Oil-Weighted Growth Engine. January 2018 Corporate Presentation

Transcription

1 Oil-Weighted Growth Engine January 2018 Corporate Presentation

2 About PRAIRIE PROVIDENT Oil and liquids focused E&P company operating primarily in Alberta Low-decline production generates attractive operating netbacks* in current environment - ~70% liquids (62% light oil) and ~20% base decline - > 5 years of low cost drilling locations* drives long-term growth engine Balance sheet well supported by reserves, cash flow and active hedging program - Debt to EBITDAX* currently 1.7x; target of 1x on a rolling 12 month basis High working interests and operatorship allows control over pace of development - Competition for capital allocation drives enhanced capital efficiencies and IRRs 2 * Note: See Oil and Gas Metrics and Non-IFRS Measures Advisories on slide 24

3 STRATEGY Focus on development of conventional western Canadian oil and liquids plays that offer compelling economics in a low price environment Maintain high working interests and operatorship Maintain and grow production through waterflood and light oil focused development Deliver accretive growth through exploitation plus opportunistic acquisitions Competition for capital across areas improves IRRs Maintain strong balance sheet through capital discipline and robust hedging program 3

4 As at January 22, 2018 Shares Outstanding Current Production Market and Financial Summary MM Management & Board Equity Ownership 3% Market Capitalization Total Debt Net of Cash Credit Capacity (1) Company OVERVIEW $57 MM $52 MM $70 MM 2018 Forecast Adjusted EBITDAX(*) $27-30 MM Operational Summary ~5,000 boe/d 2017 Oil & liquids weighting ~70% Base decline rate ~20% Reserves (YE2017) P+P Reserves (*) Reserve Life Index (P+P) (*) P+P Reserves NPV10 (*) PDP Reserves (*) PDP Reserves NPV10 (*) 20,677 Mboe 11.3 years $298 MM 9,386 Mboe $150 MM 4 (*) See Oil and Gas Metrics and Non-IFRS Measures Advisories on slide 24 and Reserves Data Disclosure Advisories on slide 25 (1) Applying a USD/CAD exchange rate of $0.80 per US$1.00

5 FOCUSED ASSET BASE KEY FOCUS AREAS 773,238 PPR Total Net Acres EVI ~2,200 boe/d Evi Slave Point light oil low risk Granite Wash light oil play 121 sections Emerging waterflood; initial reserves booked 20.7 MMboe Proved + Probable Reserves (1) Wheatland Lower cretaceous oil/gas 116 sections; year round access Hz development $298.5MM Proved + Probable NPV10 Value (1) Other ~600 boe/d WHEATLAND ~1,600 boe/d PRINCESS ~600 boe/d Princess Multi-zone potential Lithic Glauc & Detrital 75 sections Hz and Vt development 5 (1) See Reserves Data Disclosure Advisories on slide 25 ALBERTA

6 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 CFO Vice President, Finance & Controller, Manager, Financial Reporting at Harvest Operations Corp, Sr. Manager at Financial Accounting Advisory Services Ernst & Young LLP Robert Guy, VP Operations Vice President, Production Operations at Spyglass Resources Corp., Manager, Operations at Ketch Resources Trust, Various Management Positions at Acclaim Energy Trust Tony van Winkoop, VP Exploration President and CEO at Arsenal Energy Inc., General Manager of Development at PrimeWest Energy, Co-founder of Venator Petroleum Gjoa Taylor, VP Land Vice 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 Ajay Sabherwal Rob Wonnacott Terence (Tad) Flynn Tim Granger (President & CEO) 6

7 POSITIONED FOR GROWTH Built an oil-weighted and low-risk asset base in Alberta focused in Wheatland / Princess and Evi, which offers: 5 years of drilling inventory on internally identified development drilling opportunities (assuming a notional 30 MM$/yr. capital budget) 2017 activity was reduced to defer capital spending in low a commodity price environment and to refocus on higher net back liquids weighted opportunities Refocused drilling to the Wayne area to target better economics through higher liquids rate Attractive Waterflood, Granite Wash and future Slave Point development opportunities at Evi Increased Princess footprint Multiple M&A targets in close proximity to focus areas 7 7

8 2017 RESERVES HIGHLIGHTS Reserve Category (1)(4) Volumes Value (Btax) Oil (mbbl) Gas (mmcf) NGL (mbbl) Total (mboe) NPV 10 ($m) Proved developed producing 6,305 11, , ,439 Proved developed nonproducing 328 2, ,290 Proved undeveloped 4,074 5, ,172 50,097 Total proved 10,707 19, , ,826 Probable 4,639 9, ,327 90,640 Reserves per BOE/Share (1)(2)(3) % YoY Increase 13% YoY Increase Total proved plus probable 15,346 28, , , P 2P 8 (1) Sproule Report, effective December 31, 2017; company interest gross reserves (2) Sproule Report, effective December 31, 2016; company interest gross reserves (3) Per share numbers based on basic shares outstanding at December 31 (4) Columns may not add due to rounding ABILITY TO INCREASE RESERVES PER SHARE IN A CHALLENGING ENVIRONMENT

9 ATTRACTIVE ECONOMICS & INVENTORY 2018 estimated capital program of ~$26 million* (flexibility to increase, depending on commodity prices and results) Cash flow, hedges and access to capital support growth plans Average Type Well Economics *(1) Princess Detrital Princess Glauconite Wheatland Wayne Evi Granite Wash drill EVI Waterflood Drill, Complete, Equip & Tie-in ($MM) $0.7 $1.6 $1.5 $1.1 $1.0 Production, IP30 (boe/d) 65 boe/d 180 boe/d 350 boe/d 66 boe/d n/a Production, IP365 (boe/d) 45 boe/d 130 boe/d 180 boe/d 55 boe/d 60 boe/d EUR (mboe) 55 mboe 150 mboe 260 mboe 133 mboe 150 mboe Rate of return (%) 73% 60% 40% 106% 40% Payout (years) 1.2 yrs 1.4 yrs 1.9 yrs 1.7 yrs 2.5 yrs Finding and development cost ($/boe) $13.55/boe $10.69/boe $5.77/boe $8.41/boe $7.49/boe Operating netback ($/boe) $35.00/boe $29.00/boe $15.00/boe $43.00/boe $40.00/boe Recycle ratio * Note: See Oil and Gas Metrics and Non-IFRS Measures Advisories on slide 24 (1) Based on Jan 15, 2018 strip pricing average 2018 WTI US$63.00/bbl, AECO - C$1.43/mcf, WCS - C$51.50/bbl, Edmonton Light to WTI differential - C$6.00/bbl and USD/CAD FX - $0.81 9

10 CORE AREA DEVELOPMENT Drilling program allocated across core areas at Wheatland, Princess and Evi 2018 estimated capital program of approximately $26 million* Core Area Wheatland / Wayne Princess Evi Drilling Evi Waterflood Total Capex $9 MM $10 MM $3 MM $4 MM $26 MM Business development opportunities can supplement accretive organic growth Strong balance sheet and access to capital supports M&A * $26 million 2018 capital program does not include ARO or capitalized G&A 10

11 R21 R20W4 WHEATLAND WAYNE AREA T28 Current production of 850 boe/d 2017 netbacks of approximately $15/boe* 2017 activity: Drilled one well adding 350 boe/d Added an additional 3.5 sections of land in the Wayne area Commitment with PSK has been extended to March 31, 2019 possible additional extension to September 30, 2019 T budget: 3 Ellerslie horizontals in Q1 Additional 3 Ellerslie horizontals in Q3 * Note: See Oil and Gas Metrics and Non-IFRS Measures Advisories on slide 24 PPR Land PPR Wells 2017 Drill 2018 Drills R21 (1) Based on Jan 15, 2018 strip pricing average 2018 WTI US$63.00/bbl, AECO - C$1.43/mcf, WCS - C$51.50/bbl, Edmonton Light to WTI differential - C$6.00/bbl and USD/CAD FX - $0.81

12 WAYNE AREA ECONOMICS Average Type Well Economics* Ellerslie Type Well Capital: $1.5 million/well IP30: 350 boe/day EUR: 260 Mboe Operating Netback: $15.00/boe NPV10: $740,000 /location Production (boe/d) ROR: 40% (1) Payout: 1.9 years Recycle Ratio: ~700 boe/d Producing Months * Note: See Oil and Gas Metrics and Non-IFRS Measures Advisories on slide 24 (1) Based on Jan 15, 2018 strip pricing average 2018 WTI US$63.00/bbl, AECO - C$1.43/mcf, WCS - C$51.50/bbl, Edmonton Light to WTI differential - C$6.00/bbl and USD/CAD FX - $

13 PRINCESS Robust Economics & Low-Risk Growth Driver Current production of 600 boe/d of medium gravity oil 100% owned oil battery 2017 netbacks of approximately $27/boe 2017 activity: Tied in three wells adding 240 boe/d Acquired 11.5 sections prospective for Glauconite and Basal Mannville Acquired roughly 30 sections of additional 3D seismic 2018 budget: 3 Glauconite horizontals in Q1 Additional 3 Glauconite horizontals in Q3 Current inventory of 15 locations prospective for Glauconite, Basal Mannville and Detrital oil PPR lands Newly Acquired Lands Well Locations 13 (1) Based on Jan 15, 2018 strip pricing average 2018 WTI US$63.00/bbl, AECO - C$1.43/mcf, WCS - C$51.50/bbl, Edmonton Light to WTI differential - C$6.00/bbl and USD/CAD FX - $0.81

14 PRINCESS AREA Average Type Well Economics* Glauconite Type Well Capital: $1.6 million/well IP30: 180 boe/day EUR: 150 Mboe Production (boe/d) ROR: 60% (1) Payout: 1.4 years Recycle Ratio: months 14 * Note: See Oil and Gas Metrics and Non-IFRS Measures Advisories on slide 24 (1) Based on Jan 15, 2018 strip pricing average 2018 WTI US$63.00/bbl, AECO - C$1.43/mcf, WCS - C$51.50/bbl, Edmonton Light to WTI differential - C$6.00/bbl and USD/CAD FX - $0.81

15 FULL FIELD (EVI MAIN) WATERFLOOD DEVELOPMENT Impact 1.4 MMboe of incremental oil reserves have been booked as a result of waterflood efforts to date; opportunity to increase further 4 additional injectors to be online in Q with an additional 4 conversions planned during the remainder of the year Future Potential: With Evi area acquisition completed in Q we have increased waterflood development potential RPS study found: 2% recovery factor (RF) to date Potential for 9% RF with water flood development Incremental EUR* potential from waterflood ~6.8 MMbbl Study was completed in 2015 and will be updated based on activity to date and to include new land acquisition Oil (bbl/d)/inj. (x10bbl/d)/gor (scf/bbl) Cumulative Oil Production 15 * Note: See Oil and Gas Metrics and Non-IFRS Measures Advisories on slide 24 and Reserves Data Disclosures Advisories on slide 25.

16 WATERFLOOD RESULTS 4,500 Evi Slave Pt. Production Decline operated wells (includes both waterflood and non-waterflood areas) 4,000 Oil Production (bbl/d) 3,500 3,000 2,500 2,000 1,500 1,000 CD Rate bbl/d 35% annual decline 25% annual decline 15% annual decline Jan-14 Mar-14 May-14 Jul-14 Sep-14 Nov-14 Jan-15 Mar-15 May-15 Jul-15 Sep-15 Nov-15 Jan-16 Mar-16 May-16 Jul-16 Sep-16 Nov-16 Jan-17 Mar-17 May-17 Declines have been arrested where waterflood has been introduced Significant room for flood expansion on existing land base Low-cost mechanism to add reserves and production Waterflood Area Waterflood SLVP Producers Non-waterflood SLVP Producers 16

17 ST. LAWRENCE LOWLANDS: QUEBEC CALL OPTION ON NATURAL GAS DEVELOPMENT St. Lawrence Lowlands of Quebec 309,620 gross (241,884 net) acres in the St. Lawrence Lowlands Prospective for the Utica Shale Close proximity to major markets has historically provided for premium product pricing compared to NYMEX for natural gas produced from the area Drilling suspended since 2011 pending development of the provincial energy policy and regulation Quebec Petroleum Resources Act recently enacted to establish new regime for oil and gas exploration and development Champlain #1 (100% WI) Operator: PPR Becancour #8 (100% WI) Operator: PPR St-Francois-du-Lac #1 (60% WI) Operator: PPR St-Francois-du-Lac HZ #1 (60% WI) Operator: PPR St-Louis Richelieu HZ #1 (60% WI) Operator: PPR St-Denis Richelieu #1 (60% WI) Operator: PPR 17

18 2018 OUTLOOK Current Estimates (1)* Average production (boe/d) 5,200 5,600 % liquids weighting 68% - 71% Operating netback ($/boe) Forecast Adjusted EBITDAX* ($millions) Royalties (%) 15% Operating expenses ($/boe) $ $18.50 Capital expenditures (2) ($millions) ~ 26 (1) Based on Jan 15, 2018 strip pricing average 2018 WTI US$63.00/bbl, AECO - C$1.43/mcf, WCS - C$51.50/bbl, Edmonton Light to WTI differential - C$6.00/bbl and USD/CAD FX - $0.81 (2) 2018 $26 million 2018 capital program does not include ARO or capitalized G&A * Note: See Oil and Gas Metrics and Non-IFRS Measures Advisories on slide 24 and Forward Looking Information on slide 25 18

19 WHY INVEST IN PPR Focused on returns Compelling value opportunity PPR trading at ~38% of PDP NPV10 (2) (Btax) Disciplined approach to capital allocation and focus on projects that provide the highest IRR Asset portfolio provides returns ranging from 40% - 106% (1) in current price environment, supporting organic growth and development Oil-weighted, low-risk asset base >5 years identified development drilling opportunities* 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 Total Debt (net of cash on hand) of $52 MM representing 1.7x debt / next twelve-month EBITDAX* Strong hedge position (60%, 45% and 25% of base net production for 2018, 2019 and 2020, respectively Remain focused on prudent capital management and will scale our 2018 budget depending on commodity prices * Note: See Oil and Gas Metrics and Non-IFRS Measures Advisories on slide 24 (1) Based on Jan 15, 2018 strip pricing average 2018 WTI US$63.00/bbl, AECO - C$1.43/mcf, WCS - C$51.50/bbl, Edmonton Light to WTI differential - C$6.00/bbl and USD/CAD FX - $0.81 (2) Based on Sproule Associates Limited s forecase prices as at December 31,

20 COMPELLING OPPORTUNITY PROVEN ASSETS, COMMITTED TEAM, STRONG TORQUE TO OIL PRICES Current valuation presents attractive entry point EV / 2017E DACF (x) 9.0x 8.0x 7.0x 6.0x 5.0x 4.0x 3.0x 2.0x 1.0x 0.0x 2017 EV / DACF Comparatives 2017 EV / Production Comparatives EV / 2017E Production ($/boe/d) $60,000 $50,000 $40,000 $30,000 $20,000 $10,000 $0 20 (1) Source: Bloomberg, Mackie Research Capital as at September 5, 2017 (2) Companies included above: SRX, BXE, RMP, GXO, EGL, SGY, TVL, JOY,DEE, GXE, ATU

21 ACTIVE RISK MANAGEMENT 60% hedged of forecast 2018 base volumes (net of royalties) 45% hedged of forecast 2019 base volumes (net of royalties) Commodity Contract Reference Notional Quantity Remaining Term Weighted Average Price Oil (bbl/d) Swap WTI ($USD) 1,050 Cal Swap WTI ($USD) 510 Cal Swap WTI ($USD) 419 Cal Collar WTI ($USD) 675 Cal x Collar WTI ($USD) 175 Cal x Sold Call WTI ($USD) 500 Cal 2018 (65.00) Sold Call WTI ($USD) 400 Cal 2020 (60.50) Collar WTI ($CAD) 800 Cal x Sold Call WTI ($CAD) 400 Cal 2019 (85.00) Gas (GJ/d) Swap AECO ($CAD) 4,000 Q Swap AECO ($CAD) 1,500 Q3 - Q Swap AECO ($CAD) 3,000 Q Sold Call AECO ($CAD) 1,500 Cal 2018 (2.76) 21

22 SUMMARY OIL-WEIGHTED GROWTH ENGINE Oil & liquids focused E&P company executing a returns-based growth strategy ATTRACTIVE ASSETS ~5,000 boe/d current production ~70% oil and liquids weighted ~60% of 2018 base production is hedged, economic netbacks and returns in current environment FUTURE GROWTH Sizeable drilling inventory for organic growth Consolidation opportunities in core areas Low maintenance capital requirements LIQUIDITY Development funded with future operating cash flows $11 MM (US$9 MM) available on $70 MM credit facility Steady cash flows from low-decline assets 20.7 MMboe Total Proved Reserves (1) $298.5 MM Total Proved NPV10 (1) 22 (1) See Reserves Data Disclosure Advisories on slide 25

23 Prairie Provident Corporate Information HEAD OFFICE Prairie Provident Resources 1100, 640 5th Avenue SW Calgary, Alberta T2P 3G4 PHONE: / WEB: info@ppr.ca STOCK EXCHANGE LISTING: TSX: PPR LEGAL COUNSEL: Bennett Jones LLP RESERVE ENGINEERS: Sproule Partners Limited INVESTOR RELATIONS: 5 Quarters Investor Relations Inc.

24 ADVISORIES Oil and Gas Metrics and Non-IFRS Measures Oil and Gas Metrics and Non-IFRS Measures. 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. 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. EBITDAX. Prairie Provident monitors its capital structure and liquidity based on a debt-to-ebitdax ratio, which provides a measure of its ability to manage its debt levels under current operating conditions. For purposes of this calculation, "debt" refers to borrowings under the Company's credit arrangements, while "EBITDAX" corresponds to defined terms under the Company's credit agreements and means net earnings before financing charges, foreign exchange gain (loss), E&E expense, income taxes, depreciation, depletion, amortization, other non-cash expense items and nonrecurring items over the most recent four consecutive fiscal quarters, adjusted for major acquisitions and material dispositions assuming that such transactions had occurred on the first day of the applicable calculation period. Adjusted EBITDAX "Adjusted EBITDAX" corresponds to defined terms under the Company's credit agreements and means EBITDAX (defined above) as adjusted for major acquisitions and material dispositions assuming that such transactions had occurred on the first day of the applicable calculation period. Management believes this to be a useful supplemental measure for assessing Prairie Provident's operational performance on a continuing basis by eliminating certain non-cash charges and charges that are non-recurring, and utilizes the measure to assess the Company's ability to generate the cash necessary to finance operating activities, capital expenditures and debt repayments. Adjusted EBITDAX as presented does not and is not intended to represent, and should not be considered an alternative to or more meaningful than, cash flow from operating activities, net earnings or other measures of financial performance calculated in accordance with IFRS Funds from Operations. The Company calculates funds from operations as cash flow from operating activities (as determined in accordance with IFRS) adjusted for changes in non-cash working capital, transaction costs, restructuring costs, decommissioning expenditures and other non-recurring items. Management believes this to be a useful supplemental measure for assessing Prairie Provident's operational performance on a continuing basis by eliminating certain non-cash charges and charges that are non-recurring, and utilizes the measure to assess the Company's ability to generate the cash necessary to finance operating activities, capital expenditures and debt repayments. Funds from operations as presented does not and is not intended to represent, and should not be considered an alternative to or more meaningful than, cash flow from operating activities, net earnings or other measures of financial performance calculated in accordance with IFRS. Reserve Life Index. Reserve life index (RLI) is calculated by dividing total company share reserves by annualized production. RLI provides a summary measure of the relative magnitude of the Company's reserves through an indication as to how long they would last based on a current, annualized production rate and assuming no additions to reserves. F&D Costs. Prairie Provident calculates F&D (finding and development) 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. Recycle Ratio. The Company calculates recycle ratio by dividing operating netback per share by F&D costs for the period. Management considers recycle ratio to be a useful measure for capital deployment and comparing the cost of replacement reserves against produced reserves. Financial Outlook Information. Information in this presentation regarding 2017 forecast adjusted EBITDAX constitutes a financial outlook within the meaning of applicable Canadian securities laws, and is also forward-looking information subject to the cautionary statements under "Forward- Looking Information" below. See also "Oil and Gas Metrics and Non-IFRS Measures" above. 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 operating activities, capital expenditures and debt repayments. The financial outlook information contained herein should not be used, and may be inappropriate for, any other purpose. Drilling Inventory and Locations. This presentation refers to drilling inventory and drilling locations or opportunities. Drilling inventory is expressed in years and is based on identified drilling locations and internal estimates regarding pace of drilling activity. Drilling locations include (i) proved locations, being those for which Sproule has attributed proved reserves in its current evaluation report under NI , (ii) probable locations, being those for which Sproule has attributed probable reserves in its current evaluation report under NI , and (iii) unbooked locations, being those for which there are no attributed reserves but which the Company internally estimates can be drilled based on current land holdings, industry practice regarding well density, and internal review. Unbooked locations represent an estimation of multi-year drilling activity based on internal evaluation of geological, geophysical, seismic, engineering, production and resource information. 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 the Company 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 type wells for the Company. Type well information reflects Prairie Provident's current operating experience in relation to wells of the indicated types, including with respect to costs, production and decline rates, and reflects commodity price forecasts based on January 15, 2018 strip pricing that contemplates an average 2018 WTI price of US$63.00 and AECO price of Cdn$1.46/mmbtu. There is no assurance that actual well-related results will be in accordance with those suggested by the type well information. Actual results will differ, and the difference may be material. The type well information includes estimated ultimate recovery (EUR), which is not a resource category or defined term under NI 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 estimates reflect type curve information based on internal empirical data and publicly available information sources believed to be independent but which the Company cannot confirm was prepared by a qualified reserves evaluator or in accordance with the COGE Handbook. 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. The presentation discloses well-flow test rates of production for certain wells and initial production (IP) rates for type wells. Test results and 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 testing or an initial short-term production period, and the difference may be material. Barrel of Oil Equivalent (boe). Production and reserves information in this presentation is provided on a barrel of oil equivalent (boe) basis, with natural gas volumes converted to a boe measure at a ratio of six thousand cubic feet to one barrel. Boes may be misleading, particularly if used in isolation. A boe conversion ratio of six mcf (six thousand cubic feet) to one bbl (one barrel) is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead or at the plant gate. Although the 6:1 conversion ratio is an industry accepted norm, it is not reflective of price or market value differentials between product types. Based on current commodity prices, the value ratio between natural gas and oil is significantly different than the 6:1 ratio based on energy equivalency. Accordingly, a 6:1 conversion ratio may be misleading as an indication of value. 24

25 ADVISORIES Forward Looking Information 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 otherthan statements of currentorhistorical factconstitute forward-looking information. Forward-looking information is typically, butnotalways, 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: drilling inventory and future drilling locations; the Company's target debt-to-ebitdax ratio; forecast funds from operations for 2018; reserve life index (RLI); future M&A opportunities; type well economics (including estimated ultimate recovery); estimated capital program for 2018; future exploration and development activity (including 2018 drilling plans at Wheatland and future vertical well development opportunities at Evi); expectations with respect to further hedging activity; estimated average production, liquids weighting, operating netback, royalty rate, operating expenses, general and administrative costs and capital expenditures for 2018; and expected benefits of Evi waterflood initiatives. 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 2018 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 otherrisksare discussed in more detail in the Company's currentannual information form and otherdocuments filedby itfrom 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 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. Reserves Data Disclosure Reserves Data Disclosure. Figures provided in this presentation as to Prairie Provident's 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, 2017 based on evaluations by Sproule Associates Limited ("Sproule"), the Company's independent qualified reserves evaluator, of the Company's reserves data which evaluation was effective December 31, Sproule's evaluations were in accordance with NI and, pursuant thereto, the standards contained in the Canadian Oil and Gas Evaluation Handbook ("COGE Handbook"). Information in this presentation regarding the Company's 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 afterdeduction 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 orgeneral 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 the Company's 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 respect to reserves, net present value of estimated future net revenue related to the reserves, discounted at 10% per year. 25