positioned for growth - prairie provident resources · *assumes completion of the arrangement with...

Corporate Presentation

PositionedforGrowth

October 2016

2

Prairie ProvidentOVERVIEW

E&P company with operations primarily focused in the Western Canadian Sedimentary Basin in Alberta

Significant liquidity ($55 MM facility) and strong hedge position through 2018 underpins growth potential

Liquids-weighted and low decline asset base generates attractive economics in current environment

• 50-70% liquids• Low base decline of 23%• Identified upside with long running room: greater than 5 years of sustained development

locations on 765,618* net acres of land• Light oil waterflood development offers attractive economics + significant reserve addition

Assets with high working interests and operatorship allows control over pace of development

• Capital allocation flexibility drives enhanced capital efficiencies

*AsatJune23,2016

3

• 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

• Deliver accretive growth through organic exploitation plus opportunistic acquisitions

• Competition for capital across areas improves IRRs

• Maintain strong balance sheet through capital discipline and robust hedge program

• Target 1X debt to EBITDA on annual average basis

STRATEGY

4

Operational Summary(1)

Production (boe/d) (Aug. 2016 est.) 4,000(2)

Oil & liquids weighting (%) 71%

Base decline rate (%) 24%

Pro Forma Reserves as at year end 2015

PDP Reserves (Mboe) 7,019

PDP PV10 ($MM) $109

TP Reserves (Mboe) 11,980

TP Reserves PV10 ($MM) $152

P+P Reserves (Mboe) 18,489

P+P Reserves PV10 ($MM) $235

(1)(2)(3)(4)(5)Seeendnotesonslide23

Financial Summary

Shares Outstanding (MM) 97.4

Bank Debt ($MM) $5

Credit Capacity ($MM) $55

Q4 ‘16 Forecast Funds from Operations ($MM)(3)(4)(5) ~ $6.0

PRO FORMA OVERVIEW

5

MANAGEMENT TEAM AND BOARDManagementTim S. Granger, President & CEO CEO Molopo Energy Limited, President and CEO of Compton Petroleum Corporation, COO Paramount Energy, Managing Director of TAQA North, COO Primewest

Mimi M. Lai, VP Finance and CFOVice President, Finance & Controller, Manager, Financial Reporting at Harvest Operations Corp, Sr. Manager, Financial Accounting Advisory Services Ernst & Young LLP,

Robert Guy, VP OperationsVice President Production Operations at Spyglass Resources Corp., Manager Operations at Ketch Resources Trust, Various Management Positions at Acclaim Energy Trust

Tony van Winkoop, VP ExplorationPresident and CEO Arsenal Energy Inc., General Manager of Development Primewest, Co-founder Venator Petroleum

Gjoa Taylor, VP LandVice President Land Arsenal Energy Inc. Various positions with Imperial Oil, Crestar Energy, and at PrimeWest Energy as Manager, Negotiations

BoardofDirectorsPatrick R. McDonald, Chairman

David M. Fitzpatrick

Terence (Tad) Flynn

Ajay Sabherwal

Rob Wonnacott

Derek Petrie

Tim Granger (President & CEO)

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• Built an oil-weighted and low-risk asset base in Alberta focused in Wheatland / Princess and Evi, which offers:• Over 170(1) internally identified development drilling opportunities (unrisked)• Proven water flood program that requires minimal capital and reduces

corporate decline rates• Significant future consolidation prospects in core areas

• Organically grew Wheatland to ~ 1,200 boe/d in 9 months while reducing capital costs from ~$2.7MM to $1.5MM per well

• Advanced waterflood project at Evi in 2016 with four new injector wells

• Multiple M&A targets in close proximity to focus areas

POSITIONEDFOR GROWTH

*Assumescompletion ofthearrangementwithArsenal

7

765,618Total Net Acres(1)

PrincessMulti-zone potential: Lithic Glauc & DetritalHz and Vt development

WheatlandLower cretaceous oil/gas128 sections; year round accessHz development

EviSlave Point light oil – low risk 56 sectionsEmerging waterflood; initial reserves booked

EVI

PRINCESS

WHEATLAND

KEY FOCUS AREASASSET BASE

ALBERTA

18.5 MMBOEProved + Probable

Reserves(1)

$235 MMNPV10 Value(1)

(1)Seeendnotes onpage15(2)AsatQ22016

1,400 boe/d

1,100 boe/d

500 boe/d

Other1,000 boe/d

8

ATTRACTIVE ECONOMICS + INVENTORYAverage Type Well Economics Princess Wheatland

Drill, Complete, Equip & Tie-in ($MM) $0.7 MM $1.55 MM

Production, IP30 (boe/d) 65 boe/d 260 boe/d

Production, IP365 (boe/d) 45 boe/d 160 boe/d

EUR (mboe) 60 mboe 166 mboe

Rate of return (%)* 70% 31%

Payout (years) 1.3 yrs 2.1 yrs

Reserve cost ($/boe) $11.71/boe $9.15/boe

Initial operating netback ($/boe/d) $27.26/boe $18.12/boe

Recycle ratio 2.3 2.0

*Based on May 17 strip price

9

Focus on development at Wheatland, Princess and Evi:

Core Area Capex Activities

Wheatland / Princess $13MMDrill, complete, tie-in 8-10 wells $2.1 million (CEE)

Evi $1MM Electrification and capital maintenance

ARO $2MM Abandonment in B.C.

Other $2MM Capitalized G&A, lease rentals, etc.

2H 2016 Capex est. ~$18 MM

• Flexibility to expand 2H capital program based on commodity prices• Seek further growth through organic drilling on sizeable land base or

pursue accretive acquisitions• Strong balance sheet and access to capital supports M&A

CORE AREA DEVELOPMENT

10

• Shallow Mannville / Detrital Fairway with large OOIP

• Lithic Glauconite Fluvial Channels• Subaqueous Marine Ellerslie Deposition• Horizontal efficiencies with pad drilling• Bypassed pay identification

WHEATLAND / PRINCESS OPPORTUNITY

Multi-zonestackedbypasslightoilplay

29-33º API oil3,500 – 7,500 scf/bbl8-25m thick9-15% porosity15-45% WTC

11

WHEATLANDShallow Mannville Fairway: Large OOIP

*Basedoninternally identified locations

1

2

3

45

67

T29

T28

T27

T26

T25

T24

T23

T22

T21R26 R25 R24 R23 R22 R21 R20

8

Zone Status

1. 1-10-28-21 Ellerslie Producing


3.15-35-25-22 Ellerslie Producing





8. 13-7-25-22 Glauconite Producing

9. 4-21-25-22 Ellerslie Completed10. 3-25-25-22 Ellerslie Completed11. 16-28-25-22 Ellerslie Completed12. 3-25-27-21 Ellerslie Drilled & Cased13. 2-26-27-21 Ellerslie Drilled & Cased14. 1-17-25-22 Ellerslie Drilled & Cased15. 13-22-28-22 Ellerslie Drilling16. 1-3-28-20 Ellerslie Licensed17. 4-16-25-22 Glauconite Licensed18. 16-10-25-22 Glauconite Licensed

1

2

45

3

67

911

10

12

14

13

16

1718

128sections(gross)

145 Unrisked Locations*

8ProducingMannvilleWells

15

PPRLand

PPRWells

PPRH2’16Wells

#

#

12

WHEATLAND

Encouraging Results to Date• Explorationtodatehasyieldedfour

significantdiscoveries

• Eachdiscoveryhasmultiple followupdrills

T29

T28

T27

T26

T25

T24

T23

T22

T21R26 R25 R24 R23 R22 R21 R20

100/01-10-028-20W4OnProd:Dec 2015

FollowLocations:Upto12

102/14-28-028-20W4OnProd:Mar2016


102/13-07-025-22W4OnProd:Aug 2016

Future Exploration Upside• Fiveadditionalexploration

blockstobetestedduringthenext2years


ExplorationBlocks

Shallow Mannville Fairway: Large OOIP

Main Clastic Targets:Lithic Glauconite Fluvial ChannelsSubaqueous Marine Ellerslie Deposition

PPRLand

PPRWells

13

WHEATLAND

PPRLand

PPRWells

Discoveries

14-28Discovery

IP(partial1stMonth):Oil:140bbl/dGas:828Mcf/d

CurrentOil:67bbl/d

Gas:438Mcf/dNetPorosityMapSP>30mVor9%Porosity

102/14-28-028-20W4OnProd:Mar2016


1-10Discovery

IP(partial1stMonth):Oil:267bbl/dGas:738Mcf/d

CurrentOil:125bbl/dGas:673Mcf/d

100/01-10-028-20W4OnProd:Dec2015


13-7DiscoveryIP(partial1st Month):

Oil:50bbl/dGas:1500Mcf/d

102/13-07-025-22W4OnProd:Aug 2016


14

WHEATLAND

-

50

100

150

200

250

300

Prod

uctio

n (b

oed)

months

ROR: 31%Payout: 2.1 yearsRecycle Ratio: 2.0

May 17 strip price*

Mannville Type Well

Play is Economic at Current Prices

Freehold Lands with Extensive Drilling Inventory

Capital Efficiencies Through Multi-Well Drilling Programs and Pad Drilling

*2016WTI@$45and2017WTI@50$

15

PRINCESS

• 9 Identified Detrital Locations• 6 Identified Glauconite Locations• 3 discovery wells awaiting tie in

• Cumulatively tested in excess of 600 bbl/d of oil

• Expansion opportunity regionally• 500+ boe/d currently behind pipe• 3D Seismic controlled• Low risk exploitation

70 sections(gross)

95%averageworkingInterest

450mLateral,265mPayMixedPorosity23APIOil

Tested:~250Bbl/dPendingTieIn

05-24Detrital

850mLateral,670mPayMixedPorosityOilandGasTested:110Bbl/d

150E3/dGasPendingTieIn

05-24Glauconite

05-24Glauconite

VerticalWell4.5m30%+PorosityPay

28APIOilTested:~250Bbl/dPendingTieIn

Detrital Oil

Detrital Gas

GlaucChannel

Exploration Locations

Recompletions

16

PRINCESS

Potential Cost Savings:• Gas processing (with incremental

expenditure estimated at <$5.0MM)

Low-Risk Organic Growth Driver

Robust Economics

-

10

20

30

40

50

60

70

Oil

Pro

duct

ion

(bop

d)

Risked Detrital Type Well*


May 17 strip price*

*Riskedat50%

months

*2016WTI@$45and2017WTI@50$

17

EVILone Pine Land

Arsenal Land

• Company controls pace of development & capital

• 2D & 3D seismic coverage

• Established infrastructure supports strong netbacks

Synergies:

• Field Staff

• Battery consolidation

• Economies of scale (services chemicals)

Slave Point Light Oil Resource Play

Stable PDP Profile

82%Working Interest

95%Operated

39ºAPI Oil

PPRLand

18

0

5

10

15

20

25

30

35

11 16 21 26 31

Cal

Dai

ly O

il (B

OPD

)

Time (months)

• Base Assumptions:• Q1 2016 expansion - $2.3MM

(4 conversions + facility work)• “Full field low scenario” – 14 additional producing

wells to be converted to injection wells – $3.5MM capex

• Future facility and tie-in capex estimated at $10.0MM

• Impact• LPR EVI YE 2015 TP reserves were 6.6MMBoe• Risked production in model by 50%• Estimated incremental EUR from waterflood model ~

6.8MMBoe• Potential for a doubling on reserve bookings and

recovery over time

FULL FIELD (EVI MAIN) WATERFLOOD DEVELOPMENT

Waterflood (single injector)May 17 strip price


*2016WTI@$45and2017WTI@50$

19

WATERFLOOD SUMMARY

15 Producing wellsSlavePoint (3)Gilwood (6)Granite Wash (6)

• $2.3 MM spent in Q1 on waterflood expansion

• 2 wells reactivated in section 20 to take advantage of the waterflood expansion

Opportunity for a doubling of reserve

bookings and recovery over time

Initial results of early waterflood pilots show production increases in wells offsetting injectors

RPS study supported:• Points to a 2% RF to date

• Points to a 9% RF with water flood development

• EVI YE 2015 TP reserves were 6.6MMboe(1)

• Incremental EUR from waterflood ~6.8 MMbbl

(1)Seeendnotes onpage23

Lone Pine Land

Arsenal Land

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ACTIVE RISK MANAGEMENTVolume Price Price

Commodity Contract Type (GJ/d) (bbls/d) Strike/Floor Ceiling Term

Gas Swap 2,500 - AECO $2.50 February – Dec. 2016Swap 1,800 - AECO $2.20 Jul. 1 – Dec.31 2016Swap 1,800 - AECO $2.60 Calendar 2017

Oil Basis Swap - 1,000 MSW $5.35 Calendar 2016Swap - 750 WTI $91.19 Calendar 2016Collar - 250 WTI $65.00 $75.00 Calendar 2016 - 2017Collar - 350 WTI $58.00 $67.50 Jun. 1 – Dec. 31 2016

Basis Swap - 1,000 MSW $5.70 Calendar 2017Collar - 500 WTI $58.00 $67.50 Calendar 2017Swap - 500 WTI $87.78 Calendar 2017

Sold Call Swaption - (382) WTI $93.50 Calendar 2017Collar - 800 WTI $58.00 $67.50 Calendar 2018

Sold Call Option - (500) WTI $65.00 Calendar 2018

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NON-CORE PRODUCING ASSETSProvost ~98% WI (TWP 37-4W4)• 400 Boe/d (92% liquids) net• YE2015 - TP NPV10 $14.3MM • Operated production and battery• Medium to heavy oil (cold production)

Chinchaga ~ 33% WI (TWP 97-8W6)• 195 Boe/d (15% liquids) net• YE15 - TP NPV10 $3.11MM • Non-Operated (CNRL)• Cretaceous shallow gas

Waterton ~12-40% WI (TWP 6-3W5)• 432 Boe/d (5% liquids) net• YE15 - TP NPV10 $4.52MM • Non-Operated (Shell)• Wabamun - Sour gas

22

Pointed Mountain, North West Territories – Shale Gas• Lease extended by 21 years by Aboriginal Affairs and Northern Development on Dec. 10, 2013• 53,000 net acres in Liard Basin prospective for Besa River & Muskwa shales• Land in close proximity to a major pipeline with significant capacity• 21 Tcf Best estimate undiscovered shale gas initially in place • 3.8 Tcf of Best estimate unrisked prospective shale gas resources*

Saint Lawrence Lowlands, QC - Utica Shale• Large contiguous acreage position• 36 Bcf of best estimate unrisked contingent and 2.6 Tcf of best estimate unrisked prospective shale

gas resource**

EXPLORATIONFUTURE OPPORTUNITIES

*Netherland,Sewell&AssociatesInc.Estimatesofunrisked ProspectiveShaleGasResourcesintheUpperandLowerBesa RiverFormationShalesatPointedMountain,asofSept302012**SourceCompany Filings:Netherland,Sewell&AssociatesInc.independentassessmenteffectiveMay31,2012

23

SUMMARY

FUTUREGROWTHSizeable drilling inventory for organic growthConsolidation opportunities in core areasLow maintenance capital requirements

LIQUIDITY$55 MM credit facilityVery low debtAble to internally fund growth

ATTRACTIVEASSETS~4,000 Boe/dOil weightedEconomic even in current environment

$152MMTotalProvedNPV10

(1)

12MMboeTotalProved reserves(1)

(1)Seeendnotes onpage23

New Lone Pine offers exposure to a high-growth, light oil weighted company with significant liquidity to fuel future organic and acquisition growth

Prairie ProvidentCo rp o rate In fo rmat ion

PrairieProvidentResources1100,640– 5thAvenueSWCalgary,AlbertaT2P3G4

[email protected]

EMAIL/WEB:

STOCKEXCHANGELISTING:TSX:PPR

LEGAL COUNSEL:BennetJones

RESERVEENGINEERS:Sproule

BANKERS:ATB,SociétéGénérale

HEADOFFICE

INVESTORRELATIONS:5QuartersInvestorRelationsInc.

PHONE:+1.403.292-8000

25

ENDNOTES1. BasedontherespectivereservesevaluationreportsofLonePineandArsenal,preparedbySprouleAssociates Ltd.("Sproule")forLone Pineandby

DeloitteLLPforArsenal, evaluatingthereservesdataofeachcompanyasofDecember31,2015inaccordancewiththerequirementsofNationalInstrument51-101Standards ofDisclosureforOilandGasActivities.TheestimatedproformareservesdataofNewLonePineatDecember31,2015hasbeencalculatedby(i)applyingSproule's forecastpricedeckasofJanuary 1,2016toArsenal’s existingevaluation,(ii)deductingfromArsenal'sestimatedreservesdataatDecember31,2015theportionthereofattributabletotheDesanandUSpropertiessold byArsenalin2016as wellastheadditionalCanadianproperties thatArsenalproposes tosell(asdisclosed initsJune2,2016newsrelease),and(iii) addingLonePine's estimatedreservesdataatDecember31,2015(fromtheSproulereport,withoutadjustment)toArsenal's estimatedreservesdataatDecember31,2015(fromtheDeloitteLLPreport,adjustedasdescribed). Exceptasspecifically described inclause(i)andclause(ii), theestimatedproformareservesdataofNewLonePineatDecember31,2015setforthhereindoesnottakeintoaccountanychangesoccurringin2016.

2. BasedonforecastAugust2016production, assumingthatArsenalcompletesthedisposition ofcertainCanadianproperties asdisclosed initsJune2,2016newsrelease.

3. Assumes thatArsenalcompletesthedisposition ofcertainCanadianproperties asdisclosed initsJune2,2016newsrelease.

4. Funds fromoperationsareestimatedfortheperiod betweentheclosing ofthePlanofArrangementandDecember31,2016.

5. See"Non-GAAPMeasures"intheadvisories attheendofthispresentation.

26

ADVISORIESThis presentation contai ns forward-looking information within the meaning of applicabl e Canadi an securities laws. Statem ents that constituteforward-looking i nformati on relate to future performance, events or circumstances , and are based upon internal assumpti ons, pl ans, intentions ,expectations and beliefs. All statements other than statements of present or historical fac t are forward-looking statements. Forward-lookingstatements ar e often, but not always, identifi ed by words such as " expect", "anticipate", "continue", "es timate", "will", "should", "believe", "forecast" ,"budget", "potential" and similar expressions.Although Lone Pine and Arsenal believe that the forward-looking statem ents contai ned herein are reasonable, they should not be unduly reliedupon. There can be no assur ance that the assumptions, plans , intentions, expectations or beliefs contained in the forward-looking statements orupon w hich they are based will in fact occur or be r ealized (or if they do, what benefits Lone Pine, Arsenal or New Lone Pine will derive therefrom).Actual results or outcomes may differ from those expressed or implied in the forward-looking statements. The difference may be material.Forward-looking statements address future events and circumstances and, accordingly, by their very nature i nvolve inherent risks and uncertainties ,both known and unknown, many of which are beyond Arsenal's, Lone Pi ne's and N ew Lone Pine's influence or control. Shoul d one or more ofthese risks or uncertai nties materialize, or should assumptions underlying forward-looking s tatements pr ove incorrect, actual results or outcom esmay vary m aterially from those currently anticipated. Such risks and uncertainties i nclude, but are not limited to, the potential for counter parties tobe unabl e or unwilling to close transac tions and the i nherent risks associated with the oil and gas industry, such as : operational risks in exploration,development, exploitation and production; delays or changes in plans with respec t to exploration or developm ent projects or capital expenditures ;uncertainty of estimates and projections rel ating to produc tion rates, costs and expenses ; commodity price and exchange r ate fluctuations ;marketing and transportation risks; environmental risks; competition from others for scarce resources; the ability to access sufficient capital frominternal and external sources ; changes in laws or governm ental regulati on of the oil and gas indus try, including with respec t to tax, royalty andenvironm ental matters. This list is not exhaus tive. R eaders should also review the risk factors described in other documents filed by Arsenal fromtime to time with securities regulatory authorities in Canada, including its most recent annual i nformati on form, available el ectronically may beaccessed through the SEDAR website at www.sedar.com.In respec t of the forward-looki ng information and statements concerning anticipated benefits and completion of the pr oposed Arrangement and theanticipated timing for completi on of the Arrangement, Lone Pine and Arsenal have provided such i n reliance on certain assumptions that theybelieve are reasonable at this time, including assumptions as to the time required to pr epare and mail shar eholder m eeti ng materials, including therequired information circular; the ability of Lone Pi ne and Arsenal to each receive, in a timely manner, the necessary regulatory, court, shareholder,stock exchange and other third party approvals, i ncludi ng but not limited to the receipt of applicable competition approvals; the ability of each ofLone Pi ne and Arsenal to satisfy , in a timely manner, the other conditions to the cl osing of the Arrangement; and expectations and assum ptionsconcerning, among other things: commodity prices and interest and forei gn exchange rates; pl anned synergies, capital efficiencies and cost-savings ; applicable tax l aws; future produc tion rates; the sufficiency of budgeted capital expenditures i n carrying out planned activities; and theavailability and cost of labour and services. Other specific forward-looki ng statements contained in this news release such as, outstanding debt atclosing, estimated produc tion levels, anticipated completi on of non-core asset dispositi ons by Arsenal, estimated combined tax pools and borrowingbase available to N ew Lone Pine on closing, are pr ovided based on the assumption Arsenal will complete its proposed dispositions of non-cor eassets i n the manner consistent with the disclosures in its June 2, 2016 news release. To the extent that the proposed sal es are not compl ete,such forward-looking statements may be materially inaccurate.Financial outlook information contained i n this news rel ease regarding prospective results of operations, financial position or cash flows is based onassumpti ons about future events and circumstances, i ncludi ng economic conditions and pr oposed courses of ac tion, based on internal assessmentby management of relevant information currently available.

The forward-looking statements included herein are made as of the date of this news release andneither Lone Pine nor Arsenal undertakes any obligation to publicly update or revise any forward-looking statements, whether as a result of new information, futur e events or otherwise, except as maybe required by securities laws.All forward-looking statem ents contained in this news release ar e expressly qualified i n their entirety bythis cautionary statement

Barrels of Oil Equivalent (BOEs)The production and reserves information provided in this news release is presented on the basis of a barrel of oil equivalent (BOE) measure, 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.Reserves DisclosureReserves included herein are stated on a company interest basis (working interest and royalty interest before deduction of royalties payable) unless noted otherwise. The reserves estimates attributed to the properties of Lone Pine and Arsenal are estimates only. Actual reserves may be greater or less than those estimated, and the difference may be material.The determination of oil and gas reserves involves the preparation of estimates that have an inherent degree of associated risk and uncertainty. 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 and decisions 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, reserves estimates also change. Revisions may be positive or negative.It should not be assumed that the estimates of future net revenues presented in this news release represent the fair market value of Arsenal’s, Lone Pine’s or New Lone Pine’s reserves. There is no assurance that the price forecast and cost assumptions applied by the independent reserves evaluators in evaluating the reserves of Arsenal or Lone Pine will be attained and variances between actual and forecast prices and costs could be material.Non-IFRS MeasuresThis news release includes reference to "funds from operations", which is not a measure that has a standardized meaning under International Financial Reporting Standards (IFRS) and is not presented in the financial statements of Arsenal or Lone Pine. Accordingly, that measure as presented herein may not be comparable to similarly defined measures presented by other entities. "Funds from operations" is calculated as cash flow from operating activities, as determined in accordance with IFRS, adjusted for cash paid financing costs, changes in non-cash working capital and decommissioning obligations expenditures. Management considers funds from operations a useful measure of the ability to generate cash flow necessary to fund future growth through capital investment and to repay debt. Funds from operations should not be considered an alternative to, or more meaningful than, cash flow from operating activities as determined in accordance with IFRS.

Forward Looking Statements

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