 51-101. Additional information not required by NI 51-101 has been presented to provide continuity and additional information which the Company believes is important to the readers of this information. Pine Cliff engaged McDaniel to provide an evaluation of proved and proved plus probable reserves and no attempt was made to evaluate possible reserves.

All evaluations of future net production revenue set forth in the tables below are based on the average forecast prices of McDaniel & Associates Consultants Ltd., GLJ Petroleum Consultants Ltd. and Sproule Associates Limited as of January 1, 2021 and are stated for Pine Cliff's working interest share of reserves (referred to as "Gross" in NI 51-101) in accordance with the COGE Handbook. Pine Cliff's net interest share is after deduction for royalty burdens payable and receivable. It should not be assumed that the discounted future net production revenue estimated by the Pine Cliff Reserve Report represents the fair market value of the reserves. There is no assurance that the future price and cost assumptions used in the Pine Cliff Reserve Report will prove accurate and variances could be material. The recovery and reserve estimates of oil, natural gas and NGLs reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual oil, natural gas and NGLs reserves may be greater than or less than the estimates provided herein. Tables may not add due to rounding.

Estimates of reserves and future net revenue have been made assuming that development of each property in respect of which the estimate is made will occur, without regard to the likely availability to Pine Cliff of adequate liquidity and capital resources required for that development to occur.

Pine Cliff's Reserves Committee reviews the qualifications and appointment of the independent qualified reserves evaluators and the procedures for providing information to the evaluators. Pine Cliff's board of directors has reviewed and approved the Pine Cliff Reserve Report.

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

PART 1 – DATE OF STATEMENT

Relevant dates:

• (1) Statement date is February 10, 2021
• (2) Effective date is December 31, 2020
• (3) Preparation date is February 10, 2021

PART 2 – DISCLOSURE OF RESERVE DATA

SUMMARY OF OIL AND GAS RESERVES AS OF DECEMBER 31, 2020 FORECAST PRICES AND COSTS

		Light and Medium CrudeOil Combined	Heavy Oil		Conventional Natural Gas
	Gross	Net	Gross	Net	Gross	Net
Reserve Category:	(MBbl)(MBbl)		(MMcf)	(MMcf)	(MMcf)	(MMcf)
Proved
Developed Producing	833.6	785.8	15.0	13.4	198,793.9	182,690.8
Developed Non-Producing	12.2	11.8	11.9	10.7	2,152.7	1,931.2
Undeveloped	830.0	757.1	-	-	5,567.7	5,141.7
Total Proved	1,675.7	1,554.7	27.0	24.1	206,514.3	189,763.6
Probable	1,125.8	995.3	4.0	3.5	52,402.0	48,308.3
Total Proved plus Probable	2,801.6	2,550.1	31.0	27.6	258,916.3	238,072.0

		Coal Bed Methane	Natural Gas Liquids		Total Oil Equivalent
	Gross	Net	Gross	Net	Gross	Net
Reserve Category:	(MMcf)	(MMcf)	(MBbl)	(MBbl)	(MBoe)
Proved
Developed Producing	22,095.8	20,212.1	2,763.9	2,103.7	40,427.4	36,720.0
Developed Non-Producing	242.1	234.2	48.1	38.7	471.3	422.1
Undeveloped	(0.0)	0.0	242.4	215.9	2,000.4	1,829.9
Total Proved	22,338.020,446.3		3,054.3	2,358.3	42,899.1	38,972.1
Probable	3,929.43,600.7		1,422.6	1,230.3	11,941.0	10,880.6
Total Proved plus Probable	26,267.324,047.1		4,476.93,588.5		54,840.0	49,852.7

FUTURE NET REVENUE AS OF DECEMBER 31, 2020 FORECAST PRICES AND COSTS

Net Present Values of Future Net Revenue (1) Before Income Taxes

						Unit Value
($ millions)		Before Income Taxes Discounted at (% per year)				Before Tax@10% (2)
Reserve Category:	0%	5%	10%	15%	20%	$/Boe
Proved
Developed Producing	(170,632.5)	(10,473.5)	43,502.0	61,480.9	66,365.5	1.18
Developed Non-Producing	3,566.8	2,895.9	2,414.9	2,057.1	1,782.6	5.72
Undeveloped	28,042.6	15,247.0	8,288.6	4,240.7	1,747.2	4.53
Total Proved	(139,023.1)	7,669.4	54,205.6	67,778.6	69,895.2	1.39
Total Probable	111,814.3	66,811.2	43,963.8	31,044.7	23,087.2	4.04
Total Proved plus Probable	(27,208.8)	74,480.6	98,169.4	98,823.3	92,982.5	1.97

(1) Net of abandonment and reclamation costs.

(2) The unit values are based on net reserve volumes.

FUTURE NET REVENUE AS OF DECEMBER 31, 2020 FORECAST PRICES AND COSTS

Net Present Values of Future Net Revenue (1)

After Income Taxes

						Unit Value
($ millions)		After Income Taxes Discounted at (% per year)				Before Tax@10% (2)
Reserve Category:	0%	5%	10%	15%	20%	$/Boe
Proved
Developed Producing	(170,632.5)	(10,473.5)	43,502.0	61,480.9	66,365.5	1.18
Developed Non-Producing	3,566.8	2,895.9	2,414.9	2,057.1	1,782.6	5.72
Undeveloped	28,042.6	15,247.0	8,288.6	4,240.7	1,747.2	4.53
Total Proved	(139,023.1)	7,669.4	54,205.6	67,778.6	69,895.2	1.39
Total Probable	111,814.3	66,811.2	43,963.8	31,044.7	23,087.2	4.04
Total Proved plus Probable	(27,208.8)	74,480.6	98,169.4	98,823.3	92,982.5	1.97

(1) Net of abandonment and reclamation costs.

(2) The unit values are based on net reserve volumes.

TOTAL FUTURE NET REVENUE (UNDISCOUNTED) AS OF DECEMBER 31, 2020 FORECAST PRICES AND COSTS

($ millions)	Revenue (1)	Royalties (2)	OperatingCosts	DevelopmentCosts	AbandonmentandReclamationCosts	Future NetRevenueBeforeIncomeTaxes	IncomeTaxes	Future NetRevenueAfterIncomeTaxes
Proved	924,355	58,888	619,204	53,373	331,913	(139,023)	-	(139,023)
Proved plus Probable	1,248,372	81,282	774,491	86,362	333,446	(27,209)	-	(27,209)

(1) Includes all product revenues and other revenues as forecast.

(2) Royalties include any net profits interests paid, as well as the Saskatchewan Corporation Capital Tax Surcharge.

NET PRESENT VALUE OF FUTURE NET REVENUE BY PRODUCT TYPE AS OF DECEMBER 31, 2020 FORECAST PRICES AND COSTS

		Future Net Revenue Before	Unit Value Before Income
		Income Taxes (Discounted at	Taxes (Discounted at 10%
($ millions)		10% per year)	per year)
Reserve Category:	Product	(M$)	$/Mcf, $/Bbl
	Light and Medium Crude Oil
Proved	Combined(1)	23,915	18.37
	Heavy Oil (1)	694	28.82
	Conventional Natural Gas (2)	16,596	0.09
	Coal Bed Methane(2)	13,001	0.64
	Total	54,206
	Light and Medium Crude Oil
Proved plus Probable	Combined (1)	38,587	19.00
	Heavy Oil (1)	773	28.00
	Conventional Natural Gas (2)	42,960	0.19
	Coal Bed Methane(2)	14,848	0.62
	Total	98,169

(1) Including solution gas and by-products.

(2) Including by-products.

PART 3 – PRICING ASSUMPTIONS

SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONS AS OF DECEMBER 31, 2020 FORECAST PRICES AND COSTS

McDaniel has used a three consultant (McDaniel & Associates Consultants Ltd., GLJ Petroleum Consultants Ltd. and Sproule Associates Limited) average price forecast in the preparation of the Pine Cliff Reserve Report:

			Edmonton
		Edmonton	Cond &				Alberta	$C to $US
	WTI Crude	Light Crude	Natural	Edmonton	Edmonton	Edmonton	AECO Spot	Exchange
	Oil	Oil	Gasolines	Ethane	Propane	Butanes	Price	Rate
	$US/Bbl	$C/Bbl	$/Bbl	$/Bbl	$/Bbl	$/Bbl	$C/MMBtu
2021	47.17	55.76	59.24	8.91	18.18	26.36	2.78	0.768
2022	50.17	59.89	63.19	8.65	21.91	32.85	2.70	0.765
2023	53.17	63.48	67.34	8.35	24.57	39.20	2.61	0.763
2024	54.97	65.76	69.77	8.46	25.47	40.65	2.65	0.763
2025	56.07	67.13	71.18	8.63	26.00	41.50	2.70	0.763
2026	57.19	68.53	72.61	8.81	26.54	42.36	2.76	0.763
2027	58.34	69.95	74.07	8.99	27.09	43.24	2.81	0.763
2028	59.50	71.40	75.56	9.17	27.65	44.14	2.87	0.763
2029	60.69	72.88	77.08	9.36	28.23	45.06	2.92	0.763
2030	61.91	74.34	78.62	9.54	28.79	45.96	2.98	0.763
2031	63.15	75.83	80.20	9.74	29.37	46.88	3.04	0.763
2032	64.41	77.34	81.80	9.93	29.95	47.82	3.10	0.763
2033	65.70	78.89	83.44	10.13	30.55	48.77	3.16	0.763
2034	67.01	80.47	85.10	10.33	31.16	49.75	3.23	0.763
2035	68.35	82.08	86.81	10.54	31.79	50.74	3.29	0.763
Thereafter	+2%/year	+2%/year	+2%/year	+2%/year	+2%/year	+2%/year	+2%/year	0.763

Pine Cliff's weighted average realized sale price for the year ended December 31, 2020 was $37.31 per Bbl for crude oil, $23.11 per Bbl for NGLs and $2.28 per Mcf ($2.17 per MMBtu) for natural gas.

PART 4 – RECONCILIATION OF CHANGES IN RESERVES

RECONCILIATION OF PINE CLIFF'S GROSS RESERVES (BEFORE ROYALTY) BY PRINCIPAL PRODUCT TYPE AS OF DECEMBER 31, 2020 FORECAST PRICES AND COSTS

	Light and Medium Crude OilCombined				Heavy Oil		Conventional Natural Gas
	Proved(MBbl)	Probable(MBbl)	ProvedPlusProbable(MBbl)	Proved(MBbl)	Probable(MBbl)	ProvedPlusProbable(MBbl)	Proved(MMcf)	Probable(MMcf)	Proved PlusProbable(MMcf)
December 31, 2019	1,590.4	878.4	2,468.8	32.9	6.5	39.3	227,618.3	53,556.6	281,174.9
Extension and Improved Recovery	198.6	216.7	415.4	-	-	-	2,325.6	1,665.9	3,991.5
Technical Revisions	151.0	45.5	196.6	(1.8)	(1.7)	(3.4)	36,727.5	(616.9)	36,110.7
Acquisitions	0.7	0.1	0.9	-	-	-	2,372.1	504.1	2,876.1
Dispositions	(4.6)	(1.5)	(6.1)	-	-	-	(3,470.2)	(815.6)	(4,285.8)
Economic Factors	(102.3)	(13.5)	(115.8)	(1.6)	(0.7)	(2.4)	(23,712.6)	(1,892.0)	(25,604.6)
Total Changes	243.5	247.4	490.9	(3.4)	(2.4)	(5.8)	14,242.4	(1,154.6)	13,087.8
Production	158.1	-	158.1	2.5	-	2.5	35,346.4	-	35,346.4
December 31, 2020	1,675.7	1,125.8	2,801.6	27.0	4.0	31.0	206,514.3	52,402.0	258,916.3

	Coal Bed Methane				Natural Gas Liquids		Oil Equivalent
	ProvedPlus					ProvedPlus			ProvedPlus
	Proved(MMcf)	Probable(MMcf)	Probable(MMcf)	Proved(MBbl)	Probable(MBbl)	Probable(MBbl)	Proved(MBoe)	Probable(MBoe)	Probable(MBoe)
December 31, 2019	19,258.9	3,075.1	22,334.0	3,372.8	1,295.5	4,668.3	46,142.3	11,618.9	57,761.2
Extension and Improved Recovery	-	-	-	64.5	53.6	118.1	650.7	548.0	1,198.7
Technical Revisions	6,741.1	1,055.8	7,796.9	430.8	98.2	529.0	7,824.8	215.3	8,040.0
Acquisitions	426.8	65.8	492.6	41.7	8.9	50.6	508.9	104.0	612.9
Dispositions	-	-	-	(28.5)	(6.7)	(35.2)	(611.5)	(144.1)	(755.6)
Economic Factors	(1,269.7)	(267.3)	(1,537.0)	(392.6)	(26.9)	(419.5)	(4,660.2)	(401.0)	(5,061.2)
Total Changes	5,898.2	854.3	6,752.4	115.9	127.1	243.0	3,712.7	322.1	4,034.8
Production	2,819.1	-	2,819.1	434.4	-	434.4	6,955.9	-	6,955.9
December 31, 2020	22,338.0	3,929.4	26,267.3	3,054.3	1,422.6	4,476.9	42,899.0	11,941.0	54,840.0

PART 5 – ADDITIONAL INFORMATION RELATED TO RESERVE DATA

Undeveloped Reserves

Undeveloped reserves were attributed in accordance with the standards and procedures in the COGE Handbook. The following chart shows the Company's gross reserves, first attributed by year.

	Light and Medium Crude				Conventional Natural Gas
	Oil Combined(MBbl)		Heavy Oil (MBbl)		(MMcf)		Coal Bed Methane (MMcf)
	First	Total at	First	Total at	First	Total at	First	Total at
	Attributed	Year End	Attributed	Year End	Attributed	Year End	Attributed	Year End
Proved Undeveloped Reserves
Prior	-	4.5	27.1	27.1	2,364.0	5,054.3	-	-
2018	180.1	185.8	-	-	823.9	5,223.4	-	-
2019	409.3	606.2	-	-	1,614.7	7,053.6	-	-
2020	202.8	830.0	-	-	1,179.1	5,567.7	-	-
Probable Undeveloped Reserves
Prior	22.0	115.6	6.6	6.6	1,092.5	24,331.3	-	10,984.6
2018	98.9	192.7	-	-	1,317.4	24,764.4	-	-
2019	455.5	649.1	-	-	2,823.3	14,174.2	-	-
2020	216.9	909.1	-	-	1,340.0	15,091.4	-	-

	Natural Gas Liquids
	(MBbl)		MBoe (MBbl)
	First	Total at	First	Total at
	Attributed	Year End	Attributed	Year End
Proved Undeveloped Reserves
Prior	103.8	152.7	524.9	1,026.7
2018	35.9	174.0	353.3	1,230.4
2019	64.7	229.4	743.1	2,011.1
2020	40.7	242.4	440.0	2,000.4
Probable Undeveloped Reserves
Prior	47.5	562.4	258.2	6,570.6
2018	57.1	490.2	375.6	4,810.3
2019	112.5	671.5	1,038.6	3,683.1
2020	46.2	832.6	486.4	4,256.9

Proved undeveloped reserves comprise approximately 4.7% of Pine Cliff's total proved reserves on a Boe basis. Proved undeveloped reserves of 2,000.4 MBoe were assigned by McDaniel in accordance with NI 51-101. In general, proved undeveloped reserves were assigned to certain properties as a result of Pine Cliff's capital program. Pine Cliff plans to convert the proved undeveloped reserves to proved developed producing reserves over the next three years through future capital spending.

Probable undeveloped reserves were assigned by McDaniel in accordance with NI 51-101 requirements and standards. Pine Cliff's probable undeveloped reserves amount to 4,256.9 MBoe and represent about 68.0% of the total proved plus probable undeveloped reserves. Probable undeveloped reserves are assigned for similar reasons and generally to the same properties as proved undeveloped reserves, but also meet the requirements of the reserve classification to which they belong. Probable undeveloped reserves are those reserves that are less certain to be recovered than proved reserves and are expected to be recovered from known accumulations. Pine Cliff plans to convert the probable undeveloped reserves to proved developed producing reserves over the next five years as a result of historical and future capital spending.

Significant Factors or Uncertainties

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

As circumstances change and additional data becomes 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 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 either be positive or negative.

Future Development Costs

The following table outlines development costs deducted in the Pine Cliff Reserve Report in the estimation of future net revenue attributable to proved reserves and proved plus probable reserves, in each instance using forecast prices and costs.

(M$)	Total Proved	Total Proved plus Probable
2021	9,160	9,798
2022	11,759	13,250
2023	9,541	12,054
2024	6,068	15,868
2025	9,085	11,699
Remainder	7,760	23,693
Total for all years undiscounted	53,373	86,362
Total for all years discounted at 10% per year	41,204	62,484

Undeveloped Locations

Undeveloped locations consist of drilling and recompletion locations booked in the Pine Cliff Reserve Report and unbooked drilling and recompletion locations. Booked locations are proposed proved and probable locations identified in the Pine Cliff Reserve Report. Unbooked drilling and recompletion locations are internal estimates based on an evaluation of geology, volumetrics and analogs evaluation of geologic, reserves and spacing based on industry practice. As outlined in the following table, Pine Cliff has identified 139 gross (83.1 net) undeveloped locations of which 14 gross (10.3 net) are proved drilling locations, 24 gross (9.5 net) are probable drilling locations, and 101 gross (63.3 net) are unbooked drilling and recompletion locations.

	Unbooked Locations		Booked Locations		Total Locations
	Gross	Net	Gross	Net	Gross	Net
Camrose Mannville Recomplete	3	2.9	-	-	3	2.9
Carrot Creek Ellerslie	14	4.0	3	1.3	17	5.3
Carrot Creek Ostracod	-	-	1	0.4	1	0.4
Carrot Creek Rock Creek	-	-	3	1.1	3	1.1
Ghost Pine Basal Quartz Gas	4	3.4	-	-	4	3.4
Ghost Pine Basal Quartz Oil	10	8.4	1	1.0	11	9.4
Ghost Pine Sparky Gas	6	5.6	-	-	6	5.6
Pine Creek Bluesky	-	-	6	2.2	6	2.2
Pine Creek/McLeod Ellerslie	17	3.3	4	0.5	21	3.8
Sundance Wilrich	-	-	3	0.5	3	0.5
Three Hills Pekisko Oil	8	8.0	-	-	8	8.0
Twining Pekisko Oil	21	19.0	9	9.0	30	28.0
Twining Unit Pekisko Oil	18	8.7	8	3.8	26	12.5
Total	101	63.3	38	19.8	139	83.1

There is no guarantee that Pine Cliff will drill any or all of the undrilled locations and there is no certainty that the drilling of these locations will result in additional reserves or production or achieve expected rates of return. Pine Cliff's drilling activity depends on availability of capital, regulatory approvals, commodity prices, drilling costs and other factors. As such, Pine

Cliff's actual drilling activities may materially differ from those presently identified, which could adversely affect Pine Cliff's business.

Pine Cliff estimates that its internally generated cash flow will be sufficient to fund the future development costs disclosed above. Pine Cliff typically has available three sources of funding to finance its capital expenditure program: internally generated cash flow from operating activities; debt financing when appropriate; and new equity issues, if available on favorable terms.

PART 6 – OTHER OIL AND GAS INFORMATION

Well Count

The wells in which Pine Cliff had an interest in as at December 31, 2020 are set out in the following table:

	Oil & Liquids Wells		Gas Wells		Total Wells
	Gross	Net	Gross	Net	Gross	Net
Producing wells
Alberta	235	135	6,418	4,504	6,653	4,639
Saskatchewan	-	-	1,469	1,407	1,469	1,407
Total producing	172	63	7,950	5,983	8,122	6,047
Non-producing wells
Alberta	145	79	945	649	1,090	728
Saskatchewan	1	1	262	233	263	234
Total non-producing	146	79	1,207	882	1,353	961
Total	381	215	9,094	6,793	9,475	7,008

Additionally, the Company has 793 gross (595.8 net) wells in the Province of Alberta and 16 gross (13.8 net) wells in the Province of Saskatchewan that are abandoned and not yet reclaimed.

Marketing and Forward Contracts

The Corporation currently sells its natural gas at the AECO, Dawn, and TEP trading points. The Corporation has used fixed price, daily and monthly physical sales contracts to manage the risks related to fluctuating commodity prices and may continue to use these and various types of derivative financial instruments in the future. For details of the Company's physical sales contracts, please refer to Note 6 – Risk Management of the Company's audited annual financial statements for the year ended December 31, 2020.

Abandonment and Reclamation Costs

In connection with its operations, the Company will incur abandonment and reclamation costs for surface leases, wells, facilities and pipelines. The Company budgets for and recognizes as a liability the estimated present value of the future decommissioning liabilities associated with its property, plant and equipment. The Company estimates such costs through a model that incorporates data from the Company's operating history, industry sources and cost formulas used by Alberta Energy Regulator, together with other operating assumptions. The Company expects all of its net wells to incur these costs.

(M$)	Total Proved	Total Proved Plus Probable
2021	1,500	1,500
2022	1,500	1,500
2023	3,040	3,040
2024	3,101	3,101
2025	3,163	3,163
Remainder	319,609	321,142
Total for all years, inflated but undiscounted	331,913	333,446
Total for all years, inflated and discounted at 10% per year	72,666	72,688

Tax Horizon

Pine Cliff does not expect to pay income tax in the 2021 fiscal year. Depending on production, commodity prices and capital spending levels, Pine Cliff does not expect to pay cash income taxes in the foreseeable future.

The Company has the following tax pools, which may be used to reduce taxable income in future years, limited to the applicable rates of utilization:

(M$)	Rate of Utilization (%)	2020
Undepreciated capital costs	7 - 100	26,584
Canadian oil and gas property expenditures	10	199,174
Canadian development expenditures	30	8,476
Canadian exploration expenditures	100	167
Share issue costs	20	58
Non-capital losses carried forward(1)	100	158,236
Capital losses carried forward(2)		5,462
Total		398,157

1Non-capital losses expire between the years 2031 and 2040.

2The capital losses carried forward can only be claimed against taxable capital gains.

Capital Expenditures Incurred

The following table summarizes petroleum and natural gas capital expenditures incurred by the Company on acquisitions, dispositions, land, seismic, exploration and development drilling and production facilities for the year ended December 31, 2020:

(M$)
Property acquisition costs – proved	(6)
Property disposition proceeds – proved	(829)
Exploration	37
Development	7,480
Net oil and natural gas capital expenditures	6,682

Exploration and Development Activities

	Development		Exploratory		Total
	Gross	Net	Gross	Net	Gross	Net
Oil	3	0.3	-	-	3	0.3
Gas	-	-	-	-	-	-
Dry Holes	-	-	-	-	-	-
Total	3	0.3	-	-	3	0.3
Success Rate	100%	100%	0%	0%	100%	100%

The following table summarizes Pine Cliff's gross and net drilling activity and success in the year ended December 31, 2020:

In 2020, Pine Cliff drilled three successful gross (0.3 net) Ellerslie liquids rich natural gas wells in the Edson Assets. Pine Cliff's development drilling activities in 2021 are expected to be focused on Pekisko oil drilling and recompletions in the Central Alberta Assets and natural gas drilling in the Edson Assets.

Production Estimates

The following table summarizes the estimated 2021 production reflected in the estimates of future net revenue disclosed under Part 2 in the Pine Cliff Reserve Report:

	Gross Daily Production Total
Total Proved
Light, Medium and Heavy Oil Combined (Bbl/d)	501.9
Natural Gas (Boe/d)	16,904.2
Natural Gas Liquids (Bbl/d)	1,084.1
Total (Boe/d)	18,490.2
Total Proved plus Probable
Light, Medium and Heavy Oil Combined (Bbl/d)	531.2
Natural Gas (Boe/d)	17,094.0
Natural Gas Liquids (Bbl/d)	1,104.9
Total (Boe/d)	18,730.1

Production History

	Quarter ended	Quarter ended	Quarter ended	Quarter ended	Year ended
	March 31, 2020	June 30, 2020	September 30, 2020	December 31, 2020	December 31, 2020
Average daily production
Natural gas volumes
(Mcf/d)	104,412	104,611	103,303	104,788	104,277
NGLs (Bbl/d)	1,231	1,075	11,71	1,270	1,187
Light, Medium and Heavy
oil (Bbl/d)	536	458	367	395	439
Combined (BOE/d)	19,169	18,968	18,756	19,130	19,006
Light, Medium and Heavy
oil netbacks ($/Bbl)
Average sales price	43.47	22.10	40.54	43.46	37.31
Royalty expense	(2.57)	(0.90)	(2.37)	(3.39)	(2.28)
Operating expenses	(11.28)	(8.68)	(11.38)	(9.52)	(10.23)
Operating netback	29.62	12.52	26.79	30.55	24.80
Natural Gas netbacks
($/Mcf)
Average sales price	2.19	2.03	2.18	2.74	2.28
Royalty expense	(0.12)	(0.03)	(0.03)	(0.08)	(0.07)
Transportation expenses	(0.23)	(0.23)	(0.21)	(0.21)	(0.22)

Processing & Gathering
income	0.09	0.08	0.11	0.12	0.10
Operating expenses	(1.76)	(1.75)	(1.86)	(1.63)	(1.75)
Operating netback	0.17	0.10	0.19	0.94	0.34
NGLs netbacks ($/Bbl)
Average sales price	22.69	14.56	25.07	28.89	23.11
Royalty expense	(4.04)	(6.75)	(7.04)	(12.50)	(7.67)
Operating expenses	(9.82)	(11.10)	(10.71)	(10.38)	(10.48)
Operating netback	8.83	(3.29)	7.32	6.01	4.96
Combined netbacks($/Boe)
Average sales price	14.58	12.57	14.34	17.78	14.83
Royalty expense	(1.00)	(0.59)	(0.67)	(1.34)	(0.90)
Transportation	(1.36)	(1.37)	(1.28)	(1.26)	(1.32)
Processing and Gathering
Expense	0.54	0.46	0.65	0.74	0.60
Operating expenses	(10.51)	(10.48)	(11.14)	(9.84)	(10.49)
Operating netback	2.25	0.59	1.90	6.08	2.72

The following table provides a summary of the average production volumes from Pine Cliff's main producing areas:

	Quarter ended	Quarter ended	Quarter ended	Quarter ended	Year ended
	March 31, 2020	June 30, 2020	September 30, 2020	December 31, 2020	December 31, 2020
Light, Medium and Heavy
Crude Oil (Bbl/d)
Central Alberta Assets	470	391	343	344	386
Southern Assets	3	2	5	2	3
Edson Assets	63	64	21	50	48
Total	536	457	369	396	437
Natural Gas (Mcf/d)
Central Alberta Assets	8,683	8,754	8,664	8,855	8,740
Southern Assets	7,502	7,543	7,528	7,515	7,522
Edson Assets	1,217	1,139	1,025	1,094	1,120
Total	17,402	17,436	17,217	17,464	17,382
Natural Gas Liquids (Bbl/d)
Central Alberta Assets	783	704	740	843	768
Southern Assets	3	2	3	-	2
Edson Assets	445	369	427	427	417
Total	1,231	1,075	1,170	1,270	1,187
Total (Boe/d)
Central Alberta Assets	9,936	9,849	9,747	10,042	9,894
Southern Assets	7,508	7,547	7,536	7,517	7,527
Edson Assets	1,725	1,572	1,473	1,571	1,585
Total	19,169	18,968	18,756	19,130	19,006

Lease Holdings

	Developed Acres		Undeveloped Acres		Total
	Gross	Net	Gross	Net	Gross	Net
Area:
Viking	623,452	534,019	87,253	62,038	710,706	596,057
Ghost Pine	402,804	313,818	14,034	9,658	416,838	323,476
Pendor/Black Butte	309,380	293,831	10,080	8,445	319,460	302,276
Many Islands/Long Valley	226,558	219,553	4,999	4,759	231,557	224,313
Hatton	128,325	116,546	82,063	14,662	210,388	131,208
Tilley/Monogram	173,318	63,330	-	-	173,318	63,330
Edson	84,640	39,452	24,960	5,835	109,600	45,287
Eagle Butte	49,523	49,523	2	2	49,525	49,525
Wymark/Vidora	43,537	39,147	2,240	2,240	45,777	41,387
Other	93,123	84,332	6,080	4,653	99,203	88,986
Total	2,134,661	1,753,554	231,712	112,292	2,366,373	1,865,845

Pine Cliff's December 31, 2020 holdings of petroleum and natural gas leases and rights are as follows:

There are no attributed reserves assigned to 45,577 gross (41,387 net) acres in the Wymark/Vidora area. The Company has interests in 480 gross (184 net) acres that will expire within one year.

MINING ASSETS

Through its non-material wholly-owned subsidiary, Geomark, Pine Cliff holds mining assets, including certain mineral leases and claims located in Ontario, the Northwest Territories, Nunavut and Utah. None of the mineral leases and claims are presently material to Pine Cliff from an accounting or securities perspective. The Company does not plan to incur any capital expenditures on the properties in 2021.

DESCRIPTION OF THE BUSINESS

Competition

The oil and natural gas industry is competitive in all the respective phases. Pine Cliff competes with numerous other participants in the search acquisition and exploitation of, oil and natural gas properties and in the production and marketing of oil and natural gas. Pine Cliff's competitors include resource companies which have greater financial resources, staff and facilities than those of Pine Cliff which could give them a competitive advantage. Competitive factors in the distribution and marketing of oil and natural gas include price, and methods and reliability of delivery. Pine Cliff believes that its competitive position is equivalent to that of companies of similar size and at a similar stage of development. See "Risk Factors".

Seasonality and Climate

The level of activity in the Canadian oil and gas industry is influenced by seasonal weather patterns. A mild winter or wet spring may result in limited access and, as a result, reduced operations or a cessation of operations.

Municipalities and provincial transportation departments enforce road bans that restrict the movement of drilling rigs and other heavy equipment during periods of wet weather, 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 Pine Cliff. See "Risk Factors".

Environmental Regulation

The oil and natural gas industry is currently subject to environmental regulations pursuant to a variety of municipal, provincial and federal legislation. Compliance with such legislation can 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. See "Risk Factors".

Personnel

As at December 31, 2020, Pine Cliff had 31 full-time employees at its head office and 51 full-time employees in the field. Pine Cliff has also entered into various contracting and consulting agreements with individuals to assist in the conduct of its business.

Specialized Skills and Knowledge

Pine Cliff believes that its success is dependent on the performance of its management and key employees, all of whom have specialized knowledge and skills relating to oil and natural gas operations. Pine Cliff believes it has, or will be able to attract, adequate personnel with the specialized skills required to successfully carry out its operations but the failure to attract or retain such personnel could have a material adverse impact on its business. See "Risk Factors".

Bankruptcies and Reorganizations

There has not been any bankruptcy, receivership or similar proceedings against Pine Cliff or any of its subsidiaries, or any voluntary bankruptcy, receivership or similar proceedings by Pine Cliff or any of its subsidiaries, within the three most recently completed financial years or during or proposed for the current financial year. There has not been any material reorganization of Pine Cliff as a whole or any of its subsidiaries within the three most recently completed financial years or completed during or proposed for the current financial year.

INDUSTRY CONDITIONS

Production and Operation Regulations

The oil and natural gas industry is subject to extensive controls, laws and regulations imposed by various levels of government. These laws and regulations may be changed in response to economic or political conditions, and regulate among other things, land tenure and the exploration, development, production, handling, storage, transportation, and disposal of oil and gas, oil and gas by-products, and other substances and materials produced or used in connection with oil and gas operations. While it is not expected that any of these controls or regulations will affect the operations of the Company in a manner materially different than they would affect other oil and gas corporations of similar size, the controls and regulations should be considered carefully by investors. All current legislation is a matter of public record and the Company 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 in Canada

Crude Oil

In Canada, the producers of oil are entitled to negotiate sales contracts directly with oil purchasers. As a result, macroeconomic and microeconomic market forces determine the price of crude oil. Oil prices are primarily based on worldwide supply and demand; however, regional market and transportation issues also influence prices. Specific prices depend in part on oil quality, prices of competing fuels, distance to market, access to downstream transportation, value of refined products, length of contract term, weather conditions, the balance of supply and demand and other contractual terms.

In 2020, worldwide oversupply of crude oil, a lack of available storage capacity and decreased demand due to the Novel Coronavirus ("COVID-19") have had a significant impact on the pricing of crude oil. In an effort to stabilize global oil markets, the Organization of the Petroleum Exporting Countries ("OPEC") and a number of other oil producing countries announced an agreement to cut crude oil production by approximately 10 million Bbl/d in April 2020, which has been amended and adjusted throughout 2020 and early 2021 and remains subject to additional modification and uncertainty.

Natural Gas

Negotiation between buyers and sellers determines the price of natural gas sold in intra-provincial, interprovincial and international trade. The price received by a natural gas producer depends, in part, on the price of competing natural gas supplies and other fuels, natural gas quality, distance to market, availability of transportation, length of contract term, weather conditions, supply and demand balance and other contractual terms. Spot and future prices can also be influenced by supply and demand fundamentals on various trading platforms.

Natural Gas Liquids

The pricing of condensates and other NGLs such as ethane, butane, propane and pentane plus sold in intra-provincial, interprovincial and international trade is determined by negotiation between buyers and sellers. Such prices depend, in part, on the quality of the NGL, price of competing chemical stock, distance to market, access to downstream transportation, length of contract term, supply and demand balance and other contractual terms.

Exports from Canada

On August 28, 2019, Bill C-69 came into force, replacing, among other things, the National Energy Board Act (the "NEB Act") with the Canadian Energy Regulator Act (the "CERA"), the Canadian Environmental Assessment Act, 2012 with the Impact Assessment Act (the "IAA") and replacing the National Energy Board (the "NEB") with the CER. The CER has assumed the NEB's responsibilities broadly, including with respect to the export of crude oil, natural gas and NGL from Canada. The legislative regime relating to exports of crude oil, natural gas and NGL from Canada has not changed substantively under the new regime.

Exports of crude oil, natural gas and NGL from Canada are subject to CERA and remain subject to the National Energy Board Act Part VI (Oil and Gas) Regulation (the "Part VI Regulation") until such time as the Part VI Regulation is replaced. The CERA and the Part VI Regulation authorize crude oil, natural gas and NGL exports under either short-term orders or long-term licences. For natural gas, the maximum duration of an export licence is 40 years; for crude oil and other gas substances (e.g., NGL), the maximum term is 25 years. To obtain a crude oil export licence, a mandatory public hearing with the CER is required; however, there is no public hearing requirement for the export of natural gas and NGL. Instead, the CER will continue to apply the NEB's written process that includes a public comment period for impacted persons. Following the comment period, the CER completes its assessment of the application and either approves or denies the application. The CER can approve an application if it is satisfied that proposed export volumes are not greater than Canada's reasonably foreseeable needs, and if the proposed exporter is in compliance with the CERA and all associated regulations and orders made under the CERA. Following the CER's approval of an export license, the federal Minister of Natural Resources is mandated to give his or her final approval. While the Part VI Regulation remains in effect, approval of the cabinet of the Canadian federal government ("Cabinet") is also required. The discretion of the Minister of Natural Resources and Cabinet will be framed by the Minister of Natural Resources' mandate to implement the CERA safely and efficiently, as well as the purpose of the CERA, to effect "oil and natural gas exploration and exploitation in a manner that is safe and secure and that protects people, property and the environment".

Orders from the CER provide a short-term alternative to export licenses and may be issued more expediently, since they do not require a public hearing (in the case of crude oil) or approval from the cabinet of the Canadian federal government. Orders are issued pursuant to the Part VI Regulation for up to one or two years depending on the substance, with the exception of natural gas (other than NGLs) for which an order may be issued for up to twenty years for quantities not exceeding 30,000 m3 per day.

As to price, exporters are free to negotiate prices and other terms with purchasers, provided that the export contracts continue to meet certain other criteria prescribed by the CER and the federal government. The Company does not directly enter into contracts to export its production outside of Canada.

As discussed in more detail below, one major constraint to the export of crude oil, natural gas and NGLs outside of Canada is the deficit of overall pipeline and other transportation capacity to transport production from Western Canada to the United States and other international markets. Although certain pipeline and other transportation projects are underway, many contemplated projects have been cancelled or are delayed due to regulatory hurdles, court challenges and economic and other socio-political factors. The transportation capacity deficit is not likely to be resolved quickly. Major pipeline and other transportation infrastructure projects typically require a significant length of time to complete once all regulatory and other hurdles have been cleared. In addition, production of crude oil, natural gas and NGLs in Canada is expected to continue to increase, which may further exacerbate the transportation capacity deficit.

Transportation Constraints, Pipeline Capacity and Market Access

Producers negotiate with pipeline operators (or other transport providers) to transport their products to market on a firm or interruptible basis. Transportation availability is highly variable across different areas and regions. This variability can determine the nature of transportation commitments available, the number of potential customers that can be reached in a cost-effective manner and the price received. Due to growing production and a lack of new and expanded pipeline and rail infrastructure capacity, producers in Western Canada have experienced low commodity pricing relative to other markets in the last several years.

Under the Canadian constitution, interprovincial and international pipelines fall within the federal government's jurisdiction and, under the CERA, new interprovincial and international pipelines will require a federal regulatory review and approval by Cabinet. However, recent years have seen a perceived lack of policy and regulatory certainty such that, even when projects are approved, they often face delays due to actions taken by provincial and municipal governments. Additional delays causing further uncertainty result from legal opposition related to issues such as Indigenous rights and title, the government's duty to consult and accommodate Indigenous peoples, and the sufficiency of all relevant environmental review processes. Export pipelines from Canada to the United States face additional unpredictability as such pipelines require approvals of several levels of government in the United States.

In the face of this regulatory uncertainty, the Canadian oil and natural gas industry has experienced significant difficulty expanding the existing network of transportation infrastructure for crude oil, natural gas and NGLs, including pipelines, rail, trucks and marine transport. Improved access to global markets, especially the Midwest United States and export shipping terminals on the west coast of Canada, could help to alleviate the downward pressures affecting commodity prices. Several proposals have been announced to increase pipeline capacity out of Western Canada to reach Eastern Canada, the United States and international markets via export terminals. While certain projects are proceeding, the regulatory approval process and other economic and socio-political factors related to transportation and export infrastructure has led to the delay, suspension or cancellation of many pipeline projects.

With respect to the current state of the transportation and exportation of crude oil from Western Canada to domestic and international markets, the Enbridge Line 3 Replacement from Hardisty, Alberta, to Superior, Wisconsin, formerly expected to be in-service in late 2019, continues to experience permitting difficulties in the United States and completion of the United States portion of the pipeline replacement has been delayed following the announcement that the Minnesota Pollution Control Agency will require a public hearing concerning a key water permit. It is now expected that most of the construction work on the United States portion of the pipeline replacement will happen in 2021. The Canadian portion of the replaced pipeline began commercial operation on December 1, 2019.

The proposed Trans Mountain Pipeline expansion received Cabinet approval in November 2016. Following a period of sustained political opposition in British Columbia, the Federal government entered into an agreement with Kinder Morgan Cochin ULC in May 2018 to purchase the shares and units of the entities that own and operate the Trans Mountain Pipeline system. The Shareholders subsequently voted to approve the transaction in August 2018. However, the Trans Mountain Pipeline expansion experienced a setback when, in August 2018, the Federal Court of Appeal identified deficiencies in the NEB's environmental assessment and the federal government's indigenous consultations. The Court quashed the accompanying certificate of public convenience and necessity and directed Cabinet to correct these deficiencies. Following a reconsideration by the NEB and enhanced consultation efforts led by the federal government, Cabinet reapproved the Trans Mountain Pipeline expansion. Subsequent challenges to the approval were rejected by the Federal Court of Appeal in February 2020 and the Supreme Court of Canada in July 2020.

In addition, on April 25, 2018, the Government of British Columbia submitted a reference question to the British Columbia Court of Appeal, seeking to determine whether it has the constitutional jurisdiction to amend the Environmental Management Act (the BC EMA) to impose a permitting requirement on carriers of heavy crude oil within British Columbia. The British Columbia Court of Appeal answered the reference questions unanimously in the negative, and on January 16, 2020, the Supreme Court of Canada heard the Attorney General of British Columbia's appeal. The Supreme Court unanimously dismissed the appeal and adopted the reasons of the British Columbia Court of Appeal.

Construction commenced on the Trans Mountain Pipeline expansion in late 2019 and it is expected to be in-service in late 2022.

TC Energy's Keystone XL Pipeline was expected to begin construction in the first half of 2019, but pre-construction work was halted in late 2018 when a U.S. Federal Court Judge determined the underlying environmental review was inadequate. The United States Department of State issued its final supplemental environmental impact statement in late 2019, and in January 2020, the United States Government announced its approval of a right-of-way that would allow the Keystone XL Pipeline to cross 74 kilometers of federal land. On March 31, 2020, TC Energy announced it would proceed with the Keystone XL Pipeline. TC Energy also announced that the Government of Alberta had made a US $1.1 billion equity investment in the project and would guarantee a US $4.2 billion project level credit facility.

While construction on the Keystone XL Pipeline started in April 2020, the Keystone XL Pipeline remained subject to legal and regulatory barriers in the United States. In December 2019, a federal judge in Montana rejected the United States Government's request to dismiss a lawsuit by Native American tribes attempting to block certain permits and on April 15, 2020, a Montana judge ruled against the U.S. Army Corps of Engineers' use of a national permit for water crossings in the United States (Nationwide Permit 12). The United States Court of Appeals for the Ninth Circuit refused to stay the ruling. While the Supreme Court of the United States subsequently reinstated Nationwide Permit 12 in July 2020, it determined that the reinstatement would not apply to the Keystone XL Pipeline.

On January 20, 2021, Mr. Joseph Biden was sworn in as the 46th President of the United States, following which the Biden administration announced its decision to revoke the federal permit granted by the previous administration for the Keystone XL Pipeline, which has overturned a comprehensive regulatory process that lasted more than a decade. As a result of the revocation, TC Energy has indicated that they have suspended advancement of the Keystone XL Pipeline project while it reviews the decision, assesses the implications of the decision and considers its options.

Curtailment

On December 2, 2018, the Government of Alberta announced that, commencing January 1, 2019, it would mandate a shortterm reduction in provincial crude oil and crude bitumen production. As contemplated in the Curtailment Rules, as amended effective October 1, 2019, the Government of Alberta can, on a monthly basis, subject oil producers producing more than 20,000 Bbl/d to curtailment orders that limit their production according to a pre-determined formula that allocates production limits proportionately amongst all operators subject to curtailment orders.

Where an operator to whom a curtailment order applies is a joint venture or partnership, the partners or joint venturers may enter into an agreement respecting the allocation of the combined production among themselves to comply with the curtailment order.

Curtailment first took effect on January 1, 2019, limiting province-wide production of crude oil and crude bitumen to 3.56 million Bbl/d. The curtailment rate dropped gradually over the course of 2019 and was set at 3.81 million Bbl/d through 2020. As of January 2021, monthly oil production limits are no longer in effect. However, the Curtailment Rules, which were set to be repealed on December 31, 2020, have been extended so that the Government of Alberta retains the ability to impose production limits if needed.

NAFTA/USMCA and Other Trade Agreements

The North American Free Trade Agreement ("NAFTA") that previously existed among the governments of Canada, the United States and Mexico has been replaced by a new trade agreement, widely referred to as the United States Mexico Canada Agreement (the "USMCA") and sometimes referred to as the Canada United States Mexico Agreement or CUSMA. The USMCA came into force on July 1, 2020. Because the United States remains Canada's primary trading partner and the largest international market for the export of crude oil, natural gas and NGL from Canada, the implementation of the USMCA could have an impact on Western Canada's petroleum and natural gas industry at large, including the Company's business.

While the proportionality rules in Article 605 of NAFTA previously prevented Canada from implementing policies that limit exports to the United States and Mexico relative to the total supply produced in Canada, the USMCA does not contain the same proportionality requirements. This may allow Canadian producers to develop a more diversified export portfolio than was possible under NAFTA, subject to the construction of infrastructure allowing more Canadian production to reach other international markets.

Canada has also pursued a number of other international free trade agreements with other countries around the world and, as a result, a number of free trade or similar agreements are in force between Canada and certain other countries. Canada and the European Union recently agreed to the Comprehensive Economic and Trade Agreement ("CETA"), which provides for duty-free, quota-free market access for Canadian oil and gas products to the European Union. Although CETA remains subject to ratification by certain national legislatures in the European Union, provisional application of CETA commenced on September 21, 2017. In light of the United Kingdom's departure from the European Union ("Brexit") on January 31, 2020, the United Kingdom and Canada have reached an interim post-Brexit trade agreement, the Canada-United Kingdom Trade Continuity Agreement ("CUKTCA"). On December 9, 2020, the Government of Canada introduced Bill C-18, an Act to Implement the Trade Continuity Agreement. CETA ceased to apply to Canada-United Kingdom trade on January 1, 2021. The CUKTCA replicates CETA on a bilateral basis and is meant to maintain the status quo of the Canada-United Kingdom trade relationship.

Canada and ten other countries have agreed on the text of the Comprehensive and Progressive Agreement for Trans-Pacific Partnership ("CPTPP"), which is intended to allow for preferential market access among the countries that are parties to the CPTPP. The CPTPP is in force among the first seven countries to ratify the agreement: Canada, Australia, Japan, Mexico, New Zealand, Vietnam, and Singapore.

While it is uncertain what effect CETA, CPTPP, CUKTCA or any other trade agreements will have on the oil and gas industry in Canada, the lack of available infrastructure for the offshore export of oil and gas may limit the ability of Canadian oil and gas producers to benefit from such trade agreements.

Royalties and Incentives

General

In addition to federal regulation, each province has legislation and regulations which govern royalties, production rates and other matters. The royalty regime in a given province is a significant factor in the profitability of crude oil, natural gas liquids, sulphur and natural gas production. Royalties payable on production from lands other than Crown lands are determined by negotiations between the mineral owner and the lessee, although production from such lands is subject to certain provincial taxes and royalties. Crown royalties are determined by governmental regulation and are generally calculated as a percentage of the value of the gross production. The rate of royalties payable generally depends in part on prescribed reference prices, well productivity, geographical location, field discovery date 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 have established incentive programs for exploration and development. Such programs often provide for royalty reductions, credits and holidays, and are generally introduced when commodity prices are low to encourage exploration and development activity. Additional programs may be introduced to

encourage producers to prioritize certain kinds of development or undertake initiatives using new technologies that may enhance or improve recovery of crude oil, natural gas and NGLs or improve environmental performance.

The federal government also creates incentives and other financial aid programs intended to assist businesses operating in the petroleum and natural gas industry. Recently, these programs, including, but not limited to, programs that provide direct financial support to companies operating in the petroleum and natural gas industry and/or targeted funding for various initiatives related to industry diversification and environmental matters, including those programs created in response to the COVID-19 pandemic, have been administered through federal agencies such as the Business Development Bank of Canada, Natural Resources Canada, Export Development Canada, and Innovation, Science and Economic Development Canada.

Producers and working interest owners of crude oil and natural gas rights may also carve out additional royalties or royaltylike interests through non-public transactions, which include the creation of instruments such as overriding royalties, net profits interests and net carried interests.

Alberta - Royalties

In terms of oil or natural gas production from Crown lands, royalties are payable to the Province of Alberta. In respect of freehold lands, royalties are payable to the mineral owner and taxes are payable to the Province of Alberta. The Government of Alberta's approach to the royalty and tax regime is regularly reviewed for compliance with the purpose of the regimes; to ensure that Albertans are receiving a fair share from energy development through royalties, taxes and fees.

On January 29, 2016, the Government of Alberta released and accepted the Royalty Review Advisory Panel's recommendations, which outlined the implementation of Modernized Royalty Framework for Alberta ("MRF"). The MRF formally took effect on January 1, 2017 for new wells drilled after this date. The previous royalty framework (the "Old Framework") will continue to apply to wells drilled prior to January 1, 2017 for a period of ten years ending on December 31, 2026. After the expiry of this ten-year period, these older wells will become subject to the Modernized Framework. On July 12, 2016, the Government of Alberta announced that producers could apply for early adoption of the MRF in respect of wells spud between July 13, 2016 and December 31, 2016. As of January 1, 2027, these older wells will become subject to the Modernized Framework. The Royalty Guarantee Act (Alberta), which came into effect on July 18, 2019, provides that no major changes will be made to the current crude oil and natural gas royalty structure for a period of at least 10 years.

The MRF applies to all hydrocarbons other than oil sands which will remain subject to their existing royalty regime. Royalties on production from non-oil sands wells under the MRF is determined on a "revenue-minus-costs" basis with the cost component based on a drilling and completion cost allowance formula for each well, depending on its vertical depth and horizontal length. The formula is based on the industry's average drilling and completion costs as determined by the Alberta Energy Regulator ("AER") on an annual basis.

Producers pay a flat royalty rate of five percent of gross revenue from each well that is subject to the Modernized Framework until the well reaches payout. Payout for a well is the point at which cumulative gross revenues from the well equals the Drilling and Completion Cost Allowance for the well set by the AER. After payout, producers pay an increased post-payout royalty on revenues determined by reference to the then current commodity prices of the various hydrocarbons. Similar to the Old Framework, the post-payout royalty rate under the Modernized Framework varies with commodity prices. Once production in a mature well drops below a threshold level where the rate of production is too low to sustain the full royalty burden, its royalty rate is adjusted downward as the mature well's production declines.

As the MRF uses deemed drilling and completion costs in calculating the royalty and not the actual drilling and completion costs incurred by a producer, low cost producers benefit if their well costs are lower than the drilling and completion cost allowance and, accordingly, they continue to pay the lower 5% royalty rate for a period of time after their wells achieve actual payout.

The Old Framework is applicable to all conventional oil and natural gas wells drilled prior to January 1, 2017 and bitumen production. Subject to certain available incentives, effective from the January 2011 production month, royalty rates for conventional oil production under the Old Framework range from a base rate of 0% to a cap of 40%. The Old Framework also includes a natural gas royalty formula which provides for a reduction based on the measured depth of the well below

2,000 metres deep, as well as the acid gas content of the produced gas. Subject to certain available incentives, effective from the January 2011 production month royalty rates for natural gas production under the Old Framework range from a base rate of 5% to a cap of 36%. Under the Old Framework, the royalty rate applicable to natural gas liquids is a flat rate of 40% for pentanes and 30% for butanes and propane.

The Government of Alberta has from time to time implemented drilling credits, incentives or transitional royalty programs to encourage crude oil and natural gas development and new drilling. In addition, the Government of Alberta has implemented certain initiatives intended to accelerate technological development and facilitate the development of unconventional resources, including as applied to coalbed methane wells, shale gas wells and horizontal crude oil and natural gas wells. In addition to royalties, producers of crude oil and natural gas from Crown lands in Alberta are also required to pay annual rental payments, at a rate of $3.50 per hectare.

Royalty rates for the production of privately-owned crude oil and natural gas are negotiated between the producer and the resource owner.

Freehold mineral taxes are levied annually for production from freehold mineral lands. On average, the tax levied in Alberta is 4% of revenues reported from freehold mineral title properties. Freehold mineral taxes are in addition to any other negotiated royalty or other payment required to be paid to the owner of such freehold mineral rights.

Saskatchewan - Royalties

The amount payable as a royalty with respect to oil depends on the type and vintage of the oil, the quality of the oil produced in the month and the value of the oil determined monthly by the provincial government. Each month, royalty rates are adjusted based on reference prices established by the Province for each type of oil. There are separate reference prices established for each type of oil (heavy oil, Southwest designated oil, or non-heavy oil other than Southwest designated oil) which represents the average well head price received by producers during the month for sales of that oil type in Saskatchewan.

The Government of Saskatchewan has introduced the Oil and Gas Orphan Fund, funded by oil and gas companies to cover the cost of cleaning up abandoned wells and facilities where the owner cannot be located or has gone out of business. The program is composed of a security deposit, based upon a formula considering assets of the well and the facility licensee against the estimated cost of decommissioning the well and facility once it is no longer producing, and an annual levy assessed to each licensee.

The Government of Saskatchewan currently provides a number of targeted incentive programs. These include both royalty reduction and incentive volume programs, with targeted programs in effect for certain vertical crude oil wells, exploratory gas wells, horizontal crude oil and natural gas wells, enhanced crude oil recovery wells and high water-cut crude oil wells.

For production from freehold lands, producers must pay a freehold production tax, determined by first determining the Crown royalty rate, and then subtracting a calculated production tax factor. Depending on the classification of the petroleum substance produced, this subtraction factor may range between 6.9 and 12.5, however, in certain circumstances, the minimum rate for freehold production tax can be zero. This means that the ultimate tax payable to the Crown by producers on freehold lands will vary based on the underlying characteristics of the producer's assets.

Freehold and Other Types of Non-Crown Royalties

Royalties on production from privately-owned freehold lands are negotiated between the mineral freehold owner and the lessee under a negotiated lease or other contract. Producers and working interest participants ("WIP") may also pay additional royalties to parties other than the mineral freehold owner where such royalties are negotiated through private transactions.

In addition to the royalties payable to the mineral owners (or to other royalty holders if applicable), producers of crude oil and natural gas from freehold lands in each of the Western Canadian provinces are required to pay freehold mineral taxes or production taxes. Freehold mineral taxes or production taxes are taxes levied by a provincial government on crude oil and natural gas production from lands where the Crown does not hold the mineral rights. A description of the freehold

mineral taxes payable in each of the Western Canadian provinces is included in the above descriptions of the royalty regimes in such provinces.

Indian Oil and Gas Canada (the "IOGC") is a special agency responsible for managing and regulating the crude oil and natural gas resources located on indigenous reservations across Canada. IOGC's responsibilities include negotiating and issuing the crude oil and natural gas agreements between indigenous groups and crude oil and natural gas companies, as well as collecting royalty revenues on behalf of indigenous groups and depositing the revenues in their trust accounts. While certain standards exist, the exact terms and conditions of each crude oil and natural gas lease dictate the calculation of royalties owed, which may vary depending on the involvement of the specific indigenous group. Ultimately, the relevant indigenous group must approve the terms.

Regulatory Authorities and Environmental Regulation

The Canadian 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. The regulatory regimes set out the requirements with respect to oilfield waste handling and storage, habitat protection and the satisfactory operation, maintenance, abandonment and reclamation of well, facility and pipeline sites. Compliance with such legislation can require significant expenditures and a breach of such requirements may result in suspension or revocation of necessary licences and authorizations, civil liability and the imposition of material fines and penalties. In addition to these specific, known requirements, future changes to environmental legislation, including anticipated legislation for air pollution and greenhouse gas ("GHG") emissions, may impose further requirements on operators and other companies in the oil and natural gas industry.

Pine Cliff has established internal guidelines to be followed in order to comply with environmental laws and regulations in the jurisdictions in which the Company operates. The Company ensures that our operations are carried out in accordance with applicable environmental guidelines and safety precautions. Although the Company maintains pollution insurance against the costs of cleanup operations, public liability, and physical damage, there is no assurance that such insurance will be adequate to cover all such costs or that such insurance will continue to be available in the future.

Federal

Canadian environmental regulation is the responsibility of the federal government and provincial governments. Where there is a direct conflict between federal and provincial environmental legislation in relation to the same matter, the federal law will prevail, however, such conflicts are uncommon. The federal government has primary jurisdiction over federal works, undertakings and federally regulated industries such as railways, aviation and interprovincial transport including interprovincial pipelines. The Canadian Environmental Protection Act, 1999 and the Canadian Environmental Assessment Act, 2012 provide the foundation for the federal government to protect the environment and cooperate with provinces to do the same.

On August 28, 2019, with the passing of Bill C-69, the CERA and the Impact Assessment Act ("IAA") came into force and the NEB Act and the Canadian Environmental Assessment Act, 2012 ("CEAA 2012") were repealed. In addition, the IA Agency replaced the Canadian Environmental Assessment Agency ("CEA Agency").

Bill C-69 introduced a number of important changes to the regulatory regime for federally regulated major projects and associated environmental assessments. Previously, the NEB administered its statutory jurisdiction as an integrated regulatory body. Now, the CERA separates the CER's administrative and adjudicative functions. A board of directors and a chief executive officer will manage strategic, administrative and policy considerations while adjudicative functions will fall into the purview of a group of independent commissioners. The CER has assumed the jurisdiction previously held by the NEB over matters such as the environmental and economic regulation of pipelines, transmission infrastructure and offshore renewable energy projects, including offshore wind and tidal facilities. In its adjudicative role, the CERA tasks the CER with reviewing applications for the development, construction and operation of these projects, culminating in their eventual abandonment.

Designated projects will require an impact assessment as part of their regulatory review. The impact assessment, conducted by a review panel, jointly appointed by the CER and the IA Agency, includes expanded criteria the review panel may consider when reviewing an application. The impact assessment also requires consideration of the project's potential adverse effects, the overall societal impact and the expanded public interest that a project may have. The IA Agency must look at the direct result of the project's construction and operation, including environmental, biophysical and socio-economic factors, including consideration of a gender-based analysis, climate change, and impacts to Indigenous rights. Designated projects include pipelines that require more than 75 kilometres of new right of way and pipelines located in national parks. Large scale in situ oil sands projects not regulated by provincial greenhouse gas emissions and certain refining, processing and storage facilities will also require an impact assessment.

The federal government has stated that an objective of the legislative changes was to improve decision certainty and turnaround times. Once a review or assessment is commenced under either the CERA or IAA, there are limits on the amount of time the relevant regulatory authority will have to issue its report and recommendation. Designated projects will go through a planning phase to determine the scope of the impact assessment, which the federal government has stated should provide more certainty as to the length of the full review process. Applications for non-designated projects will follow a similar process as under the NEB Act. There is significant uncertainty surrounding the impact of Bill C-69 on oil and natural gas projects. There was significant opposition from industry and others in respect of Bill C-69, and notwithstanding its stated purpose, there is concern that the changes brought about by Bill C-69 will result in projects not being approved or increased delays in approvals. The Government of Alberta has submitted a reference question to the Alberta Court of Appeal regarding the constitutionality of the IAA and the hearing is expected to take place in the first half of 2021.

Alberta

The discharge of crude 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 Company to incur costs to remedy such discharge in the event that they are not covered by Pine Cliff's insurance. Although the Company maintains insurance to industry standards, which in part covers liabilities associated with discharges, it is not certain that such insurance will cover all possible environmental events, foreseeable or otherwise, or whether changing regulatory requirements or emerging jurisprudence may render such insurance of little benefit. In addition to these specific, known requirements, future changes to environmental legislation, including anticipated legislation for air pollution and GHG emissions, may impose further requirements on operators and other companies in the oil and natural gas industry.

The AER is the single regulator responsible for all energy resource development in Alberta. It derives its authority from the Responsible Energy Development Act and a number of related Acts including the Oil and Gas Conservation Act (the "OGCA"), the Oil Sands Conservation Act, the Pipeline Act, and the Environmental Protection and Enhancement Act. The AER is responsible for ensuring the safe, efficient, orderly and environmentally responsible development of hydrocarbon resources including allocating and conserving water resources, managing public lands, and protecting the environment. The AER's responsibilities exclude the functions of the Alberta Utilities Commission and the Surface Rights Board, as well as Alberta Energy's responsibility for mineral tenure. The objective behind a single regulator is an enhanced regulatory regime that is intended to be efficient, attractive to business and investors and effective in supporting public safety, environmental management and resource conservation while respecting the rights of landowners.

The Government of Alberta relies on regional planning to accomplish its responsible resource development goals. Its approach to natural resource management provides for engagement and consultation with stakeholders and the public and examines the cumulative impacts of development on the environment and communities by incorporating the management of all resources, including energy, minerals, land, air, water and biodiversity. While the AER is the primary regulator for energy development, several other governmental departments and agencies may be involved in land use issues, including Alberta Environment and Parks, Alberta Energy, the Policy Management Office, the Aboriginal Consultation Office and the Land Use Secretariat.

The Government of Alberta's land-use policy for surface land in Alberta sets out an approach to manage public and private land use and natural resource development in a manner that is consistent with the long-term economic, environmental and social goals of the province. It calls for the development of seven region-specific land-use plans in order to manage the combined impacts of existing and future land use within a specific region and the incorporation of a cumulative effect

management approach into such plans. As a result, several regional plans have been implemented and others are in the process of being implemented. These regional plans may affect further development and operations in such regions.

The AER monitors seismic activity across Alberta to assess the risks associated with, and instances of, increased seismicity induced by hydraulic fracturing. Hydraulic fracturing involves the injection of water, sand or other proppants and additives under pressure into targeted subsurface formations to fracture the surrounding rock and stimulate crude oil and natural gas production. In recent years, hydraulic fracturing has been linked to increased seismicity in the areas in which hydraulic fracturing takes place, prompting regulatory authorities to investigate the practice further.

The AER has developed monitoring and reporting requirements that apply to all crude oil and natural gas producers working in certain areas where the likelihood of increased seismic activity is higher, and implemented the requirements in Subsurface Order Nos. 2, 6 and 7. The regions with seismic protocols in place are Fox Creek, Red Deer, and Brazeau (the Seismic Protocol Regions). Crude oil and natural gas producers in each of the Seismic Protocol Regions are subject to a "traffic light" reporting system that sets thresholds on the Richter scale of earthquake magnitude. The thresholds vary among the Seismic Protocol Regions, and trigger a sliding scale of obligations from the crude oil or natural gas producers operating there. Such obligations range from no action required, to informing the AER and invoking an approved response plan, to ceasing operations and informing the AER. The AER has the discretion to suspend operations while it investigates following a seismic event until it has assessed the ongoing risk in a specific area and/or may require the operator to update its response plan. The AER may extend these requirements to other areas of Alberta if necessary, subject to the results of its ongoing provincewide monitoring.

Saskatchewan

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

Liability Management Rating Programs

Alberta

The AER administers the licensee Liability Management Rating Program (the "AB LMR Program"). The AB LMR Program is a liability management program governing most conventional upstream crude oil and natural gas wells, facilities and pipelines. It consists of three distinct programs: the Licensee Liability Rating Program (the "AB LLR Program"), the Oilfield Waste Liability Program (the "AB OWL Program") and the Large Facility Liability Management Program (the "AB LFP"). At its core, the AER uses the AB LMR Program to aid in determining the ability of licensees to manage the abandonment and reclamation obligations associated with the licensee's assets. If a licensee's deemed liabilities in the AB LLR Program, the AB OWL Program and/or the AB LFP exceed its deemed assets in those programs, the AB LMR Program requires the licensee to provide the AER with a security deposit and may restrict the licensee's ability to transfer licenses. This ratio of a licensee's assets to liabilities across the three programs is referred to as the licensee's liability management rating ("LMR"). Where the AER determines that a security deposit is required, the failure to post any required amounts may result in the initiation of enforcement action by the AER.

The AER previously assessed the LMR of all licensees on a monthly basis and posted the individual ratings on the AER's public website. However, in December 2019 the AER ceased posting the detailed LMR report, stating that resource and budget

limitations have impacted its ability to maintain and administer the AB LMR Program. Licensees can continue to access their individual LMR calculations through the AER's Digital Data Submission System, but they do not have access to other licensees' LMR.

Complementing the AB LMR Program, Alberta's OGCA establishes an orphan fund (the "Orphan Fund") to help pay the costs to suspend, abandon, remediate and reclaim a well, facility or pipeline included in the AB LLR Program and the AB OWL Program if a licensee or WIP becomes insolvent or is unable to meet its obligations. Licensees in the AB LLR Program and AB OWL Program fund the Orphan Fund through a levy administered by the AER. A separate orphan levy applies to persons holding licenses subject to the AB LFP. Collectively, these programs are designed to minimize the risk to the Orphan Fund posed by the unfunded liabilities of licensees and to prevent the taxpayers of Alberta from incurring costs to suspend, abandon, remediate and reclaim wells, facilities or pipelines.

As a result of the Supreme Court of Canada's decision in Orphan Well Association v Grant Thornton (also known as the Redwater decision), receivers and trustees can no longer avoid the AER's legislated authority to impose abandonment orders against licensees or to require a licensee to pay a security deposit before approving a transfer when such a licensee is subject to formal insolvency proceedings. This means that insolvent estates can no longer disclaim assets of a bankrupt licensee that have reached the end of their productive lives and represent a liability while dealing with the company's valuable assets for the benefit of the company's creditors without first satisfying abandonment and reclamation obligations. In April 2020, the Government of Alberta passed Bill 12: The Liabilities Management Statutes Amendment Act. Bill 12 places the burden of a defunct licensees' abandonment and reclamation obligations first on the defunct licensee's working interest partners, and second, the AER may order the Orphan Fund to assume care and custody and accelerate the clean-up of wells or sites which do not have a responsible owner. Bill 12 will come into force on proclamation.

In response to the increase in orphaned crude oil and natural gas sites and the environmental risks associated therewith, the AER issued several bulletins and interim rule changes to govern the AER's administration of its licensing and liability management programs. The AER amended its Directive 067: Eligibility Requirements for Acquiring and Holding Energy Licences and Approvals, which deals with licence eligibility to operate wells and facilities, to require the provision of extensive corporate governance and shareholder information, including whether any director and officer was a director or officer of an energy company that has been subject to insolvency proceedings in the last five years. All transfers of well, facility and pipeline licences in the province are subject to AER approval. As a condition of transferring existing AER licences, approvals and permits, all transfers are now assessed on a non-routine basis and the AER now requires all transferees to demonstrate that they have an LMR of 2.0 or higher immediately following the transfer, or to otherwise prove to the satisfaction of the AER that it can meet its abandonment and reclamation obligations.

Both the Government of Alberta and/or the AER may make further rule changes to Alberta's liability management programs at any time. For example, on July 30, 2020, the Government of Alberta announced a new Liability Management Framework ("AB LMF") that will replace the AB LLR Program and its constituent programs. Among other changes under the AB LMF, the AB LLR Program will be replaced with the Licensee Capability Assessment System, which is intended to be a more comprehensive assessment of corporate health and will consider a wider variety of factors than those considered under the AB LLR Program and will establish clear expectations for industry with regards to the management of liabilities throughout the entire lifecycle of crude oil and natural gas projects. Importantly, the AB LMF will also provide proactive support to distressed operators and will require companies operating in Alberta's petroleum and natural gas industry to make mandatory annual minimum payments towards outstanding reclamation obligations in accordance with five year rolling spending targets. It is not yet clear how or when then AB LMF will be implemented.

The AER has also implemented the Inactive Well Compliance Program (the "IWCP") to address the growing inventory of inactive wells in Alberta and to increase the AER's surveillance and compliance efforts under Directive 013: Suspension Requirements for Wells ("Directive 013"). The IWCP applies to all inactive wells that are noncompliant with Directive 013 as of April 1, 2015. The objective is to bring all inactive noncompliant wells under the IWCP into compliance with the requirements of Directive 013 within five years. As of April 1, 2015, each licensee is required to bring 20% of its inactive wells into compliance every year, either by reactivating or by suspending the wells in accordance with Directive 013 or by abandoning them in accordance with Directive 020: Well Abandonment.

As part of its strategy to encourage the decommissioning, remediation and reclamation of inactive or marginal crude oil and natural gas infrastructure, the AER announced a voluntary area-based closure ("ABC") program in 2018. The ABC program is designed to reduce the cost of abandonment and reclamation operations though industry collaboration and economies of scale. Participants seeking to participate in the program must commit to an inactive liability reduction target to be met through closure work of inactive assets.

Saskatchewan

The Ministry of the Economy administrates the Licensee Liability Rating Program (the "SK LLR Program"). The SK LLR Program is designed to assess and manage the financial risk that a licensee's well and facility abandonment and reclamation liabilities pose to the orphan fund (the "Oil and Gas Orphan Fund") established under the SKOGCA. The Oil and Gas Orphan Fund is responsible for carrying out the abandonment and reclamation of wells and facilities contained within the SK LLR Program when a licensee or WIP is defunct or missing. The SK LLR Program requires a licensee whose deemed liabilities exceed its deemed assets (i.e., an LLR of below 1.0) to post a security deposit. The ratio of deemed assets to deemed liabilities is assessed once each month for all licensees of crude oil, natural gas and service wells and upstream crude oil and natural gas facilities. On August 19, 2016, the Ministry of the Economy released a notice to all operators introducing interim measures in response to Redwater. Among other things, the Ministry announced that it considers all license transfer applications nonroutine as the Ministry does not strictly rely on the standard LMR calculation in evaluating deposit requirements, and that further changes may be forthcoming.

Federal and Provincial Support for Liability Management

As part of an announcement of federal relief for Canada's petroleum and natural gas industry in response to COVID-19, the federal government pledged $1.72 billion to clean up orphan and inactive wells in Alberta, Saskatchewan and British Columbia. However, these funds are being administered by regulatory authorities in each province. In Alberta, the Ministry of Energy is disbursing its $1 billion share of the federally provided funds through the Site Rehabilitation Program. The Government of British Columbia is disbursing its $120 million share of the federally provided funds through three programs: the Dormant Sites Reclamation Program, the Orphan Sites Supplemental Reclamation Program and the Legacy Sites Reclamation Program. In addition to the funds administered by the respective provincial governments, the federal government announced a $200 million loan to Alberta's Orphan Fund. And in early March 2020, the Government of Alberta announced an extension by up to $100 million of an existing $235 million loan to the Orphan Fund. In Saskatchewan, $400 million in federal funding will be allocated through the Accelerated Site Closure Program ("ASCP"). The first phase of the ASCP will make $100 million available to eligible service companies to conduct abandonment and reclamation work. Further tranches of the ASCP, up to $300 million, will be made available in the future.

Climate Change Regulation

Climate change regulation at both the federal and provincial level has the potential to significantly affect the regulation of the crude oil and natural gas industry in Canada. In general, there is some uncertainty with regard to the impacts of federal or provincial climate change and environmental laws and regulations, as it is currently not possible to predict the extent of future requirements. Any new laws and regulations, or additional requirements to existing laws and regulations, could have a material impact on the Company's operations and cash flow.

Federal

Canada has been a signatory to the United Nations Framework Convention on Climate Change (the "UNFCCC") since 1992. Since its inception, the UNFCCC has instigated numerous policy experiments with respect to climate governance. On April 22, 2016, 197 countries, including Canada, signed the Paris Agreement, committing to prevent global temperatures from rising more than 2° Celsius above pre-industrial levels and to pursue efforts to limit this rise to no more than 1.5° Celsius. To date, 189 of the 197 parties to the convention have ratified the Paris Agreement, including Canada. In December 2019, the United Nations annual Conference of the Parties took place in Madrid, Spain. The Conference concluded with the attendees delaying decisions about a prospective carbon market and emissions cuts until the next climate conference, scheduled to take place in November 2021.

The Government of Canada has pledged to cut its emissions by 30% from 2005 levels by 2030, but indicated in the recent Speech from the Throne (also referred to as the Throne Speech) that it may implement policy changes to exceed this target. Specific details have not yet been announced. In connection with this target, the Government of Canada released the PanCanadian Framework on Clean Growth and Climate Change in 2016, setting out a plan to meet the federal government's 2030 emissions reduction targets.

On December 11, 2020, the Government of Canada released its Healthy Environment and a Healthy Economy Plan (the "HEHE Plan") which builds on the Pan-Canadian Framework and provides a road map forward to meet Canada's 2030 emissions reduction target. The HEHE Plan includes a $3-billion investment over five years to a Net-Zero Accelerator Fund to invest in projects to decarbonize large emitters, scale-up clean technology and otherwise accelerate industry transformation across all sectors. In addition, the HEHE Plan proposes to invest an additional $964 million over four years towards renewable energy and grid modernization projects and $300 million over five years to advance the use of clean and reliable energy in rural, remote and Indigenous communities. The third component of the HEHE Plan pertains to zero emission vehicles. This includes investing an additional $287 million to continue the federal government's Incentives for Zero-Emission Vehicles program until March 2022, $150 million over three years towards charging and refueling stations across Canada, and $1.5 billion towards a Low-Carbon and Zero-Emissions Fuels Fund to increase the production of lowcarbon fuels. Also of relevance to the petroleum and natural gas industry, the federal government has announced that it will implement a ban on certain single-use plastics in 2021.

On November 19, 2020, the federal government announced Bill C-12, an Act respecting transparency and accountability in Canada's efforts to achieve net-zero greenhouse gas emissions by the year 2050. Canada joins over 120 countries in committing to net-zero emissions by 2050, including the UK, Germany, France and Japan. Once passed, Bill C-12 will legally bind the federal government to a process to achieve net-zero emissions by 2050. The legislation will, among other things, set rolling five-year emissions-reduction targets (starting in 2030) and require plans to reach each target on a reporting basis and enshrine greater accountability and public transparency into Canada's plan for meeting net-zero emissions by 2050 by providing for independent third-party review by the Commissioner of the Environment and Sustainable Development.

On June 21, 2018, the federal government enacted the Greenhouse Gas Pollution Pricing Act (the "GGPPA"), which came into force on January 1, 2019. This regime has two parts: an output-based pricing system for large industry and a regulatory fuel charge imposing an initial price of $20/tonne of CO2e emissions. This system applies in provinces and territories that request it and in those that do not have their own emissions pricing systems in place that meet the federal standards. The effect of the GGPPA is that, regardless of whether a particular province has enacted legislation of its own, there is a uniform price on emissions across the country. Under current federal plans, this price will escalate by $10 per year until it reaches a price of $50/tonne of CO2e in 2022. Starting April 1, 2021, the minimum price permissible under the GGPPA is $40/tonne of CO2e.

The provinces of Alberta, Saskatchewan, Ontario and Manitoba have challenged the constitutionality of the GGPPA. In both the Saskatchewan and Ontario references, the appellate Courts ruled in favour of the constitutionality of the GGPPA; the Alberta Court of Appeal determined that the GGPPA is unconstitutional. All three judgments have been appealed to the Supreme Court of Canada and the hearing took place in September 2020. A decision is expected in early 2021, Manitoba's judicial review application was heard by the Federal Court of Canada on December 7, 2020.

On April 26, 2018, the Federal Government passed the Regulations Respecting Reduction in the Release of Methane and Certain Volatile Organic Compounds (Upstream Oil and Gas Sector) (the "Federal Methane Regulations"). The Federal Methane Regulations seek to reduce emissions of methane from the crude oil and natural gas sector, and came into force on January 1, 2020. By introducing a number of new control measures, the Federal Methane Regulations aim to reduce unintentional leaks and intentional venting of methane, as well as ensuring that crude oil and natural gas operations use low-emission equipment and processes. Among other things, the Federal Methane Regulations limit how much methane upstream oil and gas facilities are permitted to vent. These facilities would need to capture the gas and either re-use it, reinject it, send it to a sales pipeline, or route it to a flare. In addition, in provinces other than Alberta and British Columbia (which already regulate such activities), well completions by hydraulic fracturing would be required to conserve or destroy gas instead of venting. The Federal Government anticipates that these actions will reduce annual GHG emissions by about 20 megatonnes by 2030.

As part of its efforts to provide relief to Canada's petroleum and natural gas industry in light of the COVID-19 pandemic, on October 29, 2020, the federal government launched the $750-million Emission Reduction Fund to reduce methane and GHG emissions. The fund will provide repayable funding to eligible onshore and offshore crude oil and natural gas companies to support investments to reduce GHG emissions by adopting greener technologies.

In October 2018, the federal government announced a pricing scheme as an alternative for large electricity generators so as to incentivize a reduction in emissions intensity, rather than encouraging a reduction in generation capacity.

The federal government has enacted the Multi-Sector Air Pollutants Regulation under the authority of the Canadian Environmental Protection Act, 1999, which seeks to regulate certain industrial facilities and equipment types, including boilers and heaters used in the upstream petroleum and natural gas industry, to limit the emission of air pollutants such as nitrogen oxides and sulphur dioxide.

The federal government has also announced that it will proceed with the development and implementation of a Clean Fuel Standard ("CFS") that will require producers, importers and distributors to reduce the emissions intensity of gaseous, liquid and solid fuels. On December 18, 2020, the federal government published proposed CFS regulations, the final regulations of which are expected to be published in 2021 with the CFS regulations scheduled to come into force in 2022. The proposed CFS regulations take a performance-based approach to reducing greenhouse gas emissions. The CFS regulations require suppliers of liquid fuels, such as gasoline, diesel and kerosene to gradually cut the amount of carbon in their product. It is the goal of the program to incentivize innovation and adoption of clean technologies while giving fuel suppliers the ability to meet requirements in a cost-effective way that works for their business. The proposed regulations offer compliance credits to incentive industries to innovate and adopt cleaner technologies to lower their compliance costs.

Alberta

On November 22, 2015, the Government of Alberta introduced its Climate Leadership Plan (the "CLP"). Under this strategy, the Climate Leadership Act (the "CLA") came into force on January 1, 2017 and established a fuel charge intended to first outstrip and subsequently keep pace with the federal price. On December 14, 2016, the Oil Sands Emissions Limit Act came into force, establishing an annual 100 megatonne limit for GHG emissions from all oil sands sites, excluding some attributable to upgraders, the electric energy portion of cogeneration and other prescribed emissions. In June 2019, the Government of Alberta pivoted in its implementation of the CLP and repealed the CLA. The Carbon Competitiveness Incentives Regime ("CCIR") remained in place. As a result, the federally imposed fuel charge took effect in Alberta on January 1, 2020, at a rate of $20/tonne. In accordance with the GGPPA, this increased to $30/tonne on April 1, 2020 and will increase to $40/tonne on April 1, 2021. However, on December 4, 2019, the federal government approved Alberta's proposed Technology Innovation and Emissions Reduction ("TIER") regulation intended to replace the CCIR, so the regulation of emissions from heavy industry remains subject to provincial regulation, while the federal fuel charge still applies. The TIER regulation came into effect on January 1, 2020.

The TIER regulation operates differently than the former facility-based CCIR, and instead applies to industry-wide to emitters that emit more than 100,000 tonnes of CO2e per year in 2016 or any subsequent year. The 2020 target for most TIERregulated facilities is to reduce emissions intensity by 10% as measured against that facility's individual benchmark (which is, generally, its average emissions intensity during the period from 2013 to 2015), with a further 1% reduction for each subsequent year. The facility-specific benchmark does not apply to all facilities. Certain facilities, such as those in the electricity sector, are compared against the good-as-best-gas standard, which measures against the emissions produced by the cleanest natural gas-fired generation system. Similarly, for facilities that have already made substantial headway in reducing their emissions, a different "high-performance" benchmark is available to ensure that the cost of ongoing compliance takes this into account. As with the former CCIR, the TIER regulation targets emissions intensity rather than total emissions. Under the TIER regulation, facilities in high-emitting sectors can opt-in to the program despite the fact that they do not meet the 100,000 tonne threshold. A facility can opt-in to TIER regulation if it competes directly against another TIERregulated facility or if it has annual CO2e emissions that exceed 10,000 tonnes per year and belongs to an emissionsintensive or trade exposed sector with international competition. In addition, the owner of two or more "conventional oil and gas facilities" may apply to have those facilities regulated under the TIER regulation. To encourage compliance with the emissions intensity reduction targets, TIER-regulated facilities must provide annual compliance reports and facilities that are unable to achieve their targets may either purchase credits from other facilities, purchase carbon offsets, or pay a levy to the Government of Alberta.

The Government of Alberta also signaled its intention through its CLP to implement regulations that would lower annual methane emissions by 45% by 2025. Pursuant to this goal, the Government of Alberta enacted the Methane Emission Reduction Regulation (the "Alberta Methane Regulations") on January 1, 2020, and the AER simultaneously released an updated edition of Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting. The release of Directive 060 complements a previously released update to Directive 017: Measurement Requirements for Oil and Gas Operations that took effect in December 2018. Together, these new Directives represent Alberta's first step toward achieving its 2025 goal, as outlined in the Alberta Methane Regulations. In May 2020, the Government of Canada and the Government of Alberta announced a preliminary equivalency agreement regarding the reduction of methane emissions such that the Federal Methane Regulations will not apply once the agreement is effective.

The Province of Alberta was also the first jurisdiction in North America to direct dedicated funding to implement carbon capture and storage technology across industrial sectors. Alberta has committed $1.24 billion through 2025 to fund two commercial-scale carbon capture and storage projects that will begin commercializing the technology on the scale needed to be successful. Both projects will help reduce the CO2 emissions from the oil sands and fertilizer sectors and reduce GHG emissions by 2.76 million megatonnes per year. On December 2, 2010, the Government of Alberta passed the Carbon 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. This legislation is intended to encourage new carbon capture and storage projects in Alberta.

Saskatchewan

On May 11, 2009, the Government of Saskatchewan announced The Management and Reduction of Greenhouse Gases Act (the "MRGGA") to regulate GHG emissions in the province. The MRGGA, partially proclaimed into force on January 1, 2018, establishes a framework to reduce GHG emissions by 20% of 2006 levels by 2020. On October 18, 2016, the Government of Saskatchewan released a White Paper on Climate Change, resisting a carbon tax and committing to an approach that focuses on technological innovation and adaptation. Subsequently, the Government released Prairie Resilience: A Made-in-Saskatchewan Climate Change Strategy outlining its strategy to reduce GHG emissions by 12 million tonnes by 2030. The MRGGA, which is partially compliant with the federal emissions trading system, was partially proclaimed into force on January 1, 2018, establishes a framework to reduce GHG emissions by 20% of 2006 levels by 2020. An amended version of the MRGGA was proclaimed in full in December 18, 2018, establishing the framework of an output-based emissions management framework.

Under the MRGGA, facilities that have annual GHG emissions in excess of 50,000 tonnes are regulated to meet the province's reduction targets. The following regulations were enacted throughout 2018: The Management and Reduction of Greenhouse Gases (General and Electricity Producer) Regulations, the Management and Reduction of Greenhouse Gases (Reporting and General) Regulations, and The Management and Reduction of Greenhouse Gases (Standards and Compliance) Regulations. These Regulations establish reporting requirements and impose various emissions limits for those emitters that fall within the program. On January 1, 2019, The Oil and Gas Emissions Management Regulations (the "Saskatchewan O&G Emissions Regulations") came into effect. The Saskatchewan O&G Emissions Regulations apply to licensees of oil facilities that may generate more than 50,000 tonnes of CO2e per year, obliging each licensee to propose an emissions reduction plan in accordance with an annual emissions limit with the goal of achieving annual emissions reductions of 40 to 45% by 2025. The Saskatchewan O&G Emissions Regulations aim to achieve 4.5 million tonne CO2e reduction in emissions by 2025, and a total reduction of 38.2 million tonnes CO2e between 2020 and 2030.

On April 10, 2019, Saskatchewan produced the first annual report on climate resilience. The report measures the Province's progress on goals set out under Prairie Resilience: A Made-in-Saskatchewan Climate Change Strategy. Among these goals is the aim of increasing the role of renewable energy in the provincial energy mix to 50% by 2030.

On October 1, 2019, Bill 147 – An Act to amend The Oil and Gas Conservation Act, was proclaimed into force that, in part, amends the SKOGCA to the extent necessary to bring it into alignment with the Saskatchewan O&G Emissions Regulations discussed above.

RISK FACTORS

The following are certain risk factors relating to the business of Pine Cliff which prospective investors should carefully consider before deciding whether to purchase shares. The following information is a summary only of certain risk factors and is qualified in its entirety by reference to, and must be read in conjunction with, the detailed information appearing elsewhere in this Annual Information Form. The risks set out below are not an exhaustive list and should not be taken as a complete summary or description of all the risks associated with the Company's business, the business of third parties with whom the Company conducts business and the crude oil and natural gas business generally.

Exposure to Widespread Pandemic

In December 2019, COVID-19 surfaced in Wuhan, China. Since then the outbreak has spread to over 200 countries and territories and infections have been reported around the world. The World Health Organization declared a global emergency on January 30, 2020 with respect to the outbreak and subsequently characterized it as a pandemic on March 11, 2020. In response to the outbreak, governmental authorities in Canada and internationally have introduced various recommendations and measures to try to limit the pandemic, including travel restrictions, border closures, non- essential business closures, quarantines, self-isolations, shelters-in-place and social distancing. COVID-19 and the response of governmental authorities to try to limit it are having a significant impact on the private sector and individuals, including unprecedented business, employment and economic disruptions.

The Company has been closely monitoring developments related to COVID-19. COVID-19 and other macro-economic conditions around the world have contributed to a drastic decrease in global oil and liquids demand since the beginning of 2020. These events have resulted in significant price volatility of oil and liquids prices and increased economic uncertainty. Natural gas prices have also been very volatile. At this time, the extent to which COVID-19 may continue to affect the Company is uncertain; however, it is possible that COVID-19 may have further adverse effects on commodity prices, the Company's business, results of operations, and financial condition depending on the severity and duration of the pandemic.

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 Company depends on its ability to find, acquire, develop and commercially produce oil and natural gas reserves. Without the continual addition of new reserves, the Company's existing reserves, and the production from them, will decline over time as the Company produces from such reserves. A future increase in the Company's reserves will depend on both the ability of the Company to explore and develop its existing properties and its ability to select and acquire suitable producing properties or prospects. There is no assurance that the Company will be able to continue to find satisfactory properties to acquire or participate in. Moreover, management of the Company may determine that current markets, terms of acquisition, participation or pricing conditions make potential acquisitions or participation uneconomic. There is also no assurance that the Company will discover or acquire further commercial quantities of oil and natural gas.

Future oil and natural gas exploration may involve unprofitable efforts from dry wells or 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 ensure a profit on the investment or recovery of drilling, completion and operating costs.

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

Oil and natural gas exploration, development and production operations are subject to all the risks and hazards typically associated with such operations, including, but not limited to, fire, explosion, blowouts, cratering, sour gas releases, spills

and other environmental hazards. These typical risks and hazards could result in substantial damage to oil and natural gas wells, production facilities, other property and the environment and cause personal injury or threaten wildlife. Particularly, the Company may explore for and produce sour gas in certain areas. An unintentional leak of sour 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 Company.

Oil and natural gas exploration, development and production operations are subject to all the risks and hazards typically associated with such operations, including but not limited to hazards such as fire, explosion, blowouts, cratering, sour gas releases and spills and 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 in personal injury. Oil and natural gas production operations are also subject to all the risks typically associated with such operations, including geological and seismic risks, 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 could have a material adverse effect on future results of operations, liquidity and financial condition.

As is standard industry practice, the Company is not fully insured against all risks, nor are all risks insurable. Although the Company maintains liability insurance and business interruption insurance in an amount that it considers consistent with industry practice, liabilities associated with certain risks could exceed policy limits or not be covered. See "Insurance Risks" in these Risk Factors. In either event, the Company could incur significant costs.

Weakness in the Oil and Gas Industry

Market events and conditions, including global excess oil and natural gas supply, recent actions taken by OPEC, sanctions against Iran and Venezuela, slowing growth in China and emerging economies, market volatility and disruptions in Asia, weakening global relationships, conflict between the U.S. and Iran, isolationist trade policies, increased U.S. shale production, sovereign debt levels and political upheavals in various countries including growing anti-fossil fuel sentiment, have caused significant weakness and volatility in commodity prices. See "Risk Factors - Political Uncertainty". These events and conditions have caused a significant decrease in the valuation of oil and natural gas companies and a decrease in confidence in the oil and natural gas industry. These difficulties have been exacerbated in Canada by political and other actions resulting in uncertainty surrounding regulatory, tax, royalty changes and environmental regulation. (See "Royalties and Incentives", "Regulatory Authorities and Environmental Regulation" and "Climate Change Regulation" in "Industry Conditions"). In addition, difficulties encountered by midstream proponents to obtain the necessary approvals on a timely basis to build pipelines, liquefied natural gas plants and other facilities to provide better access to markets for the crude oil and natural gas industry in Western Canada has led to additional downward price pressure on crude oil and natural gas produced in Western Canada. The resulting price differential between Western Canadian Select crude oil, Brent and West Texas Intermediate crude oil has created uncertainty and reduced confidence in the petroleum and natural gas industry in Western Canada (see "Industry Conditions - Transportation Constraints, Pipeline Capacity and Market Access").

Lower commodity prices may also affect the volume and value of the Company's reserves, especially as certain reserves become uneconomic. In addition, lower commodity prices have reduced, and may continue to reduce, the Company's cash flow which could result in a reduced capital expenditure budget. As a result, the Company may not be able to replace its production with additional reserves and both the Company's production and reserves could be reduced on a year over year basis. Given the current market conditions and the lack of confidence in the Canadian oil and gas industry, the Company may have difficulty raising additional funds in the future or if it is able to do so, it may be on unfavourable and highly dilutive terms. If these conditions persist, Pine Cliff's cash flow may not be sufficient to continue to fund operations and to satisfy obligations when due and will require additional equity or debt financing and/or proceeds from asset sales. There can be no assurance that such equity or debt financing will be available on terms that are satisfactory or at all. Similarly, there can be no assurance that the Company will be able to realize any or sufficient proceeds from asset sales to discharge its obligations.

Commodity Prices, Markets and Marketing

The marketability and price of oil and natural gas that may be acquired, discovered or produced by Pine Cliff is, and will continue to be, affected by numerous factors beyond its control. The Company's ability to market its crude oil and natural gas may depend upon its ability to acquire space on pipelines that deliver oil and natural gas to commercial markets or

contract for the delivery of crude oil by rail. (See "Industry Conditions – Transportation Constraints, Pipeline Capacity and Market Access" and "Risk Factors" - Weakness in the Oil and Natural Gas Industry"). The Company may also be affected by deliverability uncertainties related to the proximity of its reserves to pipelines, railway lines processing and storage facilities; and operational problems affecting such pipelines, railway lines and facilities as well as extensive government regulation relating to price, taxes, royalties, land tenure, allowable production, the export of crude oil and natural gas and many other aspects of the oil and natural gas business.

The prices of oil and natural gas are expected to remain volatile for the near future because of market uncertainties over the supply and demand of these commodities due to the current state of the world economies, shale oil production in the United States, OPEC actions, political uncertainties, sanctions imposed on certain oil producing nations by other countries, conflicts in the Middle East and ongoing credit and liquidity concerns. Prices for crude oil and natural gas are also subject to the availability of foreign markets and the ability to access such markets. Any material decline in prices or a continued low crude oil and natural gas price environment could result in a reduction of Pine Cliff's anticipated 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 Company's reserves. Pine Cliff might also elect not to produce from certain wells at lower prices.

Volatile crude 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 crude oil and natural gas producing properties, as buyers, sellers, lessors and lessees have difficulty agreeing on the value or terms of such arrangements. Price volatility also makes it difficult to budget for and project the return on potential acquisitions, divestitures or leasing opportunities. See "Weakness in the Oil and Natural Gas Industry".

All of these factors could result in a material decrease in Pine Cliff's expected net production revenue and a reduction in its future crude oil and natural gas acquisition, exploration, development and production activities. Any substantial and extended decline in or continued low crude oil and natural gas prices would have an adverse effect on the Company's carrying value of its reserves, borrowing capacity, revenues, profitability and cash flows from operations and may have a material adverse effect on the Company's business and financial condition.

In addition, bank borrowings available to Pine Cliff may, in part, be determined by its borrowing base. A sustained material decline in prices from historical average prices could reduce Pine Cliff's borrowing base, therefore reducing the bank credit available which could require that a portion, or all, of Pine Cliff's bank debt be repaid.

Title to and Right to Produce from Assets

The Company's actual title to and interest in its properties, and its right to produce and sell the oil and natural gas therefrom, may vary from the Company's records. In addition, there may be valid legal challenges or legislative changes that affect the Company's title to and right to produce from its oil and natural gas properties, which could impair the Company's activities and result in a reduction of the revenue received by the Company.

If a defect exists in the chain of title or in the Company's right to produce, or a legal challenge or legislative change arises, it is possible that the Company may lose all, or a portion of, the properties to which the title defect relates and/or its right to produce from such properties. This may have a material adverse effect on the Company's business, financial condition, results of operations and prospects.

Volatility of Market Price of Common Shares

The trading price of securities of crude oil and natural gas issuers is subject to substantial volatility often based on factors related and unrelated to the financial performance or prospects of the issuers involved. The volatility may affect the ability of holders to sell the Common Shares at an advantageous price. Factors unrelated to the Company's performance could include macroeconomic developments nationally, within North America or globally, domestic and global commodity prices and/or current perceptions of the crude oil and natural gas market. This includes, but is not limited to, changing and in some cases, negative investor sentiment towards energy-related businesses. In recent years, the volatility of commodities has increased due to, in part, the implementation of computerized trading and the decrease of discretionary commodity trading. In addition, the volatility, trading volume and share price of issuers have been impacted by increasing investment levels in

passive funds that track major indices, as such funds only purchase securities included in such indices. In addition, in certain jurisdictions, institutions, including government sponsored entities, have determined to decrease their ownership in crude oil and natural gas entities which may impact the liquidity of certain securities and put downward pressure on the trading price of those securities.

Similarly, the market price of the Common Shares may be due to Pine Cliff's operating results failing to meet the expectations of securities analysts or investors in any quarter, downward revision in securities analysts' estimates, governmental regulatory action, adverse change in general market conditions or economic trends, acquisitions, dispositions or other material public announcements by Pine Cliff or its competitors, along with a variety of additional factors, including, without limitation, those set forth under "Forward-Looking Statements". In addition, in recent years the market price for securities in the stock markets, including the TSX, experienced significant price and trading fluctuations. These fluctuations have resulted in volatility in the market prices of securities that often has been unrelated or disproportionate to changes in operating performance. These broad market fluctuations may adversely affect the market prices of the Common Shares. Accordingly, the price at which the Common Shares will trade cannot be accurately predicted.

Regulatory Approvals

In order to conduct its oil and natural gas operations, the Company requires regulatory approvals from various government authorities. There can be no assurance that Pine Cliff will be able obtain or renew all of the regulatory approvals that may be required to conduct operations that it may wish to undertake or that it will obtain such approvals on terms and conditions acceptable to Pine Cliff.

Surface Conditions

The exploration for and development of oil and natural gas reserves depends upon access to areas where operations are to be conducted. Oil and gas industry operations are affected by road bans imposed from time to time during the winter breakup and thaw period in the spring. Road bans are also imposed due to snow, mud and rock slides and periods of high water or wild fires which can restrict access to Pine Cliff's well sites and production facilities.

Pine Cliff conducts a portion of its operations in areas accessible only on a seasonal basis. Unless the surface is sufficiently frozen, Pine Cliff is unable to access its properties, drill or otherwise conduct its operations as planned. In addition, if the surface thaws earlier than expected, Pine Cliff must cease its operations for the season earlier than planned. Limitations on Pine Cliff's ability to access properties or conduct its operations as planned could result in a shut down or slowdown of its operations, which may adversely affect its business.

Operating and Capital Costs

The Company's financial performance is significantly affected by the cost of operating and the capital costs associated with its assets. Operating and capital costs are affected by a number of factors including, but not limited to inflationary price pressure, scheduling delays, failure to maintain quality standards and supply chain disruptions. Electricity, chemicals, supplies, abandonment, reclamation and labour costs are examples of operating costs that are susceptible to significant fluctuations. Fluctuations in operating and capital costs could negatively impact Pine Cliff's business, financial condition, results of operations, cash flows and value of its oil and gas reserves.

The following is a summary of certain risk factors relating to the business of Pine Cliff. The following information is only a summary of certain risk factors and is qualified in its entirety by reference to, and must be read in conjunction with, the detailed information appearing elsewhere in this Annual Information Form. Shareholders and potential Shareholders should consider carefully the information contained herein and, in particular, the following risk factors. If any of these risks occur, Pine Cliff's production, revenues and financial conditions could be materially harmed, with a resulting decrease in the market price of the Common Shares.

Legal Proceedings

Pine Cliff may from time to time be subject to litigation and regulatory proceedings arising in the normal course of its business. Pine Cliff cannot determine whether such litigation and regulatory proceedings will, individually or collectively, have a material adverse effect on its business, results or operations and financial condition. To the extent expenses incurred in connection with litigation or any potential regulatory proceeding or action (which may include substantial fees of attorneys and other professional advisors and potential obligations to indemnify officers and directors who may be parties to such actions) are not covered by available insurance, such expenses could adversely affect Pine Cliff's cash position.

Third Party Credit Risk

Pine Cliff 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, such failures could have a material adverse effect on Pine Cliff and its cash flow from operations. In addition, poor credit conditions in the industry and of joint venture partners may impact a joint venture partner's willingness to participate in Pine Cliff's ongoing capital program, potentially delaying the program and the results of such program until it finds a suitable alternative partner.

Numerous applications have been filed with regulatory bodies within Canada and the U.S. to build or expand existing pipeline infrastructure to transport crude oil and natural gas to markets. If the projects are not approved it may impact our ability to ship our products to sales markets, which could have a material adverse effect on production levels or on the prices that we receive for our production.

Operational Dependence

Other companies operate some of the assets in which Pine Cliff has an interest. As a result, Pine Cliff will have limited ability to exercise influence over the operation of those assets or their associated costs, which could adversely affect its financial performance. Pine Cliff's return on assets operated by others will therefore depend upon a number of factors that may be outside of its 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.

Access to Capital

The Company will have to incur capital expenditures in the future in order to carry out its oil and natural gas exploration and development activities. While there are various financing forms available to the Company, including the issuance of new equity or debt, asset sales, joint ventures or other alternatives, the Company's ability to arrange such financings or other satisfactory arrangements in the future may depend in part upon the prevailing capital market conditions, as well as the Company's business performance. These factors could negatively impact the Company in terms of its ability to raise additional capital, as well as increased volatility in oil and gas prices which could affect revenues and cash flows and Company valuations.

General Economic Conditions, Business Environment

The business of the Company is subject to general economic conditions. Adverse changes in general economic and market conditions could negatively impact demand for crude oil and natural gas, revenues, operating costs, access to capital, timing and extent of capital expenditures, credit risk and counter party risk. There can be no assurance that any risk management steps taken by the Company, with the objective of mitigating the foregoing risks, will avoid future loss due to the occurrence of such risks.

Refinancing Risk

Pine Cliff currently has the 2022 Tranche that matures on July 31, 2022, the 2024 Tranche, Related Party Note and the $6 Million Notes that all mature on December 31, 2024. There can be no assurance that debt or equity financing or cash flow from operations will be available, sufficient or on terms acceptable to Pine Cliff to meet these obligations. The inability of

Pine Cliff to access sufficient capital on favorable terms to repay or refinance any of these debt obligations could have a material adverse effect on the Company.

Issuance of Debt

From time to time, Pine Cliff may enter into transactions to acquire assets or shares of other companies. These transactions may be financed partially or wholly through debt, which may increase debt levels above industry standards. Pine Cliff's articles and bylaws do not limit the amount of indebtedness it may incur. The level of Pine Cliff's indebtedness from time to time could impair its ability to obtain additional financing in the future on a timely basis in order to take advantage of business opportunities that may arise.

Variations in Foreign Exchange Rates and Interest Rates

Operating costs incurred by Pine Cliff are generally paid in Canadian dollars. World crude oil and natural gas prices are quoted in U.S. dollars and the price received by Canadian producers is therefore affected by the Canadian/U.S. dollar exchange rate, which fluctuates over time. Material increases in the value of the Canadian dollar negatively impact Pine Cliff's production revenues. Future Canadian/U.S. exchange rates could accordingly impact the future value of Pine Cliff's reserves as determined by independent evaluators. Although a low value of the Canadian dollar relative to the U.S. dollar may positively impact the price the Company receives for crude oil and natural gas production it could also result in an increase in the price of certain goods used in operations which may have a negative impact on the Company's financial results.

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

An increase in interest rates could result in a significant increase in the amount Pine Cliff pays to service debt, which could negatively impact the market price of the Common Shares.

Delay in Cash Receipts

In addition to the usual delays in payment by the purchasers of oil and natural gas to the operators of Pine Cliff's properties, and by the operator to Pine Cliff, payments between any of such parties may also be delayed by restrictions imposed by lenders, delays in the sale or delivery of products, delays in the connection of wells to a gathering system, blow-outs or other accidents, recovery by the operator of expenses incurred in the operation of the properties or the establishment by the operator of reserves for such expenses.

Reserves Estimates

Although McDaniel has prepared Pine Cliff's reserve figures using methods of estimating reserves consistent with those commonly followed in the industry and believe that those methods have been verified by operating experience, such figures are estimates and no assurance can be given that the indicated levels of reserves will be produced. Probable reserves estimated for properties may require revisions based on the actual development strategies employed to prove such reserves. Estimated reserves may also be affected by changes in oil and natural gas prices. Declines in the reserves of Pine Cliff which are not offset by the acquisition or development of additional reserves may reduce the underlying value of the common shares to Shareholders.

The reserve report under the heading "Statement of Reserves Data and Other Oil and Gas Information – Part II - Disclosure of Reserve Data" has been prepared using certain commodity price assumptions which are described in the notes to the reserve tables. If lower prices for crude oil, NGLs and natural gas are realized by Pine Cliff and substituted for the price assumptions utilized in the reserve report, the present value of estimated future net cash flows for Pine Cliff's reserves would be reduced and the reduction could be significant.

Expiration of Licenses and Leases

The Company's properties are held in the form of licences and leases and working interests in licences and leases. If the Company 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 Company's licences or leases or the working interests relating to a licence or lease may have a material adverse effect on the Company's business, financial condition, results of operations and prospects.

Failure to Realize Anticipated Benefits of Acquisitions and Dispositions

The Company considers acquisitions and dispositions of businesses and assets in the ordinary course of business. Achieving the benefits of acquisitions depends on successfully consolidating functions and integrating operations and procedures in a timely and efficient manner and the Company's ability to realize the anticipated growth opportunities and synergies from combining the acquired businesses and operations with those of the Company. The integration of acquired businesses and assets may require substantial management effort, time and resources diverting management's focus from other strategic opportunities and operational matters. Management continually assesses the value and contribution of services provided by third parties and the resources required to provide such services. In this regard, non-core assets may be periodically disposed of so the Company 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 Company may realize less on disposition than their carrying value on the financial statements of the Company.

Risks Relating to Hedging Activities

Any substantial and extended decline in the price of oil, NGLs or natural gas would have an adverse effect on the carrying value of Pine Cliff's proved and probable reserves, borrowing capacity, revenues, profitability and cash flows from operating activities. Pine Cliff may manage the risk associated with changes in commodity prices by entering into oil or natural gas price hedges. If Pine Cliff hedges its commodity price exposure, it may forego some of the benefits it would otherwise experience if commodity prices were to increase. In addition, commodity hedging activities could expose Pine Cliff to losses. To the extent Pine Cliff engages in risk management activities related to commodity prices, it will be subject to credit risks associated with counterparties with which it contracts. Pine Cliff continually evaluates the use of, and may employ derivative structures to hedge commodity, interest rate and foreign exchange risk. Risks associated with such products, include but are not limited to counterparty risk, settlement risk, basis risk, liquidity risk and market risk which could impair or negate the hedging strategy with a consequential negative impact on earnings and cash flow.

Environmental Regulation

The oil and natural gas industry is subject to environmental regulation pursuant to local, provincial and federal legislation. A breach of such legislation may result in the imposition of fines or issuance of clean up orders in respect of Pine Cliff or its properties. Such legislation may be changed to impose higher standards and potentially more costly obligations on Pine Cliff, and there can be no assurance that Pine Cliff will be able to satisfy its actual future environmental and reclamation obligations.

Actual asset retirement costs incurred in the ordinary course in a specific period will reduce the amount of cash available for repayment of indebtedness or payment of dividends to Shareholders.

Abandonment and Reclamation Costs

The Company is required to abandon and reclaim all of its projects at the end of their economic life. These costs will be substantial. The estimate for abandonment and reclamation costs are based on a number of sources including guidelines from provincial regulatory groups, historical data from operations and management's estimation of costs to remediate, reclaim and abandon wells and facilities in which it has a working interest.

Recently as a result of the prolonged downturn in the oil and gas industry the number of orphan wells (wells owned by insolvent parties) has increased. The cost of abandoning orphan wells has largely been funded by industry. Accordingly, the

increase in the number of orphan wells could result in an increase in fees or assessments to other oil and gas producers, such as Pine Cliff, to fund the abandonment and reclamation of these orphan wells.

Carbon Pricing Risk

The majority of countries across the globe have agreed to reduce their carbon emissions in accordance with the Paris Agreement. See "Industry Conditions – Regulatory Authorities and Environmental Regulation – Climate Change Regulation". In Canada, the federal and certain provincial governments have implemented legislation aimed at incentivizing the use of alternative fuels and in turn reducing carbon emissions. The federal system currently applies in provinces and territories without their own system that meets federal standards. The federal regime is subject to a number of court challenges. See "Industry Conditions – Regulatory Authorities and Environmental Regulation – Climate Change Regulation". The taxes placed on carbon emissions may have the effect of decreasing the demand for oil and natural gas products and at the same time, increasing the Company's operating expenses, each of which may have a material adverse effect on the Company's profitability and financial condition. Further, the imposition of carbon taxes puts the Company at a disadvantage with its counterparts who operate in jurisdictions where there are less costly carbon regulations.

Political Uncertainty

In the last several years, the U.S. and certain European countries have experienced significant political events that have cast uncertainty on global financial and economic markets. Since the 2016 U.S. presidential election, the American administration has withdrawn the U.S. from the CPTPP and Congress has passed sweeping tax reform, which, among other things, significantly reduces U.S. corporate tax rates. This has affected the competitiveness of other jurisdictions, including Canada. On January 20, 2021, Mr. Joseph Biden was sworn in as the 46th President of the United States and on January 20, 2021 the Biden administration announced its decision to revoke the federal permit granted by the former administration for the Keystone XL Pipeline, which has overturned a comprehensive regulatory process that lasted more than a decade. In addition, NAFTA has been replaced with the USMCA. This has affected the competitiveness of other jurisdictions, including Canada. On January 25, 2021, the Biden administration signed an executive order with respect to stringent new Made-In-America rules for the U.S. government and has indicated that the exceptions to such rules will be very limited. It is unclear what the impact of the new executive order will be and how it may impact the USMCA and the Canada-U.S. supply chain. Further, it is unclear exactly what other actions the U.S. administration will implement, and if implemented, how these actions may impact Canada and in particular the petroleum and natural gas industry. Any actions taken by the current United States administration may have a negative impact on the Canadian economy and on the businesses, financial condition, results of operations, prospects and the valuation of Canadian oil and natural gas companies, including the Company.

In addition to the political disruption in the U.S., the impact of the United Kingdom's exit from the European Union remains to be determined. Some European countries have also experienced the rise of antiestablishment political parties and public protests held against open-door immigration policies, trade and globalization. Conflict and political uncertainty also continues to progress in the Middle East. To the extent that certain political actions taken in North America, Europe and elsewhere in the world result in a marked decrease in free trade, access to personnel and freedom of movement it could have an adverse effect on the Company's ability to market its products internationally, increase costs for goods and services required for operations, reduce access to skilled labour and negatively impact Pine Cliff's business, operations, financial condition and the market value of its Common Shares.

A change in federal, provincial or municipal governments in Canada may have an impact on the directions taken by such governments on matters that may impact the oil and gas industry including the balance between economic development and environmental policy. Alberta elected a new government in 2019 that is supportive of the Trans Mountain Pipeline expansion project. In January 2020, the Supreme Court of Canada unanimously rejected the Government of British Columbia's proposed regulation of the transport of heavy oil products into and through British Columbia. Continued uncertainty and delays have led to decreased investor confidence, increased capital costs and operational delays for producers and service providers operating in the jurisdictions where assets are located.

The federal government was re-elected in 2019, but in a minority position. The ability of the minority federal government to pass legislation will be subject to whether it is able to come to agreement with, and garner the support of, the other elected parties, most of whom are opposed to the development of the petroleum and natural gas industry. The minority federal government will also be required to rely on the support of the other elected parties to remain in power, which

provides less stability and may lead to an earlier subsequent federal election. Lack of political consensus, at both the federal and provincial government level, continues to create regulatory uncertainty, the effects of which become apparent on an ongoing basis, particularly with respect to carbon pricing regimes, curtailment of crude oil production and transportation and export capacity, and may affect the business of participants in the petroleum and natural gas industry. See "Industry Conditions – Climate Change Regulation", "Industry Conditions – Transportation Constraints, Pipeline Capacity and Market Access", "Industry Conditions - Curtailment" and "Industry Conditions – NAFTA/USMCA and other Trade Agreements".

Climate Change Regulations

The Company's exploration and production facilities and other operations and activities emit GHG which may require the Company to comply with greenhouse gas emissions legislation at the provincial or federal level. Climate change policy is evolving at regional, national and international levels, and political and economic events may significantly affect the scope and timing of climate change measures that are ultimately put in place.

As a signatory to the United Nations Framework Convention on Climate Change (the "UNFCCC") and a signatory to the Paris Agreement, which was ratified in Canada on October 3, 2016, the Government of Canada pledged to cut its GHG emissions by 30 per cent from 2005 levels by 2030. One of the pertinent policies announced to date by the Government of Canada to reduce GHG emission is the implementation of a nation-wide price on carbon emissions. The federal carbon levy came into effect on April 1, 2019 and affects provinces which have not implemented their own carbon taxes, cap-and-trade systems or other plans for carbon pricing. The federal carbon levy had an initial rate of $20 per tonne and escalates by $10 per year until it reaches a price of $50/tonne. The implementation of the federal carbon levy is currently subject to a constitutional challenge by the provinces of Alberta, Saskatchewan, Ontario and Manitoba.

The direct or indirect costs of compliance with GHG-related regulations may have a material adverse effect on the Company's business, financial condition, results of operations and prospects. Some of the Company's significant facilities may ultimately be subject to future regional, provincial and/or federal climate change regulations to manage GHG emissions. In addition, concerns about climate change have resulted in a number of environmental activists and members of the public opposing the continued exploitation and development of fossil fuels. Given the evolving nature of the debate related to climate change and the control of GHG and resulting requirements, it is expected that current and future climate change regulations will have the effect of increasing the Company's operating expenses and in the long-term reducing the demand for oil and gas production resulting in a decrease in the Company's profitability and a reduction in the value of its assets or asset write-offs. See "Industry Conditions – Regulatory Authorities and Environmental Regulation – Climate Change Regulation".

Climate change has been linked to extreme weather conditions. Extreme hot and cold weather, heavy snowfall, heavy rainfall and wildfires may restrict or could interfere with Pine Cliff's operations, increasing costs and negatively impacting production. Moreover, extreme weather conditions may lead to disruptions in the ability to transport produced oil and natural gas as well as goods and services along supply chains. At this time, the Company is unable to determine the extent to which climate change may lead to increased storm or weather hazards affecting operations.

Royalty Regimes

There can be no assurance that the governments in the jurisdictions in which the Company has assets will not adopt new royalty regimes, or modify the existing royalty regimes, which may have an impact on the economics of the Company's properties. An increase in royalties would reduce the Company's earnings and cash flow and could make future capital investments or the Company's operations uneconomic.

Reliance on Key Personnel

The Company's success depends in large measure on certain key personnel. Losing the services of such key personnel may have a material adverse effect on the Company's business, financial condition, results of operations and prospects. The Company does not have any key personnel insurance in effect. The contributions of the existing management team to the immediate and near term operations of the Company 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 Company 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 Company.

Management of Growth

The Company may be subject to growth related risks including capacity constraints and pressure on its internal systems and controls. The ability of the Company 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. If the Company is unable to deal with this growth, it may have a material adverse effect on the Company's business, financial condition, results of operations and prospects.

Liability Management

The provinces of Alberta, Saskatchewan and British Columbia have developed liability management programs designed to prevent taxpayers from incurring costs associated with suspension, abandonment, remediation and reclamation of wells, facilities and pipelines in the event that a licensee or permit holder is unable to satisfy its regulatory obligations. These programs involve an assessment of the ratio of a licensee's deemed assets to deemed liabilities. If a licensee's deemed liabilities exceed its deemed assets, a security deposit is generally required. Changes to the required ratio of the Company's deemed assets to deemed liabilities or other changes to the requirements of liability management programs may result in significant increases to the Company's compliance obligations. The impact and consequences of the Supreme Court of Canada's decision in Redwater on the AER's rules and policies, lending practices in the petroleum and natural gas industry and on the nature and determination of secured lenders to take enforcement proceedings are expected to evolve as the consequences of the decision are evaluated and considered by regulators, lenders and receivers/trustees. In addition, the liability management regime may prevent or interfere with the Company's ability to acquire or dispose of assets, as both the vendor and the purchaser of oil and natural gas assets must be in compliance with the liability management programs (both before and after the transfer of the assets) for the applicable regulatory agency to allow for the transfer of such assets. See "Industry Conditions – Regulatory Authorities and Environmental Regulation – Liability Management Rating Programs".

Information Technology Systems and Cyber-security

The Company has become increasingly dependent upon the availability, capacity, reliability and security of our information technology infrastructure and our ability to expand and continually update this infrastructure, to conduct daily operations. The Company depends on various information technology systems to estimate reserve quantities, process and record financial data, manage our land base, manage financial resources, analyze seismic information, administer our contracts with our operators and lessees and communicate with employees and third-party partners.

Further, the Company is subject to a variety of information technology and system risks as a part of its normal course operations, including potential breakdown, invasion, virus, cyber-attack, cyber-fraud, security breach, and destruction or interruption of the Company's information technology systems by third parties or insiders. Unauthorized access to these systems by employees or third parties could lead to corruption or exposure of confidential, fiduciary or proprietary information, interruption to communications or operations or disruption to our business activities or our competitive position. In addition, cyber phishing attempts, in which a malicious party attempts to obtain sensitive information such as usernames, passwords, and credit card details (and money) by disguising as a trustworthy entity in an electronic communication, have become more widespread and sophisticated in recent years. If the Company becomes a victim to a cyber phishing attack it could result in a loss or theft of the Company's financial resources or critical data and information or could result in a loss of control of the Company's technological infrastructure or financial resources. The Company's employees are often the targets of such cyber phishing attacks, as they are and will continue to be targeted by parties using fraudulent "spoof" emails to misappropriate information or to introduce viruses or other malware through "Trojan horse" programs to the Company's computers. These emails appear to be legitimate emails, but direct recipients to fake websites operated by the sender of the email or request recipients to send a password or other confidential information through email or to download malware.

The Company maintains policies and procedures that address and implement employee protocols with respect to electronic communications and electronic devices and conducts annual cyber-security risk assessments. The Company also employs encryption protection of its confidential information, all computers and other electronic devices. Despite the Company's

efforts to mitigate such cyber phishing attacks through education and training, cyber phishing activities remain a serious problem that may damage its information technology infrastructure. The Company applies technical and process controls in line with industry-accepted standards to protect its information, assets and systems, including a written incident response plan for responding to a cyber-security incident. However, these controls may not adequately prevent cyber-security breaches. Disruption of critical information technology services, or breaches of information security, could have a negative effect on our performance and earnings, as well as on our reputation, and any damages sustained may not be adequately covered by the Company's current insurance coverage, or at all. The significance of any such event is difficult to quantify, but may in certain circumstances be material and could have a material adverse effect on the Company's business, financial condition and results of operations.

Social Media

Increasingly, social media is used as a vehicle to carry out cyber phishing attacks. Information posted on social media sites, for business or personal purposes, may be used by attackers to gain entry into the Company's systems and obtain confidential information. The Company restricts the social media access of its employees and periodically reviews, supervises, retains and maintains the ability to retrieve social media content. Despite these efforts, as social media continues to grow in influence and access to social media platforms becomes increasingly prevalent, there are significant risks that the Company may not be able to properly regulate social media use and preserve adequate records of business activities and client communications conducted through the use of social media platforms.

Changing Investor Sentiment

A number of factors, including the concerns of the effects of the use of fossil fuels on climate change, the impact of oil and natural gas operations on the environment, environmental damage relating to spills of petroleum products during transportation and indigenous rights, have affected certain investors' sentiments towards investing in the oil and natural gas industry. As a result of these concerns, some institutional, retail and public investors have announced that they no longer are willing to fund or invest in oil and natural gas properties or companies, or are reducing the amount thereof over time. In addition, certain institutional investors are requesting that issuers develop and implement more robust social, environmental and governance policies and practices. Developing and implementing such policies and practices can involve significant costs and require a significant time commitment from the Board, management and employees of the Company. Failing to implement the policies and practices, as requested by institutional investors, may result in such investors reducing their investment in the Company, or not investing in the Company at all. Any reduction in the investor base interested or willing to invest in the oil and natural gas industry and more specifically, the Company, may result in limiting the Company's access to capital, increasing the cost of capital, and decreasing the price and liquidity of the Company's securities even if the Company's operating results, underlying asset values or prospects have not changed. Additionally, these factors, as well as other related factors, may cause a decrease in the value of the Company's asset which may result in an impairment change.

Evolving Corporate Governance and Reporting Framework

The Company's business is subject to evolving corporate governance and public disclosure regulations that have increased both compliance costs and the risk of noncompliance, which could have an adverse effect on the price of the Company's securities. Pine Cliff is subject to changing rules and regulations promulgated by a number of governmental and selfregulated organizations, including the Canadian Securities Administrators, the TSX and the Financial Accounting Standards Board. These rules and regulations continue to evolve in scope and complexity making compliance more difficult and uncertain. Further, the Company's efforts to comply with these and other new and existing rules and regulations have resulted in, and are likely to continue to result in, increased general and administrative expenses and a diversion of management time and attention from revenue-generating activities to compliance activities.

Dilution

The Board may issue an unlimited number of Common Shares without any vote or action by the Shareholders, subject to the rules of any stock exchange on which the Company's securities may be listed from time to time. The Company may make future acquisitions or enter into financings or other transactions involving the issuance of securities. If the Company issues any additional equity, the percentage ownership of existing Shareholders will be reduced and diluted and the price of the Common Shares could decline.

Depletion of Reserves

Pine Cliff has certain unique attributes which may differentiate it from other oil and gas industry participants. Pine Cliff may not reinvest cash flow in the same manner as other industry participants. Pine Cliff has a long reserve life index and its decline rate is lower than many other industry participants. Pine Cliff may retain a portion of its cash flow for reinvestment purposes, but the retained amount may be less than other industry participants and could result in decreases in production levels and reserves.

The future oil and natural gas reserves and production of Pine Cliff, and therefore its cash flows, will be highly dependent on its success in exploiting its reserve base and acquiring additional reserves. Without reserve additions through acquisition or development activities, Pine Cliff's reserves and production will decline over time as reserves are exploited.

There can be no assurance that Pine Cliff will be successful in developing or acquiring additional reserves on terms that meet Pine Cliff's investment objectives.

Competition

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

Indigenous Claims

Indigenous peoples have claimed Indigenous rights and title in portions of Western Canada. The Company 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 Company's business, financial condition, results of operations and prospects. In addition, the process of addressing such claims, regardless of the outcome, is expensive and time consuming and could result in delays which could have a material adverse effect on the Company's business and financial results.

Breach of Confidentiality

While discussing potential business relationships or other transactions with third parties, the Company may disclose confidential information relating to its business, operations or affairs. Although confidentiality agreements are generally signed by third parties prior to the disclosure of any confidential information, a breach could put the Company at competitive risk and may cause significant damage to its business. The harm to the Company's business from a breach of confidentiality cannot presently be quantified, but may be material and may not be compensable in damages. There is no assurance that, in the event of a breach of confidentiality, the Company will be able to obtain equitable remedies, such as injunctive relief, from a court of competent jurisdiction in a timely manner, if at all, in order to prevent or mitigate any damage to its business that such a breach of confidentiality may cause.

Net Asset Value

The net asset value of Pine Cliff's assets from time to time will vary dependent upon a number of factors beyond the control of management, including oil, natural gas and NGL prices. The trading price of Pine Cliff's common shares from time to time is also determined by a number of factors which are beyond the control of management and such trading prices may be less than the net asset value of Pine Cliff's assets.

Management Estimates and Assumptions

In preparing consolidated financial statements estimates and assumptions are used by management in determining the reported amounts of assets and liabilities, revenues and expenses recognized during the periods presented and disclosures

of contingent assets and liabilities known to exist as of the date of the financial statements. These estimates and assumptions must be made because certain information that is used in the preparation of such financial statements is dependent on future events, cannot be calculated with a high degree of precision from data available, or is not capable of being readily calculated based on generally accepted methodologies. In some cases, these estimates are particularly difficult to determine and the Company must exercise significant judgment. Estimates may be used in management's assessment of items such as depreciation and accretion, fair values, useful life of assets, income taxes, stock-based compensation and asset retirement obligations. Actual results for all estimates could differ materially from the estimates and assumptions used by the Company, which could have a material adverse effect on the financial condition, results of operations and cash flows of the Company.

Insurance Risks

The Company's property and liability insurance is subject to deductibles, limits and exclusions, and may not provide sufficient coverage for these or other insurable risks. There can be no assurance that such insurance will continue to be offered on an economically feasible basis, that all events that could give rise to a loss or liability are insurable, or that the amounts of insurance (net of applicable deductibles) will at all times be sufficient to cover each and every loss or claim that may occur involving the assets or operations of the Company.

Global Financial Markets

The market events and conditions that transpired in recent years, including disruptions in the international credit markets and other financial systems and the deterioration of global economic conditions, have, among other things, caused significant volatility in commodity prices. 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. These factors negatively impacted enterprise valuations and impacted the performance of the global economy. Petroleum prices are expected to remain volatile for the near future as a result of market uncertainties regarding the supply and demand fundamentals for petroleum products due to the current state of the world's economies, actions taken by the Organization of the Petroleum Exporting Countries, the ongoing risks facing the North American and global economies and increased supplies of crude oil which may be created by the application of new drilling technology to unconventional resource plays.

Changes in Legislation and Canadian Tax Considerations

There can be no assurances that income tax laws and government incentive programs relating to the oil and natural gas industry will not be changed in a manner which adversely affects Pine Cliff and its Shareholders. There can be no assurance that the Canada Revenue Agency will agree with how Pine Cliff calculates its income for tax purposes or that the Canada Revenue Agency will not change its administrative practices to the detriment of Pine Cliff or its Shareholders.

As Pine Cliff is engaged in the oil and natural gas business its operations are subject to certain unique provisions of the Income Tax Act (Canada) and applicable provincial income tax legislation relating to characterization of costs incurred in their businesses which effects whether such costs are deductible and, if deductible, the rate at which they may be deducted for the purposes of calculating taxable income. Pine Cliff has reviewed its historical income tax returns with respect to the characterization of the costs incurred in the oil and natural gas business as well as other matters generally applicable to all corporations including the ability to offset future income against prior year losses. Pine Cliff has filed or will file all required income tax returns and believes that it is full compliance with the provisions of the Income Tax Act (Canada) and applicable provincial income tax legislation, but such returns are subject to reassessment. In the event of a successful reassessment it may be subject to a higher than expected past or future income tax liability as well as potentially interest and penalties and such amount could be material.

Internal Controls over Financial Reporting

Internal control over financial reporting ("ICFR"), as defined in National Instrument 52-109 (NI 52-109), includes those policies and procedures that:

• 1. Pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect transactions and dispositions of Pine Cliff;
• 1. Are designed to provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles and that receipts and expenditures of Pine Cliff are being made in accordance with authorizations of management and Directors of Pine Cliff; and
• 1. Are designed to provide reasonable assurance regarding prevention or timely detection of authorized acquisition, use, or disposition of the Company's assets that could have a material effect on the financial statements.

The Company has designed and implemented ICFR as defined in NI 52-109 of the Canadian Securities Administrators, in order to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with IFRS. The control framework the Company used to design its ICFR was in accordance with the Committee of Sponsoring Organizations of the Treadway Commission (COSO 2013).

It should be noted that while the Company's believes its internal controls and procedures provide a reasonable level of assurance and are effective; they do not expect that these controls will prevent all errors and fraud.

Project Risks

The Company 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 overruns could make a project uneconomic. The Company's ability to execute projects and market oil and natural gas depends upon numerous factors beyond the Company's control, including the following: processing capacity availability; availability and proximity of pipeline capacity; availability of storage capacity; availability of, and the ability to acquire, water supplies needed for drilling, hydraulic fracturing, and waterfloods; the Company's ability to dispose of water used or removed from strata at a reasonable cost and in accordance with applicable environmental regulations; effects of inclement weather; availability of drilling and related equipment; unexpected cost increases; accidental events; currency fluctuations; regulatory changes; availability and productivity of skilled labour; and regulation of the oil and natural gas industry by various levels of government and governmental agencies.

These factors could result in Pine Cliff being unable to execute projects on time, on budget, or at all and may be unable to effectively market its oil and natural gas products.

Alternatives to, and Changing Demand for, Petroleum Products

Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, and technological advances in fuel economy and energy generation devices could reduce the demand for crude oil and other liquid hydrocarbons. Pine Cliff cannot predict the impact of changing demand for oil and natural gas products, and any major changes may have a material adverse effect on the Company's business, financial condition, results of operations and cash flows.

Gathering and Processing Facilities, Pipeline Systems and Rail

The products that Pine Cliff produces must be delivered through gathering, processing and pipeline systems, some of which are not owned by the Company, and in certain circumstances, by rail. The amount of crude oil and natural gas produced and sold from Pine Cliff's assets is subject to the accessibility, availability, proximity and capacity of these gathering and processing facilities, pipeline systems and railway lines. The lack of firm pipeline capacity, production limits, and limits on availability of capacity in gathering and processing facilities continues to affect the petroleum and natural gas industry and limits the ability to transport produced crude oil and natural gas to market. However, in early 2020, the Supreme Court of Canada and the Federal Court of Appeal both dismissed the challenges to the Cabinet's approval of the Trans Mountain Pipeline expansion, and construction on the pipeline expansion is underway. (see "Industry Conditions – Pricing and Marketing in Canada - Transportation Constraints, Pipeline Capacity and Market Access" and "Industry Conditions - Curtailment"). In addition, the pro-rationing of capacity on inter-provincial pipeline systems continues to affect the ability of crude oil and natural gas companies to export crude oil and natural gas, and could result in the inability to realize the full economic potential of the produced crude oil or natural gas or a reduction of the price offered for the production from Pine Cliff's assets. Unexpected shutdowns or curtailment of capacity of pipelines for maintenance or integrity work or because of actions taken by regulators could also affect production and operations which may have a material adverse effect on the Company's business and financial condition.

A portion of Pine Cliff's production is processed through facilities owned by third parties over which the Company has no 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 third party facility operations could have a materially adverse effect on Pine Cliff's production and ability to deliver the same for sale, which, in turn, would indirectly reduce the Company's revenues. Midstream and pipeline companies may take actions to maximize their return on investment which may in turn adversely affect producers and shippers, especially when combined with a regulatory framework that may not always align with the interests of particular shippers.

DIVIDENDS

To date, Pine Cliff has not paid any dividends on its Common Shares. There are no restrictions on paying dividends and the Pine Cliff board of directors will determine the actual timing, payment and amount of dividends, if any, that may be paid from time to time based upon, among other things, cash flow, financial conditions, the need for funds to finance ongoing operations and other business considerations.

DESCRIPTION OF SHARE CAPITAL

General Description of Share Capital

Pine Cliff is authorized to issue an unlimited number of Common Shares without nominal or par value and an unlimited number of Class B shares (the "Preferred Shares"), issuable in series. A brief summary of the characteristics of the shares is set forth below. As of the date hereof, 335,596,261 Common Shares and no Preferred Shares were issued and outstanding. As of the date hereof, 23,744,933 options to acquire Common Shares ("Options") were outstanding. As of the date hereof, 2,850,000 warrants to acquire Common Shares were outstanding.

Common Shares

The Shareholders are entitled to receive notice of and to attend any meeting of the Shareholders and are entitled to one vote for each Common Share held (except at meetings at which only the holders of another class of shares are entitled to vote). The Shareholders are entitled to receive dividends, on a pro rata basis, if, as and when declared by the Pine Cliff board of directors and, subject to prior satisfaction of all preferential rights, to participate rateably in the net assets of Pine Cliff in the event of any liquidation, dissolution or winding-up of Pine Cliff, whether voluntary or involuntary, or other distribution of assets of Pine Cliff among Shareholders for the purpose of winding up its affairs.

Preferred Shares

The Preferred Shares may be issued in one or more series and the Pine Cliff board of directors may, by resolution, fix the number of shares in each series and determine the designation, rights, privileges, restrictions and conditions to be attached to shares of each series. The holders of the Preferred Shares are entitled to dividends as and when declared by the Pine Cliff board of directors, and to receive out of the net assets of Pine Cliff in the event of any liquidation, dissolution or windingup of Pine Cliff, payment in full of the respective amounts which each holder of Preferred Shares is entitled, in preference and priority to any dividend or payment on the Common Shares.

MARKET FOR SECURITIES

The following table sets forth the reported high and low sales prices (which are not necessarily the closing prices) and the trading volumes for the Common Shares on the TSX, as applicable, as reported by sources Pine Cliff believes to be reliable for the most recently completed financial year:

Pricing Range ($)
Date	High	Low	Trading Volume
2020
January	0.165	0.115	3,221,689
February	0.135	0.09	3,209,685
March	0.125	0.05	7,539,146
April	0.15	0.095	11,126,728
May	0.19	0.12	17,390,316
June	0.165	0.11	6,972,993
July	0.15	0.12	3,098,429
August	0.24	0.13	21,229,717
September	0.23	0.155	10,818,848
October	0.295	0.19	8,371,339
November	0.31	0.255	3,592,300
December	0.27	0.205	6,374,378

OPTION AND WARRANT GRANTS

The following table sets forth, for each class of securities of the Company that is outstanding but not listed or quoted on a marketplace, the price at which securities of the class have been issued during the financial year ended December 31, 2020 and the number of securities of the class issued at that price and the date on which the securities were issued.

Date of Issue	Securities	Price per Security	Number of Securities
January 1, 2020	Options	$0.151	15,000
January 6, 2020	Options	$0.151	27,750
March 2, 2020	Options	$0.101	45,000
April 1, 2020	Options	$0.101	45,000
May 21, 2020	Options	$0.151	8,374,100
August 17, 2020	Options	$0.171	150,000

1 Represents the exercise price per Option.

DIRECTORS AND OFFICERS

The following table lists the names of the directors and officers of Pine Cliff, their province and country of residence, their positions and offices with Pine Cliff and their principal occupations. All directors have been elected to serve as such until Pine Cliff's next annual meeting of Shareholders, or until their successor is duly elected, unless their office is vacated earlier in accordance with the by-laws of Pine Cliff or applicable law.

Name, Province andCountry of Residence	Positions and Offices withthe Company	Principal OccupationDuring the Past Five Years
Jacqueline Ricci1	Director since 2020	Ms. Ricci serves as Equity Portfolio Manager, Director and Vice President
Ontario, Canada		of J.Zechner Associates Inc. and is a director of Bonterra Energy Corp.
George F. Fink	Chairman; Director since	Chairman, Chief Executive Officer and Director of Bonterra Energy Corp. a
Alberta, Canada	2004	TSX listed resource company and Chairman of the Pine Cliff board ofdirectors.
Philip B. Hodge	President and Chief	President and Chief Executive Officer of Pine Cliff since January 2012.
Alberta, Canada	Executive Officer; Directorsince 2011
Randy M. Jarock1	Director since 2012	Mr. Jarock is a private investor and director of Bonterra Energy Corp.
Alberta, Canada
William S. Rice, Q.C.1	Director since 2016	Mr. Rice is a private investor and was Chair and Chief Executive Officer of
Alberta, Canada		the Alberta Securities Commission from 2005 to 2015 and Chair of theCanadian Securities Administrators from 2011 to 2015.
Terry L. McNeill	Chief Operating Officer	Chief Operating Officer of Pine Cliff since January 2015 and prior thereto
Alberta, Canada		the Vice President Operations of Pine Cliff from April 2014.
Christopher S. Lee		Vice President, Exploration Vice President, Exploration since 2020, Vice President, Geology of Pine Cliff
Alberta, Canada		since November 2017 and prior thereto Senior Geologist of Pine Cliff since
		March 2012.
Alan MacDonald	Chief Financial Officer and	Mr. MacDonald rejoined Pine Cliff in December 2019 as Chief Financial
Alberta, Canada	Corporate Secretary	Officer and Corporate Secretary. Mr. MacDonald joined Pine Cliff in
		September 2017 as Interim Chief Financial Officer and Corporate Secretary
		until September 2018. Prior thereto, Mr. MacDonald was Chief Financial
		Officer at United Hydrocarbon International Corp., a private oil and gas
		company.

1Member of the Audit Committee, Reserves Committee, and Governance, Nomination and Compensation Committee.

As at the date hereof, the current directors and officers of the Company, as a group, owned, or controlled or directed, directly or indirectly 48,690,874 Common Shares or approximately 13.9% of the issued and outstanding Common Shares. The information as to the number of Common Shares beneficially owned has been furnished by the respective directors and officers of the Company.

Cease Trade Orders

To the best of Pine Cliff's knowledge, no director or executive officer is, or within the ten years prior to the date hereof has been, a director, chief executive officer or chief financial officer of any corporation (including the Company) that: (i) while that person was acting in that capacity, was subject to a cease trade or similar order or an order that denied such corporation access to any exemptions under securities legislation, that was in effect for a period of more than 30 consecutive days; or (ii) was subject to a cease trade or similar order or an order that denied such corporation access to any exemptions under securities legislation, that was in effect for a period of more than 30 consecutive days that was issued after that person ceased to act in such capacity and which resulted from an event that occurred while that person was acting in such capacity.

Bankruptcies

To the best of Pine Cliff's knowledge, no director or executive officer of the Company, or Shareholder holding a sufficient number of securities of the Company to affect materially the control of the Company: (i) is, as at the date of this Annual Information Form, or has been within the past 10 years, a director or executive officer of any corporation (including the

Company) that while the 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 (ii) has, within the past 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 its assets.

Penalties or Sanctions

To the best of Pine Cliff's knowledge, no director or executive officer of the Company, or Shareholder holding sufficient securities of the Company to affect materially the control of the Company, has been subject to: (i) any penalties or sanctions imposed by a court relating to securities legislation or by a securities regulatory authority or has entered into a settlement agreement with a securities regulatory authority; or (ii) any other penalties or sanctions imposed by a court or regulatory body that would likely be considered important to a reasonable investor making an investment decision.

CONFLICTS OF INTEREST

Pine Cliff's directors and officers may serve as directors or officers of other companies or have significant shareholdings in other resource companies and, to the extent that such other companies may participate in ventures in which Pine Cliff may participate, the directors of Pine Cliff may have a conflict of interest in negotiating and concluding terms respecting the extent of such participation. In the event that such a conflict of interest arises at a meeting of Pine Cliff's directors, a director who has such a conflict will generally abstain from voting for or against the approval of such participation or the terms of such participation. From time to time, several companies may participate in the acquisition, exploration and development of natural resource properties, thereby allowing for their participation in larger programs, the involvement in a greater number of programs or a reduction in financial exposure in respect of any one program. It may also occur that a particular company will assign all or a portion of its interest in a particular program to another of these companies due to the financial position of the company making the assignment. In accordance with the laws of Canada, the directors of Pine Cliff are required to act honestly, in good faith and in the best interests of Pine Cliff. In determining whether or not Pine Cliff will participate in a particular program and the interest therein to be acquired by it, the directors will primarily consider the degree of risk to which Pine Cliff may be exposed and the financial position at that time.

The directors and officers of Pine Cliff are aware of the existence of laws governing the accountability of directors and officers for corporate opportunity and requiring disclosure by the directors of conflicts of interest and Pine Cliff will rely upon such laws in respect of any directors and officers conflicts of interest or in respect of any breaches of duty by any of its directors and officers. All such conflicts will be disclosed by such directors or officers in accordance with the ABCA and they will govern themselves in respect thereof to the best of their ability in accordance with the obligations imposed upon them by law. Other than as disclosed above, the directors and officers of Pine Cliff are not aware of any such conflicts of interest in any existing or contemplated contracts with or transactions involving Pine Cliff.

LEGAL PROCEEDINGS AND REGULATORY ACTIONS

To the knowledge of the Company, there are no legal proceedings that the Company is or was a party to or of which any of its properties is or was the subject of, during the most recently completed financial year, nor are there any such proceedings known to the Company to be contemplated, which involve a claim for damages, exclusive of interest and costs, that may exceed 10% of the current assets of the Company.

There were no: (i) penalties or sanctions imposed against the Company by a court relating to securities legislation or by a securities regulatory authority during the most recently completed financial year; (ii) other penalties or sanctions imposed by a court or regulatory body against the Company that would likely be considered important to a reasonable investor in making an investment decision; and (iii) settlement agreements the Company entered into before a court relating to securities legislation or with a securities regulatory authority during the most recently completed financial year.

INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS

Other than as disclosed in this Annual Information Form, Management is not aware of any material interests, direct or indirect, of any directors or executive officers of the Company, any person or company which beneficially owns or controls or directs, directly or indirectly, more than 10% of the outstanding Common Shares, or any known associate or affiliate of such persons, in any transaction within the last three financial years of the Company, or during the current financial year which has materially affected or is reasonably expected to materially affect the Company.

MATERIAL CONTRACTS

Except for contracts entered into in the ordinary course of business, the material contracts entered into by Pine Cliff since the beginning of the two most recently completed financial years and still in effect as at the date hereof that can be reasonably regarded as presently material are:

• i) the Floating Charge Debenture in favour of Alberta Investment Management Corporation dated October 1, 2019 for $150 million; and
• ii) the Credit Agreement between Pine Cliff and Alberta Investment Management Corporation dated October 1, 2019.

All of the above contracts are available on Pine Cliff's SEDAR profile at www.sedar.com.

INTERESTS OF EXPERTS

There is no person or company whose profession or business gives authority to a statement made by such person or company and who is named as having prepared or certified a statement, report or valuation described or included in a filing, or referred to in a filing, made under NI 51-102 by Pine Cliff during, or related to, the two most recently completed financial years other than McDaniel, Pine Cliff's independent qualified reserves evaluator and Deloitte LLP, Chartered Accountants, Pine Cliff's auditor. None of the designated professionals of McDaniel had any registered or beneficial interests, direct or indirect, in any securities or other property of Pine Cliff or of Pine Cliff's associates or affiliates either at the time they prepared the statement, report or valuation prepared by it, at any time thereafter or to be received by them. Deloitte LLP have advised that they are independent with respect to Pine Cliff within the meaning of the Rules of Professional Conduct of the Institute of Chartered Accountants of Alberta.

AUDIT COMMITTEE INFORMATION

The following information is provided in accordance with Form 52-110F1 under National Instrument 52-110 Audit Committees ("NI 52-110").

Audit Committee Charter

The Audit Committee Charter is attached as Appendix "C" to this Annual Information Form.

Composition of the Audit Committee

The Audit Committee is currently comprised of Messrs. Jarock, Ricci and Rice. Mr. Jarock is the Chairman of the Audit Committee. Each member of the Audit Committee has been determined to be financially literate, as defined in NI 52-110. Messrs. Jarock, Ricci and Rice are independent members of the Audit Committee as such term is defined by NI 52-110.

Relevant Education and Experience

Each member of the Audit Committee is financially literate i.e. has the ability to read and understand financial statements. Pine Cliff's board of directors believes that collectively, the Audit Committee has the education and experience to fulfill the responsibilities outlined in the Audit Committee Charter. The education and current and past experience of each Audit Committee member that is relevant to the performance of his responsibilities as an Audit Committee member is summarized below:

Name	Education and Experience
Randy M. Jarock	Bachelor of Science in Petroleum EngineeringDirector of Bonterra Energy Corp
	Over 30 years of extensive experience related to all aspects of reading, reviewingand understanding financial statements and matters
	Former President of Bonterra
	Former Chief Operating Officer of Pine Cliff
Jacqueline Ricci	Honors in Business Administration, Chartered Financial AnalystDirector of Bonterra Energy CorpOver 30 years of experience related to all aspects of reading, reviewing and
William S. Rice	understanding financial statements of public companiesSecurities/corporate lawyer for many years, including five years as nationalmanaging partner of Bennett Jones LLP
	Chair and Chief Executive of the Alberta Securities Commission for 10 yearsServed as a director of several public companies
	Over 40 years of extensive experience related to all aspects of reading, reviewingand understanding financial statements of public companies

Audit Committee Attendance

The following is a summary of the attendance of the members of the Audit Committee for 2020:

Name	Audit Committee
Jacqueline Ricci	2/2
Randy M. Jarock	4/4
William S. Rice	4/4

Audit Committee Oversight

At no time since the commencement of the Company's most recently completed financial year has a recommendation of the Audit Committee to nominate or compensate an external auditor not been adopted by the Pine Cliff board of directors.

Reliance on Certain Exemptions

At no time since the commencement of the Company's most recently completed financial year has the Company relied on any exemption from NI 52-110, including Section 2.4 De Minimis Non-audit Services of NI 52-110, or an exemption from NI 52-110, in whole or in part, granted under Part 8 Exemptions of NI 52-110.

Pre-Approval Policies and Procedures

The Audit Committee has adopted specific policies and procedures for the engagement of non-audit services as described above under the heading "Duties and Responsibilities of the Committee" in the Audit Committee Charter as attached as Appendix "C".

External Auditor Service Fees (By Category)

The fees for auditor services billed by the Company's external auditors in each of the last two fiscal years are as follows:

Financial Year Ending December 31 Audit Fees Audit-related Fees Tax Fees All Other Fees 2020 $142,000 $51,000(1) Nil $25,000(2 2019 $142,000 $51,000(1) nil $25,000(2)

(1) Quarterly reviews of the financial statements.

(2) Internal Control review.

ADDITIONAL INFORMATION

Additional information about the Company can be found on SEDAR at www.sedar.com and on the Company's website at www.pinecliffenergy.com

Additional information, including directors' and officers' remuneration and indebtedness, principal holders of the Common Shares and securities authorized for issuance under equity compensation plans, is contained in the Company's management information circular relating to its most recent annual meeting of Shareholders held on May 21, 2020.

Additional financial information is provided in the Company's consolidated financial statements and management's discussion and analysis for the year ended December 31, 2020.

Additional copies of this Annual Information Form, the materials listed in the preceding paragraph, and any interim financial statements which have been issued by the Company will be available upon request by contacting the Company at Suite 850, 1015 – 4th Street S.W., Calgary, Alberta T2R 1J4, Telephone: (403) 269-2289.

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

February 10, 2021

Pine Cliff Energy Ltd.

850, 1015 – 4th Street SW Calgary, Alberta T2R 1J4

Attention: The Board of Directors of Pine Cliff Energy Ltd.

Re: Form 51-101F2 Report on Reserves Data by Independent Qualified Reserves Evaluator or Auditor of Pine Cliff Energy Ltd. (the "Company")

To the Board of Directors of Pine Cliff Energy Ltd. (the "Company"):

• 1. We have evaluated the Company's reserves data as at December 31, 2020. The reserves data are estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2020 estimated using forecast prices and costs.
• 1. 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.
• 1. We carried out our evaluation in accordance with standards set out in the Canadian Oil and Gas Evaluation Handbook as amended from time to time (the "COGE Handbook") maintained by the Society of Petroleum Evaluation Engineers (Calgary Chapter).
• 1. 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.
• 1. The following table shows the net present value of future net revenue (before deduction of income taxes) attributed to proved + 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 for the year ended December 31, 2020, and identifies the respective portions thereof that we have evaluated and reported on to the Company's Board of Directors:

			Net Present Value of Future Net Revenue $M(before income taxes, 10% discount rate)
Independent QualifiedReserves Evaluator	Effective Date ofEvaluation Report	Location ofReserves	Audited	Evaluated	Reviewed	Total
McDaniel	December 31, 2020	Canada	-	98,169	-	98,169

• 1. 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.
• 1. We have no responsibility to update our report referred to in paragraph 5 for events and circumstances occurring after the effective date of our report.
• 1. Because the reserves data are based on judgments regarding future events, actual results will vary and the variations may be material.

Executed as to our report referred to above:

MCDANIEL & ASSOCIATES CONSULTANTS LTD.

"signed by B. R. Hamm"

_________________________

Brian R. Hamm, P. Eng. President & CEO

Calgary, Alberta, Canada February 10, 2021

APPENDIX "B" FORM 51-101F3 REPORT OF MANAGEMENT AND DIRECTORS ON OIL AND GAS DISCLOSURE

Report of Management and Directors on Reserves Data and Other Information

Management of Pine Cliff Energy Ltd. (the "Company") are responsible for the preparation and disclosure of information with respect to the Company'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, 2020, estimated using forecast prices and costs.

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

The board of directors of the Company has:

• a) reviewed the Company'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 board of directors of the Company has reviewed the Company'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 approved:

• a) the content and filing with securities regulatory authorities of Form 51-101F1 containing reserves data and other oil and gas information;
• b) the filing of Form 51-101F2 which is the report of the independent qualified reserves evaluator on the reserves data; and
• c) the content and filing of this report.

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

"Signed Philip B. Hodge" Philip B. Hodge, President and Chief Executive Officer

"Signed Alan MacDonald" Alan MacDonald, Chief Financial Officer and Corporate Secretary

"Signed George F. Fink" George F. Fink, Director

"Signed Randy M. Jarock" Randy M. Jarock, Director

March 9, 2021

APPENDIX "C" AUDIT COMMITTEE CHARTER of PINE CLIFF ENERGY LTD.

Approved by the Board of Directors on May 18, 2017

1. Establishment of the Audit Committee

It is the policy of Pine Cliff Energy Ltd. (the "Corporation") to establish and maintain an Audit Committee (the "Committee") to assist the Board of Directors of the Corporation (the "Board") in the exercise of its duties and responsibilities.

2. Composition of the Committee

The membership of the Committee shall be as follows:

• (a) the Committee shall consist of a minimum of three directors of the Corporation;
• (b) each of the members of the Committee must be "independent" within the meaning of National Instrument 52-110 – Audit Committees;
• (c) all members of the Committee shall be "financially literate" in that they must be able 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 the Corporation's financial statements;
• (d) members of the Committee shall be appointed annually by the Board, at the first meeting of the Board after the annual general meeting of Shareholders of the Corporation, from among directors of the Corporation;
• (e) the chair (the "Chair") of the Committee shall be appointed by the Board;
• (f) a member of the Committee shall ipso facto cease to be a member of the Committee upon ceasing to be a director of the Corporation; and
• (g) any member of the Committee may be removed or replaced at any time by resolution of the directors of the Corporation. If and whenever a vacancy shall exist on the Committee, the remaining members may exercise all its powers so long as a quorum remains.

3. Meetings of the Committee

Subject to the following requirements, the Committee may determine its own meeting procedures:

• (a) The Committee shall convene at such dates, times and places as may be designated or approved by the Chair whenever a meeting is requested by the Board, a member of the Committee, the Corporation's external auditors (the "Auditors"), the Chief Executive Officer of the Corporation (the "CEO") or a senior executive of the Corporation. The Committee shall convene a minimum of four times per year to correspond with the review of the annual and quarterly financial statements;

• (b) Notice of each meeting shall be given to each member of the Committee, the Chairman of the Board, the CEO, the Auditors and all other persons the Committee determines should be provided with notice of the meeting;

• (c) Notice of a meeting of the Committee shall:

• (i) be in writing;

• (ii) state the nature of the business to be transacted at the meeting in reasonable detail;

• (iii) provide the location of the meeting and instructions how to participate remotely if required;

• (iv) to the extent practicable, be accompanied by copies of documentation to be considered at the meeting; and

• (v) be given at least two business days prior to the time stipulated for the meeting or such shorter period as the members of the Committee may permit;

• (d) A quorum for the transaction of business at a meeting of the Committee shall consist of a majority of its members. Every motion at the Committee meeting shall be decided by a majority of votes cast; in the event of a tie vote on any matters, such matters shall be presented to the Board for its consideration and determination;

• (e) Any member of the Committee may participate in a meeting of the Committee by means of such telephonic, electronic or other communication facilities as permit all persons participating in the meeting to communicate adequately with each other, and a member participating in such a meeting by any such means is deemed to be present at the meeting;

• (f) In the absence of the Chair, the members of the Committee shall choose one of the members present to be chair of the meeting. In addition, the members of the Committee shall choose one of the persons present to be the secretary of the meeting;

• (g) The Chairman of the Board, the CEO, senior financial Management and other parties may attend meetings of the Committee; however, the Committee: (i) shall meet with the Auditors independent of Management; and (ii) may meet separately with Management;

• (h) The Committee shall meet in a separate, non-Management, in camera session at each meeting. The Committee may invite such officers, directors and employees of the Corporation or affiliates as it see fit from time to time to attend meetings of the Committee and to assist thereat in the discussion of matters being considered by the Committee;

• (i) Minutes shall be kept of all meetings of the Committee and shall be signed by the chair and the secretary of the meeting; and

• (j) Minutes of Committee meetings will be sent to all Board members and relevant Management. Reports on the conduct of the meetings will be made to the Board by the Chair or in their absence, by the chair of the meeting.

4. Duties and Responsibilities of the Committee

The Committee's primary duties and responsibilities are to assist the Board with the following:

• (a) providing an open avenue of communication among Management, the Auditors and the Board;

• (b) monitoring the adequacy of this Charter and recommending any proposed changes to the Board;

• (c) reviewing the appointments of the Corporation's Chief Financial Officer and any other key financial executives involved in the financial reporting process;

• (d) identifying and monitoring the Management of the principal risks that could impact the financial reporting of the Corporation;

• (e) reviewing with Management and the Auditors the adequacy and effectiveness of the Corporation's accounting and financial controls and overseeing the integrity, adequacy and timeliness of its financial reporting processes. The Committee shall review to ensure, to its satisfaction, that adequate procedures are in place for the review of the Corporation's disclosure of financial information extracted or derived from the Corporation's financial statements and will periodically assess the adequacy of those procedures;

• (f) reviewing with Management and the external auditors the audited annual financial statements and related documents and review with Management the unaudited quarterly financial statements and related documents, prior to filing or distribution, including matters required to be reviewed under applicable legal or regulatory requirements, for submission to the Board of Directors for approval;

• (g) reviewing with Management, where appropriate and prior to release, any news releases that disclose annual or interim financial results or contain other significant financial information that has not previously been released to the public;

• (h) reviewing the Corporation's financial reporting and accounting standards and principles and significant changes in such standards or principles or in their application, including key accounting decisions affecting the financial statements, alternatives thereto and the rationale for decisions made;

• (i) reviewing the quality and appropriateness of the accounting policies and the clarity of financial information and disclosure practices adopted by the Corporation, including consideration of the Auditors' judgment about the quality and appropriateness of the Corporation's accounting policies. This review may include discussions with the external auditors without the presence of Management;

• (j) reviewing with Management and the Auditors, significant related party transactions and potential conflicts of interest;

• (k) pre-approving all non-audit services in excess of $20,000 to be provided to the Corporation by the Auditors and applicable fees;

• (l) if deemed necessary, inspecting any and all of the books and records of the Corporation, its subsidiaries and affiliates;

• (m) discussing with Management, its subsidiaries and affiliates and staff of the Corporation, any affected party, contractors and consultants of the Corporation and the external auditors, such accounts, records and other matters as any member of the Committee considers necessary and appropriate;

• (n) when there is to be a change of Auditors, reviewing all issues and provide documentation related to the change, including the information to be included in the Notice of Change of Auditors and documentation required pursuant to National Instrument 51-102 (or any successor legislation) of the Canadian Securities Administrators and the planned steps for an orderly transition;

• (o) reviewing all securities offering documents (including the documents incorporated therein by reference) of the Corporation;

• (p) reviewing findings, if any, from examinations performed by regulatory agencies with respect to financial matters;

• (q) reviewing and overseeing Management's procedure for monitoring the Corporation's compliance with laws and regulations related to financial reporting;

• (r) reviewing current and expected future compliance with covenants under financing agreements;

• (s) reviewing the proposed issuance of debt and equity instruments including public and private debt, equity and hybrid securities, credit facilities with banks and others, and other credit arrangements such as material capital and operating leases. When applicable, the Committee shall review the related securities;

• (t) monitoring and overseeing the independence of the Auditors by reviewing all relationships between the Auditors and the Corporation and all non-audit work performed for the Corporation by the Auditors;

• (u) establishing and reviewing the Corporation's procedures for the:

  • (i) receipt, retention and treatment of complaints regarding accounting, financial disclosure, internal controls or auditing matters; and
  • (ii) confidential, anonymous submission by employees of the Corporation regarding questionable accounting, auditing and financial reporting and disclosure matters.

• (v) reviewing and approving the Corporation's hiring policies regarding partners, employees and former partners and employees of the present and former Auditors of the Corporation;

• (w) conducting or authorizing investigations into any matters that the Committee believes is within the scope of its responsibilities;

• (x) performing such other functions and exercise such other powers as are prescribed from time to time for the audit committee of a reporting issuer in Parts 2 and 4 of NI 52-110, all other applicable laws and policies and procedures of all applicable regulatory authorities, the Business Corporations Act (Alberta) and the By-laws of the Corporation; and

• (y) performing any other activities consistent with this Charter as the Committee or the Board deems necessary or appropriate.

5. Management and Auditor's Role

Management is responsible for preparing the Corporation's financial statements and other financial information and for the fair presentation of the information set forth in the financial statements in accordance with International Financial Reporting Standards. Management is also responsible for establishing internal controls and procedures and for maintaining the appropriate accounting and financial reporting principles and policies designed to assure compliance with accounting standards and all applicable laws and regulations.

The Auditors' responsibility is to express an opinion on the Corporation's financial statements, based on their audit conducted in accordance with generally accepted auditing standards.

6. Reporting

At the earliest reasonable opportunity after each meeting, the Committee shall report to the Board the results of its activities and any reviews undertaken and make recommendations to the Board as deemed appropriate.

7. Access to Outside Advisors

The Committee has the authority to retain independent counsel, accountants or other advisors to assist it, as it considers necessary, to carry out its duties, and to set and pay the compensation of such advisors at the expense of the Corporation. If these costs exceed $10,000 per annum for a Committee member, such member will obtain prior approval from the Board for the amount exceeding $10,000 per annum. The Committee, and any outside advisors retained by it, will have access to all records and information relating to the Corporation and its subsidiaries which it deems relevant to the performance of its duties.