Oil-Weighted Stability€¦ · PPR’S FOCUSED STRATEGY (1) See Oil and Gas Metrics and Non-IFRS...

Oil-Weighted

Stability

May 2019

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 70% to oil & liquids (94% light & medium oil) with low ~16% base decline(1)

• >90% working interests and >98% operatorship allows control over pace of development

• 2019 capital budget of $14.2MM (excl. ARO) will underspend forecast adjusted funds flow(2)

by ~$4MM

• Competition for capital allocation enhances capital efficiencies and IRRs

• >100 gross proved drilling locations(2) that can generate compelling expected returns at current

strip prices gives ability to increase / decrease development as prices fluctuate

• Supportive lenders and rolling three-year hedging program support capital expenditures

and allow conservative management of production, reserves and cash flow

• Year end 2018 estimated NAV of $0.43/share on PDP, $1.16/share on 1P and

$2.29/share on 2P(3); current share price of $0.14 = 33% of PDP NAV

(1) Excluding three higher decline Princess wells to be drilled in 2019; 22% including the anticipated impact of the Princess wells

(2) See Oil and Gas Metrics and Non-IFRS Measures Advisories on slide 23.

(3) Based on year end 2018 independent reserves evaluation of NPV10 BT 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 25.

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 flows 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 23.

4

• Increased size, scale and self-funded growth potential affords

opportunity to command increased market awareness

• Financial metrics improve as cash inflows expected to be

balanced with cash outflows in 2019

• 2019 capital expenditures (excl. ARO) forecast at $14.2MM,

with $12.3MM directed to development capital

• Synergies & operational efficiencies captured with declining

operating costs

• 2019 G&A projected at $3.60 – $3.80 / boe, a 15% reduction

over 2018

• Improved capital investment efficiency with low annual

production decline rate

PPR STRATEGIC HIGHLIGHTS

PPR Snap Shot(1)

Production(2) 6,300 boe/d

(70% liquids)

Base production decline(3) ~16%

P+P reserves (Mboe)(4) 33,836

Net debt(5) $118 million

Enterprise value(6) $142 million

Outstanding shares 171 million

1) See Oil and Gas Metrics and Non-IFRS Measures Advisories on slide 23

2) April 2019 production

3) Excluding three higher decline Princess wells to be drilled in 2019; 22% including the impact of the Princess wells

4) Based on year end 2018 independent reserves evaluation, results of which were announced January 31, 2019. See Reserves Data Disclosure Advisories on slide 25

5) Net debt at March 31, 2019 (based on unaudited financial information)

6) Enterprise value is calculated above by adding net debt and equity value, based on a share price of $0.13/share

5

• Recorded operating netback of $8.5MM in Q1/19, a 676% increase from Q4/18 as Canadian crude oil

prices rebounded

• Q1/19 production averaged 5,962 boe/d, up 29% from Q1 2018, despite 400 boe/d of offline production

due to extreme cold weather

• Strengthening of oil prices improves the economics across our plays and free cash flows for the year

• Careful revaluation of the Michichi play brings forth new development concepts that are expected to

improve drilling economics

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

our capital program

• Eliminated $17.3 million of capital commitments, enhancing flexibility in future capital deployment

• Secured additional 21 sections (13,440 acres) of lands in the Princess area, further strengthening our

foothold in the Lithic Glauconite prospects

PPR YTD 2019 HIGHLIGHTS

6

0.00

0.02

0.04

0.06

0.08

0.10

0.12

0.14

0.16

0.18

0.20

0.22

1P 2P

2016

2017

2018

2018 RESERVES HIGHLIGHTS

Reserves Category(1)(4)(5)

VolumesValue

(Btax)

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 6,924 313 9,208 11,025 338 10,946 174.8

Proved developed

non-producing 359 9 488 10 3 453 9.3

Proved undeveloped 7,803 124 0 15,953 374 10,960 117.3

Total proved 15,085 446 9,696 26,988 714 22,360 301.4

Probable 7,413 552 3,234 15,806 365 11,504 193.6

Total proved plus probable 22,498 998 12,930 42,795 1,080 33,863 495.0

STEADILY INCREASING

RESERVES PER SHARE Through strategic M&A and successful

drilling programs within challenging

environments through 2017 & 2018

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

(4) See Reserves Data Disclosure Advisories on slide 25

(5) Columns may not add due to rounding

+15%‘16-’18

+25%‘16-’18

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

699,100PPR Total Net Acres

33.9 MMboeProved + Probable Reserves(1)

$495 MMProved + Probable NPV10 Value(1)

(1) See Reserves Data Disclosure Advisories on slide 25

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

~2,000 boe/d

~1,200 boe/d

Other~400 boe/d

EviSlave Point light oil – low risk

Granite Wash light oil play

Emerging waterflood; initial

reserves booked

MICHICHI/

WAYNE~2,700 boe/d

9

PRINCESS

Current production: 1,200 boe/d of medium gravity oil

• Revenue/boe(1) $41.75

• Opex/boe(2) $10.05

• Royalty/boe(1) $6.95

• Operating Netbacks(3) $24.30/boe

2018 activity:

• Drilled and tied in 5 wells adding >2MMboe of P+P reserves

2019 planned activity:• Drill, complete and tie-in 2 wells

Emerging Ellerslie potential on PPR’s acreage:• Competitors on offsetting land have drilled wells with IP30 rates

~200 to 300 bbls/d

Offers Robust Economics

2018 Drill Locations2019 Drill Locations(1) Based on Q1 operating results

(2) Based on normalized Q1 operating results

(3) See Oil and Gas Metrics and Non-IFRS Measures Advisories on slide 23

14-12-019-11W4IP30 625 boe/d

13-26-020-11W4IP30 800 boe/d

2019 Drill

2019 Drill

Newly acquired acreage

10

Current production: 2,000 boe/d


• Opex/boe(2) $22.91


• Operating Netbacks(3) $32.59/boe

2018 activity:

• 5km expansion of waterflood pipeline

• Conversion of 3 wells to injectors

• Brought 2 Granite Wash oil wells on production

2019 activity:• Completed and tied-in 2 Slave Point wells in Q1;

further advancing waterflood development

EVI AREA

High value, low-decline

Light oil play

2-12-87-12IP30 250 boe/d

9-12-87-12IP30 80 boe/d

16-4-87-11IP30 125 boe/d

16-31-86-11IP30 120 boe/d

(1) Based on Q1 operating results



11

Primary Producers – 30% decline rate

Waterflood Producers – minor decline

WATERFLOOD STRATEGY:

SHALLOW THE DECLINE CURVE

Added 363.5 mboe of P+P

reserves in 2018 & 850 mboe over last 3 years

Existing PPR Waterflood

12

FUTURE WATERFLOOD

DEVELOPMENTOtter WF

Evi WF Expansion

Evi BTY WF

Current WF

(1) Based on AER approved recovery factors for the pool, volumetrics and results to date


Primary Recovery (1) 7%

Waterflood Recovery(1) 5%

Total 12%

• Estimated additional EUR of ~2MMBBL of oil through the addition of 3 additional waterfloods(2)

13

EXPANDED FOOTPRINT AT MICHICHI/WAYNE

Sizeable and contiguous acreage

Current production: 2,700 boe/d of medium gravity oil


• Opex/boe(2) $18.71


• Operating netbacks(3) $12.85

2018 activity:

• Acquired P+P reserves of 16.5 MMboe, 60+ gross proved

drilling locations(1) and ~2,000 boe/d of production.

• Drilled and tied-in 3 wells in Wayne and added 250 Mboe of

P+P reserves

2019 planned activity:

• Drill 2 wells in the 2H 2019, dependent on commodity prices

(1) Based on Q1 operating results



14

MICHICHI TYPE LOG & PORE VOLUME

Net Paymetres

Average Porosity

Ave core Perm

Pore Volume

Detrital 2.4 13.5% 5mD 0.32

Banff 21 4.4% 0.5mD 0.92

Total 1.24

Top Detrital porosity

Base Banff porosity

100/16-33-031-17W4/00

15

MICHICHI MAIN

DEVELOPMENT AREA

Pool outline• Michichi Main is comprised of ~12 sections situated within

the broader Michichi/Wayne area

• Within these ~12 sections, current production = ~1,100 boe/d

• Estimated Proven Developed Producing recoverable reserves

remaining of 2,042 MBOE ~30% Detrital and 70% Banff

• 35 wells drilled to date, with cumulative production of

2.1 MMbbls

• An additional 28 Proven “Type” wells(1) have been recognized

by Sproule, with remaining recoverable reserves of 3,460

MBOE

Michichi Main Development Area

(1) Based on type curves developed by Sproule Associates Limited and applied by Sproule in its evaluation

of Prairie Provident’s reserves as of December 31, 2018

16

Waterflood pilot• Baker Hughes waterflood simulation run in 2015

• Results suggest that waterflood could more than double the

recovery factor

PILOT WATERFLOOD

SIMULATION

Recovery Factor (%)

Case 1: Base Case

Detrital 4.4%

Banff 7.3%

Total 5.0%

Case 4: Full Waterflood

Detrital 11.0%

Banff 16.9%

Total 12.2%

• Pilot waterflood can be installed for about $1.5MM

• Requires free water knockout, water pump & conversion of

2 wells to injection

• Facilities work will pay for itself on water trucking savings

alone

17

• Cash flow, hedges and balanced capital spending support growth plans

Average Type Well Economics(1)(2)Evi

Slave Point(3)

Princess

Glauconite(3) Michichi/ Banff(4) Evi Waterflood(4)

Drill, Complete, Equip & Tie-in ($MM) $2.8 $1.6 $2.6 $1.0

Production, IP30 (boe/d) 285 boe/d 380 boe/d 325 boe/d n/a

Production, IP365 (boe/d) 110 boe/d 190 boe/d 90 boe/d 60 boe/d

EUR (mboe) 140 mboe 275 mboe 185 mboe 150 mboe

Rate of return (%) 42% 148% 63% 69%

Payout (years) 1.9 yrs 0.8 yrs 1.4 yrs 1.6 yrs

Finding and development cost ($/boe) $20.00/boe $5.75/boe $14.05/boe $6.67/boe

ATTRACTIVE ECONOMICS & INVENTORY


(2) Based on April 3, 2019 strip pricing.

(3) Based on type curves developed by Sproule Associates Limited and applied by Sproule in its evaluation

of Prairie Provident’s reserves as of December 31, 2018

(4) Based on estimates by Internal Qualified Reserves Evaluator in accordance with the Canadian Oil and

Gas Evaluation handbook.

18

• Oil-weighted and low-risk asset base

• Michichi/Wayne area offers significant development potential

with attractive economics

• 2019 budget underspends forecast annual cash flow while

maintaining stable production

• Attractive waterflood, Granite Wash and future Slave Point

development opportunities at Evi

• New development opportunities in Princess with the

acquisition of synergistic assets

• Proven track record of successful execution with multiple

M&A targets in close proximity to core areas offers further

consolidation potential

DISCIPLINED 2019 BUDGET UNDERSPENDS CASH FLOW

Forecast 2019 Guidance(1)

Average production (boe/d) 6,100 – 6,500

Exit production (boe/d) 6,650

% liquids weighting ~69%

Capital expenditures(2) ~$14.2MM

Development capital ~$12.3MM

(1) See Forward Looking Information Advisories on slides 24 & 25

(2) 2019 capital expenditure guidance excludes ARO

19

ACTIVE RISK MANAGEMENT

>60% hedgedof forecast 2019 base volumes (net of royalties)

Gas HedgesOil Hedges

0%

10%

20%

30%

40%

50%

60%

70%

80%

-

500

1,000

1,500

2,000

2,500

3,000

Q12019

Q22019

Q32019

Q42019

Q12020

Q22020

Q32020

Q42020

Q12021

Q22021

Q32021

Q42021

He

dge

d V

olu

me

(b

bl/

d)

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

0%

10%

20%

30%

40%

50%

60%

70%

80%

-

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

Q1 2019 Q2 2019 Q3 2019 Q4 2019 Q1 2020 Q2 2020

He

dge

d V

olu

me

(G

J/d

)AECO Swap NYMEX Swap Collar Put Option % of Base Gas Volume Hedged (net of royalties)

20

ECONOMICS SENSITIVITIES

*70% of the low and high end points of 2019 production guidance (i.e., 6,100 and 6,500 boe/d)

Blended WTI (US$) from Hedged and Unhedged Production

2019 2020

Liquids Production (bbl/d)* 4,270 4,550 4,270 4,550

WT

I (U

S$)

$ 40 $ 45.76 $ 45.41 $ 43.23 $ 43.03

$ 45 $ 48.33 $ 48.12 $ 46.79 $ 46.68

$ 50 $ 51.13 $ 51.06 $ 50.47 $ 50.44

$ 55 $ 54.87 $ 54.88 $ 54.59 $ 54.62

$ 60 $ 58.98 $ 59.05 $ 58.55 $ 58.64

$ 65 $ 62.12 $ 62.30 $ 61.84 $ 62.04

$ 70 $ 65.15 $ 65.45 $ 65.10 $ 65.40

$ 75 $ 68.17 $ 68.59 $ 68.35 $ 68.76

21

WHY INVEST IN PPR

Compelling value opportunity ~33% PPR trading at

of PDP NAV(3)

(1) Based on April 3, 2019 strip pricing


(3) Based on year end 2018 independent reserves evaluation of NPV10 BT 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 25

Focused on returns

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

• Asset portfolio provides returns ranging from 42% - 148%(1) in current price environment, supporting

organic growth and development

Oil-weighted, low-risk asset base

• >5 years identified development drilling opportunities(2) 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 (>60% and >40% of base net production for 2019 and 2020, respectively)

• Remain focused on prudent capital management with a 2019 budget that underspends adjusted

funds flow(2)

22

SUMMARYOIL-WEIGHTED PRODUCTION & RESERVES

Ability to Grow as Pricing AllowsSizeable drilling inventory for organic growth

Consolidation opportunities in core areas

Low maintenance capital requirements

Capital ManagementDevelopment fully funded with forecast adjusted funds

flow(1)

Flexibility to accelerate development or pursue

additional acquisitions depending on commodity prices

Steady cash flows from low-decline oil-weighted assets

Waterflood program flattens decline curve and reduces

maintenance capex

Attractive Assets6,100-6,500 boe/d for 2019; target exit ~6,650 boe/d

~69% oil and liquids weighted, economic netbacks

>60% of 2019 base production hedged to secure

project economics with upside participation

$495.0 MMTotal Proved + Probable

NPV10(2)

33.9 MMboeTotal Proved + Probable

Reserves(2)

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

1) See Oil and Gas Metrics and Non-IFRS Measures Advisories on slide 23

2) See Reserves Data Disclosure Advisories on slide 25

23

Unaudited Financial Information

Certain financial and operating information included in this presentation for the year ended December 31, 2018, 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, 2018 and changes could be material.

Adjusted Funds Flow

This presentation contains disclosures regarding the Company’s forecast 2019 adjusted funds flow in relation to its approved capital expenditure budget for 2019. 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.

Operating Netback. The Company calculates operating netback as production revenues (excluding realized and unrealized gains and losses on commodity hedging) less royalties and operating expenses, divided by gross working interest

production (on a boe basis). Management considers operating netback to provide a useful measure for evaluating operational performance at the oil and gas lease level, as an indicator of field-level profitability relative to current commodity

prices.

Finding and Development Costs. Prairie Provident calculates finding and development (F&D) costs for a particular period by dividing the sum of all capital costs for the period (except capitalized general and administrative expenses) and

change in estimated future development costs by the change in reserves relating to discoveries, infill drilling, improved recovery, extensions and technical revisions for the same period. Management considers F&D costs to provide a useful

measure of capital efficiency.

Drilling Locations. This presentation refers to proved drilling locations, which are locations to which Sproule Associates Limited ("Sproule"), independent QRE, attributed proved reserves in its most recent year-end evaluation of Prairie

Provident's reserves, effective December 31, 2018. Sproule's year-end evaluation was in accordance with National Instrument 51-101 ("NI 51-101") and, pursuant thereto, the Canadian Oil and Gas Evaluation Handbook ("COGE

Handbook"). See "Reserves Data Disclosure" below. There is no certainty that the Company will drill any particular locations, or that drilling activity on any locations will result in additional oil and gas reserves, resources or production.

Locations on which Prairie Provident in fact drills wells will ultimately depend upon the availability of capital, regulatory approvals, seasonal restrictions, commodity prices, 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, 2018 or (ii) internal estimates developed by the Company’s Internal QRE in accordance with the COGE Handbook; using commodity price forecasts based on

April 3, 2019 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.

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), the

COGE Handbook or 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

24

ADVISORIES

Forward 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: forecast adjusted funds flow for 2019; budgeted capital expenditures for 2019; base decline, net debt and

enterprise value information; anticipated returns; a balancing of cash inflows and outflows for 2019; projected G&A expense levels for 2019; anticipated 2019 capital projects (including drilling, completion and tie-in plans); type well economics

(including expected capital requirements, initial production rates, rates of return, payout information and finding and development costs); forecast base production volumes in 2019 and beyond; 2019 forecasts for average production rate,

target exit production rate, liquids weighting, and capital expenditure and development capital amounts; and future development and consolidation opportunities.

.

Information in this presentation regarding the Company's forecasted 2019 adjusted funds flow constitutes forward-looking information, as well as financial outlook information within the meaning of applicable Canadian securities laws. Such

financial outlook is made as of the date hereof and is provided for the sole purpose of describing the Company's internal expectations as to its ability to generate funds necessary to finance capital expenditures and debt repayments. The

financial outlook information contained herein should not be used, and may be inappropriate for, any other purpose.

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.

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, Continued

25

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, 2018 based on an evaluation by

Sproule Associates Limited, independent qualified reserves evaluator (QRE) of Prairie Provident’s reserves, effective December 31, 2018. 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) "TP" reserves means total proved reserves, (iii) "P+P" reserves means proved reserves plus probable reserves, and (iv) "NPV10" means, with respectto reserves, net present value of estimated future net revenue related to the reserves, discounted at 10% per year.

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.

Assumptions used for 2019 guidance include WTI US$56.90/bbl, CAD WTI C$75.00/bbl, WCS C$52.60/bbl, Edmonton Light Diff C$(6.80)/bbl, WCS Diff C$22.30/bbl, and AECO gas C$1.90/GJ.

Forward Looking Information, Continued

Oil-Weighted Stability€¦ · PPR’S FOCUSED STRATEGY (1) See Oil and Gas Metrics and Non-IFRS...

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