Oil-Weighted Stability...1) See Oil and Gas Metrics and Non-IFRS Measures Advisories on slide 20 & 21 2) As at December 31, 2019 (based on unaudited financial information) 3) 2019

Oil-Weighted

Stability

February 2020

Corporate Presentation

2

About

PRAIRIE PROVIDENT• Oil and liquids-focused Alberta E&P with three core areas (Michichi/Wayne,

Princess & Evi) which offer significant torque to oil prices

• Production weighted 68% to oil & liquids with low base decline

• >80% working interests and >80% operatorship allows control over pace of

development

• Committed to executing a conservative capital program balanced with cash flow

to maintain our balance sheet and financial flexibility

• Supportive lenders and solid hedging program support capital expenditures

and allow conservative management of production, reserves and cash flow

• Year-end 2019 estimated reserves-based NAV of $0.16/share on PDP,

$0.87/share on 1P and $1.92/share on 2P(1); current share price of

$0.04 = 25% of PDP NAV

(1) Based on year-end 2019 independent reserves evaluation of NPV10 after accounting for estimated long-term

debt, less cash collateralized letters of credit, divided by basic shares outstanding. See Reserves Data

Disclosure Advisories on slide 23

3

• Development of conventional oil and liquids plays across core Michichi/Wayne,

Princess and Evi areas that offer compelling economics

• Maintain capital spending levels to approximate adjusted funds flow(1); remain

flexible to quickly respond to increases or decreases in commodity prices

• Pursue accretive business combinations to add scale, improve efficiencies and

increase cash flow to drive growth; management has track record of successful

acquisitions completed to date

• Remain committed to protecting and strengthening the balance sheet through

capital expenditure discipline and a robust hedging program

PPR’S FOCUSED STRATEGY

(1) See Oil and Gas Metrics and Non-IFRS Measures Advisories on slide 20 & 21

4

• Increased size, scale and self-funded growth potential

affords opportunity to command increased market

awareness

• 2019 capital expenditures (excl. ARO) were $11.9MM,

~16% below budget(2)

• Synergies & operational efficiencies captured with

declining operating costs

• Improved capital investment efficiency with low annual

production decline rate

• Replaced 163% of 2019 production with reserves

additions and positive technical revisions on a 2P

basis(5)

PPR STRATEGIC HIGHLIGHTS

PPR Snapshot(1)

Average 2019 production(2)(3) 6,071 boe/d

(68% liquids)

Base production decline(4) ~19%

2P reserves(5) 34,467 Mboe

2P FD&A costs(2)(5) $12.48/boe

2P recycle ratio(2)(5) 1.5x

Net debt(2) $111 million

Enterprise value(6) $118 million

Outstanding shares 171 million

1) See Oil and Gas Metrics and Non-IFRS Measures Advisories on slide 20 & 212) As at December 31, 2019 (based on unaudited financial information)

3) 2019 average production of 6,071 boe/d includes 61% in light/medium oil, 4% in heavy oil, 32% in conventional natural gas and 3% in natural gas liquids

4) Excluding two higher decline Princess wells drilled in 2019; 21% including the impact of the Princess wells

5) Based on year-end 2019 independent reserves evaluation, results of which were announced February 3, 2020. See Reserves Data Disclosure Advisories on slide 23

6) Enterprise value is calculated above by adding net debt and equity value, based on a share price of $0.04/share

5

• Competed 4 development wells, two each at Princess and Evi with a 100% success rate

• Advanced Evi waterflood resulting in incremental reserves assigned to future waterflood

expansions

• Executed a modest 2019 capital program yet still replaced reserves year-over-year(3)

• Recorded significant reserves additions and positive technical revisions at Michichi due to opex

reductions(2)(3)

• Achieved robust recycle ratios of 1.5x, 14.4x and 3.0x based on FD&A costs of $12.48/boe,

$1.29/boe and $6.16/boe for 2P, 1P and PDP, respectively(1)(2)(3)

• Reduced overall net debt by $6.4 million on a year-over-year basis(1)(2)

• Re-confirmed our senior revolver borrowing base, providing financial stability and flexibility to

execute our capital program

PPR 2019 HIGHLIGHTS

1) See Oil and Gas Metrics and Non-IFRS Measures Advisories on slide 20 & 21

2) As at December 31, 2019 (based on unaudited financial information)

3) Based on year-end 2019 independent reserves evaluation, results of which were announced February 3, 2020.

See Reserves Data Disclosure Advisories on slide 23

6

2019 RESERVES HIGHLIGHTS

As at December 31, 2019Volumes

Value

(Btax)

Reserves Category(1)(4)(5)

Light &

Medium Oil

(Mbbl)

Heavy Oil

(Mbbl)

Conventional

Natural Gas(2)

(other than

Solution Gas)

(MMcf)

Conventional

Natural Gas (Solution Gas)

(MMcf)

Natural Gas

Liquids

(Mbbl)

Barrels of Oil

Equivalent(4)

(Mboe)

NPV10

($MM)

Proved developed producing 6,065 403 9,063 10,381 329 10,038 135.4

Proved developed

non-producing 137 - - 253 4 183 3.2

Proved undeveloped 7,910 459 - 16,905 316 11,502 118.8

Total proved 14,112 862 9,063 27,540 648 21,723 257.4

Probable 8,004 748 2,448 19,214 383 12,744 180.3

Total proved plus probable 22,115 1,610 11,511 46,754 1,031 34,467 437.7

STEADILY INCREASING

RESERVES PER SHARE Through strategic M&A and

successful drilling programs within

challenging environments

2P Reserves per

Basic Share(1)(3)(4)

(1) Based on Sproule’s forecast prices and costs, applicable for the effective date of the independent reserves

evaluation report. Forecast commodity prices can be found at www.Sproule.com

(2) Including both non-associated gas and associated gas but excluding solution gas (gas dissolved in crude oil)

(3) Per share numbers based on basic shares outstanding at December 31 for the applicable year

(4) See Reserves Data Disclosure Advisories on slide 23

(5) Columns may not add due to rounding

+28%‘16-‘19

0

0.03

0.06

0.09

0.12

0.15

0.18

0.21

2016 2017 2018 2019

7

MANAGEMENT TEAM AND BOARD

Management

Tim S. Granger, President & CEO CEO at Molopo Energy Limited, President and CEO at Compton Petroleum

Corporation, COO at Paramount Energy, Managing Director at TAQA North, COO

at PrimeWest Energy

Mimi M. Lai, VP Finance and CFOVice President, Finance & Controller, Manager Financial Reporting at Harvest

Operations Corp., Sr. Manager at Ernst & Young LLP

Brad Likuski, VP OperationsManager of Exploitation, Vice President Production at Spyglass Resources Corp.,

Vice President Engineering at AvenEx Energy Corp.

Tony van Winkoop, VP ExplorationPresident and CEO at Arsenal Energy Inc., General Manager of Development at

PrimeWest Energy, Co-founder of Venator Petroleum

Gjoa Taylor, VP LandVice President, Land at Arsenal Energy Inc., various land positions of increasing

responsibility with Imperial Oil, Crestar Energy, and Manager, Negotiations

at PrimeWest Energy

Board of Directors

Patrick R. McDonald, Chairman

Derek Petrie

William Roach

Ajay Sabherwal

Rob Wonnacott

Terence (Tad) Flynn

Tim Granger (President & CEO)

8

635,000PPR Total Net Acres

34.5 MMboeProved + Probable Reserves(1)

$437.7 MMProved + Probable NPV10 Value(1)


CURRENT ASSET

OVERVIEW

PrincessMulti-zone potential

Lithic Glauc & Detrital

Hz and Vt development

Michichi/WayneLower cretaceous oil/gas

Year round access

Hz development

EVI

PRINCESS

KEY FOCUS AREAS

ALBERTA

EviSlave Point light oil – low risk

Granite Wash light oil play

Emerging waterflood; proven

and probable reserves booked

MICHICHI/

WAYNE

9

PRINCESSCurrent production(1): 1,350 boe/d of medium crude oil

• Revenue/boe(2) $41.68

• Opex/boe(2) $9.63

• Royalty/boe(2) $7.67

• Operating Netback(2)(3) $24.38/boe

Activity:

• Drilled and tied in 2 wells in 2019 adding 1.3MMboe of 2P

reserves. Since inception PPR has drilled 7 Glauconite wells

adding an average of 405 Mboe/well of 2P reserves.

• Shot 3D seismic to identify the Glauconite channel and Detrital

structures on new lands.

• Drilled a stratigraphic test at 12-24 to confirm Glauconite channel

Emerging Ellerslie potential on PPR’s acreage:

• Competitors on offsetting land have drilled wells with IP30 rates

~200 to 300 bbls/d(3)

(1) February 2020 production

(2) Based on unaudited Q3 2019 operating results


(3)

(3)

10

EVI

Otter WF

Evi WF Expansion

Evi BTY WF

Current WF

Current Production(1) : 1,720 boe/d of light oil


• Opex/boe(2) $21.01


• Operating Netback(2)(3) $33.90/boe

Future Outlook:• Further advance waterflood development

• Continue the transition of our depletion plan from infill

drilling to waterflood.




11

EVI

Production Plot of CURRENT WF

Minor decline over 4 years

• Incremental 1.5 MMboe and 1.2 MMboe of 2P and 1P

undeveloped reserves (98% liquids), respectively,

have been assigned to future waterflood expansions.

• Removal of infill locations in the waterflood areas, has

resulted in 1.2 MMboe and 0.9 MMboe of negative

technical revisions on a 2P and 1P basis.

• The transition from infill drilling to waterflood reduced

1P future capital by $5.3 million; improving the

development economics.

At Evi, PPR has transitioned its depletion plan from infill

drilling to waterflood. That transition has resulted in

changes to reserves and future capital.

12

MICHICHI

• Merger with Marquee Energy created

one large contiguous field including an

operated oil battery tied to sales, and 2

operated gas plants

Current production(1): 2,140 boe/d of

medium crude oil


• Opex/boe(2) $17.66


• Operating netback(2)(3) $9.32




Current Banff Development Area

Future Banff Development

Area

13

Current production(1): 700 boe/d of medium

crude oil


• Opex/boe(2) $14.11


• Operating netback(2)(3) $23.31

Q1 2020 Activity:• Drill 1 Banff horizontal well at 15-16-32-17W4

• Convert 1 horizontal well at 3-3-32-17W4 to water

injection to initiate a pilot waterflood project and to

save water trucking costs

CURRENT BANFF DEVELOPMENT AREA

15-16-32-17W4 Q1 Drill

Existing Battery

Waterline alreadyconstructed

Injector Conversion

15-16-32-17W4 Q1 Drill




14

Average Type Well Economics(1)(2)Princess

Glauconite(3)

Princess

Ellerslie(3) Princess Detrital(3) Michichi/ Banff(4)

Drill, Complete, Equip & Tie-in ($MM) $2.0 $2.2 $1.0 $2.2

Production, IP30 (boe/d) 460 boe/d 105 boe/d 75 boe/d 325 boe/d

Production, IP365 (boe/d) 125 boe/d 85 boe/d 65 boe/d 90 boe/d

EUR (mboe) 330 mboe 225 mboe 260 mboe 185 mboe

Rate of return (%) 58% 32% 90% 50%

Payout (years) 1.3 yrs 2.6 yrs 1.4 yrs 1.7 yrs

Finding and development cost ($/boe) $6.10/boe $9.82/boe $3.86/boe $11.89/boe

DRILLING INVENTORY


(2) Based on Jan 21, 2020 strip pricing

(3) Based on type curves developed by Sproule Associates Limited, the Company’s independent qualified

reserves evaluator, and applied by Sproule in its evaluation of Prairie Provident’s reserves as of

December 31, 2019

(4) Based on estimates prepared by an internal (non-independent) qualified reserves evaluator, effective as

of December 31, 2019, in accordance with the Canadian Oil and Gas Evaluation Handbook

15

Development Economics(1)(2)Evi East

Waterflood(3)

Evi Battery

Waterflood(3)

Evi Otter

Waterflood(3)

Michichi Banff

Waterflood(4)

Capital ($MM) $4.7 $5.6 $5.1 $0.7

EUR (mboe) 260 mboe 430 mboe 545 mboe 290 mboe

Finding and development cost ($/boe) $18.41/boe $13.04/boe $9.38/boe $2.41/boe

Incremental Recovery (%) 3% 3% 3% 4%

WATERFLOOD INVENTORY


(2) Based on Jan 21, 2020 strip pricing

(3) Based on type curves developed by Sproule Associates Limited, the Company’s independent qualified

reserves evaluator, and applied by Sproule in its evaluation of Prairie Provident’s reserves as of

December 31, 2019

(4) Based on estimates prepared by an internal (non-independent) qualified reserves evaluator, effective as

of December 31, 2019, in accordance with the Canadian Oil and Gas Evaluation Handbook

16

ACTIVE RISK MANAGEMENT

>80% hedgedof forecast 2020 base oil volumes (net of royalties)

Gas HedgesOil Hedges

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

-

500

1,000

1,500

2,000

2,500

3,000

Q1 2020 Q2 2020 Q3 2020 Q4 2020 Q1 2021 Q2 2021 Q3 2021 Q4 2021

He

dge

d V

olu

me

(b

bl/

d)

Swap Collar % of Base Oil Production (net of royalties)

0%

10%

20%

30%

40%

50%

60%

-500

500

1,500

2,500

3,500

4,500

5,500

6,500

7,500

8,500

9,500

He

dge

d V

olu

me

(G

J/d

)

Put Option % of Base Gas Volume Hedged (net of royalties)

Q1 2019 Q2 2019

PPR’s conservative approach to hedging employs a 12 to 18-month program designed to

respond to backwardation in forward prices

17

ECONOMICS SENSITIVITIES

Market Price

WTI (US$)

Blended WTI (US$) from Hedged and

Unhedged Production

$45 $49.50

$50 $51.61

$55 $54.71

$60 $57.78

$65 $60.15

$70 $61.84

PPR’s hedge strategy provides meaningful protection for downside price movements

18

WHY INVEST IN PPR

Compelling value opportunity ~25% PPR trading at

of PDP NAV(2)


(2) Based on year-end 2019 independent reserves evaluation of NPV10 after accounting for estimated long-term

debt, less cash collateralized letters of credit, divided by basic shares outstanding. See Reserves Data

Disclosure Advisories on slide 23

Focused on returns

• Disciplined approach to capital allocation and focus on projects that provide the highest IRR

• Asset portfolio returns support organic growth and development in current price environment

Oil-weighted, low-risk asset base

• >5 years identified development drilling opportunities(1) and ability to capture upside as oil prices

increase

• Light oil waterflood project at Evi offers attractive economics + significant reserves addition potential

• High working interest and operatorship allows control over pace of development

Financial flexibility

• Strong hedge position (>80% of base net oil production for 2020)

• Committed to a conservative capital program balanced with cash flow to maintain our balance

sheet and financial flexibility

19

SUMMARYOIL-WEIGHTED PRODUCTION & RESERVES

Ability to Grow as Pricing Allows

Sizeable drilling inventory for organic growth

Consolidation opportunities in core areas

Low maintenance capital requirements

Capital Management

Conservative capital program balanced with cash flow

Flexibility to accelerate development or pursue

additional acquisitions depending on commodity prices

Steady cash flow from low-decline oil-weighted assets

Waterflood program flattens decline curve and reduces

maintenance capex

Attractive Assets

~6,071 boe/d production average in 2019

~68% oil and liquids weighted, economic netback

>80% of 2020 base oil production hedged to secure

project economics with upside participation

$437.7 MMTotal Proved + Probable

NPV10(1)

34.5 MMboeTotal Proved + Probable

Reserves(1)

Oil & liquids focused E&P executing a stable, returns-based strategy


20

Unaudited Financial Information. Certain financial and operating information included in this presentation for the year ended December 31, 2019, are based on estimated unaudited financial results for the year then

ended and are subject to the same limitations as discussed under Forward Looking Information set out below. These estimated amounts may change upon the completion of audited financial statements for the year

ended December 31, 2019 and changes could be material.

Adjusted Funds Flow. The term “adjusted funds flow” is a non-IFRS measure and is calculated based on forecasted cash flow from operating activities before the following forecasted items: changes in noncash

working capital, transaction costs, restructuring costs, and other non-recurring items. Management believes that such a measure provides an insightful information on the Company’s internal expectations of its ability to

fund its budgeted program and decommissioning expenditures from production activity without resort to additional debt or equity capital. Management uses this information for internal capital budgeting purposes and in

its review of the Company’s liquidity and capital resources. Adjusted funds flow as presented is not intended to represent cash flow from operating activities, net earnings or other measures of financial performance

calculated in accordance with IFRS.

Net Debt. Net debt is defined as long-term debt plus working capital surplus or deficit. Net debt is commonly used in the oil and gas industry for assessing the liquidity of a company.

Finding, Development and Acquisition Costs (“FD&A costs”). The Company calculates FD&A costs by dividing the sum of exploration and development capital and all acquisition costs (net of disposition proceeds)

for the period, plus the change in estimated FDC required to bring the reserves within the specified reserves category on production, by the change in reserves relating to discoveries, infill drilling, improved recovery,

extensions and technical revisions inclusive of changes due to acquisitions and dispositions for the same period. FD&A costs have been presented in this news release because acquisitions and dispositions can have a

significant impact on Prairie Provident’s ongoing reserves replacement costs and excluding these amounts could result in an inaccurate portrayal of its cost structure. Management uses FD&A as measure of its ability to

execute its capital programs (and success in doing so) and of its asset quality.

Recycle Ratio. Recycle ratio is defined as operating netback per boe divided by FD&A costs on a per boe basis. PPR’s operating netback in 2019, used in the above calculations, averaged $18.58 per boe (unaudited).

Operating Netback. Operating netback is a non-IFRS measure commonly used in the oil and gas industry. This measurement assists management and investors to evaluate the specific operating performance at the oil

and gas lease level. Operating netbacks included in this presentation are based on 2019 (unaudited) realized operating netback before any hedging gains/losses, and were determined by taking (oil and gas revenues

less royalties less operating costs) divided by gross working interest production. Operating netback, including realized commodity (loss) and gain, adjusts the operating netback for only realized gains and losses on

derivatives.

ADVISORIES

This presentation includes reference to certain measures commonly used in the oil and gas industry but which do not have standardized meanings or methods of calculation under International Financial Reporting

Standards (IFRS), National Instrument 51-101 (NI 51-101) of the Canadian Securities Administrators, the Canadian Oil and Gas Evaluation (COGE) Handbook, or other applicable law. Accordingly, such measures, as

determined by the Company and presented in this presentation (or in other documents published by Prairie Provident), may not be comparable to similarly defined or described measures presented by other entities,

and should not be used for any such comparisons. The following measures are provided as supplementary information by which readers may wish to consider the Company's performance, but should not be relied

upon for comparative or investment purposes.

Oil and Gas Metrics and Non-IFRS Measures

21

ADVISORIES

Drilling Opportunities. The drilling opportunities referenced in this presentation include booked locations to which reserves were assigned by Sproule Associates Limited, the Company’s independent qualified

reserves evaluator, in its year-end evaluation of Prairie Provident's reserves effective December 31, 2019, as well as drilling prospects assessed internally by management (through personnel that is a qualified

reserves evaluator within the meaning of NI 51-101 but is not independent of the Company) based on land holdings, development history and geological experience. These other opportunities have not been

independently evaluated and assigned reserves or resources in accordance with the COGE Handbook. There is no certainty that the Company will drill any particular locations, or that drilling activity on any location will

result in additional oil and gas reserves, resources or production. Locations on which Prairie Provident does drill wells will ultimately depend upon the availability of capital, regulatory approvals, seasonal restrictions,

commodity prices, anticipated costs, actual drilling results, additional reservoir information and other factors.

Type Well Information. This presentation provides indicative information regarding selected type of wells for the Company. This information reflects either: (i) the type curves developed by Sproule, independent QRE,

and applied in its most recent year-end evaluation of Prairie Provident's reserves, effective December 31, 2019 or (ii) internal estimates developed by the Company’s Internal QRE in accordance with the COGE

Handbook; using commodity price forecasts based on January 21, 2020 strip pricing. These estimates have been provided for illustrative purposes and are useful in understanding management's assumptions of well

performance and costs in making investment decisions in relation to future drilling and for assessing the performance of future wells. However, there is no certainty that such results will be achieved or that PPR will be

able to achieve the economics, production rates and estimated ultimate recoverable volumes assumed in the well economics described in this presentation. The estimated well economics included in this presentation

are based on expected type curves that were constructed by completing appropriate reservoir and statistical analyses of analogous wells in analogous areas over the past 12 to 24 months that are most representative

of the reservoirs being developed and the completion methods to be utilized by PPR over the next 12 to 24 months of drilling. The reservoir engineering and statistical analysis methods utilized is broad and can include

various methods of technical decline analyses, and reservoir simulation all of which are generally prescribed and accepted by the COGE Handbook and widely accepted reservoir engineering practices. The type

curves generated internally and validated by our internal QRE do not necessarily reflect the type curves used by our independent QRE in estimating our reserves volumes. The type well information includes estimated

ultimate recovery (EUR), which is not a resource category or defined term under NI 51-101 or the COGE Handbook. EUR refers to the quantity of petroleum estimated to be potentially recoverable from an

accumulation, plus quantities already produced therefrom. EUR volumes are not reserves. There is no assurance that EUR volumes are recoverable or that it will be commercially viable to produce any portion thereof.

Initial Production Rates. This presentation discloses initial production (IP) rates for certain wells drilled by Prairie Provident, as well as for certain type wells of the Company. The term "IP30" refers to a production

rate for the first 30 days of production, and the term "IP365" refers to a production rate for the first 365 days of production. Initial production rates are not necessarily indicative of long-term well or reservoir performance

or of ultimate recovery. Actual results will differ from those realized during an initial short-term production period, and the difference may be material.

Barrel of Oil Equivalent. The oil and gas industry commonly expresses production volumes and reserves on a “barrel of oil equivalent” basis (“boe”) whereby natural gas volumes are converted at the ratio of six

thousand cubic feet to one barrel of oil. The intention is to sum oil and natural gas measurement units into one basis for improved analysis of results and comparisons with other industry participants. A boe conversion

ratio of six thousand cubic feet to one barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner tip. It does not represent a value equivalency at the wellhead nor at the plant

gate, which is where Prairie Provident sells its production volumes. Boes may therefore be a misleading measure, particularly if used in isolation. Given that the value ratio based on the current price of crude oil as

compared to natural gas is significantly different from the energy equivalency ratio of 6:1, utilizing a 6:1 conversion ratio may be misleading as an indication of value.

Oil and Gas Metrics and Non-IFRS Measures (cont’d)

22

ADVISORIESForward Looking Information

Certain information included in this presentation constitutes forward-looking information within the meaning of applicable Canadian securities laws. Statements that constitute forward-looking information relate to future

performance, events or circumstances, and are based upon internal assumptions, plans, intentions, expectations and beliefs. All statements other than statements of current or historical fact constitute forward-looking

information. Forward-looking information is typically, but not always, identified by words such as "anticipate", "believe", "expect", "intend", "plan", "budget", "forecast", "target", "estimate", "propose", "potential", "project",

"continue", "may", "will", "should" or similar words suggesting future outcomes or events or statements regarding an outlook. In particular, this presentation includes forward-looking information regarding: base decline;

anticipated returns; and a balancing of cash inflows and outflows.

The forward-looking information in this presentation reflects expectations and assumptions of Prairie Provident regarding, among other things: commodity prices and foreign exchange rates for 2019 and beyond; the

timing and success of future drilling, development and completion activities (and the extent to which the results thereof meet Management's expectations); the continued availability of financing (including borrowings

under the Company's credit facility) and cash flow to fund current and future expenditures, with external financing on acceptable terms; future capital expenditure requirements and the sufficiency thereof to achieve the

Company's objectives; the performance of both new and existing wells; the stability of production from Prairie Provident's properties and capital and operating costs in respect thereof; the timely availability and

performance of facilities, pipelines and other infrastructure in areas of operation; the geological characteristics and quality of Prairie Provident's properties and the reservoirs in which the Company conducts oil and gas

activities (including field production and decline rates); successful integration of acquired assets into the Company's operations; the successful application of drilling, completion and seismic technology; future

exploration, development, operating, transportation, royalties and other costs; the Company's ability to economically produce oil and gas from its properties and the timing and cost to do so; the predictability of future

results based on past and current experience; prevailing weather conditions; prevailing legislation and regulatory requirements affecting the oil and gas industry (including royalty regimes); the timely receipt of required

regulatory approvals; the availability of capital, labour and services on a timely and cost-effective basis; the creditworthiness of industry partners; the ability to source and complete acquisitions; and the general

economic, regulatory and political environment in which the Company operates.

Although Prairie Provident believes that its underlying expectations and assumptions are reasonable based on currently available information, undue reliance should not be placed on forward-looking information, which

is inherently uncertain, depends upon the accuracy of such expectations and assumptions, and is subject to known and unknown risks, uncertainties and other factors, both general and specific, many of which are

beyond the Company's control, that may cause actual results or events to differ materially from those indicated or suggested in the forward-looking information. Prairie Provident can give no assurance that the forward-

looking information contained herein will prove to be correct or that the expectations and assumptions upon which they are based will occur or be realized. Actual results will differ, and the differences may be material

and adverse to the Company. Relevant risk factors include, but are not limited to: risks inherent to oil and gas exploration, development, exploitation and production operations and the oil and gas industry in general,

including geological, technical, engineering, drilling, completion, processing and other operational problems and potential delays, cost overruns, production or reserves loss or reduction in production, and environmental,

health and safety implications arising therefrom; uncertainties associated with the estimation of reserves, production rates, product type and costs; adverse changes in commodity prices, foreign exchange rates or

interest rates; the ability to access capital when required and on acceptable terms; increases in future costs of capital; the ability to secure required services on a timely basis and on acceptable terms; increases in

operating costs; unexpected capital cost requirements; environmental risks; changes in laws and governmental regulation (including with respect to royalties, taxes and environmental matters); adverse weather or

break-up conditions; competition for labour, services, equipment and materials necessary to further the Company's oil and gas activities; and changes in plans with respect to exploration or development projects or

capital and operating costs in respect thereof. These and other risks are discussed in more detail in the Company's current annual information form and other documents filed by it from time to time with securities

regulatory authorities in Canada, copies of which are available electronically under Prairie Provident's issuer profile on the SEDAR website and on the Company's website at www.ppr.ca. This list is not exhaustive.

The forward-looking information contained in this presentation is made as of the date hereof and Prairie Provident undertakes no obligation to update publicly or revise any forward-looking information, whether as a

result of new information, future events or otherwise, unless required by applicable securities laws. All forward-looking information contained in this presentation is expressly qualified by this cautionary statement.

23

ADVISORIES

Reserves Data Disclosure

Figures provided in this presentation as to proved reserves and probable reserves volumes, and net present value of related future net revenue, are estimates of such volumes and values as at December 31, 2019

based on an evaluation by Sproule Associates Limited, independent qualified reserves evaluator (QRE) of Prairie Provident’s reserves, effective December 31, 2019. Sproule's evaluation was in accordance with NI

51-101 and, pursuant thereto, the standards contained in the COGE Handbook. Information in this presentation regarding estimated reserves, net present value of related future net revenue, and production is

expressed on a net company interest basis, being its working interest (operating and non-operating) share after deduction of royalty obligations plus any royalty interest. Estimates of future net revenue are after

deduction of royalties, operating costs, estimated well abandonment and reclamation costs and estimated future development costs, but without any provision for interest costs, debt service charges or general and

administrative expenses.

The determination of oil and gas reserves involves estimating subsurface accumulations of oil, natural gas and natural gas liquids that cannot be measured in an exact manner. The preparation of estimates is subject

to an inherent degree of associated risk and uncertainty, including factors that are beyond the Company's control. The estimation and classification of reserves is a complex process involving the application of

professional judgment combined with geological and engineering knowledge to assess whether specific classification criteria have been satisfied. It requires significant judgments based on available geological,

geophysical, engineering, and economic data as well as forecasts of commodity prices and anticipated costs. As circumstances change and additional data becomes available, whether through the results of drilling,

testing and production or from economic factors such as changes in product prices or development and production costs, reserves estimates also change. Revisions may be positive or negative. Reserves volumes

attributed to properties and related future net revenue (and net present values thereof) are estimates only. There is no assurance that the estimated reserves can or will be recovered. Actual reserves may be greater

or less than those estimated, and the difference may be material. Estimated net present values of future net revenue do not represent fair market value of the reserves. There is no assurance that the forecast prices

and cost assumptions applied in evaluating the reserves will be attained, and variances between actual and forecast prices and costs may be material.

References herein to (i) "PDP" reserves means proved developed producing reserves, (ii) “1P" reserves means total proved reserves, (iii) “2P" reserves means proved reserves plus probable reserves, and (iv)

"NPV10" means, with respect to reserves, net present value of estimated future net revenue related to the reserves, discounted at 10% per year before tax.

Oil-Weighted Stability...1) See Oil and Gas Metrics and Non-IFRS Measures Advisories on slide 20 & 21 2) As at December 31, 2019 (based on unaudited financial information) 3) 2019

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